10-K 1 h95293e10-k.txt CARRIZO OIL & GAS INC - DECEMBER 31, 2001 ================================================================================ 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, 2001 COMMISSION NO. 0-22915 CARRIZO OIL & GAS, INC. (Exact name of registrant as specified in its charter) TEXAS 76-0415919 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 14701 ST. MARY'S LANE, SUITE 800 77079 Houston, Texas (Zip Code) (Principal executive offices) Registrant's telephone number, including area code: (281) 496-1352 Securities Registered Pursuant to Section 12(g) of the Act: COMMON STOCK, $.01 PAR VALUE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] At March 20, 2002, the aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $25.6 million based on the closing price of such stock on such date of $5.60. At March 20, 2002, the number of shares outstanding of the registrant's Common Stock was 14,140,549. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrant's 2002 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, 2001. ================================================================================ TABLE OF CONTENTS PART I...................................................................... 2 Item 1. and Item 2. Business and Properties............................... 2 Item 3. Legal Proceedings................................................. 19 Item 4. Submission of Matters to a Vote of Security Holders............... 21 Executive Officers of the Registrant...................................... 21 PART II..................................................................... 21 Item 5. Market for Registrant's Common Stock and Related Shareholder Matters................................................................ 21 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....... 36 Item 8. Financial Statements and Supplementary Data....................... 36 Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure............................................... 36 PART III.................................................................... 36 Item 10. Directors and Executive Officers of the Registrant............... 36 Item 11. Executive Compensation........................................... 37 Item 12. Security Ownership of Certain Beneficial Owners and Management... 37 Item 13. Certain Relationships and Related Party Transactions............. 37 PART IV..................................................................... 37 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 37
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 primarily onshore in proven oil and gas producing trends along the Gulf Coast, 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 2001 the Company assembled over 400,000 gross acres under lease or option and acquired 52 3-D seismic surveys with over 2,700 square miles of 3-D data. In addition, the Company also has approximately 1,325 square miles of 3-D data in non-core areas in which the Company presently does not have active projects, but which the Company is screening for potential drilling prospects. The Company would typically seek to acquire seismic permits from landowners that included options to lease the acreage prior to conducting proprietary surveys. In other circumstances, including when the Company participates in 3-D group shoots, the Company typically seeks to obtain leases or farm-ins rather than lease options. After the 3-D seismic 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 believed is not prospective. As of December 31, 2001, the Company had 124,390 gross acres in Texas and Louisiana under lease or option, most of which is covered by 3-D seismic data, and 233,875 gross acres in Wyoming and Montana under lease or option. The Company is continually analyzing and reprocessing 3-D seismic data in search of prospects which the Company believes have a high probability of containing natural gas or oil. From the 3-D data Carrizo has amassed a large drillsite inventory, with as many as 250 gross wells that could be drilled over the next five years, assuming sufficient capital resources. In addition, the Company anticipates, based upon its past experience, that as its existing as 3-D seismic data is further evaluated, additional prospects will be generated for drilling beyond 2006. Most of the Company's drilling targets in the past have been shallow (from 4,000 to 7,000 feet), normally pressured reservoirs that generally involve moderate cost (typically $250,000 to $400,000 per completed well) and risk. Many of the Company's current drilling prospects are deeper, over-pressured targets which have greater economic potential but generally involve higher cost (typically $1 million to $4 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 but has in recent times retained larger percentages of and increased its exposure to higher cost, higher potential wells. The Company operates the majority of its projects through the exploratory phase but may relinquish operator status to qualified partners in the production phase in order to focus resources on the higher-value exploratory phase. As of December 31, 2001, the Company operated 73 producing oil and gas wells, which accounted for 41% of the wells in which the Company had an interest. During 2001, the Company, through its wholly-owned subsidiary, CCBM, Inc. ("CCBM") acquired 50% of the working interests held by Rocky Mountain Gas, Inc. ("RMG") in approximately 107,000 net mineral acres prospective for coalbed methane located in the Powder River Basin in Wyoming and Montana. The Company participated in the drilling of 31 gross test wells in Wyoming during 2002, all of which encountered coal accumulations and are currently under evaluation to determine if they are likely to result in commercial production of natural gas. No proved reserves have been assigned to the coalbed methane properties as of December 31, 2001. The Company has experienced increases in reserves and EBITDA from its inception in 1993 due to its 3-D based drilling and development activities. From January 1, 1996 to December 31, 2001, the Company participated in the drilling of 243 gross wells (72.2 net) with a commercial well success rate of approximately 66%, excluding 31 gross (12 net) wells drilled by CCBM that are currently under evaluation. This drilling success contributed to the Company's total proved reserves as of December 31, 2001 of 59.0 Bcfe with a PV-10 Value of $58.4 million. See "Oil and Natural Gas Properties." During 2001, the Company added 16.2 Bcfe to proved reserves through drilling offset by 5.4 Bcfe of production. EBITDA increased 8% from $19.6 million for the year ended December 31, 2000 to $21.1 million for the year ended December 31, 2001. 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 primarily 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. 2 As a result of the increased availability of economic onshore 3-D seismic surveys and the improvement and increased affordability of data interpretation technologies, the Company has relied almost exclusively on the interpretation of 3-D seismic data in its exploration strategy. The Company generally does not invest any substantial portion of the costs for an exploration well without first interpreting 3-D seismic data. The principal advantage of 3-D seismic data over traditional 2-D seismic analysis is that it affords the geoscientist the ability to interpret a three dimensional cube of data representing a specific project area as compared to interpreting between widely separated two dimensional vertical profiles. As a consequence, the geoscientist is able to more fully and accurately evaluate prospective areas, improving the probability of drilling commercially successful wells in both exploratory and development drilling. The use of 3-D seismic allows the geoscientist to identify and use areas of irregular sand geometry to augment or replace structural interpretation in the identification of potential hydrocarbon accumulations. Additionally, detailed analysis and correlation of the 3-D seismic response to lithology and contained fluids assist geoscientists in identifying and prioritizing drilling targets. Because 3-D analysis is completed over an entire target area cube, shallow, intermediate and deep objectives can be analyzed. Additionally, the more precise structural definition allowed by 3-D seismic data combined with integration of available well and production data assists in the positioning of new development wells. The Company has sought to obtain large volumes of 3-D seismic data either by participating in large seismic data acquisition programs either alone or pursuant to joint venture arrangements with other energy companies, or through "group shoots" in which the Company shares the costs and results of seismic surveys. By participating in joint ventures and group shoots, the Company is able to share the up-front costs of seismic data acquisition and interpretation, thereby enabling it to participate in a larger number of projects and diversify exploration costs and risks. Most of the Company's operations are conducted through joint operations with industry participants. As of December 31, 2001, the Company was actively involved in 48 project areas. The Company's primary strategy for acreage acquisition in prior years was to obtain leasing options covering large geographic areas in connection with 3-D seismic surveys. Prior to conducting proprietary surveys, the Company typically sought to acquire seismic permits that included options to lease the acreage, thereby ensuring the price and availability of leases on drilling prospects that may result upon completing a successful seismic data acquisition program over a project area. The Company generally attempted to obtain these options covering at least 80% of the project area for proprietary surveys. The size of these surveys has ranged from 10 to 80 square miles. When the Company participated in 3-D group shoots, it generally sought prospective leases as quickly as possible following interpretation of the survey. In connection with some group shoots in which the Company believed that competition for acreage was especially strong, the Company sought to obtain lease options or leases in prospective areas prior to the receipt or interpretation of 3-D seismic data. After receipt of and interpretation of the 3-D seismic data, the Company generally seeks to retain only such acreage or leases as it deems to be prospective based upon the 3-D results and the Company's interpretation. In more recent years, the Company has focused less on conducting proprietary 3-D surveys, and has focused instead on (1) the continual interpretation and evaluation of its existing 3-D seismic database and the drilling of identified prospects on such acreage and (2) the acquisition of existing non-proprietary 3-D data at reduced prices, in many cases contiguous to or in areas nearby existing Company project areas where the Company has extensive knowledge and subsequent acquisition of related acreage as the Company deems to be prospective based upon its interpretation of such 3-D data. The Company maintains a flexible and diversified approach to project identification by focusing on the estimated financial results of a project area rather than limiting its focus to any one method or source for obtaining leads for new project areas. The Company's current project areas 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 exploration 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 19 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, 2001, the Company operated 73 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. 3 The Company seeks to use advanced production techniques to exploit and expand its reserve base. Following the discovery of proved reserves, the Company typically continues to evaluate its producing properties through the use of 3-D seismic data to locate undrained fault blocks and identify new drilling prospects and performs further reserve analysis and geological field studies using computer aided exploration techniques. The Company seeks to integrate its 3-D seismic data with reservoir characterization and management systems through the use of geophysical workstations which are compatible with industry standard reservoir simulation programs. SIGNIFICANT PROJECT AREAS This section is an explanation and detail of some relevant project groupings from the Company's overall inventory of seismic data and prospects. It is difficult to uniquely categorize many of the 3-D projects because they were originally screened and selected for multiple objectives. In the Texas Wilcox Areas, additional 3-D data connects and overlaps existing project area grids continues to be acquired and integrated into the Company's prospect evaluations. This further blurs the distinction between original 3-D project areas and, as a result, geographical sub-grouping is used rather than the original project areas for this focus area. The discussion clarifies this organizational framework and highlights the project area and Wilcox area sub-groups where the majority of the expected drilling will take place over the next 12 to 18 months. 3-D PROJECT SUMMARY CHART As of December 31, 2001
SQUARE 2002 MILES PLANNED OF 3-D SEISMIC GROSS NET FOCUS AREA 3-D PROJECT SEISMIC ACQUISITION ACREAGE ACREAGE ---------- ----------- ------- ----------- ------- ------- TEXAS WILCOX AREAS Wilcox Central 377 45 24,263 10,781 Wilcox South 474 20 313 78 Wilcox East 311 25 11,668 1,658 TEXAS FRIO/VICKSBURG/YEGUA AREAS Matagorda 98 65 7,218 3,863 Ganado 32 844 357 Starr 320 2,879 910 SOUTHEAST TEXAS AREAS Cedar Point 30 1,846 610 Liberty 66 50 8,406 2,621 LOUISIANA AREAS West Bay 4 377 189 Larose 3 12 1,240 486 ------- ------ --------- -------- Subtotal 1,715 217 59,054 21,553 OTHER PROJECTS (20 PROJECTS) 1,053 - 69,548 23,667 ------- ------ --------- -------- Total 2,768 217 128,602 45,220 ======= ====== ========= ======== OTHER PROJECTS - NONCORE AREAS(1) 1,325 -- -- ======= ========= ======== WYOMING/MONTANA COALBED METHANE AREA -- 277,586 54,074 ======= ========= ========
---------- (1) 3-D Seismic coverage in oil & gas producing basins outside areas of current leasehold activity. TEXAS - WILCOX AREAS The Wilcox Central subgroup area contains the Cabeza Creek Project Area in Goliad County along with the Higgins Project Area in Bee and Live Oak Counties, Texas. The Wilcox South subgroup contains project areas in Duval, Webb, Zapata and McMullen Counties, Texas. The Wilcox East subgroup contains project areas primarily in Victoria, Fort Bend and Wharton Counties, as well as in Dewitt and Lavaca Counties, Texas and includes the Company's Cologne Project Area and Highway 59 Project Area. The prolific Wilcox trend in South Texas continues to be a primary area of exploration and development focus for Carrizo. The Company has a total of 1,162 square miles of 3-D seismic data that covers potential Wilcox formation exploration and development targets. 4 Wilcox prospects occur at a variety of depths but are often relatively deeper targets with both high reserve potential as well as higher well costs. While Carrizo operates almost all of its Wilcox area projects, portions of these wells are typically sold down to industry partners to reduce costs and offset exploration and operational risk. Wilcox Central - Goliad, Live Oak, Bee Counties The Company drilled six wells within the central Wilcox area in 2001 with a 100% success rate. The Company continued its exploration activities and drilling in the Cabeza Creek area, drilling three successful wells during 2001, including a significant discovery well, the "Riverdale #2". Carrizo is the operator of the well and owns a 68.75% working interest. The well commenced production in October 2001 at a rate of approximately 9,000 Mcfe per day. Two additional successful Wilcox wells have been drilled in the Cabeza Creek area since year end. Two successful wells were also drilled during 2001 on the NE Weesatche prospect area in Goliad County where the Company owns a 15.5% working interest. The latest field extension well reached total depth in November 2001, logged 32 feet of Wilcox net pay and commenced production in January 2002 at a rate of 3,410 Mcfe per day. Currently the Company is participating in an 11,500 foot test in Goliad County with the results expected in the second quarter 2002. If successful, this well has the potential to have two additional follow up locations. The Company has identified nine additional prospects that are drill ready within the 10,781 net acre area that the Company plans to further evaluate over the next 12 to 18 months. Wilcox South - Duval, Webb, Zapata, McMullen Counties The Company continues to develop prospects within its 474 square mile 3-D database and is working to secure leases over the areas it believes have the highest potential. Target intervals include Upper Wilcox through Lobo formations. The Company plans to drill an initial test well in this area during 2002. Wilcox East - Dewitt, Lavaca, Victoria, Fort Bend, Wharton Counties The Company continues to develop prospects within its 311 square mile 3-D database and is working to secure leases over the areas it believes have the highest potential. Targets range from the Lower Wilcox to expanded Upper Wilcox between 12,000 and 16,000 feet. Depending upon the success of leasing efforts, initial drilling is expected to begin in 2003. TEXAS FRIO/VICKSBURG/YEGUA AREAS This combined area trend sometimes overlaps but is generally closer to the Texas Gulf Coast than the Wilcox areas discussed above. In any particular target or prospect, the Frio is usually a shallower formation, while the Yegua and Vicksburg are generally relatively deeper formations. Across the Carrizo project areas, prospect targets vary greatly in depth and area distribution. The Company has a total of 1,385 square miles of 3D seismic data that covers development potential within these Frio, Vicksburg and Yegua sands, 450 acres of which are in the Matagorda, Ganado and Starr Project Areas. Several key areas are discussed below which highlight areas of expected focus during 2002 and future years. Matagorda The Matagorda area currently includes license to 98 square miles of 3-D seismic and over 3,863 net acres of current leasehold. The Company continues to have success in the area with two successful exploratory wells being drilled in 2001. These successful wells, the "Pitchfork Ranch #1" and the "Staubach #1" both exhibited high reservoir quality and deliverability in the target Middle and Lower Frio sands each having initial production rates of over 15 MMcfe per day. While the Pitchfork Ranch well declined fairly rapidly, the most recent well the "Staubach #1" in which Carrizo owns a 35% interest before payout, was a significant discovery, reaching total depth in December 2001 and logging 36 feet of net pay. The well commenced production in January 2002 at 2,094 Bbls and 4,769 Mcf (17,333 Mcfe) per day and as of March 25, 2002 was continuing to produce at a rate of 2,000 Bbls and 5,500 Mcf per day. The first follow up well targeting the same formations as the Staubach #1 well was spud on March 6, 2002, at the far south end of the structure. On March 24, 2002, a subsidiary of the Brigham Exploration Company, the operator of this well (the "Burkhart #1") in the Matagorda area, reported a loss of surface control while drilling the well and as of March 28, 2002, operations were underway to bring the well under control. The Company owns a 35% working interest in the well and has liability and well control insurance that it believes will be sufficient to cover any liabilities to third parties and the cost to bring the well under control, including, if necessary, the drilling of a replacement well. The production from the Staubach #1 well has not been affected by the incident as the Staubach #1 well is currently producing from a deeper interval than that of the gas flow from the Burkhart #1 well. Carrizo operates the northern portion of the 3-D defined prospect area with a 55% working interest and plans to drill the initial test well in this area in the third quarter of 2002. Four additional prospects are drill-ready within current acreage control which the Company plans to further evaluate within the next 18 months. Ganado The Ganado Project Area is located in Wharton County and targets both normal pressured Frio and expanded Yegua prospect opportunities within the 32 square mile proprietary seismic dataset. Following initial drilling success in the Frio, additional leases have been secured for further Frio drilling in 2002. The deeper prospect opportunities continue to be studied, however no deeper drilling is currently planned until 2003. 5 Starr The Company has a non-exclusive license to 340 square miles of 3-D seismic data which covers Frio and Vicksburg producing trends in Starr and Hildalgo Counties, Texas. Carrizo is continuing to develop prospects from this data and acquire leases, and plans to drill two additional wells in the next 12 to 18 months. Carrizo's working interest in its leases within this project area averages approximately 50%. SOUTHEAST TEXAS AREAS Carrizo has acquired approximately 96 square miles of 3-D data over its Southeast Texas project areas which are focused primarily on the Yegua and Vicksburg formations. The Liberty Project Area and Cedar Point Project Area have proven to be successful for the Company and the Company expects that the Liberty Project Area will constitute a significant portion of its 2002 drilling program. Carrizo is considering additional purchases of 3-D data during 2002 in an attempt to further exploit successful trends. Cedar Point The Cedar Point Project Area is located in Chambers County, Texas, adjacent to Trinity Bay. The 30 square mile 3-D survey targets the lower Frio and Vicksburg formations. Five of six wells drilled to date, including two during 2001, have been successful. Carrizo plans to drill one or two additional wells in the next 12 to 18 months. The Company's working interest in leases in this project area ranges from 25% to 100% in these prospects. Liberty Carrizo has identified and leased prospects ranging from the Frio to the Cook Mountain formations within the 52 square mile 3-D survey in the Liberty Project Area in Liberty County, Texas. The Company drilled one successful Cook Mountain and one unsuccessful Yegua well during 2001. Four wells are anticipated to be drilled in 2002. The Company's average working interest in the leases in the project area ranges from 40% to over 80%. LOUISIANA West Bay During 2000, a test well logged apparent pay in several zones and was successfully completed in the Company's West Bay Project Area in Plaquemine Parish Louisiana. After a unitization hearing, the Company's interest in the currently producing zone was set at 12.7%. Carrizo is currently establishing pre drill units for deeper objectives on the now proven structure. The trap configuration and seismic signature appears to be similar for the lower objectives as compared with the proven pay. Permitting is near completion for a Company operated non-pressured test well expected to be drilled mid year 2002. The Company expects its working interest in the project area wells to range from 25% to 50% depending on the amount of acreage developed and unitization results. LaRose The Company successfully drilled and completed the LaRose Prospect discovery well, the "Louisiana Delta Farms #1" in Lafourche Parish, Louisiana in 2001. This well, which Carrizo operates, logged over 100 feet of net pay in three Cris I sand intervals at depths ranging from 13,500 feet to 15,300 feet. The well tested at a gross rate of 11,650 Mcf of gas and 1,466 barrels of condensate (20,446 Mcfe) per day with flowing tubing pressure of approximately 9,740 psi from approximately 18 net feet of pay from the deepest sand interval. During the fourth quarter, unitization hearings were completed, setting the Company's working interest at 40%. While production was delayed pending construction of a new pipeline, the well commenced production on March 25, 2002. The Company is closely monitoring the well's performance and has steadily increased the production rate since commencement to a rate of approximately 9,600 Mcf of natural gas and 1,100 barrels of condensate per day (16,200 Mcfe per day) as of March 28, 2002. Based upon the current performance of the well, the Company expects to be able to increase the production rate to 18,000 to 20,000 Mcfe per day by March 31, 2002. The Company currently holds approximately 1,240 gross acres of leases in the LaRose Prospect area. An additional follow-up well is planned for drilling during 2002. CAMP HILL PROJECT The Company owns interests in eight leases totaling approximately 619 gross acres in the Camp Hill field in Anderson County, Texas. The Company currently operates seven of these leases. During the year ended December 31, 2001, the project produced 71 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, 2001 averaged $12.84 per barrel ($2.14 per Mcfe). In response to high fuel gas prices, steam injection was reduced in mid 2000. Because profitability increases when natural gas prices drop relative to oil prices, the project is a natural hedge against decreases in natural gas prices 6 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, 2001) than West Texas intermediate crude due to its suitability as a lube oil feedstock. As of December 31, 2001, the Company had 6.21 million barrels of proved oil reserves in this project, with 771 MBbls of oil reserves 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 90% in its leases in this field and an average net revenue interest of 74%. WYOMING/MONTANA COALBED METHANE PROJECT AREA The Company, through CCBM, acquired interests from RMG in certain oil and gas leases covering 233,875 gross acres and 43,711 gross acres in options during 2001 in areas prospective for coalbed methane in the Powder River Basin ("PRB") in southwestern Wyoming and Montana. The Company's working interest ranges from 6.25% to 50% in the leases. As consideration for the interests, CCBM paid RMG $7.5 million in the form of a non-recourse promissory note (the "CCBM Note"), secured solely by CCBM's interest in the undeveloped acreage. In addition, the Company intends to spend up to $5 million to drill and test coalbed methane wells on this acreage over the next two to three years, 50% of which would be spent pursuant to an obligation by Carrizo to fund $2.5 million of drilling costs on behalf of RMG. During 2001, the Company participated in the drilling of 31 gross wells at a cost of $820,000, all of which encountered coal accumulations and are currently under evaluation to determine if they are likely to result in commercial production of natural gas. Coalbed methane wells typically first produce water and then, as the water production declines, begin producing methane gas. Eight wells, located in the Clearmont area of the PRB in Wyoming in which the Company owns a 50% working interest, are currently being dewatered in an effort to establish commercial production. No proved reserves have been assigned to the project area as of December 31, 2001. In the event of default by CCBM on the CCBM Note, RMG would be entitled to foreclose on the undeveloped portion of the acreage. OTHER PROJECT AREAS In addition to the project areas described above, the Company has 20 additional project areas in various stages of development as of December 31, 2001. 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, 2001 had acquired leases and seismic options in these areas covering 69,548 gross acres and 23,667 net 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 may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rights and the delivery of equipment. Although the Company believes that its use of 3-D seismic data and other advanced technologies should increase the probability of success of its exploratory wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis 2-D seismic data, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies only assist geoscientists in identifying subsurface structures and do not enable the interpreter to know whether hydrocarbons are in fact present in such structures. In addition, the use of 3-D seismic data and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and the Company could incur losses as a result of such expenditures. The Company's future drilling 7 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, 2001. The reserve data and the present value as of December 31, 2001 were prepared by Ryder Scott Company and Fairchild & Wells, Inc., Independent Petroleum Engineers. For further information concerning Ryder Scott's and Fairchild's estimate of the proved reserves of the Company at December 31, 2001, 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) 1,158 5,699 6,857 Natural gas (MMcf) 13,754 4,104 17,858 Total proved reserves (MMcfe) 20,702 38,298 59,000 PV-10 Value(1) $ 29,461 $ 20,121 $ 49,582
---------- (1) The PV-10 Value as of December 31, 2001 is pre-tax and was determined by using the December 31, 2001 sales prices, which averaged $17.71 per Bbl of oil, $2.76 per Mcf of natural gas and $9.20 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"). 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 percent 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. 8 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 cash impact of hedging activities and the effect of certain hedge positions with an affiliate of Enron Corp. reclassified as derivatives during November 2001.
YEAR ENDED DECEMBER 31, --------------------------------------- 1999 2000 2001 ------------- ------------ ------------ Production volumes Oil (MBbls) 179 198 160 Natural gas (MMcf) 3,235 5,461 4,432 Natural gas equivalent (MMcfe) 4,311 6,651 5,390 Average sales prices Oil (per Bbl) $ 16.80 $ 27.81 $ 24.28 Natural gas (per Mcf) 2.23 3.90 5.04 Natural gas equivalent (per Mcfe) 2.37 4.03 4.87 Average costs (per Mcfe) Camp Hill operating expenses $ 1.73 $ 3.08 $ 2.14 Other operating expenses 0.66 0.59 0.43 Total operating expenses(1) 0.70 0.74 0.77
---------- (1) Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs and the administrative costs of production offices, insurance and property and severance taxes. FINDING AND DEVELOPMENT COSTS From inception through December 31, 2001, the Company has incurred total gross development, exploration and acquisition costs of approximately $137 million. Total exploration, development and acquisition activities from inception through December 31, 2001 have resulted in the addition of approximately 77.0 Bcfe, net to the Company's interest, of proved reserves at an average finding and development cost of $1.78 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. 9
YEAR ENDED DECEMBER 31, ---------------------------------------- 1999 2000 2001 ------------- ------------ ------------- (IN THOUSANDS) Acquisition costs Unproved prospects $ 4,166 $ 6,641 $12,607 Proved properties 472 337 800 Exploration 3,163 7,843 3,065 Development 937 1,361 18,356 ------- ------- ------- Total costs incurred(1) $ 8,738 $16,182 $34,828 ======= ======= =======
---------- (1) Excludes capitalized interest on unproved properties of $1,547,879, $3,563,555 and $3,170,754 for the years ended December 31, 1999, 2000 and 2001, respectively. DRILLING ACTIVITY The following table sets forth the drilling activity of the Company for the years ended December 31, 1999, 2000 and 2001. 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, 2001 has resulted in a commercial success rate of approximately 66 percent.
YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------------- 1999 2000 2001 -------------------------- -------------------------- -------------------------- GROSS NET GROSS NET GROSS NET ------------ ------------- ------------ ------------- ------------ ------------- Exploratory Wells Productive 14 2.3 19 4.7 18 5.9 Nonproductive 12 1.6 15 3.4 5 1.4 ----------- ------------ ----------- ------------ ----------- ------------ Total 26 3.9 34 8.1 23 7.3 =========== ============ =========== ============ =========== ============ Development Wells Productive 4 0.9 5 1.9 2 0.3 Nonproductive 2 0.8 -- -- -- -- ----------- ------------ ----------- ------------ ----------- ------------ Total 6 1.7 5 1.9 2 0.3 =========== ============ =========== ============ =========== ============
The above table excludes 31 gross (12 net) wells drilled by CCBM during 2001 that are currently being evaluated. 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, 2001.
COMPANY OPERATED OTHER TOTAL ------------------------- ------------------------- ------------------------- GROSS NET GROSS NET GROSS NET ------------ ----------- ------------ ----------- ------------ ----------- Oil 25 14 28 9 53 23 Natural gas 48 46 78 20 126 66 ------------ ----------- ------------ ----------- ------------ ----------- Total 73 60 106 29 179 89 ============ =========== ============ =========== ============ ===========
ACREAGE DATA The following table sets forth certain information regarding the Company's developed and undeveloped lease acreage as of December 31, 2001. 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. 10
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL ----------------------------------- ---------------------------------- ------------------------- GROSS NET GROSS NET GROSS NET ---------------- ----------------- ---------------- ---------------- ------------ ----------- Louisiana 898 226 2,052 617 2,950 843 Texas 48,889 17,598 72,551 24,884 121,440 42,482 Montana/Wyoming -- -- 233,875 38,083 233,875 38,083 ---------------- ----------------- ---------------- ---------------- ------------ ----------- Total 49,787 17,824 308,478 63,584 358,265 81,408 ================ ================= ================ ================ ============ ===========
The table does not include 4,212 gross acres (1,895 net) that the Company had a right to acquire in Texas pursuant to various seismic option agreements at December 31, 2001. Under the terms of its option agreements, the Company typically has the right for a period of one year, subject to extensions, to exercise its option to lease the acreage at predetermined terms. The Company's lease agreements generally terminate if producing wells have not been drilled on the acreage within a period of three years. Further, the table does not include 43,711 gross and 15,991 net acres in Wyoming that the Company has the right to earn pursuant to certain drilling obligations and other pre-determined terms. MARKETING The Company's production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply/demand conditions. The Company's marketing objective is to receive the highest possible wellhead price for its product. The Company is aided by the presence of multiple outlets near its production in the Texas and Louisiana Gulf Coast. The Company takes an active role in determining the available pipeline alternatives for each property based upon historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability. There are a variety of factors which affect the market for oil and natural gas, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas production and sales. The Company has not experienced any difficulties in marketing its oil and natural gas. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. The availability of a ready market for the Company's oil and natural gas production depends on the proximity of reserves to, and the capacity of, oil and natural gas gathering systems, pipelines and trucking or terminal facilities. The Company delivers natural gas through gas gathering systems and gas pipelines that it does not own. Federal and state regulation of natural gas and oil production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect the Company's ability to produce and market its oil and natural gas. The Company from time to time markets its own production where feasible with a combination of market-sensitive pricing and forward-fixed pricing. Forward pricing is utilized to take advantage of anomalies in the futures market and to hedge a portion of the Company's production deliverability at prices exceeding forecast. All of such hedging transactions provide for financial rather than physical settlement. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-General Overview". Despite the measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas sold in the spot market due primarily to seasonality of demand and other factors beyond the Company's control. Domestic oil prices generally follow worldwide oil prices, which are subject to price fluctuations resulting from changes in world supply and demand. The Company continues to evaluate the potential for reducing these risks by entering into, and expects to enter into, additional hedge transactions in future years. In addition, the Company may also close out any portion of hedges that may exist from time to time as determined to be appropriate by management. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and crude oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the 11 Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. In November 2001, the Company had costless collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from December 2001 through December 2002. The value of these derivatives at that time was $759,000. Because of Enron's financial condition, the Company concluded that the derivatives contracts no longer qualified for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 ($759,000) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. An allowance for the related asset was charged to other expense. At December 31, 2001, $706,000 remained in accumulated other comprehensive income. Total oil purchased and sold under hedging arrangements during 1999, 2000 and 2001 were 45,200 Bbls, 87,900 Bbls and 18,000 Bbls, respectively. Total natural gas purchased and sold under hedging arrangements in 1999, 2000 and 2001 were 2,050,000 MMBtu, 1,590,000 MMBtu and 3,087,000 MMBtu, respectively. The net gains and (losses) realized by the Company under such hedging arrangements were $(412,000) and $(1,537,700) and $2,015,000 for 1999, 2000 and 2001, respectively. At December 31, 2001, the Company had no derivative instruments outstanding designated as hedge positions. At December 31, 2000, the Company had outstanding hedge positions covering 1,710,000 MMBtu and 18,000 Bbls. These consisted of 1,080,000 MMBtu with a floor of $4.00 and a ceiling of $5.19 for January through December 2001 production and 630,000 MMBtu at an average fixed price of $6.60 for January through March 2001 production. The 18,000 Bbls of oil hedges had a floor of $30.00 and a ceiling of $32.28 for January through March 2001 production. These instruments had a fair market value of ($3,025,000) at December 31, 2000. At March 28, 2002, the Company had outstanding hedge positions covering 1,705,000 MMBtu of natural gas at an average fixed price of $3.19 for April 2002 through December 2002 production. The Company also had outstanding hedge positions covering 18,200 Bbls of oil at an average fixed price of $24.65 for April 2002 through June 2002 production and 54,900 Bbls of oil hedged under a costless collar arrangement at a $22.00 floor and a $25.00 cap for April 2002 through September 2002 production. COMPETITION AND TECHNOLOGICAL CHANGES The Company encounters competition from other oil and natural gas companies in all areas of its operations, including the acquisition of exploratory prospects and proven properties. The Company's competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of its competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than those of the Company and which, in many instances, have been engaged in the oil and natural gas business for a much longer time than the Company. Such companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that the Company believes are and will be increasingly important to the current and future success of oil and natural gas companies. The Company's ability to explore for oil and natural gas prospects and to acquire additional properties in the future will be dependent upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company believes that its exploration, drilling and production capabilities and the experience of its management generally enable it to compete effectively. Many of the Company's competitors, however, have financial resources and exploration and development budgets that are substantially greater than those of the Company, which may adversely affect the Company's ability to compete with these companies. The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, the Company may be placed at a competitive disadvantage, and competitive pressures may force the Company to implement such new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before the Company. There can be no assurance that the Company will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies currently utilized by the Company or implemented in the future may become obsolete. In such case, the Company's business, financial condition and results of operations could be materially adversely affected. If the Company is unable to utilize the most advanced commercially available technology, the Company's business, financial condition and results of operations could be materially and adversely affected. REGULATION The availability of a ready market for oil and gas production depends upon numerous factors beyond the Company's control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, and the effects of regulation on the amount of oil and natural gas available for sale, the availability of adequate pipeline and other regulated transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an oversupply of 12 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 percent 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 and transportation was substantially modified by the Natural Gas Policy Act of 1978 (the "NGPA"), under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas, including all sales by the Company of its own production. As a result, all of the Company's domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC's jurisdiction over 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 with passage by Congress of the NGPA, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters. Through similar orders affecting intrastate pipelines that provide similar interstate services, the FERC expanded the impact of open access regulations to intrastate commerce. Beginning in April 1992, the FERC issued Order No. 636 and a series of related orders, which required interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. All gas marketing by the pipelines was required to be divested to a marketing affiliate, which operates separately from the transporter and in direct competition with other gas merchants. Although Order No. 636 does not directly regulate the Company's production and marketing activities, it does affect how buyers and sellers gain access to the necessary transportation facilities and how natural gas is sold in the marketplace. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines. However, some appeals remain pending and the FERC continues to review and modify its regulations regarding the transportation of natural gas. For example, in 2000, the FERC issued Order No. 637 which: o lifts the cost-based cap on pipeline transportation rates in the capacity release market until September 30, 2002, for short-term releases of pipeline capacity of less than one year, 13 o permits pipelines to file for authority to charge different maximum cost-based rates for peak and off-peak periods, o encourages, but does not mandate, auctions for pipeline capacity, o requires pipelines to implement imbalance management services, o restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders, and o implements a number of new pipeline reporting requirements. Order No. 637 also requires the Federal Energy Regulatory Commission Staff to analyze whether the FERC should implement additional fundamental policy changes. These include whether to pursue performance-based or other non-cost based ratemaking techniques and whether the FERC should mandate greater standardization in terms and conditions of service across the interstate pipeline grid. In April 1999, the FERC issued Order No. 603, which implemented new regulations governing the procedure for obtaining authorization to construct new pipeline facilities. In September 1999, the FERC issued a related policy statement establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates for service on new pipeline facilities based solely on the costs associated with such new pipeline facilities. 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 natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. The Company believes these changes generally have improved the Company's access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. 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. There regularly are other legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Company. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on the Company's sales of gas, cannot be predicted. The Company owns certain natural gas pipelines that it believes meet the standards the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both state and federal levels in the post-Order No. 636 environment. Oil Price Controls and Transportation Rates. Sales of 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. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The first such review was completed in 2000 and on December 14, 2000, FERC reaffirmed the current index. 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 14 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. CERCLA, also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that 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. 15 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, except to the extent described in Note 8 of the Notes to the Consolidated Financial Statements with respect to certain Starr County properties. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, including a title opinion of local counsel, are generally made before commencement of drilling operations. The Company's revolving credit facility is secured by substantially all of its oil and natural gas properties. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact and their accuracy inherently uncertain. In connection with such an assessment, the Company performs a review of the subject properties that it believes to be generally consistent with industry practices, which generally includes on-site inspections and the review of reports filed with various regulatory entities. Such a review, however, will not reveal all existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. There can be no assurances that any acquisition of property interests by the Company will be successful and, if unsuccessful, that such failure will not have an adverse effect on the Company's future results of operations and financial condition. EMPLOYEES At December 31, 2001, the Company had 36 full-time employees, including six geoscientists and six engineers. The Company believes that its relationships with its employees are good. In order to optimize prospect generation and development, the Company utilizes the services of independent consultants and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testings, are generally provided by independent contractors. The Company believes that this use of third party service providers has enhanced its ability to contain general and administrative expenses. 16 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 where under the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out". Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Finding costs. Costs associated with acquiring and developing proved oil and natural gas reserves which are capitalized by the Company pursuant to generally accepted accounting principles, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing wells. Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. MBbls. One thousand barrels of crude oil or other liquid hydrocarbons. MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per day. 17 Mcf. One thousand cubic feet of natural gas. Mcf/d. One thousand cubic feet of natural gas per day. Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of 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 often been higher or substantially higher for crude oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower. Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells. 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 percent. Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells. Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market. Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves. Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. PV-10 Value. The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as 18 general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10 percent. 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. ITEM 3. LEGAL PROCEEDINGS From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. Settlement of Litigation. The Company, as one of three plaintiffs, filed a lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial District Court of Duval County, Texas, for fraud and breach of contract in connection with an agreement between plaintiffs and defendants whereby the defendants were obligated to drill a test well in an area known as the Slick Prospect in Duval County, Texas. The allegations of the Company in this litigation were that BNP gave the Company inaccurate and incomplete information on which the Company relied in making its decision not to participate in the test well and the prospect, resulting in the loss of the Company's interest in the lease, the test well and four subsequent wells drilled in the prospect. The Company has sought to enforce its approximate 23.68% interest in the prospect and sought damages or rescission, as well as costs and attorneys' fees. The case was originally filed in Duval County, Texas on February 25, 2000. In mid March, 2000, the defendants filed an original answer and certain counterclaims against plaintiffs, seeking unspecified damages for slander of title, tortious interference with business relations, and exemplary damages. The case proceeded to trial before the Court (without a jury) on June 19, 2000 after the plaintiffs' were found by the court to have failed to comply with procedural requirements regarding the request for a jury. After several days of trial the case was recessed and later resumed on September 5, 2000. The court at that time denied the plaintiffs' motion for mistrial based on the court's denial of a jury trial. The court also ordered that the defendants' counterclaims would be the subject of a separate trial that would commence on December 11, 2000. The parties proceeded to try issues related to the plaintiffs' claims on September 5, 2000. All parties rested on the plaintiffs' claims on September 13, 2000. The court took the matter under advisement and has not yet announced a ruling. Defendants filed a second amended answer and counterclaim and certain supplemental responses to request for disclosure in which they stated that they were seeking damages in the amount of $33.5 million by virtue of an alleged lost sale of the subject properties, $17 million in alleged lost profits from other prospective contracts, and unspecified incidental and consequential damages from the alleged wrongful suspension of funds under their gas sales contract with the gas purchaser on the properties, alleged damage to relationships with trade creditors and financial institutions, including the inability to leverage the Slick Prospect, and attorneys' fees at prevailing hourly rates in Duval County, Texas incurred in defending against plaintiffs' claims and for 40% of any aggregate recovery in prosecuting their counterclaims. In subsequent testimony, the defendants verbally alleged $26 million of damages by virtue of the alleged lost sale of the properties (as opposed to the $33.5 million previously sought), $7.5 million of damages by virtue of loss of a lease development opportunity and $100 million of damages by virtue of the loss of a business opportunity related to BNP's alleged inability to participate in a 3-D seismic project. The Company had also alleged that BNP Petroleum Corporation, Seiskin Interests, LTD and Pagenergy Company, LLC breached a contract with the plaintiffs by obtaining oil and gas leases within an area restricted by that contract. This breach of contract allegation 19 is the subject of an additional lawsuit by plaintiffs in the 165th District Court in Harris County, Texas. The defendants took the position that the claim must be tried in the Duval County case. The Duval County court, without issuing a formal ruling, took the position that this claim should be included in the Duval County case. The Company was seeking damages as a result of defendants' actions as well as costs and attorneys' fees. On December 8, 2000 the Company entered into a Compromise and Settlement Agreement ("Settlement Agreement") with the defendants with regard to the above described litigation. Under the terms of the Settlement Agreement, the Company and the defendants agreed to enter into an Agreed Order of Dismissal with Prejudice of the litigation and, among other things, agreed as follows: 1. Should a co-plaintiff to the Duval County litigation secure a final judgment (without regard to appeals, new trials or other such actions) in the trial court in Duval County that results in such plaintiff being entitled to recover a five percent or greater undivided interest in the Slick Prospect, BNP will pay to Carrizo, at BNP's option, either $500,000 or an amount equal to the judgment rendered in favor of such plaintiff. 2. Should the defendants secure a final judgment (without regard to appeals, new trials or other such actions) in the trial court in Duval County against a co-plaintiff, the Company will be obligated to pay BNP an amount equal to five percent of any percentage of the total judgment apportioned to the Company in the case, such payment being limited however to no more than five percent of 47.2 percent of the total judgment entered in the case. 3. In the event the defendants and such co-plaintiff reach a full and final settlement prior to the entry of a written final judgment in the trial court in Duval County (including but not limited to any type of agreed judgment or any agreement that such co-plaintiff will not be ultimately liable to BNP for the full amount of any judgment rendered in favor of the defendants), the obligations described in (1) and (2) above will be null and void. Also, in the event BNP and such co-plaintiff both only obtain take nothing judgments in the case, such obligations will be null and void. 4. Both the Company and the defendants released each other from any and all claims, demands, actions or causes of action relating to or arising out of the litigation. The case proceeded to trial on the counterclaims on December 11, 2000. BNP presented evidence that its damages were in the amounts of $19.6 million for the alleged lost sale of the properties, $35 million for loss of the lease development opportunity, and $308 million for loss of the opportunity related to participation in the 3-D seismic project. During the course of the trial, the co-plaintiff presented its motion for summary judgment on the counterclaims based on the doctrine of absolute judicial proceeding privilege. The court partially granted the co-plaintiff's motion for summary judgment as it related to the filing of a lis pendens, but denied it with regard to the other allegations of BNP. The court also granted to co-plaintiff's plea in abatement relating to the breach of contract allegation, ruling that the District Court in Harris County has dominant jurisdiction of that issue. Upon completion of the trial, the court announced that it would take the case under advisement. On November 5, 2001, the court filed with the clerk a final judgment that had been signed by the court on October 26, 2001. Pursuant to the terms of the judgment, the Company, and its co-plaintiffs, take nothing on their claims against BNP and are denied any recovery of their interests in the lease, the prospect, or the wells of the Slick Prospect. Instead, the court confirmed title in the lease, prospect, and wells in BNP's affiliate. In addition, the Company and its co-defendants were found to have tortiously and maliciously interfered with two different BNP contracts or prospective contracts and the business of BNP and its affiliate, causing damages with respect to the loss of a sale and the loss of a lease. Under the terms of the Settlement Agreement, the Company paid $472,000 to BNP. The settlement amount, along with the related legal fees, has been included as other expense in the accompanying financial statements. In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in N. LaCopita Prospect in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of their lease, remove cloud on title, quiet title to the property, and for conversion, trespass and punitive damages. ExxonMobil seek unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that the Company acted in good faith and intends to vigorously defend our position. The Company, along with GMT and the other partners, are attempting to negotiate a settlement with ExxonMobil that would allow GMT et al (including the Company) to participate for their respective shares of a working interest in the Neblett unit, and would allow for the recovery of well costs. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its costs as a good faith trespasser. A complete loss of the lease in question would result in the loss to the Company of approximately .6 Bcfe of reported proved reserves as of December 31, 2000 or .9 Bcfe of reported proved reserves as of June 30, 2001. No reserves with respect to these properties were included in the Company's reported proved reserves as of December 31, 2001. At the time of shut in, the Neblett #1 well was producing at the rate of approximately 45 Mcfe per day, the Neblett #2 well was producing at the rate of approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate of approximately 895 Mcfe per day, all net to the Company's interest. The Company believes that an unfavorable outcome in this matter would not have a material impact on its financial statements. The Company has recorded revenues only to the extent of well costs funded by the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 20 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 45 President and Chief Executive Officer Frank A. Wojtek 46 Chief Financial Officer, Vice President, Secretary and Treasurer George F. Canjar 44 Vice President of Exploration Development Kendall A. Trahan 51 Vice President of Land J. Bradley Fisher 41 Vice President of Operations
Set forth below is a description of the backgrounds of each of the executive officers of the Company: S.P. Johnson IV has served as the President, Chief Executive Officer and a director of the Company since December 1993. Prior to that, he worked 15 years for Shell Oil Company. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado. Frank A. Wojtek has served as the Chief Financial Officer, 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 holds a B.S. degree from the University of Southwestern Louisiana. J. Bradley Fisher has served as Vice President of Operations since July 2000. Prior to joining the company, Mr. Fisher spent 14 years with Cody Energy and its predecessor Ultramar Oil & Gas Limited where he held various managerial and technical positions, last serving as Senior Vice President of Engineering and Operations. Mr. Fisher hold a B.S. degree in Petroleum Engineering from Texas A&M University. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS The Company's common stock, par value $0.01 per share (the "Common Stock"), has been publicly traded through the Nasdaq National Market tier of The Nasdaq Stock Market under the symbol CRZO since the Company's initial public offering (the "Offering") effective August 6, 1997. The following table sets forth the quarterly high and low bid prices for each indicated quarter. 21
QUARTER ENDED HIGH LOW -------------------------- ------------ ------------ March 31, 2000 4.125 1.688 June 30, 2000 7.250 2.875 September 30, 2000 14.000 5.250 December 31, 2000 12.375 7.875 March 31, 2001 10.125 5.688 June 30, 2001 7.380 4.900 September 30, 2001 6.240 4.200 December 31, 2001 5.450 3.600
---------- There were approximately 44 shareholders of record (excluding brokerage firms and other nominees) of the Company's Common Stock as of March 20, 2002. 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 percent 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". SALES OF UNREGISTERED SECURITIES On February 20, 2002, the Company consummated the transactions (the "2002 Financing") contemplated by a Securities Purchase Agreement dated February 20, 2002 (the "2002 Securities Purchase Agreement") among the Company, Mellon Ventures, L.P. ("Mellon") and Steven A. Webster (excluding the Company, the "2002 Investors"). Such transactions included (i) the payment by the 2002 Investors of an aggregate purchase price of $6,000,000, (ii) the sale of 60,000 shares of Series B Convertible Participating Preferred Stock (the "Series B Preferred Stock") the terms of which are set forth in the Statement of Resolution Establishing a Series of Shares designated Series B Convertible Participating Preferred Stock (the "Statement of Resolution") and which include the right to convert such shares into Common Stock, par value $0.01 (the "Common Stock") of the Company (the "Underlying Shares") at a price of $5.70 per share, subject to adjustments, to the 2002 Investors pursuant to the terms of the 2002 Securities Purchase Agreement and (iii) the sale of warrants (the "2002 Warrants") to purchase up to 252,632 shares of the Company's Common Stock (the "2002 Warrant Shares") at the exercise price of $5.94 per share, subject to adjustments, to the 2002 Investors pursuant to the terms of the Warrant Agreement dated February 20, 2002 (the "2002 Warrant Agreement") among the Company, Mellon and Steven A. Webster, (iv) the execution of the Shareholders Agreement dated February 20, 2002 (the "2002 Shareholders Agreement") among the Company, Mellon, Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P., (v) the execution of the Registration Rights Agreement dated February 20, 2002 ("2002 Registration Rights Agreement") among the Company, Mellon and Steven A. Webster and (vi) the execution of a Compliance Sideletter dated as of February 20, 2002 by and between the Company and Mellon (the "2002 Compliance Sideletter"). The holders of the Series B Preferred Stock have the right, at each holders' option, to convert all or a portion of such Series B Preferred Stock into the number of fully paid and nonassessable shares of Common Stock convertible at any time prior to the fourth business day preceding the Redemption Date (as defined in the Statement of Resolutions) obtained by dividing (i) the product of (A) $100 plus all cumulative and accrued dividends (whether or not earned or declared) accumulated and unpaid on such share through the date of surrender of such share of Series B Preferred Stock multiplied by (B) each share of Series B Preferred Stock to be converted by (ii) the Conversion Price (as defined below). "Conversion Price" is defined to mean the conversion price per share of the Common Stock into which the Series B Preferred Stock is convertible, as such Conversion Price may be adjusted pursuant to the Statement of Resolution. The initial Conversion Price is $5.70. The Conversion Price is subject to adjustment in certain circumstances, including (a) if the Company pays a dividend in Common Stock or grants certain rights to purchase securities, (b) if the Company 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, (c) if the Company pays certain dividends or makes certain distributions to all holders of its Common Stock of any shares of capital stock of the Company or its subsidiaries (other than Common Stock) or evidences of its indebtedness or assets, including all equity and debt, subject to certain exceptions, and (d) if, subject to certain exclusions, the Company sells or issues Common Stock, options or convertible securities without consideration or with a consideration per share of Common Stock less than the Conversion Price, including in the first year a "full ratchet" adjustment for issuances in excess of $5 million; provided, however, that the Conversion Price as adjusted according to this subsection (d) will not be less than $4.75, appropriately adjusted for stock splits, reverse stock splits and similar recapitalizations (the "Floor Price"). 22 The 2002 Warrants are exercisable at any time prior to the expiration date on February 20, 2007 for the purchase of an aggregate of 252,632 shares of Common Stock at an exercise price of $5.94 per share, subject to certain adjustments. Each Warrant may be exercised by cash payment or on a "cashless basis" by utilizing the average market price during the 4-day trading period preceding the date of exercise. The number and kind of 2002 Warrant Shares issued and the exercise price are subject to adjustment in certain circumstances, including (a) 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, (b) 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 2002 Warrant Agreement) of the Common Stock, subject to certain exceptions, provided that adjustments under this clause may not result in the exercise price falling below the Floor Price, (c) 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, (d) 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 (e) the Company takes certain other actions affecting its Common Stock. The sale of the shares of Series B Preferred Stock and the 2002 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. For additional information regarding the Series B Preferred Stock and the 2002 Financing, including the 2002 Securities Purchase Agreement, the Statement of Resolution, the 2002 Shareholders Agreement, the 2002 Warrants, the 2002 Warrant Agreement, the 2002 Registration Rights Agreement and the 2002 Compliance Sideletter, see the Company's Current Report on Form 8-K dated February 20, 2002, which is incorporated herein by reference. The rights of the holders of Common Stock may be deemed to be limited by the securities issued and agreements entered into in connection with the 2002 Financing. The approximately $5,800,000 net proceeds of this financing are expected to be used primarily to fund the Company's ongoing exploration and development program. ITEM 6. SELECTED FINANCIAL DATA The financial information of the Company set forth below for each of the five years ended December 31, 2001, 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. 23
YEAR ENDED DECEMBER 31, ------------------------------------------------------------- 1997 1998 1999 2000 2001 --------- --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA: Oil and natural gas revenues $ 8,712 $ 7,859 $ 10,204 $ 26,834 $ 26,226 Costs and expenses: Oil and natural gas operating expenses 2,334 2,770 3,036 4,941 4,138 Depreciation, depletion and amortization 2,358 3,952 4,301 7,170 6,492 Write-down of oil and gas properties -- 20,305 -- -- -- General and administrative 1,591 2,667 2,195 3,143 3,333 Stock option compensation expense -- -- -- 652 (558) --------- --------- --------- --------- --------- Total costs and expenses 6,283 29,694 9,532 15,906 13,405 --------- --------- --------- --------- --------- Operating income (loss) 2,429 (21,835) 672 10,928 12,821 Interest expense (net of amounts capitalized and interest income (98) 285 13 579 269 Other income -- -- -- 1,482 1,778 --------- --------- --------- --------- --------- Income (loss) before income taxes 2,331 (21,550) 685 12,989 14,868 Income tax expense (benefit) (1) 2,300 (2,218) (1,057) 1,004 5,336 --------- --------- --------- --------- --------- Net income (loss) before cumulative effect of change in accounting principle 31 (19,332) 1,742 11,985 9,532 Cumulative effect of change in accounting principle -- -- (78) -- -- --------- --------- --------- --------- --------- Net income (loss)(1)(3) $ 31 $ (19,332) $ 1,664 $ 11,985 $ 9,532 ========= ========= ========= ========= ========= Basic earnings (loss) per share(1) (3) $ -- $ (2.15) $ 2.00 $ 0.85 $ 0.68 ========= ========= ========= ========= ========= Diluted earnings (loss) per share(1) (3) $ -- $ (2.15) $ 2.00 $ 0.74 $ 0.57 ========= ========= ========= ========= ========= Basic weighted average shares outstanding 8,639 10,375 10,544 14,028 14,059 Diluted weighted average shares outstanding 8,810 10,375 10,546 16,256 16,731 STATEMENTS OF CASH FLOW DATA: Net cash provided by operating activities $ 3,068 $ 2,387 $ 2,200 $ 17,133 $ 23,951 Net cash used in investing activities (28,141) (37,178) (14,179) (16,438) (31,225) Net cash provided by (used in) financing activities 26,255 32,916 21,457 (3,823) 2,292 OTHER OPERATING DATA: EBITDA $ 4,787 $ 2,422 $ 4,921 $ 19,580 $ 21,091 Operating cash flow (2) 4,689 2,707 4,986 19,329 19,024 Capital expenditures 32,234 36,570 10,286 19,746 38,264 Debt repayments(4) 20,409 7,950 8,174 3,923 5,479
AS OF DECEMBER 31, ------------------------------------------------------------- 1997 1998 1999 2000 2001 --------- --------- --------- --------- --------- BALANCE SHEET DATA: Working capital $ (2,276) $ (5,204) $ 8,338 $ 6,433 $ (582) Property and equipment, net 45,083 57,878 64,337 72,129 104,133 Total assets 53,658 64,988 83,666 93,000 117,392 Long-term debt, including current maturities 7,950 12,056 37,170 34,556 38,188 Mandatorily redeemable preferred stock -- 30,731 -- -- -- Equity 32,895 11,202 40,853 52,939 63,204
---------- (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 24 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. 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) Operating cash flow represents cash flows from operating activities prior to changes in assets and liabilities. (3) Net income for the year ended December 31, 1999 excludes, and earnings per share for the year ended December 31, 1999 includes, the discount on the redemption of the Company's Preferred Stock in the amount of $21,868,413. (4) Debt repayments include amounts refinanced. Forward Looking Statements. The statements contained in all parts of this document, (including any portion attached hereto) including, but not limited to, those relating to the Company's schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow up wells, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having oil and natural gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement its business strategy, future hiring, future exploration activity, production rates, efforts to regain control of the Burkhart #1 well and sufficiency of insurance for liabilities and costs in connection with the Burkhart #1 well, all and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words "anticipate", "budgeted", "targeted", "potential" "estimate", "expect", "may", "project", "believe" and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company's dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, risks relating to its limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, industry partner issues, availability of equipment, weather and other factors detailed herein and in the Company's other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 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 32, 39 and 25 gross wells in the Gulf Coast region in 1999, 2000 and 2001 respectively. The Company has budgeted to drill 16 gross wells (6.6 net) in 2002 in the Gulf Coast region; however, the actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, Company cash flow, success of drilling programs, weather delays and other factors. If the Company drills the number of wells it has budgeted for 2002, depreciation, depletion and amortization are expected to increase and oil and gas operating expenses are expected to increase over levels incurred in 2001. 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. 25 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. During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM") as a wholly-owned subsidiary. CCBM was formed to acquire interests in certain oil and gas leases in Wyoming and Montana in areas prospective for coalbed methane and develop such interests. CCBM plans to spend up to $5 million for drilling costs on these leases through December 2003, 50 percent of which would be spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf of RMG, from whom the interests in the leases were acquired. CCBM drilled 31 gross wells (12.0 net) and incurred total drilling costs of $819,000 through December 31, 2001. These wells typically take up to 18 months to evaluate and determine whether or not they are successful. CCBM has budgeted to drill 30 gross (15 net) wells in 2002. 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 percent discount rate) of estimated future net after-tax cash flows from proved oil and gas reserves, such excess costs are charged to operations. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of oil and gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a ceiling writedown. Using prices in effect on December 31, 2001 the ceiling writedown would have been approximately $700,000. Because of the volatility of oil and gas prices, no assurance can be given that the Company will not experience a ceiling test writedown in future periods. Once incurred, a write-down of oil and gas properties is not reversible at a later date. RESULTS OF OPERATIONS Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000 Oil and natural gas revenues for 2001 decreased 2% to $26.2 million from $26.8 million in 2000. Production volumes for natural gas in 2001 decreased 19% to 4,431.9 MMcf from 5,460.6 MMcf in 2000. Realized average natural gas prices increased 29% to $5.04 per Mcf in 2001 from $3.90 per Mcf in 2000. Production volumes for oil in 2001 decreased 20% to 159.7 MBbls from 198.5 MBbls in 2000. The decrease in oil production was due to the natural decline in production primarily at the Jones Branch wells and the initial Matagorda Project wells offset by the commencement of production of the Pitchfork Ranch well. The decrease in natural gas production was due primarily to the sale of the Metro Project during 2000 and the natural decline in production primarily at the initial Matagorda Project wells offset by the commencement of production at the additional Cedar Point Project wells, the West Bay Project well and the Pitchfork Ranch well. Oil and natural gas revenues include the cash effect of hedging activities as discussed below under "Volatility of Oil and Natural Gas Prices". Average oil prices decreased 13% to $24.28 per barrel in 2001 from $27.81 per barrel in 2000. The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the years ended December 31, 2000 and 2001: 26
2001 PERIOD DECEMBER 31, COMPARED TO 2000 PERIOD -------------------------- INCREASE % INCREASE 2000 2001 (DECREASE) (DECREASE) ----------- ------------ ----------- ---------- Production volumes- Oil and condensate (Mbbls) 198.5 159.7 (38.8) (20%) Natural gas (MMcf) 5,460.6 4,431.9 (1,028.7) (19%) Average sales prices-(1) Oil and condensate (per Bbl) $ 27.81 $ 24.28 $ (3.53) (13%) Natural gas (per Mcf) 3.90 5.04 1.14 29% Operating revenues- Oil and condensate $ 5,518,825 $ 3,876,941 $(1,641,884) (30%) Natural gas 21,314,985 22,349,111 1,034,126 5% ----------- ------------ ----------- Total $26,833,810 $ 26,226,052 $ (607,758) (2%) =========== ============ ===========
---------- (1) Including cash impact of hedging. Oil and natural gas operating expenses for 2001 decreased 16% to $4.1 million from $4.9 million in 2000. Oil and natural gas operating expenses decreased primarily as a result of the lower production taxes and the implementation of cost reduction measures in fields with decreased production. Operating expenses per equivalent unit in 2001 increased to $0.77 per Mcfe from $0.74 per Mcfe in 2000. The per unit cost increased primarily as a result of an increase in severance taxes and decreased production of natural gas as wells naturally decline. Depreciation, depletion and amortization ("DD&A") expense for 2001 decreased 9% to $6.5 million from $7.2 million in 2000. This decrease was primarily due to the seismic and drilling costs added to the proved property cost base. General and administrative ("G&A") expense for 2001 increased 6% to $3.3 million from $3.1 million for 2000. The increase in G&A was due primarily to the addition of staff to handle increased drilling and production activities. Stock option compensation expense is a non-cash charge resulting from a decrease during 2001 and an increase during the last six months of 2000 in the stock price underlying the stock options that were repriced in February 2000. Interest expense, net of amounts capitalized, for 2001 decreased 47% to $7,000 from $13,003 in 2000. Income taxes increased to $5.3 million in 2001 from $1.0 million in 2000. The increase was the result of an adjusted valuation allowance during 2000 on net operating loss carryforwards expected to be realized that resulted in a deferred income tax benefit adjustment of $3.6 million which reduced the Company's effective tax rate to eight percent in 2000. Other income for the year ended December 31, 2001 included a gain on the sale of an investment in Michael Petroleum Corporation ("MPC") of $3.9 million offset by (1) a charge and related legal expenses of $1.4 million in respect of the final settlement of litigation with BNP Petroleum Corporation and (2) a non-cash valuation allowance of $759,000 relating to certain hedge arrangements with Enron North America Corp. Net income for 2001 decreased to $9.5 million from $12.0 million in 2000 as a result of the factors described above. Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999 Oil and natural gas revenues for 2000 increased 163% to $26.8 million from $10.2 million in 1999. Production volumes for natural gas in 2000 increased 69 percent to 5,460.6 MMcf from 3,235.0 MMcf in 1999. Realized average natural gas prices increased 75% to $3.90 per Mcf in 2000 from $2.23 per Mcf in 1999. Production volumes for oil in 2000 increased 11% to 198.5 MBbls from 179.3 MBbls in 1999. Oil and natural gas production increased primarily as a result of the commencement of production from the Cabeza Creek Project wells, additional Matagorda Project wells, the Cedar Point Project wells, the North La Copita Project wells, the West Bay Project well and higher than anticipated production from wells in which the Company had a back-in working interest after payout, offset by the natural decline of existing wells. Oil and natural gas revenues include the impact of hedging activities as discussed below under "Volatility of Oil and Gas Prices." 27 Average oil prices increased 66% to $27.81 per barrel in 2000 from $16.80 per barrel in 1999. 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, 1999 and 2000:
2000 PERIOD COMPARED TO 1999 PERIOD DECEMBER 31, INCREASE % INCREASE 1999 2000 (DECREASE) (DECREASE) ----------- ----------- ----------- ------------ Production volumes- Oil and condensate (Mbbls) 179.3 198.5 19.2 11% Natural gas (MMcf) 3,235.0 5,460.6 2,225.6 69% Average sales prices-(1) Oil and condensate (per Bbl) $ 16.80 $ 27.81 $ 11.01 66% Natural gas (per Mcf) 2.23 3.90 1.67 75% Operating revenues- Oil and condensate $ 2,975,998 $ 5,518,825 $ 2,542,827 85% Natural gas 7,228,347 21,314,985 14,086,638 195% ----------- ----------- ----------- Total $10,204,345 $26,833,810 $16,629,465 163% =========== =========== ===========
---------- (1) Including cash impact of hedging. Oil and natural gas operating expenses for 2000 increased 63% to $4.9 million from $3.0 million in 1999. 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, 1999 offset by a reduction in costs on older producing fields. Operating expenses per equivalent unit in 2000 increased to $.74 per Mcfe from $.70 per Mcfe in 1999. The per unit cost increased primarily as a result of an increase in severance taxes, increased costs at the Camp Hill Project and decreased production of natural gas as wells naturally decline offset by the addition of new wells with high production rates during 2000. Depreciation, depletion and amortization ("DD&A") expense for 2000 increased 67% to $7.2 million from $4.3 million in 1999. This increase was primarily due to the increased amortization of deferred loan costs, increased production and additional seismic and drilling costs offset by the sale of the Metro Project in the second quarter of 2000. General and administrative ("G&A") expense for 2000 increased 43% to $3.1 million from $2.2 million for 1999. The increase in G&A was due primarily to the addition of staff to handle increased drilling and production activities. Stock option compensation expense for 2000 is a non-cash charge resulting from the increase during the last six months of 2000 in the stock price underlying the stock options that were repriced in February 2000. Interest expense, net of amounts capitalized, for 2000 decreased 63% to $13,003 from $35,000 in 1999. This decrease was primarily due to higher interest cost in 1999 which was not available to be capitalized. Income taxes changed from a $1.1 million benefit in 1999 to a $1.0 million expense in 2000 based on improvements in the results which influence taxable income. The Company also adjusted its valuation allowance during 2000 on net operating loss carryforwards expected to be realized. This change in estimate resulted in a deferred income tax benefit adjustment of $3.6 million which reduced the Company's effective tax rate to eight percent in 2000. Dividends and accretion of discount on preferred stock decreased to none in 2000 from $2.4 million in 1999 as a result of the redemption of preferred stock in the fourth quarter of 1999. As a result of this redemption, no such future charges will be accrued. Net income for 2000 increased to $12.0 million from $1.7 million in 1999 as a result of the factors described above. LIQUIDITY AND CAPITAL RESOURCES The Company has made and is expected to make oil and gas capital expenditures in excess of its net cash flow from operations in order to complete the exploration and development of its existing properties. 28 The Company will require additional sources of financing to fund drilling expenditures on properties currently owned by the Company and to fund leasehold costs and geological and geophysical cost on its exploration projects. While the Company believes that current cash balances and anticipated 2002 operating cash flow will provide sufficient capital to carry out the Company's 2002 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 1997 initial public offering, the December 1999 sale of Subordinated Notes, Common Stock and Warrants, the 1998 sale of shares of Series A Preferred Stock and Warrants, the February 2002 sale of Series B Preferred Stock and Warrants, funds generated by operations, equity capital contributions, borrowings (primarily under revolving credit facilities) and funding under the Palace Agreement that provided a portion of the funding for the Company's 1999, 2000 and 2001 drilling program in return for participation in certain wells. Cash flows provided by operations (after changes in working capital) were $2.2 million, $17.1 million and $24.0 million for 1999, 2000 and 2001, respectively. The increase in cash flows provided by operations in 2001 as compared to 2000 was due primarily to the increase in trade accounts payable. The increase in cash flows provided by operations in 2000 as compared to 1999 was due primarily to increases in production and commodity prices. The Company budgeted capital expenditures in 2002 of approximately $17.7 million of which $2.8 million is expected to be used to fund 3-D seismic surveys and land acquisitions and $14.9 million of which is expected to be used for drilling activities in the Company's project areas. The Company has budgeted to drill approximately 16 gross wells (seven net) in the Gulf Coast region and 30 gross (15 net) CCBM coalbed methane wells in 2002. The actual number of wells drilled and capital expended is dependent upon available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors. The Company has continued to reinvest a substantial portion of its cash flows into increasing its 3-D prospect portfolio, improving its 3-D seismic interpretation technology and funding its drilling program. Oil and gas capital expenditures were $10.3 million, $19.7 and $38.2 million for 1999, 2000 and 2001, respectively. The Company's drilling efforts resulted in the successful completion of 18 gross wells (3.2 net) in 1999, 24 gross wells (6.6 net) in 2000 and 20 gross wells (5.9 net) in 2001 in the Gulf Coast region. All of the 31 gross wells (12 net) drilled by CCBM are awaiting evaluation before a determination can be made as to their success During November 2000, the Company entered into a one-year contract with Grey Wolf, Inc. for utilization of a 1,500 horsepower drilling rig capable of drilling wells to a depth of approximately 18,000 feet. The contract, which commenced in March 2001, provides for a dayrate of $12,000 per day. The rig was utilized primarily to drill wells in the Company's focus areas, including the Matagorda Project Area and the Cabeza Creek Project Area. The contract contained a provision which would allow the Company to terminate the contract early by tendering payment equal to one-half the dayrate for the number of days remaining under the term of the contract as of the date of termination. The contract expired in February 2002. Steven A. Webster, who is the Chairman of the Board of Directors of the Company, is a member of the Board of Directors of Grey Wolf, Inc. FINANCING ARRANGEMENTS In connection with the 1997 initial public 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 April 2003, 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 had provided collateral, primarily in the form of marketable securities, to secure the revolving credit loans. This collateral was released during April 2001. 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 addition to the required semiannual reviews at the Company's cost. 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 29 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. Principal payments on the Term Loan were due 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. As of December 31, 2001, the principal balance of the Term Loan had been repaid. 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, 2000, and 2001, outstanding revolving credit loans totaled $5,426,000 and $7,166,000, respectively, with an additional $2,900,884 and $620,000, respectively, available for future borrowings. The outstanding amount of the Term Loan was $5,260,000 and none at December 31, 2000 and 2001. 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, 2000 and 2001. The Borrowing Base facility was amended in November 2000 to provide up to $2 million of Guidance Line letters of credit (the "Guidance Line letters of credit") relating exclusively to the Company's outstanding hedge positions. At December 31, 2000, the Company had one Guidance Line letter of credit outstanding amounting to $180,000. The weighted average interest rates for 2000 and 2001 on the Company Credit Facility were 9 and 7 percent, respectively. On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company ("CCBM"), issued a non-recourse promissory note payable in the amount of $7,500,000 to RMG as consideration for certain interest in oil and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $125,000 plus interest at eight percent per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and gas leases in Wyoming and Montana. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $243,369. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6 percent per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1. Estimated maturities of long-term debt are $2,107,030 in 2002, $8,205,391 in 2003, $3,836,498 in 2004 and the remainder in 2007. 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 percent per annum. Also in consideration for the bridge loan, the Company assigned to Messrs. Hamilton, Webster, and Loyd an aggregate 1.0 percent overriding royalty interest ("ORRI") in the Huebner #1 and Fondren Letulle #1 wells (combined with the prior assignment, a 2 percent overriding royalty interest), a .8794 percent ORRI in Neblett #1 (N. La Copita), a 1.0466 percent ORRI in STS 104-5 #1, a 1.544 percent ORRI in USX Hematite #1, a 2.0 percent ORRI in Huebner #2 and a 2.0 percent ORRI in Burkhart #1. On December 15, 1999 the bridge loan was repaid in its entirety with proceeds from the sale of Common Stock, Subordinated Notes and Warrants. Such overriding royalty interests are limited to the well bore and proportionately reduced to the Company's working interest in the well. In December 1999, the Company consummated the sale of $22 million principal amount of 9 percent 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 percent of the interest which would otherwise be payable in cash. For the year ended December 31, 2001, the amount of Subordinated Notes was increased by $1,282,295 for such interest. Concurrent with the sale of the notes, the Company consummated the sale of 3,636,364 shares of Common Stock at a price of $2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's Common Stock at an exercise price of $2.20 per share. For accounting purposes, the Warrants are valued at $0.25 per Warrant. The 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 of the related Securities Purchase Agreement, including but not limited to, (a) maintenance of a specified Tangible Net Worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes 30 depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) limit its capital expenditures to a specified amount for the year ended December 31, 2000, and thereafter to an amount equal to the Company's EBITDA for the immediately prior fiscal year, as well as limits on the Company's ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv) declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v) engage in transactions with affiliates (vi) make certain repayments and prepayments, including any prepayment of the 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 remaining proceeds were used to fund the Company's ongoing exploration and development program and general corporate purposes. In January 1998, the Company consummated the sale of 300,000 shares of Series A Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to affiliates of Enron Corp. The net proceeds received by the Company from this transaction were approximately $28.8 million and were used primarily for oil and natural gas exploration and development activities in Texas and Louisiana and to repay related indebtedness. The Series A Preferred Stock provided for annual cumulative dividends of $9.00 per share, payable quarterly in cash or, at the option of the Company until January 15, 2002, in additional shares of Series A Preferred Stock. Dividend payments for the 12 months ended December 31, 1999 were made by the issuance of an additional 22,508.23 shares of Series A Preferred Stock. In December 1999, the Company consummated the repurchase of all the outstanding shares of Series A Preferred Stock and 750,000 Warrants for $12 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. In February 2002, the Company consummated the sale of 60,000 shares of Series B Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common Stock for an aggregate purchase price of $6,000,000 to an investor group led by Mellon Ventures, L.P. which included Steven A. Webster, the Company's Chairman of the Board of Directors. The Series B Preferred Stock is convertible into Common Stock by the investors at a conversion price of $5.70 per share, subject to adjustment, and is initially convertible into 1,052,632 shares of Common Stock. The approximately $5,800,000 net proceeds of this financing were used to fund the Company's ongoing exploration and development program and general corporate purposes. Dividends on the Series B Preferred Stock will be payable in either cash at a rate of eight percent per annum or, at the Company's option, by payment in kind of additional shares of the Series B Preferred Stock at a rate of ten percent per annum. In addition to the foregoing, if the Company declares a cash dividend on the Common Stock of the Company, the holders of shares of Series B Preferred Stock are entitled to receive for each share of Series B Preferred Stock a cash dividend in the amount of the cash dividend that would be received by a holder of the Common Stock into which such share of Series B Preferred Stock is convertible on the record date for such cash dividend. Unless all accrued dividends on the Series B Preferred Stock shall have been paid and a sum sufficient for the payment thereof set apart, no distributions may be paid on any Junior Stock (which includes the Common Stock) (as defined in the Statement of Resolutions for the Series B Preferred Stock) and no redemption of any Junior Stock shall occur other than subject to certain exceptions. The Series B Preferred Stock is required to be redeemed by the Company at any time after the third anniversary of the initial issuance of the Series B Preferred Stock (the "Issue Date") upon request from any holder at a price per share equal to Purchase Price/Dividend Preference (as defined below). The Company may redeem the Series B Preferred Stock after the third anniversary of the Issue Date, at a price per share equal to the Purchase Price/Dividend Preference and, prior to that time, at varying preferences to the Purchase Price/Dividend Purchase. "Purchase Price/Dividend Preference" is defined to mean, generally, $100 plus all cumulative and accrued dividends on such share of Series B Preferred Stock. In the event of any dissolution, liquidation or winding up or certain mergers or sales or other disposition by the Company of all or substantially all of its assets (a "Liquidation"), the holder of each share of Series B Preferred Stock then outstanding will be entitled to be paid out of the assets of the Company available for distribution to its shareholders, the greater of the following amounts per share of Series B Preferred Stock: (i) $100 in cash plus all cumulative and accrued dividends and (ii) in certain circumstances, the "as-converted" liquidation distribution, if any, payable in such Liquidation with respect to each share of Common Stock. Upon the occurrence of certain events constituting a "Change of Control" (as defined in the Statement of Resolutions), the Company is required to make a offer to each holder of Series B Preferred Stock to repurchase all of such holder's Series B Preferred Stock at an offer price per share of Series B Preferred Stock in cash equal to 105% of the Change of Control Purchase Price, which is generally defined to mean $100 plus all cumulative and accrued dividends. 31 The 2002 Warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo's Common Stock at a price of $5.94 per share, subject to adjustment, and are exercisable at any time after issuance. For accounting purposes, the 2002 Warrants are valued at $0.06 per 2002 Warrant. ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY The Company's growth has placed, and is expected to continue to place, a significant strain on the Company's financial, technical, operational and administrative resources. The Company has relied in the past and expects to continue to rely on project partners and independent contractors that have provided the Company with seismic survey planning and management, project and prospect generation, land acquisition, drilling and other services. At December 31, 2001, the Company had 36 full-time employees. There will be additional demands on the Company's financial, technical, operational and administrative resources and continued reliance by the Company on project partners and independent contractors, and these strains on resources, additional demands and continued reliance may negatively affect the Company. The Company's ability to grow will depend upon a number of factors, including its ability to obtain leases or options on properties for 3-D seismic surveys, its ability to acquire additional 3-D seismic data, its ability to identify and acquire new exploratory sites, its ability to develop existing sites, its ability to continue to retain and attract skilled personnel, its ability to maintain or enter into new relationships with project partners and independent contractors, the results of its drilling program, hydrocarbon prices, access to capital and other factors. Although the Company intends to continue to upgrade its technical, operational and administrative resources and to increase its ability to provide internally certain of the services previously provided by outside sources, there can be no assurance that it will be successful in doing so or that it will be able to continue to maintain or enter into new relationships with project partners and independent contractors. The failure of the Company to continue to upgrade its technical, 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. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. On June 29, 2001, the FASB approved its proposed SFAS No. 141, ("FAS 141") "Business Combinations," and SFAS No. 142 ("FAS 142"), "Goodwill and Other Intangible Assets." Under FAS 141, all business combinations should be accounted for using the purchase method of accounting; use of the pooling-of-interests method is prohibited. The provisions of the statement will apply to all business combinations initiated after June 30, 2001. FAS 142 will apply to all acquired intangible assets whether acquired singly, as part of a group, or in a business combination. The statement will supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible Assets," and will carry forward provisions in APB Opinion No. 17 related to internally developed intangible assets. Adoption of FAS 142 will result in ceasing amortization of goodwill. All of the provisions of the statement should be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company does not have any goodwill or intangible assets recorded as of December 31, 2001 and does not expect the adoption of this standard to have a material impact on its financial position or results of operations. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement of obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the effect of adopting Statement No. 143 on its financial statements and has not determined the timing of adoption and does not expect the adoption of this standard to have a material impact on its financial position or results of operations. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121 but retains its fundamental provisions for the (a) recognition/measurement of impairment of long-lived assets to be held and used and (b) measurement of long-lived assets to be disposed of by sale. SFAS 144 also supercedes the accounting/reporting provisions of APB Opinion No. 30 for segments of a business to be disposed of but retains the requirement to report discontinued operations separately from continuing operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. SFAS No. 144 is effective for the Company beginning in 2002. The Company is currently evaluating the impact of this new standard. CRITICAL 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. The Company proportionally consolidates its interests in oil and gas properties. During 1999, the Company also capitalized as oil and natural gas properties $139,910 of deferred compensation related to stock options granted to personnel directly associated with exploration activities. No deferred compensation cost was capitalized in 2000 or 2001. Additionally, the Company capitalized compensation costs for employees working directly on exploration activities of $581,000, $886,000 and $1,021,000 in 1999, 2000 and 2001, respectively. 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 periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per thousand cubic feet equivalent (Mcfe) for 1999, 2000 and 2001, was $1.00, $1.03 and $1.15, 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% interest rate, of future net revenues from proved reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. No write-down of the Company's oil and natural gas assets was necessary in 1999, 2000 or 2001. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of oil and gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a ceiling writedown. Using prices in effect on December 31, 2001 the pretax writedown would have been approximately $700,000. Because of the volatility of oil and gas prices, no assurance can be given that the Company will not experience a ceiling test writedown in future periods. Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years. STOCK-BASED COMPENSATION The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations. Under this method, the Company records no compensation expense for stock options granted when the exercise price of those options is equal to or greater than the market price of the Company's common stock on the date of grant. Repriced options are accounted for as compensatory options using variable accounting treatment. Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company's common stock. Variable plan accounting is applied to the repriced options until the options are exercised, forfeited, or expired unexercised. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities". This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement requires all derivative instruments to be carried on the balance sheet at fair value with changes in a derivative instrument's fair value recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was effective for the Company beginning January 1, 2001 and was adopted by the Company on that date. In accordance with the current transition provisions of SFAS No. 133, the Company recorded a cumulative effect transition adjustment of $2.0 million (net of related tax expense of $1.1 million) in accumulated other comprehensive income to recognize the fair value of its derivatives designated as cash-flow hedging instruments at the date of adoption. Upon entering into a derivative contract, the Company designates the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as oil and gas revenues when the forecasted transaction occurs. All of the Company's derivative instruments at January 1, 2001 and December 31, 2001 were designated and effective as cash flow hedges except for its positions with an affiliate of Enron Corp. discussed in Note 12 to the Consolidated Financial Statements. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in future earnings. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and crude oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. 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 and future income taxes. 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. 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 32 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 percent. 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. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of our oil and gas properties exceeded the cost center ceiling. In accordance with full cost accounting rules, improvements in pricing subsequent to December 31, 2001, removed the necessity to record a "ceiling" writedown. Using prices in effect on December 31, 2001 the "ceiling" writedown would have been approximately $700,000. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and crude oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. In November 2001, the Company had costless collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from December 2001 through December 2002. The value of these derivatives at that time was $759,000. Because of Enron's financial condition, the Company concluded that the derivatives contracts no longer qualified for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 ($759,000) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. An allowance for the related asset was charged to other expense. At December 31, 2001, $706,000 remained in accumulated other comprehensive income. Total oil purchased and sold under hedging arrangements during 1999, 2000 and 2001 were 45,200 Bbls, 87,900 Bbls and 18,000 Bbls, respectively. Total natural gas purchased and sold under hedging arrangements in 1999, 2000 and 2001 were 2,050,000 MMBtu, 1,590,000 MMBtu and 3,087,000 MMBtu, respectively. The net gains and (losses) realized by the Company under such hedging arrangements were $(412,000) and $(1,537,700) and $2,015,000 for 1999, 2000 and 2001, respectively. At December 31, 2001, the Company had no derivative instruments outstanding designated as hedge positions. At December 31, 2000, the Company had outstanding hedge positions covering 1,710,000 MMBtu and 18,000 Bbls. These consisted of 1,080,000 MMBtu with a floor of $4.00 and a ceiling of $5.19 for January through December 2001 production and 630,000 MMBtu at an average fixed price of $6.60 for January through March 2001 production. The 18,000 Bbls of oil hedges had a floor of $30.00 and a ceiling of $32.28 for January through March 2001 production. These instruments had a fair market value of ($3,025,000) at December 31, 2000. At March 28, 2002, the Company had outstanding hedge positions covering 1,705,000 MMBtu of natural gas at an average fixed price of $3.19 for April 2002 through December 2002 production. The Company also had outstanding hedge positions covering 18,200 Bbls. of oil at an average fixed price of $24.65 for April 2002 through June 2002 production and 54,900 Bbls of oil hedged under a costless collar arrangement at a $22.00 floor and a $25.00 cap for April 2002 through September 2002 production. 33 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 percent fluctuation in the price received for oil and gas production would have an approximate $2.6 million impact on the Company's annual revenues and operating income. To mitigate some of this risk, the Company engages periodically in certain limited hedging activities but only to the extent of buying protection price floors. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and were not significant for any year presented. The costs to purchase put options are amortized over the option period. The Company does not hold or issue derivative instruments for trading purposes. Income and (losses) realized by the Company related to these instruments were ($412,000), ($1,537,000) and $2,015,000 or ($0.18), ($0.73) and $0.63 per MMBtu for the years ended December 31, 1999, 2000, and 2001,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 percent fluctuation in short-term interest rates would have impacted 2001 cash flow by approximately $38,000. FINANCIAL INSTRUMENTS & DEBT MATURITIES. The Company's financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowing, Subordinated Notes payable and Series B Redeemable Preferred Stock. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank and vendor borrowings approximate the carrying amounts as of December 31, 2001 and 2000, and were determined based upon interest rates currently available to the Company for borrowings with similar terms. Maturities of the debt are $2,107,000 in 2002, $8,205,391 in 2003, $3,836,498 in 2004 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 Arnold L. Chavkin resigned as a director of the Company, effective March 11, 2002. Bryan Martin has been elected as a director of the Company. Mr. Martin is a Principal with JP Morgan Partners, LLC. 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 "2002 Proxy Statement") for its 2002 annual meeting of shareholders. The 2002 Proxy Statement will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to December 31, 2001. 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 2002 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2001. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to the 2002 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2001. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The information required by this item is incorporated herein by reference to the 2002 Proxy Statement which will be filed with the Commission not later than 120 days subsequent to December 31, 2001. 34 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 EXHIBIT INDEX EXHIBIT NUMBER DESCRIPTION ------- ----------- +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1998 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company (Incorporated herein by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). +3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915), Amendment No. 2 (Incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999) and Amendment No. 3 (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated February 20, 2002). +3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other rights thereof (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated February 20, 2002). +4.1 -- 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). +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 -- Fifth 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999). +4.6 -- Sixth 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 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999). +4.7 -- Seventh 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999). +4.8 -- Eighth 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 4.8 to the Company's Annual Report of From 10-K for the year ended December 31, 2000). +4.9 -- Ninth 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 99.10 to the Company's Current Report on Form 8-K dated December 15, 1999). 35 +4.10 -- Tenth 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 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000). +4.11 -- Eleventh 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001). +4.12 -- Twelfth 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001). +4.13 -- Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage Program, dated May 1, 2001 (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +4.14 -- Amendment No. 1 to the Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage Program, dated June 1, 2001 (Incorporated herein by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +4.15 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM, Inc. (Incorporated herein by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +10.1 -- Amended and Restated Incentive Plan of the Company effective as of February 17, 2000 (Incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000). +10.2 -- 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)). +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). 36 +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). +10.19 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc. and CCBM, Inc., dated June 29, 2001 (Incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +10.20 -- Securities Purchase Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.21 -- Shareholders' Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.22 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (including Warrant Certificate) (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.23 -- Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.24 -- Compliance Sideletter dated February 20, 2002 between the Company and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.25 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.26 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the Company's Current Report on Form 8-K dated February 20, 2002). 21.1 -- Subsidiaries of the Company. 23.1 -- Consent of Arthur Andersen LLP. 23.2 -- Consent of Ryder Scott Company Petroleum Engineers. 23.3 -- Consent of Fairchild & Wells, Inc. 99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2001. 99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2001. 99.3 -- Letter to the Securities and Exchange Commission regarding Arthur Andersen LLP. ---------- + Incorporated by reference as indicated. REPORTS ON FORM 8-K On December 17, 2001 the Company filed a Current Report on Form 8-K to disclose the status of certain hedging arrangements with Enron North America Corp. 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: April 1, 2002. 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 April 1, 2002 -------------------------------- Officer and Director (Principal S. P. Johnson IV Executive Officer) /s/ FRANK A. WOJTEK Chief Financial Officer, Vice April 1, 2002 -------------------------------- President, Secretary, Treasurer Frank A. Wojtek and Director (Principal Financial Officer and Principal Accounting Officer) /s/ STEVEN A. WEBSTER Chairman of the Board April 1, 2002 -------------------------------- Steven A. Webster /s/ CHRISTOPHER C. BEHRENS Director April 1, 2002 -------------------------------- Christopher C. Behrens /s/ BRYAN MARTIN Director April 1, 2002 -------------------------------- Bryan Martin /s/ DOUGLAS A. P. HAMILTON Director April 1, 2002 -------------------------------- Douglas A. P. Hamilton /s/ PAUL B. LOYD, JR. Director April 1, 2002 -------------------------------- Paul B. Loyd, Jr. /s/ F. GARDNER PARKER Director April 1, 2002 -------------------------------- F. Gardner Parker
38 CARRIZO OIL & GAS, INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ---- Carrizo Oil & Gas, Inc. -- Report of Independent Public Accountants F-2 Consolidated Balance Sheets, December 31, 2000 and 2001 F-3 Consolidated Statements of Operations for the Years Ended December 31, 1999, 2000 F-4 and 2001 Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 1999, 2000 and 2001 F-5 Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 2000 F-6 and 2001 Notes to Financial Statements F-7
F-1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Carrizo Oil & Gas, Inc.: We have audited the accompanying consolidated balance sheets of Carrizo Oil & Gas, Inc. (a Texas corporation) as of December 31, 2000 and 2001, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2000 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities to conform with Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activities." Additionally, as explained in Note 10 to the consolidated financial statements, effective January 1, 1999, the Company changed its method of accounting for start up costs. ARTHUR ANDERSEN LLP Houston, Texas March 20, 2002 F-2 CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS ASSETS
AS OF DECEMBER 31, ------------------------------ 2000 2001 ------------- ------------- CURRENT ASSETS: Cash and cash equivalents $ 8,217,427 $ 3,235,712 Accounts receivable, net of allowance for doubtful accounts of $480,000 at December 31, 2000 and 2001, respectively 7,392,621 8,111,482 Advances to operators 1,756,396 508,563 Deposits 629,460 47,901 Other current assets 401,181 599,882 ------------- ------------- Total current assets 18,397,085 12,503,540 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and gas properties) 72,128,589 104,132,392 INVESTMENT IN MPC 1,544,180 -- OTHER ASSETS 930,059 755,731 ------------- ------------- $ 92,999,913 $ 117,391,663 ============= ============= LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade $ 3,353,570 $ 10,263,176 Accrued liabilities 1,775,830 347,778 Advances for joint operations 376,190 367,942 Current maturities of long-term debt 6,458,310 2,107,030 ------------- ------------- Total current liabilities 11,963,900 13,085,926 LONG-TERM DEBT 28,097,490 36,081,057 DEFERRED INCOME TAXES -- 5,020,576 COMMITMENTS AND CONTINGENCIES (Note 7) SHAREHOLDERS' EQUITY: Warrants (3,010,189 outstanding at December 31, 2000 and 2001, respectively) 765,047 765,047 Common stock, par value $.01, (40,000,000 shares authorized with 14,055,061 and 14,064,077 issued and outstanding at December 31, 2000 and 2001, respectively) 140,551 140,641 Additional paid in capital 62,708,100 62,735,659 Accumulated deficit (10,675,175) (1,143,634) Other comprehensive income -- 706,391 ------------- ------------- 52,938,523 63,204,104 ------------- ------------- $ 92,999,913 $ 117,391,663 ============= =============
The accompanying notes are an integral part of these financial statements. F-3 CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, -------------------------------------------------- 1999 2000 2001 -------------- -------------- -------------- OIL AND NATURAL GAS REVENUES $ 10,204,345 $ 26,833,810 $ 26,226,052 COSTS AND EXPENSES: Oil and natural gas operating expenses (exclusive of depreciation shown separately below) 3,035,610 4,940,860 4,138,353 Depreciation, depletion and amortization 4,301,268 7,170,273 6,491,521 General and administrative 2,195,364 3,143,283 3,332,673 Stock option compensation -- 651,741 (557,566) -------------- -------------- -------------- Total costs and expenses 9,532,242 15,906,157 13,404,981 -------------- -------------- -------------- OPERATING INCOME 672,103 10,927,653 12,821,071 OTHER INCOME AND EXPENSES: Other income and expenses, net of related expenses -- 1,482,372 1,777,424 Interest income 47,494 592,310 275,896 Interest expense (1,549,205) (3,372,916) (2,963,912) Interest expense, related parties (33,454) (203,642) (213,715) Capitalized interest 1,547,879 3,563,555 3,170,754 -------------- -------------- -------------- INCOME BEFORE INCOME TAXES 684,817 12,989,332 14,867,518 INCOME TAX EXPENSE (BENEFIT) (1,057,208) 1,004,361 5,335,977 -------------- -------------- -------------- NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 1,742,025 11,984,971 9,531,541 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES (77,731) -- -- -------------- -------------- -------------- NET INCOME $ 1,664,294 $ 11,984,971 $ 9,531,541 ============== ============== ============== DISCOUNT ON REDEMPTION OF PREFERRED STOCK 21,868,413 -- -- DIVIDENDS AND ACCRETION ON PREFERRED STOCK (2,417,358) -- -- -------------- -------------- -------------- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 21,115,349 $ 11,984,971 $ 9,531,541 ============== ============== ============== BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 2.01 $ 0.85 $ 0.68 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES (0.01) -- -- -------------- -------------- -------------- BASIC EARNINGS PER COMMON SHARE $ 2.00 $ 0.85 $ 0.68 ============== ============== ============== DILUTED EARNINGS PER COMMON SHARE BEFORE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 2.01 $ 0.74 $ 0.57 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES (0.01) -- -- -------------- -------------- -------------- DILUTED EARNINGS PER COMMON SHARE $ 2.00 $ 0.74 $ 0.57 ============== ============== ==============
The accompanying notes are an integral part of these financial statements. F-4 CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
WARRANTS COMMON STOCK ADDITIONAL -------------------------------- ------------------------------- PAID IN NUMBER AMOUNT SHARES AMOUNT CAPITAL -------------- -------------- -------------- -------------- -------------- BALANCE, January 1, 1999 1,000,000 $ 300,000 10,375,000 $ 103,750 $ 32,845,727 Net income -- -- -- -- -- Warrants issued 2,760,189 690,047 -- -- -- Warrants cancelled (750,000) (225,000) -- -- 225,000 Common stock issued -- -- 3,636,364 36,364 7,669,203 Redemption of preferred stock -- -- -- -- 21,868,413 Dividends and accretion on preferred stock -- -- -- -- -- Amortization of deferred compensation -- -- -- -- -- -------------- -------------- -------------- -------------- -------------- BALANCE, December 31, 1999 3,010,189 765,047 14,011,364 140,114 62,608,343 Net income -- -- -- -- -- Common stock issued -- -- 43,697 437 99,757 -------------- -------------- -------------- -------------- -------------- BALANCE, December 31, 2000 3,010,189 765,047 14,055,061 140,551 62,708,100 -------------- -------------- -------------- -------------- -------------- Comprehensive income Net income Cumulative effect of change in accounting principle Reclassification adjustments for cumulative effect of change in accounting principle Reclassification adjustments for settled contracts Change in fair value of hedging instruments -------------- -------------- -------------- -------------- -------------- Comprehensive income Common stock issued -- -- 9,016 90 27,559 -------------- -------------- -------------- -------------- -------------- BALANCE, December 31, 2001 3,010,189 $ 765,047 14,064,077 $ 140,641 $ 62,735,659 ============== ============== ============== ============== ==============
The accompanying notes are an integral part of these consolidated financial statements. F-5
ACCUMULATED OTHER COMPREHENSIVE ACCUMULATED COMPREHENSIVE DEFERRED SHAREHOLDERS' INCOME DEFICIT INCOME COMPENSATION EQUITY ------------- ------------ ------------- ------------ ------------- $ -- $(21,907,082) $ -- $ (139,910) $ 11,202,485 -- 1,664,294 -- -- 1,664,294 -- -- -- -- 690,047 -- -- -- -- -- -- -- -- -- 7,705,567 -- -- -- -- 21,868,413 -- (2,417,358) -- -- (2,417,358) -- -- -- 139,910 139,910 ------------ ------------ ------------ ------------ ------------- -- (22,660,146) -- -- 40,853,358 -- 11,984,971 -- -- 11,984,971 -- -- -- -- 100,194 ------------ ------------ ------------ ------------ ------------- -- (10,675,175) -- -- 52,938,523 ------------ ------------ ------------ ------------ ------------- 9,531,541 9,531,541 -- -- 9,531,541 (1,966,823) -- (1,966,823) -- (1,966,823) 1,966,823 -- 1,966,823 -- 1,966,823 (2,019,436) -- (2,019,436) -- (2,019,436) 2,725,827 -- 2,725,827 -- 2,725,827 ------------ ------------ ------------ ------------ ------------- $ 10,237,932 ============ -- -- -- 27,649 ------------ ------------ ------------ ------------- $ (1,143,634) $ 706,391 $ -- $ 63,204,104 ============ ============ ============ =============
CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, -------------------------------------------------- 1999 2000 2001 -------------- -------------- -------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 1,664,294 $ 11,984,971 $ 9,531,541 Adjustment to reconcile net income to net cash provided by operating activities - Depreciation, depletion and amortization 4,301,268 7,170,273 6,491,521 Discount accretion 3,537 81,853 85,384 Interest payable in kind 48,822 1,227,325 1,282,295 Stock option compensation (benefit) -- 651,741 (557,566) Valuation allowance on derivative instruments -- -- 706,391 Gain on sale of Michael Petroleum Corporation -- -- (3,900,723) Finders fee -- (1,544,180) -- Cumulative effect of change in accounting principle 77,731 -- -- Deferred income taxes (1,085,216) 902,160 5,203,632 Changes in assets and liabilities - Accounts receivable (196,918) (2,968,338) (718,861) Other current assets (369,784) (625,151) 199,802 Other assets (746,556) (236,190) (57,295) Accounts payable 26,580 (154,754) 6,555,036 Accrued liabilities (1,523,298) 642,850 (870,487) -------------- -------------- -------------- Net cash provided by operating activities 2,200,460 17,132,560 23,950,670 -------------- -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures - accrual basis (10,286,305) (19,745,805) (38,263,701) Proceeds from sale of Michael Petroleum Corporation -- -- 5,444,903 Proceeds for sale of Metro Project -- 5,075,127 -- Adjustment to cash basis (3,817,547) (587,243) 354,570 Advances to operators (74,691) (489,626) 1,247,833 Advances for joint operations 678,783 (690,013) (8,248) -------------- -------------- -------------- Net cash used in investing activities (13,499,760) (16,437,560) (31,224,643) -------------- -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from sale of common stock 7,705,567 100,194 27,649 Net proceeds from sale of preferred stock and warrants 690,047 -- -- Net proceeds from debt issuance 31,235,257 -- 7,743,369 Debt repayments (8,173,609) (3,923,385) (5,478,760) Proceeds from related party notes 2,000,000 -- -- Redemption of preferred stock (12,000,000) -- -- -------------- -------------- -------------- Net cash provided by (used in) financing activities 21,457,262 (3,823,191) 2,292,258 -------------- -------------- -------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 10,157,962 (3,128,191) (4,981,715) CASH AND CASH EQUIVALENTS, beginning of year 1,187,656 11,345,618 8,217,427 -------------- -------------- -------------- CASH AND CASH EQUIVALENTS, end of year $ 11,345,618 $ 8,217,427 $ 3,235,712 ============== ============== ============== SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized) $ 31,243 $ -- $ -- ============== ============== ==============
The accompanying notes are an integral part of these financial statements. F-6 CARRIZO OIL & GAS, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its subsidiary, affiliates and predecessors, the Company) is an independent energy company formed in 1993 and is engaged in the exploration, development, exploitation and production of oil and natural gas. The financial statements reflect the accounts of the Company and its subsidiary after elimination of all significant intercompany transactions and balances. Its operations are focused on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and Vicksburg trends. The Company has acquired 2,768 square miles of 3-D seismic data and has assembled approximately 128,602 gross acres under lease or option in the Gulf Coast region as of December 31, 2001. Also, the Company, through CCBM Inc. (a wholly-owned subsidiary) acquired interests in certain oil and gas leases in Wyoming and Montana in areas prospective for coalbed methane. CCBM Inc. plans to spend up to $5 million for drilling costs on these leases through December 2003, 50% of which would be spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf of Rocky Mountain Gas, Inc. ("RMG"), from whom the interests in the leases were acquired. 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 its exploration and development program through cash from operations, existing credit facilities or arrangements with other industry participants. Should the sources of capital currently available to the Company not be sufficient to explore and develop its prospects and meet current and near-term obligations, the Company may be required to seek additional sources of financing which may not be available on terms acceptable to the Company. This lack of additional financing could force the Company to defer its planned exploration and development drilling program which could adversely affect the recoverability and ultimate value of the Company's oil and gas properties. F-7 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. The Company proportionally consolidates its interests in oil and gas properties. During 1999, the Company also capitalized as oil and natural gas properties $139,910 of deferred compensation related to stock options granted to personnel directly associated with exploration activities. No deferred compensation cost was capitalized in 2000 or 2001. Additionally, the Company capitalized compensation costs for employees working directly on exploration activities of $581,000, $886,000 and $1,021,000 in 1999, 2000 and 2001, respectively. 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 periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per thousand cubic feet equivalent (Mcfe) for 1999, 2000 and 2001, was $1.00, $1.03 and $1.15, 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 revenues from proved reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. No write-down of the Company's oil and natural gas assets was necessary in 1999, 2000 or 2001. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of oil and gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a ceiling writedown. Using prices in effect on December 31, 2001 the pretax writedown would have been approximately $700,000. Because of the volatility of oil and gas prices, no assurance can be given that the Company will not experience a ceiling test writedown in future periods. Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years. FINANCING COSTS Long-term debt financing costs included in other assets of $930,059 and $755,731 as of December 31, 2000 and 2001, respectively, are being amortized using the effective yield method over the term of the loans (through April 1, 2003 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 recorded financial instruments consist of cash, receivables, payables and long-term debt. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying amount of long-term debt (except the subordinated notes payable) approximates fair value as the individual borrowings bear interest at floating market interest rates. STOCK-BASED COMPENSATION The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations. Under this method, the Company records no compensation expense for stock options granted when the exercise price of those options is equal to or greater than the market price of the Company's common stock on the date of grant. Repriced options are accounted for as compensatory options using variable accounting treatment. Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company's common stock. Variable plan accounting is applied to the repriced options until the options are exercised, forfeited, or expire unexercised. F-8 DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities". This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement requires all derivative instruments to be carried on the balance sheet at fair value with changes in a derivative instrument's fair value recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was effective for the Company beginning January 1, 2001 and was adopted by the Company on that date. In accordance with the current transition provisions of SFAS No. 133, the Company recorded a cumulative effect transition adjustment of $2.0 million (net of related tax expense of $1.1 million) in accumulated other comprehensive income to recognize the fair value of its derivatives designated as cash flow hedging instruments at the date of adoption. Upon entering into a derivative contract, the Company designates the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as oil and gas revenues when the forecasted transaction occurs. All of the Company's derivative instruments at January 1, 2001 and December 31, 2001 were designated and effective as cash flow hedges except for its positions with an affiliate of Enron Corp. discussed in Note 12. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in future earnings. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and crude oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. 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 and future income taxes. 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. F-9 EARNINGS PER SHARE Supplemental earnings per share information is provided below:
FOR THE YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------------------------------- INCOME (LOSS) SHARES ----------------------------------------------- ---------------------------------------------- 1999 2000 2001 1999 2000 2001 ------------ ------------ ------------ ------------ ------------ ------------ Net income before cumulative effect of change in accounting principle $ 1,742,025 $ 11,984,971 $ 9,531,541 Plus: Discount on redemption of preferred stock 21,868,413 -- -- Less: Dividends and accretion on preferred stock (2,417,358) -- -- ------------ ------------ ------------ Basic earnings per share before cumulative effect of change in accounting principle Net income available to common shareholders 21,193,080 11,984,971 9,531,541 10,544,365 14,028,176 14,059,151 Stock options and warrants -- -- -- 1,886 2,227,479 2,671,850 ------------ ------------ ------------ ------------ ------------ ------------ Diluted earnings per share before cumulative effect of change in accounting principle Net income available to common shareholders plus assumed conversions $ 21,193,080 $ 11,984,971 $ 9,531,541 10,546,251 16,255,655 16,731,001 ============ ============ ============ ============ ============ ============ 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) -- -- 10,544,365 14,028,176 14,059,151 Stock options and warrants -- -- -- 1,886 2,227,479 2,671,850 ------------ ------------ ------------ ------------ ------------ ------------ Diluted earnings per share of cumulative effect of change in accounting principle Net loss available to common shareholders plus assumed conversions $ (77,731) $ -- $ -- 10,546,251 16,255,655 16,731,001 ============ ============ ============ ============ ============ ============ Net income $ 1,664,294 $ 11,984,971 $ 9,531,541 Plus: Discount on redemption of preferred stock 21,868,413 -- -- Less: Dividends and accretion on preferred stock (2,417,358) -- -- ------------ ------------ ------------ Basic earnings per share Net income available to common shareholders 21,115,349 11,984,971 9,531,541 10,544,365 14,028,176 14,059,151 Stock options and warrants -- -- -- 1,886 2,227,479 2,671,850 ------------ ------------ ------------ ------------ ------------ ------------ Diluted earnings per share Net income available to common shareholders plus assumed conversions $ 21,115,349 $ 11,984,971 $ 9,531,541 10,546,251 16,255,655 16,731,001 ============ ============ ============ ============ ============ ============ -------------------------------------- PER-SHARE AMOUNT -------------------------------------- 1999 2000 2001 ----------- --------- --------- Net income 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 available to common shareholders $ 2.01 $ 0.85 $ 0.68 =========== ========== ========= Stock options and warrants Diluted earnings per share before cumulative effect of change in accounting principle Net income (loss) available to common shareholders plus assumed conversions $ 2.01 $ 0.74 $ 0.57 =========== ========== ========= 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 and warrants 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 Plus: Discount on redemption of preferred stock Less: Dividends and accretion on preferred stock Basic earnings per share Net income available to common shareholders $ 2.00 $ 0.85 $ 0.68 =========== ========== ========= Stock options and warrants Diluted earnings per share Net income available to common shareholders plus assumed conversions $ 2.00 $ 0.74 $ 0.57 =========== ========== =========
F-10 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. The Company had outstanding 799,620, 149,000 and 79,500 stock options at December 31, 1999, 2000 and 2001, respectively, that were antidilutive. The Company also had outstanding 3,010,189 warrants at December 31, 1999 that were antidilutive. These antidilutive stock options and warrants were not included in the calculation because the exercise price of these instruments exceeded the underlying market value of the options and warrants as of the dates presented. CONTINGENCIES Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable. Costs to remedy or defend against such contingencies are charged to the liability, if one exists, or otherwise to income. NEW ACCOUNTING PRONOUNCEMENTS On June 29, 2001, the FASB approved its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Under SFAS 141, all business combinations should be accounted for using the purchase method of accounting; use of the pooling-of-interests method is prohibited. The provisions of the statement will apply to all business combinations initiated after June 30, 2001. SFAS 142 will apply to all acquired intangible assets whether acquired singly, as part of a group, or in a business combination. The statement will supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible Assets," and will carry forward provisions in APB Opinion No. 17 related to internally developed intangible assets. Adoption of SFAS 142 will result in ceasing amortization of goodwill. All of the provisions of the statement should be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company does not have any goodwill or intangible assets recorded as of December 31, 2001 and does not expect the adoption of this standard to have a material impact on its financial position or results of operations. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement of obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the effect of adopting SFAS No. 143 on its financial statements and has not determined the timing of adoption. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121 but retains its fundamental provisions for the (a) recognition/measurement of impairment of long-lived assets to be held and used and (b) measurement of long-lived assets to be disposed of by sale. SFAS 144 also supercedes the accounting/reporting provisions of APB Opinion No. 30 for segments of a business to be disposed of but retains the requirement to report discontinued operations separately from continuing operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. SFAS No. 144 is effective for the Company beginning in 2002. The Company is currently evaluating the impact of this new standard. 3. INVESTMENT IN MICHAEL PETROLEUM CORPORATION: In 2000 the Company received a finder's fee valued at $1,544,180 from affiliates of Donaldson, Lufkin & Jenrette ("DLJ") in connection with their purchase of a significant minority shareholder interest in Michael Petroleum Corporation ("MPC"). MPC is a privately held exploration and production company which focuses on the prolific gas producing Lobo Trend in South Texas. The minority shareholder interest in MPC was purchased by entities affiliated with DLJ. The Company elected to receive the fee in the form of 18,947 shares of common stock, 1.9% of the outstanding common shares of MPC, which, until its sale in 2001, was accounted for as a cost basis investment. Steven A. Webster, who is the Chairman of the Board of the Company, and a Managing Director of Global Energy Partners Ltd., a merchant banking affiliate of DLJ which makes investments in energy companies, joined the Board of Directors of MPC in connection with the transaction. In 2001, the Company agreed to sell its interest in MPC pursuant to an agreement between MPC and its shareholders for the sale of a majority interest in MPC to Calpine Natural Gas Company. The Company expects to receive total cash proceeds of between $5.5 and $5.7 million, of which $5.5 million was paid to the Company during the third quarter of 2001, resulting in a financial statement gain of $3.9 million being reflected in the third quarter 2001 financial results. 4. PROPERTY AND EQUIPMENT At December 31, 2000 and 2001, property and equipment consisted of the following: F-11
DECEMBER 31, ---------------------------------- 2000 2001 --------------- --------------- Proved oil and natural gas properties $ 73,427,767 $ 104,005,045 Unproved oil and natural gas properties 36,994,563 44,416,146 Other equipment 343,723 608,562 --------------- --------------- Total property and equipment 110,766,053 149,029,753 Accumulated depreciation, depletion and amortization (38,637,464) (44,897,361) --------------- --------------- Property and equipment, net $ 72,128,589 $ 104,132,392 =============== ===============
Oil and natural gas properties not subject to amortization consist of the cost of unevaluated leaseholds, seismic costs associated with specific unevaluated properties, exploratory wells in progress, and secondary recovery projects before the assignment of proved reserves. These unproved costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and natural gas leases not held by production, production response to secondary recovery activities and available funds for exploration and development. Of the $44,416,146 of unproved property costs at December 31, 2001 being excluded from the amortizable base, $4,231,137, $4,498,294 and $11,251,050 were incurred in 1999, 2000 and 2001, respectively. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two to five years. 5. INCOME TAXES All of the Company's income is derived from domestic activities. Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows:
YEAR ENDED DECEMBER 31, ----------------------------------------------- 1999 2000 2001 ------------- ------------- ------------- Provision at the statutory tax rate $ 212,480 $ 4,546,265 $ 5,203,632 Increase (decrease) in valuation allowance pertaining to expected net operating loss utilization (1,297,696) (3,644,105) -- Other 28,008 102,201 132,345 ------------- ------------- ------------- Income tax provision (benefit) $ (1,057,208) $ 1,004,361 $ 5,335,977 ============= ============= =============
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, 2000 and 2001, the tax effects of these temporary differences resulted principally from the following:
AS OF DECEMBER 31, ----------------------------- 2000 2001 ------------- ------------- Deferred income tax assets: Net operating loss carryforward $ 3,613,677 3,150,000 ------------- ------------- 3,613,677 3,150,000 Deferred income tax liabilities: Oil and gas acquisition, exploration and development costs deducted for tax purposes in excess of financial statement DD&A 1,804,911 5,436,502 Capitalized interest 1,625,710 2,734,074 ------------- ------------- 3,430,621 8,170,576 ------------- ------------- Net deferred income tax asset $ 183,056 ============= Net deferred income tax liability $ 5,020,576 =============
F-12 The net deferred income tax asset is classified as follows:
AS OF DECEMBER 31, --------------------------------- 2000 2001 --------------- --------------- Other current assets $ 183,056 $ -- Deferred income taxes -- 5,020,576 --------------- --------------- $ 183,056 $ 5,020,576 =============== ===============
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 its deferred tax assets will be fully realized. The Company has net operating loss carryforwards totaling approximately $9.0 million which begin expiring in 2012. 6. LONG-TERM DEBT At December 31, 2000 and 2001, long-term debt consisted of the following:
AS OF DECEMBER 31, -------------------------------- 2000 2001 -------------- -------------- Credit facility: Borrowing base facility $ 5,426,000 $ 7,166,000 Term loan facility 5,260,000 -- Senior subordinated notes 20,462,797 21,635,252 Senior subordinated notes, related parties 2,208,693 2,403,916 Capital lease obligation -- 232,919 Vendor notes payable 1,198,310 -- Non-recourse note payable to Rocky Mountain Gas, Inc. -- 6,750,000 -------------- -------------- 34,555,800 38,188,087 Less: current maturities (6,458,310) (2,107,030) -------------- -------------- $ 28,097,490 $ 36,081,057 ============== ==============
Carrizo amended its existing credit facility with Compass Bank ("Compass") 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") which provided for a maximum loan amount of $25 million subject to Borrowing Base limitations. 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. 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, 2000 and 2001, amounts outstanding under the Borrowing Base Facility totaled $5,426,000 and $7,166,000, respectively, with an additional $2,676,884 and $620,000, respectively, available for future borrowings. The Borrowing Base totaled $8,010,000 at December 31, 2001. The Borrowing Base Facility was also available for letters of credit, one of which has been issued for $224,000 at December 31, 2000 and 2001. The Borrowing Base facility was amended in November 2000 to provide up to $2 million of Guidance Line letters of credit (the "Guidance Line letters of credit") relating exclusively to the Company's outstanding hedge positions. At December 31, 2000, the Company had one Guidance Line letter of credit outstanding amounting to $180,000 and no Guidance Line letters of credit outstanding at December 31, 2001. The weighted average interest rate for 2000 and 2001 on the Facility was nine and seven percent, respectively. F-13 The Term Loan was initially due and payable upon maturity in September 1999. 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. 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 had guaranteed the Term Loan. The Term Loan was repaid during September 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. In March 1999, the Company Credit Facility was amended to decrease the required specified tangible net worth covenant. The Company is currently in compliance with the covenants under the Company Credit Facility. On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company ("CCBM"), issued a non-recourse promissory note payable in the amount of $7,500,000 to RMG as consideration for certain interest in oil and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $125,000 plus interest at eight percent per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and gas leases in Wyoming and Montana. At December 31, 2001, the principal balance of this note was $6,750,000. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $243,369. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6 percent per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1. 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 percent 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 1999. 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. (now known as JP Morgan Partners, LLC) which included certain members of the Board of Directors. As discussed in Note 9, 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. Quarterly interest payments began on March 31, 2000. The Company may elect to increase the amount of the Subordinated Notes for 60 percent of the interest which would otherwise be payable in cash. For the years ended December 31, 2000 and 2001, the amount of the Subordinated Notes was increased by $1,227,325 and $1,282,295 for such interest. Such Senior Subordinated Notes had a fair market value at December 31, 2001 of approximately $24 million. The Company is subject to certain covenants under the terms of 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 (as defined) 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 (unless approved by the Company's Board of Directors and a CB Capital Investors, L.P. director). The Company is currently in compliance with the covenants under the Subordinated Notes. Estimated maturities of long-term debt are $2,107,030 in 2002, $8,205,391 in 2003, $3,836,498 in 2004 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 $1,198,310 and none at December 31, 2000 and 2001, respectively, and bear interest at rates of 8 percent to 10 percent. The weighted average interest rates of such notes was 9 percent in 2000. F-14 7. MANDATORILY REDEEMABLE PREFERRED STOCK In January 1998, the Company consummated the sale of 300,000 shares of Series A Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to affiliates of Enron Corp. The net proceeds received by the Company from this transaction were approximately $28.8 million. 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 Series A Preferred Stock provided for annual cumulative dividends of $9.00 per share, payable quarterly in cash or, at the option of the Company until January 15, 2002, in additional shares of Series A Preferred Stock. During 1999, the Company issued preferred stock dividends to the holders of the Series A Preferred Stock of 29,684.39 shares. In December 1999, the Company consummated the repurchase of all the outstanding shares of Series A 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 was included in 1999 net income available to common shareholders, net of stock dividends paid to the holders of the Series A Preferred Stock of $2,417,358. 8. 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. Settlement of Litigation. The Company, as one of three plaintiffs, filed a lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial District Court of Duval County, Texas, for fraud and breach of contract in connection with an agreement between plaintiffs and defendants whereby the defendants were obligated to drill a test well in an area known as the Slick Prospect in Duval County, Texas. The allegations of the Company in this litigation were that BNP gave the Company inaccurate and incomplete information on which the Company relied in making its decision not to participate in the test well and the prospect, resulting in the loss of the Company's interest in the lease, the test well and four subsequent wells drilled in the prospect. The Company has sought to enforce its approximate 23.68% interest in the prospect and sought damages or rescission, as well as costs and attorneys' fees. The case was originally filed in Duval County, Texas on February 25, 2000. In mid March 2000, the defendants filed an original answer and certain counterclaims against plaintiffs, seeking unspecified damages for slander of title, tortious interference with business relations, and exemplary damages. The case proceeded to trial before the Court (without a jury) on June 19, 2000 after the plaintiffs' were found by the court to have failed to comply with procedural requirements regarding the request for a jury. After several days of trial the case was recessed and later resumed on September 5, 2000. The court at that time denied the plaintiffs' motion for mistrial based on the court's denial of a jury trial. The court also ordered that the defendants' counterclaims would be the subject of a separate trial that would commence on December 11, 2000. The parties proceeded to try issues related to the plaintiffs' claims on September 5, 2000. All parties rested on the plaintiffs' claims on September 13, 2000. The court took the matter under advisement. Defendants filed a second amended answer and counterclaim and certain supplemental responses to request for disclosure in which they stated that they were seeking damages in the amount of $33.5 million by virtue of an alleged lost sale of the subject properties, $17 million in alleged lost profits from other prospective contracts, and unspecified incidental and consequential damages from the alleged wrongful suspension of funds under their gas sales contract with the gas purchaser on the properties, alleged damage to relationships with trade creditors and financial institutions, including the inability to leverage the Slick Prospect, and attorneys' fees at prevailing hourly rates in Duval County, Texas incurred in defending against plaintiffs' claims and for 40 percent of any aggregate recovery in prosecuting their counterclaims. In subsequent testimony, the defendants verbally alleged $26 million of damages by virtue of the alleged lost sale of the properties (as opposed to the $33.5 million previously sought), $7.5 million of damages by virtue of loss of a lease development opportunity and $100 million of damages by virtue of the loss of a business opportunity related to BNP's alleged inability to participate in a 3-D seismic project. On December 8, 2000 the Company entered into a Compromise and Settlement Agreement ("Settlement Agreement") with the defendants with regard to the above described litigation. Under the terms of the Settlement Agreement, the Company and the defendants agreed to enter into an Agreed Order of Dismissal with Prejudice of the litigation and, among other things, agreed as follows: 1. Should a co-plaintiff to the Duval County litigation secure a final judgment (without regard to appeals, new trials or other such actions) in the trial court in Duval County that results in such plaintiff being entitled to recover a five percent or greater undivided interest in the Slick Prospect, BNP will pay to Carrizo, at BNP's option, either $500,000 or an amount equal to the judgment rendered in favor of such plaintiff. 2. Should the defendants secure a final judgment (without regard to appeals, new trials or other such actions) in the trial court in Duval County against a co-plaintiff, the Company will be obligated to pay BNP an amount equal to five percent of any percentage of the total judgment apportioned to the Company in the case, such payment being limited however to no more than five percent of 47.2% of the total judgment entered in the case. 3. In the event the defendants and such co-plaintiff reach a full and final settlement prior to the entry of a written final judgment in the trial court in Duval County (including but not limited to any type of agreed judgment or any agreement that such co-plaintiff will not be ultimately liable to BNP for the full amount of any judgment rendered in favor of the defendants), the obligations described in (1) and (2) above will be null and void. Also, in the event BNP and such co-plaintiff both only obtain take nothing judgments in the case, such obligations will be null and void. F-15 4. Both the Company and the defendants released each other from any and all claims, demands, actions or causes of action relating to or arising out of the litigation. The case proceeded to trial on the counterclaims on December 11, 2000 in the Duval County court. BNP presented evidence that its damages were in the amounts of $19.6 million for the alleged lost sale of the properties, $35 million for loss of the lease development opportunity, and $308 million for loss of the opportunity related to participation in the 3-D seismic project. During the course of the trial, the co-plaintiff presented its motion for summary judgment on the counterclaims based on the doctrine of absolute judicial proceeding privilege. The court partially granted the co-plaintiff's motion for summary judgment as it related to the filing of a lis pendens, but denied it with regard to the other allegations of BNP on November 12, 2001 in final settlement of the litigation. Upon completion of the trial, the court announced that it would take the case under advisement. On November 5, 2001, the court filed with the clerk a final judgment that had been signed by the court on October 26, 2001. Pursuant to the terms of the judgment, the Company, and its co-plaintiffs, take nothing on their claims against BNP and are denied any recovery of their interests in the lease, the prospect, or the wells of the Slick Prospect. Instead, the court confirmed title in the lease, prospect, and wells in BNP's affiliate. In addition, the Company and its co-defendants were found to have tortiously and maliciously interfered with two different BNP contracts or prospective contracts and the business of BNP and its affiliate, causing damages with respect to the loss of a sale and the loss of a lease. Under the terms of the Settlement Agreement, the Company paid $472,000 to BNP. The settlement amount, along with the related legal fees, has been included as other expense in the accompanying financial statements. In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in N. LaCopita Prospect in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of their lease, remove cloud on title, quiet title to the property, and for conversion, trespass and punitive damages. ExxonMobil seek unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that the Company acted in good faith and intends to vigorously defend its position. The Company, along with GMT and the other partners, are attempting to negotiate a settlement with ExxonMobil that would allow GMT et al (including the Company) to participate for their respective shares of a working interest in the Neblett unit, and would allow for the recovery of well costs. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its costs as a good faith trespasser. A complete loss of the lease in question would result in the loss to the Company of approximately .6 Bcfe of reported proved reserves as of December 31, 2000 or .9 Bcfe of reported proved reserves as of June 30, 2001. No reserves with respect to these properties were included in the Company's reported proved reserves as of December 31, 2001. At the time of shut in, the Neblett #1 well was producing at the rate of approximately 45 Mcfe per day, the Neblett #2 well was producing at the rate of approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate of approximately 895 Mcfe per day, all net to the Company's interest. The Company believes that an unfavorable outcome in this matter would not have a material impact on its financial statements. The Company has recorded revenues only to the extent of well costs funded by the Company. During November 2000, the Company entered into a one-year contract with Grey Wolf, Inc. for utilization of a 1,500 horsepower drilling rig capable of drilling wells to a depth of approximately 18,000 feet. The contract provided for a dayrate of $12,000 per day. The rig was utilized primarily to drill wells in the Company's focus areas, including the Matagorda Project Area and the Cabeza Creek Project Area. The contract contained a provision which would allow the Company to terminate the contract early by tendering payment equal to one-half the dayrate for the number of days remaining under the term of the contract as of the date of termination. The contract commenced in February 2001 and expired in February 2002. Steven A. Webster, who is the Chairman of the Board of Directors of the Company, is a member of the Board of Directors of Grey Wolf, Inc. During August 2001, the Company entered into an agreement whereby the lessor will provide to the Company up to $800,000 in financing for production equipment utilizing capital leases. At December 31, 2001, one lease in the amount of $243,369 had been executed under this facility. At December 31, 2001, the Company was obligated under a noncancelable operating lease for office space. Rent expense for the years ended December 31, 1999, 2000 and 2001 was $108,700, $207,000 and $207,000, respectively. The Company is obligated for remaining lease payments of $225,000 per year through December 31, 2004. 9. SHAREHOLDERS' EQUITY In December 1999, in connection with the sale of the Subordinated Notes (see Note 6) 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. (now known as J.P. Morgan Partners, LLC) which included certain members of the Board of Directors. The Warrants have an exercise price of $2.20 per share and expire December 2007. F-16 In connection with its 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 $139,910 being recorded in the year ended December 31, 1999. The following table summarizes information for the options outstanding at December 31, 2001:
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 12/31/01 LIFE IN YEARS PRICE AT 12/31/01 PRICE -------------------------------- ------------------ -------------------- --------------- ------------------- --------------- $1.75-2.25 729,537 8.03 $ 2.19 278,478 $ 2.16 $3.14-3.60 309,120 5.92 $ 3.54 247,120 $ 3.58 $4.01-5.00 424,000 9.85 $ 4.25 -- $ -- $5.17-8.00 174,000 7.92 $ 7.01 99,833 $ 6.73
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 "Accounting For Stock Issued to Employees" ("APB No. 25"), under which no compensation cost has been recognized on options which have exercise prices at least equal to the market price of the stock on the date of the grant. Had compensation cost been determined consistent with SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the Company's net income (loss) and earnings per share would have been as follows:
1999 2000 2001 ------------ ------------ ----------- Net income available to common shareholders As reported $ 21,115,349 $ 11,984,971 $ 9,531,541 Pro forma $ 20,292,252 $ 11,487,013 $ 8,161,856 Diluted earnings (loss) per share As reported $ 2.00 $ 0.74 $ 0.57 Pro forma $ 1.94 $ 0.71 $ 0.49
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 1999, 2000 and 2001: risk free interest rate of 6.81 percent, 6.66 percent and 4.93 percent, respectively, expected dividend yield of 0 percent, expected life of 10 years and expected volatility of 70.0 percent, 70.8 percent and 80.7 percent, respectively. The Company may grant options ("Incentive Plan Options") to purchase up to 1,500,000 shares under the Incentive Plan and has granted options on 1,466,500 shares through December 31, 2001. Through December 31, 2001, 43,963 stock options had been exercised. A summary of the status of the Company's stock options at December 31, 1999, 2000 and 2001 is presented in the table below: F-17
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 $ 1.75 - 11.00 ============ ============= ================= Exercisable at end of year 446,286 $ 6.70 ============ ============= ================= Weighted average of fair value of options granted during the year $ 1.34 ============
2000 ------------------------------------------------- WEIGHTED AVERAGE RANGE OF EXERCISE EXERCISE SHARES PRICES PRICES -------------- ------------- ------------------- Outstanding at beginning of year 827,120 $ 6.01 $1.75 - $11.00 Granted (Incentive Plan Options) 425,000 $ 3.85 $2.20 - $8.00 Exercised (Pre-IPO Options) (3,000) $ 3.60 $3.60 Exercised (Incentive Plan Options) (40,697) $ 2.20 $2.00 - $6.00 Expired (Incentive Plan Options) (2,000) $ 3.50 $3.50 -------------- ------------- Outstanding at end of year 1,206,423 $ 5.20 $2.00 - $11.00 ============== ============= Exercisable at end of year 316,388 $ 3.79 ============== ============= Weighted average of fair value of options granted during the year $ 2.94 ==============
2001 ------------------------------------------------- WEIGHTED AVERAGE RANGE OF EXERCISE EXERCISE SHARES PRICES PRICES -------------- ------------- ------------------- Outstanding at beginning of year 1,206,423 $ 5.20 $1.75 - $11.00 Granted (Incentive Plan Options) 436,500 $ 4.34 $4.01 - $7.40 Exercised (Pre-IPO Options) (3,000) $ 3.60 $3.60 Exercised (Incentive Plan Options) (3,266) $ 2.13 $2.00 - $2.25 -------------- ------------- Outstanding at end of year 1,636,657 $ 3.49 ============== ============= Exercisable at end of year 625,701 $ 3.45 ============== ============= Weighted average of fair value of options granted during the year $ 3.57 ==============
In March of 2000, the FASB issued Interpretation No. 44 "Accounting for Certain Transactions involving Stock Compensation - an interpretation of APB No. 25" ("the Interpretation") which was effective July 1, 2000 and clarifies the application of APB No. 25 for certain issues associated with the issuance or subsequent modifications of stock compensation. For certain modifications, including stock option repricings made subsequent to December 15, 1998, the Interpretation requires that variable plan accounting be applied to those modified awards prospectively from July 1, 2000. This requires that the change in the intrinsic value of the modified awards be recognized as compensation expense. On February 17, 2000, Carrizo repriced certain employee and director stock options covering 348,500 shares of stock with a weighted average exercise price of $9.13 to a new exercise price of $2.25 through the F-18 cancellation of existing options and issuance of new options at current market prices. Subsequent to the adoption of the Interpretation, the Company is required to record the effects of any changes in its stock price over the remaining vesting period through February 2010 on the corresponding intrinsic value of the repriced options in its results of operations as compensation expense until the repriced options either are exercised or expire. Stock option compensation expense (benefit) relating to the repriced options for the years ended December 31, 2000 and 2001 amounted to $651,741 and $(557,566), respectively. 10. 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 totaled $77,731 in 1999. 11. RELATED-PARTY TRANSACTIONS 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 were members of the Board of Directors of both the Company and R&B Falcon Corporation ("R&B"). In addition, Mr. Loyd was 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. There were no transactions with R&B during the year ended December 31, 2000. During the year ended December 31, 2001, the Company incurred drilling costs in the amount of $6.3 million with Grey Wolf Drilling. Mr. Webster is the Chairman of the Board of Carrizo and a member of the Board of Directors of Grey Wolf Drilling. It is management's opinion that these transactions with Grey Wolf were performed at prevailing market rates. During the year ended 2001, the Company participated in the drilling of two wells that were operated by a subsidiary of Brigham Exploration Company. Mr. Webster is a member of the Board of Directors of Brigham Exploration Company ("Brigham"). The terms of the operating agreement between Carrizo and Brigham are consistent with standard industry practices. See Notes 6 and 13 for a discussion of the December 1999 and February 2002 financings with parties that included members of the Company's Board of Directors. 12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from December 2001 through December 2002. The value of these derivatives at that time was $759,000. Because of Enron's financial condition, the Company concluded that the derivatives contracts were no longer effective and thus did not qualify for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 ($759,000) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. An allowance for the related asset totaling $759,000, net of tax of $409,000, was charged to other expense. At December 31, 2001, $706,000, net of tax of $380,000, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. Total oil purchased and sold under hedging arrangements during 1999, 2000 and 2001 were 45,200 Bbls, 87,900 Bbls and 18,000 Bbls, respectively. Total natural gas purchased and sold under hedging arrangements in 1999, 2000 and 2001 were 2,050,000 MMBtu, 1,590,000 MMBtu and 3,087,000 MMBtu, respectively. The net gains and (losses) realized by the Company under such hedging arrangements were $(412,000) and $(1,537,700) and $2,015,000 for 1999, 2000 and 2001, respectively, and are included in oil and gas revenues. At December 31, 2000, the Company had outstanding hedge positions covering 1,710,000 MMBtu and 18,000 Bbls. These consisted of 1,080,000 MMBtu with a floor of $4.00 and a ceiling of $5.19 for January through December 2001 production and 630,000 MMBtu at an average fixed price of $6.60 for January through March 2001 production. The 18,000 Bbls of oil hedges had a floor of $30.00 and a ceiling of $32.28 for January through March 2001 production. These instruments had a fair market value of ($3,025,000) at December 31, 2000. At December 31, 2001, the Company had no derivative instruments outstanding designated as hedge positions. 13. SUBSEQUENT EVENTS In February 2002, the Company consummated the sale of $6 million of Convertible Participating Series B Preferred Stock and warrants to purchase Carrizo common stock to an investor group led by Mellon Ventures, Inc. which included Steven A. Webster, the Company's Chairman of the Board of Directors. The Series B Preferred Stock is convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustments, and is initially convertible into 1,052,632 shares of common stock. Dividends on the Series B Preferred Stock will be payable in either cash at a rate of eight percent per annum or, at the Company's option, by payment in kind of additional shares of the same series of preferred stock at a rate of ten percent per annum. The Series B Preferred Stock is redeemable at varying prices in whole or in part at the holders' option after three years or at the Company's option at any time. The Series B Preferred Stock will also participate in any dividends declared on the common stock. Holders of the Preferred Stock will receive a liquidation preference upon the liquidation of, or certain mergers or sales of substantially all assets involving, the Company. Such holders will also have the option of receiving a change of control repayment price upon certain deemed change of control transactions. The warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo's common stock at a price of $5.94 per share, subject to adjustments, and are exercisable at any time after issuance. The warrants may be exercised on a cashless exercise basis. The approximately $5,800,000 proceeds of this financing are expected to be used primarily to fund the Company's ongoing exploration and development program. Event (unaudited) subsequent to the date of the auditor's report. On March 24, 2002, a subsidiary of the Brigham Exploration Company, the operator of the "Burkhart #1" well in the Company's Matagorda Project Area in Matagorda County, Texas reported a loss of surface control while drilling the well, and as of March 28, 2002, operations were underway to bring the well under control. The Company owns a 35% working interest in the well. The Company has liability and well control insurance that it believes will be sufficient to cover any liabilities to third parties and the cost to bring the well under control, including, if necessary, the drilling of a replacement well. 14. 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." F-19 COSTS INCURRED Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:
YEAR ENDED DECEMBER 31, ------------------------------------------ 1999 2000 2001 ------------ ------------ ------------ Property acquisition costs Unproved $ 4,166,033 $ 6,641,275 $ 12,607,025 Proved 472,229 336,750 800,000 Exploration cost 3,163,309 7,843,425 3,064,585 Development costs 936,855 1,360,800 18,356,533 ------------ ------------ ------------ Total costs incurred (1) $ 8,738,426 $ 16,182,250 $ 34,828,143 ============ ============ ============
---------- (1) Excludes capitalized interest on unproved properties of $1,547,879, $3,563,555 and $3,170,754 for the years ended December 31, 1999, 2000 and 2001, respectively. OIL AND NATURAL GAS RESERVES Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities at December 31, 2000 and 2001, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company and Fairchild & Wells, Inc., independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. 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, ----------------------------------------------------- 1999 2000 2001 --------------- --------------- --------------- Proved developed and undeveloped reserves - Beginning of year 3,647,000 4,877,000 6,397,000 Purchase of oil and gas properties in place -- -- -- Discoveries and extensions 113,000 93,000 600,000 Revisions 1,296,000 1,625,000 20,000 Production (179,000) (198,000) (160,000) --------------- --------------- --------------- End of year 4,877,000 6,397,000 6,857,000 =============== =============== =============== Proved developed reserves at end of year 1,070,000 1,017,000 1,158,000 =============== =============== ===============
F-20
THOUSANDS OF CUBIC FEET OF NATURAL GAS AT DECEMBER 31, ------------------------------------------------- 1999 2000 2001 --------------- --------------- --------------- Proved developed and undeveloped reserves - Beginning of year 10,155,000 11,323,000 10,992,000 Purchases of oil and gas properties in place - - - Discoveries and extensions 4,820,000 4,179,000 12,560,000 Revisions (417,000) 1,553,000 (1,262,000) Sales of oil and gas properties in place - (603,000) - Production (3,235,000) (5,460,000) (4,432,000) --------------- --------------- --------------- End of year 11,323,000 10,992,000 17,858,000 =============== =============== =============== Proved developed reserves at end of year- 10,680,000 10,351,000 13,754,000 =============== =============== ===============
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, ------------------------------------------- 1999 2000 2001 ------------ ------------ ------------ Future cash inflows $140,851,000 $266,725,000 $169,856,000 Future oil and natural gas operating expenses 46,679,000 126,526,000 76,348,000 Future development costs 12,428,000 14,284,000 16,083,000 Future income tax expenses 11,952,000 25,242,000 5,822,000 ------------ ------------ ------------ Future net cash flows 69,792,000 100,673,000 71,603,000 10% annual discount for estimating timing of cash flows 27,062,000 30,567,000 27,026,000 ------------ ------------ ------------ Standard measure of discounted future net cash flows $ 42,730,000 $ 70,106,000 $ 44,577,000 ============ ============ ============
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 1999, 2000 and 2001 future cash flows were $23.40, $24.85 and $17.71 for oil, respectively and $2.35, $10.34 and $2.76 for natural gas, respectively. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for tax basis and availability of applicable tax assets. A discount factor of 10 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. 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: F-21
1999 2000 2001 -------------- -------------- -------------- Changes due to current-year operations - Sales of oil and natural gas, net of oil and natural gas operating expenses $ (7,169,000) $ (21,893,000) $ (23,622,000) Extensions and discoveries 9,095,000 26,214,000 28,009,000 Purchases of oil and gas properties -- -- -- Changes due to revisions in standardized variables Prices and operating expenses 32,560,000 16,686,000 (38,472,000) Income taxes (8,447,000) (14,090,000) 13,367,000 Estimated future development costs (4,581,000) (1,122,000) (1,070,000) Revision of quantities 11,770,000 2,921,000 (1,109,000) Sales of reserves in place -- (254,000) -- Accretion of discount 1,876,000 4,736,000 8,768,000 Production rates, timing and other (11,129,000) 14,178,000 (11,400,000) -------------- -------------- -------------- Net change 23,975,000 27,376,000 (25,529,000) Beginning of year 18,755,000 42,730,000 70,106,000 -------------- -------------- -------------- End of year $ 42,730,000 $ 70,106,000 $ 44,577,000 ============== ============== ==============
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, extentions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pretax discounted basis, while the accretion of discount is presented on an after-tax basis. F-22 SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
2001 FIRST SECOND THIRD FOURTH ------------- ------------- ------------- ------------- Revenues $ 8,727,481 $ 7,092,202 $ 6,161,679 $ 4,244,690 Costs and expenses, net 5,263,672 4,792,472 2,615,653 4,022,714 ------------- ------------- ------------- ------------- Net income $ 3,463,809 $ 2,299,730 $ 3,546,026 $ 221,976 ============= ============= ============= ============= Basic net income per share (1) $ 0.25 $ 0.16 $ 0.25 $ 0.02 ============= ============= ============= ============= Diluted net income per share (1) $ 0.21 $ 0.14 $ 0.22 $ 0.01 ============= ============= ============= =============
2000 FIRST SECOND THIRD FOURTH ------------- ------------- ------------- ------------- Revenues $ 4,279,597 $ 5,826,737 $ 8,007,583 $ 8,719,893 Costs and expenses, net 3,151,082 3,363,276 3,113,126 5,221,355 ------------- ------------- ------------- ------------- Net income $ 1,128,515 $ 2,463,461 $ 4,894,457 $ 3,498,538 ============= ============= ============= ============= Basic net income per share (1) $ 0.08 $ 0.18 $ 0.35 $ 0.25 ============= ============= ============= ============= Diluted net income per share (1) $ 0.08 $ 0.15 $ 0.29 $ 0.20 ============= ============= ============= =============
(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-23 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------- ----------- +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1998 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company (Incorporated herein by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). +3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915), Amendment No. 2 (Incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999) and Amendment No. 3 (Incorporated by reference to Exhibit 3.1 to the Company's current report on Form 8-K dated February 20, 2002.) +3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other rights thereof (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated February 20, 2002). +4.1 -- 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). +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 -- Fifth 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999). +4.6 -- Sixth 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 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999). +4.7 -- Seventh 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999). +4.8 -- Eighth 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 4.8 to the Company's Annual Report of From 10-K for the year ended December 31, 2000). +4.9 -- Ninth 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 99.10 to the Company's Current Report on Form 8-K dated December 15, 1999). +4.10 -- Tenth 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 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000). +4.11 -- Eleventh 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001). +4.12 -- Twelfth 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 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001). +4.13 -- Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage Program, dated May 1,
F-24 2001 (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +4.14 -- Amendment No. 1 to the Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage Program, dated June 1, 2001 (Incorporated herein by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +4.15 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM, Inc. (Incorporated herein by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +10.1 -- Amended and Restated Incentive Plan of the Company effective as of February 17, 2000 (Incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000). +10.2 -- 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)). +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). +10.19 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc. and CCBM, Inc., dated June 29, 2001
F-25 (Incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). +10.20 -- Securities Purchase Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.21 -- Shareholders' Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.22 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (including Warrant Certificate) (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.23 -- Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.24 -- Compliance Sideletter dated February 20, 2002 between the Company and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.25 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to the Company's Current Report on Form 8-K dated February 20, 2002). +10.26 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the Company's Current Report on Form 8-K dated February 20, 2002). 21.1 -- Subsidiaries of the Company. 23.1 -- Consent of Arthur Andersen LLP. 23.2 -- Consent of Ryder Scott Company Petroleum Engineers. 23.3 -- Consent of Fairchild & Wells, Inc. 99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2001. 99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2001. 99.3 -- Letter to the Securities and Exchange Commission regarding Arthur Andersen LLP.
---------- + Incorporated by reference as indicated. F-26