-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, M76bqMfz9KcEupraCNpBkGC9FUZhm3ZqmTgzjh5XHQh2GCFNpJxvfxB+30Isvl1b Tphvb23yBFtGCqh0UY4wSg== 0000950129-99-001577.txt : 19990415 0000950129-99-001577.hdr.sgml : 19990415 ACCESSION NUMBER: 0000950129-99-001577 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990414 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CARRIZO OIL & GAS INC CENTRAL INDEX KEY: 0001040593 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760415919 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 000-29187-87 FILM NUMBER: 99593774 BUSINESS ADDRESS: STREET 1: 14811 ST MARYS LANE STREET 2: STE 148 CITY: HOUSTON STATE: TX ZIP: 77079 BUSINESS PHONE: 2814961352 MAIL ADDRESS: STREET 1: CARRIZO OIL & GAS INC STREET 2: 14811 ST MARYS LANE STE 148 CITY: HOUSTON STATE: TX ZIP: 77079 10-K/A 1 CARRIZO OIL & GAS, INC. - DATED 12/31/1998 1 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 COMMISSION NO. 0-22915 CARRIZO OIL & GAS, INC. (Exact name of registrant as specified in its charter) TEXAS 76-0415919 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 14811 ST. MARY'S LANE, SUITE 148 77079 HOUSTON, TEXAS (Zip Code) (Principal executive offices)
Registrant's telephone number, including area code: (281) 496-1352 Securities Registered Pursuant to Section 12(g) of the Act: COMMON STOCK, $.01 PAR VALUE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. _________ At March 26, 1999, the aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $5.3 million based on the closing price of such stock on such date of $1 11/32. At March 26, 1999, the number of shares outstanding of the registrant's Common Stock was 10,375,000. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrant's 1999 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 1998. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 TABLE OF CONTENTS PART I...................................................... 1 Item 1. and Item 2. Business and Properties............... 1 Item 3. Legal Proceedings................................. 22 Item 4. Submission of Matters to a Vote of Security Holders................................................ 22 Executive Officers of the Registrant...................... 22 PART II..................................................... 23 Item 5. Market for Registrant's Common Stock and Related Shareholder Matters.................................... 23 Item 6. Selected Financial Data........................... 24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 25 Item 7A. Qualitative and Quantitative Disclosures About Market Risk............................................ 34 Item 8. Financial Statements and Supplementary Data....... 35 Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.................... 35 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
Carrizo Oil & Gas, Inc. hereby amends its Annual Report on Form 10-K for the year ended December 31, 1998, to correct certain information in the fifth paragraph under "Part I -- Item 1. and Item 2. Business and Properties" and in the first paragraph under "Part II -- Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and restates this report in its entirety to reflect such amendment. 3 PART I ITEM 1. AND ITEM 2. BUSINESS AND PROPERTIES GENERAL Carrizo Oil & Gas, Inc. ("Carrizo" or the "Company") is an independent oil and gas company engaged in the exploration, development, exploitation and production of natural gas and crude oil. The Company's operations are currently focused onshore in proven oil and gas producing trends along the Gulf Coast, primarily in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends. The Company believes that the availability of economic onshore 3-D seismic surveys has fundamentally changed the risk profile of oil and gas exploration in these regions. Recognizing this change, the Company has aggressively sought to control significant prospective acreage blocks for targeted 3-D seismic surveys. As of December 31, 1998, the Company had assembled approximately 407,123 gross acres under lease or option and acquired 31 3-D seismic surveys. 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 90% 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. The Company expects to acquire or cause to be acquired additional 3-D seismic data during the remainder of 1999 that will cover most of the remaining current acreage position. Carrizo has amassed a large drillsite inventory from the 3-D surveys, with as many as 280 gross wells that could be drilled over the next four years, assuming sufficient capital resources. In addition, the Company anticipates that as its existing 3-D seismic data is further evaluated, and 3-D seismic data is acquired over the balance of its acreage, additional prospects will be generated for drilling beyond 2002. 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 $150,000 to $400,000 per completed well) and risk. Many of these drilling prospects also have secondary, deeper, over-pressured targets which have greater economic potential but generally involve higher cost (typically $1 million to $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, 1998, the Company operated 75 producing oil and gas wells, which accounted for 39% of the wells in which the Company had an interest. The Company has experienced rapid increases in reserves, production and EBITDA from its inception in 1993 through 1997 due to the growth of its 3-D based drilling and development activities. From January 1, 1996 to December 31, 1998, the Company participated in the drilling of 147 gross wells (51.9 net) with a commercial well success rate of approximately 67%. This drilling success contributed to the Company's total proved reserves as of December 31, 1997 of 43.2 Bcfe with a PV-10 Value of $26.1 million. During 1998, the Company added 6.4 Bcfe to proved reserves through drilling and acquisitions, however total proved reserves decreased to approximately 32.0 Bcfe, with a PV-10 Value of $18.7 million, as a result of production and 8.4 Bcfe of reserves deemed uneconomic due to low oil and gas prices at December 31, 1998. While the Company's production increased 2% from 3,424 MMcfe for the year ended December 31, 1997 to 3,495 MMcfe for the year ended December 31, 1998, EBITDA decreased from $4,787,000 for the year ended December 31, 1997 to $2,707,000 for the year ended December 31, 1998 due to significantly lower oil and gas sales prices. 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's strategy has been to rapidly accumulate large amounts of 3-D seismic data along prolific, producing trends of the onshore Gulf Coast after obtaining options to lease areas covered by the data. The Company then uses 3-D seismic data to identify or evaluate prospects before drilling the prospects that fit its risk/reward criteria. The Company typically seeks to explore in locations within its core areas of expertise that it believes have (i) numerous accumulations of normally pressured reserves at shallow depths and in geologic traps that are difficult to define without the interpretation of 3-D seismic data and (ii) the potential for large accumulations of deeper, over-pressured reserves. As a result of the increased availability of economic onshore 3-D seismic surveys and the improvement and increased affordability of data interpretation technologies, the Company has relied almost exclusively on the interpretation of 3-D seismic data in its exploration strategy. The Company generally does not invest any substantial portion of the costs for an exploration well without first interpreting 3-D seismic data. The principal advantage of 3-D seismic data over traditional 2-D seismic analysis is that it affords the geoscientist the ability to interpret a three dimensional cube of data representing a specific project area as compared to interpreting between widely separated two dimensional vertical profiles. As a consequence, the geoscientist is able to more fully and accurately evaluate prospective areas, improving the probability of drilling commercially successful wells in both exploratory and development drilling. The use of 3-D seismic allows the geoscientist to identify and use areas of irregular sand geometry to augment or replace structural interpretation in the identification of potential hydrocarbon accumulations. Additionally, detailed analysis and correlation of the 3-D seismic response to lithology and contained fluids assist geoscientists in identifying and prioritizing drilling targets. Because 3-D analysis is completed over an entire target area cube, shallow, intermediate and deep objectives can be analyzed. Additionally, the more precise structural definition allowed by 3-D seismic data combined with integration of available well and production data assists in the positioning of new development wells. The Company has sought to obtain large volumes of 3-D seismic data either by participating in large seismic data acquisition programs either alone or pursuant to joint venture arrangements with other energy companies, or through "group shoots" in which the Company shares the costs and results of seismic surveys. By participating in joint ventures and group shoots, the Company is able to share the up-front costs of seismic data acquisition and interpretation, thereby enabling it to participate in a larger number of projects and diversify exploration costs and risks. Most of the Company's operations are conducted through joint operations with industry participants. As of December 31, 1998, the Company was actively involved in 45 project areas. The Company's primary strategy for acreage acquisition is to obtain leasing options covering large geographic areas in connection with 3-D seismic surveys. Prior to conducting proprietary surveys, the Company typically seeks to acquire seismic permits that include options to lease the acreage, thereby ensuring the price and availability of leases on drilling prospects that may result upon completing a successful seismic data acquisition program over a project area. The Company generally attempts to obtain these options covering at least 80% of the project area for these proprietary surveys. The size of these surveys has ranged from 10 to 80 square miles. When the Company participates in 3-D group shoots, it generally seeks prospective leases as quickly as possible following interpretation of the survey. In connection with some group shoots in which the Company believes that competition for acreage may be especially strong, the Company may seek to obtain lease options or leases in prospective areas prior to the receipt or interpretation of 3-D seismic data. The Company maintains a flexible and diversified approach to project identification by focusing on the estimated financial results of a project area rather than limiting its focus to any one method or source for obtaining leads for new project areas. The Company's current project areas resulted from leads developed by its project generation network that includes small, independent "prospect generators", the Company's joint venture partners and the Company's internal staff. The Company believes that it has been able to increase the number of potential projects and reduce its costs through the use of these outside sources of project generation. When identifying specific drillsites from within a project area, the Company relies upon its own geoscientists. 2 5 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 16 years of industry experience, in many cases with major and large independent oil companies, including Shell Oil Company, Vastar Resources, Inc., Pennzoil Company and Tenneco Inc. The Company generally seeks to obtain lease operator status and control over field operations, and in particular seeks to control decisions regarding 3-D survey design parameters and drilling and completion methods. As of December 31, 1998, the Company operated 75 producing oil and natural gas wells. The Company emphasizes preplanning in project development to lower capital and operational costs and to efficiently integrate potential well locations into the existing and planned infrastructure, including gathering systems and other surface facilities. In constructing surface facilities, the Company seeks to use reliable, high quality, used equipment in place of new equipment to achieve cost savings. The Company also seeks to minimize cycle time from drilling to hook-up of wells, thereby accelerating cash flow and improving ultimate project economics. The Company seeks to use advanced production techniques to exploit and expand its reserve base. Following the discovery of 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 45 exploration project areas. As of December 31, 1998, the Company had an existing 3-D seismic database of 1,673 square miles and was acquiring an additional 98 square miles of data (totaling 1,771 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. The Company generally groups its exploration projects into four geographical/geological trends and areas. TEXAS -- WILCOX/YEGUA TREND Carrizo has acquired 12 3-D surveys totaling 727 square miles in the prolific Wilcox trend of south Texas. Eleven of the surveys also include the Yegua and/or Cook Mountain sections. TEXAS FRIO/VICKSBURG TREND Carrizo has acquired 15 3-D surveys totaling 908 square miles in the Frio/Vickburg productive trend of South Texas. Three of these surveys also have downdip Wilcox/Yegua exploration potential. TEXAS -- SOUTHEAST TEXAS AREAS 3-D surveys have been acquired over four areas in Southeast Texas including Nacogdoches, Liberty and Chambers Counties, totaling 130 square miles. Exploration targets include Cotton Valley Lime, Yegua/Cook Mountain and Expanded Frio/Vicksburg. As of December 31, 1998, the Company had received data in two of these areas. 3 6 LOUISIANA-SOUTH LOUISIANA AREAS 3-D seismic has been acquired over two of the Company's three most attractive Louisiana areas. In these areas, the Company typically leases ahead of large speculative surveys then seeks access to relevant data through data agreements with the seismic contractor. 1999 EXPLORATION AND DEVELOPMENT PROGRAM
SQ. MILES OF 3-D GROSS SEISMIC DATA AT ACREAGE DECEMBER 31, 1999 LEASED OR ---------------------- UNDER BUDGETED AVERAGE OPTION AT EXISTING FOR AVERAGE NET DECEMBER 31, OR BEING ACQUISITION WORKING REVENUE PROJECT AREAS 1998 ACQUIRED 1999 INTEREST(1) INTEREST(1) ------------- ------------ -------- ----------- ----------- ----------- TEXAS Starr/Hidalgo........................ 4,435 340(2) -- 50.0% 37.5% Encinitas/Kelsey..................... 9,110 32 -- 27.5% 23.0% Buckeye.............................. 11,946 62(2) -- 65.0% 48.75% La Rosa.............................. 5,827 22 -- 31.2% 23.6% Mexican Sweetheart................... 6,182 40 -- 25.0% 18.8% McFaddin Ranch ...................... 5,374 15 -- 34.4% 25.8% Cologne.............................. 7,134 40 -- 25.0% 18.8% South Cabeza Creek................... 3,349 65(2) -- 77.5% 39.4% Western 325.......................... 499 250(2) -- 50.0% 37.5% Highway 59........................... 5,633 36 -- 25.0% 15.0% Geronimo............................. 10,139 107 -- 15.0% 11.3% RPP Welder........................... 25,633 60 -- 15.0% 11.3% Cedar Point.......................... 10,112 30 25.0% 18.7% Felicia/Devers....................... 2,981 52(2) 87.5% 75.0% Jailhouse............................ 9,400 50 12.5% 9.25% Scott-Farish......................... 22,811 42 70.0% 52.5% Higgins.............................. 30,087 66(2) 100.0% 75.0% Ganado............................... 13,682 32 50.0% 37.5% Lost Bridge.......................... 4,658 17 -- 70.0% 52.5% Metro................................ 7,032 30 -- 25.0% 18.7% South Texas Syndicate................ 38,032 65 -- 44.375% 34.70% Victoria............................. 3,924 50 -- 50.0% 42.75% Matagorda............................ 19,870 51(2) 98.0% 73.5% Driscoll Ranch ...................... 59,000 84 23.88% 17.8% Other (14 Areas)..................... 84,481 177 -- 53.03% 40.36% LOUISIANA Calcasieu............................ 1,342 -- -- 100.0% 75.0% N. Tigre Lagoon...................... 437 6 -- 100.0% 75.0% Other (5 Areas)...................... 4,013 -- 6 23.92% 17.94% ------- ----- --- Total........................ 407,123 1,771 56 49.07% 36.68% ======= ===== ===
- --------------- (1) Anticipated interests based on ownership or contractual rights as of December 31, 1998. (2) 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 4 7 partners to share the up-front costs associated with obtaining option arrangements with landowners, seismic data acquisition and related data interpretation, to mitigate its exploration risk and to increase the number of projects in which it is able to participate. Although the Company is currently pursuing prospects within the project areas described below, there can be no assurance that these prospects will be drilled at all or within the expected time frame. In some project areas, the Company has budgeted for wells that are based upon statistical results of drilling activities in other project areas; these wells are subject to greater uncertainties than wells for which drillsites have been identified. The final determination with respect to the drilling of any identified drillsites or budgeted wells will be dependent on a number of factors, including (i) the results of exploration efforts and the acquisition, review and analysis of the seismic data, (ii) the availability of sufficient capital resources by the Company and the other participants for the drilling of the prospects (not all of which resources are currently available), (iii) the approval of the prospects by other participants after additional data has been compiled, (iv) the economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, (v) the financial resources and results of the Company and its partners and (vi) the availability of leases on reasonable terms and permitting for the prospect. There can be no assurance that these projects can be successfully developed or that any identified drillsites or budgeted wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. The Company may seek to sell or reduce all or a portion of its interest in a project area or with respect to prospects or wells within a project area. The success of the Company will be materially dependent upon the success of its exploratory drilling program. Exploratory drilling involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations my be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rights and the delivery of equipment. Although the Company believes that its use of 3-D seismic data and other advanced technologies should increase the probability of success of its exploratory wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis 2-D seismic data, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies only assist geoscientists in identifying subsurface structures and do not enable the interpreter to know whether hydrocarbons are in fact present in such structures. In addition, the use of 3-D seismic data and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and the Company could incur losses as a result of such expenditures. The Company's future drilling activities may not be successful, and if unsuccessful, such failure will have a material adverse effect on the Company's results of operations and financial condition. There can be no assurance the Company's overall drilling success rate or its drilling success rate for activity within a particular project area will not decline. The Company may choose not to acquire option and lease rights prior to acquiring seismic data and, in many cases, the Company may identify a prospect or drilling location before seeking option or lease rights in the prospect or location. Although the Company has identified or budgeted for numerous drilling prospects, there can be no assurance that such prospects will ever be leased or drilled (or drilled within the scheduled or budgeted time frame) or that oil or natural gas will be produced from any such prospects or any other prospects. In addition, prospects may initially be identified through a number of methods, some of which do not include interpretation of 3-D or other seismic data. Wells that are currently in the Company's capital budget may be based upon statistical results of drilling activities in other 3-D project areas that the Company believes are geologically similar, rather than on analysis of seismic or other data. Actual drilling and results are likely to vary from such statistical results and such variance may be material. Similarly, the Company's drilling schedule may vary from its capital budget because of future uncertainties, including those described above. The description of a well as "budgeted" does not mean that the Company currently has or will have the capital resources to drill the well. See "Management's Discussion and Analysis of financial Condition and Results of Operations." 5 8 The reserve data set forth below is based upon the reserve report (the "Ryder Scott Report") dated February 19, 1999 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 March 11, 1999 prepared by Fairchild, Ancell & Wells, Inc., independent petroleum engineers ("Fairchild"). The 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 -- WILCOX/YEGUA TRENDS Buckeye Project Area: Jackson and Wilcox Formations The Buckeye Project Area is located in Live Oak County, Texas. As of December 31, 1998, the Company and its partner currently hold 11,946 acres under lease. The approximately 62 square mile 3-D seismic survey has led to the successful exploitation of shallow zones of the Hockley, Pettus and Yegua formations. In addition, deeper zones within the expanded Wilcox section have been identified within four prospect closures. Lease control is complete and the first test well is budgeted to be drilled in 1999, depending on available financing for both the Company and its partners. During the quarter ended December 31, 1998, the Company's share of production from wells in this project area averaged approximately 100 barrels per day of oil and 1.1 MMcf per day of natural gas. As of December 31, 1998, the Company and its partners have drilled 32 wells in this project area, resulting in 25 producing wells. The estimated proved reserves net to the Company for this project area were 90 MBbls of oil and 1.2 BCF of natural gas at December 31, 1998. South Cabeza Creek Project Area: Frio, Yegua and Wilcox Formations The South Cabeza Creek Project Area is located in Goliad County, Texas in an area having significant production in the shallow Frio and Wilcox trends. The Company has received 65 square miles of data from a non exclusive shoot completed in December of 1998. Several Wilcox prospects and shallow lead areas have been defined from the 3-D interpretation. The initial prospect is budgeted to be drilled in 1999, depending on available financing for both the Company and its partners. The Company and its partners had 1,926 acres under lease and 1,423 acres under seismic option as of December 31, 1998. Western 325 Project Area: Wilcox and Jackson Formations The Western 325 Project Area is located in Webb and Duval Counties, Texas in the Wilcox and Jackson-Yegua formations. The Company and a partner have joined others in underwriting a non-proprietary 3-D seismic data shoot covering approximately 320 square miles in the project area. Multiple prospects have been identified from data received to date. The Company is currently attempting to acquire land control over what it believes are the highest potential prospects identified so far. Highway 59 Project Area: 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 cooperative shoot effort resulted in access to 36 square miles of 3-D seismic to define both Wilcox and Yegua/Cook Mountain prospects. The drilling of the initial well is budgeted for 1999, depending on available financing for both the Company and its partners. The well is designed to test a highside Wilcox closure as well as gain information within the Yegua. Metro Project Area: 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 30 square mile 3-D seismic program has been completed and numerous drilling opportunities have been identified. The Company has participated in two successful shallow wells, one successful upper Wilcox well and is currently drilling a follow up development well to the 1998 Wilcox discovery. The Company has budgeted the drilling of two additional shallow wells and one additional Wilcox well in 1999 depending upon 6 9 available financing for the Company and its partners. The Company and its partners had 7,032 acres under lease as of December 31, 1998. South Texas Syndicate: Oligocene through Jurassic Formations The South Texas Syndicate Project Area is located in LaSalle and McMullen Counties, Texas. A 65 square mile 3-D survey has been completed with data received in December 1998. Ten prospect areas have been identified from the Wilcox through the Jurassic. Land control over these areas has been completed and drilling of the initial well is budgeted in 1999, depending on the available financing for both the Company and its partners. The Company and its partners had 38,032 acres under option as of December 31, 1998. Driscoll Project Area: Frio through Yegua Formations The Driscoll 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. Eighty-four square miles of 3-D seismic data was acquired in 1998 and interpretation began in November 1998. Numerous structural closures in the Yegua have been identified and lease options are being exercised in preparation for drilling. The Company has budgeted to drill two wells in 1999, depending on the available financing for both the Company and its partners. The Company and its partners had 59,000 acres under option as of December 31, 1998. Scott/Farish Ranch Project Area: Frio/Jackson/Wilcox Formations The Scott/Farish Ranch Project Area is located in Bee County, Texas and targets structural and stratigraphic traps in the Frio through Yegua intervals with deeper prospectivity in the Wilcox Formations. Approximately 42 square miles of data was acquired in 1998 with interpretation beginning February 1999. Over 10 shallow prospects have been identified along with one deeper Wilcox prospect. Leasing is currently underway with drilling of the initial prospect budgeted for late 1999, depending on available financing for both the Company and its partners. As of December 31, 1998, the Company and its partners had 22,811 acres under option. TEXAS -- FRIO/VICKSBURG TRENDS 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 were identified in the shallow Frio trend and the deeper, structurally complex Vicksburg trend. As of December 31, 1998, the Company and its partner had leases covering 3,715 acres and options covering 720 acres in this project. During 1997, production from the Company's wells in the Wheeler area was curtailed by the Texas Railroad Commission. The Company has sought to return the production, however the curtailment is presently continuing. The Company estimates that it has 4,000 Mcfe/d of production shut-in as of December 31, 1998. The Company's share of production from wells in this project area during 1998 was approximately 30 Bbls/d of oil and 1.5 MMcf/d natural gas. As of December 31, 1998, the Company and its partners had drilled a total of 27 wells in this project area, resulting in 18 producing wells. The estimated proved reserves net to the Company for this project area was 100 MBbls of oil and 1.7 Bcf of natural gas at December 31, 1998. The Company and its partners have identified four locations that have been or are budgeted to be drilled during 1999, depending on available financing for both the Company and its partners. 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. Mexican Sweetheart Project Area: Frio Yegua/ Formations The Mexican Sweetheart Project Area is located in southwestern Jackson County, Texas in the Frio producing trend and proximate to successful industry activity in the expanded Yegua. The 40 square mile shoot has identified shallow Frio prospects as well as two approximately 1,000 acre Yegua prospects. Both lead 7 10 areas are lease controlled and the initial prospect is budgeted to be drilled in 1999, depending on available financing for both the Company and its partners. As of December 31, 1998, the Company and its partners had 6,182 acres under lease. Cologne Project Area: Frio and Wilcox Formations The Cologne Project Area is located in Goliad and Victoria Counties, Texas in the Frio and Wilcox formations. A 40 square mile 3-D seismic survey has been shot over the project area, has been interpreted and yielded drillsites to evaluate prospectivity from the Frio through the Wilcox formations. As of December 31, 1998, the Company had drilled five successful Frio wells in six attempts. In addition, three large highside Wilcox structures covering over 2,500 areas have been identified and leased. The first of these structures is budgeted to be drilled in 1999, depending on available financing for both the Company and its partners. As of December 31, 1998, the Company and its partner's leasehold covered 7,134 acres. Matagorda Project Area: Frio Formation The Matagorda Project Area is located in Matagorda County, Texas covering numerous Middle Frio structural opportunities in addition to the Lower Frio expanded section. The preliminary data from the 3-D has identified over ten prospects from the Middle and Lower Frio. Options are currently being exercised in preparation for drilling in third quarter of 1999. The Company has budgeted to drill as many as three to five wells in this project area in 1999, depending on available financing for both the Company and its partners. The Company had acquired 1,756 acres of leasehold and lease options covering 18,114 acres as of December 31, 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. The 15 square mile 3-D seismic survey has yielded seven prospect areas targeting the upper through basal Frio. One unsuccessful well was drilled in 1998. All additional prospect areas are leased and a minimum of two additional drillsites have been identified. As of December 31, 1998, the Company and its partners had leases in this area covering 5,374 acres. TEXAS -- SOUTHEAST TEXAS AREAS Felicia/Devers Project Area: Frio Yegua Cook Mountain Formations The Felicia/Devers Project Area is located in Liberty County, Texas and targets amplitude supported Frio and structural-stratigraphic targets in the Yegua and Cook Mountain Formations. The 3-D seismic survey was acquired in 1998 with 52 square miles of data in house for interpretation in February 1999. Over 10 prospects have been identified to date and leasing is currently underway for initial drilling budgeted to commence in late 1999, depending on available financing for both the Company and its partners. As of December 31, 1998, the Company had 2,981 acres under lease or option. Cedar Point Project Area: Lower Frio to Vicksburg Formations The Cedar Point Project Area is located in Chambers County adjacent to Trinity Bay and targets the lower Frio and Vicksburg Formations. The 30 square mile 3-D seismic was acquired in 1998 and delivered for interpretation in September 1998. Over 14 prospects have been identified within the Frio, Vicksburg and Yegua Formations. The primary prospects are lease controlled and initial drilling is budgeted for late 1999, depending on available financing for both the Company and its partners. As of December 31, 1998, the Company and its partners had 10,112 acres under seismic option. 8 11 LOUISIANA -- SOUTH LOUISIANA AREAS North Tigre Lagoon Prospect: Vermilion Parish The North Tigre Lagoon Prospect lies in the prolific lower Miocene producing trend of Southwest Louisiana. The prospect targets normally pressured Rob. C., Rob. C. 2 and Siph. D. Sands. The Company has budgeted to drill a test well in 1999, depending on available financing for both the Company and its partners. West Bay Prospect: Plaquemines Parish, Louisiana The West Bay Prospect is located in the prolific upper and middle Miocene producing trend of Southeast Louisiana. It lies proximate to successful industry activity in the West Bay Field complex. The prospect targets normally pressured upper Miocene sands. The Company has budgeted to drill a test well in 1999, depending on available financing for both the Company and its partners. Ursa Minor Prospect: Cameron Parish, Louisiana The prospect is located in the prolific Miocene producing trend of Southwest Louisiana. The prospective play is a series of stratigraphic traps, with associated seismic amplitude anomalies, located on the north flank of a major, regional salt withdrawal minibasin. The prospect targets normally pressured middle Miocene sands between 4,000 feet and 8,000 feet. The Company has budgeted to drill a test well in 1999, depending on available financing for both the Company and its partners. OTHER PROJECT AREAS In addition to the project areas described above, the Company has 19 additional project areas in various stages of development as of December 31, 1998. These project areas are located in the onshore Texas and Louisiana Gulf Coast regions, 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, 1998 had acquired leases and seismic options covering 88,494 acres. 3-D seismic surveys covering an aggregate of approximately 6 square miles are budgeted for acquisition during 1999. CAMP HILL PROJECT The Company owns interests in eight leases totaling approximately 900 gross acres in the Camp Hill field in Anderson County, Texas. The Company currently operates six of these leases. During the year ended December 31, 1998, the project produced 97 barrels per day of 19 API gravity oil. The project produces from a depth of 500 feet and utilizes a tertiary steam drive as an enhanced oil recovery process. Although efficient at maximizing oil recovery, the steam drive process is relatively expensive to operate because natural gas or produced crude is burned to create the steam injectant. Lifting costs during the year ended December 31, 1998 averaged $14.10 per barrel ($2.35 per Mcfe). In response to lower commodity prices, steam injection was reduced in November 1998, resulting in fourth quarter lifting costs of $11.35 per barrel. Because profitability increases when natural gas prices drop relative to oil prices, the project is a natural hedge against decreases in natural gas prices relative to oil prices. The crude oil produced, although viscous, commands a higher price (an average premium of $.75 per barrel during the year ended December 31, 1998) than West Texas intermediate crude due to its suitability as a lube oil feedstock. As of December 31, 1998, the Company had 3,290 MBbls of oil of proved reserves in this project, with 837 MBbls of oil currently developed reflecting a loss of 1,372 MBbls of reserves deemed uneconomic at year end due to low oil prices. 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%. 9 12 JONES BRANCH PROPERTIES During November, 1998 the Company acquired an interest in four oil and gas producing properties along with rights to participate in certain exploration prospects (primarily in the Wilcox formation) in Wharton County, Texas and associated rights of access to certain 2-D and 3-D seismic data and related information and other related assets. The Company has an average working interest of 31.3% and an average net revenue interest of 23.7%. The wells were producing at a combined rate of 1,994 Mcf per day and 152 Bbls of condensate per day during December 1998. 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, 1998. The reserve data and the present value as of December 31, 1998 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, 1998, see the Reserve Reports included as exhibits to this Annual Report on Form 10-K. The PV-10 Value was prepared using constant prices as of the calculation date, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. For further information concerning the present value of future net revenue from these proved reserves, see Note 12 of Notes to Financial Statements.
PROVED RESERVES --------------------------------- DEVELOPED UNDEVELOPED TOTAL --------- ----------- ------- (DOLLARS IN THOUSANDS) Oil and condensate (MBbls)............................ 1,112 2,535 3,647 Natural gas (MMcf).................................... 9,097 1,058 10,155 Total proved reserves (MMcfe)......................... 15,770 16,266 32,036 PV-10 Value(1)........................................ $15,154 $ 3,601 $18,755
- --------------- (1) The PV-10 Value as of December 31, 1998 is pre-tax and was determined by using the December 31, 1998 sales prices, which averaged $10.15 per Bbl of oil, $2.18 per Mcf of natural gas and $8.24 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, 1998. 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, 1998. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced. 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 10 13 downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material. In addition, the 10% discount factor, which is required by the Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general. In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent the Company conducts successful exploration and development activities or acquires properties containing proved reserves, or both, the proved reserves of the Company will decline as reserves are produced. The Company's future oil and natural gas production is, therefore, highly dependent upon its level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital investment to maintain or expand its asset base of oil and natural gas reserves would be impaired. The failure of an operator of the Company's wells to adequately perform operations, or such operator's breach of the applicable agreements, could adversely impact the Company. In addition, there can be no assurance that the Company's future exploration, development and acquisition activities will result in additional proved reserves or that the Company will be able to drill productive wells at acceptable costs. Furthermore, although the Company's revenues could increase if prevailing prices for oil and natural gas increase significantly, the Company's finding and development costs could also increase. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." VOLUMES, PRICES AND OIL & GAS OPERATING EXPENSE The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with the Company's sales of oil and natural gas for the periods indicated. The table includes the impact of hedging activities.
YEAR ENDED DECEMBER 31, ------------------------ 1996 1997 1998 ------ ------ ------ Production volumes Oil (MBbls).............................................. 107 113 140 Natural gas (MMcf)....................................... 1,273 2,749 2,655 Natural gas equivalent (MMcfe)........................... 1,915 3,424 3,495 Average sales prices Oil (per Bbl)............................................ $21.54 $18.66 $12.30 Natural gas (per Mcf).................................... 2.27 2.41 2.31 Natural gas equivalent (per Mcfe)........................ 2.71 2.54 2.25 Average costs (per Mcfe) Camp Hill operating expenses............................. $ 3.15 $ 2.59 $ 2.35 Other operating expenses................................. 0.94 0.54 0.69 Total operating expenses(1).............................. 1.24 0.68 0.79
- ---------- (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, 1998, the Company has incurred total gross development, exploration and acquisition costs of approximately $80.7 million. Total exploration, development and acquisition activities from inception through December 31, 1998 have resulted in the addition of approximately 52.5 Bcfe, net to the Company's interest, of proved reserves at an average finding and development cost of $1.54 per Mcfe. 11 14 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, --------------------------------- 1996 1997 1998 ------ -------------- ------- (IN THOUSANDS) Acquisition costs Unproved prospects................................. $ 51 $14,223 $ 9,619 Proved properties.................................. 1,908 5,492 16,197 Exploration.......................................... 4,724 9,328 10,429 Development.......................................... 1,956 2,257 313 ------ ------- ------- Total costs incurred(1).................... $8,639 $31,300 $36,558 ====== ======= =======
- ---------- (1) Excludes capitalized interest on unproved properties of $422,493, $699,625 and $291,496 for the years ended December 31, 1996, 1997 and 1998, respectively. DRILLING ACTIVITY The following table sets forth the drilling activity of the Company for the years ended December 31, 1996, 1997 and 1998. 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, 1996 to December 31, 1998 has resulted in a commercial success rate of approximately 67%.
YEAR ENDED DECEMBER 31, ----------------------------------------- 1996 1997 1998 ----------- ------------ ------------ GROSS NET GROSS NET GROSS NET ----- --- ----- ---- ----- ---- Exploratory Wells Productive.................................. 16 6.0 39 15.7 29 9.3 Nonproductive............................... 4 1.1 23 9.4 24 7.0 -- --- -- ---- -- ---- Total............................... 20 7.1 62 25.1 53 16.3 == === == ==== == ==== Development Wells Productive.................................. -- -- 7 1.8 3 1.0 Nonproductive............................... -- -- 1 0.6 1 -- -- --- -- ---- -- ---- Total............................... -- -- 8 2.4 4 1.0 == === == ==== == ====
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, 1998.
COMPANY OPERATED OTHER TOTAL ------------ ------------ ------------- GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- ----- Oil......................................... 55 53.3 31 10.9 86 64.2 Natural gas................................. 20 11.8 84 26.7 104 38.5 -- ---- --- ---- --- ----- Total............................. 75 65.1 115 37.6 190 102.7 == ==== === ==== === =====
12 15 ACREAGE DATA The following table sets forth certain information regarding the Company's developed and undeveloped lease acreage as of December 31, 1998. 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................... 302 33 5,505 2,393 5,807 2,426 Texas....................... 32,664 11,691 123,643 38,623 156,307 50,314 ------ ------ ------- ------ ------- ------ Total............. 32,966 11,724 129,148 41,016 162,114 52,740 ====== ====== ======= ====== ======= ======
The table does not include 245,009 gross acres (114,362 net) that the Company had a right to acquire pursuant to various seismic option agreements at December 31, 1998. Under the terms of its option agreements, the Company typically has the right for a period of one year, subject to extensions, to exercise its option to lease the acreage at predetermined terms. The Company's lease agreements generally terminate if wells have not been drilled on the acreage within a period of three years. MARKETING The Company's production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply/demand conditions. The Company's marketing objective is to receive the highest possible wellhead price for its product. The Company is aided by the presence of multiple outlets near its production in the Texas and Louisiana Gulf Coast. The Company takes an active role in determining the available pipeline alternatives for each property based upon historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability. There are a variety of factors which affect the market for oil and natural gas, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas production and sales. The Company has not experienced any difficulties in marketing its oil and natural gas. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. The 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 13 16 other factors beyond the Company's control. Domestic oil prices generally follow worldwide oil prices, which are subject to price fluctuations resulting from changes in world supply and demand. The Company continues to evaluate the potential for reducing these risks by entering into, and expects to enter into, additional hedge transactions in future years. In addition, the Company may also close out any portion of hedges that may exist from time to time as determined to be appropriate by management. At December 31, 1998, there were no open hedge positions. Total natural gas purchased and sold under such swap arrangements during the years ended December 31, 1996, 1997 and 1998 were 60,000 MMBtu, 210,000 MMBtu and 1,760,000 MMBTU, respectively. Gains (losses) realized by the Company under such swap arrangements were ($26,887), ($48,000) and $167,000 for the years ended December 31, 1996, 1997 and 1998, respectively. COMPETITION AND TECHNOLOGICAL CHANGES The Company encounters competition from other oil and natural gas companies in all areas of its operations, including the acquisition of exploratory prospects and proven properties. The Company's competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of its competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than those of the Company and which, in many instances, have been engaged in the oil and natural gas business for a much longer time than the Company. Such companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that the Company believes are and will be increasingly important to the current and future success of oil and natural gas companies. The Company's ability to explore for oil and natural gas prospects and to acquire additional properties in the future will be dependent upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company believes that its exploration, drilling and production capabilities and the experience of its management generally enable it to compete effectively. Many of the Company's competitors, however, have financial resources and exploration and development budgets that are substantially greater than those of the Company, which may adversely affect the Company's ability to compete with these companies. The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, the Company may be placed at a competitive disadvantage, and competitive pressures may force the Company to implement such new technologies at substantial cost. In addition, 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 14 17 natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Company is also subject to changing and extensive tax laws, the effects of which cannot be predicted. The following discussion summarizes the regulation of the United States oil and gas industry. The Company believes that it is in substantial compliance with the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject, although there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect the Company's results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject. Regulation of Oil and Natural Gas Exploration and Production. The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and gas industry increases the Company's costs of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. Regulation of Sales and Transportation of Natural Gas. Federal legislation and regulatory controls have historically affected the price of natural gas produced by the Company and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate natural gas sales was substantially modified by the Natural Gas Policy Act, under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas, including all sales by the Company of its own production. As a result, all of the Company's domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts which may be in effect. The FERC's jurisdiction over natural gas transportation was not affected by the Decontrol Act. The Company's natural gas sales are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesaler marketers of gas to the primary role of gas transporters. All gas marketing by the pipelines was required to be divested to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and the individual pipeline restructuring proceedings of the early to mid-1990s, the interstate pipelines are now required to provide open and 15 18 nondiscriminatory transportation and transportation-related services to all producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, the FERC expanded the impact of open access regulations to intrastate commerce. More recently, the FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (i) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies, (ii) further development of rules governing the relationship of the pipelines with their marketing affiliates, (iii) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis, (iv) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market and (v) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. It remains to be seen what effect the FERC's other activities will have on access to markets, the fostering of competition and the cost of doing business. As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. The Company believes these changes generally have improved the Company's access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. The Company cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on the Company's activities. In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation and the promotion of competition in the gas industry. Thus, in addition to "first sale" deregulation, Congress also repealed incremental pricing requirements and gas use restraints previously applicable. There are other legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Company. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on the Company's sales of gas, cannot be predicted. The Company owns certain natural gas pipelines that it believes meet the standards the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both state and federal levels in the post-Order No. 636 environment. Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. The price the Company receives from the sale of these products may be affected by the cost of transporting the products to market. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. The Company is not able at this time to predict the effects of these regulations, if any, on the transportation costs associated with oil production from the Company's oil producing operations. Environmental Regulations. The Company's operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the 16 19 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 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 17 20 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 from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In addition, the Company may be liable for environmental damages caused by previous owners of property purchased and leased by the Company. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of the Company's properties. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks and losses. The Company does not carry business interruption insurance or protect against loss of revenues. There can be no assurance that any insurance obtained by the Company will be adequate to cover any losses or liabilities. The Company cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect the Company's financial condition and operations. The Company may elect to self-insure if management believes that the cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on the financial condition and results of operations of the Company. The Company participates in a substantial percentage of its wells on a nonoperated basis, which may limit the Company's ability to control the risks associated with oil and natural gas operations. 18 21 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, 1998, the Company had 28 full-time employees, including six geoscientists and four engineers. The Company believes that its relationships with its employees are good. In order to optimize prospect generation and development, the Company utilizes the services of independent consultants and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testings, are generally provided by independent contractors. The Company believes that this use of third party service providers has enhanced its ability to contain general and administrative expenses. The Company depends to a large extent on the services of certain key management personnel, the loss of, any of which could have a material adverse effect on the Company's operations. The Company does not maintain key-man life insurance with respect to any of its employees. GLOSSARY OF CERTAIN INDUSTRY TERMS The definitions set forth below shall apply to the indicated terms as used herein. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple. After payout. With respect to an oil or gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bbls/d. Stock tank barrels per day. Bcf. Billion cubic feet. 19 22 Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Before payout. With respect to an oil or gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered. Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. Completion. The installation of permanent equipment for the production of oil or gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. Farm-in or farm-out. An agreement whereunder the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out." Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Finding costs. Costs associated with acquiring and developing proved oil and natural gas reserves which are capitalized by the Company pursuant to generally accepted accounting principles, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing wells. Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. MBbls. One thousand barrels of crude oil or other liquid hydrocarbons. 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, 20 23 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. 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. 21 24 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....................... 42 President and Chief Executive Officer Frank A. Wojtek....................... 43 Chief Financial Officer, Vice President, Secretary and Treasurer George F. Canjar...................... 41 Vice President of Exploration Development Kendall A. Trahan..................... 48 Vice President of Land
Set forth below is a description of the backgrounds of each of the executive officers of the Company: S.P. Johnson IV has served as the President, Chief Executive Officer and a director of the Company since December 1993. Prior to that, he worked 15 years for Shell Oil Company. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado. Frank A. Wojtek has served as the Chief Financial Officer, Vice President, Secretary, Treasurer and a director of the Company since 1993. In addition, from 1992 to 1997, Mr. Wojtek was the Assistant to the Chairman of the Board of Reading & Bates Corporation ("Reading & Bates") (an offshore drilling company). Mr. Wojtek also holds the positions of Vice President and Secretary /Treasurer for Loyd and Associates, Inc. (a private financial consulting and investment banking firm). Mr. Wojtek held the positions of Vice President and Chief Financial Officer of Griffin-Alexander Drilling Company from 1984 to 1987, Treasurer of Chiles-Alexander International Inc. from 1987 to 1989 and Vice President and Chief Financial Officer of India Offshore Inc. from 1989 to 1992, all of which are companies in the offshore drilling industry. Mr. Wojtek is a Certified Public Accountant and holds a B.B.A. in Accounting from the University of Texas. George F. Canjar has been head of the Company's exploration activities since joining the Company in July 1996 and was elected Vice President of Exploration Development in June 1997. Prior thereto he worked for over 15 years for Shell Oil Company and its overseas affiliates where he held various technical and managerial positions, including Technical Manager-Geology & Petrophysics, Section Head Geology & Seismology and Team Leader for numerous integrated production, development, exploration and project 22 25 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 The Company's common stock, par value $0.01 per share (the "Common Stock"), has been publicly traded through the Nasdaq National Market tier of The Nasdaq Stock Market under the symbol CRZO since the Company's initial public offering (the "Offering") effective August 6, 1997. The following table sets forth the quarterly high and low bid prices for each indicated quarter.
QUARTER ENDED HIGH LOW ------------- ---- --- September 30, 1997.......................................... 15 10 15/16 December 31, 1997........................................... 17 1/4 7 7/8 March 31, 1998.............................................. 8 3/4 6 1/16 June 30, 1998............................................... 7 1/2 5 1/2 September 30, 1998.......................................... 5 3/4 2 5/8 December 31, 1998........................................... 3 1/16 1 1/8
There were approximately 60 shareholders of record (excluding brokerage firms and other nominees) of the Company's Common Stock as of March 26, 1999. 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 to pay dividends. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." 23 26 ITEM 6. SELECTED FINANCIAL DATA The financial information of the Company set forth below for each of the five years ended December 31, 1998, has been derived from the audited combined financial statements of the Company. The following table also sets forth certain pro forma income taxes, net income and net income per share information. The information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited financial statements of the Company and the related notes thereto included elsewhere herein.
YEAR ENDED DECEMBER 31, ------------------------------------------------ 1994 1995 1996 1997 1998 ------ ------- ------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA: Oil and natural gas revenues................ $ 596 $ 2,428 $ 5,195 $ 8,712 $ 7,859 Costs and expenses: Oil and natural gas operating expenses.... 518 1,814 2,384 2,334 2,770 Depreciation, depletion and amortization........................... 98 488 1,136 2,358 3,952 Write-down of oil and gas properties...... -- -- -- -- 20,305 General and administrative................ 238 425 515 1,591 2,667 ------ ------- ------- -------- -------- Total costs and expenses.......... 854 2,727 4,035 6,283 29,694 ------ ------- ------- -------- -------- Operating income (loss)..................... (258) (299) 1,160 2,429 (21,835) Interest expense (net of income and amounts capitalized).............................. (7) (192) (80) (98) 285 Other income................................ 6 24 20 -- -- ------ ------- ------- -------- -------- Income (loss) before income taxes........... (259) (467) 1,100 2,331 (21,550) Deferred income taxes(1).................... -- -- -- 2,300 (2,218) ------ ------- ------- -------- -------- Net income (loss)(1)........................ $ (259) $ (467) $ 1,100 $ 31 $(19,332) ====== ======= ======= ======== ======== Basic (loss) earnings per share(1).......... $(0.04) $ (0.07) $ 0.15 $ 0.00 $ (2.15) ====== ======= ======= ======== ======== Diluted (loss) earnings per share(1)........ $(0.04) $ (0.07) $ 0.15 $ 0.00 $ (2.15) ====== ======= ======= ======== ======== Basic weighted average shares outstanding... 6,501 7,021 7,476 8,639 10,375 Diluted weighted average shares outstanding............................... 6,501 7,021 7,545 8,810 10,375 STATEMENTS OF CASH FLOW DATA: Net cash provided by (used in) operating activities................................ $ (258) $ 406 $ 3,325 $ 3,068 $ 2,774 Net cash used in investing activities....... (819) (6,785) (8,221) (28,141) (37,178) Net cash provided by financing activities... 1,183 6,343 6,319 26,255 32,916 OTHER OPERATING DATA: EBITDA (2)(4)............................... $ (158) $ 189 $ 2,296 $ 4,787 $ 2,707 Operating cash flow (3)(4).................. (159) 21 2,236 4,689 2,422 Capital expenditures........................ 819 6,857 9,480 32,234 36,570 Debt repayments(5).......................... -- -- 2,084 20,409 7,950
AS OF DECEMBER 31, ------------------------------------------------ 1994 1995 1996 1997 1998 ------ ------- ------- -------- -------- BALANCE SHEET DATA: Working capital............................. $ 152 $ (265) $(1,025) $ (2,276) $ (5,204) Property and equipment, net................. 803 6,960 15,206 45,083 57,878 Total assets................................ 1,057 7,645 18,869 53,658 64,988 Long-term debt, including current maturities................................ 533 3,480 9,684 7,950 12,056 Mandatorily redeemable preferred stock...... -- -- -- -- 30,731 Equity...................................... 452 3,381 4,596 32,895 11,202
- ---------- (1) On May 16, 1997, Carrizo and a number of affiliated entities were combined with the Company in a series of transactions in connection with its initial public offering (the "Combination Transactions"). Prior to that date, Carrizo and those other entities were not required to pay federal income taxes due to their status as partnerships or Subchapter S corporations. The amounts shown reflect pro forma income 24 27 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 5 to the Company's financial statements. (2) EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization and writedown of oil and gas properties. (3) Operating cash flow represents cash flows from operating activities prior to changes in assets and liabilities. (4) 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 net revenue interests, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), use of proceeds from the Company's initial public offering and the sale of shares of Preferred Stock and the warrants, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement its business strategy, future hiring, future exploration activity and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words "anticipate," "budgeted", "potential" "estimate," "expect," "may," "project," "believe" and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company's dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, risks relating to its limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks and other factors detailed herein and in the Company's other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 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, 70 and 57 wells in 1996, 1997 and 1998 respectively. The Company has budgeted to drill a range of between 18 to 44 gross wells (4.6 to 17.8 net) in 1999; however, in order to drill more than the minimum expected number of wells the Company will need to obtain additional 25 28 financing and the actual number of wells drilled will vary depending upon the Company's ability to obtain this financing, weather delays and other factors. If the Company drills the number of wells it has budgeted for 1999, depreciation, depletion and amortization are expected to decrease and oil and gas operating expenses are expected to increase over levels incurred in 1998. The Company has typically retained the majority of its interests in shallow, normally pressured prospects and sold a portion of its interests in deeper, over-pressured prospects. The financial statements set forth herein are prepared on the basis of a combination of Carrizo and the entities that were a party to the Combination Transactions. Carrizo and the entities combined with it in the Combination Transactions were not required to pay federal income taxes due to their status as partnerships or Subchapter S corporations, which are not subject to federal income taxation. Instead, taxes for such periods were paid by the shareholders and partners of such entities. On May 16, 1997, Carrizo terminated its status as an S corporation and thereafter became subject to federal income taxes. In accordance with SFAS No. 109, "Accounting for Income Taxes," the Company established a deferred tax liability in the second quarter of 1997 resulting in a noncash charge to income of approximately $1.6 million. The Company has primarily grown through the internal development of properties within its exploration project areas, although the Company acquired properties with existing production in the Camp Hill Project in late 1993, the Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company made these acquisitions through the use of limited partnerships with Carrizo or Carrizo Production, Inc. as the general partner. In addition, in November 1998 the Company acquired assets in Wharton County, Texas in the Jones Branch project area for approximately $3,000,000. Prior to the Offering, Carrizo conducted its oil and natural gas operations directly, with industry partners and through the following affiliated entities: Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd. and Placedo Partners Ltd. Concurrently with the closing of the Offering, Combination Transactions were closed. The Combination Transactions consisted of the following: (i) Carrizo Production, Inc. merged into Carrizo; (ii) Carrizo acquired Encinitas Partners Ltd. in two steps: (a) Carrizo acquired the limited partner interests in Encinitas Partners Ltd. held by certain of the Company's directors and (b) Encinitas Partners Ltd. merged into Carrizo; (iii) La Rosa Partners Ltd. merged into Carrizo; and (iv) Carrizo Partners Ltd. merged into Carrizo. As a result of the merger of Carrizo and Carrizo Partners Ltd., Carrizo became the owner of all of the partnership interest in Placedo Partners Ltd. The Company uses the full-cost method of accounting for its oil and gas properties. Under this method, all acquisition, exploration and development costs, including any general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full-cost pool" as incurred. The Company records depletion of its full-cost pool using the unit-of-production method. To the extent that such capitalized costs in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and gas reserves, such excess costs are charged to operations. At December 31, 1998, the Company recorded a full cost ceiling test write down of its oil and natural gas properties of $20.3 million primarily as a result of declines in product pricing and revisions to prior estimates of proved reserves. Once incurred, a write-down of oil and gas properties is not reversible at a later date. Oil and natural gas prices have declined significantly over the last year. Average prices at December 31, 1998 were $10.15 per Bbl for oil and $2.18 per Mcf for natural gas (excluding the effect of hedging). Continued product pricing at these levels or any decrease in pricing could continue to adversely effect the Company, and the Company could be required to make additional charges to earnings related to its oil and gas properties. RESULTS OF OPERATIONS Year Ended December 31, 1998 Compared to the Year Ended December 31, 1997 Oil and natural gas revenues for 1998 decreased 10% to $7.9 million from $8.7 million in 1997. Production volumes for natural gas in 1998 decreased 3% to 2,655.1 MMcf from 2,749.2 MMcf in 1997. 26 29 Average natural gas prices decreased 4% to $2.31 per Mcf in 1998 from $2.41 per Mcf in 1997. Production volumes for oil in 1998 increased 24% to 140 MBbls from 112.5 MBbls in 1997. Average oil prices decreased 34% to $12.30 per barrel in 1998 from $18.66 per barrel in 1997. The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the years ended December 31, 1997 and 1998:
1998 PERIOD COMPARED TO 1997 PERIOD DECEMBER 31, ----------------------- ----------------------- INCREASE % INCREASE 1997 1998 (DECREASE) (DECREASE) ---------- ---------- ---------- ---------- Production volumes Oil and condensate (MBbls)......... 112.5 140 27.5 24% Natural gas (MMcf)................. 2,749.2 2,655.1 (94.1) (3)% Average sales prices (1) Oil and condensate (per Bbl)....... $ 18.66 $ 12.30 $ (6.36) (34)% Natural gas (per Mcf).............. 2.41 2.31 0.10 (4)% Operating revenues Oil and condensate................. $2,099,699 $1,721,162 $(378,537) (18)% Natural gas........................ 6,611,955 6,137,340 (474,615) (7)% ---------- ---------- ---------- Total...................... $8,711,654 $7,858,502 $(853,152) (10)% ========== ========== ==========
- --------------- (1) Including impact of hedging. Oil and natural gas operating expenses for 1998 increased 19% to $2.8 million from $2.3 million in 1997. Oil and natural gas operating expenses increased primarily as a result of the addition of new oil and gas wells drilled and completed since December 31, 1996. Operating expenses per equivalent unit in 1998 increased to $.81 per Mcfe from $.68 per Mcfe in 1997. The per unit cost increased primarily as a result of decreased production of natural gas as wells naturally decline. DD&A expense for 1998 increased 68% to $4.0 million from $2.4 million in 1997. This increase was primarily due to the increased production, additional land, seismic and drilling costs. Primarily as a result of quantity revisions and depressed commodity prices, the Company recorded a write-down of oil and gas properties of $20.3 million in 1998. The Company had not previously been required to record any such write-downs. General and administrative expense for 1998 increased 68% to $2.7 million from $1.6 million for 1997 reflecting ramp-up expenses relating to the hiring of additional technical and administrative staff to handle the Company's increased level of exploration activities and operations as well as other costs related to being a public company. Interest expense for 1998 decreased 94% to $9,000 from $151,000 in 1997. This decrease was primarily due to lower interest expense in 1998 which allowed a larger percentage of the interest to be capitalized. As a result of the adoption of SFAS 109 in the second quarter of 1997, the Company recorded a one-time non-cash charge to income of $1.6 million to establish a deferred tax liability. Dividends and accretion of discount on preferred stock increased to $2.9 million in 1998 from none in 1997 as a result of the sale of preferred stock in the first quarter of 1998. Net income for 1998 decreased to a loss of $22.2 million from income of $31,000 in 1997 as a result of the factors described above. 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 27 30 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. Net income for 1997 decreased to $31,000 from $1.1 million in 1996 as a result of the factors described above. LIQUIDITY AND CAPITAL RESOURCES Note 3 to the Financial Statements notes that the financial statements have been prepared assuming the Company will continue as a going concern but also notes the uncertainties about the Company's future ability to pay its obligations when they become due and the lack of firm commitments for additional capital raised substantial doubt about the ability of the Company to continue as a going concern. As noted in that paragraph, the financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern. See Note 3 to the Notes to the Company's Financial Statements. 28 31 The Company has made and will be required to make oil and gas capital expenditures substantially in excess of its net cash flow from operations in order to complete the exploration and development of its existing properties. The Company will require additional sources of financing to fund drilling expenditures on properties currently owned by the Company and to fund leasehold costs and geological and geophysical cost on its active exploration projects. Management of the Company continues to seek financing for its capital program from a variety of sources. The Company is seeking common or preferred equity investors. The Company is also seeking additional debt financing, although it has no additional borrowings currently available under its credit agreement. No assurance can be given that the Company will be able to obtain additional financing by these or other means on terms that would be acceptable to the Company. The Company's inability to obtain additional financing would have a material adverse effect on the Company. Without raising additional capital, the Company anticipates that it will be required to limit or defer its planned oil and gas exploration and development program, which could adversely affect the recoverability and ultimate value of the Company's oil and gas properties. The Company may also be required to pursue other financial alternatives, which could include sales of assets or a sale or merger of the Company. 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, 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 $3.3 million, $3.1 million and $2.7 million for 1996, 1997 and 1998, respectively. The decrease in cash flows provided by operations in 1997 as compared to 1996 was due primarily to increases in accounts receivable relating to joint interest billings and prepayments on upcoming outside operated drilling projects. The decrease in cash flows provided by operations in 1998 as compared to 1997 was due primarily to decreases in commodity prices. The Company has budgeted capital expenditures in 1999 of approximately $2.2 million to $9.5 million of which $500,000 is expected to be used to fund 3-D seismic surveys and land acquisitions and $1.7 million to $9.0 million of which is expected to be used for drilling activities in the Company's project areas. The Company budgeted to drill approximately 18 to 44 gross wells (4.6 to 17.8 net) in 1999. The actual number of wells drilled and capital expended is dependent upon available financing and cash flow. This decrease in planned drilling activity resulted primarily from the lack of availability of capital resources. 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 $9.1 million, $32.2 and $36.6 million for 1996, 1997 and 1998, respectively. The Company's drilling efforts resulted in the successful completion of 18 gross wells (6.9 net) in 1996, 46 gross wells (17.5 net) in 1997 and 31 gross wells (10.3 net) in 1998. FINANCING ARRANGEMENTS In connection with the Offering, the Company entered into an amended revolving credit agreement 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 is due and payable upon maturity in June 2000 with interest due monthly. The Company Credit Facility was subsequently amended in September 1998 to provide for a term loan under the facility (the "Term Loan") in addition to the revolving credit facility limited by the Company's borrowing base. The Term Loan was initially due and payable upon maturity in September 1999. 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. 29 32 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, 1998, the borrowing base was $6,076,000 and borrowings outstanding were $5,056,000. Proceeds from the Borrowing Base portions of this credit facility have been used to provide funding for exploration and development activity. Substantially all of Carrizo's oil and natural gas property and equipment is pledged as collateral under this facility. At December 31, 1997, and 1998, borrowings under this facility totaled $4,950,000 and $5,056,000, respectively, with an additional $276,000 and $1,020,000, respectively, available for future borrowings. Borrowings outstanding under the Term Loan portion of the facility were zero and $7,000,000 at December 31, 1997 and 1998, respectively. The facility was also available for letters of credit, one of which has been issued for $224,000 at December 31, 1997 and 1998. The weighted average interest rates for 1997 and 1998 on the Facility were 9 and 8 percent, respectively. Outstanding borrowings at December 31, 1997 were repaid with the proceeds of the Company's Preferred Stock sale (see Note 9). The term loan is guaranteed by certain members of the Board of Directors. 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 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 March 1999, the Company Credit Facility was amended to decrease the required specified tangible net worth covenant. 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, which was repaid in January 1998. In March 1999, the Company borrowed an additional $2 million on the term loan portion of the Company Credit Facility increasing the total outstanding borrowing under the Term Loan to $9 million. Certain members of the Board of Directors have guaranteed the Term Loan. The maturity date of the Term Loan was amended to provide for twelve monthly installments of $750,000 beginning January 1, 2000. The Company also received a deferral of principal payments due under the borrowing base facility until July 1, 1999. At such time, the available borrowing base portion of the loan will be reviewed and is expected to begin to reduce ratably at $325,000 per month with any difference between the available borrowing base and amounts outstanding being currently due. Should the Company be able to add sufficient value to its borrowing base through drilling activities, the required principal payments would be reduced. Certain members of the Board of Directors have provided $2 million in collateral primarily in the form of marketable securities to secure the borrowing base facility. In January 1998, the Company consummated the sale of 300,000 shares of Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to affiliates of Enron Corp. The net proceeds received by the Company from this transaction were approximately $28.8 million and were used primarily for oil and natural gas exploration and development activities in Texas and Louisiana and to repay related indebtedness. The Preferred Stock 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 Company expects to continue PIK dividends due in 1999. Dividend payments for the 12 months ended December 31, 1998 were made by the issuance of an additional 27,286.69 shares of Preferred Stock. As of January 15, 1999 there were 32,728.69 shares of Preferred Stock outstanding. 30 33 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 refinancing, but including prepayments (other than in connection with refinancing) 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. If the Company fails to meet its redemption obligations, the holders of the Preferred Stock will generally have the right, voting separately as a class, to elect additional directors, which in most cases will constitute a majority of the board. The Company currently expects that its Cash Flow (as defined above) for the three months ended March 31, 1999 will be less than the amount of the dividends accrued with respect to the Preferred Stock for such period. There can be no assurance as to whether the Company's Cash Flow for the three months ended June 30, 1999 will exceed the amount of the dividends to be accrued with respect to the Preferred Stock. 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. ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY The Company's growth has placed, and is expected to continue to place, a significant strain on the Company's financial, technical, operational and administrative resources. The Company has relied in the past and expects to continue to rely on project partners and independent contractors that have provided the Company with seismic survey planning and management, project and prospect generation, land acquisition, drilling and other services. At December 31, 1998, the Company had 28 full-time employees. There will be additional demands on the Company's financial, technical, operational and administrative resources and continued reliance by the Company on project partners and independent contractors, and these strains on resources, additional demands and continued reliance may negatively affect the Company. The Company's ability to grow will depend upon a number of factors, including its ability to obtain leases or options on properties for 3-D seismic surveys, its ability to acquire additional 3-D seismic data, its ability to identify and acquire new exploratory sites, its ability to develop existing sites, its ability to continue to retain and attract skilled personnel, its ability to maintain or enter into new relationships with project partners and independent contractors, the results of its drilling program, hydrocarbon prices, access to capital and other factors. 31 34 Although the Company intends to continue to upgrade its technical, operational and administrative resources and to increase its ability to provide internally certain of the services previously provided by outside sources, there can be no assurance that it will be successful in doing so or that it will be able to continue to maintain or enter into new relationships with project partners and independent contractors. The failure of the Company to continue to upgrade its technical, operational and administrative resources or the occurrence of unexpected expansion difficulties, including difficulties in recruiting and retaining sufficient numbers of qualified personnel to enable the Company to expand its seismic data acquisition and drilling program, or the reduced availability of project partners and independent contractors that have historically provided the Company seismic survey planning and management, project and prospect generation, land acquisition, drilling and other services, could have a material adverse effect on the Company's business, financial condition and results of operations. In addition, the Company has only limited experience operating and managing field operations, and there can be no assurances that the Company will be successful in doing so. Any increase in the Company's activities as an operator will increase its exposure to operating hazards. See "Business and Properties -- Operating Hazards and Insurance." The Company's lack of capital will also constrain its ability to grow and achieve its business strategy. There can be no assurance that the Company will be successful in achieving growth or any other aspect of its business strategy. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Statement No. 133 is effective for fiscal years beginning after June 15, 1999. A company may also implement the Statement as of the beginning of any fiscal quarter after issuance. Statement No. 133 cannot be applied retroactively. Statement No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 and, at the company's election, before January 1, 1998. The Company routinely enters into financial instrument contracts to hedge price risks associated with the sale of crude oil and natural gas. Statement No. 133 amends, modifies and supercedes significantly all of the authoritative literature governing the accounting for and disclosure of derivative financial instruments and hedging activities. As a result, adoption of Statement No. 133 will impact the accounting for and disclosure of the Company's operations. The Company is assessing the impact Statement No. 133 will have on its financial accounting and disclosures and intends to adopt the provisions of such statement in accordance with the requirements provided by the statement. In June 1997, the Financial Accounting Standards Board issued Statement No. 130, "Reporting Comprehensive Income" ("Statement No. 130") and Statement No. 131, "Disclosures About Segments of an Enterprise and Related Information ("Statement No. 131"). In February 1998, the FASB issued Statement No. 132 "Employers' Disclosure About Pension and Other Post-retirement Benefits" ("Statement No. 132") that revised disclosure requirements for pension and other post-retirement benefits. Statement No. 132 does not impact Carrizo's disclosure or reporting. During the first quarter of 1998, the Accounting Standards Executive Committee of the American Institute of Certified Public Accounts issued two Statements of Position ("SOP"), SOP 98-5 "Reporting on the Costs of Start-up Activities" and SOP 98-1 "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". SOP 98-1 establishes guidance on the accounting for the costs of computer software developed or obtained for internal use. The Company's current accounting policies adhere to the provisions of the SOP. 32 35 SOP 98-5 provides guidance on the accounting for start up costs and organization costs, and must be adopted for fiscal years beginning after December 15, 1998. At adoption, the Company will be required to record the cumulative effect of a change in accounting principle to write off any unamortized start up or organization costs remaining on the balance sheet. The Company plans to adopt the SOP in the first quarter of 1999 and does not expect the adoption to have a material impact on its financial statements or results of operations. VOLATILITY OF OIL AND NATURAL GAS PRICES The Company's revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of its properties, are substantially dependent upon prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices may materially adversely affect the Company's financial condition, liquidity, and ability to finance planned capital expenditures and results of operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that the Company can produce economically. Oil and natural gas prices have declined in the recent past and there can be no assurance that prices will recover or will not decline further. See "Business and Properties -- Marketing." The Company periodically reviews the carrying value of its oil and natural gas properties under the full cost accounting rules of the Commission. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of this ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. The Company may be required to write down the carrying value of its oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. For example, at December 31, 1998, the Company recorded a full cost ceiling test write down of its oil and natural gas properties of $20.3 million because its carrying cost of proved reserves was in excess of the present value of estimated future net revenues from those reserves. If additional write-downs are required, they would result in additional charges to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. In order to reduce its exposure to short-term fluctuations in the price of oil and natural gas, the Company periodically enters into hedging arrangements. The Company's hedging arrangements apply to only a portion of its production and provide only partial price protection against declines in oil and natural gas prices. Such hedging arrangements may expose the Company to risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In addition, the Company's hedging arrangements limit the benefit to the Company of increases in the price of oil and natural gas. Total natural gas purchased and sold under swap arrangements during the years ended December 31, 1996, 1997 and 1998 was 60,000 MMBTU, 210,000 MMBTU and 1,760,000 MMBTU, respectively. Income and (losses) realized by the Company under such swap arrangements were ($26,887), $48,000 and $167,000 for the years ended December 31, 1996, 1997 and 1998, respectively. The Company had outstanding no hedge positions as of December 31, 1998. See "Business and Properties -- Marketing." YEAR 2000 The "Year 2000 Issue" is a general term used to refer to certain business implications of the arrival of the new millennium. In simple terms, on January 1, 2000, all computerized systems that use the two-digit 33 36 convention to identify the applicable year, including both information technology systems and non-information technology systems that use embedded technology, could fail completely or create erroneous data as a result of the system failing to recognize the two digit internal date "00" as representing the year 2000. The Company has completed its initial assessment of Year 2000 compliance of its internal information technology systems, which consist primarily of financial and accounting systems and geological evaluation systems, and does not believe that these systems have any material issues with respect to Year 2000 compliance. The Company's internal information technology systems are all new and widely utilized. Its vendors have advised the Company that all of these systems are either Year 2000 compliant or can be easily upgraded to be Year 2000 compliant. The Company anticipates that its Year 2000 remediation efforts for information technology systems, consisting primarily of software upgrades, will continue through 1999, and anticipates incurring less than $10,000 in connection with these efforts. The Company has not identified any non-information technology systems the use embedded technology on which it relies; however such assessment is expected to continue through 1999. Through communications with industry partners and others, the Company is also evaluating the risk presented by potential Year 2000 non-compliance of third parties. Because such risks vary substantially, companies are being contacted based on the estimated magnitude of the risk posed to the Company by their potential Year 2000 non-compliance. The Company anticipates that these efforts will continue through 1999 and will not result in significant costs to the Company. The Company's assessment of its Year 2000 issues involves many assumptions. There can be no assurance that the Company's assumptions will prove accurate, and actual results could differ significantly from the assumptions. In conducting its Year 2000 compliance efforts, the Company has relied primarily on vendor representations with respect to its internal computerized systems and representations from third parties with which the Company has business relationships and has not independently verified these representations. There can be no assurance that these representations will prove to be accurate. A Year 2000 failure could result in a business disruption that adversely affects the Company's business, financial condition or results of operations. Although it is not currently aware of any likely business disruption, the Company is developing contingency plans to address Year 2000 failures and expects this work to continue through 1999. ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK COMMODITY RISK. The Company's major market risk exposure is the commodity pricing applicable to its oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of such pricing volatility have been discussed above, and such volatility is expected to continue. A 10% fluctuation in the price received for oil and gas production would have an approximate $800,000 impact on the Company's annual revenues and operating income. To mitigate some of this risk, the Company engages periodically in certain limited hedging activities but only to the extent of buying protection price floors. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and were not significant for any year presented. The costs to purchase put options are amortized over the option period. The Company does not hold or issue derivative instruments for trading purposes. Income and (losses) realized by the Company related to these instruments were $(27,000), $48,000 and $167,000 or $(2.22), $4.38 and $10.54 per MMBtu for the years ended December 31, 1996, 1997 and 1998, respectively. INTEREST RATE RISK. The Company's exposure to changes in interest rates results from its floating rate debt. In regards to its Revolving Credit Facility, the result of a 10% fluctuation in short-term interest rates would impact 1999 cash flow by approximately $150,000. FINANCIAL INSTRUMENTS & DEBT MATURITIES. The Company's financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and bank borrowings. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank borrowings approximate the carrying 34 37 amounts as of December 31, 1998 and 1997, and were determined based upon interest rates currently available to the Company for borrowings with similar terms. Current maturities of the debt are $930,000 in 1999 and $11,126,000 in 2000. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The response to this item is included elsewhere in this report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated by reference to information under the caption "Proposal 1-Election of Directors" and to the information under the caption "Section 16(a) Reporting Delinquencies" in the Company's definitive Proxy Statement (the "1999 Proxy Statement") for its 1999 annual meeting of shareholders. The 1999 Proxy Statement will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to December 31, 1998. On February 6, 1999, Roberto Marsella resigned as a member of the Board of Directors of the Company. 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 1999 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1998. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to the 1999 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1998. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The information required by this item is incorporated herein by reference to the 1999 Proxy Statement which will be filed with the Commission not later than 120 days subsequent to December 31, 1998. 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. 35 38 (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 (Incorporated herein by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). +3.2 -- Statement of Resolution Establishing Series of Shares designated 9% Series A Preferred Stock (Incorporated herein by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). +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 (Incorporated herein by reference to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). +4.3 -- Second Amendment to First Amended, Restated, and Combined Loan Agreement between the Company and Compass Bank dated December 30, 1997 (Incorporated herein by reference to Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 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. +4.4 -- Fourth Amendment to First Amended, Restated, and Combined Loan Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank (Incorporated herein by reference to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998). +4.5 -- Limited Guaranty by Douglas A. P. Hamilton for the benefit of Compass Bank (Incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998). +4.6 -- Notice of Final Agreement with respect to a term loan from Compass Bank (Incorporated herein by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998). +4.7 -- Limited Guaranty by Paul B. Loyd, Jr. for the benefit of Compass Bank (Incorporated herein by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998). +4.8 -- Limited Guaranty by Steven A. Webster for the benefit of Compass Bank (Incorporated herein by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998).
36 39 +10.1 -- Incentive Plan of the Company (Incorporated herein by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.2 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.3 -- Employment Agreement between the Company and Frank A. Wojtek (Incorporated herein by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.4 -- Employment Agreement between the Company and Kendall A. Trahan (Incorporated herein by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.5 -- Employment Agreement between the Company and George Canjar (Incorporated herein by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +10.6 -- Indemnification Agreement between the Company and each of its directors and executive officers (Incorporated herein by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). +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). *21.1 -- Subsidiaries of the Company. *23.1 -- Consent of Arthur Andersen LLP. *23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
37 40 *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, 1998. *99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells, Inc. as of December 31, 1998.
- --------------------- + Incorporated by reference as indicated. * Previously filed on March 31, 1999 REPORTS ON FORM 8-K On December 28, 1998, the Company filed a Current Report on Form 8-K (as amended by Form 8-K/A filed on February 23, 1999) to report under Item 2 thereof its acquisition (the "Acquisition") of certain oil and gas producing properties in Wharton County, Texas, along with certain rights to participate in certain exploration prospects (primarily in the Wilcox formation) in Wharton County, Texas and associated rights of access to certain 2-D and 3-D seismic data and related information and certain other related assets (collectively, the "Assets") from Hall-Houston Oil Company, a Texas corporation, Hall-Houston 1996 Exploration and Development Facility Overriding Royalty Trust, a Texas trust, and Hall-Houston Oil Company Employee Royalty Trust, a Texas trust (collectively, "Hall-Houston"). A Statement of Revenues and Direct Operating Expenses for the Oil and Gas Properties of Hall-Houston Oil Company, et al Acquired by Carrizo Oil and Gas Inc. for the year ended December 31, 1997 was included in such Current Report. Such Current Report also included unaudited pro forma statements of operations for the year ended December 31, 1997 and the nine months ended September 30, 1998, and the unaudited pro forma balance sheet as of September 30, 1998 based on the historical financial statements of the Company and the historical statements of revenues and direct operating expenses of the oil and gas properties acquired from Hall-Houston, et al (the "Hall-Houston, et al Properties Acquisition"), adjusted to give effect to the Hall-Houston, et al Properties Acquisition and borrowings under the Company's bank loan. 38 41 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CARRIZO OIL & GAS, INC. By: /s/ FRANK A. WOJTEK ------------------------------------ Frank A. Wojtek Chief Financial Officer, Vice President, Secretary and Treasurer Date: April 14, 1999. 39 42 CARRIZO OIL & GAS, INC. INDEX TO FINANCIAL STATEMENTS
PAGE ---- Carrizo Oil & Gas, Inc. -- Report of Independent Public Accountants.................. F-2 Balance Sheets, December 31, 1997 and 1998................ F-3 Statements of Operations for the Years Ended December 31, 1996, 1997 and 1998.................................... F-4 Statements of Shareholders' Equity for the Years Ended December 31, 1996, 1997 and 1998....................... F-5 Statements of Cash Flows for the Years Ended December 31, 1996, 1997 and 1998.................................... F-6 Notes to Financial Statements............................. F-7
F-1 43 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Carrizo Oil & Gas, Inc.: We have audited the accompanying balance sheets of Carrizo Oil & Gas, Inc. (a Texas corporation) as of December 31, 1997 and 1998, and the related statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1998. 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, 1997 and 1998, and the results of its operations and cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, due principally to depressed oil and gas prices, the Company's operating cash flows have decreased significantly in 1998 and through the first quarter of 1999. The Company projects that, at current commodity price levels, its cash sources will exceed its planned needs for cash in 1999. The Company also has specific plans which involve, among other things, cost reductions, hedging activities to lock in higher prices and the drilling of high probability exploration and development prospects that it believes will generate the necessary borrowing capacity and cash flow to fund its 1999 obligations. There are no assurances, however, that the Company will be able to generate cash flows sufficient to pay all of its 1999 obligations as they become due because of the sensitivity of such cash flow projections to factors such as oil and gas sales price volatility, production levels, operating cost fluctuations, and other variables inherent in the oil and gas industry. The current uncertainties surrounding the sufficiency of its future cash flows and the lack of firm commitments for additional capital raise substantial doubt about the ability of the Company to continue as a going concern. Management's plans in regard to these matters are also described in Note 3. The accompanying financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern. ARTHUR ANDERSEN LLP Houston, Texas March 22, 1999 F-2 44 CARRIZO OIL & GAS, INC. BALANCE SHEETS ASSETS
AS OF DECEMBER 31, -------------------------- 1997 1998 ----------- ------------ CURRENT ASSETS: Cash and cash equivalents................................. $ 2,674,837 $ 1,187,656 Accounts receivable, trade................................ 1,794,175 1,421,964 Accounts receivable, joint interest owners................ 1,841,329 2,805,401 Advances to operators..................................... 1,817,990 1,192,079 Other current assets...................................... 108,633 117,614 ----------- ------------ Total current assets.............................. 8,236,964 6,724,714 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and gas properties)............................... 45,082,833 57,878,191 OTHER ASSETS................................................ 338,638 385,127 ----------- ------------ $53,658,435 $ 64,988,032 =========== ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade................................... $10,433,479 $ 10,003,376 Dividends payable......................................... -- 720,360 Other current liabilities................................. 79,328 275,116 Current maturities of long-term debt...................... -- 930,000 ----------- ------------ Total current liabilities......................... 10,512,807 11,928,852 LONG-TERM DEBT.............................................. 7,950,000 11,126,000 DEFERRED INCOME TAXES....................................... 2,300,267 -- COMMITMENTS AND CONTINGENCIES (Note 7) MANDATORILY REDEEMABLE PREFERRED STOCK (10,000,000 shares authorized with none and 320,110.53 issued and outstanding at December 31, 1997 and 1998, respectively) (Note 9)..... -- 30,730,695 SHAREHOLDERS' EQUITY: Warrants.................................................. -- 300,000 Common stock, $0.01 per share par value, 40,000,000 shares authorized with 10,375,000 issued and outstanding December 31, 1997 and 1998, respectively............... 103,750 103,750 Additional paid in capital................................ 32,845,727 32,845,727 Retained earnings (deficit)............................... 365,690 (21,907,082) Deferred compensation..................................... (419,806) (139,910) ----------- ------------ 32,895,361 11,202,485 ----------- ------------ $53,658,435 $ 64,988,032 =========== ============
The accompanying notes are an integral part of these financial statements. F-3 45 CARRIZO OIL & GAS, INC. STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, -------------------------------------- 1996 1997 1998 ---------- ---------- ------------ OIL AND NATURAL GAS REVENUES........................... $5,194,709 $8,711,654 $ 7,858,502 COSTS AND EXPENSES: Oil and natural gas operating expenses (exclusive of depreciation shown separately below).............. 2,384,145 2,334,009 2,769,595 Depreciation, depletion and amortization............. 1,135,797 2,358,256 3,951,548 Write-down of oil and gas properties................. -- -- 20,305,448 General and administrative........................... 514,644 1,590,358 2,667,234 ---------- ---------- ------------ Total costs and expenses..................... 4,034,586 6,282,623 29,693,825 ---------- ---------- ------------ OPERATING INCOME (LOSS)................................ 1,160,123 2,429,031 (21,835,323) OTHER INCOME AND EXPENSES: Interest income...................................... -- 53,417 293,736 Interest expense..................................... (312,409) (713,999) (300,083) Interest expense, related parties.................... (189,881) (137,067) -- Capitalized interest................................. 422,493 699,625 291,496 Other income......................................... 19,525 -- -- ---------- ---------- ------------ INCOME (LOSS) BEFORE TAXES............................. 1,099,851 2,331,007 (21,550,174) INCOME TAXES........................................... -- 2,300,267 (2,218,027) ---------- ---------- ------------ NET INCOME (LOSS)...................................... $1,099,851 $ 30,740 $(19,332,147) ========== ========== ============ LESS: DIVIDENDS AND ACCRETION ON PREFERRED SHARES...... -- -- 2,940,625 ---------- ---------- ------------ NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS..... $1,099,851 $ 30,740 $(22,272,772) ========== ========== ============ BASIC EARNINGS (LOSS) PER COMMON SHARE (Note 2)........ $ 0.15 $ 0.00 $ (2.15) ========== ========== ============ DILUTED EARNINGS (LOSS) PER COMMON SHARE (Note 2)...... $ 0.15 $ 0.00 $ (2.15) ========== ========== ============ BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (Note 2)................................. 7,475,650 8,638,699 10,375,000 ========== ========== ============ DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (Note 2)................................. 7,545,063 8,809,572 10,375,000 ========== ========== ============
The accompanying notes are an integral part of these financial statements. F-4 46 CARRIZO OIL & GAS, INC. STATEMENTS OF SHAREHOLDERS' EQUITY (NOTES 1 AND 2)
WARRANTS COMMON STOCK ADDITIONAL RETAINED -------------------- --------------------- PAID IN EARNINGS DEFERRED NUMBER AMOUNT SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION --------- -------- ---------- -------- ----------- ------------ ------------ BALANCE, January 1, 1996............. -- $ -- 7,451,300 $ 74,513 $ 4,071,487 $ (764,901) $ -- Net income......................... -- -- -- -- -- 1,099,851 -- Distributions...................... -- -- -- -- (335,000) -- -- Common stock issued to unitholders...................... -- -- 48,700 487 449,513 -- -- --------- -------- ---------- -------- ----------- ------------ --------- BALANCE, December 31, 1996........... -- $ -- 7,500,000 $ 75,000 $ 4,186,000 $ 334,950 $ -- Net income......................... -- -- -- -- -- 30,740 -- Distributions...................... -- -- -- -- (90,000) -- -- Public offering.................... -- -- 2,875,000 28,750 28,050,049 -- -- Deferred compensations related to certain stock options............ -- -- -- -- 699,678 -- (699,678) Amortization of deferred compensation..................... -- -- -- -- -- -- 279,872 --------- -------- ---------- -------- ----------- ------------ --------- BALANCE, December 31, 1997........... -- $ -- 10,375,000 $103,750 $32,845,727 $ 365,690 $(419,806) Net loss........................... -- -- -- -- -- (19,332,147) -- Warrants issued.................... 1,000,000 300,000 -- -- -- -- -- Dividends and accretion on preferred shares................. -- -- -- -- -- (2,940,625) -- Amortization of deferred compensation..................... -- -- -- -- -- -- 279,896 --------- -------- ---------- -------- ----------- ------------ --------- BALANCE, December 31, 1998........... 1,000,000 $300,000 10,375,000 $103,750 $32,845,727 $(21,907,082) $(139,910) ========= ======== ========== ======== =========== ============ ========= SHAREHOLDERS' EQUITY ------------- BALANCE, January 1, 1996............. $ 3,381,099 Net income......................... 1,099,851 Distributions...................... (335,000) Common stock issued to unitholders...................... 450,000 ------------ BALANCE, December 31, 1996........... $ 4,595,950 Net income......................... 30,740 Distributions...................... (90,000) Public offering.................... 28,078,799 Deferred compensations related to certain stock options............ -- Amortization of deferred compensation..................... 279,872 ------------ BALANCE, December 31, 1997........... $ 32,895,361 Net loss........................... (19,332,147) Warrants issued.................... 300,000 Dividends and accretion on preferred shares................. (2,940,625) Amortization of deferred compensation..................... 279,896 ------------ BALANCE, December 31, 1998........... $ 11,202,485 ============
The accompanying notes are an integral part of these financial statements. F-5 47 CARRIZO OIL & GAS, INC. STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, ----------------------------------------- 1996 1997 1998 ----------- ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)................................. $ 1,099,851 $ 30,740 $(19,332,147) Adjustment to reconcile net income (loss) to net cash provided by (used in) operating activities -- Depreciation, depletion and amortization....... 1,135,797 2,358,256 3,951,548 Write-down of oil and gas properties.............. -- -- 20,305,448 Deferred income taxes............................. -- 2,300,267 (2,300,267) Changes in assets and liabilities -- Accounts receivable............................ (1,457,950) (1,819,598) (591,861) Other current assets........................... 322 (93,161) (8,981) Other assets................................... -- -- (249,175) Accounts payable, trade........................ 2,422,257 475,268 803,867 Interest payable to related parties and other current liabilities.......................... 125,164 (183,845) 195,788 ----------- ------------ ------------ Net cash provided by operating activities.............................. 3,325,441 3,067,927 2,774,220 ----------- ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures -- accrual basis............. (9,479,561) (32,234,351) (36,569,773) Adjustment to cash basis.......................... 1,258,132 5,911,784 (1,233,970) Advances to operators............................. -- (1,817,990) 625,911 ----------- ------------ ------------ Net cash used in investing activities..... (8,221,429) (28,140,557) (37,177,832) ----------- ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from sale of common stock............ -- 28,078,799 -- Net proceeds from sale of preferred stock and warrants....................................... -- -- 28,810,431 Proceeds from debt issuance....................... 6,910,000 18,544,454 12,056,000 Debt repayments................................... (2,083,684) (20,408,934) (7,950,000) Proceeds from related party notes payable......... 1,377,739 130,545 -- Capital contributions............................. 450,000 -- -- Capital distributions............................. (335,000) (90,000) -- ----------- ------------ ------------ Net cash provided by financing activities.............................. 6,319,055 26,254,864 32,916,431 ----------- ------------ ------------ NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....................................... 1,423,067 1,182,234 (1,487,181) CASH AND CASH EQUIVALENTS, beginning of year........ 69,536 1,492,603 2,674,837 ----------- ------------ ------------ CASH AND CASH EQUIVALENTS, end of year.............. $ 1,492,603 $ 2,674,837 $ 1,187,656 =========== ============ ============ SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized)................................... $ -- $ 151,441 $ 8,587 =========== ============ ============
The accompanying notes are an integral part of these financial statements. F-6 48 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS, COMBINATION AND OFFERING NATURE OF OPERATIONS Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its affiliates and predecessors, the Company) is an independent energy company engaged in the exploration, development, exploitation and production of oil and natural gas. Its operations are focused on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and Vicksburg trends. The Company has acquired or is in the process of acquiring 1,771 square miles of 3-D seismic data. Additionally, the Company has assembled approximately 407,123 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) consumated on August 11, 1997. The Combination included the following transactions: (a) Carrizo Production, Inc. (a Texas corporation and an affiliated entity with ownership identical to Carrizo) was merged into Carrizo and the outstanding shares of capital stock of Carrizo Production, Inc. were exchanged for an aggregate of 343,000 shares of common stock of Carrizo (the Common Stock); (b) Carrizo acquired Encinitas Partners Ltd. (a Texas limited partnership of which Carrizo Production, Inc. served as the general partner) as follows: Carrizo acquired from the shareholders who serve as directors of Carrizo (the Founders) their limited partner interests in Encinitas Partners Ltd. for an aggregate consideration of 468,533 shares of Common Stock and, on the same date, Encinitas Partners Ltd. was merged into Carrizo and the outstanding limited partner interests in Encinitas Partners Ltd. were exchanged for an aggregate of 860,699 shares of Common Stock; (c) La Rosa Partners Ltd. (a Texas limited partnership of which Carrizo served as the general partner) was merged into Carrizo and the outstanding limited partner interests in La Rosa Partners Ltd. were exchanged for an aggregate of 48,700 shares of Common Stock; and (d) Carrizo Partners Ltd. (a Texas limited partnership of which Carrizo served as the general partner) was merged into Carrizo and the outstanding limited partner interests in Carrizo Partners Ltd. were exchanged for an aggregate of 569,068 shares of Common Stock. The Combination was accounted for as a reorganization of entities as prescribed by Securities and Exchange Commission (SEC) Staff Accounting Bulletin 47 because of the high degree of common ownership among, and the common control of, the combining entities. Accordingly, the accompanying financial statements have been prepared using the historical costs and results of operations of the affiliated entities up to the date of the Combination. There were no significant differences in accounting methods or their application among the combining entities. All intercompany balances have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period's financial statement presentation. INITIAL PUBLIC OFFERING Simultaneous with the Combination, the Company completed its initial public offering (the Offering) of 2,875,000 shares of its common stock at a public offering price of $11.00 per share. The Offering provided the Company with proceeds of approximately $28.1 million, net of expenses. 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. During the years ended December 31, 1997 and 1998, the Company capitalized as oil and natural gas F-7 49 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) properties $279,872 and $279,896, respectively, of deferred compensation related to stock options granted to personnel directly associated with exploration activities. (See Note 8.) 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 1996, 1997 and 1998, was $0.59, $0.69 and $1.06, 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 1996 or 1997. Primarily as a result of downward reserve quantity revisions combined with depressed oil and natural gas prices, the Company recorded a ceiling test write-down of $20,305,448 in 1998. Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years. FINANCING COSTS Long-term debt financing costs included in other assets of $226,247 and $300,005 as of December 31, 1997 and 1998, respectively, are being amortized over the term of the loans (June 1, 2000.) 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 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. Should the necessary correlation between the hedged item and the designated hedging instrument be lost, the gain or loss would no longer be F-8 50 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) deferred and would be recognized in the period the correlation is lost. Total oil and natural gas quantities sold under swap arrangements in 1996, 1997, and 1998 were 3,000 Bbls, 0 Bbls and 0 Bbls, respectively, and 60,000 MMBtu, 210,000 MMBtu, and 1,760,000 MMBtu, respectively. Hedging gains (losses) are included in oil and natural gas revenues and amounted to $(27,000), $48,000 and $167,000 for the years ended December 31, 1996, 1997 and 1998, 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. At December 31, 1998, the Company had no outstanding hedged positions. INCOME TAXES Through May 15, 1997, Carrizo and its affiliated entities had elected to be treated as S Corporations under the Internal Revenue Code or were otherwise not taxed as entities for federal income tax purposes. The taxable income or loss was therefore allocated to the equity owners of Carrizo and the affiliated entities. Accordingly, no provision was made for income taxes in the accompanying historical financial statements for the year ended December 31, 1996. The Company entered into tax indemnification agreements with the founders of the Company pertaining to periods in which the Company was an S Corporation. On May 16, 1997, Carrizo terminated its status as an S corporation and thereafter became subject to federal income taxes. The Company, beginning with the termination of its tax exempt status, provides income taxes for the difference in the tax and financial reporting bases of its assets and liabilities in accordance with Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." The termination of its tax exempt status in 1997 required the Company to establish a deferred tax liability, which resulted in a one-time noncash charge to income in 1997 of $1,623,000. Had Carrizo been a taxpaying entity prior to May 17, 1997, its net income and earnings per share would have been as follows:
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 ========== ========== 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. F-9 51 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) EARNINGS PER SHARE Supplemental earnings per share information is provided below:
FOR THE YEAR ENDED DECEMBER 31 ------------------------------------------------------------------------------------------------- INCOME SHARES PER-SHARE AMOUNT ----------------------------------- ---------------------------------- ---------------------- 1996 1997 1998 1996 1997 1998 1996 1997 1998 ---------- ------- ------------ --------- --------- ---------- ----- ----- ------ Net income (loss)............. $1,099,851 $30,740 $(19,332,147) Less: Dividends and accretion on preferred stock.......... -- -- (2,940,625) ---------- ------- ------------ Basic earnings per Share Net income (loss) available to common shareholders.... 1,099,851 30,740 (22,272,772) 7,475,650 8,638,699 10,375,000 $0.15 $0.00 $(2.15) ===== ===== ====== Stock options................. -- 170,873 -- --------- --------- ---------- Diluted earnings per share Net Income (loss) available to common shareholders plus assumed conversions............... $1,099,851 $30,740 $(22,272,772) 7,475,650 8,809,572 10,375,000 $0.15 $0.00 $(2.15) ========== ======= ============ ========= ========= ========== ===== ===== ======
Net income (loss) per common share has been computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the periods. During the years ended December 31, 1997 and 1998, the Company had outstanding 250,000 and 443,550 stock options, respectively, and warrants to purchase 1,000,000 shares of common stock at December 31, 1998, which were antidilutive and were therefore not included in the calculation because the exercise price of these instruments exceeded the underlying market value of the options and warrants. NEW ACCOUNTING PRONOUNCEMENTS In June 1997, The Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 130 "Reporting Comprehensive Income." This statement requires the reporting of comprehensive income which includes net income plus all other changes in equity during the period not reflected in net income such as the impact of foreign currency translation. This statement is effective for the fiscal year ended December 31, 1998. The Company did not have any items of other comprehensive income for any of the periods presented herein. The FASB has also issued SFAS No. 131 "Disclosures about Segments of an Enterprise and Related Information." This statement requires the reporting of expanded information of a company's operating segments and expands the definition of what constitutes an entity's operating segments. This statement is effective for the year ended December 31, 1998. This statement did not have an impact on the Company's disclosure as the Company has only one reportable operating segment as defined by SFAS 131. 3. GOING CONCERN The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. Due principally to depressed oil and gas prices, the Company's operating cash flows have decreased significantly in 1998 and through the first quarter of 1999. The Company projects that, after considering advances and borrowing base adjustments obtained during the first quarter of 1999, and without further increases in borrowing base capacity under its existing revolving credit facility, debt repayments totaling approximately $1,950,000 will be required in 1999. The Company raised $2 million in additional financing under its existing credit facility in March 1999; however, it is anticipated that these proceeds will be utilized to fund the Company's ongoing drilling program and for working capital. The Company must find additional oil and gas reserves in order to significantly increase the financing available through its existing revolving credit facility. The Company projects that, at current commodity price levels, its cash sources will exceed its planned needs for cash in 1999. Such cash sources include additional borrowings subject to borrowing availability, cash F-10 52 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) flows from currently producing properties along with those nearing completion or pending pipeline hookup and projected net cash flows from wells to be drilled. Cash needs in 1999 include debt requirements, working capital, drilling expenditures, lease bonus payments, geological and geophysical costs on its active exploration projects and cash general and administrative costs. The Company also has specific plans which involve, among other things, cost reductions, hedging activities to lock in higher prices and the drilling of high probability exploration and development prospects that it believes will generate the necessary borrowing capacity and cash flow to fund its 1999 obligations. There are no assurances, however, that the Company will be able to generate cash flows sufficient to pay all of its 1999 obligations as they become due because of the sensitivity of such cash flow projections to factors such as oil and gas sales price volatility, production levels, operating cost fluctuations, and other variables inherent in the oil and gas industry. The current uncertainties surrounding the sufficiency of its future cash flows and the lack of firm commitments for additional capital raise substantial doubt about the ability of the Company to continue as a going concern. The accompanying financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern. As of December 31, 1998, the Company had $37,060,418 of investment in unevaluated properties. In order to fully realize this investment through the exploration and development of these properties, additional capital resources above the amount borrowed in March 1999 and currently available net cash flow from operations will be necessary to fund such capital expenditures. The Company is continuing to seek additional financing from a variety of sources, including new common or preferred equity investors and additional debt financing. No assurance can be given that additional financing will be available by these or other means on terms acceptable to the Company. Without an increase in commodity prices, successful drilling or raising additional capital, the Company anticipates that it will be required to limit or defer its planned oil and gas exploration and development program, which could adversely affect the recoverability and ultimate value of the Company's oil and gas properties. The Company has the ability to control the pace of drilling in projects where it has a 100 percent working interest. In other projects where the Company only has a partial ownership, the Company generally has the right, but not the obligation, to participate for its percentage interest in drilling wells and can decline to participate if it does not have sufficient capital resources at the time such drilling operations commence. The Company may also transfer its right to participate in drilling wells in exchange for cash, a reversionary interest, or some combination thereof or may seek to sell or transfer all or a portion of its interest in undeveloped properties. 4. PROPERTY AND EQUIPMENT At December 31, 1997 and 1998, property and equipment consisted of the following:
DECEMBER 31, -------------------------- 1997 1998 ----------- ------------ Proved oil and natural gas properties..................... $26,994,076 $ 48,390,909 Unproved oil and natural gas properties................... 21,678,368 37,060,418 Other equipment........................................... 225,069 295,854 ----------- ------------ Total property and equipment.................... 48,897,513 85,747,181 Accumulated depreciation, depletion and amortization...... (3,814,680) (27,868,990) ----------- ------------ Property and equipment, net............................... $45,082,833 $ 57,878,191 =========== ============
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 F-11 53 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 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 $37,060,418 of unproved property costs at December 31, 1998 being excluded from the amortizable base, $1,201,873, $13,087,450 and $22,771,095 were incurred in 1996, 1997 and 1998, respectively. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two years. 5. INCOME TAXES Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows:
YEAR ENDED DECEMBER 31, ------------------------ 1997 1998 ---------- ----------- Provision at the statutory tax rate......................... $ 816,852 $(7,542,561) Increase in valuation allowance pertaining to net operating loss...................................................... -- 5,324,534 Increase resulting from change in tax exempt status......... 1,483,415 -- ---------- ----------- Income tax provision (benefit).............................. $2,300,267 $(2,218,027) ========== ===========
Deferred income tax provisions result from temporary differences in the recognition of income and expenses for financial reporting purposes and for tax purposes. At December 31, 1997 and 1998, the tax effects of these temporary differences resulted principally from the following:
YEAR ENDED DECEMBER 31, ------------------------ 1997 1998 ---------- ----------- Deferred income tax asset: Statutory depletion carryforward.......................... $ 78,159 $ 78,159 Write-down of oil and properties.......................... -- 7,106,907 Valuation allowance....................................... -- (5,271,079) ---------- ----------- 78,159 1,913,987 Deferred income tax liabilities: Intangible drilling costs................................. 1,944,634 1,378,171 Capitalized interest...................................... 433,792 535,816 ---------- ----------- 2,378,426 1,913,987 ---------- ----------- Net deferred income tax liability................. $2,300,267 $ -- ========== ===========
F-12 54 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 6. LONG-TERM DEBT: At December 31, 1997 and 1998, notes payable and long-term debt consisted of the following:
YEAR ENDED DECEMBER 31, ------------------------ 1997 1998 ---------- ----------- Bridge loan payable to Compass Bank......................... $3,000,000 $ -- Credit facility Borrowing base facility................................... 4,950,000 5,056,000 Term loan facility........................................ -- 7,000,000 ---------- ----------- 7,950,000 12,056,000 Less: current maturities.................................... -- (930,000) ---------- ----------- $7,950,000 $11,126,000 ========== ===========
In connection with the Offering, Carrizo amended its existing 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 2000 with interest due monthly. The Company Credit Facility was subsequently amended in September 1998 to provide for a term loan under the facility (the "Term Loan") in addition to the revolving credit facility limited by the Company's borrowing base. The Term Loan was initially due and payable upon maturity in September 1999. 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, 1998, the borrowing base was $6,076,000 and borrowings outstanding were $5,056,000. Proceeds from the Borrowing Base portions of this credit facility have been used to provide funding for exploration and development activity. Substantially all of Carrizo's oil and natural gas property and equipment is pledged as collateral under this facility. At December 31, 1997, and 1998, borrowings under this facility totaled $4,950,000 and $5,056,000, respectively, with an additional $276,000 and $1,020,000, respectively, available for future borrowings. Borrowings outstanding under the Term Loan portion of the facility were zero and $7,000,000 at December 31, 1997 and 1998, respectively. The facility was also available for letters of credit, one of which has been issued for $224,000 at December 31, 1997 and 1998. The weighted average interest rates for 1997 and 1998 on the Facility were 9 and 8 percent, respectively. Outstanding borrowings at December 31, 1997 were repaid with the proceeds of the Company's Preferred Stock sale (see Note 9). The term loan is guaranteed by certain members of the Board of Directors. 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 places restrictions on, among other things, (a) incurring additional indebtedness, guaranties, loans and liens, (b) changing the nature of business or business structure, (c) selling assets and (d) paying dividends. In March 1999, the Company Credit Facility was amended to decrease the required specified tangible net worth covenant F-13 55 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 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 paid with proceeds from the Preferred Stock sale. In March 1999, the Company borrowed an additional $2 million on the term loan portion of the Company Credit Facility increasing the total outstanding borrowing under the Term Loan to $9 million. Certain members of the Board of Directors have guaranteed the Term Loan. The maturity date of the Term Loan was amended to provide for twelve monthly installments of $750,000 beginning January 1, 2000. The Company also received a deferral of principal payments due under the borrowing base facility until July 1, 1999. At such time, the available borrowing base portion of the loan will be reviewed and is expected to begin to reduce ratably at $325,000 per month with any difference between the available borrowing base and amounts outstanding being currently due. Should the Company be able to add sufficient value to its borrowing base through drilling activities, the required principal payments would be reduced. Certain members of the Board of Directors have provided $2 million in collateral primarily in the form of marketable securities to secure the borrowing base facility. Estimated maturities of debt at December 31, 1998 are $930,000 in 1999 and $11,126,000 in 2000. 7. 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, 1998, Carrizo was obligated under a noncancelable operating lease for office space. Rent expense for the years ended December 31, 1996, 1997 and 1998, was $14,900, $80,000 and $108,700 respectively. Following is a schedule of the remaining future minimum lease payments under this lease: 1999.............................................. $108,700 2000.............................................. $ 54,350
8. SHAREHOLDERS' EQUITY On June 4, 1997, the board of directors authorized a 521-for-1 split of the Company's common stock and increased the number of authorized shares to 40 million shares of common stock and 10 million shares of preferred stock. All common share amounts presented in these financial statements are presented on a retroactive, post-split basis. 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 F-14 56 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) period in which the options vest, which resulted in $279,872 and $279,896 being recorded in the years ended December 31, 1997 and 1998, respectively. The following table summarizes information for the options outstanding at December 31, 1998:
OPTIONS OUTSTANDING -------------------------------------- OPTIONS EXERCISABLE WEIGHTED ----------------------- NUMBER OF AVERAGE WEIGHTED NUMBER OF WEIGHTED OPTIONS REMAINING AVERAGE OPTIONS AVERAGE OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE RANGE OF EXERCISE PRICES AT 12/31/98 LIFE IN YEARS PRICE AT 12/31/98 PRICE - ------------------------ ----------- ------------- -------- ------------ -------- $ 3.60..................................... 222,120 7.97 $ 3.60 180,473 $ 3.60 $ 6.00-7.00................................ 193,500 9.44 $ 6.20 -- $ -- $11.00..................................... 250,000 8.40 $11.00 83,333 $11.00
In June of 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. ("the Incentive Plan"). The Company accounts for this plan under APB Opinion No. 25, under which no compensation cost has been recognized. Had compensation cost been determined consistent with SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the Company's net income and earnings per share would have been as follows:
1996 1997 1998 ---------- -------- ------------ Net Income (loss) As reported................................... $1,099,851 $ 30,740 $(22,272,772) Pro forma..................................... $1,038,490 $(75,582) $(23,020,534) Diluted earnings (loss) per share As reported................................... $ 0.14 $ -- $ (2.15) Pro forma..................................... $ 0.13 $ (.01) $ (2.22)
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 443,500 shares through December 31, 1998. Under the Incentive Plan, the option exercise price equals the stock market price on the date of grant. Options granted under the plan vest ratably over three years and have a term of ten years. Through December 31, 1998, no stock options have been exercised. A summary of the status of the Company's stock options at December 31, 1996, 1997 and 1998 is presented in the table below:
1996 ------------------------------------- WEIGHTED AVERAGE EXERCISE RANGE OF SHARES PRICES EXERCISE PRICES -------- -------- --------------- Outstanding at beginning of year................... -- -- Granted (Pre-IPO Options).......................... 138,825 $ 3.60 $ 3.60 -------- ------ Outstanding at end of year......................... 138,825 $ 3.60 $ 3.60 ======== ====== Exercisable at end of year......................... 46,275 Weighted average of fair value per share of options granted during year.............................. $ 2.21
F-15 57 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
1997 ------------------------------------- WEIGHTED AVERAGE EXERCISE RANGE OF SHARES PRICES EXERCISE PRICES -------- -------- --------------- Outstanding at beginning of year................... 138,825 $ 3.60 $ 3.60 Granted (Pre-IPO Options).......................... 83,295 $ 3.60 $ 3.60 Granted (Incentive Plan Options)................... 250,000 $11.00 $ 11.00 -------- ------ Outstanding at end of year......................... 472,120 $ 7.52 $3.60-11.00 ======== ====== Exercisable at end of year......................... 120,315 Weighted average of fair value of options granted during the year.................................. $ 6.91
1998 ------------------------------------- WEIGHTED AVERAGE EXERCISE RANGE OF SHARES PRICES EXERCISE PRICES -------- -------- --------------- Outstanding at beginning of year................... 427,120 $ 7.52 $3.60-11.00 Granted (Incentive Plan Options)).................. 193,500 $ 6.20 $6.00- 6.88 -------- ------ Outstanding at end of year......................... 620,620 $ 6.63 $3.60-11.00 ======== ====== Exercisable at end of year......................... 277,688 Weighted average of fair value of options granted during the year.................................. $ 3.05
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 1996, 1997 and 1998: risk free interest rate of 6.82%, 6.26% and 5.81% respectively, expected dividend yield of 0%, expected life of 10 years and expected volatility of 30%, 39.4% and 80.6%, respectively. 9. MANDATORILY REDEEMABLE PREFERRED STOCK In January 1998, the Company consummated the sale of 300,000 share 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 6, above. The remaining proceeds were 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 along with offering costs through the term of the Preferred Stock to the redemption value. 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 F-16 58 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 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 refinancing, but including prepayments (other than in connection with refinancing) 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 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. In the third quarter of 1998, the Company did not meet the Cash Flow test as described above. However, the Company did meet the Cash Flow test during the fourth quarter of 1998. Should the Company be unable to redeem the Preferred Stock, the holders of the Preferred Stock would have the right to elect the majority of the members of the Company's Board of Directors. In 1998, the Company issued preferred stock dividends to the holders of the Preferred Stock of 20,110.53 shares. At December 31, 1998, the redemption value of the existing shares of the Preferred Stock is $33.4 million. The total redemption value as of January 8, 2005 would be $32.0 million. 10. BUSINESS COMBINATION During the fourth quarter of 1998, Carrizo acquired from Hall Houston Oil Company, Hall Houston 1996 Exploration and Development Facility Overriding Trust and Hall Houston Oil Company Employee Royalty Trust (Hall Houston) certain proved oil and gas properties located in Wharton County, Texas (the Hall Houston Properties Acquisition) for approximately $3 million. The Hall Houston Properties Acquisition was accounted for under the purchase method of accounting and, accordingly, the cash price paid was recorded as evaluated oil and gas properties. The results of operations of the acquired Hall-Houston properties are included in the results of operations beginning on the date acquired. The following table reflects certain unaudited pro forma information for the periods presented as if the Hall Houston Properties Acquisition had occurred on January 1, 1997.
YEARS ENDED DECEMBER 31, ---------------------------- 1997 1998 ---------- ------------ Pro forma revenues...................................... $8,718,736 $ 9,198,212 ========== ============ Pro forma net income (loss)............................. $ 33,237 $(18,523,141) ========== ============ Pro forma net income (loss) per share: Basic................................................. $ 0.00 $ (2.07) ========== ============ Diluted............................................... $ 0.00 $ (2.07) ========== ============
F-17 59 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 11. RELATED-PARTY TRANSACTIONS In August 1996, the Company entered into the Master Technical Services Agreement (the MTS Agreement) with Reading & Bates Development Co. (R&B), which is a subsidiary of R&B Falcon Corporation, a company that was created by the merger of Falcon Drilling, Inc. and Reading & Bates Corporation. 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 provided $117,726 and $103,161 in service fees under this agreement in 1996 and 1997, respectively. No services were performed under this agreement in 1998. 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 and $38,113 in 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. As discussed in Note 6, in September, 1998 and March, 1999, certain members of the Board of Directors have guaranteed a portion of the Company's outstanding indebtedness. F-18 60 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 12. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) The following disclosures provide unaudited information required by SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." COSTS INCURRED Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:
YEAR ENDED DECEMBER 31 -------------------------------------- 1996 1997 1998 ---------- ----------- ----------- Property acquisition costs -- Unproved..................................... $ 50,720 $14,222,674 $ 9,618,647 Proved....................................... 1,907,890 5,491,839 16,196,887 Exploration cost............................... 4,724,102 9,328,210 10,429,247 Development costs.............................. 1,955,917 2,257,375 313,391 ---------- ----------- ----------- Total costs incurred(1).............. $8,638,629 $31,300,098 $36,558,172 ========== =========== ===========
- --------------- (1) Excludes capitalized interest on unproved properties of $422,493, $699,625 and $291,496 for the years ended December 31, 1996, 1997 and 1998, respectively. OIL AND NATURAL GAS RESERVES Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities at December 31, 1997 and 1998, 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. F-19 61 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 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, ---------------------------------- 1996 1997 1998 -------- ---------- ---------- Proved developed and undeveloped reserves -- Beginning of year................................ 3,810,000 3,895,000 5,169,500 Purchases of oil and gas properties.............. 12,000 -- 81,000 Discoveries...................................... 180,000 285,000 82,000 Extensions....................................... -- 1,102,000 14,000 Revisions........................................ -- -- (1,559,500) Production....................................... (107,000) (112,500) (140,000) -------- --------- ---------- End of year........................................ 3,895,000 5,169,500 3,647,000 ======== ========= ========== Proved developed reserves at end of year........... 1,048,000 1,146,000 1,112,000 ======== ========= ==========
THOUSANDS OF CUBIC FEET OF NATURAL GAS AT DECEMBER 31, ------------------------------------ 1996 1997 1998 ---------- ---------- ---------- Proved developed and undeveloped reserves -- Beginning of year.............................. 5,437,000 12,148,000 12,142,000 Purchases of oil and gas properties............ 338,000 7,696,000 1,325,000 Discoveries and extensions..................... 7,646,000 6,946,000 4,039,000 Revisions...................................... -- (7,190,000) (4,696,000) Sales of oil and gas properties................ -- (4,709,000) -- Production..................................... (1,273,000) (2,749,000) (2,655,000) ---------- ---------- ---------- End of year...................................... 12,148,000 12,142,000 10,155,000 ========== ========== ========== Proved developed reserves at end of year......... 8,110,000 9,299,000 9,097,000 ========== ========== ==========
STANDARDIZED MEASURE The standardized measure of discounted future net cash flows relating to the Company's ownership interests in proved oil and natural gas reserves as of year-end is shown below:
YEAR ENDED DECEMBER 31 ----------------------------------------- 1996 1997 1998 ------------ ------------ ----------- Future cash inflows......................... $126,155,000 $103,842,000 $59,095,000 Future oil and natural gas operating expenses............................... 47,675,000 55,484,000 28,582,000 Future development costs.................. 9,375,000 13,230,000 4,841,000 Future income tax expenses................ 19,864,000 6,870,000 -- ------------ ------------ ----------- Future net cash flows..................... 49,241,000 28,258,000 25,672,000 10% annual discount for estimating timing of cash flows.......................... 16,220,000 7,285,000 6,917,000 ------------ ------------ ----------- Standardized measure of discounted future net cash flows......................... $ 33,021,000 $ 20,973,000 $18,755,000 ============ ============ ===========
F-20 62 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 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, 1997 and 1998 future cash flows were $20.88, $16.37 and $10.15 for oil, respectively and $3.69, $2.56 and $2.18 for natural gas, respectively. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company's oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. 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, ---------------------------------------- 1996 1997 1998 ----------- ------------ ----------- Changes due to current-year operations -- Sales of oil and natural gas, net of oil and natural gas operating expenses...... $(2,811,000) $ (6,378,000) $(5,089,000) Extensions and discoveries................. 19,641,000 16,074,000 5,003,000 Purchases of oil and gas properties........ 2,079,000 6,954,000 2,889,000 Changes due to revisions in standardized variables -- Prices and operating expenses.............. 9,781,000 (29,115,000) (5,820,000) Income taxes............................... (8,834,000) 11,410,000 5,098,000 Estimated future development costs......... (670,000) (2,683,000) 6,757,000 Quantities................................. -- (3,449,000) (9,056,000) Sales of reserves in place................. -- (3,933,000) -- Accretion of discount...................... 1,647,000 4,634,000 2,607,000 Production rates (timing) and other........ 207,000 (5,562,000) (4,607,000) ----------- ------------ ----------- Net change................................... 21,040,000 (12,048,000) (2,218,000) Beginning of year............................ 11,981,000 33,021,000 20,973,000 ----------- ------------ ----------- End of year.................................. $33,021,000 $ 20,973,000 $18,755,000 =========== ============ ===========
Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pretax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pretax discounted basis, while the accretion of discount is presented on an after-tax basis. F-21 63 CARRIZO OIL & GAS, INC NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH ---------- ---------- ----------- ------------ 1998 Revenues.............................. $2,338,882 $1,848,765 $ 1,508,897 $ 2,161,958 Expenses, net......................... 2,153,347 1,955,539 2,004,086 21,077,677 ---------- ---------- ----------- ------------ Net Income (Loss)..................... $ 185,535 $ (106,774) $ (495,189) $(18,915,719) ========== ========== =========== ============ Dividends and accretion............... 670,494 741,444 756,595 772,091 ---------- ---------- ----------- ------------ Net income (loss) available To Common Shareholders.............. $ (489,959) $ (848,218) $(1,251,784) $(19,687,810) ========== ========== =========== ============ Diluted net income (loss) per share(1)........................ $ (0.05) $ (0.08) $ (0.12) $ (1.90) ========== ========== =========== ============ 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 (loss)..................... 715,616 (1,364,025) 281,437 397,712 ========== ========== =========== ============ Diluted net income (loss) per share(1)............................ $ 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 Statement of Financial Accounting Standards No. 128 "Earnings Per Share." F-22 64 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------- ----------- +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company. +3.2 -- Statement of Resolution Establishing Series of Shares designated 9% Series A Preferred Stock. +3.3 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915). +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.
65
EXHIBIT NUMBER DESCRIPTION ------- ----------- +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). *21.1 -- Subsidiaries of the Company. *23.1 -- Consent of Arthur Andersen LLP. *23.2 -- Consent of Ryder Scott Company Petroleum Engineers. *23.3 -- Consent of Fairchild, Ancell & Wells, Inc. *27.1 -- Financial Data Schedule. *99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 1998. *99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells, Inc. as of December 31, 1998.
- --------------- + Incorporated by reference as indicated. * Previously filed on March 31, 1999 -----END PRIVACY-ENHANCED MESSAGE-----