<PAGE> 1
2,500,000 SHARES
[CARRIZO LOGO]
CARRIZO OIL & GAS, INC.
COMMON STOCK
($0.01 PAR VALUE)
All of the shares of Common Stock offered hereby are being sold by Carrizo
Oil & Gas, Inc. (the "Company"). The Common Stock has been approved for
inclusion on the Nasdaq National Market under the symbol "CRZO." Prior to the
Offering, there has been no public market for the Common Stock. See
"Underwriting" for factors considered in determining the initial public offering
price.
THE COMMON STOCK OFFERED HEREBY INVOLVES A HIGH DEGREE OF RISK. SEE "RISK
FACTORS" ON PAGE 10.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
==============================================================================================================
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS(1) COMPANY(2)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Share............................... $11.00 $0.77 $10.23
- --------------------------------------------------------------------------------------------------------------
Total(3)................................ $27,500,000 $1,925,000 $25,575,000
==============================================================================================================
</TABLE>
(1) See "Underwriting" for indemnification arrangements.
(2) The estimated expenses of $1.2 million are payable by the Company.
(3) The Company has granted to the Underwriters a 30-day option to purchase up
to an additional 375,000 shares of Common Stock solely to cover
over-allotments. If this option is exercised in full, total Price to Public,
Underwriting Discounts and Commissions and Proceeds to Company will be
$31,625,000, $2,213,750 and $29,411,250, respectively. See "Underwriting."
The shares of Common Stock offered hereby are being offered by the several
Underwriters, subject to prior sale and acceptance by the Underwriters and
subject to their right to reject any order in whole or in part. It is expected
that the Common Stock will be available for delivery on or about August 11, 1997
at the offices of Schroder & Co. Inc., New York, New York.
SCHRODER & CO. INC. JEFFERIES & COMPANY, INC.
August 6, 1997
<PAGE> 2
[MAP SHOWING COUNTIES AND PARISHES WITH CARRIZO ACTIVITY AND A 3-D SEISMIC
VOLUME FROM ONE OF CARRIZO'S GULF COAST PROJECTS]
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS THAT
STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK.
SPECIFICALLY, THE UNDERWRITERS MAY OVERALLOT IN CONNECTION WITH THE OFFERING,
AND MAY BID FOR, AND PURCHASE, SHARES OF THE COMMON STOCK IN THE OPEN MARKET.
FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING."
<PAGE> 3
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements, including the notes thereto, appearing
elsewhere in this Prospectus. Unless otherwise indicated, the information in
this Prospectus (i) gives effect to the Combination Transactions (as defined
below under "-- The Combination Transactions") and the issuance of approximately
2,290,000 shares of Common Stock pursuant to such transactions, (ii) assumes
that the Underwriters' over-allotment option will not be exercised and (iii) has
been adjusted to reflect the 521-for-one split of the Common Stock effected in
June 1997. Unless otherwise indicated by the context, references herein to
"Carrizo" mean Carrizo Oil & Gas, Inc., a Texas corporation that is the issuer
of the Common Stock offered hereby, and references to the "Company" mean Carrizo
and its corporate and partnership subsidiaries and predecessors. Certain terms
used herein relating to the oil and natural gas industry are defined in the
Glossary of Certain Industry Terms included elsewhere in this Prospectus.
THE COMPANY
OVERVIEW
Carrizo is an independent oil and gas company engaged in the exploration,
development, exploitation and production of natural gas and crude oil. The
Company's operations are currently focused onshore in proven oil and gas
producing trends along the Gulf Coast, primarily in Texas and Louisiana in the
Frio, Wilcox and Vicksburg trends. The Company believes that the availability of
economic onshore 3-D seismic surveys has fundamentally changed the risk profile
of oil and gas exploration in these regions. Recognizing this change, the
Company has aggressively sought to control significant prospective acreage
blocks for targeted, proprietary, 3-D seismic surveys. As of July 31, 1997, the
Company had assembled approximately 355,000 gross acres under lease or option.
Approximately 70% of the Company's current acreage position is covered by
3-D seismic data that the Company has acquired, or is in the process of
acquiring, in its first 15 seismic surveys. The Company expects to acquire
additional 3-D seismic data during the remainder of 1997 and 1998 that will
cover substantially all of its remaining current acreage position. From the data
generated by its first seven proprietary seismic surveys, covering 200 square
miles (128,000 acres), 94 drillsites have been identified. The Company's capital
budgets for 1997 and 1998 of approximately $21.9 million and $43.8 million,
respectively, include amounts for the acquisition of additional 3-D seismic data
and for the drilling of 67 gross wells (26.9 net) in 1997 with a 40% average
working interest and the drilling of 147 gross wells (67.5 net) in 1998 with an
anticipated 46% average working interest. In addition, the Company anticipates
that as its existing 3-D seismic data is further evaluated, and 3-D seismic data
is acquired over the balance of its acreage, additional prospects will be
generated for drilling beyond 1998.
The Company's primary drilling targets have been shallow (from 4,000 to
7,000 feet), normally pressured reservoirs that generally involve moderate cost
(typically $200,000 to $500,000 per completed well) and risk. Many of these
drilling prospects also have secondary, deeper, over-pressured targets which
have greater economic potential but generally involve higher cost (typically $1
million to $2 million per completed well) and risk. The Company often seeks to
sell a portion of these deeper prospects to reduce its exploration risk and
financial exposure while still allowing the Company to retain significant upside
potential. Deeper targets have been identified in seven of the Company's 67
prospects budgeted for drilling in 1997. The Company operates the majority of
its projects through the exploratory phase but may relinquish operator status to
qualified partners in the production phase to control costs and focus resources
on the higher-value exploratory phase. As of June 30, 1997, the Company operated
66 producing oil and gas wells, which accounted for 57% of the wells in which
the Company had an interest.
1
<PAGE> 4
The Company has experienced rapid increases in reserves, production and
earnings before interest expense, income taxes, depreciation, depletion and
amortization ("EBITDA") since its inception in 1993 due to the growth of its 3-D
based drilling and development activities. From January 1, 1996 to March 31,
1997, the Company participated in the drilling of 29 gross wells (10.2 net) with
a commercial well success rate of approximately 79%. This drilling success
contributed to the Company's total proved reserves as of March 31, 1997 of
approximately 38.8 Bcfe, with a PV-10 Value of $30.4 million. From inception
through March 31, 1997, the Company's average finding and development cost was
approximately $0.47 per Mcfe. The Company's production has increased 125% from
321 MMcfe for the three months ended March 31, 1996 to 721 MMcfe for the three
months ended March 31, 1997. EBITDA has also increased significantly from
$328,000 for the three months ended March 31, 1996 to $1.1 million for the three
months ended March 31, 1997.
In addition to its core exploratory operations, the Company operates a
heavy oil project in Anderson County, Texas which, as of March 31, 1997,
contained proved reserves of approximately 3.6 MMBbls of 19 degrees API gravity
crude oil. The project produces from a depth of 500 feet and utilizes a tertiary
steam drive as an enhanced oil recovery process. During the first quarter of
1997, the Company produced 107 Bbls/d of oil from this project, which averaged a
$0.65 per Bbl premium over West Texas Intermediate crude due to the produced
oil's suitability as a lube oil feedstock.
The Company's management team has extensive energy industry experience.
S.P. Johnson IV, the Company's President and Chief Executive Officer, has 18
years of industry experience, including 15 years with Shell Oil Company where he
served in various managerial positions. The Company's technical and operating
employees have an average of 15 years of industry experience, in many cases with
major and large independent oil companies, including Shell Oil Company, Vastar
Resources, Inc., Pennzoil Company and Tenneco Inc. The Company's Board of
Directors and major shareholders include its Chairman, Steven A. Webster, who is
also Chairman and Chief Executive Officer of Falcon Drilling Company Inc., and
Paul B. Loyd, Jr., the Chairman and Chief Executive Officer of Reading & Bates
Corporation.
The Company believes that its future growth will be driven by the drilling
and development of existing identified opportunities as well as new 3-D based
prospects that are continually being identified from its growing project
portfolio. The Company intends to use the proceeds of this Offering to
accelerate its drilling and development activities, expand its prospective
acreage acquisition program and increase the number and size of, and working
interest in, additional 3-D based projects.
BUSINESS STRATEGY
The Company's business strategy is to profitably expand its reserve base,
production levels and EBITDA through the following key elements:
Aggressive Acreage and Seismic Acquisition Program. The Company seeks to
control significant prospective acreage positions in proven producing trends and
then acquire 3-D seismic data to evaluate this acreage. The Company believes
that recent technical improvements and cost reductions of onshore 3-D seismic
surveys and oil and gas drilling techniques have changed the risk/reward profile
of exploration in these regions and allow for the profitable exploration and
development of previously undetected or uneconomic drilling prospects. The
Company believes that its existing large acreage position and seismic database
will generate a significant inventory of drillsites over the next several years.
Focused Exploration. The Company intends to maintain its exploration focus
primarily in the onshore Gulf Coast region, which it believes offers numerous
advantages, including: (i) geologic trends that are prone to the accumulation of
significant oil and gas reserves in multiple target zones, (ii) a large number
of over-looked or under-exploited drilling prospects, (iii) familiarity of the
Company's personnel with the geology of the region, (iv) established
relationships with other regional participants and (v) availability of pipeline
and operating infrastructure. Based on the
2
<PAGE> 5
results to date of its exploration activities, the Company believes that
significant undiscovered reserves remain in this region, and the Company plans
to utilize its existing database of 3-D seismic and geologic data and its
knowledge of the region's producing fields and trends to further expand its
operations within this core region.
Leveraged Project and Drillsite Generation Program. The Company maintains a
flexible and diversified approach to project identification to increase its
exposure to projects in its core areas. The Company's project areas have been
identified by a broad network that includes contract geoscientists who have
expertise in a particular project area, the exploration teams of several
industry partners as well as the Company's internal geophysical team. This
approach has enabled the Company to increase the number and diversity of
projects from which the Company has developed its exploration program while
controlling the costs associated with these operations. Similarly, in
identifying specific drillsites within a project area, the Company's internal
exploration team has worked with outside contract geoscientists and joint
venture partners.
Prospects with Attractive Risk/Reward Balance. The Company seeks to retain
significant working interest positions in exploration prospects that fit its
risk/reward criteria. Many of the Company's exploration prospects contain both
primary targets with shallower, normally pressured reservoirs that generally
involve moderate cost and risk, as well as secondary targets that consist of
deeper, over-pressured and often larger reservoirs but involve higher cost and
risk. The Company typically retains all or the majority of its interests in the
shallow targets and often sells a portion of its interests in the deeper targets
to industry partners in order to mitigate its exploration risk and fund the
anticipated capital requirements for the retained portion of these targets. The
Company believes that this strategy affords it significant upside potential with
reduced overall risk.
The Company's ability to implement its business strategy will be subject to
numerous risks, including those described under "Dependence on Exploratory
Drilling Activities," "Volatility of Oil and Natural Gas Prices," "Ability to
Manage Growth and Achieve Business Strategy" and other captions under "Risk
Factors."
RECENT OPERATING RESULTS
During the second quarter of 1997, the Company participated in the drilling
of 21 gross wells (8.8 net), of which 18 (7.3 net) were successfully completed.
Partly as a result of this drilling activity, production volumes for the second
quarter of 1997 increased to 835.9 MMcf of natural gas and 27.2 MBbls of oil.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Recent Operating Results."
3
<PAGE> 6
CURRENT EXPLORATORY PROJECTS
The Company is currently evaluating 32 exploration project areas. As of
June 30, 1997, the Company had an existing 3-D seismic database of 651 square
miles and was acquiring an additional 486 square miles of data (totaling 1,137
square miles of 3-D seismic data). To date, all project areas for which seismic
data has been interpreted have yielded multiple prospects and drillsites. The
Company is continuing to receive and interpret data covering these project areas
and believes that each project area has the potential for additional prospects
and drillsites. For additional information as to these project areas, see
"Business -- Significant Project Areas."
1997-1998 EXPLORATION PROGRAM
<TABLE>
<CAPTION>
SQ. MILES OF 3-D
GROSS SEISMIC DATA AT TOTAL
ACREAGE JUNE 30, 1997 1997
LEASED OR ---------------------- AND
UNDER BUDGETED 1997 1998 1998 AVERAGE
OPTION AT EXISTING FOR BUDGETED BUDGETED BUDGETED AVERAGE NET
JULY 31, OR BEING ACQUISITION GROSS GROSS GROSS WORKING REVENUE
PROJECT AREAS 1997 ACQUIRED 1997-1998 WELLS(1) WELLS(2) WELLS INTEREST(3) INTEREST(3)
------------- --------- -------- ----------- -------- -------- -------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
TEXAS
Starr/Hidalgo........... 4,435 340(4) -- 12 15 27 50.0% 37.5%
Encinitas/Kelsey........ 9,110 32 -- 10 1 11 27.5% 23.0%
Buckeye................. 36,105 62 -- 16 11 27 50.0% 39.0%
La Rosa................. 8,249 22 -- -- 4 4 31.5% 23.6%
Mexican Sweetheart...... 30,795 40 -- -- 8 8 25.0% 18.8%
McFaddin Ranch.......... 5,374 15 -- 4 4 8 37.5% 28.1%
Cologne................. 18,200 40 -- -- 8 8 25.0% 18.8%
South Cabeza Creek...... 7,128 20 -- -- 4 4 52.5% 39.4%
East McFaddin........... 6,440 11 -- 1 -- 1 20.0% 16.5%
Hiawatha................ 15,516 22 -- 12 4 16 42.0% 31.5%
Western 325............. -- 320(4) -- 2(2) 5 7 50.0% 37.5%
Lance................... 18,536 30 -- 4 5 9 25.0% 19.3%
Highway 59.............. 4,995 -- 20 -- 4 4 20.0% 15.0%
Geronimo................ 29,358 107 -- 3 10 13 15.0% 11.3%
RPP Welder.............. 31,182 60 -- -- 10 10 15.0% 11.3%
Midway.................. 1,235 -- 15 -- 4 4 50.0% 37.5%
Lost Bridge............. 5,065 16 -- -- 3 3 50.0% 37.5%
Drake 202............... 3,877 -- 19 -- -- -- 100.0% 82.8%
Other (11 Areas)........ 114,664 -- 291 -- 42 42 72.5% 56.9%
LOUISIANA
North Chalkley.......... 1,130 -- 20 1 2 3 18.0% 14.2%
Atchafalaya............. 3,611 -- -- 1 2 3 55.4% 41.5%
Live Oak................ 350 -- -- 1 1 2 20.0% 15.0%
------- ----- --- -- --- ---
TOTAL..................... 355,355 1,137 365 67 147 214
======= ===== === == === ===
</TABLE>
- ---------------
(1) Consists of identified drillsites included in the Company's 1997 capital
budget that are fully evaluated, leased and have been or are scheduled to be
drilled during 1997, except as otherwise indicated. Of these budgeted wells,
30 had been drilled as of June 30, 1997.
(2) Consists of wells included in the Company's 1997 and 1998 capital budgets,
but as to which 3-D seismic data has either not been obtained or fully
evaluated, or for which the Company has not yet acquired leases or option
rights. The number of wells indicated is based upon statistical results of
drilling activities in 3-D project areas that the Company believes are
geologically similar.
(3) Anticipated interests based on contractual rights as of June 30, 1997.
(4) Represents non-proprietary "group shoots" in which the Company is a
participant.
4
<PAGE> 7
Although the Company has budgeted to drill the number of wells set forth in
the preceding table, there can be no assurance that these wells will be drilled
at all or within the expected time frame. In particular, budgeted wells that are
based upon statistical results of drilling activities in other project areas are
subject to greater uncertainties than wells for which drillsites have been
identified. The final determination with respect to the drilling of any budgeted
wells will be dependent upon a number of factors, including (i) the results of
exploration efforts and the acquisition, review and analysis of the seismic
data, (ii) the availability of sufficient capital resources by the Company and
the other participants for the drilling of the prospects, (iii) the approval of
the prospects by other participants after additional data has been compiled,
(iv) the economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for oil and natural gas and the availability
of drilling rigs and crews, (v) the financial resources and results of the
Company, and (vi) the availability of leases on reasonable terms and permitting
for the prospect. There can be no assurance that any of the budgeted wells
identified on the preceding table will, if drilled, encounter reservoirs of
commercially productive oil or natural gas. See "Risk Factors -- Dependence on
Exploratory Drilling Activities," "-- Reserve Replacement Risk" and
" -- Uncertainty of Reserve Information and Future Net Revenue Estimates."
THE COMBINATION TRANSACTIONS
The Company currently conducts its operations through a number of
affiliated entities that will be combined in a series of transactions at the
time of the closing of the Offering (the "Combination Transactions"). As a
result of the Combination Transactions, the Company will issue approximately
2,290,000 shares of Common Stock in exchange for the equity interests in these
entities that it does not currently own. See "Certain Transactions -- The
Combination Transactions."
Carrizo presently conducts oil and natural gas operations directly, with
industry partners and through the following affiliated entities: Carrizo
Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo
Partners Ltd. and Placedo Partners Ltd. Encinitas Partners Ltd. owns the
Company's interest in the Encinitas/Kelsey Project, the Midway Project and the
East McFaddin Project. Carrizo Partners Ltd. owns the Company's interest in the
Camp Hill Project as well as a 50% interest in Placedo Partners Ltd. La Rosa
Partners Ltd. owns the Company's interest in the La Rosa Project. Placedo
Partners Ltd. owns an interest in the Placedo Project (which incudes two
producing leases in Victoria County, Texas and for which the Company has
budgeted for the drilling of one well in 1998). Carrizo Production, Inc. owns
the general partner interest in Encinitas Partners Ltd. All of the Company's
other assets are owned by Carrizo Oil & Gas, Inc. The operations of all of these
entities have been managed through the same management team. See "Business --
Significant Project Areas."
The Combination Transactions will include the following: (i) Carrizo
Production, Inc. will be merged into Carrizo, and the outstanding shares of
capital stock of Carrizo Production, Inc. will be converted into an aggregate of
343,000 shares of Common Stock; (ii) Carrizo will acquire Encinitas Partners
Ltd. in two steps: (a) Carrizo will acquire the limited partner interests in
Encinitas Partners Ltd. held by certain of the Company's directors for an
aggregate consideration of 468,533 shares of Common Stock and (b) Encinitas
Partners Ltd. will be merged into Carrizo, and the outstanding partnership
interests in Encinitas Partners Ltd. will be converted into an aggregate of
860,699 shares of Common Stock; (iii) La Rosa Partners Ltd. will be merged into
Carrizo, and the outstanding partnership interests in La Rosa Partners Ltd. will
be converted into an aggregate of 48,700 shares of Common Stock; and (iv)
Carrizo Partners Ltd. will be merged into Carrizo, and the outstanding
partnership interests in Carrizo Partners Ltd. will be converted into an
aggregate of 569,068 shares of Common Stock. As a result of the merger of
Carrizo and Carrizo Partners Ltd., Carrizo will own all of the partnership
interests in Placedo Partners Ltd. Each of the Combination Transactions will
close concurrently with the closing of the Offering.
5
<PAGE> 8
THE OFFERING
Common Stock offered by the
Company.......................... 2,500,000 shares
Common Stock to be outstanding
after the Offering............... 10,000,000 shares(1)
Nasdaq National Market Symbol.... CRZO
Use of proceeds.................. To accelerate the Company's exploration and
development program, to repay indebtedness
and for general corporate purposes,
including funding the acquisition of
additional acreage and 3-D seismic data.
See "Use of Proceeds."
- ---------------
(1) Assumes approximately 2,290,000 shares will be issued in connection with the
Combination Transactions. Does not include (i) approximately 250,000 shares
of Common Stock issuable pursuant to options at an exercise price per share
equal to the initial public offering price that will be granted to
directors, officers and employees of the Company concurrent with the
Offering and (ii) 222,120 shares of Common Stock issuable pursuant to
outstanding options at a weighted average exercise price of $3.60 per share
(including vested options for 99,954 shares). See "Management -- Incentive
Plan."
6
<PAGE> 9
SUMMARY COMBINED FINANCIAL AND OPERATING DATA
The financial information of the Company set forth below for the three
years ended December 31, 1996 has been derived from the audited combined
financial statements of the Company. The financial information of the Company
set forth below as of March 31, 1997 and for the three months ended March 31,
1996 and 1997 has been derived from unaudited combined financial statements of
the Company. The results of operations for the interim periods are not
necessarily indicative of a full year's operations. The following table also
sets forth certain pro forma income taxes, net income and net income per share
information. The information should be read in conjunction with
"Capitalization," "Selected Combined Financial and Operating Data,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the combined financial statements of the Company and the related
notes thereto included elsewhere in this Prospectus.
[CAPTION]
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
-------------------------- -------------------
1994 1995 1996 1996 1997
------ ------- ------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues............... $ 596 $ 2,428 $ 5,195 $ 791 $ 1,853
Costs and expenses:
Oil and natural gas operating expenses... 518 1,814 2,384 418 557
Depreciation, depletion and
amortization.......................... 98 488 1,136 142 382
General and administrative............... 238 425 515 44 198
------ ------- ------- ------- -------
Total costs and expenses......... 854 2,727 4,035 604 1,137
------ ------- ------- ------- -------
Operating income (loss).................... (258) (299) 1,160 187 716
Interest expense (net of amounts
capitalized)............................. (7) (192) (80) (43) --
Other income............................... 6 24 20 -- --
------ ------- ------- ------- -------
Net income (loss).......................... $ (259) $ (467) $ 1,100 $ 144 $ 716
====== ======= ------- ======= -------
Pro forma income taxes(1).................. 396 258
------- -------
Pro forma net income(1).................... $ 704 $ 458
======= =======
Pro forma net income per share(1)(2)....... $ 0.09 $ 0.06
======= =======
Pro forma weighted average shares
outstanding(2)........................... 7,722 7,722
STATEMENT OF CASH FLOW DATA:
Net cash provided by (used in) operating
activities............................... $ (258) $ 406 $ 3,325 $ 486 $ 1,836
Net cash provided by (used in) investing
activities............................... (819) (6,785) (8,221) (1,353) (4,354)
Net cash provided by financing
activities............................... 1,183 6,343 6,319 867 2,525
OTHER OPERATING DATA:
EBITDA(3)(5)............................... $ (158) $ 189 $ 2,296 $ 328 $ 1,098
Operating cash flow(4)(5).................. (159) 21 2,236 285 1,098
Capital expenditures....................... 819 6,857 9,480 1,353 4,417
Debt repayments(6)......................... -- -- 2,084 -- 500
</TABLE>
7
<PAGE> 10
<TABLE>
<CAPTION>
AS OF MARCH 31, 1997
----------------------
AS ADJUSTED
FOR THE
ACTUAL OFFERING(7)
------- -----------
<S> <C> <C>
BALANCE SHEET DATA:
Working capital............................................. $(1,758) $10,072
Property and equipment, net................................. 19,162 19,162
Total assets................................................ 23,912 35,743
Long-term debt, including current maturities................ 12,254 --
Equity...................................................... 5,407 29,734
</TABLE>
- ---------------
(1) During each of the periods presented, Carrizo and the other entities being
combined in the Combination Transactions were not required to pay federal
income taxes due to their status as partnerships or Subchapter S
corporations. The amounts shown reflect pro forma income taxes that
represent federal income taxes which would have been reported under
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes," had Carrizo and such entities been tax-paying entities during the
periods presented. See Note 8 to the Company's combined financial
statements. Additionally, compensation expense for 1997 attributable to the
Company's four executive officers is expected to be approximately $476,000
($305,000 on an after-tax basis), an increase of $244,000 ($156,000 on an
after-tax basis) from 1996. See "Management -- Employment Agreements."
(2) Pro forma net income (loss) per share has been computed based on the pro
forma net income shown above, assuming the 5,210,000 currently outstanding
shares of Common Stock, the estimated 2,290,000 shares of Common Stock that
may be issued in connection with the Combination Transactions and the
currently outstanding options to purchase 222,120 shares of Common Stock
were outstanding since January 1, 1996. Supplemental pro forma net income
assuming a portion of the proceeds from the Offering was used to retire debt
(thereby reducing interest expense) would increase pro forma net income to
$755,000, or $0.10 per share, in 1996. There would be no change for the
three months ended March 31, 1997 as all interest costs incurred during the
period were capitalized.
(3) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization.
(4) Operating cash flow represents cash flows from operating activities prior to
changes in assets and liabilities.
(5) Management of the Company believes that EBITDA and operating cash flow may
provide additional information about the Company's ability to meet its
future requirements for debt service, capital expenditures and working
capital. EBITDA and operating cash flow are financial measures commonly used
in the oil and gas industry and should not be considered in isolation or as
a substitute for net income, operating income, cash flows from operating
activities or any other measure of financial performance presented in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity. Because EBITDA excludes some, but
not all, items that affect net income and because operating cash flow
excludes changes in assets and liabilities and these measures may vary among
companies, the EBITDA and operating cash flow data presented above may not
be comparable to similarly titled measures of other companies.
(6) Debt repayments include amounts refinanced.
(7) Assumes the issuance in the Offering of 2,500,000 shares of Common Stock at
$11.00 per share and the application of the net proceeds therefrom. See "Use
of Proceeds" for updated information on outstanding indebtedness to be
repaid.
8
<PAGE> 11
SUMMARY RESERVE AND OPERATING DATA
<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
--------------------------- ----------------
1994 1995 1996 1996 1997
------- ------- ------- ------ -------
<S> <C> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil (MBbls)................................... 33 78 107 21 21
Natural gas (MMcf)............................ 5 565 1,273 196 592
Natural gas equivalent (MMcfe)................ 203 1,033 1,915 321 721
AVERAGE SALES PRICES:
Oil (per Bbl)................................. $ 17.94 $ 19.64 $ 21.54 $19.02 $ 21.50
Natural gas (per Mcf)......................... 0.88 1.60 2.27 1.97 2.35
Natural gas equivalent (per Mcfe)............. 2.94 2.36 2.71 2.44 2.57
AVERAGE COSTS (PER MCFE):
Camp Hill operating expenses.................. $ 2.64 $ 2.06 $ 3.15 $ 2.55 $ 2.80
Other operating expenses...................... 1.85 1.63 0.94 0.99 0.60
Total operating expenses............ 2.55 1.76 1.24 1.29 0.77
General and administrative expenses........... 1.17 0.41 0.27 0.14 0.27
Gross profit (loss)........................... (0.78) 0.19 1.19 1.01 1.53
ESTIMATED PROVED RESERVES (AT PERIOD END)(1):
Oil (MBbls)................................... 3,785 3,810 3,895 N/A 4,289
Natural gas (MMcf)............................ 272 5,437 12,148 N/A 13,026
Total (MMcfe)................................. 22,982 28,297 35,518 N/A 38,758
PV-10 Value (in thousands)(2)................. $ 9,677 $16,467 $46,342 N/A $30,421
Standardized Measure (in thousands)(3)........ 6,498 11,981 33,021 N/A 22,120
Oil prices used............................... $ 16.31 $ 17.64 $ 20.88 N/A $ 19.71
Natural gas prices used....................... 1.54 1.94 3.69 N/A 1.74
FINDING AND DEVELOPMENT COST (PER MCFE)(4).... $ 0.47
NUMBER OF WELLS DRILLED:
Gross......................................... -- -- 20.0 4.0 9.0
Net........................................... -- -- 7.1 1.5 3.1
</TABLE>
- ---------------
N/A -- Not available.
(1) The estimated net proved oil and natural gas reserves and the present
value of estimated future net revenues attributable thereto are based
upon (i) the reserve report (the "Ryder Scott Report") prepared by Ryder
Scott Company, independent petroleum engineers ("Ryder Scott"), and (ii)
the reserve report (the "Fairchild Report" and, collectively with the
Ryder Scott Report, the "Reserve Reports") prepared by Fairchild, Ancell
& Wells, Inc., independent petroleum engineers ("Fairchild"). Summaries
of the Reserve Reports as of March 31, 1997 are included as Annex A to
this Prospectus. All calculations of estimated net proved reserves have
been prepared in accordance with the rules and regulations of the
Securities and Exchange Commission (the "Commission") and in accordance
with such regulations, the Reserve Reports used oil and natural gas
prices in effect at period end (as shown above) to calculate the
estimated future net revenues as of such period end. The declines in
PV-10 Value and Standardized Measure from December 31, 1996 to March 31,
1997 were primarily attributable to decreases in prices used for these
calculations at such dates for natural gas, and to a lesser extent oil,
which decreases more than offset the effect of increased volumes of
proved reserves during the period. There are numerous uncertainties
inherent in estimating quantities of proved reserves and in projecting
future rates of production and timing of development expenditures,
including many factors beyond the control of the Company. See "Risk
Factors -- Uncertainty of Reserve Information and Future Net Revenue
Estimates."
(2) Represents the estimated future net revenues attributable to the
Company's reserves giving no effect to federal or state income taxes
otherwise attributable to estimated future net revenues from the sale of
oil and natural gas and discounted at 10% per annum.
(3) Represents the present value of estimated future net revenues after
income taxes discounted at 10% per annum.
(4) Calculated as total capital expenditures from inception in 1993 to March
31, 1997 divided by reserve additions for such period.
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<PAGE> 12
RISK FACTORS
Prospective purchasers of the Common Stock should carefully consider the
risk factors set forth below, as well as the other information contained in this
Prospectus. This Prospectus contains certain forward-looking statements. Actual
results may differ materially from those projected in the forward-looking
statements as a result of any number of factors, including the risk factors set
forth below.
DEPENDENCE ON EXPLORATORY DRILLING ACTIVITIES
The success of the Company will be materially dependent upon the success of
its exploratory drilling program, which will be funded in part with the proceeds
of the Offering. Exploratory drilling involves numerous risks, including the
risk that no commercially productive oil or natural gas reservoirs will be
encountered. The cost of drilling, completing and operating wells is often
uncertain, and drilling operations may be curtailed, delayed or canceled as a
result of a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
adverse weather conditions, compliance with governmental requirements and
shortages or delays in the availability of drilling rigs and the delivery of
equipment. Although the Company believes that its use of 3-D seismic data and
other advanced technologies should increase the probability of success of its
exploratory wells and should reduce average finding costs through elimination of
prospects that might otherwise be drilled solely on the basis of 2-D seismic
data, exploratory drilling remains a speculative activity. Even when fully
utilized and properly interpreted, 3-D seismic data and other advanced
technologies only assist geoscientists in identifying subsurface structures and
do not enable the interpreter to know whether hydrocarbons are in fact present
in such structures. In addition, the use of 3-D seismic data and other advanced
technologies requires greater predrilling expenditures than traditional drilling
strategies and the Company could incur losses as a result of such expenditures.
The Company's future drilling activities may not be successful, and if
unsuccessful, such failure will have a material adverse effect on the Company's
results of operations and financial condition. There can be no assurance that
the Company's overall drilling success rate or its drilling success rate for
activity within a particular project area will not decline. The Company may
choose not to acquire option and lease rights prior to acquiring seismic data
and, in many cases, the Company may identify a prospect or drilling location
before seeking option or lease rights in the prospect or location. Although the
Company has identified or budgeted for numerous drilling prospects, there can be
no assurance that such prospects will ever be leased or drilled (or drilled
within the scheduled or budgeted time frame) or that oil or natural gas will be
produced from any such prospects or any other prospects. In addition, prospects
may initially be identified through a number of methods, some of which do not
include interpretation of 3-D or other seismic data. Wells that are currently
included in the Company's capital budget may be based upon statistical results
of drilling activities in other 3-D project areas that the Company believes are
geologically similar, rather than on analysis of seismic or other data. Actual
drilling and results are likely to vary from such statistical results and such
variance may be material. Similarly, the Company's drilling schedule may vary
from its capital budget, and there is increased risk of such variance from the
1998 capital budget because of future uncertainties, including those described
above. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
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
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<PAGE> 13
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, ability to finance planned capital expenditures
and results of operations. Lower oil and natural gas prices also may reduce the
amount of oil and natural gas that the Company can produce economically. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business -- Marketing."
The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10%. Application of this "ceiling" test generally requires pricing
future revenue at the unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down for accounting purposes if the ceiling is
exceeded, even if prices were depressed for only a short period of time. The
Company may be required to write down the carrying value of its oil and natural
gas properties when oil and natural gas prices are depressed or unusually
volatile. If a write-down is required, it would result in a charge to earnings,
but would not impact cash flow from operating activities. Once incurred, a
write-down of oil and natural gas properties is not reversible at a later date.
In order to reduce its exposure to short-term fluctuations in the price of
oil and natural gas, the Company periodically enters into hedging arrangements.
The Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in oil and natural gas
prices. Such hedging arrangements may expose the Company to risk of financial
loss in certain circumstances, including instances where production is less than
expected, the Company's customers fail to purchase contracted quantities of oil
or natural gas or a sudden, unexpected event materially impacts oil or natural
gas prices. In addition, the Company's hedging arrangements limit the benefit to
the Company of increases in the price of oil and natural gas. Total natural gas
purchased and sold under swap arrangements during the years ended December 31,
1995 and 1996 was 40,000 MMbtu and 60,000 MMbtu, respectively. Losses realized
by the Company under such swap arrangements were $23,466 and $26,887 for the
years ended December 31, 1995 and 1996, respectively. The Company did not engage
in hedging prior to 1995 and did not engage in hedging during the quarter ended
March 31, 1997. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- General" and "Business -- Marketing."
RESERVE REPLACEMENT RISK
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
11
<PAGE> 14
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."
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES
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 Prospectus 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. See "Business -- Oil
and Natural Gas Reserves."
OPERATING RISKS OF OIL AND NATURAL GAS OPERATIONS
The oil and natural gas business involves certain operating hazards such as
well blowouts, craterings, 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, any of which could result in substantial losses to the Company. The
availability of a ready market for the Company's oil and natural gas production
also 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. 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. The Company may elect to self-insure if management
believes that the cost of insurance, although available, is excessive relative
to the risks presented. In addition, pollution and environmental risks generally
are not fully insurable. The occurrence of an event not fully covered by
insurance could have a material adverse effect on the financial condition and
results of operations of the Company. The Company participates in a substantial
percentage of its wells on a non-operated basis, which may limit the Company's
ability to control the risks associated with oil and natural gas operations. See
"Business -- Operating Hazards and Insurance."
12
<PAGE> 15
DEPENDENCE ON KEY PERSONNEL
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 has entered into employment
agreements with each of S.P. Johnson IV (the Company's President and Chief
Executive Officer), Frank A. Wojtek (the Company's Chief Financial Officer),
George F. Canjar (the Company's Vice President of Exploration Development) and
Kendall A. Trahan (the Company's Vice President of Land) substantially as
described herein under "Management -- Employment Agreements." The Company does
not maintain key-man life insurance with respect to any of its employees.
ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY
The Company has experienced significant growth in the recent past through
the expansion of its 3-D seismic data acquisition and drilling program. The
Company's rapid growth has placed, and is expected to continue to place, a
significant strain on the Company's financial, technical, operational and
administrative resources. The Company has relied in the past and expects to
continue to rely on project partners and independent contractors that have
provided the Company with seismic survey planning and management, project and
prospect generation, land acquisition, drilling and other services. At June 30,
1997, the Company had 16 full-time employees and two part-time employees. As the
Company increases the number of projects it is evaluating or in which it is
participating, there will be additional demands on the Company's financial,
technical, operational and administrative resources and continued reliance by
the Company on project partners and independent contractors, and these strains
on resources, additional demands and continued reliance may negatively affect
the Company. The Company's ability to continue its growth will depend upon a
number of factors, including its ability to obtain leases or options on
properties for 3-D seismic surveys, its ability to acquire additional 3-D
seismic data, its ability to identify and acquire new exploratory sites, its
ability to develop existing sites, its ability to continue to retain and attract
skilled personnel, its ability to maintain or enter into new relationships with
project partners and independent contractors, the results of its drilling
program, hydrocarbon prices, access to capital and other factors. Although the
Company intends to upgrade its technical, operational and administrative
resources following the Offering and to increase its ability to provide
internally certain of the services previously provided by outside sources, there
can be no assurance that it will be successful in doing so or that it will be
able to continue to maintain or enter into new relationships with project
partners and independent contractors. The failure of the Company to continue to
upgrade its technical, operational and administrative resources or the
occurrence of unexpected expansion difficulties, including difficulties in
recruiting and retaining sufficient numbers of qualified personnel to enable the
Company to expand its seismic data acquisition and drilling program, or the
reduced availability of project partners and independent contractors that have
historically provided the Company seismic survey planning and management,
project and prospect generation, land acquisition, drilling and other services,
could have a material adverse effect on the Company's business, financial
condition and results of operations. In addition, the Company has only limited
experience operating and managing field operations, and there can be no
assurances that the Company will be successful in doing so. Any increase in the
Company's activities as an operator will increase its exposure to operating
hazards. See "Risk Factors -- Operating Risks of Oil and Natural Gas
Operations." There can be no assurance that the Company will be successful in
achieving growth or any other aspect of its business strategy.
SIGNIFICANT CAPITAL REQUIREMENTS
The Company has experienced and expects to continue to experience
substantial working capital needs, particularly as a result of its active 3-D
seismic data acquisition and drilling program. In addition to cash generated
from operations, additional financing may be required in the future to fund the
Company's growth. No assurances can be given as to the availability or terms of
any such
13
<PAGE> 16
additional financing that may be required or that financing will continue to be
available under existing or new credit facilities. In the event such capital
resources are not available to the Company, its drilling, development and other
activities may be curtailed. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
CONTROL BY CERTAIN SHAREHOLDERS
Upon completion of the Offering and the Combination Transactions, the
Company's officers and directors will beneficially own approximately 59.3%
(57.2% if the Underwriters' over-allotment option is exercised in full) of the
outstanding shares of Common Stock. As a result, such shareholders will be in a
position to significantly influence or control the outcome of certain matters
requiring a shareholder vote, including the election of directors, the adoption
or amendment of provisions in the Company's Articles of Incorporation or Bylaws
and the approval of mergers and other significant corporate transactions. Such
ownership of Common Stock may have the effect of delaying, deferring or
preventing a change of control of the Company and may adversely affect the
voting and other rights of other shareholders. See "Security Ownership of
Certain Beneficial Owners and Management."
TECHNOLOGICAL CHANGES
The oil and gas industry is characterized by rapid and significant
technological advancements and introductions of new products and services
utilizing new technologies. As others use or develop new technologies, the
Company may be placed at a competitive disadvantage, and competitive pressures
may force the Company to implement such new technologies at substantial cost. In
addition, other oil and gas companies may have greater financial, technical and
personnel resources that allow them to enjoy technological advantages and may in
the future allow them to implement new technologies before the Company. There
can be no assurance that the Company will be able to respond to such competitive
pressures and implement such technologies on a timely basis or at an acceptable
cost. One or more of the technologies currently utilized by the Company or
implemented in the future may become obsolete. In such case, the Company's
business, financial condition and results of operations could be materially
adversely affected. If the Company is unable to utilize the most advanced
commercially available technology, the Company's business, financial condition
and results of operations could be materially and adversely affected. See
"Business -- Competition."
GOVERNMENT REGULATION AND ENVIRONMENTAL MATTERS
Oil and natural gas operations are subject to various federal, state and
local government regulations which may be changed from time to time in response
to economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties and
taxation. From time to time, regulatory agencies have imposed price controls and
limitations on production by restricting the rate of flow of oil and natural gas
wells below actual production capacity in order to conserve supplies of oil and
natural gas. The Company is also subject to changing and extensive tax laws, the
effects of which cannot be predicted. Legal requirements are frequently changed
and subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations. No
assurance can be given that existing laws or regulations, as currently
interpreted or reinterpreted in the future, or future laws or regulations will
not materially adversely affect the Company's results of operations and
financial condition. The development, production, handling, storage,
transportation and disposal of oil and natural gas, by-products thereof and
other substances and materials produced or used in connection with oil and
natural gas operations are subject to federal, state and local laws and
regulations primarily relating to protection of human health and the
environment. The discharge of oil, natural gas, or pollutants into the air, soil
or water may give rise to significant liabilities on the part of the Company to
the
14
<PAGE> 17
government and third parties and may require the Company to incur substantial
costs of remediation. See "Business -- Regulation."
COMPETITION
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 define, evaluate, bid for and purchase a greater number of properties
and prospects than the Company's financial or human resources permit. 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. See
"Business -- Competition."
LIMITED OPERATING HISTORY AND HISTORICAL OPERATING LOSSES
The Company commenced its operations in September 1993 and has only a
limited operating history. Potential investors, therefore, have limited
historical financial and operating information upon which to base an evaluation
of the Company's performance and an investment in shares of Common Stock. For
example, the producing wells within exploration projects in which the Company is
participating have been on production only for a short period of time.
Therefore, estimations with respect to the proved reserves and level of future
production attributable to these wells are difficult to determine and there can
be no assurance as to the volume of recoverable reserves that will be realized
from such wells. The Company's prospects must be considered in light of the
risks, expenses and difficulties frequently encountered by companies in the
early stages of their development. The Company incurred net losses in 1994 and
1995 of $258,509 and $466,610, respectively. The development of the Company's
business and its participation in an increasingly larger number of projects have
required and will continue to require substantial expenditures. The Company's
future financial results will depend primarily on its ability to economically
locate and produce hydrocarbons in commercial quantities and on the market
prices for oil and natural gas. There can be no assurance that the Company will
achieve or sustain profitability or positive cash flows from operating
activities in the future. See "-- Significant Capital Requirements," "Selected
Combined Financial Data," "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Business -- Oil and Gas Reserves."
ACQUISITION RISKS
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
15
<PAGE> 18
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.
SHARES ELIGIBLE FOR FUTURE SALE
Future sales of substantial amounts of Common Stock in the public market
following the Offering could adversely affect the market price for the Common
Stock. The 5,210,000 shares outstanding prior to the Offering were not, and the
approximately 2,290,000 shares to be issued in the Combination Transactions will
not be, registered under the Securities Act of 1933, as amended (the "Securities
Act"), and, therefore, are not freely tradeable unless subsequently registered
under the Securities Act or exempted from such registration. At the time of the
expiration of the lock-up period described below, all of the previously
outstanding shares may be sold pursuant to the requirements of Rule 144
promulgated under the Securities Act ("Rule 144"), subject to certain volume
limitations, manner of sale and other requirements relating to the sale of
securities. Following a period of one year from the closing of this Offering,
all of such shares to be issued in the Combination Transactions may be sold
pursuant to the requirements of Rule 144, subject to certain volume limitations,
manner of sale and other requirements relating to the sale of securities. In
addition, options to purchase shares of Common Stock are issuable pursuant to
outstanding options and up to 250,000 shares of Common Stock will be issuable
pursuant to options to be granted to certain directors, officers and employees
of the Company prior to or immediately after the closing of the Offering, and
the Company anticipates that shares of Common Stock issuable upon exercise of
such options will become available for future sale in the public market pursuant
to a subsequently filed registration statement on Form S-8. In addition, the
Company will enter into a registration rights agreement with certain of the
Company's current shareholders who will own approximately 6,267,069 shares of
Common Stock following the Combination Transactions. Pursuant to the
registration rights agreement, such persons collectively will receive demand and
piggyback registration rights that provide for the registration of the resale of
such shares at the Company's expense. The Company, its current shareholders, its
executive officers and its directors have agreed not to offer for sale, sell or
otherwise dispose of any shares of Common Stock or any securities convertible
into or exercisable or exchangeable for shares of Common Stock for a period of
180 days after the date of this Prospectus, without the prior written consent of
the representatives of the Underwriters, subject to certain exceptions. Such
consent may be given at any time and without public notice. See
"Management -- Incentive Plan," "Shares Eligible for Future Sale" and
"Underwriting."
ABSENCE OF DIVIDENDS ON COMMON STOCK
The Company currently intends to retain any earnings for the future
operation and development of its business and does not currently anticipate
paying any dividends in the foreseeable future. Any future dividends also may be
restricted by the Company's then-existing loan agreements. See "Dividend
Policy," "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources" and Note 4 to the
Company's Financial Statements.
CERTAIN ANTI-TAKEOVER EFFECTS
The Company's Articles of Incorporation authorize the Board of Directors to
set the terms of and issue Preferred Stock without shareholder approval. The
Board of Directors could use the Preferred Stock as a means to delay, defer or
prevent a takeover attempt that a shareholder might consider to be in the
Company's best interest. In addition, certain provisions of the Texas Business
Corporation Act and the Company's Articles of Incorporation and Bylaws might
impede a takeover of the Company. See "Description of Capital Stock."
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<PAGE> 19
NO PRIOR PUBLIC MARKET
Prior to the Offering, there has been no public market for the Common
Stock. The initial public offering price has been determined by negotiation
between the Company and the Underwriters and may not be indicative of the price
at which the Common Stock will trade following the completion of the Offering.
See "Underwriting" for a discussion of the factors considered in determining the
initial public offering price. The completion of the Offering provides no
assurance that an active trading market for the Common Stock will develop or, if
developed, that it will be sustained. The market price of the Common Stock could
also be subject to significant fluctuation and may be influenced by many
factors, including variations in results of operations, variations in oil and
natural gas prices, investor perceptions of the Company and the oil and natural
gas industry and general economic and other conditions.
DILUTION
Purchasers of Common Stock in the Offering will experience immediate and
substantial dilution in the net tangible book value of their stock of $8.02 per
share. See "Dilution."
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USE OF PROCEEDS
The net proceeds to the Company from the Offering at the initial public
offering price of $11.00 per share are estimated to be approximately $24.4
million ($28.2 million if the Underwriters' over-allotment option is exercised
in full). The Company intends to use a portion of the net proceeds to repay
approximately $16.5 million of indebtedness outstanding under the Company's
revolving credit facilities that currently bear interest at rates ranging from
9.3% to 10.5% and mature in June 1998 and approximately $3.2 million of
promissory notes outstanding to certain of the Company's directors and officers
that currently bear interest at 8.5% and are due on the earlier of (i) April or
July 1998 or (ii) the closing of the Offering. The remainder of the net proceeds
will be used to accelerate the Company's exploration and development program and
for general corporate purposes, including funding additional acreage and 3-D
seismic acquisitions. The indebtedness incurred under both the Company's
revolving credit facilities and such promissory notes was used primarily for its
exploration, development and acquisition activities and to provide working
capital. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
DIVIDEND POLICY
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. Following the Offering, the Company expects to enter into an
amendment to its Secured Revolving Line of Credit with Compass Bank (the
"Company Credit Facility"). Under the proposed terms of the facility, the
Company's ability to pay dividends will be restricted. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
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DILUTION
As of March 31, 1997, the pro forma net tangible book value of the Company
would have been approximately $5.4 million, or approximately $0.72 per share of
Common Stock, after giving pro forma effect to the issuance of approximately
2,290,000 shares of Common Stock in connection with the Combination Transactions
as if such transactions had been completed at such date. Net tangible book value
per share represents the amount of the Company's tangible book value (total book
value of tangible assets less total liabilities) divided by the total number of
shares of Common Stock outstanding. After further giving effect to the receipt
of the estimated net proceeds from the Offering (net of estimated underwriting
discounts and offering expenses) at the initial public offering price of $11.00
per share, the adjusted pro forma net tangible book value of the Common Stock
outstanding at March 31, 1997 would have been $2.98 per share, representing an
immediate increase in net tangible book value of $2.26 per share to existing
shareholders and an immediate dilution of $8.02 per share (the difference
between the initial public offering price and the net tangible book value per
share after the Offering) to persons purchasing Common Stock at the initial
public offering price. The following table illustrates such per share dilution:
<TABLE>
<CAPTION>
<S> <C> <C>
Initial public offering price per share..................... $11.00
Pro forma net tangible book value per share before the
Offering............................................... $0.72
Increase in pro forma net tangible book value per share
attributable to sale of Common Stock in the Offering... 2.26
-----
Adjusted pro forma net tangible book value per share after
giving effect to the Offering............................. 2.98
------
Dilution in net tangible book value to the purchasers of
Common Stock in the Offering.............................. $ 8.02
======
</TABLE>
The following table sets forth, on a pro forma basis to give effect to the
Combination Transactions as of March 31, 1997, differences between the number of
shares of Common Stock to be acquired or to be acquired from the Company by
existing shareholders and by investors purchasing shares in the Offering, the
total price paid or to be paid and the average price per share paid or to be
paid by existing shareholders and investors purchasing shares in the Offering.
<TABLE>
<CAPTION>
SHARES PURCHASED(1) TOTAL CONSIDERATION(2)
--------------------- ---------------------- AVERAGE PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
---------- ------- ----------- ------- -------------
<S> <C> <C> <C> <C> <C>
Existing shareholders......... 7,500,000 75% $ 5,296,000 16% $ 0.71
New investors................. 2,500,000 25% 27,500,000 84% 11.00
---------- ---- ----------- ----
Total............... 10,000,000 100% $32,796,000 100%
========== ==== =========== ====
</TABLE>
- ---------------
(1) Does not include (i) approximately 250,000 shares of Common Stock issuable
pursuant to options at an exercise price per share equal to the initial
public offering price that will be granted to directors, officers and
employees of the Company upon completion of the Offering and (ii) 222,120
shares of Common Stock issuable pursuant to outstanding options at a
weighted average exercise price of $3.60 per share (including vested options
for 99,954 shares). The exercise of such stock options at a price below the
initial public offering price will be dilutive to new investors. See
"Management -- Incentive Plan."
(2) Total consideration paid by existing shareholders represents the aggregate
of (i) in the case of the current shareholders of Carrizo, the amounts paid
by such shareholders to the Company for their Common Stock and (ii) in the
case of persons receiving Common Stock in the Combination Transactions, the
book value at March 31, 1997 of the allocable portion of the net assets and
liabilities received by the Company in the Combination Transactions.
19
<PAGE> 22
CAPITALIZATION
The following table gives effect to the 521-for-one split of the Common
Stock effected in June 1997 and sets forth the Company's cash and cash
equivalents and capitalization as of March 31, 1997 as follows: (i) on a
historical basis, (ii) pro forma after giving effect to the issuance of
approximately 2,290,000 shares of Common Stock in connection with the
Combination Transactions and (iii) pro forma as adjusted to give effect to the
sale of 2,500,000 shares of Common Stock in the Offering at the initial public
offering price of $11.00 per share and the application of the estimated net
proceeds therefrom. This table should be read in conjunction with the Combined
Financial Statements and notes thereto and "Management's Discussion and Analysis
of Financial Condition and Results of Operations" included elsewhere in this
Prospectus.
<TABLE>
<CAPTION>
MARCH 31, 1997
------------------------------------
PRO FORMA
AS ADJUSTED PRO FORMA
FOR THE AS ADJUSTED
COMBINATION FOR THE
ACTUAL TRANSACTIONS OFFERING
------- ------------ -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash and cash equivalents................................... $ 1,500 $ 1,500 $13,331
======= ======= =======
Long-term debt.............................................. $12,254 $12,254 --
Shareholders' equity(1):
Preferred stock, $0.01 par value, 10,000,000 shares
authorized; none outstanding........................... -- -- --
Common stock, $0.01 par value, 40,000,000 shares
authorized; 5,210,000 shares issued and outstanding;
7,500,000 shares issued and outstanding pro forma;
10,000,000 shares issued and outstanding pro forma as
adjusted............................................... -- 75 100
Additional paid-in capital................................ 4,356 4,281 28,583
Retained earnings......................................... 1,051 1,051 1,051
------- ------- -------
Total shareholders' equity........................... 5,407 5,407 29,734
------- ------- -------
Total capitalization.............................. $17,661 $17,661 $29,734
======= ======= =======
</TABLE>
- ---------------
(1) Does not include (i) approximately 250,000 of Common Stock issuable pursuant
to options at an exercise price per share equal to the initial public
offering price in the Offering that will be granted to directors, officers
and employees of the Company upon completion of the Offering and (ii)
222,120 shares of Common Stock issuable pursuant to outstanding options at a
weighted average exercise price of $3.60 per share (including vested options
for 99,954 shares).
20
<PAGE> 23
SELECTED COMBINED FINANCIAL AND OPERATING DATA
The financial information of the Company set forth below for the period
from inception of operations (September 24, 1993) through December 31, 1993, and
for the three years ended December 31, 1996, has been derived from the audited
combined financial statements of the Company. The financial information of the
Company set forth below as of March 31, 1997 and for the three months ended
March 31, 1996 and 1997 has been derived from the unaudited combined financial
statements of the Company. The results of operations for the interim periods are
not necessarily indicative of a full year's operations. The following table also
sets forth certain pro forma income taxes, net income and net income per share
information. The information should be read in conjunction with
"Capitalization," "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the audited combined financial statements of the
Company and the related notes thereto included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
PERIOD FROM
INCEPTION OF
OPERATIONS
(SEPTEMBER 24, THREE MONTHS ENDED
1993) THROUGH YEAR ENDED DECEMBER 31, MARCH 31,
DECEMBER 31, --------------------------- -------------------
1993 1994 1995 1996 1996 1997
-------------- ------- ------- ------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Oil and natural gas
revenues.................... $ 5 $ 596 $ 2,428 $ 5,195 $ 791 $ 1,853
Costs and expenses:
Oil and natural gas
operating expenses....... 20 518 1,814 2,384 418 557
Depreciation, depletion and
amortization............. 1 98 488 1,136 142 382
General and
administrative........... 24 238 425 515 44 198
----- ------- ------- ------- ------- -------
Total costs and
expenses.......... 45 854 2,727 4,035 604 1,137
----- ------- ------- ------- ------- -------
Operating income (loss)....... (40) (258) (299) 1,160 187 716
Interest expense (net of
amounts capitalized)........ -- (7) (192) (80) (43) --
Other income.................. -- 6 24 20 -- --
----- ------- ------- ------- ------- -------
Net income (loss)............. $ (40) $ (259) $ (467) $ 1,100 $ 144 $ 716
===== ======= ======= ------- ======= -------
Pro forma income taxes(1)..... 396 258
------- -------
Pro forma net income(1)....... $ 704 $ 458
======= =======
Pro forma net income per
share(1)(2)................. $ 0.09 $ 0.06
======= =======
Pro forma weighted average
shares outstanding(2)....... 7,722 7,722
STATEMENTS OF CASH FLOW DATA:
Net cash provided by (used in)
operating activities........ $ 12 $ (258) $ 406 $ 3,325 $ 486 $ 1,836
Net cash provided by (used in)
investing activities........ (118) (819) (6,785) (8,221) (1,353) (4,354)
Net cash provided by financing
activities.................. 106 1,183 6,343 6,319 867 2,525
OTHER OPERATING DATA:
EBITDA(3)(5).................. $ (41) $ (158) $ 189 $ 2,296 $ 328 $ 1,098
Operating cash flow(4)(5)..... (41) (159) 21 2,236 285 1,098
Capital expenditures.......... 113 819 6,857 9,480 1,353 4,417
Debt repayments(6)............ -- -- -- 2,084 -- 500
</TABLE>
21
<PAGE> 24
<TABLE>
<CAPTION>
AS OF MARCH 31, 1997
---------------------
AS
AS OF DECEMBER 31, ADJUSTED
-------------------------------- FOR THE
1993 1994 1995 1996 ACTUAL OFFERING(7)
---- ------ ------ ------- ------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital..................... $(52) $ 152 $ (265) $(1,025) $(1,758) $10,072
Property and equipment, net......... 113 803 6,960 15,206 19,162 19,162
Total assets........................ 130 1,057 7,645 18,869 23,912 35,743
Long-term debt, including current
maturities........................ -- 533 3,480 9,684 12,254 --
Equity.............................. 65 452 3,381 4,596 5,407 29,734
</TABLE>
- ---------------
(1) During each of the periods presented, Carrizo and the other entities being
combined in the Combination Transactions were not required to pay federal
income taxes due to their status as partnerships or Subchapter S
corporations. The amounts shown reflect pro forma income taxes that
represent federal income taxes which would have been reported under
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes," had Carrizo and such entities been tax-paying entities during the
periods presented. See Note 8 to the Company's combined financial
statements. Additionally, compensation expense for 1997 attributable to the
Company's four executive officers is expected to be approximately $476,000
($305,000 on an after-tax basis), an increase of $244,000 ($156,000 on an
after-tax basis) from 1996. See "Management -- Employment Agreements."
(2) Pro forma net income (loss) per share has been computed based on the pro
forma net income shown above, and assuming the 5,210,000 currently
outstanding shares of Common Stock, the estimated 2,290,000 shares of Common
Stock that may be issued in connection with the Combination Transactions and
the currently outstanding options to purchase 222,120 shares of Common Stock
were outstanding since January 1, 1996. Supplemental pro forma net income
assuming a portion of the proceeds from the Offering was used to retire debt
(thereby reducing interest expense) would increase pro forma net income to
$755,000, or $0.10 per share, in 1996. There would be no change for the
three months ended March 31, 1997 as all interest costs incurred during the
period were capitalized.
(3) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization.
(4) Operating cash flow represents cash flows from operating activities prior to
changes in assets and liabilities.
(5) Management of the Company believes that EBITDA and operating cash flow may
provide additional information about the Company's ability to meet its
future requirements for debt service, capital expenditures and working
capital. EBITDA and operating cash flow are financial measures commonly used
in the oil and gas industry and should not be considered in isolation or as
a substitute for net income, operating income, cash flows from operating
activities or any other measure of financial performance presented in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity. Because EBITDA excludes some, but
not all, items that affect net income and because operating cash flow
excludes changes in assets and liabilities and these measures may vary among
companies, the EBITDA and operating cash flow data presented above may not
be comparable to similarly titled measures of other companies.
(6) Debt repayments include amounts refinanced.
(7) Assumes the issuance in the Offering of 2,500,000 shares of Common Stock at
$11.00 per share and the application of the net proceeds therefrom. See "Use
of Proceeds" for updated information on outstanding indebtedness to be
repaid.
22
<PAGE> 25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL OVERVIEW
The Company began operations in September 1993 and initially focused on the
acquisition of producing properties. As a result of the increasing availability
of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic
data and options to lease substantial acreage in 1995 and began to drill its 3-D
based prospects in 1996. The Company drilled 20 wells in 1996 and 30 wells
through the six months ended June 30, 1997. The Company expects such increases
to continue and has budgeted to drill a total of 67 gross wells (26.9 net) in
1997 and 147 gross wells (67.5 net) in 1998. As a result, depreciation,
depletion and amortization, oil and gas operating expenses and production are
expected to increase. The Company has typically retained the majority of its
interests in shallow, normally pressured prospects and sold a portion of its
interests in deeper, over-pressured prospects.
The Company uses the full-cost method of accounting for its oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including any general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit-of-production method. To
the extent that such capitalized costs in the full-cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed the
present value (using a 10% discount rate) of estimated future net after-tax cash
flows from proved oil and gas reserves, such excess costs are charged to
operations. The Company has not been required to make any such write-downs. Once
incurred, a write-down of oil and gas properties is not reversible at a later
date.
The Company has primarily grown through the internal development of
properties within its exploration project areas, although the Company acquired
properties with existing production in the Camp Hill Project in late 1993, the
Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company
made these acquisitions through the use of limited partnerships with Carrizo or
Carrizo Production, Inc. as the general partner. However, as operations have
expanded, the Company has increasingly funded its activities through bank
borrowings and cash flow from operations in order to retain a greater portion of
the interests it develops.
The combined financial statements set forth elsewhere in this Prospectus
are prepared on the basis of a combination of Carrizo and the entities that are
a party to the Combination Transactions. Carrizo and the entities being combined
with it in the Combination Transactions were not required to pay federal income
taxes due to their status as partnerships or Subchapter S corporations, which
are not subject to federal income taxation. Instead, taxes for such periods were
paid by the shareholders and partners of such entities. On May 16, 1997, Carrizo
terminated its status as an S corporation and thereafter became subject to
federal income taxes. In accordance with SFAS No. 109, "Accounting for Income
Taxes," the Company will be required to establish a deferred tax liability in
the second quarter of 1997 which will result in a noncash charge to income that
is currently estimated in the range of approximately $1.5 million to $2.0
million. The Company is currently in the process of finalizing such amount.
Giving pro forma effect to the Combination Transactions, for the 12 months ended
December 31, 1996 and the three months ended March 31, 1997, pro forma income
taxes were $396,000 and $258,000, respectively.
RECENT OPERATING RESULTS
During the second quarter of 1997, the Company participated in the drilling
of 21 gross wells (8.8 net), of which 18 (7.3 net) were successfully completed,
as compared to the Company's participation in the drilling of nine gross wells
(3.1 net), of which seven were successfully completed, during the first quarter
of 1997. Oil and natural gas revenues for the second quarter of 1997 increased
24% to approximately $2.3 million from approximately $1.9 million for the first
23
<PAGE> 26
quarter of 1997. Production volumes for natural gas during the second quarter of
1997 increased 41% to 835.9 MMcf from 592.3 MMcf for the first quarter of 1997.
Average gas prices in the second quarter of 1997 decreased 9% to $2.15 per Mcf
from $2.35 per Mcf in the first quarter of 1997. Production volumes for oil
during the second quarter of 1997 increased 27% to 27.2 MBbls from 21.4 MBbls
for the first quarter of 1997. Average oil prices in the second quarter of 1997
decreased 14% to $18.46 per Bbl from $21.50 per Bbl in the first quarter of
1997.
The Company is in the process of preparing its operating results for the
second quarter of 1997. Although the information is not yet complete, the
preliminary information for the quarter indicates that (i) oil and natural gas
operating expenses increased in absolute terms, but decreased as a percentage of
production, (ii) depreciation, depletion and amortization expense increased in
absolute terms, but remained relatively constant as a percentage of production
and (iii) general and administrative expenses increased in absolute terms and
increased slightly as a percentage of production, in each case as compared to
the first quarter of 1997.
RESULTS OF OPERATIONS
Three Months Ended March 31, 1997 Compared to the Three Months Ended March 31,
1996
Oil and natural gas revenues for the three months ended March 31, 1997
increased 134% to $1.9 million from $791,000 for the same period in 1996.
Production volumes for natural gas during the three months ended March 31, 1997
increased 202% to 592.3 MMcf from 195.9 MMcf for the same period in 1996.
Average gas prices increased 19% to $2.35 per Mcf in the first quarter of 1997
from $1.97 per Mcf in the same period in 1996. Production volumes for oil in the
first quarter of 1997 were flat at 21.4 MBbls from 21.3 MBbls for the same
period in 1996 as reduced production at the Camp Hill Project (resulting from
reduced steam injection levels because of high fuel gas prices) offset increases
in production elsewhere. Average oil prices increased 13% to $21.50 per barrel
in the first quarter of 1997 from $19.02 per barrel in the same period in 1996.
The increase in natural gas production was due primarily to production from new
wells drilled and completed in the second half of 1996 and early 1997, as well
as the acquisition of the La Rosa properties in 1996, which were fully onstream
for the first quarter of 1997.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
three months ended March 31, 1997 and 1996:
<TABLE>
<CAPTION>
1997 PERIOD COMPARED TO
MARCH 31, 1996 PERIOD
--------------------- -----------------------
1996 1997 INCREASE % INCREASE
-------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Production volumes
Oil and condensate (MBbls)........... 21.3 21.4 0.1 --
Natural gas (MMcf)................... 195.9 592.3 396.4 202%
Average sales prices(1)
Oil and condensate (per Bbl)......... $ 19.02 $ 21.50 $ 2.48 13%
Natural gas (per Mcf)................ 1.97 2.35 0.38 19%
Operating revenues
Oil and condensate................... $405,189 $ 459,975 $ 54,786 14%
Natural gas.......................... 385,324 1,393,195 1,007,871 262%
-------- ---------- ----------
Total........................ $790,513 $1,853,170 $1,062,657 134%
======== ========== ==========
</TABLE>
- ---------------
(1) Including impact of hedging.
Oil and natural gas operating expenses for the three months ended March 31,
1997 increased 33% to $557,000 from $418,000 for the same period in 1996. Oil
and natural gas operating expenses increased primarily due to increased
production as described above, which was offset by a
24
<PAGE> 27
decrease in operating expenses per equivalent unit to $0.77 per Mcfe in the
first quarter of 1997 from $1.29 per Mcfe in the same period in 1996. The per
unit cost decreased as a result of increased production of natural gas which had
lower per unit operating costs.
Depreciation, depletion and amortization ("DD&A") expense for the three
months ended March 31, 1997 increased 170% to $382,000 from $142,000 for the
same period in 1996. This increase was due to increased production and a 20%
increase in the 1997 depletion rate to $0.53 per Mcfe from $0.44 per Mcfe in the
three months ended March 31, 1996, as a result of increased drilling and related
seismic costs.
General and administrative expense for the three months ended March 31,
1997 increased 347% to $198,000 from $44,000 for the same period in 1996, as a
result of increases in the number of employees and related benefits, plus
increased office space.
Interest expense for the three months ended March 31, 1997 increased 77% to
$188,000 from $107,000 in the same period in 1996. Increases in interest expense
were due to increased debt levels in late 1996 and early 1997. Capitalized
interest increased to $188,000 in the first quarter of 1997 from $64,000 in the
first quarter of 1996 as a result of increased levels of exploration activity
and higher levels of unevaluated property. All interest expense during the first
quarter of 1997 was capitalized.
Net income for the three months ended March 31, 1997 increased to $716,000
from $144,000 for the same period in 1996, as a result of the factors described
above.
Year Ended December 31, 1996 Compared to the Year Ended December 31, 1995
Oil and natural gas revenues for 1996 increased 114% to $5.2 million from
$2.4 million in 1995. Production volumes for natural gas in 1996 increased 125%
to 1,272.5 MMcf from 565.3 MMcf in 1995. Average natural gas prices increased
42% to $2.27 per Mcf in 1996 from $1.60 per Mcf in 1995. Production volumes for
oil in 1996 increased 38% to 107.3 MBbls from 77.6 MBbls in 1995. Average oil
prices increased 10% to $21.54 per barrel in 1996 from $19.64 per barrel in
1995. The increase in oil and natural gas production was due primarily to new
wells being successfully drilled and completed during 1996, along with
recompletions of existing wells. Also contributing to the increase in oil and
gas revenues from 1995 to 1996 was the acquisition of the La Rosa properties.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1995 and 1996:
<TABLE>
<CAPTION>
1996 PERIOD COMPARED TO
DECEMBER 31, 1995 PERIOD
----------------------- -----------------------
1995 1996 INCREASE % INCREASE
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Production volumes
Oil and condensate (MBbls)......... 77.6 107.3 29.7 38%
Natural gas (MMcf)................. 565.3 1,272.5 707.2 125%
Average sales prices(1)
Oil and condensate (per Bbl)....... $ 19.64 $ 21.54 $ 1.90 10%
Natural gas (per Mcf).............. 1.60 2.27 0.67 42%
Operating revenues
Oil and condensate................. $1,524,002 $2,310,798 $ 786,796 52%
Natural gas........................ 904,046 2,883,911 1,979,865 219%
---------- ---------- ----------
Total...................... $2,428,048 $5,194,709 $2,766,661 114%
========== ========== ==========
</TABLE>
- ---------------
(1) Including impact of hedging.
25
<PAGE> 28
Oil and natural gas operating expenses for 1996 increased 31% to $2.4
million from $1.8 million in 1995. Oil and natural gas operating expenses
increased due to increased production generated from new oil and gas wells
drilled and completed since December 31, 1995, as well as the acquisitions of
the La Rosa and Encinitas properties. Operating expenses per equivalent unit in
1996 decreased to $1.24 per Mcfe from $1.76 per Mcfe in 1995. The per unit cost
decreased as a result of increased production of natural gas which had lower per
unit operating costs.
DD&A expense for 1996 increased 133% to $1.1 million from $488,000 in 1995.
This increase was due to the increase in oil and gas production as well as a 25%
increase in the depletion rate (to $0.59 per Mcfe in 1996 from $0.47 per Mcfe in
1995). The increased depletion rate was primarily caused by increased
exploration expenditures attributable to 3-D seismic surveys performed for new
wells drilled and completed since December 31, 1995.
General and administrative expense for 1996 increased 21% to $515,000 from
$425,000 for 1995 due primarily to an increase in salary expense as a result of
the addition of new employees.
Interest expense for 1996 decreased 59% to $80,000 from $192,000 in 1995.
This decrease was primarily due to the increase in interest capitalized
consistent with increases in capital expenditures.
Net income for 1996 increased to $1.1 million from a loss of $467,000 in
1995 as a result of the factors described above.
Year Ended December 31, 1995 Compared to the Year Ended December 31, 1994
Oil and natural gas revenues for 1995 increased 307% to $2.4 million from
$597,000 in 1994. Production volumes for natural gas for 1995 increased to 565.3
MMcf from 5.4 MMcf in 1994. Average gas prices increased 81% to $1.60 per Mcf in
1995 from $0.88 per Mcf in 1994. Production volumes for oil for 1995 increased
135% to 77.6 MBbls from 33 MBbls in 1994. Average oil prices increased 9% to
$19.64 per barrel in 1995 from $17.94 per barrel in 1994. Oil and natural gas
revenues were significantly impacted by the acquisition of the Encinitas
properties, which added 579 MMcfe of production.
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, 1994 and 1995:
<TABLE>
<CAPTION>
1995 PERIOD COMPARED TO
DECEMBER 31, 1994 PERIOD
--------------------- -----------------------
1994 1995 INCREASE % INCREASE
-------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Production volumes
Oil and condensate (MBbls)......... 33.0 77.6 44.6 135%
Natural gas (MMcf)................. 5.4 565.3 559.9 *
Average sales prices (1)
Oil and condensate (per Bbl)....... $ 17.94 $ 19.64 $ 1.70 9%
Natural gas (per Mcf).............. 0.88 1.60 0.72 81%
Operating revenues
Oil and condensate................. $591,975 $1,524,002 $ 932,027 157%
Natural gas........................ 4,758 904,046 899,288 *
-------- ---------- ----------
Total...................... $596,733 $2,428,048 $1,831,315 307%
======== ========== ==========
</TABLE>
- ---------------
* Not meaningful.
(1) Including impact of hedging.
Oil and gas operating expenses increased 250% to $1.8 million from $518,000
in 1994. The increase was primarily attributable to increased operating expenses
of approximately $964,000 on the Encinitas properties. Operating expenses per
equivalent unit in 1995 decreased to $1.76 per
26
<PAGE> 29
Mcfe from $2.55 per Mcfe in 1994. The per unit cost decreased as a result of
increased production of natural gas which had lower per unit operating costs.
DD&A expense increased 397% to $488,000 from $98,000 in 1994 as a result of
increased production with a relatively flat depletion rate ($0.47 per Mcfe in
1995 from $0.48 per Mcfe in 1994).
General and administrative expense increased 79% to $425,000 from $237,000
in 1994, primarily as a result of the hiring of additional engineering staff and
other employees as well as salary increases for existing employees.
Interest expense increased to $192,000 from $7,000 in 1994. This increase
in 1995 was due to the additional debt incurred to finance the acquisition of
the Encinitas properties. The increase in the weighted average outstanding debt
balance and effective interest rate was due to the additional debt incurred
which bore interest at a bank's prime rate plus 2.75%.
The Company incurred a net loss in 1995 of $467,000, compared to a net loss
of $259,000 in 1994, as a result of the factors described above.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of liquidity have included funds generated by
operations, equity capital contributions and borrowings, primarily under
Carrizo's Secured Reducing Revolving Line of Credit (the "Carrizo Credit
Facility") with Compass Bank ("Compass"). A portion of the proceeds from this
Offering will be used to repay the amounts outstanding under the Carrizo Credit
Facility, the Encinitas Credit Facility (defined below) and the notes from
certain of the Company's directors and officers. Following the Offering, the
Encinitas Credit Facility and the director and officer loans will be terminated,
and the Company expects to enter into an amendment to the Carrizo Credit
Facility, whereupon it will become the Company Credit Facility, as described
below under "-- Financing Arrangements."
Cash flows (used in) provided by operations were $(258,000), $406,000, $3.3
million and $1.8 million in 1994, 1995, 1996 and the three months ended March
31, 1997, respectively. The increase in cash flows provided by operations in
1996 as compared to 1995, and 1995 as compared to 1994, was due primarily to
increased revenues from production.
The Company has budgeted capital expenditures in 1997 of approximately
$21.9 million, $12.6 million of which is expected to be used to fund 3-D seismic
surveys and land acquisitions and $9.3 million of which is expected to be used
for drilling activities in the Company's project areas. The Company has budgeted
capital expenditures in 1998 of approximately $43.8 million. The Company expects
to drill approximately 67 gross wells (26.9 net) in 1997 and has budgeted for
approximately 147 gross wells (67.5 net) in 1998. The actual amounts of capital
expenditures and number of wells drilled may differ significantly from such
estimates. See "Business -- Significant Project Areas." In addition to its
existing leased acreage, as of July 31, 1997, the Company has acquired various
3-D seismic options that will allow it to lease up to approximately 253,000
gross undeveloped acres (95,242 net) if determined by 3-D seismic data to be
prospective for drilling.
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 $800,000, $6.6 million, $9.1 million and $4.3 million in 1994,
1995, 1996 and the three months ended March 31, 1997, respectively. The
Company's drilling efforts resulted in the successful completion of 16 gross
wells (6.0 net) in 1996 that increased the Company's net reserves by 4.3 Bcf of
gas and 70 MBbls of oil at March 31, 1997.
The Company's revenues, profitability, future growth and ability to borrow
funds or obtain additional capital, and the carrying value of its properties,
are substantially dependent on prevailing prices of oil and natural gas. It is
impossible to predict future oil and natural gas price movements with certainty.
Declines in prices received for oil and natural gas may have an adverse effect
on the
27
<PAGE> 30
Company's financial condition, liquidity, ability to finance capital
expenditures and results of operations. Lower prices may also impact the amount
of reserves that can be produced economically by the Company.
Due to the instability of oil and natural gas prices, in 1995 the Company
began utilizing, from time to time, certain hedging instruments (e.g., NYMEX
futures contracts) for a portion of its oil and gas production to achieve a more
predictable cash flow, as well as to reduce the exposure to price fluctuations.
The Company's hedging arrangements apply to only a portion of its production,
provide only partial price protection against declines in oil and natural gas
prices and limit potential gains from future increases in prices. Such hedging
arrangements may expose the Company to risk of financial loss in certain
circumstances, including instances where production is less than expected, the
Company's customers fail to purchase contracted quantities of oil or natural gas
or a sudden unexpected event materially impacts oil or natural gas prices. The
Company accounts for all these transactions as hedging activities and,
accordingly, gains and losses from hedging activities are included in oil and
gas revenues during the period the hedged transactions occur. Historically,
gains and losses from hedging activities have not been material. The Company
expects that the amount of hedges that it has in place will vary from time to
time. The Company had no outstanding hedge positions as of December 31, 1996 or
March 31, 1997.
The Company has experienced and expects to continue to experience
substantial working capital requirements primarily due to the Company's active
exploration and development programs and, to a much lesser extent, its
technology enhancement programs. While the Company believes that the net
proceeds from this Offering, cash flow from operations and borrowings under the
Company Credit Facility should allow the Company to implement its present
business strategy during 1997 and 1998, additional financing may be required in
the future to fund the Company's growth, development and exploration program and
continued technological enhancement. In the event such capital resources are not
available to the Company, its exploration and other activities may be curtailed.
FINANCING ARRANGEMENTS
Following the closing of this Offering, the Company expects to enter into
the Company Credit Facility, which will provide for a maximum loan amount of $25
million, subject to borrowing base limitations. Under the new facility, the
principal outstanding will be due and payable upon maturity in June 1999 with
interest due monthly. The interest rate for borrowings will be calculated at a
floating rate based on the Compass index rate or LIBOR plus 2%. The Company's
obligations will be secured by certain of its oil and gas properties and cash or
cash equivalents included in the borrowing base.
Under the Company Credit Facility, Compass, in its sole discretion, will
make semiannual borrowing base determinations based upon the proved oil and
natural gas properties of the Company. Compass may redetermine the borrowing
base and the monthly borrowing base reduction at any time and from time to time.
The Company may also request borrowing base redeterminations in addition to
their required semiannual reviews at the Company's cost.
The Company will be subject to certain covenants under the terms of the
Company Credit Facility, including but not limited to, (a) maintenance of
specified tangible net worth and (b) maintenance of a ratio of quarterly cash
flow (net income plus depreciation and other noncash charges, less noncash
income) to quarterly debt service (payments made for principal in connection
with the credit facility plus payments made for principal other than in
connection with such credit facility) of no less than 1.25 to 1.00. The Company
Credit Facility will also place restrictions on, among other things, (i)
incurring additional indebtedness, loans and liens, (ii) changing the nature of
business or business structure, (iii) selling assets and (iv) paying dividends.
The foregoing description of the Company Credit Facility is based upon the
terms of a commitment letter with the lender. The Company Credit Facility will
be subject to the negotiation of
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<PAGE> 31
documentation acceptable to the parties and the completion of the Offering with
net cash proceeds of at least $20 million. There can be no assurance that the
Company will enter into any final agreement with the terms described, or at all.
In December 1996, Carrizo entered into the Carrizo Credit Facility with
Compass, which currently provides for a revolving credit commitment amount of
$8.0 million, subject to borrowing base limitations, and a term loan of $7.0
million. Under the Carrizo Credit Facility, the principal outstanding is due and
payable upon maturity in June 1998 with interest due monthly. At June 30, 1997,
(i) the borrowing base was $7.9 million and borrowings outstanding were $6.9
million under the revolving portion of this facility and (ii) borrowings
outstanding were $7.0 million under the term loan portion of this facility. The
interest rate for borrowings is calculated at a floating rate based on a
published prime rate plus .75% with respect to the revolving portion of this
facility and a published rate plus 2.00% with respect to the term loan portion
of this facility. Carrizo's obligations under this facility are secured by
substantially all of its oil and natural gas properties. Individually and
collectively, Paul B. Loyd, Jr., Frank A. Wojtek, Steven A. Webster, Douglas
A.P. Hamilton and S.P. Johnson IV are guarantors of Carrizo's obligations under
the Carrizo Credit Facility. In addition, certain shares of Common Stock owned
by current shareholders are pledged to Compass as security for borrowings under
the Carrizo Credit Facility. The provisions of the Carrizo Credit Facility
regarding borrowing base determinations and restrictive covenants are
substantially the same as those described above with respect to the Company
Credit Facility (except that at Carrizo's option, the borrowing base
determinations may be based on a percentage of the market value of securities
pledged to the bank in addition to the proved oil and natural gas properties of
Carrizo). The Company will use a portion of the proceeds of the Offering to
repay all outstanding indebtedness under the Carrizo Credit Facility. Upon such
repayment, this facility will be amended to become the Company Credit Facility
and such guarantees and pledges will be released.
In June 1996, Encinitas Partners Ltd. ("Encinitas") entered into the
Secured Reducing Revolving Line of Credit (the "Encinitas Credit Facility") with
Compass, which provides for a commitment amount equal to the borrowing base.
Under the Encinitas Credit Facility, the principal outstanding is due and
payable upon maturity in June 1998 with interest due monthly. At June 30, 1997,
the borrowing base under the Encinitas Credit Facility was $2.2 million, of
which $1.9 million was outstanding and $224,000 was reserved for outstanding
letters of credit. The interest rate for borrowings is calculated at a floating
rate based on a published prime rate plus .75%. Encinitas' obligations under
this facility are secured by substantially all of its oil and natural gas
properties. The provisions of the Encinitas Credit Facility regarding borrowing
base determinations and restrictive covenants are substantially the same as
those described above with respect to the Company Credit Facility. The Company
will use a portion of the proceeds of the Offering to repay all outstanding
indebtedness under the Encinitas Credit Facility. Upon such repayment, this
facility will be terminated.
Necessary waivers effective as of December 31, 1996 were received from
Compass to decrease the tangible net worth requirement (Encinitas Facility) and
to permit Carrizo (under the Carrizo Credit Facility) to advance funds to one of
the affiliated entities for exploration expenditures.
In January 1995, the Company entered into a loan agreement with Texas
Commerce Bank, National Association ("TCB") for the acquisition and development
of oil and gas properties by Encinitas Partners Ltd. Borrowings under the loan
facility, which totaled $2.1 million and bore interest at the prime rate as
specified by TCB plus 2.75%, were repaid with borrowings under the Encinitas
Credit Facility, and this loan facility was terminated. As additional
consideration, the Company assigned to TCB a 1% royalty interest in the
Encinitas/Kelsey properties.
In addition to borrowings under the credit facilities described above, the
Company had outstanding borrowings from certain directors and officers of the
Company totaling $1.4 million, $2.8 million and $2.9 million at December 31,
1995 and 1996 and March 31, 1997, respectively. See "Certain Transactions."
These loans bear interest at TCB's prime rate and are due on the earlier of (i)
April or July 1998 or (ii) the closing of the Offering. The Company will use a
portion of the
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<PAGE> 32
proceeds of the Offering to prepay all outstanding borrowings from its
shareholders and does not expect to continue such arrangements with its
shareholders following the Offering.
EFFECTS OF INFLATION AND CHANGES IN PRICE
The Company's results of operations and cash flows are affected by changing
oil and gas prices. If the price of oil and gas increases (decreases), there
could be a corresponding increase (decrease) in the operating cost that the
Company is required to bear for operations, as well as an increase (decrease) in
revenues. Inflation has had a minimal effect on the Company.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In March 1995, the Financial Accounting Standards Board issued SFAS No. 121
regarding accounting for the impairment of long-lived assets. The Company
adopted SFAS No. 121 effective January 1, 1996. However, its provisions are not
applicable to the Company's oil and gas properties as they are accounted for
under the full-cost method of accounting.
In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, which is a new standard of accounting for stock-based compensation that
establishes a fair value method of accounting for awards granted after December
31, 1995 under stock compensation plans. SFAS No. 123 encourages, but does not
require, companies to adopt the fair value method of accounting in place of the
existing method of accounting for stock-based compensation, whereupon
compensation, costs are recognized only in situations where stock compensation
plans award intrinsic value to recipients at the date of grant.
The Company has elected not to adopt the fair value accounting of SFAS No.
123 and will account for any plans under APB Opinion No. 25, under which no
compensation costs have been recognized. The Company has reported the impact of
SFAS No. 123 on a pro forma basis as allowed under the pronouncement. See Note 6
of the notes to combined financial statements.
In February 1997, the Financial Accounting Standards Board issued SFAS No.
128 regarding earnings per share. SFAS No. 128 cannot be adopted until December
15, 1997; however, pro forma disclosures are allowed to minimize the impact of
year-end adoption. As a result of the noncomplex nature of the Company's capital
structure and treatment of all stock options as outstanding for all periods
pursuant to Staff Accounting Bulletin No. 83, SFAS No. 128 would have no current
impact on the pro forma calculation of earnings per share.
30
<PAGE> 33
BUSINESS
OVERVIEW
Carrizo is an independent oil and gas company engaged in the exploration,
development, exploitation and production of natural gas and crude oil. The
Company's operations are currently focused onshore in proven oil and gas
producing trends along the Gulf Coast, primarily in Texas and Louisiana in the
Frio, Wilcox and Vicksburg trends. The Company believes that the availability of
economic onshore 3-D seismic surveys has fundamentally changed the risk profile
of oil and gas exploration in these regions. Recognizing this change, the
Company has aggressively sought to control significant prospective acreage
blocks for targeted, proprietary, 3-D seismic surveys. As of July 31, 1997, the
Company had assembled approximately 355,000 gross acres under lease or option.
The Company typically seeks to acquire seismic permits from landowners that
include options to lease the acreage prior to conducting proprietary surveys. In
other circumstances, including when the Company participates in 3-D group
shoots, the Company typically seeks to obtain leases or farm-ins rather than
lease options.
Approximately 70% of the Company's current acreage position is covered by
3-D seismic data that the Company has acquired, or is in the process of
acquiring, in its first 15 seismic surveys. The Company expects to acquire
additional 3-D seismic data during the remainder of 1997 and 1998 that will
cover substantially all of its remaining current acreage position. From the data
generated by its first seven proprietary seismic surveys, covering 200 square
miles (128,000 acres), 94 drillsites have been identified. The Company's capital
budgets for 1997 and 1998 of approximately $21.9 million and $43.8 million,
respectively, include amounts for the acquisition of additional 3-D seismic data
and for the drilling of 67 gross wells (26.9 net) in 1997 with a 40% average
working interest and the drilling of 147 gross wells (67.5 net) in 1998 with an
anticipated 46% average working interest. In addition, the Company anticipates
that as its existing 3-D seismic data is further evaluated, and 3-D seismic data
is acquired over the balance of its acreage, additional prospects will be
generated for drilling beyond 1998.
The Company's primary drilling targets have been shallow (from 4,000 to
7,000 feet), normally pressured reservoirs that generally involve moderate cost
(typically $200,000 to $500,000 per completed well) and risk. Many of these
drilling prospects also have secondary, deeper, over-pressured targets which
have greater economic potential but generally involve higher cost (typically $1
million to $2 million per completed well) and risk. The Company often seeks to
sell a portion of these deeper prospects to reduce its exploration risk and
financial exposure while still allowing the Company to retain significant upside
potential. Deeper targets have been identified in seven of the Company's 67
prospects budgeted for drilling in 1997. The Company operates the majority of
its projects through the exploratory phase but may relinquish operator status to
qualified partners in the production phase to control costs and focus resources
on the higher-value exploratory phase. As of June 30, 1997, the Company operated
66 producing oil and gas wells, which accounted for 57% of the wells in which
the Company had an interest.
The Company has experienced rapid increases in reserves, production and
EBITDA since its inception in 1993 due to the growth of its 3-D based drilling
and development activities. From January 1, 1996 to March 31, 1997, the Company
participated in the drilling of 29 gross wells (10.2 net) with a commercial well
success rate of approximately 79%. This drilling success contributed to the
Company's total proved reserves as of March 31, 1997 of approximately 38.8 Bcfe,
with a PV-10 Value of $30.4 million. From inception through March 31, 1997, the
Company's average finding and development cost was approximately $0.47 per Mcfe.
The Company's production has increased 125% from 321 MMcfe for the three months
ended March 31, 1996 to 721 MMcfe for the three months ended March 31, 1997.
EBITDA has also increased significantly from $328,000 for the three months ended
March 31, 1996 to $1.1 million for the three months ended March 31, 1997.
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<PAGE> 34
In addition to its core exploratory operations, the Company operates a
heavy oil project in Anderson County, Texas which, as of March 31, 1997,
contained proved reserves of approximately 3.6 MMBbls of 19 degrees API gravity
crude oil. The project produces from a depth of 500 feet and utilizes a tertiary
steam drive as an enhanced oil recovery process. During the first quarter of
1997, the Company produced 107 Bbls/d of oil from this project, which averaged a
$0.65 per Bbl premium over West Texas Intermediate crude due to the produced
oil's suitability as a lube oil feedstock.
The Company's management team has extensive energy industry experience.
S.P. Johnson IV, the Company's President and Chief Executive Officer, has 18
years of industry experience, including 15 years with Shell Oil Company where he
served in various managerial positions. The Company's technical and operating
employees have an average of 15 years of industry experience, in many cases with
major and large independent oil companies, including Shell Oil Company, Vastar
Resources, Inc., Pennzoil Company and Tenneco Inc. The Company's Board of
Directors and major shareholders include its Chairman, Steven A. Webster who is
also Chairman and Chief Executive Officer of Falcon Drilling Company Inc., and
Paul B. Loyd, Jr., the Chairman and Chief Executive Officer of Reading & Bates
Corporation.
The Company believes that its future growth will be driven by the drilling
and development of existing identified opportunities as well as new 3-D based
prospects that are continually being identified from its growing project
portfolio. The Company intends to use the proceeds of this Offering to
accelerate its drilling and development activities, expand its prospective
acreage acquisition program and increase the number and size of, and working
interest in, additional 3-D based projects.
The address of the Company's principal executive office is 14811 St. Mary's
Lane, Suite 148, Houston, Texas 77079 and its telephone number is (281)
496-1352.
BUSINESS STRATEGY
The Company's business strategy is to profitably expand its reserve base,
production levels and EBITDA through the following key elements:
Aggressive Acreage and Seismic Acquisition Program. The Company seeks to
control significant prospective acreage positions in proven producing trends and
then acquire 3-D seismic data to evaluate this acreage. The Company believes
that recent technical improvements and cost reductions of onshore 3-D seismic
surveys and oil and gas drilling techniques have changed the risk/reward profile
of exploration in these regions and allow for the profitable exploration and
development of previously undetected or uneconomic drilling prospects. The
Company believes that its existing large acreage position and seismic database
will generate a significant inventory of drillsites over the next several years.
Focused Exploration. The Company intends to maintain its exploration focus
primarily in the onshore Gulf Coast region, which it believes offers numerous
advantages, including: (i) geologic trends that are prone to the accumulation of
significant oil and gas reserves in multiple target zones, (ii) a large number
of over-looked or under-exploited drilling prospects, (iii) familiarity of the
Company's personnel with the geology of the region, (iv) established
relationships with other regional participants and (v) availability of pipeline
and operating infrastructure. Based on the results to date of its exploration
activities, the Company believes that significant undiscovered reserves remain
in this region, and the Company plans to utilize its existing database of 3-D
seismic and geologic data and its knowledge of the region's producing fields and
trends to further expand its operations within this core region.
Leveraged Project and Drillsite Generation Program. The Company maintains a
flexible and diversified approach to project identification to increase its
exposure to projects in its core areas. The Company's project areas have been
identified by a broad network that includes contract geoscientists who have
expertise in a particular project area, the exploration teams of several
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<PAGE> 35
industry partners as well as the Company's internal geophysical team. This
approach has enabled the Company to increase the number and diversity of
projects from which the Company has developed its exploration program while
controlling the costs associated with these operations. Similarly, in
identifying specific drillsites within a project area, the Company's internal
exploration team has worked with outside contract geoscientists and joint
venture partners.
Prospects with Attractive Risk/Reward Balance. The Company seeks to retain
significant working interest positions in exploration prospects that fit its
risk/reward criteria. Many of the Company's exploration prospects contain both
primary targets with shallower, normally pressured reservoirs that generally
involve moderate cost and risk, as well as secondary targets that consist of
deeper, over-pressured and often larger reservoirs but involve higher cost and
risk. The Company typically retains all or the majority of its interests in the
shallow targets and often sells a portion of its interests in the deeper targets
to industry partners in order to mitigate its exploration risk and fund the
anticipated capital requirements for the retained portion of these targets. The
Company believes that this strategy affords it significant upside potential with
reduced overall risk.
The Company's ability to implement its business strategy will be subject to
numerous risks, including those described under "Dependence on Exploratory
Drilling Activities," "Volatility of Oil and Natural Gas Prices," "Ability to
Manage Growth and Achieve Business Strategy" and other captions under "Risk
Factors."
EXPLORATION APPROACH
The Company generally seeks to rapidly accumulate large amounts of 3-D
seismic data along prolific, producing trends of the onshore Gulf Coast after
obtaining options to lease areas covered by the data. The Company then uses this
data to identify or evaluate prospects before drilling the prospects that fit
its risk/reward criteria. The Company typically seeks to explore in locations
within its core areas of expertise that it believes have (i) numerous
accumulations of normally pressured reserves at shallow depths and in geologic
traps that are difficult to define without the interpretation of 3-D seismic
data and (ii) the potential for large accumulations of deeper, over-pressured
reserves.
As a result of the increased availability of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company has relied almost exclusively on the interpretation of
3-D seismic data in its exploration strategy. The Company generally does not
invest any substantial portion of the costs for an exploration well without
first interpreting 3-D seismic data. The principal advantage of 3-D seismic data
over traditional 2-D seismic analysis is that it affords the geoscientist the
ability to interpret a three dimensional cube of data representing a specific
project area as compared to interpreting between widely separated two
dimensional vertical profiles. As a consequence, the geoscientist is able to
more fully and accurately evaluate prospective areas, improving the probability
of drilling commercially successful wells in both exploratory and development
drilling. The use of 3-D seismic allows the geoscientist to identify and use
areas of irregular sand geometry to augment or replace structural interpretation
in the identification of potential hydrocarbon accumulations. Additionally,
detailed analysis and correlation of the 3-D seismic response to lithology and
contained fluids assist geoscientists in identifying and prioritizing drilling
targets. Because 3-D analysis is completed over an entire target area cube,
shallow, intermediate and deep objectives can be analyzed. Additionally, the
more precise structural definition allowed by 3-D seismic data combined with
integration of available well and production data assists in the positioning of
new development wells.
The Company has sought to obtain large volumes of 3-D seismic data either
by participating in large seismic data acquisition programs either alone or
pursuant to joint venture arrangements with other energy companies, or through
"group shoots" in which the Company shares the costs and results of seismic
surveys. By participating in joint ventures and group shoots, the Company is
able to share the up-front costs of seismic data acquisition and interpretation,
thereby enabling it to
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<PAGE> 36
participate in a larger number of projects and diversify exploration costs and
risks. Substantially all of the Company's operations are conducted through joint
operations with industry participants. The Company is currently actively
involved in 32 project areas, and following the Offering, intends to further
increase the number and size of seismic data acquisition projects in which it
participates to accelerate its exploration activities.
The Company's primary strategy for acreage acquisition is to obtain leasing
options covering large geographic areas in connection with 3-D seismic surveys.
Prior to conducting proprietary surveys, the Company typically seeks to acquire
seismic permits that include options to lease the acreage, thereby ensuring the
price and availability of leases on drilling prospects that may result upon
completing a successful seismic data acquisition program over a project area.
The Company generally attempts to obtain these options covering at least 80% of
the project area for these proprietary surveys. The size of these surveys has
ranged from 10 to 70 square miles. When the Company participates in 3-D group
shoots, it generally seeks prospective leases as quickly as possible following
interpretation of the survey. In connection with some group shoots in which the
Company believes that competition for acreage may be especially strong, the
Company may seek to obtain lease options or leases in prospective areas prior to
the receipt or interpretation of 3-D seismic data.
The Company maintains a flexible and diversified approach to project
identification by focusing on the estimated financial results of a project area
rather than limiting its focus to any one method or source for obtaining leads
for new project areas. The Company's current project areas resulted from leads
developed by its project generation network that includes small, independent
"prospect generators," the Company's joint venture partners and the Company's
internal staff. The Company believes that it has been able to increase the
number of potential projects and reduce its costs through the use of these
outside sources of project generation. Similarly, in identifying specific
drillsites from within a project area, the Company has relied upon outside
contract geoscientists and joint venture partners who have worked with the
Company's own geoscientists. Currently, over 20 geoscientists from this network
are devoting some or all of their time to identifying project areas or
evaluating drillsites in which the Company expects to have an interest.
Similarly, the Company also utilizes outside independent landmen with expertise
in a particular project area. This outsourcing strategy has enabled the Company
to control costs without maintaining a large internal land and exploration
department.
OPERATING APPROACH
The Company's management team has extensive experience in the development
and management of projects along the Texas and Louisiana Gulf Coast. The Company
believes that the experience of its management in the development of 3-D
projects in its core operating areas is a competitive advantage for the Company.
The Company's technical and operating employees have an average of 15 years of
industry experience, in many cases with major and large independent oil
companies, including Shell Oil Company, Vastar Resources, Inc., Pennzoil Company
and Tenneco Inc.
The Company generally seeks to obtain lease operator status and control
over field operations, and in particular seeks to control decisions regarding
3-D survey design parameters and drilling and completion methods. In some cases,
the Company may thereafter relinquish its operator status in order to
concentrate its resources on exploration activities, especially if the Company
has had successful prior experience with an industry partner acting as operator.
The Company currently operates 66 producing oil and natural gas wells, which
range in depth from 450 feet to greater than 6,500 feet.
The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations into
the existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the
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<PAGE> 37
Company seeks to use reliable, high quality, used equipment in place of new
equipment to achieve cost savings. The Company also seeks to minimize cycle time
from drilling to hook-up of wells, thereby accelerating cash flow and improving
ultimate project economics.
The Company seeks to use advanced production techniques to exploit and
expand its reserve base. Following the discovery of proved reserves, the Company
typically continues to evaluate its producing properties through the use of 3-D
seismic data to locate undrained fault blocks and identify new drilling
prospects and performs further reserve analysis and geological field studies
using computer aided exploration techniques. The Company seeks to integrate its
3-D seismic data with reservoir characterization and management systems through
the use of geophysical workstations which are compatible with industry standard
reservoir simulation programs.
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SIGNIFICANT PROJECT AREAS
The Company is currently evaluating 32 exploration project areas. As of
June 30, 1997, the Company had an existing 3-D seismic database of 651 square
miles and was acquiring an additional 486 square miles of data (totaling 1,137
square miles of 3-D seismic data). To date, all project areas for which seismic
data has been interpreted have yielded multiple prospects and drillsites. The
Company is continuing to receive and interpret data covering these project areas
and believes that each project area has the potential for additional prospects
and drillsites.
1997-1998 EXPLORATION PROGRAM
<TABLE>
<CAPTION>
SQ. MILES OF 3-D
GROSS SEISMIC DATA AT
ACREAGE JUNE 30, 1997
LEASED OR ---------------------- TOTAL 1997
UNDER BUDGETED 1997 1998 AND 1998 AVERAGE
OPTION AT EXISTING FOR BUDGETED BUDGETED BUDGETED AVERAGE NET
JULY 31, OR BEING ACQUISITION GROSS GROSS GROSS WORKING REVENUE
PROJECT AREAS 1997 ACQUIRED 1997-1998 WELLS(1) WELLS(2) WELLS INTEREST(3) INTEREST(3)
------------- --------- -------- ----------- -------- -------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
TEXAS
Starr/Hidalgo............. 4,435 340(4) -- 12 15 27 50.0% 37.5%
Encinitas/Kelsey.......... 9,110 32 -- 10 1 11 27.5% 23.0%
Buckeye................... 36,105 62 -- 16 11 27 50.0% 39.0%
La Rosa................... 8,249 22 -- -- 4 4 31.5% 23.6%
Mexican Sweetheart........ 30,795 40 -- -- 8 8 25.0% 18.8%
McFaddin Ranch............ 5,374 15 -- 4 4 8 37.5% 28.1%
Cologne................... 18,200 40 -- -- 8 8 25.0% 18.8%
South Cabeza Creek........ 7,128 20 -- -- 4 4 52.5% 39.4%
East McFaddin............. 6,440 11 -- 1 -- 1 20.0% 16.5%
Hiawatha.................. 15,516 22 -- 12 4 16 42.0% 31.5%
Western 325............... -- 320(4) -- 2(2) 5 7 50.0% 37.5%
Lance..................... 18,536 30 -- 4 5 9 25.0% 19.3%
Highway 59................ 4,995 -- 20 -- 4 4 20.0% 15.0%
Geronimo.................. 29,358 107 -- 3 10 13 15.0% 11.3%
RPP Welder................ 31,182 60 -- -- 10 10 15.0% 11.3%
Midway.................... 1,235 -- 15 -- 4 4 50.0% 37.5%
Lost Bridge............... 5,065 16 -- -- 3 3 50.0% 37.5%
Drake 202................. 3,877 -- 19 -- -- -- 100.0% 82.8%
Other (11 Areas).......... 114,664 -- 291 -- 42 42 72.5% 56.9%
LOUISIANA
North Chalkley............ 1,130 -- 20 1 2 3 18.0% 14.2%
Atchafalaya............... 3,611 -- -- 1 2 3 55.4% 41.5%
Live Oak.................. 350 -- -- 1 1 2 20.0% 15.0%
------- ----- --- -- --- ---
TOTAL.............. 355,355 1,137 365 67 147 214
======= ===== === == === ===
</TABLE>
- ---------------
(1) Consists of identified drillsites included in the Company's 1997 capital
budget that are fully evaluated, leased and have been or are scheduled to be
drilled during 1997, except as otherwise indicated. Of these budgeted wells,
30 had been drilled as of June 30, 1997.
(2) Consists of wells included in the Company's 1997 and 1998 capital budgets,
but as to which 3-D seismic data has either not been obtained or fully
evaluated, or for which the Company has not yet acquired leases or option
rights. The number of wells indicated is based upon statistical results of
drilling activities in 3-D project areas that the Company believes are
geologically similar.
(3) Anticipated interests based on contractual rights as of June 30, 1997.
(4) Represents non-proprietary "group shoots" in which the Company is a
participant.
36
<PAGE> 39
Set forth below are descriptions of the Company's key project areas where
it is actively exploring for potential oil and natural gas prospects and in some
cases currently has production. The 3-D surveys the Company is using to analyze
its project areas range from regional, non-proprietary "group shoots" to single
field proprietary surveys. The Company has, in many cases, participated in these
project areas with industry partners to share the up-front costs associated with
obtaining option arrangements with landowners, seismic data acquisition and
related data interpretation, to mitigate its exploration risk and to increase
the number of projects in which it is able to participate.
Although the Company is currently pursuing prospects within the project
areas described below, and has budgeted to drill the number of wells set forth
in the preceding table, there can be no assurance that these prospects will be
drilled at all or within the expected time frame. In particular, budgeted wells
that are based upon statistical results of drilling activities in other project
areas are subject to greater uncertainties than wells for which drillsites have
been identified. The final determination with respect to the drilling of any
identified drillsites or budgeted wells will be dependent on a number of
factors, including (i) the results of exploration efforts and the acquisition,
review and analysis of the seismic data, (ii) the availability of sufficient
capital resources by the Company and the other participants for the drilling of
the prospects, (iii) the approval of the prospects by other participants after
additional data has been compiled, (iv) the economic and industry conditions at
the time of drilling, including prevailing and anticipated prices for oil and
natural gas and the availability of drilling rigs and crews, (v) the financial
resources and results of the Company and (vi) the availability of leases on
reasonable terms and permitting for the prospect. There can be no assurance that
these projects can be successfully developed or that the identified drillsites
or budgeted wells discussed will, if drilled, encounter reservoirs of
commercially productive oil or natural gas. The reserve data set forth below is
based upon the Reserve Reports. There are numerous uncertainties in estimating
quantities of proved reserves, including many factors beyond the control of the
Company. See "Risk Factors -- Dependence on Exploratory Drilling Activities,"
"-- Reserve Replacement Risk" and "-- Uncertainty of Reserve Information and
Future Net Revenue Estimates."
TEXAS
Starr/Hidalgo Project Area: Frio and Vicksburg Formations
The Starr/Hidalgo Project Area is located in Starr and Hidalgo Counties,
Texas in the Frio and Vicksburg formations. The Company and a partner licensed
approximately 340 square miles of non-proprietary 3-D seismic data that was
delivered during August 1995 and June 1996. Sixty-four prospects have been
identified in the shallow Frio trend and the deeper, structurally complex
Vicksburg trend, as well as two large prospects in the relatively unexplored
Eocene trend. The Company and its partner have leases covering 3,715 acres and
options covering 720 acres in this project area and currently control 18 of
these prospects (10 Frio, seven Vicksburg and one Eocene). The Company sold a
portion of its interest in four of the deeper and riskier Vicksburg prospects to
industry partners. During the quarter ended June 30, 1997, the Company's share
of production from wells in this project area was approximately 47 Bbls/d of oil
and 4.1 MMcf/d of natural gas. As of June 30, 1997, the Company and its partners
have drilled a total of 18 wells in this project area, resulting in 14 producing
wells. The estimated proved reserves net to the Company for this project area
was 19.0 MBbls of oil and 2.5 Bcf of natural gas at March 31, 1997. The Company
and its partners have identified 12 locations that have been or are scheduled to
be drilled during 1997. The Company believes that continuing interpretation and
seismic processing of the Starr/Hidalgo Project Area 3-D seismic data will
result in additional prospects and drilling locations.
Encinitas/Kelsey Project Area: Frio and Vicksburg Formations
The Encinitas/Kelsey Project Area is located in Brooks County, Texas in the
Frio and Vicksburg formations. The Company acquired an interest in leases
covering 9,110 acres in this area in
37
<PAGE> 40
December 1994 to re-develop the property. Upon acquisition of its interests in
this project area, the Company undertook a comprehensive petrophysical study and
acquired a 32 square mile 3-D seismic survey. This effort has resulted in the
identification of numerous Frio and Vicksburg prospects. At March 31, 1997, the
Company had estimated proved reserves net to the Company of 106.4 MBbls of oil
and 2.1 Bcf of natural gas for this project area. During the quarter ended June
30, 1997, the Company's share of production from wells in this project area was
184 Bbls/d of oil and 2.6 MMcf/d of natural gas. As of June 30, 1997, the
Company and its partners have drilled a total of 11 wells resulting in nine
producing wells. The Company and its partners have identified 10 locations that
have been or are scheduled to be drilled in 1997, with the possibility of
additional follow-up drilling in 1998.
Buckeye Project Area: Wilcox, Hockley, Pettus and Yegua Formations
The Buckeye Project Area is located in Live Oak County, Texas. The Company
and its partner currently hold 9,806 acres under lease and 26,299 acres under
option and have acquired an approximately 22 square mile 3-D seismic survey over
the first 12,000 optioned acres. A 3-D seismic survey over the remaining acres
under option is currently being acquired. The exploration objectives for the
Buckeye Project Area are the shallow zones of the Hockley, Pettus and Yegua
formations and the deep zones of the expanded Upper Wilcox formation. The data
for the first phase was received from processing in April 1997 and initial
interpretation has generated 16 shallow prospects. Twelve of these prospects
have been drilled with nine successful completions. The remaining prospects are
planned to be drilled in the second half of 1997.
La Rosa Project Area: Frio Formation
The La Rosa Project Area is located in Refugio County, Texas over a
producing field leasehold of 3,700 acres. The area covers Frio
barrier/strandplain sands productive down to 8,200 feet. Data is currently being
processed from a 3-D seismic survey over 22 square miles that was conducted by
the Company during the first quarter of 1997. The Company will attempt to use
the 3-D seismic data to identify shallow objectives, delineate reservoir
compartments for drilling of bypassed reserves and identify flank prospects and
deeper prospects in the Vicksburg trend. The Company's leases cover 3,689 acres
and its seismic options cover 4,560 acres in this project area.
Mexican Sweetheart Project Area: Frio Formation
The Mexican Sweetheart Project Area is located in southwestern Jackson
County, Texas in the Frio producing trend. A secondary objective for this
project area may be the shallow Miocene trend and the Yegua and Wilcox trends.
The area is directly south of successful 3-D seismic projects conducted by the
Company's partners in this project and covers historical field discoveries. The
Company has planned and directed a 40 square mile 3-D seismic survey covering
the project area, and field operations were initiated in March 1997. The Company
will seek to use the 3-D seismic data to identify shallow objectives, delineate
reservoir compartments for drilling of bypassed reserves and identify flank
prospects and deeper, higher risk prospects in the Yegua and Upper Wilcox
trends, which the Company would seek to explore on a carried basis with an
industry partner. The Company's leases cover 848 acres and its seismic options
cover 29,947 acres in this project area.
McFaddin Ranch Project Area: Miocene and Frio Formations
The McFaddin Ranch Project Area is located in Victoria County, Texas in the
Miocene and Frio formations. Data is currently being interpreted from a 15
square mile 3-D seismic survey conducted in the first quarter of 1997. The
Company will seek to use the 3-D seismic data to delineate a prospect identified
through subsurface geological work and interpretation of 2-D seismic data. This
project area is immediately northwest of the East McFaddin Field Project Area.
The Company has
38
<PAGE> 41
identified and budgeted to drill four prospects in this project area during
1997. The Company's seismic options in this project area cover 5,374 acres.
Cologne Project Area: Frio Formation
The Cologne Project Area is located in Goliad and Victoria Counties, Texas
in the Frio formation. A secondary objective for this project area may be the
Yegua and Wilcox formations. The area covers several historical field
discoveries. A 40 square mile 3-D seismic survey has been shot over the project
area and is currently being interpreted. The Company will seek to use the 3-D
seismic data to identify shallow opportunities, to delineate any reservoir
compartments for drilling of bypassed reserves and seek to identify flank
prospects and deeper, higher risk, prospects in the Yegua and Upper Wilcox
formations. The Company's seismic options cover 18,200 acres in this project
area.
South Cabeza Creek Project Area: Frio Formation to Lower Wilcox Sands
The South Cabeza Creek Project Area is located in Goliad County, Texas in
an area having significant production in the shallow Frio and lower Wilcox
trends. The Company is currently in the process of acquiring seismic options and
leases for a proposed 20 square mile 3-D seismic shoot in the project area that
is currently scheduled to begin in the third quarter of 1997. The Company
intends to use the 3-D seismic data to identify potential Frio, Vicksburg and
Yegua opportunities and to verify and optimize a Wilcox prospect. The Company
currently has 525 acres under lease and 6,603 acres under seismic option in this
project area.
East McFaddin Project Area: Frio Formation
The East McFaddin Project Area is located in Victoria County, Texas. In
1995, the Company obtained a 20% working interest in acreage in this project
area by funding an approximately 11 square mile 3-D seismic survey. During the
quarter ended March 31, 1997, the Company's share of production from wells in
this project area was 18 Bbls/d of oil and 0.5 MMcf/d of natural gas. As of June
30, 1997, the Company and its partners had drilled a total of five wells
resulting in two producing wells. At March 31, 1997, this project area had
estimated proved reserves net to the Company of 2.3 MBbls of oil and 0.6 Bcf of
gas. The Company and its partners have identified one location scheduled to be
drilled in 1997, with the possibility of additional follow-up drilling in 1998.
The Company currently has 6,440 acres under lease in this project area.
Hiawatha Project Area: Pettus and Yegua Formations
The Hiawatha Project Area is located in Duval County, Texas and covers
existing producing fields originally developed in the 1940s, with the most
recent drilling in the 1970s. In August 1996, the Company and its partners
acquired an approximately 22 square mile 3-D seismic survey and currently hold
leases covering 15,516 acres in the project area. During the quarter ended June
30, 1997, the Company's share of production from wells in this project area was
30 Bbls/d of oil and 0.7 MMcf/d of natural gas. As of June 30, 1997, the Company
and its partners have drilled a total of 12 wells resulting in eight producing
wells. This project area had estimated proved reserves net to the Company of
28.2 MBbls of oil and 0.5 Bcf of natural gas at March 31, 1997. The Company and
its partners have identified 12 locations that have been or are scheduled to be
drilled in 1997, with the possibility of additional follow-up drilling depending
on the results of the scheduled drilling.
Western 325 Project Area: Wilcox and Jackson-Yegua Formations
The Western 325 Project Area is located in Webb and Duval Counties, Texas
in the Wilcox and Jackson-Yegua formations. The Company and a partner have
joined others in underwriting a non-proprietary 3-D seismic data shoot covering
approximately 320 square miles in the project area. Multiple prospects have been
identified from data covering approximately 50 square miles that was
39
<PAGE> 42
delivered in April 1997. The remainder of the data is currently expected to be
delivered in the third quarter of 1997 and in 1998. The Company has budgeted to
drill two wells in this project area during the second half of 1997. The Company
believes that experience gained in the Starr/Hidalgo Project Area may assist in
exploration efforts in the Western 325 Project Area.
Lance Project Area: Frio Formation
The Lance Project Area is located in Bee County, Texas in an area of
prolific shallow Frio production. The primary exploration objectives in this
project area are the Frio/Vicksburg trends, with secondary objectives in the
deeper Vicksburg, Jackson and Yegua formations. The Company is currently
interpreting data from a 30 square mile 3-D seismic survey completed in the
second half of 1996. The Company will seek to use the 3-D seismic data to
delineate reservoir compartments for drilling of bypassed Frio reserves as well
as to identify flank and deeper Vicksburg prospects. The Company has scheduled
to drill four prospects in this project area during 1997. The Company's leases
in this project area cover 500 acres and its seismic options in this project
area cover 18,036 acres.
Highway 59 Project Area: Frio, Yegua and Wilcox Formations
The Highway 59 Project Area is located in Fort Bend and Wharton Counties,
Texas in an area of several historical field discoveries and production in the
Frio and Yegua formations and in the highly competitive Wharton County Wilcox
trend. A survey design has been completed for a 20 square mile 3-D seismic
survey in the project area, and field work is expected to begin during the third
quarter of 1997. The Company and two large independent industry partners will
seek to use the 3-D seismic data to identify shallow opportunities and to
delineate Yegua and Wilcox prospects identified through the interpretation of
2-D seismic data. The Company's leases in this project area currently cover
4,995 acres.
Geronimo Project Area: Frio Formation
The Geronimo Project Area is located in San Patricio County, Texas in an
area of predominantly Frio production. Numerous fault systems run through the
area, particularly in the basal Frio and Vicksburg formations. A 67 square mile
3-D seismic survey was conducted in 1996, with the initial interpretation of
data generating five prospects. The Company has scheduled to drill three of
these prospects during 1997, with possible follow-up development anticipated in
1998. A northeast extension of the initial 3-D seismic survey covering an
additional 40 square miles is currently being acquired. The Company's leases
cover 10,278 acres and its seismic options cover 19,080 acres in this project
area.
RPP Welder Project Area: Frio and Vicksburg Formations
The RPP Welder Project Area is located in San Patricio and Refugio
Counties, Texas in an area of predominantly upper Frio production and is
adjacent to the Geronimo, Midway and LaRosa Project Areas. Numerous fault
systems run through the area, particularly at the relatively unexplored basal
Frio and Vicksburg levels. The primary producing formations in this area have
historically been Miocene and upper Frio oil objectives. Field operations for a
60 square mile 3-D seismic survey commenced during the second quarter of 1997.
The Company's leases cover 1,128 acres and its options cover 30,055 acres in
this project area.
Midway Project Area: Frio Formation
The Midway Project Area is located in San Patricio County, Texas in an area
of predominantly Frio production. The area is a southwest extension of the
Geronimo Project Area and includes the Company's producing properties from the
Midway Field along with contiguous leases and seismic option areas. The Company
has designed a 15 square mile 3-D seismic survey in this project area,
40
<PAGE> 43
and field operations are planned to commence in the third quarter of 1997. The
Company's leases cover 1,235 acres in this project area.
Lost Bridge Project Area: Frio, Yegua and Wilcox Formations
The Lost Bridge Project Area is located in northern Jackson County, Texas
in the Frio, Yegua and Wilcox formations. The area covers several historical
field discoveries and recent Wilcox production. The Company expects to begin
work in the third quarter of 1997 on a 16 square mile 3-D seismic survey. The
Company will seek to use the 3-D seismic data to delineate a Yegua prospect
identified with 2-D seismic data, identify shallow opportunities and image the
deeper Wilcox trend. The Company's strategy is to drill any Yegua prospects and
sell a portion of its interest in any Wilcox prospects while retaining a carried
interest. The Company is currently acquiring seismic options in the project area
and has 751 acres under lease and 4,314 acres under option to date.
Drake 202 Project Area: Frio and Vicksburg Formations
The Drake 202 Project Area is located in Bee County, Texas adjacent to the
Lance Project Area. Primary exploration objectives for this project area are the
Frio and Vicksburg formations, as well as deeper, higher risk prospects in the
Yegua formation. In this project area, the Company has seismic options covering
3,877 acres. A 19 square mile 3-D seismic survey is budgeted for late 1997.
LOUISIANA
North Chalkley Project Area: Miogyp Sand
The North Chalkley Project Area is located in Calcasieu and Cameron
Parishes, Louisiana in an area of production from the Miogyp sand trend. The
exploration objective of this project area is a prospect identified through the
interpretation of 2-D seismic data in the third Camerina and Miogyp sands. The
Company's leases in this project area cover 1,130 acres. The Company sold a
portion of its interest in the project area to two large independent oil and
natural gas companies for cash and retained an 18% working interest, of which
15.5% will be carried to casing point on the first well that is currently being
drilled. Depending on well results, the Company expects that it and its partners
would conduct a 20 square mile 3-D seismic survey of the area.
Atchafalaya Project Area: Cib Op-C Sand
The Atchafalaya Project Area is located in Atchafalaya Bay in Louisiana. In
1991, a well was drilled in this fault block resulting in a field discovery at
approximately 17,500 feet. The Company and its partners control 3,611 acres in
this project area under a farm-in agreement and two state leases. The farm-in
agreement requires the commencement of the drilling of an initial well by
September 30, 1997. The Company's partners have access to 20 square miles of 3-D
seismic data covering this project area. As of March 31, 1997, the Company's net
estimated proved reserves in this project area were 308 MBbls of oil and 5.8 Bcf
of natural gas, all of which are undeveloped. The Company plans to drill one
well in this project area with a barge rig during the remainder of 1997. The
Company plans to sell a significant portion of its interests in this project
area.
Live Oak Project Area: Chris II Sand
The Live Oak Project Area is located in Vermillion Parish, Louisiana. In
1996, the Company and its partners acquired access to a 20 square mile 3-D
seismic survey. The Company promoted its interest in the project area to two
independents and will pay 11% of the well costs for 20% of the working interest.
The Company's leases in this project area cover an aggregate of approximately
350 acres. One well is scheduled to be drilled in the third quarter of 1997.
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<PAGE> 44
OTHER PROJECT AREAS
In addition to the project areas described above, the Company has 11
additional project areas in the early stages of development. These project areas
are located in the onshore Texas Gulf Coast region, with the primary exploration
objectives being the Frio and Yegua formations, as well as one project area in
the Cotton Valley Lime Reef trend. The Company is in the process of acquiring
interests with respect to most of these project areas and has acquired leases
and seismic options covering 114,664 acres to date. 3-D seismic surveys covering
an aggregate of approximately 291 square miles are budgeted for acquisition
during 1997 and 1998. Any drilling in these project areas is not expected to be
completed any earlier than 1998.
SIGNIFICANT DEVELOPMENT PROJECT -- Camp Hill
The Company owns interests in and operates six leases totaling 282 acres in
the Camp Hill field in Anderson County, Texas. During the quarter ended March
31, 1997, the project produced 107 Bbls/d of 19 degrees API gravity oil. The
project produces from a depth of 500 feet and utilizes a tertiary steam drive as
an enhanced oil recovery process. Although efficient at maximizing oil recovery,
the steam drive process is relatively expensive to operate because natural gas
is burned to create the steam injectant. Lifting costs during the first quarter
of 1997 averaged $16.80 per barrel ($2.80 per Mcfe). Because profitability
increases when natural gas prices drop relative to oil prices, the project is a
natural hedge against decreases in natural gas prices relative to oil prices.
The crude oil produced, although viscous, commands a higher price (an average
premium of $.65 per barrel during the first quarter of 1997) than West Texas
intermediate crude due to its suitability as a lube oil feedstock. As of March
31, 1997, the Company had 3.6 MMBbls of oil of proved reserves in this project,
with 0.9 MMBbls of oil currently developed. The Company anticipates that it will
drill additional wells and increase steam injection to develop the proved
undeveloped reserves in this project, with the timing and amount of expenditures
depending on the relative prices of oil and natural gas. The Company has an
average working interest of 92.5% in its leases in this field and an average net
revenue interest of 74.0%.
OIL AND NATURAL GAS RESERVES
The following table sets forth estimated net proved oil and natural gas
reserves of the Company and the PV-10 Value of such reserves as of March 31,
1997. The reserve data and the present value as of March 31, 1997 were prepared
by Ryder Scott and Fairchild. For further information concerning Ryder Scott's
and Fairchild's estimate of the proved reserves of the Company at March 31,
1997, see the Reserve Reports included as Annex A to this Prospectus. 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 9 of Notes to Financial Statements. Also see
"Risk Factors -- Uncertainty of Reserve Information and Future Net Revenue
Estimates."
<TABLE>
<CAPTION>
PROVED RESERVES(1)
--------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Oil and condensate (MBbls)................... 1,225 3,063 4,289
Natural gas (MMcf)........................... 6,405 6,621 13,026
Total proved reserves (MMcfe)................ 13,757 25,001 38,758
PV-10 Value(2)............................... $15,344 $15,076 $30,421
</TABLE>
- ---------------
(1) The Reserve Reports as of March 31, 1997 do not include reserves for five
wells completed as of March 31. In addition, 18 wells were completed from
March 31, 1997 through June 30, 1997. See "-- Drilling Activity."
42
<PAGE> 45
(2) The PV-10 Value as of March 31, 1997 was determined by using the March 31,
1997 weighted average sales prices of $19.71 per Bbl of oil and $1.74 per
Mcf of natural gas. The decline in PV-10 Value from December 31, 1996 to
March 31, 1997 was primarily attributable to decreases in prices used for
these calculations at such dates for natural gas (from $3.69 per Mcf to
$1.74 per Mcf), and to a lesser extent oil (from $20.88 per Bbl to $19.71
per Bbl), which decreases more than offset the effect of increased volumes
of proved reserves during the period.
There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and in projecting future rates of production
and timing of development expenditures, including many factors beyond the
control of the producer. The reserve data set forth herein represents estimates
only. Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates made by different engineers often vary from one another. In
addition, results of drilling, testing and production subsequent to the date of
an estimate may justify revision of such estimates, and such revisions may be
material. Accordingly, reserve estimates are generally different from the
quantities of oil and natural gas that are ultimately recovered. Furthermore,
the estimated future net revenues from proved reserves and the present value
thereof are based upon certain assumptions, including future prices, production
levels and costs, that may not prove correct.
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Commission.
In accordance with Commission regulations, the Reserve Reports used oil and
natural gas prices in effect at March 31, 1997. The prices used in calculating
the estimated future net revenue attributable to proved reserves do not
necessarily reflect market prices for oil and natural gas production subsequent
to March 31, 1997. There can be no assurance that all of the proved reserves
will be produced and sold within the periods indicated, that the assumed prices
will actually be realized for such production or that existing contracts will be
honored or judicially enforced.
43
<PAGE> 46
VOLUMES, PRICES AND OIL & GAS OPERATING EXPENSE
The following table sets forth certain information regarding the production
volumes of, average sales prices received for and average production costs
associated with the Company's sales of oil and natural gas for the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, THREE MONTHS
---------------------------- ENDED
1994 1995 1996 MARCH 31, 1997
------ ------ ------ --------------
<S> <C> <C> <C> <C>
PRODUCTION VOLUMES
Oil (MBbls).................................... 33 78 107 21
Natural gas (MMcf)............................. 5 565 1,273 592
Natural gas equivalent (MMcfe)................. 203 1,033 1,915 721
AVERAGE SALES PRICES
Oil (per Bbl).................................. $17.94 $19.64 $21.54 $21.50
Natural gas (per Mcf).......................... 0.88 1.60 2.27 2.35
Natural gas equivalent (per Mcfe).............. 2.94 2.36 2.71 2.57
AVERAGE COSTS (PER MCFE)
Camp Hill operating expenses................... $ 2.64 $ 2.06 $ 3.15 $ 2.80
Other operating expenses....................... 1.85 1.63 0.94 0.60
Total operating expenses(1).......... 2.55 1.76 1.24 0.77
</TABLE>
- ---------------
(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 March 31, 1997, the Company has incurred total gross
development, exploration and acquisition costs of approximately $20.0 million.
Total exploration, development and acquisition activities from inception through
March 31, 1997 have resulted in the addition of approximately 42.4 Bcfe, net to
the Company's interest, of proved reserves at an average finding and development
cost of $0.47 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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, THREE MONTHS
------------------------ ENDED
1994 1995 1996 MARCH 31, 1997
---- ------ ------ --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Acquisition costs
Unproved prospects............................. $ -- $ 317 $ 51 $ 11
Proved properties.............................. 329 3,588 1,908 --
Exploration...................................... 280 2,364 4,724 3,550
Development...................................... 177 209 1,956 549
---- ------ ------ ------
Total costs incurred(1)................ $786 $6,478 $8,639 $4,110
==== ====== ====== ======
</TABLE>
- ---------------
(1) Excludes capitalized interest on unproved properties of $117,288 and
$422,493 for the years ended December 31, 1995 and 1996, respectively.
44
<PAGE> 47
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
years ended December 31, 1994, 1995 and 1996 and the three months ended March
31,1997. In the table, "gross" refers to the total wells in which the Company
has a working interest and "net" refers to gross wells multiplied by the
Company's working interest therein. As shown below, the Company's drilling
activity from January 1, 1994 to March 31, 1997 has resulted in a commercial
success rate of approximately 79%.
<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED
---------------------------------------------- MARCH 31,
1994 1995 1996 1997
------------- ------------- ------------ ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory Wells
Productive.................. -- -- -- -- 16 6.0 7 2.2
Nonproductive............... -- -- -- -- 4 1.1 2 0.9
---- ---- ---- ---- -- --- -- ---
Total............... -- -- -- -- 20 7.1 9 3.1
==== ==== ==== ==== == === == ===
Development Wells
Productive.................. -- -- -- -- -- -- -- --
Nonproductive............... -- -- -- -- -- -- -- --
---- ---- ---- ---- -- --- -- ---
Total............... -- -- -- -- -- -- -- --
==== ==== ==== ==== == === == ===
</TABLE>
From March 31, 1997 to July 31, 1997, the Company drilled 28 gross
productive exploratory wells (12.7 net), of which 20 were successfully
completed, and one gross productive development well (0.3 net) that was
successfully completed. As of July 31, 1997, the Company was drilling or
evaluating four gross exploratory wells (1.4 net) and no gross development
wells.
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 March 31, 1997.
<TABLE>
<CAPTION>
COMPANY-
OPERATED OTHER TOTAL
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Oil............................................... 56 56.0 23 5.0 79 61.0
Natural gas....................................... 10 6.9 26 7.3 36 14.2
-- ---- -- ---- --- ----
Total................................... 66 62.9 49 12.3 115 75.2
== ==== == ==== === ====
</TABLE>
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of March 31, 1997. Developed acres
refers to acreage within producing units and undeveloped acres refers to acreage
that has not been placed in producing units. Leases covering substantially all
of the undeveloped acreage in the following table will expire within the next
three years. In general, the Company's leases will continue past their primary
terms if oil or natural gas in commercial quantities is being produced from a
well on such leases.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
ACREAGE ACREAGE TOTAL
-------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
------ ----- ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Louisiana............................... 0 0 4,390 3,217 4,390 3,217
Texas................................... 29,643 9,979 32,972 9,945 62,615 19,924
------ ----- ------ ------ ------ ------
Total......................... 29,643 9,979 37,362 13,162 67,005 23,141
====== ===== ====== ====== ====== ======
</TABLE>
45
<PAGE> 48
The table does not include leases covering 35,008 gross acres (9,194 net)
acquired between March 31, 1997 and July 31, 1997. In addition, the table does
not include 253,342 gross acres (95,242 net) that the Company has a right to
acquire pursuant to various seismic option agreements at July 31, 1997. Under
the terms of its option agreements, the Company typically has the right for a
period of one year, subject to extensions, to exercise its option to lease the
acreage at predetermined terms. The Company's lease agreements generally
terminate if wells have not been drilled on the acreage within a period of three
years.
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 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. As of March 31, 1997, there were no existing hedge positions. Total
natural gas purchased and sold under swap arrangements during the years ended
December 31, 1995 and 1996 were 40,000 MMbtu and 60,000 MMbtu, respectively.
Gains and losses realized by the Company under such swap arrangements were
$23,466 and $26,887 for the years ended December 31, 1995 and 1996,
respectively. The Company did not engage in hedging prior to 1995 and did not
engage in hedging during the quarter ended March 31, 1997.
COMPETITION
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
46
<PAGE> 49
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.
REGULATION
The availability of a ready market for oil and gas production depends upon
numerous factors beyond the Company's control. These factors include regulation
of oil and natural gas production, federal and state regulations governing
environmental quality and pollution control, state limits on allowable rates of
production by well or proration unit, the amount of oil and natural gas
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of an available natural gas pipeline in the
areas in which the Company may conduct operations. State and federal regulations
generally are intended to prevent waste of oil and natural gas, protect rights
to produce oil and natural gas between owners in a common reservoir, control the
amount of oil and natural gas produced by assigning allowable rates of
production and control contamination of the environment. Pipelines are subject
to the jurisdiction of various federal, state and local agencies. The following
discussion summarizes the regulation of the United States oil and gas industry.
The Company believes that it is in substantial compliance with such statutes,
rules, regulations and governmental orders, although there can be no assurance
that this is or will remain the case. 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 in, 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 which may
be drilled in and the unitization or pooling of oil and gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units, and therefore, more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and natural gas the Company can produce
from its
47
<PAGE> 50
wells and may limit the number of wells or the locations at which the Company
can drill. The regulatory burden on the oil and gas industry increases the
Company's costs of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently expanded, amended and
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.
Regulation of Sales and Transportation of Natural Gas. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural
Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder
by the Federal Energy Regulatory Commission (the "FERC"). Maximum selling prices
of certain categories of natural gas sold in "first sales," whether sold in
interstate or intrastate commerce, were regulated pursuant to the NGPA. The
Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of not
later than January 1, 1993, all remaining federal price controls from natural
gas sold in "first sales." The FERC's jurisdiction over natural gas
transportation was unaffected by the Decontrol Act. While sales by producers of
natural gas and all sales of crude oil, condensate and natural gas liquids can
currently be made at market prices, Congress could reenact price controls in the
future.
The Company's sales of natural gas are affected by the availability, terms
and cost of transportation. The price and terms for access to pipeline
transportation are subject to extensive regulation. In recent years, the FERC
has undertaken various initiatives to increase competition within the natural
gas industry. As a result of initiatives like FERC Order 636, issued in April
1992, the interstate natural gas transportation and marketing system has been
substantially restructured to remove various barriers and practices that
historically limited non-pipeline natural gas sellers, including producers, from
effectively competing with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers. The most significant
provisions of Order No. 636 require that interstate pipelines provide
transportation separate or "unbundled" from their sales service, and require
that pipelines provide firm and interruptible transportation service on an open
access basis that is equal for all natural gas supplies. In many instances, the
result of Order No. 636 and related initiatives have been to substantially
reduce or eliminate the interstate pipelines' traditional role as wholesalers of
natural gas in favor of providing only storage and transportation services.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
ratemaking methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, the FERC
announced a broad inquiry into issues facing the natural gas industry to assist
the FERC in establishing regulatory goals and priorities in the post-Order No.
636 environment. Similarly, the Texas Railroad Commission has been reviewing
changes to its regulations governing transportation and gathering services
provided by intrastate pipelines and gatherers. While the changes being
considered by these federal and state regulators would affect the Company only
indirectly, they are intended to further enhance competition in natural gas
markets.
The Company owns certain natural gas pipelines that it believes meet the
standards the FERC has used to establish a pipeline's status as a gatherer not
subject to FERC jurisdiction under the NGA. State regulation of gathering
facilities generally includes various safety, environmental, and in some
circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation. Natural gas gathering may receive greater regulatory
scrutiny at both state and federal levels in the post-Order No. 636 environment.
The Company cannot predict what further action the FERC or state regulators
will take on these matters; however, the Company does not believe that it will
be affected by any action taken materially differently than other natural gas
producers with which it competes.
48
<PAGE> 51
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
market prices. The price the Company receives from the sale of these products
may be affected by the cost of transporting the products to market. Effective
January 1995, the FERC implemented regulations establishing an indexing system
under which oil pipelines will be able to change their transportation rates,
subject to prescribed ceiling limits. The indexing system generally indexes such
rates to inflation, subject to certain conditions and limitations. The Company
is not able at this time to predict the effects of these regulations, if any, on
the transportation costs associated with oil production from the Company's oil
producing operations.
Environmental Regulations. The Company's operations are subject to numerous
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. 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
could continue. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes environmental protection requirements
that result in increased costs to the oil and gas industry in general, 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 utilized good operating and waste disposal
practices, prior owners and operators of these properties may not have utilized
similar practices, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by the Company or on or
under locations where such wastes have been taken for disposal. In addition,
many of these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the Company's
control. These properties and the wastes disposed thereon may be subject to the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
RCRA and analogous state laws as well as state laws governing the management of
oil and gas wastes. Under such laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from the operations
of the Company. The EPA and states have been developing regulations to implement
these requirements. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related
49
<PAGE> 52
issues. However, the Company does not believe its operations will be materially
adversely affected by any such requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure ("SPCC") and response plans relating
to the possible discharge of oil into surface waters. The Company has
acknowledged the need for SPCC plans at certain of its properties and believes
that it will be able to develop and implement these plans in the near future.
The Oil Pollution Act of 1990, ("OPA") contains numerous requirements relating
to the prevention of and response to oil spills into waters of the United
States. The OPA subjects owners of facilities to strict joint and several
liability for all containment and cleanup costs and certain other damages
arising from a spill, including, but not limited to, the costs of responding to
a release of oil to surface waters. The OPA also requires owners and operators
of offshore facilities that could be the source of an oil spill into federal or
state waters, including wetlands, to post a bond, letter of credit or other form
of financial assurance in amounts ranging from $10 million in specified state
waters to $35 million in federal outer continental shelf waters, subject to
later increase to as much as $150 million if a formal risk assessment indicates
that the increase is warranted, to cover costs that could be incurred by
governmental authorities in responding to an oil spill. Noncompliance with OPA
may result in varying civil and criminal penalties and liabilities. Operations
of the Company are also subject to the federal Clean Water Act ("CWA") and
analogous state laws. In accordance with the CWA, the state of Louisiana has
issued regulations prohibiting discharges of produced water in state coastal
waters effective July 1, 1997. The Company plans to drill a well in Louisiana
coastal waters. Assuming that production from the planned well is feasible, the
Company will be obligated to comply with these regulations. Pursuant to other
requirements of the CWA, the EPA has adopted regulations concerning discharges
of storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under an EPA
general permit. While certain of its properties may require permits for
discharges of storm water runoff, the Company believes that it will be able to
obtain, or be included under, such permits, where necessary, and make minor
modifications to existing facilities and operations that would not have a
material effect on the Company. Like OPA, the CWA and analogous state laws
relating to the control of water pollution provide varying civil and criminal
penalties and liabilities for releases of petroleum or its derivatives into
surface waters or into the ground.
CERCLA, also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources, and it is
not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.
The Company also is subject to a variety of federal, state and local
permitting and registration requirements relating to protection of the
environment. Management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse effect on
the Company.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosion, blow-out, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures and discharges of toxic gases, the occurrence
50
<PAGE> 53
of any of which could result in substantial losses to the Company due to 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 accordance with customary industry practice, the Company maintains
insurance against some, but not all, of the risks described above. The Company's
insurance does not cover business interruption 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.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties. As is customary in the industry
in the case of undeveloped properties, little investigation of record title is
made at the time of acquisition (other than a preliminary review of local
records). Investigations, including a title opinion of local counsel, are
generally made before commencement of drilling operations. The Company's
revolving credit facilities are secured by substantially all of its oil and
natural gas properties.
EMPLOYEES
At June 30, 1997, the Company had 16 full-time employees, including two
geoscientists and three engineers, and two part-time employees. As drilling and
production activities increase, the Company intends to hire additional
technical, operational and administrative personnel as appropriate. The Company
believes that its relationships with its employees are good. In order to
optimize prospect generation and development, the Company utilizes the services
of independent consultants and contractors to perform various professional
services, particularly in the areas of 3-D seismic data mapping, acquisition of
leases and lease options, construction, design, well site surveillance,
permitting and environmental assessment. Field and on-site production operation
services, such as pumping, maintenance, dispatching, inspection and testing, are
generally provided by independent contractors. The Company believes that this
use of third party service providers has enhanced its ability to contain general
and administrative expenses, which averaged $0.27 per Mcfe for the first quarter
of 1997.
LEGAL PROCEEDINGS
From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. The Company is not currently a party
to any litigation that it believes could have a material adverse effect on the
financial position of the Company.
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<PAGE> 54
MANAGEMENT
EXECUTIVE OFFICERS AND DIRECTORS
The following table sets forth certain information with respect to
executive officers and directors of the Company:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
S.P. Johnson IV................ 41 President, Chief Executive Officer and Director
Frank A. Wojtek................ 41 Chief Financial Officer, Vice President, Secretary,
Treasurer and Director
George F. Canjar............... 39 Vice President of Exploration Development
Kendall A. Trahan.............. 46 Vice President of Land
Steven A. Webster.............. 45 Chairman of the Board
Douglas A.P. Hamilton.......... 50 Director
Paul B. Loyd, Jr. ............. 51 Director
</TABLE>
Set forth below is a description of the backgrounds of each of the
executive officers and directors of the Company:
S.P. Johnson IV has served as the President, Chief Executive Officer and a
director of the Company since December 1993. Prior to that he worked 15 years
for Shell Oil Company. His managerial positions included Operations
Superintendent, Manager of Planning and Finance and Manager of Development
Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in
Mechanical Engineering from the University of Colorado.
Frank A. Wojtek has served as the Chief Financial Officer, Vice President,
Secretary, Treasurer and a director of the Company since 1993. In addition,
since 1992 Mr. Wojtek has been the Assistant to the Chairman of the Board of
Reading & Bates Corporation ("Reading & Bates") (an offshore drilling company).
Mr. Wojtek also holds the positions of Vice President and Secretary/Treasurer
for Loyd and Associates, Inc. (a private financial consulting and investment
banking firm). Following the Offering, Mr. Wojtek will serve full time as the
Company's Chief Financial Officer. Mr. Wojtek has held the positions of Vice
President and Chief Financial Officer of Griffin-Alexander Drilling Company from
1984 to 1987, Treasurer of Chiles-Alexander International Inc. from 1987 to 1989
and Vice President and Chief Financial Officer of India Offshore Inc. from 1989
to 1992, all of which are companies in the offshore drilling industry. Mr.
Wojtek is a Certified Public Accountant and holds a B.B.A. in Accounting from
the University of Texas.
George F. Canjar has been head of the Company's exploration activities
since joining the Company in July 1996 and was elected Vice President of
Exploration Development in June 1997. Prior thereto he worked for over 15 years
for Shell Oil Company and its overseas affiliates where he held various
technical and managerial positions, including Technical Manager-Geology &
Petrophysics, Section Head Geology & Seismology and Team Leader for numerous
integrated production, development, exploration and project execution groups.
Mr. Canjar is a Registered Petroleum Engineer, Registered Geologist and has a
B.S. in Geological Engineering from the Colorado School of Mines.
Kendall A. Trahan has been head of the Company's land activities since
joining the Company in March 1997 and was elected Vice President of Land of the
Company in June 1997. From 1994 to February 1997, he served as a Director of
Joint Ventures Onshore Gulf Coast for Vastar Resources, Inc. From 1982 to 1994,
he worked as an Area Landman and then a Division Landman and Director of
Business Development for Arco Oil & Gas Company. Prior to that, Mr. Trahan
served as a Staff Landman for Amerada Hess Corporation and as an independent
landman. He is a Certified Professional Landman and holds a B.S. degree from the
University of Southwestern Louisiana.
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<PAGE> 55
Steven A. Webster has been the Chairman of the Board of the Company since
June 1997 and has been a director of the Company since 1993. Mr. Webster has
been Chairman and Chief Executive Officer of Falcon Drilling Company Inc.
("Falcon"), an offshore drilling company, and its predecessor companies since
1988. Mr. Webster is also a director of DI Industries, Inc. (an onshore drilling
company) and Crown Resources Corporation (a precious metals mining company). He
is a trust manager of Camden Property Trust (a real estate investment trust).
Mr. Webster holds an M.B.A. degree from Harvard Business School.
Douglas A.P. Hamilton has been a director of the Company since 1993 and of
Falcon Drilling Company, Inc. since 1992. Mr. Hamilton has since 1979 been the
President of Anatar Investments, Inc., a diversified investment capital firm
with active investments in oil and gas and offshore contract drilling. Mr.
Hamilton has a degree from the University of North Carolina and completed the
PMD program at Harvard Business School.
Paul B. Loyd, Jr. has been a Director of the Company since 1993. Mr. Loyd
has been Chairman of the Board and Chief Executive Officer of Reading & Bates
since 1991 and President of Reading & Bates since 1993. Mr. Loyd has been
President of Loyd & Associates, Inc., a financial consulting firm, since 1989.
Mr. Loyd was Chief Executive Officer and a director of Chiles-Alexander
International, Inc. from 1987 to 1989, President and a director of
Griffin-Alexander Drilling Company, from 1984 to 1987, and prior to that, a
director and Chief Financial Officer of Houston Offshore International, all of
which are companies in the offshore drilling industry. Mr. Loyd is also a
director of Wainoco Oil Corporation. Mr. Loyd served as President of the Company
from its inception in September 1993 until December 1993. Mr. Loyd holds an
M.B.A. degree from Harvard Business School.
On July 10, 1997, Falcon and Reading & Bates announced that they had
entered into an agreement to merge the two companies, and that Mr. Loyd would be
the Chairman of the Board and Mr. Webster would be the President and Chief
Executive Officer of the combined company.
Officers are elected annually by the Board of Directors and serve at the
discretion of the Board. The Company's Board of Directors is currently composed
of five directors, two of whom are employees of the Company. All of the current
directors serve until the next annual shareholders' meeting or until their
successors have been duly elected and qualified. The Board of Directors will
have two standing committees: the Audit Committee (which will consist of Messrs.
Wojtek, Hamilton and Loyd) and the Compensation Committee (which will consist of
Messrs. Webster, Hamilton and Loyd).
DIRECTOR COMPENSATION
Directors who are employees of the Company are not entitled to receive
additional compensation for serving as directors. Following the Offering, each
director who is not an employee of the Company or a subsidiary (a "Non-employee
Director") will receive an annual retainer of $7,500. All directors will be
reimbursed for out-of-pocket expenses incurred in attending meetings of the
Board or Board committees and for other expenses incurred in their capacity as
directors. In addition, Nonemployee Directors will receive options for the
purchase of Common Stock pursuant to the Incentive Plan of the Company (the
"Incentive Plan"). See "-- Incentive Plan."
OFFICER AND DIRECTOR INDEMNIFICATION
The Company's Bylaws provide for the indemnification of its officers and
directors, and the advancement to them of expenses in connection with
proceedings and claims, to the fullest extent permitted by the Texas Business
Corporation Act. The Company has also entered into indemnification agreements
with each of its directors and certain of its officers that contractually
provide for indemnification and expense advancement and include related
provisions meant to facilitate the indemnitee's receipt of such benefits. In
addition, the Company expects to purchase directors' and officers' liability
insurance policies for its directors and officers in the future. The Bylaws and
such
53
<PAGE> 56
agreements with directors and officers provide for indemnification for amounts
(i) in respect of the deductibles for such insurance policies, (ii) that exceed
the liability limits of such insurance policies and (iii) that are available,
were available or which become available to the Company or which are generally
available to companies comparable to the Company but which the officers or
directors of the Company determine is inadvisable for the Company to purchase,
given the cost involved of the Company. Such indemnification may be made even
though directors and officers would not otherwise be entitled to indemnification
under other provisions of the Bylaws or such agreements.
EXECUTIVE COMPENSATION
The following table sets forth certain summary information concerning the
compensation provided by the Company to its President and Chief Executive
Officer during the year ended December 31, 1996 (the "Named Executive Officer").
No other executive officer of the Company received combined salary and bonus
from the Company that exceeded $100,000 during such year.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
ANNUAL
COMPENSATION(1)
--------------------
NAME AND PRINCIPAL POSITION SALARY BONUS
--------------------------- -------- --------
<S> <C> <C>
S. P. Johnson IV............................................ $180,000 --
President and Chief Executive Officer
</TABLE>
- ---------------
(1) The Named Executive Officer did not receive any annual compensation not
properly categorized as salary or bonus, except for certain perquisites and
other personal benefits which are not shown because the aggregate amount of
such compensation, if any, for the named executive officer during the fiscal
year did not exceed the lesser of $50,000 or 10% of total salary and bonus
reported for such executive officer.
No options were granted to the Named Executive Officer in 1996, and the
Named Executive Officer did not exercise any stock options during 1996. The
Company has no outstanding stock appreciation rights, shares of restricted stock
or long-term incentive plans. See "-- Incentive Plan" below for information
regarding the Incentive Plan, which the Company expects to adopt prior to
completion of the Offering.
EMPLOYMENT AGREEMENTS
The Company has entered into employment agreements with each of Mr. S. P.
Johnson IV and Mr. Frank A. Wojtek which provides for an annual base salary in
an amount not less than $180,000 in the case of Mr. Johnson and $150,000 in the
case of Mr. Wojtek (but Mr. Wojtek's salary will not begin until he commences
full time employment with the Company). Upon completion of this Offering, Mr.
Johnson and Mr. Wojtek will also each receive option grants, pursuant to the
Incentive Plan, to purchase 100,000 and 40,000 shares of Common Stock,
respectively, at the price to the public set forth on the cover page of this
Prospectus. See "-- Incentive Plan."
The Company and Mr. Kendall Trahan entered into a two-year employment
agreement in March 1997, pursuant to which Mr. Trahan served as the Company's
Vice President of Land at an annual salary of $135,000. The Company recently has
entered into a new employment agreement which provides for an annual base salary
in an amount not less than $135,000. The new agreement continues and revises a
previously granted stock option, such that he has the option to purchase up to
83,295 shares of the Company's Common Stock at an aggregate exercise price of
$300,000. These options vest according to a two-year vesting schedule.
The Company and Mr. George Canjar entered into a three-year employment
agreement in July 1996, pursuant to which Mr. Canjar served as the Company's
Manager of Exploration Development at an annual salary of $126,000. The Company
recently has entered into a new employment
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<PAGE> 57
agreement with Mr. Canjar which provides for an annual base salary in an amount
not less than $126,000. The agreement includes a provision that entitles Mr.
Canjar to an undivided 0.5% overriding royalty interest, proportionately reduced
to the Company's working interest, in all oil, gas and other minerals that may
be produced and saved from prospects generated by Mr. Canjar. The new agreement
continues and revises a previously granted stock option, such that he has the
option to purchase up to 138,825 shares of the Company's Common Stock at an
aggregate exercise price of $500,000. These options vest according to a two-year
vesting schedule.
Each of the employment agreements of Mr. Johnson, Mr. Wojtek, Mr. Trahan
and Mr. Canjar has an initial three-year term provided that at the end of the
second year of such initial term and on every day thereafter, the term of each
such employment agreement will automatically be extended for one day, such that
the remaining term of the agreement shall never be less than one year. Under
each agreement both the Company and the employee may terminate the employee's
employment at any time. Upon termination of employment on account of disability
or if employment is terminated by the Company for any reason (except under
certain limited circumstances defined as "for cause" in the agreement), or if
employment is terminated either (x) by the employee subsequent to a change of
control (as defined and including certain terminations prior to a change of
control if caused by a person involved in precipitating a change of control) or
(y) by reason of death during a sixty day period following the elapse of one
year after such a change of control ("window period") or with good reason (as
defined), under the agreement the employee will generally be entitled to (i) an
immediate lump sum cash payment equal to 150% (375% if termination occurs after
a change of control) of his annual base salary that would have been payable for
the remainder of the term of the applicable agreement discounted at 6%, (ii)
continued participation in all the Company's welfare benefit plans and continued
life insurance and medical benefits coverage and (iii) the immediate vesting of
any stock options or restricted stock previously granted to such employee and
outstanding as of the time immediately prior to the date of his termination, or
a cash payment in lieu thereof. If employment terminates due to death of the
employee and other than in a window period, the Company will pay a sum equal to
the amount of the employee's annual base salary for the remaining term of the
agreement, reduced by the amount payable under any life insurance policies to
the extent that such amounts are attributable to premiums paid by the Company.
The salaries in each of these agreements are subject to periodic review and
provide for increases consistent with increases in base salary generally awarded
to other executives of the Company. Each agreement entitles the employee to
participate in all of the Company's incentive, savings, retirement and welfare
benefit plans in which other executive officers of the Company participate. The
agreements each provide for an annual bonus in an amount comparable to the
annual bonus of other Company executives, taking into account the individual's
position and responsibilities.
INCENTIVE PLAN
Prior to the completion of the Offering, the Company expects to adopt the
Incentive Plan. The objectives of the Incentive Plan are to (i) attract and
retain the services of key employees, qualified independent directors and
qualified consultants and other independent contractors and (ii) encourage the
sense of proprietorship in and stimulate the active interest of those persons in
the development and financial success of the Company by making awards ("Awards")
designed to provide participants in the Incentive Plan with proprietary interest
in the growth and performance of the Company.
The Company plans to reserve 1,000,000 shares of Common Stock for use in
connection with the Incentive Plan. Persons eligible for Awards are (i)
employees holding positions of responsibility with the Company or any of its
subsidiaries and whose performance can have a significant effect on the success
of the Company, (ii) Nonemployee Directors and (iii) certain nonemployed
consultants and other independent contractors providing, or who will provide,
services to the Company or any of its subsidiaries.
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<PAGE> 58
The Compensation Committee of the Company's Board of Directors (the
"Committee") will administer the Incentive Plan. With respect to Awards to
employees and independent contractors, the Committee has the exclusive power to
administer the Incentive Plan, to take all actions specifically contemplated
thereby or necessary or appropriate in connection with the administration
thereof, to interpret the Incentive Plan and to adopt such rules, regulations
and guidelines for carrying out its purposes as the Committee may deem necessary
or proper in keeping with the objectives of such plan. With respect to Awards to
employees and independent contractors, the Committee may, in its discretion,
among other things, extend or accelerate the exercisability of, accelerate the
vesting of or eliminate or make less restrictive any restrictions contained in
any Award, waive any restriction or other provision of the Incentive Plan or in
any Award or otherwise amend or modify any Award in any manner that is either
(i) not adverse to that participant holding the Award or (ii) consented to by
that participant. The Committee also may delegate to the chief executive officer
and other senior officers of the Company its duties under the Incentive Plan.
The Board of Directors may amend, modify, suspend or terminate the
Incentive Plan for the purpose of addressing any changes in legal requirements
or for any other lawful purpose, except that (i) no amendment or alteration that
would adversely affect the rights of any participant under any Award previously
granted to such participant shall be made without the consent of such
participant and (ii) no amendment or alteration shall be effective prior to its
approval by the shareholders of the Company to the extent such approval is then
required pursuant to Rule 16b-3 in order to preserve the applicability of any
exemption provided by such rule to any Award then outstanding (unless the holder
of such Award consents) or to the extent shareholder approval is otherwise
required by applicable legal requirements. The Board of Directors may make
certain adjustments in the event of any subdivision, split or consolidation of
outstanding shares of Common Stock, any declaration of a stock dividend payable
in shares of Common Stock, any recapitalization or capital reorganization of the
Company, any consolidation or merger of the Company with another corporation or
entity, any adoption by the Company of any plan of exchange affecting the Common
Stock or any distribution to holders of Common Stock of securities or property
(other than normal cash dividends).
Awards to employees and independent contractors may be in the form of (i)
rights to purchase a specified number of shares of Common Stock at a specified
price ("Options"), (ii) rights to receive a payment, in cash or Common Stock,
equal to the fair market value or other specified value of a number of shares of
Common Stock on the rights exercise date over a specified strike price, (iii)
grants of restricted or unrestricted Common Stock or units denominated in Common
Stock, (iv) grants denominated in cash and (v) grants denominated in cash,
Common Stock, units denominated in Common Stock or any other property which are
made subject to the attainment of one or more performance goals ("Performance
Awards"). An Option may be either an incentive stock option ("ISO") that
qualifies, or a nonqualified stock option ("NSO") that does not qualify, with
the requirements of Section 422 of the Code; provided, that independent
contractors cannot be awarded ISOs. The Committee will determine the employees
and independent contractors to receive Awards and the terms, conditions and
limitations applicable to each such Award, which conditions may, but need not,
include continuous service with the Company, achievement of specific business
objectives, attainment of specified growth rates, increases in specified indices
or other comparable measures of performance. Performance Awards may include more
than one performance goal, and a performance goal may be based on one or more
business criteria applicable to the grantee, the Company as a whole or one or
more of the Company's business units and may include any of the following:
increased revenue, net income, stock price, market share, earnings per share,
return on equity or assets or decrease in costs.
On the date the Offering closes, Options under the Incentive Plan will be
granted to approximately 10 employees of the Company to purchase a total of
approximately 220,000 shares of Common Stock at an exercise price per share
equal to the initial public offering price per share set forth on the cover page
of this Prospectus. These awards include options to be granted to
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<PAGE> 59
Messrs. Johnson and Wojtek to purchase 100,000 and 40,000 shares of Common
Stock, respectively. All such options will have a term of ten years and become
exercisable in cumulative annual increments of one-third of the total number of
shares of Common Stock subject thereto, beginning on the first anniversary of
the date of grant.
On the date the Offering closes, each of the current Nonemployee Directors,
Messrs. Webster, Hamilton and Loyd, automatically will be granted NSOs to
purchase 10,000 shares of Common Stock. In addition, on the first business day
following the date on which each annual meeting of the Company's shareholders is
held, each Nonemployee Director then serving will automatically be granted NSOs
to purchase 2,500 shares of Common Stock. Any person who first becomes a
Nonemployee Director on or after the date the Offering closes automatically will
be granted, on the date of his or her election, NSOs to purchase 10,000 shares
of Common Stock. Each NSO granted to Nonemployee Directors will (i) have a
ten-year term, (ii) have an exercise price per share equal to the fair market
value of a Common Stock share on the date of grant (the initial public offering
price in the case of NSOs granted on the closing of the Offering) and (iii)
become exercisable in cumulative annual increments of one-third of the total
number of shares of Common Stock subject thereto, beginning on the first
anniversary of the date of grant. If a Nonemployee Director resigns from the
Board without the consent of a majority of the other directors, such director's
NSOs may be exercised only to the extent they were exercisable on the
resignation date.
The foregoing description summarizes the principal terms and conditions of
the Incentive Plan, does not purport to be complete and is qualified in its
entirety by reference to the Incentive Plan, a copy of which has been filed as
an exhibit to the Registration Statement of which this Prospectus is a part.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
In June 1997, the Company established a Compensation Committee. In the
past, matters with respect to the compensation of executive officers of the
Company were determined by the nonemployee members of the Board of Directors, as
a whole.
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CERTAIN TRANSACTIONS
THE COMBINATION TRANSACTIONS
The Company currently conducts its operations through a number of
affiliated entities that will be combined in the Combination Transactions.
Carrizo conducts oil and natural gas operations directly, with industry partners
and through certain affiliated partnerships as described below. Prior to
completion of the Offering, the shareholders of the Company are Steven A.
Webster, S.P. Johnson IV, Frank A. Wojtek, Douglas A.P. Hamilton and Paul B.
Loyd, Jr. (the "Founders"), each of whom is an officer and/or a director of the
Company, Cerrito Partners, a partnership of which Mr. Webster is a general
partner, and DAPHAM Partnership L.P., the limited partner of which is a
charitable remainder trust of which the beneficiaries include Mr. Hamilton and
his wife and children. Carrizo Production, Inc. is a corporation that is owned
by the Founders. The officers and directors of Carrizo Production, Inc. also
serve in the same capacity for Carrizo. Carrizo Production, Inc. is the general
partner of and holds a 1.42% before payout/28.82% after payout interest in
Encinitas Partners Ltd. The remaining partnership interests in Encinitas
Partners Ltd. are held by limited partners, including the Founders. Carrizo
holds a 50% general partner interest in La Rosa Partners Ltd. The remaining 50%
interest in La Rosa Partners Ltd. is held by the Founders (other than Mr.
Wojtek) as limited partners. Carrizo is the general partner and holds a 13.33%
before payout/31.67% after payout interest in Carrizo Partners Ltd.; the
remaining partnership interests in Carrizo Partners Ltd. are held by limited
partner investors that include S.P. Johnson IV who as a special limited partner
is entitled to a 0.001% prepayout and 25% after payout interest. Carrizo owns a
50% general partner interest in Placedo Partners Ltd., and Carrizo Partners Ltd.
holds the remaining 50% limited partner interest in Placedo Partners Ltd.
Encinitas Partners Ltd. owns the Company's interest in the Encinitas/Kelsey
Project, the Midway Project and the East McFaddin Project. Carrizo Partners Ltd.
owns the Company's interest in the Camp Hill Project as well as a 50% interest
in Placedo Partners Ltd. La Rosa Partners Ltd. owns the Company's interest in
the La Rosa Project. Placedo Partners Ltd. owns an interest in the Placedo
Project (which includes two producing leases in Victoria County, Texas and for
which the Company has budgeted for the drilling of one well in 1998). Carrizo
Production, Inc. owns the general partner interest in Encinitas Partners Ltd.
All of the Company's other assets are owned by Carrizo Oil & Gas, Inc. The
operations of all of these entities have been managed through the same
management team.
The Combination Transactions will include the following: (i) Carrizo
Production, Inc. will be merged into Carrizo (the "Carrizo Production Merger"),
and the outstanding shares of capital stock of Carrizo Production, Inc. will be
converted into an aggregate of 343,000 shares of Common Stock; (ii) Carrizo will
acquire Encinitas Partners Ltd. in two steps: (a) Carrizo will acquire the
Founder's limited partner interests in Encinitas Partners Ltd. for an aggregate
consideration of 468,533 shares of Common Stock (the "Founder's Purchase
Transaction") and (b) Encinitas Partners Ltd. will be merged into Carrizo (the
"Encinitas Merger"), and the outstanding partnership interests in Encinitas
Partners Ltd. will be converted into an aggregate of 860,699 shares of Common
Stock; (iii) La Rosa Partners Ltd. will be merged into Carrizo (the "La Rosa
Merger"), and the outstanding partnership interests in La Rosa Partners Ltd.
will be converted into an aggregate of 48,700 shares of Common Stock; and (iv)
Carrizo Partners Ltd. will be merged into Carrizo (the "Carrizo Partners
Merger"), and the outstanding partnership interests in Carrizo Partners Ltd.
will be converted into an aggregate of 569,068 shares of Common Stock. As a
result of the Carrizo Partners Merger, Carrizo will own all of the partnership
interests in Placedo Partners Ltd. Each of the Combination Transactions will
close concurrently with the closing of the Offering. The determination of the
number of shares of Common Stock that would be issued to the various parties in
the Combination Transactions was made by management of the Company based upon
the following four valuation criteria for the assets attributable to each party:
(i) PV-10 Values of proved reserves; (ii) estimates of discounted net asset
values that gave effect to all assets (rather than proved reserves only) for all
of management's then proposed projects; (iii) projected 1997 cash flows; and
(iv) projected 1998 cash flows.
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An aggregate of 2,290,000 shares of Common Stock will be issued in
connection with the Combination Transactions. Mr. Webster will receive 77,175
shares of Common Stock in the Carrizo Production Merger, 132,721 shares of
Common Stock in the Founder's Purchase Transaction and 14,610 shares of Common
Stock in the La Rosa Merger, and Cerrito Partners, of which Mr. Webster is a
general partner, will receive 31,126 shares of Common Stock in the Encinitas
Merger. Mr. Johnson will receive 34,300 shares of Common Stock in the Carrizo
Production Merger, 46,075 shares of Common Stock in the Founder's Purchase
Transaction, 4,870 shares of Common Stock in the La Rosa Merger and 176,841
shares of Common Stock in the Carrizo Partners Merger. Mr. Wojtek will receive
77,175 shares of Common Stock in the Carrizo Production Merger and 24,296 shares
of Common Stock in the Founder's Purchase Transaction. Mr. Hamilton will receive
77,175 shares of Common Stock in the Carrizo Production Merger, 132,721 shares
of Common Stock in the Founder's Purchase Transaction and 14,610 shares of
Common Stock in the La Rosa Merger. Mr. Loyd will receive 77,175 shares of
Common Stock in the Carrizo Production Merger, 132,721 shares of Common Stock in
the Founder's Purchase Transaction and 14,610 shares of Common Stock in the La
Rosa Merger.
MASTER TECHNICAL SERVICES AGREEMENT
In August 1996, the Company entered into the Master Technical Services
Agreement (the "MTS Agreement") with Reading & Bates Development Co. ("R&B
Development"), which is a subsidiary of Reading & Bates. Paul B. Loyd, Jr., a
director of the Company, is the Chairman of the Board, Chief Executive Officer
and President and a director of Reading & Bates. Under the MTS Agreement, the
Company provides certain engineering and technical services to R&B Development
in connection with R&B Development's technical service, procurement and
construction projects in offshore drilling and floating production, and the
Company is paid an amount generally equal to the salaries of its personnel that
provide such services, pro rata based on the amount of time that is spent
providing such services. The Company was paid $117,726 for services provided
during 1996 under the MTS Agreement, has continued to perform services under the
contract in 1997 and expects to continue to perform services under the contract
following the Offering. The MTS Agreement may generally be terminated by either
party upon five days prior written notice to the other party.
AMOUNTS OWED BY THE COMPANY TO CERTAIN OFFICERS AND DIRECTORS
Between December 1993 and December 1996, Carrizo issued promissory notes to
certain officers and directors of the Company, in consideration of funds
advanced to Carrizo by such officers and directors to assist Carrizo in its
operations. Each of such promissory notes is payable at the earlier of (i) April
or July 1998 or (ii) the closing of the Offering and bears interest equal to the
Texas Commerce Bank, N.A. prime rate. The outstanding aggregate balance,
including accrued interest, of the notes payable to Paul B. Loyd, Jr. was, as of
December 31, 1994, 1995 and 1996, respectively, $67,000, $371,000 and $776,000.
The outstanding aggregate balance, including accrued interest, of the notes
payable to Steven A. Webster was, as of December 31, 1994, 1995 and 1996,
respectively, $63,000, $370,000 and $772,000. The outstanding aggregate balance,
including accrued interest, of the notes payable to Frank A. Wojtek was, as of
December 31, 1994, 1995 and 1996, respectively, $67,000, $345,000 and $711,000.
The outstanding aggregate balance, including accrued interest, of the notes
payable to Douglas A.P. Hamilton was, as of December 31, 1994, 1995 and 1996,
respectively, $73,000, $371,000 and $775,000. The outstanding aggregate balance,
including accrued interest, of the notes payable to S.P. Johnson IV was, as of
December 31, 1994 and 1995, respectively, $27,000 and $15,000. The Company
borrowed $1.8 million from Douglas A. P. Hamilton on May 31, 1997. The Company
used the proceeds of this loan to make principal repayment on such promissory
notes in the amount of $600,000 to each of Messrs. Loyd and Wojtek on May 31,
1997 and to Mr. Webster on June 3, 1997. As of June 30, 1997, the total
principal owed on such promissory notes was $116,000 to Paul B. Loyd, Jr.;
$116,000 to Steven A. Webster; $59,000 to Frank A. Wojtek and $2,516,000 to
Douglas A.P. Hamilton. As of June 30, 1997,
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the remaining amounts due on such promissory notes, including accrued interest,
are as follows: $201,000 to Paul B. Loyd, Jr.; $198,000 to Steven A. Webster;
$134,000 to Frank A. Wojtek and $2,618,000 to Douglas A.P. Hamilton.
In addition, between February 1997 and March 1997, La Rosa Partners, Ltd.
issued promissory notes in favor of certain officers and directors of the
Company, in consideration of funds advanced to La Rosa Partners, Ltd. by such
officers and directors to assist La Rosa Partners, Ltd. in its operations. Each
of such promissory notes is payable on demand and bears interest equal to the
TCB prime rate. As of June 30, 1997, the total principal owed on such promissory
notes is $30,000 to Paul B. Loyd, Jr.; $30,000 to Steven A. Webster; $15,000 to
Frank A. Wojtek and $30,000 to Douglas A. P. Hamilton. As of June 30, 1997, the
remaining amounts due on such promissory notes, including accrued interest, are
as follows: $31,000 to Paul B. Loyd, Jr.; $31,000 to Steven A. Webster; $15,000
to Frank A. Wojtek and $31,000 to Douglas A.P. Hamilton.
The Company intends to repay Carrizo's and La Rosa Partners Ltd.'s
indebtedness to such officers and directors of the Company evidenced by the
above-referenced promissory notes from the proceeds of the Offering. The Company
does not intend to incur any further indebtedness to, or make any loans to, any
of its executive officers, directors or other affiliates following the
completion of the Offering.
FINANCIAL/ACCOUNTING SERVICES AGREEMENT
In March 1994, the Company entered into the Financial/Accounting Services
Agreement (the "Services Agreement"), effective as of December 1, 1993, with
Loyd & Associates, Inc. ("Loyd & Associates"), a private financial consulting
and investment banking firm. Paul B. Loyd, Jr. serves as President and owns
92.5% of the stock of Loyd & Associates, and Frank A. Wojtek serves as Vice
President and Secretary/Treasurer and owns 7.5% of the stock of Loyd &
Associates. Under the Services Agreement, Loyd & Associates provides, on an
as-needed basis and at market rates, financial consulting, accounting and
administrative services to the Company, Carrizo Partners Ltd. and Placedo
Partners Ltd. The Services Agreement also provides for reimbursement to Loyd &
Associates of certain expenses. Total payments for services rendered were
$43,500 in 1994, $60,000 in 1995 and $60,000 in 1996. The Services Agreement
will terminate at the closing of the Offering. In addition to serving as Vice
President and Secretary/Treasurer of Loyd & Associates, Mr. Wojtek serves as
Assistant to the Chairman of the Board of Reading & Bates. Following the
Offering, Mr. Wojtek will serve full time as the Company's Chief Financial
Officer, Vice President and Secretary.
AGREEMENTS WITH THE COMPANY'S CURRENT SHAREHOLDERS
From the date of its formation until shortly prior to the closing of the
Offering, Carrizo Production, Inc. will be, and from the date of its formation
until May 16, 1997 Carrizo was, an S corporation for federal income tax
purposes. The Company has entered into tax indemnification agreements with the
Founders that provide for, among other things, the indemnification of the
Founders for any losses or liabilities with respect to any additional taxes
(including interest, penalties and legal fees) resulting from Carrizo's and
Carrizo Production, Inc.'s operations during the period in which each was an S
Corporation. The Company also has entered into a registration rights agreement
with certain of the current shareholders of the Company as described under
"Shares Eligible for Future Sale."
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information with respect to beneficial
ownership of the Common Stock both after giving effect to the Combination
Transactions but before giving effect to the Offering and after giving effect to
the Combination Transactions and the Offering by: (i) all persons who will be
the beneficial owner of 5% or more of the outstanding Common Stock; (ii) each
director; (iii) each executive officer of the Company; and (iv) all officers and
directors of the Company as a group, assuming in each case, the issuance of an
aggregate of 2,290,000 shares of Common Stock to all parties to the Combination
Transactions.
<TABLE>
<CAPTION>
COMMON
STOCK
BENEFICIALLY PERCENT OF COMMON
OWNED STOCK BENEFICIALLY
FOLLOWING THE OWNED FOLLOWING THE
COMBINATION COMBINATION
TRANSACTIONS TRANSACTIONS
------------- ---------------------
PRIOR TO
NUMBER OF THE AFTER THE
NAME(1) SHARES OFFERING OFFERING
------- ------------- -------- ---------
<S> <C> <C> <C>
S.P. Johnson IV(2)......................................... 783,085 10.4% 7.8%
Frank A. Wojtek(3)......................................... 1,273,721 17.0% 12.7%
George Canjar(4)........................................... 83,295 1.1% *
Ken Trahan(5).............................................. 33,318 * *
Steven A. Webster(6)....................................... 1,427,882 19.0% 14.3%
Douglas A.P. Hamilton(7)................................... 1,000,796 13.3% 10.0%
Paul B. Loyd, Jr.(8)....................................... 1,396,756 18.6% 14.0%
All directors and executive officers as a group (7
persons)(9).............................................. 5,998,853 78.8% 59.3%
Kenneth Huff(10)........................................... 441,695 5.9% 4.4%
</TABLE>
- ---------------
* Less than one percent.
(1) Except as otherwise noted and pursuant to applicable community property
laws, each shareholder has sole voting and investment power with respect to
the shares beneficially owned. The business address of each director and
executive officer is c/o Carrizo Oil & Gas, Inc., 14811 St. Mary's Lane,
Suite 148, Houston, Texas 77079.
(2) Shares shown represent (i) 521,000 shares of Common Stock currently owned,
(ii) 34,300 shares of Common Stock to be acquired through the Carrizo
Production Merger, (iii) 46,075 shares of Common Stock to be acquired
through the Founder's Purchase Transaction, (iv) 4,870 shares of Common
Stock to be acquired through the La Rosa Merger and (v) 176,840 shares of
Common Stock to be acquired through the Carrizo Partners Merger.
(3) Shares shown represent (i) 1,172,250 shares of Common Stock currently
owned, (ii) 77,175 shares of Common Stock to be acquired through the
Carrizo Production Merger and (iii) 24,296 shares of Common Stock to be
acquired through the Founder's Purchase Transaction.
(4) Shares shown represent 83,295 shares of Common Stock to be acquired
pursuant to stock options that are immediately exercisable or exercisable
within 60 days of the date of this Prospectus.
(5) Shares shown represent 33,318 shares of Common Stock to be acquired
pursuant to stock options that are immediately exercisable or exercisable
within 60 days of the date of this Prospectus.
(6) Shares shown represent (i) 1,146,510 shares of Common Stock currently owned
by Mr. Webster and 25,740 shares of Common Stock currently owned by Cerrito
Partners, of which Mr. Webster is a general partner and shares voting and
dispositive power with the other general partners, (ii) 77,175 shares of
Common Stock to be acquired through the Carrizo
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Production Merger, (iii) 132,721 shares of Common Stock to be acquired
through the Founder's Purchase Transaction by Mr. Webster and 31,126 shares
of Common Stock to be acquired through the Encinitas Merger by Cerrito
Partners and (iv) 14,610 shares of Common Stock to be acquired through the
La Rosa Merger. Mr. Webster may be deemed a beneficial owner of the shares
of Common Stock currently owned by Cerrito Partners and the shares of
Common Stock to be acquired through the Encinitas Merger by Cerrito
Partners. Mr. Webster disclaims such beneficial ownership.
(7) Shares shown represent (i) 776,290 shares of Common Stock currently owned
by Mr. Hamilton, (ii) 77,175 shares of Common Stock to be acquired through
the Carrizo Production Merger, (iii) 132,721 shares of Common Stock to be
acquired through the Founder's Purchase Transaction and (iv) 14,610 shares
of Common Stock to be acquired through the La Rosa Merger.
(8) Shares shown represent (i) 1,172,250 shares of Common Stock currently
owned, (ii) 77,175 shares of Common Stock to be acquired through the
Carrizo Production Merger, (iii) 132,721 shares of Common Stock to be
acquired through the Founder's Purchase Transaction and (iv) 14,610 shares
of Common Stock to be acquired through the La Rosa Merger.
(9) Shares shown include 116,613 shares of Common Stock to be acquired pursuant
to stock options that are immediately exercisable or exercisable within 60
days of the date of this Prospectus.
(10) Shares shown represent (i) 395,960 shares of Common Stock currently owned
by DAPHAM Partnership L.P., of which the general partner is Mr. Huff and
the limited partner is a charitable remainder trust, of which Mr. Hamilton
and his wife and children are among the beneficiaries, (ii) 15,564 shares
of Common Stock to be acquired through the Encinitas Merger and (iii)
30,171 shares of Common Stock to be acquired through the Carrizo Partners
Merger. The business address of Mr. Huff is 9256 N. Pelham Parkway,
Milwaukee, Wisconsin 53217.
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DESCRIPTION OF CAPITAL STOCK
The Company's authorized capital stock consists of 40,000,000 shares of
Common Stock and 10,000,000 shares of Preferred Stock. Following consummation of
the Offering and the Combination Transactions, there will be approximately
10,000,000 shares of Common Stock outstanding (assuming the over-allotment
option is not exercised and the issuance of approximately 2,290,000 shares of
Common Stock in the Combination Transactions), and no shares of Preferred Stock
will be outstanding.
The following description of certain provisions of the Company's Amended
and Restated Articles of Incorporation (the "Articles of Incorporation") and the
Company's Amended and Restated Bylaws (the "Bylaws") are necessarily general and
do not purport to be complete and are qualified in their entirety by reference
to the Articles of Incorporation and Bylaws, which are included as exhibits to
the Registration Statement of which this Prospectus is a part. The Company was
organized in September 1993 and is a Texas corporation.
COMMON STOCK
Holders of Common Stock are entitled to one vote per share with respect to
all matters required by law to be submitted to shareholders of the Company.
Holders of Common Stock have no preemptive rights to purchase or subscribe for
securities of the Company, and the Common Stock is not convertible or subject to
redemption by the Company.
Subject to the rights of the holders of any class of capital stock of the
Company having any preference or priority over the Common Stock, none of which
will be outstanding upon completion of the Offering, the holders of the Common
Stock are entitled to dividends in such amounts as may be declared by the Board
of Directors of the Company from time to time out of funds legally available for
such payments and, in the event of liquidation, dissolution or winding up of the
Company, to share ratably in any assets of the Company remaining after payment
in full of all creditors and provisions for any liquidation preferences on any
outstanding stock ranking prior to the Common Stock.
American Securities Transfer & Trust, Inc. is the registrar and transfer
agent for the Common Stock.
PREFERRED STOCK
The Board of Directors, without further action by the shareholders, is
authorized to issue up to 10 million shares of Preferred Stock in one or more
series and to fix and determine as to any series all the relative rights and
preferences of shares in such series, including, without limitation,
preferences, limitations or relative rights with respect to such series. The
Company has no present intention to issue any Preferred Stock, but may determine
to do so in the future.
The issuance of shares of Preferred Stock, or the issuance of rights to
purchase such shares, could adversely affect the voting power of the Common
Stock, discourage an unsolicited acquisition proposal or make it more difficult
for a third party to gain control of the Company. For instance, the issuance of
a series of Preferred Stock might impede a business combination by including
class voting rights that would enable the holder to block such a transaction, or
facilitate a business combination by including voting rights that would provide
a required percentage vote of the shareholders. In addition, under certain
circumstances, the issuance of Preferred Stock could adversely affect the voting
power of the holders of the Common Stock. Although the Board of Directors is
required to make any determination to issue such stock based on its judgment as
to the best interests of the shareholders of the Company, the Board of Directors
could act in a manner that would discourage an acquisition attempt or other
transaction that some, or a majority, of the shareholders might believe to be in
their best interests or in which shareholders might receive a premium for their
stock over the then market price of such stock. The Board of Directors does not
at
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present intend to seek shareholder approval prior to any issuance of currently
authorized stock, unless otherwise required by law or the rules of the Nasdaq
National Market.
SPECIAL MEETINGS
Special Meetings of the shareholders of the Company may be called by the
chairman of the board, the president, the Board of Directors or by shareholders
holding not less than 50% of the outstanding voting stock of the Company.
VOTING
Holders of Common Stock are entitled to cast one vote per share on matters
submitted to a vote of shareholders and do not have cumulative voting rights.
Each director will be elected annually. Because the Common Stock does not have
cumulative voting rights, the holders of more than 50% of the shares may, if
they choose to do so, elect all of the directors and, in that event, the holders
of the remaining shares will not be able to elect any directors. See "Risk
Factors -- Control by Principal Shareholders."
Subject to any additional voting rights that may be granted to holders of
future classes or series of stock, the Company's Articles of Incorporation
and/or Texas law requires the affirmative vote of holders of 66 2/3% of the
outstanding shares entitled to vote thereon to approve any merger, consolidation
or share exchange, any disposition of the assets of the Company or any
dissolution of the Company and requires the affirmative vote of holders of a
majority of the outstanding shares entitled to vote thereon to approve any
amendment to the Articles of Incorporation or any other matter for which a
shareholder vote is required by the Texas Business Corporation Act. If any class
or series of shares is entitled to vote as a class with regard to the
above-described events, the vote required will be the affirmative vote of the
holders of a majority of the outstanding shares within each class or series of
shares entitled to vote thereon as a class and at least a majority of the
outstanding shares of capital stock otherwise entitled to vote thereon.
Approval of any other matter not described above that is submitted to the
shareholders requires the affirmative vote of the holders of a majority of the
shares of Common Stock entitled to vote on, and that voted for or against or
expressly abstained with respect to, that matter at a meeting at which a quorum
is present. The holders of a majority of the shares entitled to vote will
constitute a quorum at meetings of shareholders.
The Company's Bylaws provide that shareholders who wish to nominate
directors or to bring business before a shareholders' meeting must notify the
Company and provide certain pertinent information at least 80 days before the
meeting date (or within ten days after public announcement pursuant to the
Bylaws of the meeting date, if the meeting date has not been publicly announced
at least 90 days in advance).
The Company's Articles of Incorporation and Bylaws provide that following
the Offering no director may be removed from office, except for cause and upon
the affirmative vote of the holders of a majority of the outstanding shares of
all capital stock of the Company entitled to vote generally in the election of
the Company's directors. The following constitute "cause": (i) such director has
been convicted, or is granted immunity to testify where another has been
convicted, of a felony; (ii) such director has been found to be grossly
negligent or guilty of willful misconduct in the performance of duties to the
Company by a court or by the affirmative vote of a majority of all other
directors; (iii) such director is adjudicated mentally incompetent; or (iv) such
director has been found by a court or by the affirmative vote of a majority of
all other directors to have breached his duty of loyalty to the Company or its
shareholders or to have engaged in a transaction with the Company from which
such director derived an improper personal benefit.
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BUSINESS COMBINATION LAW
The Company will be subject to Part Thirteen (the "Business Combination
Law") of the Texas Business Corporation Act, which takes effect September 1,
1997. In general, the Business Combination Law prevents an "affiliated
shareholder" (defined generally as a person that is or was within the preceding
three-year period the beneficial owner of 20% or more of a corporation's
outstanding voting shares) or its affiliates or associates from entering into or
engaging in a "business combination" (defined generally to include (i) mergers
or share exchanges, (ii) dispositions of assets having an aggregate value equal
to 10% or more of the market value of the assets or of the outstanding common
stock or representing 10% or more of the earning power or net income of the
corporation, (iii) certain issuances or transactions by the corporation that
would increase the affiliated shareholder's number of shares of the corporation,
(iv) certain liquidations or dissolutions, and (v) the receipt of tax,
guarantee, loan or other financial benefits by an affiliated shareholder other
than proportionately as a shareholder of the corporation) with an "issuing
public corporation" (defined generally as a Texas corporation with 100 or more
shareholders, any voting shares registered under the Securities Exchange Act of
1934 or any voting shares qualified for trading in a national market system)
during the three-year period immediately following the affiliated shareholder's
acquisition of shares unless (a) before the date such person became an
affiliated shareholder, the board of directors of the issuing public corporation
approves the business combination or the acquisition of shares made by the
affiliated shareholder on such date or (b) not less than six months after the
date such person became an affiliated shareholder, the business combination is
approved by the affirmative vote of holders of at least two-thirds of the
issuing public corporation's outstanding voting shares not beneficially owned by
the affiliated shareholder or its affiliates or associates. The Business
Combination Law does not apply to a business combination of an issuing public
corporation that elects not be governed thereby through either its original
articles of incorporation or bylaws or by an amendment thereof. The Company's
original articles and bylaws do not so provide, nor does the Company currently
intend to make any such amendments. As a result of the approval of the Board of
Directors of the acquisition of shares by the current shareholders of the
Company, none of Steven A. Webster, Douglas A. P. Hamilton, Paul B. Loyd, Jr. or
Frank A. Wojtek (those shareholders of the Company owning 20% or more of the
outstanding voting shares prior to the Combination Transactions and the
Offering) will be subject to the restrictions imposed on affiliated shareholders
by the Business Combination Law.
LIMITATION OF DIRECTOR LIABILITY AND INDEMNIFICATION ARRANGEMENTS
The Articles of Incorporation of the Company contain a provision that
limits the liability of the Company's directors as permitted by the Texas
Business Corporation Act. The provision eliminates the personal liability of a
director to the Company and its shareholders for monetary damages for an act or
omission in the director's capacity as a director. The provision does not change
the liability of a director for breach of his duty of loyalty to the Company or
to shareholders, acts or omissions not in good faith that involve intentional
misconduct or a knowing violation of law, an act or omission for which the
liability of a director is expressly provided for by an applicable statute, or
in respect of any transaction from which a director received an improper
personal benefit. Pursuant to the Articles of Incorporation, the liability of
directors will be further limited or eliminated without action by shareholders
if Texas law is amended to further limit or eliminate the personal liability of
directors.
The Company's Bylaws provide for the indemnification of its officers and
directors, and the advancement to them of expenses in connection with
proceedings and claims, to the fullest extent permitted by the Texas Business
Corporation Act. The Company has also entered into indemnification agreements
with each of its directors and certain of its officers that contractually
provide for indemnification and expense advancement and include related
provisions meant to facilitate the indemnitee's receipt of such benefits. In
addition, the Company may purchase directors' and officers' liability insurance
policies for its directors and officers in the future. The Bylaws and such
agreements with directors and officers provide for indemnification for amounts
(i) in respect of the
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deductibles for such insurance policies, (ii) that exceed the liability limits
of such insurance policies and (iii) that are available, were available or
become available to the Company or are generally available to companies
comparable to the Company but which the officers or directors of the Company
determine is inadvisable for the Company to purchase, given the cost involved of
the Company. Such indemnification may be made even though directors and officers
would not otherwise be entitled to indemnification under other provisions of the
Bylaws or such agreements.
SHARES ELIGIBLE FOR FUTURE SALE
Upon consummation of the Combination Transactions and the Offering,
approximately 10,000,000 shares of Common Stock will be outstanding. The shares
of Common Stock sold in the Offering will be registered under the Securities Act
and will be freely tradeable without restriction or further registration under
the Securities Act, except for certain manner of sale, volume limitations and
other restrictions with respect to any shares purchased in the Offering by an
affiliate of the Company (a "Company Affiliate"), which will be subject to the
resale limitations of Rule 144 (not including the holding period requirement)
under the Securities Act. Under Rule 144 under the Securities Act, a person is
an affiliate of an entity if such person directly or indirectly controls or is
controlled by or is under common control with such entity and may include
certain officers and directors, principal shareholders and certain other
shareholders with special relationships. All of the remaining 7,500,000 shares
that will be outstanding following the Offering will constitute "restricted
securities" within the meaning of Rule 144. Such shares may not be resold in a
public distribution except pursuant to an effective registration statement under
the Securities Act or an applicable exemption from registration, including
pursuant to Rule 144. This Prospectus may not be used in connection with any
resale of shares of Common Stock acquired in the Offering by Company Affiliates
or in the Combination Transactions.
In general, under Rule 144 as currently in effect, if a minimum of one year
has elapsed since the later of the date of acquisition of the restricted
securities from the issuer or from an affiliate of the issuer, a person (or
persons whose shares of Common Stock are aggregated), including persons who may
be deemed "affiliates" of the Company, would be entitled to sell within any
three-month period a number of shares of Common Stock that does not exceed the
greater of (i) 1% of the then-outstanding shares of Common Stock (i.e.,
approximately 100,000 shares immediately after consummation of the Offering) and
(ii) the average weekly trading volume during the four calendar weeks preceding
the date on which notice of the sale is filed with the Commission. Sales under
Rule 144 are also subject to certain provisions as to the manner of sale (which
provision is proposed to be eliminated), notice requirements and the
availability of current public information about the Company. In addition, under
Rule 144(k), if a period of at least two years has elapsed since the later of
the date restricted securities were acquired from the Company or the date they
were acquired from an affiliate of the Company, a shareholder who is not an
affiliate of the Company at the time of sale and who has not been an affiliate
for at least three months prior to the sale would be entitled to sell shares of
Common Stock in the public market immediately without compliance with the
foregoing requirements under Rule 144. Rule 144 does not require the same person
to have held the securities for the applicable periods. The foregoing summary of
Rule 144 is not intended to be a complete description thereof.
The Company currently has outstanding options to purchase 222,120 shares of
Common Stock (99,954 of which are vested) and will grant options to purchase
250,000 shares (none of which will be vested) as of the closing of the Offering
under the Incentive Plan. Such shares for which the vested portion of
outstanding options may be exercised may generally be sold in reliance on the
resale provisions of Rule 701. In general, any employee or consultant to the
Company who purchased shares pursuant to a written compensatory plan or contract
entered into prior to the Company's initial public offering is entitled to rely
on the resale provisions of Rule 701, which permit non-affiliates to sell their
Rule 701 shares without having to comply with the public information, holding
period, volume limitation or notice provisions of Rule 144, and permit
affiliates to sell their
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Rule 701 shares without having to comply with the Rule 144 holding period
restrictions, in each case commencing 90 days after the date of this Prospectus.
The holders of vested outstanding options to purchase 99,954 shares could
exercise these options and could then sell such shares in compliance with Rule
701. Holders of all options granted prior to the Offering have agreed not to
sell the shares of Common Stock for a period of 180 days following the date of
the final prospectus for the Offering.
The Company intends to file a registration statement on Form S-8 under the
Securities Act to register the shares of Common Stock reserved or to be
available for issuance pursuant to the Long-Term Incentive Plan. Shares of
Common Stock issued pursuant to such plan generally will be available for sale
in the open market by holders who are not Company Affiliates and, subject to the
volume and other limitations of Rule 144, by holders who are Company Affiliates.
The Company, its executive officers, its directors and its current
shareholders have agreed not to offer for sale, sell, or otherwise dispose of
any shares of Common Stock or any securities convertible into or exercisable or
exchangeable for shares of Common Stock for a period of 180 days after the date
of this Prospectus, without the prior written consent of the representatives of
the Underwriters, subject to certain exceptions. See "Underwriting."
Prior to the Offering, there has been no public market for the Common
Stock, and no prediction can be made of the effect, if any, that sales of Common
Stock or the availability of shares for sale will have on the market price
prevailing from time to time. Following the Offering, sales of substantial
amounts of Common Stock in the public market or otherwise, or the perception
that such sales could occur, could adversely affect the prevailing market price
for the Common Stock.
REGISTRATION RIGHTS OF CURRENT SHAREHOLDERS
The Registration Rights Agreement dated as of June 6, 1997 among the
Company and the Founders and DAPHAM Partnership L.P. provides registration
rights with respect to currently outstanding Common Stock as well as shares
issued in the Combination Transactions or otherwise purchased from the Company
(the "Registrable Securities") (currently approximately 6,267,069 shares of
Common Stock). Shareholders owning not less than 51% of the then-outstanding
shares of Registrable Securities may demand that the Company effect a
registration under the Securities Act for the sale of not less than 5% of the
shares of Registrable Securities then outstanding. The holders of the
registration rights also have limited rights to require the Company to include
their shares of Common Stock in connection with registered offerings by the
Company. The holders of the registration rights have agreed to waive these
registration rights in connection with the Offering. The Company may generally
be required to effect three demand registrations (provided that no such
registration may occur prior to six months after the closing of the Offering)
and three additional demand registrations for certain offerings registered on
SEC Form S-3, subject to certain conditions and limitations. The registration
rights will terminate as to any holder of Registrable Securities at the later of
(i) one year after the closing of the Offering or (ii) at such time as such
holder may sell under Rule 144 in a three-month period all Registrable
Securities then held by such holder. The holders of the registration rights may
not exercise their registration rights with respect to any shares received in
the Combination Transaction for a period of at least one year following the
effective date of the registration statement of which this Prospectus is a part.
Registration of shares under the Securities Act would result in such shares
becoming freely tradeable without restriction under the Securities Act (except
for shares purchased by affiliates of the Company) immediately upon the
effectiveness of such registration.
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UNDERWRITING
Subject to the terms and conditions set forth in the Underwriting
Agreement, the Underwriters named below, for whom Schroder & Co. Inc. and
Jefferies & Company, Inc. are acting as Representatives (the "Representatives"),
have severally agreed to purchase from the Company an aggregate of 2,500,000
shares of Common Stock. The number of shares of Common Stock that each
Underwriter has agreed to purchase is set forth opposite its name below:
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITERS SHARES
------------ ---------
<S> <C>
Schroder & Co. Inc.......................................... 912,500
Jefferies & Company, Inc.................................... 912,500
Credit Suisse First Boston Corporation...................... 50,000
Dillon, Read & Co. Inc...................................... 50,000
Donaldson, Lufkin & Jenrette Securities Corporation......... 50,000
Goldman, Sachs & Co. ....................................... 50,000
Lehman Brothers Inc. ....................................... 50,000
Morgan Stanley & Co. Incorporated........................... 50,000
Oppenheimer & Co., Inc. .................................... 50,000
PaineWebber Incorporated.................................... 50,000
Salomon Brothers Inc ....................................... 50,000
Smith Barney Inc. .......................................... 50,000
Gerard Klauer Mattison & Co., Inc. ......................... 25,000
Johnson Rice & Company L.L.C. .............................. 25,000
Petrie Parkman & Co. ....................................... 25,000
Rauscher Pierce Refsnes, Inc. .............................. 25,000
Raymond James & Associates, Inc. ........................... 25,000
Simmons & Company International............................. 25,000
Southcoast Capital Corp. ................................... 25,000
---------
Total............................................. 2,500,000
=========
</TABLE>
The Underwriting Agreement provides that the Underwriters' obligation to
pay for and accept delivery of the shares of Common Stock offered hereby is
subject to certain conditions precedent and that the Underwriters will be
obligated to purchase all such shares, excluding shares covered by the
over-allotment option, if any are purchased. The Underwriters have informed the
Company that no sales of Common Stock will be confirmed to discretionary
accounts.
The Company has been advised by the Underwriters that they propose
initially to offer the Common Stock to the public at the public offering price
set forth on the cover page of this Prospectus and to certain dealers at such
price, less a concession not in excess of $0.45 per share. The Underwriters may
allow and such dealers may reallow a concession not in excess of $0.10 per share
to certain other brokers and dealers. After the Offering, the public offering
price, the concession and reallowances to dealers and other selling terms may be
changed by the Underwriters.
The Company has granted to the Underwriters an option exercisable for 30
days after the date of this Prospectus to purchase up to an aggregate of 375,000
additional shares of Common Stock to cover over-allotments, if any, at the same
price per share to be paid by the Underwriters for the other shares of Common
Stock offered hereby. If the Underwriters purchase any such additional shares
pursuant to the over-allotment option, each Underwriter will be committed,
subject to certain conditions, to purchase a number of the additional shares of
Common Stock proportionate to such Underwriter's initial commitment.
The Company, its directors and executive officers, and each of its current
shareholders have agreed with the Representatives, for a period of 180 days
after the date of this Prospectus, not to
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issue, sell, offer to sell, grant any options for the sale of, or otherwise
dispose of any shares of Common Stock or any rights to purchase shares of Common
Stock (other than stock issued or options granted pursuant to the Company's
stock incentive plans, the Company's stock options outstanding on the date of
this Prospectus, acquisitions in which the shares issued remain subject to a
comparable lock-up agreement, the Combination Transactions, intra-family
transfers and transfers for estate planning purposes), without the prior written
consent of Schroder & Co. Inc. See "Shares Eligible for Future Sale."
The Company has agreed to indemnify the Underwriters against certain
liabilities that they may incur in connection with the sale of the Common Stock,
including liabilities arising under the Securities Act, and to contribute to
payments that the Underwriters may be required to make with respect thereto.
Prior to this Offering, there has been no public market for the Common
Stock. The initial public offering price for the Common Stock has been
determined by negotiation between the Company and the Representatives. Among
other factors considered in determining the public offering price were
prevailing market and economic conditions, revenues and earnings of the Company,
the state of the Company's business operations, an assessment of the Company's
management and consideration of the above factors in relation to market
valuation of companies in related businesses and other factors deemed relevant.
There can be no assurance, however, that the prices at which the Common Stock
will sell in the public market after the Offering will not be lower than the
public offering price.
In order to facilitate the Offering of the Common Stock, the Underwriters
may engage in transactions that stabilize, maintain or otherwise affect the
price of the Common Stock. Specifically, the Underwriters may overallot in
connection with the Offering, creating a short position in the Common Stock for
their own account. In addition, to cover over-allotments or to stabilize the
price of the Common Stock, the Underwriters may bid for, and purchase, shares of
Common Stock in the open market. Finally, the underwriting syndicate may reclaim
selling concessions allowed to an underwriter or a dealer for distributing the
Common Stock in the Offering, if the syndicate repurchases previously
distributed Common Stock in transactions to cover syndicate short positions, in
stabilization or otherwise. Any of these activities may stabilize or maintain
the market price of the Common Stock above independent market levels. The
Underwriters are not required to engage in these activities, and may end any of
these activities at any time.
The Common Stock has been approved for inclusion on the Nasdaq National
Market under the symbol "CRZO."
LEGAL MATTERS
Certain legal matters in connection with the shares of Common Stock offered
hereby are being passed upon for the Company by Baker & Botts, L.L.P., Houston,
Texas, and for the Underwriters by Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
The audited combined financial statements included in this Prospectus and
elsewhere in the registration statement have been audited by Arthur Andersen
LLP, independent public accountants, as indicated by their report with respect
thereto, and is included herein in reliance upon the authority of said firm as
experts in giving said report.
The letter reports of Ryder Scott and Fairchild included as Annex A to this
Prospectus and certain information with respect to the Company's oil and natural
gas reserves derived therefrom have been included herein in reliance upon such
firms as experts with respect to such matters.
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ADDITIONAL INFORMATION
The Company has not previously been subject to the reporting requirements
of the Exchange Act. The Company has filed a Registration Statement under the
Securities Act with the Commission with respect to the Offering. This
Prospectus, filed as a part of the Registration Statement, does not contain all
of the information set forth in the Registration Statement or the exhibits and
schedules thereto in accordance with the rules and regulations of the
Commission, and reference is hereby made to such omitted information. Statements
made in this Prospectus concerning any document filed as an exhibit to the
Registration Statement are not necessarily complete, and in each instance
reference is made to such exhibit for a complete statement of its provisions.
The Registration Statement and the exhibits and schedules thereto may be
inspected, without charge, at the public reference facilities of the Commission
at its principal office at Judiciary Plaza, 450 Fifth Street, N.W., Room 1024,
Washington, D.C. 20549, and its regional offices at Citicorp Center, 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661, and at 7 World Trade
Center, 13th Floor, New York, New York 10048. Copies of all or any portion of
the Registration Statement can be obtained at prescribed rates from the Public
Reference Section of the Commission at its principal office at Judiciary Plaza,
450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549. The Commission
maintains an Internet web site that contains reports, proxy and information
statements and other information regarding registrants that file electronically
with the Commission (http://www.sec.gov).
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GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used
in this Prospectus. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
After payout. With respect to an oil or gas interest in a property, refers
to the time period after which the costs to drill and equip a well have been
recovered.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Bbls/d. Stock tank barrels per day.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Before payout. With respect to an oil or gas interest in a property, refers
to the time period before which the costs to drill and equip a well have been
recovered.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of
oil or gas or, in the case of a dry hole, the reporting of abandonment to the
appropriate agency.
Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or gas reserves
not classified as proved, to find a new reservoir in a field previously found to
be productive of oil or gas in another reservoir or to extend a known reservoir.
Farm-in or farm-out. An agreement whereunder the owner of a working
interest in an oil and natural gas lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Finding costs. Costs associated with acquiring and developing proved oil
and natural gas reserves which are capitalized by the Company pursuant to
generally accepted accounting principles, including all costs involved in
acquiring acreage, geological and geophysical work and the cost of drilling and
completing wells.
Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
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MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per
day.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million British Thermal Units.
MMcf. One million cubic feet.
MMcf/d. One million cubic feet per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas. Prices have historically been
higher or substantially higher for crude oil than natural gas on an energy
equivalent basis.
Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells.
Normally pressured reservoirs. Reservoirs with a formation-fluid pressure
equivalent to 0.465 psi per foot of depth from the surface. For example, if the
formation pressure is 4,650 psi at 10,000 feet, then the pressure is considered
to be normal.
Over-pressured reservoirs. Reservoirs subject to abnormally high pressure
as a result of certain types of subsurface formations.
Petrophysical study. Study of rock and fluid properties based on well log
and core analysis.
Present value. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
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Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
PV-10 Value. The present value of estimated future revenues to be generated
from the production of proved reserves calculated in accordance with Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation, without
giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expense and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or gas production free of costs of production.
3-D seismic data. Three-dimensional pictures of the subsurface created by
collecting and measuring the intensity and timing of sound waves transmitted
into the earth as they reflect back to the surface.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
Workover. Operations on a producing well to restore or increase production.
73
<PAGE> 76
CARRIZO OIL & GAS, INC.
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Carrizo Oil & Gas, Inc., and Affiliated Entities --
Report of Independent Public Accountants.................. F-2
Combined Balance Sheets, December 31, 1995 and 1996, and
March 31, 1997......................................... F-3
Combined Statements of Operations for the Years Ended
December 31, 1994, 1995 and 1996, and the Three Months
Ended March 31, 1996 and 1997.......................... F-4
Combined Statements of Equity for the Years Ended December
31, 1994, 1995 and 1996, and the Three Months Ended
March 31, 1997......................................... F-5
Combined Statements of Cash Flows for the Years Ended
December 31, 1994, 1995 and 1996, and the Three Months
Ended March 31, 1996 and 1997.......................... F-6
Notes to Combined Financial Statements.................... F-7
</TABLE>
F-1
<PAGE> 77
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and
Board of Directors of
Carrizo Oil & Gas, Inc.:
We have audited the accompanying combined balance sheets of Carrizo Oil &
Gas, Inc. (a Texas corporation), and affiliated entities identified in Note 1
(collectively, the Company) as of December 31, 1995 and 1996, and the related
combined statements of operations, equity and cash flows for each of the three
years in the period ended December 31, 1996. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the combined financial position of the Company as of
December 31, 1995 and 1996, and the combined results of their operations and
cash flows for each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
June 5, 1997
F-2
<PAGE> 78
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
COMBINED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
------------------------- MARCH 31,
1995 1996 1997
---------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents............. $ 69,536 $ 1,492,603 $ 1,500,493
Accounts receivable, trade............ 357,956 1,654,032 2,283,104
Accounts receivable, joint interest
owners............................. -- 82,296 295,394
Accounts receivable from related
parties............................ -- 79,578 55,598
Other current assets.................. 15,794 15,472 57,924
---------- ----------- -----------
Total current assets.......... 443,286 3,323,981 4,192,513
PROPERTY AND EQUIPMENT, net (full-cost
method of accounting for oil and gas
properties)........................... 6,959,513 15,205,587 19,162,276
OTHER ASSETS............................ 242,099 339,789 557,506
---------- ----------- -----------
$7,644,898 $18,869,357 $23,912,295
========== =========== ===========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable, trade............... $ 646,238 $ 4,326,299 $ 5,928,520
Other current liabilities............. 62,315 22,976 22,125
---------- ----------- -----------
Total current liabilities..... 708,553 4,349,275 5,950,645
NOTES PAYABLE TO RELATED PARTIES........ 1,396,196 2,773,935 2,878,935
LONG-TERM DEBT.......................... 2,083,684 6,910,000 9,375,000
OTHER LONG-TERM LIABILITIES............. 75,366 240,197 301,213
COMMITMENTS AND CONTINGENCIES (Note 5)
EQUITY:
Capital (at June 4, 1997; 10,000,000
authorized shares of Preferred
Stock with none outstanding,
40,000,000 authorized shares of
Common Stock, $0.01 par value, with
5,210,000 shares issued and
outstanding)....................... 4,146,000 4,261,000 4,915,678
Retained earnings (deficit)........... (764,901) 334,950 1,050,566
Deferred compensation................. -- -- (559,742)
---------- ----------- -----------
3,381,099 4,595,950 5,406,502
---------- ----------- -----------
$7,644,898 $18,869,357 $23,912,295
========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
F-3
<PAGE> 79
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
COMBINED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
FOR THE THREE MONTHS
FOR THE YEAR ENDED DECEMBER 31, ENDED MARCH 31,
----------------------------------- ---------------------
1994 1995 1996 1996 1997
--------- ---------- ---------- -------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
OIL AND NATURAL GAS REVENUES............ $ 596,733 $2,428,048 $5,194,709 $790,513 $1,853,170
COSTS AND EXPENSES:
Oil and natural gas operating expenses
(exclusive of depreciation shown
separately below).................. 518,022 1,813,406 2,384,145 417,728 557,464
Depreciation, depletion and
amortization....................... 98,262 487,949 1,135,797 141,674 382,475
General and administrative............ 237,460 425,198 514,644 44,194 197,615
--------- ---------- ---------- -------- ----------
Total costs and
expenses.................... 853,744 2,726,553 4,034,586 603,596 1,137,554
--------- ---------- ---------- -------- ----------
OPERATING INCOME (LOSS)................. (257,011) (298,505) 1,160,123 186,917 715,616
OTHER INCOME AND EXPENSES:
Interest expense...................... -- (274,585) (312,409) (76,480) (146,447)
Interest expense, related
parties............................ (7,263) (35,059) (189,881) (30,306) (42,051)
Capitalized interest.................. -- 117,288 422,493 64,216 188,498
Other income.......................... 5,765 24,251 19,525 -- --
--------- ---------- ---------- -------- ----------
NET INCOME (LOSS)....................... $(258,509) $ (466,610) $1,099,851 $144,347 $ 715,616
========= ========== ========
UNAUDITED:
PRO FORMA INCOME TAXES.................. 395,946 257,622
---------- ----------
NET INCOME (after pro forma income
taxes)................................ $ 703,905 $ 457,994
========== ==========
PRO FORMA PRIMARY AND FULLY DILUTED
EARNINGS PER SHARE (Note 2)........... $ 0.09 $ 0.06
========== ==========
PRO FORMA WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING (Note 2).... 7,722,120 7,722,120
========== ==========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
F-4
<PAGE> 80
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
COMBINED STATEMENTS OF EQUITY
<TABLE>
<CAPTION>
RETAINED
EARNINGS DEFERRED TOTAL
CAPITAL (DEFICIT) COMPENSATION EQUITY
---------- ---------- ------------ ----------
<S> <C> <C> <C> <C>
BALANCE, December 31, 1993.............. $ 100,000 $ (39,782) $ -- $ 60,218
Net loss.............................. -- (258,509) -- (258,509)
Capital contributions................. 650,000 -- -- 650,000
---------- ---------- --------- ----------
BALANCE, December 31, 1994.............. 750,000 (298,291) -- 451,709
Net loss.............................. -- (466,610) -- (466,610)
Capital contributions................. 3,500,000 -- -- 3,500,000
Distributions......................... (104,000) -- -- (104,000)
---------- ---------- --------- ----------
BALANCE, December 31, 1995.............. 4,146,000 (764,901) -- 3,381,099
Net income............................ -- 1,099,851 -- 1,099,851
Capital contributions................. 450,000 -- -- 450,000
Distributions......................... (335,000) -- -- (335,000)
---------- ---------- --------- ----------
BALANCE, December 31, 1996.............. 4,261,000 334,950 -- 4,595,950
UNAUDITED:
Net income............................ -- 715,616 -- 715,616
Distributions......................... (45,000) -- -- (45,000)
Deferred compensation related to
certain stock options.............. 699,678 -- (699,678) --
Compensation related to certain stock
options............................ -- -- 139,936 139,936
---------- ---------- --------- ----------
BALANCE, March 31, 1997................. $4,915,678 $1,050,566 $(559,742) $5,406,502
========== ========== ========= ==========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
F-5
<PAGE> 81
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
COMBINED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED MARCH 31,
------------------------------------- -----------------------------
1994 1995 1996 1996 1997
---------- ---------- ----------- ------------- -------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss).................... $ (258,509) $ (466,610) $ 1,099,851 $ 144,347 $ 715,616
Adjustment to reconcile net income
(loss) to net cash provided by
(used in) operating activities --
Depreciation, depletion and
amortization................. 98,262 487,949 1,135,797 141,674 382,475
Changes in assets and liabilities --
Accounts receivable............... (100,090) (245,365) (1,457,950) (158,401) (818,190)
Other current assets.............. 9,296 (9,433) 322 2,334 (42,452)
Accounts payable, trade........... 38,215 518,166 2,422,257 341,309 1,538,883
Interest payable to related
parties and other current
liabilities..................... (45,003) 120,946 125,164 14,545 60,165
---------- ---------- ----------- ----------- -----------
Net cash provided by (used
in) operating activities... (257,829) 405,653 3,325,441 485,808 1,836,497
---------- ---------- ----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -- accrual
basis............................. (818,775) (6,857,057) (9,479,561) (1,353,233) (4,416,945)
Adjustment to cash basis............. -- 71,664 1,258,132 -- 63,338
---------- ---------- ----------- ----------- -----------
Net cash used in investing
activities................. (818,775) (6,785,393) (8,221,429) (1,353,233) (4,353,607)
---------- ---------- ----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt......... -- 2,083,684 6,910,000 194,733 2,965,000
Debt repayments...................... -- -- (2,083,684) -- (500,000)
Proceeds from related party notes
payable........................... 532,500 863,696 1,377,739 222,643 105,000
Contributions........................ 650,000 3,500,000 450,000 450,000 --
Distributions........................ -- (104,000) (335,000) -- (45,000)
---------- ---------- ----------- ----------- -----------
Net cash provided by
financing activities....... 1,182,500 6,343,380 6,319,055 867,376 2,525,000
---------- ---------- ----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS..................... 105,896 (36,360) 1,423,067 (49) 7,890
CASH AND CASH EQUIVALENTS, beginning of
year................................. -- 105,896 69,536 69,536 1,492,603
---------- ---------- ----------- ----------- -----------
CASH AND CASH EQUIVALENTS, end of
year................................. $ 105,896 $ 69,536 $ 1,492,603 $ 69,487 $ 1,500,493
========== ========== =========== =========== ===========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of
amounts capitalized).............. $ -- $ 122,471 $ -- $ -- $ --
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
F-6
<PAGE> 82
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS
1. ORGANIZATION, COMBINATION AND NATURE OF OPERATIONS:
The Combination
Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation) was formed in 1993
and will be the surviving entity upon the completion of a series of combination
transactions (the Combination). The Combination will include the following
transactions: (a) Carrizo Production, Inc. (a Texas corporation and an
affiliated entity with ownership identical to Carrizo) will be merged into
Carrizo and the outstanding shares of capital stock of Carrizo Production, Inc.
will be exchanged for an aggregate of 343,000 shares of common stock of Carrizo
(the Common Stock); (b) Carrizo will acquire Encinitas Partners Ltd. (a Texas
limited partnership of which Carrizo Production, Inc. serves as the general
partner) as follows: Carrizo will acquire from the current shareholders who
serve as directors of Carrizo (the Founders) their limited partner interests in
Encinitas Partners Ltd. for an aggregate consideration of 468,533 shares of
Common Stock and, on the same date, Encinitas Partners Ltd. will be merged into
Carrizo and the outstanding limited partner interests in Encinitas Partners Ltd.
will be exchanged for an aggregate of 860,699 shares of Common Stock; (c) La
Rosa Partners Ltd. (a Texas limited partnership of which Carrizo serves as the
general partner) will be merged into Carrizo and the outstanding limited partner
interests in La Rosa Partners Ltd. will be exchanged for an aggregate of 48,700
shares of Common Stock; and (d) Carrizo Partners Ltd. (a Texas limited
partnership of which Carrizo serves as the general partner) will be merged into
Carrizo and the outstanding limited partner interests in Carrizo Partners Ltd.
will be exchanged for an aggregate of 569,068 shares of Common Stock. Carrizo
plans to complete each of the above transactions concurrently with the
consummation of an initial public offering of its Common Stock (see Note 6).
Principles of Combination
The accompanying combined financial statements include the accounts of
Carrizo, Carrizo Production, Inc., and the combined interests of the
aforementioned limited partnerships, all of which share common ownership and
management (collectively, the Company). Upon completion of the transactions
described above, the combination will be accounted for as a reorganization of
entities as prescribed by Securities and Exchange Commission (SEC) Staff
Accounting Bulletin 47 because of the high degree of common ownership among, and
the common control of, the combining entities. Accordingly, the accompanying
combined accounts have been prepared using the historical costs and results of
operations of the affiliated entities. There were no significant differences in
accounting methods or their application among the combining entities. All
intercompany balances have been eliminated.
Nature of Operations
The Company is an independent energy company engaged in the exploration,
development, exploitation and production of oil and natural gas. The Company's
operations are focused on Texas and Louisiana Gulf Coast trends, primarily the
Frio, Wilcox and Vicksburg trends. The Company has acquired or is in the process
of acquiring 1,097 square miles of 3-D seismic data. Additionally, the Company
has assembled approximately 322,000 gross acres under lease or option.
Consistent with other companies in the energy industry, the Company is subject
to certain risks, including volatility of oil and natural gas prices,
uncertainty of reserve information, operating risks of oil and natural gas
operations, and significant requirements for capital.
F-7
<PAGE> 83
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Oil and Natural Gas Properties
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. No general and administrative costs have been
capitalized at December 31, 1994, 1995 or 1996. During the three-months ended
March 31, 1997, the Company capitalized $139,936 of deferred compensation
related to stock options granted to personnel directly associated with
exploration activities.(See Note 6.)
Oil and natural gas properties are amortized based on the
unit-of-production method using estimates of proved reserve quantities.
Investments in unproved properties are not amortized until proved reserves
associated with the projects can be determined or until impairment occurs.
Unevaluated properties were evaluated for impairment on a property-by-property
basis annually through 1995 and quarterly beginning in 1996. 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 1994, 1995, 1996 and the three months ended March 31, 1997, was
$0.48, $0.47, $0.59 and $0.53, respectively.
Dispositions of oil and gas properties are accounted for as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. Through March 31, 1997, there have been no dispositions of oil and gas
properties.
The net capitalized costs of proved oil and gas properties are subject to a
"ceiling test," which limits such costs to the estimated present value,
discounted at a 10 percent interest rate, of future net cash flows from proved
reserves, based on current economic and operating conditions. If net capitalized
costs exceed this limit, the excess is charged to operations through
depreciation, depletion and amortization. For the accompanying reporting
periods, no write-down of the Company's oil and natural gas assets was
necessary.
Depreciation of other property and equipment is provided using the
straight-line method based on estimated useful lives ranging from five to 10
years.
Financing Costs
Offering costs of $211,575 through March 31, 1997 have been deferred and
are anticipated to be applied against stock offering proceeds (see Note 6).
Long-term debt financing costs of $47,194 are capitalized as deferred assets and
are being amortized over the term of the loans.
Statements of Cash Flows
For statement of cash flow purposes, all highly liquid investments with
original maturities of three months or less are considered to be cash
equivalents.
Financial Instruments
The Company's financial instruments consist of cash, receivables, payables
and long-term debt. The carrying amount of cash, receivables and payables
approximates fair value because of the
F-8
<PAGE> 84
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
short-term nature of these items. The carrying amount of long-term debt
approximates fair value as the individual borrowings bear interest at floating
market interest rates.
Hedging Activities
The Company periodically enters into hedging arrangements to manage price
risks related to oil and natural gas sales and not for speculative purposes. The
Company's hedging arrangements apply only to a portion of its production,
provide only partial price protection against declines in oil and natural gas
prices and limit potential gains from future increases in prices. For financial
reporting purposes, gains and losses related to hedging are recognized as income
when the hedged transaction occurs. Historically, gains and losses from hedging
activities have not been material. Total oil and natural gas hedged in 1995 and
1996 was 9,000 Bbls and 3,000 Bbls, respectively, and 40,000 MMBtu and 60,000
MMBtu, respectively. There was no hedging activity during 1994. The Company had
no outstanding hedged positions as of December 31, 1996, or March 31, 1997.
Income Taxes
Carrizo and the combined affiliated entities either have elected to be
treated as S Corporations under the Internal Revenue Code or are otherwise not
taxed as entities for federal income tax purposes. The taxable income or loss is
therefore allocated to the equity owners of Carrizo and the combined affiliated
entities. Accordingly, no provision was made for income taxes in the
accompanying combined historical financial statements. (See Note 8.)
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these estimates. Significant
estimates include depreciation, depletion and amortization of proved oil and
natural gas properties. Oil and natural gas reserve estimates, which are the
basis for unit-of-production depletion and the ceiling test, are inherently
imprecise and are expected to change as future information becomes available.
Concentration of Credit Risk
Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables.
Recently Issued Accounting Pronouncements
In March 1995, the Financial Accounting Standards Board issued SFAS No. 121
regarding accounting for the impairment of long-lived assets. The Company
adopted SFAS No. 121 effective January 1, 1996. However, its provisions are not
applicable to the Company's oil and gas properties as they are accounted for
under the full-cost method of accounting.
In February 1997, the Financial Accounting Standards Board issued SFAS No.
128 regarding earnings per share. SFAS No. 128 cannot be adopted until December
15, 1997; however, pro forma disclosures are allowed to minimize the impact of
year-end adoption. As a result of the noncomplex
F-9
<PAGE> 85
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
nature of the Company's capital structure and treatment of all stock options as
outstanding for all periods pursuant to Staff Accounting Bulletin No. 83, SFAS
No. 128 would have no current impact on the pro forma calculation of earnings
per share.
Interim Financial Data (Unaudited)
The unaudited financial statements as of March 31, 1997, and for the
three-month periods ended March 31, 1996 and 1997, and all related footnote
information for these periods have been prepared on the same basis as the
audited financial statements and, in the opinion of management, include all
adjustments, consisting of normal recurring adjustments, necessary for a fair
presentation of financial position and results of operations and cash flows in
accordance with generally accepted accounting principles.
Earnings Per Share
Historical earnings per share have been omitted from the combined
statements of operations since such information is not meaningful and the
historically combined company is not a separate legal entity with a singular
capital structure. Pro forma earnings per share is presented using the weighted
average number of common shares outstanding after giving effect to the
Combination (7,500,000 shares). All common stock options have been treated as
outstanding for all periods presented (222,120 shares), as required by SEC Staff
Accounting Bulletin No. 83.
3. PROPERTY AND EQUIPMENT:
At December 31, 1995 and 1996, and March 31, 1997, property and equipment
consisted of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------ MARCH 31,
1995 1996 1997
---------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C>
Proved oil and natural gas properties........ $4,813,440 $ 9,217,027 $10,550,738
Unproved oil and natural gas properties...... 2,680,876 7,455,698 10,416,676
Other equipment.............................. -- 62,073 106,548
---------- ----------- -----------
Total property and equipment....... 7,494,316 16,734,798 21,073,962
Accumulated depreciation, depletion and
amortization............................... (534,803) (1,529,211) (1,911,686)
---------- ----------- -----------
Property and equipment, net.................. $6,959,513 $15,205,587 $19,162,276
========== =========== ===========
</TABLE>
Oil and natural gas properties not subject to amortization consist of the
cost of undeveloped leaseholds, undesignated seismic costs, exploratory wells in
progress, and secondary recovery projects before the assignment of proved
reserves. These costs are reviewed periodically by management for impairment,
with the impairment provision included in the cost of oil and natural gas
properties subject to amortization. Factors considered by management in its
impairment assessment include drilling results by the Company and other
operators, the terms of oil and natural gas leases not held by production,
production response to secondary recovery activities and available funds for
exploration and development. Of the $7,455,698 of unproved property costs at
December 31, 1996 being excluded from the amortizable base, $2,680,876 and
$4,774,822 were incurred in 1995 and 1996, respectively. The Company expects it
will complete its evaluation of the properties representing the majority of
these costs within the next three years.
F-10
<PAGE> 86
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
4. LONG-TERM DEBT:
In January 1995, the Company entered into a loan agreement with Texas
Commerce Bank (TCB) in the amount of $1,800,000 for the acquisition of the
Encinitas oil and gas properties. This loan was amended on February 18, 1995, to
provide funds for the development of those properties. Borrowings under this
agreement, which totaled $2,083,684 at December 31, 1995, and bore interest at
the prime rate as specified by TCB plus 2.75 percent, were repaid with
borrowings under the Encinitas Facility (defined below), and this loan facility
was terminated in 1996. As additional consideration, the Company assigned a 1
percent royalty interest in the Encinitas/Kelsey properties to TCB.
In June 1996, the Company entered into a $10 million revolving credit
facility with Compass Bank (the Encinitas Facility). Proceeds from this facility
were used to pay off the existing loan from TCB as well as fund exploration and
development activities. The facility is subject to a borrowing base calculation
and had a commitment of $3,350,000 at December 31, 1996, and $2,634,000 at March
31, 1997. The facility is also available for letters of credit, one of which has
been issued for $224,000. The Encinitas Facility is secured by the interests in
oil and natural gas properties owned by Encinitas Partners, Ltd., and bears
interest at the prime rate as defined by Compass Bank plus .75 percent, and the
borrowings must be repaid by June 1, 1998. At December 31, 1996, and March 31,
1997, borrowings under the Encinitas Facility totaled $2,910,000 and $2,410,000,
respectively. At December 31, 1996, $216,000 was available to the Company for
future borrowings. No additional amounts were available for borrowing at March
31, 1997. The weighted average interest rate under the Encinitas Facility for
1996 was 9 percent.
In December 1996, Carrizo entered into a separate $25 million revolving
credit facility with Compass Bank (the Carrizo Facility), which is subject to a
borrowing base determination, and total commitment was $6 million and
approximately $7.2 million at December 31, 1996, and March 31, 1997,
respectively. Interest on this facility is the prime rate as defined by Compass
Bank plus .75 percent, and the borrowings must be repaid by June 1, 1998.
Proceeds from this facility have been used to provide working capital for
exploration and development activity. Substantially all of Carrizo's oil and
natural gas property and equipment is pledged as collateral under this facility.
At December 31, 1996, and March 31, 1997, borrowings under this facility totaled
$4 million and $6,965,000, respectively, with an additional $2 million and
approximately $250,000, respectively, available for future borrowings. The
weighted average interest rate for 1996 on the Carrizo Facility was 9 percent.
Encinitas Partners, Ltd., and Carrizo are each subject to certain covenants
under the terms of the Encinitas Facility and the Carrizo Facility,
respectively, including but not limited to (a) maintenance of specified tangible
net worth and (b) maintenance of a ratio of quarterly cash flow (net income plus
depreciation and other noncash expenses, less noncash net income) to quarterly
debt service (payments made for principal in connection with each credit
facility plus payments made for principal other than in connection with such
credit facility) of no less than 1.25 to 1.00. The credit facilities also place
restrictions on, among other things, (a) incurring additional indebtedness,
guaranties, loans and liens, (b) changing the nature of business or business
structure and (c) selling assets. Necessary waivers effective as of December 31,
1996, were received from Compass Bank to decrease the Encinitas Facility
tangible net worth requirement and to permit Carrizo (under the Carrizo
Facility) to advance funds to one of the affiliated entities for exploration
expenditures.
The Company also had outstanding borrowings from certain shareholders
totaling $1,396,196, $2,773,935 and $2,878,935 at December 31, 1995 and 1996,
and March 31, 1997, respectively.
F-11
<PAGE> 87
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
These loans bore interest at the TCB prime rate, and repayment of the funds and
interest is due in April 1998. Accrued interest on shareholder borrowings is
included in other long-term liabilities.
At December 31, 1995 and 1996, and at March 31, 1997, notes payable and
long-term debt consisted of the following:
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
------------------------ -----------
1995 1996 1997
---------- ---------- -----------
(UNAUDITED)
<S> <C> <C> <C>
Notes payable to shareholders (due April,
1998)................................... $1,396,196 $2,773,935 $ 2,878,935
Notes payable to TCB...................... 2,083,684 -- --
$10 million revolving credit facility (due
June 1, 1998)........................... -- 2,910,000 2,410,000
$25 million revolving credit facility (due
June 1, 1998)........................... -- 4,000,000 6,965,000
---------- ---------- -----------
$3,479,880 $9,683,935 $12,253,935
========== ========== ===========
</TABLE>
5. COMMITMENTS AND CONTINGENCIES:
The Company is, from time to time, party to certain legal actions and
claims arising in the ordinary course of business. While the outcome of these
events cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the financial position or results
of operations of the Company.
At December 31, 1996, Carrizo was obligated under a noncancelable operating
lease for office space. Rent expense for the years ended December 31, 1994, 1995
and 1996, was $5,400, $7,600 and $14,900, respectively. Following is a schedule
of the remaining future minimum lease payments under this lease:
<TABLE>
<S> <C>
1997.................................................... $ 68,680
1998.................................................... 75,390
1999.................................................... 75,390
2000.................................................... 12,562
</TABLE>
6. EQUITY:
On July 19, 1996, and March 1, 1997, the Company entered into separate
stock option agreements with two executives of Carrizo whereby such employees
were granted the option to purchase 138,825 shares and 83,295 shares of Carrizo
common stock, respectively, at an exercise price of $3.60 per share. The options
vest ratably through August 1, 1998, and March 1, 1999, respectively.
The Company did not record any compensation expense related to the July,
1996 options because the related exercise price was at or above the estimated
fair value of Carrizo's common stock at the time such options were granted. In
connection with an initial public offering, the Company has recorded deferred
compensation related to the March 1997 stock option agreement, as additional
paid-in capital and an offsetting contra-equity account. Such compensation
accrual is based on the difference between the option price and the fair value
of Carrizo's common stock when such options were granted (using an estimate of
the initial public offering common stock price as an
F-12
<PAGE> 88
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
estimate of fair value). Such deferred compensation is recognized in the period
in which the options vest, which resulted in $139,936 being recorded in the
three-month period ended March 31, 1997.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 123. SFAS No. 123 is a new standard
of accounting for stock-based compensation and establishes a fair value method
of accounting for awards granted under stock compensation plans. SFAS No. 123
encourages, but does not require, companies to adopt the fair value method of
accounting in place of the existing method of accounting for stock-based
compensation whereupon compensation costs are recognized only in situations
where stock compensation plans award intrinsic value to recipients at the date
of grant. Companies that do not adopt the fair value method of accounting
prescribed in SFAS No. 123 must, nonetheless, make annual pro forma disclosures
of the estimated effects on net income and earnings per share in their year-end
1996 financial statements as if the fair value method had been used for grants
after December 31, 1994. Had compensation cost for the options granted in July,
1996 been determined consistent with SFAS 123, the Company's reported 1996 net
income and pro forma earnings per share would have been adjusted to the
following pro forma amounts:
<TABLE>
<S> <C> <C>
Net Income..................... As reported $1,099,851
Pro forma $1,038,490
EPS............................ As reported (pro forma) $ 0.14
Pro forma $ 0.13
</TABLE>
The fair value of these options is estimated on the date of grant using the
Black-Scholes option pricing model, with the following assumptions: risk-free
interest rate of 6.82%, expected dividend yield of 0%, expected life of 10
years, and expected volatility of 30%.
Event Subsequent to Date of Auditors' Report (Unaudited):
Carrizo filed a registration statement on Form S-1, which became effective
August 5, 1997, for the sale of 2,500,000 shares of common stock. The net
proceeds from this sale at the initial public offering price of $11.00 per share
are estimated to be approximately $24.4 million. Carrizo intends to use a
portion of the net proceeds to repay indebtedness outstanding under the
revolving credit facilities and promissory notes to certain of the Company's
directors and officers. The remainder of the net proceeds will be used to
accelerate the Company's exploration and development program and for general
corporate purposes. Following the completion of the initial public offering, the
Company expects to enter into a new credit facility and the Encinitas Facility
and Carrizo Facility will be terminated.
Carrizo and its affiliated entities are anticipated to be combined in a
series of transactions concurrent with the consummation of the initial public
offering. As a result of the Combination, Carrizo will issue approximately
2,290,000 shares of common stock for the equity interests that it does not
already own in these entities.
7. RELATED-PARTY TRANSACTIONS:
In August 1996, the Company entered into the Master Technical Services
Agreement (the MTS Agreement) with Reading & Bates Development Co. (R&B), which
is a subsidiary of Reading & Bates Corporation. Paul Loyd, a member of the board
of the Company, is the chairman of the board, president, chief executive officer
and a director of Reading & Bates Corporation. Under the MTS Agreement, certain
employees of the Company provide engineering and technical services to R&B at
market rates in connection with R&B's technical service, procurement and
construction projects
F-13
<PAGE> 89
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
in offshore drilling and floating production. The Company provided $117,726 in
services under this agreement in 1996.
The Company has an agreement with Loyd & Associates Inc., which is owned by
Paul Loyd, a director of Carrizo, and Frank Wojtek, vice president, chief
financial officer and a director of Carrizo, to provide certain financial
consulting and administrative services at market rates to the Company. Payments
are made monthly and total payments to Loyd & Associates Inc. for services
rendered were $43,500, $60,000 and $60,000 in 1994, 1995 and 1996, respectively.
These expenditures were included in general and administrative expenses for each
year.
8. SUBSEQUENT EVENTS (UNAUDITED):
On June 4, 1997, the board of directors authorized a 521-for-1 split of the
Company's stock and increased the number of authorized shares to 40 million
shares of common stock and 10 million shares of preferred stock. All share
amounts presented in these combined financial statements are presented on a
retroactive, post-split basis.
On May 16, 1997, Carrizo terminated its status as an S corporation and
thereafter became subject to federal income taxes. In accordance with SFAS No.
109, "Accounting for Income Taxes", the Company will be required to establish a
deferred tax liability in the second quarter of 1997 which will result in a
noncash charge to income that is currently estimated in the range of
approximately $1.5 million to $2.0 million. The Company is currently in process
of finalizing such amount. Additionally, the Company has entered into tax
indemnification agreements with the founders of the Company pertaining to
periods in which the Company was an S Corporation.
9. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT
AND PRODUCTION ACTIVITIES (UNAUDITED):
The following disclosures provide unaudited information required by SFAS
No. 69, "Disclosures About Oil and Gas Producing Activities."
Costs Incurred
Costs incurred in oil and natural gas property acquisition, exploration and
development activities are summarized below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------------------
1994 1995 1996
-------- ---------- ----------
<S> <C> <C> <C>
Property acquisition costs --
Unproved................................... $ -- $ 316,820 $ 50,720
Proved..................................... 329,146 3,588,173 1,907,890
Exploration cost............................. 280,001 2,364,056 4,724,102
Development costs............................ 177,285 208,696 1,955,917
-------- ---------- ----------
Total costs incurred(1)............ $786,432 $6,477,745 $8,638,629
======== ========== ==========
</TABLE>
- ---------------
(1) Excludes capitalized interest on unproved properties of $117,288 and
$422,493 for the years ended December 31, 1995 and 1996, 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
F-14
<PAGE> 90
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1996, and the
related discounted future net cash flows before income taxes are based on
estimates prepared by Ryder Scott Company and Fairchild, Ancell & Wells, Inc.,
independent petroleum engineers. Such estimates have been prepared in accordance
with guidelines established by the Securities and Exchange Commission. Amounts
at December 31, 1994 and 1995, and for the periods then ended were rolled back
from December 31, 1996, balances, ignoring the impact of revisions of estimates
during those periods, if any.
The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:
<TABLE>
<CAPTION>
BARRELS OF
OIL, CONDENSATE AND
NATURAL GAS LIQUIDS
-----------------------------------
AT DECEMBER 31,
-----------------------------------
1994 1995 1996
--------- --------- ---------
<S> <C> <C> <C>
Proved developed and undeveloped reserves --
Beginning of year............................ 3,750,000 3,785,000 3,810,000
Purchases of oil and gas properties.......... 68,000 103,000 12,000
Extensions and discoveries................... -- -- 180,000
Production................................... (33,000) (78,000) (107,000)
--------- --------- ---------
End of year.................................... 3,785,000 3,810,000 3,895,000
========= ========= =========
Proved developed reserves at end of year....... 1,085,000 1,100,000 1,048,000
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
THOUSANDS OF CUBIC FEET OF
NATURAL GAS
----------------------------------
AT DECEMBER 31,
----------------------------------
1994 1995 1996
------- --------- ----------
<S> <C> <C> <C>
Proved developed and undeveloped reserves --
Beginning of year............................ 277,000 272,000 5,437,000
Purchases of oil and gas properties.......... -- 5,730,000 338,000
Extensions and discoveries................... -- -- 7,646,000
Production................................... (5,000) (565,000) (1,273,000)
------- --------- ----------
End of year.................................... 272,000 5,437,000 12,148,000
======= ========= ==========
Proved developed reserves at end of year....... -- 3,810,000 8,110,000
======= ========= ==========
</TABLE>
F-15
<PAGE> 91
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Standardized Measure
The standardized measure of discounted future net cash flows relating to
the Company's ownership interests in proved oil and natural gas reserves as of
year-end is shown below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1994 1995 1996
----------- ----------- ------------
<S> <C> <C> <C>
Future cash inflows...................... $61,727,000 $77,739,000 $126,155,000
Future oil and natural gas operating
expenses.............................. 40,576,000 43,529,000 47,675,000
Future development costs................. 7,711,000 7,918,000 9,375,000
Future income tax expenses............... 4,415,000 7,163,000 19,864,000
----------- ----------- ------------
Future net cash flows.................... 9,025,000 19,129,000 49,241,000
10% annual discount for estimating timing
of cash flows......................... 2,527,000 7,148,000 16,220,000
----------- ----------- ------------
Standardized measure of discounted future
net cash flows........................ $ 6,498,000 $11,981,000 $ 33,021,000
=========== =========== ============
</TABLE>
Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Prices used in computing year end 1996 future cash flows were $20.88 and $3.69
for oil and natural gas, respectively. Such prices declined significantly in the
first quarter of 1997. Future operating expenses and development costs are
computed primarily by the Company's petroleum engineers by estimating the
expenditures to be incurred in developing and producing the Company's proved oil
and natural gas reserves at the end of the year, based on the year-end costs and
assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for tax
basis and applicable tax credits. A discount factor of 10 percent was used to
reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties. An
estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the
time value of money and the risks inherent in reserve estimates.
F-16
<PAGE> 92
CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Change in Standardized Measure
Changes in the standardized measure of future net cash flows relating to
proved oil and natural gas reserves are summarized below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1994 1995 1996
----------- ----------- -----------
<S> <C> <C> <C>
Changes due to current-year operations --
Sales of oil and natural gas, net of oil
and natural gas operating expenses..... $ (79,000) $ (614,000) $(2,811,000)
Extensions and discoveries................ - - 19,641,000
Purchases of oil and gas properties....... 104,000 2,770,000 2,079,000
Changes due to revisions in standardized
variables-
Prices and operating expenses............. 6,761,000 6,343,000 9,781,000
Income taxes.............................. (2,785,000) (1,307,000) (8,834,000)
Estimated future development costs........ - - (670,000)
Accretion of discount..................... 131,000 968,000 1,647,000
Production rates (timing) and other....... 1,449,000 (2,677,000) 207,000
----------- ----------- -----------
Net change.................................. 5,581,000 5,483,000 21,040,000
Beginning of year........................... 917,000 6,498,000 11,981,000
----------- ----------- -----------
End of year................................. $ 6,498,000 $11,981,000 $33,021,000
=========== =========== ===========
</TABLE>
Sales of oil and natural gas, net of oil and natural gas operating
expenses, are based on historical pretax results. Sales of oil and natural gas
properties, extensions and discoveries, purchases of minerals in place and the
changes due to revisions in standardized variables are reported on a pretax
discounted basis, while the accretion of discount is presented on an after-tax
basis.
F-17
<PAGE> 93
ANNEX A
[RYDER SCOTT COMPANY LETTERHEAD]
June 9, 1997
Carrizo Oil & Gas, Inc.
14811 St. Mary's Lane, Suite 148
Houston, Texas 77079
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold interests of Carrizo
Oil & Gas, Inc. (Carrizo) as of March 31, 1997. The subject properties are
located in the states of Louisiana and Texas. The income data were estimated
using the Securities and Exchange Commission (SEC) guidelines for future price
and cost parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. March 1997 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from these prices. Therefore, volumes of
reserves actually recovered and amounts of income actually received may differ
significantly from the estimated quantities presented in this report. The
results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
CARRIZO OIL & GAS, INC.
As of March 31, 1997
-------------------------------------------------
<TABLE>
<CAPTION>
Proved
--------------------------------------------------------------------------------------
Developed Total
------------------------------------------
Producing Non-Producing Undeveloped Proved
------------------ -------------------- ------------------- ----------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate - Barrels 126,049 15,876 322,180 464,105
Plant Products - Barrels 78,040 76,981 40,875 195,896
Gas - MMCF 4,394 2,011 6,621 13,026
INCOME DATA
Future Gross Revenue $10,022,455 $4,204,793 $18,145,781 $32,373,029
Deductions 1,909,546 1,106,379 5,738,842 8,754,767
----------- ---------- ----------- -----------
Future Net Income (FNI) $ 8,112,909 $3,098,414 $12,406,939 $23,618,262
Discounted FNI @ 10% $ 6,852,037 $1,933,074 $ 7,593,621 $16,378,732
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are sales gas expressed in millions of cubic feet (MMCF) at the
official temperature and pressure bases of the areas in which the gas reserves
are located.
<PAGE> 94
Carrizo Oil & Gas, Inc.
June 9, 1997
Page 2
The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs, and development costs. The future net income
is before the deduction of state and federal income taxes and general
administrative overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or undistributed
income. No attempt was made to quantify or otherwise account for any
accumulated gas production imbalances that may exist. Gas reserves account for
approximately 66 percent and liquid hydrocarbon reserves account for the
remaining 34 percent of total future gross revenue from proved reserves.
RESERVES INCLUDED IN THIS REPORT
The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definition
of proved reserves is included in the section entitled "Definitions of
Reserves" which is attached with this report.
The proved developed non-producing reserves included herein are comprised
of the behind pipe category. The various reserve status categories are defined
in the section entitled "Reserve Status Categories" which is attached with this
report.
ESTIMATES OF RESERVES
In general, the reserves included herein were predominantly estimated by
the volumetric method due to the limited production history of the wells
considered in this study. However, performance methods were used in certain
cases where characteristics of the data indicated this method was more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive. Reserves were estimated by the volumetric method in those
cases where there were inadequate historical performance data to establish a
definitive trend or where the use of production performance data as a basis for
the reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for
those wells now on production. Test data and other related information were
used to estimate the anticipated initial production rates for those wells or
locations which are not currently producing. If no production decline trend has
been established, future production rates were held constant, or adjusted for
the effects of curtailment where appropriate, until a decline in ability to
produce was anticipated. An estimated rate of decline was then applied to
depletion of the reserves. If a decline trend has been established, this trend
was used as the basis for estimating future production rates. For reserves not
yet on production, sales were estimated to commence at an anticipated date
furnished by Carrizo.
In general, we estimate that future gas production rates limited by
allowables or marketing conditions will continue to be the same as the average
rate for the latest available 12 months of actual production until such time
that the well or wells are incapable of producing at this
<PAGE> 95
Carrizo Oil & Gas, Inc.
June 9, 1997
Page 3
rate. The well or wells were then projected to decline at their decreasing
delivery capacity rate. Our general policy on estimates of future gas
production rates is adjusted when necessary to reflect actual gas market
conditions in specific cases.
The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
HYDROCARBON PRICES
Carrizo furnished us with prices in effect at March 31, 1997 and these
prices were held constant except for known and determinable escalations.
Product prices which were actually used for each property reflect adjustment
for gravity, quality, local conditions, and/or distance from market. In
accordance with Securities and Exchange Commission guidelines, changes in
liquid and gas prices subsequent to March 31, 1997 were not taken into account
in this report. Future prices used in this report are discussed in more detail
in the section entitled "Hydrocarbon Pricing Parameters" which is attached with
this report.
COSTS
Operating costs for the leases and wells in this report are based on the
operating expense reports of Carrizo and include only those costs directly
applicable to the leases or wells. When applicable, the operating costs include
a portion of general and administrative costs allocated directly to the leases
and wells under terms of operating agreements. No deduction was made for
indirect costs such as general administration and overhead expenses, loan
repayments, interest expenses, and exploration and development prepayments that
are not charged directly to the leases or wells.
Development costs were furnished to us by Carrizo and are based on
authorizations for expenditure for the proposed work or actual costs for
similar projects. At the request of Carrizo, their estimate of zero abandonment
costs after salvage value was used in this report. Ryder Scott has not
performed a detailed study of the abandonment costs nor the salvage value and
makes no warranty for Carrizo's estimate.
Current costs were held constant throughout the life of the properties.
GENERAL
While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration
in making this evaluation.
The estimates of reserves presented herein were based upon a detailed
study of the properties in which Carrizo owns an interest; however, we have not
made any field examination of the properties. No consideration was given in
this report to potential environmental liabilities which may exist nor were any
costs included for potential liability to restore and clean up damages, if any,
caused by past operating practices. Carrizo has informed us that they have
furnished us all of the accounts, records, geological and engineering data, and
reports and other data required for this investigation.
<PAGE> 96
Carrizo Oil & Gas, Inc.
June 9, 1997
Page 4
The ownership interests, prices, and other factual data furnished by Carrizo
were accepted without independent verification. The estimates presented in this
report are based on data available through March 1997.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation
is contingent on our estimates of reserves and future income for the subject
properties.
This report was prepared for the exclusive use and sole benefit of Carrizo
Oil & Gas, Inc. The data, work papers, and maps used in this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ MICHAEL F. STELL
Michael F. Stell, P.E.
Petroleum Engineer
MFS/sw
Approved:
/s/ DON P. ROESLE
- -------------------------------------
Don P. Roesle, P.E.
Senior Vice President
<PAGE> 97
DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing operating conditions, i.e., prices and costs as
of the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalation based on future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated, associated
and dissolved gas. An appropriate reduction in gas reserves has been made for
the expected removal of natural gas liquids, for lease and plant fuel, and for
the exclusion of non-hydrocarbon gases if they occur in significant quantities
and are removed prior to sale. Estimates of proved reserves do not include
crude oil, natural gas, or natural gas liquids being held in underground or
surface storage.
Proved reserves are estimates of hydrocarbons to be recovered from a given
date forward. They may be revised as hydrocarbons are produced and additional
data become available.
<PAGE> 98
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of
wells and/or reservoirs.
PROVED DEVELOPED (SEC DEFINITION)
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the
operation of an installed program has confirmed through production response
that increased recovery will be achieved.
Developed reserves may be subcategorized as producing or non-producing
using the SPE/SPEE Definitions:
Producing
Producing reserves are expected to be recovered from completion intervals
open at the time of the estimate and producing. Improved recovery reserves
are considered to be producing only after an improved recovery project is
in operation.
Non-Producing
Non-producing reserves include shut-in and behind pipe reserves. Shut-in
reserves are expected to be recovered from completion intervals open at the
time of the estimate, but which had not started producing, or were shut-in
for market conditions or pipeline connection, or were not capable of
production for mechanical reasons, and the time when sales will start is
uncertain. Behind pipe reserves are expected to be recovered from zones
behind casing in existing wells, which will require additional completion
work or a future recompletion prior to the start of production.
PROVED UNDEVELOPED (SEC DEFINITION)
Proved undeveloped oil and gas reserves are 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. Reserves on
undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it can be
demonstrated with reasonable certainty that there is continuity of production
from the existing productive formation. Estimates for proved undeveloped
reserves are attributable to any acreage for which an application of fluid
injection or other improved technique is contemplated, only when such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
<PAGE> 99
HYDROCARBON PRICING PARAMETERS
SECURITIES AND EXCHANGE COMMISSION PARAMETERS
OIL AND CONDENSATE
Carrizo furnished us with oil and condensate prices in effect at March 31,
1997 and these prices were held constant to depletion of the properties. In
accordance with Securities and Exchange Commission guidelines, changes in
liquid prices subsequent to March 31, 1997 were not considered in this report.
PLANT PRODUCTS
Carrizo furnished us with plant product prices in effect at March 31, 1997
and these prices were held constant to depletion of the properties.
GAS
Carrizo furnished us with gas prices in effect at March 31, 1997 and with
its forecasts of future gas prices which take into account SEC guidelines,
current spot market prices, contract prices, and fixed and determinable price
escalations where applicable. In accordance with SEC guidelines, the future gas
prices used in this report make no allowances for future gas price increases
which may occur as a result of inflation nor do they make any allowance for
seasonal variations in gas prices which may cause future yearly average gas
prices to be somewhat lower than March 31, 1997 gas prices. For gas sold under
contract, the contract gas price including fixed and determinable escalations,
exclusive of inflation adjustments, was used until the contract expires and
then was adjusted to the current market price for the area and held at this
adjusted price to depletion of the reserves.
<PAGE> 100
[FAIRCHILD, ANCELL & WELLS, INC. LETTERHEAD]
June 4, 1997
Carrizo Oil & Gas, Inc.
14811 St. Mary's Lane, Suite 148
Houston, Texas 77079
Re: Reserves Evaluation to the Interests of Carrizo Oil & Gas, Inc.
Heavy Oil Properties, Anderson County, Texas
Gentlemen:
Fairchild, Ancell & Wells, Inc. (FAW) has performed an engineering evaluation
to estimate proved reserves and future cash flows from heavy oil (steamflood)
properties to the interests of Carrizo Oil & Gas, Inc. in Anderson County,
Texas. This evaluation was authorized by Mr. S.P. Johnson IV, President of
Carrizo Oil & Gas, Inc. (Carrizo). Projections of the anticipated future annual
oil production and future cash flows have also been prepared utilizing property
development schedules provided by Carrizo. The reserves and future cash flows
to the evaluated interests were based on economic parameters and operating
conditions considered applicable and are pursuant to the financial reporting
requirements of the Securities and Exchange Commission (SEC).
The results of the study are summarized below.
ESTIMATED PROVED RESERVES AND FUTURE CASH FLOWS
CAMP HILL FIELD ANDERSON COUNTY, TEXAS
TO THE INTERESTS OF CARRIZO OIL & GAS, INC.
EFFECTIVE 3/31/97
<TABLE>
<CAPTION>
Future
Cash Flows (M$)
Net --------------------------------------
Reserves Mbbls Undiscounted Discounted at 10%
-------------- ------------ -----------------
<S> <C> <C> <C>
Proved Producing 928.4 8,270.8 6,559.3
Proved Undeveloped 2,700.2 13,242.6 7,482.7
Total Proved 3,628.6 21,513.4 14,042.0
</TABLE>
<PAGE> 101
Carrizo Oil & Gas, Inc. Page 2
June 4, 1997
FUTURE CASH FLOW -
TOTAL PROJECT BY YEAR
<TABLE>
<CAPTION>
Future
Cash Flows (M$)
-----------------------------------
Discounted
Year Undiscounted at 10%
--- ------------ ----------
<S> <C> <C> <C>
1997 262.8 250.6
1998 2,541.9 2,203.3
1999 4,067.4 3,205.0
2000 2,809.9 2,012.9
2001 2,906.3 1,892.6
2002 3,044.9 1,802.6
2003 2,255.9 1,214.1
2004 2,426.3 1,187.1
2005 979.2 435.5
2006 218.9 88.5
TOTAL 21,513.4 14,042.0
</TABLE>
The estimated reserves and future cash flows shown in this report are for
proved developed producing and proved undeveloped reserves. Our estimates do
not include any value which might be attributed to interests in undeveloped
acreage beyond those tracts for which reserves have been assigned.
In performance of this evaluation, we have relied upon information furnished by
Carrizo with respect to property interests owned, production from such
properties, current costs of operation and development, current prices for
production, agreements relating to current and future operations and sale of
production. With respect to the technical files supplied by Carrizo, we have
accepted the authenticity and sufficiency of the data contained therein.
Future cash flow is presented after deducting production taxes and after
deducting future capital costs and operating expenses, but before consideration
of Federal income taxes. The future cash flow has been discounted at an annual
rate of 10 percent to determine its "present worth." The present worth is shown
to indicate the effect of time on the value of money and should not be
construed as being the fair market value of the properties Our estimates of
future revenue do not include any salvage value for the lease and well
equipment nor the costs of abandoning the properties.
Fairchild, Ancell & Wells, Inc. expresses no opinion as to the fair market
value of the evaluated properties.
<PAGE> 102
Carrizo Oil & Gas, Inc. Page 3
June 4, 1997
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Because of governmental
policies and uncertainties of supply and demand, the actual sales rates and the
prices actually received for the reserves along with the costs incurred in
recovering such reserves may vary from those assumptions included in this
report. Also, estimates of reserves may increase or decrease as a result of
future operations.
In evaluating the information at our disposal concerning this report, we have
excluded from our consideration all matters as to which legal or accounting,
rather than engineering, interpretation may be controlling. As in all aspects
of oil and gas evaluation, there are uncertainties inherent in the
interpretation of engineering data and, therefore, our conclusions necessarily
represent only informed professional judgments.
The titles to the properties have not been examined by Fairchild, Ancell &
Wells, Inc. nor has the actual degree or type of interest owned been
independently confirmed. We are independent petroleum engineers and geologists;
we do not own an interest in these properties and are not employed on a
contingent basis. Basic geologic and field performance data together with our
engineering work sheets are maintained on file in our office and are available
for review.
It has been a pleasure to serve you by preparing this engineering evaluation.
Yours very truly,
/s/ FAIRCHILD, ANCELL & WELLS, INC.
Fairchild, Ancell & Wells, Inc.
<PAGE> 103
======================================================
NO DEALER, SALESPERSON OR OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN THIS PROSPECTUS IN
CONNECTION WITH THE OFFERING COVERED BY THIS PROSPECTUS. IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY THE COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER
TO SELL, OR A SOLICITATION OF AN OFFER TO BUY, THE COMMON STOCK IN ANY
JURISDICTION WHERE, OR TO ANY PERSON TO WHOM, IT IS UNLAWFUL TO MAKE SUCH OFFER
OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS
NOT BEEN ANY CHANGE IN THE FACTS SET FORTH IN THIS PROSPECTUS OR IN THE AFFAIRS
OF THE COMPANY SINCE THE DATE HEREOF.
---------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary................... 1
Risk Factors......................... 10
Use of Proceeds...................... 18
Dividend Policy...................... 18
Dilution............................. 19
Capitalization....................... 20
Selected Combined Financial and
Operating Data..................... 21
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 23
Business............................. 31
Management........................... 52
Certain Transactions................. 58
Security Ownership of Certain
Beneficial Owners and Management.. 61
Description of Capital Stock......... 63
Shares Eligible for Future Sale...... 66
Underwriting......................... 68
Legal Matters........................ 69
Experts.............................. 69
Additional Information............... 70
Glossary of Certain Industry Terms... 71
Index to Financial Statements........ F-1
Letters of Petroleum Engineers....... A-1
</TABLE>
---------------------
UNTIL AUGUST 31, 1997 (25 DAYS AFTER THE COMMENCEMENT OF THE OFFERING), ALL
DEALERS EFFECTING TRANSACTIONS IN THE COMMON STOCK, WHETHER OR NOT PARTICIPATING
IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN
ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS
UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.
======================================================
======================================================
2,500,000 SHARES
[CARRIZO LOGO]
CARRIZO OIL & GAS, INC.
COMMON STOCK
($0.01 PAR VALUE)
SCHRODER & CO. INC.
JEFFERIES & COMPANY, INC.
AUGUST 6, 1997
======================================================
