-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, VC2kU40WXxYBNe2k8FILhjYySuQL8dmjXRrRIBgIFKopsV+u9OD2CVp24y9eBx1G TY8ItL5CbMNNNt1rpzqP1w== 0000950129-97-003079.txt : 19970806 0000950129-97-003079.hdr.sgml : 19970806 ACCESSION NUMBER: 0000950129-97-003079 CONFORMED SUBMISSION TYPE: S-1/A PUBLIC DOCUMENT COUNT: 2 FILED AS OF DATE: 19970805 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: CARRIZO OIL & GAS INC CENTRAL INDEX KEY: 0001040593 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760415919 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: S-1/A SEC ACT: 1933 Act SEC FILE NUMBER: 333-29187 FILM NUMBER: 97651709 BUSINESS ADDRESS: STREET 1: 14811 ST MARYS LANE STREET 2: STE 148 CITY: HOUSTON STATE: TX ZIP: 77079 BUSINESS PHONE: 2814961352 MAIL ADDRESS: STREET 1: CARRIZO OIL & GAS INC STREET 2: 14811 ST MARYS LANE STE 148 CITY: HOUSTON STATE: TX ZIP: 77079 S-1/A 1 CARRIZO OIL & GAS, INC. (AMENDMENT #3) 1 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON AUGUST 5, 1997 REGISTRATION NO. 333-29187 ================================================================================ SECURITIES AND EXCHANGE COMMISSION --------------------- AMENDMENT NO. 3 TO FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 --------------------- CARRIZO OIL & GAS, INC. (Exact name of registrant as specified in its charter) TEXAS 1311 76-0415919 (State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer incorporation or organization) Classification Code Number) Identification No.)
CARRIZO OIL & GAS, INC. 14811 ST. MARY'S LANE, SUITE 148 HOUSTON, TEXAS 77079 (281) 496-1352 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) S. P. JOHNSON IV PRESIDENT AND CHIEF EXECUTIVE OFFICER CARRIZO OIL & GAS, INC. 14811 ST. MARY'S LANE, SUITE 148 HOUSTON, TEXAS 77079 (281) 496-1352 (Name, address, including zip code, and telephone number, including area code, of agent for service) --------------------- Copies to: GENE J. OSHMAN T. MARK KELLY BAKER & BOTTS, L.L.P. VINSON & ELKINS L.L.P. 3000 ONE SHELL PLAZA 1001 FANNIN, SUITE 2500 HOUSTON, TEXAS 77002-4995 HOUSTON, TEXAS 77002-6760 (713) 229-1234 (713) 758-2222
--------------------- APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after this Registration Statement becomes effective. If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] --------------------- THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE. ================================================================================ 2 INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH STATE. SUBJECT TO COMPLETION, DATED AUGUST 5, 1997 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. It is currently anticipated that the initial public offering price will be between $11.00 and $13.00 per share. See "Underwriting" for factors to be 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.
============================================================================================================== UNDERWRITING PRICE TO DISCOUNTS AND PROCEEDS TO PUBLIC COMMISSIONS(1) COMPANY(2) - -------------------------------------------------------------------------------------------------------------- Per Share............................... $ $ $ - -------------------------------------------------------------------------------------------------------------- Total(3)................................ $ $ $ ==============================================================================================================
(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 $ , $ and $ , 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 , 1997 at the offices of Schroder & Co. Inc., New York, New York. SCHRODER & CO. INC. JEFFERIES & COMPANY, INC. , 1997 3 [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." 4 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 5 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 6 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 7 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
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) ------------- --------- -------- ----------- -------- -------- -------- ----------- ----------- 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 ======= ===== === == === ===
- --------------- (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 8 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 9 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 10 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]
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, -------------------------- ------------------- 1994 1995 1996 1996 1997 ------ ------- ------- -------- -------- (UNAUDITED) (IN THOUSANDS, EXCEPT PER SHARE DATA) 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
7 11
AS OF MARCH 31, 1997 ---------------------- AS ADJUSTED FOR THE ACTUAL OFFERING(7) ------- ----------- BALANCE SHEET DATA: Working capital............................................. $(1,758) $12,086 Property and equipment, net................................. 19,162 19,162 Total assets................................................ 23,912 38,068 Long-term debt, including current maturities................ 12,254 -- Equity...................................................... 5,407 32,060
- --------------- (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 $12.00 per share and the application of the net proceeds therefrom. 8 12 SUMMARY RESERVE AND OPERATING DATA
THREE MONTHS YEAR ENDED DECEMBER 31, ENDED MARCH 31, --------------------------- ---------------- 1994 1995 1996 1996 1997 ------- ------- ------- ------ ------- 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)........................... (0.19) 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
- --------------- 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. 9 13 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 10 14 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 15 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 16 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 17 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 18 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 19 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." 16 20 NO PRIOR PUBLIC MARKET Prior to the Offering, there has been no public market for the Common Stock. The initial public offering price will be 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 to be 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 $8.79 per share (assuming an initial public offering price of $12.00 per share). See "Dilution." 17 21 USE OF PROCEEDS The net proceeds to the Company from the Offering at an assumed initial public offering price of $12.00 per share are estimated to be approximately $26.7 million ($30.9 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." 18 22 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 an assumed initial public offering price of $12.00 per share, the adjusted pro forma net tangible book value of the Common Stock outstanding at March 31, 1997 would have been $3.21 per share, representing an immediate increase in net tangible book value of $2.49 per share to existing shareholders and an immediate dilution of $8.79 per share (the difference between the assumed initial public offering price and the net tangible book value per share after the Offering) to persons purchasing Common Stock at the assumed initial public offering price. The following table illustrates such per share dilution:
Assumed initial public offering price per share............. $12.00 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... 2.49 ----- Adjusted pro forma net tangible book value per share after giving effect to the Offering............................. 3.21 ------ Dilution in net tangible book value to the purchasers of Common Stock in the Offering.............................. $ 8.79 ======
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 (based upon an assumed initial public offering price per share of $12.00).
SHARES PURCHASED(1) TOTAL CONSIDERATION(2) --------------------- ---------------------- AVERAGE PRICE NUMBER PERCENT AMOUNT PERCENT PER SHARE ---------- ------- ----------- ------- ------------- Existing shareholders......... 7,500,000 75% $ 5,296,000 15% $ 0.71 New investors................. 2,500,000 25% 30,000,000 85% 12.00 ---------- ---- ----------- ---- Total............... 10,000,000 100% $35,296,000 100% ========== ==== =========== ====
- --------------- (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 23 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 an assumed initial public offering price of $12.00 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.
MARCH 31, 1997 ------------------------------------ PRO FORMA AS ADJUSTED PRO FORMA FOR THE AS ADJUSTED COMBINATION FOR THE ACTUAL TRANSACTIONS OFFERING ------- ------------ ----------- (IN THOUSANDS) Cash and cash equivalents................................... $ 1,500 $ 1,500 $15,656 ======= ======= ======= 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 30,909 Retained earnings......................................... 1,051 1,051 1,051 ------- ------- ------- Total shareholders' equity........................... 5,407 5,407 32,060 ------- ------- ------- Total capitalization.............................. $17,661 $17,661 $32,060 ======= ======= =======
- --------------- (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 24 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.
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) 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
21 25
AS OF MARCH 31, 1997 --------------------- AS AS OF DECEMBER 31, ADJUSTED -------------------------------- FOR THE 1993 1994 1995 1996 ACTUAL OFFERING(7) ---- ------ ------ ------- ------- ----------- (IN THOUSANDS) BALANCE SHEET DATA: Working capital..................... $(52) $ 152 $ (265) $(1,025) $(1,758) $12,086 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 38,068 Long-term debt, including current maturities........................ -- 533 3,480 9,684 12,254 -- Equity.............................. 65 452 3,381 4,596 5,407 32,060
- --------------- (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 $12.00 per share and the application of the net proceeds therefrom. 22 26 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 27 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:
1997 PERIOD COMPARED TO MARCH 31, 1996 PERIOD --------------------- ----------------------- 1996 1997 INCREASE % INCREASE -------- ---------- ---------- ---------- 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% ======== ========== ==========
- --------------- (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 28 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:
1996 PERIOD COMPARED TO DECEMBER 31, 1995 PERIOD ----------------------- ----------------------- 1995 1996 INCREASE % INCREASE ---------- ---------- ---------- ---------- Production volumes Oil and condensate (MBbls)......... 77.6 107.3 29.7 38% Natural gas (MMcf)................. 565.3 1,272.5 707.2 125% Average sales prices(1) Oil and condensate (per Bbl)....... $ 19.64 $ 21.54 $ 1.90 10% Natural gas (per Mcf).............. 1.60 2.27 0.67 42% Operating revenues Oil and condensate................. $1,524,002 $2,310,798 $ 786,796 52% Natural gas........................ 904,046 2,883,911 1,979,865 219% ---------- ---------- ---------- Total...................... $2,428,048 $5,194,709 $2,766,661 114% ========== ========== ==========
- --------------- (1) Including impact of hedging. 25 29 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:
1995 PERIOD COMPARED TO DECEMBER 31, 1994 PERIOD --------------------- ----------------------- 1994 1995 INCREASE % INCREASE -------- ---------- ---------- ---------- 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% ======== ========== ==========
- --------------- * 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 30 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 31 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 28 32 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 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 29 33 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 34 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. 31 35 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 32 36 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 33 37 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 34 38 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. 35 39 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
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) ------------- --------- -------- ----------- -------- -------- ---------- ----------- ----------- 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 ======= ===== === == === ===
- --------------- (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 40 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 41 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 42 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 43 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 44 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. 41 45 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."
PROVED RESERVES(1) -------------------------------------------- DEVELOPED UNDEVELOPED TOTAL --------- ----------- ------- (DOLLARS IN THOUSANDS) 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
- --------------- (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 46 (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 47 VOLUMES, PRICES AND OIL & GAS OPERATING EXPENSE The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with the Company's sales of oil and natural gas for the periods indicated.
YEAR ENDED DECEMBER 31, THREE MONTHS ---------------------------- ENDED 1994 1995 1996 MARCH 31, 1997 ------ ------ ------ -------------- 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
- --------------- (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.
YEAR ENDED DECEMBER 31, THREE MONTHS ------------------------ ENDED 1994 1995 1996 MARCH 31, 1997 ---- ------ ------ -------------- (IN THOUSANDS) 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 ==== ====== ====== ======
- --------------- (1) Excludes capitalized interest on unproved properties of $117,288 and $422,493 for the years ended December 31, 1995 and 1996, respectively. 44 48 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%.
THREE MONTHS YEAR ENDED DECEMBER 31, ENDED ---------------------------------------------- MARCH 31, 1994 1995 1996 1997 ------------- ------------- ------------ ------------ GROSS NET GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- --- ----- --- 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............... -- -- -- -- -- -- -- -- ==== ==== ==== ==== == === == ===
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.
COMPANY- OPERATED OTHER TOTAL ------------ ------------ ------------ GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- ---- 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 == ==== == ==== === ====
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.
DEVELOPED UNDEVELOPED ACREAGE ACREAGE TOTAL -------------- --------------- --------------- GROSS NET GROSS NET GROSS NET ------ ----- ------ ------ ------ ------ 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 ====== ===== ====== ====== ====== ======
45 49 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 50 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 51 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 52 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 53 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 54 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. 51 55 MANAGEMENT EXECUTIVE OFFICERS AND DIRECTORS The following table sets forth certain information with respect to executive officers and directors of the Company:
NAME AGE POSITION ---- --- -------- 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
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. 52 56 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 57 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
ANNUAL COMPENSATION(1) -------------------- NAME AND PRINCIPAL POSITION SALARY BONUS --------------------------- -------- -------- S. P. Johnson IV............................................ $180,000 -- President and Chief Executive Officer
- --------------- (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 54 58 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. 55 59 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 56 60 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. 57 61 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. 58 62 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, 59 63 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." 60 64 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.
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.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%
- --------------- * 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 61 65 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. 62 66 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 63 67 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. 64 68 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 65 69 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 66 70 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. 67 71 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:
NUMBER OF UNDERWRITERS SHARES ------------ --------- Schroder & Co. Inc.......................................... Jefferies & Company, Inc.................................... --------- Total............................................. 2,500,000 =========
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 $ per share. The Underwriters may allow and such dealers may reallow a concession not in excess of $ 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 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 68 72 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 will be determined by negotiation between the Company and the Representatives. Among other factors considered in determining the public offering price will be 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. 69 73 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). 70 74 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. 71 75 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. 72 76 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 77 CARRIZO OIL & GAS, INC. INDEX TO FINANCIAL STATEMENTS
PAGE ---- 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
F-1 78 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 79 CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES COMBINED BALANCE SHEETS ASSETS
AS OF DECEMBER 31, AS OF ------------------------- MARCH 31, 1995 1996 1997 ---------- ----------- ----------- (UNAUDITED) 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 ========== =========== ===========
The accompanying notes are an integral part of these combined financial statements. F-3 80 CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES COMBINED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS FOR THE YEAR ENDED DECEMBER 31, ENDED MARCH 31, ----------------------------------- --------------------- 1994 1995 1996 1996 1997 --------- ---------- ---------- -------- ---------- (UNAUDITED) 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 ========== ==========
The accompanying notes are an integral part of these combined financial statements. F-4 81 CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES COMBINED STATEMENTS OF EQUITY
RETAINED EARNINGS DEFERRED TOTAL CAPITAL (DEFICIT) COMPENSATION EQUITY ---------- ---------- ------------ ---------- 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 ========== ========== ========= ==========
The accompanying notes are an integral part of these combined financial statements. F-5 82 CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES COMBINED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED MARCH 31, ------------------------------------- ----------------------------- 1994 1995 1996 1996 1997 ---------- ---------- ----------- ------------- ------------- (UNAUDITED) 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 $ -- $ -- $ --
The accompanying notes are an integral part of these combined financial statements. F-6 83 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 8). 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 84 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 8). 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 85 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 86 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:
DECEMBER 31, ------------------------ MARCH 31, 1995 1996 1997 ---------- ----------- ----------- (UNAUDITED) 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 ========== =========== ===========
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 87 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 88 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:
DECEMBER 31, MARCH 31, ------------------------ ----------- 1995 1996 1997 ---------- ---------- ----------- (UNAUDITED) 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 ========== ========== ===========
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: 1997.................................................... $ 68,680 1998.................................................... 75,390 1999.................................................... 75,390 2000.................................................... 12,562
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 a planned initial public offering (see Note 8), 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 ($3.60) and the fair value of Carrizo's common stock when such options were granted (using the $12.00 per share estimate of the initial public offering common stock price as an estimate of fair value). Such deferred compensation is F-12 89 CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 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: Net Income..................... As reported $1,099,851 Pro forma $1,038,490 EPS............................ As reported (pro forma) $ 0.14 Pro forma $ 0.13
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%. 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 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): Carrizo and its affiliated entities are anticipated to be combined in a series of transactions concurrent with the consummation of an initial public offering of common stock. 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. F-13 90 CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) Carrizo anticipates filing a registration statement on Form S-1 in June 1997 for the sale of 2,500,000 shares of common stock. The net proceeds from this sale at an assumed initial public offering price of $12.00 per share are estimated to be approximately $26.7 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. 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:
YEAR ENDED DECEMBER 31 ------------------------------------ 1994 1995 1996 -------- ---------- ---------- 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 ======== ========== ==========
- --------------- (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 reservoirs under existing economic and operating conditions. Proved developed reserves are F-14 91 CARRIZO OIL & GAS, INC. AND AFFILIATED ENTITIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 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:
BARRELS OF OIL, CONDENSATE AND NATURAL GAS LIQUIDS ----------------------------------- AT DECEMBER 31, ----------------------------------- 1994 1995 1996 --------- --------- --------- 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 ========= ========= =========
THOUSANDS OF CUBIC FEET OF NATURAL GAS ---------------------------------- AT DECEMBER 31, ---------------------------------- 1994 1995 1996 ------- --------- ---------- 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 ======= ========= ==========
F-15 92 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:
YEAR ENDED DECEMBER 31, ---------------------------------------- 1994 1995 1996 ----------- ----------- ------------ 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 =========== =========== ============
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 93 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:
YEAR ENDED DECEMBER 31, --------------------------------------- 1994 1995 1996 ----------- ----------- ----------- 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 =========== =========== ===========
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 94 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 -------------------------------------------------
Proved -------------------------------------------------------------------------------------- Developed Total ------------------------------------------ Producing Non-Producing Undeveloped Proved ------------------ -------------------- ------------------- ---------------- 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
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. 95 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 96 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. 97 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 98 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. 99 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. 100 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. 101 [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
Future Cash Flows (M$) Net -------------------------------------- Reserves Mbbls Undiscounted Discounted at 10% -------------- ------------ ----------------- 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
102 Carrizo Oil & Gas, Inc. Page 2 June 4, 1997 FUTURE CASH FLOW - TOTAL PROJECT BY YEAR
Future Cash Flows (M$) ----------------------------------- Discounted Year Undiscounted at 10% --- ------------ ---------- 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
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. 103 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. 104 ====================================================== 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
PAGE ---- 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
--------------------- UNTIL , 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. , 1997 ====================================================== 105 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION. The following are the estimated expenses (other than underwriting discounts and commission) of the issuance and distribution of the securities being registered, all of which shall be paid by the Company: Securities and Exchange Commission Registration Fee......... $ 11,326 NASD Filing Fee............................................. 4,238 Nasdaq National Market Fees................................. 42,500 Printing Expenses........................................... 100,000 Legal Fees and Expenses..................................... 390,000 Accountants' Fees and Expenses.............................. 400,000 Blue Sky Fees and Expenses.................................. 10,000 Transfer Agent and Registrar Fees........................... 12,000 Miscellaneous Expenses...................................... 229,936 ---------- Total............................................. $1,200,000 ==========
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Article 2.02-1 of the Texas Business Corporation Act provides that a corporation may indemnify any director or officer who was, is or is threatened to be made a named defendant or respondent in a proceeding because he is or was a director or officer, provided that the director or officer (i) conducted himself in good faith, (ii) reasonably believed (a) in the case of conduct in his official capacity, that his conduct was in the corporation's best interests or (b) in all other cases, that his conduct was at least not opposed to the corporation's best interests and (iii) in the case of any criminal proceeding, had no reasonable cause to believe his conduct was unlawful. Subject to certain exceptions, a director or officer may not be indemnified if the person is found liable to the corporation or if the person is found liable on the basis that he improperly received a personal benefit. Under Texas law, reasonable expenses incurred by a director or officer may be paid or reimbursed by the corporation in advance of a final disposition of the proceeding after the corporation receives a written affirmation by the director or officer of his good faith belief that he has met the standard of conduct necessary for indemnification and a written undertaking by or on behalf of the director or officer to repay the amount if it is ultimately determined that the director or officer is not entitled to indemnification by the corporation. Texas law requires a corporation to indemnify an officer or director against reasonable expenses incurred in connection with the proceeding in which he is named defendant or respondent because he is or was a director or officer if he is wholly successful in defense of the proceeding. Texas law also permits a corporation to purchase and maintain insurance or another arrangement on behalf of any person who is or was a director or officer against any liability asserted against him and incurred by him in such a capacity or arising out of his status as such a person, whether or not the corporation would have the power to indemnify him against that liability under Article 2.02-1. 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' receipt of such benefits. These provisions cover, among other things: (i) specification II-1 106 of the method of determining entitlement to indemnification and the selection of independent counsel that will in some cases make such determination, (ii) specification of certain time periods by which certain payments or determinations must be made and actions must be taken and (iii) the establishment of certain presumptions in favor of an indemnitee. The benefits of certain of these provisions are available to an indemnitee only if there has been a change in control (as defined). 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 (1) in respect of the deductibles for such insurance policies, (2) that exceed the liability limits of such insurance policies and (3) that are available, were available or which become available 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. The above discussion of Article 2.02-1 of the Texas Business Corporation Act and of the Company's Bylaws is not intended to be exhaustive and is respectively qualified in its entirety by such statute and the Bylaws. Reference is made to the form of the Underwriting Agreement, filed as Exhibit 1.1 hereto, which contains provisions for indemnification of the Company, its directors, officers and any controlling persons by the Underwriters against certain liabilities for information furnished by the Underwriters. ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES. Carrizo Oil & Gas, Inc. has not sold any securities, registered or otherwise, within the past three years, except as set forth below. Carrizo Oil & Gas, Inc. has granted to employees options to purchase 222,120 shares of Common Stock. Such transaction was exempt from the registration requirements of the Securities Act by virtue of Rule 701 thereunder. Carrizo Oil & Gas, Inc. expects to sell approximately 2,290,000 shares of Common Stock in the Combination Transactions. Such transaction is exempt from the registration requirements of the Securities Act by virtue of Section 4(2) thereof as a transaction not involving any public offering. ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a) Exhibits.
EXHIBIT NUMBER DESCRIPTION ------- ----------- +1.1 -- Form of Underwriting Agreement. +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997. +3.1 -- Amended and Restated Articles of Incorporation of the Company. +3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915). +4.1 -- Form of certificate representing Common Stock. +4.2 -- Secured Reducing Revolving Line of Credit by and between Encinitas Partners Ltd. And Compass Bank dated June 26, 1996.
II-2 107
EXHIBIT NUMBER DESCRIPTION ------- ----------- +4.3 -- First Amendment to Loan Agreement by and between Encinitas Partners Ltd. and Compass Bank dated December 6, 1996. +4.4 -- Secured Reducing Revolving Line of Credit by and between the Company and Compass Bank dated December 6, 1996. +4.5 -- First Amendment to Loan Agreement by and between the Company and Compass Bank dated April 4, 1997. +4.6 -- Second Amendment to Loan Agreement by and between the Company and Compass Bank dated May 15, 1997. +4.7 -- Third Amendment to Loan Agreement by and between the Company and Compass Bank dated June 26, 1997. +4.8 -- Fourth Amendment to Loan Agreement by and between the Company and Compass Bank dated June 27, 1997 -- The Company is a party to several debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the Company agrees to furnish a copy of such instruments to the Commission upon request. +5.1 -- Opinion of Baker & Botts, L.L.P. +10.1 -- Incentive Plan of the Company. +10.2 -- Employment Agreement between the Company and S. P. Johnson IV. +10.3 -- Employment Agreement between the Company and Frank A. Wojtek. +10.4 -- Employment Agreement between the Company and Kendall A. Trahan. +10.5 -- Employment Agreement between the Company and George Canjar. +10.6 -- Form of Indemnification Agreement between the Company and each of its directors and executive officers. +10.7 -- Registration Rights Agreement by and among the Company, Paul B. Loyd, Jr., Steven A. Webster, S. P. Johnson IV, Douglas A. P. Hamilton and Frank A. Wojtek dated as of June 6, 1997. +10.8 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek. +10.9 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek. +21.1 -- Subsidiaries of the Company. 23.1 -- Consent of Arthur Andersen LLP. +23.2 -- Consent of Ryder Scott Company. +23.3 -- Consent of Fairchild, Ancell & Wells, Inc. +23.4 -- Consent of Baker & Botts, L.L.P. (included in Exhibit 5.1). +24.1 -- Power of Attorney (included on the signature page of this Registration Statement). +27.1 -- Financial Data Schedule.
- --------------- + Previously filed. (b) Financial Statement Schedules. Schedule I -- Condensed Financial Information of Registrant II-3 108 All other schedules are omitted because they are not applicable or because the required information is contained in the financial statements or notes thereto included in this Registration Statement. ITEM 17. UNDERTAKINGS. The undersigned registrant hereby undertakes to provide to the Underwriters, at the closing specified in the Underwriting Agreement, certificates representing the shares of Common Stock offered hereby in such denominations and registered in such names as required by the Underwriters to permit prompt delivery to each purchaser. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. The undersigned registrant hereby undertakes that: (1) For the purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as a part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective. (2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the Offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. II-4 109 SIGNATURES PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, THE REGISTRANT HAS DULY CAUSED THIS AMENDMENT TO THE REGISTRATION STATEMENT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY OF HOUSTON, STATE OF TEXAS, ON THE 5TH DAY OF AUGUST, 1997. CARRIZO OIL & GAS, INC. By: /s/ S. P. JOHNSON IV ---------------------------------- S. P. Johnson IV President and Chief Executive Officer Pursuant to the requirements of the Securities Act of 1933, this Amendment to the Registration Statement has been signed by the following persons in the capacities indicated on August 5, 1997.
SIGNATURE TITLE --------- ----- /s/ S. P. JOHNSON IV President, Chief Executive Officer and - ----------------------------------------------------- Director (Principal Executive Officer) S. P. Johnson IV /s/ FRANK A. WOJTEK Chief Financial Officer, Vice President, - ----------------------------------------------------- Secretary, Treasurer and Director (Principal Frank A. Wojtek Financial Officer and Principal Accounting Officer) * Chairman of the Board - ----------------------------------------------------- Steven A. Webster * Director - ----------------------------------------------------- Douglas A. P. Hamilton * Director - ----------------------------------------------------- Paul B. Loyd, Jr. *By /s/ FRANK A. WOJTEK ------------------------------------------------ Frank A. Wojtek Attorney-in-Fact
II-5 110 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION ------- ----------- +1.1 -- Form of Underwriting Agreement. +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997. +3.1 -- Amended and Restated Articles of Incorporation of the Company. +3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915). +4.1 -- Form of certificate representing Common Stock. +4.2 -- Secured Reducing Revolving Line of Credit by and between Encinitas Partners Ltd. And Compass Bank dated June 26, 1996. +4.3 -- First Amendment to Loan Agreement by and between Encinitas Partners Ltd. and Compass Bank dated December 6, 1996. +4.4 -- Secured Reducing Revolving Line of Credit by and between the Company and Compass Bank dated December 6, 1996. +4.5 -- First Amendment to Loan Agreement by and between the Company and Compass Bank dated April 4, 1997. +4.6 -- Second Amendment to Loan Agreement by and between the Company and Compass Bank dated May 15, 1997. +4.7 -- Third Amendment to Loan Agreement by and between the Company and Compass Bank dated June 26, 1997. +4.8 -- Fourth Amendment to Loan Agreement by and between the Company and Compass Bank dated June 27, 1997 -- The Company is a party to several debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the Company agrees to furnish a copy of such instruments to the Commission upon request. +5.1 -- Opinion of Baker & Botts, L.L.P. +10.1 -- Incentive Plan of the Company. +10.2 -- Employment Agreement between the Company and S. P. Johnson IV. +10.3 -- Employment Agreement between the Company and Frank A. Wojtek. +10.4 -- Employment Agreement between the Company and Kendall A. Trahan. +10.5 -- Employment Agreement between the Company and George Canjar. +10.6 -- Form of Indemnification Agreement between the Company and each of its directors and executive officers. +10.7 -- Registration Rights Agreement by and among the Company, Paul B. Loyd, Jr., Steven A. Webster, S. P. Johnson IV, Douglas A. P. Hamilton and Frank A. Wojtek dated as of June 6, 1997. +10.8 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek. +10.9 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek. +21.1 -- Subsidiaries of the Company. 23.1 -- Consent of Arthur Andersen LLP.
111
EXHIBIT NUMBER DESCRIPTION ------- ----------- +23.2 -- Consent of Ryder Scott Company. +23.3 -- Consent of Fairchild, Ancell & Wells, Inc. +23.4 -- Consent of Baker & Botts, L.L.P. (included in Exhibit 5.1). +24.1 -- Power of Attorney (included on the signature page of this Registration Statement). +27.1 -- Financial Data Schedule.
- --------------- + Previously filed. EX-23.1 2 CONSENT OF ARTHUR ANDERSEN LLP 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the use of our report (and to all references to our Firm) included in or made a part of this registration statement. ARTHUR ANDERSEN LLP Houston, Texas August 5, 1997 -----END PRIVACY-ENHANCED MESSAGE-----