Carizo Oil & Gas, Inc.
Filed 3/31/03
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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, 2002
COMMISSION NO. 0-22915
CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
TEXAS 76-0415919
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
14701 ST. MARY'S LANE, SUITE 800 77079
Houston, Texas (Zip Code)
(Principal executive offices)
Registrant's telephone number, including area code: (281) 496-1352
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
[X]
Indicate by check mark whether the registrant is an accelerated filer.
YES [ ] NO [X]
At June 28, 2002, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $21.0 million
based on the closing price of such stock on such date of $4.26.
At March 20, 2003, the number of shares outstanding of the registrant's
Common Stock was 14,200,716.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2003 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, 2002.
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TABLE OF CONTENTS
PART I....................................................................... 2
Item 1. and Item 2. Business and Properties................................ 2
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............................................ 23
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................... 26
Item 7A. Qualitative and Quantitative Disclosures About Market Risk........ 37
Item 8. Financial Statements and Supplementary Data........................ 38
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure................................................ 38
PART III..................................................................... 38
Item 10. Directors and Executive Officers of the Registrant................ 38
Item 11. Executive Compensation............................................ 38
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Shareholder Matters.......................................... 38
Item 13. Certain Relationships and Related Party Transactions.............. 39
Item 14. Controls and Procedures........................................... 39
PART IV...................................................................... 39
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 39
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 current operations are
primarily focused onshore in proven oil and gas producing trends along the Gulf
Coast, in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends ("Gulf
Coast Core Areas").
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. During the period from 1996 through December 2001 the Company
acquired 52 3-D seismic surveys with over 2,700 square miles of 3-D data in the
Gulf Coast Core Areas. In late 2002 the Company acquired (or obtained the right
to acquire) an additional 2,750 square miles of 3-D seismic data in the Gulf
Coast Core Areas, including primarily either recently merged and reprocessed
data sets or data newly released to industry. The Company also acquired
additional 3-D seismic data during 2002 as a result of certain data licensing
swaps. The 2002 data acquisitions nearly double the amount of 3-D seismic data
the Company owns in the Gulf Coast Core Areas, and has led to the identification
of additional drilling prospects over which the Company is currently in the
process of acquiring additional lease acreage. These new data, if all are
acquired, will bring the Company's 3-D seismic database in the Gulf Coast Core
Areas to 6,732 square miles, which the Company believes is one of the largest
such databases owned by an independent exploration company in the region. The
Company also has approximately 1,840 square miles of 3-D data in non-core areas
in which the Company presently does not have active projects, but which the
Company is screening for potential drilling prospects. The Company continuously
analyzes and reprocesses the 3-D seismic data in search of prospects which the
Company believes have a high probability of containing natural gas or oil.
Historically, the Company aggressively sought to control significant
prospective acreage blocks for 3-D seismic surveys. The Company would typically
seek to acquire seismic permits from landowners that included options to lease
the acreage prior to conducting proprietary surveys. In other circumstances,
including when the Company participated in 3-D group shoots, the Company
typically sought to obtain leases or farm-ins rather than lease options. From
1996 through 2002, the Company assembled over 400,000 gross acres under lease or
option. After the 3-D seismic data was processed and analyzed, the Company
sought to retain such acreage as it deemed to be prospective and released
non-prospective acreage. As of December 31, 2002, the Company had 100,707 gross
acres in Texas and Louisiana under lease or lease option, most of which is
covered by 3-D seismic data, and 287,994 gross acres in Wyoming and Montana
under lease or option.
From the analysis and interpretation of the 3-D seismic data, Carrizo has
amassed a large drill-site inventory, with as many as 210 gross wells that could
be drilled over the next three to five years, assuming sufficient capital
resources. Most of the Company's drilling targets in prior years have been
shallow (from 4,000 to 7,000 feet), normally pressured reservoirs that generally
involve moderate cost (typically $0.3 million to $0.4 million per completed
well) and risk. Many of the Company's current drilling prospects are deeper,
over-pressured targets which have greater economic potential but generally
involve higher cost (typically $1.0 million to $4.0 million per completed well)
and risk. The Company usually seeks to sell a portion of these deeper prospects
to reduce its exploration risk and financial exposure while still allowing the
Company to retain significant upside potential. The Company has recently begun
to retain larger percentages of, and increased its exposure to, higher cost,
higher potential wells.
The Company operates the majority of its projects through the exploratory
phase but may relinquish operator status to qualified partners in the production
phase in order to focus resources on the higher-value exploratory phase. As of
December 31, 2002, the Company operated 85 producing oil and gas wells, which
accounted for 52% of the onshore Gulf Coast producing wells in which the Company
had an interest.
During 2001, the Company, through its wholly-owned subsidiary, CCBM, Inc.
("CCBM") acquired 50% of the working interests held by Rocky Mountain Gas, Inc.
("RMG") in approximately 107,000 net mineral acres prospective for coalbed
methane located in the Powder River Basin in Wyoming and Montana. The Company
has participated in the acquisition and/or drilling of 75 gross wells, all
of which encountered coal accumulations. Of these wells, 24 wells are currently
producing, 19 are in the dewatering phase and 36 wells are under evaluation to
determine if they are likely to result in commercial production of natural gas.
Proved reserves of 0.6 Bcfe are assigned to the Company's coalbed methane
properties as of December 31, 2002.
The Company has increased its oil and gas reserves from its inception in
1993 primarily due to its 3-D based drilling and development
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activities. From January 1, 1996 to December 31, 2002, the Company participated
in the drilling of 263 gross wells (82.2 net) with a commercial well success
rate of approximately 66%, excluding the 75 gross (28 net) coalbed methane wells
drilled by CCBM. This drilling success contributed to the Company's total proved
reserves as of December 31, 2002 of 63.2 Bcfe with a PV-10 Value of $83.6
million. See "Oil and Natural Gas Properties". During 2002, the Company added a
net 11.4 Bcfe to proved reserves, offset by 7.2 Bcfe of production. The Company
has financed the majority of its drilling activity through internal cash flow
generated primarily from oil and natural gas production sales revenue.
Certain terms used herein relating to the oil and natural gas industry are
defined in "Glossary of Certain Industry Terms" below.
EXPLORATION APPROACH
The Company's strategy has been to rapidly accumulate large amounts of 3-D
seismic data along primarily 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 as compared to
interpreting between widely separated two dimensional vertical profiles.
Consequently, 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 are 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.
Historically, the Company 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 shared the costs and results of
seismic surveys. By participating in joint ventures and group shoots, the
Company was 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.
The Company has also participated in 3-D data licensing swaps, whereby the
Company transfers license rights to certain proprietary 3-D data it owns in
exchange for license rights to other 3-D data within its core areas, thus
allowing the Company to obtain access to additional 3-D data within its Gulf
Coast Core Areas at either minimal or no out-of-pocket cash cost.
In late 2002, the Company acquired (or obtained the right to acquire) an
additional 2,750 square miles of 3-D seismic data in its Gulf Coast Core Areas.
These new data are primarily either recently merged and reprocessed data sets or
former proprietary data sets newly released to industry. Specific Company
operating areas to which new data were added as a result of the late 2002 data
acquisition include (1) 450 square miles of newly reprocessed 3-D data to the
Matagorda project area, (2) 167 square miles of newly released 3-D data to the
Liberty Project area, (3) 239 square miles to the Wilcox project area, and (4)
826 square miles of newly reprocessed 3-D data to the South Louisiana project
area. These data acquisitions consist of existing nonproprietary data sets
obtained from seismic companies at what the Company believes to be attractive
pricing.
The Company's primary strategy for acreage acquisition in prior years was
to obtain leasing options covering large geographic areas in connection with 3-D
seismic surveys. Prior to conducting proprietary surveys, the Company typically
sought to acquire seismic permits that included 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 attempted to obtain these options covering
at least 80% of the project area for proprietary surveys. The size of these
surveys ranged from 10 to 80 square miles. When the Company participated in 3-D
group shoots, it generally sought prospective leases as quickly as possible
following interpretation of the survey. In connection with some group shoots in
which the Company believed that competition for acreage was especially strong,
the Company sought to obtain lease options or leases in prospective areas prior
to the receipt or interpretation of 3-D seismic data. After receipt of and
interpretation of the 3-D seismic data, the Company generally seeks to retain
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only such acreage or leases as it deems to be prospective based upon the 3-D
results and the Company's interpretation. In more recent years, the Company has
focused less on conducting proprietary 3-D surveys, and has focused instead on
(1) the continual interpretation and evaluation of its existing 3-D seismic
database and the drilling of identified prospects on such acreage and (2) the
acquisition of existing non-proprietary 3-D data at reduced prices, in many
cases contiguous to or in areas nearby existing Company project areas where the
Company has extensive knowledge and subsequent acquisition of related acreage as
the Company deems to be prospective based upon its interpretation of such 3-D
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 result from leads
developed primarily by the Company's internal staff. Additionally, the Company
monitors competitor activity and reviews outside prospect generation by small,
independent "prospect generators", or the Company's joint venture partners. The
Company complements its exploratory drilling portfolio through the use of these
outside sources of project generation, and typically retains operation rights.
Specific drill-sites are typically chosen by the Company's own geoscientists.
OPERATING APPROACH
The Company's management team has extensive experience in the development
and management of exploration projects along the Texas and Louisiana Gulf Coast.
The Company believes that the experience of its management in the development,
processing and analysis of 3-D projects and data in the Gulf Coast Core Areas is
a competitive advantage for the Company. The Company's technical and operating
employees have an average of 20 years of industry experience, in many cases with
major and large independent oil companies, including Shell Oil Company, Arco,
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, 2002, the Company operated 85 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 has integrated its 3-D
seismic data with reservoir characterization and management systems through the
use of geophysical workstations which are compatible with industry standard
reservoir simulation programs.
SIGNIFICANT PROJECT AREAS
This section is an explanation and detail of some of the relevant project
groupings from the Company's overall inventory of seismic data and prospects. It
is difficult to uniquely categorize many of the 3-D projects because they were
originally screened and selected for multiple objectives. In the Texas Wilcox
Areas, additional 3-D data that connects and overlaps existing project area
grids continues to be acquired and integrated into the Company's prospect
evaluations and as such, a geographical subgrouping is now used to describe the
Company's areas of focus, rather than the original project area descriptions.
This discussion clarifies this organizational framework and highlights the
project areas where the majority of the expected drilling will take place over
the next 12 to 18 months.
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3-D PROJECT SUMMARY CHART
As of December 31, 2002
SQUARE 2003
MILES PLANNED
OF 3-D SEISMIC GROSS NET
FOCUS AREA 3-D PROJECT SEISMIC ADDITIONS(2) ACREAGE ACREAGE
---------- ----------- ------- ------------ ------- -------
TEXAS WILCOX AREAS
Wilcox Central 957 180 18,854 8,416
Wilcox South 562 -- 17,347 2,809
Wilcox East 274 -- 1,187 824
TEXAS FRIO/VICKSBURG/YEGUA AREAS
Matagorda 542 125 7,355 3,951
Wharton/Victoria 83 -- 14,979 2,743
Other Areas 1,477 -- 19,259 5,164
SOUTHEAST TEXAS AREAS
Liberty 223 60 7,488 2,321
Cedar Point 30 3,268 1,159
Other Areas 9 265 -- -
SOUTH TEXAS
LaSalle/McMullen 65 -- 6,729 6,159
LOUISIANA AREAS
La Rose 39 -- 2,342 1,557
Other Areas 1,166 675 1,899 242
----- ----- ------- ------
GULF COAST CORE AREA 5,427 1,305 100,707 35,345
===== ===== ======= ======
NONCORE AREAS(1) 1,840 -- -- --
===== ===== ======= ======
WYOMING/MONTANA COALBED
METHANE AREA -- -- 287,994 55,167
========= ======== ======= ======
- ----------
(1) 3-D seismic coverage in oil & gas producing basins outside areas of current
leasehold activity.
(2) 2003 planned seismic additions are primarily 3-D seismic data, the rights
to which the Company acquired as part of a 2,750 square mile data purchase
in late 2002, that is expected to be delivered to the Company in 2003.
TEXAS -- WILCOX AREAS
The prolific Wilcox trend in South Texas continues to be a primary area of
exploration and development focus for Carrizo. The
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Company has a total of 1,793 square miles of 3-D seismic data that covers
potential Wilcox formation exploration and development targets. Wilcox prospects
occur at a variety of depths but are often relatively deeper targets with both
high reserve potential as well as higher well costs. While Carrizo operates
almost all of its Wilcox area projects, portions of these wells are typically
sold down to industry partners to reduce costs and offset exploration and
operational risk.
The Wilcox Central subgroup area contains Company project areas in Goliad,
Lavaca, Dewitt, and Bee Counties, Texas and includes the Cabeza Creek Project
Area. The Wilcox South subgroup contains projects in Duval, Live Oak, Webb,
Zapata and McMullen Counties, Texas. The Wilcox East subgroup contains projects
in Colorado, Jackson, Victoria, Fort Bend and Wharton Counties, Texas.
Wilcox Central -- Goliad, Lavaca, Dewitt, and Bee Counties
The Company was successful on six out of seven wells drilled within the
central Wilcox area during 2002 with drilling focused in the Cabeza Creek
Project Area. Two successful field extension wells to the "Riverdale #2"
discovery well were drilled during 2002, the "Riverdale #1" which commenced
production in May 2002 and the "Riverdale #3" well which commenced production in
August 2002. Carrizo is the operator of the wells and owns a 68.75% working
interest. The Company has eleven additional prospects that are drill-ready
within the 8,416 net acre area that the Company plans to further evaluate over
the next 12 to 18 months, including six wells expected to be drilled during
2003. The primary targets range from the Lower Wilcox to the expanded Upper
Wilcox between 12,000 and 16,000 feet. During 2003, the Company plans to
participate in a Lower Wilcox test well. The Company continues to develop
prospects within its 957 square mile central Wilcox 3-D database, and is working
to secure leases over the areas it believes have the highest potential.
Wilcox South -- Live Oak, Duval, Webb, Zapata, and McMullen Counties
The Company continues to develop prospects within its 562 square mile
southern Wilcox 3-D seismic database and is working to secure leases over areas
it believes have the highest potential. The primary targets include upper Wilcox
through Lobo formations. The Company was successful on both of the wells drilled
in the area during 2002, the "S. Marshall Jr. A-2123 #1" and "S. Marshall Jr.
A-2123 #2" wells in Duval County, both of which commenced sales in February
2003. The Company operates the wells and owns a 29.25% working interest. The
Company plans to drill at least one additional well in this area during 2003
near a recent discovery well drilled by a competitor.
Wilcox East -- Colorado, Jackson, Victoria, Fort Bend, and Wharton Counties
The Company continues to develop prospects within its 274 square mile 3-D
database and is working to secure leases over the areas it believes have the
highest potential. Targets range from the Lower Wilcox to expanded Upper Wilcox
between 12,000 and 16,000 feet. Depending upon the success of leasing efforts,
initial drilling could occur in late 2003 or 2004.
TEXAS FRIO/VICKSBURG/YEGUA AREAS
This combined area trend sometimes overlaps but is generally closer to the
Texas Gulf Coast than the Wilcox areas discussed above. In any particular target
or prospect, the Frio is usually a shallower formation, while the Yegua and
Vicksburg are generally relatively deeper formations. Across the Carrizo project
areas, prospect targets vary greatly in depth and area distribution. The Company
has a total of 2,102 miles of 3-D seismic data over these Frio, Vicksburg and
Yegua sands. Several key areas are discussed below which highlight areas of
expected focus during 2003 and future years.
Matagorda -- Matagorda County
The Matagorda Project Area currently includes license to 542 square miles
of 3-D seismic and 3,951 net acres of current leasehold in Matagorda County,
Texas. The Company continued its drilling success during 2002 in the Matagorda
Project Area with three successful wells. All three wells were drilled as
offsets to the field discovery well, the "Staubach #1" that commenced production
in January 2002 at over 17,000 Mcfe per day. The "Burkhart #1R" was completed
and commenced production in July 2002 at a gross rate of 1,500 barrels of oil
and 8,700 Mcf of natural gas (17,700 Mcfe) per day. Carrizo owns a 35% working
interest in the well. In July 2002, the Company spud the "Pauline Huebner A-382
#1" well which Carrizo operates and owns a 45% working interest. This well
commenced production in mid-November 2002 at a gross rate of approximately 1,800
barrels of oil and 5,000 Mcf of natural gas (approximately 15,800 Mcfe) per day.
The latest successful well, the "Matthes-Huebner #1" well, reached
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total depth of 12,500 feet on December 17, 2002, logged approximately 60 feet of
net pay in the Lower Frio section, and was the first well to have multiple pay
zones. Carrizo owns an approximate 32.21% working interest in the well which
commenced production in early January 2003 at a gross rate of approximately
2,518 barrels of oil and 7,700 Mcf of natural gas (22,800 Mcfe) per day. These
four wells are currently continuing to produce at a combined gross rate of
approximately 4,990 barrels of oil and 18,800 Mcf of natural gas (48,740 Mcfe)
per day, or 12,140 Mcfe/d net to the Company's interest. The Company plans to
drill four additional prospects within the next 12 months. Two of the planned
wells were spud during March 2003.
Wharton and Victoria Counties
The Wharton and Victoria County project areas target both normal pressured
Frio and expanded Yegua prospect opportunities identified on the Wharton County
and Victoria County, Texas 3-D seismic data sets that cover approximately 83
square miles. The Company plans to drill three normal pressured Frio wells in
these areas during 2003 retaining working interests as high as 51%. Although
relatively small prospects, these are seismic amplitude anomaly targets that are
expected to have relatively high chance of success.
SOUTHEAST TEXAS AREAS
Carrizo has now acquired approximately 587 square miles of 3-D data
(including 325 square miles of newly released data delivered in 2003) over its
Southeast Texas project areas which are focused primarily on the Frio, Yegua,
Cook Mountain and Vicksburg formations. The Liberty Project Area and Cedar Point
Project Area have proven to be successful for the Company and the Company
expects that the Liberty Project Area will constitute a significant portion of
the 2003 drilling program.
Liberty
Carrizo has identified and leased prospects ranging from the Frio to the
Cook Mountain formations within the 223 square miles of 3-D seismic in the
Liberty Project Area which, along with 60 square miles of newly released 3-D
seismic data acquired in early 2003, now covers significant areas of Liberty and
Hardin Counties, Texas. To date, the Company has been successful on four of six
wells drilled, including one Yegua well, one Frio well and two Cook Mountain
wells. The latest Cook Mountain test well drilled during the fourth quarter of
2002, the "Hankamer #1" well, logged approximately 40 feet of net pay in the
Cook Mountain interval and tested at a gross rate of 10,490 MCF of natural gas
and 772 barrels of oil (15,122 Mcfe). Carrizo operates the well and owns a 40%
working interest. Efforts to put the well online have been delayed due to
flooding late last year and the inability to connect to infrastructure, however,
the well is expected to commence production in early April 2003. Carrizo plans
to drill three additional wells in the Liberty Project Area during 2003.
Cedar Point
The Cedar Point Project Area is located in Chambers County, Texas, adjacent
to Trinity Bay. The 30 square mile 3-D survey targets the lower Frio and
Vicksburg formations. Five of six wells drilled to date have been successful.
Carrizo plans to drill an additional well in 2003. The Company's working
interest in leases in this project area is approximately 25%.
SOUTH TEXAS
LaSalle and McMullen Counties
The South Texas Project Area is located in LaSalle and McMullen Counties,
Texas. Analysis and interpretation of the 65 square mile proprietary 3-D seismic
survey has revealed two large Sligo Patch reef prospects. The Company believes
these prospects could hold significant potential, and expects to spud the first
test well in late 2003. The Company currently has an approximate 79% working
interest in these prospects, but expects to sell down a portion of its interest
to industry partners in order to mitigate the exploration risk and the Company's
financial exposure.
LOUISIANA
LaRose
During 2002, the Company successfully drilled and completed the "Louisiana
Delta Farms #2" well, offsetting the LaRose Prospect 2001 discovery well, the
"Louisiana Delta Farms #1", in Lafourche Parish, Louisiana. Carrizo operates the
wells and owns a 40% working interest. Through February 2003, the two wells have
produced over 4.5 Bcfe since commencement of production. The
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Company plans to participate in the drilling of three additional wells in areas
either near or within the LaRose Project Area during 2003. During 2002, the
Company acquired the rights to over 1,150 square miles of additional 3-D seismic
data in Louisiana for future potential prospect evaluation.
CAMP HILL PROJECT
The Company owns interests in eight leases totaling approximately 619 gross
acres in the Camp Hill field in Anderson County, Texas. The Company currently
operates seven of these leases. During the year ended December 31, 2002, the
project produced an average of 58 Bbls/d of 19 API gravity oil. The wells
produce from a depth of 500 feet and utilize 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, 2002 averaged $14.99 per barrel ($2.50 per Mcfe). In
response to high fuel gas prices, steam injection was reduced in mid 2000.
Because profitability increases when natural gas prices drop relative to oil
prices, the project is a natural hedge against decreases in natural gas prices
relative to oil prices. The oil produced, although viscous, commands a higher
price (an average premium of $1.00 per Bbl during the year ended December 31,
2002) than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 2002, the Company had 7.7 MBbls of proved oil
reserves in this project, with 750 MBbls of oil reserves currently developed.
The Company anticipates drilling additional wells and increasing 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 90% in this field and an average
net revenue interest of 74%.
WYOMING/MONTANA COALBED METHANE PROJECT AREA
The Company, through CCBM, acquired interests from RMG in certain oil and
gas leases covering 233,875 gross acres and 43,711 gross acres in options during
2001 in areas prospective for coalbed methane in the Powder River Basin ("PRB")
in southwestern Wyoming and Montana. The Company's working interest ranges from
6.25% to 50.00% in the leases. As consideration for the interests, CCBM paid RMG
$7.5 million in the form of a non-recourse promissory note (the "CCBM Note"),
secured solely by CCBM's interest in the undeveloped acreage. In addition, the
Company committed to spend up to $5.0 million to drill and test coalbed methane
wells on this acreage during 2001 through 2003, 50% of which would be spent
pursuant to an obligation by Carrizo to fund $2.5 million of drilling costs on
behalf of RMG. As of December 31, 2002, the Company has participated in the
acquisition and/or drilling of 75 gross wells (28 net) satisfying approximately
$3.0 million of the $5.0 million drilling commitment. All of the wells
encountered coal accumulations and are in various stages of development and/or
stages of production. Coalbed methane wells typically first produce water and
then, as the water production declines, begin producing methane gas at an
increasing rate. As the wells mature the production peaks and begins declining.
At the "Clearmont Project" in Wyoming, in which CCBM owns an average 50%
working interest, 32 wells have been drilled and completed to date, including 19
wells currently on pump in the dewatering stage of development. As there are
only a few other coalbed methane projects/wells in the immediate vicinity, the
dewatering process has taken longer than originally estimated. All of the wells
on pump are producing small amounts of gas consistent with expectations given
the current development stage of the project. The gas gathering, compression
facilities and sales pipeline are in place, and depending upon the progress of
the dewatering process, commercial production could commence in late 2003.
At the 1,940 gross acre "Bobcat Project" in Wyoming, in which CCBM owns an
average working interest of approximately 28%, gross production has reached a
level of over 2,600 Mcf/d, with wellhead prices in excess of $4.00 per Mcf. Many
of the 24 production wells in the project area are still in the dewatering stage
and as such, production is expected to increase in the months ahead. In addition
to the existing wells, the Company believes that there are numerous additional
potential drilling locations which could target the coal seams currently being
produced as well as three additional deeper prospective coal seams.
Of the 55,167 net mineral acres held by CCBM as of December 31, 2002,
approximately 25,600 net mineral acres are located in the state of Montana. The
issuance of new coalbed methane drilling permits in Montana has been temporarily
halted pending a final Record of Decision for Montana's Environmental Impact
Statement (EIS) which is expected to be issued by the Federal Bureau of Land
Management (BLM) in mid-year 2003. The Company anticipates a favorable outcome
and as a result new drilling permits could be issued soon and new wells could
again be drilled by coalbed methane industry participants in Montana. Opponents
of coalbed methane drilling in Montana could continue their legal challenge, but
the Company believes that the decision will ultimately be upheld which would
allow new coalbed methane development to commence in Montana as early as late
2003. RMG, CCBM's partner and project operator, holds approximately 114
grandfathered drilling permits in Montana for acreage in which CCBM also has an
interest. There can be no assurances when, if ever, any new permits will be
obtained.
OTHER PROJECT AREAS
In addition to the specific project areas described above, the Company has
15 additional active project areas in various stages of development as of
December 31, 2002. These project areas are located in the onshore Texas and
Louisiana Gulf Coast regions. The Company is in the process of evaluating and
acquiring interests with respect to most of these project areas and as of
December 31, 2002 had acquired leases in these areas covering 21,158 gross acres
and 5,406 net acres.
8
WORKING INTEREST AND DRILLING IN PROJECT AREAS
The actual working interest that the Company will ultimately own in a well
will vary based upon several factors, including the depth, cost and risk of each
well relative to the Company's strategic goals, activity levels and budget
availability. From time to time some fraction of these wells may be sold to
industry partners either on a prospect by prospect basis or a program basis. In
addition, the company may also contribute acreage to larger drilling units
thereby reducing prospect working interest. The Company has, in the past,
retained less than 100% working interest in its drilling prospects. References
to Company interests are not intended to imply that the Company has or will
maintain any particular level of working interest.
Although the Company is currently pursuing prospects within the project
areas described above, there can be no assurance that these prospects will be
drilled at all or within the expected time frame. In some project areas, the
Company has budgeted for wells that are based upon statistical results of
drilling activities in other project areas; these wells are subject to greater
uncertainties than wells for which drillsites have been identified. The final
determination with respect to the drilling of any identified drillsites or
budgeted wells will be dependent on a number of factors, including (i) the
results of exploration efforts and the acquisition, review and analysis of the
seismic data, (ii) the availability of sufficient capital resources by the
Company and the other participants for the drilling of the prospects (not all of
which resources are currently available), (iii) the approval of the prospects by
other participants after additional data has been compiled, (iv) the economic
and industry conditions at the time of drilling, including prevailing and
anticipated prices for oil and natural gas and the availability of drilling rigs
and crews, (v) the financial resources and results of the Company and its
partners and (vi) the availability of leases on reasonable terms and permitting
for the prospect. There can be no assurance that these projects can be
successfully developed or that any identified drillsites or budgeted wells
discussed will, if drilled, encounter reservoirs of commercially productive oil
or natural gas. The Company may seek to sell or reduce all or a portion of its
interest in a project area or with respect to prospects or wells within a
project area.
The success of the Company will be materially dependent upon the success of
its exploratory drilling program. Exploratory drilling involves numerous risks,
including the risk that no commercially productive oil or natural gas reservoirs
will be encountered. The cost of drilling, completing and operating wells is
often uncertain, and drilling operations may be curtailed, delayed or canceled
as a result of a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
adverse weather conditions, compliance with governmental requirements and
shortages or delays in the availability of drilling rights and the delivery of
equipment. Although the Company believes that its use of 3-D seismic data and
other advanced technologies should increase the probability of success of its
exploratory wells and should reduce average finding costs through elimination of
prospects that might otherwise be drilled solely on the basis 2-D seismic data,
exploratory drilling remains a speculative activity. Even when fully utilized
and properly interpreted, 3-D seismic data and other advanced technologies only
assist geoscientists in identifying subsurface structures and do not enable the
interpreter to know whether hydrocarbons are in fact present in such structures.
In addition, the use of 3-D seismic data and other advanced technologies
requires greater predrilling expenditures than traditional drilling strategies
and the Company could incur losses as a result of such expenditures. The
Company's future drilling activities may not be successful, and if unsuccessful,
such failure will have a material adverse effect on the Company's results of
operations and financial condition. There can be no assurance the Company's
overall drilling success rate or its drilling success rate for activity within a
particular project area will not decline. The Company may choose not to acquire
option and lease rights prior to acquiring seismic data and, in many cases, the
Company may identify a prospect or drilling location before seeking option or
lease rights in the prospect or location. Although the Company has identified or
budgeted for numerous drilling prospects, there can be no assurance that such
prospects will ever be leased or drilled (or drilled within the scheduled or
budgeted time frame) or that oil or natural gas will be produced from any such
prospects or any other prospects. In addition, prospects may initially be
identified through a number of methods, some of which do not include
interpretation of 3-D or other seismic data. Wells that are currently in the
Company's capital budget may be based upon statistical results of drilling
activities in other 3-D project areas that the Company believes are geologically
similar, rather than on analysis of seismic or other data. Actual drilling and
results are likely to vary from such statistical results and such variance may
be material. Similarly, the Company's drilling schedule may vary from its
capital budget because of future uncertainties, including those described above.
The description of a well as "budgeted" does not mean that the Company currently
has or will have the capital resources to drill the well. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations".
OIL AND NATURAL GAS RESERVES
The following table sets forth estimated net proved oil and natural gas
reserves of the Company and the PV-10 Value of such reserves as of December 31,
2002. The reserve data and the present value as of December 31, 2002 were
prepared by Ryder Scott Company and Fairchild & Wells, Inc., Independent
Petroleum Engineers. For further information concerning Ryder Scott's and
Fairchild's estimate of the proved reserves of the Company at December 31, 2002,
see the reserve reports included as exhibits to this
9
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 13 of Notes to Consolidated
Financial Statements.
PROVED RESERVES
----------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- --------
(DOLLARS IN THOUSANDS)
Oil and condensate (MBbls) 1,393 6,988 8,381
Natural gas (MMcf) 12,826 96 12,922
Total proved reserves (MMcfe) 21,184 42,024 63,208
PV-10 Value(1) $ 55,235 $ 28,379 $ 83,614
- ----------
(1) The PV-10 Value as of December 31, 2002 is pre-tax and was determined by
using the December 31, 2002 sales prices, which averaged $29.16 per Bbl of
oil, $4.70 per Mcf of natural gas.
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Securities and
Exchange Commission (the "Commission").
There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this Annual Report on Form 10-K
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from
the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions concerning
future oil and natural gas prices, future operating costs, severance and excise
taxes, development costs and workover and remedial costs, all of which may in
fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom
prepared by different engineers or by the same engineers but at different times
may vary substantially and such reserve estimates may be subject to downward or
upward adjustment based upon such factors. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material. In addition, the 10% discount
factor, which is required by the Commission to be used in calculating discounted
future net cash flows for reporting purposes, is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company or the oil and natural gas industry in
general.
In general, the volume of production from oil and natural gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent the Company conducts successful
exploration and development activities or acquires properties containing proved
reserves, or both, the proved reserves of the Company will decline as reserves
are produced. The Company's future oil and natural gas production is, therefore,
highly dependent upon its level of success in finding or acquiring additional
reserves. The business of exploring for, developing or acquiring reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investment to maintain or expand its asset base of
oil and natural gas reserves would be impaired. The failure of an operator of
the Company's wells to adequately perform operations, or such operator's breach
of the applicable agreements, could adversely impact the Company. In addition,
there can be no assurance that the Company's future exploration, development and
acquisition activities will result in additional proved reserves or that the
Company will be able to drill productive wells at acceptable costs. Furthermore,
although the Company's revenues could increase if prevailing prices for oil and
natural gas increase significantly, the Company's finding and development costs
could also increase. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations".
VOLUMES, PRICES AND OIL & NATURAL 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
10
cash impact of hedging activities and the
effect of certain hedge positions with an affiliate of Enron Corp. reclassified
as derivatives during November 2001.
YEAR ENDED DECEMBER 31,
---------------------------------------
2000 2001 2002
------- ------- -------
Production volumes
Oil (MBbls) 198 160 401
Natural gas (MMcf) 5,461 4,432 4,801
Natural gas equivalent (MMcfe) 6,651 5,390 7,207
Average sales prices
Oil (per Bbl) $ 27.81 $ 24.28 $ 24.94
Natural gas (per Mcf) 3.90 5.04 3.50
Natural gas equivalent (per Mcfe) 4.03 4.87 3.72
Average costs (per Mcfe)
Camp Hill operating expenses $ 3.08 $ 2.14 $ 2.50
Other operating expenses 0.59 0.43 0.44
Total operating expenses(1) 0.74 0.77 0.68
- ----------
(1) Includes direct lifting costs (labor, repairs and maintenance, materials
and supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.
FINDING AND DEVELOPMENT COSTS
From inception through December 31, 2002, the Company has incurred total
gross development, exploration and acquisition costs of approximately $153.5
million. Total exploration, development and acquisition activities from
inception through December 31, 2002 have resulted in the addition of
approximately 82.5 Bcfe, net to the Company's interest, of proved reserves at an
average finding and development cost of $1.86 per Mcfe.
The Company's finding and development costs have historically fluctuated on
a year-to-year basis. Finding and development costs, as measured annually, may
not be indicative of the Company's ability to economically replace oil and
natural gas reserves because the recognition of costs may not necessarily
coincide with the addition of proved reserves.
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES
The following table sets forth certain information regarding the gross
costs incurred in the purchase of proved and unproved properties and in
development and exploration activities.
YEAR ENDED DECEMBER 31,
----------------------------------------
2000 2001 2002
-------- -------- --------
(IN THOUSANDS)
Acquisition costs
Unproved prospects $ 6,641 $ 12,607 $ 6,402
Proved properties 337 800 660
Exploration 7,843 18,356 14,194
Development 1,361 3,065 2,351
-------- -------- --------
Total costs incurred(1) $ 16,182 $ 34,828 $ 23,607
======== ======== ========
- ----------
(1) Excludes capitalized interest on unproved properties of $3.6 million, $3.2
million and $3.1 million for the years ended December 31, 2000, 2001 and
2002, respectively.
11
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
years ended December 31, 2000, 2001 and 2002. In the table, "gross" refers to
the total wells in which the Company has a working interest and "net" refers to
gross wells multiplied by the Company's working interest therein. The Company's
drilling activity from January 1, 1996 to December 31, 2002 has resulted in a
commercial success rate of approximately 66%.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
2000 2001 2002
----------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
------- ------- ------- ------- ------- -------
Exploratory Wells
Productive 19 4.7 18 5.9 16 5.6
Nonproductive 15 3.4 5 1.4 3 1.1
------- ------- ------- ------- ------- -------
Total 34 8.1 23 7.3 19 6.7
======= ======= ======= ======= ======= =======
Development Wells
Productive 5 1.9 2 0.3 1 0.4
Nonproductive -- -- -- -- -- --
------- ------- ------- ------- ------- -------
Total 5 1.9 2 0.3 1 0.4
======= ======= ======= ======= ======= =======
The above table excludes 75 gross (28 net) wells drilled or acquired by
CCBM through 2002. At December 31, 2002, the Company has ownership in 11 gross
(2.7 net) wells with dual completion in single bore holes.
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, 2002.
COMPANY
OPERATED OTHER TOTAL
----------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
------- ------- ------- ------- ------- -------
Oil 49 46 18 6 67 52
Natural gas 36 19 59 15 95 34
------- ------- ------- ------- ------- -------
Total 85 65 77 21 162 86
======= ======= ======= ======= ======= =======
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 2002. 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 1,647 361 1,871 715 3,518 1,076
Texas 48,686 12,994 43,339 16,111 92,025 29,105
Montana/Wyoming 7,345 376 236,938 38,800 244,283 39,176
------- ------- ------- ------- ------- -------
Total 57,678 13,731 282,148 55,626 339,826 69,357
======= ======= ======= ======= ======= =======
The table does not include 4,441 and 723 gross acres (4,441 and 723 net)
that the Company had a right to acquire in Texas and Louisiana, respectively,
pursuant to various seismic option agreements at December 31, 2002. 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
producing wells have not been drilled on the acreage within a period of three
years. Further, the table does not include 43,711 gross and 15,991 net acres in
Wyoming that the Company has the right to earn pursuant to certain
12
drilling obligations and other predetermined terms.
MARKETING
The Company's production is marketed to third parties consistent with
industry practices. Typically, oil is sold at the wellhead at field-posted
prices plus a bonus and natural gas is sold under contract at a negotiated price
based upon factors normally considered in the industry, such as distance from
the well to the pipeline, well pressure, estimated reserves, quality of natural
gas and prevailing supply/demand conditions.
The Company's marketing objective is to receive the highest possible
wellhead price for its product. The Company is aided by the presence of multiple
outlets near its production in the Texas and Louisiana Gulf Coast. The Company
takes an active role in determining the available pipeline alternatives for each
property based upon historical pricing, capacity, pressure, market
relationships, seasonal variances and long-term viability.
There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and natural
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. The Company has not experienced any
difficulties in marketing its oil and natural gas. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual customers. The
availability of a ready market for the Company's oil and natural gas production
depends on the proximity of reserves to, and the capacity of, oil and natural
gas gathering systems, pipelines and trucking or terminal facilities. The
Company delivers natural gas through gas gathering systems and gas pipelines
that it does not own. Federal and state regulation of natural gas and oil
production and transportation, tax and energy policies, changes in supply and
demand and general economic conditions all could adversely affect the Company's
ability to produce and market its oil and natural gas.
The Company from time to time markets its own production where feasible
with a combination of market-sensitive pricing and forward-fixed pricing.
Forward pricing is utilized to take advantage of anomalies in the futures market
and to hedge a portion of the Company's production deliverability at prices
exceeding forecast. All of such hedging transactions provide for financial
rather than physical settlement. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations-General Overview".
Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas sold in the
spot market due primarily to seasonality of demand and other factors beyond the
Company's control. Domestic oil prices generally follow worldwide oil prices,
which are subject to price fluctuations resulting from changes in world supply
and demand. The Company continues to evaluate the potential for reducing these
risks by entering into, and expects to enter into, additional hedge transactions
in future years. In addition, the Company may also close out any portion of
hedges that may exist from time to time as determined to be appropriate by
management.
The Company typically uses fixed rate swaps and costless collars to hedge
its exposure to material changes in the price of natural gas and oil. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated cash flow hedges to forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.
The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.
In November 2001, the Company had costless collars with an affiliate of
Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts no longer qualified for hedge
accounting treatment. As required by SFAS No. 133, the value of these derivative
instruments as of November 2001 $(0.8 million)
13
was recorded in accumulated other comprehensive income and will be reclassified
into earnings over the original term of the derivative instruments. An allowance
for the related asset was charged to other expense. At December 31, 2001 and
2002, $0.7 million and none, respectively, remained in accumulated other
comprehensive income.
Total oil purchased and sold under hedging arrangements during 2000, 2001
and 2002 were 87,900 Bbls, 18,000 Bbls and 131,300 Bbls, respectively. Total
natural gas purchased and sold under hedging arrangements in 2000, 2001 and 2002
were 1,590,000 MMBtu, 3,087,000 MMBtu and 2,314,000 MMBtu, respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$(1.5 million) and $2.0 million and $(0.9 million) for 2000, 2001 and 2002,
respectively.
At December 31, 2001 the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2002 the Company had the
following outstanding hedge positions:
December 31, 2002
- ----------------------------------------------------------------------------------------------------------------
Contract Volumes
------------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
------- ---- ----- ----------- ----------- -------------
First Quarter 2003 27,000 $ 24.85
First Quarter 2003 36,000 $23.50 $26.50
First Quarter 2003 540,000 3.40 5.25
Second Quarter 2003 27,300 24.85
Second Quarter 2003 36,000 23.50 26.50
Second Quarter 2003 546,000 3.40 5.25
Third Quarter 2003 552,000 3.40 5.25
Fourth Quarter 2003 552,000 3.40 5.25
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 natural 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 natural 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.
14
REGULATION
The availability of a ready market for oil and natural 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, and the effects of
regulation on the amount of oil and natural gas available for sale, the
availability of adequate pipeline and other regulated transportation and
processing facilities and the marketing of competitive fuels. For example, a
productive natural gas well may be "shut-in" because of an oversupply of natural
gas or lack of an available natural gas pipeline in the areas in which the
Company may conduct operations. State and federal regulations generally are
intended to prevent waste of oil and natural gas, protect rights to produce oil
and natural gas between owners in a common reservoir, control the amount of oil
and natural gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines are subject to the jurisdiction of
various federal, state and local agencies. The Company is also subject to
changing and extensive tax laws, the effects of which cannot be predicted. The
following discussion summarizes the regulation of the United States oil and gas
industry. The Company believes that it is in substantial compliance with the
various statutes, rules, regulations and governmental orders to which the
Company's operations may be subject, although there can be no assurance that
this is or will remain the case. Moreover, such statutes, rules, regulations and
government orders may be changed or reinterpreted from time to time in response
to economic or political conditions, and there can be no assurance that such
changes or reinterpretations will not materially adversely affect the Company's
results of operations and financial condition. The following discussion is not
intended to constitute a complete discussion of the various statutes, rules,
regulations and governmental orders to which the Company's operations may be
subject.
Regulation of Oil and Natural Gas Exploration and Production. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells that may
be drilled in and the unitization or pooling of oil and natural 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 natural 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 and transportation was substantially modified by
the Natural Gas Policy Act of 1978 (the "NGPA"), under which the FERC continued
to regulate the maximum selling prices of certain categories of natural 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 that may be in effect. The FERC's
jurisdiction over interstate 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. Following the passage by Congress of the NGPA,
the FERC adopted a series of regulatory changes that have significantly altered
the transportation and marketing of natural gas. Beginning with the adoption of
"open access" regulation in Order No. 436, issued in October 1985, these changes
were intended by the FERC to foster competition by, among other things,
transforming the role of interstate pipeline companies from wholesale marketers
of gas to the primary role of gas transporters. Through similar orders affecting
intrastate pipelines that provide similar interstate services, the FERC expanded
the impact of these open access regulations to intrastate commerce.
In April 1992, the FERC issued Order No. 636 and a series of related
orders, which among other things required interstate pipelines to "unbundle"
their gas merchant services from their transportation services, thereby further
enhancing their obligation to
15
provide open-access transportation on a not unduly discriminatory basis for all
natural gas shippers. All gas marketing by the pipelines was required to be
provided upstream at the wellhead, and, as a result, most pipelines divested
their merchant functions to a marketing affiliate, which operates separately
from the transporter and can participate in downstream sales markets on a
bundled basis, in direct competition with other gas merchants. Order No. 636
also established a mechanism that allows shippers to "release" their firm
capacity to other shippers, either temporarily or permanently, when it is not
needed by those shippers. Although Order No. 636 does not directly regulate the
Company's production and marketing activities, it does affect how buyers and
sellers gain access to the necessary transportation facilities and how natural
gas is sold in the marketplace.
In February 2000, the FERC issued Order No. 637 which:
o lifted the cost-based cap on pipeline transportation rates in the
capacity release market on an experimental basis until September
30, 2002, for short-term releases of pipeline capacity of less
than one year (the FERC did not renew this program),
o permits pipelines to file for authority to charge different
maximum cost-based rates for peak and off-peak periods,
o encourages, but does not mandate, auctions for pipeline capacity,
o requires pipelines to implement imbalance management services,
o restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow
orders, and
o expands the opportunities for shippers to "segment" their
capacity into multiple parts, and implements a number of new
pipeline reporting requirements.
Order No. 637 also requires the FERC's Staff to analyze whether the FERC
should implement additional fundamental policy changes. These include whether to
pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid. Order No. 637 was largely
affirmed by the courts, and most pipelines' tariff filings to implement the
requirements of Order No. 637 have been accepted by the FERC and placed into
effect. Finally, in July 2002, the FERC commenced an inquiry into whether it
should make changes to its policy of allowing pipelines in certain circumstances
to charge "negotiated rates" for their services including negotiated rates tied
to various natural gas commodity market indices.
As a result of these changes, sellers and buyers of natural gas have gained
direct access to the particular pipeline services they need and are better able
to conduct business with a larger number of counterparties. The Company believes
these changes generally have improved the Company's access to markets while, at
the same time, substantially increasing competition in the natural gas
marketplace. It remains to be seen, however, what effect the FERC's other
activities will have on access to markets, the fostering of competition and the
cost of doing business. 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 natural gas
regulation. However, as discussed above, the more recent trend has been in favor
of deregulation or "lighter handed" regulation and the promotion of competition
in the gas industry. There regularly 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 oil, condensate and
natural gas liquids by the Company are not currently
16
regulated and are made at market prices. The price the Company receives from the
sale of these products may be affected by the cost of transporting the products
to market. Much of that transportation is through interstate common carrier
pipelines. Effective as of January 1, 1995, the FERC implemented regulations
generally grandfathering all previously approved interstate transportation rates
and establishing an indexing system for those rates by which adjustments are
made annually based on the rate of inflation, subject to certain conditions and
limitations. These regulations may tend to increase the cost of transporting oil
and natural gas liquids by interstate pipeline, although the annual adjustments
may result in decreased rates in a given year. These regulations have generally
been approved on judicial review. Every five years, the FERC must examine the
relationship between the annual change in the applicable index and the actual
cost changes experienced in the oil pipeline industry. The first such review was
completed in 2000 and on December 14, 2000, the FERC reaffirmed the current
index. Following a successful court challenge of these orders by an association
of oil pipelines, on February 24, 2003 the FERC acting on remand increased the
index slightly for the current five year period, effective July 2001. The
Company is not able at this time to predict the effects of these regulations, if
any, on the transportation costs associated with oil production from the
Company's oil producing operations.
Environmental Regulations. The Company's operations are subject to numerous
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentration of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit drilling activities on
certain lands within wilderness, wetlands and other protected areas, require
remedial measures to mitigate pollution from former operations, such as pit
closure and plugging abandoned wells, and impose substantial liabilities for
pollution resulting from production and drilling operations. Public interest in
the protection of the environment has increased dramatically in recent years.
The trend of more expansive and stricter environmental legislation and
regulations applied to the oil and natural gas industry could continue,
resulting in increased costs of doing business and consequently affecting
profitability. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes more stringent and costly waste
handling, disposal and cleanup requirements, the business and prospects of the
Company could be adversely affected.
The Company generates wastes that may be subject to the federal Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S.
Environmental Protection Agency ("EPA") and various state agencies have limited
the approved methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, certain wastes generated by the Company's oil and natural gas
operations that are currently exempt from treatment as "hazardous wastes" may in
the future be designated as "hazardous wastes," and therefore be subject to more
rigorous and costly operating and disposal requirements.
The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Although
the Company believes that it has used good operating and waste disposal
practices, prior owners and operators of these properties may not have used
similar practices, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by the Company or on or
under locations where such wastes have been taken for disposal. In addition,
many of these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the Company's
control. These properties and the wastes disposed thereon may be subject to the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
RCRA and analogous state laws as well as state laws governing the management of
oil and natural gas wastes. Under such laws, the Company could be required to
remove or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
CERCLA, also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that have resulted 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 developed and continue to
develop 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
17
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 has
developed and implemented these plans. The Oil Pollution Act of 1990, ("OPA")
contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States. The OPA subjects owners of facilities
to strict joint and several liability for all containment and cleanup costs and
certain other damages arising from a spill, including, but not limited to, the
costs of responding to a release of oil to surface waters. The OPA also requires
owners and operators of offshore facilities that could be the source of an oil
spill into federal or state waters, including wetlands, to post a bond, letter
of credit or other form of financial assurance in amounts ranging from $10
million in specified state waters to $35 million in federal outer continental
shelf waters to cover costs that could be incurred by governmental authorities
in responding to an oil spill. Such financial assurances may be increased by as
much as $150 million if a formal risk assessment indicates that the increase is
warranted. Noncompliance with OPA may result in varying civil and criminal
penalties and liabilities. Operations of the Company are also subject to the
federal Clean Water Act ("CWA") and analogous state laws. In accordance with the
CWA, the state of Louisiana has issued regulations prohibiting discharges of
produced water in state coastal waters effective July 1, 1997. Pursuant to other
requirements of the CWA, the EPA has adopted regulations concerning discharges
of storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under an EPA
general permit. While certain of its properties may require permits for
discharges of storm water runoff, the Company believes that it will be able to
obtain, or be included under, such permits, where necessary, and make minor
modifications to existing facilities and operations that would not have a
material effect on the Company. Like OPA, the CWA and analogous state laws
relating to the control of water pollution provide varying civil and criminal
penalties and liabilities for releases of petroleum or its derivatives into
surface waters or into the ground.
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.
As further described in "Wyoming/Montana Coalbed Methane Project Area", the
issuance of new coalbed methane drilling permits in Montana has been temporarily
halted pending a final Record of Decision by the Federal Bureau of Land
Management.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating hazards
and risks such as well blowouts, craterings, pipe failures, casing collapse,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
formations with abnormal pressures, pipeline ruptures or spills, pollution,
releases of toxic gas and other environmental hazards and risks. These hazards
and risks could result in substantial losses to the Company from, among other
things, injury or loss of life, severe damage to or destruction of property,
natural resources and equipment, pollution or other environmental damage,
cleanup responsibilities, regulatory investigation and penalties and suspension
of operations. In addition, the Company may be liable for environmental damages
caused by previous owners of property purchased and leased by the Company. As a
result, substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce or eliminate the funds available for
exploration, development or acquisitions or result in the loss of the Company's
properties. In accordance with customary industry practices, the Company
maintains insurance against some, but not all, of such risks and losses. The
Company does not carry business interruption insurance or protect against loss
of revenues. There can be no assurance that any insurance obtained by the
Company will be adequate to cover any losses or liabilities. The Company cannot
predict the continued availability of insurance or the availability of insurance
at premium levels that justify its purchase. The occurrence of a significant
event not fully insured or indemnified against could materially and adversely
affect the Company's financial condition and operations. The Company may elect
to self-insure if management believes that the cost of insurance, although
available, is excessive relative to the risks presented. In addition, pollution
and environmental risks generally are not fully insurable. The occurrence of an
event not fully covered by insurance could have a material adverse effect on the
financial condition and results of operations of the Company. The Company
participates in a substantial percentage of its wells on a nonoperated basis,
which may limit the Company's ability to control the risks associated with oil
and natural gas operations.
TITLE TO PROPERTIES; ACQUISITION RISKS
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties. As is customary in the industry
in the case of undeveloped properties, little investigation of record title is
made at the time of acquisition (other than a preliminary review of local
records). Investigations, including a title opinion of local
18
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, 2002, the Company had 36 full-time employees, including six
geoscientists and six 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 oil or other liquid hydrocarbons.
Bbls/d. Stock tank barrels per day.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of 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 natural gas or, in the case of a dry hole, the
19
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 natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Farm-in or farm-out. An agreement where under the owner of a working
interest in an oil and natural gas lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out".
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Finding costs. Costs associated with acquiring and developing proved oil
and natural gas reserves which are capitalized by the Company pursuant to
generally accepted accounting principles, including all costs involved in
acquiring acreage, geological and geophysical work and the cost of drilling and
completing wells.
Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of oil or other liquid hydrocarbons per day.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. One thousand cubic feet of natural gas per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbls. One million barrels of 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 oil, condensate or natural gas liquids, which
approximates the relative energy content of oil, condensate and natural gas
liquids as compared to natural gas. Prices have historically often been higher
or substantially higher for oil than natural gas on an energy equivalent basis,
although there have been periods in which they have been lower or substantially
lower.
Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells.
Net Revenue Interest. The operating interest used to determine the owner's
share of total production.
Normally pressured reservoirs. Reservoirs with a formation-fluid pressure
equivalent to 0.465 psi per foot of depth from the
20
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 Securities
and Exchange Commission guidelines, net of estimated production and future
development costs, using prices and costs as of the date of estimation without
future escalation, without giving effect to non-property related expenses such
as general and administrative expenses, debt service, future income tax expense
and depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
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 natural gas production free of costs of
production.
3-D seismic data. Three-dimensional pictures of the subsurface created by
collecting and measuring the intensity and timing of sound waves transmitted
into the earth as they reflect back to the surface.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
21
Workover. Operations on a producing well to restore or increase production.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. The Company, along
with GMT and other partners, reached a final settlement with ExxonMobil on
February 11, 2003. Under the terms of the settlement, the Company recovered the
balance its drilling costs (approximately $0.1 million) and certain other costs
and retained no further interest in the property. No reserves with respect to
these properties were included in the Company's reported proved reserves as of
December 31, 2001 and 2002.
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 46 President and Chief Executive Officer
Frank A. Wojtek 47 Chief Financial Officer, Vice
President, Secretary and Treasurer
Jeremy T. Greene 42 Vice President of Exploration
Development
Kendall A. Trahan 52 Vice President of Land
J. Bradley Fisher 42 Vice President of Operations
Set forth below is a description of the backgrounds of each of the
executive officers of the Company:
S.P. Johnson IV has served as the President, Chief Executive Officer and a
director of the Company since December 1993. Prior to that, he worked 15 years
for Shell Oil Company. His managerial positions included Operations
Superintendent, Manager of Planning and Finance and Manager of Development
Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in
Mechanical Engineering from the University of Colorado.
Frank A. Wojtek has served as the Chief Financial Officer ("CFO"), 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 has also been Vice President and Secretary /Treasurer for
Loyd and Associates, Inc. (a private financial consulting and investment banking
firm) since 1989. Mr. Wojtek held the positions of Vice President and CFO of
Griffin-Alexander Drilling Company from 1984 to 1987, Treasurer of
Chiles-Alexander International Inc. from 1987 to 1989 and Vice President and CFO
of India Offshore Inc. from 1989 to
22
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.
Jeremy T. Greene was elected Vice President of Exploration in August 2002.
From September 2000 to August 2002 he was the Deepwater Gulf of Mexico Division
Specialist for EOG Resources, Inc. He spent the previous 17 years with Vastar
Resources, Inc., ARCO, and ARCO International where he held various technical
and managerial positions, including Director of Joint Ventures Onshore Gulf
Coast, Director of Geophysical Interpretation Research, and Eastern Deepwater
Exploration Manager, including the position of Eastern Area Deepwater
Exploration Manager for Vastar Resources, Inc. from August 1997 to September
2000. Mr. Greene received his B.S. in Geophysical Engineering from the Colorado
School of Mines, and his M.S. in Geophysics from the University of Texas at
Austin.
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 holds a B.S. degree from the University of Southwestern Louisiana.
J. Bradley Fisher has served as Vice President of Operations since July
2000 and General Manager of Operations from April 1998 to June 2000. Prior to
joining the Company, Mr. Fisher was the Vice President of Engineering and
Operations for Tri-Union Development Corp. from August 1997 to April 1998. He
spent the prior 14 years with Cody Energy and its predecessor Ultramar Oil & Gas
Limited where he held various managerial and technical positions, last serving
as Senior Vice President of Engineering and Operations. Mr. Fisher hold a B.S.
degree in Petroleum Engineering from Texas A&M University.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS
The Company's common stock, par value $0.01 per share (the "Common Stock"),
has been publicly traded through the Nasdaq National Market tier of The Nasdaq
Stock Market under the symbol CRZO since the Company's initial public offering
(the "Offering") effective August 6, 1997. The following table sets forth the
quarterly high and low bid prices for each indicated quarter.
QUARTER ENDED HIGH LOW
- ----------------------------- ------ -----
March 31, 2001 10.125 5.688
June 30, 2001 7.380 4.900
September 30, 2001 6.240 4.200
December 31, 2001 5.450 3.600
March 31, 2002 6.000 4.100
June 30, 2002 5.750 4.260
September 30, 2002 4.700 3.600
December 31, 2002 5.730 3.900
There were approximately 48 shareholders of record (excluding brokerage
firms and other nominees) of the Company's Common Stock as of March 19, 2003.
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 credit agreement with Hibernia National Bank and the
terms of its 9% Senior Subordinated Notes, restrict the Company's ability to pay
dividends. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources".
ITEM 6. SELECTED FINANCIAL DATA
The financial information of the Company set forth below for each of the
five years ended December 31, 2002, has been derived from the audited
consolidated financial statements of the Company. The information should be read
in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Company's consolidated financial statements
and related notes included in Item 8. Financial Statements and Supplementary
Data.
23
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------
1998 1999 2000 2001 2002
------------ ------------ ------------ ------------ ------------
Statement Of Operations Data:
Oil and natural gas revenues $ 7,859 $ 10,204 $ 26,834 $ 26,226 $ 26,802
Costs and expenses:
Oil and natural gas operating expenses 2,770 3,036 4,941 4,138 4,908
Depreciation, depletion and
amortization 3,952 4,301 7,170 6,492 10,575
Write-down of oil and gas properties 20,305 -- -- -- --
General and administrative 2,667 2,195 3,143 3,333 4,133
Stock option compensation expense -- -- 652 (558) (85)
------------ ------------ ------------ ------------ ------------
Total costs and expenses 29,694 9,532 15,906 13,405 19,531
------------ ------------ ------------ ------------ ------------
Operating income (loss) (21,835) 672 10,928 12,821 7,271
Interest expense (net of amounts capitalized and
interest income) 285 13 579 269 54
Other income and expenses -- -- 1,482 1,777 274
------------ ------------ ------------ ------------ ------------
Income (loss) before income taxes (21,550) 685 12,989 14,867 7,599
Income tax expense (benefit) (2,218) (1,057) 1,004 5,336 2,809
------------ ------------ ------------ ------------ ------------
Net income (loss) before cumulative effect of change
in accounting principle (19,332) 1,742 11,985 9,531 4,790
Cumulative effect of change in accounting principle -- (78) -- -- --
------------ ------------ ------------ ------------ ------------
Net income (loss)(1) $ (19,332) $ 1,664 $ 11,985 $ 9,531 $ 4,790
============ ============ ============ ============ ============
Basic earnings (loss) per share(1) $ (2.15) $ 2.00 $ 0.85 $ 0.68 $ 0.30
============ ============ ============ ============ ============
Diluted earnings (loss) per share(1) $ (2.15) $ 2.00 $ 0.74 $ 0.57 $ 0.26
============ ============ ============ ============ ============
Basic weighted average shares outstanding 10,375 10,544 14,028 14,059 14,158
Diluted weighted average shares
outstanding 10,375 10,546 16,256 16,731 16,148
Statements of Cash Flow Data:
Net cash provided by operating activities $ 2,387 $ 2,200 $ 17,133 $ 23,951 $ 19,925
Net cash used in investing activities (37,178) (14,179) (16,438) (31,224) (24,100)
Net cash provided by (used in) financing activities 32,916 21,457 (3,823) 2,292 5,682
Other Operating Data:
EBITDA, as defined (2) $ 2,422 $ 4,895 $ 19,580 $ 21,091 $ 18,120
Capital expenditures 36,570 10,286 19,746 38,264 26,707
Debt repayments(3) 7,950 8,174 3,923 5,479 8,745
AS OF DECEMBER 31,
----------------------------------------------------------------------------
1998 1999 2000 2001 2002
------------ ------------ ------------ ------------ ------------
Balance Sheet Data:
Working capital $ (5,204) $ 8,338 $ 6,433 $ (582) $ (1,442)
Property and equipment, net 57,878 64,337 72,129 104,132 120,526
Total assets 64,988 83,666 93,000 117,392 135,388
Long-term debt, including current
maturities 12,056 37,170 34,556 38,188 39,495
Mandatorily redeemable preferred stock 30,731 -- -- -- --
Convertible participating preferred stock -- -- -- -- 6,373
Equity 11,202 40,853 52,939 63,204 66,816
24
- ----------
(1) Net income for the year ended December 31, 1999 excludes, and earnings per
share for the year ended December 31, 1999 includes, the discount on the
redemption of the Company's Preferred Stock in the amount of $21.9 million.
(2) Management of the Company believes that EBITDA, as defined, may provide
additional information about the Company's ability to meet its future
requirements for debt service, capital expenditures and working capital.
EBITDA, as defined, is a financial measure commonly used in the oil and
natural 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, as defined,
excludes some, but not all, items that affect net income, the EBITDA
presented above may not be comparable to similarly titled measures of other
companies. The following is a reconciliation of EBITDA, as defined, to net
income:
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------
1998 1999 2000 2001 2002
------------ ------------ ------------ ------------ ------------
(IN THOUSANDS)
Net Income $ (19,332) $ 1,664 $ 11,985 $ 9,532 $ 4,790
Adjustments:
Depreciation, depletion and amortization 3,952 4,301 7,170 6,492 10,575
Interest expense, net of amounts
capitalized and interest income (285) (13) (579) (269) (54)
Income taxes (benefit) (2,218) (1,057) 1,004 5,336 2,809
Write-down of oil and gas properties 20,305 -- -- -- --
------------ ------------ ------------ ------------ ------------
EBITDA, as defined $ 2,422 $ 4,895 $ 19,580 $ 21,091 $ 18,120
============ ============ ============ ============ ============
(3) 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, the timing and risk involved in drilling follow-up
wells, expected working or net revenue interests, planned expenditures,
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), planned evaluation of prospects, probability of prospects
having oil and natural gas, expected production or reserves, increases in
reserves, acreage, working capital requirements, hedging activities, the ability
of expected sources of liquidity to implement its business strategy, future
hiring, future exploration activity, production rates, potential drilling
locations targeting coal seams, the outcome of a final Record of Decision by the
Federal Bureau of Land Management relating to new coalbed methane drilling
permits in Montana and related legal challenges, timing of new coalbed methane
development in Montana, all and any other statements regarding future
operations, financial results, business plans and cash needs and other
statements that are not historical facts are forward looking statements. When
used in this document, the words "anticipate", "budgeted", "targeted",
"potential", "estimate", "expect", "may", "project", "believe" and similar
expressions are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties, including,
but not limited to, those relating to the Company's dependence on its
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil and
natural gas operations, the Company's dependence on its key personnel, factors
that affect the Company's ability to manage its growth and achieve its business
strategy, risks relating to its limited operating history, technological
changes, significant capital requirements of the Company, the potential impact
of government regulations, adverse regulatory determinations, including those
related to coalbed methane drilling in Montana, litigation, competition, the
uncertainty of reserve information and future net revenue estimates, property
acquisition risks, industry partner issues, availability of equipment, weather
and other factors detailed herein and in the Company's other filings with the
Securities and Exchange Commission. Should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect,
actual outcomes may vary materially from those indicated.
25
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 39, 25 and 20 gross wells in the
Gulf Coast region in 2000, 2001 and 2002 respectively. The Company has budgeted
to drill 27 gross wells (10.7 net) in 2003 in the Gulf Coast region; however,
the actual number of wells drilled will vary depending upon various factors,
including the availability and cost of drilling rigs, land and industry partner
issues, Company cash flow, success of drilling programs, weather delays and
other factors. If the Company drills the number of wells it has budgeted for
2003, depreciation, depletion and amortization are expected to increase and oil
and gas operating expenses are expected to increase over levels incurred in
2002. The Company has typically retained the majority of its interests in
shallow, normally pressured prospects and sold a portion of its interests in
deeper, over-pressured prospects.
The Company has primarily grown through the internal development of
properties within its exploration project areas, although the Company acquired
properties with existing production in the Camp Hill Project in late 1993, the
Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company
made these acquisitions through the use of limited partnerships with Carrizo or
Carrizo Production, Inc. as the general partner. In addition, in November 1998
the Company acquired assets in Wharton County, Texas in the Jones Branch project
area for approximately $3.0 million.
During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM")
as a wholly-owned subsidiary. CCBM was formed to acquire interests in certain
oil and gas leases in Wyoming and Montana in areas prospective for coalbed
methane and develop such interests. The Company also acquired a 1,940 gross acre
coalbed methane property in Wyoming, the "Bobcat Project", for $0.7 million in
cash and common stock in July 2002. CCBM plans to spend up to $5.0 million for
drilling costs on these leases through December 2003, 50% of which would be
spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf
of RMG, from whom the interests in the leases were acquired. Through December
31, 2002, CCBM has satisfied $1.5 million of its drilling obligations on behalf
of RMG. CCBM has drilled or acquired 75 gross wells (28 net) and incurred
total drilling costs of $3.0 million through December 31, 2002. These wells
typically take up to 18 months to evaluate and determine whether or not they are
successful. CCBM has budgeted to drill up to 50 gross (18 net) wells in 2003.
The coalbed methane wells include 17 wells acquired as a result of the Bobcat
acquisition.
The Company uses the full-cost method of accounting for its oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including any general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit-of-production method. To
the extent that such capitalized costs in the full-cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed the
present value (using a 10 discount rate) of estimated future net after-tax cash
flows from proved oil and gas reserves, such excess costs are charged to
operations. Based on oil and gas prices in effect on December 31, 2001, the
unamortized cost of oil and gas properties exceeded the cost center ceiling. As
permitted by full cost accounting rules, improvements in pricing subsequent to
December 31, 2001 removed the necessity to record a write-down. Using prices in
effect on December 31, 2001 the write-down would have been approximately $0.7
million. Because of the volatility of oil and gas prices, no assurance can be
given that the Company will not experience a write-down in future periods. Once
incurred, a write-down of oil and gas properties is not reversible at a later
date.
RESULTS OF OPERATIONS
Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001
Oil and natural gas revenues for 2002 increased 2% to $26.8 million from
$26.2 million in 2001. Production volumes for natural gas in 2002 increased 8%
to 4,801 MMcf from 4,432 MMcf in 2001. Realized average natural gas prices
decreased 31% to $3.50 per Mcf in 2002 from $5.04 per Mcf in 2001. Production
volumes for oil in 2002 increased 151% to 401 MBbls from 160 MBbls in 2001. The
increase in oil production was due primarily to the commencement of production
at the Delta Farms #1, Riverdale #2, Staubach #1 and Burkhart #1R wells offset
by the natural decline in production of other older wells. The increase in
natural gas production was due primarily to the commencement of production at
the Delta Farms #1, Riverdale #2, Staubach #1, Burkhart #1R and Pauline Huebner
A-382 #1 wells offset by the natural decline in production at other wells,
primarily from the initial Matagorda County Project wells. Oil and natural gas
revenues include the impact of hedging activities as discussed below under
"Volatility of Oil and Gas Prices".
Average oil prices increased 3% to $24.94 per bbl in 2002 from $24.28 per
bbl in 2001.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 2001 and 2002:
26
2002 PERIOD
DECEMBER 31, COMPARED TO 2001 PERIOD
-------------------------- INCREASE % INCREASE
2001 2002 (DECREASE) (DECREASE)
------------ ------------ ------------ ------------
Production volumes-
Oil and condensate (Mbbls) 160 401 241 151%
Natural gas (MMcf) 4,432 4,801 369 8%
Average sales prices-(1)
Oil and condensate (per Bbl) $ 24.28 $ 24.94 $ 0.66 3%
Natural gas (per Mcf) 5.04 3.50 (1.54) (31%)
Operating revenues (In thousands) -
Oil and condensate $ 3,877 $ 10,001 $ 6,124 158%
Natural gas 22,349 16,801 (5,548) (25%)
------------ ------------ ------------
Total $ 26,226 $ 26,802 $ 576 2%
============ ============ ============
- ----------
(1) Including the impact of hedging.
Oil and natural gas operating expenses for 2002 increased 19% to $4.9
million from $4.1 million in 2001. Oil and natural gas operating expenses
increased primarily as a result of the addition of new oil and gas wells drilled
and completed since December 31, 2001 and higher ad valorem taxes. Operating
expenses per equivalent unit in 2002 decreased to $0.68 per Mcfe from $0.77 per
Mcfe in 2001. The per unit cost decreased primarily as a result of the addition
of higher production rate, lower cost per unit wells offset by an increase in ad
valorem taxes and decreased production of natural gas as wells naturally
decline.
Depreciation, depletion and amortization ("DD&A") expense for 2002
increased 63% to $10.6 million from $6.5 million in 2001. This increase was
primarily due to increased production and the additional seismic and drilling
costs added to the proved property cost base.
General and administrative ("G&A") expense for 2002 increased 24% to $4.1
million from $3.3 million for 2001. The increase in G&A was due primarily to the
addition of contract staff to handle increased drilling and production
activities and higher insurance costs.
Interest income for 2002 decreased to $0.1 million from $0.3 million in
2001 primarily as a result of lower interest rates during 2002. Capitalized
interest decreased to $3.1 million in 2002 from $3.2 million in 2001 primarily
due to lower interest costs during 2002.
Income taxes decreased to $2.8 million in 2002 from $5.3 million in 2001.
Dividends and accretion of discount on preferred stock increased to $0.6
million in 2002 from none in 2001 as a result of the sale of preferred stock in
the first quarter of 2002.
Net income for 2002 decreased to $4.8 million from $9.5 million in 2001
primarily as a result of the factors described above.
Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000
Oil and natural gas revenues for 2001 decreased 2% to $26.2 million from
$26.8 million in 2000. Production volumes for natural gas in 2001 decreased 19%
to 4,432 MMcf from 5,461 MMcf in 2000. Realized average natural gas prices
increased 29% to $5.04 per Mcf in 2001 from $3.90 per Mcf in 2000. Production
volumes for oil in 2001 decreased 20% to 160 MBbls from 199 MBbls in 2000. The
decrease in oil production was due to the natural decline in production
primarily at the Jones Branch wells and the initial Matagorda Project wells
offset by the commencement of production of the Pitchfork Ranch well. The
decrease in natural gas production was due primarily to the sale of the Metro
Project during 2000 and the natural decline in production primarily at the
initial Matagorda Project wells offset by the commencement of production at the
additional Cedar Point Project wells, the West Bay Project well and the
Pitchfork Ranch well. Oil and natural gas revenues include the cash effect of
hedging activities as discussed below under
27
"Volatility of Oil and Natural Gas Prices".
Average oil prices decreased 13% to $24.28 per bbl in 2001 from $27.81 per
bbl in 2000.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 2000 and 2001:
2001 PERIOD
DECEMBER 31, COMPARED TO 2000 PERIOD
--------------------------- INCREASE % INCREASE
2000 2001 (DECREASE) (DECREASE)
------------ ------------ ------------ ------------
Production volumes-
Oil and condensate (Mbbls) 199 160 (39) (20%)
Natural gas (MMcf) 5,461 4,432 (1,029) (19%)
Average sales prices-(1)
Oil and condensate (per Bbl) $ 27.81 $ 24.28 $ (3.53) (13%)
Natural gas (per Mcf) 3.90 5.04 1.14 29%
Operating revenues (In thousands) -
Oil and condensate $ 5,519 $ 3,877 $ (1,642) (30%)
Natural gas 21,315 22,349 1,034 5%
------------ ------------ ------------
Total $ 26,834 $ 26,226 $ (608) (2%)
============ ============ ============
- ----------
(1) Including the impact of hedging.
Oil and natural gas operating expenses for 2001 decreased 16% to $4.1
million from $4.9 million in 2000. Oil and natural gas operating expenses
decreased primarily as a result of the lower production taxes and the
implementation of cost reduction measures in fields with decreased production.
Operating expenses per equivalent unit in 2001 increased to $0.77 per Mcfe from
$0.74 per Mcfe in 2000. The per unit cost increased primarily as a result of an
increase in severance taxes and decreased production of natural gas as wells
naturally decline.
Depreciation, depletion and amortization ("DD&A") expense for 2001
decreased 9% to $6.5 million from $7.2 million in 2000. This decrease was
primarily due to the seismic and drilling costs added to the proved property
cost base.
General and administrative ("G&A") expense for 2001 increased 6% to $3.3
million from $3.1 million for 2000. The increase in G&A was due primarily to the
addition of staff to handle increased drilling and production activities. Stock
option compensation expense is a non-cash charge resulting from a decrease
during 2001 and an increase during the last six months of 2000 in the stock
price underlying the stock options that were repriced in February 2000.
Interest expense, net of amounts capitalized, for 2001 decreased 47% to
$7,000 from $13,003 in 2000.
Income taxes increased to $5.3 million in 2001 from $1.0 million in 2000.
The increase was the result of an adjusted valuation allowance during 2000 on
net operating loss carryforwards expected to be realized that resulted in a
deferred income tax benefit adjustment of $3.6 million which reduced the
Company's effective tax rate to 8% in 2000.
Other income for the year ended December 31, 2001 included a gain on the
sale of an investment in Michael Petroleum Corporation ("MPC") of $3.9 million
offset by (1) a charge and related legal expenses of $1.4 million in respect of
the final settlement of litigation with BNP Petroleum Corporation and (2) a
non-cash valuation allowance of $0.8 million relating to certain hedge
arrangements with Enron North America Corp.
Net income for 2001 decreased to $9.5 million from $12.0 million in 2000 as
a result of the factors described above.
28
LIQUIDITY AND CAPITAL RESOURCES
The Company has made and is expected to make oil and gas capital
expenditures in excess of its net cash flows provided by operating activities in
order to complete the exploration and development of its existing properties.
The Company will require additional sources of financing to fund drilling
expenditures on properties currently owned by the Company and to fund leasehold
costs and geological and geophysical cost on its exploration projects.
While the Company believes that current cash balances and anticipated 2003
cash provided by operating activities will provide sufficient capital to carry
out the Company's 2003 exploration plans, management of the Company continues to
seek financing for its capital program from a variety of sources. No assurance
can be given that the Company will be able to obtain additional financing on
terms that would be acceptable to the Company. The Company's inability to obtain
additional financing could have a material adverse effect on the Company.
Without raising additional capital, the Company anticipates that it may be
required to limit or defer its planned oil and natural gas exploration and
development program, which could adversely affect the recoverability and
ultimate value of the Company's oil and natural gas properties.
The Company's primary sources of liquidity have included proceeds from the
1997 initial public offering, the December 1999 sale of Subordinated Notes,
Common Stock and Warrants, the 1998 sale of shares of Series A Preferred Stock
and Warrants, the February 2002 sale of Series B Preferred Stock and Warrants,
funds generated by operations, equity capital contributions, borrowings
(primarily under revolving credit facilities) and funding under the Palace
Agreement that provided a portion of the funding for the Company's 2000, 2001
and 2002 drilling program in return for participation in certain wells.
Cash flows provided by operating activities were $17.1 million, $24.0
million and $19.9 million for 2000, 2001 and 2002, respectively. The increase in
cash flows provided by operating activities in 2001 as compared to 2000 was due
primarily to the increase in trade accounts payable and the one-time gain on the
sale of an investment in MPC. The decrease in cash flows provided by operating
activities in 2002 as compared to 2001 was due primarily to the one-time gains
on the sale of an investment in MPC in 2001.
The Company budgeted capital expenditures in 2003 of approximately $27.2
million of which $20.3 million of which is expected to be used for drilling
activities in the Company's project areas and the balance is expected to be used
to fund 3-D seismic surveys, land acquisitions and capitalized interest and
overhead costs. The Company has budgeted to drill approximately 27 gross wells
(10.7 net) in the Gulf Coast region and 50 gross (18 net) CCBM coalbed methane
wells in 2003. The actual number of wells drilled and capital expended is
dependent upon available financing, cash flow, availability and cost of drilling
rigs, land and partner issues and other factors.
The Company has continued to reinvest a substantial portion of its cash
flows into increasing its 3-D prospect portfolio, improving its 3-D seismic
interpretation technology and funding its drilling program. Oil and gas capital
expenditures were $19.7 million, $38.2 million and $26.7 million for 2000, 2001
and 2002, respectively. The Company's drilling efforts resulted in the
successful completion of 24 gross wells (6.6 net) in 2000 and 20 gross wells
(5.9 net) in 2001 and 17 gross wells (6.0 net in 2002) in the Gulf Coast region.
Of the 75 gross wells (28 net) drilled or acquired by CCBM, 24 gross wells (8
net) are currently producing and 51 gross wells (20 net) are awaiting evaluation
before a determination can be made as to their success.
During November 2000, the Company entered into a one-year contract with
Grey Wolf, Inc. for utilization of a 1,500 horsepower drilling rig capable of
drilling wells to a depth of approximately 18,000 feet. The contract, which
commenced in March 2001, provides for a dayrate of $12,000 per day. The rig was
utilized primarily to drill wells in the Company's focus areas, including the
Matagorda Project Area and the Cabeza Creek Project Area. The contract contained
a provision which would allow the Company to terminate the contract early by
tendering payment equal to one-half the dayrate for the number of days remaining
under the term of the contract as of the date of termination. The contract
expired in February 2002. Steven A. Webster, who is the Chairman of the Board of
Directors of the Company, is a member of the Board of Directors of Grey Wolf,
Inc.
CCBM plans to spend up to $5.0 million for drilling costs through December
2003, 50% of which would be spent pursuant to an obligation to fund $2.5 million
of drilling costs on behalf of RMG. Through December 31, 2002, CCBM has
satisfied $1.5 million of its drilling obligations on behalf of RMG.
FINANCING ARRANGEMENTS
On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30.0 million. It
is secured by substantially all of the Company's assets and is guaranteed by
CCBM.
29
The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12.0 million and the borrowing base as of October 31, 2002 was $13.0 million.
Each party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. Hibernia National Bank will reset the borrowing base amount
at each scheduled and each unscheduled borrowing base determination date. The
initial quarterly borrowing base reduction, which commenced on June 30, 2002,
was $1.3 million. The quarterly borrowing base reduction effective January 31,
2003 is $1.8 million.
On December 12, 2002, the Company entered into an Amended and Restated
Credit Agreement with Hibernia National Bank that provided additional
availability under the Hibernia Facility in the amount of $2.5 million which is
structured as an additional "Facility B" under the Hibernia Facility. As such,
the total borrowing base under the Hibernia Facility as of December 31, 2002 was
$15.5 million, of which $8.5 million is currently drawn. The Facility B bears
interest at LIBOR plus 3.375%, is secured by certain leases and working
interests in oil and natural gas wells and matures on April 30, 2003.
If the principal balance of the Hibernia Facility ever exceeds the
borrowing base as reduced by the quarterly borrowing base reduction (as
described above), the principal balance in excess of such reduced borrowing base
will be due as of the date of such reduction. Otherwise, any unpaid principal or
interest will be due at maturity.
If the principal balance of the Hibernia Facility ever exceeds any
re-determined borrowing base, the Company has the option within thirty days to
(individually or in combination): (i) make a lump sum payment curing the
deficiency; (ii) pledge additional collateral sufficient in Hibernia National
Bank's opinion to increase the borrowing base and cure the deficiency; or (iii)
begin making equal monthly principal payments that will cure the deficiency
within the ensuing six-month period. Such payments are in addition to any
payments that may come due as a result of the quarterly borrowing base
reductions.
For each tranche of principal borrowed under the revolving line of credit,
the interest rate will be, at the Company's option: (i) the Eurodollar Rate,
plus an applicable margin equal to 2.375% if the amount borrowed is greater than
or equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.
The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the credit facility.
The Hibernia Facility also places restrictions on additional indebtedness,
dividends to non-preferred stockholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of the Company's common or preferred
stock, speculative commodity transactions, and other matters.
At December 31, 2001, amounts outstanding under the Compass Facility
totaled $7.2 million with an additional $0.6 million available for future
borrowings. At December 31, 2002, amounts outstanding under the Hibernia
Facility totaled $8.5 million with an additional $4.3 million available for
future borrowings. At December 31, 2001, one letter of credit was issued and
outstanding under the Compass Facility in the amount of $0.2 million. At
December 31, 2002, one letter of credit was issued and outstanding under the
Hibernia Facility in the amount of $0.2 million.
On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company
("CCBM"), issued a non-recourse promissory note payable in the amount of $7.5 to
Rocky Mountain Gas, Inc. ("RMG") as consideration for certain interests in oil
and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in
41-monthly principal payments of $0.1 million plus interest at 8% per annum
commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is
secured solely by CCBM's interests in the oil and gas leases in Wyoming and
Montana. At December 31, 2001 and 2002, the outstanding principal balance of
this note was $6.8 million and $5.3 million, respectively.
In December 2001, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.2 million. The lease
is payable in one payment of $11,323 and 35 monthly payments of $7,549 including
interest at 8.6% per annum. In October 2002, the Company entered a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
30
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. Under both leases the Company has the option to acquire the equipment
at the conclusion of the lease for $1.
Estimated maturities of long-term debt are $1.6 million in 2003, $3.9
million in 2004, $8.5 million in 2005 and the remainder in 2007.
In November 1999, Messrs. Hamilton, Webster and Loyd provided a bridge loan
in the amount of $2.0 million, to the Company, secured by certain oil and
natural gas properties. This bridge loan bore interest at 14% per annum. Also in
consideration for the bridge loan, the Company assigned to Messrs. Hamilton,
Webster, and Loyd an aggregate 1.0% overriding royalty interest ("ORRI") in the
Huebner #1 and Fondren Letulle #1 wells (combined with the prior assignment, a
2% overriding royalty interest), a .8794% ORRI in Neblett #1 (N. La Copita), a
1.0466% ORRI in STS 104-5 #1, a 1.544% ORRI in USX Hematite #1, a 2.0% ORRI in
Huebner #2 and a 2.0% ORRI in Burkhart #1. On December 15, 1999 the bridge loan
was repaid in its entirety with proceeds from the sale of Common Stock,
Subordinated Notes and Warrants. Such overriding royalty interests are limited
to the well bore and proportionately reduced to the Company's working interest
in the well.
In December 1999, the Company consummated the sale of $22.0 million
principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated
Notes"). The Subordinated Notes were sold at a discount of $0.7 million, which
is being amortized over the life of the notes. Interest is payable quarterly
beginning March 31, 2000. The Company may elect, for a period of five years, to
increase the amount of the Subordinated Notes for up to 60% of the interest
which would otherwise be payable in cash. The amount of Subordinated Notes was
increased by $1.4 million and $1.3 million as of December 31, 2002 and 2001,
respectively, for such interest. Concurrent with the sale of the notes, the
Company consummated the sale of 3,636,364 shares of Common Stock at a price of
$2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's
Common Stock at an exercise price of $2.20 per share. For accounting purposes,
the Warrants are valued at $0.25 per Warrant. The Warrants have an exercise
price of $2.20 per share and expire in December 2007. The Company sold $17.6
million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal
amount of Subordinated Notes; 2,909,091, 363,636, 121,212, 121,212 and 121,212
shares of the Company's common stock and 2,208,151, 276,019, 92,006, 92,006 and
92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners,
LLC), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas
A.P. Hamilton, respectively.
The Company is subject to certain covenants under the terms of the related
Securities Purchase Agreement, including but not limited to, (a) maintenance of
a specified Tangible Net Worth, (b) maintenance of a ratio of EBITDA (earnings
before interest, taxes depreciation and amortization) to quarterly Debt Service
(as defined in the agreement) of not less than 1.00 to 1.00, and (c) limit its
capital expenditures to a specified amount for the year ended December 31, 2000,
and thereafter to an amount equal to the Company's EBITDA for the immediately
prior fiscal year, as well as limits on the Company's ability to (i) incur
indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation,
sales of assets and acquisitions, (iv) declare dividends and effect certain
distributions (including restrictions on distributions upon the Common Stock),
(v) engage in transactions with affiliates (vi) make certain repayments and
prepayments, including any prepayment of the subordinated debt, indebtedness
that is guaranteed or credit-enhanced by any affiliate of the Company, and
prepayments that effect certain permanent reductions in revolving credit
facilities.
Of the approximately $29.0 million net proceeds of this financing, $12.0
million was used to fund the Enron Repurchase described below and related
expenses, $2.0 million was used to repay the bridge loan extended to the Company
by its outside directors, $2.0 million was used to repay a portion of the
Compass Term Loan, $1.0 million was used to repay a portion of the Compass
Borrowing Base Facility, and the remaining proceeds were used to fund the
Company's ongoing exploration and development program and general corporate
purposes.
In January 1998, the Company consummated the sale of 300,000 shares of
Series A Preferred Stock and Warrants to purchase 1,000,000 shares of Common
Stock to affiliates of Enron Corp. The net proceeds received by the Company from
this transaction were approximately $28.8 million and were used primarily for
oil and natural gas exploration and development activities in Texas and
Louisiana and to repay related indebtedness. The Series A Preferred Stock
provided for annual cumulative dividends of $9.00 per share, payable quarterly
in cash or, at the option of the Company until January 15, 2002, in additional
shares of Series A Preferred Stock. Dividend payments for the 12 months ended
December 31, 1999 were made by the issuance of an additional 22,508.23 shares of
Series A Preferred Stock.
In December 1999, the Company consummated the repurchase of all the
outstanding shares of Series A Preferred Stock and 750,000 Warrants for $12.0
million. At the same time, the Company reduced the exercise price of the
remaining 250,000 Warrants from $11.50 per share to $4.00 per share.
31
In February 2002, the Company consummated the sale of 60,000 shares of
Series B Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common
Stock for an aggregate purchase price of $6.0 million. The Company sold $4.0
million and $2.0 million of Series B Preferred Stock and 168,422 and 84,210
Warrants to Mellon Ventures, Inc. and Steven A. Webster, respectively. The
Series B Preferred Stock is convertible into Common Stock by the investors at a
conversion price of $5.70 per share, subject to adjustment, and is initially
convertible into 1,052,632 shares of Common Stock. The approximately $5.8
million net proceeds of this financing were used to fund the Company's ongoing
exploration and development program and general corporate purposes.
Dividends on the Series B Preferred Stock will be payable in either cash at
a rate of 8% per annum or, at the Company's option, by payment in kind of
additional shares of the Series B Preferred Stock at a rate of 10% per annum. At
December 31, 2002 the outstanding balance of the Series B Preferred Stock had
been increased by $0.5 million (5,294 shares) for dividends paid in kind. In
addition to the foregoing, if the Company declares a cash dividend on the Common
Stock of the Company, the holders of shares of Series B Preferred Stock are
entitled to receive for each share of Series B Preferred Stock a cash dividend
in the amount of the cash dividend that would be received by a holder of the
Common Stock into which such share of Series B Preferred Stock is convertible on
the record date for such cash dividend. Unless all accrued dividends on the
Series B Preferred Stock shall have been paid and a sum sufficient for the
payment thereof set apart, no distributions may be paid on any Junior Stock
(which includes the Common Stock) (as defined in the Statement of Resolutions
for the Series B Preferred Stock) and no redemption of any Junior Stock shall
occur other than subject to certain exceptions.
The Series B Preferred Stock is required to be redeemed by the Company at
any time after the third anniversary of the initial issuance of the Series B
Preferred Stock (the "Issue Date") upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). The
Company may redeem the Series B Preferred Stock after the third anniversary of
the Issue Date, at a price per share equal to the Purchase Price/Dividend
Preference and, prior to that time, at varying preferences to the Purchase
Price/Dividend Purchase. "Purchase Price/Dividend Preference" is defined to
mean, generally, $100 plus all cumulative and accrued dividends on such share of
Series B Preferred Stock.
In the event of any dissolution, liquidation or winding up or certain
mergers or sales or other disposition by the Company of all or substantially all
of its assets (a "Liquidation"), the holder of each share of Series B Preferred
Stock then outstanding will be entitled to be paid out of the assets of the
Company available for distribution to its shareholders, the greater of the
following amounts per share of Series B Preferred Stock: (i) $100 in cash plus
all cumulative and accrued dividends and (ii) in certain circumstances, the
"as-converted" liquidation distribution, if any, payable in such Liquidation
with respect to each share of Common Stock.
Upon the occurrence of certain events constituting a "Change of Control"
(as defined in the Statement of Resolutions), the Company is required to make an
offer to each holder of Series B Preferred Stock to repurchase all of such
holder's Series B Preferred Stock at an offer price per share of Series B
Preferred Stock in cash equal to 105% of the Change of Control Purchase Price,
which is generally defined to mean $100 plus all cumulative and accrued
dividends.
The 2002 Warrants have a five-year term and entitle the holders to purchase
up to 252,632 shares of Carrizo's Common Stock at a price of $5.94 per share,
subject to adjustment, and are exercisable at any time after issuance. For
accounting purposes, the 2002 Warrants are valued at $0.06 per 2002 Warrant.
ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY
The Company's growth has placed, and is expected to continue to place, a
significant strain on the Company's financial, technical, operational and
administrative resources. The Company has relied in the past and expects to
continue to rely on project partners and independent contractors that have
provided the Company with seismic survey planning and management, project and
prospect generation, land acquisition, drilling and other services. At December
31, 2002, the Company had 36 full-time employees. There will be additional
demands on the Company's financial, technical, operational and administrative
resources and continued reliance by the Company on project partners and
independent contractors, and these strains on resources, additional demands and
continued reliance may negatively affect the Company. The Company's ability to
grow will depend upon a number of factors, including its ability to obtain
leases or options on properties for 3-D seismic surveys, its ability to acquire
additional 3-D seismic data, its ability to identify and acquire new exploratory
sites, its ability to develop existing sites, its ability to continue to retain
and attract skilled personnel, its ability to maintain or enter into new
relationships with project partners and independent contractors, the results of
its drilling program, hydrocarbon prices, access to capital and other factors.
Although the Company intends to continue to upgrade its technical, operational
and administrative resources and to increase its ability to provide internally
certain of the services previously provided by outside sources, there can be no
assurance that it will be successful in doing so or that it will be able to
continue to maintain or enter into new relationships with project partners and
independent contractors. The failure of the Company to continue to upgrade its
technical,
32
operational and administrative resources or the occurrence of unexpected
expansion difficulties, including difficulties in recruiting and retaining
sufficient numbers of qualified personnel to enable the Company to expand its
seismic data acquisition and drilling program, or the reduced availability of
project partners and independent contractors that have historically provided the
Company seismic survey planning and management, project and prospect generation,
land acquisition, drilling and other services, could have a material adverse
effect on the Company's business, financial condition and results of operations.
Any increase in the Company's activities as an operator will increase its
exposure to operating hazards. See "Business and Properties -- Operating Hazards
and Insurance". The Company's lack of capital will also constrain its ability to
grow and achieve its business strategy. There can be no assurance that the
Company will be successful in achieving growth or any other aspect of its
business strategy.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". The statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement of
obligations of tangible long-lived assets in the period in which it is incurred.
When the asset is placed in service, a liability is recorded and a corresponding
asset is recorded. Accretion of the liability is recognized each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. On January 1, 2003, the Company recorded $0.7 million as
proved properties and $0.6 million as a liability for its plugging and
abandonment expenses.
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". This Statement is effective for
fiscal years beginning after June 15, 2002, and the Company will adopt the
Statement effective January 1, 2003.
The Company has adopted the disclosure requirements of SFAS No. 148,
"Accounting for Stock Based Compensation -- Transition and Disclosure", issued
in December 2002, effective with its December 31, 2002 consolidated financial
statements and related footnotes.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The following summarizes several of our critical accounting policies. See
a complete list of significant accounting policies in Note 2 to the
Consolidated Financial Statements.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these estimates.
Oil and Natural Gas Properties
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and natural gas properties. The Company capitalized
compensation costs for employees working directly on exploration activities of
$0.9 million, $1.0 million and $1.0 million in 2000, 2001 and 2002,
respectively. Maintenance and repairs are expensed as incurred.
Oil and natural gas properties are amortized based on the
unit-of-production method using estimates of proved reserve quantities.
Investments in unproved properties are not amortized until proved reserves
associated with the projects can be determined or until they are impaired.
Unevaluated properties are evaluated periodically for impairment on a
property-by-property basis. If the results of an assessment indicate that the
properties are impaired, the amount of impairment is added to the proved oil and
natural gas property costs to be amortized. The amortizable base includes
estimated future development costs and, where significant, dismantlement,
restoration and abandonment costs, net of estimated salvage values. The
depletion rate per thousand cubic feet equivalent (Mcfe) for 2000, 2001 and 2002
was $1.03, $1.15 and $1.41 respectively.
Dispositions of oil and natural gas properties are accounted for as
adjustments to capitalized costs with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between capitalized costs
and proved reserves.
The net capitalized costs of proved oil and natural gas properties are
subject to a "ceiling test," which limits such costs to the estimated present
value, discounted at a 10% interest rate, of future net revenues from proved
reserves, based on current economic and operating conditions. If net capitalized
costs exceed this limit, the excess is charged to operations through
depreciation, depletion and amortization. No write-down of the Company's oil and
natural gas assets was necessary in 2000, 2001 or 2002. Based on oil and natural
gas prices in effect on December 31, 2001, the unamortized cost of oil and
natural gas properties exceeded the cost center ceiling. As permitted by full
cost accounting rules, improvements in pricing subsequent to December 31, 2001
removed the necessity to record a write-down. Using prices in effect on December
31, 2001 the pretax writedown would have been approximately $0.7 million.
Because of the volatility of oil and natural gas prices, no assurance can be
given that the Company will not experience a
33
write-down in future periods.
Depreciation of other property and equipment is provided using the
straight-line method based on estimated useful lives ranging from five to 10
years.
Oil and Natural Gas Reserve Estimates
The process of estimating quantities of proved reserves is inherently
uncertain, and the reserve data included in this document are estimates prepared
by Ryder Scott Company and Fairchild & Wells, Inc., Independent Petroleum
Engineers. Reserve engineering is a subjective process of estimating underground
accumulations of hydrocarbons that cannot be measured in an exact manner. The
process relies on interpretation of available geologic, geophysical, engineering
and production data. The extent, quality and reliability of this data can vary.
The process also requires certain economic assumptions regarding drilling and
operating expense, capital expenditures, taxes and availability of funds. The
SEC mandates some of these assumptions such as oil and natural gas prices and
the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or
lower than the Company's estimates. Because these estimates depend on many
assumptions, all of which may differ from actual results, reserve quantities
actually recovered may be significantly different than estimated. Material
revisions to reserve estimates may be made depending on the results of drilling,
testing, and rates of production.
You should not assume that the present value of future net cash flows is the
current market value of the Company's estimated proved reserves. In accordance
with SEC requirements, the Company based the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
The Company's rate of recording depreciation, depletion and amortization
expense for proved properties is dependent on the Company's estimate of proved
reserves. If these reserve estimates decline, the rate at which the Company
records these expenses will increase.
34
Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for
Derivative Instruments and Hedging Activities". This statement, as amended by
SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and
disclosures of derivative instruments and hedging activities. This statement
requires all derivative instruments to be carried on the balance sheet at fair
value with changes in a derivative instrument's fair value recognized currently
in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was
effective for the Company beginning January 1, 2001 and was adopted by the
Company on that date. In accordance with the current transition provisions of
SFAS No. 133, the Company recorded a cumulative effect transition adjustment of
$2.0 million (net of related tax expense of $1.1 million) in accumulated other
comprehensive income to recognize the fair value of its derivatives designated
as cash flow hedging instruments at the date of adoption.
Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). Changes in the fair value of a cash flow hedge are recorded
in other comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at January 1, 2001, December 31, 2001 and
December 31, 2002 were designated and effective as cash flow hedges except for
its positions with an affiliate of Enron Corp. discussed in Note 12.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in future earnings.
The Company typically uses fixed rate swaps and costless collars to hedge
its exposure to material changes in the price of natural gas and oil. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated cash flow hedges to forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.
The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.
35
Income Taxes
Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"),
"Accounting for Income Taxes," deferred income taxes are recognized at each
yearend for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. Valuation allowances are established when
necessary to reduce the deferred tax asset to the amount expected to be
realized.
Contingencies
Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Company's revenues, future rate of growth, results of operations,
financial condition and ability to borrow funds or obtain additional capital, as
well as the carrying value of its properties, are substantially dependent upon
prevailing prices of oil and natural gas. Historically, the markets for oil and
natural gas have been volatile, and such markets are likely to continue to be
volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of foreign imports and overall economic conditions. It is impossible to
predict future oil and natural gas price movements with certainty. Declines in
oil and natural gas prices may materially adversely affect the Company's
financial condition, liquidity, and ability to finance planned capital
expenditures and results of operations. Lower oil and natural gas prices also
may reduce the amount of oil and natural gas that the Company can produce
economically. Oil and natural gas prices have declined in the recent past and
there can be no assurance that prices will recover or will not decline further.
See "Business and Properties -- Marketing".
The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10%. Application of this ceiling test generally requires pricing
future revenue at the unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down for accounting purposes if the ceiling is
exceeded, even if prices were depressed for only a short period of time. The
Company may be required to write-down the carrying value of its oil and natural
gas properties when oil and natural gas prices are depressed or unusually
volatile. Once incurred, a write-down of oil and natural gas properties is not
reversible at a later date. Based on oil and gas prices in effect on December
31, 2001, the unamortized cost of our oil and gas properties exceeded the cost
center ceiling. In accordance with full cost accounting rules, improvements in
pricing subsequent to December 31, 2001, removed the necessity to record a
write-down. Using prices in effect on December 31, 2001 the write-down would
have been approximately $0.7 million.
The Company typically uses fixed rate swaps and costless collars to hedge
its exposure to material changes in the price of natural
36
gas and oil. The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objectives and
strategy for undertaking various hedge transactions. This process includes
linking all derivatives that are designated cash flow hedges to forecasted
transactions. The Company also formally assesses, both at the hedge's inception
and on an ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in cash flows of hedged
transactions.
The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.
In November 2001, the Company had no-cost collars with an affiliate of
Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts were no longer effective and thus did
not qualify for hedge accounting treatment. As required by SFAS No. 133, the
value of these derivative instruments as of November 2001 $(0.8 million) was
recorded in accumulated other comprehensive income and will be reclassified into
earnings over the original term of the derivative instruments. An allowance for
the related asset totaling $0.8 million, net of tax of $0.4 million, was charged
to other expense. At December 31, 2001 and 2002, $0.7 million and none, net of
tax of $0.4 million and none, respectively, remained in accumulated other
comprehensive income related to the deferred gains on these derivatives.
Total oil purchased and sold under hedging arrangements during 2000, 2001
and 2002 were 87,900 Bbls, 18,000 Bbls and 131,300 Bbls, respectively. Total
natural gas purchased and sold under hedging arrangements in 2000, 2001 and 2002
were 1,590,000 MMBtu and 3,087,000 MMBtu and 2,314,000 MMBtu, respectively. The
net gains and (losses) realized by the Company under such hedging arrangements
were $(1.5 million), $2.0 million and $(0.9 million) for 2000, 2001 and 2002,
respectively, and are included in oil and gas revenues.
At December 31, 2001 the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2002 the Company had the
following outstanding hedge positions:
December 31, 2002
- ------------------------------------------------------------------------------------------------------------
Contract Volumes
---------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ----------------------------- ------ ------- ----------- ----------- -------------
First Quarter 2003 27,000 $ 24.85
First Quarter 2003 36,000 $23.50 $26.50
First Quarter 2003 540,000 3.40 5.25
Second Quarter 2003 27,300 24.85
Second Quarter 2003 36,000 23.50 26.50
Second Quarter 2003 546,000 3.40 5.25
Third Quarter 2003 552,000 3.40 5.25
Fourth Quarter 2003 552,000 3.40 5.25
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
COMMODITY RISK. The Company's major market risk exposure is the commodity
pricing applicable to its oil and natural gas production. Realized commodity
prices received for such production are primarily driven by the prevailing
worldwide price for oil and spot prices applicable to natural gas. The effects
of such pricing volatility have been discussed above, and such volatility is
expected to continue. A 10% fluctuation in the price received for oil and gas
production would have an approximate $2.6 million impact on the Company's annual
revenues and operating income.
To mitigate some of this risk, the Company engages periodically in certain
limited hedging activities but only to the extent of buying protection price
floors. Costs and any benefits derived from these price floors are accordingly
recorded as a reduction or increase, as applicable, in oil and gas sales revenue
and were not significant for any year presented. The costs to purchase put
options are amortized over the option period. The Company does not hold or issue
derivative instruments for trading purposes. Income and
37
(losses) realized by the Company related to these instruments were $(1.5
million), $2.0 million and $(0.9 million) or $(0.73), $0.63, and $(0.12) per
MMBtu for the years ended December 31, 2000, 2001, and 2002, respectively.
INTEREST RATE RISK. The Company's exposure to changes in interest rates
results from its floating rate debt. In regards to its Revolving Credit
Facility, the result of a 10% fluctuation in short-term interest rates would
have impacted 2002 cash flow by approximately $32,000.
FINANCIAL INSTRUMENTS & DEBT MATURITIES. The Company's financial
instruments consist of cash and cash equivalents, accounts receivable, accounts
payable, bank borrowing, Subordinated Notes payable and Series B Redeemable
Preferred Stock. The carrying amounts of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value due to the highly liquid
nature of these short-term instruments. The fair values of the bank and vendor
borrowings approximate the carrying amounts as of December 31, 2002 and 2001,
and were determined based upon interest rates currently available to the Company
for borrowings with similar terms. Maturities of the debt are $1.6 million in
2003, $3.9 million in 2004, $8.5 million in 2005 and the balance in 2007.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this item is included elsewhere in this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to
information under the caption "Proposal 1-Election of Directors" and to the
information under the caption "Section 16(a) Reporting Delinquencies" in the
Company's definitive Proxy Statement (the "2003 Proxy Statement") for its 2003
annual meeting of shareholders. The 2003 Proxy Statement will be filed with the
Securities and Exchange Commission (the "Commission") not later than 120 days
subsequent to December 31, 2002.
Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company is set forth in Part I of
this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference
to the 2003 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2002.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information concerning our equity compensation plan at December 31, 2002 is
as follows:
38
Number of securities
remaining available
Number of securities for future issuance
to be issued upon Weighted-average under equity
exercise of outstanding exercise price of compensation plans
options, warrants and outstanding options, (excluding securities
rights warrants and rights reflected in column (a))
Plan Category (a) (b) (c)
- ---------------------------------- ----------------------- -------------------- ------------------------
Equity compensation plans
approved by security holders 1,414,203 $ 3.31 284,000
Equity compensation plans
not approved by security holders 216,120 3.60 --
----------------------- -------------------- ----------------------
Total 1,630,323 $ 3.35 284,000
======================= ==================== ======================
Other information required by this item is incorporated herein by reference
to the 2003 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2002.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference
to the 2003 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2002.
ITEM 14. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this report, the Company carried
out an evaluation, under the supervision and with the participation of the
Company's management, including the Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based
on that evaluation, the Chief Executive Officer and the Chief Financial Officer
concluded that the Company's disclosure controls and procedures are effective in
timely alerting them to material information relating to the Company (including
its consolidated subsidiaries) required to be included in the Company's periodic
SEC filings. Subsequent to the date of their evaluation, there were no
significant changes in the Company's internal controls or in other factors that
could significantly affect the internal controls, including any corrective
actions with regard to significant deficiencies and material weakness.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) FINANCIAL STATEMENTS
The response to this item is submitted in a separate section of this
report.
(a)(2) FINANCIAL STATEMENT SCHEDULES
All schedules and other statements for which provision is made in the
applicable regulations of the Commission have been omitted because they are not
required under the relevant instructions or are inapplicable.
39
(a)(3) EXHIBITS
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
+2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa
Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton
and Frank A. Wojtek dated as of June 6, 1998 (Incorporated herein by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the Company (Incorporated herein by reference to Exhibit 3.1
to the Company's Annual Report on Form 10-K for the year ended December 31, 1998).
+3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915), Amendment No. 2
(Incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15,
1999) and Amendment No. 3 (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K
dated February 20, 2002).
+3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred
Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other
rights thereof (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated
February 20, 2002).
+4.1 -- Credit Agreement dated as of May 24, 2002 by and between Carrizo Oil & Gas, Inc., CCBM, Inc. and Hibernia
National Bank (Incorporated by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2002).
+4.2 -- Revolving Note by and between Carrizo Oil & Gas, Inc. and Hibernia National Bank dated May 24, 2002
(Incorporated by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 2002).
+4.3 -- Commercial Guarantee by and between CCBM, Inc. and Hibernia National Bank dated May 24, 2002 (Incorporated by
reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
+4.4 -- Stock Pledge and Security Agreement by and between Carrizo Oil & Gas, Inc. and Hibernia National Bank dated May
24, 2002 (Incorporated by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002).
+4.5 -- First Amendment to Credit Agreement dated July 9, 2002 to the Credit Agreement by and between Carrizo Oil & Gas,
Inc. and Hibernia National Bank dated May 24, 2002 (Incorporated by reference to Exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
4.6 -- Amended and Restated Credit Agreement dated as of December 12, 2002 by and between Carrizo Oil & Gas, Inc.,
CCBM, Inc. and Hibernia National Bank.
+4.7 -- Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage Program, dated May 1, 2001
(Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).
+4.8 -- Amendment No. 1 to the Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage
Program, dated June 1, 2001 (Incorporated herein by reference to Exhibit 4.2 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2001).
+4.9 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM, Inc. (Incorporated herein by reference to Exhibit
4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
+10.1 -- Amended and Restated Incentive Plan of the Company effective as of February 17, 2000 (Incorporated herein by
reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000).
+10.2 -- Amendment No. 1 to the Amended and Restated Incentive Plan of the Company (Incorporated by reference to Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
10.3 -- Amendment to the Amended and Restated Incentive Plan of the Company.
+10.4 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by reference to Exhibit 10.2
to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.5 -- Employment Agreement between the Company and Frank A. Wojtek (Incorporated herein by reference to Exhibit 10.3
to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.6 -- Employment Agreement between the Company and Kendall A. Trahan (Incorporated herein by reference to Exhibit 10.4
to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.7 -- Employment Agreement between the Company and Jeremy T. Greene (Incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
+10.8 -- Indemnification Agreement between the Company and each of its directors and executive officers (Incorporated
herein by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31,
1998).
40
+10.9 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster,
Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.8 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+10.10 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs.
Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.11 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by reference to Exhibit 99.3
to the Company's Current Report on Form 8-K dated January 8, 1998).
+10.12 -- Amended Enron Warrant Certificates (Incorporated herein by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K dated December 15, 1999).
+10.13 -- Securities Purchase Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to
Exhibit 99.1 to the Company's Current Report on Form 8-K dated December 15, 1999).
+10.14 -- Shareholders Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures,
L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K
dated December 15, 1999).
+10.15 -- Warrant Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P.,
Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.3 to
the Company's Current Report on Form 8-K dated December 15, 1999).
+10.16 -- Registration Rights Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon
Ventures, L.P. (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8- K dated
December 15, 1999).
+10.17 -- Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd Jr.,
Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated December 15,
1999).
+10.18 -- Compliance Sideletter dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures,
L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated December
15, 1999).
+10.19 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated December 15, 1999).
+10.20 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated December 15, 1999).
+10.21 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc. and CCBM, Inc., dated June 29, 2001
(Incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).
+10.22 -- Securities Purchase Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated
February 20, 2002).
+10.23 -- Shareholders' Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P., Paul B. Loyd, Jr.,
Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated February 20,
2002).
+10.24 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster
(including Warrant Certificate) (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report
on Form 8-K dated February 20, 2002).
+10.25 -- Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated
February 20, 2002).
+10.26 -- Compliance Sideletter dated February 20, 2002 between the Company and Mellon Ventures, L.P. (Incorporated herein
by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated February 20, 2002).
+10.27 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated February 20, 2002).
+10.28 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated February 20, 2002).
41
21.1 -- Subsidiaries of the Company.
23.1 -- Consent of Ernst & Young LLP
23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
23.3 -- Consent of Fairchild & Wells, Inc.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2002.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2002.
99.3 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers for CCBM, Inc. as of December 31, 2002.
99.4 -- Notice Regarding Consent of Arthur Andersen LLP.
- ----------
+ Incorporated by reference as indicated.
REPORTS ON FORM 8-K
None.
42
CARRIZO OIL & GAS, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Carrizo Oil & Gas, Inc. --
Report of Independent Auditors and Independent Public Accountants F-2
Consolidated Balance Sheets, December 31, 2001 and 2002 F-4
Consolidated Statements of Operations for the Years Ended December 31, 2000,
2001 and 2002 F-5
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 2000, 2001 and 2002 F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2000,
2001 and 2002 F-7
Notes to Consolidated Financial Statements F-8
F-1
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Shareholders of
Carrizo Oil & Gas, Inc.
We have audited the accompanying consolidated balance sheet of Carrizo Oil
& Gas, Inc. as of December 31, 2002, and the related consolidated statements of
operations, shareholders' equity and cash flows for the year then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The consolidated financial statements of Carrizo Oil & Gas, Inc. as
of December 31, 2001 and for the two years then ended, were audited by other
auditors who have ceased operations and whose report dated March 20, 2002,
expressed an unqualified opinion on those statements, before the revisions
described in Note 5.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the 2002 consolidated financial statements referred to
above present fairly, in all material respects, the financial position of the
Company as of December 31, 2002, and the results of its operations and its cash
flows for the year then ended, in conformity with accounting principles
generally accepted in the United States.
As discussed above, the consolidated financial statements of the Company as
of December 31, 2001 and for the two years then ended were audited by other
auditors who have ceased operations. As described in Note 5, the Company revised
the reported amounts of certain temporary differences at December 31, 2001. We
audited the adjustments described in Note 5 that were applied to revise the
reported amounts of temporary differences in the 2001 consolidated financial
statements. Our procedures included (a) agreeing the revised temporary
differences to the Company's underlying records obtained from management, and
(b) testing the mathematical accuracy of the revisions to the temporary
differences. In our opinion, such adjustments are appropriate and have been
properly applied. However, we were not engaged to audit, review, or apply any
procedures to the 2001 consolidated financial statements of the Company other
than with respect to such adjustments and, accordingly, we do not express an
opinion or any other form of assurance on the 2001 consolidated financial
statements taken as a whole.
ERNST & YOUNG LLP
Houston, Texas
March 14, 2003
F-2
THIS IS A COPY OF AN ACCOUNTANTS' REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. AS
DESCRIBED IN NOTE 5 TO CARRIZO'S CONSOLIDATED FINANCIAL STATEMENTS AS OF
DECEMBER 31, 2002, THE FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2001
REFERRED TO IN THIS REPORT HAVE BEEN REVISED SUBSEQUENT TO THE DATE OF THE
REPORT TO REFLECT REVISIONS TO TEMPORARY DIFFERENCES IN THE RECOGNITION OF
INCOME AND EXPENSES FOR FINANCIAL REPORTING PURPOSES AND FOR TAX PURPOSES. THE
REVISIONS HAVE BEEN REPORTED ON BY ERNST & YOUNG LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and
Board of Directors of
Carrizo Oil & Gas, Inc.:
We have audited the accompanying consolidated balance sheets of Carrizo Oil
& Gas, Inc. (a Texas corporation) as of December 31, 2000 and 2001, and the
related consolidated statements of operations, shareholders' equity and cash
flows for each of the three years in the period ended December 31, 2001. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of the Company
as of December 31, 2000 and 2001, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities to conform with Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." Additionally, as explained in Note 10 to the consolidated financial
statements, effective January 1, 1999, the Company changed its method of
accounting for start up costs.
ARTHUR ANDERSEN LLP
Houston, Texas
March 20, 2002
F-3
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
As of December 31,
----------------------------
2001 2002
------------ ------------
(In thousands)
CURRENT ASSETS:
Cash and cash equivalents $ 3,236 $ 4,743
Accounts receivable, trade (net of allowance for doubtful accounts of
$0.5 million at December 31, 2001 and 2002, respectively) 8,111 8,207
Advances to operators 509 501
Deposits 48 46
Other current assets 600 605
------------ ------------
Total current assets 12,504 14,102
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and natural gas properties) 104,132 120,526
Deferred financing costs 756 760
------------ ------------
$ 117,392 $ 135,388
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 10,263 $ 9,957
Accrued liabilities 348 1,014
Advances for joint operations 368 1,550
Current maturities of long-term debt 2,107 1,609
Current maturities of seismic obligation payable -- 1,414
------------ ------------
Total current liabilities 13,086 15,544
LONG-TERM DEBT 36,081 37,886
SEISMIC OBLIGATION PAYABLE -- 1,103
DEFERRED INCOME TAXES 5,021 7,666
COMMITMENTS AND CONTINGENCIES (Note 9)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000
shares of preferred stock authorized, of which 150,000 are shares designated as
convertible participating shares, with 65,294 convertible participating shares
issued and outstanding at December 31, 2002) (Note 8) -- 6,373
SHAREHOLDERS' EQUITY:
Warrants (3,010,189 and 3,262,821 outstanding at
December 31, 2001 and 2002, respectively) 765 780
Common stock, par value $.01, (40,000,000 shares authorized with 14,064,077 and
14,177,383 issued and outstanding at December 31, 2001 and 2002, respectively) 141 142
Additional paid in capital 62,736 63,224
Retained earnings (deficit) (1,144) 3,058
Accumulated other comprehensive income (loss) 706 (388)
------------ ------------
63,204 66,816
------------ ------------
$ 117,392 $ 135,388
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31,
--------------------------------------------
2000 2001 2002
------------ ------------ ------------
(In thousands except for per share amounts)
OIL AND NATURAL GAS REVENUES $ 26,834 $ 26,226 $ 26,802
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depreciation shown separately below) 4,941 4,138 4,908
Depreciation, depletion and amortization 7,170 6,492 10,574
General and administrative 3,143 3,333 4,133
Stock option compensation 652 (558) (84)
------------ ------------ ------------
Total costs and expenses 15,906 13,405 19,531
------------ ------------ ------------
OPERATING INCOME 10,928 12,821 7,271
OTHER INCOME AND EXPENSES:
Other income and expenses 1,482 1,777 274
Interest income 592 275 55
Interest expense (1,459) (1,040) (846)
Interest expense, related parties (2,118) (2,137) (2,255)
Capitalized interest 3,564 3,171 3,100
------------ ------------ ------------
INCOME BEFORE INCOME TAXES 12,989 14,867 7,599
INCOME TAXES 1,004 5,336 2,809
------------ ------------ ------------
NET INCOME $ 11,985 $ 9,531 $ 4,790
============ ============ ============
DIVIDENDS AND ACCRETION ON PREFERRED STOCK -- -- 588
------------ ------------ ------------
NET INCOME AVAILABLE TO
COMMON SHAREHOLDERS $ 11,985 $ 9,531 $ 4,202
============ ============ ============
BASIC EARNINGS
PER COMMON SHARE $ 0.85 $ 0.68 $ 0.30
============ ============ ============
DILUTED EARNINGS PER COMMON SHARE $ 0.74 $ 0.57 $ 0.26
============ ============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
WARRANTS COMMON STOCK
--------------------------- ---------------------------
NUMBER AMOUNT SHARES AMOUNT
------------ ------------ ------------ ------------
BALANCE, January 1, 2000 3,010,189 $ 765 14,011,364 $ 141
Net income -- -- -- --
Common stock issued -- -- 43,697 --
------------ ------------ ------------ ------------
BALANCE, December 31, 2000 3,010,189 765 14,055,061 141
------------ ------------ ------------ ------------
Comprehensive income
Net income -- -- -- --
Cummulative effect of change
in accounting principle -- -- -- --
Reclassification adjustments for
cummulative effect of change in
accounting principle -- -- -- --
Reclassification adjustments for
settled contracts -- -- -- --
Net change in fair value of
hedging instruments -- -- -- --
------------ ------------ ------------ ------------
Comprehensive income
Common stock issued -- -- 9,016 --
------------ ------------ ------------ ------------
BALANCE, December 31, 2001 3,010,189 765 14,064,077 141
------------ ------------ ------------ ------------
Net income -- -- -- --
Net change in fair value of
hedging instruments -- -- -- --
------------ ------------ ------------ ------------
Comprehensive income
Warrants issued 252,632 15 -- --
Common stock issued -- -- 113,306 1
Dividends and accretion of
discount on preferred stock -- -- -- --
------------ ------------ ------------ ------------
BALANCE, December 31, 2002 3,262,821 $ 780 14,177,383 $ 142
============ ============ ============ ============
The accompanying notes are an integral part of
these consolidated financial statements.
F-6
Accumulated
Additional Retained Other
Paid in Comprehensive Earnings Comprehensive Shareholders'
Capital Income (Deficit) Income (loss) Equity
- ------------ ------------- ------------ ------------- -------------
(Dollars in thousands)
$ 62,608 -- $ (22,660) -- $ 40,854
-- -- 11,985 -- 11,985
100 -- -- -- 100
- ------------ ------------ ------------ ------------ ------------
62,708 -- (10,675) -- 52,939
- ------------ ------------ ------------ ------------ ------------
-- $ 9,531 9,531 -- 9,531
-- (1,967) -- $ (1,967) (1,967)
-- 1,967 -- 1,967 1,967
-- (2,020) -- (2,020) (2,020)
-- 2,726 -- 2,726 2,726
- ------------ ------------ ------------ ------------ ------------
$ 10,237
============
28 -- -- 28
- ------------ ------------ ------------ ------------
62,736 (1,144) 706 63,204
- ------------ ------------ ------------ ------------
-- 4,790 4,790 -- 4,790
-- (1,094) -- (1,094) (1,094)
- ------------ ------------ ------------ ------------ ------------
$ 3,696
============
-- -- 15
488 -- -- 489
(588) -- (588)
- ------------ ------------ ------------ ------------
$ 63,224 $ 3,058 $ (388) $ 66,816
============ ============ ============ ============
F-7
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,
--------------------------------------------
2000 2001 2002
------------ ------------ ------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 11,985 $ 9,531 $ 4,790
Adjustment to reconcile net income to net
cash provided by operating activities -
Depreciation, depletion and amortization 7,170 6,492 10,574
Discount accretion 82 85 86
Ineffective derivative instruments -- 706 (706)
Interest payable in kind 1,227 1,282 1,353
Stock option compensation (benefit) 652 (558) (84)
Gain on sale of Michael Petroleum Corporation -- (3,900) --
Finders fee (1,544) -- --
Deferred income taxes 902 5,204 2,645
Changes in assets and liabilities -
Accounts receivable (2,968) (719) 530
Deposits and other current assets (625) 200 206
Other assets (236) (57) (265)
Accounts payable (155) 6,555 643
Accrued liabilities 643 (870) 153
------------ ------------ ------------
Net cash provided by operating
activities 17,133 23,951 19,925
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (19,746) (38,264) (24,696)
Proceeds from sale of Michael Petroleum Corporation -- 5,445 --
Proceeds for sale of Metro Project 5,075 -- --
Proceeds from the sale of oil and natural gas properties -- -- 355
Change in capital expenditure accrual (587) 355 (949)
Advances to operators (490) 1,248 8
Advances for joint operations (690) (8) 1,182
------------ ------------ ------------
Net cash used in investing activities (16,438) (31,224) (24,100)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from sale of common stock 100 27 14
Net proceeds from sale of preferred stock -- -- 5,800
Net proceeds from debt issuance -- 7,744 8,613
Debt repayments (3,923) (5,479) (8,745)
------------ ------------ ------------
Net cash provided by (used in) financing activities (3,823) 2,292 5,682
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (3,128) (4,981) 1,507
CASH AND CASH EQUIVALENTS, beginning of year 11,345 8,217 3,236
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, end of year $ 8,217 $ 3,236 $ 4,743
============ ============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ -- $ -- $ 1
============ ============ ============
Cash paid for income taxes $ -- $ -- $ --
============ ============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
F-8
CARRIZO OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS
Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its
subsidiary, affiliates and predecessors, the Company) is an independent energy
company formed in 1993 and is engaged in the exploration, development,
exploitation and production of oil and natural gas. Its operations are focused
on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and
Vicksburg trends. The Company, through CCBM Inc. (a wholly-owned subsidiary)
("CCBM") acquired interests in certain oil and natural gas leases in Wyoming and
Montana in areas prospective for coalbed methane. CCBM has an obligation to fund
$2.5 million of drilling costs on behalf of Rocky Mountain Gas, Inc. ("RMG"),
from whom the interests in the leases were acquired. Through December 31, 2002,
CCBM has satisfied $1.5 million of its drilling obligations on behalf of RMG.
The exploration for oil and natural gas is a business with a significant
amount of inherent risk requiring large amounts of capital. The Company intends
to finance its exploration and development program through cash from operations,
existing credit facilities or arrangements with other industry participants.
Should the sources of capital currently available to the Company not be
sufficient to explore and develop its prospects and meet current and near-term
obligations, the Company may be required to seek additional sources of financing
which may not be available on terms acceptable to the Company. This lack of
additional financing could force the Company to defer its planned exploration
and development drilling program which could adversely affect the recoverability
and ultimate value of the Company's oil and natural gas properties.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statement are presented in accordance with
generally accepted accounting principles in the United States. The consolidated
financial statements include the accounts of the Company and its subsidiary. All
intercompany accounts and transactions have been eliminated in consolidation.
CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting periods. Actual results could differ from these estimates.
The Company believes the following critical accounting policies affect its
more significant judgements and estimates used in the preparation of its
consolidated financial statements:
OIL AND NATURAL GAS PROPERTIES
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and natural gas properties. The Company capitalized
compensation costs for employees working directly on exploration activities of
$0.9 million, $1.0 million and $1.0 million in 2000, 2001 and 2002,
respectively. Maintenance and repairs are expensed as incurred.
Oil and natural gas properties are amortized based on the
unit-of-production method using estimates of proved reserve quantities.
Investments in unproved properties are not amortized until proved reserves
associated with the projects can be determined or until they are impaired.
Unevaluated properties are evaluated periodically for impairment on a
property-by-property basis. If the results of an assessment indicate that the
properties are impaired, the amount of impairment is added to the proved oil and
natural gas property costs to be amortized. The amortizable base includes
estimated future development costs and, where significant, dismantlement,
restoration and abandonment costs, net of estimated salvage values. The
depletion rate per Mcfe for
F-9
2000, 2001 and 2002 was $1.03, $1.15 and $1.41 respectively.
Dispositions of oil and natural gas properties are accounted for as
adjustments to capitalized costs with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between capitalized costs
and proved reserves.
The net capitalized costs of proved oil and natural gas properties are
subject to a "ceiling test," which limits such costs to the estimated present
value, discounted at a 10% interest rate, of future net revenues from proved
reserves, based on current economic and operating conditions. If net capitalized
costs exceed this limit, the excess is charged to operations through
depreciation, depletion and amortization. No write-down of the Company's oil and
natural gas assets was necessary in 2000, 2001 or 2002. Based on oil and natural
gas prices in effect on December 31, 2001, the unamortized cost of oil and
natural gas properties exceeded the cost center ceiling. As permitted by full
cost accounting rules, improvements in pricing subsequent to December 31, 2001
removed the necessity to record a write-down. Using prices in effect on December
31, 2001 the pretax write-down would have been approximately $0.7 million.
Because of the volatility of oil and natural gas prices, no assurance can be
given that the Company will not experience a write-down in future periods.
Depreciation of other property and equipment is provided using the
straight-line method based on estimated useful lives ranging from five to 10
years.
OIL AND NATURAL GAS RESERVE ESTIMATES
The process of estimating quantities of proved reserves is inherently
uncertain, and the reserve data included in this document are estimates prepared
by Ryder Scott Company and Fairchild & Wells, Inc., Independent Petroleum
Engineers. Reserve engineering is a subjective process of estimating underground
accumulations of hydrocarbons that cannot be measured in an exact manner. The
process relies on interpretation of available geologic, geophysical, engineering
and production data. The extent, quality and reliability of this data can vary.
The process also requires certain economic assumptions regarding drilling and
operating expense, capital expenditures, taxes and availability of funds. The
SEC mandates some of these assumptions such as oil and natural gas prices and
the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or
lower than the Company's estimates. Because these estimates depend on many
assumptions, all of which may differ from actual results, reserve quantities
actually recovered may be significantly different than estimated. Material
revisions to reserve estimates may be made depending on the results of drilling,
testing, and rates of production.
You should not assume that the present value of future net cash flows is the
current market value of the Company's estimated proved reserves. In accordance
with SEC requirements, the Company based the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
The Company's rate of recording depreciation, depletion and amortization
expense for proved properties is dependent on the Company's estimate of proved
reserves. If these reserve estimates decline, the rate at which the Company
records these expenses will increase.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include highly liquid investments with maturities
of three months or less when purchased.
REVENUE RECOGNITION AND NATURAL GAS IMBALANCES
The Company follows the sales method of accounting for revenue recognition
and natural gas imbalances, which recognizes over and under lifts of natural gas
when sold, to the extent sufficient natural gas reserves or balancing agreements
are in place. Natural gas sales volumes are not significantly different from the
Company's share of production.
FINANCING COSTS
Long-term debt financing costs of $0.8 million and $0.8 million are included
in other assets as of December 31, 2001 and 2002, respectively, are being
amortized using the effective yield method over the term of the loans (through
January 31, 2005 for a credit facility and through December 15, 2007 for
subordinated notes payable).
F-10
SUPPLEMENTAL CASH FLOW INFORMATION
The statement of cash flows for the year ended December 31, 2002 does not
reflect the following non-cash transactions: the $2.5 million of seismic data
acquisitions, the acquisition $0.5 million in oil and natural gas properties
through the issuance of common stock, and the $0.6 million reduction of oil and
natural gas properties for the amount of insurance recoveries expected to be
received related to difficulties encountered in the drilling of a well.
FINANCIAL INSTRUMENTS
The Company's recorded financial instruments consist of cash, receivables,
payables and long-term debt. The carrying amount of cash, receivables and
payables approximates fair value because of the short-term nature of these
items. The carrying amount of bank debt approximates fair value as this
borrowing bears interest at floating market interest rates. The fair value of
the Subordinated Notes payable and the RMG note at December 31, 2002 was $32.6
million and $5.6 million, respectively. Fair values for the Subordinated Notes
payable and the RMG note were determined based upon interest rates available to
the Company at December 31, 2002 with similar terms.
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees" and related interpretations.
Under this method, the Company records no compensation expense for stock options
granted when the exercise price of those options is equal to or greater than the
market price of the Company's common stock on the date of grant. Repriced
options are accounted for as compensatory options using variable accounting
treatment. Under variable plan accounting, compensation expense is adjusted for
increases or decreases in the fair market value of the Company's common stock.
Variable plan accounting is applied to the repriced options until the options
are exercised, forfeited, or expire unexercised.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for
Derivative Instruments and Hedging Activities". This statement, as amended by
SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and
disclosures of derivative instruments and hedging activities. This statement
requires all derivative instruments to be carried on the balance sheet at fair
value with changes in a derivative instrument's fair value recognized currently
in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was
effective for the Company beginning January 1, 2001 and was adopted by the
Company on that date. In accordance with the current transition provisions of
SFAS No. 133, the Company recorded a cumulative effect transition adjustment of
$2.0 million (net of related tax expense of $1.1 million) in accumulated other
comprehensive income to recognize the fair value of its derivatives designated
as cash flow hedging instruments at the date of adoption.
Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). Changes in the fair value of a cash flow hedge are recorded
in other comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at January 1, 2001, December 31, 2001 and
December 31, 2002 were designated and effective as cash flow hedges except for
its positions with an affiliate of Enron Corp. discussed in Note 12.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in future earnings.
The Company typically uses fixed rate swaps and costless collars to hedge
its exposure to material changes in the price of natural gas and oil. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated cash flow hedges to forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of
F-11
hedged transactions.
The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.
INCOME TAXES
Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"),
"Accounting for Income Taxes," deferred income taxes are recognized at each
year-end for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. Valuation allowances are established when
necessary to reduce the deferred tax asset to the amount expected to be
realized.
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables. Derivative
contracts subject the Company to concentration of credit risk. The Company
transacts the majority of its derivative contracts with two counterparties. The
Company does not require collateral from its customers.
MAJOR CUSTOMERS
The Company sold oil and natural gas production representing more than 10%
of its oil and natural gas revenues for the year ended December 31, 2001 to
Cokinos Natural Gas Company (17%); for the year ended December 31, 2002 to
Cokinos Natural Gas Company (12%) and Discovery Producer Services, LLC (10%).
Because alternate purchasers of oil and natural gas are readily available, the
Company believes that the loss of any of its purchasers would not have a
material adverse effect on the financial results of the Company.
F-12
EARNINGS PER SHARE
Supplemental earnings per share information is provided below:
FOR THE YEAR ENDED DECEMBER 31, (IN THOUSANDS EXCEPT SHARE AND PER SHARE AMOUNTS)
-------------------------------------------------------------------------------------------
INCOME SHARES PER-SHARE AMOUNT
------------------------- ------------------------------------ ------------------------
2000 2001 2002 2000 2001 2002 2000 2001 2002
------- ------ ------ ---------- ---------- ---------- ------ ------ ------
Basic Earnings per Common Share:
Net income $11,985 $9,531 $4,790
Less: Dividends and Accretion
of Discount on Preferred Shares -- -- 588
------- ------ ------
Net income available to
common shareholders $11,985 $9,531 $4,202 14,028,176 14,059,151 14,158,438 $ 0.85 $ 0.68 $ 0.30
======= ====== ====== ========== ========== ========== ====== ====== ======
Diluted Earnings per Common Share:
Net Income $11,985 $9,531 $4,790 14,028,176 14,059,151 14,158,438
Less: Dividends and Accretion of
Discount on Preferred Shares -- -- 558
Stock Options 558,960 807,628 514,077
Warrants 1,668,519 1,864,222 1,475,928
------- ------ ------ ---------- ---------- ----------
Net income available to
common shareholders $11,985 $9,531 $4,202 16,255,655 16,731,001 16,148,443 $ 0.74 $ 0.57 $ 0.26
======= ====== ====== ========== ========== ========== ====== ====== ======
F-13
Basic earnings per common share has been computed by dividing net income by
the weighted average number of shares of Common Stock outstanding during the
periods. Diluted earnings per common share is based on the weighted average
number of common shares and all dilutive potential common shares outstanding
during the period. The Company had outstanding 149,000, 79,500 and 172,333 stock
options at December 31, 2000, 2001 and 2002, respectively, that were
antidilutive. The Company had outstanding 252,632 warrants at December 31, 2002
that were antidilutive. These antidilutive stock options and warrants were not
included in the calculation because the exercise price of these instruments
exceeded the underlying market value of the options and warrants as of the dates
presented. The Company had 1,145,515 convertible preferred shares at December
31, 2002 that were antidilutive and were not included in the calculation.
CONTINGENCIES
Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". This Statement is effective for
fiscal years beginning after June 15, 2002, and the Company will adopt the
Statement effective January 1, 2003. On January 1, 2003, the Company recorded
$0.4 million as proved properties and $0.5 million as a liability for its
plugging and abandonment expenses.
The Company has adopted the disclosure requirements of SFAS No. 148,
"Accounting for Stock Based Compensation - Transition and Disclosure", issued in
December 2002, effective with its December 31, 2002 consolidated financial
statements and related footnotes.
3. INVESTMENT IN MICHAEL PETROLEUM CORPORATION:
In 2000 the Company received a finder's fee valued at $1.5 million from
affiliates of Donaldson, Lufkin & Jenrette ("DLJ") in connection with their
purchase of a significant minority shareholder interest in Michael Petroleum
Corporation ("MPC"). MPC is a privately held exploration and production company
which focuses on the prolific natural gas producing Lobo Trend in South Texas.
The minority shareholder interest in MPC was purchased by entities affiliated
with DLJ. The Company elected to receive the fee in the form of 18,947 shares of
common stock, 1.9% of the outstanding common shares of MPC, which, until its
sale in 2001, was accounted for as a cost basis investment. Steven A. Webster,
who is the Chairman of the Board of the Company, and a Managing Director of
Global Energy Partners Ltd., a merchant banking affiliate of DLJ which makes
investments in energy companies, joined the Board of Directors of MPC in
connection with the transaction.
In 2001, the Company agreed to sell its interest in MPC pursuant to an
agreement between MPC and its shareholders for the sale of a majority interest
in MPC to Calpine Natural Gas Company. The Company received total cash proceeds
of $5.7 million, of which $5.5 million was paid to the Company during the third
quarter of 2001, resulting in a financial statement gain of $3.9 million being
reflected in the third quarter 2001 financial results. The remaining amounts
will be paid in 2003.
4. PROPERTY AND EQUIPMENT
At December 31, 2001 and 2002, property and equipment consisted of the
following:
F-14
AS OF DECEMBER 31,
----------------------------
2001 2002
------------ ------------
(IN THOUSANDS)
Proved oil and natural gas properties $ 104,005 $ 133,032
Unproved oil and natural gas properties 44,416 42,020
Other equipment 609 685
------------ ------------
Total property and equipment 149,030 175,737
Accumulated depreciation, depletion and amortization (44,898) (55,211)
------------ ------------
Property and equipment, net $ 104,132 $ 120,526
============ ============
Oil and natural gas properties not subject to amortization consist of the
cost of unevaluated leaseholds, seismic costs associated with specific
unevaluated properties, exploratory wells in progress, and secondary recovery
projects before the assignment of proved reserves. These unproved costs are
reviewed periodically by management for impairment, with the impairment
provision included in the cost of oil and natural gas properties subject to
amortization. Factors considered by management in its impairment assessment
include drilling results by the Company and other operators, the terms of oil
and natural gas leases not held by production, production response to secondary
recovery activities and available funds for exploration and development. Of the
$42.0 million of unproved property costs at December 31, 2002 being excluded
from the amortizable base, $2.7 million, $11.7 million and $6.3 million were
incurred in 2000, 2001 and 2002, respectively and $21.3 million was incurred in
prior years. These costs are primarily seismic and lease acquisition costs. The
Company expects it will complete its evaluation of the properties representing
the majority of these costs within the next two to five years.
5. INCOME TAXES
All of the Company's income is derived from domestic activities. Actual
income tax expense differs from income tax expense computed by applying the U.S.
federal statutory corporate rate of 35% to pretax income as follows:
YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 2001 2002
------------ ------------ ------------
(IN THOUSANDS)
Provision at the statutory tax rate $ 4,546 $ 5,204 $ 2,660
Decrease in valuation allowance pertaining to
expected net operating loss utilization (3,644) -- --
Other 102 132 149
------------ ------------ ------------
Income tax provision $ 1,004 $ 5,336 $ 2,809
============ ============ ============
Deferred income tax provisions result from temporary differences in the
recognition of income and expenses for financial reporting purposes and for tax
purposes. At December 31, 2001 and 2002, the tax effects of these temporary
differences resulted principally from the following:
F-15
AS OF DECEMBER 31,
----------------------------
2001 2002
------------ ------------
(IN THOUSANDS)
Deferred income tax asset:
Net operating loss carryforward $ 1,797 $ 2,462
Hedge valuation -- 209
------------ ------------
1,797 2,671
------------ ------------
Deferred income tax liabilities:
Oil and gas acquisition, exploration
and development costs deducted for
tax purposes in excess of financial
statement DD&A 4,084 6,309
Capitalized interest 2,734 3,819
------------ ------------
6,818 10,128
------------ ------------
Net deferred income tax liability $ 5,021 $ 7,457
============ ============
The December 31, 2001 deferred income tax asset relating to the net
operating loss carry forward and the deferred income tax liability relating to
oil and natural gas acquisition, exploration and development costs deducted for
tax purposes in excess of financial statement DD&A have been revised to reflect
the 2001 results of operations as a reduction of the deferred income tax asset
relating to the net operating loss carry forward. This revision adjustment
resulted in a $1.4 million decrease in the deferred income tax asset relating to
net operating loss carry forward and a corresponding decrease to the deferred
income tax liability relating to oil and natural gas acquisition, exploration
and development costs deducted for tax purposes in excess of financial statement
DD&A. The net effect of these revisions resulted in no change to the net
deferred income tax liability as reflected on the December 31, 2001 balance
sheet.
The net deferred income tax liability is classified as follows:
AS OF DECEMBER 31,
----------------------------
2001 2002
------------ ------------
(IN THOUSANDS)
Other current assets $ -- $ 209
Deferred income taxes 5,021 7,666
------------ ------------
Net deferred income tax liability $ 5,021 $ 7,457
============ ============
Realization of the net deferred tax asset is dependent on the Company's
ability to generate taxable earnings in the future. The Company believes it will
generate taxable income in the NOL carryforward period. As such management
believes that it is more likely than not that its deferred tax assets will be
fully realized. The Company has net operating loss carryforwards totaling
approximately $7.0 million, which begin expiring in 2012.
6. LONG-TERM DEBT
At December 31, 2001 and 2002, long-term debt consisted of the following:
F-16
AS OF DECEMBER 31,
----------------------------
2001 2002
------------ ------------
(IN THOUSANDS)
Compass Facility $ 7,166 $ --
Hibernia Facility -- 8,500
Senior subordinated notes, related parties 24,039 25,478
Capital lease obligations 233 267
Non-recourse note payable to RMG 6,750 5,250
------------ ------------
38,188 39,495
Less: current maturities (2,107) (1,609)
------------ ------------
$ 36,081 $ 37,886
============ ============
On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30.0 million. It
is secured by substantially all of the Company's assets and is guaranteed by the
Company's subsidiary.
The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12.0 million, and the borrowing base as of October 31, 2002 was $13.0 million.
Each party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. Hibernia National Bank will reset the borrowing base amount
at each scheduled and each unscheduled borrowing base determination date. The
initial quarterly borrowing base reduction, which commenced on June 30, 2002,
was $1.3 million. The quarterly borrowing base reduction effective January 31,
2003 is $1.8 million.
On December 12, 2002, the Company entered into an Amended and Restated
Credit Agreement with Hibernia National Bank that provided additional
availability under the Hibernia Facility in the amount of $2.5 million which is
structured as an additional "Facility B" under the Hibernia Facility. As such,
the total borrowing base under the Hibernia Facility as of December 31, 2002 was
$15.5 million, of which $8.5 million is currently drawn. The Facility B bears
interest at LIBOR plus 3.375%, is secured by certain leases and working
interests in oil and natural gas wells and matures on April 30, 2003.
If the principal balance of the Hibernia Facility ever exceeds the
borrowing base as reduced by the quarterly borrowing base reduction (as
described above), the principal balance in excess of such reduced borrowing base
will be due as of the date of such reduction. Otherwise, any unpaid principal or
interest will be due at maturity.
If the principal balance of the Hibernia Facility ever exceeds any
re-determined borrowing base, the Company has the option within thirty days to
(individually or in combination): (i) make a lump sum payment curing the
deficiency; (ii) pledge additional collateral sufficient in Hibernia National
Bank's opinion to increase the borrowing base and cure the deficiency; or (iii)
begin making equal monthly principal payments that will cure the deficiency
within the ensuing six-month period. Such payments are in addition to any
payments that may come due as a result of the quarterly borrowing base
reductions.
For each tranche of principal borrowed under the revolving line of credit,
the interest rate will be, at the Company's option: (i) the Eurodollar Rate,
plus an applicable margin equal to 2.375% if the amount borrowed is greater than
or equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.
The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the credit facility.
The Hibernia Facility also places restrictions on additional indebtedness,
dividends to non-preferred stockholders, liens, investments, mergers,
acquisitions, asset dispositions, asset
F-17
pledges and mortgages, change of control, repurchase or redemption for cash of
the Company's common or preferred stock, speculative commodity transactions, and
other matters.
At December 31, 2001, amounts outstanding under the Compass Facility
totaled $7.2 million, with an additional $0.6 million available for future
borrowings. At December 31, 2002, amounts outstanding under the Hibernia
Facility totaled $8.5 million, with an additional $4.3 million available for
future borrowings. No amounts under the Compass Facility were outstanding at
December 31, 2002. At December 31, 2001, one letter of credit was issued and
outstanding under the Compass Facility in the amount of $0.2 million. At
December 31, 2002, one letter of credit was issued and outstanding under the
Hibernia Facility in the amount of $0.2 million.
On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company
("CCBM"), issued a non-recourse promissory note payable in the amount of $7.5
million to RMG as consideration for certain interests in oil and natural gas
leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly
principal payments of $0.1 million plus interest at 8% per annum commencing July
31, 2001 with the balance due December 31, 2004. The RMG note is secured solely
by CCBM's interests in the oil and natural gas leases in Wyoming and Montana. At
December 31, 2001 and 2002, the outstanding principal balance of this note was
$6.8 million and $5.3 million, respectively.
In December 2001, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.2 million. The lease
is payable in one payment of $11,323 and 35 monthly payments of $7,549 including
interest at 8.6% per annum. In October 2002, the Company entered a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. The Company has the option to acquire the equipment at the conclusion
of the lease for $1, under both leases. DD&A on the capital leases for the year
ended December 31, 2002 amounted to $28,000 and accumulated DD&A on the leased
equipment at December 31, 2002 amounted to $28,000.
In December 1999, the Company consummated the sale of $22.0 million
principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated
Notes") and $8.0 million of common stock and Warrants. The Company sold $17.6
million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal
amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212
shares of the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and
92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners,
LLC), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas
A.P. Hamilton, respectively. The Subordinated Notes were sold at a discount of
$0.7 million, which is being amortized over the life of the notes. Interest
payments are due quarterly commencing on March 31, 2000. The Company may elect,
for a period of up to five years, to increase the amount of the Subordinated
Notes for 60% of the interest which would otherwise be payable in cash. As of
December 31, 2001 and 2002, the outstanding balance of the Subordinated Notes
had been increased by $2.6 million and $3.9 million, respectively, for such
interest paid in kind.
The Company is subject to certain covenants under the terms under the
Subordinated Notes securities purchase agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director).
Estimated maturities of long-term debt are $1.6 million in 2003, $3.9
million in 2004, $8.5 million in 2005 and the remainder in 2007. At December 31,
2002, the Company believes it was in compliance with all of its debt covenants.
7. SEISMIC OBLIGATION PAYABLE
In 2002 the Company acquired (or obtained the right to acquire) certain
seismic data in its core areas in the Texas and Louisiana Gulf Coast regions.
Under the terms of the acquisition agreements, the Company is required to make
monthly payments of $0.1 million through March 2004 and additional payments
totalling $0.8 million are due in April 2004.
8. CONVERTIBLE PARTICIPATING PREFERRED STOCK:
In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and Warrants to purchase Carrizo 252,632 shares of common stock for an
aggregate purchase price of $6.0 million. The Company sold 40,000 and 20,000
shares of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon
Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock
is convertible into common stock by the investors at
F-18
a conversion price of $5.70 per share, subject to adjustments, and is initially
convertible into 1,052,632 shares of common stock. Dividends on the Series B
Preferred Stock will be payable in either cash at a rate of 8% per annum or, at
the Company's option, by payment in kind of additional shares of the same series
of preferred stock at a rate of 10% per annum. At December 31, 2002, the
outstanding balance of the Series B Preferred Stock has been increased by $0.5
million (5,294 shares) for dividends paid in kind. The Series B Preferred Stock
is redeemable at varying prices in whole or in part at the holders' option after
three years or at the Company's option at any time. The Series B Preferred Stock
will also participate in any dividends declared on the common stock. Holders of
the Series B Preferred Stock will receive a liquidation preference upon the
liquidation of, or certain mergers or sales of substantially all assets
involving, the Company. Such holders will also have the option of receiving a
change of control repayment price upon certain deemed change of control
transactions. The warrants have a five-year term and entitle the holders to
purchase up to 252,632 shares of Carrizo's common stock at a price of $5.94 per
share, subject to adjustments, and are exercisable at any time after issuance.
The warrants may be exercised on a cashless exercise basis.
Net proceeds of this financing were approximately $5.8 million and were
used primarily to fund the Company's ongoing exploration and development program
and general corporate purposes.
9. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.
The operations and financial position of the Company continue to be
affected from time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to restrictions
on oil and natural gas production, imports and exports, natural gas regulation,
tax increases, environmental regulations and cancellation of contract rights.
Both the likelihood and overall effect of such occurrences on the Company vary
greatly and are not predictable.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. The Company, along
with GMT and other partners, reached a final settlement with ExxonMobil on
February 11, 2003. Under the terms of the settlement, the Company recovered the
balance of its drilling costs (approximately $0.1 million) and certain other
costs and retained no further interest in the property. No reserves with respect
to these properties were included in the Company's reported proved reserves as
of December 31, 2001 and 2002.
During August 2001, the Company entered into an agreement whereby the
lessor will provide to the Company up to $0.8 million in financing for
production equipment utilizing capital leases. At December 31, 2002, two leases
in the amount of $0.5 million had been executed under this facility.
At December 31, 2002, the Company was obligated under a noncancelable
operating lease for office space. Rent expense for the years ended December 31,
2000, 2001 and 2002 was $0.2 million. The Company is obligated for remaining
lease payments of $0.2 million per year through December 31, 2004.
CCBM has an obligation to fund $2.5 million of drilling costs on behalf of
RMG. Through December 31, 2002, CCBM has satisfied $1.5 million of its drilling
obligations on behalf of RMG.
10. SHAREHOLDERS' EQUITY
The Company issued 9,016 and 113,306 shares of common stock valued at
$28,000 and $0.5 million for the years ended December
F-19
31, 2001 and 2002, respectively. Of these shares, 106,472 were issued as partial
consideration for the acquisition of interests in certain oil and natural gas
properties during 2002.
The following table summarizes information for the options outstanding at
December 31, 2002:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------- ----------------------
WEIGHTED
NUMBER OF AVERAGE WEIGHTED NUMBER OF WEIGHTED
OPTIONS REMAINING AVERAGE OPTIONS AVERAGE
OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
RANGE OF EXERCISE PRICES AT 12/31/02 LIFE IN YEARS PRICE AT 12/31/02 PRICE
- ------------------------ ----------- ------------- -------- ----------- --------
$1.75-2.25 718,870 7.04 $ 2.19 522,203 $ 2.17
$3.14-4.00 341,120 5.34 $ 3.21 279,453 $ 3.56
$4.01-5.00 420,500 8.88 $ 4.26 136,000 $ 4.24
$5.17-8.00 149,833 6.88 $ 6.71 110,555 $ 6.72
In June of 1997, the Company established the Incentive Plan of Carrizo Oil
& Gas, Inc. (the 'Incentive Plan"). In October 1995, the FASB issued SFAS No.
123, "Accounting for Stock-Based Compensation", which requires the Company to
record stock-based compensation at fair value. In December 2002, the FASB issued
SFAS No. 148, "Accounting for Stock Based Compensation - Transition and
Disclosure". The Company has adopted the disclosure requirements of SFAS No. 148
and has elected to record employee compensation expense utilizing the intrinsic
value method permitted under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees". The Company accounts for its
employees' stock-based compensation plan under APB Opinion No. 25 and its
related interpretations. Accordingly, any deferred compensation expense would be
recorded for stock options based on the excess of the market value of the common
stock on the date the options were granted over the aggregate exercise price of
the options. This deferred compensation would be amortized over the vesting
period of each option. Had compensation cost been determined consistent with
SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the
Company's net income (loss) and earnings per share would have been as follows:
2000 2001 2002
---------- ---------- ----------
(In thousands except per share amounts)
Net income as reported $ 11,985 $ 9,531 $ 4,790
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (498) (1,369) (872)
---------- ---------- ----------
Pro forma net income $ 11,487 $ 8,162 $ 3,918
========== ========== ==========
Net income per common share, as reported:
Basic $ 0.85 $ 0.68 $ 0.30
Diluted 0.74 0.57 0.26
Pro Forma net income per common share, as if
value method had been applied to all awards:
Basic $ 0.82 $ 0.58 $ 0.28
Diluted 0.71 0.49 0.24
The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in 2000, 2001 and 2002: risk free interest rate of 6.7%, 4.9% and
4.8%, respectively, expected dividend yield of 0%, expected life of 10 years and
expected volatility of 70.8%, 80.7% and 77.7% respectively.
The Company may grant options ("Incentive Plan Options") to purchase up to
1,850,000 shares under the Incentive Plan and has
F-20
granted options on 1,566,000 shares through December 31, 2002. Through December
31, 2002, 56,797 stock options had been exercised. A summary of the status of
the Company's stock options at December 31, 2000, 2001 and 2002 is presented in
the table below:
2000
-----------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- ---------- --------------
Outstanding at beginning of year 827,120 $ 6.01 $1.75 - $8.00
Granted (Incentive Plan Options) 425,000 $ 3.85 $2.20 - $8.00
Exercised (Pre-IPO Options) (3,000) $ 3.60 $3.60
Exercised (Incentive Plan Options) (40,697) $ 2.20 $2.00 - $6.00
Expired (Incentive Plan Options) (2,000) $ 3.50 $3.50
--------- ----------
Outstanding at end of year 1,206,423 $ 5.20 $2.00 - $8.00
========= ==========
Exercisable at end of year 316,388 $ 3.79
========= ==========
Weighted average of fair value of
options granted during the year $ 2.94
=========
2001
-----------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- ---------- --------------
Outstanding at beginning of year 1,206,423 $ 5.20 $1.75 - $8.00
Granted (Incentive Plan Options) 436,500 $ 4.34 $4.01 - $7.40
Exercised (Pre-IPO Options) (3,000) $ 3.60 $3.60
Exercised (Incentive Plan Options) (3,266) $ 2.13 $2.00 - $2.25
--------- ----------
Outstanding at end of year 1,636,657 $ 3.49 $1.75 - $8.00
========= ==========
Exercisable at end of year 625,701 $ 3.45
========= ==========
Weighted average of fair value of
options granted during the year $ 3.57
=========
2002
-----------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- ---------- --------------
Outstanding at beginning of year 1,636,657 $ 3.49 $1.75 - $8.00
Granted (Incentive Plan Options) 54,500 $ 4.31 $3.76 - $5.37
Exercised (Incentive Plan Options) (6,834) $ 2.12 $2.00 - $2.25
Expired (Incentive Plan Options) (54,000) $ 6.38 $1.75 - $8.00
--------- ----------
Outstanding at end of year 1,630,323 $ 3.35 $1.75 - $8.00
========= ==========
Exercisable at end of year 1,048,212 $ 3.28
========= ==========
Weighted average of fair value of
options granted during the year $ 3.57
==========
In March of 2000, the FASB issued Interpretation No. 44 "Accounting for
Certain Transactions involving Stock Compensation - an interpretation of APB No.
25" ("the Interpretation") which was effective July 1, 2000 and clarifies the
application of APB No. 25 for certain issues associated with the issuance or
subsequent modifications of stock compensation. For certain modifications,
including stock option repricings made subsequent to December 15, 1998, the
Interpretation requires that variable plan accounting be
F-21
applied to those modified awards prospectively from July 1, 2000. This requires
that the change in the intrinsic value of the modified awards be recognized as
compensation expense. On February 17, 2000, Carrizo repriced certain employee
and director stock options covering 348,500 shares of stock with a weighted
average exercise price of $9.13 to a new exercise price of $2.25 through the
cancellation of existing options and issuance of new options at current market
prices. Subsequent to the adoption of the Interpretation, the Company is
required to record the effects of any changes in its stock price over the
remaining vesting period through February 2010 on the corresponding intrinsic
value of the repriced options in its results of operations as compensation
expense until the repriced options either are exercised or expire. Stock option
compensation expense (benefit) relating to the repriced options for the years
ended December 31, 2001 and 2002 amounted to $(0.6 million) and $(0.1 million),
respectively.
11. RELATED-PARTY TRANSACTIONS
During the years ended December 31, 2001 and 2002, the Company incurred
drilling costs in the amount of $6.3 million and $2.9 million, respectively,
with Grey Wolf Drilling. Mr. Webster is the Chairman of the Board of Carrizo and
a member of the Board of Directors of Grey Wolf Drilling. It is management's
opinion that these transactions with Grey Wolf were performed at prevailing
market rates.
At December 31, 2002, the Company had outstanding related party accounts
receivable, payable and advances for joint operations balances of $1.2 million,
$1.2 million and $0.3 million, respectively.
During the years ended December 31, 2001 and 2002, the Company participated
in the drilling of two wells and one well, respectively, that were operated by a
subsidiary of Brigham Exploration Company. During the year ended December 31,
2002, Brigham Exploration Company ("Brigham") participated in the drilling of
two wells operated by the Company. Mr. Webster is a member of the Board of
Directors of Brigham. Mr. Webster is also a managing director of a merchant
banking affiliate of the beneficial owner of approximately 35% of the common
stock of the parent company of Brigham Oil and Gas, LP. The terms of the
operating agreements between the Company and Brigham are consistent with
standard industry practices.
During the year ended December 31, 2002, the Company sold a 2% working
interest in certain leases in Matagorda County, TX to Mr. Webster. The terms of
the sale were the same as other sales of working interests in the same leases to
industry partners.
See Notes 6 and 8 for a discussion of the Subordinated Notes and Series B
Preferred Stock, respectively, with parties that include members of the
Company's Board of Directors.
In December 1999, the Company reduced the exercise price of certain
warrants originally issued to affiliates of Enron Corp. in January 1998. There
were 250,000 warrants that expire in January 2005 to purchase the Company's
common stock at $4.00 per share outstanding as of December 31, 2001 and 2002.
12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
The Company's operations involve managing market risks related to changes
in commodity prices. Derivative financial instruments, specifically swaps,
futures, options and other contracts, are used to reduce and manage those risks.
The Company addresses market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. The
Company enters into swaps, options, collars and other derivative contracts to
hedge the price risks associated with a portion of anticipated future oil and
natural gas production. While the use of hedging arrangements limits the
downside risk of adverse price movements, it may also limit future gains from
favorable movements. Under these agreements, payments are received or made based
on the differential between a fixed and a variable product price. These
agreements are settled in cash at expiration or exchanged for physical delivery
contracts. The Company enters into the majority of its hedging transactions with
two counterparties and a netting agreement is in place with those
counterparties. The Company does not obtain collateral to support the agreements
but monitors the financial viability of counterparties and believes its credit
risk is minimal on these transactions. In the event of nonperformance, the
Company would be exposed to price risk. The Company has some risk of accounting
loss since the price received for the product at the actual physical delivery
point may differ from the prevailing price at the delivery point required for
settlement of the hedging transaction.
In November 2001, the Company had no-cost collars with an affiliate of
Enron Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas
production from December 2001 through December 2002. The value of these
derivatives at that time was $0.8 million. Because of Enron's financial
condition, the Company concluded that the derivatives contracts were no longer
effective and thus did not qualify for hedge accounting treatment. As required
by SFAS No. 133, the value of these derivative instruments as of November 2001
$(0.8 million) was recorded in accumulated other comprehensive income and will
be reclassified into earnings over the original term of the derivative
instruments. An allowance for the related asset totalling $0.8 million, net of
tax of $0.4 million, was charged to other expense. At December 31, 2001, $0.7
million, net of tax of $0.4 million, remained in accumulated other comprehensive
income related to the deferred gains on these derivatives. The remaining balance
in other comprehensive income was reported as oil and natural gas revenues in
2002 as the terms of the original derivative expired.
As of December 31, 2002, $0.4 million, net of tax of $0.2 million, remained
in accumulated other comprehensive income related to the valuation of the
Company's hedging positions.
F-22
Total oil purchased and sold under swaps and collars during 2000, 2001 and
2002 were 87,900 Bbls, 18,000 Bbls and 131,300 Bbls, respectively. Total natural
gas purchased and sold under swaps and collars in 2000, 2001 and 2002 were
1,590,000 MMBtu and 3,087,000 MMBtu and 2,314,000 MMBtu, respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$(1.5 million), $2.0 million and $(0.9 million) for 2000, 2001 and 2002,
respectively, and are included in oil and natural gas revenues.
At December 31, 2001 the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2002 the Company had the
following outstanding hedge positions:
December 31, 2002
- ----------------------------------------------------------------------------------------------------------------
Contract Volumes
------------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ------------------------------ --------------- -------------- -------------- --------------- ------------------
First Quarter 2003 27,000 $ 24.85
First Quarter 2003 36,000 $ 23.50 $26.50
First Quarter 2003 540,000 3.40 5.25
Second Quarter 2003 27,300 24.85
Second Quarter 2003 36,000 23.50 26.50
Second Quarter 2003 546,000 3.40 5.25
Third Quarter 2003 552,000 3.40 5.25
Fourth Quarter 2003 552,000 3.40 5.25
13. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following disclosures provide unaudited information required by SFAS
No. 69, "Disclosures About Oil and Gas Producing Activities".
COSTS INCURRED
Costs incurred in oil and natural gas property acquisition, exploration and
development activities are summarized below:
YEAR ENDED DECEMBER 31,
------------------------------------------
2000 2001 2002
------------ ------------ ------------
(IN THOUSANDS)
Property acquisition costs
Unproved $ 6,641 $ 12,607 $ 6,402
Proved 337 800 660
Exploration cost 7,843 18,356 $ 14,194
Development costs 1,361 3,065 2,351
------------ ------------ ------------
Total costs incurred(1) $ 16,182 $ 34,828 $ 23,607
============ ============ ============
- ----------
(1) Excludes capitalized interest on unproved properties of $3.6 million, $3.2
million and $3.1 million for the years ended December 31, 2000, 2001 and
2002, respectively.
OIL AND NATURAL GAS RESERVES
Proved reserves are estimated quantities of oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved oil and natural gas reserve quantities at December 31, 2001 and
2002, and the related discounted future net cash flows before income taxes are
based on estimates prepared by Ryder Scott Company and Fairchild & Wells, Inc.,
independent petroleum engineers. Such estimates have been prepared in accordance
with guidelines established by the Securities and Exchange Commission.
F-23
The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:
THOUSANDS OF BARRELS OF
OIL AND CONDENSATE
AT DECEMBER 31,
--------------------------------------------
2000 2001 2002
------------ ------------ ------------
Proved developed and undeveloped reserves -
Beginning of year 4,877 6,397 6,857
Discoveries and extensions 93 600 369
Revisions 1,625 20 1,568
Sales of oil and gas properties in place -- -- (12)
Production (198) (160) (401)
------------ ------------ ------------
------------ ------------ ------------
End of year 6,397 6,857 8,381
============ ============ ============
Proved developed reserves at beginning of year 1,070 1,017 1,158
============ ============ ============
Proved developed reserves at end of year 1,017 1,158 1,393
============ ============ ============
MILLIONS OF CUBIC FEET
OF NATURAL GAS
AT DECEMBER 31,
--------------------------------------------
2000 2001 2002
------------ ------------ ------------
Proved developed and undeveloped reserves -
Beginning of year 11,323 10,992 17,858
Purchases of oil and gas properties in place -- -- 585
Discoveries and extensions 4,179 12,560 3,280
Revisions 1,553 (1,262) (3,726)
Sales of oil and gas properties in place (603) -- (274)
Production (5,460) (4,432) (4,801)
------------ ------------ ------------
End of year 10,992 17,858 12,922
============ ============ ============
Proved developed reserves at beginning of year 10,680 10,351 13,754
============ ============ ============
Proved developed reserves at end of year- 10,351 13,754 12,826
============ ============ ============
STANDARDIZED MEASURE
The standardized measure of discounted future net cash flows relating to the
Company's ownership interests in proved oil and natural gas reserves as of
year-end is shown below:
YEAR ENDED DECEMBER 31,
------------------------------------------
2000 2001 2002
------------ ------------ ------------
(IN THOUSANDS)
Future cash inflows $ 266,725 $ 169,856 $ 305,087
Future oil and natural gas operating expenses 126,526 76,348 138,106
Future development costs 14,284 16,083 15,259
Future income tax expenses 25,242 5,822 32,133
------------ ------------ ------------
Future net cash flows 100,673 71,603 119,589
10% annual discount for estimating timing of cash flows 30,567 27,026 54,292
------------ ------------ ------------
Standard measure of discounted future net cash flows $ 70,106 $ 44,577 $ 65,297
============ ============ ============
F-24
Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Average prices used in computing year end 2000, 2001 and 2002 future cash flows
were $24.85, $17.71 and $29.16 for oil, respectively and $10.34, $2.76 and $4.70
for natural gas, respectively. Future operating expenses and development costs
are computed primarily by the Company's petroleum engineers by estimating the
expenditures to be incurred in developing and producing the Company's proved oil
and natural gas reserves at the end of the year, based on year end costs and
assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for tax
basis and availability of applicable tax assets. A discount factor of 10% was
used to reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties. An
estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the
time value of money and the risks inherent in reserve estimates.
CHANGE IN STANDARDIZED MEASURE
Changes in the standardized measure of future net cash flows relating to
proved oil and natural gas reserves are summarized below:
YEAR ENDED DECEMBER 31,
--------------------------------------------
2000 2001 2002
------------ ------------ ------------
(IN THOUSANDS)
Changes due to current-year operations -
Sales of oil and natural gas, net of oil
and natural gas operating expenses $ (21,893) $ (23,622) $ (23,377)
Extensions and discoveries 26,214 28,009 20,680
Purchases of oil and gas properties -- -- 888
Changes due to revisions in standardized variables
Prices and operating expenses 16,686 (38,472) 37,023
Income taxes (14,090) 13,367 (14,692)
Estimated future development costs (1,122) (1,070) 417
Revision of quantities 2,921 (1,109) 8,910
Sales of reserves in place (254) -- (191)
Accretion of discount 4,736 8,768 4,820
Production rates, timing and other 14,178 (11,400) (13,758)
------------ ------------ ------------
Net change 27,376 (25,529) 20,720
Beginning of year 42,730 70,106 44,577
------------ ------------ ------------
End of year $ 70,106 $ 44,577 $ 65,297
============ ============ ============
Sales of oil and natural gas, net of oil and natural gas operating
expenses, are based on historical pretax results. Sales of oil and natural gas
properties, extentions and discoveries, purchases of minerals in place and the
changes due to revisions in standardized variables are reported on a pretax
discounted basis, while the accretion of discount is presented on an after-tax
basis.
F-25
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
2002 FIRST SECOND THIRD FOURTH
-------- -------- -------- --------
Revenues $ 4,027 $ 6,780 $ 6,752 $ 9,243
Costs and expenses, net 3,883 5,706 5,576 6,847
-------- -------- -------- --------
Net income 144 1,074 1,176 2,396
Dividends and accretion 74 168 173 173
-------- -------- -------- --------
Net income available to
common shareholders $ 70 $ 906 $ 1,003 $ 2,223
======== ======== ======== ========
Basic net income per share(1) $ 0.00 $ 0.06 $ 0.07 $ 0.30
======== ======== ======== ========
Diluted net income per share(1) $ 0.00 $ 0.06 $ 0.06 $ 0.26
======== ======== ======== ========
2001
Revenues $ 8,727 $ 7,092 $ 6,162 $ 4,245
Costs and expenses, net 5,263 4,792 2,616 4,023
-------- -------- -------- --------
Net income $ 3,464 $ 2,300 $ 3,546 $ 222
======== ======== ======== ========
Basic net income per share(1) $ 0.25 $ 0.16 $ 0.25 $ 0.02
======== ======== ======== ========
Diluted net income per share(1) $ 0.21 $ 0.14 $ 0.22 $ 0.01
======== ======== ======== ========
(1) The sum of individual quarterly net income per common share may not agree
with year-to-date net income per common share as each period's computation
is based on the weighted average number of common shares outstanding during
that period.
F-26
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CARRIZO OIL & GAS, INC.
By: /s/ FRANK A. WOJTEK
-------------------------------------
Frank A. Wojtek
Chief Financial Officer, Vice President,
Secretary and Treasurer
Date: March 28, 2003.
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
NAME CAPACITY DATE
- -------------------------- ------------------------------- --------------
/s/ S. P. JOHNSON IV President, Chief Executive March 31, 2003
- -------------------------- Officer and Director (Principal
S. P. Johnson IV Executive Officer)
/s/ FRANK A. WOJTEK Chief Financial Officer, Vice March 31, 2003
- -------------------------- President, Secretary, Treasurer
Frank A. Wojtek and Director (Principal
Financial Officer and Principal
Accounting Officer)
/s/ STEVEN A. WEBSTER Chairman of the Board March 31, 2003
- --------------------------
Steven A. Webster
/s/ CHRISTOPHER C. BEHRENS Director March 31, 2003
- --------------------------
Christopher C. Behrens
/s/ BRYAN R. MARTIN Director March 31, 2003
- --------------------------
Bryan R. Martin
/s/ DOUGLAS A. P. HAMILTON Director March 31, 2003
- --------------------------
Douglas A. P. Hamilton
/s/ PAUL B. LOYD, JR. Director March 31, 2003
- --------------------------
Paul B. Loyd, Jr.
/s/ F. Gardner Parker Director March 31, 2003
- --------------------------
F. Gardner Parker
CERTIFICATIONS
PRINCIPAL EXECUTIVE OFFICER
I, S.P. Johnson, IV, certify that:
1. I have reviewed this annual report on Form 10-K of Carrizo Oil & Gas, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons fulfilling the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003 /s/ S.P. JOHNSON, IV
----------------------------------------
S.P. Johnson, IV,
President and Chief Executive Officer
PRINCIPAL FINANCIAL OFFICER
I, Frank A. Wojtek, certify that:
1. I have reviewed this annual report on Form 10-K of Carrizo Oil & Gas, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons fulfilling the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003 /s/ FRANK A. WOJTEK
----------------------------------------
Frank A. Wojtek
Chief Financial Officer
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
+2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa
Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton
and Frank A. Wojtek dated as of June 6, 1998 (Incorporated herein by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the Company (Incorporated herein by reference to Exhibit 3.1
to the Company's Annual Report on Form 10-K for the year ended December 31, 1998).
+3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915), Amendment No. 2
(Incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15,
1999) and Amendment No. 3 (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K
dated February 20, 2002).
+3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred
Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other
rights thereof (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated
February 20, 2002).
+4.1 -- Credit Agreement dated as of May 24, 2002 by and between Carrizo Oil & Gas, Inc., CCBM, Inc. and Hibernia
National Bank (Incorporated by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2002).
+4.2 -- Revolving Note by and between Carrizo Oil & Gas, Inc. and Hibernia National Bank dated May 24, 2002
(Incorporated by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 2002).
+4.3 -- Commercial Guarantee by and between CCBM, Inc. and Hibernia National Bank dated May 24, 2002 (Incorporated by
reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
+4.4 -- Stock Pledge and Security Agreement by and between Carrizo Oil & Gas, Inc. and Hibernia National Bank dated May
24, 2002 (Incorporated by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002).
+4.5 -- First Amendment to Credit Agreement dated July 9, 2002 to the Credit Agreement by and between Carrizo Oil & Gas,
Inc. and Hibernia National Bank dated May 24, 2002 (Incorporated by reference to Exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
4.6 -- Amended and Restated Credit Agreement dated as of December 12, 2002 by and between Carrizo Oil & Gas, Inc.,
CCBM, Inc. and Hibernia National Bank.
+4.7 -- Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage Program, dated May 1, 2001
(Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).
+4.8 -- Amendment No. 1 to the Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage
Program, dated June 1, 2001 (Incorporated herein by reference to Exhibit 4.2 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2001).
+4.9 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM, Inc. (Incorporated herein by reference to Exhibit
4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
+10.1 -- Amended and Restated Incentive Plan of the Company effective as of February 17, 2000 (Incorporated herein by
reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000).
+10.2 -- Amendment No. 1 to the Amended and Restated Incentive Plan of the Company (Incorporated by reference to Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
10.3 -- Amendment to the Amended and Restated Incentive Plan of the Company.
+10.4 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by reference to Exhibit 10.2
to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.5 -- Employment Agreement between the Company and Frank A. Wojtek (Incorporated herein by reference to Exhibit 10.3
to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.6 -- Employment Agreement between the Company and Kendall A. Trahan (Incorporated herein by reference to Exhibit 10.4
to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.7 -- Employment Agreement between the Company and Jeremy T. Greene (Incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
+10.8 -- Indemnification Agreement between the Company and each of its directors and executive officers (Incorporated
herein by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31,
1998).
+10.9 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster,
Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.8 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+10.10 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs.
Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.11 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by reference to Exhibit 99.3
to the Company's Current Report on Form 8-K dated January 8, 1998).
+10.12 -- Amended Enron Warrant Certificates (Incorporated herein by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K dated December 15, 1999).
+10.13 -- Securities Purchase Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to
Exhibit 99.1 to the Company's Current Report on Form 8-K dated December 15, 1999).
+10.14 -- Shareholders Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures,
L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K
dated December 15, 1999).
+10.15 -- Warrant Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P.,
Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.3 to
the Company's Current Report on Form 8-K dated December 15, 1999).
+10.16 -- Registration Rights Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon
Ventures, L.P. (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8- K dated
December 15, 1999).
+10.17 -- Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd Jr.,
Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated December 15,
1999).
+10.18 -- Compliance Sideletter dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures,
L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated December
15, 1999).
+10.19 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated December 15, 1999).
+10.20 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated December 15, 1999).
+10.21 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc. and CCBM, Inc., dated June 29, 2001
(Incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).
+10.22 -- Securities Purchase Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated
February 20, 2002).
+10.23 -- Shareholders' Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P., Paul B. Loyd, Jr.,
Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated February 20,
2002).
+10.24 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster
(including Warrant Certificate) (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report
on Form 8-K dated February 20, 2002).
+10.25 -- Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated
February 20, 2002).
+10.26 -- Compliance Sideletter dated February 20, 2002 between the Company and Mellon Ventures, L.P. (Incorporated herein
by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated February 20, 2002).
+10.27 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated February 20, 2002).
+10.28 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated February 20, 2002).
21.1 -- Subsidiaries of the Company.
23.1 -- Consent of Ernst & Young LLP
23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
23.3 -- Consent of Fairchild & Wells, Inc.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2002.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2002.
99.3 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers for CCBM, Inc. as of December 31, 2002.
99.4 -- Notice Regarding Consent of Arthur Andersen LLP.
- ----------
+ Incorporated by reference as indicated.
EX-4.6
3
h03362exv4w6.txt
AMENDED & RESTATED CREDIT AGREEMENT
EXHIBIT 4.6
================================================================================
AMENDED AND RESTATED CREDIT AGREEMENT
DATED AS OF
DECEMBER 12, 2002
BY AND AMONG
CARRIZO OIL & GAS, INC.,
A TEXAS CORPORATION
AS BORROWER
CCBM, INC.,
A DELAWARE CORPORATION
AS GUARANTOR
AND
HIBERNIA NATIONAL BANK
AS LENDER
================================================================================
TABLE OF CONTENTS
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS............................................1
Section 1.1. Defined Terms...............................................1
Section 1.2. Accounting Terms............................................15
ARTICLE II
COMMITMENT .................................................................15
Section 2.1. The Revolving Line of Credit................................15
Section 2.2. The Borrowing Base Amount...................................15
Section 2.3. Revolving Loans.............................................16
ARTICLE III
NOTES EVIDENCING THE LOANS..................................................18
Section 3.1. Revolving Note..............................................18
ARTICLE IV
INTEREST RATES..............................................................18
Section 4.1. Options.....................................................18
Section 4.2. Interest Rate Determination.................................19
Section 4.3. Conversion Option...........................................19
ARTICLE V
CHANGE OF CIRCUMSTANCES.....................................................20
Section 5.1. Unavailability of Funds or Inadequacy of Pricing............20
Section 5.2. Change in Laws..............................................20
Section 5.3. Increased Cost or Reduced Return............................20
Section 5.4. Breakage Costs..............................................22
i
ARTICLE VI
FEES........................................................................23
Section 6.1. Facility Fee................................................23
Section 6.2. Unused Fee..................................................23
Section 6.3. Letter of Credit Fee........................................24
Section 6.4. Engineering Fee.............................................24
ARTICLE VII
CERTAIN GENERAL PROVISIONS..................................................24
Section 7.1. Payments to the Lender......................................24
Section 7.2. No Offset, etc..............................................24
Section 7.3. Principal Amount of Revolving Note..........................24
Section 7.4. Rate Management Transactions................................25
Section 7.5. Calculation of Fees.........................................25
ARTICLE VIII
PREPAYMENTS.................................................................25
Section 8.1. Voluntary Prepayments.......................................25
Section 8.2. Mandatory Prepayment Resulting from a Quarterly Reduction...25
Section 8.3. Mandatory Prepayment Resulting from Overadvances............25
ARTICLE IX
SECURITY FOR THE INDEBTEDNESS...............................................26
Section 9.1. Security....................................................26
ARTICLE X
CONDITIONS PRECEDENT........................................................26
Section 10.1. Conditions Precedent to all Revolving Loans................26
ii
ARTICLE XI
REPRESENTATIONS AND WARRANTIES..............................................28
Section 11.1. Corporate Authority of the Borrower........................28
Section 11.2. Financial Statements.......................................28
Section 11.3. Title to Mortgaged Properties..............................29
Section 11.4. Litigation.................................................30
Section 11.5. Approvals..................................................30
Section 11.6. Required Insurance.........................................30
Section 11.7. Licenses...................................................30
Section 11.8. Adverse Agreements.........................................30
Section 11.9. Default or Event of Default................................30
Section 11.10. Employee Benefit Plans....................................30
Section 11.11. Investment Company Act....................................31
Section 11.12. Public Utility Holding Company Act........................31
Section 11.13. Regulations X, T and U....................................31
Section 11.14. Location of Offices and Records...........................31
Section 11.15. Information...............................................31
Section 11.16. Environmental Matters.....................................31
Section 11.17. Solvency of the Borrower..................................33
Section 11.18. Governmental Requirements.................................33
Section 11.19. Corporate Authority of the Guarantor......................33
Section 11.20. Chase Purchase Agreement..................................34
Section 11.21. Security Agreement........................................34
iii
Section 11.22. Survival of Representations and Warranties................34
ARTICLE XII
AFFIRMATIVE COVENANTS.......................................................34
Section 12.1. Financial Statements; Other Reporting Requirements.........34
Section 12.2. Notice of Default; Litigation; ERISA Matters...............36
Section 12.3. Maintenance of Existence, Properties and Liens.............36
Section 12.4. Taxes......................................................36
Section 12.5. Intentionally Deleted......................................36
Section 12.6. Compliance with Environmental Laws.........................36
Section 12.7. Further Assurances.........................................38
Section 12.8. Financial Covenants........................................38
Section 12.9. Operations.................................................39
Section 12.10. Change of Location........................................39
Section 12.11. Employee Benefit Plans....................................39
Section 12.12. Deposit and Operating Accounts............................39
Section 12.13. Production Proceeds.......................................39
Section 12.14. Field Audits; Other Information...........................39
Section 12.15. Insurance.................................................39
Section 12.16. Subsidiaries..............................................40
Section 12.17 Post Closing Requirements..................................40
ARTICLE XIII
NEGATIVE COVENANTS..........................................................40
Section 13.1. Limitations on Fundamental Changes.........................40
Section 13.2. Disposition of Assets......................................40
iv
Section 13.3. Repurchase of Stock; Restricted Payments...................41
Section 13.4. Encumbrances; Negative Pledge..............................41
Section 13.5. Debts, Guaranties and Other Obligations....................43
Section 13.6. Investments, Loan and Advances.............................44
Section 13.7. Other Agreements...........................................46
Section 13.8. Transactions with Affiliates...............................46
Section 13.9. Use of Revolving Loan Proceeds.............................46
Section 13.10. Commodity Transactions....................................47
Section 13.11. Intentionally Deleted.....................................47
Section 13.12. Payments on Permitted Subordinated Debt...................47
ARTICLE XIV
EVENTS OF DEFAULT...........................................................47
Section 14.1. Events of Default..........................................47
Section 14.2. Waivers....................................................49
Section 14.3. Notice to Delta Farms Lessors..............................50
ARTICLE XV
MISCELLANEOUS...............................................................50
Section 15.1. No Waiver; Modification in Writing.........................50
Section 15.2. Addresses for Notices......................................50
Section 15.3. Fees and Expenses..........................................51
Section 15.4. Security Interest and Right of Set-off.....................51
Section 15.5. Waiver of Marshaling.......................................52
Section 15.6. Governing Law..............................................52
v
Section 15.7. Consent to Loan Participation..............................52
Section 15.8. Consent to Syndication.....................................52
Section 15.9. Indemnity..................................................52
Section 15.10. Maximum Interest Rate.....................................53
Section 15.11. Waiver of Jury Trial; Submission to Jurisdiction..........54
Section 15.12. Severability..............................................54
Section 15.13. Headings..................................................55
Section 15.14. Confidentiality...........................................55
SCHEDULES
Schedule 10.1 No Material Adverse Effect
Schedule 11.1 No Violation
Schedule 11.3 Exceptions to Title
Schedule 11.4 Litigation
Schedule 13.4 Encumbrances
Schedule 13.5 Existing Indebtedness
Schedule 13.8 Transactions with Affiliates
vi
AMENDED AND RESTATED CREDIT AGREEMENT
THIS AMENDED AND RESTATED CREDIT AGREEMENT (the "Agreement") dated as of
December 12, 2002, by and among CARRIZO OIL & GAS, INC., a Texas corporation
(the "Borrower"), CCBM, INC., a Delaware corporation (the "Guarantor") and
HIBERNIA NATIONAL BANK, a national banking association (the "Lender").
R E C I T A L S:
1. The Borrower, the Guarantor, and the Lender are the parties to that
certain Credit Agreement dated as of May 24, 2002, as amended by that certain
First Amendment to Credit Agreement dated as of July 9, 2002 (as so amended, the
"Original Agreement"), wherein the Lender extended to the Borrower a revolving
line of credit in the maximum aggregate principal amount of $30,000,000.00.
2. The Borrower has requested that the Lender provide two (2) separate
credit facilities under the Commitment (as such term is defined in the Original
Agreement).
3. The Lender, subject to the terms and conditions of this Agreement, has
agreed to provide the separate credit facilities under the Commitment. It is the
intention of the parties that this Agreement shall amend and restate the
Original Agreement in its entirety. Novation is not intended.
NOW, THEREFORE, in consideration of the mutual covenants hereunder set
forth, the Borrower, the Guarantor, and Lender do hereby amend and restate the
Original Agreement and covenant, agree, and obligate themselves as follows:
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS
SECTION 1.1. DEFINED TERMS. As used in this Agreement, and unless the
context requires a different meaning, the following terms have the meanings
indicated:
"ADVANCE OR ADVANCES" shall mean a Loan or Loans by the Lender hereunder.
"AGREEMENT" shall mean this Amended and Restated Credit Agreement, as the
same may from time to time be amended, modified, supplemented, or restated
and in effect from time to time.
"BASE RATE" shall mean the base rate of interest established from time to
time by The Wall Street Journal, as the "prime" lending rate on corporate
loans posted by at least seventy-five percent (75%) of the nation's thirty
largest banks, and which is not necessarily the lowest rate charged by the
Lender, such rate to be adjusted automatically on and as of the effective
date of any change in such Base Rate.
Page 1 of 56
"BASE RATE INTEREST PERIOD" shall mean, with respect to any Base Rate Loan,
the period ending on the last day of each month, provided, however, that
(i) if any Base Rate Interest Period would end on a day which is not a
Business Day, such Interest Period shall be extended to the next succeeding
Business Day, (ii) in the case of an Advance under Facility A, if any Base
Rate Interest Period would otherwise end after the Facility A Termination
Date, such Interest Period shall end on the Facility A Termination Date,
and (iii) in the case of an Advance under Facility B, if any Base Rate
Interest Period would otherwise end after the Facility B Termination Date,
such Interest Period shall end on the Facility B Termination Date.
"BASE RATE LOANS" shall mean any Loan during any period which bears
interest based upon the Base Rate.
"BASE RATE MARGIN" shall mean, with respect to each Base Rate Loan under
Facility A:
(i) 0.375% whenever the Facility A Borrowing Base Usage under the
Revolving Line of Credit is greater than or equal to 90%; or
(ii) 0.000% whenever the Facility A Borrowing Base Usage under the
Revolving Line of Credit is less than 90%.
"BORROWER" shall mean Carrizo Oil & Gas, Inc., a Texas corporation,
together with its successors and assigns.
"BORROWING DATE" means the date elected by Borrower pursuant to Section
2.3.4. hereof for an Advance.
"BUSINESS DAY" means a day other than a Saturday, Sunday or legal holiday
for commercial banks under the laws of the State of Louisiana or a day on
which national banks are authorized to be closed in Lafayette, Louisiana.
"CAPITAL LEASE OBLIGATIONS" means any Debt represented by obligations under
a lease that is required to be capitalized for financial reporting purposes
in accordance with GAAP.
"CHASE PURCHASE AGREEMENT" means that certain Securities Purchase Agreement
dated as of December 15, 1999 among the Borrower, CB Capital Investors,
L.P., Mellon Ventures, L.P., Douglas A. P. Hamilton, Paul B. Loyd, Jr., and
Steven A. Webster, as amended from time to time.
"COLLATERAL" shall mean the Mortgaged Properties and any interest in any
kind of property or assets pledged, mortgaged or otherwise subject to an
Encumbrance in favor of the Lender pursuant to the Collateral Documents.
"COLLATERAL DOCUMENTS" shall collectively refer to the Mortgage, the
Security Agreement, the Guaranty, and any and all other documents now or
hereafter in which an Encumbrance is created on any property of the
Borrower or of any other Person to secure
Page 2 of 56
payment of the Indebtedness (or any part thereof) of the Borrower to the
Lender under this Agreement and the Revolving Note.
"COMMITMENT" shall mean the Lender's agreement to extend the Revolving Line
of Credit as set forth in the Agreement.
"COMPASS" shall mean Compass Bank, an Alabama state chartered banking
institution.
"CONSOLIDATED CURRENT ASSETS" shall mean the total of the Borrower's
consolidated current assets, including the amounts available for borrowing
under the Facility A Borrowing Base Amount and the Facility B Borrowing
Base Amount, determined in accordance with GAAP. Current assets will not
include the effects, if any, of marking to market Hedging Agreements
pursuant to SFAS No. 133.
"CONSOLIDATED CURRENT LIABILITIES" shall mean the total of the Borrower's
consolidated current liabilities, excluding outstanding principal amounts
due under the Commitment, determined in accordance with GAAP. Current
liabilities will not include (i) the effects, if any, of Hedging Agreements
pursuant to SFAS No. 133 and (ii) the Borrower's obligations under and in
connection with the Series B Preferred Stock issued by Borrower and the
Subordinated Promissory Notes.
"CONSOLIDATED TANGIBLE NET WORTH" shall mean, at any time, the
shareholder's equity of the Borrower on a consolidated basis, determined in
accordance with GAAP, less all unamortized Debt discount and expense,
unamortized deferred charges, goodwill, patents, trademarks, service marks,
trade names, copyrights and organization expense.
"CURRENT RATIO" shall mean the ratio of Consolidated Current Assets to
Consolidated Current Liabilities.
"DEBT" shall mean without duplication: (i) indebtedness for borrowed money;
(ii) the face amounts of all outstanding standby and commercial letters of
credit and bankers acceptances, matured or unmatured, issued on behalf of
Borrower; (iii) guaranties of the Debt of any other Person, whether direct
or indirect, whether by agreement to purchase the indebtedness of any other
Person or by agreement for the furnishing of funds to any other Person
through the purchase or lease of goods, supplies or services (or by way of
stock purchase, capital contribution, advance or loan) in each case for the
purpose of paying or discharging the Debt of any other Person; and (iv) the
present value of all obligations for the payment of rent or hire of
property of any kind (real or personal) under leases or lease agreements
required to be capitalized under GAAP; provided that in no event shall the
Borrower's obligations under and in connection with the Series B Preferred
Stock issued by Borrower constitute Debt.
"DEFAULT" shall mean an event which with the giving of notice or the lapse
of time (or both) would constitute an Event of Default hereunder.
"DEFENSIBLE TITLE" shall mean, with respect to the assets of the Borrower
(i) the title of the Borrower to such assets is free and clear of all
Encumbrances of any kind whatsoever
Page 3 of 56
(except to the extent permitted by the Loan Documents), and (ii) as to
those wells for which a "working interest" and a "net revenue interest" are
set forth on Schedule 11.3 (except to the extent disposed of or abandoned
in accordance with the Loan Documents), the Borrower is entitled to receive
the percentage of all hydrocarbons produced, saved and marketed from such
wells in an amount not less than the net revenue interest set forth
therein, without reduction, suspension or termination throughout the
duration of the productive life of such wells, and the Borrower is
obligated to bear the percentage of costs and expenses related to the
maintenance, development and operation of such wells in an amount not
greater than the working interest set forth on such Schedule, without
increase throughout the productive life of such wells, except increases
that also result in a proportionate increase in net revenue interest and as
set forth on such Schedule.
"DESIGNATED TITLE EXCEPTIONS" has the meaning given to such term in Section
11.3.
"DOLLARS" and "$" shall mean lawful money of the United States of America.
"EBITDA" means the Borrower's consolidated earnings before interest
expense, income taxes, depreciation, amortization, depletion, oil and gas
asset impairment write downs, lease impairment expense, gains and losses
from the sale of capital assets, and other non-cash charges.
"ENCUMBRANCES" shall mean any interest in property securing an obligation
owed to, or a claim by, a Person other than the owner of the Property,
whether such interest is based on common law, statute or contract. The term
"Encumbrance" shall also include reservations, exceptions, encroachments,
easements, rights-of-way, covenants, conditions, restrictions, leases and
other title exceptions and encumbrances affecting property. For the purpose
of the Agreement, the Borrower shall be deemed to be the owner of any
property which it has acquired or holds subject to a conditional sale
agreement or other arrangements pursuant to which title to the property has
been retained by or vested in some other Person for security purposes;
provided, however, that the term "Encumbrance" shall not include a trust or
similar arrangement established for the purpose of defeasing any
indebtedness pursuant to the terms evidencing or providing for the issuance
of such indebtedness but only to the extent that such defeasance is
permitted under this Agreement.
"ENVIRONMENTAL LAWS" shall mean any federal, state, local or tribal
statute, law, rule, regulation, ordinance, code, permit, consent, approval,
license, written policy or rule of common law now or hereafter in effect
and in each case as amended, and any judicial or administrative
interpretation thereof, including any judicial or administrative order,
injunction, consent decree or judgment, or other authorization or
requirement whenever promulgated, issued or modified, including the
requirement to register underground storage tanks, well plugging and
abandonment requirements, and oil and gas waste disposal requirements
relating to:
(i) emissions, discharges, spills, migration, movement, releases or
threatened releases of pollutants, contaminants, Hazardous Materials, or
hazardous or toxic materials
Page 4 of 56
or wastes into or onto soil, land, ambient air, surface water, ground
water, watercourses, publicly owned treatment works, drains, sewer systems,
wetlands or septic systems;
(ii) the use, treatment, storage, disposal, handling, manufacturing,
transportation, or shipment of Hazardous Materials or hazardous and/or
toxic wastes, material, products or by-products containing Hazardous
Materials (or of equipment or apparatus containing Hazardous Materials); or
(iii) otherwise relating to pollution or the protection of human
health or the environment, including, without limitation, the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980, 42 U.S.C.
Sections 9601 et seq., as amended, the Resource Conservation and Recovery
Act, 42 U.S.C. Sections 6901 et seq., as amended, the Hazardous Materials
Transportation Act, 49 U.S.C. Sections 1801 et seq., as amended, the Clean
Water Act, 33 U.S.C. Sections 1251 et seq., as amended, the Toxic
Substances Control Act, 15 U.S.C. Sections 2601 et seq., as amended, the
Clean Air Act, 42 U.S.C. Sections 7401 et seq., as amended, the federal
Water Pollution Control Act, 33 U.S.C. Section 1251 et seq., as amended,
the Safe Drinking Water Act, 42 U.S.C. Sections 300f et seq., as amended,
the Atomic Energy Act, 42 U.S.C. Sections 2011 et seq., as amended, the
Natural Gas Pipeline Safety Act of 1968, 49 U.S.C. Section 1671 et seq., as
amended, the Federal Insecticide, Fungicide and Rodenticide Act, 7 U.C.S.
Sections 136 et seq., as amended, and the Occupational Safety and Health
Act, 29 U.S.C. Sections 651 et seq., as amended, and all comparable
statutes of the States of Louisiana and Texas, and all comparable local
Governmental Requirements in such states, and other environmental,
conservation or protection laws in effect in any jurisdiction where any of
the Mortgaged Properties of the Borrower are located.
"ENVIRONMENTAL LIABILITIES" means with respect to any Person, any and all
liabilities, responsibilities, losses, sums paid in settlement of claims,
obligations, charges, actions (formal or informal), claims (including,
without limitation, claims for personal injury or for property damage),
liens, administrative proceedings, damages (including, without limitation,
loss or damage resulting from the occurrence of an Event of Default),
punitive damages, consequential damages, treble damages, penalties, fines,
monetary sanctions, interest, court costs, response and remediation costs,
stabilization costs, encapsulation costs, treatment, storage, or disposal
costs, groundwater monitoring or environmental sampling costs, other causes
of action and any other costs and expenses (including, without limitation,
reasonable attorneys', experts', and consultants' fees, costs of
investigation and feasibility studies and disbursements in connection with
any investigative, administrative or judicial proceeding), whether direct
or indirect, known or unknown, absolute or contingent, past, present or
future arising under, pursuant to or in connection with any Environmental
Law, or any other binding obligation of such Person requiring abatement of
pollution or protection of human health and the environment.
"ENVIRONMENTAL LIEN" means a Lien in favor of any Governmental Authority
for (i) any liability under Environmental Laws or (ii) damages arising
from, or costs incurred by
Page 5 of 56
such Governmental Authority in response to, a Release or threatened Release
of a Hazardous Materials into the environment.
"ERISA" shall mean the Employee Retirement Income Security Act of 1974, as
amended from time to time.
"EURODOLLAR BUSINESS DAY" shall mean any date other than Saturday, Sunday
or a day on which banking institutions are generally authorized or
obligated by law or executive order to close in the City of London,
England.
"EURODOLLAR INTEREST PERIOD" shall mean, with respect to any Eurodollar
Loan (i) initially, the period commencing on the date such Eurodollar Loan
is made and ending one (1), two (2), three (3), or six (6) months
thereafter as selected by the Borrower pursuant to Section 3.1.2., and
thereafter, each period commencing on the day following the last day of the
next preceding Interest Period applicable to such Eurodollar Loan and
ending one (1), two (2), three (3) or six (6) months thereafter, as
selected by the Borrower pursuant to Section 4.1.2., provided, however,
that (a) if any Eurodollar Interest Period would otherwise expire on a day
which is not a Business Day, such Interest Period shall expire on the next
succeeding Business Day unless the result of such extension would be to
extend such Interest Period into the next calendar month, in which case
such Interest Period shall end on the immediately preceding Business Day,
(b) if any Eurodollar Interest Period begins on the last Business Day of a
calendar month (or on a day for which there is no numerically corresponding
day in the calendar month at the end of such Interest Period) such Interest
Period shall end on the last Business Day of a calendar month, (c) in the
case of an Advance under Facility A, any Eurodollar Interest Period which
would otherwise expire after the Facility A Termination Date shall end on
the Facility A Termination Date, and (d) in the case of an Advance under
Facility B, any Eurodollar Interest Period which would otherwise expire
after the Facility B Termination Date shall end on the Facility B
Termination Date.
"EURODOLLAR LOAN" shall mean any Loan during any period which bears
interest at the Eurodollar Rate.
"EURODOLLAR MARGIN" shall mean, with respect to each Eurodollar Loan under
Facility A:
(i) 2.375% per annum whenever the Facility A Borrowing Base Usage
under the Revolving Line of Credit is greater than or equal to 90%;
(ii) 2.000% per annum whenever the Facility A Borrowing Base Usage
under the Revolving Line of Credit is greater than or equal to 50% but less
than 90%; or
(iii) 1.625% per annum whenever the Facility A Borrowing Base Usage
under the Revolving Line of Credit is less than 50%.
Page 6 of 56
"EURODOLLAR RATE" shall mean with respect to any Eurodollar Interest
Period, the offered rate for U.S. Dollar deposits of not less than
$1,000,000 as of 11:00 A.M. City of London, England time two (2) Eurodollar
Business Days prior to the first date of each Eurodollar Interest Period as
shown on the display designated as "British Bankers Assoc. Interest
Settlement Rates" on the Telerate system ("Telerate"), Page 3750 or Page
3740, or such other page or pages as may replace such pages on Telerate for
the purpose of displaying such rate, rounded upwards, if necessary to the
nearest 1/16% and adjusted for the maximum cost of reserves, if any.
Provided, however, that if such rate is not available on Telerate then such
offered rate shall be otherwise independently obtained by the Lender from
an alternate, substantially similar independent source available to the
Lender or shall be calculated by the Lender by substantially similar
methodology as that theretofore used to determine such offered rate in
Telerate.
"EVENT OF DEFAULT" shall mean individually, collectively and
interchangeably any of the Events of Default set forth below in Section
14.1. hereof.
"FACILITY A" shall mean a reducing revolving line of credit to the Borrower
under the Revolving Line of Credit, subject at all times to the Facility A
Borrowing Base Amount then in effect.
"FACILITY A BORROWING BASE AMOUNT" shall mean at any time the valuation of
the Borrower's Mortgaged Properties, projected oil and gas prices,
underwriting factors, and any other factors deemed relevant by the Lender
in its sole and complete discretion, all as evaluated and determined by the
Lender in its sole and complete discretion on a semi-annual basis on
October 31 and April 30. In addition, the Lender, in its sole and complete
discretion, may conduct one unscheduled Facility A Borrowing Base Amount
redetermination subsequent to each semi-annual redetermination, and the
Borrower, at its option may request (and the Lender shall promptly
thereafter perform) one Facility A Borrowing Base Amount redetermination
after each scheduled semi-annual redetermination by the Lender. The
Facility A Borrowing Base Amount also is subject to mandatory Quarterly
Reductions. The Lender is not obligated under any circumstances to
establish the Facility A Borrowing Base Amount based solely on oil and gas
valuation data for the Mortgaged Properties. The Facility A Borrowing Base
Amount, based on an effective date of December 12, 2002, is $13,000,000.00.
All such determinations and valuations shall be in accordance with the
Lender's normal practices and standards for oil and gas loans as may exist
at the particular time of determination and valuation. The sum of the
Facility A Borrowing Base Amount and the Facility B Borrowing Base Amount
shall never exceed $30,000,000.00.
"FACILITY A BORROWING BASE USAGE" shall mean the quotient of all amounts
outstanding pursuant to Advances under Facility A plus the face amount of
all outstanding Letters of Credit issued by the Lender under section 2.3.2.
hereof divided by the Facility A Borrowing Base Amount then in effect.
Page 7 of 56
"FACILITY A TERMINATION DATE" shall mean the earlier to occur of (i)
January 31, 2005 or (ii) the date of termination of the Commitment pursuant
to Article XIV hereof.
"FACILITY B" shall mean a revolving line of credit to the Borrower under
the Revolving Line of Credit, subject at all times to the Facility B
Borrowing Base Amount then in effect.
"FACILITY B BORROWING BASE AMOUNT" shall mean $2,500,000.00. The Lender is
not under any obligation to renew Facility B. However, in the event the
Lender elects to renew Facility B, the parties agree and understand that
the Facility B Borrowing Base Amount shall be determined and established by
the Lender in its sole and completion discretion. The sum of the Facility A
Borrowing Base Amount and the Facility B Borrowing Base Amount shall never
exceed $30,000,000.00.
"FACILITY B TERMINATION DATE" shall mean the earlier to occur of (i) April
30, 2003 or (ii) the date of termination of the Commitment pursuant to
Article XIV hereof.
"GAAP" shall mean, at any time, accounting principles generally accepted in
the United States as then in effect.
"GOVERNMENTAL AUTHORITY" shall mean any nation or government, any state or
other political subdivision thereof, or entity exercising executive,
legislative, judicial, regulatory or administrative functions of or
pertaining to government.
"GOVERNMENTAL REQUIREMENT" shall mean any applicable state, federal or
local law, statute, ordinance, code, rule, regulation, order or decree.
"GUARANTOR" means CCBM, Inc., a Delaware corporation, and its successors
and assigns.
"GUARANTY" means that certain Commercial Guaranty of even date with the
Original Agreement by the Guarantor in favor of the Lender, as amended
and/or restated from time to time and in effect.
"HAZARDOUS MATERIALS" means (1) hazardous materials, hazardous wastes, and
hazardous substances including, but not limited to, those substances,
materials and wastes listed in the United States Department of
Transportation Hazardous Materials Table, 49 C.F.R. Section 172.101, as
amended, or listed by the federal Environmental Protection Agency as
hazardous substances under or pursuant to 40 C.F.R. Part 302, as amended,
or substances, materials, contaminants or wastes which are or become
regulated under any Environmental Law, including without limitation, those
substances, materials, contaminants or wastes as defined in the following
statutes and their implementing regulations: the Hazardous Materials
Transportation Act, 49 U.S.C. Section 1801 et seq., as amended, the
Resource Conservation and Recovery Act, 42 U.S.C. Section 6901 et seq., as
amended, the Comprehensive Environmental Response, Compensation and
Liability Act, 42 U.S.C. Section 9601 et seq., as amended, the Toxic
Substances Control Act, 15 U.S.C.
Page 8 of 56
Section 2601 et seq., as amended, the Clean Air Act, 42 U.S.C. Section 7401
et seq., as amended, the federal Water Pollution Control Act, 33 U.S.C.
Section 1251 et seq., as amended, the Occupational Safety and Health Act, 2
U.S.C. Section 651 et seq., as amended, the Safe Drinking Water Act, 42
U.S.C. Section 300f et seq., as amended and the Natural Gas Pipeline Safety
Act of 1968, 49 U.S.C. Section 1671 et seq., as amended; (2) all
substances, materials, contaminants or wastes listed in all comparable
statutes of the States of Louisiana and Texas and in comparable local
Requirements of Law in such states; (3) acid gas, sour water streams or
sour water vapor streams containing hydrogen sulfide or other forms of
sulphur, sodium hydrosulfide and ammonia; (4) Hydrocarbons; (5) natural
gas, synthetic gas, and any mixtures thereof; (6) asbestos and/or any
material which contains 1% or more, by weight, of any hydrated mineral
silicate, including but not limited to chrysotile, amosite, crocidolite,
tremolite, anthophylite and/or actinolite, whether friable or non-friable;
(7) PCB's, or PCB containing materials or fluids; (8) radon; (9) naturally
occurring radioactive material, radioactive substances or waste; (10) salt
water and other oil and gas wastes and (11) any other hazardous or noxious
substance, material, pollutant, emission, or solid, liquid or gaseous
waste.
"HEDGING AGREEMENT" means (a) any interest rate or currency swap, rate cap,
rate floor, rate collar, forward agreement, or other exchange or rate
protection agreement or any option with respect to any such transaction and
(b) any swap agreement, cap, floor, collar, exchange transaction, forward
agreement, or other exchange or protection agreement relating to
Hydrocarbons or any option with respect to any such transaction.
"HYDROCARBONS" means oil, gas, casing head gas, condensate, distillate,
liquid hydrocarbons, gaseous hydrocarbons and all products separated,
settled and dehydrated therefrom and all products refined therefrom,
including, without limitation, kerosene, liquefied petroleum gas, refined
lubricating oils, diesel fuel, drip gasoline, natural gasoline, helium,
sulphur and all other materials.
"INDEBTEDNESS" shall mean, at any time, all obligations, indebtedness, and
liabilities, whether now existing or arising in the future, of the Borrower
to the Lender pursuant to a Hedging Agreement or other commodity or price
management transaction, the Reimbursement Obligations, obligations of the
Borrower under Rate Management Transactions (including all renewals,
extensions, modifications, and substitution thereof and therefor) and all
cancellations, buy backs, reversals, terminations, or assignments of Rate
Management Transactions, and the indebtedness of the Borrower evidenced by
the Revolving Note (including Advances under Facility A and Facility B),
including principal, interest, costs, expenses and reasonable attorneys'
fees and all other fees and charges, together with all commitment fees and
other indebtedness and costs and expenses for which the Borrower is
responsible under this Agreement or under any of the Related Documents. In
addition, the word "Indebtedness" also includes, any and all other loans,
extensions of credit, obligations, debts and liabilities of the Borrower,
plus interest thereon, that may now and in the future be owed to or
incurred in favor of the Lender, as well as all claims by the Lender
against the Borrower, whether existing now or later; whether they are
voluntary or involuntary, due or to become due, direct or indirect or by
Page 9 of 56
way of assignment, determined or undetermined, absolute or contingent,
liquidated or unliquidated; whether the Borrower may be liable individually
or jointly with others, of every nature and kind whatsoever, in principal,
interest, costs, expenses and reasonable attorneys' fees and all other fees
and charges; whether the Borrower may be obligated as principal obligor,
guarantor, surety, accommodation party or otherwise.
"INTEREST PAYMENT DATE" shall mean (i) for a Base Rate Loan, the last
Business Day of each month such Loan is outstanding beginning June 30, 2002
and (ii) for a Eurodollar Loan, the last Eurodollar Business Day of each
Eurodollar Interest Period for such Loan, and during any Eurodollar
Interest Period of six (6) months, the Eurodollar Business Day occurring
three (3) months after the commencement of such Interest Period.
"INTEREST PERIOD" shall mean any Base Rate Interest Period or Eurodollar
Interest Period.
"LEASES" shall mean all present and future oil, gas and mineral leases or
interests therein now owned or hereafter acquired by the Borrower that form
part of the Mortgaged Properties.
"LENDER" means Hibernia National Bank, and its successors and assigns.
"LETTERS OF CREDIT" shall mean the letters of credit issued by the Lender
pursuant to Section 2.3.2. hereof.
"LIABILITIES" shall mean, as to any Person, all indebtedness, liabilities
and obligations of such Person, whether matured or unmatured, liquidated or
unliquidated, primary or secondary, direct or indirect, absolute, fixed or
contingent, and whether or not required to be considered pursuant to GAAP.
"LOANS" shall mean, collectively, the Revolving Loans.
"LOAN DOCUMENTS" shall mean this Agreement, the Revolving Note, the
Guaranty, the Collateral Documents and any other Related Documents.
"MATERIAL ADVERSE EFFECT" shall mean, with respect to the Borrower and/or
the Guarantor, as the case may be, an event which causes a material adverse
effect on the business, assets, operations or condition (financial or
otherwise) of such Person.
"MAXIMUM RATE" shall mean, at any particular time in question, the maximum
non-usurious rate of interest which under applicable law may then be
charged on the Loans, the Reimbursement Obligations or any other
obligations hereunder. If such Maximum Rate changes after the date hereof,
the Maximum Rate shall be automatically increased or decreased, as the case
may be, without notice to Borrower from time to time as the effective date
of each change in such Maximum Rate.
Page 10 of 56
"MEMORANDUM" shall mean that certain Memorandum of Subordination Agreement
dated as of December 15, 1999, by and among the parties to the Chase
Purchase Agreement and Compass.
"MORTGAGE" shall mean (a) those certain mortgages, security agreements,
and/or deeds of trust by the Borrower in favor of Compass, as restated in
favor of the Lender pursuant to (i) Amended and Restated Mortgage,
Collateral Assignment, Security Agreement, and Financing Statement by
Borrower in favor of the Lender dated of even date with the Original
Agreement, as the same may be amended, supplemented, and/or restated from
time to time and in effect, and (ii) Deed of Trust, Mortgage, Security
Agreement, Fixture Filing, and Financing Statement by the Borrower in favor
of the Lender dated of even date with the Original Agreement, as the same
may be amended, supplemented and/or restated from time to time and in
effect, (b) that certain Mortgage, Collateral Assignment, Security
Agreement and Financing Statement by the Borrower in favor of the lender
dated December 12, 2002, as the same may be amended, supplemented, and/or
restated from time to time and in effect, and (c) that certain Deed of
Trust, Mortgage, Security Agreement, Fixture Filing, and Financing
Statement by the Borrower in favor of the Lender dated December 12, 2002,
as the same may be amended, supplemented and/or restated from time to time
and in effect.
"MORTGAGED PROPERTIES" shall mean the property and interests of the
Borrower encumbered by the Mortgage.
"NON-RECOURSE INDEBTEDNESS" shall mean Obligations owed by the Guarantor to
Rocky Mountain Gas, Inc., and Obligations of the Borrower and/or the
Guarantor for which the Borrower and/or the Guarantor, as the case may be,
are not personally liable for payment of the Obligations.
"NOTE" shall mean the Revolving Note as said promissory note may be renewed
or extended, together with all other promissory note or notes given in
renewal, substitution, or as a refinancing of any part of the indebtedness
evidenced thereby.
"OBLIGATIONS" of any Person means Liabilities in any of the following
categories: (a) Liabilities for borrowed money; (b) Liabilities
constituting an obligation to pay the deferred purchase price of property
or services; (c) Liabilities evidenced by a bond, debenture, note or
similar instrument; (d) Liabilities which (i) would under GAAP be shown on
such Person's balance sheet as a liability, and (ii) are payable more than
one year from the date of creation thereof (other than reserves for taxes
and reserves for contingent obligations); (e) Liabilities arising under
Hedging Agreements; (f) Liabilities constituting principal under leases
capitalized in accordance with GAAP, (g) Liabilities arising under
conditional sales or other title retention agreements; (h) Liabilities
owing under direct to indirect guaranties of Obligations of any other
Person or otherwise constituting obligations to purchase or acquire or to
otherwise protect or insure a creditor against loss in respect of
Obligations of any other Person (such as obligations under working capital
maintenance agreements, agreements to keep-well, or agreements to purchase
Obligations, assets, goods, securities or services), but excluding
endorsements
Page 11 of 56
in the ordinary course of business of negotiable instruments in the course
of collection; (i) Liabilities (for example, repurchase agreements and
sale/leaseback agreements) consisting of an obligation to purchase or lease
securities or other property, if such Liabilities arises out of or in
connection with the sale of the same or similar securities or property; (j)
Liabilities with respect to letters of credit or applications or
reimbursement agreements therefor; (k) Liabilities with respect to payments
received in consideration of oil, gas or other minerals yet to be acquired
or produced at the time of payment (including obligations under
"take-or-pay" contracts to deliver gas in return for payments already
received and the undischarged balance of any production payment created by
such Person or for the creation of which such Person directly or indirectly
received payment); or (l) Liabilities with respect to other obligations to
deliver goods or services in consideration of advance payments therefor;
provided, however, that the "Obligations" of any Person shall not include
Liabilities that were incurred by such Person on ordinary trade terms to
vendors, suppliers, or other Persons providing goods and services for use
by such Person in the ordinary course of its business, unless and until
such Liabilities are outstanding more than 120 days past original invoice
or billing date therefor.
"ORIGINAL AGREEMENT" shall mean that certain Credit Agreement dated as of
May 24, 2002 by and among the Borrower, the Guarantor, and the Lender, as
amended by First Amendment thereto dated as of July 9, 2002.
"PERMITTED ENCUMBRANCES" shall have the meaning ascribed to such term in
Section 13.4. hereof.
"PERSON" shall mean an individual or a corporation, partnership, trust,
joint venture, incorporated or unincorporated association, joint stock
company, government, or an agency or political subdivision thereof, or
other entity of any kind.
"PURCHASE MONEY INDEBTEDNESS" means Debt incurred to finance the
acquisition, construction or improvement of any fixed or capital assets,
including Debt assumed in connection with the acquisition of any such
assets or secured by an Encumbrance on any such assets prior to the
acquisition thereof, and any extension, renewal or replacement of any such
Debt.
"QUARTERLY REDUCTION" shall mean each quarterly reduction, if any, to the
Facility A Borrowing Base Amount on the last day of each July, October,
January, and April based upon Lender's redetermination of the Facility A
Borrowing Base Amount. All such determinations and valuations shall be in
accordance with the Lender's normal practices and standards for oil and gas
loans as may exist at the particular time of determination and valuation.
The Quarterly Reduction will be $1,750,000.00 beginning January 31, 2003.
Thereafter, the Lender will establish the Quarterly Reduction.
"RATE MANAGEMENT TRANSACTION" means any transaction (including an agreement
with respect thereto) now existing or hereafter entered into between the
Borrower and the Lender or affiliate thereof which is (i) an interest rate
protection agreement, foreign currency exchange agreement or other interest
or interest rate hedging agreement entered
Page 12 of 56
into in the ordinary course and not for speculative purposes or (ii) a
commodity price hedging agreement or arrangement entered into in the
ordinary course and not for speculative purposes.
"REIMBURSEMENT OBLIGATIONS" shall mean at any time, the obligations of
Borrower in respect of all Letters of Credit then outstanding to reimburse
amounts paid by the Lender in respect of any drawing or drawings under a
Letter of Credit.
"RELATED DOCUMENTS" shall mean and include individually, collectively,
interchangeably and without limitation all promissory notes, credit
agreements, loan agreements, guaranties, security agreements, mortgages,
collateral mortgages, deeds of trust, and all other instruments and
documents, whether now or hereafter existing, executed in connection with
the Indebtedness.
"RELEASE" means any release, spill, emission, leak, injection, deposit,
disposal, discharge, dispersal, leaching or migration of any Hazardous
Materials into the environment or into or out of any real property of
Borrower, including the movement of Hazardous Materials through or in the
air, soil, surface water, groundwater and/or land which could reasonably be
expected to form the basis of an Environmental Liability against Borrower.
"REMEDIAL ACTION" means any action to (i) clean up, remove, treat or in any
other way address Hazardous Materials in the environment, (ii) prevent the
Release or threat of Release or minimize the further Release of Hazardous
Materials so they do not mitigate or endanger or threaten to endanger
public health or welfare or the environment or (iii) perform pre-remedial
studies and investigations and post-remedial monitoring and care.
"REQUEST FOR ADVANCE" shall mean the Borrower's request for a Revolving
Loan.
"REVOLVING LOANS" shall mean all loans under Facility A and Facility B made
by the Lender under the Revolving Note to the Borrower in accordance with
and subject to the terms of the Commitment.
"REVOLVING LINE OF CREDIT" shall mean a reducing revolving line of credit
to the Borrower pursuant to the Commitment by the Lender, subject at all
times to (i) the Facility A Borrowing Base Amount then in effect, in the
case of Advances under Facility A, or (ii) the Facility B Borrowing Base
Amount then in effect, in the case of Advances under Facility B.
"REVOLVING NOTE" means the Revolving Note dated May 24, 2002 in the
principal amount of $30,000,000.00 by Borrower payable to the order of
Lender, which was issued to Lender to evidence the indebtedness to the such
Lender arising by reason of Advances, together with all allonges thereto
and all modifications, renewals and extensions thereof or of any part
thereof.
Page 13 of 56
"SECURITY AGREEMENT" shall mean that certain Stock Pledge and Security
Agreement executed by the Borrower in favor of the Lender of even date with
the Original Agreement, affecting 100% of the outstanding stock of the
Guarantor, as the same may be amended, supplemented, and/or restated from
time to time and in effect.
"SOLVENT" shall mean, when used with respect to any Person on a particular
day, that on such date (i) the fair value of the property of such Person is
greater than the total amount of liabilities, including without limitation,
contingent liabilities, of such person, (ii) the present fair salable value
of the assets of such person is not less than the amount that will be
required to pay the probable liability of such Person on its debts as they
become absolute and matured, (iii) such Person is able to realize upon its
assets and pay its debts and other liabilities, contingent obligations and
other commitments as they mature in the ordinary course of business, (iv)
such Person does not intend to, and does not believe that it will, incur
debts and liabilities beyond such Person's ability to pay as such debts and
liabilities mature, and (v) such Person is not engaged in business or a
transaction, and is not about to engage in business or a transaction, for
which such Person's property would constitute unreasonably small capital
after giving due consideration to the prevailing practice in the industry
in which such person is engaged. In computing the amount of contingent
liabilities at any time, it is intended that such liabilities will be
computed at the amount which, in light of all of the facts and
circumstances existing at such time, represents the amount that can be
reasonably expected to become an actual or matured liability.
"SUBJECT BUSINESS" shall mean the exploration, development, exploitation
and production of natural gas and crude oil.
"SUBORDINATED PROMISSORY NOTES" shall mean those certain promissory notes
dated December 15, 1999 executed by the Borrower pursuant to the Chase
Purchase Agreement, together with all modifications, renewals and
extensions thereof or any part thereof.
"SUBSIDIARIES" shall mean at any date with respect to any Person all the
corporations of which such Person at such date, directly or indirectly,
owns 50% or more of the outstanding capital stock (excluding directors'
qualifying shares), and "SUBSIDIARY" means any one of the Subsidiaries.
"TOTAL OUTSTANDINGS" shall mean as of any date, without duplication, the
sum of (i) the total principal balance outstanding on the Revolving Note,
plus (ii) the total face amount of all outstanding Letters of Credit plus
(iii) the total of all Reimbursement Obligations.
"TRANCHE" shall mean a Eurodollar Loan for a particular Interest Period
and/or a Base Rate Loan.
"UCC" shall mean the Uniform Commercial Code-Secured Transactions (La. R.S.
10:9-101 et seq.) in the State of Louisiana, as amended from time to time,
provided that if by reason of mandatory provisions of law, the perfection
or effect of perfection or
Page 14 of 56
non-perfection of the Lender's Encumbrances against the Collateral is
governed by the Uniform Commercial Code as in effect in a jurisdiction
other than the State of Louisiana, then "UCC" means the Uniform Commercial
Code as the same may be amended from time to time and in effect in such
other jurisdiction.
SECTION 1.2. ACCOUNTING TERMS. All accounting terms not specifically
defined herein shall be construed in accordance with GAAP, and all financial
data submitted pursuant to this Agreement shall be prepared in accordance with
GAAP.
ARTICLE II
COMMITMENT
SECTION 2.1. THE REVOLVING LINE OF CREDIT. Subject to the terms and
conditions of this Agreement, the Lender agrees (a) to extend credit to the
Borrower during the period from the date hereof until the Facility A Termination
Date, by making Revolving Loans under Facility A to the Borrower from time to
time, provided, however, that at no time shall the sum of the aggregate
principal amount of such Revolving Loans to the Borrower made under Facility A
at such time outstanding exceed the Facility A Borrowing Base Amount then in
effect, and (b) to extend credit to the Borrower during the period from the date
hereof until the Facility B Termination Date, by making Revolving Loans under
Facility B to the Borrower from time to time, provided, however, that at no time
shall the aggregate principal amount of such Revolving Loans made under Facility
B exceed the Facility B Borrowing Base Amount.
SECTION 2.2. THE BORROWING BASE AMOUNTS.
(A) The Facility A Borrowing Base Amount is hereby fixed at $13,000,000.00.
It is agreed and understood that the Lender will re-evaluate and re-establish
the Facility A Borrowing Base Amount on a semi-annual basis on each October 31
and April 30. The Facility A Borrowing Base Amount also is subject, in the
Lender's sole and complete discretion, to one (1) unscheduled redetermination of
the Facility A Borrowing Base Amount after each scheduled semi-annual
redetermination by the Lender. The Borrower, at its option, also may request
(and the Lender shall promptly thereafter perform) one (1) unscheduled Facility
A Borrowing Base Amount redetermination after each scheduled semi-annual
redetermination by the Lender. The parties agree and understand that the
Facility A Borrowing Base Amount is further subject to Quarterly Reductions
based upon the Lender's re-evaluation of the Facility A Borrowing Base Amount at
such time.
(B) The Facility B Borrowing Base Amount is hereby fixed at $2,500,000.00.
The Lender is not under any obligation to renew Facility B. However, in the
event the Lender elects to renew Facility B, the parties agree and understand
that the Facility B Borrowing Base Amount shall be determined and established by
the Lender in its sole and completion discretion.
Page 15 of 56
SECTION 2.3. REVOLVING LOANS.
SECTION 2.3.1. REVOLVING LOANS. Subject to the terms and conditions of this
Agreement, the Lender agrees to make Revolving Loans under Facility A and
Facility B to the Borrower from time to time under the Revolving Line of Credit
in accordance with the terms of this Agreement. Within the limits set forth
herein, the Borrower may borrow from the Lender hereunder, repay any and all
such Revolving Loans as hereinafter provided and reborrow hereunder; provided,
however, each Revolving Loan shall be in an amount not less than $250,000.00 The
Borrower's obligation to repay the Revolving Loans (under both Facility A and
Facility B) made by the Lender shall be evidenced by the Revolving Note.
Revolving Loans under Facility A shall bear interest, at Borrower's option, at
the Base Rate plus the Base Rate Margin or the Eurodollar Rate plus the
Eurodollar Margin. Revolving Loans under Facility B shall bear interest, at
Borrower's option at the Base Rate plus 1.375% or the Eurodollar Rate plus
3.375%. The total number of Tranches under the Revolving Line of Credit which
may be outstanding at any time hereunder shall never exceed five (5) Tranches,
whether such Tranches are under Facility A or Facility B, or are Base Rate
Loans, Eurodollar Loans, or a combination thereof.
SECTION 2.3.2. LETTERS OF CREDIT. On the terms and conditions hereinafter
set forth, the Lender shall from time to time during the period beginning on the
date of this Agreement and ending on the Facility A Termination Date upon
request of Borrower issue standby letters of credit for the account of the
Borrower for general corporate purposes in such amounts as the Borrower may
request but not to exceed in the aggregate face amount at any time outstanding
the sum of $5,000,000.00 (subject to the additional limitations on the amounts
thereof set forth in Section 2.3.3. below), each such letter of credit shall
have an expiry date no later than the earlier of one (1) year from the date of
issuance or the Facility A Termination Date, whichever occurs first (the
"Letters of Credit"). On each day during the period while any such Letter of
Credit is issued and outstanding in accordance with the provisions of this
Agreement, the sum of the face amount of each such outstanding Letter of Credit
shall be treated as an Advance under Facility A. Borrower hereby unconditionally
agrees to pay and reimburse the Lender for the amount of each payment under any
Letter of Credit that is in substantial compliance with the provisions of such
Letter of Credit at or prior to the date on which payment is made by the Lender
to the beneficiary thereunder, without presentment, demand, protest or other
formalities of any kind. Upon receipt from any beneficiary of any Letter of
Credit of any demand for payment under such Letter of Credit, the Lender shall
promptly notify the Borrower of the demand and the date upon which such payment
is to be made by the Lender to such beneficiary in respect of such demand.
Forthwith upon receipt of such notice from the Lender, Borrower shall advise the
Lender whether or not it intends to borrow under Facility A to finance its
obligations to reimburse the Lender, and if so, submit a Request for Advance as
provided in Section 2.3.4. hereof. The parties agree and understand that all
outstanding letters of credit issued by the Lender under the Original Agreement,
which outstanding letters of credit have a total face amount of $224,000.00,
shall be treated as issued Letters of Credit pursuant to the provisions of
Section 2.3 of this Agreement.
SECTION 2.3.3. PROCEDURE FOR OBTAINING LETTERS OF CREDIT. The amount and
date of issuance, renewal, extension or reissuance of a Letter of Credit
pursuant to the Section 2.3.2. shall be designated by the Borrower's written
request delivered to the Lender at least three (3) Business Days prior to the
date of such issuance, renewal, extension or reissuance. Concurrently
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with or promptly following the delivery of the request for a Letter of Credit,
the Borrower shall execute and deliver to the Lender an application and
agreement with respect to the Letter of Credit, said application and agreement
to be in the form customarily used by the Lender. The terms of this Agreement
shall control in case of any conflict between the terms of this Agreement and
the Lender's form of application and agreement with respect to Letters of
Credit. The Lender shall not be obligated to issue, renew, extend or reissue
such Letters of Credit if (i) the Lender does not approve the requested form of
the Letter of Credit or any of the terms thereof, such approval not to be
unreasonably withheld, (ii) the amount thereon when added to the amount of the
outstanding Letters of Credit exceeds $5,000,000.00, or (iii) the amount thereof
when added to the total outstanding Advances under Facility A would exceed the
Facility A Borrowing Base Amount then in effect. Borrower agrees to pay the
Lender a fee for the issuance of each Letter of Credit, which fee shall be due
and payable by the Borrower to the Lender upon issuance of each Letter of Credit
by the Lender and on each anniversary date of such issuance while such Letter of
Credit is outstanding. The said fee shall be a per annum fee in the amount equal
to the applicable Eurodollar Margin times the face amount of the Letter of
Credit for such period (calculated separately for each Letter of Credit).
SECTION 2.3.4. MANNER AND NOTICE OF BORROWING UNDER THE REVOLVING LINE OF
CREDIT. Requests For Advances under the Revolving Line of Credit may be made by
the Borrower, in writing (including facsimile transmission) to the Lender and
such requests shall be fully authorized by the Borrower if made by any one of
the persons designated by the Borrower in writing to the Lender. The form of
Request for Advance is attached hereto as Exhibit "B", and includes a
designation by Borrower of the Borrowing Date. The Lender shall have the right,
but not the obligation, to verify any telephone requests by calling the person
who made the request at the telephone number designated by the Borrower in
writing to the Lender. Requests For Advances must be received by not later than
11:00 a.m. (Central Time) (i) one (1) Business Day prior to the Borrowing Date
in the case of Base Rate Loans, or (ii) three (3) Business Days prior to any
proposed Borrowing Date in the case of Eurodollar Loans. Not later than 2:00
p.m., Lafayette, Louisiana time, on the Borrowing Date, the Lender shall make
available to Borrower the aggregate amount of such requested Advance by
crediting same to Borrower's checking account and mailing the resulting credit
advice to Borrower. The Lender shall not incur any liability to Borrower in
acting upon any Request for Advance referred to above which the Lender believes
in good faith to have been given by a duly authorized officer or other person
authorized to borrow on behalf of Borrower or for otherwise acting in good faith
under this Section 2.3.4. Upon funding of Advances by the Lender in accordance
with this Agreement, pursuant to any such Request for Advance, Borrower shall
have effected Advances hereunder. Each Request for Advance for a Revolving Loan
must specify whether such Loan is a Eurodollar Loan or a Base Rate Loan, and
whether such Loan is under Facility A or Facility B. The Lender's copy of such
credit advice indicating such deposit to the account of the Borrower shall be
deemed conclusive evidence of the Borrower's indebtedness to the Lender in
connection with such borrowing. The aggregate outstanding amount of principal
and interest due by the Borrower at any given time under the Commitment shall be
and constitute the indebtedness of the Borrower to the Lender under the
Revolving Note made by the Borrower. When each Advance is made by the Lender to
the Borrower hereunder, the Borrower shall be deemed to have renewed and
reissued the
Page 17 of 56
Revolving Note for the amount of the Advance plus all amounts due by the
Borrower to the Lender under the Commitment immediately prior to such advance.
SECTION 2.3.5. USE OF PROCEEDS. The Borrower shall use the proceeds of the
Revolving Loans to finance working capital requirements and for direct
investments in its oil and gas operations.
ARTICLE III
NOTE EVIDENCING THE LOANS
SECTION 3.1. REVOLVING NOTE.
SECTION 3.1.1. FORM OF REVOLVING NOTE. The Revolving Loans shall continue
to be evidenced by the Revolving Note. Notwithstanding the face amount of the
Note, the actual principal amount due from Borrower to the Lender on account of
the Revolving Note, as of any date of computation, shall be the sum of Advances
then and theretofore made on account thereof, less all principal payments
actually received by Lender in collected funds with respect thereto. Although
the Revolving Note is dated May 24, 2002, interest in respect thereof shall be
payable only for the period during which the loans evidenced thereby are
outstanding and, although the stated amount of the Revolving Note may be higher,
the Revolving Note shall be enforceable, with respect to Borrower's obligation
to pay the principal amount thereof, only to the extent of the unpaid principal
amount of the loans.
SECTION 3.1.2. PAYMENT OF THE REVOLVING NOTE. Subject to the requirements
of Article VIII below, interest on the unpaid principal balance of the Revolving
Note shall be payable on each Interest Payment Date and for Advances under
Facility A, on the Facility A Termination Date, and for Advances under Facility
B, on the Facility B Termination Date. Subject to the requirements of Article
VIII below, (i) the outstanding principal due under the Revolving Note resulting
from Advances under Facility A shall be due and payable on the Facility A
Termination Date, and (ii) the outstanding principal due under the Revolving
Note resulting from Advances under Facility B shall be due and payable on the
Facility B Termination Date.
ARTICLE IV
INTEREST RATES
SECTION 4.1. OPTIONS.
SECTION 4.1.1. BASE RATE LOANS. On Base Rate Loans, Borrower agrees to pay
interest calculated on the basis of a year consisting of 365/366 days with
respect to the unpaid principal amount of each Base Rate Loan from the date the
proceeds thereof are made available to Borrower until maturity (whether by
acceleration or otherwise), at a varying rate per annum equal
Page 18 of 56
to (A) for Advances under Facility A, the lesser of (i) the Maximum Rate and
(ii) the Base Rate plus the Base Rate Margin; and (B) for Advances under
Facility B, the lesser of (i) the Maximum Rate and (ii) the Base Rate plus
1.375%. Past due principal, to the extent permitted by law, shall bear interest,
payable upon demand, at the lesser of (i) the Maximum Rate and (ii) the default
rate specified in the Revolving Note.
SECTION 4.1.2. EURODOLLAR LOANS. On Eurodollar Loans, Borrower agrees to
pay interest calculated on the basis of a year consisting of 360 days with
respect to the unpaid principal amount of each Eurodollar Loan from the date the
proceeds thereof are made available to Borrower until maturity (whether by
acceleration or otherwise), at a varying rate per annum equal to (A) for
Advances under Facility A, the lesser of (i) the Maximum Rate and (ii) the
Eurodollar Rate plus the Eurodollar Margin; and (B) for Advances under Facility
B, the lesser of (i) the Maximum Rate and (ii) the Eurodollar Rate plus 3.375%.
Past due principal, to the extent permitted by law, shall bear interest, payable
on demand, at the lesser of (i) the Maximum Rate and (ii) the default rate
specified in the Revolving Note. Upon three (3) Business Days written notice
prior to the making by the Lender of any Eurodollar Loan (in the case of the
initial Interest Period therefor) or the expiration date of each succeeding
Interest Period (in the case of subsequent Interest Periods therefor), Borrower
shall have the option, subject to compliance by Borrower with all of the
provisions of this Agreement, as long as no Event of Default exists, to specify
whether the Interest Period commencing on any such date shall be a one (1), two
(2), three (3) or six (6) month period. If the Lender shall not have received
timely notice of a designation of such Interest Period as herein provided,
Borrower shall be deemed to have elected to convert all maturing Eurodollar
Loans to Base Rate Loans.
SECTION 4.2. INTEREST RATE DETERMINATION. The Lender shall determine each
interest rate applicable to any Base Rate Loan or Eurodollar Loan and its
determination shall be conclusive absent manifest error. The Lender shall notify
the Borrower of each interest rate determination within a reasonable time after
each such determination.
SECTION 4.3. CONVERSION OPTION. Borrower may elect from time to time (i) to
convert all or any part of its Eurodollar Loans to Base Rate Loans by giving the
Lender irrevocable notice of such election in writing prior to 10:00 a.m.
(Lafayette, Louisiana time) on the conversion date and such conversion shall be
made on the requested conversion date, provided that any such conversion of
Eurodollar Loan shall only be made on the last day of the Eurodollar Interest
Period with respect thereof, and (ii) to convert all or any part of its Base
Rate Loans to Eurodollar Loans by giving the Lender irrevocable written notice
of such election three (3) Business Days prior to the proposed conversion and
such conversion shall be made on the requested conversion date or, if such
requested conversion date is not a Business Day on the next succeeding Business
Day. Any such conversion shall not be deemed to be a prepayment of any of the
Loans for purposes of this Agreement on the Revolving Note.
Page 19 of 56
ARTICLE V
CHANGE OF CIRCUMSTANCES
SECTION 5.1. UNAVAILABILITY OF FUNDS OR INADEQUACY OF PRICING. In the event
that, in connection with any proposed Eurodollar Loan, the Lender determines,
which determination shall, absent manifest error, be final, conclusive and
binding upon all parties, due to changes in circumstances since the date hereof,
adequate and fair means do not exist for determining the Eurodollar Rate or such
rate will not accurately reflect the costs to the Lender of funding Eurodollar
Loans for such Eurodollar Interest Period, the Lender shall give notice of such
determination to the Borrower, whereupon, until the Lender notifies the Borrower
that the circumstances giving rise to such suspension no longer exist, the
obligation of the Lender to make, continue or convert Loans into Eurodollar
Loans shall be suspended, and all loans to Borrower shall be Base Rate Loans
during the period of suspension.
SECTION 5.2. CHANGE IN LAWS. If at any time after the date hereof any new
law or any change in existing laws or in the interpretation by any governmental
authority, central bank, or comparable agency charged with the administration or
interpretation thereof, of any new or existing laws shall make it unlawful for
the Lender to make or continue to maintain or fund Eurodollar Loans hereunder,
then Lender shall promptly notify Borrower in writing of Lender's obligation to
make, continue or convert Loans into Eurodollar Loans under this Agreement shall
be suspended until it is no longer unlawful for Lender to make or maintain
Eurodollar Loans. Upon receipt of such notice, Borrower shall either repay the
outstanding Eurodollar Loans owed to the Lender, without penalty, on the last
day of the current Interest Periods (or, if Lender may not lawfully continue to
maintain and fund such Eurodollar Loans, immediately), or Borrower may convert
such Eurodollar Loans at such appropriate time to Base Rate Loans.
SECTION 5.3. INCREASED COST OR REDUCED RETURN.
(i) If, after the date hereof, the adoption of any applicable
law, rule, or regulation, or any change in any applicable law, rule, or
regulation, or any change in the interpretation or administration thereof by any
governmental authority, central bank, or comparable agency charged with the
interpretation or administration thereof, or compliance by the Lender with any
request or directive (whether or not having the force of law) of any such
governmental authority, central bank, or comparable agency:
(A) shall subject Lender to any tax, duty, or other charge
with respect to any Eurodollar Loans, the Revolving Note, or its
obligation to make Eurodollar Loans, or change the basis of
taxation of any amounts payable to Lender under this Agreement,
or the Revolving Note, in respect of any Eurodollar Loans (other
than franchise taxes and taxes imposed on the overall net income
of Lender);
Page 20 of 56
(B) shall impose, modify, or deem applicable any reserve,
special deposit, assessment, or similar requirement (other than
reserve requirements, if any, taken into account in the
determination of the Eurodollar Rate) relating to any extensions
of credit or other assets of, or any deposits with or other
liabilities or commitments of, Lender, including the Commitment
of Lender hereunder; or
(C) shall impose on Lender or on the London interbank market
any other condition affecting this Agreement or the Revolving
Note or any of such extensions of credit or liabilities or
commitments;
and the result of any of the foregoing is to increase the cost to Lender of
making, converting into, continuing, or maintaining any Eurodollar Loans or to
reduce any sum received or receivable by Lender under this Agreement or the
Revolving Note with respect to any Eurodollar Loans, then pursuant to Section
5.3(v) Borrower shall pay to Lender such amount or amounts as will compensate
Lender for such increased cost or reduction. If Lender requests compensation by
Borrower under this Section 5.3., Borrower may, by notice to Lender, suspend the
obligation of Lender to make or continue Eurodollar Loans, or to convert all or
part of the Base Rate Loan owing to Lender to Eurodollar Loans, until the event
or condition giving rise to such request ceases to be in effect (in which case
the provisions of Section 5.3. shall be applicable); provided that such
suspension shall not affect the right of Lender to receive the compensation so
requested.
(ii) If, after the date hereof, Lender shall have determined that
the adoption of any applicable law, rule, or regulation regarding capital
adequacy or any change therein or in the interpretation or administration
thereof by any governmental authority, central bank, or comparable agency
charged with the interpretation or administration thereof, or any request or
directive regarding capital adequacy (whether or not having the force of law) of
any such governmental authority, central bank, or comparable agency, has or
would have the effect of reducing the rate of return on the capital of Lender or
any corporation controlling Lender as a consequence of Lender's obligations
hereunder to a level below that which Lender or such corporation could have
achieved but for such adoption, change, request, or directive (taking into
consideration its policies with respect to capital adequacy), then from time to
time pursuant to Section 5.3(v) Borrower shall pay to Lender such additional
amount or amounts as will compensate Lender for such reduction.
(iii) Lender shall promptly notify Borrower of any event of which
it has knowledge, occurring after the date hereof, which will entitle Lender to
compensation pursuant to this Section 5.3. will designate a separate lending
office, if applicable, if such designation will avoid the need for, or reduce
the amount of, such compensation and will not, in the judgment of Lender, be
otherwise disadvantageous to it. If Lender claims compensation under this
Section 5.3., Lender shall simultaneously furnish to Borrower a statement
setting forth the additional amount or amounts to be paid to it hereunder which
shall be conclusive in the absence of manifest error. In determining such
amount, Lender may use any reasonable averaging and attribution methods.
Page 21 of 56
(iv) If Lender gives notice to the Borrower pursuant to Section
5.3. hereof, Lender shall simultaneously give to the Borrower a statement signed
by an officer of Lender setting forth in reasonable detail the basis for, and
the calculation of such additional cost, reduced payments or capital
requirements, as the case may be, and the additional amounts required to
compensate Lender therefor.
(v) Within fifteen (15) days after receipt by the Borrower of any
notice referred to in Section 5.3., the Borrower shall pay to Lender such
additional amounts as are required to compensate Lender for the increased cost,
reduce payments or increase capital requirements identified therein, as the case
may be; provided, that the Borrower shall not be obligated to compensate Lender
for any increased costs, reduced payments or increased capital requirements to
the extent that Lender incurs the same prior to a date six (6) months before
Lender gives the required notice.
SECTION 5.4. BREAKAGE COSTS. Without duplication under any other provision
hereof, if Lender incurs any actual loss, cost or expense (including, without
limitation, any loss of profit and loss, cost, expense or premium reasonably
incurred by reason of the liquidation or re-employment of deposits or other
funds acquired by Lender to fund or maintain any Eurodollar Loan or the
relending or reinvesting of such deposits or amounts paid or prepaid to the
Lender as a result of any of the following events other than any such occurrence
as a result in the change of circumstances described in Sections 5.1. and 5.2.:
(i) any payment, prepayment or conversion of a Eurodollar Loan on
a date other than the last day of its Eurodollar Interest Period
(whether by acceleration, prepayment or otherwise);
(ii) any failure to make a principal payment of a Eurodollar Loan
on the due date thereof; or
(iii) any failure by the Borrower to borrow, continue, prepay or
convert to a Eurodollar Loan on the dates specified in a notice given
pursuant to this Agreement.
then the Borrower shall within 15 days after demand pay to Lender such amount as
will reimburse Lender for such loss, cost or expense. If Lender makes such a
claim for compensation, it shall simultaneously furnish to Borrower a statement
setting forth the amount of such loss, cost or expense in reasonable detail
(including an explanation of the basis for and the computation of such loss,
cost or expense) and the amounts shown on such statement shall be conclusive and
binding absent manifest error.
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ARTICLE VI
FEES
SECTION 6.1. FACILITY FEES.
SECTION 6.1.1. FACILITY A FACILITY FEE. The Borrower shall pay to the
Lender the sum of five thousand dollars ($5,000.00), which amount represents
one-half percent (.50%) of the amount by which the Facility A Borrowing Base
Amount exceeds the highest Borrowing Base Amount that was in effect under the
Original Agreement prior to the execution of this Agreement. An additional
facility fee of one-half percent (.50%) of the incremental amount of any
increase to the Facility A Borrowing Base Amount shall be owed by Borrower to
the Lender, and such fee shall be payable by Borrower upon Borrower's acceptance
of said increase; provided, however, if the Facility A Borrowing Base Amount is
reduced and then reinstated to a higher amount, the additional facility fee will
be applicable only to the incremental amount, if any, by which the higher amount
exceeds the previous highest Facility A Borrowing Base Amount. The Borrower
hereby authorizes the Lender to debit its account maintained with the Lender for
collection of the foregoing facility fees.
SECTION 6.1.2. FACILITY B FACILITY FEE. The Borrower shall pay to the
Lender the sum of one percent (1%) of the Facility B Borrowing Base Amount. An
additional facility fee of one percent (1%) of any reinstatement or increase to
the Facility B Borrowing Base Amount shall be payable by Borrower upon its
acceptance of said reinstatement or increase. The Borrower hereby authorizes the
Lender to debit its account maintained with the Lender for collection of the
foregoing facility fees.
SECTION 6.2. UNUSED FEES.
SECTION 6.2.1. FACILITY A UNUSED FEE. The Borrower shall pay the Lender an
unused fee calculated on the unused portion of the Facility A Borrowing Base
Amount as follows: (i) if the Facility A Borrowing Base Usage is greater than or
equal to 90%, the unused fee is 0.50%; (ii) if the Facility A Borrowing Base
Usage is greater than or equal to 50% but less than 90%, the unused fee is
0.50%; and (iii) if the Facility A Borrowing Base Usage is less than 50%, the
unused fee is 0.375%. The unused fee will be payable quarterly in arrears on the
last day of each fiscal quarter, commencing December 31, 2002. The unused
portion of the Facility A Borrowing Base Amount shall be determined on a daily
basis by subtracting from the Facility A Borrowing Base Amount the Total
Outstandings under Facility A, and by averaging said daily amounts for the
period for which the fee is to be determined. The Borrower hereby authorizes the
Lender to debit its account maintained with the Lender for collection of the
unused fee.
SECTION 6.2.2. FACILITY B UNUSED FEE. The Borrower shall pay to the Lender
an unused fee of 0.50% based on the unused portion of the Facility B Borrowing
Base Amount. The unused fee will be payable quarterly in arrears on the last day
of each fiscal quarter, commencing December 31, 2002. The unused portion of the
Facility B Borrowing Base Amount shall be determined on a daily basis by
subtracting from the Facility B Borrowing Base Amount the Total Outstandings
under Facility B, and by averaging said daily amounts for the period for which
the
Page 23 of 56
fee is to be determined. The Borrower hereby authorizes the Lender to debit its
account maintained with the Lender for collection of the unused fee.
SECTION 6.3. LETTER OF CREDIT FEE. The Borrower shall pay to the Lender a
fee for each Letter of Credit as provided in Section 2.3.3. of this Agreement.
SECTION 6.4. ENGINEERING FEE. The Borrower shall pay to the Lender a fee of
$7,500.00 for each unscheduled determination of the Facility A Borrowing Base
Amount requested by Borrower. The Borrower hereby authorizes the Lender to debit
its account maintained with the Lender for collection of said fees.
ARTICLE VII
CERTAIN GENERAL PROVISIONS
SECTION 7.1. PAYMENTS TO THE LENDER. All payments of principal, interest,
fees and any other amounts due hereunder or under any of the other Related
Documents shall be made to the Lender at its office in New Orleans, Louisiana at
313 Carondelet Street, New Orleans, Louisiana 70130, or at such other location
that the Lender may from time to time designate in writing to the Borrower, in
each case in immediately available funds.
SECTION 7.2. NO OFFSET, ETC. All payments by the Borrower hereunder and
under any of the other Related Documents shall be made without setoff and free
and clear of and without deduction for any taxes, levies, imposts, duties,
charges, fees, deductions, withholdings, compulsory loans, restrictions or
conditions of any nature now or hereafter imposed or levied by any jurisdiction
or any political subdivision thereof or taxing or other authority therein unless
the Borrower is compelled by law to make such deduction or withholding. If any
such obligation is imposed upon the Borrower with respect to any amount payable
by it hereunder or under any of the other Loan Documents, the Borrower will pay
to the Lender, on the date on which such amount is due and payable hereunder or
under such other Related Document, such additional amount in Dollars as shall be
necessary to enable the Lender to receive the same net amount which the Lender
would have received on such due date had no such obligation been imposed upon
the Borrower. The Borrower will deliver promptly to the Lender certificates or
other valid vouchers for all taxes or other charges deducted from or paid with
respect to payments made by the Borrower hereunder or under such other Loan
Documents.
SECTION 7.3. PRINCIPAL AMOUNT OF REVOLVING NOTE. The Borrower acknowledges
and understands that notwithstanding the stated principal amount of the
Revolving Note, that the Lender's obligation to fund Advances under the
Revolving Note is limited for all purposes to the terms and conditions of this
Agreement, including but not limited to, availability under the Facility A
Borrowing Base Amount then in effect and the Facility B Borrowing Base Amount
then in effect, as the case may be. IN ADDITION, THE BORROWER UNDERSTANDS AND
AGREES THAT NOTWITHSTANDING ANY PROVISION IN THIS AGREEMENT OR THE REVOLVING
NOTE TO THE CONTRARY, THAT THE LENDER SHALL NOT BE OBLIGATED TO FUND ANY AMOUNT
IN EXCESS OF THE FACILITY A BORROWING
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BASE AMOUNT THEN IN EFFECT OR THE FACILITY B BORROWING BASE AMOUNT THEN IN
EFFECT, AS THE CASE MAY BE.
SECTION 7.4. RATE MANAGEMENT TRANSACTIONS. The Borrower is permitted to
enter into Rate Management Transactions with the Lender.
SECTION 7.5. CALCULATION OF FEES. The fees set forth in Article VI above
will be calculated on the basis of a year consisting of 360 days.
ARTICLE VIII
PREPAYMENTS
SECTION 8.1. VOLUNTARY PREPAYMENTS. Borrower may at any time and from time
to time, without premium or penalty, prepay Base Rate Loans. Borrower may at any
time and from time to time, without penalty or premium subject to Section 5.4.
hereof, prepay Eurodollar Loans outstanding upon at least three (3) Business
Day's notice to Lender.
SECTION 8.2. MANDATORY PREPAYMENT RESULTING FROM A QUARTERLY REDUCTION.
Subject to Section 5.4 above, in the event the outstanding principal amount of
all Loans under Facility A exceed, as a result of a Quarterly Reduction, the
Facility A Borrowing Base Amount then in effect, the Borrower shall make (on the
first Business Day of the month following the Quarterly Reduction) a mandatory
prepayment to the Lender of the excess amount and accrued, unpaid interest
(through the date of payment) on such excess amount.
SECTION 8.3. MANDATORY PREPAYMENT RESULTING FROM OVERADVANCES. Except as
otherwise required by Section 13.2, in the event the unpaid principal amount of
the Revolving Loans ever exceeds the sum of the Facility A Borrowing Base Amount
then in effect and the Facility B Borrowing Base Amount then in effect
(including any scheduled or unscheduled redeterminations thereof), the Borrower
(at its option) agrees, within thirty (30) days after notice from Lender of the
occurrence of such an excess amount (an "overadvance") to do the following
(individually or in combination): (a) make a lump sum payment to the Lender in
an amount equal to the overadvance; (b) grant to the Lender security interests
or mortgage liens on new collateral having, in the Lender's sole discretion an
incremental value at least equal to one hundred percent (100%) of such
overadvance; or (c) make the first of six (6) (or fewer) consecutive monthly
payments to the Lender, each in the amount equal to one-sixth (or such
corresponding lesser amount if fewer than six payments are made) of the
overadvance.
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ARTICLE IX
SECURITY FOR THE INDEBTEDNESS
SECTION 9.1. SECURITY. The Indebtedness of the Borrower to the Lender
under this Agreement and the Revolving Note shall be secured by the following:
(a) the Mortgage;
(b) the Security Agreement (and physical delivery to the Lender of the
stock certificates therein described);
(c) the Guaranty; and
(d) any additional Collateral Documents granted by any Person in favor of
Lender as security for the Indebtedness of the Borrower to the Lender under this
Agreement and the Revolving Note.
The Borrower understands and acknowledges that item (a) and (b) above
constitute first priority mortgage liens and security interests affecting the
Mortgaged Properties and 100% of the outstanding stock of the Guarantor in favor
of the Lender, subject only to Permitted Encumbrances and Designated Title
Exceptions as herein provided.
ARTICLE X
CONDITIONS PRECEDENT
SECTION 10.1. CONDITIONS PRECEDENT TO ALL REVOLVING LOANS. The obligation
of the Lender to make any Revolving Loan hereunder shall be subject to the
satisfaction and the continued satisfaction of the following conditions
precedent:
(a) On or prior to the date hereof, the Borrower shall have executed and
delivered to the Lender this Agreement, the Revolving Note, the Mortgage, the
Security Agreement, and all other documents required by this Agreement, all in
form and substance and in such number of counterparts as may be required by the
Lender;
(b) On or prior to the date hereof, the Guarantor shall have executed and
delivered to the Lender this Agreement, the Guaranty, and all other documents
required by this Agreement, all in form and substance and in such number of
counterparts as may be required by the Lender;
(c) The representations, warranties, and covenants of the Borrower as set
forth in this Agreement, or in any Related Document furnished to the Lender in
connection herewith, shall be and remain true and correct as of such date
(except to the extent specifically limited to a specified date);
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(d) On or prior to the date hereof, the Lender shall have received a
favorable legal opinion of counsel to the Borrower and the Guarantor covering
the transactions contemplated by this Agreement, in form, scope and substance
satisfactory to the Lender;
(e) The Lender shall have received certified resolutions of the Borrower
and the Guarantor authorizing the execution of all documents and instruments
contemplated by this Agreement;
(f) The Lender shall have received all fees, charges and expenses which are
due and payable as specified in this Agreement and any Related Documents;
(g) No Default or Event of Default shall exist or shall result from the
making of a Loan or the issuance of a Letter of Credit;
(h) The Borrower shall have provided the Lender with all financial
statements, reports and certificates required by this Agreement;
(i) On or prior to the date hereof, the Lender shall have received the
articles of incorporation and bylaws, as amended, and the Lender's counsel shall
have reviewed the foregoing documents and is satisfied with the validity, due
authorization and enforceability thereof and of all Related Documents;
(j) On or prior to the date hereof, the Lender shall have received evidence
acceptable to the Lender and their counsel that its Encumbrances affecting the
Collateral shall have a first priority position, subject only to Permitted
Encumbrances;
(k) The Borrower shall have complied with the procedure set forth in this
Agreement, for the making of a Revolving Loan;
(l) Except as disclosed on Schedule 10.1 attached hereto there shall have
occurred no Material Adverse Effect since the date of the most recent financial
statements delivered by Borrower to Lender hereunder;
(m) The Lender's reasonable satisfactory review prior to the date hereof of
all environmental matters related to the Mortgaged Properties;
(n) The Borrower must maintain insurance as required by Section 11.6, and
deliver to Lender evidence of such insurance coverage;
(o) To the extent requested by Lender and required by the Loan Documents,
the Borrower shall have executed and delivered to the Lender blank form letters
in lieu of division orders, in form and substance satisfactory to the Lender;
and
(p) On or prior to the date hereof, the Lender shall have received title
opinions from counsel to Borrower (or other title information reasonably
acceptable to the Lender) covering not
Page 27 of 56
less than eighty percent (80%) of the present value of the sum of the Facility A
Borrowing Base Amount and the Facility B Borrowing Base Amount, as determined by
the Lender, which opinions (or other title information reasonably acceptable to
the Lender) must satisfy (in the Lender's reasonable discretion) the first
sentence of Section 11.3.
The Lender reserve the right, in its sole discretion, to waive any one or
more of the foregoing conditions precedent.
ARTICLE XI
REPRESENTATIONS AND WARRANTIES
The Borrower represents and warrants to the Lender as follows:
SECTION 11.1. CORPORATE AUTHORITY OF THE BORROWER. The Borrower is a
corporation duly created, validly existing, and in good standing under the laws
of the state its incorporation, and is duly qualified and in good standing as
foreign corporation in Louisiana and all other jurisdictions where the failure
to qualify would have an adverse effect upon its ability to perform its
obligations under this Agreement and all Related Documents to which it is a
party. The Borrower has the corporate power to enter into this Agreement,
execute the Revolving Note, Mortgage, Security Agreement, and grant the liens
and security interests in the Collateral in the manner and for the purpose
contemplated by the Collateral Documents. The Borrower has the corporate power
to perform its obligations hereunder and under the Loan Documents and Related
Documents. The execution, delivery, and performance by the Borrower of the Loan
Documents and Related Documents have all been duly authorized by all necessary
corporate or company action, and do not and will not result in any violation by
the Borrower of any provision of any law, rule, regulation, order, writ,
judgment, decree, determination or award presently in effect having
applicability to the Borrower, or the articles of incorporation and bylaws of
the Borrower. Except as set forth in Schedule 11.1 attached hereto, the making
and performance by the Borrower of the Loan Documents and Related Documents do
not and will not result in a breach of or constitute a default under any
material indenture or loan or credit agreement or any other material agreement
or instrument to which the Borrower is a party or by which it may be bound or
affected, or result in, or require, the creation or imposition of any mortgage,
deed of trust, pledge, lien, security interest or other charge or encumbrance of
any nature (other than as contemplated by the Related Documents) upon or with
respect to any of the properties now owned or hereafter acquired by the
Borrower. Each of the Loan Documents and Related Documents to which the Borrower
is a party constitutes a legal, valid and binding obligation of the Borrower,
enforceable in accordance with its terms.
SECTION 11.2. FINANCIAL STATEMENTS. The most recent balance sheet of the
Borrower at the dates thereof, and the related statements of income and retained
earnings for the year then ended, copies of which have been delivered to the
Lender fairly present in all material respects the financial condition of the
Borrower as of the date or dates thereof. Each of said financial statements were
prepared in conformity with GAAP and, except as otherwise disclosed to Lender in
writing, applied on a basis consistent with the preceding year. No Material
Adverse Effect has
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occurred since said dates in the financial position or in the results of
operations of the Borrower in its business taken as a whole.
SECTION 11.3. TITLE TO MORTGAGED PROPERTIES. Except as set forth on
Schedule 11.3 attached hereto, the Borrower has Defensible Title to the
Mortgaged Properties at a book cost in excess of $200,000 (except to the extent
that (a) such assets have thereafter been disposed of in compliance with this
Agreement or (b) leases for such property have expired pursuant to their terms),
and, in each case free and clear of all Encumbrances except (other than
Permitted Encumbrances) (i) Encumbrances for taxes not yet due and payable or,
if payable, that are being contested in good faith in the ordinary course of
business, (ii) statutory Encumbrances (including materialmen's, mechanic's,
repairmen's, landlord's and other similar encumbrances) arising in the ordinary
course of business to secure payments not yet due and payable or, if payable,
that are being contested in good faith in the ordinary course of business, (iii)
easements, restrictions, reservations or other encumbrances, as well as such
imperfections or irregularities of title, if any, as are not material, (iv)
obligations or duties to any municipality or public authority with respect to
any franchise, grant, license or permit and all applicable laws, rules,
regulations and orders of any Governmental Authority, (v) all lessors'
royalties, overriding royalties, net profits interests, production payments,
carried interests, reversionary interests and other burdens on or deductions
from the proceeds of production, (vi) the terms and conditions of joint
operating agreements and other oil and gas contracts, (vii) all rights to
consent by, required notices to, and filings with or other actions by
governmental or tribal entities, if any, in connection with the change of
ownership or control of an interest in federal, state, tribal or other domestic
governmental oil and gas leases, if the same are customarily obtained subsequent
to such change of ownership or control, but only insofar as such consents,
notices, filings and other actions relate to the transactions contemplated by
this Agreement, (viii) any preferential purchase rights, (ix) required third
party consents to assignment, (x) conventional rights of reassignment prior to
abandonment and (xi) the terms and provisions of oil and gas leases, unit
agreements, pooling agreements, and other documents creating interests
comprising the oil and gas properties; provided, however, the exceptions
described in clauses (iv) through (xi) inclusive above are qualified to include
only those exceptions in each case which do not operate to (A) reduce the net
revenue interest of the Borrower below that set forth on Schedule 11.3, (B)
increase the proportionate share of costs and expenses of leasehold operations
attributable to or to be borne by the working interest of the Borrower above
that set forth on Schedule 11.3 without a proportionate increase in the net
revenue interest of the Borrower or (C) increase the working interest of the
Borrower above that set forth on Schedule 11.3 without a proportionate increase
in the net revenue interest of the Borrower, and, provided, further, that the
foregoing defects, limitations, liens and encumbrances, whether individually
material or not, do not in the aggregate create a Material Adverse Effect upon
the Borrower (the categories of exceptions in clauses (iv) through (xi), as so
qualified and as any such exceptions may exist from time to time, being referred
to as the "DESIGNATED TITLE EXCEPTIONS"). The Mortgage constitutes a legal,
valid and perfected first Encumbrance on the property interests covered thereby,
subject only to Designated Title Exceptions, Permitted Encumbrances, and matters
disclosed on Schedule 11.3. Further, as of the date hereof, the oil and gas
properties constituting not less than ninety percent (90%) of the present value
of the sum of the initial Facility A Borrowing Base Amount and Facility B
Borrowing Base Amount are Mortgaged Properties.
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SECTION 11.4. LITIGATION. Other than as set forth in Schedule 11.4 and as
may be disclosed to the Lender in writing after the date of this Agreement,
there are no legal actions, suits or proceedings pending or, to the best
knowledge of the Borrower, threatened against or affecting the Borrower, or any
of its properties before any court or administrative agency (federal, state or
local), which could reasonably be expected to constitute a Material Adverse
Effect, and there are no judgments or decrees affecting the Borrower, or its
property (including, without limitation, the Collateral) which are or could
reasonably be expected to become an Encumbrance against such property (other
than a Designated Title Exception or a Permitted Encumbrance), provided that no
breach of this Section 11.4 shall occur if the same is discharged within thirty
days after the date of entry thereof or an appeal or appropriate proceeding for
review thereof is taken within such period and a stay of execution pending such
appeal is obtained.
SECTION 11.5. APPROVALS. No authorization, consent, approval or formal
exemption of, nor any filing or registration with, any governmental body or
regulatory authority (federal, state or local), and no vote, consent or approval
of the shareholders of the Borrower is or will be required in connection with
the execution and delivery by the Borrower of the Related Documents or the
performance by the Borrower of its obligations hereunder and under the other
Related Documents, except to the extent obtained.
SECTION 11.6. REQUIRED INSURANCE. The Borrower maintains insurance with
insurance companies in such amounts and against such risks as is usually carried
by owners of similar businesses and properties in the same general areas in
which Borrower operates.
SECTION 11.7. LICENSES. The Borrower possesses adequate franchises,
licenses and permits to own its properties and to carry on its business as
presently conducted, except where the failure to do so could not reasonably be
expected to have a Material Adverse Effect.
SECTION 11.8. ADVERSE AGREEMENTS. Except as described in Schedule 10.1, the
Borrower is not a party to any agreement or instrument, nor subject to any
charter or other restriction, materially and adversely affecting the business,
properties, assets, or operations of the Borrower or its condition (financial or
otherwise), and the Borrower is not in default in the performance, observance or
fulfillment of any of the obligations, covenants or conditions contained in any
agreement or instrument to which it is a party, which default would constitute a
Material Adverse Effect.
SECTION 11.9. DEFAULT OR EVENT OF DEFAULT. No Default or Event of Default
hereunder has occurred and is continuing or will occur as a result of the giving
effect hereto.
SECTION 11.10. EMPLOYEE BENEFIT PLANS. Each employee benefit plan as to
which the Borrower may have any liability complies in all material respects with
all applicable requirements of law and regulations, and (i) no Reportable Event
(as defined in ERISA) has occurred and is continuing with respect to any such
plan, (ii) the Borrower has not withdrawn from any such plan or initiated steps
to do so, and (iii) no steps have been taken to terminate any such plan.
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SECTION 11.11. INVESTMENT COMPANY ACT. The Borrower is not an "investment
company" or a company "controlled" by an "investment company," within the
meaning of the Investment Company Act of 1940, as amended.
SECTION 11.12. PUBLIC UTILITY HOLDING COMPANY ACT. The Borrower is not a
"holding company," or a "subsidiary company" of a "holding company," within the
meaning of the Public Utility Holding Company Act of 1935, as amended.
SECTION 11.13. REGULATIONS X, T AND U. The Borrower is not engaged
principally, or as one of its important activities, in the business of extending
credit for the purpose of purchasing or carrying margin stock (within the
meaning of Regulations X, T and U of the Board of Governors of the Federal
Reserve System), and none of the proceeds of the Loans will be used for the
purpose of purchasing or carrying such margin stock.
SECTION 11.14. LOCATION OF OFFICES AND RECORDS. As of the date hereof, the
chief place of business of the Borrower, and the office where the Borrower keeps
all of its records concerning the Collateral, is 14701 St. Mary's Lane, Suite
800, Houston, Texas 77079.
SECTION 11.15. INFORMATION. All written information heretofore or
contemporaneously herewith furnished by the Borrower to the Lender for the
purposes of or in connection with this Agreement or any transaction contemplated
hereby (excluding projections, estimates, and engineering reports) is, and all
such information hereafter furnished by or on behalf of the Borrower to the
Lender will be, true and accurate in every material respect on the date as of
which such information is dated or certified; and none of such information is or
will be incomplete by omitting to state any material fact necessary to make such
information not misleading as of such date, taken as a whole. To the best
knowledge of Borrower, the engineering reports delivered to the Lender in
connection with this Agreement do not contain any material inaccuracies and/or
omissions. The said engineering reports, however, are based upon professional
opinions, estimates and projections and the Borrower does not warrant that such
opinions, estimates and projections will ultimately prove to have been accurate.
All other projections and estimates by the Borrower delivered hereunder or in
connection herewith were prepared in good faith on the basis of the assumptions
believed by the Borrower in good faith to be reasonable in light of the then
current and foreseeable business conditions of the Borrower and its Subsidiaries
at the time of preparation thereof, it being understood by the Lender that
actual results may vary from projected results.
SECTION 11.16. ENVIRONMENTAL MATTERS. Except as previously disclosed to the
Lender in writing or as could not reasonably be expected to result in a Material
Adverse Effect:
(a) To the best of Borrower's knowledge and belief after due inquiry,
Borrower is in compliance with all applicable Environmental Laws;
(b) To the best of Borrower's knowledge and belief after due inquiry,
Borrower has obtained all consents and permits required under all applicable
Environmental Laws to operate its business as presently conducted or as proposed
to be conducted and all such consents and permits
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are in full force and effect and Borrower is in compliance with all terms and
conditions of such approvals;
(c) To the best of Borrower's knowledge and belief after due inquiry,
neither Borrower nor any of the present property or operations of Borrower is
subject to any order from or agreement with any Governmental Authority or
private party respecting (i) failure to comply with any Environmental Law or any
Remedial Action or (ii) any Environmental Liabilities arising from the Release
or threatened Release except those orders and agreements with which Borrower has
complied;
(d) To the best of Borrower's knowledge and belief after due inquiry, none
of the operations of Borrower is subject to any judicial or administrative
proceeding alleging a violation of, or liability under, any Environmental Law;
(e) None of the operations of Borrower, to its best knowledge after due
inquiry, is the subject of any investigation by any Governmental Authority
evaluating whether any Remedial Action is needed to respond to a Release or
threatened Release;
(f) Borrower has not been required to file any notice under any
Environmental Law indicating past or present treatment, storage or disposal of a
hazardous waste as defined by 40 CFR Part 261 or any state or local equivalent
which could reasonably be expected to have a Material Adverse Effect;
(g) Borrower has not been required to file any notice under any applicable
Environmental Law reporting a Release which could reasonably be expected to have
a Material Adverse Effect;
(h) There is not now, nor, to the best knowledge of Borrower, has there
ever been, on or in any property of Borrower:
(i) any unauthorized generation, treatment, recycling, storage or
disposal of any hazardous waste as defined by 40 CFR Part 261 or
any state or local equivalent,
(ii) any underground storage tanks or surface impoundments without
proper permits,
(iii) any asbestos - containing material, or
(iv) any polychlorinated biphenyls (PCBs) used in hydraulic oils,
electrical transformers or other equipment;
(i) There have been no written commitments or agreements involving Borrower
from or with any Governmental Authority or any private entity (including,
without limitation, the owner of the Mortgaged Properties or any portion
thereof) relating to the generation, storage,
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treatment, presence, Release, or threatened Release which could reasonably be
expected to have a Material Adverse Effect on or into any of the properties of
Borrower or the environment (including off-site disposal of Hazardous Materials)
or any Remedial Action with respect thereto in non-compliance or violation of
any Environmental Law;
(j) Borrower has not received any written notice or claim to the effect
that it is or may be liable to any Person as a result of the Release or
threatened Release which could reasonably be expected to have a Material Adverse
Effect;
(k) To the best of Borrower's knowledge and belief after due inquiry,
Borrower has no known liability in connection with any material Release or
material threatened Release which could reasonably be expected to have a
Material Adverse Effect;
(l) After due inquiry, no Environmental Lien has attached (and continues to
attach) to any properties of Borrower, provided that no breach of this Section
11.16(l) shall occur if the same is discharged within thirty days after the
attachment thereof or an appeal or other appropriate proceeding for review
thereof is taken within said thirty day period and/or a stay of execution
pending such appeal is obtained; and
(m) To the Borrower's best knowledge after due inquiry, there have been no
environmental investigations, studies, audits, tests, reviews or other analyses
conducted by or which are in the possession of Borrower in relation to any
violation of Environmental Laws which violation could reasonably be expected to
have a Material Adverse Effect in relation to any properties or facility now or
previously owned or leased by Borrower which have not been made available to
Lender.
SECTION 11.17. SOLVENCY OF THE BORROWER. The Borrower is and after
consummation of the transactions contemplated by this Agreement (including the
making of the Loans and the issuance of Letters of Credit), and after giving
effect to all obligations incurred by the Borrower in connection herewith, will
be, Solvent.
SECTION 11.18. GOVERNMENTAL REQUIREMENTS. The Collateral is in compliance
with all current governmental requirements affecting the said property, except
where failure could not reasonably be expected to have a Material Adverse
Effect.
SECTION 11.19. CORPORATE AUTHORITY OF THE GUARANTOR. The Guarantor is a
corporation duly created, validly existing, and in good standing under the laws
of the state of its incorporation, and is duly qualified and in good standing as
foreign corporation in all other jurisdictions where the failure to qualify
would have an adverse effect upon its ability to perform its obligations under
this Agreement and all Related Documents to which it is a party. The Guarantor
has the corporate power to enter into this Agreement and the Guaranty. The
Guarantor has the power to perform its obligations hereunder and under the Loan
Documents and Related Documents to which it is a party. The making and
performance by the Guarantor of the Loan Documents and Related Documents to
which it is a party have all been duly authorized by all necessary corporate or
company action, and do not and will not violate any provision of any law, rule,
regulation, order, writ, judgment, decree, determination or award presently in
effect having
Page 33 of 56
applicability to the Guarantor, or the articles of incorporation and bylaws of
the Guarantor. The making and performance by the Guarantor of the Loan Documents
and Related Documents to which it is a party do not and will not result in a
breach of or constitute a default under any material indenture or loan or credit
agreement or any other material agreement or instrument to which the Guarantor
is a party or by which it may be bound or affected, or result in, or require,
the creation or imposition of any mortgage, deed of trust, pledge, lien,
security interest or other charge or encumbrance of any nature (other than as
contemplated by the Related Documents) upon or with respect to any of the
properties now owned or hereafter acquired by the Guarantor, and the Guarantor
is not in default under or in violation of any such order, writ, judgment,
decree, determination, award, indenture, agreement or instrument to the extent
any such default or violation could reasonably be expected to have a Material
Adverse Effect. Each of the Loan Documents and Related Documents to which the
Guarantor is a party constitutes a legal, valid and binding obligation of the
Guarantor, enforceable in accordance with its terms.
SECTION 11.20. CHASE PURCHASE AGREEMENT. As of the date hereof (without
giving effect to any material modifications which may hereafter be made to this
Agreement), (i) the Indebtedness is entitled to the benefits accorded the Senior
Indebtedness (as such term is defined in the Chase Purchase Agreement) and (ii)
the consent of the Investors (as such term is defined in the Chase Purchase
Agreement) is not required for the Borrower's execution of and performance under
this Agreement.
SECTION 11.21. SECURITY AGREEMENT. The Security Agreement constitutes a
first priority security interest affecting one hundred percent (100%) of the
issued and outstanding stock of the Guarantor, and there are no other
Encumbrances affecting the said stock.
SECTION 11.22. SURVIVAL OF REPRESENTATIONS AND WARRANTIES. The Borrower
understands and agrees that the Lender is relying upon the above representations
and warranties in making the Loans to the Borrower. The Borrower further agrees
that the foregoing representations and warranties shall be true and correct in
all material respects as of the date(s) made or deemed made and shall remain in
full force and effect until such time as the Indebtedness shall be paid in full,
or until this Agreement shall be terminated, whichever is the last to occur.
ARTICLE XII
AFFIRMATIVE COVENANTS
In addition to the covenants contained in the Collateral Documents, which
covenants are hereby ratified and confirmed by the Borrower, the Borrower
covenants and agrees as follows:
SECTION 12.1. FINANCIAL STATEMENTS; OTHER REPORTING REQUIREMENTS. The
Borrower will furnish or cause to be furnished to the Lender:
(a) as soon as available and in any event within one hundred twenty (120)
days following the close of fiscal year of the Borrower, audited
consolidated financial statements of the Borrower consisting of a
balance sheet as at the end of such
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fiscal year and statements of income, and statement of cash flow for
such fiscal year, setting forth in each case in comparative form the
corresponding figures for the preceding fiscal year, certified by
Ernst & Young or such other independent certified public accountants
of recognized standing acceptable to the Lender (such acceptance not
to be unreasonably withheld),
(b) as soon as available and in any event within forty-five (45) days
following the close of each calendar quarter, interim consolidated
financial statements of the Borrower, consisting of a balance sheet as
of the end of such quarter and statements of income and cash flow,
certified as true and correct by the Borrower's chief financial
officer as having been prepared in accordance with GAAP consistently
applied,
(c) upon each submission of the financial statements required by (a) and
(b) above, a compliance certificate signed by the chief financial
officer of the Borrower in the form attached hereto as Exhibit A,
certifying that he has reviewed this Agreement and to the best of his
knowledge no Default or Event of Default has occurred, or if such
Default or Event of Default has occurred, specifying the nature and
extent thereof, that all financial covenants in this Agreement have
been met, and providing a computation of all financial covenants
contained herein, and details of any waivers, amendments, or
modifications of any covenant contained in this Agreement, and said
certificate shall include a schedule of all Hedging Agreements,
(d) as soon as available and in any event within thirty (30) days after
filing, a copy of the Borrower's federal tax returns,
(e) by March 31st of each year, a third party engineering report (at
Borrower's expense) dated as of the preceding December 31 covering oil
and gas properties owned by the Borrower and included or to be
included in the Borrowing Base Amount, in form and substance
reasonably satisfactory to the Lender,
(f) as soon as available and in any event within forty five (45) days
after the end of each quarter, the following reports and data: reports
of production (attributable to oil and gas properties owned by the
Borrower and included or to be included in the Facility A Borrowing
Base Amount), commodity prices, sales revenues, operating expenses for
the Leases evaluated for determination of the Facility A Borrowing
Base Amount, and production taxes, in form and content reasonably
acceptable to the Lender,
(g) as soon as available and in any event by September 30th of each year,
an internally prepared engineering report covering oil and gas
properties owned by the Borrower and included or to be included in the
Facility A Borrowing Base Amount, and dated as of no earlier than the
preceding June 30, in form and content reasonably satisfactory to the
Lender, and
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(i) subject to Section 12.14, such other financial information or other
information concerning the Borrower as the Lender may reasonably
request from time to time.
SECTION 12.2. NOTICE OF DEFAULT; LITIGATION; ERISA MATTERS. The Borrower
will give written notice to the Lender as soon as reasonably possible and in no
event more than five (5) Business Days of (i) the occurrence of any Default or
Event of Default hereunder of which it has knowledge, (ii) the filing of any
actions, suits or proceedings against the Borrower in any court or before any
governmental authority or tribunal of which it has knowledge, which could
reasonably be expected to cause a Material Adverse Effect with respect to the
Borrower, (iii) the occurrence of a reportable event under, or the institution
of steps by the Borrower to withdraw from, or the institution of any steps to
terminate, any employee benefit plan as to which the Borrower may have
liability, or (iv) the occurrence of any other action, event or condition of any
nature of which it has knowledge which could reasonably be expected to cause, or
lead to, or result in, any Material Adverse Effect to the Borrower.
SECTION 12.3. MAINTENANCE OF EXISTENCE, PROPERTIES AND LIENS. The Borrower
will (i) continue to engage in the Subject Business and other business
activities reasonably related to thereto; (ii) maintain its existence and good
standing in each jurisdiction in which it is required to be qualified; (iii)
keep and maintain all franchises, licenses and properties necessary in the
conduct of its business in good order and condition, except to the extent the
failure to do so could not reasonably be expected to cause a Material Adverse
Effect; (iv) duly observe and conform to all material requirements of any
governmental authorities relative to the conduct of its business or the
operation of its properties or assets, except to the extent the failure to do so
could not reasonably be expected to cause a Material Adverse Effect; and (v) the
Borrower will maintain in favor of the Lender a first perfected lien and
security interest in the Collateral, subject only to Permitted Encumbrances and
Designated Title Exceptions.
SECTION 12.4. TAXES. The Borrower shall pay or cause to be paid when due,
all taxes, local and special assessments, and governmental charges of every type
and description, that may from time to time be imposed, assessed and levied
against its properties. The Borrower further agrees to furnish the Lender with
evidence that such taxes, assessments, and governmental and other charges due by
the Borrower have been paid in full and in a timely manner, if such data is
requested by the Lender. Notwithstanding the foregoing, the Borrower may
withhold any such payment or elect to contest any lien if the Borrower is in
good faith conducting an appropriate proceeding to contest the obligation to pay
and so long as the Lender's interest in the Collateral is not jeopardized.
SECTION 12.5. INTENTIONALLY DELETED.
SECTION 12.6 COMPLIANCE WITH ENVIRONMENTAL LAWS. The Borrower shall comply
with and shall use reasonable commercial efforts to cause all of its employees,
agents, invitees or sublessees (while such Persons are acting within the scope
of their relationship with the Borrower) to (i) comply with all Environmental
Laws with respect to the disposal of Hazardous Materials, (ii) pay immediately
when due the cost of removal of any such Hazardous Materials, and (iii) keep the
Borrower's properties free of any lien imposed pursuant to any Environmental
Laws, provided that no breach of this Section 12.6 shall occur if (a) the same
is discharged within
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thirty (30) days after the Borrower is notified of non-compliance or an appeal
or appropriate proceedings for review thereof is taken within such period and
Borrower is not obligated to comply pending such appeal or other appropriate
proceedings or (b) failure to do so could not reasonably be expected to have a
Material Adverse Effect.
The Borrower shall give notice to the Lender as soon as reasonably possible
and in no event more than five (5) days after it receives any compliance orders,
environmental citations, or other notices from any Governmental Authority
relating to any Environmental Liabilities relating to its properties or
elsewhere which may reasonably be expected to result in a Default of Event of
Default; the Borrower agrees to take any and all reasonable steps, and to
perform any and all reasonable actions necessary or appropriate to promptly
comply with any such citations, compliance orders or Environmental Laws
requiring the Borrower to remove, treat or dispose of such Hazardous Materials,
and, upon Lender's request, to provide the Lender with satisfactory evidence of
such compliance in excess of $500,000; provided, however, that nothing contained
herein shall preclude the Borrower from contesting any such compliance orders or
citations if such contest is made in good faith, appropriate reserves are
established for the payment for the cost of compliance therewith, and the
Lender's security interest in any such property affected thereby (or the
priority thereof) is not jeopardized.
Regardless of whether any Event of Default hereunder shall have occurred
and be continuing, the Borrower (i) releases and waives any present or future
claims against the Lender for indemnity or contribution in the event the
Borrower becomes liable for any Environmental Lien and/or Remedial Action, and
(ii) agrees to defend, indemnify and hold harmless the Lender from any and all
liabilities (including strict liability), actions, demands, penalties, losses,
costs or expenses (including, without limitation, reasonable attorneys fees and
remedial costs), suits, administrative orders, agency demand letters, costs of
any settlement or judgment and claims of any and every kind whatsoever which may
now or in the future (whether before or after the termination of this Agreement)
be paid, incurred, or suffered by, or asserted against the Lender by any person
or entity or governmental agency for, with respect to, or as a direct or
indirect result of, the presence on or under, or the escape, seepage, leakage,
spillage, discharge, emission, or release from or onto the property of the
Borrower of any Hazardous Materials, regulated by any Environmental Laws,
contamination resulting therefrom, or arising out of, or resulting from, the
environmental condition of such property or the applicability of any
Environmental Laws relating to hazardous materials (including, without
limitation, CERCLA or any so called federal, state or local "super fund" or
"super lien" laws, statute, ordinance, code, rule, regulation, order or decree)
regardless of whether or not caused by or within the control of the Lender (the
costs and/or liabilities described in (i) and (ii) above being hereinafter
referred to as the "Environmental Liabilities"). THE COVENANTS AND INDEMNITIES
CONTAINED IN THIS SECTION 12.6 SHALL SURVIVE THE TERMINATION OF THIS AGREEMENT,
BUT EXCLUDING ALL INDEMNITY MATTERS ARISING BY REASON OF THE GROSS NEGLIGENCE OR
WILLFUL MISCONDUCT ON THE PART OF ANY INDEMNIFIED PARTY; AND, PROVIDED, HOWEVER,
NO RELEASE, WAIVER, DEFENSE OR INDEMNITY SHALL BE AFFORDED UNDER THIS SECTION
12.6 IN RESPECT OF ANY PROPERTY FOR ANY OCCURRENCE ARISING FROM THE ACTS OR
OMISSIONS OF THE LENDER OR ITS AGENTS OR
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REPRESENTATIVES DURING THE PERIOD AFTER WHICH SUCH PERSON, ITS SUCCESSORS OR
ASSIGNS, OR ITS AGENTS OR REPRESENTATIVES, SHALL HAVE OBTAINED OWNERSHIP,
OPERATION OR POSSESSION OF SUCH PROPERTY (WHETHER BY FORECLOSURE OR DEED IN LIEU
OF FORECLOSURE, AS MORTGAGEE-IN-POSSESSION OR OTHERWISE). ANY CLAIMS UNDER THIS
SECTION 12.6 SHALL BE SUBJECT TO SECTION 15.9.
SECTION 12.7. FURTHER ASSURANCES. The Borrower will, at any time and from
time to time, execute and deliver such further instruments and take such further
action as may reasonably be requested by the Lender, in order to cure any
defects in the execution and delivery of, or to comply with or accomplish the
covenants and agreements contained in this Agreement or the Collateral
Documents.
SECTION 12.8. FINANCIAL COVENANTS. The Borrower shall comply with the
following covenants and ratios:
(a) MINIMUM CURRENT RATIO. The Borrower shall at all times maintain a
minimum Current Ratio of 1.0 to 1.0.
(b) MINIMUM TANGIBLE NET WORTH. The Borrower shall at all times maintain a
minimum Consolidated Tangible Net Worth of $56,000,000.00 plus 100% of
the any increase in shareholder's equity resulting from the sale or
issuance of preferred (to the extent such issuances increase
shareholders equity on a GAAP basis) and common stock in Borrower
subsequent to March 31, 2002, plus 50% of the Borrower's net income
(excluding losses) subsequent to March 31, 2002, excluding the effect
of any cumulative after-tax amounts of ceiling test write-downs
incurred pursuant to Regulation SX4.10 of the Securities and Exchange
Commission subsequent to December 31, 2001.
(c) MINIMUM QUARTERLY DEBT SERVICE COVERAGE RATIO. The Borrower shall
maintain at the end of each quarter a Debt service coverage ratio of
not less than 1.25 to 1.0. For purposes of this covenant, the non-cash
effects, if any, of Hedging Agreements pursuant to SFAS 133 will not
be included, nor will the effect, if any, of ceiling test write-downs
pursuant to Regulation SX4.10 of the Securities and Exchange
Commission be included. Debt service coverage shall be calculated
based on GAAP as follows: the ratio of (a) the difference of (i)
EBITDA for the quarter just ended (excluding EBITDA related to assets
pledged to secure Non-Recourse Indebtedness), minus (ii) permitted
cash dividends paid during the quarter just ended, divided by (b) the
sum of (i) required principal and interest paid in cash on the
Indebtedness during the quarter just ended, plus (ii) all principal
and interest paid in cash on Debt other than the Indebtedness during
the quarter just ended, plus (iii) the positive difference, if any, of
(x) principal and interest paid in cash on Non-Recourse Indebtedness
during the quarter just ended, minus (y) positive EBITDA related to
assets pledged to secure Non-Recourse Indebtedness during the quarter
just ended.
SECTION 12.9. OPERATIONS. The Borrower shall conduct its business affairs
in a reasonable and prudent manner and in compliance with all applicable
federal, state and municipal laws,
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ordinances, rules and regulations respecting its properties, charters,
businesses and operations, including compliance with all minimum funding
standards and other requirements of ERISA of 1974, and other laws applicable to
any employee benefit plans which they may have, except to the extent the failure
to do so could not reasonably be expected to cause a Material Adverse Effect.
SECTION 12.10. CHANGE OF LOCATION. The Borrower shall, within ten (10)
Business Days prior to any such change, notify the Lender in writing of any
proposed change in the location of its chief executive office.
SECTION 12.11. EMPLOYEE BENEFIT PLANS. The Borrower will maintain each
employee benefit plan as to which it may have any liability, in material
compliance with all applicable requirements of law and regulations.
SECTION 12.12. DEPOSIT AND OPERATING ACCOUNTS. The Borrower will maintain
its primary operating and savings accounts with the Lender.
SECTION 12.13. PRODUCTION PROCEEDS. Subject to the terms and conditions of
the Mortgage, the Borrower will cause all production proceeds and revenues
attributable to the Mortgaged Properties to be paid and deposited in the
Borrower's accounts maintained with Lender, and shall not redirect initial
deposit of such proceeds to any other accounts.
SECTION 12.14. FIELD AUDITS; OTHER INFORMATION. Upon reasonable prior
notice, the Borrower shall allow the Lender's employees and agents access to its
books and records and properties during normal business hours to perform field
audits from time to time. The Borrower shall pay all reasonable costs and
expenses associated with such field audits. The Borrower will provide the Lender
with such other information as the Lender may reasonably request from time to
time, subject in all cases to any confidentiality restrictions that may be
applicable to the Borrower and its Subsidiaries and to any confidentiality
restrictions that the Borrower reasonably imposes on the Persons receiving such
information; provided, however, that neither the Borrower nor any of its
Subsidiaries shall be required to disclose to Lender or any agents or
representatives thereof any information which is the subject of attorney-client
privilege or attorney's work product privilege properly asserted by the
applicable Person to prevent the loss of such privilege in connection with such
information; and provided, further, that the Borrower will use commercially
reasonable efforts to furnish such information (excluding information covered by
confidentiality restrictions in agreements relating to seismic, geologic or
geophysical data or similar technical and business matters relating to the
exploration for oil and gas), which requirement shall be satisfied if the Lender
is offered the opportunity to review such confidential information by executing
or otherwise becoming a party to the confidentiality restrictions on
substantially the same terms (including any standstill provisions) as are
applicable to the Borrower.
SECTION 12.15. INSURANCE. The Borrower shall maintain in effect all
insurance required by this Agreement and the Collateral Documents, and the
Borrower agrees to comply with the requirements of Section 11.6. above. The
Borrower agrees to provide the Lender with certificates or binders evidencing
such insurance coverage on an annual basis, and, if requested
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by the Lender, the Borrower further agrees to promptly furnish the Lender with
copies of all renewal notices and copies of receipts for paid premiums. The
Borrower shall provide the Lender with certificates or binders evidencing
insurance coverage pursuant to all renewal or replacement policies of insurance
no later than fifteen (15) days before any such existing policy or policies
should expire.
SECTION 12.16. SUBSIDIARIES. The Borrower agrees that any Subsidiary of the
Borrower formed by or behalf of the Borrower after the date of this Agreement
shall execute a guaranty of the Indebtedness (in a form substantially similar to
the Guaranty).
SECTION 12.17. POST CLOSING REQUIREMENTS. The Borrower agrees that within
ninety (90) days from the execution of this Agreement, the Borrower shall (i)
obtain marital status information for Jean E. Mitchell and Robert W. Irvine as
of June 12, 2000. If either were married on such date, Borrower agrees to obtain
ratification(s) from Jean E. Mitchell and/or Robert W. Irvine's spouse(s) of the
Oil, Gas and Mineral Lease dated June 1, 2002, recorded under Entry No. 920196,
records of Lafourche Parish, Louisiana, to file such ratification(s) in the
public records of Lafourche Parish, Louisiana and to provide certified copies of
the recorded ratifications to the Lender; (ii) obtain a ratification from the
spouse of Phil Bryant, Jr. of the July 23, 2002 assignment in favor of Borrower,
recorded under Entry No. 920198 records of Lafourche Parish, Louisiana; and
(iii) search the public records of Lafourche Parish Louisiana for the time
period March 31, 2002 through May 31, 2002 in the name of Patricia Jones
Edgerton, as Executrix of the Succession of Nettie Marie Jones and to submit any
documents filed of record within that time period to Lender.
ARTICLE XIII
NEGATIVE COVENANTS
In addition to the negative covenants contained in the Collateral
Documents, which covenants are hereby ratified and confirmed by the Borrower,
the Borrower covenants and agrees as follows:
SECTION 13.1. LIMITATIONS ON FUNDAMENTAL CHANGES. Without the prior written
consent of the Lender, the Borrower shall not form any Subsidiary that does not
execute a guaranty of the Indebtedness, nor shall the Borrower consummate any
transaction of merger or consolidation unless the Borrower is the surviving
entity, or liquidate or dissolve itself (or suffer any liquidation or
dissolution).
SECTION 13.2. DISPOSITION OF ASSETS. The Borrower shall not convey, sell,
lease, assign, transfer or otherwise dispose of, any of its property or assets
to which the Lender has included a value in the Facility A Borrowing Base Amount
(whether now owned or hereafter acquired) in excess of $500,000.00 in the
aggregate between any two scheduled semi-annual Facility A Borrowing Base Amount
redeterminations, without first obtaining the Lender's written consent, which
consent will not be withheld provided the Borrower pays in full such portion of
the Total
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Outstandings, if any, that exceeds the Facility A Borrowing Base Amount,
attributable to the proposed asset sale, as determined by Lender in its complete
and sole discretion based on its normal practices and standards for oil and gas
loans.
SECTION 13.3. REPURCHASE OF STOCK; RESTRICTED PAYMENTS. The Borrower shall
not (i) repurchase or redeem for cash any of its common or preferred stock or
(ii) pay any dividends or distributions, without the prior written consent of
the Lender; provided, however, that (a) the Borrower may pay dividends on its
existing Series B Convertible preferred stock and any additional shares of
Series B Convertible preferred stock issued after the date of this Agreement, so
long as no Event of Default exists hereunder at the time of such payment and/or
results from such payment, (b) the Borrower may declare and pay dividends
consisting entirely of capital stock of the Borrower, (c) the Borrower may make
cash payments in lieu of fractional shares in an aggregate amount not exceeding
$100,000, and (d) the Borrower may declare and pay distributions effecting
"poison pill" rights plans provided that any securities or rights so distributed
have a nominal fair market value at the time of declaration.
SECTION 13.4. ENCUMBRANCES; NEGATIVE PLEDGE. The Borrower shall not create,
incur, assume or permit to exist any Encumbrances on any of its property now
owned or hereafter acquired, except for the following (hereinafter referred to
as the "Permitted Encumbrances"):
(a) Encumbrances for taxes, assessments, or other governmental charges not
yet due or which are being contested in good faith by appropriate
action promptly initiated and diligently conducted, if such reserves
as shall be required by GAAP shall have been made therefor;
(b) Encumbrances of landlords, vendors, carriers, warehousemen, mechanics,
laborers, materialmen and other Encumbrances arising by law in the
ordinary course of business for sums either not yet due or being
contested in good faith by appropriate action promptly initiated and
diligently conducted, if such reserve as shall be required by GAAP
shall have been made therefor;
(c) Inchoate liens arising under ERISA to secure the contingent
liabilities, if any, permitted by this Agreement;
(d) Encumbrances created by the Collateral Documents and any other
Encumbrances in favor of the Lender to secure the Indebtedness;
(e) Subject to Section 13.11. below, Encumbrances granted prior to the
date of this Agreement to secure Non-Recourse Indebtedness, and/or
Encumbrances granted after the date of this Agreement to secure
Non-Recourse Indebtedness;
(f) Encumbrances existing on the date hereof and set forth in Schedule
13.4, provided that such Encumbrances shall secure only those
obligations which they secure on the date hereof;
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(g) Pledges and deposits made in the ordinary course of business in
compliance with workmen's compensation, unemployment insurance and
other social security laws or regulations;
(h) Deposits to secure the performance of bids, trade contracts (other
than for Indebtedness), leases (other than capital lease obligations),
statutory obligations, surety and appeal bonds, performance bonds and
other obligations of a like nature incurred in the ordinary course of
business;
(i) Zoning restrictions, easements, licenses, covenants, conditions,
rights-of-way, restrictions on use of real property and other similar
encumbrances incurred in the ordinary course of business and minor
irregularities of title that, in the aggregate, are not substantial in
amount and do not materially detract from the value of the property
subject thereto or interfere with the ordinary conduct of the business
of the Borrower or any of its Subsidiaries;
(j) Deposits, encumbrances or pledges to secure payments of workmen's
compensation and other payments, public liability, unemployment and
other insurance, old-age pensions or other social security
obligations, or the performance of bids, tenders, leases, contracts
(other than contracts for the payment of money), public or statutory
obligations, surety, stay or appeal bonds, or other similar
obligations arising in the ordinary course of business;
(k) Any Designated Title Exceptions which are incurred in the ordinary
course of business and would not materially adversely affect the
operations of the Borrower or otherwise in the aggregate have a
Material Adverse Effect;
(l) Any Encumbrance securing Purchase Money Debt, provided that, (i) such
security interest is incurred, and the Debt secured thereby is
created, within 180 days after the acquisition (or completion of
construction) of the property or assets subject thereto, (ii) the Debt
secured thereby does not include any other Debt that is not from the
same financing source, (iii) such security interest do not apply to
any other property or assets of the Borrower or any Subsidiary except
any such property or assets which are the subject of any Encumbrance
securing Debt from such financing source, and (iv) such Encumbrance
does not affect any of the Mortgaged Properties included in the
determination of the Facility A Borrowing Base Amount;
(m) Any Encumbrance existing on any property or asset (together with any
receivables, intangibles and proceeds related thereto) prior to the
acquisition thereof by the Borrower or any Subsidiary, provided that
(i) such Encumbrance is not created in contemplation of or in
connection with such acquisition and (ii) such Encumbrance does not
apply to any other property or assets of the Borrower or any
Subsidiary; and provided, further, that (x) such Encumbrances do not
secure any Debt or other obligation not permitted under this
Agreement, and (y)
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such Encumbrances do not affect any of the Mortgaged Properties
included in the determination of the Facility A Borrowing Base Amount;
(n) Encumbrances securing Purchase Money Debt and Capital Lease
Obligations in real property, improvements thereto or equipment
hereafter acquired (or, in the case of improvements, constructed) by
the Borrower or any Subsidiary (together with any receivables,
intangibles and proceeds related thereto), provided that (i) such
security interests secure Debt permitted by Section 13.5(l)(i), (ii)
such security interests are incurred, and the Debt secured thereby is
created, within 180 days after such acquisition (or completion of
construction), (iii) such security interests do not apply to any other
property or assets of the Borrower or any Subsidiary, and (iv) such
security interests do not affect any of the Mortgaged Properties
included in the determination of the Facility A Borrowing Base Amount;
(o) Encumbrances arising out of judgments or awards in respect of which
the Borrower shall in good faith be prosecuting an appeal or
proceedings for review and in respect of which it shall have secured a
subsisting stay of execution pending such appeal or proceedings for
review, provided the Borrower shall have set aside on its books
adequate reserves, in accordance with GAAP, with respect to such
judgment or award;
(p) Encumbrances on the property or assets of any Person existing at the
time such Person becomes a Subsidiary of the Borrower and not incurred
as a result of (or in connection with or in anticipation of) such
Person's becoming a Subsidiary of the Borrower, provided that such
Encumbrances do not extend to or cover any property or assets of the
Borrower or any of its Subsidiaries other than the property or assets
encumbered at the time such Person becomes a Subsidiary of the
Borrower, and provided, further, that (i) such Encumbrances do not
secure any Debt or other obligation not permitted under this
Agreement, and (ii) such Encumbrances do not affect any of the
Mortgaged Properties included in the determination of the Facility A
Borrowing Base Amount; and
(q) Encumbrances securing Debt permitted to be incurred under Section
13.5(j).
SECTION 13.5. DEBTS. The Borrower, without the prior written consent of the
Lender, will not incur, create, assume or in any manner become or be liable in
respect of any Debt, except for:
(a) The Indebtedness;
(b) Trade payables or operating and facility leases from time to time
incurred in the ordinary course of business;
(c) Non-Recourse Indebtedness not to exceed $25,000,000.00 at any time
outstanding;
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(d) Taxes, assessments or other government charges which are not yet due
or are being contested in good faith by appropriate action promptly
initiated and diligently conducted, if such reserve as shall be
required by generally accepted accounting principles shall have been
made therefore;
(e) The indebtedness evidenced by the Subordinated Promissory Notes and
guaranties executed by any Subsidiary of the Borrower guaranteeing
payment thereof;
(f) Indebtedness existing as of the date of this Agreement as set forth in
Schedule 13.5;
(g) Indebtedness arising under any performance bond, or letter of credit
obtained for similar purposes, or any reimbursement obligations in
respect thereof, entered into in the ordinary course of business;
(h) Debt of the Borrower to any wholly owned Subsidiary of the Borrower
and Debt of any wholly owned Subsidiary of the Borrower to the
Borrower or any other wholly owned Subsidiary of the Borrower;
(i) Contingent liability in the aggregate amount of $5,000,000.00
representing the Guarantor's proportionate share of costs and expenses
to be incurred in the performance of RMG's drilling program, as said
drilling program is described in Section 2.1 of the Purchase and Sale
Agreement dated June 29, 2001 between the Guarantor, as Purchaser, and
RMG, as Seller;
(j) Debt represented by Hedging Agreements permitted by this Agreement;
(k) Guaranties by the Borrower of Debt of any Subsidiary and by any
Subsidiary of Debt of the Borrower or any other Subsidiary; and
(l) Subject to a maximum aggregate principal amount at any time
outstanding not in excess of $1,000,000.00, the following: (i)
Purchase Money Debt and Capitalized Lease Obligations; (ii) additional
unsecured Debt; and (iii) Debt of any Person that becomes a Subsidiary
after the date hereof; provided, that such Debt exists at the time
such Person becomes a Subsidiary and is not created in contemplation
of or in connection with such Person becoming a Subsidiary.
SECTION 13.6. INVESTMENTS, LOANS AND ADVANCES. The Borrower will not make
or permit to remain outstanding any loans or advances to or make investments or
acquire an equity interest in any Person, except for:
(a) Direct obligations of, or obligations the principal of and interest on
which are unconditionally guarantied by, the United States of America
(or by any agency thereof to the extent such obligations are backed by
the full faith and credit of the United States of America), in each
case maturing within one year from the date of acquisition thereof;
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(b) Investments in commercial paper maturing within 270 days from the date
of acquisition thereof and having, at such date of acquisition, the
highest credit rating obtainable from Standard & Poor's Ratings
Service or from Moody's Investors Service, Inc.;
(c) Investments in certificates of deposit, banker's acceptances,
repurchase agreements and time deposits maturing within one year from
the date of acquisition thereof issued or guaranteed by or placed
with, and money market deposit accounts issued or offered by, any
domestic office of any commercial bank organized under the laws of the
United States of America or any State thereof that has a combined
capital and surplus and undivided profits of not less than
$250,000.000;
(d) Shares of funds registered under the Investment Company Act of 1940,
as amended, that have assets of at least $100,000,000 and invest only
in obligations described in clauses (a) through (c) above to the
extent that such shares are rated by Moody's Investors Service, Inc.
or Standard & Poor's Ratings Service in one of the two highest rating
categories assigned by such agency for shares of such nature;
(e) Loans by the Borrower to the Guarantor and any other Subsidiary of
Borrower that is a guarantor of the Indebtedness and/or capital
contributions and/or investments by the Borrower in the Guarantor and
any other Subsidiary of Borrower that is a guarantor of the
Indebtedness;
(f) Loans or advances to employees in the ordinary course of business in
an aggregate amount to any single employee not in excess of $75,000
(or, if and to the extent such loans or advances shall be used by such
employee for relocation expenses, $100,000) and in an aggregate amount
for all employees of the Borrower and the Subsidiaries not in excess
of $500,000 at any one time outstanding;
(g) Trade credits and accounts arising in the ordinary course of business;
(h) Investments made as a result of the receipt of non-cash consideration
from an asset sale that was made pursuant to and in compliance with
this Agreement;
(i) Investments made in any debtor of the Borrower as a result of the
receipt of stock, obligations or securities in settlement of debts
created in the ordinary course of business and owing to the Borrower
or any of its Subsidiaries;
(j) Investments made pursuant to the requirements of farm-out, farm-in,
joint operating, joint venture or area of mutual interest agreements,
gathering systems, pipelines or other similar or customary
arrangements entered into in the ordinary course of business
(including, without limitation, advances to operators under operating
agreements entered into by Borrower in the ordinary course of
business)
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(provided that any such single investment in excess of $1,000,000
shall be approved by the Board of Directors of the Borrower);
(k) Investments made in connection with the purchase, lease or other
acquisition of all or substantially all of the business, property or
assets of any Person, or capital stock of any Person, or any division,
line of business or business unit of any Person (including, without
limitation, (i) by the merger or consolidation of such Person into the
Borrower or any of its Subsidiaries or by the merger of a Subsidiary
of the Borrower into such Person and (ii) the purchase of proved
reserves); and
(l) Any other investments in any Person having an aggregate fair market
value (measured on the date each such investment was made and without
giving effect to subsequent changes in value), when taken together
with all other investments made pursuant to this clause (l) not to
exceed $1,000,000.
SECTION 13.7. OTHER AGREEMENTS. The Borrower will not enter into any
agreement containing any provision which would be violated or breached by the
performance of its obligations hereunder or under any instrument or document
delivered or to be delivered by it hereunder or in connection herewith; provided
that the Borrower may agree to the redemption or repurchase of its securities
upon a change of control or dissolution, winding-up or liquidation of, or the
merger or sale of substantially all the assets of, the Borrower (provided that
nothing in this Section 13.7 shall permit any action otherwise prohibited by
Sections 13.1 and 13.2 hereof.).
SECTION 13.8. TRANSACTIONS WITH AFFILIATES. Except as set forth on Schedule
13.8 attached hereto, the Borrower shall not sell or transfer any property or
assets to, or purchase or acquire any property or assets from, or otherwise
engage in any other transactions with, any of its affiliates unless such
transaction is on terms that are no less favorable to the Borrower or such
Subsidiary, as the case may be, than those that could be obtained at the time of
such transaction on an arm's-length basis from a Person who is not an affiliate
and if such transaction involves an amount in excess of $500,000, such
transaction has been approved by a majority of the members of the Board of
Directors of the Borrower having no personal stake in such transaction;
provided, however, that this Section 13.8 (i) shall not apply to transactions
between a Subsidiary and the Borrower or any other Subsidiary, (ii) shall not
prohibit any person serving as an officer, director, employee or consultant of
the Borrower or any Subsidiary from (A) receiving reasonable compensation,
benefits or indemnification in connection with his or her services in such
capacity (except as otherwise included hereby), provided that any such
compensation, benefits or indemnification are approved by a majority of the
disinterested members of the Board of Directors of the Borrower or by the
Compensation Committee of the Borrower, (B) receiving advances for travel or
other business expenses made in the ordinary course of business or (C)
participating in any benefit or compensation plan; and (iii) shall not restrict
the Borrower from repaying to any director or its affiliates when due on its
scheduled maturity dates any indebtedness for borrowed money permitted to be
incurred in accordance with this Agreement.
SECTION 13.9. USE OF REVOLVING LOAN PROCEEDS. The Borrower shall not use
any Revolving Loan proceeds to finance investments in marketable securities.
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SECTION 13.10. COMMODITY TRANSACTIONS. The Borrower shall not enter into
any speculative commodity transactions of any type or Hedging Agreement relating
to the sale of aggregate Hydrocarbons production in excess of seventy-five
percent (75%) of the total volume of such production projected in the most
recent independent engineering report delivered to the Lender pursuant to
Section 12.1(e) or as projected in the most recent internally prepared
engineering report delivered to the Lender pursuant to Section 12.1(g),
whichever is more recent, to come from the Borrower's proved developed producing
reserves during the term of such Hedging Agreement. Notwithstanding the
foregoing, the maximum duration of any permitted Hedging Agreement shall not
exceed twenty-four (24) months. In addition, if Borrower desires to enter into
Hedging Agreements affecting new wells, Borrower agrees to obtain the Lender's
prior written consent to such Hedging Agreements, which consent shall not be
unreasonably withheld.
SECTION 13.11. INTENTIONALLY DELETED.
SECTION 13.12. PAYMENTS ON PERMITTED SUBORDINATED DEBT. The Borrower and
the Lender agree that the Borrower is permitted to pay the Subordinate