-----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, D4bnolG3JGUzM54YvMCUlrmchh2Av0uGXF9oyHoVhwrhVtYzq2AYkbOGCiuHADmf klv6zFpRMX+kbkotNMJZGQ== 0000950129-00-001543.txt : 20000331 0000950129-00-001543.hdr.sgml : 20000331 ACCESSION NUMBER: 0000950129-00-001543 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 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: 10-K SEC ACT: SEC FILE NUMBER: 000-29187-87 FILM NUMBER: 587882 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 10-K 1 CARRIZO OIL & GAS, INC. - DATED 12/31/99 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 COMMISSION NO. 0-22915 CARRIZO OIL & GAS, INC. (Exact name of registrant as specified in its charter) TEXAS 76-0415919 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 14811 ST. MARY'S LANE, SUITE 148 77079 Houston, Texas (Zip Code) (Principal executive offices) Registrant's telephone number, including area code: (281) 496-1352 Securities Registered Pursuant to Section 12(g) of the Act: COMMON STOCK, $.01 PAR VALUE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] At March 23, 2000, the aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $14.2 million based on the closing price of such stock on such date of $4.00. At March 23, 2000, the number of shares outstanding of the registrant's Common Stock was 14,011,364. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrant's 2000 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 1999. ================================================================================ 2 TABLE OF CONTENTS PART I...................................................................... 3 Item 1. and Item 2. Business and Properties............................... 3 Item 3. Legal Proceedings................................................. 22 Item 4. Submission of Matters to a Vote of Security Holders............... 22 Executive Officers of the Registrant...................................... 22 PART II..................................................................... 23 Item 5. Market for Registrant's Common Stock and Related Shareholder Matters................................................................ 23 Item 6. Selected Financial Data........................................... 24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................................. 26 Item 7A. Qualitative and Quantitative Disclosures About Market Risk....... 33 Item 8. Financial Statements and Supplementary Data....................... 33 Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure............................................... 33 PART III.................................................................... 33 Item 10. Directors and Executive Officers of the Registrant............... 33 Item 11. Executive Compensation........................................... 33 Item 12. Security Ownership of Certain Beneficial Owners and Management... 34 Item 13. Certain Relationships and Related Party Transactions............. 34 PART IV..................................................................... 34 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 34
2 3 PART I ITEM 1. AND ITEM 2. BUSINESS AND PROPERTIES GENERAL Carrizo Oil & Gas, Inc. ("Carrizo" or the "Company") is an independent oil and gas company engaged in the exploration, development, exploitation and production of natural gas and crude oil. The Company's operations are currently focused onshore in proven oil and gas producing trends along the Gulf Coast, primarily in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends. The Company believes that the availability of economic onshore 3-D seismic surveys has fundamentally changed the risk profile of oil and gas exploration in these regions. Recognizing this change, the Company has aggressively sought to control significant prospective acreage blocks for targeted 3-D seismic surveys. During the period from 1996 through December 1999 the Company assembled over 400,000 gross acres under lease or option and acquired 45 3-D seismic surveys with over 1,800 square miles of 3-D data. 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. After the 3-D data is processed and analyzed, the Company seeks to retain such acreage as it deems to be prospective and usually releases such acreage as it believes is not prospective. As of December 31, 1999, the Company had 195,464 gross acres under lease or option, most of which is covered by 3-D seismic data. From the 3-D data Carrizo has amassed a large drillsite inventory, with as many as 300 gross wells that could be drilled over the next four years, assuming sufficient capital resources. In addition, the Company anticipates that as its existing 3-D seismic data is further evaluated, and 3-D seismic data is acquired over the balance of its acreage, additional prospects will be generated for drilling beyond 2003. The Company's primary drilling targets in the past have been shallow (from 4,000 to 7,000 feet), normally pressured reservoirs that generally involve moderate cost (typically $150,000 to $400,000 per completed well) and risk. Many of these drilling prospects also have secondary, deeper, over-pressured targets which have greater economic potential but generally involve higher cost (typically $1 million to $3 million per completed well) and risk. The Company usually seeks to sell a portion of these deeper prospects to reduce its exploration risk and financial exposure while still allowing the Company to retain significant upside potential. The Company operates the majority of its projects through the exploratory phase but may relinquish operator status to qualified partners in the production phase to control costs and focus resources on the higher-value exploratory phase. As of December 31, 1999, the Company operated 63 producing oil and gas wells, which accounted for 34 percent of the wells in which the Company had an interest. The Company has experienced increases in reserves, production and EBITDA from its inception in 1993 due to its 3-D based drilling and development activities. From January 1, 1996 to December 31, 1999, the Company participated in the drilling of 179 gross wells (57.5 net) with a commercial well success rate of approximately 63 percent. This drilling success contributed to the Company's total proved reserves as of December 31, 1999 of 40.6 Bcfe with a PV-10 Value of $51.1 million. During 1999, the Company added 5.5 Bcfe to proved reserves through drilling, however total proved reserves also increased approximately 8.5 Bcfe, primarily as a result of improved oil and natural gas prices, offset by production. The Company's production increased 23 percent from 3,495 MMcfe for the year ended December 31, 1998 to 4,311 MMcfe for the year ended December 31, 1999, and EBITDA increased 103 percent from $2,422,000 for the year ended December 31, 1998 to $4,921,000 for the year ended December 31, 1999 due to higher production levels, significantly higher oil and gas sales prices, and the implementation of cost control measures. Certain terms used herein relating to the oil and natural gas industry are defined in "Glossary of Certain Industry Terms" below. EXPLORATION APPROACH The Company's strategy has been to rapidly accumulate large amounts of 3-D seismic data along prolific, producing trends of the onshore Gulf Coast after obtaining options to lease areas covered by the data. The Company then uses 3-D seismic data to identify or evaluate prospects before drilling the prospects that fit its risk/reward criteria. The Company typically seeks to explore in locations within its core areas of expertise that it believes have (i) numerous accumulations of normally pressured reserves at shallow depths and in geologic traps that are difficult to define without the interpretation of 3-D seismic data and (ii) the potential for large accumulations of deeper, over-pressured reserves. As a result of the increased availability of economic onshore 3-D seismic surveys and the improvement and increased affordability 3 4 of data interpretation technologies, the Company has relied almost exclusively on the interpretation of 3-D seismic data in its exploration strategy. The Company generally does not invest any substantial portion of the costs for an exploration well without first interpreting 3-D seismic data. The principal advantage of 3-D seismic data over traditional 2-D seismic analysis is that it affords the geoscientist the ability to interpret a three dimensional cube of data representing a specific project area as compared to interpreting between widely separated two dimensional vertical profiles. As a consequence, the geoscientist is able to more fully and accurately evaluate prospective areas, improving the probability of drilling commercially successful wells in both exploratory and development drilling. The use of 3-D seismic allows the geoscientist to identify and use areas of irregular sand geometry to augment or replace structural interpretation in the identification of potential hydrocarbon accumulations. Additionally, detailed analysis and correlation of the 3-D seismic response to lithology and contained fluids assist geoscientists in identifying and prioritizing drilling targets. Because 3-D analysis is completed over an entire target area cube, shallow, intermediate and deep objectives can be analyzed. Additionally, the more precise structural definition allowed by 3-D seismic data combined with integration of available well and production data assists in the positioning of new development wells. The Company has sought to obtain large volumes of 3-D seismic data either by participating in large seismic data acquisition programs either alone or pursuant to joint venture arrangements with other energy companies, or through "group shoots" in which the Company shares the costs and results of seismic surveys. By participating in joint ventures and group shoots, the Company is able to share the up-front costs of seismic data acquisition and interpretation, thereby enabling it to participate in a larger number of projects and diversify exploration costs and risks. Most of the Company's operations are conducted through joint operations with industry participants. As of December 31, 1999, the Company was actively involved in 41 project areas. The Company's primary strategy for acreage acquisition is to obtain leasing options covering large geographic areas in connection with 3-D seismic surveys. Prior to conducting proprietary surveys, the Company typically seeks to acquire seismic permits that include options to lease the acreage, thereby ensuring the price and availability of leases on drilling prospects that may result upon completing a successful seismic data acquisition program over a project area. The Company generally attempts to obtain these options covering at least 80 percent of the project area for these proprietary surveys. The size of these surveys has ranged from 10 to 80 square miles. When the Company participates in 3-D group shoots, it generally seeks prospective leases as quickly as possible following interpretation of the survey. In connection with some group shoots in which the Company believes that competition for acreage may be especially strong, the Company may seek to obtain lease options or leases in prospective areas prior to the receipt or interpretation of 3-D seismic data. The Company maintains a flexible and diversified approach to project identification by focusing on the estimated financial results of a project area rather than limiting its focus to any one method or source for obtaining leads for new project areas. The Company's current project areas resulted from leads developed by its project generation network that includes small, independent "prospect generators", the Company's joint venture partners and the Company's internal staff. The Company believes that it has been able to increase the number of potential projects and reduce its costs through the use of these outside sources of project generation. When identifying specific drillsites from within a project area, the Company relies upon its own geoscientists. 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 17 years of industry experience, in many cases with major and large independent oil companies, including Shell Oil Company, Vastar Resources, Inc., Pennzoil Company and Tenneco Inc. The Company generally seeks to obtain lease operator status and control over field operations, and in particular seeks to control decisions regarding 3-D survey design parameters and drilling and completion methods. As of December 31, 1999, the Company operated 63 producing oil and natural gas wells. The Company emphasizes preplanning in project development to lower capital and operational costs and to efficiently integrate potential well locations into the existing and planned infrastructure, including gathering systems and other surface facilities. In constructing surface facilities, the Company seeks to use reliable, high quality, used equipment in place of new equipment to achieve cost savings. The Company also seeks to minimize cycle time from drilling to hook-up of wells, thereby accelerating cash flow and improving ultimate project economics. The Company seeks to use advanced production techniques to exploit and expand its reserve base. Following the discovery of 4 5 proved reserves, the Company typically continues to evaluate its producing properties through the use of 3-D seismic data to locate undrained fault blocks and identify new drilling prospects and performs further reserve analysis and geological field studies using computer aided exploration techniques. The Company seeks to integrate its 3-D seismic data with reservoir characterization and management systems through the use of geophysical workstations which are compatible with industry standard reservoir simulation programs. SIGNIFICANT PROJECT AREAS This section is an explanation and detail of some relevant project groupings from the overall inventory of seismic data and prospects. It is difficult to categorize many of the 3D projects because they were originally screened and selected for multiple objectives. The discussion below however, highlights the project areas that include a majority of the expected drilling targets over the next 12 to 18 months. 3-D PROJECT SUMMARY CHART As of December 31, 1999
SQ. 2000 MILES POSSIBLE SEISMIC GROSS NET FOCUS AREA 3D Project OF SEISMIC 3D ACQUISITION ACREAGE ACREAGE ---------- -------------- ------------- ---------------- ------- ------- TEXAS WILCOX AREAS Cabeza Creek 65 25 3,705 1,815 Buckeye 62 20 6,420 2,932 Metro 30 15 6,601 1,497 Cologne 40 -- 7,134 1,496 Western-Duval 340 -- 936 468 STS 65 -- 6,731 2,212 TEXAS FRIO/VICKSBURG/YEGUA AREAS Matagorda 51 -- 7,520 4,387 Driscoll 84 -- 6,192 1,479 Ganado 32 -- 13,682 5,680 Western-Starr 320 -- 3,783 2,642 Jones Branch -- 967 302 Rpp Welder 60 -- 8,144 1,853 SOUTHEAST TEXAS AREAS Cedar Point 30 -- 5,665 1,336 Liberty 52 -- 3,823 1,295 Rusk / Nacogdoches -- 42 23,513 7,538 LOUISIANA AREAS -- North Tigre Lagoon 6 -- 534 107 West Bay -- 6 217 217 ------- ------- ------- ------- Subtotal 1,237 108 105,567 37,256 OTHER PROJECTS (24 PROJECTS) 604 -- 89,897 29,569 ------- -------- ------- ------- Total 1,841 108 195,464 66,825 ======= ======== ======= =======
TEXAS - WILCOX AREAS The prolific Wilcox trend in South Texas is a primary area of exploration and development focus for Carrizo. The Company has a total of 754 square miles of 3D seismic data that covers potential Wilcox formation development opportunities. Wilcox wells often have relatively deeper targets with higher reserve potential and higher risk than many of the Company's other wells. Several key Wilcox project areas are discussed below and represent a significant portion of the expected 2000 and early 2001 drilling inventory. Goliad County - Cabeza Creek Project Area The primary opportunities at the 65 square mile Cabeza Creek Project include exploitation of historical producing closures, development of deeper objectives on proven structures and large deep exploration opportunities targeting known reservoir intervals. The Company commenced drilling in the Cabeza Creek Project Area with the Wilcox J1 prospect well which was drilled in March 2000 and is currently being completed. The shallow development objectives were completed and appear to support another well location for immediate consideration while the deeper exploration section verified sand, hydrocarbons and improved the risk profile for another test planned in 2000. The Company anticipates drilling between one and three additional wells during the next 12 months pending reservoir performance and the sale of promoted interests in the deeper opportunities to industry partners. The average working interest owned by Carrizo in the Cabeza Creek acreage is approximately 49 percent. Live Oak County - Buckeye Project Area The 62 square mile Buckeye Project Area is centrally located in Carrizo's Wilcox area of interest in Bee and Live Oak Counties, Texas, and includes a series of prospects targeting the Luling through Tom Lyne Wilcox sands. The initial test well has an expected total depth of 15,800 feet and is planned for drilling during the first half of 2000. If the well is successful, the Company believes that two additional closures could provide significant follow-up exploration and development potential. The average working interest owned by Carizzo in the Buckeye acreage is approximately 46 percent. Cologne Wilcox Project Area The Cologne Wilcox prospects are three large expanded Upper Wilcox structures in a single fault block within the 40 square mile Cologne Project Area in Victoria and Goliad Counties, Texas. The initial test well is currently being drilled and has a targeted total depth of approximately 16,500 feet. The well is primarily a test which, if successful, would attempt to exploit improved deliverability with modern frac technology and take advantage of expected improved reservoir properties on top of the structure. In addition, below 15,500 feet, the well will also test a stratigraphically deeper section that the Company correlates with productive sands in the surrounding area. Two additional closures along a large regional fault could provide significant follow-up exploitation potential. Carrizo has approximately a seven percent working interest in the initial test well and approximately a 20 percent working interest in the other two potential follow-up structures. Dewitt County - Metro Project Area The 30 square mile Metro Project Area is located along the northern and eastern boundaries of Carrizo's Wilcox area of interest in Dewitt County, Texas. The Company drilled two successful Wilcox wells in the project area in 1998 and 1999. Offset competitors have recently been successful in testing slightly deeper stratigraphic intervals, which the Company believes has improved the probability of success on identified deeper opportunities in the Metro Project Area. Additional 3D seismic data will be available to Carrizo and its partners in 2000 to help to further 5 6 define closure elements on prospects both within and peripheral to the original 3D shoot boundaries. Carrizo and its partners plan to drill a Wilcox well to test the deeper opportunities during 2000. Carrizo has approximately a 25 percent working interest in the project area. Western Duval Project Area Carrizo's Western Duval Project Area consists of non-exclusive license rights to 320 square miles of speculative 3D data along the southern and western limits of Carrizo's Wilcox area of interest within Webb and Duval Counties, Texas. The Company is planning to drill a test well during the second quarter of 2000, with potential follow up drilling in the second half of 2000. The Company expects to identify additional drilling prospects and is working to secure leases over the areas it believes has the highest potential. STS Project Area The STS Project Area is along the updip portion of the Company's Wilcox area of interest and includes 65 square miles of 3D data straddling LaSalle and McMullen Counties, Texas. Although numerous formations are found to be productive in the area (including a 1999 Carrizo Olmos formation discovery), the Wilcox formation represents an attractive risk/reward target. The Company is presently focusing on several Wilcox opportunities based upon a successful initial test well, in which Carrizo has a 22.375 percent working interest, which recently commenced production at a rate of approximately 100 BOPD. The Company is planning to drill at least one follow up well and to test at least one additional structure in 2000. Further appraisal drilling in the Olmos formation is also being evaluated. TEXAS FRIO/VICKSBURG/YEGUA AREAS This combined area trend sometimes overlaps but is generally closer to the Texas coast than the Wilcox areas discussed above. This is an area of expected continued focus for Carrizo in 2000 and future years. In any particular target or prospect, the Frio is usually a shallower formation, while the Yegua and Vicksburg are generally relatively deeper formations. The Company has a total of 918 square miles of 3D seismic data that covers development potential within the Frio, Vicksburg and Yegua sands. Several key areas are discussed below which represent a significant portion of 2000 and 2001 drilling inventory. Matagorda Project Area The 51 square mile Matagorda Project Area was an area of significant drilling activity and success for the Company in 1999. The Company expects to further develop its leasehold interest in 2000 and beyond. The Company has drilled six wells to date in the Matagorda Project Area, of which four have been successful. The "Fondren-Letulle #1" and "Burkhart #1" wells drilled in late 1999, in which the Company has a 30 percent working interest, continue to produce at a combined rate of 28,200 Mcfe per day as of March 1, 2000. The Company controls over 5,000 acres under lease in the project area, including a 4,200 acre lease in which the Company has a 96 percent working interest. The Company plans to drill six wells in the area in 2000. The Company's expected working interest in these prospects is expected to be approximately 50 percent. Driscoll Project Area The Company continued to prioritize and lease the identified Yegua and Frio prospects in the 84 square mile Driscoll Project Area during 1999. The Company plans to drill two wells in this area in 2000. This area, which lies in Jim Wells and Duval counties in Texas has experienced high industry activity in both the pressured Yegua and shallow Frio formations. The 3D seismic data is being evaluated for additional processing to further highgrade the numerous opportunities. Carrizo has approximately a 24 percent working interest in the project area. Ganado Project Area The Ganado Project Area is located in Ganado and Wharton Counties, Texas and targets both amplitude supported Frio and expanded Yegua opportunities. The initial Frio test well was successfully drilled in February of 2000 and tested at approximately 750 Mcf per day. Carrizo has a 25 percent working interest in this well which is expected to commence production in April 2000. The Company plans to drill additional Frio wells and a Yegua prospect in the area in 2000. Western-Starr Project Area The Company has obtained a non-exclusive license to 340 square miles of 3D seismic data which covers Frio and Vicksburg producing trends in Starr and Hildalgo Counties. The Company and its working interest partners have drilled 29 wells in the project area since 1996, 6 7 resulting in 20 producing wells. Carrizo is continuing to develop prospects from this data and acquire leases, and plans to drill at least one Vicksburg test in 2000. Carrizo's working interest in its leases within this project area averages approximately 50%. RPP Welder Project Area Additional reprocessing of the 60 square mile RPP 3-D survey data has provided additional seismic attributes to help prioritize the numerous Frio and Vicksburg prospects identified in the project area, which is located in Refugio and San Patricio Counties, Texas. The Company participated in four wells drilled in the project area during 1999, of which three were successful. Three to six additional wells are planned in 2000. Carrizo has an average 17 percent working interest in the project area. SOUTHEAST TEXAS AREAS Carrizo has acquired approximately 82 square miles of 3-D data over its Southeast Texas project areas which are focused primarily on the Yegua and Vicksburg formations. The Company expects that these areas will constitute a significant portion of its 2000 and 2001 drilling programs. Carrizo is considering additional purchases of 3-D data during 2000 to further exploit successful trends. Chambers County - Cedar Point Project Area The Cedar Point Project Area is located in Chambers County, Texas, adjacent to Trinity Bay. The 30 square mile 3-D survey acquired in late 1998 targets the Vicksburg and lower Frio formations. The initial test well, the "USX Hematite #1", in which Carrizo has a 14 percent working interest was drilled and successfully completed in late 1999. The well commenced production at a rate of over 16,000 Mcfe per day and continues to produce at a rate of 15,200 Mcfe per day as of March 1, 2000. The Company has identified four additional prospects on leased acreage which the Company believes exhibit similar seismic signatures within the same stratigraphic interval as the Hematite well. The Company has a 28 percent working interest in these prospects, the first of which is planned to spud during the second quarter of 2000. Liberty Project Area Carrizo has identified and leased prospects ranging from the Frio to the Cook Mountain formations within the 52 square mile 3-D survey acquired in 1999 in the Liberty Project Area in Liberty County, Texas. An initial Frio test well, in which the Company has a 43.75 percent working interest, was drilled and successfully completed in March 2000 and is awaiting pipeline hookup to commence production. Carrizo is currently evaluating the drilling sequence of four additional prospects, with the next well expected to spud during April 2000. In addition, a Cook Mountain sand amplitude-supported prospect is targeted for drilling in mid 2000. Carrizo is the operator and has approximately an 85 percent working interest in the properties in the project area. Rusk - Nacogdoches Project Area Carrizo has acquired 7,538 net acres of leases and options in the Rusk - Nacogdoches project areas located in Rusk and Cherokee Counties, Texas. The projects target the James Lime, Travis Peak, Pettet and Cotton Valley formations. There has been recent successful horizontal drilling activity in the area by others in addition to vertical James Lime production in the Trawick field which is adjacent to a portion of the Company's acreage. Carrizo has a 58 percent working interest in the project area and is currently negotiating with industry partners to sell a portion of the interest in exchange for a drilling commitment and lease reimbursement. The Company is also considering whether to acquire certain 3-D seismic data covering a portion of the average held which is expected to become available in 2000. LOUISIANA North Tigre Lagoon The North Tigre Lagoon prospect well was spud during late March 2000. The well, located in Vermilion Parish, Louisiana, targets lower Miocene sands. Carrizo is the operator and has approximately a 25% working interest in this project area. West Bay 7 8 Carrizo is currently resolving participation interests with potential partners and plans to spud the West Bay Prospect well during May of 2000. The prospect is located in Plaquemine Parish, Louisiana. Carrizo estimates its average working interest in the properties in this project area at 25 to 50% depending on the amount of acreage developed. CAMP HILL PROJECT The Company owns interests in eight leases totaling approximately 900 gross acres in the Camp Hill field in Anderson County, Texas. The Company currently operates six of these leases. During the year ended December 31, 1999, the project produced 72 barrels per day of 19 API gravity oil. The project produces from a depth of 500 feet and utilizes a tertiary steam drive as an enhanced oil recovery process. Although efficient at maximizing oil recovery, the steam drive process is relatively expensive to operate because natural gas or produced crude is burned to create the steam injectant. Lifting costs during the year ended December 31, 1999 averaged $10.40 per barrel ($1.73 per Mcfe). In response to lower commodity prices, steam injection was reduced in November 1998. Because profitability increases when natural gas prices drop relative to oil prices, the project is a natural hedge against decreases in natural gas prices relative to oil prices. The crude oil produced, although viscous, commands a higher price (an average premium of $.75 per barrel during the year ended December 31, 1999) than West Texas intermediate crude due to its suitability as a lube oil feedstock. As of December 31, 1999, the Company had 4.64 million barrels of proved oil reserves in this project, with 841.9 MBbls of oil currently developed. The Company anticipates that it will drill additional wells and increase steam injection to develop the proved undeveloped reserves in this project, with the timing and amount of expenditures depending on the relative prices of oil and natural gas. The Company has an average working interest of 92.5 percent in its leases in this field and an average net revenue interest of 74.0 percent. 8 9 JONES BRANCH PROPERTIES During November 1998, the Company acquired an interest in four oil and gas producing properties along with rights to participate in certain exploration prospects (primarily in the Wilcox formation) in Wharton County, Texas, including associated rights of access to certain 2-D and 3-D seismic data and related information. The Company has an average working interest of 31.3 percent and an average net revenue interest of 23.7 percent in the properties. OTHER PROJECT AREAS In addition to the project areas described above, the Company has 24 additional project areas in various stages of development as of December 31, 1999. These project areas are located in the onshore Texas and Louisiana Gulf Coast regions. The Company is in the process of evaluating and acquiring interests with respect to most of these project areas and as of December 31, 1999 had acquired leases and seismic options covering 89,897 gross acres. WORKING INTEREST AND DRILLING IN PROJECT AREAS The actual working interest that the Company will ultimately own in a well will vary based upon several factors including the depth, cost and risk of each well relative to the Company's strategic goals, activity levels and budget availability. From time to time some fraction of these wells may be sold to industry partners either on a prospect by prospect basis or a program basis. In addition, the Company may also contribute acreage to larger drilling units thereby reducing prospect working interest. The Company has, in the past, retained less than 100 percent working interest in its drilling prospects. References to Company property is not intended to imply that the Company has or will maintain any particular level of working interest. Although the Company is currently pursuing prospects within the project areas described above, there can be no assurance that these prospects will be drilled at all or within the expected time frame. In some project areas, the Company has budgeted for wells that are based upon statistical results of drilling activities in other project areas; these wells are subject to greater uncertainties than wells for which drillsites have been identified. The final determination with respect to the drilling of any identified drillsites or budgeted wells will be dependent on a number of factors, including (i) the results of exploration efforts and the acquisition, review and analysis of the seismic data, (ii) the availability of sufficient capital resources by the Company and the other participants for the drilling of the prospects (not all of which resources are currently available), (iii) the approval of the prospects by other participants after additional data has been compiled, (iv) the economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, (v) the financial resources and results of the Company and its partners and (vi) the availability of leases on reasonable terms and permitting for the prospect. There can be no assurance that these projects can be successfully developed or that any identified drillsites or budgeted wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. The Company may seek to sell or reduce all or a portion of its interest in a project area or with respect to prospects or wells within a project area. The success of the Company will be materially dependent upon the success of its exploratory drilling program. Exploratory drilling involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations my be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rights and the delivery of equipment. Although the Company believes that its use of 3-D seismic data and other advanced technologies should increase the probability of success of its exploratory wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis 2-D seismic data, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies only assist geoscientists in identifying subsurface structures and do not enable the interpreter to know whether hydrocarbons are in fact present in such structures. In addition, the use of 3-D seismic data and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and the Company could incur losses as a result of such expenditures. The Company's future drilling 9 10 activities may not be successful, and if unsuccessful, such failure will have a material adverse effect on the Company's results of operations and financial condition. There can be no assurance the Company's overall drilling success rate or its drilling success rate for activity within a particular project area will not decline. The Company may choose not to acquire option and lease rights prior to acquiring seismic data and, in many cases, the Company may identify a prospect or drilling location before seeking option or lease rights in the prospect or location. Although the Company has identified or budgeted for numerous drilling prospects, there can be no assurance that such prospects will ever be leased or drilled (or drilled within the scheduled or budgeted time frame) or that oil or natural gas will be produced from any such prospects or any other prospects. In addition, prospects may initially be identified through a number of methods, some of which do not include interpretation of 3-D or other seismic data. Wells that are currently in the Company's capital budget may be based upon statistical results of drilling activities in other 3-D project areas that the Company believes are geologically similar, rather than on analysis of seismic or other data. Actual drilling and results are likely to vary from such statistical results and such variance may be material. Similarly, the Company's drilling schedule may vary from its capital budget because of future uncertainties, including those described above. The description of a well as "budgeted" does not mean that the Company currently has or will have the capital resources to drill the well. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." OIL AND NATURAL GAS RESERVES The following table sets forth estimated net proved oil and natural gas reserves of the Company and the PV-10 Value of such reserves as of December 31, 1999. The reserve data and the present value as of December 31, 1999 were prepared by Ryder Scott Company and Fairchild, Ancell & Wells, Inc., Independent Petroleum Engineers. For further information concerning Ryder Scott's and Fairchild's estimate of the proved reserves of the Company at December 31, 1999, see the reserve reports included as exhibits to this Annual Report on Form 10-K. The PV-10 Value was prepared using constant prices as of the calculation date, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. For further information concerning the present value of future net revenue from these proved reserves, see Note 12 of Notes to Financial Statements.
PROVED RESERVES DEVELOPED UNDEVELOPED TOTAL --------- --------------- -------- (DOLLARS IN THOUSANDS) Oil and condensate (MBbls) 1,070 3,807 4,877 Natural gas (MMcf) 10,680 643 11,323 Total proved reserves (MMcfe) 17,100 23,485 40,585 PV-10 Value(1) $ 28,925 $ 22,252 $ 51,177
- ---------- (1) The PV-10 Value as of December 31, 1999 is pre-tax and was determined by using the December 31, 1999 sales prices, which averaged $23.40 per Bbl of oil, $2.35 per Mcf of natural gas and $14.63 per Bbl of NGL. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission (the "Commission"). In accordance with Commission regulations, the reserve reports used oil and natural gas prices in effect at December 31, 1999. The prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and natural gas production subsequent to December 31, 1999. 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. 10 11 There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. The reserve data set forth in this Annual Report on Form 10-K represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at different times may vary substantially and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material. In addition, the 10% discount factor, which is required by the Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general. In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent the Company conducts successful exploration and development activities or acquires properties containing proved reserves, or both, the proved reserves of the Company will decline as reserves are produced. The Company's future oil and natural gas production is, therefore, highly dependent upon its level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital investment to maintain or expand its asset base of oil and natural gas reserves would be impaired. The failure of an operator of the Company's wells to adequately perform operations, or such operator's breach of the applicable agreements, could adversely impact the Company. In addition, there can be no assurance that the Company's future exploration, development and acquisition activities will result in additional proved reserves or that the Company will be able to drill productive wells at acceptable costs. Furthermore, although the Company's revenues could increase if prevailing prices for oil and natural gas increase significantly, the Company's finding and development costs could also increase. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." VOLUMES, PRICES AND OIL & GAS OPERATING EXPENSE The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with the Company's sales of oil and natural gas for the periods indicated. The table includes the impact of hedging activities.
YEAR ENDED DECEMBER 31, 1997 1998 1999 -------- -------- -------- Production volumes Oil (MBbls) 113 140 179 Natural gas (MMcf) 2,749 2,655 3,235 Natural gas equivalent (MMcfe) 3,424 3,495 4,311 Average sales prices Oil (per Bbl) $ 18.66 $ 12.30 $ 16.60 Natural gas (per Mcf) 2.41 2.31 2.23 Natural gas equivalent (per Mcfe) 2.54 2.25 2.37 Average costs (per Mcfe) Camp Hill operating expenses $ 2.59 $ 2.35 $ 1.73 Other operating expenses 0.54 0.69 0.66 Total operating expenses(1) 0.68 0.79 0.70
11 12 - ---------- (1) Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs and the administrative costs of production offices, insurance and property and severance taxes. FINDING AND DEVELOPMENT COSTS From inception through December 31, 1999, the Company has incurred total gross development, exploration and acquisition costs of approximately $91.0 million. Total exploration, development and acquisition activities from inception through December 31, 1999 have resulted in the addition of approximately 58.0 Bcfe, net to the Company's interest, of proved reserves at an average finding and development cost of $1.57 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, --------------------------- 1997 1998 1999 ------- ------- ------- (IN THOUSANDS) Acquisition costs Unproved prospects $14,223 $ 9,619 $ 4,166 Proved properties 5,492 16,197 472 Exploration 9,328 10,429 3,163 Development 2,257 313 937 ------- ------- ------- Total costs incurred(1) $31,300 $36,558 $ 8,738 ======= ======= =======
- ---------- (1) Excludes capitalized interest on unproved properties of $699,625, and $291,496, and $1,547,879 for the years ended December 31, 1997, 1998 and 1999, respectively. DRILLING ACTIVITY The following table sets forth the drilling activity of the Company for the years ended December 31, 1997, 1998 and 1999. In the table, "gross" refers to the total wells in which the Company has a working interest and "net" refers to gross wells multiplied by the Company's working interest therein. The Company's drilling activity from January 1, 1996 to December 31, 1999 has resulted in a commercial success rate of approximately 63%. 12 13
YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------------- 1997 1998 1999 -------------------------- -------------------------- -------------------------- GROSS NET GROSS NET GROSS NET ------------ ------------- ------------ ------------- ------------ ------------- Exploratory Wells Productive 39 15.7 29 9.3 14 2.3 Nonproductive 23 9.4 24 7.0 12 1.6 ------------ ------------- ------------ ------------- ------------ ------------- Total 62 25.1 53 16.3 26 3.9 ============ ============= ============ ============= ============ ============= Development Wells Productive 7 1.8 3 1.0 4 0.9 Nonproductive 1 0.6 1 -- 2 0.8 ------------ ------------- ------------ ------------- ------------ ------------- Total 8 2.4 4 1.0 6 1.7 ============ ============= ============ ============= ============ =============
PRODUCTIVE WELLS The following table sets forth the number of productive oil and natural gas wells in which the Company owned an interest as of December 31, 1999.
COMPANY OPERATED OTHER TOTAL -------------------------- -------------------------- -------------------------- GROSS NET GROSS NET GROSS NET ------------- ------------ ------------- ------------ ------------- ------------ Oil 45 43.2 31 9.1 76 52.3 Natural gas 18 10.9 91 24.9 109 35.8 ------------- ------------ ------------- ------------ ------------- ------------ Total 63 54.1 122 34.0 185 88.1 ============= ============ ============= ============ ============= ============
ACREAGE DATA The following table sets forth certain information regarding the Company's developed and undeveloped lease acreage as of December 31, 1999. Developed acres refers to acreage within producing units and undeveloped acres refers to acreage that has not been placed in producing units. Leases covering substantially all of the undeveloped acreage in the following table will expire within the next three years. In general, the Company's leases will continue past their primary terms if oil or natural gas in commercial quantities is being produced from a well on such leases.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL -------------------------- -------------------------- -------------------------- GROSS NET GROSS NET GROSS NET ------------- ------------ ------------- ------------ ------------- ------------ Louisiana 286 33 5,252 1,004 5,538 1,037 Texas 51,399 17,616 117,341 38,831 168,740 56,447 ------------- ------------ ------------- ------------ ------------- ------------ Total 51,685 17,649 122,593 39,835 174,278 57,484 ============= ============ ============= ============ ============= ============
The table does not include 21,186 gross acres (9,341 net) that the Company had a right to acquire pursuant to various seismic option agreements at December 31, 1999. 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. 13 14 The Company's marketing objective is to receive the highest possible wellhead price for its product. The Company is aided by the presence of multiple outlets near its production in the Texas and Louisiana Gulf Coast. The Company takes an active role in determining the available pipeline alternatives for each property based upon historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability. There are a variety of factors which affect the market for oil and natural gas, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas production and sales. The Company has not experienced any difficulties in marketing its oil and natural gas. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. The availability of a ready market for the Company's oil and natural gas production depends on the proximity of reserves to, and the capacity of, oil and natural gas gathering systems, pipelines and trucking or terminal facilities. The Company delivers natural gas through gas gathering systems and gas pipelines that it does not own. Federal and state regulation of natural gas and oil production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect the Company's ability to produce and market its oil and natural gas. The Company from time to time markets its own production where feasible with a combination of market-sensitive pricing and forward-fixed pricing. Forward pricing is utilized to take advantage of anomalies in the futures market and to hedge a portion of the Company's production deliverability at prices exceeding forecast. All of such hedging transactions provide for financial rather than physical settlement. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-General Overview." Despite the measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas sold in the spot market due primarily to seasonality of demand and other factors beyond the Company's control. Domestic oil prices generally follow worldwide oil prices, which are subject to price fluctuations resulting from changes in world supply and demand. The Company continues to evaluate the potential for reducing these risks by entering into, and expects to enter into, additional hedge transactions in future years. In addition, the Company may also close out any portion of hedges that may exist from time to time as determined to be appropriate by management. At December 31, 1998, there were no open hedge positions. At December 31, 1999, the Company had 300,000 MMBtu and 30,200 Bbls of outstanding hedge positions (at an average price of $2.33 per MMBtu and $25.60 per Bbl for January through June 2000 production.) Total oil and natural gas purchased and sold under such swap arrangements during the years ended December 31, 1997, 1998 and 1999 were, 0 Bbls, 0 Bbls and 45,200 Bbls, respectively, and 210,000 MMBtu and 1,760,000 MMBtu, and 2,050,000 MMBtu respectively. Gains (losses) realized by the Company under such swap arrangements were ($48,000), $167,000 and ($412,000), for the years ended December 31, 1997, 1998 and 1999, respectively. COMPETITION AND TECHNOLOGICAL CHANGES The Company encounters competition from other oil and natural gas companies in all areas of its operations, including the acquisition of exploratory prospects and proven properties. The Company's competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of its competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than those of the Company and which, in many instances, have been engaged in the oil and natural gas business for a much longer time than the Company. Such companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that the Company believes are and will be increasingly important to the current and future success of oil and natural gas companies. The Company's ability to explore for oil and natural gas prospects and to acquire additional properties in the future will be dependent upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company believes that its exploration, drilling and production capabilities and the experience of its management generally enable it to compete effectively. Many of the Company's competitors, however, have financial resources and exploration and development budgets that are substantially greater than those of the Company, which may adversely affect the Company's ability to compete with these companies. The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, the Company may be placed at a competitive disadvantage, and competitive pressures may force the Company to implement such new technologies at substantial cost. In addition, 14 15 other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before the Company. There can be no assurance that the Company will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies currently utilized by the Company or implemented in the future may become obsolete. In such case, the Company's business, financial condition and results of operations could be materially adversely affected. If the Company is unable to utilize the most advanced commercially available technology, the Company's business, financial condition and results of operations could be materially and adversely affected. REGULATION The availability of a ready market for oil and gas production depends upon numerous factors beyond the Company's control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which the Company may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Company is also subject to changing and extensive tax laws, the effects of which cannot be predicted. The following discussion summarizes the regulation of the United States oil and gas industry. The Company believes that it is in substantial compliance with the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject, although there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect the Company's results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject. Regulation of Oil and Natural Gas Exploration and Production. The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and gas industry increases the Company's costs of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. Regulation of Sales and Transportation of Natural Gas. Federal legislation and regulatory controls have historically affected the price of natural gas produced by the Company and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate natural gas sales was substantially modified by the Natural Gas Policy Act, under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas, including all sales by the Company of its own production. As a result, all of the Company's domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts which may be in effect. The FERC's jurisdiction over natural gas transportation was not affected by the Decontrol Act. The Company's natural gas sales are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were 15 16 intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesaler marketers of gas to the primary role of gas transporters. All gas marketing by the pipelines was required to be divested to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and the individual pipeline restructuring proceedings of the early to mid-1990s, the interstate pipelines are now required to provide open and nondiscriminatory transportation and transportation-related services to all producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, the FERC expanded the impact of open access regulations to intrastate commerce. More recently, the FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (i) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies, (ii) further development of rules governing the relationship of the pipelines with their marketing affiliates, (iii) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis, (iv) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market and (v) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. It remains to be seen what effect the FERC's other activities will have on access to markets, the fostering of competition and the cost of doing business. As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. The Company believes these changes generally have improved the Company's access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. The Company cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on the Company's activities. In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation and the promotion of competition in the gas industry. Thus, in addition to "first sale" deregulation, Congress also repealed incremental pricing requirements and gas use restraints previously applicable. There are other legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Company. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on the Company's sales of gas, cannot be predicted. Beginning later this year, the FERC will conduct a scheduled review of the indexing system. Any changes resulting from that review, however, would not take effect until July 2001. The Company owns certain natural gas pipelines that it believes meet the standards the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both state and federal levels in the post-Order No. 636 environment. Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. The price the Company receives from the sale of these products may be affected by the cost of transporting the products to market. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. The Company is not able at this time to predict the effects of these regulations, if any, on the transportation costs associated with oil production from the Company's oil producing operations. Environmental Regulations. The Company's operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution 16 17 resulting from production and drilling operations. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, the business and prospects of the Company could be adversely affected. The Company generates wastes that may be subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil and natural gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company believes that it has used good operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing the management of oil and gas wastes. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, the Company does not believe its operations will be materially adversely affected by any such requirements. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention, control, countermeasure ("SPCC") and response plans relating to the possible discharge of oil into surface waters. The Company has acknowledged the need for SPCC plans at certain of its properties and believes that it will be able to develop and implement these plans in the near future. The Oil Pollution Act of 1990, ("OPA") contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. The OPA also requires owners and operators of offshore facilities that could be the source of an oil spill into federal or state waters, including wetlands, to post a bond, letter of credit or other form of financial assurance in amounts ranging from $10 million in specified state waters to $35 million in federal outer continental shelf waters to cover costs that could be incurred by governmental authorities in responding to an oil spill. Such financial assurances may be increased by as much as $150 million if a formal risk assessment indicates that the increase is warranted. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Operations of the Company are also subject to the federal Clean Water Act ("CWA") and analogous state laws. In accordance with the CWA, the state of Louisiana has issued regulations prohibiting discharges of produced water in state coastal waters effective July 1, 1997. Pursuant to other requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. While certain of its properties may require permits for discharges of storm water runoff, the Company believes that it will be able to obtain, or be included under, such permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on the Company. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground. 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 17 18 the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Company also is subject to a variety of federal, state and local permitting and registration requirements relating to protection of the environment. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on the Company. OPERATING HAZARDS AND INSURANCE The oil and natural gas business involves a variety of operating hazards and risks such as well blowouts, craterings, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks. These hazards and risks could result in substantial losses to the Company from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In addition, the Company may be liable for environmental damages caused by previous owners of property purchased and leased by the Company. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of the Company's properties. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks and losses. The Company does not carry business interruption insurance or protect against loss of revenues. There can be no assurance that any insurance obtained by the Company will be adequate to cover any losses or liabilities. The Company cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect the Company's financial condition and operations. The Company may elect to self-insure if management believes that the cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on the financial condition and results of operations of the Company. The Company participates in a substantial percentage of its wells on a nonoperated basis, which may limit the Company's ability to control the risks associated with oil and natural gas operations. TITLE TO PROPERTIES; ACQUISITION RISKS The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and natural gas industry. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, including a title opinion of local counsel, are generally made before commencement of drilling operations. The Company's revolving credit facility is secured by substantially all of its oil and natural gas properties. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact and their accuracy inherently uncertain. In connection with such an assessment, the Company performs a review of the subject properties that it believes to be generally consistent with industry practices, which generally includes on-site inspections and the review of reports filed with various regulatory entities. Such a review, however, will not reveal all existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. There can be no assurances that any acquisition of property interests by the Company will be successful and, if unsuccessful, that such failure will not have an adverse effect on the Company's future results of operations and financial condition. 18 19 EMPLOYEES At December 31, 1999, the Company had 26 full-time employees, including five geoscientists and four engineers. The Company believes that its relationships with its employees are good. In order to optimize prospect generation and development, the Company utilizes the services of independent consultants and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testings, are generally provided by independent contractors. The Company believes that this use of third party service providers has enhanced its ability to contain general and administrative expenses. The Company depends to a large extent on the services of certain key management personnel, the loss of, any of which could have a material adverse effect on the Company's operations. The Company does not maintain key-man life insurance with respect to any of its employees. GLOSSARY OF CERTAIN INDUSTRY TERMS The definitions set forth below shall apply to the indicated terms as used herein. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple. After payout. With respect to an oil or gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bbls/d. Stock tank barrels per day. Bcf. Billion cubic feet. 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." 19 20 Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Finding costs. Costs associated with acquiring and developing proved oil and natural gas reserves which are capitalized by the Company pursuant to generally accepted accounting principles, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing wells. Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. MBbls. One thousand barrels of crude oil or other liquid hydrocarbons. MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per day. Mcf. One thousand cubic feet. Mcf/d. One thousand cubic feet per day. Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. MMBbls. One million barrels of crude oil or other liquid hydrocarbons. MMBtu. One million British Thermal Units. Mmcf. One million cubic feet. MMcf/d. One million cubic feet per day. MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, 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. 20 21 Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves. Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. PV-10 Value. The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. Royalty interest. An interest in an oil and natural gas property entitling the owner to a share of oil or gas production free of costs of production. 3-D seismic data. Three-dimensional pictures of the subsurface created by collecting and measuring the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface. 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. 21 22 ITEM 3. LEGAL PROCEEDINGS From time to time the Company is a party to various legal proceedings arising in the ordinary course of business. The Company is not currently a party to any litigation that it believes could have a material adverse effect on the financial position or results of operations of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. EXECUTIVE OFFICERS OF THE REGISTRANT Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this Form 10-K. The following table sets forth certain information with respect to executive officers of the Company:
NAME AGE POSITION ------------------- ---- -------------------------------------- S.P. Johnson IV 43 President and Chief Executive Officer Frank A. Wojtek 44 Chief Financial Officer, Vice President, Secretary and Treasurer George F. Canjar 42 Vice President of Exploration Development Kendall A. Trahan 49 Vice President of Land
Set forth below is a description of the backgrounds of each of the executive officers of the Company: S.P. Johnson IV has served as the President, Chief Executive Officer and a director of the Company since December 1993. Prior to that, he worked 15 years for Shell Oil Company. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado. Frank A. Wojtek has served as the Chief Financial Officer, Vice President, Secretary, Treasurer and a director of the Company since 1993. In addition, from 1992 to 1997, Mr. Wojtek was the Assistant to the Chairman of the Board of Reading & Bates Corporation ("Reading & Bates") (an offshore drilling company). Mr. Wojtek also holds the positions of Vice President and Secretary /Treasurer for Loyd and Associates, Inc. (a private financial consulting and investment banking firm). Mr. Wojtek held the positions of Vice President and Chief Financial Officer of Griffin-Alexander Drilling Company from 1984 to 1987, Treasurer of Chiles-Alexander International Inc. from 1987 to 1989 and Vice President and Chief Financial Officer of India Offshore Inc. from 1989 to 1992, all of which are companies in the offshore drilling industry. Mr. Wojtek is a Certified Public Accountant and holds a B.B.A. in Accounting from the University of Texas. George F. Canjar has been head of the Company's exploration activities since joining the Company in July 1996 and was elected Vice President of Exploration Development in June 1997. Prior thereto he worked for over 15 years for Shell Oil Company and its overseas affiliates where he held various technical and managerial positions, including Technical Manager-Geology & Petrophysics, Section Head Geology & Seismology and Team Leader for numerous integrated production, development, exploration and project 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. 22 23 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS The Company's common stock, par value $0.01 per share (the "Common Stock"), has been publicly traded through the Nasdaq National Market tier of The Nasdaq Stock Market under the symbol CRZO since the Company's initial public offering (the "Offering") effective August 6, 1997. The following table sets forth the quarterly high and low bid prices for each indicated quarter.
QUARTER ENDED HIGH LOW -------------------------- ------------ ------------ September 30, 1997 15 10 15/16 December 31, 1997 17 1/4 7 7/8 March 31, 1998 8 3/4 6 1/16 June 30, 1998 7 1/2 5 1/2 September 30, 1998 5 3/4 2 5/8 December 31, 1998 3 1/16 1 1/8 March 31, 1999 1 11/16 1 June 30, 1999 2 1 September 30, 1999 2 1/4 1 1/2 December 31, 1999 2 1/8 1 3/8
There were approximately 60 shareholders of record (excluding brokerage firms and other nominees) of the Company's Common Stock as of March 23, 2000. The Company has not paid any dividends in the past and does not intend to pay cash dividends on its Common Stock in the foreseeable future. The Company currently intends to retain any earnings for the future operation and development of its business, including exploration, development and acquisition activities. The Company's revolving line of credit with Compass Bank (the "Company Credit Facility") and the terms of its 9% Senior Subordinated Notes, restrict the Company's ability to pay dividends. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." RECENT SALES OF UNREGISTERED SECURITIES On December 15, 1999, the Company consummated the transactions (the "Financing") contemplated by a Securities Purchase Agreement dated December 15, 1999 (the "Securities Purchase Agreement") among the Company, CB Capital Investors, L.P. ("Chase"), Mellon Ventures, L.P. ("Mellon"), Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A. Webster (excluding the Company, the "Investors"). Such transactions included (i) the payment by the Investors of an aggregate purchase price of $30,000,000, (ii) the sale of an aggregate of $22,000,000 principal amount of 9% Senior Subordinated Notes due 2007 (the "Notes") to the Investors, (iii) the sale of an aggregate of 3,636,364 shares of the Company's Common Stock for $2.20 per share to the Investors, (iv) the sale of warrants (the "Warrants") to purchase up to 2,760,189 shares of the Company's Common Stock (the "Warrant Shares") at the exercise price of $2.20 per share, subject to adjustments, to the Investors, (v) the execution of the Shareholders Agreement dated December 15, 1999 (the "Shareholders Agreement") among the Company, Chase, Mellon, Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P., (vi) the execution and delivery of the Warrant Agreement dated December 15, 1999 (the "Warrant Agreement") among the Company, Chase, Mellon, Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A. Webster, (vii) the execution of the Registration Rights Agreement dated December 15, 1999 ("Chase Registration Rights Agreement") among the Company, Chase and Mellon, (viii) the execution of the Amended and Restated Registration Rights Agreement dated December 15, 1999 ("Amended Founders Registration Rights Agreement") among the Company, Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P., and (ix) the execution of a Compliance Sideletter dated December 15, 1999 among the Company, Chase and Mellon (the "Compliance Sideletter"). The Warrants are exercisable at any time prior to the expiration date on December 15, 2007 for the purchase of an aggregate of 2,760,189 shares of Common Stock at an exercise price of $2.20 per share, subject to certain adjustments. Each Warrant may be exercised by (i) paying the exercise price in cash or (ii) on a cashless basis by exercising the Warrant for a number of net Warrant Shares equal to the number of Warrant Shares issuable upon exercise of the Warrant minus the number of shares obtained by dividing (A) the product of the exercise price times the number of net Warrant Shares issuable upon exercise of the Warrant by (B) the average market price during the 4-day trading period preceding the date of exercise. The number and kind of Warrant Shares issued and the exercise price are subject to adjustment in certain circumstances, including (i) if the Company pays a dividend in Common Stock or distributes shares of its Common Stock, subdivides, splits or reclassifies its outstanding shares of Common Stock into a larger number of shares of Common Stock, or combines its outstanding shares of Common Stock into a smaller number of shares of Common Stock, (ii) if the Company issues shares of Common Stock or securities exercisable or exchangeable for or convertible into shares of Common Stock for no consideration or for less than the market value (as specified in the Warrant) of the Common Stock, subject to certain exceptions, (iii) if the Company distributes any of its equity securities (other than Common Stock or options) to the holders of the Common Stock on a pro rata basis, (iv) if the Company engages in a consolidation, merger or business combination, sells all of its assets to another person or entity, or enters into certain capital reorganizations or reclassifications of the capital stock of the Company or (v) the Company takes certain other actions affecting its Common Stock. The sale of the shares of Common Stock, the Notes and the Warrants pursuant to the Securities Purchase Agreement is exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof as a transaction not involving a public offering. 23 24 ITEM 6. SELECTED FINANCIAL DATA The financial information of the Company set forth below for each of the five years ended December 31, 1999, has been derived from the audited combined financial statements of the Company. The following table also sets forth certain pro forma income taxes, net income and net income per share information. The information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited financial statements of the Company and the related notes thereto included elsewhere herein.
YEAR ENDED DECEMBER 31, -------------------------------------------------------- 1995 1996 1997 1998 1999 -------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA: Oil and natural gas revenues $ 2,428 $ 5,195 $ 8,712 $ 7,859 $ 10,204 Costs and expenses: Oil and natural gas operating expenses 1,814 2,384 2,334 2,770 3,036 Depreciation, depletion and amortization 488 1,136 2,358 3,952 4,301 Write-down of oil and gas properties -- -- -- 20,305 -- General and administrative 425 515 1,591 2,667 2,195 -------- -------- -------- -------- -------- Total costs and expenses 2,727 4,035 6,283 29,694 9,532 -------- -------- -------- -------- -------- Operating income (loss) (299) 1,160 2,429 (21,835) 672 Interest expense (net of amounts capitalized and interest income) (192) (80) (98) 285 13 Other income 24 20 -- -- -- -------- -------- -------- -------- -------- Income (loss) before income taxes (467) 1,100 2,331 (21,550) 685 Deferred income taxes (benefit)(1) -- -- 2,300 (2,218) (1,057) -------- -------- -------- -------- -------- Net income (loss) before cumulative effect of change in accounting principle (467) 1,100 31 (19,332) 1,742 Cumulative effect of change in accounting principle -- -- -- -- (78) -------- -------- -------- -------- -------- Net income (loss)(1)(4) $ (467) $ 1,100 $ 31 $(19,332) $ 1,664 ======== ======== ======== ======== ======== Basic earnings (loss) per share (1)(4) $ (0.07) $ 0.15 $ -- $ (2.15) $ 2.00 ======== ======== ======== ======== ======== Diluted earnings (loss) per share (1)(4) $ (0.07) $ 0.15 $ -- $ (2.15) $ 2.00 ======== ======== ======== ======== ======== Basic weighted average shares outstanding 7,021 7,476 8,639 10,375 10,544 Diluted weighted average shares outstanding 7,021 7,545 8,810 10,375 10,546 STATEMENTS OF CASH FLOW DATA: Net cash provided by operating activities $ 406 $ 3,325 $ 3,068 $ 2,387 $ 2,200 Net cash used in investing activities (6,785) (8,221) (28,141) (37,178) (14,179) Net cash provided by financing activities 6,343 6,319 26,255 32,916 21,457 OTHER OPERATING DATA: Adjusted EBITDA (2) $ 189 $ 2,296 $ 4,787 $ 2,422 $ 4,921 Operating cash flow (3) 21 2,236 4,689 2,707 4,986 Capital expenditures 6,857 9,480 32,234 36,570 10,286 Debt repayments(5) -- 2,084 20,409 7,950 8,174
24 25
AS OF DECEMBER 31, -------------------------------------------------------- 1995 1996 1997 1998 1999 -------- -------- -------- -------- -------- BALANCE SHEET DATA: Working capital $ (265) $ (1,025) $ (2,276) $ (5,204) $ 8,338 Property and equipment, net 6,960 15,206 45,083 57,878 64,337 Total assets 7,645 18,869 53,658 64,988 83,666 Long-term debt, including current maturities 3,480 9,684 7,950 12,056 33,627 Mandatorily redeemable preferred stock -- -- -- 30,731 -- Equity 3,381 4,596 32,895 11,202 40,853
- ---------- (1) On May 16, 1997, Carrizo and a number of affiliated entities were combined with the Company in a series of transactions in connection with its initial public offering (the "Combination Transactions"). Prior to that date, Carrizo and those other entities were not required to pay federal income taxes due to their status as partnerships or Subchapter S corporations. The amounts shown reflect pro forma income taxes that represent federal income taxes which would have been reported under Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes," had Carrizo and such entities been tax-paying entities during each of the periods presented. See Notes 2 and 4 to the Company's financial statements. 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. (2) Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization and writedown of oil and gas properties. (3) Operating cash flow represents cash flows from operating activities prior to changes in assets and liabilities. (4) Net income (loss) for the year ended December 31, 1999 excludes and earnings per share for the year ended December 31, 1999 includes the discount on the redemption of the Company's Preferred Stock in the amount of $21,868,413. (5) Debt repayments include amounts refinanced. Forward Looking Statements. The statements contained in all parts of this document, (including any portion attached hereto) including, but not limited to, those relating to the Company's schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, expected working or net revenue interests, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), use of proceeds from the Company's initial public offering and the sale of shares of Preferred Stock and the warrants, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement its business strategy, future hiring, future exploration activity and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words "anticipate," "budgeted", "targeted", "potential" "estimate," "expect," "may," "project," "believe" and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company's dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, risks relating to its limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks and other factors detailed herein and in the Company's other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 25 26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL OVERVIEW The Company began operations in September 1993 and initially focused on the acquisition of producing properties. As a result of the increasing availability of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic data and options to lease substantial acreage in 1995 and began to drill its 3-D based prospects in 1996. The Company drilled 70, 57 and 32 wells in 1997, 1998 and 1999 respectively. The Company has budgeted to drill 45 gross wells (14.1 net) in 2000; however, in order to drill the expected number of wells the Company will need to obtain additional financing and the actual number of wells drilled will vary depending upon the Company's ability to obtain this financing, success of drilling program, weather delays and other factors. If the Company drills the number of wells it has budgeted for 2000, depreciation, depletion and amortization are expected to increase and oil and gas operating expenses are expected to increase over levels incurred in 1999. The Company has typically retained the majority of its interests in shallow, normally pressured prospects and sold a portion of its interests in deeper, over-pressured prospects. The financial statements set forth herein are prepared on the basis of a combination of Carrizo and the entities that were a party to the Combination Transactions. Carrizo and the entities combined with it in the Combination Transactions were not required to pay federal income taxes due to their status as partnerships or Subchapter S corporations, which are not subject to federal income taxation. Instead, taxes for such periods were paid by the shareholders and partners of such entities. On May 16, 1997, Carrizo terminated its status as an S corporation and thereafter became subject to federal income taxes. In accordance with SFAS No. 109, "Accounting for Income Taxes," the Company established a deferred tax liability in the second quarter of 1997, resulting in a noncash charge to income of approximately $1.6 million. The Company has primarily grown through the internal development of properties within its exploration project areas, although the Company acquired properties with existing production in the Camp Hill Project in late 1993, the Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company made these acquisitions through the use of limited partnerships with Carrizo or Carrizo Production, Inc. as the general partner. In addition, in November 1998 the Company acquired assets in Wharton County, Texas in the Jones Branch project area for approximately $3,000,000. Prior to the Offering, Carrizo conducted its oil and natural gas operations directly, with industry partners and through the following affiliated entities: Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd. and Placedo Partners Ltd. Concurrently with the closing of the Offering, Combination Transactions were closed. The Combination Transactions consisted of the following: (i) Carrizo Production, Inc. merged into Carrizo; (ii) Carrizo acquired Encinitas Partners Ltd. in two steps: (a) Carrizo acquired the limited partner interests in Encinitas Partners Ltd. held by certain of the Company's directors and (b) Encinitas Partners Ltd. merged into Carrizo; (iii) La Rosa Partners Ltd. merged into Carrizo; and (iv) Carrizo Partners Ltd. merged into Carrizo. As a result of the merger of Carrizo and Carrizo Partners Ltd., Carrizo became the owner of all of the partnership interest in Placedo Partners Ltd. The Company uses the full-cost method of accounting for its oil and gas properties. Under this method, all acquisition, exploration and development costs, including any general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full-cost pool" as incurred. The Company records depletion of its full-cost pool using the unit-of-production method. To the extent that such capitalized costs in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and gas reserves, such excess costs are charged to operations. At December 31, 1998, the Company recorded a full cost ceiling test write down of its oil and natural gas properties of $20.3 million primarily as a result of declines in product pricing and revisions to prior estimates of proved reserves. Once incurred, a write-down of oil and gas properties is not reversible at a later date. RESULTS OF OPERATIONS Year Ended December 31, 1999 Compared to the Year Ended December 31, 1998 Oil and natural gas revenues for 1999 increased 30% to $10.2 million from $7.9 million in 1998. Production volumes for natural gas in 1999 increased 22% to 3235.0 MMcf from 2,655.1 MMcf in 1998. Realized average natural gas prices decreased 3% to $2.23 per Mcf in 1999 from $2.31 per Mcf in 1998. Production volumes for oil in 1999 increased 28% to 179.3 MBbls from 140.0 MBbls in 1998. The increase in oil production was due primarily to the Jones Branch acquisition during the fourth quarter of 1998 and the completion of the Matagorda Project wells in the second half of 1999. Natural gas production increased primarily as a result of the Jones Branch acquisition, the completion of the Matagorda Project area wells and the Cedar Point Project Area well in the second half of 1999 offset by the natural decline of existing wells. 26 27 Average oil prices increased 37% to $16.80 per barrel in 1999 from $12.30 per barrel in 1998. 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, 1998 and 1999:
1999 PERIOD COMPARED TO 1998 PERIOD DECEMBER 31, INCREASE % INCREASE 1998 1999 (DECREASE) (DECREASE) ------------ ------------ ----------- ----------- Production volumes- Oil and condensate (MBbls) 140.0 179.3 39.3 28% Natural gas (MMcf) 2,655.1 3,235.0 579.9 22% Average sales prices-(1) Oil and condensate (per Bbl) $ 12.30 $ 16.80 $ 4.50 37% Natural gas (per Mcf) 2.31 2.23 (0.08) (3%) Operating revenues- Oil and condensate $ 1,721,162 $ 2,975,998 $ 1,254,836 73% Natural gas 6,137,340 7,228,347 1,091,007 18% ------------ ------------ ----------- Total $ 7,858,502 $ 10,204,345 $ 2,345,843 30% ============ ============ ===========
- ---------- (1) Including impact of hedging. Oil and natural gas operating expenses for 1999 increased 10% to $3.0 million from $2.8 million in 1998. Oil and natural gas operating expenses increased primarily as a result of the addition of new oil and gas wells drilled and completed since December 31, 1998 offset by a reduction in costs on older producing fields. Operating expenses per equivalent unit in 1999 decreased to $.70 per Mcfe from $.79 per Mcfe in 1998. The per unit cost decreased primarily as a result of the addition of new wells with high production rates during 1999 and the implementation of cost control measures in certain oil producing fields offset by decreased production of natural gas as wells naturally decline. Depreciation, depletion and amortization ("DD&A") expense for 1999 increased nine percent to $4.3 million from $4.0 million in 1998. This increase was primarily due to the increased amortization of deferred loan costs, increased production and additional seismic and drilling costs offset by the lower asset base resulting from the ceiling test write-down in the fourth quarter of 1998. Primarily as a result of quantity revisions and depressed commodity prices, the Company recorded a write-down of oil and gas properties of $20.3 million in 1998. Prior to 1998 and during 1999 the Company was not required to record any such write-downs. General and administrative expense for 1999 decreased 18% to $2.2 million from $2.7 million for 1998 reflecting the cost control measures implemented in the fourth quarter of 1998 and first quarter of 1999. Interest expense, net of amounts capitalized, for 1999 increased 305% to $35,000 from $9,000 in 1998. This increase was primarily due to higher interest expense in 1999 which was not available to be capitalized. The Company expects future interest costs to increase as a result of its issuance of $22 million principal amount of senior subordinated notes in December 1999. Income tax benefits changed from $2.2 million to $1.1 million based on improvements in the expected results which influence future taxable income. The Company adjusted its valuation allowance in the fourth quarter of 1999 on net operating loss carryforwards expected to be realized which resulted in a deferred income tax benefit of $1.1 million. Dividends and accretion of discount on preferred stock decreased to $2.4 million in 1999 from $2.9 in 1998 as a result of the redemption of preferred stock in the fourth quarter of 1999. As a result of this redemption, no future charges will be accrued. Net income for 1999 increased to $1.7 million from a loss of $22.2 million in 1998 as a result of the factors described above. The redemption of the Company's mandatorily redeemable preferred stock at a discount resulted in a credit of $21,868,413 which is included in net income available to common shareholders, net of stock dividends paid to the holders of the preferred stock of $2,417,358. 27 28 Year Ended December 31, 1998 Compared to the Year Ended December 31, 1997 Oil and natural gas revenues for 1998 decreased 10% to $7.9 million from $8.7 million in 1997. Production volumes for natural gas in 1998 decreased 3% to 2,655.1 MMcf from 2,749.2 MMcf in 1997. Average natural gas prices decreased 4% to $2.31 per Mcf in 1998 from $2.41 per Mcf in 1997. Production volumes for oil in 1998 increased 24% to 140 MBbls from 112.5 MBbls in 1997. Average oil prices decreased 34% to $12.30 per barrel in 1998 from $18.66 per barrel in 1997. 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, 1997 and 1998:
1998 PERIOD COMPARED TO 1997 PERIOD DECEMBER 31, INCREASE % INCREASE 1997 1998 (DECREASE) (DECREASE) ------------ ------------ ----------- ----------- Production volumes Oil and condensate (MBbls) 112.5 140 27.5 24% Natural gas (MMcf) 2,749.2 2,655.1 (94.1) (3%) Average sales prices-(1) Oil and condensate (per Bbl) $ 18.66 $ 12.30 $ (6.36) (34%) Natural gas (per Mcf) 2.41 2.31 (0.10) (4%) Operating revenues- Oil and condensate $ 2,099,699 $ 1,721,162 $ (378,537) (18%) Natural gas 6,611,955 6,137,340 (474,615) (7%) ------------ ------------ ----------- Total $ 8,711,654 $ 7,858,502 $ (853,152) (10%) ============ ============ ===========
- ---------- (1) Including impact of hedging. Oil and natural gas operating expenses for 1998 increased 19% to $2.8 million from $2.3 million in 1997. Oil and natural gas operating expenses increased primarily as a result of the addition of new oil and gas wells drilled and completed since December 31, 1996. Operating expenses per equivalent unit in 1998 increased to $.81 per Mcfe from $.68 per Mcfe in 1997. The per unit cost increased primarily as a result of decreased production of natural gas as wells naturally decline. DD&A expense for 1998 increased 68% to $4.0 million from $2.4 million in 1997. This increase was primarily due to the increased production, additional land, seismic and drilling costs. Primarily as a result of quantity revisions and depressed commodity prices, the Company recorded a write-down of oil and gas properties of $20.3 million in 1998. General and administrative expense for 1998 increased 68% to $2.7 million from $1.6 million for 1997 reflecting ramp-up expenses relating to the hiring of additional technical and administrative staff to handle the Company's increased level of exploration activities and operations as well as other costs related to being a public company. Interest expense for 1998 decreased 94% to $9,000 from $151,000 in 1997. This decrease was primarily due to lower interest expense in 1998 which allowed a larger percentage of the interest to be capitalized. As a result of the adoption of SFAS 109 in the second quarter of 1997, the Company recorded a one-time non-cash charge to income of $1.6 million to establish a deferred tax liability. Dividends and accretion of discount on preferred stock increased to $2.9 million in 1998 from none in 1997 as a result of the sale of preferred stock in the first quarter of 1998. 28 29 Net income for 1998 decreased to a loss of $22.2 million from income of $31,000 in 1997 as a result of the factors described above. LIQUIDITY AND CAPITAL RESOURCES The Company has made and will be required to make oil and gas capital expenditures substantially in excess of its net cash flow from operations in order to complete the exploration and development of its existing properties. The Company will require additional sources of financing to fund drilling expenditures on properties currently owned by the Company and to fund leasehold costs and geological and geophysical cost on its activities exploration projects. While the Company believes that the recent financing consummated in December 1999 (see Financing Arrangements below) will provide sufficient capital to carry out the Company's 2000 exploration plans, management of the Company continues to seek financing for its capital program from a variety of sources. No assurance can be given that the Company will be able to obtain additional financing on terms that would be acceptable to the Company. The Company's inability to obtain additional financing could have a material adverse effect on the Company. Without raising additional capital, the Company anticipates that it may be required to limit or defer its planned oil and gas exploration and development program, which could adversely affect the recoverability and ultimate value of the Company's oil and gas properties. The Company's primary sources of liquidity have included proceeds from the initial public offering from the December 1999 sale of Subordinated Notes, Common Stock and Warrants, the 1998 sale of shares of Preferred Stock and Warrants, funds generated by operations, equity capital contributions, borrowings, primarily under revolving credit facilities and the Palace Agreement. Cash flows provided by operations (after changes in working capital) were $3.1 million, $2.4 million and $2.2 million for 1997, 1998 and 1999, respectively. The decrease in cash flows provided by operations in 1998 as compared to 1997 was due primarily to decreases in commodity prices. The decrease in cash flows provided by operations in 1999 as compared to 1998 was due primarily to the decrease in current liabilities offset by increases in commodity prices. The Company has budgeted capital expenditures in 2000 of approximately $13.9 million of which $2.3 is expected to be used to fund 3-D seismic surveys and land acquisitions and $11.6 million of which is expected to be used for drilling activities in the Company's project areas. The Company has budgeted to drill approximately 45 gross wells (14.1 net) in 2000. The actual number of wells drilled and capital expended is dependent upon available financing, cash flow, drilling rigs and other factors. The Company has continued to reinvest a substantial portion of its cash flows into increasing its 3-D prospect portfolio, improving its 3-D seismic interpretation technology and funding its drilling program. Oil and gas capital expenditures were $32.2 million, $36.6 and $10.3 million for 1997, 1998 and 1999, respectively. The Company's drilling efforts resulted in the successful completion of 46 gross wells (17.5 net) in 1997, 31 gross wells (10.3 net) in 1998 and 18 gross wells (3.2 net) in 1999. FINANCING ARRANGEMENTS In connection with the Offering, Carrizo entered into an amended revolving credit facility with Compass Bank (the "Company Credit Facility") to provide for a maximum loan amount of $25 million, subject to borrowing base limitations. The principal outstanding is due and payable in January 2002, with interest due monthly. The Company Credit Facility was amended in March 1999 to provide for a maximum loan amount under such facility of $10 million. The interest rate on all revolving credit loans is calculated, at the Company's option, at a floating rate based on the Compass index rate or LIBOR plus 2 percent. The Company's obligations are secured by substantially all of its oil and gas properties and cash or cash equivalents included in the borrowing base. Certain members of the Board of Directors have provided collateral, primarily in the form of marketable securities, to secure the revolving credit loans. As of March 1, 2000, the aggregate amount of this collateral was approximately $5.5 million. 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 also redetermine the borrowing base and the monthly borrowing base reduction at any time at its discretion. The Company may also request borrowing base redeterminations in additions to the required semiannual reviews at the Company's cost. In December 1997, the Company Credit Facility was amended to provide for a term loan of $3 million, bearing interest at the Index Rate. The amount outstanding under the $3 million term loan as of December 31, 1998 was $3 million, which was repaid in January 1999. In September, 1998, the Company Credit Facility was further amended to provide for an additional $7 million term loan bearing interest at the Index Rate, of which $7 million was borrowed in the fourth quarter of 1998. In March 1999, the Company Credit Facility was further amended to increase the $7 million term loan by $2 million. In December 1999, $2 million principal amount of the term loan was repaid with proceeds from the sale from the Subordinated Notes, Common Stock and Warrants. Certain members of the Board of Directors have guaranteed the term loan. As currently amended pursuant to an amendment dated December 1999, interest on the term loan is payable monthly, bearing interest at the Index Rate. Unless preceded by the Term Loan Maturity Date (as defined below), principal payments on the term loan are not due until June 1, 2000, whereupon the term loan is repayable in consecutive monthly installments in the amount $290,000 each, beginning July 1, 2000 through December 1, 2000, and thereafter in the amount of $440,000, beginning January 1, 2001 until the Term Loan Maturity Date, when the entire principal balance, plus interest, is payable. Term Loan Maturity Date means the earlier of: (1) the date of closing of the issuance of additional equity of the Company, if the net proceeds of such issuance are sufficient to repay in full the term loan; (2) the date of closing of the issuance of convertible subordinated debt of the Company, if the proceeds of such issuance are sufficient to repay in full the term loan; (3) the date of repayment of the revolving credit loans and the termination of the revolving commitment; and (4) July 1, 2001. The Company is subject to certain covenants under the terms of the Company Credit Facility, including but not limited to (a) maintenance of specified tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly debt service of not less than 1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company Credit Facility also places restrictions on, among other things, (a) incurring additional indebtedness, guaranties, loans and liens, (b) changing the nature of business or business structure, (c) selling assets and (d) paying dividends. Proceeds of the revolving credit loans have been used to provide funding for exploration and development activity. At December 31, 1998, and 1999, outstanding revolving credit loans totaled $5,056,000 and $5,876,000, respectively, with an additional $1,020,000 and $1,208,392, respectively, available for future borrowings. The outstanding amount of the term loan was $7,000,000 at December 31, 1998 and 1999. The Company Credit Facility also provides for the issuance of letters of credit, one of which has been issued for $224,000 at December 31, 1998 and 1999. The weighted average interest rates for 1998 and 1999 on the Company Credit Facility were 8 and 9 percent, respectively. In November 1999, Messrs. Hamilton, Webster and Loyd provided a bridge loan in the amount of $2,000,000, to the Company, secured by certain oil and natural gas properties. This bridge loan bore interest at 14% per annum. Also in consideration for the bridge loan, the Company assigned to Messrs. Hamilton, Webster and Loyd an aggregate 1.0% overriding royalty interest ("ORRI") in the Huebner #1 and Fondren Letulle #1 wells (combined with the prior assignment, a 2% overriding royalty interest), a .8794% ORRI in Neblett #1 (N.La.Copita), a 1.0466% ORRI in STS 104-5#1, a 1.544% ORRI in USX Hematite #1, a 2.0% ORRI in Huebner #2 and a 2.0% ORRI in Buckhart #1. On December 15, 1999 the bridge loan was repaid in its entirety with proceeds from the sale of Common Stock, Subordinated Notes and Warrants. Such overriding royalty interests are limited to the well bore and proportionately reduced to the Company's working interest in the well. 29 30 In December 1999, the Company consummated the sale of $22 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. which included certain members of the Board of Directors. The Subordinated Notes were sold at a discount of $688,761 which is being amortized over the life of the notes. Interest is payable quarterly beginning March 31, 2000. The Company may elect, for a period of five years, to increase the amount of the Subordinated Notes for up to 60% of the interest which would otherwise be payable in cash. Concurrent with the sale of the notes, the Company consummated the sale of 3,636,364 shares of Common Stock at a price of $2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's Common Stock at an exercise price of $2.20 per share. For accounting purposes, the Warrants are valued at $0.25 per Warrant. The sale was made to an investor group led by CB Capital Investors, L.P. which included certain members of the Board of Directors. The Warrants have an exercise price of $2.20 per share and expire in December 2007. The Company is subject to certain covenants under the terms under the related Securities Purchase Agreement, including but not limited to, (a) maintenance of a specified Tangible Net Worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) limit its capital expenditures to a specified amount for the year ended December 31, 2000, and thereafter to an amount equal to the Company's EBITDA for the immediately prior fiscal year as well as limits on the Company's ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidations, sales of assets and acquisitions, (iv) declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v) engage in transactions with affiliates, (vi) make certain repayments and prepayments, including any prepayment of the Company's term loan, any subordinated debt, indebtedness that is guaranteed or credit-enhanced by any affiliate of the Company, and prepayments that effect certain permanent reductions in revolving credit facilities. Of the approximately $29,000,000 net proceeds of this financing, $12,060,000 was used to fund the Enron Repurchase described below and related expenses, $2,025,000 was used to repay the bridge loan extended to the Company by its outside directors, $2 million was used to repay a portion of the Compass Term Loan, $1 million was used to repay a portion of the Compass Borrowing Base Facility, and the Company expects the remaining proceeds to be used to fund the Company's ongoing exploration and development program and general corporate purposes. In January 1998, the Company consummated the sale of 300,000 shares of Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to affiliates of Enron Corp. The net proceeds received by the Company from this transaction were approximately $28.8 million and were used primarily for oil and natural gas exploration and development activities in Texas and Louisiana and to repay related indebtedness. The Preferred Stock provided for annual cumulative dividends of $9.00 per share, payable quarterly in cash or, at the option of the Company until January 15, 2002, in additional shares of Preferred Stock. Dividend payments for the 12 months ended December 31, 1999 were made by the issuance of an additional 22,508.23 shares of Preferred Stock. 30 31 In December 1999, the Company consummated the repurchase of all the outstanding shares of Preferred Stock and 750,000 Warrants for $12 million. At the same time, the Company reduced the exercise price of the remaining 250,000 Warrants from $11.50 per share to $4.00 per share. ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY The Company's growth has placed, and is expected to continue to place, a significant strain on the Company's financial, technical, operational and administrative resources. The Company has relied in the past and expects to continue to rely on project partners and independent contractors that have provided the Company with seismic survey planning and management, project and prospect generation, land acquisition, drilling and other services. At December 31, 1999, the Company had 26 full-time employees. There will be additional demands on the Company's financial, technical, operational and administrative resources and continued reliance by the Company on project partners and independent contractors, and these strains on resources, additional demands and continued reliance may negatively affect the Company. The Company's ability to grow will depend upon a number of factors, including its ability to obtain leases or options on properties for 3-D seismic surveys, its ability to acquire additional 3-D seismic data, its ability to identify and acquire new exploratory sites, its ability to develop existing sites, its ability to continue to retain and attract skilled personnel, its ability to maintain or enter into new relationships with project partners and independent contractors, the results of its drilling program, hydrocarbon prices, access to capital and other factors. Although the Company intends to continue to upgrade its technical, operational and administrative resources and to increase its ability to provide internally certain of the services previously provided by outside sources, there can be no assurance that it will be successful in doing so or that it will be able to continue to maintain or enter into new relationships with project partners and independent contractors. The failure of the Company to continue to upgrade its technical, operational and administrative resources or the occurrence of unexpected expansion difficulties, including difficulties in recruiting and retaining sufficient numbers of qualified personnel to enable the Company to expand its seismic data acquisition and drilling program, or the reduced availability of project partners and independent contractors that have historically provided the Company seismic survey planning and management, project and prospect generation, land acquisition, drilling and other services, could have a material adverse effect on the Company's business, financial condition and results of operations. In addition, the Company has only limited experience operating and managing field operations, and there can be no assurances that the Company will be successful in doing so. Any increase in the Company's activities as an operator will increase its exposure to operating hazards. See "Business and Properties -- Operating Hazards and Insurance." The Company's lack of capital will also constrain its ability to grow and achieve its business strategy. There can be no assurance that the Company will be successful in achieving growth or any other aspect of its business strategy. 31 32 RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In September 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging activities - Deferral of the Effective Date of SFAS No. 133" is effective for fiscal years beginning after June 15, 2000. A Company may also implement the Statement as of the beginning of any fiscal quarter after issuance. Statement No. 133 cannot be applied retroactively. Statement No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1998 and, at the company's election, before January 1, 1999. The Company routinely enters into financial instrument contracts to hedge price risks associated with the sale of crude oil and natural gas. Statement No. 133 amends, modifies and supercedes significantly all of the authoritative literature governing the accounting for and disclosure of derivative financial instruments and hedging activities. As a result, adoption of Statement No. 133 will impact the accounting for and disclosure of the Company's operations. The Company intends to adopt the provisions of such statement in accordance with the requirements provided by the statement. Management is currently assessing the financial statement impact; however, such impact is not ascertainable at this time. VOLATILITY OF OIL AND NATURAL GAS PRICES The Company's revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of its properties, are substantially dependent upon prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices may materially adversely affect the Company's financial condition, liquidity, and ability to finance planned capital expenditures and results of operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that the Company can produce economically. Oil and natural gas prices have declined in the recent past and there can be no assurance that prices will recover or will not decline further. See "Business and Properties -- Marketing." The Company periodically reviews the carrying value of its oil and natural gas properties under the full cost accounting rules of the Commission. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of this ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. The Company may be required to write down the carrying value of its oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. On December 31, 1998, the Company recorded a full cost ceiling test write down of its oil and natural gas properties of $20.3 million because its carrying cost of proved reserves was in excess of the present value of estimated future net revenues from those reserves. If additional write-downs are required, they would result in additional charges 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, 1997, 1998 and 1999 were 0 Bbls, 0 Bbls and 45,200 Bbls, respectively, and 210,000 MMBTU, 1,760,000 MMBTU and 2,050,000 MMBTU, respectively. Income and (losses) 32 33 realized by the Company under such swap arrangements were $48,000, $167,000 and $(412,000) for the years ended December 31, 1997, 1998 and 1999, respectively. The Company had outstanding no hedge positions as of December 31, 1998. At December 31, 1999, the Company had 300,000 MMBtu and 30,250 Bbls of outstanding hedge positions (at an average price of $2.23 per MMBtu and $25.60 per Bbl for January through June 2000.) See "Business and Properties -- Marketing." ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK COMMODITY RISK. The Company's major market risk exposure is the commodity pricing applicable to its oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of such pricing volatility have been discussed above, and such volatility is expected to continue. A 10% fluctuation in the price received for oil and gas production would have an approximate $1.0 million impact on the Company's annual revenues and operating income. To mitigate some of this risk, the Company engages periodically in certain limited hedging activities but only to the extent of buying protection price floors. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and were not significant for any year presented. The costs to purchase put options are amortized over the option period. The Company does not hold or issue derivative instruments for trading purposes. Income and (losses) realized by the Company related to these instruments were $48,000, and $167,000 and $(412,000) or $4.38, and $10.54 and $(5.64) per MMBtu for the years ended December 31, 1997, 1998 and 1999, respectively. INTEREST RATE RISK. The Company's exposure to changes in interest rates results from its floating rate debt. In regards to its Revolving Credit Facility, the result of a 10% fluctuation in short-term interest rates would impact 2000 cash flow by approximately $120,000. FINANCIAL INSTRUMENTS & DEBT MATURITIES. The Company's financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings and subordinated notes payable. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank and vendor borrowings approximate the carrying amounts as of December 31, 1999 and 1998, and were determined based upon interest rates currently available to the Company for borrowings with similar terms. Maturities of the debt are $3,542,742 in 2000, $6,388,953 in 2001, $5,576,000 in 2002 and the balance in 2007. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The response to this item is included elsewhere in this report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated by reference to information under the caption "Proposal 1-Election of Directors" and to the information under the caption "Section 16(a) Reporting Delinquencies" in the Company's definitive Proxy Statement (the "2000 Proxy Statement") for its 2000 annual meeting of shareholders. The 2000 Proxy Statement will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to December 31, 1999. Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to executive officers of the Company is set forth in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by reference to the 2000 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1999. 33 34 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to the 2000 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1999. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The information required by this item is incorporated herein by reference to the 2000 Proxy Statement which will be filed with the Commission not later than 120 days subsequent to December 31, 1999. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a)(1) FINANCIAL STATEMENTS THE RESPONSE TO THIS ITEM IS SUBMITTED IN A SEPARATE SECTION OF THIS REPORT. (a)(2) FINANCIAL STATEMENT SCHEDULES All schedules and other statements for which provision is made in the applicable regulations of the Commission have been omitted because they are not required under the relevant instructions or are inapplicable. (a)(3) EXHIBITS +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1998 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company (Incorporated herein by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). +3.2 -- Statement of Resolution Establishing Series of Shares designated 9% Series A Preferred Stock (Incorporated herein by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). +3.3 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915) and Amendment No. 2 (Incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999). +4.1 -- First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated August 28, 1998 (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998). +4.2 -- First Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 23, 1998 (Incorporated herein by reference to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). +4.3 -- Second Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 30, 1998 (Incorporated herein by reference to Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 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 34 35 to furnish a copy of such instruments to the Commission upon request. +4.4 -- Fourth Amendment to First Amended, Restated, and Combined Loan Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank (Incorporated herein by reference to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999). +4.5 -- Limited Guaranty by Douglas A. P. Hamilton for the benefit of Compass Bank (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999). +4.6 -- Notice of Final Agreement with respect to a term loan from Compass Bank (Incorporated herein by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999). +4.7 -- Limited Guaranty by Paul B. Loyd, Jr. for the benefit of Compass Bank (Incorporated herein by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999). +4.8 -- Limited Guaranty by Steven A. Webster for the benefit of Compass Bank (Incorporated herein by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999). +10.1 -- Incentive Plan of the Company (Incorporated herein by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.2 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.3 -- Employment Agreement between the Company and Frank A. Wojtek (Incorporated herein by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.4 -- Employment Agreement between the Company and Kendall A. Trahan (Incorporated herein by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.5 -- Employment Agreement between the Company and George Canjar (Incorporated herein by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.6 -- Indemnification Agreement between the Company and each of its directors and executive officers (Incorporated herein by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). +10.7 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.8 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). 35 36 +10.9 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated January 8, 1999). +10.10 -- Amended Enron Warrant Certificates (Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.11 -- Securities Purchase Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.12 -- Shareholders Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.13 -- Warrant Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.14 -- Registration Rights Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.15 -- Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.16 -- Compliance Sideletter dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.17 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.18 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the Company's Current Report on Form 8-K dated December 15, 1999). 21.1 -- Subsidiaries of the Company. 23.1 -- Consent of Arthur Andersen LLP. 23.2 -- Consent of Ryder Scott Company Petroleum Engineers. 23.3 -- Consent of Fairchild, Ancell & Wells, Inc. 27.1 -- Financial Data Schedule. 99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 1999. 99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells, Inc. as of December 31, 1999. - ---------- + Incorporated by reference as indicated. REPORTS ON FORM 8-K On December 3, 1999, the Company filed a Current Report on Form 8-K to report under Item 5 thereof that it had signed agreements relating to certain of the transactions later describe in the December 22, 1999 Form 8-K. On December 22, 1999, the Company filed a Current Report on Form 8-K to report under Item 5 thereof of the following transactions: (a) the sale of $22,000.00 face value 9% Senior Subordinated Notes due 2007. (b) the sale of 3,634,364 shares of the Company's Common Stock for $2.20 per share. (c) the sale of Warrants to purchase up to 2,760,189 shares of the Company's Common Stock at $2.20 per share. (d) the repurchase of all the Company's outstanding Preferred Stock, the repurchase of 750,000 of the Company's outstanding Warrants and the reduction of the exercise price of the remaining 250,000 Warrants from $11.50 to $4.00 per share. (e) the Company's execution of a securities purchase agreement, a Shareholders' Agreement, new and amended registration rights agreements, a compliance sideletter, amendments to employment agreements, bylaws and certain other agreements. (f) the execution of the Ninth Amendment to the First Amended Restated and Combined Loan Agreement dated August 28, 1997, between the Company and Compass Bank. 36 37 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CARRIZO OIL & GAS, INC. By: /s/ FRANK A. WOJTEK ------------------------------------- Frank A. Wojtek Chief Financial Officer, Vice President, Secretary and Treasurer Date: March 30, 2000. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
NAME CAPACITY DATE -------------------------- -------------------------- -------------- /s/ S. P. JOHNSON IV President, Chief Executive March 30, 2000 -------------------- Officer and Director (Principal S. P. Johnson IV Executive Officer) /s/ FRANK A. WOJTEK Chief Financial Officer, Vice March 30, 2000 ------------------- President, Secretary, Treasurer Frank A. Wojtek and Director (Principal Financial Officer and Principal Accounting Officer) /s/ STEVEN A. WEBSTER Chairman of the Board March 30, 2000 --------------------- Steven A. Webster /s/ DOUGLAS A. P. HAMILTON Director March 30, 2000 -------------------------- Douglas A. P. Hamilton /s/ PAUL B. LOYD, JR. Director March 30, 2000 --------------------- Paul B. Loyd, Jr. /s/ CHRISTOPHER C. BEHRENS Director March 30, 2000 -------------------------- Christopher C. Behrens /s/ ARNOLD L. CHAVKIN Director March 30, 2000 -------------------------- Arnold L. Chavkin
37 38 CARRIZO OIL & GAS, INC. INDEX TO FINANCIAL STATEMENTS
PAGE ---- Carrizo Oil & Gas, Inc. -- Report of Independent Public Accountants.......................................... F-2 Balance Sheets, December 31, 1998 and 1999........................................ F-3 Statements of Operations for the Years Ended December 31, 1997, 1998 and 1999.......................................................................... F-4 Statements of Shareholders' Equity for the Years Ended December 31, 1997, 1998 and 1999....................................................................... F-5 Statements of Cash Flows for the Years Ended December 31, 1997, 1998 and 1999...... F-6 Notes to Financial Statements...................................................... F-7
F-1 39 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Carrizo Oil & Gas, Inc.: We have audited the accompanying balance sheets of Carrizo Oil & Gas, Inc. (a Texas corporation) as of December 31, 1998 and 1999, and the related statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1999. 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 auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1998 and 1999, and the results of its operations and cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. As explained in Note 9 to the financial statements, effective January 1, 1999, the Company changed its method of accounting for start up costs. ARTHUR ANDERSEN LLP Houston, Texas March 17, 2000 F-2 40 CARRIZO OIL & GAS, INC. BALANCE SHEETS
ASSETS As of December 31, ---------------------------- 1998 1999 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents $ 1,187,656 $ 11,345,618 Accounts receivable, net of allowance for doubtful accounts of $480,000 at December 31, 1999 4,227,365 4,424,283 Advances to operators 1,192,079 1,266,770 Other current assets 117,614 487,398 ------------ ------------ Total current assets 6,724,714 17,524,069 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and gas properties) (Note 3) 57,878,191 64,336,738 DEFERRED INCOME TAXES -- 820,252 OTHER ASSETS 385,127 985,315 ------------ ------------ $ 64,988,032 $ 83,666,374 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade $ 7,886,536 $ 4,095,567 Accrued liabilities 2,004,536 481,239 Advances for joint operations 387,420 1,066,203 Current maturities of long-term debt 930,000 3,542,742 ------------ ------------ Total current liabilities 11,208,492 9,185,751 LONG-TERM DEBT 11,126,000 33,627,265 COMMITMENTS AND CONTINGENCIES (Note 6) MANDATORILY REDEEMABLE PREFERRED STOCK (10,000,000 shares authorized with 320,110.53 shares issued and outstanding at December 31, 1998)(Note 8) Issued and outstanding 30,730,695 -- Dividends payable 720,360 -- SHAREHOLDERS' EQUITY: Warrants (1,000,000 and 3,010,189 outstanding at December 31, 1998 and 1999, respectively) 300,000 765,047 Common stock (40,000,000 shares authorized with 10,375,000 and 14,011,364 issued and outstanding at December 31, 1998 and 1999, respectively) (Note 8) 103,750 140,114 Additional paid in capital 32,845,727 62,608,343 Accumulated deficit (21,907,082) (22,660,146) Deferred compensation (139,910) -- ------------ ------------ 11,202,485 40,853,358 ------------ ------------ $ 64,988,032 $ 83,666,374 ============ ============
The accompanying notes are an integral part of these financial statements. F-3 41 CARRIZO OIL & GAS, INC. STATEMENTS OF OPERATIONS
For the Year Ended December 31, -------------------------------------------- 1997 1998 1999 ------------ ------------ ------------ OIL AND NATURAL GAS REVENUES $ 8,711,654 $ 7,858,502 $ 10,204,345 COSTS AND EXPENSES: Oil and natural gas operating expenses (exclusive of depreciation shown separately below) 2,334,009 2,769,595 3,035,610 Depreciation, depletion and amortization 2,358,256 3,951,548 4,301,268 Write-down of oil and gas properties -- 20,305,448 -- General and administrative 1,590,358 2,667,234 2,195,364 ------------ ------------ ------------ Total costs and expenses 6,282,623 29,693,825 9,532,242 ------------ ------------ ------------ OPERATING INCOME (LOSS) 2,429,031 (21,835,323) 672,103 OTHER INCOME AND EXPENSES: Interest income 53,417 293,736 47,494 Interest expense (713,999) (300,083) (1,549,205) Interest expense, related parties (137,067) -- (33,454) Capitalized interest 699,625 291,496 1,547,879 ------------ ------------ ------------ INCOME (LOSS) BEFORE INCOME TAXES 2,331,007 (21,550,174) 684,817 INCOME TAXES (Note 5) 2,300,267 (2,218,027) (1,057,208) ------------ ------------ ------------ NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 30,740 (19,332,147) 1,742,025 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE -- -- (77,731) NET OF INCOME TAXES ------------ ------------ ------------ NET INCOME (LOSS) $ 30,740 $(19,332,147) $ 1,664,294 ============ ============ ============ DISCOUNT ON REDEMPTION OF PREFERRED STOCK (Note 8) -- -- 21,868,413 DIVIDENDS AND ACCRETION ON PREFERRED STOCK -- (2,940,625) (2,417,358) ------------ ------------ ------------ NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS $ 30,740 $(22,272,772) $ 21,115,349 ============ ============ ============ BASIC AND DILUTED EARNINGS (LOSS) PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (Note 2) $ -- $ (2.15) $ 2.01 ============ ============ ============ CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES $ -- $ -- $ (0.01) ============ ============ ============ BASIC AND DILUTED EARNINGS (LOSS) PER COMMON SHARE (Note 2) $ -- $ (2.15) $ 2.00 ============ ============ ============ BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (Note 2) 8,638,699 10,375,000 10,544,365 ============ ============ ============ DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (Note 2) 8,809,572 10,375,000 10,546,251 ============ ============ ============
The accompanying notes are an integral part of these financial statements. F-4 42 CARRIZO OIL & GAS, INC. STATEMENTS OF SHAREHOLDERS' EQUITY (NOTES 1 AND 2)
WARRANTS COMMON STOCK ----------------------- ----------------------- ADDITIONAL RETAINED PAID IN EARNINGS DEFERRED SHAREHOLDERS' NUMBER AMOUNT SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION EQUITY ---------- ----------- ----------- ----------- ----------- ------------ ------------- ------------- BALANCE, January 1, 1997 -- $ -- 7,500,000 $ 75,000 $ 4,186,000 $ 334,950 $ -- $ 4,595,950 Net income -- -- -- -- -- 30,740 -- 30,740 Distributions -- -- -- -- (90,000) -- -- (90,000) Common stock issued -- -- 2,875,000 28,750 28,050,049 -- -- 28,078,799 Deferred compensations related to certain stock options -- -- -- -- 699,678 -- (699,678) -- Amortization of deferred compensation -- -- -- -- -- -- 279,872 279,872 ---------- ----------- ----------- ----------- ----------- ------------ ------------- ------------ BALANCE, December 31, 1997 -- $ -- 10,375,000 $ 103,750 $32,845,727 $ 365,690 $ (419,806) $ 32,895,361 Net loss -- -- -- -- -- (19,332,147) -- (19,332,147) Warrants issued 1,000,000 300,000 -- -- -- -- -- 300,000 Dividends and accretion on preferred shares -- -- -- -- -- (2,940,625) -- (2,940,625) Amortization of deferred compensation -- -- -- -- -- -- 279,896 279,896 ---------- ----------- ----------- ----------- ----------- ------------ ------------- ------------ BALANCE, December 31, 1998 1,000,000 $ 300,000 10,375,000 $ 103,750 $32,845,727 $(21,907,082) $ (139,910) $ 11,202,485 Net income -- -- -- -- -- 1,664,294 -- 1,664,294 Warrants issued 2,760,189 690,047 -- -- -- -- -- 690,047 Warrants cancelled (750,000) (225,000) -- -- 225,000 -- -- -- Common stock issued -- -- 3,636,364 36,364 7,669,203 -- -- 7,705,567 Redemption of preferred stock -- -- -- -- 21,868,413 -- -- 21,868,413 Dividends and accretion on preferred stock (2,417,358) (2,417,358) Amortization of deferred compensation -- -- -- -- -- -- 139,910 139,910 ---------- ----------- ----------- ----------- ----------- ------------ ------------- ------------ BALANCE, December 31, 1999 3,010,189 $ 765,047 14,011,364 $ 140,114 $62,608,343 $(22,660,146) $ -- $ 40,853,358 ========== =========== =========== =========== =========== ============ ============= ============
The accompanying notes are an integral part of these financial statements. F-5 43 CARRIZO OIL & GAS, INC. STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, -------------------------------------------- 1997 1998 1999 ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (loss) $ 30,740 $(19,332,147) $ 1,664,294 Adjustment to reconcile net income (loss) to net cash provided by operating activities - Depreciation, depletion and amortization 2,358,256 3,951,548 4,301,268 Discount accretion -- -- 3,537 Interest payable in kind -- -- 48,822 Cumulative effect of change in accounting principle -- -- 77,731 Write-down of oil and gas properties -- 20,305,448 -- Deferred income taxes 2,300,267 (2,300,267) (1,085,216) Changes in assets and liabilities - Accounts receivable (1,819,598) (591,861) (196,918) Other current assets (93,161) (8,981) (369,784) Other assets -- (249,175) (746,556) Accounts payable 475,268 416,447 26,580 Accrued liabilities (183,845) 195,788 (1,523,298) ------------ ------------ ------------ Net cash provided by operating activities 3,067,927 2,386,800 2,200,460 ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures - accrual basis (32,234,351) (36,569,773) (10,286,305) Adjustment to cash basis 5,911,784 (1,233,970) (3,817,547) Advances to operators (1,817,990) 625,911 (74,691) Advances for joint operations -- 387,420 678,783 ------------ ------------ ------------ Net cash used in investing activities (28,140,557) (36,790,412) (13,499,760) ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from sale of common stock 28,078,799 -- 7,705,567 Net proceeds from sale of preferred stock and warrants -- 28,810,431 690,047 Net proceeds from debt issuance 18,544,454 12,056,000 31,235,257 Debt repayments (20,408,934) (7,950,000) (8,173,609) Proceeds from related party notes 130,545 -- 2,000,000 Redemption of preferred stock -- -- (12,000,000) Capital distributions (90,000) -- -- ------------ ------------ ------------ Net cash provided by financing activities 26,254,864 32,916,431 21,457,262 ------------ ------------ ------------ NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1,182,234 (1,487,181) 10,157,962 CASH AND CASH EQUIVALENTS, beginning of year 1,492,603 2,674,837 1,187,656 ------------ ------------ ------------ CASH AND CASH EQUIVALENTS, end of year $ 2,674,837 $ 1,187,656 $ 11,345,618 ============ ============ ============ SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized) $ 151,441 $ 8,587 $ 31,243 ============ ============ ============
The accompanying notes are an integral part of these financial statements. F-6 44 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS, COMBINATION AND OFFERING NATURE OF OPERATIONS Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its affiliates and predecessors, the Company) is an independent energy company engaged in the exploration, development, exploitation and production of oil and natural gas. Its 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 1,841 square miles of 3-D seismic data. Additionally, the Company has assembled approximately 195,464 gross acres under lease or option. The exploration for oil and gas is a business with a significant amount of inherent risk requiring large amounts of capital. The Company intends to finance the exploration and development of its significant 3-D seismic data and its acreage under lease or option through cash from operations, existing credit facilities or arrangements with other industry participants. Should the sources of capital currently available to the Company not be sufficient to explore and develop its prospects and meet current and near-term obligations, the Company may be required to seek additional sources of financing which may not be available on terms acceptable to the Company. This lack of additional financing could force the Company to curtail its planned drilling program. THE COMBINATION Carrizo was formed in 1993 and is the surviving entity after a series of combination transactions (the Combination) consummated on August 11, 1997. The Combination included the following transactions: (a) Carrizo Production, Inc. (a Texas corporation and an affiliated entity with ownership identical to Carrizo) was merged into Carrizo and the outstanding shares of capital stock of Carrizo Production, Inc. were exchanged for an aggregate of 343,000 shares of common stock of Carrizo (the Common Stock); (b) Carrizo acquired Encinitas Partners Ltd. (a Texas limited partnership of which Carrizo Production, Inc. served as the general partner) as follows: Carrizo acquired from the shareholders who serve as directors of Carrizo (the Founders) their limited partner interests in Encinitas Partners Ltd. for an aggregate consideration of 468,533 shares of Common Stock and, on the same date, Encinitas Partners Ltd. was merged into Carrizo and the outstanding limited partner interests in Encinitas Partners Ltd. were exchanged for an aggregate of 860,699 shares of Common Stock; (c) La Rosa Partners Ltd. (a Texas limited partnership of which Carrizo served as the general partner) was merged into Carrizo and the outstanding limited partner interests in La Rosa Partners Ltd. were exchanged for an aggregate of 48,700 shares of Common Stock; and (d) Carrizo Partners Ltd. (a Texas limited partnership of which Carrizo served as the general partner) was merged into Carrizo and the outstanding limited partner interests in Carrizo Partners Ltd. were exchanged for an aggregate of 569,068 shares of Common Stock. The Combination was accounted for as a reorganization of entities as prescribed by Securities and Exchange Commission (SEC) Staff Accounting Bulletin 47 because of the high degree of common ownership among, and the common control of, the combining entities. Accordingly, the accompanying financial statements were prepared using the historical costs and results of operations of the affiliated entities up to the date of the Combination. There were no significant differences in accounting methods or their application among the combining entities. All intercompany balances have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period's financial statement presentation. INITIAL PUBLIC OFFERING Simultaneous with the Combination, the Company completed its initial public offering (the Offering) of 2,875,000 shares of its common stock at a public offering price of $11.00 per share. The Offering provided the Company with proceeds of approximately $28.1 million, net of expenses. SALE OF SENIOR SUBORDINATED NOTES, COMMON STOCK AND WARRANTS In December 1999, the Company consummated the sale of $22 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. which included certain members of the Board of Directors. The Subordinated Notes were sold at a discount of $688,761 which is being amortized over the life of the notes. Interest is payable quarterly beginning March 31, 2000. The Company may elect, for a period of five years, to increase the amount of the Subordinated Notes for up to 60% of the interest which would otherwise be payable in cash. Concurrent with the sale of the notes, the Company consummated the sale of 3,636,364 shares of Common Stock at a price of $2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's Common Stock at an exercise price of $2.20 per share. For accounting purposes, the Warrants are valued at $0.25 per Warrant. The sale was made to an investor group led by CB Capital Investors, L.P. which included certain members of the Board of Directors. The Warrants have an exercise price of $2.20 per share and expire in December 2007. Of the approximately $29,000,000 net proceeds of this financing, $12,060,000 was used to fund the Enron Repurchase described below and related expenses, $2,025,000 was used to repay the bridge loan extended to the Company by its outside directors, $2 million was used to repay a portion of the Compass Term Loan, $1 million was used to repay a portion of the Compass Borrowing Base Facility, and the Company expects the remaining proceeds to be used to fund the Company's ongoing exploration and development program and general corporate purposes. In December 1999, the Company consummated the repurchase of all the outstanding shares of Preferred Stock and 750,000 Warrants for $12 million. At the same time, the Company reduced the exercise price of the remaining 250,000 Warrants from $11.50 per share to $4.00 per share. 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. As of December 31, 1998 and 1999, the Company also capitalized as oil and natural gas properties $279,896 and $139,910, respectively, of deferred compensation related to stock options granted to personnel directly associated with exploration activities. (See Note 7.) Oil and natural gas properties are amortized based on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. Unevaluated properties are evaluated quarterly for impairment on a property-by-property basis. If the results of an F-7 45 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 1997, 1998 and 1999, was $0.69, $1.06 and $1.00, respectively. Dispositions of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The net capitalized costs of proved oil and gas properties are subject to a "ceiling test," which limits such costs to the estimated present value, discounted at a 10 percent interest rate, of future net cash flows from proved reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. No write-down of the Company's oil and natural gas assets was necessary in 1997 or 1999. Primarily as a result of downward reserve quantity revisions combined with depressed oil and natural gas prices, the Company recorded a ceiling test write-down of $20,305,448 in 1998. 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 Long-term debt financing costs included in other assets of $300,005 and $985,315 as of December 31, 1998 and 1999, respectively, are being amortized over the term of the loans (through January 1, 2002 for a credit facility and through December 15, 2007 for subordinated notes payable). STATEMENTS OF CASH FLOWS For statement of cash flow purposes, all highly liquid investments with original maturities of three months or less are considered to be cash equivalents. FINANCIAL INSTRUMENTS The Company's financial instruments consist of cash, receivables, payables and long-term debt. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying amount of long-term debt (except the subordinated notes payable) 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 with the hedged item when the hedged transaction occurs. Should the necessary correlation between the hedged item and the designated hedging instrument be lost, the future gain or loss would no longer be deferred and would be recognized in the period the correlation is lost. Total oil and natural gas quantities sold under swap arrangements in 1997, 1998, and 1999 were 0 Bbls, 0 Bbls and 45,200 Bbls, respectively, and 210,000 MMBtu, 1,760,000 MMBtu, and 2,050,000 MMBtu, respectively. Hedging gains (losses) are included in oil and natural gas revenues and amounted to $48,000, $167,000 and ($412,000) for the years ended December 31, 1997, 1998 and 1999, respectively. At December 31, 1998, the Company had no outstanding hedged positions. At December 31, 1999, the Company had 300,000 MMBtu and 30,200 Bbls of outstanding hedge positions (at an average price of $2.33 per MMBtu and $25.60 per Bbl for January through June 2000 production.) The instruments had a fair market value of $2,000 at December 31, 1999. INCOME TAXES Through May 15, 1997, Carrizo and its affiliated entities had elected to be treated as S Corporations under the Internal Revenue Code or were otherwise not taxed as entities for federal income tax purposes. The taxable income or loss was therefore allocated to the equity owners of Carrizo and the affiliated entities. The Company entered into tax indemnification agreements with the founders of the Company pertaining to periods in which the Company was an S Corporation. F-8 46 On May 16, 1997, Carrizo terminated its status as an S corporation and thereafter became subject to federal income taxes. The Company, beginning with the termination of its tax exempt status, provides income taxes for the difference in the tax and financial reporting bases of its assets and liabilities in accordance with Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." The termination of its tax exempt status in 1997 required the Company to establish a deferred tax liability, which resulted in a one-time noncash charge to income in 1997 of $1,623,000. Had Carrizo been a taxpaying entity prior to May 17, 1997, its net income and earnings per share would have been as follows:
Unaudited Pro Forma 1997 ----------- Net income (after pro forma income taxes of $816,852) $ 1,514,155 =========== Diluted earnings per share $ 0.17 =========== Weighted average diluted number of common shares outstanding 8,809,572 ===========
USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Significant estimates include depreciation, depletion and amortization of proved oil and natural gas properties. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, are inherently imprecise and are expected to change as future information becomes available. CONCENTRATION OF CREDIT RISK Substantially all of the Company's accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced credit losses on such receivables. EARNINGS PER SHARE Supplemental earnings per share information is provided below: F-9 47
FOR THE YEAR ENDED DECEMBER 31 ------------------------------------------------------------------------------- INCOME SHARES ------------------------------------ ----------------------------------------- 1997 1998 1999 1997 1998 1999 -------- ------------ ------------ ----------- ------------ ----------- Net income (loss) before cumulative effect of change in accounting principle $ 30,740 $(19,332,147) $ 1,742,025 Plus: Discount on redemption of preferred stock -- -- 21,868,413 Less: Dividends and accretion on preferred stock -- (2,940,625) (2,417,358) -------- ------------ ------------ Basic earnings per share before cumulative effect of change in accounting principle Net Income (loss) available to common shareholders 30,740 (22,272,772) 21,193,080 8,638,699 10,375,000 10,544,365 Stock options -- -- -- 170,873 -- 1,886 -------- ------------ ------------ ----------- ------------ ----------- Diluted earnings per share before cumulative effect of change in accounting principle Net Income (loss) available to common shareholders plus assumed conversions $ 30,740 $(22,272,772) $ 21,193,080 8,809,572 10,375,000 10,546,251 ======== ============ ============ =========== ============ ============ Cumulative effect of change in accounting principle $ -- $ -- $ (77,731) Basic earnings per share of cumulative effect of change in accounting principle Net loss available to common shareholders -- -- (77,731) 8,638,699 10,375,000 10,544,365 Stock Options -- -- -- 170,873 -- 1,886 -------- ------------ ------------ ----------- ------------ ----------- Diluted earnings per share of cumulative effect of change in accounting principle Net loss available to common shareholders plus assumed conversions $ -- $ -- $ (77,731) 8,809,572 10,375,000 10,546,251 ======== ============ ============ =========== ============ ============ Net income (loss) $ 30,740 $(19,332,147) $ 1,664,294 Plus: Discount on redemption of preferred stock -- -- 21,868,413 Less: Dividends and accretion on preferred stock -- (2,940,625) (2,417,358) -------- ------------ ------------ Basic earnings per share Net income (loss) available to common shareholders 30,740 (22,272,772) 21,115,349 8,638,699 10,375,000 10,544,365 Stock options -- -- -- 170,873 -- 1,886 -------- ------------ ------------ ----------- ------------ ----------- Diluted earnings per share Net income (loss) available to common shareholders plus assumed conversions $ 30,740 $(22,272,772) $ 21,115,349 8,809,572 10,375,000 10,546,251 ======== ============ ============ =========== ============ ============ ---------------------------------- PER-SHARE AMOUNT ---------------------------------- 1997 1998 1999 ---------- --------- -------- Net income (loss) before cumulative effect of change in accounting principle Plus: Discount on redemption of preferred stock Less: Dividends and accretion on preferred stock Basic earnings per share before cumulative effect of change in accounting principle Net Income (loss) available to common shareholders $ -- $ (2.15) $ 2.01 ========== ========= ======== Stock options Diluted earnings per share before cumulative effect of change in accounting principle Net Income (loss) available to common shareholders plus assumed conversions $ -- $ (2.15) $ 2.01 ========== ========= ======== Cumulative effect of change in accounting principle Basic earnings per share of cumulative effect of change in accounting principle Net loss available to common shareholders $ -- $ -- $ (0.01) ========== ========= ======== Stock Options Diluted earnings per share of cumulative effect of change in accounting principle Net loss available to common shareholders plus assumed conversions $ -- $ -- $ (0.01) ========== ========= ======== Net income (loss) Plus: Discount on redemption of preferred stock Less: Dividends and accretion on preferred stock Basic earnings per share Net income (loss) available to common shareholders $ -- $ (2.15) $ 2.00 ========== ========= ======== Stock options Diluted earnings per share Net income (loss) available to common shareholders plus assumed conversions $ -- $ (2.15) $ 2.00 ========== ========= ========
Net income (loss) per common share has been computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the periods. During the years ended December 31, 1997, 1998 and 1999, respectively, the Company had outstanding 250,000, 443,550 and 799,620 stock options, respectively, and warrants to purchase 1,000,000 and 3,010,189 shares of common stock at December 31, 1998 and 1999, respectively, which were antidilutive and were therefore not included in the calculation because the exercise price of these instruments exceeded the underlying market value of the options and warrants. CONTINGENCIES Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimatable. Costs to remedy or defend against such contingencies are charged to the liability, if one exists, or otherwise to income. NEW ACCOUNTING PRONOUNCEMENTS In September 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes accounting and F-10 48 reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging activities - Deferral of the Effective Date of SFAS No. 133" is effective for fiscal years beginning after June 15, 2000. A Company may also implement the Statement as of the beginning of any fiscal quarter after issuance. Statement No. 133 cannot be applied retroactively. Statement No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1998 and, at the company's election, before January 1, 1999. The Company routinely enters into financial instrument contracts to hedge price risks associated with the sale of crude oil and natural gas. Statement No. 133 amends, modifies and supercedes significantly all of the authoritative literature governing the accounting for and disclosure of derivative financial instruments and hedging activities. As a result, adoption of Statement No. 133 will impact the accounting for and disclosure of the Company's operations. The Company intends to adopt the provisions of such statement in accordance with the requirements provided by the statement. Management is currently assessing the financial statement impact; however, such impact is not determinable at this time. 3. PROPERTY AND EQUIPMENT At December 31, 1998 and 1999, property and equipment consisted of the following:
DECEMBER 31, ---------------------------- 1998 1999 ------------ ------------ Proved oil and natural gas properties $ 48,390,909 $ 57,719,508 Unproved oil and natural gas properties 37,060,418 38,145,486 Other equipment 295,854 308,402 ------------ ------------ Total property and equipment 85,747,181 96,173,396 Accumulated depreciation, depletion and amortization (27,868,990) (31,836,658) ------------ ------------ Property and equipment, net $ 57,878,191 $ 64,336,738 ============ ============
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 unproved costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and natural gas leases not held by production, production response to secondary recovery activities and available funds for exploration and development. Of the $38,145,486 of unproved property costs at December 31, 1999 being excluded from the amortizable base, $11,817,865, $22,161,588 and $4,166,033 were incurred in 1997, 1998 and 1999, respectively. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two years. 4. INCOME TAXES Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows:
YEAR ENDED DECEMBER 31, ---------------------------------------- 1997 1998 1999 ----------- ----------- ----------- Provision at the statutory tax rate $ 816,852 $(7,542,561) $ 240,488 Increase (decrease) in valuation allowance pertaining to expected net operating loss utilization -- 5,324,534 (1,297,696) Increase resulting from change in tax exempt status 1,483,415 -- -- ----------- ----------- ----------- Income tax provision (benefit) $ 2,300,267 $(2,218,027) $(1,057,208) =========== =========== ===========
F-11 49 Deferred income tax provisions result from temporary differences in the recognition of income and expenses for financial reporting purposes and for tax purposes. At December 31, 1998 and 1999, the tax effects of these temporary differences resulted principally from the following:
AS OF DECEMBER 31, -------------------------- 1998 1999 ----------- ----------- Deferred income tax asset: Statutory depletion carryfoward $ 78,159 $ 78,159 Timing differences and net operating losses 10,091,730 11,305,810 Valuation allowance (8,255,902) (7,843,009) ----------- ----------- 1,913,987 3,540,960 Deferred income tax liabilities: Intangible drilling costs 1,378,171 1,378,171 Capitalized interest 535,816 1,077,573 ----------- ----------- 1,913,987 2,455,744 ----------- ----------- Net deferred income tax asset $ -- $ 1,085,216 =========== ===========
The net deferred income tax asset is classified as follows:
AS OF DECEMBER 31, ------------------------- 1998 1999 -------- ---------- Other current assets $ -- $ 264,964 Deferred income taxes -- 820,252 -------- ---------- $ -- $1,085,216 ======== ==========
Realization of the net deferred tax asset is dependent on the Company's ability to generate taxable earnings in the future. Management believes that it is more likely than not that the deferred tax asset, net of the valuation allowance, will be fully realized. The Company has net operating loss carryforwards totaling approximately $12 million which begin expiring in 2012. 5. LONG-TERM DEBT: At December 31, 1998 and 1999, long-term debt consisted of the following:
AS OF DECEMBER 31, ---------------------------- 1998 1999 ------------ ------------ Credit facility: Borrowing base facility $ 5,056,000 $ 5,876,000 Term loan facility 7,000,000 7,000,000 Senior subordinated notes -- 19,226,082 Senior subordinated notes, related parties -- 2,136,230 Vendor notes payable -- 2,931,695 ------------ ------------ 12,056,000 37,170,007 Less: current maturities (930,000) (3,542,742) ------------ ------------ $ 11,126,000 33,627,265 ============ ============
In connection with the Offering, Carrizo amended its existing credit facility with Compass Bank ("Compass"), to provide for a maximum loan amount of $25 million, subject to borrowing base limitations. Under this facility, the principal outstanding is due and payable upon maturity in January 2002, with interest due monthly. This facility was subsequently amended in September 1998 to provide for a term loan under the facility (the "Term Loan") in addition to the then existing revolving credit facility limited by the Company's borrowing base (the "Borrowing Base Facility"). The Borrowing Base Facility was amended in March, 1999 to provide for a maximum loan amount under such facility of $10 million. Substantially all of Carrizo's oil and natural gas property and equipment is pledged as collateral under this facility. The interest rate for both borrowings is calculated at a floating rate based on the Compass index rate or LIBOR plus 2 percent. The Company's obligations are secured by certain of its oil and gas properties and cash or cash equivalents included in the borrowing base. The Borrowing Base Facility and the Term Loan are referred to collectively as the "Company Credit Facility". Proceeds from the Borrowing Base portions of this credit facility have been used to provide funding for exploration and development activity. F-12 50 Under the Borrowing Base 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 also redetermine the borrowing base and the monthly borrowing base reduction at any time at its discretion. The Company may also request borrowing base redeterminations in addition to the required semiannual reviews at the Company's cost. At December 31, 1998 and 1999, amounts outstanding under the Borrowing Base Facility totaled $5,056,000 and $5,876,000, respectively, with an additional $1,020,000 and $1,208,392, respectively, available for future borrowings. The Borrowing Base totaled $7,308,382 at December 31, 1999. The Borrowing Base Facility was also available for letters of credit, one of which has been issued for $224,000 at December 31, 1998 and 1999. The weighted average interest rates for 1998 and 1999 on the Facility were 8 and 9 percent, respectively. Certain members of the Board of Directors have provided $4 million in collateral primarily in the form of marketable securities to secure the Borrowing Base Facility. The Term Loan was initially due and payable upon maturity in September 1999. The Company had $7,000,000 outstanding under the Term Loan at December 31, 1998. In March 1999, the Company borrowed an additional $2 million on the term loan portion of the Company Credit Facility, increasing outstanding borrowings under the Term Loan to $9 million. In March 1999, the maturity date of the Term Loan was amended to provide for twelve monthly installments of $750,000 beginning January 1, 2000. In December 1999, the additional $2 million under the term loan was repaid with proceeds from the sale of subordinated notes, common stock and warrants leaving $7,000,000 outstanding at December 31, 1999. The repayment terms were also amended to provide for $1.74 million of principal due ratably over the last six months of 2000, $2.64 million of principal due ratably over the first six months of 2001, and the balance due in July 2001. Certain members of the Board of Directors have guaranteed the Term Loan. The Company is subject to certain covenants under the terms of the Company Credit Facility, including but not limited to (a) maintenance of specified tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly debt service of not less than 1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company Credit Facility also places restrictions on, among other things, (a) incurring additional indebtedness, guaranties, loans and liens, (b) changing the nature of business or business structure, (c) selling assets and (d) paying dividends. In March 1999, the Company Credit Facility was amended to decrease the required specified tangible net worth covenant. In November 1999, certain members of the Board of Directors provided a bridge loan in the amount of $2,000,000 to the Company secured by certain oil and natural gas properties. This bridge loan bore interest at 14% per annum. Also, in consideration for the bridge loan, the Company assigned to those members of the Board of Directors an overriding royalty interest in certain of the Company's producing properties. The bridge loan was repaid from the proceeds of the sale of Subordinated notes, common stock and warrants. In December 1999, the Company consummated the sale of $22 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. which included certain members of the Board of Directors. As discussed in Note 7, the Company also sold Common Stock and Warrants to this investor group. The Subordinated Notes were sold at a discount of $688,761, which is being amortized over the life of the notes. Interest is payable quarterly beginning March 31, 2000. The Company may elect to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. Such Senior Subordinated Notes had a fair market value at December 31, 1999 (16 days subsequent to issuance) of approximately $22 million. The Company is subject to certain covenants under the terms under the Subordinated Notes securities purchase agreement, including but not limited to, (a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) a limitation of its capital expenditures to a specified amount for the year ended December 31, 2000 and thereafter equal to the Company's EBITDA for the immediately prior fiscal year. Estimated maturities of long-term debt are $3,542,742 in 2000, $6,388,953 in 2001, $5,576,000 in 2002 and the remainder in 2007. During 1999, Carrizo restructured certain current accounts payable into vendor notes, extending the payment dates through 2001. Such notes totaled $2,931,695 at December 31, 1999 and bear interest at rates of 8 percent to 10 percent. The weighted average interest rates of such notes was 9 percent in 1999. F-13 51 6. COMMITMENTS AND CONTINGENCIES From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. At December 31, 1999, Carrizo was obligated under a noncancelable operating lease for office space. Rent expense for the years ended December 31, 1997, 1998 and 1999, was $80,000, $108,700 and $108,700, respectively. The Company is obligated for remaining lease payments in 2000 of $54,350. 7. SHAREHOLDERS' EQUITY On June 4, 1997, the board of directors authorized a 521-for-1 split of the Company's common stock and increased the number of authorized shares to 40 million shares of common stock and 10 million shares of preferred stock. All common share amounts presented in these financial statements are presented on a retroactive, post-split basis. In December 1999, the Company consummated the sale of 3,636,364 shares of its Common Stock at a price of $2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's Common Stock valued at $0.25 per Warrant to an investor group led by CB Capital Investors, L.P. which included certain members of the Board of Directors. The Warrants have an exercise price of $2.20 per share and expire December 2007. In connection with an initial public offering, the Company recorded deferred compensation related to the March 1997 stock option agreement as additional paid-in capital and an offsetting contra-equity account. This compensation accrual is based on the difference between the option price and the fair value of Carrizo's common stock when the options were granted (using an estimate of the initial public offering common stock price as an estimate of fair value). The deferred compensation was amortized in the period in which the options vest, which resulted in $279,896 and $139,910 being recorded in the years ended December 31, 1998 and 1999, respectively. On July 19, 1996, and March 1, 1997, the Company entered into separate stock option agreements (the "Pre-IPO Options") with two executives of Carrizo whereby such employees were granted the option to purchase 138,825 shares and 83,295 shares of Carrizo common stock, respectively, at an exercise price of $3.60 per share. The options vested 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. The following table summarizes information for the options outstanding at December 31, 1999:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------- --------------------- WEIGHTED NUMBER OF AVERAGE WEIGHTED NUMBER OF WEIGHTED OPTIONS REMAINING AVERAGE OPTIONS AVERAGE OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE RANGE OF EXERCISE PRICES AT 12/31/99 LIFE IN YEARS PRICE AT 12/31/99 PRICE - ------------------------------------ ----------- ------------- -------- ----------- -------- $1.75-2.00 182,500 9.54 $ 1.96 -- -- $3.60 222,120 6.97 $ 3.60 222,120 $ 3.60 $6.00-7.00 172,500 8.44 $ 6.17 57,500 $ 6.17 $11.00 250,000 7.40 $ 11.00 166,667 $ 11.00
F-14 52 In June of 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. ("the Incentive Plan"). The Company accounts for this plan under APB Opinion No. 25, under which no compensation cost has been recognized. Had compensation cost been determined consistent with SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the Company's net income and earnings per share would have been as follows:
1997 1998 1999 -------- ------------- ------------ Net income (loss) available to common shareholders As reported $ 30,740 $ (22,272,772) $ 21,115,349 Pro forma $(75,582) $ (23,020,534) $ 20,292,252 Diluted earnings (loss) per share As reported $ -- $ (2.15) $ 2.00 Pro forma $ (0.01) $ (2.22) $ 1.94
The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants in 1997, 1998 and 1999: risk free interest rate of 6.26%, 5.81% and 6.81% respectively, expected dividend yield of 0%, expected life of 10 years and expected volatility of 39.4%, 80.6% and 70.0%, respectively. The Company may grant options ("Incentive Plan Options") to purchase up to 1,000,000 shares under the Incentive Plan and has granted options on 605,000 shares through December 31, 1999. Under the Incentive Plan, the option exercise price equals the stock market price on the date of grant. Options granted under the plan vest ratably over three years and have a term of ten years. Through December 31, 1999, no stock options had been exercised. A summary of the status of the Company's stock options at December 31, 1997, 1998 and 1999 is presented in the table below:
1997 ------------------------------------ WEIGHTED AVERAGE RANGE OF EXERCISE EXERCISE SHARES PRICES PRICES ---------- -------- ------------- Outstanding at beginning of year 138,825 $ 3.60 $3.60 Granted (Pre-IPO Options) 83,295 $ 3.60 $3.60 Granted (Incentive Plan Options) 250,000 $ 11.00 $11.00 ---------- -------- Outstanding at end of year 472,120 $ 7.52 $3.60 - 11.00 ========== ======== Exercisable at end of year 120,315 $ 3.60 Weighted average of fair value of options granted during year $ 6.90
1998 ------------------------------------ WEIGHTED AVERAGE RANGE OF EXERCISE EXERCISE SHARES PRICES PRICES ---------- -------- ------------- Outstanding at beginning of year 472,120 $ 7.52 $3.60-11.00 Granted (Incentive Plan Options) 193,500 $ 6.20 $6.00-6.88 ---------- -------- Outstanding at end of year 665,620 $ 6.63 $3.60-11.00 ========== ======== Exercisable at end of year 277,688 $ 5.80 Weighted average of fair value of options granted during year $ 3.00
F-15 53
1999 ------------------------------------ WEIGHTED AVERAGE RANGE OF EXERCISE EXERCISE SHARES PRICES PRICES ---------- -------- ------------- Outstanding at beginning of year 665,620 $ 6.63 $3.60 - 11.00 Granted (Incentive Plan Options) 206,500 $ 1.98 $1.75 - 2.00 Expired (Incentive Plan Options) (45,000) $ 4.06 $2.00 - 6.88 ---------- -------- Outstanding at end of year 827,120 $ 6.01 ========== ======== Exercisable at end of year 446,286 $ 6.70 Weighted average of fair value of options granted during the year $ 1.34
8. MANDATORILY REDEEMABLE PREFERRED STOCK In January 1998, the Company consummated the sale of 300,000 shares of Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to affiliates of Enron Corp. The net proceeds received by the Company from this transaction were approximately $28.8 million. A portion of the proceeds were used to repay indebtedness. The remaining proceeds were used primarily for oil and natural gas exploration and development activities in Texas and Louisiana. The Preferred Stock provided for annual cumulative dividends of $9.00 per share, payable quarterly in cash or, at the option of the Company until January 15, 2002, in additional shares of Preferred Stock. During 1999, the Company issued preferred stock dividends to the holders of the Preferred Stock of 29,684.39 shares. In December 1999, the Company consummated the repurchase of all the outstanding shares of Preferred Stock and 750,000 Warrants for $12 million. At the same time, the Company reduced the exercise price of the remaining 250,000 Warrants from $11.50 per share to $4.00 per share. This repurchase at a discount resulted in a credit of $21,868,413 which is included in net income available to common shareholders, net of stock dividends paid to the holders of the preferred stock of $2,417,358. 9. CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE: On January 1, 1999 the Company adopted the American Institute of Certified Public Accountants Statement of Position ("SOP") 98-5, which provides guidance on the accounting for start up costs. SOP 98-5 requires that start up costs be expensed as incurred. The cumulative effect of this change in accounting principle to write off unamortized organization costs is $77,731 in 1999. 10. BUSINESS COMBINATION During the fourth quarter of 1998, Carrizo acquired from Hall Houston Oil Company, Hall Houston 1996 Exploration and Development Facility Overriding Trust and Hall Houston Oil Company Employee Royalty Trust (referred to collectively as "Hall Houston") certain proved oil and gas properties located in Wharton County, Texas (the Hall Houston Properties Acquisition) for approximately $3 million. The Hall Houston Properties Acquisition was accounted for under the purchase method of accounting and, accordingly, the purchase cost was recorded as evaluated oil and gas properties. The results of operations of the acquired Hall Houston properties are included in the results of operations beginning on the date acquired. The following table reflects certain unaudited pro forma information for the periods presented as if the Hall Houston Properties Acquisition had occurred on January 1, 1997. F-16 54
YEAR ENDED DECEMBER 31, ----------------------------- 1997 1998 ----------- ------------- Pro forma revenues $ 8,718,736 $ 9,198,212 =========== ============= Pro forma net income (loss) $ 33,237 $ (18,523,141) =========== ============= Pro forma net income (loss) per share: Basic $ -- $ (2.07) =========== ============= Diluted $ -- $ (2.07) =========== =============
11. RELATED-PARTY TRANSACTIONS In August 1996, the Company entered into the Master Technical Services Agreement (the MTS Agreement) with Reading & Bates Development Co. (R&B), which is a subsidiary of R&B Falcon Corporation, a company that was created by the merger of Falcon Drilling, Inc. and Reading & Bates Corporation. Mr. Loyd, a member of the board of the Company, was the chairman of the board, president, chief executive officer and a director of Reading & Bates Corporation. Under the MTS Agreement, certain employees of the Company provide engineering and technical services to R&B at market rates in connection with R&B's technical service, procurement and construction projects in offshore drilling and floating production. The Company provided $103,161 in service fees under this agreement in 1997. No services were performed under this agreement in 1998 or 1999. The Company had an agreement with Loyd & Associates Inc., which is owned by Paul Loyd, a director of Carrizo, and Frank Wojtek, vice president, chief financial officer and a director of Carrizo, to provide certain financial consulting and administrative services at market rates to the Company. Payments were made monthly and total payments to Loyd & Associates Inc. for services rendered were $38,113 in 1997. These expenditures were included in general and administrative expenses for each year. This arrangement was terminated in August, 1997 concurrent with the Company's initial public offering. In September, 1998 and March, 1999, certain members of the Board of Directors guaranteed a portion of the Company's outstanding indebtedness, provided a bridge loan of $2 million which was repaid in December 1999, and purchased a portion of the subordinated notes payable. During the year ended December 31, 1999, the Company incurred drilling costs in the amount of $130,742 with R & B Falcon Corporation. Messrs. Loyd, Webster, Hamilton and Chavkin are members of the Board of Directors of both the Company and R & B Falcon Corporation ("R & B"). In addition, Mr. Loyd was the chairman of the board, president and chief executive officer of R & B and Mr. Webster was the Vice Chairman of R & B. It is management's opinion that these transactions were performed at prevailing market rates. 12. 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, --------------------------------------- 1997 1998 1999 ----------- ----------- ----------- Property acquisition costs Unproved $14,222,674 $ 9,618,647 $ 4,166,033 Proved 5,491,839 16,196,887 472,229 Exploration cost 9,328,210 10,429,247 3,163,309 Development costs 2,257,375 313,391 936,855 ----------- ----------- ----------- Total costs incurred (1) $31,300,098 $36,558,172 $ 8,738,426 =========== =========== ===========
- ---------- (1) Excludes capitalized interest on unproved properties of $699,625, $291,496 and 1,547,879 for the years ended December 31, 1997, 1998 and 1999, respectively. F-17 55 OIL AND NATURAL GAS RESERVES Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities at December 31, 1998 and 1999, 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. The Company's net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below:
BARRELS OF OIL AND CONDENSATE AT DECEMBER 31, -------------------------------------- 1997 1998 1999 ---------- ---------- ---------- Proved developed and undeveloped reserves - Beginning of year 3,895,000 5,169,500 3,647,000 Purchase of oil and gas properties -- 81,000 -- Discoveries 285,000 82,000 101,000 Extensions 1,102,000 14,000 12,000 Revisions -- (1,559,500) 1,296,000 Production (112,500) (140,000) (179,000) ---------- ---------- ---------- End of year 5,169,500 3,647,000 4,877,000 ========== ========== ========== Proved developed reserves at end of year 1,146,000 1,112,000 997,000 ========== ========== ==========
F-18 56
THOUSANDS OF CUBIC FEET OF NATURAL GAS AT DECEMBER 31, ----------------------------------------- 1997 1998 1999 ----------- ----------- ----------- Proved developed and undeveloped reserves - Beginning of year 12,148,000 12,142,000 10,155,000 Purchases of oil and gas properties 7,696,000 1,325,000 -- Discoveries and extensions 6,946,000 4,039,000 4,820,000 Revisions (7,190,000) (4,696,000) (417,000) Sales of oil and gas properties (4,709,000) -- -- Production (2,749,000) (2,655,000) (3,235,000) ----------- ----------- ----------- End of year 12,142,000 10,155,000 11,323,000 =========== =========== =========== Proved developed reserves at end of year 9,299,000 9,097,000 7,030,000 =========== =========== ===========
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, ------------------------------------------ 1997 1998 1999 ------------ ------------ ------------ Future cash inflows $103,842,000 $ 59,095,000 $140,851,000 Future oil and natural gas operating expenses 55,484,000 28,582,000 46,679,000 Future development costs 13,230,000 4,841,000 12,428,000 Future income tax expenses 6,870,000 -- 11,952,000 ------------ ------------ ------------ Future net cash flows 28,258,000 25,672,000 69,792,000 10% annual discount for estimating timing of cash flows 7,285,000 6,917,000 27,062,000 ------------ ------------ ------------ Standard measure of discounted future net cash flows $ 20,973,000 $ 18,755,000 $ 42,730,000 ============ ============ ============
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. Average prices used in computing year end 1997, 1998 and 1999 future cash flows were $16.37, $10.15 and $23.40 for oil, respectively and $2.56, $2.18 and $2.35 for natural gas, respectively. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for tax basis and 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-19 57 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, -------------------------------------------- 1997 1998 1999 ------------ ------------ ------------ Changes due to current-year operations - Sales of oil and natural gas, net of oil and natural gas operating expenses $ (6,378,000) $ (5,089,000) $ (7,169,000) Extensions and discoveries 16,074,000 5,003,000 9,095,000 Purchases of oil and gas properties 6,954,000 2,889,000 -- Changes due to revisions in standardized variables Prices and operating expenses (29,115,000) (5,820,000) 32,560,000 Income taxes 11,410,000 5,098,000 (8,447,000) Estimated future development costs (2,683,000) 6,757,000 (4,581,000) Revision of quantities (3,449,000) (9,056,000) 11,770,000 Sales of reserves in place (3,933,000) -- -- Accretion of discount 4,634,000 2,607,000 1,876,000 Production rates (timing) and other (5,562,000) (4,607,000) (11,129,000) ------------ ------------ ------------ Net change (12,048,000) (2,218,000) 23,975,000 Beginning of year 33,021,000 20,973,000 18,755,000 ------------ ------------ ------------ End of year $ 20,973,000 $ 18,755,000 $ 42,730,000 ============ ============ ============
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-20 58 SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH ------------ ------------ ------------ ------------ 1999 Revenues $ 1,842,314 $ 1,925,265 $ 2,537,960 $ 3,898,806 Costs and expenses, net 2,472,668 2,105,581 2,212,791 1,749,011 ------------ ------------ ------------ ------------ Net income (loss) (630,354) (180,316) 325,169 2,149,795 ============ ============ ============ ============ Discount on redemption -- -- -- 21,868,413 Dividends and accretion (788,843) (806,736) (822,553) 774 ------------ ------------ ------------ ------------ Net income (loss) available to common shareholders $ (1,419,197) $ (987,052) $ (497,384) $ 24,018,982 ============ ============ ============ ============ Diluted net income (loss) per share (1) $ (0.14) $ (0.10) $ (0.05) $ 2.17 ============ ============ ============ ============ 1998 Revenues $ 2,338,882 $ 1,848,765 $ 1,508,897 $ 2,161,958 Costs and expenses, net 2,153,347 1,955,539 2,004,086 21,077,677 ------------ ------------ ------------ ------------ Net income (loss) $ 185,535 $ (106,774) $ (495,189) $(18,915,719) ============ ============ ============ ============ Dividends and accretion (670,494) (741,444) (756,595) (772,091) ------------ ------------ ------------ ------------ Net Income (loss) available To common shareholders $ (489,959) $ (848,218) $ (1,251,784) $(19,687,810) ============ ============ ============ ============ Diluted net income (loss) per share (1) $ (0.05) $ (0.08) $ (0.12) $ (1.90) ============ ============ ============ ============
- ---------- (1) The sum of individual quarterly net income per common share may not agree with year-to-date net income per common share as each period's computation is based on the weighted average number of common shares outstanding during that period. F-21 59 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------- ----------- +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company. +3.2 -- Statement of Resolution Establishing Series of Shares designated 9% Series A Preferred Stock. +3.3 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915) and Amendment No. 2 (Incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999). +4.1 -- First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated August 28, 1997 (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997). +4.2 -- First Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 23, 1997. +4.3 -- Second Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 30, 1997. -- The Company is a party to several debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the Company agrees to furnish a copy of such instruments to the Commission upon request. +10.1 -- Incentive Plan of the Company (Incorporated herein by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.2 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.3 -- Employment Agreement between the Company and Frank A. Wojtek (Incorporated herein by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.4 -- Employment Agreement between the Company and Kendall A. Trahan (Incorporated herein by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.5 -- Employment Agreement between the Company and George Canjar (Incorporated herein by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.6 -- Indemnification Agreement between the Company and each of its directors and executive officers. +10.7 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)).
60 +10.8 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.9 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated January 8, 1998). +10.10 -- Amended Enron Warrant Certificates (Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.11 -- Securities Purchase Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.12 -- Shareholders Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.13 -- Warrant Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.14 -- Registration Rights Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.15 -- Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.16 -- Compliance Sideletter dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.17 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to the Company's Current Report on Form 8-K dated December 15, 1999). +10.18 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the Company's Current Report on Form 8-K dated December 15, 1999). 21.1 -- Subsidiaries of the Company. 23.1 -- Consent of Arthur Andersen LLP. 23.2 -- Consent of Ryder Scott Company Petroleum Engineers. 23.3 -- Consent of Fairchild, Ancell & Wells, Inc. 27.1 -- Financial Data Schedule. 99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 1999. 99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells Inc. as of December 31, 1999.
- ---------- + Incorporated by reference as indicated. EX-21.1 2 SUBSIDIARIES OF THE COMPANY 1 Exhibit 21.1 The Company has no subsidiaries. EX-23.1 3 CONSENT OF ARTHUR ANDERSEN LLP 1 Exhibit 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K into the Company's previously filed registration Statement File No. 333-35245 on Form S-8. ARTHUR ANDERSEN LLP Houston, Texas March 30, 2000 EX-23.2 4 CONSENT OF RYDER SCOTT COMPANY PETROLEUM ENGINEERS 1 Exhibit 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Registration No. 333-35245; the "Registration Statement") of Carrizo Oil & Gas, Inc., a Texas corporation (the "Company"), relating to the 1997 Incentive Plan of the Company of information contained in our reserve report that is summarized as of December 31, 1999 in our summary letter dated February 18, 2000, relating to the oil and gas reserves and revenue, as of December 31, 1998, of certain interests of the Company. We hereby consent to all references to such reports, letters and/or to this firm in each of the Registration Statement and the Prospectus to which the Registration Statement relates, and further consent to our being named as an expert in each of the Registration Statement and the Prospectus to which the Registration Statement relates. [Signature of Ryder Scott Company] Ryder Scott Company Petroleum Engineers Houston, Texas March 30, 2000 EX-23.3 5 CONSENT OF FAIRCHILD, ANCELL & WELLS, INC. 1 Exhibit 23.3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Registration No. 333-35245; the "Registration Statement") of Carrizo Oil & Gas, Inc., a Texas corporation (the "Company"), relating to the 1997 Incentive Plan of the Company of information contained in our reserve report that is summarized as of December 31, 1999 in our summary letter dated February, 29, 2000, relating to the oil and gas reserves and revenue, as of December 31, 1998, of certain interests of the Company. We hereby consent to all references to such reports, letters and/or to this firm in each of the Registration Statement and the Prospectus to which the Registration Statement relates, and further consent to our being named as an expert in each of the Registration Statement and the Prospectus to which the Registration Statement relates. [Signature of Fairchild, Ancell & Wells, Inc.] Fairchild, Ancell & Wells, Inc. Houston, Texas March 30, 2000 EX-27.1 6 FINANCIAL DATA SCHEDULE
5 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 11,345,618 0 4,424,283 480,000 0 17,524,069 64,336,738 31,714,539 83,666,374 9,185,751 0 0 0 140,114 40,713,244 83,666,374 10,204,345 10,204,345 7,336,878 7,336,878 2,195,364 0 34,870 684,817 (1,057,208) 1,742,025 0 0 77,731 1,664,294 2.00 2.00
EX-99.1 7 SUMMARY OF RESERVE REPORT 1 EXHIBIT 99.1 March 30, 2000 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 and royalty interests of Carrizo Oil & Gas, Inc. (Carrizo) as of December 31, 1999. 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. December 1999 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from December 1999 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 and Royalty Interests of CARRIZO OIL & GAS, INC. As of December 31, 1999 -------------------------------------------------
Proved ------------------------------------------------------------------------------------- Developed ------------------------------------------ Total Producing Non-Producing Undeveloped Proved ----------------- ------------------ ---------------- --------------- NET REMAINING RESERVES Oil/Condensate - Barrels 154,833 73,547 10,382 238,762 Plant Products - Barrels 64,365 93,474 26,010 183,849 Gas - MMCF 6,644 3,089 487 10,220 INCOME DATA Future Gross Revenue $ 19,108,259 $ 9,369,016 $ 1,581,079 $ 30,058,354 Deductions 3,098,817 2,253,336 391,617 5,743,770 --------------- ----------------- --------------- -------------- Future Net Income (FNI) $ 16,009,442 $ 7,115,680 $ 1,189,462 $ 24,314,584 Discounted FNI @ 10% $ 13,845,521 $ 4,619,189 $ 607,942 $ 19,072,652
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. 2 Carrizo Oil & Gas, Inc. March 30, 2000 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, development costs, and certain abandonment costs net of salvage. 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 74 percent and liquid hydrocarbon reserves account for the remaining 26 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 shut-in and behind pipe categories. The various reserve status categories are defined in the section entitled "Reserve Status Categories (SEC)" which is attached with this report. ESTIMATES OF RESERVES In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other methods were used in certain cases where characteristics of the data indicated such other methods were 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 rate. The 3 Carrizo Oil & Gas, Inc. March 30, 2000 Page 3 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 December 31, 1999 and these prices were held constant except for known and determinable escalations. In accordance with Securities and Exchange Commission guidelines, changes in liquid and gas prices subsequent to December 31, 1999 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. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage are significant. At the request of Carrizo, their estimate of zero abandonment costs after salvage value for onshore properties 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. The ownership interests, prices, and other factual data furnished by Carrizo were accepted without 4 Carrizo Oil & Gas, Inc. March 30, 2000 Page 4 independent verification. The estimates presented in this report are based on data available through December 1999. 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, L.P. Michael F. Stell, P.E. Vice President MFS/sw 5 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. 6 RESERVE STATUS CATEGORIES (SEC) Reserve status categories define the development and producing status of wells and/or reservoirs. PROVED DEVELOPED 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/WPC Definitions: Producing Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Non-Producing Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. PROVED UNDEVELOPED 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. 7 HYDROCARBON PRICING PARAMETERS SECURITIES AND EXCHANGE COMMISSION PARAMETERS OIL AND CONDENSATE Carrizo furnished us with oil and condensate prices in effect at December 31, 1999 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 December 31, 1999 were not considered in this report. PLANT PRODUCTS Carrizo furnished us with plant product prices in effect at December 31, 1999 and these prices were held constant to depletion of the properties. GAS Carrizo furnished us with gas prices in effect at December 31, 1999 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 December 31, 1999 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. EX-99.2 8 SUMMARY OF RESERVE REPORT 1 EXHIBIT 99.2 February 29, 2000 Carrizo Oil & Gas, Inc. 14811 St. Mary's Lane, Suite 148 Houston, Texas 77079 RE: RESERVES EVALUATION TO THE INTERESTS OF CARRIZO OIL & GAS CORP. HEAVY OIL PROPERTIES, ANDERSON COUNTY, TEXAS Gentlemen: Fairchild and 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 Corporation in Anderson County, Texas. This evaluation was authorized by Mr. S.P. Johnson IV, President of Carrizo Oil & Gas Corporation (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). December, 1999 hydrocarbon prices were used in the preparation of this report and current costs were held constant throughout the life of the properties. The results of the study are summarized below. SUMMARY ESTIMATED PROVED RESERVES AND FUTURE CASH FLOWS CAMP HILL FIELD ANDERSON COUNTY, TEXAS TO THE INTERESTS OF CARRIZO OIL & GAS CORP. EFFECTIVE 1/1/2000
Future Cash Flows, Before NPI (M$) Net -------------------------------------- Reserves Mbbls Undiscounted Discounted at 10% -------------- ------------ ----------------- Proved Producing 18 Pattern Leases 703.4 11,748.9 9,750.1 10 Pattern Lease 138.5 2,135.8 1,809.3 ------------ ------------ ------------ Total Proved Producing 841.9 13,884.7 11,559.4
2 Carrizo Oil & Gas, Inc. February 29, 2000 Page 2 Proved Undeveloped Delaney A Lease 704.6 8,088.6 5,290.3 Temple Eastex C Lease 1,359.5 17,645.2 11,025.1 Moore A Lease 405.5 4,090.1 1,854.4 Moore B Lease 93.8 1,196.6 663.9 Hanks Lease 137.1 1,849.3 1,025.1 C. Rosson 1,095.3 10,675.2 4,010.6 ------------ ------------ ------------ Total Proved Undeveloped 3,795.8 43,544.9 23,869.5 Total Proved 4,637.8 57,429.6 35,428.9
FUTURE CASH FLOW - TOTAL PROJECT BY YEAR (AFTER NET PROFITS INTEREST)
Future Cash Flows After NPI (M$) ----------------------------------------- Year Undiscounted Discounted at 10% ---- ------------ ----------------- 2000 8.9 8.5 2001 7,311.4 6,337.4 2002 6,264.5 4,936.3 2003 5,718.5 4,096.5 2004 6,015.4 3,917.4 2005 6,057.2 3,586.0 2006 5,150.6 2,772.1 2007 4,086.4 1,999.4 2008 2,358.4 1,049.0 2009 2,096.8 847.9 2010 3,494.5 1,284.6 2011 2,749.5 918.8 2012 992.3 301.5 2013 176.9 48.9 TOTAL 52,481.4 32,104.3
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 3 Carrizo Oil & Gas, Inc. February 29, 2000 Page 3 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 Fairchild and Wells, Inc. expresses no opinion as to the fair market value of the evaluated properties. 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 and 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, Fairchild and Wells, Inc. -----END PRIVACY-ENHANCED MESSAGE-----