1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 COMMISSION NO. 0-22915 CARRIZO OIL & GAS, INC. (Exact name of registrant as specified in its charter) TEXAS 76-0415919 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 14811 ST. MARY'S LANE, SUITE 148 HOUSTON, TEXAS 77079 (Principal executive offices) (Zip Code) 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 25, 1998, the aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $26.9 million based on the closing price of such stock on such date of $6.75. At March 25, 1998, the number of shares outstanding of registrant's Common Stock was 10,375,000. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrant's 1998 Annual Meeting of Shareholders to be held on May 20, 1998 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, 1997. ================================================================================ 2 TABLE OF CONTENTS PAGE ---- PART I...................................................... 1 Item 1. and Item 2. Business and Properties............... 1 Item 3. Legal Proceedings................................. 23 Item 4. Submission of Matters to a Vote of Security Holders................................................ 23 Executive Officers of the Registrant...................... 23 PART II..................................................... 24 Item 5. Market for Registrant's Common Stock and Related Shareholder Matters.................................... 24 Item 6. Selected Financial Data........................... 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................................... 28 Item 8. Financial Statements and Supplementary Data....... 34 Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure............... 34 PART III.................................................... 35 Item 10. Directors and Executive Officers of the Registrant............................................. 35 Item 11. Executive Compensation........................... 35 Item 12. Security Ownership of Certain Beneficial Owners and Management......................................... 35 Item 13. Certain Relationships and Related Party Transactions........................................... 35 PART IV..................................................... 35 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................................... 35 3 PART I ITEM 1. AND ITEM 2. BUSINESS AND PROPERTIES GENERAL Carrizo Oil & Gas, Inc. ("Carrizo" or the "Company") is an independent oil and gas company engaged in the exploration, development, exploitation and production of natural gas and crude oil. The Company's operations are currently focused onshore in proven oil and gas producing trends along the Gulf Coast, primarily in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends. The Company believes that the availability of economic onshore 3-D seismic surveys has fundamentally changed the risk profile of oil and gas exploration in these regions. Recognizing this change, the Company has aggressively sought to control significant prospective acreage blocks for targeted, proprietary, 3-D seismic surveys. As of December 31, 1997, the Company had assembled approximately 419,953 gross acres under lease or option. The Company typically seeks to acquire seismic permits from landowners that include options to lease the acreage prior to conducting proprietary surveys. In other circumstances, including when the Company participates in 3-D group shoots, the Company typically seeks to obtain leases or farm-ins rather than lease options. Approximately 60% of the Company's current acreage position is covered by 3-D seismic data that the Company has acquired, or is in the process of acquiring, in its first 18 seismic surveys. The Company expects to acquire or cause to be acquired additional 3-D seismic data during the remainder of 1998 that will cover approximately 80% of its remaining current acreage position. From the data generated by its first seven proprietary seismic surveys, covering 200 square miles (128,000 acres), 94 drillsites were identified. The Company's capital budget for 1998 of approximately $43.3 million includes amounts for the acquisition of additional 3-D seismic data and for the drilling of approximately 150 gross wells (71.8 net) in 1998 with an anticipated 48% average working interest. In addition, the Company anticipates that as its existing 3-D seismic data is further evaluated, and 3-D seismic data is acquired over the balance of its acreage, additional prospects will be generated for drilling beyond 1998. The Company's primary drilling targets have been shallow (from 4,000 to 7,000 feet), normally pressured reservoirs that generally involve moderate cost (typically $200,000 to $500,000 per completed well) and risk. Many of these drilling prospects also have secondary, deeper, over-pressured targets which have greater economic potential but generally involve higher cost (typically $1 million to $2 million per completed well) and risk. The Company often seeks to sell a portion of these deeper prospects to reduce its exploration risk and financial exposure while still allowing the Company to retain significant upside potential. The Company operates the majority of its projects through the exploratory phase but may relinquish operator status to qualified partners in the production phase to control costs and focus resources on the higher-value exploratory phase. As of December 31, 1997, the Company operated 69 producing oil and gas wells, which accounted for 43% of the wells in which the Company had an interest. The Company has experienced rapid increases in reserves, production and EBITDA since its inception in 1993 due to the growth of its 3-D based drilling and development activities. From January 1, 1996 to December 31, 1997, the Company participated in the drilling of 90 gross wells (34.6 net) with a commercial well success rate of approximately 69%. This drilling success contributed to the Company's total proved reserves as of December 31, 1997 of approximately 43.2 Bcfe, with a PV-10 Value of $26.1 million. From inception through December 31, 1997, the Company's average finding and development cost was approximately $.95 per Mcfe. The Company's production has increased 79% from 1,916 MMcfe for the year ended December 31, 1996 to 3,424 MMcfe for the year ended December 31, 1997. EBITDA has also increased significantly from $2,296,000 for the year ended December 31, 1996 to $4,787,000 for the year ended December 31, 1997. Certain terms used herein relating to the oil and natural gas industry are defined in "Glossary of Certain Industry Terms" below. 1 4 EXPLORATION APPROACH The Company generally seeks to rapidly accumulate large amounts of 3-D seismic data along prolific, producing trends of the onshore Gulf Coast after obtaining options to lease areas covered by the data. The Company then uses this data to identify or evaluate prospects before drilling the prospects that fit its risk/ reward criteria. The Company typically seeks to explore in locations within its core areas of expertise that it believes have (i) numerous accumulations of normally pressured reserves at shallow depths and in geologic traps that are difficult to define without the interpretation of 3-D seismic data and (ii) the potential for large accumulations of deeper, over-pressured reserves. As a result of the increased availability of economic onshore 3-D seismic surveys and the improvement and increased affordability of data interpretation technologies, the Company has relied almost exclusively on the interpretation of 3-D seismic data in its exploration strategy. The Company generally does not invest any substantial portion of the costs for an exploration well without first interpreting 3-D seismic data. The principal advantage of 3-D seismic data over traditional 2-D seismic analysis is that it affords the geoscientist the ability to interpret a three dimensional cube of data representing a specific project area as compared to interpreting between widely separated two dimensional vertical profiles. As a consequence, the geoscientist is able to more fully and accurately evaluate prospective areas, improving the probability of drilling commercially successful wells in both exploratory and development drilling. The use of 3-D seismic allows the geoscientist to identify and use areas of irregular sand geometry to augment or replace structural interpretation in the identification of potential hydrocarbon accumulations. Additionally, detailed analysis and correlation of the 3-D seismic response to lithology and contained fluids assist geoscientists in identifying and prioritizing drilling targets. Because 3-D analysis is completed over an entire target area cube, shallow, intermediate and deep objectives can be analyzed. Additionally, the more precise structural definition allowed by 3-D seismic data combined with integration of available well and production data assists in the positioning of new development wells. The Company has sought to obtain large volumes of 3-D seismic data either by participating in large seismic data acquisition programs either alone or pursuant to joint venture arrangements with other energy companies, or through "group shoots" in which the Company shares the costs and results of seismic surveys. By participating in joint ventures and group shoots, the Company is able to share the up-front costs of seismic data acquisition and interpretation, thereby enabling it to participate in a larger number of projects and diversify exploration costs and risks. Substantially all of the Company's operations are conducted through joint operations with industry participants. As of December 31, 1997, the Company was actively involved in 40 project areas. The Company intends to further increase the number and size of seismic data acquisition projects in which it participates to accelerate its exploration activities. The Company's primary strategy for acreage acquisition is to obtain leasing options covering large geographic areas in connection with 3-D seismic surveys. Prior to conducting proprietary surveys, the Company typically seeks to acquire seismic permits that include options to lease the acreage, thereby ensuring the price and availability of leases on drilling prospects that may result upon completing a successful seismic data acquisition program over a project area. The Company generally attempts to obtain these options covering at least 80% of the project area for these proprietary surveys. The size of these surveys has ranged from 10 to 70 square miles. When the Company participates in 3-D group shoots, it generally seeks prospective leases as quickly as possible following interpretation of the survey. In connection with some group shoots in which the Company believes that competition for acreage may be especially strong, the Company may seek to obtain lease options or leases in prospective areas prior to the receipt or interpretation of 3-D seismic data. The Company maintains a flexible and diversified approach to project identification by focusing on the estimated financial results of a project area rather than limiting its focus to any one method or source for obtaining leads for new project areas. The Company's current project areas resulted from leads developed by its project generation network that includes small, independent "prospect generators", the Company's joint venture partners and the Company's internal staff. The Company believes that it has been able to increase the number of potential projects and reduce its costs through the use of these outside sources of project generation. Similarly, in identifying specific drillsites from within a project area, the Company has relied upon 2 5 outside contract geoscientists and joint venture partners who have worked with the Company's own geoscientists. As of December 31, 1997, over 20 geoscientists from this network were devoting some or all of their time to identifying project areas or evaluating drillsites in which the Company expects to have an interest. Similarly, the Company also utilizes outside independent landmen with expertise in a particular project area. This outsourcing strategy has enabled the Company to control costs without maintaining a large internal land and exploration department. OPERATING APPROACH The Company's management team has extensive experience in the development and management of projects along the Texas and Louisiana Gulf Coast. The Company believes that the experience of its management in the development of 3-D projects in its core operating areas is a competitive advantage for the Company. The Company's technical and operating employees have an average of 15 years of industry experience, in many cases with major and large independent oil companies, including Shell Oil Company, Vastar Resources, Inc., Pennzoil Company and Tenneco Inc. The Company generally seeks to obtain lease operator status and control over field operations, and in particular seeks to control decisions regarding 3-D survey design parameters and drilling and completion methods. In some cases, the Company may thereafter relinquish its operator status in order to concentrate its resources on exploration activities, especially if the Company has had successful prior experience with an industry partner acting as operator. As of December 31, 1997, the Company operated 69 producing oil and natural gas wells, which ranged in depth from 450 feet to greater than 6,100 feet. The Company emphasizes preplanning in project development to lower capital and operational costs and to efficiently integrate potential well locations into the existing and planned infrastructure, including gathering systems and other surface facilities. In constructing surface facilities, the Company seeks to use reliable, high quality, used equipment in place of new equipment to achieve cost savings. The Company also seeks to minimize cycle time from drilling to hook-up of wells, thereby accelerating cash flow and improving ultimate project economics. The Company seeks to use advanced production techniques to exploit and expand its reserve base. Following the discovery of proved reserves, the Company typically continues to evaluate its producing properties through the use of 3-D seismic data to locate undrained fault blocks and identify new drilling prospects and performs further reserve analysis and geological field studies using computer aided exploration techniques. The Company seeks to integrate its 3-D seismic data with reservoir characterization and management systems through the use of geophysical workstations which are compatible with industry standard reservoir simulation programs. SIGNIFICANT PROJECT AREAS The Company is currently evaluating approximately 40 exploration project areas. As of December 31, 1997, the Company had an existing 3-D seismic database of 930 square miles and was acquiring an additional 240 square miles of data (totaling 1,170 square miles of 3-D seismic data). To date, all project areas for which seismic data has been interpreted have yielded multiple prospects and drillsites. The Company is continuing to receive and interpret data covering these project areas and believes that each project area has the potential for additional prospects and drillsites. 3 6 1998 EXPLORATION PROGRAM SQ. MILES OF 3-D GROSS SEISMIC DATA AT ACREAGE DECEMBER 31, 1997 LEASED OR ----------------------- UNDER BUDGETED 1998 AVERAGE OPTION AT EXISTING FOR BUDGETED AVERAGE NET DEC. 31, OR BEING ACQUISITION GROSS WORKING REVENUE PROJECT AREAS 1997 ACQUIRED 1998 WELLS(1) INTEREST(2) INTEREST(2) ------------- --------- -------- ----------- -------- ----------- ----------- TEXAS Starr/Hidalgo........... 9,186 340(3) -- 6 50.0% 37.5% Encinitas/Kelsey........ 9,300 32 -- 3 27.5% 23.0% Buckeye................. 34,303 62 -- 14 50.0% 39.0% La Rosa................. 8,249 22 -- 6 31.5% 23.6% Mexican Sweetheart...... 30,795 40 -- 4 25.0% 18.8% McFaddin Ranch.......... 5,374 15 -- 4 37.5% 28.1% Cologne................. 18,200 40 -- 23 25.0% 18.8% South Cabeza Creek...... 7,128 -- 78 4 52.5% 39.4% Western 325............. -- 320(3) -- 2 50.0% 37.5% Lance................... 18,536 30 -- 1 25.0% 19.3% Highway 59.............. 4,995 -- 20 4 20.0% 15.0% Geronimo................ 29,358 107 -- 4 15.0% 11.3% RPP Welder.............. 31,182 60 -- 9 15.0% 11.3% Midway.................. 1,235 -- 15 2 100.0% 75.0% Lost Bridge............. 5,065 16 -- 6 50.0% 37.5% Drake 202............... 3,877 20 -- 8 100.0% 80.0% Metro................... 11,349 20 -- 4 25.0% 18.7% North Heyser............ 8,100 13 -- 3 47.0% 34.7% Victoria................ 21,288 -- 60 5 57.0% 42.75% Matagorda............... 16,093 -- 51 6 87.5% 64.75% Driscoll Ranch.......... 23,135 -- 80 7 50.0% 37.0% Other (16 Areas)........ 110,042 33 268 17 66.0% 48.8% LOUISIANA North Chalkley.......... 1,130 -- -- 0 18.0% 13.5% Atchafalaya............. 3,611 -- -- 1 55.4% 41.5% Live Oak................ 350 -- -- 1 15.0% 10.8% Other (5 Areas)......... 8,072 -- 14 6 28.7% 21.7% ------- ----- --- --- Total........... 419,953 1,170 586 150 ======= ===== === === - --------------- (1) Consists of (i) identified drill sites included in the Company's 1998 capital budget that are fully evaluated, leased and have been or are scheduled to be drilled in 1998 and (ii) wells included in the Company's 1998 capital budgets, but as to which 3-D seismic data has either not been obtained or fully evaluated, or for which the Company has not yet acquired leases or option rights. A portion of the number of wells indicated is based upon statistical results of drilling activities in 3-D project areas that the Company believes are geologically similar. (2) Anticipated interests based upon ownership or contractual rights as of December 31, 1997. (3) Represents non-proprietary "group shoots" in which the Company is a participant. Set forth below are descriptions of the Company's key project areas where it is actively exploring for potential oil and natural gas prospects and in some cases currently has production. The 3-D surveys the Company is using to analyze its project areas range from regional, non-proprietary "group shoots" to single field proprietary surveys. The Company has, in many cases, participated in these project areas with industry partners to share the up-front costs associated with obtaining option arrangements with landowners, seismic 4 7 data acquisition and related data interpretation, to mitigate its exploration risk and to increase the number of projects in which it is able to participate. Although the Company is currently pursuing prospects within the project areas described below, and has budgeted to drill the number of wells set forth in the preceding table, there can be no assurance that these prospects will be drilled at all or within the expected time frame. In particular, budgeted wells that are based upon statistical results of drilling activities in other project areas are subject to greater uncertainties than wells for which drillsites have been identified. The final determination with respect to the drilling of any identified drillsites or budgeted wells will be dependent on a number of factors, including (i) the results of exploration efforts and the acquisition, review and analysis of the seismic data, (ii) the availability of sufficient capital resources by the Company and the other participants for the drilling of the prospects, (iii) the approval of the prospects by other participants after additional data has been compiled, (iv) the economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, (v) the financial resources and results of the Company and (vi) the availability of leases on reasonable terms and permitting for the prospect. There can be no assurance that these projects can be successfully developed or that the identified drillsites or budgeted wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. The 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 rigs and the delivery of equipment. Although the Company believes that its use of 3-D seismic data and other advanced technologies should increase the probability of success of its exploratory wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies only assist geoscientists in identifying subsurface structures and do not enable the interpreter to know whether hydrocarbons are in fact present in such structures. In addition, the use of 3-D seismic data and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and the Company could incur losses as a result of such expenditures. The Company's future drilling activities may not be successful, and if unsuccessful, such failure will have a material adverse effect on the Company's results of operations and financial condition. There can be no assurance that the Company's overall drilling success rate or its drilling success rate for activity within a particular project area will not decline. The Company may choose not to acquire option and lease rights prior to acquiring seismic data and, in many cases, the Company may identify a prospect or drilling location before seeking option or lease rights in the prospect or location. Although the Company has identified or budgeted for numerous drilling prospects, there can be no assurance that such prospects will ever be leased or drilled (or drilled within the scheduled or budgeted time frame) or that oil or natural gas will be produced from any such prospects or any other prospects. In addition, prospects may initially be identified through a number of methods, some of which do not include interpretation of 3-D or other seismic data. Wells that are currently included in the Company's capital budget may be based upon statistical results of drilling activities in other 3-D project areas that the Company believes are geologically similar, rather than on analysis of seismic or other data. Actual drilling and results are likely to vary from such statistical results and such variance may be material. Similarly, the Company's drilling schedule may vary from its capital budget because of future uncertainties, including those described above. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." The reserve data set forth below is based upon the reserve report (the "Ryder Scott Report") dated February 26, 1998 prepared by Ryder Scott Company, independent petroleum engineers ("Ryder Scott"), and the reserve report (the "Fairchild Report" and collectively with the Ryder Scott Report, the "Reserve Reports") dated February 25, 1998 prepared by Fairchild, Ancell & Wells, Inc., independent petroleum 5 8 engineers ("Fairchild"). There are numerous uncertainties in estimating quantities of proved reserves, including many factors beyond the control of the Company. See "-- Oil and Natural Gas Reserves." TEXAS Starr/Hidalgo Project Area: Frio and Vicksburg Formations The Starr/Hidalgo Project Area is located in Starr and Hidalgo Counties, Texas in the Frio and Vicksburg formations. The Company and a partner licensed approximately 340 square miles of non-proprietary 3-D seismic data that was delivered during August 1995 and June 1996. More than 70 prospects have been identified in the shallow Frio trend and the deeper, structurally complex Vicksburg trend, as well as two large prospects in the relatively unexplored Eocene trend. As of December 31, 1997, the Company and its partner had leases covering 9,186 acres in this project area and currently control 25 of these prospects (11 Frio, 13 Vicksburg and one Eocene). The Company sold a portion of its interest in six of the deeper and riskier Vicksburg and Eocene prospects to industry partners. During the six months ended June 30, 1997, the Company's share of production from wells in this production area was approximately 36 Bbls/d of oil and 3.4 MMcf/d of natural gas. Primarily as a result of the curtailment of production by the wells in the Wheeler area by the Texas Railroad Commission, during the quarter ended December 31, 1997, the Company's share of production from wells in this project area was approximately 12 Bbls/d of oil and 0.8 MMcf/d natural gas. As of December 31, 1997, the Company and its partners had drilled a total of 23 wells in this project area, resulting in 15 producing wells. The estimated proved reserves net to the Company for this project area was 130 MBbls of oil and 1.6 BCF of natural gas at December 31, 1997. The Company and its partners have identified 6 locations that have been or are budgeted to be drilled during 1998. The Company believes that continuing interpretation and seismic processing of the Starr/Hidalgo Project Area 3-D seismic data will result in additional prospects and drilling locations. Encinitas/Kelsey Project Area: Frio and Vicksburg Formations The Encinitas/Kelsey Project Area is located in Brooks County, Texas in the Frio and Vicksburg formations. The Company acquired an interest in leases covering 9,300 acres in this area in December 1994 to re-develop the property. Upon acquisition of its interests in this project area, the Company undertook a comprehensive petrophysical study and acquired a 32 square mile 3-D seismic survey. This effort has resulted in the identification of numerous Frio and Vicksburg prospects. During the quarter ended December 31, 1997, the Company's share of production from wells in this project area was approximately 33 Bbls/d of oil, 86 Bbls/d of natural gas liquids and 2.5 MMcf/d of natural gas. As of December 31, 1997, the Company and its partners had drilled a total of 12 wells in this project area, resulting in 10 producing wells. The estimated proved reserves net to the Company for this project area was 27.8 MBbls of oil, 192.3 MBbls of natural gas liquids and 3.6 BCF of natural gas at December 31, 1997. The Company and its partners have identified three locations that are budgeted to be drilled in 1998. Buckeye Project Area: Wilcox, Hockley, Pettus and Yegua Formations The Buckeye Project Area is located in Live Oak County, Texas. As of December 31, 1997, the Company and its partner held 13,492 acres under lease and 20,811 acres under option and have acquired an approximately 62 square mile 3-D seismic survey. The exploration objectives for the Buckeye Project Area are the shallow zones of the Hockley, Pettus and Yegua formations and the deep zones of the expanded Upper Wilcox formation. The data for this project area was received from processing in 1997 and initial interpretation has generated 38 shallow prospects. During the quarter ended December 31, 1997, the Company's share of production from wells in this project area was approximately 125 Bbls/d of oil and 1.7 MMcf/d of natural gas. As of December 31, 1997, the Company and its partners have drilled 24 wells in this project area, resulting in 17 producing wells. The estimated proved reserves net to the Company for this project area was 118.3 MBbls of oil and 1.4 BCF of natural gas at December 31, 1997. The remaining prospects are planned to be drilled in 1998. 6 9 La Rosa Project Area: Frio Formation The La Rosa Project Area is located in Refugio County, Texas over a producing field leasehold of 3,689 acres. The area covers Frio barrier/strandplain sands productive down to 8,200 feet. Data is currently being integrated from a 3-D seismic survey over 22 square miles that was conducted by the Company during the first quarter of 1997. As of December 31, 1997, the Company's leases covered 3,689 acres and its seismic options covered 4,560 acres in this project area. During the quarter ended December 31, 1997, the Company's share of production from wells in this project area was approximately 8 Bbls/d of oil and 0.2 MMcf/d natural gas. As of December 31, 1997, the Company and its partners have drilled one well in this project area, resulting in one producing well. The estimated proved reserves net to the Company for this project area was 10.2 MBbls of oil and 0.2 BCF of natural gas at December 31, 1997. Additional drilling opportunities within and peripheral to the producing field exist and are being evaluated for 1998 drilling. Mexican Sweetheart Project Area: Frio Formation The Mexican Sweetheart Project Area is located in southwestern Jackson County, Texas in the Frio producing trend. Secondary objectives for this project area include the shallow Miocene trend, the downdip Yegua and Wilcox trends. The area is directly south of successful 3-D seismic projects conducted by the Company's partners in this project and covers historical field discoveries. The Company has planned and directed a 40 square mile 3-D seismic survey covering the project area. The Company will seek to use the 3-D seismic data to identify shallow objectives, delineate reservoir compartments for drilling of bypassed reserves and identify flank prospects and deeper, higher risk prospects in the Yegua and Upper Wilcox trends, which the Company would seek to explore with an industry partner. As of December 31, 1997, the Company's leases covered 848 acres and its seismic options covered 29,947 acres in this project area. Interpretation of the 3-D has led to four initial prospects budgeted to be drilled in 1998. McFaddin Ranch Project Area: Miocene and Frio Formations The McFaddin Ranch Project Area is located in Victoria County, Texas in the Miocene and Frio formations. Data is currently being interpreted from a 15 square mile 3-D seismic survey conducted in the first quarter of 1997. The Company has identified and budgeted to drill four initial prospects in this project area during 1998. As of December 31, 1997, the Company's leases in this project area covered 5,374 acres. Cologne Project Area: Frio Formation The Cologne Project Area is located in Goliad and Victoria Counties, Texas in the Frio formation. A secondary objective for this project area is Wilcox formations. The area covers several historical field discoveries. A 40 square mile 3-D seismic survey has been shot over the project area, has been interpreted and yielded drillsites to evaluate prospectively from the Frio through the Wilcox formations. As of December 31, 1997, the Company's multiple seismic options covered 18,200 acres in this project area. Drilling on the 23 identified prospects is expected to begin in April, 1998. South Cabeza Creek Project Area: Frio Formation to Lower Wilcox Sands The South Cabeza Creek Project Area is located in Goliad County, Texas in an area having significant production in the shallow Frio and lower Wilcox trends. The Company is currently in the process of acquiring seismic options and leases for participation in a 78 square mile non-exclusive 3-D seismic shoot in the project area that is currently scheduled to seek to begin in the second quarter of 1998. The Company intends to use the 3-D seismic data to identify potential Frio, Vicksburg and Yegua opportunities and to verify and optimize a Wilcox prospect. The Company currently has 525 acres under lease and 6,603 acres under seismic option in this project area. Western 325 Project Area: Wilcox and Jackson-Yegua Formations The Western 325 Project Area is located in Webb and Duval Counties, Texas in the Wilcox and Jackson-Yegua formations. The Company and a partner have joined others in underwriting a non-proprietary 3-D 7 10 seismic data shoot covering approximately 320 square miles in the project area. Multiple prospects have been identified from data covering approximately 160 square miles that was delivered in 1997. The remainder of the data is currently expected to be delivered in 1998. The Company has budgeted to drill two wells in this project area during the second quarter of 1998. The Company believes that experience gained in the Starr/Hidalgo Project Area may assist in exploration efforts in the Western 325 Project Area. Lance Project Area: Frio and Vicksburg Formations The Lance Project Area is located in Bee County, Texas in an area of prolific shallow Frio production. The primary exploration objectives in this project area are the Frio/Vicksburg trends, with secondary objectives in the deeper Vicksburg, Jackson and Yegua formations. The Company is currently interpreting data from a 30 square mile 3-D seismic survey completed in the second half of 1996. As of December 31, 1997, the Company and its partners held 500 acres in leases and 18,036 acres in options. During the quarter ended December 31, 1997, the Company's share of production from wells in this project area was approximately 0.03 MMcf/d of natural gas. As of December 31, 1997, the Company and its partners have drilled six wells in this project area, resulting in three producing wells. The estimated proved reserves net to the Company for this project area was 0.09 BCF of natural gas at December 31, 1997. A deeper Yegua well is planned for May 1998. Highway 59 Project Area: Frio, Yegua and Wilcox Formations The Highway 59 Project Area is located in Fort Bend and Wharton Counties, Texas in an area of several historical field discoveries and production in the Frio and Yegua formations and in the highly competitive Wharton County Wilcox trend. A survey design has been completed for a 20 square mile 3-D seismic survey in the project area, and fieldwork is expected to begin during the third quarter of 1998. The Company and two large independent industry partners will seek to use the 3-D seismic data to identify shallow opportunities and to delineate Yegua and Wilcox prospects identified through the interpretation of 2-D seismic data. As of December 31, 1997, the Company's leases in this project area covered 4,995 acres. Geronimo Project Area: Frio Formation The Geronimo Project Area is located in San Patricio County, Texas in an area of predominantly Frio production. Numerous fault systems run through the area, particularly in the basal Frio and Vicksburg formations. A 67 square mile 3-D seismic survey was conducted in 1996, with the initial interpretation of data generating five prospects. A northeast extension of the initial 3-D seismic survey covering an additional 40 square miles was later acquired. As of December 31, 1997, the Company's leases covered 10,278 acres and its seismic options covered 19,080 acres in this project area. During the quarter ended December 31, 1997, the Company's share of production from wells in this project area was approximately 16 Bbls/d of oil and 0.3 MMcf/d of natural gas. As of December 31, 1997, the Company and its partners had drilled three wells in this project area, resulting in two producing wells. The estimated proved reserves net to the Company for this project area was 10.4 MBbls of oil and 0.4 BCF of natural gas at December 31, 1997. Four additional wells are planned for 1998. RPP Welder Project Area: Frio and Vicksburg Formations The RPP Welder Project Area is located in San Patricio and Refugio Counties, Texas in an area of predominantly upper Frio production and is adjacent to the Geronimo, Midway and LaRosa Project Areas. Numerous fault systems run through the area, particularly at the relatively unexplored basal Frio and Vicksburg levels. The primary producing formations in this area have historically been Miocene and upper Frio oil objectives. Field operations for a 60 square mile 3-D seismic survey commenced during the second quarter of 1997. Data was received from processing in March 1998 and interpretation has been initiated. The Company's leases cover 1,127 acres and its options cover 30,055 acres in this project area. 8 11 Midway Project Area: Frio Formation The Midway Project Area is located in San Patricio County, Texas in an area of predominantly Frio production. The area is a southwest extension of the Geronimo Project Area and includes the Company's producing properties from the Midway Field along with contiguous leases and seismic option areas. The Company has designed a 15 square mile 3-D seismic survey in this project area, and field operations are planned to commence in the third quarter of 1998. As of December 31, 1997, the Company's leases covered 1,235 acres in this project area. Lost Bridge Project Area: Frio, Yegua and Wilcox Formations The Lost Bridge Project Area is located in northern Jackson County, Texas in the Frio, Yegua and Wilcox formations. The area covers several historical field discoveries and recent Wilcox production. The Company began work in the third quarter of 1997 on a 16 square mile 3-D seismic survey. The Company will seek to use the 3-D seismic data to delineate a Yegua prospect identified with 2-D seismic data, identify shallow opportunities and image the deeper Wilcox trend. The Company's strategy is to drill Frio and Yegua prospects and sell a portion of its interest in any Wilcox prospects while retaining a carried interest. The Company is currently interpreting the seismic data over the project area and has 751 acres under lease and 4,314 acres under option to date. Drake 202 Project Area: Frio and Vicksburg Formations The Drake 202 Project Area is located in Bee County, Texas adjacent to the Lance Project Area. Primary exploration objectives for this project area are the Frio and Vicksburg formations, as well as deeper, higher risk prospects in the Yegua formation. In this project area, the Company has seismic options covering 3,877 acres. A 20 square mile 3-D seismic survey is scheduled for April, 1998. Metro Project Area: Frio, Yegua and Wilcox Formations The Metro Project Area is located in Dewitt County, Texas in the active Wilcox producing trend. Target reservoirs include the Frio, Yegua, upper and middle Wilcox ranging in depth from 3,500 feet to 14,500 feet. A 20 square mile 3-D seismic program has been completed and numerous drilling opportunities have been identified. The first well was drilled to a depth of 14,500 feet in the first quarter of 1998 and is currently being completed in the Wilcox formation. The Company has 2,064 acres under lease and 9,285 gross acres under option. North Heyser: Miocene And Frio Formations The North Heyser Project Area is located in Victoria County, Texas. The 3-D seismic shoot area covers significant historical production and targets primarily Basal Frio structural traps and extensions to existing area production. A 13 square mile 3-D seismic program was completed in the fourth quarter of 1997 and is currently being interpreted. As of December 31, 1997 the Company had 8,100 acres under seismic option in this project area. Victoria Project Area: Miocene and Frio Formation The Victoria Project Area is located in Victoria County, Texas and is targeting the Miocene to Basal Frio formations. The area includes several historical field discoveries. A 3-D seismic shoot of approximately 60 square miles has been initiated with expected completion in May of 1998. Interpretation of processed data and identification of potential drillsites is scheduled for the fourth quarter of 1998. As of December 31, 1997, the Company had 5,492 acres under lease and 15,796 under seismic option in this project area. Matagorda Project Area: Frio Formations The Matgorda Project Area is located in Matagorda County, Texas covering numerous Middle Frio structural opportunities in addition to the Lower Frio shelf edge expanded section. The Company has 9 12 committed to a non exclusive 3-D seismic shoot covering 51 square miles that is expected to be initiated in the first quarter of 1998. Interpretation of the 3-D data and initial drilling is expected to begin in the late third quarter of 1998. The Company has acquired 16,093 acres of seismic options in the project area. Driscoll Ranch Project Area: Frio through Yegua Formations The Driscoll Ranch Project Area is located in Jim Wells and Duval Counties, Texas. Industry activity in this area is high with substantial activity to the north and east. Existing 2-D seismic data has generated several leads in the project area and is being used to optimize the 3-D parameters. Target reservoirs include the Frio Formation to the Hockley/Pettus/Yegua intervals between 5,000 feet and 8,000 feet. The anticipated area of a planned seismic shoot is approximately 80 square miles, with acquisition beginning mid 1998. The Company had 23,135 acres under seismic option as of December 31, 1997 in this project area. South Texas Syndicate The South Texas Syndicate Project Area is located in LaSalle and McMullen Counties, Texas. Seismic options covering over 88,000 acres are being negotiated and are expected to be finalized by the first quarter of 1998. Industry activity in the area has been initiated with 3-D seismic projects both east and west along trend. Target reservoirs include the Cook Mountain, Queen City, Wilcox, Edwards and Sligo, ranging in depth from 1,100 feet to 14,500 feet. An initial phase of 3-D coverage covering approximately 40 square miles is planned for 1998. LOUISIANA North Chalkley Project Area: Miogyp Sand The North Chalkley Project Area is located in Calcasieu and Cameron Parishes, Louisiana in an area of production from the Miogyp sand trend. The Company's leases in this project area cover 1,130 acres and control both upthrown and expanded Miogyp closures against the regional Camerina/Miogyp expansion fault. An upthrown 2-D supported opportunity was sold to two large independent oil and natural gas companies for cash and carried working interest in 1997. The well logged gas pay but was not adequately tested due to mechanical problems. The Company now has a 45% working interest in the subject leases and is planning to acquire 3-D seismic data for delineation of drilling future prospects. Atchafalaya Project Area: Cib Op-C Sand The Atchafalaya Project Area is located in Atchafalaya Bay in Louisiana. In 1991, a well was drilled in this fault block resulting in a field discovery at approximately 17,500 feet. The Company and its partners control 3,611 acres in this project area under a farm-in agreement and two state leases. The Company's partners have access to 20 square of 3-D seismic data covering this project area. As of March 31, 1997, the Company's net estimated proved reserves in this project area were 308 MBbls of oil and 5.8 Bcf of natural gas, all of which are undeveloped. The Company subsequently sold down to an approximately 10% carried interest in the first well that has been spudded in March 1998. Live Oak Project Area: Chris II Sand The Live Oak Project Area is located in Vermillion Parish, Louisiana. In 1996, the Company and its partners acquired access to a 20 square mile 3-D seismic survey. The Company promoted its interest in the project area to two independents and will be carried to casing point for a 12% interest in the first well, which should be completed in April 1998. The Company's leases in this project area cover an aggregate of approximately 350 acres. The well is drilling as of March 1998. OTHER PROJECT AREAS In addition to the project areas described above, the Company had over 23 additional project areas in various stages of development as of December 31, 1997. These project areas are located in the onshore Texas 10 13 and Louisiana Gulf Coast region, as well as one project area in the Cotton Valley Lime Reef trend. The Company is in the process of evaluating and acquiring interests with respect to most of these project areas and as of December 31, 1997 had acquired leases and seismic options covering 118,114 acres. 3-D seismic surveys covering an aggregate of approximately 282 square miles in these areas are budgeted for acquisition during 1998. SIGNIFICANT DEVELOPMENT PROJECT -- CAMP HILL The Company owns interests in eight leases totaling approximately 900 acres in the Camp Hill field in Anderson County, Texas. The Company currently operates six of these leases. During the year ended December 31, 1997, the project produced 110 Bbls/d 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, 1997 averaged $15.54 per barrel ($2.59 per Mcfe). Because profitability increases when natural gas prices drop relative to oil prices, the project is a natural hedge against decreases in natural gas prices relative to oil prices. The crude oil produced, although viscous, commands a higher price (an average premium of $.71 per barrel during the year ended December 31, 1997) than West Texas intermediate crude due to its suitability as a lube oil feedstock. As of December 31, 1997, the Company had 4,697 MBbls of oil of proved reserves in this project, with 902 MBbls of oil currently developed. The Company anticipates that it will drill additional wells and increase steam injection to develop the proved undeveloped reserves in this project, with the timing and amount of expenditures depending on the relative prices of oil and natural gas. The Company has an average working interest of 92.5% in its leases in this field and an average net revenue interest of 74.0%. OIL AND NATURAL GAS RESERVES The following table sets forth estimated net proved oil and natural gas reserves of the Company and the PV-10 Value of such reserves as of December 31, 1997. The reserve data and the present value as of December 31, 1997 were prepared by Ryder Scott Company and Fairchild, Ancell & Wells, Inc., Independent Petroleum Engineers. For further information concerning Ryder Scott's and Fairchild's estimate of the proved reserves of the Company at December 31, 1997, 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 10 of Notes to Financial Statements. PROVED RESERVES ----------------------------------- DEVELOPED UNDEVELOPED TOTAL --------- ----------- ------- (DOLLARS IN THOUSANDS) Oil and condensate (MBbls).......................... 1,146 4,023.5 5,169.5 Natural gas (MMcf).................................. 9,299 2,843 12,142 Total proved reserves (MMcfe)....................... 16,173 26,986 43,159 PV-10 Value(1)...................................... $18,515 $ 7,556 $26,071 - --------------- (1) The PV-10 Value as of December 31, 1997 is pre-tax and was determined by using the December 31, 1997 sales prices, which averaged $16.37 per Bbl of oil, $2.56 per Mcf of natural gas and $10.90 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 Commission. In accordance with Commission regulations, the reserve reports used oil and natural gas prices in effect at December 31, 1997. The prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and natural gas production subsequent to December 31, 1997. There can be no assurance that all of the proved reserves will be produced and sold within the periods 11 14 indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. The reserve data set forth in this Annual Report on Form 10-K represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at different times may vary substantially and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material. In addition, the 10% discount factor, which is required by the Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general. In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent the Company conducts successful exploration and development activities or acquires properties containing proved reserves, or both, the proved reserves of the Company will decline as reserves are produced. The Company's future oil and natural gas production is, therefore, highly dependent upon its level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital investment to maintain or expand its asset base of oil and natural gas reserves would be impaired. The failure of an operator of the Company's wells to adequately perform operations, or such operator's breach of the applicable agreements, could adversely impact the Company. In addition, there can be no assurance that the Company's future exploration, development and acquisition activities will result in additional proved reserves or that the Company will be able to drill productive wells at acceptable costs. Furthermore, although the Company's revenues could increase if prevailing prices for oil and natural gas increase significantly, the Company's finding and development costs could also increase. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." 12 15 VOLUMES, PRICES AND OIL & GAS OPERATING EXPENSE The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with the Company's sales of oil and natural gas for the periods indicated. YEAR ENDED DECEMBER 31, -------------------------- 1995 1996 1997 ------ ------ ------ PRODUCTION VOLUMES Oil (MBbls)................................................. 78 107 113 Natural gas (MMcf).......................................... 565 1,273 2,749 Natural gas equivalent (MMcfe).............................. 1,033 1,915 3,424 AVERAGE SALES PRICES Oil (per Bbl)............................................... $19.64 $21.54 $18.66 Natural gas (per Mcf)....................................... 1.60 2.27 2.41 Natural gas equivalent (per Mcfe)........................... 2.36 2.71 2.54 AVERAGE COSTS (PER MCFE) Camp Hill operating expenses................................ $ 2.06 $ 3.15 $ 2.59 Other operating expenses.................................... 1.63 0.94 0.54 Total operating expenses(1)................................. 1.76 1.24 0.68 - --------------- (1) Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs and the administrative costs of production offices, insurance and property and severance taxes. FINDING AND DEVELOPMENT COSTS From inception through December 31, 1997, the Company has incurred total gross development, exploration and acquisition costs of approximately $47.4 million. Total exploration, development and acquisition activities from inception through December 31, 1997 have resulted in the addition of approximately 49.7 Bcfe, net to the Company's interest, of proved reserves at an average finding and development cost of $.95 per Mcfe. The Company's finding and development costs have historically fluctuated on a year-to-year basis. Finding and development costs, as measured annually, may not be indicative of the Company's ability to economically replace oil and natural gas reserves because the recognition of costs may not necessarily coincide with the addition of proved reserves. DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities. YEAR ENDED DECEMBER 31 --------------------------- 1995 1996 1997 ------ ------ ------- (IN THOUSANDS) Acquisition costs Unproved prospects........................................ $ 317 $ 51 $ -- Proved properties......................................... 3,588 1,908 14,820 Exploration................................................. 2,364 4,724 14,223 Development................................................. 209 1,956 2,257 ------ ------ ------- Total costs incurred(1)................................ $6,478 $8,639 $31,300 ====== ====== ======= - --------------- (1) Excludes capitalized interest on unproved properties of $117,288, $422,493 and $699,625 for the years ended December 31, 1995, 1996 and 1997, respectively. 13 16 DRILLING ACTIVITY The following table sets forth the drilling activity of the Company for the years ended December 31, 1995, 1996 and 1997. In the table, "gross" refers to the total wells in which the Company has a working interest and "net" refers to gross wells multiplied by the Company's working interest therein. As shown below, the Company's drilling activity from January 1, 1995 to December 31, 1997 has resulted in a commercial success rate of approximately 69%. YEAR ENDED DECEMBER 31, --------------------------------------------- 1995 1996 1997 ------------ ------------ ------------- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- ---- Exploratory Wells Productive.................................... -- -- 16 6.0 39 15.7 Nonproductive................................. -- -- 4 1.1 23 9.4 ----- --- ----- ---- Total................................. -- -- 20 7.1 62 25.1 ===== === ===== ==== Development Wells Productive.................................... -- -- -- -- 7 1.8 Nonproductive................................. -- -- -- -- 1 0.6 ----- ---- Total................................. -- -- -- -- 8 2.4 ===== ==== 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, 1997. COMPANY OPERATED OTHER ---------------- ------------- TOTAL GROSS NET GROSS NET GROSS NET -------- ---- ----- ---- ----- ---- Oil........................................ 56 54.4 24 8.7 80 63.1 Natural gas................................ 13 8.2 68 23.7 81 31.9 --- ---- ---- ---- ---- ---- Total.................................... 69 62.6 92 32.4 161 95.0 === ==== ==== ==== ==== ==== ACREAGE DATA The following table sets forth certain information regarding the Company's developed and undeveloped lease acreage as of December 31, 1997. Developed acres refers to acreage within producing units and undeveloped acres refers to acreage that has not been placed in producing units. Leases covering substantially all of the undeveloped acreage in the following table will expire within the next three years. In general, the Company's leases will continue past their primary terms if oil or natural gas in commercial quantities is being produced from a well on such leases. DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL ------------------- --------------------- ---------------- GROSS NET GROSS NET GROSS NET --------- ------ ----------- ------ ------- ------ Louisiana...................... -- -- 7,310 2,770 7,310 2,770 Texas.......................... 28,245 11,609 83,130 26,582 111,375 38,191 ------ ------ ------ ------ ------- ------ Total................ 28,245 11,609 90,440 29,352 118,685 40,961 ====== ====== ====== ====== ======= ====== The table does not include 301,268 gross acres (127,915 net) that the Company had a right to acquire pursuant to various seismic option agreements at December 31, 1997. Under the terms of its option agreements, the Company typically has the right for a period of one year, subject to extensions, to exercise its option to lease the acreage at predetermined terms. The Company's lease agreements generally terminate if wells have not been drilled on the acreage within a period of three years. 14 17 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. At December 31, 1997, natural gas sold under such swap arrangements was 364,000 MMBtu at an average price of $2.86 per MMBtu relating to first quarter of 1998 production. Total natural gas purchased and sold under such swap arrangements during the years ended December 31, 1995, 1996 and 1997 were 40,000 MMBtu, 60,000 MMBtu and 210,000 MMBtu, respectively. Gains (losses) realized by the Company under such swap arrangements were ($23,466), ($26,887) and $48,000 for the years ended December 31, 1995, 1996 and 1997, respectively. The Company did not engage in hedging prior to 1995. 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 15 18 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, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which the Company may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Company is also subject to changing and extensive tax laws, the effects of which cannot be predicted. The following discussion summarizes the regulation of the United States oil and gas industry. The Company believes that it is in substantial compliance with the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject, although there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect the Company's results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject. Regulation of Oil and Natural Gas Exploration and Production. The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These 16 19 include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and gas industry increases the Company's costs of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (the "FERC"). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of not later than January 1, 1993, all remaining federal price controls from natural gas sold in "first sales." The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. Although sales by producers, such as the Company, of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future. The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the result of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The FERC has announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and a request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology to establish the rates interstate pipelines may charge for their services. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. In February 1997, the FERC announced a broad inquiry into issues facing the natural gas industry to assist the FERC in establishing regulatory goals and priorities in the post-Order No. 636 environment. Similarly, the Texas Railroad Commission has been reviewing changes to its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers and recently implemented a code of conduct intended to prevent undue discrimination by intrastate pipelines and gatherers in favor of their marketing affiliates. Although the changes being considered by these federal and state regulators would affect the Company only indirectly, they are intended to further enhance competition in natural gas markets. The Company owns certain natural gas pipelines that it believes meet the standards the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both state and federal levels in the post-Order No. 636 environment. 17 20 The Company cannot predict what further action the FERC or state regulators will take on these matters; however, the Company does not believe that it will be affected by any action taken materially differently than other natural gas producers with which it competes. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. The price the Company receives from the sale of these products may be affected by the cost of transporting the products to market. Effective January 1995, the FERC implemented regulations establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling limits. The indexing system generally indexes such rates to inflation, subject to certain conditions and limitations. The Company is not able at this time to predict the effects of these regulations, if any, on the transportation costs associated with oil production from the Company's oil producing operations. Environmental Regulations. The Company's operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, the business and prospects of the Company could be adversely affected. The Company generates wastes that may be subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil and natural gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company believes that it has used good operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing the management of oil and gas wastes. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the 18 21 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. The Company plans to drill a well in Louisiana coastal waters. Assuming that production from the planned well is feasible, the Company will be obligated to comply with these regulations. Pursuant to other requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. While certain of its properties may require permits for discharges of storm water runoff, the Company believes that it will be able to obtain, or be included under, such permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on the Company. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground. CERCLA, also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Company also is subject to a variety of federal, state and local permitting and registration requirements relating to protection of the environment. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on the Company. OPERATING HAZARDS AND INSURANCE The oil and natural gas business involves a variety of operating hazards and risks such as well blowouts, craterings, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks. These hazards and risks could result in substantial losses to the Company 19 22 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 non-operated basis, which may limit the Company's ability to control the risks associated with oil and natural gas operations. TITLE TO PROPERTIES; ACQUISITION RISKS The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and natural gas industry. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, including a title opinion of local counsel, are generally made before commencement of drilling operations. The Company's revolving credit facility is secured by substantially all of its oil and natural gas properties. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact and their accuracy inherently uncertain. In connection with such an assessment, the Company performs a review of the subject properties that it believes to be generally consistent with industry practices, which generally includes on-site inspections and the review of reports filed with various regulatory entities. Such a review, however, will not reveal all existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. There can be no assurances that any acquisition of property interests by the Company will be successful and, if unsuccessful, that such failure will not have an adverse effect on the Company's future results of operations and financial condition. EMPLOYEES At December 31, 1997, the Company had 22 full-time employees, including four geoscientists and three engineers. As drilling and production activities increase, the Company intends to hire additional technical, operational and administrative personnel as appropriate. The Company believes that its relationships with its employees are good. In order to optimize prospect generation and development, the Company utilizes the services of independent consultants and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Field and on-site production operation services, such as pumping, 20 23 maintenance, dispatching, inspection and testing, are generally provided by independent contractors. The Company believes that this use of third party service providers has enhanced its ability to contain general and administrative expenses. The Company depends to a large extent on the services of certain key management personnel, the loss of any of which could have a material adverse effect on the Company's operations. The Company does not maintain key-man life insurance with respect to any of its employees. GLOSSARY OF CERTAIN INDUSTRY TERMS The definitions set forth below shall apply to the indicated terms as used herein. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple. After payout. With respect to an oil or gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bbls/d. Stock tank barrels per day. Bcf. Billion cubic feet. Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Before payout. With respect to an oil or gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered. Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. Completion. The installation of permanent equipment for the production of oil or gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. Farm-in or farm-out. An agreement whereunder the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out." 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. 21 24 Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. MBbls. One thousand barrels of crude oil or other liquid hydrocarbons. MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per day. Mcf. One thousand cubic feet. Mcf/d. One thousand cubic feet per day. Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. MMBbls. One million barrels of crude oil or other liquid hydrocarbons. MMBtu. One million British Thermal Units. Mmcf. One million Cubic feet. MMcf/d. One million cubic feet per day. MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis. Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells. Normally pressured reservoirs. Reservoirs with a formation-fluid pressure equivalent to 0.465 psi per foot of depth from the surface. For example, if the formation pressure is 4,650 psi at 10,000 feet, then the pressure is considered to be normal. Over-pressured reservoirs. Reservoirs subject to abnormally high pressure as a result of certain types of subsurface formations. Petrophysical study. Study of rock and fluid properties based on well log and core analysis. Present value. When used with respect to oil and natural gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to nonproperty-related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells. Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market. 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. 22 25 Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. PV-10 Value. The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. Royalty interest. An interest in an oil and natural gas property entitling the owner to a share of oil or gas production free of costs of production. 3-D seismic data. Three-dimensional pictures of the subsurface created by collecting and measuring the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface. Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. Workover. Operations on a producing well to restore or increase production. ITEM 3. LEGAL PROCEEDINGS From time to time the Company is a party to various legal proceedings arising in the ordinary course of business. The Company is not currently a party to any litigation that it believes could have a material adverse effect on the financial position of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. EXECUTIVE OFFICERS OF THE REGISTRANT Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this Form 10-K. The following table sets forth certain information with respect to executive officers of the Company: NAME AGE POSITION ---- --- -------- S.P. Johnson IV....................... 41 President and Chief Executive Officer Frank A. Wojtek....................... 42 Chief Financial Officer, Vice President, Secretary and Treasurer George F. Canjar...................... 39 Vice President of Exploration Development Kendall A. Trahan..................... 47 Vice President of Land 23 26 Set forth below is a description of the backgrounds of each of the executive officers of the Company: S.P. Johnson IV has served as the President, Chief Executive Officer and a director of the Company since December 1993. Prior to that, he worked 15 years for Shell Oil Company. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado. Frank A. Wojtek has served as the Chief Financial Officer, Vice President, Secretary, Treasurer and a director of the Company since 1993. In addition, from 1992 to 1997, Mr. Wojtek was the Assistant to the Chairman of the Board of Reading & Bates Corporation ("Reading & Bates", an offshore drilling company). Mr. Wojtek also holds the positions of Vice President and Secretary/Treasurer for Loyd and Associates, Inc. (a private financial consulting and investment banking firm). Mr. Wojtek held the positions of Vice President and Chief Financial Officer of Griffin-Alexander Drilling Company from 1984 to 1987, Treasurer of Chiles-Alexander International Inc. from 1987 to 1989 and Vice President and Chief Financial Officer of India Offshore Inc. from 1989 to 1992, all of which are companies in the offshore drilling industry. Mr. Wojtek is a Certified Public Accountant and holds a B.B.A. in Accounting from the University of Texas. George F. Canjar has been head of the Company's exploration activities since joining the Company in July 1996 and was elected Vice President of Exploration Development in June 1997. Prior thereto he worked for over 15 years for Shell Oil Company and its overseas affiliates where he held various technical and managerial positions, including Technical Manager-Geology & Petrophysics, Section Head Geology & Seismology and Team Leader for numerous integrated production, development, exploration and project execution groups. Mr. Canjar is a Registered Petroleum Engineer, Registered Geologist and has a B.S. in Geological Engineering from the Colorado School of Mines. Kendall A. Trahan has been head of the Company's land activities since joining the Company in March 1997 and was elected Vice President of Land of the Company in June 1997. From 1994 to February 1997, he served as a Director of Joint Ventures Onshore Gulf Coast for Vastar Resources, Inc. From 1982 to 1994, he worked as an Area Landman and then a Division Landman and Director of Business Development for Arco Oil & Gas Company. Prior to that, Mr. Trahan served as a Staff Landman for Amerada Hess Corporation and as an independent landman. He is a Certified Professional Landman and holds a B.S. degree from the University of Southwestern Louisiana. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS (a) 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 of fiscal 1997: QUARTER ENDED HIGH LOW ------------- ---- ----- September 30, 1997.......................................... 15 10 15/16 December 31, 1997........................................... 17 1/4 7 7/8 There were approximately 48 shareholders of record (excluding brokerage firms and other nominees) of the Company's Common Stock as of March 25, 1998. 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% Series A Preferred Stock, par value $.01 per share (the "Preferred Stock"), restrict the Company's ability 24 27 to pay dividends. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." (b) Use of Proceeds. The Company's Registration Statement on Form S-1 (Registration No. 333-29187), as amended, with respect to the initial public offering of shares of Company's Common Stock was declared effective by the Securities and Exchange Commission on August 5, 1997. In the Offering, the Company sold 2,500,000 shares of Common Stock on August 11, 1997 and 375,000 shares of Common Stock on September 8, 1997 pursuant to the exercise of the underwriters' over-allotment option. The net proceeds to the Company from the Offering were $28.1 million. As of December 31, 1997, the Company has used such net proceeds as follows: (i) to repay $16.5 million of indebtedness outstanding under the Company's revolving credit facilities, (ii) to repay $3.2 million of promissory notes outstanding to certain of the Company's directors and officers and (iii) to provide $8.4 million for capital expenditures. Except as set forth in clause (ii), none of such payments were direct or indirect payments to directors or officers of the Company or their associates, to persons owning ten percent or more of any class of equity securities of the Company or to affiliates of the Company. RECENT SALES OF UNREGISTERED SECURITIES On January 8, 1998, the Company consummated the transactions contemplated by the Stock Purchase Agreement dated January 8, 1998 (the "Purchase Agreement") among the Company, Enron Capital & Trade Resources Corp., a Delaware corporation ("Enron"), and Joint Energy Development Investments II, a Delaware limited partnership ("JEDI II"). Such transactions included (i) the payment by Enron and JEDI II of an aggregate purchase price of $30,000,000, (ii) the sale of 75,000 shares of Preferred Stock, the terms of which are set forth in the Statement of Resolution Establishing Series of Shares designated 9% Series A Preferred Stock, to Enron and 225,000 shares of Preferred Stock to JEDI II, (iii) the grant of warrants (the "Warrants") to purchase 250,000 and 750,000 shares of Common Stock to Enron and JEDI II, respectively, and (iv) the execution and delivery of the Shareholders' Agreement dated January 8, 1998 among the Company, S.P. Johnson IV, Frank A. Wojtek, Steven A. Webster, Paul B. Loyd, Jr., Douglas A.P. Hamilton, DAPHAM Partnership L.P., the Douglas A.P. Hamilton 1997 GRAT, Enron and JEDI II. The Warrants are exercisable during the period beginning January 8, 1999 and ending January 8, 2005 for the purchase of an aggregate of 1,000,000 shares of Common Stock (the "Warrant Shares") at an exercise price of $11.50 per share, subject to certain adjustments. Each Warrant may be exercised by (i) paying the exercise price (A) in cash or (B) by surrender to the Company of shares of Preferred Stock or (ii) exercising the Warrant for a number of net Warrant Shares equal to (x) the number of Warrant Shares issuable upon exercise of the Warrant multiplied by the difference between the average market price of the Common Stock during the 20 trading day period preceding the date of exercise and the exercise price divided by (y) the average market price of the Common Stock during the 20 trading day period preceding the date of exercise. In addition, with the consent of the Company, the holder of the Warrant may receive a cash payment equal to the number of Warrant Shares for which the Warrant is exercised multiplied by the difference between the average market price of the Common Stock during the 20 trading day period preceding the date of exercise and the exercise price. The number of Warrant Shares and exercise price are subject to adjustment in certain circumstances, including (i) if the Company makes a distribution of shares of Common Stock, subdivides or combines its outstanding shares of Common Stock or issues any shares of its capital stock or distributes other assets in a reclassification or reorganization of the Common Stock, (ii) if the Company issues shares of Common Stock or securities exercisable or exchangeable for or convertible into shares of Common Stock for no consideration or for less than the market value of the Common Stock, subject to certain exceptions, and (iii) if the Company engages in a consolidation, merger or business combination with, or sells all or substantially all of its assets to, another corporation. 25 28 The sale of the shares of Preferred Stock and the Warrants pursuant to the 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 any public offering. ITEM 6. SELECTED FINANCIAL DATA The financial information of the Company set forth below for the period from inception of operations (September 24, 1993) through December 31, 1993, and for each of the four years ended December 31, 1997, 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. PERIOD ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, ------------------------------------------ 1993 1994 1995 1996 1997 -------------- ------ ------- ------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA: Oil and natural gas revenues........ $ 5 $ 596 $ 2,428 $ 5,195 $ 8,712 Costs and expenses: Oil and natural gas operating expenses....................... 20 518 1,814 2,384 2,334 Depreciation, depletion and amortization................... 1 98 488 1,136 2,358 General and administrative........ 24 238 425 515 1,591 ----- ------ ------- ------- ---------- Total costs and expenses................ 45 854 2,727 4,035 6,283 ----- ------ ------- ------- ---------- Operating income (loss)............. (40) (258) (299) 1,160 2,429 Interest expense (net of amounts capitalized)...................... -- (7) (192) (80) (98) Other income........................ -- 6 24 20 -- ----- ------ ------- ------- ---------- Income (loss) before income taxes... (40) (259) (467) 1,100 2,331 ----- ------ ------- ------- ---------- Deferred income taxes(1)............ -- -- -- -- 2,300 ----- ------ ------- ------- ---------- Net income (loss)(1)................ $ (40) $ (259) $ (467) $ 1,100 $ 31 ===== ====== ======= ======= ========== Basic (loss) earnings per share(1).......................... $0.00 $(0.04) $ (0.07) $ 0.15 $ 0.00 ===== ====== ======= ======= ========== Diluted (loss) earnings per share(1).......................... $0.00 $(0.04) $ (0.07) $ 0.15 $ 0.00 ===== ====== ======= ======= ========== Basic weighted average shares outstanding....................... 5,210 6,501 7,021 7,476 8,639 Diluted weighted average shares outstanding....................... 5,210 6,501 7,021 7,545 8,810 STATEMENTS OF CASH FLOW DATA: Net cash provided by (used in) operating activities.............. $ 12 $ (258) $ 406 $ 3,325 $ 3,068 Net cash used in investing activities........................ (118) (819) (6,785) (8,221) (28,141) Net cash provided by financing activities........................ 106 1,183 6,343 6,319 26,255 OTHER OPERATING DATA: EBITDA(2)(4)........................ $ (41) $ (158) $ 189 $ 2,296 $ 4,787 Operating cash flow(3)(4)........... (41) (159) 21 2,236 4,689 Capital expenditures................ 113 819 6,857 9,480 32,234 Debt repayments(5).................. -- -- -- 2,084 20,409 26 29 AS OF DECEMBER 31, ---------------------------------------------- 1993 1994 1995 1996 1997 ---- ------ ------ ------- ------- BALANCE SHEET DATA: Working capital............................... $(52) $ 152 $ (265) $(1,025) $(2,276) Property and equipment, net................... 113 803 6,960 15,206 45,083 Total assets.................................. 130 1,057 7,645 18,869 53,658 Long-term debt, including current maturities.................................. -- 533 3,480 9,684 7,950 Equity........................................ 65 452 3,381 4,596 32,895 - --------------- (1) From inception of operation to May 16, 1997, Carrizo and the other entities combined in a series of transactions pursuant to which a number of affiliated entities were combined with the Company in connection with its initial public offering (the "Combination Transactions") were not required to pay federal income taxes due to their status as partnerships or S corporations. The amounts shown reflect pro forma income taxes that represent federal income taxes which would have been reported under Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes," had Carrizo and such entities been tax-paying entities during each of the periods presented. See Notes 2 and 4 to the Company's financial statements. (2) EBITDA represents earnings before interest expense, income taxes, depreciation, depletion and amortization. (3) Operating cash flow represents cash flows from operating activities prior to changes in assets and liabilities. (4) 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. (5) Debt repayments include amounts refinanced. Forward Looking Statements. The statements contained in all parts of this document, (including any portion attached hereto) including, but not limited to, those relating to the Company's schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, expected working or revenue interests, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), use of proceeds from the Company's initial public offering and the sale of shares of Preferred Stock and the warrants, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement its business strategy, budgeted expenditures, future hiring, future exploration activity and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words "anticipate," "budgeted" "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 27 30 net revenue estimates, property acquisition risks and other factors detailed herein and in the Company's other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 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 20 wells in 1996 and 70 wells in 1997. The Company expects such increases to continue and has budgeted to drill a total of 150 gross wells (71.8 net) in 1998. As a result, depreciation, depletion and amortization, oil and gas operating expenses and production are expected to increase. The Company has typically retained the majority of its interests in shallow, normally pressured prospects and sold a portion of its interests in deeper, over-pressured prospects. The financial statements set forth herein are prepared on the basis of a combination of Carrizo and the entities that were a party to the Combination Transactions. Carrizo and the entities combined with it in the Combination Transactions were not required to pay federal income taxes due to their status as partnerships or Subchapter S corporations, which are not subject to federal income taxation. Instead, taxes for such periods were paid by the shareholders and partners of such entities. On May 16, 1997, Carrizo terminated its status as an S corporation and thereafter became subject to federal income taxes. In accordance with SFAS No. 109, "Accounting for Income Taxes," the Company was required to establish a deferred tax liability in the second quarter of 1997 which resulted 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. However, as operations have expanded, the Company has increasingly funded its activities through bank borrowings and cash flow from operations in order to retain a greater portion of the interests it develops. Prior to the Offering, Carrizo conducted its oil and natural gas operations directly, with industry partners and through the following affiliated entities: Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd. and Placedo Partners Ltd. Concurrently with the closing of the Offering, Combination Transactions were closed. The Combination Transactions consisted of the following: (i) Carrizo Production, Inc. merged into Carrizo; (ii) Carrizo acquired Encinitas Partners Ltd. in two steps: (a) Carrizo acquired the limited partner interests in Encinitas Partners Ltd. held by certain of the Company's directors and (b) Encinitas Partners Ltd. merged into Carrizo; (iii) La Rosa Partners Ltd. merged into Carrizo; and (iv) Carrizo Partners Ltd. merged into Carrizo. As a result of the merger of Carrizo and Carrizo Partners Ltd., Carrizo became the owner of all of the partnership interest in Placedo Partners Ltd. The Company uses the full-cost method of accounting for its oil and gas properties. Under this method, all acquisition, exploration and development costs, including any general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full-cost pool" as incurred. The Company records depletion of its full-cost pool using the unit-of-production method. To the extent that such capitalized costs in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and gas reserves, such excess costs are charged to operations. The Company has not been required to make any such write-downs. Once incurred, a write-down of oil and gas properties is not reversible at a later date. The ceiling test for many full cost companies, including Carrizo, could be negatively impacted by prolonged unfavorable oil and gas prices. The deterioration of prices from year-end levels could result in the Company recording a first quarter 1998 non-cash charge to earnings related to its oil and gas properties. 28 31 RESULTS OF OPERATIONS Year Ended December 31, 1997 Compared to the Year Ended December 31, 1996 Oil and natural gas revenues for 1997 increased 68% to $8.7 million from $5.2 million in 1996. Production volumes for natural gas in 1997 increased 116% to 2,749.2 MMcf from 1,272.5 MMcf in 1996. Average natural gas prices increased 6% to $2.41 per Mcf in 1997 from $2.27 per Mcf in 1996. Production volumes for oil in 1997 increased 5% to 112.5 MBbls from 107.3 MBbls in 1996. Average oil prices decreased 13% to $18.66 per barrel in 1997 from $21.54 per barrel in 1996. The increase in oil and natural gas production was due primarily to new wells being successfully drilled and completed during 1997, along with recompletions of existing wells. 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, 1996 and 1997: 1997 PERIOD COMPARED TO 1996 PERIOD DECEMBER 31, ----------------------- ----------------------- INCREASE % INCREASE 1996 1997 (DECREASE) (DECREASE) ---- ---- ---------- ---------- Production volumes Oil and condensate (MBbls)......... 107.3 112.5 5.2 5% Natural gas (MMcf)................. 1,272.5 2,749.2 1,476.7 116% Average sales prices(1) Oil and condensate (per Bbl)....... $ 21.54 $ 18.66 $ (2.88) (13)% Natural gas (per Mcf).............. 2.27 2.41 0.14 6% Operating revenues Oil and condensate................. $2,310,798 $2,099,699 $ (211,099) (9)% Natural gas........................ 2,883,911 6,611,955 3,728,044 129% ---------- ---------- ---------- Total...................... $5,194,709 $8,711,654 $3,516,945 68% ========== ========== ========== - --------------- (1) Including impact of hedging. Oil and natural gas operating expenses for 1997 decreased 2% to $2.3 million from $2.4 million in 1996. Oil and natural gas operating expenses decreased primarily as a result of cost reductions in older wells and the addition of lower cost production in new oil and gas wells drilled and completed since December 31, 1995. Operating expenses per equivalent unit in 1997 decreased to $.68 per Mcfe from $1.24 per Mcfe in 1996. The per unit cost decreased as a result of increased production of natural gas, which had lower per unit operating costs. DD&A expense for 1997 increased 118% to $2.4 million from $1.1 million in 1996. This increase was primarily due to the increased production, additional seismic and drilling costs and depreciation on 3-D computer equipment and related software. General and administrative expense for 1997 increased 209% to $1.6 million from $515,000 for 1996 reflecting ramp-up expenses relating to the hiring of additional technical and administrative staff to handle the Company's increased level of drilling and operations, and expenses related to the initial public offering. Interest expense for 1997 increased 90% to $151,000 from $80,000 in 1996. This increase was primarily due to the increase in capital expenditures and related debt levels in anticipation of the initial public offering. As a result of the adoption of SFAS 109 in the second quarter of 1997, the Company recorded a one-time non-cash charge to income of $1.6 million to establish a deferred tax liability. Net income for 1997 decreased to $31,000 from $1.1 million in 1996 as a result of the factors described above. 29 32 Year Ended December 31, 1996 Compared to the Year Ended December 31, 1995 Oil and natural gas revenues for 1996 increased 114% to $5.2 million from $2.4 million in 1995. Production volumes for natural gas in 1996 increased 125% to 1,272.5 MMcf from 565.3 MMcf in 1995. Average natural gas prices increased 42% to $2.27 per Mcf in 1996 from $1.60 per Mcf in 1995. Production volumes for oil in 1996 increased 38% to 107.3 MBbls from 77.6 MBbls in 1995. Average oil prices increased 10% to $21.54 per barrel in 1996 from $19.64 per barrel in 1995. The increase in oil and natural gas production was due primarily to new wells being successfully drilled and completed during 1996, along with recompletions of existing wells. Also contributing to the increase in oil and gas revenues from 1995 to 1996 was the acquisition of the La Rosa properties. The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the years ended December 31, 1995 and 1996: 1996 PERIOD COMPARED DECEMBER 31, TO 1995 PERIOD ----------------------- ----------------------- 1995 1996 INCREASE % INCREASE ---- ---- ---------- ---------- Production volumes Oil and condensate (MBbls)......... 77.6 107.3 29.7 38% Natural gas (MMcf)................. 565.3 1,272.5 707.2 125% Average sales prices(1) Oil and condensate (per Bbl)....... $ 19.64 $ 21.54 $ 1.90 10% Natural gas (per Mcf).............. 1.60 2.27 0.67 42% Operating revenues Oil and condensate................. $1,524,002 $2,310,798 $ 786,796 52% Natural gas........................ 904,046 2,883,911 1,979,865 219% ---------- ---------- ---------- Total...................... $2,428,048 $5,194,709 $2,766,661 114% ========== ========== ========== - --------------- (1) Including impact of hedging. Oil and natural gas operating expenses for 1996 increased 31% to $2.4 million from $1.8 million in 1995. Oil and natural gas operating expenses increased due to increased production generated from new oil and gas wells drilled and completed since December 31, 1995, as well as the acquisitions of the La Rosa and Encinitas properties. Operating expenses per equivalent unit in 1996 decreased to $1.24 per Mcfe from $1.76 per Mcfe in 1995. The per unit cost decreased as a result of increased production of natural gas which had lower per unit operating costs. DD&A expense for 1996 increased 133% to $1.1 million from $488,000 in 1995. This increase was due to the increase in oil and gas production as well as a 25% increase in the depletion rate (to $0.59 per Mcfe in 1996 from $0.47 per Mcfe in 1995). The increased depletion rate was primarily caused by increased exploration expenditures attributable to 3-D seismic surveys performed for new wells drilled and completed since December 31, 1995. General and administrative expense for 1996 increased 21% to $515,000 from $425,000 for 1995 due primarily to an increase in salary expense as a result of the addition of new employees. Interest expense for 1996 decreased 59% to $80,000 from $192,000 in 1995. This decrease was primarily due to the increase in interest capitalized consistent with increases in capital expenditures. Net income for 1996 increased to $1.1 million from a loss of $467,000 in 1995 as a result of the factors described above. 30 33 LIQUIDITY AND CAPITAL RESOURCES The Company's primary sources of liquidity have included proceeds from the Offering and from the sale of shares of Preferred Stock and the Warrants as discussed below, funds generated by operations, equity capital contributions and borrowings, primarily under revolving credit facilities. Cash flows provided by operations (after changes in working capital) were $406,000, $3.3 million and $3.1 million for 1995, 1996 and 1997, respectively. The increase in cash flows provided by operations in 1996 as compared to 1995 was due primarily to increased revenues from production. The decrease in cash flows provided by operations in 1997 as compared to 1996 was due primarily to increase accounts receivable relating to joint interest billings and prepayments on upcoming outside operated drilling projects. The Company has budgeted capital expenditures in 1998 of approximately $43.3 million. Of this amount, $18.6 million is expected to be used to fund 3-D seismic surveys and land acquisitions and $24.7 million of which is expected to be used for drilling activities in the Company's project areas. The Company budgeted to drill approximately 150 gross wells (71.8 net) in 1998. Actual amounts of capital expenditures and number of wells drilled may differ significantly from such estimates. 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 $6.6 million, $9.1 million and $32.0 million for 1995, 1996 and 1997, respectively. The Company's drilling efforts resulted in the successful completion of 18 gross wells (6.9 net) in 1996 and 46 gross wells (17.5 net) during 1997. The Company has experienced and expects to continue to experience substantial working capital requirements primarily due to the Company's active exploration and development programs and, to a much lesser extent, its technology enhancement programs. While the Company believes that the net proceeds from the Offering, net proceeds from the sale of shares of Preferred Stock and the Warrants, cash flow from operations and borrowings under the Company's credit facility should allow the Company to implement its present business strategy during 1998, additional financing may be required in the future to fund the Company's growth, development and exploration program and continued technological enhancement. In the event such capital resources are not available to the Company, its exploration and other activities may be curtailed. FINANCING ARRANGEMENTS In connection with the Offering, the Company entered into an amended revolving credit agreement with Compass Bank (the "Company Credit Facility"), which provides for a maximum loan amount of $25 million, subject to borrowing base limitations. Prior to the Offering, the Company utilized various credit facilities as well as borrowings from certain directors and officers of the Company. Except for the Company Credit Facility, all of these facilities and borrowings were terminated with the close of the Offering. Under the Company Credit Facility, the principal outstanding is due and payable upon maturity in June 1999 with interest due monthly. The interest rate for 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. Under the Company Credit Facility, Compass, in its sole discretion, will make semiannual borrowing base determinations based upon the proved oil and natural gas properties of the Company. Compass may redetermine the borrowing base and the monthly borrowing base reduction at any time and from time to time. The Company may also request borrowing base redeterminations in addition to its required semiannual reviews at the Company's cost. As of December 31, 1997, the borrowing base was $5,450,000 and borrowings outstanding were $4,950,000. Amounts outstanding under this facility were repaid in the first quarter of 1998. 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 and (b) maintenance of a ratio of quarterly cash flow (net income plus depreciation and other noncash charges, less noncash income) to quarterly debt service (payments made for principal in connection with the credit facility plus payments made for principal 31 34 other than in connection with such credit facility) of no less than 1.25 to 1.00. The Company Credit Facility also places restrictions on, among other things, (a) incurring additional indebtedness, loans and liens, (b) changing the nature of business or business structure, (c) selling assets and (d) paying dividends. In December 1997, the Company and Compass entered into an amendment to the Company Credit Facility that provides for a term loan of $3 million. Interest for borrowings under the term loan was calculated at a floating rate based on the Company's index rate plus 2 percent. The amount outstanding under the term loan as of December 31, 1997 was $3 million. Amounts outstanding under the term loan were repaid in January 1998. In January 1998, the Company consummated the sale of 300,000 shares of Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to affiliates of Enron Corp. The net proceeds received by the Company from this transaction were approximately $28.8 million. A portion of the proceeds were used to repay indebtedness, as described above. The remaining balance is expected to be used primarily for oil and natural gas exploration and development activities in Texas and Louisiana. The Preferred Stock provides for annual cumulative dividends of $9.00 per share, payable quarterly in cash or, at the option of the Company until January 15, 2002, in additional shares of Preferred Stock. The Preferred Stock is required to be redeemed by the Company (i) on January 8, 2005, or (ii) after a request for redemption from the holders of at least 30,000 shares of the Preferred Stock (or, if fewer than such number of shares of Preferred Stock are outstanding, all of the outstanding shares of Preferred Stock) and the occurrence of the following events: (a) the Company has failed at any point in time to declare and pay any two dividends in the amount then due and payable on or before the date the second of such dividends is due and such dividends remain unpaid at such time, (b) the Company breaches certain other covenants concerning the payment of dividends or other distributions on or redemption or acquisition of shares of its capital stock ranking at parity with or junior to the Preferred Stock, (c) for two consecutive fiscal quarterly periods the quarterly Cash Flow (as defined below) of the Company is less than the amount of the dividends accrued in respect to the Preferred Stock, (d) the Company fails to pay certain amounts due on indebtedness for borrowed money or there has otherwise been an acceleration of such indebtedness for borrowed money, (e) there is a violation of the Shareholders' Agreement that is not waived or (f) the Company sells, leases, exchanges or otherwise disposes of all or substantially all of its property and assets which transaction does not provide for the redemption of the Series A Preferred Stock. "Cash Flow" means net income prior to preferred dividends and accretion (i) plus (to the extent included in net income prior to preferred dividends and accretion) depreciation, depletion and amortization and other non-cash charges and losses on the sale of property (ii) minus non-cash income items and required principal payments on indebtedness for borrowed money with a maturity from the original date of incurrence of such indebtedness of six months or greater (excluding voluntary prepayments and refinancings, but including prepayments (other than in connection with refinancings) which would otherwise be due under such indebtedness within a 60-day period following the date of such prepayment). The Preferred Stock also may be redeemed at the option of the Company at any time in whole or in part. All redemptions are at a price per share, together with dividends accumulated and unpaid to the date of redemption, decreasing over time from an initial rate of $104.50 per share to $100.00 per share. A description of the Preferred Stock and the transactions relating to the Purchase Agreement may be found in the Company's Current Report on Form 8-K dated January 8, 1998. EFFECTS OF INFLATION AND CHANGES IN PRICE. The Company's results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that the Company is required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on the Company. 32 35 ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY The Company's rapid growth has placed, and is expected to continue to place, a significant strain on the Company's financial, technical, operational and administrative resources. The Company has relied in the past and expects to continue to rely on project partners and independent contractors that have provided the Company with seismic survey planning and management, project and prospect generation, land acquisition, drilling and other services. At December 31, 1997, the Company had 22 full-time employees. As the Company increases the number of projects it is evaluating or in which it is participating, there will be additional demands on the Company's financial, technical, operational and administrative resources and continued reliance by the Company on project partners and independent contractors, and these strains on resources, additional demands and continued reliance may negatively affect the Company. The Company's ability to continue its growth will depend upon a number of factors, including its ability to obtain leases or options on properties for 3-D seismic surveys, its ability to acquire additional 3-D seismic data, its ability to identify and acquire new exploratory sites, its ability to develop existing sites, its ability to continue to retain and attract skilled personnel, its ability to maintain or enter into new relationships with project partners and independent contractors, the results of its drilling program, hydrocarbon prices, access to capital and other factors. Although the Company intends to 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." There can be no assurance that the Company will be successful in achieving growth or any other aspect of its business strategy. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In October 1995, the Financial Accounting Standards Board issued SFAS No. 123, which is a new standard of accounting for stock-based compensation that establishes a fair value method of accounting for awards granted after December 31, 1995, under stock compensation plans. SFAS No. 123 encourages, but does not require, companies to adopt the fair value method of accounting in place of the existing method of accounting for stock-based compensation, whereupon compensation costs are recognized only in situations where stock compensation plans award intrinsic value to recipients at the date of grant. The Company has elected not to adopt the fair value accounting of SFAS No. 123 and will account for any plans under Accounting Principles Board (APB) Opinion No. 25, under which no compensation costs have been recognized. VOLATILITY OF OIL AND NATURAL GAS PRICES The Company's revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of its properties, are substantially dependent upon prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, 33 36 the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices may materially adversely affect the Company's financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that the Company can produce economically. See "Business and Properties -- Marketing." The Company periodically reviews the carrying value of its oil and natural gas properties under the full cost accounting rules of the Commission. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of this "ceiling" test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. The Company may be required to write down the carrying value of its oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. If a write-down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. In order to reduce its exposure to short-term fluctuations in the price of oil and natural gas, the Company periodically enters into hedging arrangements. The Company's hedging arrangements apply to only a portion of its production and provide only partial price protection against declines in oil and natural gas prices. Such hedging arrangements may expose the Company to risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In addition, the Company's hedging arrangements limit the benefit to the Company of increases in the price of oil and natural gas. Total natural gas purchased and sold under swap arrangements during the years ended December 31, 1995, 1996 and 1997 was 40,000 MMBtu, 60,000 MMBtu and 210,000 MMBtu, respectively. Income and (losses) realized by the Company under such swap arrangements were ($23,466), ($26,887) and $48,000 for the years ended December 31, 1995, 1996 and 1997, respectively. The Company did not engage in hedging prior to 1995. See "Business and Properties -- Marketing." YEAR 2000 The Company is assessing the impact of the Year 2000 issue on its operations, including the development and implementation of project plans and cost estimates required to make its information systems infrastructure Year 2000 complaint. Based on existing information, the Company believes that anticipated spending necessary to become Year 2000 compliant will not have a material effect on the financial position, cash flows or results of operations of the Company, nor will the Year 2000 issues cause any material adverse effect on the future business operations of the Company. There can be no assurance, however, as to the ultimate effect of the Year 2000 issue on the Company. ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK The requirements of Item 7A under regulations of the Securities and Exchange Commission are at this time not required or are not applicable and therefore have been omitted. 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. 34 37 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated by reference to information under the caption "Proposal 1 -- Election of Directors" and to the information under the caption "Section 16(a) Reporting Delinquencies" in the Company's definitive Proxy Statement (the "1998 Proxy Statement") for its annual meeting of shareholders to be held on May 20, 1998. The 1998 Proxy Statement will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to December 31, 1997. 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 1998 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1997. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to the 1998 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1997. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The information required by this item is incorporated herein by reference to the 1998 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1997. 35 38 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (A)(1) FINANCIAL STATEMENTS THE RESPONSE TO THIS ITEM IS SUBMITTED IN A SEPARATE SECTION OF THIS REPORT. (A)(2) FINANCIAL STATEMENT SCHEDULES All schedules and other statements for which provision is made in the applicable regulations of the Commission have been omitted because they are not required under the relevant instructions or are inapplicable. (A)(3) EXHIBITS +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). 3.1 -- Amended and Restated Articles of Incorporation of the Company. 3.2 -- Statement of Resolution Establishing Series of Shares designated 9% Series A Preferred Stock. +3.3 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915). +4.1 -- First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated August 28, 1997 (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997). 4.2 -- First Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 23, 1997. 4.3 -- Second Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 30, 1997. -- The Company is a party to several debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the Company agrees to furnish a copy of such instruments to the Commission upon request. +10.1 -- Incentive Plan of the Company (Incorporated herein by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.2 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.3 -- Employment Agreement between the Company and Frank A. Wojtek (Incorporated herein by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.4 -- Employment Agreement between the Company and Kendall A. Trahan (Incorporated herein by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). 36 39 +10.5 -- Employment Agreement between the Company and George Canjar (Incorporated herein by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). 10.6 -- Indemnification Agreement between the Company and each of its directors and executive officers. +10.7 -- Registration Rights Agreement by and among the Company, Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997 (Incorporated herein by reference to Exhibit 10.7 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 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)). +10.9 -- 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)). +10.10 -- Stock Purchase Agreement dated January 8, 1998 among the Company, Enron Capital & Trade Resources Corp. and Joint Energy Development Investments II Limited Partnership. (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated January 8, 1998). +10.11 -- Warrant Certificates (Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated January 8, 1998.) +10.12 -- Shareholders' Agreement dated January 8, 1998 among the Company, S.P. Johnson IV, Frank A. Wojtek, Steven A. Webster, Paul B. Loyd, Jr., Douglas A.P. Hamilton, DAPHAM Partnership, L.P., The Douglas A.P. Hamilton 1997 GRAT, Enron Capital & Trade Resources Corp. and Joint Energy Development Investments II Limited Partnership. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated January 8, 1998). +10.13 -- 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). 23.1 -- Consent of Arthur Andersen LLP. 23.2 -- Consent of Ryder Scott Company Petroleum Engineers. 23.3 -- Consent of Fairchild, Ancell & Wells, Inc. 27.1 -- Financial Data Schedule. 99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 1997. 99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells, Inc. as of December 31, 1997. - --------------- + Incorporated by reference as indicated. (B) REPORTS ON FORM 8-K No reports on Form 8-K were filed during the last quarter of the period covered by this Annual Report on Form 10-K. 37 40 CARRIZO OIL & GAS, INC. INDEX TO FINANCIAL STATEMENTS PAGE ---- Carrizo Oil & Gas, Inc. -- Report of Independent Public Accountants.................. F-2 Balance Sheets, December 31, 1996 and 1997................ F-3 Statements of Operations for the Years Ended December 31, 1995, 1996 and 1997.................................... F-4 Statements of Stockholders' Equity for the Years Ended December 31, 1995, 1996 and 1997....................... F-5 Statements of Cash Flows for the Years Ended December 31, 1995, 1996 and 1997.................................... F-6 Notes to Financial Statements............................. F-7 F-1 41 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Carrizo Oil & Gas, Inc.: We have audited the accompanying balance sheets of Carrizo Oil & Gas, Inc. (a Texas corporation) as of December 31, 1996 and 1997, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1996 and 1997, and the results of its operations and cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Houston, Texas March 6, 1998 F-2 42 CARRIZO OIL & GAS, INC BALANCE SHEETS AS OF DECEMBER 31, -------------------------- 1996 1997 ----------- ----------- ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 1,492,603 $ 2,674,837 Accounts receivable, trade................................ 1,654,032 1,794,175 Accounts receivable, joint interest owners................ 82,296 1,841,329 Accounts receivable from related parties.................. 79,578 -- Advances to operators..................................... -- 1,817,990 Other current assets...................................... 15,472 108,633 ----------- ----------- Total current assets.............................. 3,323,981 8,236,964 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and gas properties)............................... 15,205,587 45,082,833 OTHER ASSETS................................................ 339,789 338,638 ----------- ----------- $18,869,357 $53,658,435 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade................................... $ 4,326,299 $10,433,479 Other current liabilities................................. 22,976 79,328 ----------- ----------- Total current liabilities......................... 4,349,275 10,512,807 NOTES PAYABLE TO RELATED PARTIES............................ 2,773,935 -- LONG-TERM DEBT.............................................. 6,910,000 7,950,000 DEFERRED INCOME TAXES....................................... -- 2,300,267 OTHER LONG-TERM LIABILITIES................................. 240,197 -- COMMITMENTS AND CONTINGENCIES (Note 6) STOCKHOLDERS' EQUITY: Preferred stock, $0.01 par value (10,000,000 shares authorized with none issued and outstanding)........... -- -- Common stock, $0.01 par value (40,000,000 shares authorized with 7,500,000 and 10,375,000 issued and outstanding at December 31, 1996 and 1997, respectively).......................................... 75,000 103,750 Additional paid-in capital................................ 4,186,000 32,845,727 Retained earnings......................................... 334,950 365,690 Deferred compensation..................................... -- (419,806) ----------- ----------- 4,595,950 32,895,361 ----------- ----------- $18,869,357 $53,658,435 =========== =========== The accompanying notes are an integral part of these financial statements. F-3 43 CARRIZO OIL & GAS, INC. STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, ------------------------------------- 1995 1996 1997 ---------- ---------- ---------- OIL AND NATURAL GAS REVENUES............................ $2,428,048 $5,194,709 $8,711,654 COSTS AND EXPENSES: Oil and natural gas operating expenses (exclusive of depreciation shown separately below)............... 1,813,406 2,384,145 2,334,009 Depreciation, depletion and Amortization.............. 487,949 1,135,797 2,358,256 General and administrative............................ 425,198 514,644 1,590,358 ---------- ---------- ---------- Total costs and Expenses...................... 2,726,553 4,034,586 6,282,623 ---------- ---------- ---------- OPERATING INCOME (LOSS)................................. (298,505) 1,160,123 2,429,031 OTHER INCOME AND EXPENSES: Interest income....................................... -- -- 53,417 Interest expense...................................... (274,585) (312,409) (713,999) Interest expense, related parties..................... (35,059) (189,881) (137,067) Capitalized interest.................................. 117,288 422,493 699,625 Other income.......................................... 24,251 19,525 -- ---------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES....................... (466,610) 1,099,851 2,331,007 INCOME TAXES............................................ -- -- 2,300,267 ---------- ---------- ---------- NET INCOME (LOSS)....................................... $ (466,610) $1,099,851 $ 30,740 ========== ========== ========== BASIC EARNINGS (LOSS) PER SHARE (Note 2)................ $ (0.07) $ 0.15 $ 0.00 ========== ========== ========== DILUTED EARNINGS (LOSS) PER SHARE (Note 2).............. $ (0.07) $ 0.15 $ 0.00 ========== ========== ========== BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (Note 2).................................. 7,020,951 7,475,650 8,638,699 ========== ========== ========== DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (Note 2).................................. 7,020,951 7,545,063 8,809,572 ========== ========== ========== The accompanying notes are an integral part of these financial statements. F-4 44 CARRIZO OIL & GAS, INC. STATEMENTS OF STOCKHOLDERS' EQUITY (NOTES 1 AND 2) COMMON STOCK ADDITIONAL RETAINED TOTAL --------------------- PAID-IN EARNINGS DEFERRED STOCKHOLDERS' SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION EQUITY ---------- -------- ----------- ---------- ------------ -------------- BALANCE, January 1, 1995......... 6,590,601 $ 65,906 $ 684,094 $ (298,291) $ -- $ 451,709 Net loss....................... -- -- -- (466,610) -- (466,610) Distributions.................. -- -- (104,000) -- -- (104,000) Common stock issued to unitholders.................. 860,699 8,607 3,491,393 -- -- 3,500,000 ---------- -------- ----------- ---------- --------- ----------- BALANCE, December 31, 1995....... 7,451,300 74,513 4,071,487 (764,901) -- 3,381,099 Net income..................... -- -- -- 1,099,851 -- 1,099,851 Distributions.................. -- -- (335,000) -- -- (335,000) Common stock issued to unitholders.................. 48,700 487 449,513 -- -- 450,000 ---------- -------- ----------- ---------- --------- ----------- BALANCE, December 31, 1996....... 7,500,000 75,000 4,186,000 334,950 -- 4,595,950 Net income..................... -- -- -- 30,740 -- 30,740 Distributions.................. -- -- (90,000) -- -- (90,000) Public offering................ 2,875,000 28,750 28,050,049 -- -- 28,078,799 Deferred compensation related to certain stock options..... -- -- 699,678 -- (699,678) -- Amortization of deferred compensation................. -- -- -- -- 279,872 279,872 ---------- -------- ----------- ---------- --------- ----------- BALANCE, December 31, 1997....... 10,375,000 $103,750 $32,845,727 $ 365,690 $(419,806) $32,895,361 ========== ======== =========== ========== ========= =========== The accompanying notes are an integral part of these financial statements. F-5 45 CARRIZO OIL & GAS, INC. STATEMENTS OF CASH FLOWS YEAR ENDED DECEMBER 31, ----------------------------------------- 1995 1996 1997 ----------- ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)................................. $ (466,610) $ 1,099,851 $ 30,740 Adjustment to reconcile net income (loss) to net cash provided by (used in) operating activities -- Depreciation, depletion and amortization....... 487,949 1,135,797 2,358,256 Deferred income taxes.......................... -- -- 2,300,267 Changes in assets and liabilities -- Accounts receivable............................ (245,365) (1,457,950) (1,819,598) Other current assets........................... (9,433) 322 (93,161) Accounts payable, trade........................ 518,166 2,422,257 475,268 Interest payable to related parties and other current liabilities.......................... 120,946 125,164 (183,845) ----------- ----------- ----------- Net cash provided by operating activities.............................. 405,653 3,325,441 3,067,927 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures -- accrual basis............. (6,857,057) (9,479,561) (32,234,351) Adjustment to cash basis.......................... 71,664 1,258,132 5,911,784 Advances to operators............................. -- -- (1,817,990) ----------- ----------- ----------- Net cash used in investing activities..... (6,785,393) (8,221,429) (28,140,557) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from sale of stock................... -- -- 28,078,799 Proceeds from debt issuance....................... 2,083,684 6,910,000 18,544,454 Debt repayments................................... -- (2,083,684) (20,408,934) Proceeds from related party notes payable......... 863,696 1,377,739 130,545 Capital contributions............................. 3,500,000 450,000 -- Capital distributions............................. (104,000) (335,000) (90,000) ----------- ----------- ----------- Net cash provided by financing activities.............................. 6,343,380 6,319,055 26,254,864 ----------- ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....................................... (36,360) 1,423,067 1,182,234 CASH AND CASH EQUIVALENTS, beginning of year.............................................. 105,896 69,536 1,492,603 ----------- ----------- ----------- CASH AND CASH EQUIVALENTS, end of year.............. $ 69,536 $ 1,492,603 $ 2,674,837 =========== =========== =========== SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized)................................... $ 122,471 $ -- $ 151,441 The accompanying notes are an integral part of these financial statements. F-6 46 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS, COMBINATION AND OFFERING: NATURE OF OPERATIONS Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its affiliates and predecessors, the Company) is an independent energy company engaged in the exploration, development, exploitation and production of oil and natural gas. It's operations are focused on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and Vicksburg trends. The Company has acquired or is in the process of acquiring 1,170 square miles of 3-D seismic data. Additionally, the Company has assembled approximately 419,953 gross acres under lease or option. THE COMBINATION Carrizo was formed in 1993 and is the surviving entity after a series of combination transactions (the Combination). The Combination included the following transactions: (a) Carrizo Production, Inc. (a Texas corporation and an affiliated entity with ownership identical to Carrizo) was merged into Carrizo and the outstanding shares of capital stock of Carrizo Production, Inc. were exchanged for an aggregate of 343,000 shares of common stock of Carrizo (the Common Stock); (b) Carrizo acquired Encinitas Partners Ltd. (a Texas limited partnership of which Carrizo Production, Inc. served as the general partner) as follows: Carrizo acquired from the shareholders who serve as directors of Carrizo (the Founders) their limited partner interests in Encinitas Partners Ltd. for an aggregate consideration of 468,533 shares of Common Stock and, on the same date, Encinitas Partners Ltd. was merged into Carrizo and the outstanding limited partner interests in Encinitas Partners Ltd. were exchanged for an aggregate of 860,699 shares of Common Stock; (c) La Rosa Partners Ltd. (a Texas limited partnership of which Carrizo served as the general partner) was merged into Carrizo and the outstanding limited partner interests in La Rosa Partners Ltd. were exchanged for an aggregate of 48,700 shares of Common Stock; and (d) Carrizo Partners Ltd. (a Texas limited partnership of which Carrizo served as the general partner) was merged into Carrizo and the outstanding limited partner interests in Carrizo Partners Ltd. were exchanged for an aggregate of 569,068 shares of Common Stock. The Combination was accounted for as a reorganization of entities as prescribed by Securities and Exchange Commission (SEC) Staff Accounting Bulletin 47 because of the high degree of common ownership among, and the common control of, the combining entities. Accordingly, the accompanying financial statements have been prepared using the historical costs and results of operations of the affiliated entities. There were no significant differences in accounting methods or their application among the combining entities. All intercompany balances have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period's financial statement presentation. INITIAL PUBLIC OFFERING Simultaneous with the Combination, the Company completed its initial public offering (the Offering) of 2,875,000 shares of its common stock at a public offering price of $11.00 per share. The Offering provided the Company with proceeds of approximately $28.1 million, net of expenses. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: OIL AND NATURAL GAS PROPERTIES Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment. No general and administrative costs were capitalized in 1995 or 1996. During the year ended December 31, 1997, the Company capitalized as oil and natural gas properties $279,872 of deferred compensation related to stock options granted to personnel directly associated with exploration activities (See Note 7). F-7 47 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) Oil and natural gas properties are amortized based on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. Unevaluated properties are evaluated quarterly for impairment on a property-by-property basis. If the results of an 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 1995, 1996, 1997, was $0.47, $0.59, and $0.69, respectively. Dispositions of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The net capitalized costs of proved oil and gas properties are subject to a "ceiling test," which limits such costs to the estimated present value, discounted at a 10 percent interest rate, of future net cash flows from proved reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. No write-down of the Company's oil and natural gas assets was necessary in 1995, 1996 or 1997. Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years. FINANCING COSTS Offering costs of $11,992 through December 31, 1997 have been deferred and are anticipated to be applied against Preferred Stock offering proceeds (see Note 9). Long-term debt financing costs of $47,194 and $226,247 as of December 31, 1996 and 1997, respectively, are capitalized as deferred assets and are being amortized over the term of the loans. STATEMENTS OF CASH FLOWS For statement of cash flow purposes, all highly liquid investments with original maturities of three months or less are considered to be cash equivalents. FINANCIAL INSTRUMENTS The Company's financial instruments consist of cash, receivables, payables and long-term debt. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying amount of long-term debt approximates fair value as the individual borrowings bear interest at floating market interest rates. HEDGING ACTIVITIES The Company periodically enters into hedging arrangements to manage price risks related to oil and natural gas sales and not for speculative purposes. The Company's hedging arrangements apply only to a portion of its anticipated production, provide only partial price protection against declines in oil and natural gas prices and limit potential gains from future increases in prices. For financial reporting purposes, gains and losses related to hedging are recognized as income when the hedged transaction occurs. Historically, gains and losses from hedging activities have not been material. Total oil and natural gas quantities hedged in 1995, 1996 and 1997 were 9,000 Bbls, 3,000 Bbls and 0 Bbls, respectively, and 40,000 MMBtu, 60,000 MMBtu, and 210,000 MMBtu, respectively. At December 31, 1997, the Company had 364,000 MMBtu of outstanding hedged positions (at an average price of $2.86 per MMBtu for first quarter 1998 production.) These instruments had a fair value market of $250,000 as of December 31, 1997. F-8 48 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) INCOME TAXES Through May 15, 1997, Carrizo and its affiliated entities either had elected to be treated as S Corporations under the Internal Revenue Code or were otherwise not taxed as entities for federal income tax purposes. The taxable income or loss was therefore allocated to the equity owners of Carrizo and the affiliated entities. Accordingly, no provision was made for income taxes in the accompanying historical financial statements for the years ended December 31, 1995 and 1996. On May 16, 1997, Carrizo terminated its status as an S corporation and thereafter became subject to federal income taxes. The Company, beginning with the termination of its tax exempt status, provides income taxes for the difference in the tax and financial reporting bases of its assets and liabilities in accordance with Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." The termination of its tax exempt status in 1997 required the Company to establish a deferred tax liability, which resulted in a one-time noncash charge to income in 1997 of $1,623,000. The Company has entered into tax indemnification agreements with the founders of the Company pertaining to periods in which the Company was an S Corporation. Had Carrizo been a taxpaying entity prior to May 17, 1997, its net income and earnings per share would have been as follows: PRO FORMA ------------------------ 1996 1997 ---------- ---------- (UNAUDITED) Net income (after unaudited pro forma income taxes of $395,946 and $816,852 in 1996 and 1997, respectively...... $ 703,905 $1,514,155 ========== ========== Basic and diluted earnings per share........................ $ 0.09 $ 0.17 ========== ========== Weighted average diluted number of common shares outstanding............................................... 7,545,063 8,809,572 ========== ========== USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Significant estimates include depreciation, depletion and amortization of proved oil and natural gas properties. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, are inherently imprecise and are expected to change as future information becomes available. CONCENTRATION OF CREDIT RISK Substantially all of the Company's accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced credit losses on such receivables. EARNINGS PER SHARE In February 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 128 "Earnings Per Share." The Company adopted this standard effective December 15, 1997. As a result of the simple nature of the Company's capital structure, this adoption had no impact on the calculation of earnings per share. F-9 49 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) Basic earnings per share represents the amount of earnings available to each share of common stock outstanding during the period. Diluted earnings per share represents the amount of earnings for the period available to each share of common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all potentially dilutive common shares outstanding during the period. For Carrizo, the difference between basic and diluted earnings per share for all periods is stock options. For certain periods in 1997, the Company had outstanding 250,000 stock options which were antidilutive or have not been included in the calculation as the exercise price exceeded the market value. Historical earnings per share for the years 1995 and 1996 reflect the effects of the Company's stock split and the issuance of shares in the Combination, applied retroactively to the date that the corresponding partnership units were issued. 3. PROPERTY AND EQUIPMENT: At December 31, 1996 and 1997, property and equipment consisted of the following: DECEMBER 31, -------------------------- 1996 1997 ----------- ----------- Proved oil and natural gas properties..................... $ 9,217,027 $26,994,076 Unproved oil and natural gas properties................... 7,455,698 21,678,368 Other equipment........................................... 62,073 225,069 ----------- ----------- Total property and equipment.................... 16,734,798 48,897,513 Accumulated depreciation, depletion and amortization...... (1,529,211) (3,814,680) ----------- ----------- Property and equipment, net............................... $15,205,587 $45,082,833 =========== =========== Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds, undesignated seismic costs, exploratory wells in progress, and secondary recovery projects before the assignment of proved reserves. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and natural gas leases not held by production, production response to secondary recovery activities and available funds for exploration and development. Of the $21,678,368 of unproved property costs at December 31, 1997 being excluded from the amortizable base, $1,421,642, $2,269,807 and $17,986,919 were incurred in 1995, 1996 and 1997, respectively. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next three years. 4. INCOME TAXES Actual income tax expense differs from income tax expense computed by applying the U. S. federal statutory corporate rate of 35 percent to pretax income as follows: YEAR ENDED DECEMBER 31, 1997 ------------ Provision at the statutory tax rate......................... $ 816,852 Increase resulting from election to forgo tax exempt status.................................................... 1,483,415 ---------- $2,300,267 ========== F-10 50 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) Deferred income tax assets and liabilities result from temporary differences in the recognition of income and expenses for financial reporting purposes and for tax purposes. At December 31, 1997, the tax effects of these temporary differences, resulted principally from the following: DECEMBER 31, 1997 ------------ Deferred income tax asset: Statutory depletion carryforward.......................... $ 78,159 Deferred income tax liabilities: Intangible drilling costs................................. 1,944,634 Capitalized interest...................................... 433,792 ---------- 2,378,426 ---------- Deferred income tax liability..................... $2,300,267 ========== 5. LONG-TERM DEBT: At December 31, 1996 and 1997, notes payable and long-term debt consisted of the following: DECEMBER 31, ------------------------ 1996 1997 ---------- ---------- Notes payable to shareholders (due April, 1998)............. $2,773,935 $ -- Bridge Loan payable to Compass Bank......................... -- 3,000,000 $10 million revolving credit facility (due June 1, 1998).... 2,910,000 -- $25 million revolving credit facility (due June 1, 1999).... 4,000,000 4,950,000 ---------- ---------- $9,683,935 $7,950,000 ========== ========== In June 1996, the Company entered into a $10 million revolving credit facility with Compass Bank (the Encinitas Facility). Proceeds from this facility were used to pay off an existing loan from Texas Commerce Bank (TCB) as well as fund exploration and development activities. The facility was subject to a borrowing base calculation and had a commitment of $3,350,000 with $2,910,000 outstanding at December 31, 1996. The facility was also available for letters of credit, one of which was issued for $224,000. The Encinitas Facility was repaid with proceeds from the Offering. In December 1996, Carrizo entered into a separate $25 million revolving credit facility with Compass Bank, which was subject to a borrowing base determination, and total commitment was $6 million at December 31, 1996. Interest on this facility was the prime rate as defined by Compass Bank plus .75 percent, and the borrowings were due on June 1, 1998. In connection with the Offering, Carrizo amended the 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. Under the Company Credit Facility, the principal outstanding was due and payable upon maturity in June 1999 with interest due monthly. The interest rate for 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 and cash equivalents included in the borrowing base. Under the Company Credit Facility, Compass, in its sole discretion, will make semiannual borrowing base determinations based upon the proved oil and natural gas properties of the Company. Compass may redetermine the borrowing base and the monthly borrowing base reduction at any time and from time to time. The Company may also request borrowing base redeterminations in addition to its required semiannual reviews at the Company's cost. F-11 51 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) Proceeds from this facility were used to provide working capital for exploration and development activity. Substantially all of Carrizo's oil and natural gas property and equipment was pledged as collateral under this facility. At December 31, 1996, and 1997, borrowings under this facility totaled $4,000,000 and $4,950,000, respectively, with an additional $2,000,000 and $276,000, respectively, available for future borrowings. The facility was also available for letters of credit, one of which had been issued for $224,000 at December 31, 1997. The weighted average interest rate for 1996 and 1997 on the Facility was 9 percent. 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 and (b) maintenance of a ratio of quarterly cash flow (net income plus depreciation and other noncash expenses, less noncash net income) to quarterly debt service (payments made for principal in connection with each credit facility plus payments made for principal other than in connection with such credit facility) of no less than 1.25 to 1.00. The Company Credit Facility also place 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 December 1997, the Company entered into a term loan facility with Compass Bank bearing interest at 10.5% and due June 1, 1998 (the Bridge Loan). Proceeds from the facility were used to fund continuing exploration activities until the Company had completed its Preferred Stock sale discussed in Note 9. At December 31, 1997, $3,000,000 was outstanding under the Bridge loan. The Bridge Loan was due the earlier of April 1998 or concurrent with the Preferred Stock sale. The Company had outstanding borrowings from certain shareholders totaling $2,773,935 at December 31, 1996. These loans bore interest at the TCB prime rate, and were repaid in August 1997 out of the proceeds of the Offering. Accrued interest on shareholder borrowings at December 31, 1996 was included in other long-term liabilities. All amounts outstanding under the Company's debt facilities were refinanced in January 1998 with the proceeds from the Preferred Stock sale. As a result, all debt at December 31, 1997 has been classified as long term. 6. COMMITMENTS AND CONTINGENCIES: From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. At December 31, 1997, Carrizo was obligated under a noncancelable operating lease for office space. Rent expense for the years ended December 31, 1995, 1996 and 1997, was $7,600, $14,900 and $80,000, respectively. Following is a schedule of the remaining future minimum lease payments under this lease: 1998............................................. $ 108,700 1999............................................. $ 108,700 2000............................................. $ 54,350 7. STOCKHOLDERS' EQUITY: On June 4, 1997, the board of directors authorized a 521-for-1 split of the Company's stock and increased the number of authorized shares to 40 million shares of common stock and 10 million shares of preferred stock. All share amounts presented in these financial statements are presented on a retroactive, post-split basis. F-12 52 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) On July 19, 1996, and March 1, 1997, the Company entered into separate stock option agreements (the "Pre-IPO Options") with two executives of Carrizo whereby such employees were granted the option to purchase 138,825 shares and 83,295 shares of Carrizo common stock, respectively, at an exercise price of $3.60 per share. The options vest ratably through August 1, 1998, and March 1, 1999, respectively. The Company did not record any compensation expense related to the July, 1996 options because the related exercise price was at or above the estimated fair value of Carrizo's common stock at the time such options were granted. In connection with an initial public offering, the Company 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 is amortized in the period in which the options vest, which resulted in $279,972 being recorded in the year ended December 31, 1997. In June of 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. ("the Incentive Plan"). The Company accounts for this plan under APB Opinion No. 25, under which no compensation cost has been recognized. Had compensation cost been determined consistent with SFAS No. 123 for all options, the Company's net income and earnings per share would have been reduced to the following pro forma amounts: 1996 1997 ---------- --------- Net income (loss)..................... As reported $1,099,851 $ 30,740 Pro forma $1,038,490 $(193,722) Diluted net income (loss) per share... As reported $ 0.14 $ -- Pro forma $ 0.13 $ (.02) The Company may grant options ("Incentive Plan Options") to purchase up to 1,000,000 shares under the Incentive Plan and has granted options on 250,000 shares through December 31, 1997. Under the Incentive Plan, the option exercise price equals the stock market price on the date of grant. Options granted under the plan vest ratably over three years and have a term of ten years. A summary of the status of the Company's stock options at December 31, 1996 and 1997 is presented in the table below: 1996 ------------------------------------------- WEIGHTED AVERAGE RANGE OF EXERCISE EXERCISE SHARES PRICES PRICES ------- ---------------- -------- Outstanding at beginning of year............. -- -- Granted (Pre-IPO Options).................... 138,825 $3.60 $0-3.60 ------- ----- Outstanding at end of year................... 138,825 $3.60 $0-3.60 ======= ===== Exercisable at end of year................... 46,275 Weighted average fair value per share of options granted during the year............ $ 2.21 F-13 53 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 1997 -------------------------------------- WEIGHTED AVERAGE RANGE OF EXERCISE EXERCISE SHARES PRICES PRICES ------- -------- ----------- Outstanding at beginning of year............... 138,825 $3.60 $ 0-3.60 Granted (Pre-IPO Options)...................... 83,295 $3.60 $ 0-3.60 Granted (Incentive Plan Options)............... 250,000 11.00 $ 0-11.00 ------- ----- Outstanding at end of year..................... 472,120 $7.52 $3.60-11.00 ======= ===== Exercisable at end of year..................... 120,315 Weighted average fair value per share of options granted during the year.............. $ 6.91 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 both 1996 and 1997: risk free interest rate of 6.82% and 6.26% respectively, expected dividend yield of 0%, expected life of 10 years and expected volatility of 30% and 39.4%, respectively. 8. RELATED-PARTY TRANSACTIONS: In August 1996, the Company entered into the Master Technical Services Agreement (the MTS Agreement) with Reading & Bates Development Co. (R&B), which is a subsidiary of R&B Falcon Corporation, a company that was created by the merger of Falcon Drilling Company, Inc. and Reading & Bates Corporation. Paul Loyd, a member of the board of the Company, was the chairman of the board, president, chief executive officer and a director of Reading & Bates Corporation. Under the MTS Agreement, certain employees of the Company provide engineering and technical services to R&B at market rates in connection with R&B's technical service, procurement and construction projects in offshore drilling and floating production. The Company billed $117,726 and $103,161 in service fees under this agreement in 1996 and 1997, respectively. The Company had an agreement with Loyd & Associates Inc., which is owned by Paul Loyd, a director of Carrizo, and Frank Wojtek, vice president, chief financial officer and a director of Carrizo, to provide certain financial consulting and administrative services at market rates to the Company. Payments were made monthly and total payments to Loyd & Associates Inc. for services rendered were $60,000, $60,000 and $38,113 in 1995, 1996 and 1997, respectively. These expenditures were included in general and administrative expenses for each year. This arrangement was terminated in August, 1997 concurrent with the Company's initial public offering. 9. SUBSEQUENT EVENT: SALES OF PREFERRED STOCK AND WARRANTS In January 1998, the Company consummated the sale of 300,000 shares of Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to affiliates of Enron Corp. The net proceeds received by the Company from this transaction were approximately $28.8 million. A portion of the proceeds were used to repay indebtedness, as described in Note 5, above. The remaining proceeds are expected to be used primarily for oil and natural gas exploration and development activities in Texas and Louisiana. The Preferred Stock provides for annual cumulative dividends of $9.00 per share, payable quarterly in cash or, at the option of the Company until January 15, 2002, in additional shares of Preferred Stock. The Warrants, which had a fair value at issuance of $0.30 per share, will be accreted through the term of the Preferred Stock. Had the F-14 54 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) Preferred Stock sale been completed as of December 31, 1997, the Company's pro forma capitalization would have been as follows: CAPITALIZATION AT DECEMBER 31, 1997 --------------------------- ACTUAL PRO FORMA ----------- ----------- Bridge Loan................................................. $ 3,000,000 $ -- Company Credit Facility..................................... 4,950,000 -- Mandatorily Redeemable Preferred Stock...................... -- 28,500,000 ----------- ----------- 7,950,000 28,500,000 Stockholders' Equity........................................ 32,895,000 33,195,000 ----------- ----------- Total Capitalization........................................ $40,845,000 $61,695,000 =========== =========== The Preferred Stock is required to be redeemed by the Company (i) on January 8, 2005, or (ii) after a request for redemption from the holders of at least 30,000 shares of the Preferred Stock (or, if fewer than such number of shares of Preferred Stock are outstanding, all of the outstanding shares of Preferred Stock) and the occurrence of certain events. The Preferred Stock also may be redeemed at the option of the Company at any time in whole or in part. All redemptions are at a price per share, together with dividends accumulated and unpaid to the date of redemption, decreasing over time from an initial rate of $104.50 per share to $100 per share. The Warrants (i) enable the holders to purchase 1,000,000 shares of Common Stock at a price of $11.50 per share (payable in cash, by "cashless exercise" and certain other methods), subject to adjustments, (ii) expire after a seven-year term, and (iii) are exercisable after one year. 10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED): The following disclosures provide unaudited information required by SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." COSTS INCURRED Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below: YEAR ENDED DECEMBER 31 ------------------------------------- 1995 1996 1997 ---------- ---------- ----------- Property acquisition costs -- Unproved...................................... $ 316,820 $ 50,720 $ -- Proved........................................ 3,588,173 1,907,890 14,820,049 Exploration cost................................ 2,364,056 4,724,102 14,222,674 Development costs............................... 208,696 1,955,917 2,257,375 ---------- ---------- ----------- Total costs incurred(1)............... $6,477,745 $8,638,629 $31,300,098 ========== ========== =========== - --------------- (1) Excludes capitalized interest on unproved properties of $117,288, $422,493 and $699,625 for the years ended December 31, 1995, 1996 and 1997, 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 F-15 55 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities at December 31, 1996 and 1997, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company and Fairchild, Ancell & Wells, Inc., independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. Amounts at December 31, 1995, and for the periods then ended were rolled back from December 31, 1996, balances, ignoring the impact of revisions of estimates during those periods, if any. The Company's net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below: BARRELS OF OIL AND CONDENSATE AT DECEMBER 31, --------------------------------- 1995 1996 1997 --------- --------- --------- Proved developed and undeveloped reserves -- Beginning of year................................. 3,785,000 3,810,000 3,895,000 Purchases of oil and gas properties............... 103,000 12,000 -- Discoveries....................................... -- 180,000 285,000 Extensions........................................ -- -- 1,102,000 Production........................................ (78,000) (107,000) (112,500) --------- --------- --------- End of year......................................... 3,810,000 3,895,000 5,169,500 ========= ========= ========= Proved developed reserves at end of year............ 1,100,000 1,048,000 1,146,000 ========= ========= ========= THOUSANDS OF CUBIC FEET OF NATURAL GAS AT DECEMBER 31, ----------------------------------- 1995 1996 1997 --------- ---------- ---------- Proved developed and undeveloped reserves -- Beginning of year............................... 272,000 5,437,000 12,148,000 Purchases of oil and gas properties............. 5,730,000 338,000 7,696,000 Discoveries and extensions...................... -- 7,646,000 6,946,000 Revisions....................................... -- -- (7,190,000) Sales of oil and gas properties................. -- -- (4,709,000) Production...................................... (565,000) (1,273,000) (2,749,000) --------- ---------- ---------- End of year....................................... 5,437,000 12,148,000 12,142,000 ========= ========== ========== Proved developed reserves at end of year.......... 3,810,000 8,110,000 9,299,000 ========= ========== ========== F-16 56 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) STANDARDIZED MEASURE The standardized measure of discounted future net cash flows relating to the Company's ownership interests in proved oil and natural gas reserves as of year-end is shown below: YEAR ENDED DECEMBER 31, ----------------------------------------- 1995 1996 1997 ----------- ------------ ------------ Future cash inflows......................... $77,739,000 $126,155,000 $103,842,000 Future oil and natural gas operating expenses.................................. 43,529,000 47,675,000 55,484,000 Future development costs.................... 7,918,000 9,375,000 13,230,000 Future income tax expenses.................. 7,163,000 19,864,000 6,870,000 ----------- ------------ ------------ Future net cash flows....................... 19,129,000 49,241,000 28,258,000 10% annual discount for estimating timing of cash flows................................ 7,148,000 16,220,000 7,285,000 ----------- ------------ ------------ Standardized measure of discounted future net cash flows............................ $11,981,000 $ 33,021,000 $ 20,973,000 =========== ============ ============ Future cash flows are computed by applying year-end prices of oil and natural gas to year-end quantities of proved oil and natural gas reserves. Prices used in computing year end 1996 and 1997 future cash flows were $20.88 and $16.37 for oil, respectively and $3.69 and $2.56 for natural gas, respectively. Such prices declined significantly in the first quarter of 1998. The ceiling test for many full cost companies, including Carrizo, could be negatively impacted by prolonged unfavorable oil and gas prices. A deterioration of prices from year-end levels could result in the Company recording a first quarter 1998 non-cash charge to earnings related to its oil and gas properties. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on the year-end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company's oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. F-17 57 CARRIZO OIL & GAS, INC. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) CHANGE IN STANDARDIZED MEASURE Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below: YEAR ENDED DECEMBER 31, ------------------------------------------ 1995 1996 1997 ----------- ----------- ------------ Changes due to current-year operations -- Sales of oil and natural gas, net of oil and natural gas operating expenses.... $ (614,000) $(2,811,000) $ (6,378,000) Extensions and discoveries............... -- 19,641,000 16,074,000 Purchases of oil and gas properties...... 2,770,000 2,079,000 6,954,000 Changes due to revisions in standardized variables -- Prices and operating expenses............ 6,343,000 9,781,000 (29,115,000) Income taxes............................. (1,307,000) (8,834,000) 11,410,000 Estimated future development costs....... -- (670,000) (2,683,000) Quantities............................... -- -- (3,449,000) Sales of reserves in place............... -- -- (3,933,000) Accretion of discount.................... 968,000 1,647,000 4,634,000 Production rates (timing) and other...... (2,677,000) 207,000 (5,562,000) ----------- ----------- ------------ Net change................................. 5,483,000 21,040,000 (12,048,000) Beginning of year.......................... 6,498,000 11,981,000 33,021,000 ----------- ----------- ------------ End of year................................ $11,981,000 $33,021,000 $ 20,973,000 =========== =========== ============ Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pretax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pretax discounted basis. F-18 58 SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED) FIRST SECOND THIRD FOURTH ---------- ----------- ---------- ---------- 1997 Revenues................................... $1,853,170 $ 2,311,854 $2,069,237 $2,477,393 Expenses, net.............................. 1,137,554 3,675,879 1,787,800 2,079,681 ---------- ----------- ---------- ---------- Net Income................................. $ 715,616 $(1,364,025) $ 281,437 $ 397,712 ========== =========== ========== ========== Diluted Net Income (Loss) Per Share(1)(2)............................. $ 0.09 $ (0.18) $ 0.03 $ 0.04 ========== =========== ========== ========== 1996 Revenues................................... $ 790,513 $ 1,428,139 $1,588,354 $1,387,703 Expenses, net.............................. 646,166 1,085,439 1,085,781 1,277,472 ---------- ----------- ---------- ---------- Net Income................................. $ 144,347 $ 342,700 $ 502,573 $ 110,231 ========== =========== ========== ========== Diluted Net Income Per Share(1)(2)......... $ 0.02 $ 0.04 $ 0.07 $ 0.01 ========== =========== ========== ========== - --------------- (1) The sum of individual quarterly net income per common share may not agree with year-to-date net income per common share as each period's computation is based on the weighted average number of common shares outstanding during that period. (2) Net income per common share amounts have been restated to conform to the provisions of SFAS No. 128, "Earnings Per Share." 59 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CARRIZO OIL & GAS, INC. By: /s/ FRANK A. WOJTEK ---------------------------------- Frank A. Wojtek Chief Financial Officer, Vice President, Secretary and Treasurer Date: March 31, 1998. Pursuant to the requirements of the Securities and 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 Officer March 31, 1998 - ----------------------------------------------------- and Director (Principal S.P. Johnson IV Executive Officer) /s/ FRANK A. WOJTEK Chief Financial Officer, Vice March 31, 1998 - ----------------------------------------------------- President, Secretary, Treasurer Frank A. Wojtek and Director (Principal Financial Officer and Principal Accounting Officer) /s/ STEVEN A. WEBSTER Chairman of the Board March 31, 1998 - ----------------------------------------------------- Steven A. Webster /s/ DOUGLAS A. P. HAMILTON Director March 31, 1998 - ----------------------------------------------------- Douglas A. P. Hamilton /s/ PAUL B. LOYD, JR. Director March 31, 1998 - ----------------------------------------------------- Paul B. Loyd, Jr. 60 EXHIBIT INDEX +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). 3.1 -- Amended and Restated Articles of Incorporation of the Company. 3.2 -- Statement of Resolution Establishing Series of Shares designated 9% Series A Preferred Stock. +3.3 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915). +4.1 -- First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated August 28, 1997 (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997). 4.2 -- First Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 23, 1997. 4.3 -- Second Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 30, 1997. -- The Company is a party to several debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the Company agrees to furnish a copy of such instruments to the Commission upon request. +10.1 -- Incentive Plan of the Company (Incorporated herein by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.2 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.3 -- Employment Agreement between the Company and Frank A. Wojtek (Incorporated herein by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.4 -- Employment Agreement between the Company and Kendall A. Trahan (Incorporated herein by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.5 -- Employment Agreement between the Company and George Canjar (Incorporated herein by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). 10.6 -- Indemnification Agreement between the Company and each of its directors and executive officers. +10.7 -- Registration Rights Agreement by and among the Company, Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997 (Incorporated herein by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). 61 +10.8 -- 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)). +10.9 -- 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)). +10.10 -- Stock Purchase Agreement dated January 8, 1998 among the Company, Enron Capital & Trade Resources Corp. and Joint Energy Development Investments II Limited Partnership. (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated January 8, 1998). +10.11 -- Warrant Certificates (Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated January 8, 1998.) +10.12 -- Shareholders' Agreement dated January 8, 1998 among the Company, S.P. Johnson IV, Frank A. Wojtek, Steven A. Webster, Paul B. Loyd, Jr., Douglas A.P. Hamilton, DAPHAM Partnership, L.P., The Douglas A.P. Hamilton 1997 GRAT, Enron Capital & Trade Resources Corp. and Joint Energy Development Investments II Limited Partnership. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated January 8, 1998). +10.13 -- 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). 23.1 -- Consent of Arthur Andersen LLP. 23.2 -- Consent of Ryder Scott Company Petroleum Engineers. 23.3 -- Consent of Fairchild, Ancell & Wells, Inc. 27.1 -- Financial Data Schedule. 99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 1997. 99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells, Inc. as of December 31, 1997. - --------------- + Incorporated by reference as indicated.