-----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, Dgs0VwZbqDypku/HNu7S8cSaTLA1BH7Vu8b5mt8k58U5FXUjW75xaRqwiOKYIztN 3DaEAqO6cPEmmJ1Ycpvuqw== 0000890566-96-001991.txt : 19961202 0000890566-96-001991.hdr.sgml : 19961202 ACCESSION NUMBER: 0000890566-96-001991 CONFORMED SUBMISSION TYPE: 424B1 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19961126 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALLON PETROLEUM CO CENTRAL INDEX KEY: 0000928022 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 640844345 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B1 SEC ACT: 1933 Act SEC FILE NUMBER: 333-15501 FILM NUMBER: 96672630 BUSINESS ADDRESS: STREET 1: 200 N CANAL ST CITY: NATCHEZ STATE: MS ZIP: 39120 BUSINESS PHONE: 6014421601 MAIL ADDRESS: STREET 1: 200 N CANAL ST CITY: NATCHEZ STATE: MS ZIP: 39120 FORMER COMPANY: FORMER CONFORMED NAME: CALLON PETROLEUM HOLDING CO DATE OF NAME CHANGE: 19940805 424B1 1 Filed pursuant to rule 424(b)(1); Registration No. 333-15501 PROSPECTUS $21,000,000 [LOGO] CALLON PETROLEUM COMPANY 10% SENIOR SUBORDINATED NOTES DUE 2001 The 10% Senior Subordinated Notes due 2001 ("Notes") are being offered by Callon Petroleum Company, a Delaware corporation ("Company" or "Callon"). The Notes mature on December 15, 2001. Interest on the Notes is payable quarterly on December 15, March 15, June 15 and September 15, commencing March 15, 1997. The Notes will be redeemable at the option of the Company, in whole or in part, on or after December 15, 1997, at 100% of the principal amount thereof, plus accrued interest to the redemption date. The Notes will be general unsecured obligations of the Company, subordinated in right of payment to all existing and future Senior Indebtedness (as defined herein) of the Company. The Notes also will be structurally subordinated to all liabilities of the Company's subsidiaries. As of September 30, 1996, the Company had $8.9 million of Senior Indebtedness and the Company's subsidiaries, excluding guarantees of Senior Indebtedness, had liabilities of $13.0 million. The Notes will be senior to the Company's existing $2.125 Convertible Exchangeable Preferred Stock, Series A ("Series A Preferred Stock") and any 8.5% Convertible Subordinated Debentures due 2010 ("Convertible Debentures") issued in exchange for such Series A Preferred Stock. The Indenture will prohibit the Company's Restricted Subsidiaries (as defined herein) from incurring subordinated indebtedness. See "Description of Notes." The Notes will be represented by a Global Certificate registered in the name of the nominee of The Depository Trust Company, which will act as the Depositary (the "Depositary"). Beneficial interests in the Global Certificate will be shown on, and transfers thereof will be effected only through, records maintained by the Depositary and its participants. Except as described herein, Notes in definitive form will not be issued. See "Description of Notes -- Book Entry Securities." The Company has been advised by the Underwriter that it intends to make a market in the Notes. No assurance can be given, however, that an active trading market for the Notes will develop. The Company has no present intention to have the Notes authorized for quotation on any automated quotation system or listed on any securities exchange. SEE "RISK FACTORS" ON PAGE 8 FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED BY PROSPECTIVE PURCHASERS OF THE NOTES OFFERED HEREBY. THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. ================================================================================ PRICE TO UNDERWRITING PROCEEDS TO PUBLIC(1) DISCOUNT(2) COMPANY(3) - -------------------------------------------------------------------------------- Per Note.. 100% 3.25% 96.75% - -------------------------------------------------------------------------------- Total(4).. $21,000,000 $682,500 $20,317,500 ================================================================================ (1) Plus accrued interest, if any, from November 27, 1996. (2) The Company has agreed to indemnify the Underwriter against certain liabilities, including liabilities under the Securities Act of 1933, as amended. See "Underwriting." (3) Before deducting expenses payable by the Company estimated at $250,000 (4) The Company has granted to the Underwriter an option for 30 days to purchase up to an additional $3.15 million aggregate principal amount of Notes, at the Price to Public, less Underwriting Discount, solely to cover overallotments, if any. If such option is exercised in full, the total Price to Public, Underwriting Discount and Proceeds to Company will be $24,150,000, $784,875, and $23,365,125, respectively. See "Underwriting." ------------------------ The Notes are offered by the Underwriter, subject to prior sale, when, as and if issued to and accepted by it and subject to certain other conditions. The Underwriter reserves the right to withdraw, cancel or modify such offer and to reject orders in whole or in part. It is expected that delivery of the Notes will be made on or about November 27, 1996 through the facilities of The Depository Trust Company in New York, New York. ------------------------ MORGAN KEEGAN & COMPANY, INC. The date of this Prospectus is November 25, 1996 AVAILABLE INFORMATION The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in accordance therewith, files reports and other information with the Securities and Exchange Commission (the "SEC"). Reports, proxy and information statements and other information filed by the Company with the SEC pursuant to the informational requirements of the Exchange Act may be inspected at the public reference facilities maintained by the SEC at 450 Fifth Street, N.W., Judiciary Plaza, Washington, D.C. 20549-1004, and at the following Regional Offices of the SEC: Chicago Regional Office, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511, and New York Regional Office, 7 World Trade Center, New York, New York 10048. Copies of such material may also be obtained from the Public Reference Section of the SEC, 450 Fifth Street, N.W., Washington, D.C. 20549-1004 at prescribed rates. The Registration Statement was filed with the SEC electronically. The SEC maintains a site on the World Wide Web that contains documents filed with the SEC electronically. The address of such site is http://www.sec.gov, and the Registration Statement may be inspected at such site. The Common Stock is traded on the Nasdaq NMS. The Company's registration statements, reports, proxy and information statements, and other information may also be inspected at the National Association of Securities Dealers, Inc., 1735 K Street, N.W., Washington, D.C. 20006. This Prospectus constitutes a part of a Registration Statement on Form S-1 filed by the Company with the SEC under the Securities Act of 1933, as amended (the "Securities Act"). This Prospectus omits certain of the information contained in the Registration Statement, and reference is hereby made to the Registration Statement for further information with respect to the Company and the securities offered hereby. Any statements contained herein concerning the provisions of any document filed as an exhibit to the Registration Statement or otherwise filed with the SEC are not necessarily complete and in each instance reference is made to the copy of such document so filed. Each such statement is qualified in its entirety by such reference. IN CONNECTION WITH THIS OFFERING, THE UNDERWRITER MAY OVERALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE NOTES AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE OVER THE COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. 2 PROSPECTUS SUMMARY THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY, AND SHOULD BE READ IN CONJUNCTION WITH, THE MORE DETAILED INFORMATION AND CONSOLIDATED FINANCIAL STATEMENTS AND THE NOTES THERETO APPEARING ELSEWHERE HEREIN. UNLESS OTHERWISE INDICATED, THE INFORMATION IN THIS PROSPECTUS ASSUMES THAT THE UNDERWRITER'S OVER-ALLOTMENT OPTION WILL NOT BE EXERCISED. REFERENCES TO "CALLON" OR THE "COMPANY" HEREIN INCLUDE CALLON PETROLEUM COMPANY AND ITS PREDECESSORS AND SUBSIDIARIES UNLESS THE CONTEXT OTHERWISE REQUIRES. CERTAIN TERMS RELATING TO THE OIL AND GAS INDUSTRY ARE DEFINED IN "GLOSSARY." THE COMPANY Callon Petroleum Company and its predecessors have been engaged in the acquisition, development, exploration and production of oil and gas since 1950. The Company's properties are geographically concentrated in Louisiana, Alabama and offshore Gulf of Mexico. Callon also manages properties for certain institutional investors. Callon was formed in 1994 through the consolidation of a publicly traded limited partnership, a joint venture with a consortium of European entities and an independent energy company owned by certain members of current management. As of December 31, 1995, the Company had estimated net proved reserves of 58.3 Bcfe with a PV-10 Value of $63.8 million, representing increases of 15% and 54% respectively, from December 31, 1994. The Company's objective is to enhance stockholder value through sustained growth in its reserve base, production levels and resulting cash flows from operations. Over the past two years, the Company has shifted its emphasis from the acquisition of producing properties to the acquisition of acreage with development and exploratory drilling opportunities to further increase potential recoverable reserves. In evaluating drilling opportunities, Callon performs extensive geological and geophysical studies using computer aided exploration techniques ("CAEX"), including, where appropriate, the acquisition of 3-D seismic or high-resolution 2-D seismic data to facilitate these efforts. EXPLORATION AND DEVELOPMENT OPERATIONS. The Company's exploratory and development operations are concentrated in two areas in the Gulf of Mexico, the Shallow Miocene focus area, located in the state waters of Alabama and the federal outer continental shelf in the Gulf of Mexico ("OCS"), and the outer regions of the OCS, at depths of between 13,000 and 18,000 feet ("Deep OCS Prospects"). Wells drilled in the Shallow Miocene focus area seek oil and gas deposits at from 1,800 to 6,000 feet, and are characterized by relatively low exploration and development costs, high initial production rates and short reserve lives. Wells drilled on the Deep OCS Prospects are more expensive to drill and complete. These wells have greater risks, but seek larger oil and gas deposits with longer reserve lives. In 1995 and 1996, the Company acquired an extensive infrastructure of production platforms, gathering systems and pipelines in the Shallow Miocene focus area. During 1996, the Company completed four proprietary high resolution seismic surveys over an eight block area contiguous to Chandeleur Block 40 ("CB 40") in the Shallow Miocene focus area. Based on these surveys, in October and November of 1996, the Company drilled two gross (1.52 net) successful development wells and one gross (1.0 net) successful exploratory well in this area. These wells are expected to be placed on production by the end of November and, coupled with the replacement of compression equipment at the CB 40 and Main Pass Block 163 production facilities, the Company anticipates a significant increase in its gas production rates by year-end 1996. The Company's capital budget currently anticipates drilling an additional five gross (4.0 net) development wells and three gross (0.9 net) exploratory wells during late 1996 and 1997 in this area, for aggregate net cost to drill and complete of $15.3 million. In 1996, the Company joined with Murphy Exploration and Production, Inc. ("Murphy") to acquire 18 blocks in the OCS. Callon owns a 25% working interest in these Deep OCS Prospects. The Company's capital budget for late 1996 and 1997 contemplates drilling eight gross (2.0 net) exploratory wells jointly with Murphy at a total cost to Callon to drill and complete of $11.3 million. The first well commenced drilling in the West Cameron 603 Block in October 1996, and drilling of the second well is scheduled in November 1996. In addition to the wells drilled with Murphy, the Company, as operator, plans to drill an additional two wells in 1997 on Deep OCS Prospects. 3 In total, the Company's current capital budget contemplates the drilling of nine gross (5.9 net) development wells and 12 gross (3.9 net) exploratory wells during late 1996 and 1997 at an estimated net cost to the Company to drill and complete of $34.9 million. These drilling operations will be financed through cash flows from operations, the net proceeds of this Offering and borrowings under the Company's credit facility with a commercial bank ("Credit Facility"). See "Use of Proceeds." PRODUCING PROPERTY ACQUISITIONS. Over the past seven years, the Company has increased its reserves through the acquisition of producing properties that are geologically complex, have (or are analogous to fields with) an established production history from stacked pay zones and are candidates for exploitation. The Company focuses on reducing operating costs and implementing production enhancements through the application of technologically advanced production and recompletion techniques. Between 1989 and September 30, 1996, Callon acquired producing properties in 16 negotiated transactions, on behalf of itself and, in certain cases, its primary institutional investor, for an aggregate net purchase price of $194 million and, during that period, the Company had an average Reserve Replacement Cost of $0.84 per Mcfe. During the nine months ended September 30, 1996, the Company invested a total of $1.0 million and acquired an average 73% working interest (55% net revenue interest) in 12 producing wells, as well as a 100% ownership of one production facility and a 49% ownership in another, both of which are located in its Shallow Miocene focus area. Estimated net proved reserves attributable to these properties, as estimated by the Company's internal reserve engineers as of September 30, 1996, is 10 Bcfe. Through its acquisition program, the Company has assembled an operational and technical database in geographical areas at a low cost to the Company. The relationship with its institutional investors has allowed the Company to pursue larger acquisitions, while the cost sharing arrangements and ongoing management fees have enabled the Company to enhance the rate of return on its properties and to maintain a larger, more experienced team of technical and operating personnel than otherwise would be feasible for a company of its size. SIGNIFICANT PRODUCING PROPERTIES. The following table shows the PV-10 Value and estimated net proved oil and gas reserves by major field for the Company's four largest producing fields and for all other properties combined at December 31, 1995.
ESTIMATED NET PROVED PERCENT ---------------------- PV-10 TOTAL OIL GAS PRIMARY VALUE PV-10 RESERVES RESERVES FIELD NAME/LOCATION OPERATOR(S) ($000) VALUE (MBBLS) (MMCF) - ------------------------------------- ------------- ------- -------- --------- --------- Chandeleur Block 40.................. Callon $16,851 26.4% -- 12,161 Federal Waters Black Bay Complex.................... Callon 10,187 16.0 2,144 684 Louisiana State Waters North Dauphin Island................. Callon 9,749 15.3 -- 6,879 Alabama State Waters Big Escambia Creek Field............. Exxon 9,330 14.6 1,053 2,305 Escambia County, Alabama Other properties..................... Various 17,647 27.7 1,569 7,638 ------- -------- --------- --------- Total........................... $63,764 100.0% 4,766 29,667 ======= ======== ========= =========
4 THE OFFERING Securities Offered...... $21,000,000 aggregate principal amount of 10% Senior Subordinated Notes due 2001, assuming no exercise of the Underwriter's overallotment option to purchase up to $3,150,000 additional aggregate principal amount of Notes. Maturity Date........... December 15, 2001. Interest Payment Dates.. December 15, March 15, June 15 and September 15, commencing March 15, 1997. The first interest payment will represent interest from the date of original issuance through March 15, 1997. Optional Redemption..... The Notes will be redeemable at the Company's option, in whole or in part, on or after December 15, 1997 at 100% of the principal amount plus accrued interest to the date of redemption. See "Description of Notes -- Optional Redemption by Company." Ranking................. The Notes will be unsecured and subordinated in right of payment to all existing and future Senior Indebtedness of the Company. The Notes will also be structurally subordinated to all liabilities of the Company's subsidiaries. On September 30, 1996, the total amount of Senior Indebtedness of the Company was $8.9 million and the total amount of liabilities of the Company's subsidiaries as of September 30, 1996 was $13.0 million excluding guarantees of Senior Indebtedness. The Notes will rank senior to the Company's existing Series A Preferred Stock and any Convertible Debentures that may be issued upon the exchange of such Series A Preferred Stock. The Indenture pursuant to which the Notes will be issued will prohibit the Company's Restricted Subsidiaries from incurring subordinated indebtedness. See "Description of Notes -- Subordination" and "-- Certain Covenants -- Limitation on Indebtedness for Money Borrowed" and "Description of Existing Securities and Debt Instruments." Principal Covenants..... The Indenture will contain covenants restricting the Company's ability to incur additional indebtedness if the ratio of the Company's consolidated Indebtedness for Money Borrowed (as defined) to Consolidated EBITDA (as defined) would exceed 10.0:1 or if the ratio of Consolidated EBITDA to Consolidated Interest Expense (as defined) would be less than 1.1:1. The Indenture will also prohibit restrictions on the payments of dividends by Restricted Subsidiaries and will place limitations on certain liens, restricted payments and transactions with Affiliates and the ranking of future subordinated indebtedness. See "Description of Notes -- Certain Covenants." Sinking Fund............ None. Use of Proceeds......... The Company intends to use the net proceeds from this Offering to fund a portion of its remaining 1996 and its 1997 capital expenditure budget. Pending the use of net proceeds as described herein, the Company will use net proceeds to repay amounts under its Credit Facility, which may be reborrowed at a later date, or invest such net proceeds in short-term liquid investments. Trustee................. American Stock Transfer & Trust Company. RISK FACTORS See "Risk Factors" for a discussion of certain matters that should be considered in evaluating an investment in the Notes. 5 SUMMARY CONSOLIDATED FINANCIAL DATA(1) (IN THOUSANDS, EXCEPT PER SHARE DATA AND RATIOS)
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1996 1995 1995 1994 1993 --------- --------- --------- --------- --------- (UNAUDITED) STATEMENT OF OPERATIONS DATA: Revenues: Oil and gas sales................... $ 18,578 $ 17,400 $ 23,210 $ 13,948 $ 10,048 Interest and other.................. 537 501 627 171 230 --------- --------- --------- --------- --------- Total revenues................. 19,115 17,901 23,837 14,119 10,278 --------- --------- --------- --------- --------- Costs and Expenses: Lease operating expenses............ 5,646 5,201 6,732 4,042 3,713 Depreciation, depletion and amortization...................... 7,697 7,929 10,376 6,049 3,411 General and administrative.......... 2,352 2,960 3,880 3,717 2,350 Interest............................ 184 1,441 1,794 624 196 --------- --------- --------- --------- --------- Total costs and expenses....... 15,879 17,531 22,782 14,432 9,670 --------- --------- --------- --------- --------- Income (loss) from operations......... 3,236 370 1,055 (313) 608 Provision (benefit) for income taxes............................... -- -- -- (200) 113 --------- --------- --------- --------- --------- Income (loss) before cumulative effect of change in accounting principle... 3,236 370 1,055 (113) 495 Cumulative effect of change in accounting principle(2)............. -- -- -- -- 5,262 --------- --------- --------- --------- --------- Net income (loss)..................... 3,236 370 1,055 (113) 5,757 Preferred stock dividends............. 2,097 -- 256 -- -- --------- --------- --------- --------- --------- Net income (loss) available to common shares.............................. $ 1,139 $ 370 $ 799 $ (113) $ 5,757 ========= ========= ========= ========= ========= Net income (loss) per common share: Income (loss) per share before change in accounting principle............. $ .20 $ .06 $ .14 $ (.03) $ .13 ========= ========= ========= ========= ========= Cumulative effect of change in accounting principle................ $ -- $ -- $ -- $ -- $ 1.40 ========= ========= ========= ========= ========= Weighted average common shares outstanding......................... 5,755 5,754 5,755 4,346 3,769 ========= ========= ========= ========= ========= STATEMENT OF CASH FLOWS DATA: Net income (loss)..................... $ 3,236 $ 370 $ 1,055 $ (113) $ 5,757 Depreciation, depletion and amortization........................ 7,913 8,131 10,600 6,328 3,657 Other non-cash items.................. 201 -- 133 (112) (5,114) Net change in assets and liabilities......................... 5,772 233 (2,080) (756) 435 --------- --------- --------- --------- --------- Cash provided by operating activities.......................... 17,122 8,734 9,708 5,347 4,735 ========= ========= ========= ========= ========= Cash provided by (used in) investing activities.......................... (19,874) (16,780) (24,237) (6,423) (2,710) ========= ========= ========= ========= ========= Cash provided by (used in) financing activities.......................... 7,196 3,617 11,509 3,916 (1,695) ========= ========= ========= ========= ========= BALANCE SHEET DATA: Working capital (deficit)............. $ 2,968 $ (7,106) $ 4,712 $ 1,896 $ (687) Oil and gas properties, net........... 68,415 51,890 57,765 43,920 21,000 Total assets.......................... 99,923 76,048 83,867 73,786 39,825 Total debt............................ 8,950 14,868 100 19,234 2,691 Total stockholders' equity............ 76,268 43,801 75,129 43,431 27,170 OTHER FINANCIAL DATA: Capital expenditures, net............. $ 19,874 $ 16,780 $ 24,237 $ 10,412 $ 2,710 EBITDA(3)............................. $ 11,318 $ 9,982 $ 13,582 $ 6,727 $ 4,496 Ratio of earnings to fixed charges(4).......................... 18.6 1.3 1.6 -- 3.6
(FOOTNOTES ON FOLLOWING PAGE) 6 - ------------ (1) The Company succeeded to the business and properties of Callon Petroleum Operating Company ("Callon Petroleum Operating"), Callon Consolidated Partners, L.P. ("CCP") and CN Resources ("CN") on September 16, 1994 (the "Consolidation"). Historical information about the Company prior to September 16, 1994 includes the financial and operating information of the predecessors of the Company, other than the interest in CN not owned by Callon Petroleum Operating, combined as entities under common control in a manner similar to a pooling of interests. See "The Company." (2) Effective January 1, 1993, the Company adopted the provisions of Financial Accounting Standards Board Statement No. 109 "Accounting for Income Taxes," which resulted in the recording of a deferred tax asset of $5,262,000 at December 31, 1993. See Note 3 of the Notes to Consolidated Financial Statements. (3) EBITDA is earnings before interest, taxes, depreciation and amortization. EBITDA is presented because it is a widely accepted financial indication of a company's ability to service and incur debt. EBITDA should not be considered as an alternative to earnings (loss) as an indicator of the Company's operating performance or to cash flow as a measure of liquidity. (4) For purpose of computing this ratio, "earnings" represent income (loss) before income taxes and extraordinary item plus fixed charges. "Fixed charges" consist of interest expense on all indebtedness and that portion of rental expense considered to be representative of the interest factor therein. As a result of the loss incurred for the year ended December 31, 1994 earnings did not cover fixed charges by $313,000. SUMMARY OPERATING AND RESERVE DATA(1)
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1996 1995 1995 1994 1993 --------- --------- --------- --------- --------- PRODUCTION DATA: Oil (MBbls)..................... 451 430 595 364 369 Gas (MMcf)...................... 4,784 5,279 6,694 4,076 1,659 Total production (MMcfe)........ 7,490 7,860 10,261 6,260 3,870 AVERAGE SALES PRICE PER UNIT: Oil (per Bbl)................... $ 18.05 $ 16.68 $ 16.68 $ 15.63 $ 16.73 Gas (per Mcf)................... 2.18 1.88 1.96 2.00 2.10 Total production (per Mcfe)..... 2.48 2.18 2.24 2.21 2.49 OTHER OPERATING DATA: Lease operating expenses/Mcfe... $ 0.56 $ 0.50 $ 0.49 $ 0.49 $ 0.72 Severance taxes/Mcfe............ 0.20 0.16 0.17 0.16 0.24 Capital expenditures (net) (000's)....................... 19,874 16,780 24,237 10,412 2,710
DECEMBER 31, ------------------------------- 1995 1994 1993 --------- --------- --------- RESERVE REPLACEMENT COSTS/Mcfe(2).... $ 1.05 $ 0.97 $ 0.58 ESTIMATED NET PROVED RESERVES: Oil (MBbls)..................... 4,766 4,424 2,842 Gas (MMcf)...................... 29,667 24,102 14,167 Gas equivalent (MMcfe).......... 58,263 50,646 31,219 Estimated future net cash flows, before income taxes (000's)................. $ 95,730 $ 59,477 $ 35,814 PV-10 Value (000's)............. $ 63,764 $ 41,383 $ 22,554 - ------------ (1) The Company succeeded to the business and properties of its predecessor entities on September 16, 1994 pursuant to the Consolidation. Historical data about the Company prior to September 16, 1994 includes the operating data of the Company's predecessors, other than the interest in CN not owned by Callon Petroleum Operating, combined as entities under common control, in a manner similar to a pooling of interests. See "The Company." (2) See "Glossary." 7 RISK FACTORS THIS PROSPECTUS INCLUDES "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF SECTION 27A OF THE SECURITIES ACT AND SECTION 21E OF THE EXCHANGE ACT. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS PROSPECTUS, INCLUDING WITHOUT LIMITATION, STATEMENTS UNDER "PROSPECTUS SUMMARY", "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS", AND "BUSINESS AND PROPERTIES" REGARDING THE COMPANY'S FINANCIAL POSITION, ESTIMATED RESERVE QUANTITIES AND NET PRESENT VALUES OF RESERVES, BUSINESS STRATEGY, PLANS AND OBJECTIVES OF MANAGEMENT OF THE COMPANY FOR FUTURE OPERATIONS AND COVENANT COMPLIANCE, ARE FORWARD-LOOKING STATEMENTS. ALTHOUGH THE COMPANY BELIEVES THAT THE ASSUMPTIONS UPON WHICH SUCH FORWARD-LOOKING STATEMENTS ARE BASED ARE REASONABLE, IT CAN GIVE NO ASSURANCES THAT SUCH ASSUMPTIONS WILL PROVE TO HAVE BEEN CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE COMPANY'S EXPECTATIONS ("CAUTIONARY STATEMENTS") ARE DISCLOSED BELOW AND ELSEWHERE IN THIS PROSPECTUS. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE COMPANY OR PERSONS ACTING ON ITS BEHALF ARE EXPRESSLY QUALIFIED BY THE CAUTIONARY STATEMENTS. PROSPECTIVE PURCHASERS OF THE NOTES OFFERED HEREBY SHOULD CAREFULLY CONSIDER, TOGETHER WITH OTHER INFORMATION IN THIS PROSPECTUS, THE FOLLOWING FACTORS THAT AFFECT THE COMPANY. SIGNIFICANT LEVERAGE AND DEBT SERVICE The Company currently anticipates that it will fund its capital expenditure budget for late 1996 and 1997 substantially with debt. As a result, the Company expects to be more highly leveraged. The Company's level of indebtedness will have several important effects on its future operations, including (i) a substantial portion of the Company's cash flow from operations must be dedicated to the payment of interest on its indebtedness and will not be available for other purposes, (ii) covenants contained in the Company's debt obligations will require the Company to meet certain financial tests, and other restrictions will limit its ability to borrow additional funds or to dispose of assets and may affect the Company's flexibility in planning for, and reacting to, changes in its business, including possible acquisition activities and (iii) the Company's ability to obtain financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired. The Company's ability to meet its debt service obligations and to reduce its total indebtedness will be dependent upon the Company's future performance, which will be subject to general economic conditions and to financial, business and other factors affecting the operations of the Company, many of which are beyond its control. SUBORDINATION The Notes will be subordinated in right of payment to all existing and future Senior Indebtedness of the Company. In the event of bankruptcy, liquidation or reorganization of the Company, the assets of the Company will be available to pay obligations on the Notes only after all Senior Indebtedness has been paid in full, and there may not be sufficient assets remaining to pay amounts due on any or all of the Notes outstanding. The Notes are also structurally subordinated to the obligations of the Company's subsidiaries. The aggregate principal amount of Senior Indebtedness of the Company as of September 30, 1996 would have been $100,000 after giving effect to the sale of the Notes and the use of proceeds as described under "Use of Proceeds," and the indebtedness and accounts payable of the Company's subsidiaries as of September 30, 1996 was $13.0 million, excluding guarantees of Senior Indebtedness. Additional Senior Indebtedness may be incurred by the Company from time to time, subject to certain restrictions, and the Company's subsidiaries may incur obligations which are structurally senior to the Notes. See "Description of Notes -- Subordination." MARKET FOR THE NOTES The Company has no present intention to have the Notes authorized for quotation on any automated quotation system or listed on any securities exchange. Although the Underwriter has advised the Company that it presently intends to make a market in the Notes, the Underwriter may discontinue making a market in the Notes at any time for any reason. Therefore, no assurance can be given that an active trading market for 8 the Notes will develop, or if it develops, that the trading market will continue for any period of time thereafter. VOLATILITY OF OIL AND GAS PRICES The Company's revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas. The Company's ability to maintain or increase its borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent upon oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternate fuel sources. Any substantial and extended decline in the price of oil or gas would have an adverse effect on the Company's carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. RISKS OF EXPLORATION AND DEVELOPMENT The major focus of the Company's operations over the next two years is expected to be the exploration for and development of oil and gas properties, primarily in federal and state waters in the Gulf of Mexico. Exploration and drilling activities are generally considered to be of a higher risk than acquisitions of producing oil and gas properties. Additionally, the Company's wells on its Deep OCS Prospects seek to discover deposits of gas at deep formations, and have more risk than wells seeking to develop hydrocarbons from shallow formations. No assurances can be made that the Company will discover oil and gas in commercial quantities in its exploration and development operations. Expenditure of a material amount of funds in exploration for oil and gas without discovery of commercial quantities of reserves will have a material adverse effect upon the Company. OPERATING HAZARDS, OFFSHORE OPERATIONS AND UNINSURED RISKS Callon's operations are subject to risks inherent in the oil and gas industry, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. These risks could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Moreover, a substantial portion of the Company's operations are offshore and therefore are subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions, to more extensive governmental regulation, including regulations that may, in certain circumstances, impose strict liability for pollution damage, and to interruption or termination of operations by governmental authorities based on environmental or other considerations. The Company maintains insurance of various types to cover its operations, including maritime employer's liability and comprehensive general liability. Amounts in excess of base coverages are provided by primary and excess umbrella liability policies with maximum limits of $50 million. In addition, the Company maintains operator's extra expense coverage, which provides coverage for the control of wells drilled and/or producing and redrilling expenses and pollution coverage for wells out of control. No assurances can be given that Callon will be able to maintain adequate insurance in the future at rates the Company considers reasonable. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect the Company's financial condition and results of operations. 9 ESTIMATES OF OIL AND GAS RESERVES This Prospectus contains estimates of oil and gas reserves, and the future net cash flows attributable to those reserves, prepared by Huddleston & Co., Inc., independent petroleum and geological engineers (the "Reserve Engineers"). There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows attributable to such reserves, including factors beyond the control of the Company and the Reserve Engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and gas prices and expenditures for future development and exploitation activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploitation activities and prices of oil and gas. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and estimates set forth herein. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. In calculating reserves on a Mcfe basis, oil was converted to gas equivalent at the ratio of six Mcf of gas to one Bbl of oil. While this ratio approximates the energy equivalency of gas to oil on a Btu basis, it may not represent the relative prices received by the Company on the sale of its oil and gas production. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to estimated proved reserves set forth in this Prospectus were prepared by the Reserve Engineers in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. ABILITY TO REPLACE RESERVES The Company's future success depends upon its ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. As is generally the case in the Gulf Coast region, many of the Company's producing properties are characterized by a high initial production rate, followed by a steep decline in production. As a result, the Company must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. Without successful exploration or acquisition activities, the Company's reserves and revenues will decline rapidly. No assurances can be given that the Company will be able to find and develop or acquire additional reserves at an acceptable cost. The exploration for oil and gas requires the expenditure of substantial amounts of capital, and there can be no assurances that commercial quantities of oil or gas will be discovered as a result of such activities. The Company's current capital budget contemplates drilling nine gross (5.9 net) development wells and 12 gross (3.9 net) exploratory wells during late 1996 and 1997. The estimated cost, net to the Company, to drill and complete these wells is $34.9 million. The drilling of several unsuccessful wells in this area could have a material adverse effect on the Company and its ability to repay the Notes. In addition, the successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact and their accuracy inherently uncertain. In addition, no assurances can be given that the Company's exploitation and development activities will result in any increases in reserves. The Company's operations may be curtailed, delayed or canceled as a result of lack of adequate capital and other factors, such as title problems, weather, compliance with governmental regulations or price controls, mechanical difficulties or shortages or delays in the delivery of equipment. In addition, the costs of exploration and development may materially exceed initial estimates. SUBSTANTIAL CAPITAL REQUIREMENTS The Company makes, and will continue to make, substantial capital expenditures for the exploitation, exploration, acquisition and production of oil and gas reserves. Historically, the Company has financed these expenditures primarily with cash generated by operations and proceeds from bank borrowings. The 10 Company's capital budget for the last quarter of 1996 and for 1997 is $69.1 million. The Company believes that it will have sufficient cash provided by operating activities, the proceeds of this Offering and borrowings under its Credit Facility to fund such planned capital expenditures. If revenues or the Company's borrowing base decrease as a result of lower oil and gas prices, operating difficulties or declines in reserves, the Company may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." HEDGING OF PRODUCTION Part of the Company's business strategy is to reduce its exposure to the volatility of oil and gas prices by hedging a portion of its production. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." In a typical hedge transaction, the Company will have the right to receive from the counterparty to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, the Company is required to pay the counterparty this difference multiplied by the quantity hedged. The Company is required to pay the difference between the floating price and the fixed price (when the floating price exceeds the fixed price) regardless of whether the Company has sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require the Company to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent the Company from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. COMPETITION The Company operates in the highly competitive areas of oil and gas exploration, development and production. The availability of funds and information relating to a property, the standards established by the Company for the minimum projected return on investment, the availability of alternate fuel sources and the intermediate transportation of gas are factors which affect the Company's ability to compete in the marketplace. The Company's competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines and national and local gas gatherers, many of which possess greater financial and other resources than the Company. See "Business and Properties -- Competition, Markets and Regulation." ENVIRONMENTAL AND OTHER REGULATIONS The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from the Company's operations. Moreover, the recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes" which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations. 11 The Company's operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. The Company could be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on the Company's financial condition and results of operations. The Company maintains insurance coverage for its operations, including limited coverage for sudden environmental damages, but does not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Moreover, the Company does not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages is available at a reasonable cost. Accordingly, the Company may be subject to liability or may lose substantial portions of its properties in the event of certain environmental damages. The Company could incur substantial costs to comply with environmental laws and regulations. The Oil Pollution Act of 1990 imposes a variety of regulations on "responsible parties" related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a material adverse impact on the Company. See "Business and Properties -- Competition, Markets and Regulation." CONTROL OF THE COMPANY, STOCKHOLDERS' AGREEMENT John S. Callon, Fred L. Callon and members of their families (collectively, the "Callon Family") and NOCO Enterprises, L.P., a limited partnership owned by a consortium of European institutional investors ("NOCO"), who collectively and beneficially own over 60% of the outstanding Common Stock have entered into a stockholders' agreement (the "Stockholders' Agreement") pursuant to which members of the Callon Family and NOCO agree (i) to vote for two directors nominated by each party; (ii) not to support certain changes in control without the consent of the other party; and (iii) not to sell Common Stock without first offering it to the other party, except in limited circumstances. As a result of the Stockholders' Agreement, it is expected that the members of the Callon Family and NOCO will be able to control the election of at least four directors of the Company. See "Principal Stockholders -- Stockholders' Agreement." THE COMPANY The Company was formed under Delaware law in 1994 to succeed to the business and properties of Callon Petroleum Operating, an independent energy company owned by members of the Callon Family, Callon Consolidated Partners, L.P., a publicly traded limited partnership ("CCP"), and CN Resources, a joint venture engaged in the oil and gas business ("CN"). The predecessors of Callon Petroleum Operating were formed in 1950 by John S. Callon. Since that time and until September 16, 1994, Callon Petroleum Operating or its predecessors were actively engaged in the oil and gas business. CCP was a publicly traded limited partnership formed in 1987 by the consolidation of oil and gas limited partnerships formed by Callon Petroleum Operating. Callon Petroleum Operating was the sole general partner of CCP. CN was a general partnership formed in April 1992 of which Callon Petroleum Operating and NOCO were the only partners. Effective September 16, 1994, pursuant to the Consolidation, CCP was merged into the Company and the Company acquired all of the capital stock of Callon Petroleum Operating, as well as the partnership interest in CN formerly owned by NOCO ("NOCO Interest"). As a result, the Company has acquired the properties and liabilities of CCP, Callon Petroleum Operating and CN. Because all of the parties to the Consolidation (other than CN) were under common control, the financial statements and operating data of the Company include the financial statements and operating data of CCP and Callon Petroleum Operating, including Callon Petroleum Operating's ownership interest in CN, which were combined in a manner similar to a pooling of interests. The acquisition of the NOCO Interest was recorded as a purchase effective as of the date of the Consolidation (September 16, 1994). Amounts related to the Company's acquisition of 12 the NOCO Interest, therefore, are included from the date of the purchase for the periods presented in the Consolidated Financial Statements. The Company's principal executive office is located at 200 North Canal Street, Natchez, Mississippi 39120, and its telephone number is (601) 442-1601. USE OF PROCEEDS The net proceeds to the Company from the sale of the Notes offered hereby are estimated to be $20.1 million ($23.1 million if the Underwriter's overallotment option is exercised in full). The Company intends to use all of such net proceeds, together with internally generated cash flows and borrowings under its primary credit facility (the "Credit Facility"), to fund a portion of its 1996 capital expenditure budget and a portion of its 1997 capital expenditure budget, estimated to be $69.1 million. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Pending the use of funds to pay capital expenditures, the Company will use the net proceeds of this Offering to repay borrowings under its Credit Facility. To the extent proceeds are in excess of amounts outstanding under the Credit Facility, the Company will invest in short-term investments. As of September 30, 1996, borrowings of $8.9 million were outstanding under the Credit Facility, with a weighted average interest rate of 6.875%. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." 13 CAPITALIZATION The following table sets forth the capitalization of the Company as of September 30, 1996 and as adjusted to give effect to the issuance and sale of the Notes offered by the Company and the application of the net proceeds therefrom as described in "Use of Proceeds." This table should be read in conjunction with the Company's Consolidated Financial Statements, including the Notes thereto, and "Management's Discussion and Analysis of Financial Condition and Results of Operations" found elsewhere in this Prospectus. SEPTEMBER 30, 1996 -------------------------- HISTORICAL AS ADJUSTED ---------- ----------- (IN THOUSANDS) Cash and cash equivalents............... $ 8,709 $19,926 ========== =========== Long-term debt: Credit Facility......................... $ 8,950 $ 100 The Notes offered hereby(1)............. -- 21,000 Stockholders' equity: Preferred Stock, $0.01 par value, 2,500,000 shares authorized; 1,315,500 shares of $2.125 Convertible Exchangeable Preferred Stock, Series A issued and outstanding with a liquidation preference of $32,887,500........................... 13 13 Common Stock, $0.01 par value, 20,000,000 shares authorized; 5,754,863 shares outstanding.......... 58 58 Capital in excess of par value.......... 73,955 73,955 Retained earnings....................... 2,242 2,242 ---------- ----------- Total stockholders' equity.............. 76,268 76,268 ---------- ----------- Total capitalization.................... $ 85,218 $97,368 ========== =========== - ------------ (1) Assumes the Underwriter's overallotment option is not exercised. 14 SELECTED FINANCIAL DATA The following table sets forth, as of the dates and for the periods indicated, selected financial information for the Company. The financial information for each of the four years in the period ended December 31, 1995 have been derived from the audited Consolidated Financial Statements of the Company for such periods. The financial information for the year ended December 31, 1991 has been derived from the audited financial statements of Callon Petroleum Operating and CCP. The financial information for the nine month periods ended September 30, 1996 and 1995 has been derived from the Company's unaudited Consolidated Financial Statements. The information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the Notes thereto. The following information is not necessarily indicative of future results for the Company.
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ----------------------------------------------------- 1996 1995 1995 1994 1993 1992 1991 --------- --------- --------- --------- --------- --------- --------- (UNAUDITED) (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA(1): Revenues: Oil and gas sales.................. $ 18,578 $ 17,400 $ 23,210 $ 13,948 $ 10,048 $ 10,015 $ 10,769 Interest and other................. 537 501 627 171 230 232 167 --------- --------- --------- --------- --------- --------- --------- Total revenues..................... 19,115 17,901 23,837 14,119 10,278 10,247 10,936 --------- --------- --------- --------- --------- --------- --------- Costs and Expenses: Lease operating expenses.............. 5,646 5,201 6,732 4,042 3,713 3,702 3,285 Depreciation, depletion and amortization....................... 7,697 7,929 10,376 6,049 3,411 3,360 3,257 General and administrative............ 2,352 2,960 3,880 3,717 2,350 1,848 2,312 Interest.............................. 184 1,441 1,794 624 196 160 321 --------- --------- --------- --------- --------- --------- --------- Total costs and expenses........... 15,879 17,531 22,782 14,432 9,670 9,070 9,175 --------- --------- --------- --------- --------- --------- --------- Income (loss) from operations......... 3,236 370 1,055 (313) 608 1,177 1,761 Provision (benefit) for income taxes.............................. -- -- -- (200) 113 235 297 --------- --------- --------- --------- --------- --------- --------- Income (loss) before cumulative effect of change in accounting principle..... 3,236 370 1,055 (113) 495 942 1,464 Cumulative effect of change in accounting principle(2)............... -- -- -- -- 5,262 -- -- --------- --------- --------- --------- --------- --------- --------- Net income (loss)....................... 3,236 370 1,055 (113) 5,757 942 1,464 Preferred stock dividends............... 2,097 -- 256 -- -- -- -- --------- --------- --------- --------- --------- --------- --------- Net income (loss) available to common shares................................ 1,139 370 799 (113) 5,757 942 1,464 Pro forma adjustment (unaudited): Provision for income taxes(2)........... -- -- -- -- 100 145 302 --------- --------- --------- --------- --------- --------- --------- Pro forma net income (loss)............. $ 1,139 $ 370 $ 799 $ (113) $ 5,657 $ 797 $ 1,162 ========= ========= ========= ========= ========= ========= ========= Net income (loss) per common share: Income (loss) per share before accounting principle change........... $ .20 $ .06 $ .14 $ (.03) $ .13 $ .25 $ .39 ========= ========= ========= ========= ========= ========= ========= Cumulative effect of accounting change................................ $ -- $ -- $ -- $ -- $ 1.40 $ -- $ -- ========= ========= ========= ========= ========= ========= ========= Pro forma............................... $ .20 $ .06 $ .14 $ (.03) $ 1.50 $ .21 $ .31 ========= ========= ========= ========= ========= ========= ========= Weighted average common shares outstanding........................... 5,755 5,754 5,755 4,346 3,769 3,769 3,769 ========= ========= ========= ========= ========= ========= =========
15
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ----------------------------------------------------- 1996 1995 1995 1994 1993 1992 1991 --------- --------- --------- --------- --------- --------- --------- (UNAUDITED) (IN THOUSANDS, EXCEPT RATIOS) STATEMENT OF CASH FLOWS DATA(1): Net income (loss)....................... $ 3,236 $ 370 $ 1,055 $ (113) $ 5,757 $ 942 $ 1,464 Depreciation, depletion and amortization.......................... 7,913 8,131 10,600 6,328 3,657 3,577 3,445 Other non-cash items.................... 201 -- 133 (112) (5,114) 270 331 Net change in assets and liabilities.... 5,772 233 (2,080) (756) 435 (2,758) 2,299 --------- --------- --------- --------- --------- --------- --------- Cash provided by operating activities... 17,122 8,734 9,708 5,347 4,735 2,031 7,539 ========= ========= ========= ========= ========= ========= ========= Cash provided by (used in) investing activities............................ (19,874) (16,780) (24,237) (6,423) (2,710) (3,817) (1,929) ========= ========= ========= ========= ========= ========= ========= Cash provided by (used in) financing activities............................ 7,196 3,617 11,509 3,916 (1,695) 233 (3,826) ========= ========= ========= ========= ========= ========= ========= BALANCE SHEET DATA(1): Working capital (deficit)............... $ 2,968 $ (7,106) $ 4,712 $ 1,896 $ (687) $ (1,011) $ (289) Oil and gas properties, net............. 68,415 51,890 57,765 43,920 21,000 22,138 22,060 Total assets............................ 99,923 76,048 83,867 73,786 39,825 35,570 36,937 Total debt.............................. 8,950 14,868 100 19,234 2,691 2,975 1,209 Total stockholders' equity.............. 76,268 43,801 75,129 43,431 27,170 22,711 23,067 OTHER FINANCIAL DATA(1): Capital expenditures, net............... $ 19,874 $ 16,780 $ 24,237 $ 10,412 $ 2,710 $ 3,817 $ 1,929 EBITDA(3)............................... $ 11,318 $ 9,982 $ 13,582 $ 6,727 $ 4,496 $ 4,949 $ 5,561 Ratio of earnings to fixed charges(4)... 18.6 1.3 1.6 -- 3.6 6.6 5.4
- ------------ (1) The Company succeeded to the business and properties of Callon Petroleum Operating, CCP and CN on September 16, 1994 pursuant to the Consolidation. Historical information about the Company prior to September 16, 1994 includes the financial and operating information of the predecessors of the Company, other than the interest in CN not owned by Callon Petroleum Operating, combined as entities under common control in a manner similar to a pooling of interests. See "The Company." (2) Effective January 1, 1993, the Company adopted the provisions of Financial Accounting Standards Board Statement No. 109 "Accounting for Income Taxes" which resulted in the recording of a deferred tax asset of $5,262,000 at December 31, 1993. See Note 3 of the Notes to Consolidated Financial Statements. (3) EBITDA is presented because it is a widely accepted financial indication of a company's ability to service and incur debt. EBITDA should not be considered as an alternative to earnings (loss) as an indicator of the Company's operating performance or to cash flow as a measure of liquidity. (4) For purpose of computing this ratio, "earnings" represent income (loss) before income taxes and extraordinary item plus fixed charges. "Fixed charges" consist of interest expense on all indebtedness and that portion of rental expense considered to be representative of the interest factor therein. As a result of the loss incurred for the year ended December 31, 1994, earnings did not cover fixed charges by $313,000. 16 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL The Company's revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas. The Company's ability to maintain or increase its borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent upon oil and gas prices. Prices for oil and gas are subject to large fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternate fuel sources. Any substantial and extended decline in the price of oil or gas would have an adverse effect on the Company's carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. The Company uses the full cost method of accounting for the Company's investment in oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas reserves are capitalized into a "full cost pool." Oil and gas properties in the pool, plus estimated future expenditures to develop proved reserves and future abandonment, site remediation and dismantlement costs, are depleted and charged to operations using the unit of production method based on the ratio of current production to total estimated proved recoverable oil and gas reserves. To the extent that such capitalized costs (net of depreciation, depletion and amortization) exceed the discounted future net cash flows on an after-tax basis of estimated proved oil and gas reserves, such excess costs are charged to operations. Once incurred, the writedown of oil and gas properties is not reversible at a later date even if oil or natural gas prices increase. RESULTS OF OPERATIONS The following table sets forth selected operating data for the Company for the periods and upon the basis indicated.
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1996 1995 1995 1994 1993 --------- --------- --------- --------- --------- Production: Oil (MBbls)........................ 451 430 595 364 369 Gas (MMcf)......................... 4,784 5,279 6,694 4,076 1,659 Total production (MMcfe)........... 7,490 7,860 10,261 6,260 3,870 Average Sales Price: Oil (per Bbl)...................... $ 18.05 $ 16.68 $ 16.68 $ 15.63 $ 16.73 Gas (per Mcf)...................... 2.18 1.88 1.96 2.00 2.10 Total production (per Mcfe)........ 2.48 2.18 2.24 2.21 2.49 Average Costs (per Mcfe): Lease operating expenses (excluding severance taxes)................. $ 0.56 $ 0.50 $ 0.49 $ 0.49 $ 0.72 Severance taxes.................... 0.20 0.16 0.17 0.16 0.24 Depreciation, depletion and amortization..................... 1.03 1.01 1.01 0.97 0.88 General and administrative (net of management fees)................. 0.31 0.38 0.38 0.59 0.61
17 The following table sets forth selected production data for the Company for the periods and upon the basis indicated.
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1996 1995 1995 1994 1993 --------- --------- --------- --------- --------- (MMCFE) (MMCFE) Production attributable to: Chandeleur Block 40................ 1,158 104 144 37 -- Black Bay Complex.................. 912 1,020 1,351 608 252 North Dauphin Island Field......... 2,514 4,074 5,102 2,524 162 Escambia Minerals properties....... 1,084 399 783 -- -- --------- --------- --------- --------- --------- 5,668 5,597 7,380 3,169 414 Other properties................... 1,822 2,262 2,881 3,091 3,456 --------- --------- --------- --------- --------- Total......................... 7,490 7,859 10,261 6,260 3,870 ========= ========= ========= ========= =========
NINE MONTHS ENDED SEPTEMBER 30, 1996 COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 1995 For the nine months ended September 30, 1996, total oil and gas revenues increased by $1.2 million, or 7%, to $18.6 million when compared to $17.4 million for the same period in 1995. This increase is principally the result of increased sales prices in both oil and gas. For the nine months ended September 30, 1996, oil production and revenues increased to 451 MBbls and $8.1 million, respectively. For the comparable period in 1995, oil production was 430 MBbls while revenues totaled $7.2 million. Oil prices during the first nine months of 1996 averaged $18.05, compared to $16.68 for the same period in 1995. Total oil revenues have increased 13% over the September 1995 level as a result of this price increase and increased production from the Escambia Minerals properties. Gas production and revenue for the nine-month period ended September 30, 1996, was 4.8 Bcf and $10.4 million, respectively, compaired with gas production of 5.3 Bcf and gas revenues of $9.9 million in the first nine months of 1995. The average sales price for natural gas sold in the first nine months in 1996 was $2.18 per Mcf, a $0.30 per Mcf increase over the average price for the same period in 1995. Revenues gained from the price increase, coupled with the decreased production, resulted in a net 5% increase in total gas revenues. Included in gas production and revenue for the nine month period ended September 30, 1996 is 526 MMcf and $996,000, respectively, representing production from October 1993 to September 1996 attributed to a disputed interest in a lease which was resolved in the Company's favor during August 1996. The following table summarizes oil and gas production from the Company's major producing properties for the comparable periods.
OIL PRODUCTION (BBLS) GAS PRODUCTION (MCF) -------------------- ------------------------ NINE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------- ------------------------ 1996 1995 1996 1995 --------- --------- ----------- ----------- Chandeleur Block 40.................. -- -- 1,158,000 104,000 Black Bay Complex.................... 152,000 169,000 -- 6,000 North Dauphin Island Field........... -- -- 2,514,000 4,074,000 Escambia Minerals properties......... 144,000 53,000 220,000 81,000 Other properties..................... 155,000 208,000 892,000 1,014,000 --------- --------- ----------- ----------- Total........................... 451,000 430,000 4,784,000 5,279,000 ========= ========= =========== ===========
Lease operating expenses, excluding severance taxes, for the first nine months of 1996 increased by 5% to $4.2 million from $3.9 million for the 1995 comparable period. This increase is primarily attributable to a corresponding increase in oil production resulting from the Company's acquisition of the Escambia Minerals properties acquired subsequent to June 1995. Severance taxes increased by 18% to $1.5 million during the first nine months of 1996 from $1.3 million for the same period in 1995, primarily as a result of higher prices for oil and gas. 18 Depreciation, depletion and amortization for the first nine months of 1996 was $7.7 million, or $1.03 per Mcfe. For the same period in 1995, the total was $7.9 million and $1.01 per Mcfe. During the first nine months of 1996, general and administrative expenses declined by 21% to $2.4 million, compared to $3.0 million for the same period in 1995. This reduction is associated with continued overall improvements in operational efficiencies and reduced executive incentive compensation payments. Interest expense as of September 30, 1996 was $184,000 compared to $1.4 million for the same period in 1995. This expense reduction is attributable to the reduction in the Company's debt using the proceeds from the sale of Series A Preferred Stock in November 1995. YEAR ENDED DECEMBER 31, 1995 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1994 Oil and gas sales increased $9.3 million, or 66%, during 1995 to $23.2 million compared with $13.9 million in 1994. This increase is partially attributable to the Company's purchase in September 1994 of NOCO's interest in CN pursuant to the Consolidation as well as the acquisition of certain properties from W&T Offshore, Inc. (the "1994 Properties"). The Company's purchase of the Escambia Minerals properties in June 1995 also contributed $1.9 million to the increase in oil and gas sales. Oil production attributable to the NOCO Interest, the Escambia Minerals properties and the 1994 Properties substantially outweighed normal production declines in previously existing properties, as oil production for 1995 increased to 594 MBbls from the 1994 level of 364 MBbls. The average price per barrel sold also increased by $1.05 in 1995 compared to 1994 prices, resulting in a total of $4.3 million increase in oil revenues. Total gas production increased 2.6 Bcf to 6.7 Bcf in 1995 compared to 4.1 Bcf in 1994. A substantial portion of this increase in production was attributable to the Company's acquisition of the North Dauphin Island Field. Gas production from the North Dauphin Island Field increased from 2.5 Bcf in 1994 to 5.1 Bcf in 1995 and added $5.0 million in revenues in 1995 compared with 1994. Although spot market gas prices declined in 1995, gas price hedges limited the effect of the decline to $.04 per Mcf. Lease operating expenses, including production taxes, increased 67% during 1995 to $6.7 million, compared to $4.0 million for 1994. This increase was largely attributable to the corresponding increase in oil and gas production caused by the Company's acquisition of the NOCO Interest, the Escambia Minerals properties and the 1994 Properties. The Company's purchase of the NOCO Interest in September 1994 resulted in an increase in combined lease operating expenses attributable to the North Dauphin Island Field and the Black Bay Complex from $1.5 million in 1994 to $3.6 million in 1995. Lease operating expenses on a Mcfe basis increased by less than 2% to $0.66 for 1995 compared to $0.65 for 1994. Total depreciation, depletion and amortization expense was $10.4 million for 1995, compared to $6.0 million for 1994. This increase reflects additional production and reserves resulting from the purchase of the NOCO Interest, the Escambia Minerals properties and the 1994 Properties. General and administrative expenses were $3.9 million for 1995, compared to $3.7 million in 1994. The increase was primarily attributable to the Company's expanding operations. The Company had a zero effective tax rate for 1995, compared to an effective rate of (63)% in 1994. The 1995 rate was primarily due to a reduction in the deferred tax asset valuation allowance of $551,000. The valuation allowance was reduced during 1995 due to a reduction in the gross deferred tax asset. This valuation allowance represents the portion of federal net operating loss carryforward and other temporary differences which the Company believes will not be utilized. YEAR ENDED DECEMBER 31, 1994 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1993 Oil production for 1994 decreased 5 MBbls from the 1993 level of 369 MBbls. In addition, the average price per barrel sold in 1994 declined by $1.10 when compared to the average price received in 1993. As a result, total oil revenue declined by $475,000 (including $100,000 related to unfavorable hedging activities during 1994). Normal production declines for several of the Company's major oil fields, primarily the Lockhart Crossing Field and several Arkansas fields, were partially offset by the Company's purchase of a 4.9% average net revenue interest in the West Delta 30 Field and NOCO's interest in CN, which owned a 19 9.5% average net revenue interest in the Black Bay Complex. Average daily oil production, net to the Company, declined to 998 Bbls/d during 1994 compared to 1,011 Bbls/d for 1993. Due to the Company's purchase of a 9.4% working interest in the North Dauphin Island Field during the fourth quarter of 1993, the Company's purchase of the NOCO Interest (which included a working interest in the North Dauphin Island Field) and the acquisition of the 1994 Properties in late September 1994, gas production increased 146% to 4.1 Bcf for 1994, from 1.7 Bcf for 1993. The production increase, offset by only a $0.10 per Mcf average price decline, resulted in a $4.7 million increase in gas revenues. This increase in revenue includes approximately $1.3 million attributable to hedging activities. Average daily gas production increased to 11.2 MMcf/d for 1994 compared to 4.5 MMcf/d for 1993. This favorable impact on production of the North Dauphin Island Field acquisition was partially offset by normal production declines for certain other major gas fields and the sale during the second half of 1993 of the Company's interest in three gas fields. Lease operating expenses, including production taxes, increased 9% during 1994 to $4.0 million, compared to $3.7 million for 1993. Of this increase, $800,000 was attributable to the Company's purchase of the NOCO Interest and the 1994 Properties. The increase was partially offset by a decline of $400,000 in expenses associated with various Arkansas oil fields, and the Lockhart Crossing, Padgitt and Main Pass Block 35 Fields. The sale of the Company's interest in three oil and gas fields during 1993 accounted for an additional $100,000 decrease. The 146% increase in gas production volumes for 1994 resulting from the Company's acquisition of the NOCO Interest, and the low operating costs for this field, resulted in a decline in lease operating expenses, on a Mcfe basis, to $0.65 for 1994, compared to $0.96 for 1993. Total depreciation, depletion and amortization expense was $6.0 million for 1994 compared to $3.4 million for 1993 and reflects a $2.6 million increase due to the acquisition of an interest in the North Dauphin Island Field in the fourth quarter of 1993, and the acquisition of the 1994 Properties and the NOCO Interest in the third quarter of 1994. On a Mcfe basis, depreciation, depletion and amortization expense increased to $0.97 in 1994 compared to $0.88 for 1993. General and administrative expenses increased during 1994 to $3.7 million compared to $2.4 million for 1993. An increase of $600,000 was due to professional fees incurred in connection with the Consolidation. The balance of the increase was attributable to increased staffing levels required to conduct the Company's expanding operations. Interest expense increased from $196,000 for 1993 to $624,000 for 1994. This increase was primarily attributable to the $19.0 million of bank debt assumed in the Consolidation. LIQUIDITY AND CAPITAL RESOURCES CAPITAL SOURCES The Company's primary sources of capital are its cash flows from operations, borrowings from commercial lenders and sales of its securities. For the year ended December 31, 1995, the Company's cash flows from operations were $9.7 million, and it borrowed $6.0 million, net of repayments, under its Credit Facility. In addition, in November, 1995, the Company sold 1,315,500 shares of Series A Preferred Stock, generating approximately $30.9 million after underwriters' discount and expense. The Company used approximately $21.5 million of the net proceeds from the sale of the Series A Preferred Stock to reduce outstanding bank indebtedness. During the nine months ended September 30, 1996, the Company had cash flows from operations of $17.1 million, borrowed $8.9 million under its Credit Facility, had net capital expenditures of $19.9 million and paid $1.7 million in dividends on the Series A Preferred Stock. The balance of the cash flow was retained for future operating expenses and potential drilling and acquisition opportunities. Effective October 31, 1996, the Company amended and restated its Credit Facility. Borrowings under the Credit Facility are secured by mortgages covering substantially all of the Company's producing oil and gas properties. The Credit Facility provides for borrowings of a maximum of the lesser of $50 million and a borrowing base ("Borrowing Base") determined periodically on the basis of a discounted present value of 20 future net cash flows attributable to the Company's proved producing oil and gas reserves. Through May 15, 1997, the Credit Facility provides a $30 million Borrowing Base. Pursuant to the Credit Facility, depending upon the percentage of the unused portion of the Borrowing Base, the interest rate is equal to either the lender's prime rate or the lender's prime rate plus 0.50%. The Company, at its option, may fix the interest rate on all or a portion of the outstanding principal balance at either 1.00% or 1.375% above a defined "Eurodollar" rate, depending upon the percentage of the unused portion of the Borrowing Base, for periods of up to six months. The weighted average interest rate for the total debt outstanding at November 5, 1996 was 6.375%. Under the Credit Facility, a commitment fee of .25% or .375% per annum on the unused portion of the Borrowing Base (depending upon the percentage of the unused portion of the Borrowing Base) is payable quarterly. The Company may borrow, pay, reborrow and repay under the Credit Facility until October 31, 2000, on which date, the Company must repay in full all amounts then outstanding. Callon's relationship with an institutional investor has historically been important to its producing property acquisition strategy. Under this arrangement, the Company transferred a non-operated interest in acquired properties to the institutional investor in exchange for a portion of the purchase price of the property. The Company believes its relationship with this institutional investor has allowed it to make larger acquisitions than would otherwise be possible. Since 1989, this institutional investor has invested $130.0 million in property acquisitions made by the Company. In addition, fees received by the Company from operating and managing properties owned by institutional investors and others enable the Company to maintain a larger and more experienced staff. The Company has not financed an acquisition with its institutional investor since September 1994. The Company periodically uses derivative financial instruments to manage oil and gas price risk. Settlements of gains and losses on commodity price swap contracts are generally based upon the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange ("NYMEX") price or other cash or futures index price, and are reported as a component of oil and gas revenues. Gains or losses attributable to the termination of a swap contract are deferred and recognized in revenue when the oil and gas is sold. From October 1, 1996 to March 31, 1997, the Company has in effect hedges of gas equivalent to approximately 16% of its production at a floor price per MMBtu of $1.75 and a ceiling price per MMBtu of $2.20 (NYMEX). In addition, the Company is party to hedges in effect from October 1, 1996 through December 31, 1996 representing approximately 81% of its oil production at a floor price per Bbl of $17.25 and a ceiling price per Bbl of $19.59 (NYMEX). The Company is also party to hedges that will be in effect for 1997 representing approximately 30% of oil production at an average fixed price of $23.33 per Bbl (NYMEX). During the third quarter of 1996, the Company terminated hedges attributable to its fourth quarter 1996 production at a profit, which will have the effect of increasing fourth quarter oil and gas revenues by $180,000. CAPITAL EXPENDITURES During the first nine months of 1996, net capital expenditures of $19.9 million were incurred. A production facility was acquired for $1.5 million and the Company's share of the total costs for the leases in the OCS was approximately $12.2 million. The remaining $6.2 million consists of the purchase of several additional leases and seismic surveys in Callon's current focus areas, production facility improvements, capitalized overhead and the purchase of office furniture and fixtures. At September 30, 1996, the Company had a working capital surplus of $3.0 million and a current ratio of 1.2 to 1. The Company has recently changed the focus of its reserve growth strategy from the acquisition and exploitation of oil and gas properties to exploration and development drilling. The Company expects to concentrate its exploration and development drilling in the Shallow Miocene focus area and the Deep OCS Prospects. The Company has identified nine development and 12 exploratory drilling locations, and has a 21 capital budget of $34.9 million to drill and complete these wells. The Company's capital budget for the remainder of 1996 and 1997 will depend upon the success of its exploration and development drilling. If the Company's exploration drilling operations are successful, it will require additional capital to develop discoveries during late 1997 and thereafter. If the Company's initial drilling operations are not successful, the Company may redeploy its remaining capital budget to other activities. ACCOUNTING POLICIES In January 1996, the Company adopted the provisions of SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 121 requires the Company to review its oil and gas properties whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable, and recognize a loss if such recoverable amounts are less than the carrying amount. There have been no impairment losses recognized as of September 30, 1996, but any future losses would be included in depletion, depreciation, amortization and impairment in future accounting periods. On October 23, 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation," effective for the Company at December 31, 1996. Under FAS 123 companies can either record expenses based on the fair value of stock-based compensation upon issuance or elect to remain under the current "APB Opinion No. 25" method, whereby no compensation cost is recognized upon grant, and make disclosures as if FAS 123 had been applied. The Company anticipates that it will continue to account for its stock-based compensation plans under APB Opinion No. 25. 22 BUSINESS AND PROPERTIES Callon Petroleum Company and its predecessors have been engaged in the acquisition, development, exploration and production of oil and gas since 1950. The Company's properties are geographically concentrated in Louisiana, Alabama and offshore Gulf of Mexico. Callon also manages properties for certain institutional investors. Callon was formed in 1994 through the consolidation of a publicly traded limited partnership, a joint venture with a consortium of European entities and an independent energy company owned by certain members of current management. As of December 31, 1995, the Company had estimated net proved reserves of 58.3 Bcfe with a PV-10 Value of $63.8 million, representing increases of 15% and 54%, respectively, from December 31, 1994. The Company's objective is to enhance stockholder value through sustained growth in its reserve base, production levels and resulting cash flows from operations. Over the past two years, the Company has shifted its emphasis from the acquisition of producing properties to the acquisition of acreage with development and exploratory drilling opportunities to further increase potential recoverable reserves. In evaluating drilling opportunities, Callon performs extensive geological and geophysical studies using CAEX, including, where appropriate, the acquisition of 3-D seismic or high-resolution 2-D seismic data to facilitate these efforts. EXPLORATION AND DEVELOPMENT OPERATIONS. The Company's exploratory and development operations are concentrated in two areas in the Gulf of Mexico, the Shallow Miocene focus area, located in the state waters of Alabama and the federal OCS in the Gulf of Mexico, and the Deep OCS Prospects. Wells drilled in the Shallow Miocene focus area seek oil and gas deposits at from 1,800 to 6,000 feet, and are characterized by relatively low exploration and development costs, high initial production rates and short reserve lives. Wells drilled on the Deep OCS Prospects are more expensive to drill and complete. These wells have greater risks, but seek larger oil and gas deposits with longer reserve lives. In 1995 and 1996, the Company acquired an extensive infrastructure of production platforms, gathering systems and pipelines in the Shallow Miocene focus area. During 1996, the Company completed four proprietary high resolution seismic surveys over an eight block area contiguous to Chandeleur Block 40 in the Shallow Miocene focus area. Based on these surveys, in October and November of 1996, the Company drilled two gross (1.52 net) successful development wells and one gross (1.0 net) successful exploratory well in this area. These wells are expectd to be placed on production by the end of November and, coupled with the replacement of compression equipment at the CB 40 and Main Pass Block 163 production facilities, the Company anticipates a significant increase in its gas production rates by year-end 1996. The Company's capital budget currently anticipates drilling an additional five gross (4.0 net) development wells and three gross (0.9 net) exploratory wells during late 1996 and 1997 in this area, for aggregate net cost to drill and complete of $15.3 million. In 1996, the Company joined with Murphy to acquire 18 blocks in the OCS. Callon owns a 25% working interest in these Deep OCS Prospects. The Company's capital budget for late 1996 and 1997 contemplates drilling eight gross (2.0 net) exploratory wells jointly with Murphy at a total cost to Callon to drill and complete of $11.3 million. The first well commenced drilling in the West Cameron 603 Block in October 1996, and drilling of the second well is scheduled in November 1996. In addition to the wells drilled with Murphy, the Company, as operator, plans to drill an additional two wells in 1997 on Deep OCS Prospects. In total, the Company's current capital budget contemplates the drilling of nine gross (5.9 net) development wells and 12 gross (3.9 net) exploratory wells during late 1996 and 1997 at an estimated net cost to the Company to drill and complete of $34.9 million. These drilling operations will be financed through cash flows from operations, the net proceeds of this Offering and borrowings under the Company's Credit Facility. See "Use of Proceeds." PRODUCING PROPERTY ACQUISITIONS. Over the past seven years, the Company has increased its reserves through the acquisition of producing properties that are geologically complex, have (or are analogous to fields with) an established production history from stacked pay zones and are candidates for exploitation. The Company focuses on reducing operating costs and implementing production enhancements through the application of technologically advanced production and recompletion techniques. Between 1989 and September 30, 1996, Callon acquired producing properties in 16 negotiated transactions, on behalf of itself 23 and, in certain cases, its primary institutional investor, for an aggregate net purchase price of $194 million and, during that period, the Company had an average Reserve Replacement Cost of $0.84 per Mcfe. During the nine months ended September 30, 1996, the Company invested a total of $1.0 million and acquired an average 73% working interest (55% net revenue interest) in 12 producing wells, as well as a 100% ownership of one production facility and a 49% ownership in another, both of which are located in its Shallow Miocene focus area. Estimated net proved reserves attributable to these properties, as estimated by the Company's internal reserve engineers as of September 30, 1996, is 10 Bcfe. Through its acquisition program, the Company has assembled an operational and technical database in geographical areas at a low cost to the Company. The relationship with its institutional investors has allowed the Company to pursue larger acquisitions, while the cost sharing arrangements and ongoing management fees have enabled the Company to enhance the rate of return on its properties and to maintain a larger, more experienced team of technical and operating personnel than otherwise would be feasible for a company of its size. SIGNIFICANT PRODUCING PROPERTIES The following table shows the PV-10 Value and estimated net proved oil and gas reserves by major field for the Company's four largest producing fields and for all other properties combined at December 31, 1995.
ESTIMATED NET PROVED PERCENT ---------------------- PV-10 TOTAL OIL GAS PRIMARY VALUE PV-10 RESERVES RESERVES FIELD NAME/LOCATION OPERATOR(S) ($000) VALUE (MBBLS) (MMCF) - ------------------------------------- ------------- ------- -------- --------- --------- Chandeleur Block 40.................. Callon $16,851 26.4% -- 12,161 Federal Waters Black Bay Complex.................... Callon 10,187 16.0 2,144 684 Louisiana State Waters North Dauphin Island Field........... Callon 9,749 15.3 -- 6,879 Alabama State Waters Big Escambia Creek Field............. Exxon 9,330 14.6 1,053 2,305 Escambia County, Alabama Other properties..................... Various 17,647 27.7 1,569 7,638 ------- -------- --------- --------- Total........................... $63,764 100.0% 4,766 29,667 ======= ======== ========= =========
CHANDELEUR BLOCK 40 The Company and its institutional investor acquired an initial 33.3% working interest in the Chandeleur Block 40 in 1994. On December 29, 1995, Callon acquired an additional 66.7% working (55.5% net revenue) interest in the Chandeleur Block 40 for $9 million and subsequently sold a 22.2% working interest in the field for $3 million. The Company currently holds a combined 52.3% working (43.6% net revenue) interest in the Chandeleur Block 40. The estimated net proved reserves as of December 31, 1995 were 12.2 Bcf of natural gas. When the Company assumed operations of the field in December 1995, two wells were producing 5.5 MMcf/d of gas from a Shallow Miocene reservoir at approximately 3,800 feet. The Company has since successfully recompleted one well, increasing the rate of production to 10.5 MMcf/d of gas, and drilled one offset well which encountered 44 feet of net pay. Production from the offset well is expected to commence in November 1996. BLACK BAY COMPLEX The Company-operated Black Bay Complex (the "Complex") is located in shallow waters off the Louisiana coast. It consists of eight fields, 94 wells producing 4.8 MBbls/d during September 1996 and approximately 30,000 acres of oil and gas leases, all of which are held by production. The Company owns 24 an average 15.4% working interest (11.6% net revenue interest) in the Complex, and an institutional investor, whose properties are managed by the Company, owns a 32.6% working interest. The discovery well in the Complex was completed in 1949. Forty-five different sandstone formations and 137 separate reservoirs ranging in depth from 6,200 to 9,600 feet have been identified within the Complex. As of year-end 1995, these fields had produced approximately 239 MMBbls of oil and 215 Bcf of gas. The Company assumed operations of the complex in August 1992, and since that time the Company has reduced operating expenses 30%, successfully drilled six development wells, including a horizontal well, and implemented 14 recompletions, seven of which employed a new stimulation technology. As of September 30, 1996, the Company has invested $3.6 million in drilled wells, recompletions and facility enhancement activities. NORTH DAUPHIN ISLAND FIELD The Company owns a 94.4% working interest in the North Dauphin Island Field, located in shallow Alabama state waters. The field was discovered in April 1990, and the wells produce from a Shallow Miocene reservoir at approximately 1,800 feet. There are five gas wells, three of which were drilled horizontally, which were producing 9.1 MMcf/d at the end of September 1996. The field had produced 56.4 Bcf of gas as of September 30, 1996. The Company also owns a state-of-the-art production platform, including compressors and dehydration facilities, an associated gathering system, and a 12-inch diameter, 12-mile pipeline ("North Dauphin Island Platform"). This pipeline leads to existing onshore connections with the pipeline systems of Koch Gateway Pipeline Company, Transcontinental Natural Gas Pipe Line Corporation and Florida Natural Gas Transmission Company. The current throughput capacity of the gathering and transportation facilities is in excess of 100 MMcf/d and with additional compression, the capacity can be increased to 130 MMcf/d. The ownership of the North Dauphin Island Platform and associated pipeline provides the Company with a significant strategic advantage in the North Dauphin Island area. In 1995, the Company signed an agreement with a subsidiary of a major oil company providing for gas gathering services and transportation through the North Dauphin Island Platform to onshore pipeline connections. The agreement further provides for the subsidiary to purchase firm capacity commitments from the Company for gas deliveries through the North Dauphin Island Platform for 15 years, which commenced in April 1996, to transport up to 100 MMcf/d of the subsidiary's gas production. Firm capacity reservations will average over $1.0 million per year through the term of the contract. Additional revenues may be received depending upon the actual throughput used by the subsidiary. A recently completed high resolution seismic survey has resulted in a good match between reservoir volumetrics and production data. The Company plans to workover one of the five field wells to restore production to an underproduced area on the western side of the field. BIG ESCAMBIA CREEK FIELD The Company holds an average working interest of 6.9% (7.1% net revenue interest), subject to a 10% reduction after payout, in 11 wells and a 2.9% average royalty interest in another five wells. The gross average daily production for these wells for September 1996 was approximately 3.6 MBbls of condensate, 1.8 MBbls of gas liquids, 9.6 MMcf of residue gas and 393 long tons of sulphur. These wells are producing from the Smackover formation at depths ranging from 15,100 to 15,600 feet. Production in this field has been partially curtailed due to low treatment plant capacity and, as a result, no significant field production decline occurred during the past several years. Big Escambia Creek Field is part of the Escambia Minerals properties acquisition. EXPLORATION AND DEVELOPMENT PROJECTS Over the last two years, the Company shifted the focus of its operations from the acquisition and exploitation of oil and gas properties to exploratory and developmental drilling. The Company's exploration and development activity is focused primarily in two areas in the Gulf of Mexico: the Shallow Miocene focus area and the Company's Deep OCS Prospects. 25 SHALLOW MIOCENE FOCUS AREA The Company's Shallow Miocene focus area is located in the OCS offshore blocks of Chandeleur, Main Pass and Viosca Knoll as well as in the state waters of Alabama. Wells drilled in the Shallow Miocene focus area are characterized by relatively low exploration and development costs, high initial production rates and short reserve lives. The Company entered this area in 1993 with the purchase of the North Dauphin Island field and has used state of the art reservoir engineering and seismic technology to develop proprietary processes which the Company believes provides it with a competitive advantage in exploiting Shallow (1,800 to 6,000 feet) Miocene reservoirs. During 1996 the Company completed five proprietary high resolution seismic surveys in this area. Designed specifically for the Shallow Miocene by the Company, four of the surveys were conducted within the eight contiguous blocks around Chandeleur 40. A drilling program was initiated as a result of the survey and three wells, which logged 44 feet, 54 feet and six feet of net pay, were completed in late October and early November 1996. In addition, the Company will participate in the drilling of an exploratory well on Main Pass 234 and has farmed in an exploratory prospect on Main Pass 240 with both wells scheduled to commence drilling in the first quarter of 1997. As a direct result of this geographic concentration of production and prospects, the Company has also developed an inventory of deeper Middle Miocene prospects. The first of these, at Main Pass 247, will be drilled before the end of 1996 to test numerous Shallow and Middle Miocene sands. In October and November of 1996, Callon drilled two gross (1.52 net) successful development wells and one gross (1.0 net) successful exploratory well in the Shallow Miocene focus area. During the fourth quarter of 1996 and 1997, the Company expects to drill five gross (4.0 net) development wells and three gross (0.9 net) exploratory wells in the Shallow Miocene focus area, at an aggregate net cost to drill and complete of $15.3 million. DEEP OCS PROSPECTS In addition to the prospects in its Shallow Miocene focus area, the Company has acquired a number of prospects in the OCS which are intended to explore for reserves at depths in excess of 10,000 feet. Wells drilled to these objectives are characterized by high drilling and completion costs and are subject to delays in commencing sales of oil and gas as production platforms and transportation facilities are built. Targeted deposits of oil and gas in this focus area are larger than in the Shallow Miocene area, and have longer reserve lives. The Company joined with Murphy in 1996 to evaluate and acquire selected tracts at OCS lease sales. Pursuant to these bids, the Company acquired a 25% working interest in 18 offshore blocks which Murphy will operate. Nine of these blocks have as their objective development of the Plio-Pleistocene formations at depths from 13,000 to 18,000 feet. The Company's Deep OCS Prospects cover the West Cameron and High Island blocks which are located in the outer regions of the OCS in water depths ranging from 150 to 350 feet. The first of the wells drilled on the properties acquired with Murphy, commenced drilling in October 1996 in the West Cameron Block 603, and is expected to reach total depths during December. The primary objective of the well is gas deposits at approximately 15,500 feet. The prospect is defined by a 3-D seismic survey, and off-set wells drilled in an adjoining block have established reservoir conditions. Net costs to the Company to drill the well are anticipated to be $1.4 million and net costs to complete the well, if productive, are estimated to be $300,000. If the well is successful, the Company anticipates that it will drill up to four development wells and construct production facilities at a net cost to the Company of approximately $10.6 million. During the fourth quarter of 1996 and 1997, the Company expects to drill eight gross (2.0 net) exploratory wells on the OCS blocks acquired with Murphy. Total costs, net to the Company's 25% working interest, to drill and complete these wells is estimated to be $11.3 million. The Company expects that Murphy will be the operator of all of these wells. 26 In addition to wells on the blocks acquired with Murphy, the Company, as operator, anticipates drilling two development wells during 1997 with objective depths between 10,500 and 13,000 feet. Total costs net to the Company's 19% working interest to drill these wells, are estimated to be $1.0 million and net costs to complete these wells, if productive, are estimated to be $400,000. If productive, these wells will be produced through nearby production facilities owned and operated by the Company. RELATIONS WITH INSTITUTIONAL INVESTOR Callon has established a relationship with an institutional investor which has been important to the Company's acquisition strategy. Between 1989 and 1994, this institutional investor has invested $130 million in property acquisitions made with the Company. These properties, which are managed by the Company, had estimated net proved reserves at December 31, 1995 of 10.3 MMBbls of oil and 33.7 Bcf of gas. The Company's arrangements with this institutional investor vary from acquisition to acquisition. In a typical transaction, the Company acquires a working interest and burdens the working interest with a net profits interest transferred to the institutional investor. The Company's arrangements with the institutional investor generally provide that the Company earns an increased interest in the properties either at the time of closing an acquisition or after the institution receives a certain level of distribution. The Company also receives operating and property management fees from institutional investors and joint interest partners. The Company believes this institutional relationship provides Callon with the ability to make larger acquisitions than would otherwise be possible. The fees received by the Company from operating and managing properties owned by institutional investors also enable the Company to maintain a larger and more experienced operations and technical staff, including petroleum engineers, geoscientists and landmen. RESERVES The following table sets forth certain information about the estimated net proved reserves of the Company as of the dates set forth below. DECEMBER 31, ------------------------------- 1995 1994 1993 --------- --------- --------- Proved developed: Oil (MBbls)........................ 3,890 3,309 2,084 Gas (MMcf)......................... 20,408 20,582 11,366 Proved undeveloped: Oil (MBbls)........................ 876 1,115 758 Gas (MMcf)......................... 9,259 3,520 2,801 Total proved: Oil (MBbls)........................ 4,766 4,424 2,842 Gas (MMcf)......................... 29,667 24,102 14,167 Estimated pre-tax future net cash flows (000's)............................... $ 95,730 $ 59,477 $ 35,814 ========= ========= ========= PV-10 Value (000's)..................... $ 63,764 $ 41,383 $ 22,554 ========= ========= ========= The Reserve Engineers prepared the estimates of proved reserves of the Company and the future net cash flows (and present value thereof) attributable to such proved reserves. Reserves were estimated using oil and gas prices and production and development costs in effect on December 31 of each such year, without escalation, and were otherwise prepared in accordance with the SEC regulations regarding disclosure of oil and gas reserve information. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company and the Reserve Engineers. The reserve data set forth in this Prospectus represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates by different engineers often vary, sometimes significantly. In addition, 27 physical factors, such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors, such as an increase or decrease in product prices that renders production of such reserves more or less economic, may justify revision of such estimates. Accordingly, reserve estimates are different from the quantities of oil and gas that are ultimately recovered. See "Risk Factors -- Estimates of Oil and Gas Reserves." OIL AND GAS PRODUCTION, AVERAGE SALES PRICES AND PRODUCTION COSTS The following table sets forth the quantities of oil and gas produced by the Company from wells located onshore in the continental United States and offshore in Alabama, Louisiana, Texas and federal waters.
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1996 1995 1995 1994 1993 --------- --------- --------- --------- --------- Production: Oil (MBbls)........................ 451 430 595 364 369 Gas (MMcf)......................... 4,784 5,279 6,694 4,076 1,659 Total production (MMcfe)........... 7,490 7,860 10,261 6,260 3,870
The following table sets forth the Company's average sales prices per Bbl of oil and per Mcf of gas and the average production costs (including severance taxes on production and property and transportation charges) per MMcfe for the periods indicated.
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1996 1995 1995 1994 1993 --------- --------- --------- --------- --------- Average sales price per Bbl............. $ 18.05 $ 16.68 $ 16.68 $ 15.63 $ 16.73 Average sales price per Mcf............. 2.18 1.88 1.96 2.00 2.10 Average production cost per MMcfe....... 0.76 0.66 0.66 0.65 0.96
PRODUCTIVE WELLS AND ACREAGE The following table sets forth the wells drilled and completed by the Company during the periods indicated. All such wells were drilled in the continental United States including federal and state waters in the Gulf of Mexico.
YEAR ENDED DECEMBER 31, -------------------------------------------------- 1995 1994 1993 ------------- ------------- -------------- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- ---- Development: Oil................................ 6 .65 7 .36 8 .59 Gas................................ 1 .13 -- -- 17 .68 Non-productive..................... -- -- 6 .42 2 .21 ----- --- ----- --- ----- ---- Total......................... 7 .78 13 .78 27 1.48 ===== === ===== === ===== ==== Exploration: Oil................................ 1 .24 -- -- 1 .12 Gas................................ -- -- -- -- 1 .04 Non-productive..................... -- -- 1 .24 2 .12 ----- --- ----- --- ----- ---- Total......................... 1 .24 1 .24 4 .28 ===== === ===== === ===== ====
The Company owned working and royalty interests in approximately 1,256 gross (48.2 net) producing oil and 291 gross (12.8 net) producing gas wells as of December 31, 1995. A well is categorized as an oil 28 well or a gas well based upon the ratio of oil to gas reserves on a Mcfe basis. However substantially all of the Company's wells produce both oil and gas. The following table shows the approximate leasehold acreage of the Company as of December 31, 1995. LEASEHOLD ACREAGE ------------------------------------------ DEVELOPED UNDEVELOPED -------------------- -------------------- STATE GROSS NET GROSS NET - ---------------------------------- --------- --------- --------- --------- Alabama........................... 14,565 11,900 3,240 444 Arkansas.......................... 2,224 383 770 41 California........................ -- -- 480 480 Louisiana......................... 53,057 6,796 2,347 220 Michigan.......................... 4,674 218 246 29 Mississippi....................... 3,103 1,290 724 572 New Mexico........................ 1,560 168 -- -- Oklahoma.......................... 9,469 1,144 -- -- Texas............................. 12,390 828 -- -- Utah.............................. 10,880 1,253 -- -- Federal waters.................... 19,995 2,675 761 761 --------- --------- --------- --------- Total................... 131,917 26,655 8,568 2,547 ========= ========= ========= ========= The royalty and mineral acreage of the Company, as of December 31, 1995, was approximately 1,336 net developed acres and 6,953 net undeveloped acres. In addition, the Company owned 5,464 developed and 134,536 undeveloped mineral acres. MAJOR CUSTOMERS For the year ended December 31, 1995, Northridge Energy Marketing Company ("Northridge") and Williams Energy Services, Inc. ("Williams") purchased 20% and 37%, respectively, of the Company's oil and gas production. Northridge purchased oil production from the Black Bay Complex and Williams purchased gas from the North Dauphin Island Field. Because of the nature of oil and gas operations and the marketing of production, the Company believes that the loss of these customers would not have a material adverse effect on the Company. TITLE TO PROPERTIES Callon believes that it has satisfactory title to the Company's oil and gas properties in accordance with standards generally accepted in the oil and gas industry, subject to the mortgages under the Credit Facility and such exceptions which, in the opinion of the Company, are not so material as to detract substantially from the use or value of such properties. In addition to the mortgages, the Company's properties are typically subject, in one degree or another, to one or more of the following: royalties and other burdens and obligations, express or implied, under oil and gas leases; overriding royalties and other burdens created by the Company or its predecessors in title; a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; back-ins and reversionary interests arising under purchase agreements and leasehold assignments; liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and communitization agreements, declarations and orders; and easements, restrictions, rights-of-way and other matters that commonly affect oil and gas producing property. To the extent that such burdens and obligations affect the Company's rights to production revenues, they have been taken into account in calculating the Company's net revenue interests and in estimating the size and value of the Company's reserves. Callon believes that 29 the burdens and obligations affecting the Company's properties are conventional in the industry for properties of the kind owned by the Company. OTHER PROPERTIES The Company's headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. The Company also maintains field offices in the area of the major fields in which Callon operates properties or has a significant interest, all of which are owned. EMPLOYEES The Company had 146 employees on October 1, 1996, none of whom are currently represented by a union. The Company considers itself to have good relations with its employees. The Company employs 10 petroleum engineers and four petroleum geoscientists. LITIGATION The Company is a defendant in various legal proceedings and claims which arise in the ordinary course of Callon's business. Callon does not believe the ultimate resolution of such actions will have a material effect on the Company's financial position or results of operations. COMPETITION, MARKETS AND REGULATIONS COMPETITION The oil and gas industry is highly competitive in all of its phases. Callon encounters competition from other oil and gas companies in all areas of the Company's operations, including the acquisition of reserves and producing properties and the marketing of oil and gas. Many of these companies possess greater financial and other resources than the Company. Competition for producing properties is affected by the amount of funds available to the Company, information about a producing property available to the Company and any standards established by the Company for the minimum projected return on investment. Because gathering systems and related facilities are the only practical method for the intermediate transportation of gas, competition for gas delivery is presented by other pipelines and gas gathering systems. Competition may also be presented by alternate fuel sources. MARKETS Callon's ability to market oil and gas from the Company's wells depends upon numerous factors beyond the Company's control, including the extent of domestic production and imports of oil and gas, the proximity of the gas production to gas pipelines, the availability of capacity in such pipelines, the demand for oil and gas by utilities and other end users, the availability of alternate fuel sources, the effects of inclement weather, state and federal regulation of oil and gas production and federal regulation of gas sold or transported in interstate commerce. No assurances can be given that Callon will be able to market all of the oil or gas produced by the Company or that favorable prices can be obtained for the oil and gas Callon produces. The supply of gas capable of being produced has exceeded demand in recent years, as a result of decreased demand for gas in response to economic factors, conservation, lower prices for alternate energy sources and other factors. As a result of this excess supply of gas, gas producers have experienced increased competitive pressure and lower prices. Substantially all of the gas produced by the Company is sold at market responsive prices. In view of the many uncertainties affecting the supply of and demand for oil, gas and refined petroleum products, the Company is unable to predict future oil and gas prices and demand or the overall effect such prices and demand will have on the Company. Callon does not believe that the loss of any of the Company's oil purchasers would have a material adverse effect on the Company's operations. Additionally, since substantially all of the Company's gas sales are on the spot market, the loss of one or more gas purchasers should not materially and adversely affect the Company's financial condition. The marketing of 30 oil and gas by Callon can be affected by a number of factors which are beyond the Company's control, the exact effects of which cannot be accurately predicted. FEDERAL REGULATIONS SALES OF GAS. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated prices for all "first sales" of gas. Thus, all sales of gas by the Company may be made at market prices, subject to applicable contract provisions. TRANSPORTATION OF GAS. The rates, terms and conditions applicable to the interstate transportation of gas by pipelines are regulated by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA"), as well as under section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985, the FERC has implemented regulations intended to make gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. Most recently, in Order No. 636, ET SEQ., the FERC promulgated an extensive set of new regulations requiring all interstate pipelines to "restructure" their services. The most significant provisions of Order No. 636 (i) require that interstate pipelines provide firm and interruptible transportation solely on an "unbundled" basis, separate from their sales service, and convert each pipeline's bundled firm city-gate sales service into unbundled firm transportation service; (ii) issue blanket certificates to pipelines to provide unbundled sales service; (iii) require that pipelines provide firm and interruptible transportation service on a basis that is equal in quality for all gas supplies, whether purchased from the pipeline or elsewhere; (iv) require that pipelines provide a new, non-discriminatory "no-notice" transportation service; (v) establish two new, generic programs for the reallocation of firm pipeline capacity; (vi) require that all pipelines offer access to their storage facilities on a firm and interruptible, open access, contract basis; (vii) provide pregranted abandonment of unbundled sales and interruptible and short-term firm transportation service and conditional pregranted abandonment of long-term transportation service; (viii) modify transportation rate design by requiring all fixed costs related to transportation to be recovered through the reservation charge under the straight fixed variable ("SFV") method. The order also recognized that the elimination of city-gate sales service and the implementation of unbundled transportation service would result in considerable costs being incurred by the pipelines. Therefore, Order No. 636 provided mechanisms for the recovery by pipelines from present, former and future customers of certain types of "transition" costs likely to occur due to these new regulations. In subsequent orders, the FERC substantially upheld the requirements imposed by Order No. 636. Pursuant to Order No. 636, pipelines and their customers engaged in extensive negotiations in order to develop and implement new service relationships under Order No. 636. Tariffs instituting these new restructured services were placed into effect on all pipelines on or before November 1, 1993. Numerous petitions for judicial review of Order No. 636 have been filed and consolidated for review in the United States Court of Appeals for the D.C. Circuit. In addition, numerous parties have sought review of separate FERC orders implementing Order No. 636 on individual pipeline systems. Since the restructuring requirements that emerge from this lengthy administrative and judicial review process may be materially different from those of Order No. 636 as originally adopted, it is not possible to predict what effect, if any, the final rule resulting from Order No. 636 will have on the Company. SALES AND TRANSPORTATION OF OIL. Sales of oil and condensate can be made by the Company at market prices not subject at this time to price controls. The price that the Company receives from the sale of these products will be affected by the cost of transporting the products to market. As required by the Energy Policy Act of 1992, the FERC has revised its regulations governing the rates that may be charged by oil pipelines. The new rules, which were effective January 1, 1995, provide a simplified, generally applicable method of regulating such rates by use of an index for setting rate ceilings. In certain circumstances, the new rules permit oil pipelines to establish rates using traditional cost of service and other methods of ratemaking. The effect that these new rules may have on moving the Company's products to market cannot yet be determined. In addition, at the same time as it issued the new rules, the FERC also issued notices of inquiry regarding market-based pricing for oil pipeline rates and the information required to be filed for 31 ratemaking and reporting purposes. It is not possible to predict what rules, if any, the FERC will ultimately adopt as a result of these inquiry proceedings or the effect that any rules that are adopted might have on the cost of moving the Company's products to market. LEGISLATIVE PROPOSALS. In the past, Congress has been very active in the area of gas regulation. There are legislative proposals pending in the state legislatures of various states, which, if enacted, could 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's operations. FEDERAL, STATE OR INDIAN LEASES. In the event the Company conducts operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management ("BLM") or Minerals Management Service or other appropriate federal or state agencies. The Mineral Leasing Act of 1920 (the "Mineral Act") prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies "similar or like privileges" to citizens of the United States. Such restrictions on citizens of a "non-reciprocal" country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and gas leases. It is possible that the Common Stock will be acquired by citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. STATE REGULATIONS Most states regulate the production and sale of oil and gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both. The Company may enter into agreements relating to the construction or operation of a pipeline system for the transportation of gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state's administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates which the Company could charge for gas, the transportation of gas, and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority. ENVIRONMENTAL REGULATIONS GENERAL. The Company's activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company anticipates that, absent the occurrence of an extraordinary event such as those noted under "Risk Factors," compliance with existing federal, state and local laws, rules and regulations regulating the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of Callon with respect to the Company's operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies issued thereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company's operations could have on its activities. Activities of the Company with respect to gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing gas and other products, 32 are subject to stringent environmental regulation by state and federal authorities including the Environmental Protection Agency ("EPA"). Such regulation can increase the cost of planning, designing, installing and operating such facilities. In most instances, the regulatory requirements impose water and air pollution control measures. Although Callon believes that compliance with environmental regulations will not have a material adverse effect on the Company, risks of substantial costs and liabilities related to environmental compliance issues are inherent in oil and gas production operations, and no assurance can be given that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production, would result in substantial costs and liabilities to the Company. SOLID AND HAZARDOUS WASTE. The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by the Company. In addition, many of these properties have been operated by third parties. The Company had no control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. Under these new laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination. The Company generates wastes, including hazardous wastes, that are subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA has limited the disposal options for certain hazardous wastes and is considering the adoption of stricter disposal standards for nonhazardous wastes. Furthermore, it is possible that certain wastes currently exempt from treatment as "hazardous wastes" generated by the Company's oil and gas operations may in the future be designated as "hazardous wastes" under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly disposal requirements. SUPERFUND. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the owner and operator of a site and any party that disposed or arranged for the disposal of the hazardous substance found at a site. CERCLA also authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs of such action. In the course of the Company's operations, Callon has generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." The Company may also be an owner of sites on which "hazardous substances" have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been disposed. At this time, neither the Company nor its predecessors has been designated as a potentially responsible party under CERCLA with respect to any such site. OIL POLLUTION ACT. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in "waters of the United States." The term "waters of the United States" has been broadly defined to include inland waterbodies, including wetlands, playa lakes and intermittent streams. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or 33 operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits also do not apply. Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill. OPA currently requires owners and operators of offshore oil and gas facilities to establish $150 million in financial responsibility. Under the rule, financial responsibility can be established through insurance, guaranty, indemnity, surety bond, letter of credit, qualification as a self-insurer or a combination thereof. It is unlikely that insurance companies or underwriters will be willing to provide coverage under the OPA because the statute provides for direct lawsuits against insurers who provide financial responsibility coverage, and most insurers have strongly protested this requirement. The financial tests or other criteria that will be used to judge self-insurance are also uncertain. On September 30, 1996, Congress passed legislation lowering the financial responsibility requirement under OPA to $35 million, subject to increase to $150 million if a formal risk assessment indicates the increase is warranted. The requirements under OPA may have the potential to result in the imposition of substantial additional annual costs on the Company or otherwise materially adversely affect the Company. The impact of the rule is not expected to be any more burdensome to the Company than it will be to other similarly or less capitalized owners or operators in the Gulf of Mexico. AIR EMISSIONS. The operations of the Company are subject to local, state and federal laws and regulations for the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require the Company to cease construction or operation of certain air emission sources, although the Company believes that in such case it would have enough permitted or permittable capacity to continue its operations without a material adverse effect on any particular producing field. OSHA AND OTHER REGULATIONS. The Company is subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require Callon to organize and/or disclose information about hazardous materials used or produced in the Company's operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. 34 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY The Company currently has a Board of Directors composed of seven members. In accordance with the Certificate of Incorporation of the Company, as amended (the "Charter"), the members of the Board of Directors are divided into three classes, Class I, Class II and Class III, and are elected for a full term of office expiring at the third succeeding annual stockholders' meeting following their election to office and when a successor is duly elected and qualified. The terms of office of the Class I, Class II and Class III directors expire at the annual meeting of stockholders in 1998, 1999 and 1997, respectively. The Charter also provides that such classes shall be as nearly equal in number as possible. The directors and executive officers of the Company are as follows: NAME AGE PRESENT COMPANY POSITION - ----------------------- --- ------------------------------------------------- Fred L. Callon......... 46 Director, President; Chief Operating Officer (Class III) John S. Callon......... 76 Director, Chairman of the Board; Chief Executive Officer (Class II) Dennis W. Christian.... 50 Director, Senior Vice President (Class III) Robert A. Stanger...... 56 Director (Class I) H. Michael Tatum....... 67 Vice President; Secretary Kathy G. Tilley........ 51 Vice President John C. Wallace........ 58 Director (Class I) B. F. Weatherly........ 52 Director (Class II) John S. Weatherly...... 44 Senior Vice President; Chief Financial Officer; Treasurer Richard O. Wilson...... 66 Director (Class I) All of the directors, other than Messrs. Stanger and Wilson, have served as directors since the Company's inception in 1994. Messrs. Stanger and Wilson have served as directors since March 2, 1995. The following is a brief description of the background and principal occupation of each director and executive officer. Fred L. Callon is President and Chief Operating Officer of the Company and Callon Petroleum Operating and has held that position with the Company or its predecessors since 1984. He has been employed by the Company or its predecessors since 1976. He graduated from Millsaps College in 1972 and received his M.B.A. degree from the Wharton School of Finance in 1974. Following graduation and until his employment by Callon Petroleum Operating, he was employed by Peat, Marwick, Mitchell & Co., certified public accountants. He is a certified public accountant and is a member of the American Institute of Certified Public Accountants and the Mississippi Society of Certified Public Accountants. He is the nephew of John S. Callon. John S. Callon is Chairman of the Board of Directors and Chief Executive Officer of the Company and Callon Petroleum Operating. Mr. Callon founded the Company's predecessors in 1950, and has held an executive office with the Company or its predecessors since that time. He has served as a director of the Mid-Continent Oil and Gas Association and as the President of the Association's Mississippi-Alabama Division. He has also served as Vice President for Mississippi of the Independent Petroleum Association of America. He is a member of the American Petroleum Institute. Mr. Callon is the uncle of Fred L. Callon. Dennis W. Christian is Senior Vice President of Acquisitions and Operations for the Company and Callon Petroleum Operating, and has held that or similar positions with the Company or its predecessors since 1981. Prior to joining Callon Petroleum Operating, he was resident manager in Stavanger, Norway, for Texas Eastern Transmission Corporation. Mr. Christian received his B.S. degree in petroleum engineering in 1969 from Louisiana Polytechnic Institute. His previous experience includes five years with Chevron U.S.A. Inc. 35 Robert A. Stanger has been the managing general partner since 1978 of Robert A. Stanger & Co., Inc., a Shrewsbury, New Jersey-based firm engaged in publishing financial material and providing investment banking services to the real estate and oil and gas industries. He is a director of Citizens Utilities, Stamford, Connecticut, a provider of telecommunications, electric, gas, and water services. Previously, Mr. Stanger was Vice President of Merrill Lynch & Co. He received his B.A. degree in economics from Princeton University in 1961. Mr. Stanger is a member of the National Association of Securities Dealers, the New York Society of Security Analysts, the International Association of Financial Planners, and the Investment Program Association. H. Michael Tatum is Vice President and Secretary for the Company and Callon Petroleum Operating and is responsible for management of administrative matters. Mr. Tatum has held this position with the Company or its predecessors since 1976, and has been employed by Callon Petroleum Operating since 1969. He graduated from Southern Methodist University in 1967 and is a member of the American Society of Corporate Secretaries and the Society for Human Resource Management. Kathy G. Tilley is Vice President of Acquisitions and New Ventures for the Company and Callon Petroleum Operating and has held that position since April 1996. She was employed by Callon Petroleum Operating in December 1989 as manager of acquisitions and prior thereto, held that or similar positions as a consultant from 1981. Ms. Tilley received her B.A. degree in economics from Louisiana State University in 1967. John C. Wallace is an executive officer of NOCO Management Ltd., the general partner of the general partner of NOCO. He is a Chartered Accountant having qualified with Coopers & Lybrand in Canada in 1963, after which he joined Baring Brothers & Co., Limited in London England. For more than the last ten years, he has served as Chairman of Fred. Olsen Ltd., a London-based corporation which he joined in 1968, where he has specialized in the business of shipping and property development. He is a director of Harland & Wolff PLC, Belfast, A/S Ganger Rolf and A/S Bonheur, Oslo, publicly traded shipping companies, and O.G.C. International P.L.C., a Scottish public company engaged in the offshore oil and gas maintenance and construction business headquartered in Aberdeen, Scotland. He is also a director of Belmont Constructors, Inc., a Houston, Texas-based industrial contractor associated with Fred. Olsen Interests, and other companies associated with Fred. Olsen Interests. B. F. Weatherly is a principal of Amerimark Capital Group, Houston, Texas, an investment banking firm. He is an executive officer of NOCO Management Ltd., the general partner of the general partner of NOCO. Prior to September 1996, he was Executive Vice President, Chief Financial Officer and a director of Belmont Constructors, Inc., a Houston, Texas-based industrial contractor associated with Fred. Olsen Interests. From 1989 to 1991, he was a partner in Amerimark Capital Corp., a Dallas investment banking firm. He holds a Master of Accountancy degree from the University of Mississippi. He has previously been associated with Arthur Andersen LLP, and has served as a Senior Vice President of Weatherford International, Inc. B. F. Weatherly and John S. Weatherly are brothers. John S. Weatherly is Senior Vice President, Chief Financial Officer and Treasurer for the Company and Callon Petroleum Operating. Prior to April 1996, he was Vice President, Chief Financial Officer and Treasurer of the Company and has held those positions since 1983. Prior to joining Callon Petroleum Operating in August 1980, he was employed by Arthur Andersen LLP as Audit Manager in the Jackson, Mississippi office. He received his B.B.A. degree in accounting in 1973 and his M.B.A. degree in 1974 from the University of Mississippi. He is a certified public accountant and a member of the American Institute of Certified Public Accountants and the Mississippi Society of Certified Public Accountants. John S. Weatherly and B. F. Weatherly are brothers. Richard O. Wilson for the past nine years has been Chairman of O.G.C. International P.L.C., a Scottish public company engaged in the offshore oil and gas maintenance and construction business headquartered in Aberdeen, Scotland. For the past 13 years, Mr. Wilson has also been Chairman of Dolphin A/S, Stavanger, Norway, and Dolphin Drilling Ltd., Aberdeen, Scotland, both offshore drilling companies owned by Fred. Olsen Interests. He is also Chairman of Belmont Constructors, Inc., a Houston, Texas-based industrial contractor associated with Fred. Olsen Interests. He holds a B.S. degree in civil engineering from 36 Rice University. Mr. Wilson is a Fellow in the American Society of Civil Engineers, a member of the Institute of Petroleum, London England, and the Cosmos Club, Washington, D.C. Messrs. John S. Callon and Fred L. Callon, as nominees of the Callon Family, and Messrs. B. F. Weatherly and John C. Wallace, as nominees of NOCO, were elected to the Board of Directors pursuant to the terms of the Stockholders' Agreement dated September 16, 1994. See "Principal Stockholders -- Stockholders' Agreement." All officers and directors of the Company are United States citizens, except Mr. Wallace, who is a citizen of Canada. COMPENSATION OF DIRECTORS The Company's Board of Directors holds four regular meetings each year. During 1996, as compensation for all services as a director of the Company, each non-employee director will be paid $10,000. Non-employee directors are also granted, upon their initial election or appointment, options to purchase 5,000 shares of Common Stock pursuant to the 1996 Callon Petroleum Stock Incentive Plan (the "1996 Plan") and will be granted options for an additional 5,000 shares for each year in which they continue to serve as directors. See " -- Incentive Plans -- 1996 Plan." On August 23, 1996, the Compensation Committee authorized a one-time grant to each non-employee director of an option to purchase 20,000 shares of Common Stock under the 1996 Plan at a purchase price of $12.00 per share, the fair market value of the Common Stock on such date, subject to approval of the 1996 Plan by the Company's stockholders at the 1997 annual meeting of stockholders. One-fourth of each option will vest at each succeeding annual meeting of directors following each annual stockholders' meeting, beginning in 1997. EXECUTIVE COMPENSATION The following table sets forth information with respect to the Chief Executive Officer of the Company and the four most highly compensated executive officers of the Company as to whom the total salary and bonus for the year ended December 31, 1995 exceeded $100,000. Such amounts include compensation from the Company's predecessors for the year ended December 31, 1994. SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION ANNUAL COMPENSATION --------------------------------- ----------------------------- AWARDS OTHER ----------------------- PAYOUTS ALL ANNUAL RESTRICTED SECURITIES ------- OTHER COMPEN- STOCK UNDERLYING LTIP COMPEN- YEAR SALARY BONUS SATION AWARD(S) OPTIONS PAYOUTS SATION (1) ($) ($) $(2) ($) (#)(3) ($) ($)(4) --------- --------- --------- ------- ---------- ---------- ------- ------- John S. Callon.......................... 1995 190,000 161,500 -- -- -- -- 10,393 Chairman and Chief Executive Officer 1994 168,000 95,000 -- -- 90,000 -- 9,565 Fred L. Callon.......................... 1995 170,000 144,500 -- -- -- -- 10,288 President and Chief Operating Officer 1994 150,000 85,000 -- -- 80,000 -- 9,096 Dennis W. Christian..................... 1995 150,000 127,500 -- -- -- -- 9,080 Senior Vice President 1994 118,450 140,000 -- -- 60,000 -- 7,186 John S. Weatherly....................... 1995 130,000 110,500 -- -- -- -- 7,873 Senior Vice President, Chief Financial 1994 100,000 107,500 -- -- 60,000 -- 6,068 Officer and Treasurer H. Michael Tatum........................ 1995 100,000 34,000 -- -- -- -- 6,061 Vice President and Secretary 1994 92,183 58,046 -- -- 25,000 -- 5,598
(FOOTNOTES ON FOLLOWING PAGE) 37 - ------------ (1) Information for years prior to 1994 is omitted under SEC rules because the Company was not a reporting company during such periods. (2) Amounts in the column do not include perquisites and other personal benefits, securities or property, unless the annual amount of such compensation exceeds the lesser of $50,000 or 10% of the total of annual salary and bonus reported for the named executive. (3) Represents awards granted under the 1994 Plan. (4) Amounts reflect the Company's contribution in 1995 and 1994, respectively, of $9,500 and $8,400 to John S. Callon's 401(k) savings plan and payment of $893 and $1,165 of term life insurance premiums; $8,500 and $7,500 to Fred L. Callon's 401(k) savings plan and payment of $1,788 and $1,596 of term life insurance premiums; $7,500 and $5,923 to Mr. Christian's 401(k) savings plan and payment of $1,580 and $1,263 of term life insurance premiums; $6,500 and $5,000 to Mr. Weatherly's 401(k) savings plan and payment of $1,373 and $1,068 of term life insurance premiums; and $5,000 and $4,609 to Mr. Tatum's 401(k) savings plan and payment of $1,061 and $989 of term life insurance premiums. RECENT COMPENSATION AWARDS On August 23, 1996, the Compensation Committee granted stock options to the Company's executive officers and senior management under the 1996 Plan, subject to stockholder approval of the 1996 Plan. Pursuant to the awards, Fred L. Callon was granted an option to purchase 75,000 shares of Common Stock; Dennis W. Christian was granted an option to purchase 70,000 shares of Common Stock; H. Michael Tatum was granted an option to purchase 15,000 shares of Common Stock; Kathy G. Tilley was granted an option to purchase 55,000 shares of Common Stock; and John S. Weatherly was granted an option to purchase 65,000 shares of Common Stock. In addition, other members of senior management were granted options to purchase an aggregate 170,000 shares of Common Stock. All of such options were granted at an exercise price of $12.00 per share, the fair market value of the Common Stock on the date of grant, and 20% of each option vests on January 1 of each succeeding year, beginning January 1, 1997. Unvested options are subject to forfeiture upon certain termination of employment events. The Compensation Committee also awarded performance shares under the 1996 Plan to the Company's executive officers on August 23, 1996, subject to stockholder approval of the 1996 Plan. Contingent upon such stockholder approval, Fred L. Callon will be awarded 60,000 performance shares; Dennis W. Christian will be awarded 55,000 performance shares; H. Michael Tatum will be awarded 15,000 performance shares; Kathy G. Tilley will be awarded 45,000 performance shares; and John S. Weatherly will be awarded 50,000 performance shares. All of the performance shares granted will vest in whole on January 1, 2001, and will be subject to forfeiture upon certain termination of employment events. EMPLOYMENT AGREEMENTS, TERMINATION OF EMPLOYMENT AND CHANGE IN CONTROL ARRANGEMENTS Fred L. Callon, Dennis W. Christian and John S. Weatherly has entered into employment agreements with the Company effective September 1, 1996 and ending December 31, 2001. The agreements provide that Mr. Callon, Mr. Christian and Mr. Weatherly will receive an annual base salary of at least $200,000, $175,000 and $165,000, respectively, and that they will be entitled to participate in any incentive compensation program established by the Company for its executive officers. Each agreement terminates upon death or disability or for cause. If the agreement is terminated because of disability, compensation payments continue for a period of two years from the date of termination, reduced by the amount of disability insurance paid. If the agreement is terminated for cause, the Company is not required to make any additional payments. "Cause" is defined generally as any of the following, as determined by a majority vote of the Board of Directors: intentional or continual neglect of duties, conviction of a felony, or failure or refusal to perform duties in accordance with the employment agreement. The employment agreements further provide that the employee may terminate the agreement for "good reason," which is defined generally as (a) failure to be re-elected to office, (b) significant change in duties, (c) reduction or failure to provide typical increases in salary following a change in control of the Company, (d) relocation to an office outside the Natchez, Mississippi area, or (e) failure to maintain the 38 level of participation in the compensation and benefit plans of the Company following a change in control. If the employee terminates his agreement for good reason (other than following a change in control), or if the Company breaches the agreement compensation shall continue for a period of two years from the date of termination. If the agreement is terminated following a change in control, compensation shall continue for a period of three years. Pursuant to the agreements, a "change in control" occurs if: (i) any person or group of persons acting in concert (within the meaning of Section 13(d) of the Exchange Act) shall have become the beneficial owner of a majority of the outstanding common stock of the Company (other than pursuant to the Stockholders' Agreement), (ii) the stockholders of the Company cause a change in a majority of the members of the Board within a twelve-month period, or (iii) the Company or its stockholders enter into an agreement to dispose of all or substantially all of the assets or outstanding capital stock of the Company. If the compensation to be paid upon a change in control would constitute a "parachute" payment under the Internal Revenue Code, the amount otherwise payable will be grossed up to an amount such that the employee will receive the amount he would have received if no portion of such compensation had been subject to the excise tax imposed by the Internal Revenue Code, and the Company will be responsible for the amount of the excise tax. On June 19, 1996, the Company entered into a consulting agreement with John S. Callon to be effective as of the day he ceases to be the Chief Executive Officer of the Company. Pursuant to the agreement, John S. Callon is to provide consulting services to the Company on matters pertaining to corporate or financial strategy, investor relations and public/private financing opportunities for no more than 20 hours per month, ten months a year. The agreement remains in effect from the effective date until December 31, 2001, subject to renewal for succeeding five year periods unless earlier terminated. As compensation for his services under the agreement, John S. Callon will be paid a fee ("Consultation Fee") of not less than $190,000 per year increased annually based upon the change in the Consumer Price Index, as adjusted for inflation. In addition, he will remain eligible to participate in the Company's major medical and disability coverage, and will be entitled to participate in all other employee benefit plans (other than a cash bonus program) provided to full-time executives of the Company. As an inducement for entering into the agreement, John S. Callon was granted 25,000 performance shares of Common Stock, 20% of which vests on each of the first five anniversaries of the effective date of the agreement. Upon termination of the agreement other than for cause, John S. Callon or his spouse shall be entitled to receive a termination payment equal to the Consultation Fee, as adjusted for inflation, to be paid annually until the later of the death of John S. Callon (if applicable) or his spouse. In lieu of the termination payment, John S. Callon or his spouse may elect to receive, subject to the approval of the Board of Directors a lump sum payment of $1.5 million. In addition, if the agreement terminates due to the Company's breach, John S. Callon and his spouse shall be entitled to liquidated damages. The Company may terminate the agreement for cause. "Cause" is defined generally in the agreement as willful misconduct or intentional and continual neglect of duties which has materially and adversely affected the Company. Mr. Callon has indicated that he currently plans to retire during 1997. Pursuant to the 1996 Plan and the 1994 Plan (as defined below), in the case of a merger or consolidation where the Company is not the surviving entity, or if the Company is about to sell or otherwise dispose of substantially all of its assets while unvested options remain outstanding, the Compensation Committee or other plan administrator may, in its discretion and without shareholder approval, declare some or all options exercisable in full before or simultaneously with such merger, consolidation or sale of assets without regard for prescribed waiting periods. Alternatively, the Compensation Committee or other plan administrator may cancel all outstanding options provided option holders are given notice and a period of 30 days prior to the merger, consolidation or sale to exercise the options in full. INCENTIVE PLANS The Company currently maintains two Common Stock-based incentive plans for employees: the 1994 Callon Petroleum Company Stock Incentive Plan (the "1994 Plan") and the 1996 Plan. The Company in the past has used and will continue to use, stock options and performance share grants to attract and retain key employees in the belief that employee stock ownership and stock related compensation devices 39 encourage a community of interest between employees and stockholders. 1994 PLAN. The 1994 Plan was adopted on June 30, 1994. Pursuant to the 1994 Plan, 600,000 shares of Common Stock were reserved for issuance upon the exercise of options or for grants of performance shares. The 1994 Plan is administered by the Compensation Committee of the Board of Directors. Members of the Compensation Committee currently are Messrs. Stanger, Wallace, B. F. Weatherly and Wilson. No awards were granted under the 1994 Plan during 1995 and 1996, other than automatic stock option grants to non-employee directors and the grant of performance shares to John S. Callon in connection with his Consulting Agreement. No additional awards may be granted under the 1994 Plan. See "-- Employment Agreements, Termination of Employment and Change in Control Arrangements." 1996 PLAN. On August 23, 1996, the Board of Directors of the Company approved and adopted the 1996 Plan, and granted awards thereunder to various employees, in each case subject to approval of the 1996 Plan by the stockholders of the Company at the 1997 annual meeting. See " -- Recent Compensation Awards." Individual awards under the 1996 Plan may take the form of one or more of (i) incentive stock options; (ii) non-qualified stock options; or (iii) performance shares. The 1996 Plan is administered by a plan administrator which may be either (i) the Board of Directors of the Company; (ii) any duly constituted committee of the Board of Directors consisting of at least two non-employee directors; or (iii) any other duly constituted committee of the Board of Directors. The plan administrator will select the officers, key employees and consultants who will receive awards and the terms and conditions of those awards. The maximum number of shares of Common Stock that may be subject to outstanding awards may not exceed 900,000. Shares of Common Stock tendered as payment for shares issued upon exercise of an option or which are attributable to awards which have expired, terminated or been canceled or forfeited are available for issuance or use in connection with future awards. The option price of any incentive stock option shall be 100% of the fair market value of a share of Common Stock on the date the incentive option is granted. Any incentive option must be exercised within ten years of the date of grant. Unless otherwise determined by the plan administrator, the option price of any non-qualified stock option shall be 100% of the fair market value of a share of Common Stock on the date the option is granted. Vesting of stock options and performance shares, and the term of any non-qualified stock option or performance share award is determined by the plan administrator. The 1996 Plan provides that each director that is not an employee of the Company shall, on the date on which he or she is initially elected or appointed a director of the Company, be granted a stock option to purchase 5,000 shares of Common Stock for the fair market price on the date of grant and for a term of ten years. After each subsequent annual meeting of stockholders at which such person continues to serve as a director, he or she will automatically be granted a stock option to purchase an additional 5,000 shares of Common Stock for the fair market price on the date of such grant and for a term of ten years. In the event of a termination of employment, outstanding options and performance shares may be subject to forfeiture and/or time limitations. Stock options and performance shares are evidenced by written agreements, the terms and provisions of which may differ. No stock option is transferable other than by will or by the laws of descent or distribution. The 1996 Plan may be amended by the Board of Directors without the consent of the stockholders except that any amendment, though effective when made, will be subject to stockholder approval if required by any federal or state law or regulation or by the rules of any stock exchange or automated quotation system on which the Common Stock may then be listed or quoted. In addition, no amendment can impair the rights of a holder of an outstanding award under the Plan without such holder's consent. As of October 25, 1996, there were 145,000 shares available for grant under the 1996 Plan. OPTION GRANTS IN LAST FISCAL YEAR There were no individual grants of stock options under the 1994 Plan made during the year ended December 31, 1995 to the Chief Executive Officer of the Company or any of the four most highly 40 compensated executive officers of the Company named in the Summary Compensation Table. In addition, no stock appreciation rights were granted by the Company in 1995. AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR END OPTION VALUES The following table sets forth certain information concerning the number and value of unexercised options to purchase Common Stock by the Chief Executive Officer and the four most highly compensated executive officers named in the Summary Compensation Table at December 31, 1995. No stock options were exercised by such persons in 1995. AGGREGATED OPTION EXERCISES IN 1995 AND OPTION VALUES AT DECEMBER 31, 1995
NUMBER OF SECURITIES VALUE OF UNDERLYING UNEXERCISED UNEXERCISED IN-THE-MONEY OPTIONS AT OPTIONS AT DECEMBER 31, DECEMBER 31, 1995 1995 ---------------- ---------------- SHARES ACQUIRED VALUE EXERCISABLE/ EXERCISABLE/ NAME ON EXERCISE (#) REALIZED($) UNEXERCISABLE(1) UNEXERCISABLE(2) - ---------------------------------------- --------------- ----------- ---------------- ---------------- John S. Callon.......................... -- -- 90,000/-- -- Fred L. Callon.......................... -- -- 80,000/-- -- Dennis W. Christian..................... -- -- 60,000/-- -- John S. Weatherly....................... -- -- 60,000/-- -- H. Michael Tatum........................ -- -- 25,000/-- --
- ------------ (1) Represents awards granted under the 1994 Plan. (2) As of December 31, 1995, the market price of stock was below the exercise price. LONG-TERM INCENTIVE PLAN AWARDS Prior to 1996, Callon had not awarded any performance shares under the 1994 Plan nor did it have any other long-term incentive plan for the Company's employees. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION The members of the Company's Compensation Committee are Messrs. Stanger, Wallace, B. F. Weatherly and Wilson, none of whom are or have been officers or employees of the Company. STOCKHOLDERS' AGREEMENT. In connection with the Consolidation, the Company, the Callon Family and NOCO entered into the Stockholders' Agreement which contains certain voting requirements and transfer restrictions. Messrs. Wallace, B. F. Weatherly and Wilson are affiliates of NOCO. See " -- Certain Transactions." REGISTRATION RIGHTS. NOCO is party to a Registration Rights Agreement dated September 16, 1994. Messrs. Wallace, B. F. Weatherly and Wilson are affiliates of NOCO. See " -- Certain Transactions." CERTAIN TRANSACTIONS CONSOLIDATION. Pursuant to the Consolidation in which certain of the Company's predecessor entities were merged into the Company effective September 16, 1994, John S. Callon, Fred L. Callon and other non-employee members of the Callon Family exchanged all of the outstanding stock of Callon Petroleum Operating for an aggregate of 1,892,278 shares of Common Stock of the Company. Certain Callon Family members also converted units of limited partnership interest ("Units") in CCP into an aggregate of 9,635 shares of Common Stock, representing one-third of a share of Common Stock for each Unit. The number of shares of Common Stock issued in the Consolidation was based upon the Company's assignment of exchange values to the assets and liabilities of CCP, Callon Petroleum Operating and CN. 41 STOCKHOLDERS' AGREEMENT. In connection with the Consolidation, the Company, the Callon Family (including John S. Callon and Fred L. Callon) and NOCO entered into the Stockholders' Agreement which (a) provides that the Callon Family shall vote for two directors to the Company's Board of Directors as directed by NOCO and NOCO will vote for two directors to the Company's Board of Directors as directed by the Callon Family, (b) contains certain restrictions on transfer of the Common Stock owned by the Callon Family and NOCO, and (c) provides that neither the Callon Family nor NOCO can transfer shares of Common Stock in connection with, or vote for, consent to or otherwise approve, a transaction which would result in certain changes of control or fundamental changes without the prior written consent of the other party. The Callon Family and NOCO own an aggregate of more than 60% of the Company's outstanding Common Stock. CONTINGENT SHARES. The Callon Family (including John S. Callon and Fred L. Callon), as former stockholders of Callon Petroleum Operating, may receive additional shares of Common Stock pursuant to a Contingent Share Agreement dated September 16, 1994 between the Callon Family and the Company (the "Contingent Share Agreement"). The number of shares issued in the Consolidation was based on the respective asset values of the parties to the Consolidation including Callon Petroleum Operating. Callon Petroleum Operating owned certain oil and gas properties which, for purposes of the Consolidation, could not be properly valued due to inadequate drilling and production history. The Contingent Share Agreement provides that promptly after December 31, 1995, a number of shares of Common Stock will be issued to the Callon Family equal to the present value of the properties (as determined by independent reserve engineers) divided by $12.05. Due to the continued limited production history of the properties, the Company has amended the Contingent Share Agreement to extend the valuation date to December 31, 1996. REGISTRATION RIGHTS. The Callon Family (including John S. Callon and Fred L. Callon) is party to a Registration Rights Agreement dated September 16, 1994, pursuant to which they are entitled to require the Company to register Common Stock owned by them with the SEC for sale to the public in a firm commitment public offering and generally to include shares owned by them in registration statements filed by the Company. NOCO and the Company have entered into a similar agreement. WILCOX ENERGY. Prior to the consummation of the Consolidation, Callon Petroleum Operating distributed the capital stock of its wholly owned subsidiary, Wilcox Energy Company ("Wilcox"), to its stockholders (i.e., the Callon Family, including John S. Callon and Fred L. Callon). The business of Wilcox is the drilling of shallow exploratory wells in the Wilcox Trend, and Callon Petroleum Operating did not believe that Wilcox would fit within the Company's business strategy. NOTE TO AFFILIATE. Prior to the Consolidation, CN from time to time loaned money to NOCO on a short-term basis, at approximately the interest rate earned by CN on short-term cash investments. In 1993, $4.0 million was borrowed. On December 31, 1993, $1.0 million was outstanding at an interest rate of 4.0%. In 1994, the outstanding loan balance of $1.0 million was repaid prior to the Consolidation. FEES TO NOCO. Prior to the Consolidation, the partnership agreement of CN provided that CN would reimburse Callon Petroleum Operating and NOCO at cost for overhead and executive and other personnel services for operations of CN. During 1993, CN paid Callon Petroleum Operating $1.4 million and paid NOCO $320,000 as such reimbursement. NOCO Management, Ltd., the general partner of NOCO Holdings, L.P. (the sole limited partner of NOCO) and whose members include John C. Wallace, Richard O. Wilson, and B. F. Weatherly, directors of the Company, received $190,200 in 1993 of such amounts in fees for services provided to CN by its members, including Mr. Wallace and Mr. Weatherly. In turn, Mr. Wallace received $13,500 of such amounts in 1993, and Mr. Weatherly received $67,500 of such amounts in 1993 from NOCO Management, Ltd. for such services. In 1994, the Company reimbursed NOCO $131,000 for costs and expenses incurred by NOCO in the Consolidation. No overhead payments have been made following the effective date of the Consolidation. 42 PRINCIPAL STOCKHOLDERS The following table sets forth, as of October 25, 1996, certain information with respect to the ownership of shares of Common Stock and the Company's Series A Preferred Stock as to (i) all persons known by the Company to be the beneficial owners of 5% or more of the outstanding shares of Common Stock, (ii) each director, (iii) each of the executive officers named in the Summary Compensation Table, and (iv) all executive officers and directors of the Company as a group. Information set forth in the table with respect to beneficial ownership of Common Stock and Series A Preferred Stock has been obtained from filings made by the named beneficial owners with the SEC or, in the case of executive officers and directors of the Company, has been provided to the Company by such individuals.
COMMON STOCK PREFERRED STOCK ------------------------ ------------------------ AMOUNT AND AMOUNT AND NAME AND NATURE OF PERCENT NATURE OF PERCENT ADDRESS OF BENEFICIAL OF BENEFICIAL OF BENEFICIAL OWNER(S) OWNERSHIP CLASS OWNERSHIP CLASS - ------------------------------------- ---------- -------- ---------- -------- DIRECTORS: John S. Callon.................. 294,040 (b) 5.03% 0 0 200 North Canal Street P.O. Box 1287 Natchez, Mississippi 39120 Fred L. Callon.................. 656,761 (c) 11.23 0 0 200 North Canal Street P.O. Box 1287 Natchez, Mississippi 39120 Dennis W. Christian............. 74,000 (d) 1.27 0 0 Robert A. Stanger............... 15,856 (e) * 0 0 John C. Wallace................. 1,999,758 (f) 34.66 0 0 65 Vincent Square London, England SW1P 2RX B.F. Weatherly.................. 2,000,125 (g) 34.66 0 0 9603 Doliver Street Houston, Texas 77063 Richard O. Wilson............... 2,002,031 (h) 34.69 1,000 * 2400 West Loop South Suite 150 Houston, Texas 77027 NAMED EXECUTIVE OFFICERS: John S. Weatherly............... 73,896 (i) 1.27 0 0 H. Michael Tatum................ 28,000 (j) * 0 0 DIRECTORS AND EXECUTIVE OFFICERS AS A GROUP (10 PERSONS)............ 3,185,951 (k) 51.5 1,000 * CERTAIN BENEFICIAL OWNERS: NOCO Enterprises, L.P........... 1,984,758 (l) 34.49 0 0 6814 Northampton Way Houston, Texas 77055 Wellington Management Company... 401,220 (m) 6.67 140,000 10.64 75 State Street Boston, Massachusetts 02109
- ------------ * less than 1% (a) Unless otherwise indicated, each of the above persons may be deemed to have sole voting and dispositive power with respect to such shares. (FOOTNOTES CONTINUED ON FOLLOWING PAGE) 43 (b) Of the 294,040 shares beneficially owned by John S. Callon, 129,040 are owned directly by him and he has sole voting and dispositive power over such shares, 75,000 shares are held in a family limited partnership, and 90,000 shares are subject to options under the Company's 1994 Plan exercisable within 60 days. Shares indicated as owned by John S. Callon do not include shares of Common Stock owned by NOCO and shares of Common Stock owned by certain other members of the Callon Family, including 61,837 shares owned by John S. Callon's wife and over which he disclaims beneficial ownership. Under the terms of the Stockholders' Agreement, John S. Callon and the other members of the Callon Family have the right of first refusal to acquire shares of Common Stock proposed to be sold by NOCO under certain circumstances and all parties to the Stockholders' Agreement have agreed to support two directors nominated by the Callon Family and two directors nominated by NOCO. John S. Callon disclaims beneficial ownership of the NOCO shares. (c) Of the 656,761 shares beneficially owned by Fred L. Callon, 201,556 shares are owned directly by him; 268,016 shares are held by him as custodian for certain minor Callon Family members; 78,430 shares are held by him as trustee of certain Callon Family trusts; 80,000 are subject to options under the 1994 Plan exercisable within 60 days; 15,000 are subject to options under the 1996 Plan exercisable within 60 days; and 13,759 shares are held by Fred L. Callon as Trustee of shares held by the Callon Petroleum Company Employee Savings and Protection Plan. Shares indicated as owned by Fred L. Callon do not include shares of Common Stock owned by NOCO and shares of Common Stock owned by other members of the Callon Family, including 25,009 shares owned by Fred L. Callon's wife over which he disclaims beneficial ownership. Under the terms of the Stockholders' Agreement, Fred L. Callon and the other members of the Callon Family have the right of first refusal to acquire shares of Common Stock proposed to be sold by NOCO under certain circumstances and all parties to the Stockholders' Agreement have agreed to support two directors nominated by the Callon Family and two directors nominated by NOCO. Fred L. Callon disclaims beneficial ownership of the NOCO shares. (d) Includes 60,000 shares subject to options under the 1994 Plan and 14,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days. (e) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days. (f) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days, and 1,984,758 shares owned by NOCO (see note (l) below). (g) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days and 1,984,758 shares owned by NOCO (see note (1) below). (h) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days, 2,273 shares issuable upon conversion of 1,000 shares of Series A Preferred Stock and 1,984,758 shares owned by NOCO (see note (l) below). (i) Includes 217 shares which are held by Mr. Weatherly as custodian for his minor children and 60,000 shares which are subject to options under the 1994 Plan and 13,000 shares which are subject to options under the 1996 Plan, all of which are exercisable within 60 days. (j) Includes 25,000 shares subject to options under the 1994 Plan and 3,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days. (k) Includes 405,000 shares subject to options under the 1994 Plan and 45,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days. (l) The sole limited partner of NOCO is NOCO Holdings, L.P., and the sole general partner of NOCO is NOCO Properties Inc., a wholly-owned subsidiary of NOCO Holdings, L.P. The general partner of NOCO Holdings, L.P. is NOCO Management, Ltd., a limited liability company. The management of NOCO Management, Ltd. is vested in its four members: John C. Wallace, Barry I. Meade, B. F. Weatherly and Richard O. Wilson. The address of NOCO Holdings, L.P. and NOCO Management, Ltd. is the same as that listed above for NOCO. Mr. Wallace's address is 65 Vincent Square, London England SW1P 2RX. Mr. Meade's address is 6814 Northampton Way, Houston, Texas 77055. Mr. Weatherly's address is 9603 Doliver Street, Houston, Texas 77063. Mr. Wilson's address is 2400 West Loop South, Suite 150, Houston, Texas 77027. Messrs. Wallace, Weatherly and Meade also serve as officers of NOCO Management, Ltd. NOCO Properties Inc. and NOCO Management, Ltd. may be deemed to be the beneficial owner of the Common Stock held by NOCO as a result of their respective general partner interests in NOCO and NOCO Holdings, L.P. As a result of their positions with NOCO (FOOTNOTES CONTINUED ON FOLLOWING PAGE) 44 Management, Ltd., Messrs. Wallace, Meade, B. F. Weatherly and Wilson may be deemed to share the power to vote and dispose of such Common Stock and thereby to be the beneficial owner of such Common Stock. Under the terms of the Stockholders' Agreement, NOCO has the right of first refusal to acquire shares of Common Stock proposed to be sold by members of the Callon Family under certain circumstances and all parties to the Stockholders' Agreement have agreed to support two directors nominated by the Callon Family and two directors nominated by NOCO. NOCO disclaims beneficial ownership of the shares owned by members of the Callon Family. Because of the Stockholders' Agreement, NOCO and members of the Callon Family may be deemed to be a "group" for purposes of beneficial ownership under SEC regulations. If such a group were deemed to exist, it would beneficially own over 60% of the Common Stock. (m) Includes 318,220 shares issuable upon conversion of 140,000 shares of Series A Preferred Stock. STOCKHOLDERS' AGREEMENT Pursuant to the Stockholders' Agreement among the Callon Family and NOCO dated September 16, 1994, the Callon Family and NOCO each elect two directors to the Company's Board of Directors. Specifically, the Stockholders' Agreement provides that the Callon Family and NOCO shall use their best efforts, including voting the shares of Common Stock which they own, to cause the Company's Board of Directors to be composed of at least four members, two of such members to be selected by the Callon Family and two of such members to be selected by NOCO. The Stockholders' Agreement also contains restrictions on transfer of shares of Common Stock owned by the Callon Family and NOCO and prohibits the Callon Family and NOCO from taking certain actions which would result in certain changes of control or fundamental changes, without the consent of the other party. See "Management -- Certain Transactions." As a result of the Stockholders' Agreement, the Callon Family, on the one hand, and the Callon Family and NOCO, on the other, may be deemed to form a "group" for purposes of beneficial ownership under SEC regulations. The Callon Family disclaims beneficial ownership of the Common Stock owned by NOCO. In addition, each Callon Family stockholder disclaims beneficial ownership of all shares of Common Stock owned by the other Callon Family stockholders and the existence of a group comprised of the Callon Family stockholders. If NOCO and the Callon Family were deemed to be a group, it would beneficially own more than 60% of the outstanding Common Stock. DESCRIPTION OF NOTES The Notes are to be issued under the Indenture, dated as of November 27, 1996, between the Company and American Stock Transfer & Trust Company, as trustee (the "Trustee"). The following summary of certain provisions of the Indenture does not purport to be complete and is subject to, and is qualified in its entirety by reference to, the provisions of the Indenture (including the definition of certain terms in the Indenture), the form of which has been filed as an exhibit to the Registration Statement of which this Prospectus is a part. Wherever particular provisions and definitions of the Indenture are referred to, such provisions and definitions are incorporated by reference as part of the statements made, and the statements are qualified in their entirety by such reference. As used in this "Description of Notes," the term "Company" refers only to Callon Petroleum Company. Article and Section references are to Articles and Sections of the Indenture. GENERAL The Notes offered by this Prospectus will be limited to $21.0 million aggregate principal amount, plus up to an additional $3.15 million aggregate principal amount if the Underwriter's overallotment option is exercised. The Notes will be issued in global or registered form only, without coupons, in denominations of $1,000 and any integral multiple thereof. Interest on the Notes will accrue from November 27, 1996 and will be payable quarterly on the 15th day of each March, June, September and December in each year, commencing March 15, 1997, at the rate per annum stated on the cover page of this Prospectus. Interest will be payable to the person in whose name the Note is registered at the close of business on the 1st day of March, June, September and December, as the case may be, immediately preceding such Interest Payment Date. The Notes will mature on December 15, 2001, unless redeemed earlier at the option of the Company as set forth 45 below. The Company is not required to make mandatory redemption or sinking fund payments with respect to the Notes. Principal and interest will be payable at an office or agency to be maintained by the Company in New York City, except that, at the option of the Company in the event the Notes do not remain in book entry form, interest may be paid by check mailed to the person entitled thereto. The Notes may be presented for registration of transfer or exchange at an office or agency to be maintained by the Company in New York City. The Notes will be exchangeable without service charge but the Company may require payment to cover taxes or other government charges. Except under the conditions described in "Certain Covenants -- Liens" below, the Notes will not be secured by the assets of the Company or any of its subsidiaries or Affiliates or otherwise. All indebtedness of the Company under the Credit Facility (which constitutes Senior Indebtedness) is secured by substantially all of the producing oil and gas assets of the Company and its Subsidiaries. In addition, the rights of the Company to participate in any distribution of assets of any subsidiary upon its liquidation or reorganization or otherwise (and thus the ability of the Holders of the Notes to benefit indirectly from such distribution) are subject to the prior claims of creditors of the subsidiary. BOOK ENTRY SECURITIES The Notes will be issued in the form of a fully registered Global Certificate. The Global Certificate will be deposited with, or on behalf of, The Depository Trust Company, New York, New York (the "Depositary") and registered in the name of the Depositary's nominee. Except as set forth below, the Global Certificate may be transferred, in whole and not in part, only to another nominee of the Depositary or to a successor of the Depositary or its nominee. The Depositary has advised the Company and the Underwriter as follows: It is a limited-purpose trust company which was created to hold securities for its participating organizations (the "Participants") and to facilitate the clearance and settlement of transactions in such securities between Participants through electronic book entry changes in accounts of its Participants. Participants include securities brokers and dealers (including the Underwriter), banks, trust companies, clearing corporations and certain other organizations. Access to the Depositary's book entry system is also available to others, such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly ("Indirect Participants"). Persons who are not Participants may beneficially own securities held by the Depositary only through Participants or Indirect Participants. The Depositary has also advised that pursuant to procedures established by it (i) upon the issuance by the Company of the Notes, the Depositary will credit the accounts of Participants designated by the Underwriter with the principal amount of the Notes purchased by the Underwriter, and (ii) ownership of beneficial interests in the Global Certificate will be shown on, and the transfer of that ownership will be effected only through, records maintained by the Depositary (with respect to Participants' interests), the Participants and the Indirect Participants. The laws of some states require that certain persons take physical delivery in definitive form of securities which they own. Consequently, the ability to transfer beneficial interests in the Global Certificate is limited to such extent. So long as a nominee of the Depositary is the registered owner of the Global Certificate, such nominee will be considered the sole owner or Holder of the Notes for all purposes under the Indenture. Except as provided below, owners of beneficial interests in the Global Certificate will not be entitled to have Notes registered in their names, will not receive or be entitled to receive physical delivery of Notes in definitive form and will not be considered the owners or Holders thereof under the Indenture. Neither the Company, the Trustee, the paying agent nor the Notes registrar will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the Global Certificate, or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. 46 Principal and interest payments on the Global Certificate registered in the name of the Depositary's nominee will be made by the Company, either directly or through a paying agent, to the Depositary's nominee as the registered owner of the Global Certificate. Under the terms of the Indenture, the Company and the Trustee will treat the persons in whose names the Notes are registered as the owners of such Notes for the purpose of receiving payments of principal and interest on such Notes and for all other purposes whatsoever. Therefore, neither the Company, the Trustee nor any paying agent has any direct responsibility or liability for the payment of principal or interest on the Notes to owners of beneficial interests in the Global Certificate. The Depositary has advised the Company and the Trustee that its present practice is, upon receipt of any payment of principal or interest to credit immediately the accounts of the Participants with payment in amounts proportionate to their respective holdings in principal amount of beneficial interests in the Global Certificate as shown on the records of the Depositary. Payments by Participants and Indirect Participants to owners of beneficial interests in the Global Certificate will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers in bearer form or registered in "street name" and will be the responsibility of such Participants or Indirect Participants. The Company will issue Notes in definitive form in exchange for the Global Certificate if, and only if, either (1) the Depositary is at any time unwilling or unable to continue as depositary and a successor depositary is not appointed by the Company within 90 days, or (2) an Event of Default has occurred and is continuing and the Notes registrar has received a request from the Depositary to issue Notes in definitive form in lieu of all or a portion of the Global Certificate. In either instance, an owner of a beneficial interest in the Global Certificate will be entitled to have Notes equal in principal amount to such beneficial interest registered in its name and will be entitled to physical delivery of such Notes in definitive form. Notes so issued in definitive form will be issued in denominations of $1,000 and integral multiples thereof and will be issued in registered form only, without coupons. SUBORDINATION OF THE NOTES The payment of the principal of and interest on the Notes will be subordinated in right of payment, as set forth in Article Thirteen of the Indenture, to the prior payment in full of Senior Indebtedness, which will include borrowings under the Credit Facility, whether outstanding on the date of the Indenture or thereafter incurred. In the event of any insolvency or bankruptcy case or proceeding, or any receivership, liquidation, reorganization or other similar case or proceeding in connection therewith, relating to the Company or to its creditors, as such, or to its assets, or any liquidation, dissolution or other winding-up of the Company, whether voluntary or involuntary and whether or not including insolvency or bankruptcy, or any assignment for the benefit of creditors or other marshalling of assets or liabilities of the Company (provided that this provision will not require the repayment of all Senior Indebtedness in full in connection with the consolidation or merger of the Company or its liquidation or dissolution following the conveyance, transfer, lease or other disposition of all or substantially all the properties and assets of the Company and its Restricted Subsidiaries on a consolidated basis upon the terms and conditions described under the "Consolidation, Merger and Sale of Assets" covenant described below as a prerequisite to any payments being made to Holders of Notes), the holders of Senior Indebtedness will first be entitled to receive payment in full of all amounts due on or in respect of all Senior Indebtedness, or provision must be made for such payment, before the Holders of Notes will be entitled to receive any direct or indirect payment or distribution of any kind or character (other than any payment or distribution in the form of Permitted Junior Securities) on account of principal of or interest on the Notes or on account of the purchase or redemption or other acquisition of the Notes (including pursuant to an optional redemption). In the event that, notwithstanding the foregoing, the Trustee or the Holder of any Note receives any payment or distribution of properties or assets of the Company of any kind or character, whether in cash, property or securities, by set-off or otherwise, in respect of principal of or interest on the Notes before all Senior Indebtedness is paid or provided for in full, then the Trustee or the Holders of Notes receiving any such payment or distribution (other than a payment or distribution in the form of Permitted Junior Securities) will be required to pay or deliver such payment or distribution forthwith to the trustee in bankruptcy, receiver, liquidating trustee, 47 custodian, assignee, agent or other Person making payment or distribution of properties of assets of the Company for application to the payment of all Senior Indebtedness remaining unpaid, to the extent necessary to pay all Senior Indebtedness in full. The Company also may not make any payment or distribution of any properties or assets of the Company of any kind or character (other than Permitted Junior Securities) on account of principal of or interest on the Notes or on account of the purchase or redemption or other acquisition of Notes upon the occurrence of a Payment Event of Default with respect to any Specified Senior Indebtedness and receipt by the Trustee of written notice thereof until such Payment Event of Default shall have been cured or waived or shall have ceased to exist or such Specified Senior Indebtedness shall have been paid in full or otherwise discharged, after which the Company shall resume making any and all required payments in respect of the Notes, including any missed payments. The Company also may not make any payment or distribution of any properties or assets of the Company of any kind or character (other than Permitted Junior Securities) on account of any principal of or interest on the Notes or on account of the purchase or redemption or other acquisition of Notes for the period specified below ("Payment Blockage Period") upon the occurrence of a Non-payment Event of Default with respect to any Specified Senior Indebtedness and receipt by the Trustee and the Company of written notice thereof from one or more of the holders of such Specified Senior Indebtedness (or their representative). The Payment Blockage Period will commence upon the earlier of the dates of receipt by the Trustee or the Company of such notice from one or more of the holders of such Specified Senior Indebtedness (or their representative) and shall end on the earliest of (i) 179 days thereafter, (ii) the date, as set forth in a written notice from the holders of the Specified Senior Indebtedness (or their representative) to the Company or the Trustee, on which such Non-payment Event of Default is cured, waived in writing or ceases to exist or such Specified Senior Indebtedness is discharged or (iii) the date on which such Payment Blockage Period shall have been terminated by written notice to the Company or the Trustee from one or more of such holders (or their representative) initiating such Payment Blockage Period, after which the Company will resume (unless otherwise prohibited pursuant to the immediately preceding paragraph) making any and all required payments in respect of the Notes, including any missed payments. In any event, not more than one Payment Blockage Period may be commenced during any period of 360 consecutive days. No Non-payment Event of Default that existed or was continuing on the date of delivery of any Payment Blockage Notice to the Trustee can be made the basis for a subsequent Payment Blockage Notice. In the event that, notwithstanding the foregoing, the Company makes any payment to the Trustee or the Holder of any Note prohibited by the subordination provision of the Indenture, then such payment will be required to be paid over and delivered forthwith to the Company. If the Company fails to make any payment on the Notes when due or within any applicable grace period, whether or not on account of the payment blockage provision described above, such failure would constitute an Event of Default under the Indenture and would enable the Holders of the Notes to accelerate the maturity thereof. See " -- Events of Default and Remedies." As a result of such subordination provisions described above, in the event of a distribution of assets upon the liquidation, receivership, reorganization or insolvency of the Company, creditors of the Company who are holders of Senior Indebtedness may recover more, ratably, than the Holders of the Notes, and assets which would otherwise be available to pay obligations in respect of the Notes will be available only after all Senior Indebtedness has been paid in full, and there may not be sufficient assets remaining to pay amounts due on any or all of the Notes. The subordination provisions described above will cease to be applicable to the Notes upon any Legal Defeasance or Covenant Defeasance of the Notes as described under " -- Legal Defeasance and Covenant Defeasance." Senior Indebtedness may also be issued and incurred in the future, subject only to certain limitations contained in the covenant described under "Certain Covenants -- Limitation on Indebtedness for Money Borrowed". The Notes will also be structurally subordinated to all liabilities of the Company's Subsidiaries. As of September 30, 1996, the Company had an aggregate of $8.9 million of outstanding Senior 48 Indebtedness, and the Subsidiaries had liabilities of $13.0 million, excluding guarantees of Senior Indebtedness. CERTAIN COVENANTS RESTRICTIONS ON DIVIDENDS, REDEMPTIONS AND OTHER PAYMENTS (a) The Indenture will provide that the Company shall not, either directly or indirectly through any Restricted Subsidiary, (i) declare or pay any dividend, either in cash or property, on any shares of its capital stock (except dividends or other distributions payable solely in shares of capital stock of the Company), (ii) purchase, redeem or retire any shares of its capital stock or any warrants, rights or options to purchase or acquire any shares of its capital stock or (iii) make any other payment or distribution in respect of the Company's capital stock (such dividends, purchases, redemptions, retirements, payments and distributions being herein collectively called "Restricted Payments") if, after giving effect thereto, (1) an Event of Default would have occurred; or (2) (A) the sum of (i) such Restricted Payments plus (ii) the aggregate amount of all Restricted Payments made during the period after the date of the Indenture would exceed (B) the sum of (i) $10 million plus (ii) 50% of the Company's Consolidated Net Income subsequent to September 30, 1996 (with 100% reduction for a loss), plus (iii) the cumulative net proceeds received by the Company from the issuance or sale after the date of the Indenture of capital stock of the Company (including in such net proceeds the face amount of any indebtedness that has been converted into common stock of the Company after the date of the Indenture). (b) Notwithstanding paragraph (a) above, the Company may take the following actions so long as no Event of Default shall have occurred and be continuing: (i) the payment of dividends on any of the shares of the capital stock of the Company (including, without limitation, the Series A Preferred Stock of the Company); and (ii) the repurchase, redemption or other acquisition or retirement of any shares of any class of capital stock of the Company or any Restricted Subsidiary, in exchange for, or out of the aggregate net cash proceeds of a substantially concurrent issue and sale (other than to a Restricted Subsidiary) of shares of common stock of the Company. The actions described in clauses (i) and (ii) of this paragraph (b) shall be Restricted Payments that shall be permitted to be taken in accordance with this covenant and shall not reduce the amount that would otherwise be available for Restricted Payments under clause (2) of paragraph (a). For purposes of this covenant, the amount of any Restricted Payment payable in property shall be deemed to be the fair market value of such property as determined by the Board of Directors of the Company. (Section 1006) LIMITATION ON INDEBTEDNESS FOR MONEY BORROWED The Indenture will provide that the Company will not, and will not permit any Restricted Subsidiary to, create, incur, assume, guarantee or become liable ("incur") with respect to any Indebtedness for Money Borrowed, including Acquired Indebtedness but excluding Permitted Indebtedness, if, immediately after giving effect to any such creation, incurrence, assumption or guarantee (including giving effect to the retirement of any existing Indebtedness for Money Borrowed from the proceeds of such additional Indebtedness for Money Borrowed): (1) The ratio of (a) the aggregate amount of the outstanding Indebtedness for Money Borrowed of the Company and its Restricted Subsidiaries as of the end of the immediately preceding fiscal quarter of the Company, as determined on a consolidated basis in accordance with GAAP, to (b) the Consolidated EBITDA for the immediately preceding four fiscal quarters of the Company, would exceed 10.0 to 1.0; or (2) The Interest Coverage Ratio would have been at least 1.1 to 1.0. 49 Further, the Indenture will provide that the Company will not permit any Restricted Subsidiary to incur any Indebtedness for Money Borrowed (except to the Company or another Restricted Subsidiary) that is expressly subordinate in right of payment to any other Indebtedness for Money Borrowed of such Restricted Subsidiary. (Section 1007) LIENS The Indenture will provide that the Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create, incur, assume or suffer to exist any Lien of any kind, except for Permitted Liens, upon any of their respective assets or properties, whether now owned or acquired after the date of the Indenture, or any income or profits therefrom to secure any Pari Passu Indebtedness or Subordinated Indebtedness, unless prior to or contemporaneously therewith the Notes are directly secured equally and ratably, provided that (1) if such secured indebtedness is Pari Passu Indebtedness, the Lien securing such Pari Passu Indebtedness shall be subordinate and junior to, or PARI PASSU with, the Lien securing the Notes and (2) if such secured indebtedness is Subordinated Indebtedness, the Lien securing such Subordinated Indebtedness shall be subordinate and junior to the Lien securing the Notes at least to the same extent as such Subordinated Indebtedness is subordinated to the Notes. The foregoing covenant will not apply to any Lien securing Acquired Indebtedness, provided that any such Lien extends only to the properties or assets that were subject to such Lien prior to the related acquisition by the Company or such Restricted Subsidiary and was not created, incurred or assumed in contemplation of such transaction. (Section 1008) LIMITATION ON RANKING OF FUTURE INDEBTEDNESS The Indenture will provide that the Company will not incur or permit to remain outstanding any Indebtedness for Money Borrowed (including Acquired Indebtedness and Permitted Indebtedness) which is expressly subordinate in right of payment to any Senior Indebtedness, other than Subordinated Indebtedness or Pari Passu Indebtedness. For purposes of this covenant, the incurrence of Senior Indebtedness which is unsecured shall not, because of its unsecured status, be deemed to be subordinate in right of payment to any Senior Indebtedness which is secured. (Section 1013) LIMITATIONS ON RESTRICTING SUBSIDIARY DIVIDENDS The Indenture will provide that the Company shall not and shall not permit any Restricted Subsidiary to, directly or indirectly, create or otherwise cause to become effective any encumbrance or restriction of any kind on the ability of any Restricted Subsidiary to (a) pay dividends in cash or make any other distribution on its capital stock to the Company or any other Restricted Subsidiary, (b) pay any indebtedness owed to the Company or any other Restricted Subsidiary, (c) make loans, advances, or capital contributions to the Company or any other Restricted Subsidiary, or (d) transfer any of its properties or assets to the Company or another Restricted Subsidiary, except in each instance (i) as set forth in the instrument evidencing or the agreement governing Acquired Indebtedness of any acquired Person which becomes a Restricted Subsidiary, provided, that any restriction or encumbrance under such instrument or agreement existed at the time of acquisition, was not put in place in anticipation of such acquisition, and is not applicable to any Person, other than the Person or property or assets of the Person so acquired; (ii) customary provisions of any lease or license of the Company or any Restricted Subsidiary relating to the property covered thereby and entered into in the ordinary course of business; (iii) any encumbrance or restriction arising under applicable law; (iv) any encumbrance or restriction arising under the Indenture, the Credit Facility, or other indebtedness or other agreements existing on the date of original issuance of the Notes; (v) any restrictions with respect to a Restricted Subsidiary imposed pursuant to an agreement that has been entered into for the sale or disposition of the stock, business, assets or properties of such Restricted Subsidiary; (vi) any encumbrance or restriction arising under the terms of purchase money obligations, but only to the extent such purchase money obligations restrict or prohibit the transfer of the property so acquired; (vii) any encumbrance or restriction arising under customary non-assignment provisions in installment purchase contracts; (viii) any encumbrance or restriction on the ability of any Restricted Subsidiary to transfer any of its property acquired after the date of the Indenture to the Company or any other Restricted Subsidiary that is required by a lender to, or purchaser of any indebtedness of, such 50 Restricted Subsidiary in connection with a financing of the acquisition of such property (including with respect to the purchase of asset portfolios and pursuant to the underwriting or origination of mortgage loans) by such Restricted Subsidiary; and (ix) any encumbrance or restriction pursuant to any agreement that extends, refinances, renews or replaces any agreement described in the foregoing clauses (i) through (viii), and except with respect to clause (d) only, restrictions in the form of Liens which are not prohibited as described in the "Liens" covenant and which contain customary limitations on the transfer of collateral. (Section 1014) LIMITATION ON TRANSACTIONS WITH AFFILIATES The Indenture will provide that the Company shall not, and shall not permit any of its Restricted Subsidiaries to, enter into any transaction (or series of related transactions), including, without limitation, the sale, purchase, lease, or exchange of any property or the rendering of any service (a "Transaction"), involving payments in excess of $50,000, with any Affiliate of the Company (other than the Company or a Restricted Subsidiary), on terms and conditions less favorable to the Company or such Restricted Subsidiary, as the case may be, than would be available at such time in a comparable Transaction in arm's length dealings with an unrelated Person as determined by the Board of Directors, such approval to be evidenced by a Board Resolution. The provisions of the immediately preceding paragraph will not apply to: (1) Restricted Payments otherwise permitted pursuant to the covenant described under " -- Restrictions on Dividends, Redemptions and Other Payments"; (2) fees and compensation (including amounts paid pursuant to employee benefit plans) paid to, and indemnity provided on behalf of, officers, directors, employees or consultants of the Company or any Restricted Subsidiary, as determined by the Board of Directors or the senior management thereof in the exercise of their reasonable business judgment; or (3) payments for goods and services purchased in the ordinary course of business on an arm's length basis. (Section 1015) REPORTS So long as the Company is a reporting company under the Exchange Act, the Company will furnish to Holders of the Notes annual reports of the Company containing audited consolidated financial statements and interim reports with unaudited consolidated summary financial data on a quarterly basis. If the Company ceases to be a reporting company under the Exchange Act, the Company will furnish to Holders of the Notes annual audited consolidated financial statements and quarterly unaudited consolidated summary financial statements. (Section 704) EVENTS OF DEFAULT AND REMEDIES An Event of Default will include: (i) failure to pay the principal of the Notes when due at Stated Maturity, upon redemption or upon acceleration, as provided in the Indenture, whether or not prohibited by the subordination provisions of the Indenture, (ii) failure to pay any interest on the Notes for 30 days, whether or not prohibited by the subordination provisions of the Indenture, (iii) failure to perform, or a breach of, any other covenant or agreement set forth in the Indenture for 30 days after receipt of written notice from the Trustee or Holders of at least 25% in aggregate principal amount of the outstanding Notes specifying the default and requiring the Company to remedy such default, (iv) default in the payment at Stated Maturity of Indebtedness for Money Borrowed of the Company or any Restricted Subsidiary having an outstanding principal amount due at Stated Maturity greater than $2.5 million and such default having continued for a period of 30 days beyond any applicable grace period, (v) an event of default as defined in any mortgage, indenture or instrument of the Company or any Restricted Subsidiary shall have happened and resulted in acceleration of Indebtedness for Money Borrowed which, together with the principal amount of any other Indebtedness for Money Borrowed so accelerated, exceeds $2.5 million or more at any time, and such default shall not be cured or waived and such acceleration shall not have been rescinded or annulled within a period of 30 days from the occurrence of such acceleration, (vi) certain events of insolvency, receivership or reorganization of the Company or any Material Subsidiary and (vii) entry of a final judgment, decree or order against the Company or any Material Subsidiary for the payment of money 51 in excess of $2.5 million and such judgment, decree or order continues unsatisfied for 30 days without a stay of execution. (Section 501) If any Event of Default (other than as specified in clause (vi) above) occurs and is continuing, the Trustee, by written notice to the Company, or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding, by notice to the Trustee and the Company, may, and the Trustee upon the request of the Holders of not less than 25% in aggregate principal amount of the Notes then outstanding shall, declare the principal of and accrued interest on all of the Notes due and payable immediately, upon which declaration all amounts payable in respect of the Notes shall be immediately due and payable. If an Event of Default specified in clause (vi) above occurs and is continuing, then the principal of and accrued interest on all of the Notes then outstanding shall automatically become and be immediately due and payable without any declaration, notice or other act on the part of the Trustee or any Holder of Notes. (Section 502) After a declaration of acceleration under the Indenture, but before a judgment or decree for payment of the money due has been obtained by the Trustee, the Holders of a majority in aggregate principal amount of the outstanding Notes, by written notice to the Company and the Trustee, may rescind such declaration if (a) the Company has paid or deposited with the Trustee a sum sufficient to pay (i) all sums paid or advanced by the Trustee under the Indenture and the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, (ii) all overdue interest on all Notes, (iii) the principal of any Notes which have become due otherwise than by such declaration of acceleration and interest thereon at the rate borne by the Notes, and (iv) to the extent that payment of such interest is lawful, interest upon overdue interest and overdue principal at the rate borne by the Notes (without duplication of any amount paid or deposited pursuant to clause (ii) or (iii) ); (b) the rescission would not conflict with any judgment or decree of a court of competent jurisdiction; and (c) all Events of Default, other than the nonpayment of principal of or interest on the Notes that has become due solely by such declaration of acceleration, have been cured or waived. (Section 502) No Holder of any of the Notes will have any right to institute any proceeding with respect to the Indenture or any remedy thereunder, unless such Holder has notified the Trustee of a continuing Event of Default and the Holders of at least 25% in aggregate principal amount of the outstanding Notes have made written request, and offered reasonable indemnity, to the Trustee to institute such proceeding as Trustee under the Notes and the Indenture, the Trustee has failed to institute such proceeding within 60 days after receipt of such notice and the Trustee, within such 60-day period, has not received directions inconsistent with such written request by Holders of a majority in aggregate principal amount of the outstanding Notes. Such limitations will not apply, however, to a suit instituted by a Holder of a Note for the enforcement of the payment of the principal of or interest on such Note on or after the respective due dates expressed in such Note. (Section 507 and 508) During the existence of an Event of Default, the Trustee will be required to exercise such rights and powers vested in it under the Indenture and use the same degree of care and skill in its exercise thereof as a prudent person would exercise under the circumstances in the conduct of such person's own affairs. Subject to the provisions of the Indenture relating to the duties of the Trustee in case an Event of Default shall occur and be continuing, the Trustee will not be under any obligation to exercise any of its rights or powers under the Indenture at the request or direction of any of the Holders of Notes unless such Holders shall have offered to the Trustee reasonable security or indemnity. Subject to certain provisions concerning the rights of the Trustee, the Holders of a majority in aggregate principal amount of the outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee under the Indenture. (Sections 512, 601 and 603) The Holders of not less than a majority in aggregate principal amount of the Notes then outstanding may on behalf of the Holders of all of the Notes waive any existing Default or Event of Default and its consequences, except in respect of the payment of the principal of or interest on any Note or in respect of a 52 provision of the Indenture which cannot be modified or amended without the consent of the Holder of each Note affected thereby as described below under " -- Modification and Waiver." (Section 513) If a Default or an Event of Default occurs and is continuing and is known to the Trustee, the Trustee shall mail to each Holder of Notes notice of the Default or Event of Default within 90 days after the occurrence thereof. Except in the case of a Default or an Event of Default in payment of principal of or interest on any Notes, the Trustee may withhold the notice to the Holders of Notes if the Trustee determines in good faith that withholding the notice is in the interest of such Holders. (Section 602) The Company is required to deliver to the Trustee annual and quarterly statements regarding compliance with the Indenture, and the Company will also be required, upon becoming aware of any Default or Event of Default, to deliver to the Trustee a statement specifying such Default or Event of Default. (Section 1011) REDEMPTION AT OPTION OF THE COMPANY The Notes are subject to redemption at 100% of the principal amount thereof plus accrued interest, at the option of the Company in whole or in part from time to time, on or after December 15, 1997, upon not less than 30 nor more than 60 days' notice mailed to the registered Holders thereof. The redemption price will be paid with interest accrued to the date fixed for redemption. If the Company elects to redeem less than all of the Notes, the Trustee will select which Notes to redeem by lot or such other method as it shall deem fair and appropriate, including the selection for redemption of a portion of the principal amount of any Note but not less than $1,000. On and after the redemption date, interest will cease to accrue on the Notes or portions thereof called for redemption. (Article Eleven) MODIFICATION AND WAIVER With certain limited exceptions which permit modifications of the Indenture by the Company and the Trustee only, the Indenture may be modified by the Company with the consent of Holders of not less than a majority in aggregate principal amount of outstanding Notes; PROVIDED, HOWEVER, that no such changes shall without the consent of the Holder of each Note affected thereby (i) change the maturity date of the principal of, or the due date of any installment of interest on, any Note, (ii) reduce the principal of, or the rate of interest on, any Note, (iii) change the place of payment or the currency in which any portion of the principal of, or interest on, any Note is payable, (iv) impair the right to institute suit for the enforcement of any such payment, (v) reduce the above-stated percentage of Holders of the outstanding Notes necessary to modify the Indenture, (vi) modify the foregoing requirements or reduce the percentage of outstanding Notes necessary to waive any past default or certain covenants or (vii) reduce the relative ranking of the Notes. (Section 902) The Holders of a majority in aggregate principal amount of outstanding Notes may waive compliance by the Company with certain covenants, most of which are described above under " -- Certain Covenants." (Section 1012) CONSOLIDATION, MERGER AND SALE OF ASSETS The Company may not consolidate with, merge with, or transfer all or substantially all of its assets to another entity where the Company is not the surviving corporation unless (i) such other entity assumes the Company's obligations under the Indenture, (ii) such other entity shall be a Person organized and existing under the laws of the United States of America, any state thereof or the District of Columbia, and (iii) after giving effect thereto, no event shall have occurred and be continuing which, after notice or lapse of time, would become an Event of Default. (Section 801) LEGAL DEFEASANCE AND COVENANT DEFEASANCE The Company may, at its option and at any time, elect to have all of the obligations of the Company discharged with respect to the outstanding Notes ("Legal Defeasance"). Such Legal Defeasance means that the Company shall be deemed to have paid and discharged the entire indebtedness represented by the outstanding Notes and to have been discharged from all their other obligations with respect to such Notes, 53 except for (i) the rights of Holders of outstanding Notes to receive payment in respect of the principal of and interest on such Notes when such payments are due, (ii) the Company's obligations to replace any temporary Notes, register the transfer or exchange of any Notes, replace mutilated, destroyed, lost or stolen Notes and maintain an office or agency for payments in respect of the Notes, (iii) the rights, powers, trusts, duties and immunities of the Trustee, and (iv) the Legal Defeasance provisions of the Indenture. In addition, the Company may, at its option and at any time, elect to have the obligations of the Company released with respect to certain covenants that are described in the Indenture, some of which are described under " -- Certain Covenants" above, and thereafter any omission to comply with such obligations shall not constitute a Default or an Event of Default with respect to the Notes ("Covenant Defeasance"). In the event Covenant Defeasance occurs, certain events (not including nonpayment, bankruptcy, insolvency and reorganization events) described under " -- Events of Default and Remedies" will no longer constitute an Event of Default with respect to the Notes. In order to exercise either Legal Defeasance or Covenant Defeasance, (i) the Company must irrevocably deposit with the Trustee, in trust, for the benefit of the Holders of the Notes, cash in United States dollars, Government Obligations (as defined in the Indenture), or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of and interest on the outstanding Notes to redemption or maturity; (ii) the Company shall have delivered to the Trustee an Opinion of Counsel to the effect that the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance or Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance or Covenant Defeasance had not occurred (in the case of Legal Defeasance, such opinion must refer to and be based upon a published ruling of the Internal Revenue Service or a change in applicable federal income tax laws); (iii) no Default or Event of Default shall have occurred and be continuing on the date of such deposit or insofar as clause (vi) under the first paragraph under " -- Events of Default and Remedies" is concerned, at any time during the period ending on the 91st day after the date of deposit; (iv) such Legal Defeasance or Covenant Defeasance shall not cause the Trustee to have a conflicting interest under the Indenture or the Trust Indenture Act of 1939 with respect to any securities of the Company; (v) such Legal Defeasance or Covenant Defeasance shall not result in a breach or violation of, or constitute a default under, any other material agreement or instrument to which the Company is a party or by which it is bound; and (vi) the Company shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, which, taken together, state that all conditions precedent under the Indenture to either Legal Defeasance or Covenant Defeasance, as the case may be, have been complied with. (Article Twelve) SATISFACTION AND DISCHARGE OF INDENTURE The Indenture will be discharged and will cease to be of further effect (except as to surviving rights of registration of transfer or exchange of the Notes, as expressly provided for in the Indenture) as to all outstanding Notes when (i) either (a) all the Notes theretofore authenticated and delivered (except lost, stolen or destroyed Notes which have been replaced or paid and Notes for whose payment money or Government Obligations have theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust) have been delivered to the Trustee for cancellation or (b) all Notes not theretofore delivered to the Trustee for cancellation have become due and payable or will become due and payable at their Stated Maturity within one year, or are to be called for redemption within one year under arrangements satisfactory to the Trustee for the serving of notice of redemption by the Trustee in the name, and at the expense, of the Company, and the Company has irrevocably deposited or caused to be deposited with the Trustee funds in an amount sufficient to pay and discharge the entire indebtedness on the Notes not theretofore delivered to the Trustee for cancellation, for principal of and interest on the Notes to the date of deposit (in the case of Notes which have become due and payable) or to the Stated Maturity or redemption date, as the case may be, together with instructions from the Company irrevocably directing the Trustee to apply such funds to the payment thereof at maturity or redemption, as the case may be; (ii) the Company has paid all other sums then due and payable under the 54 Indenture by the Company; and (iii) the Company has delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, which, taken together, state that all conditions precedent under the Indenture relating to the satisfaction and discharge of the Indenture have been complied with. (Sections 401 and 402) GOVERNING LAW The Indenture and the Notes will be governed and construed in accordance with the laws of the State of New York. (Section 113) THE TRUSTEE American Stock Transfer & Trust Company will be the Trustee under the Indenture. The Trustee is the transfer agent and registrar for both the Common Stock and the Series A Preferred Stock. The Indenture provides for the indemnification of the Trustee by the Company under certain circumstances. (Section 607) The Indenture (including the provisions of the Trust Indenture Act of 1939 incorporated by reference therein) will contain limitations on the rights of the Trustee thereunder, should it become a creditor of the Company, to obtain payment of claims in certain cases or to realize on certain property received by it in respect of any such claims, as security or otherwise. The Trustee is permitted to engage in other transactions; PROVIDED, HOWEVER, if it acquires any conflicting interest (as defined in the Trust Indenture Act of 1939) it must eliminate such conflict or resign. (Sections 613 and 614) CERTAIN DEFINITIONS Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided. (Section 101) "Acquired Indebtedness" means Indebtedness for Money Borrowed of a Person existing at the time such Person becomes a Restricted Subsidiary or assumed in connection with the acquisition by the Company or a Restricted Subsidiary of assets from such Person, and not incurred in connection with, or in anticipation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to be incurred on the date of the related acquisition of assets from any Person or the date the acquired Person becomes a Restricted Subsidiary. "Affiliate" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, "control", when used with respect to any specified Person, means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms "controlling" and "controlled" have meanings correlative to the foregoing. "Average Life" means, with respect to any Indebtedness for Money Borrowed, as at any date of determination, the quotient obtained by dividing (a) the sum of the products of (i) the number of years (and any portion thereof) from the date of determination to the date or dates of each successive scheduled principal payment (including, without limitation, any sinking fund or mandatory redemption payment requirements) of such Indebtedness for Money Borrowed multiplied by (ii) the amount of each such principal payment by (b) the sum of all such principal payments. "Board of Directors" means the board of directors of the Company or any duly authorized committee of that board. "Capitalized Lease Obligation" means, as to any Person, the obligations of such Person to pay rent or other amounts under a lease of (or other agreement conveying the right to use) real or personal property which obligations are required to be classified and accounted for as capital lease obligations on a balance sheet of such Person under GAAP and, for purposes of the Indenture, the amount of such obligations at any date shall be the capitalized amount thereof at such date, determined in accordance with GAAP. 55 "Consolidated EBITDA" means, for any period, determined in accordance with GAAP on a consolidated basis for the Company and its Restricted Subsidiaries, the sum of Consolidated Net Income, plus depreciation, depletion, amortization and other non-cash charges, income tax expense, and interest expense, for such period, each as deducted in determining such Consolidated Net Income. "Consolidated Interest Expense" means, for any period, the interest expense for such period, which is required to be shown as such on the financial statements of the Company and its Restricted Subsidiaries, on a consolidated basis, prepared in accordance with GAAP. "Consolidated Net Income" means, for any period, the amount of consolidated net income (loss) of the Company and its Restricted Subsidiaries for such period, determined in accordance with GAAP; PROVIDED, HOWEVER, that there shall be included in Consolidated Net Income any net extraordinary gains or losses for such period (less all fees and expenses related thereto); and, PROVIDED, FURTHER, that there shall not be included in Consolidated Net Income (1) any net income (loss) of a Restricted Subsidiary for any portion of such period during which it was not a Consolidated Subsidiary, (2) any net income (loss) of businesses, properties or assets acquired or disposed of (by way of merger, consolidation, purchase, sale or otherwise) by the Company or any Restricted Subsidiary for any portion of such period prior to the acquisition thereof or subsequent to the disposition thereof or (3) any net income for such period resulting from transfers of assets received by the Company or any Restricted Subsidiary from an Unrestricted Subsidiary. "Consolidated Subsidiary" means a Restricted Subsidiary the financial statements of which are consolidated with the financial statements of the Company. "Corporation" includes corporations, associations, companies, joint stock companies, limited liability companies or business trusts. "Credit Facility" means that certain Amended and Restated Credit Agreement, dated as of October 31, 1996, among the Company, Callon Petroleum Operating Company, Callon Offshore Production, Inc., the several banks and other financial institutions from time to time parties thereto (the "Banks"), and The Chase Manhattan Bank, as agent for the Banks, as the same may be amended, modified, supplemented, extended, restated, replaced, renewed or refinanced from time to time. "Event of Default" has the meaning specified in the covenant described under " -- Events of Default and Remedies." "GAAP" means United States generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board in effect on the date of the Indenture. "Holder" when used with respect to the Notes, means the Person in whose name such Note is registered in the Note Register. "Indebtedness for Money Borrowed" means any of the following obligations of the Company or any Restricted Subsidiary: (1) any obligations, contingent or otherwise, for borrowed money or for the deferred purchase price of property, assets, securities or services (including, without limitation, any interest accruing subsequent to an event of default), (2) all obligations (including the Notes) evidenced by bonds, notes, debentures or other similar instruments, (3) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), except any such obligation that constitutes a trade payable and an accrued liability arising in the ordinary course of business, if and to the extent any of the foregoing indebtedness would appear as a liability upon a balance sheet prepared in accordance with GAAP, (4) all Capitalized Lease Obligations, (5) liabilities of the Company actually due and payable under bankers acceptances and letters of credit, (6) all indebtedness of the type referred to in clause (1), (2), (3), (4) or (5) above secured by (or for which the holder of such indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien upon or security interest in property of the Company or any Restricted Subsidiary (including, without limitation, accounts and contract rights), even though the Company or any Restricted Subsidiary has not assumed or 56 become liable for the payment of such indebtedness, and (7) any guarantee or endorsement (other than for collection or deposit in the ordinary course of business) or discount with recourse of, or other agreement, contingent or otherwise, to purchase, repurchase, or otherwise acquire, to supply, or advance funds or become liable with respect to, any indebtedness or any obligation of the type referred to in any of the foregoing clauses (1) through (6), regardless of whether such obligation would appear on a balance sheet; PROVIDED, HOWEVER, that Indebtedness for Money Borrowed shall not include (i) Production Payments and Reserve Sales, (ii) any liability for gas balancing incurred in the ordinary course of business, (iii) accounts payable or other obligations of the Company or a Restricted Subsidiary in the ordinary course of business in connection with the obtaining of goods or services, and (iv) any liability under any and all (A) employment or consulting agreements or employee benefit plans or arrangements and (B) futures contracts, forward contracts, swap, cap or collar contracts, option contracts, or other similar derivative agreements. "Interest Coverage Ratio" means, for any date of determination, the ratio of (1) Consolidated EBITDA for the immediately preceding four fiscal quarters of the Company to (2) Consolidated Interest Expense for such immediately preceding four fiscal quarters. "Lien" means any mortgage, charge, pledge, lien (statutory or other), security interest, hypothecation, assignment for security, claim, or preference or priority or other encumbrance or similar agreement or preferential arrangement of any kind or nature whatsoever (including, without limitation, any agreement to give or grant a Lien or any lease, conditional sale or other title retention agreement having substantially the same economic effect as any of the foregoing) upon or with respect to any property of any kind. A Person shall be deemed to own subject to a Lien any property which such Person has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement. "Material Subsidiary" means any Restricted Subsidiary whose assets or revenues comprise at least five percent (5%) of the assets or revenues of the Company and the Restricted Subsidiaries on a consolidated basis as of the end of, or for the, Company's most recently completed fiscal quarter, as determined from time to time. "Non-payment Event of Default" means any event (other than a Payment Event of Default), the occurrence of which (with or without notice or the passage of time) entitles one or more Persons to accelerate the maturity of any Specified Senior Indebtedness. "Note Register" means the register maintained by or for the Company in which the Company shall provide for the registration of the Notes and of transfer of the Notes. "PARI PASSU Indebtedness" means any Indebtedness for Money Borrowed of the Company that is PARI PASSUin right of payment to the Notes. "Payment Event of Default" means any default in the payment or required prepayment of principal of (or premium, if any, on) or interest on any Specified Senior Indebtedness when due (whether at final maturity, upon scheduled installment, upon acceleration or otherwise). "Permitted Indebtedness" means any of the following: (i) Indebtedness for Money Borrowed outstanding on the date of the Indenture (and not repaid or defeased with the proceeds of the offering of the Notes); (ii) Indebtedness for Money Borrowed of the Company to a Restricted Subsidiary and Indebtedness for Money Borrowed of a Restricted Subsidiary to the Company or a Restricted Subsidiary; provided, however, that upon any event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any subsequent transfer of any such Indebtedness for Money Borrowed (except to the Company or a Restricted Subsidiary), such Indebtedness for Money Borrowed shall be deemed, in each case, to be incurred and shall be treated as an incurrence for purposes of the "Limitation on Indebtedness for Money Borrowed" covenant at the time the Restricted Subsidiary in question ceased to be a Restricted Subsidiary; 57 (iii) any guarantee of Senior Indebtedness incurred in compliance with the "Limitation on Indebtedness for Money Borrowed" covenant, by a Restricted Subsidiary or the Company; and (iv) any renewals, substitutions, refinancings or replacements (each, for purposes of this clause, a "refinancing") by the Company or a Restricted Subsidiary of any Indebtedness for Money Borrowed incurred pursuant to clause (i) of this definition, including any successive refinancings by the Company or such Restricted Subsidiary, so long as (A) any such new Indebtedness for Money Borrowed shall be in a principal amount that does not exceed the principal amount (or, if such Indebtedness for Money Borrowed being refinanced provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount as of the date of determination) so refinanced plus the amount of any premium required to be paid in connection with such refinancing pursuant to the terms of the Indebtedness for Money Borrowed refinanced or the amount of any premium reasonably determined by the Company or such Restricted Subsidiary as necessary to accomplish such refinancing, plus the amount of expenses of the Company or such Restricted Subsidiary incurred in connection with such refinancing, and (B) in the case of any refinancing of Indebtedness for Money Borrowed of the Company that is not Senior Indebtedness, such new Indebtedness for Money Borrowed is either PARI PASSU with the Notes or subordinated to the Notes at least to the same extent as the Indebtedness being refinanced and (C) such new Indebtedness for Money Borrowed has an Average Life equal to or longer than the Average Life of the Indebtedness for Money Borrowed being refinanced and a final Stated Maturity equal to or later than the final Stated Maturity of the Indebtedness for Money Borrowed being refinanced. "Permitted Junior Securities" means any equity securities or subordinated debt securities of the Company or any successor obligor with respect to the Senior Indebtedness provided for by a plan of reorganization or readjustment that, in the case of any such subordinated debt securities, are subordinated in right of payment to all Senior Indebtedness that may at the time be outstanding to substantially the same degree as, or to a greater extent than, the Notes are so subordinated as provided in the Indenture. "Permitted Liens" means any of the following types of Liens: (a) Liens existing as of the date the Notes are first issued (except to the extent such Liens secure any Pari Passu Indebtedness or Subordinated Indebtedness that is repaid or defeased with proceeds of the offering of the Notes), and any renewal, extension or refinancing of any such Lien provided that thereafter such Lien extends only to the properties that were subject to such Lien prior to the renewal, extension or refinancing thereof; (b) Liens securing the Notes; and (c) Liens in favor of the Company. "Person" means any individual, Corporation, partnership, joint venture, association, joint stock company, trust, unincorporated organization or government or any agency or political subdivision thereof. "Production Payments and Reserve Sales" means the grant or transfer to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), master limited partnership interest or other interest in oil and gas properties, which reserves the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard and/or subject to the obligation of the grantor or transferor to indemnify for environmental matters. "Restricted Subsidiary" means any Subsidiary, whether existing on or after the date of the Indenture, unless such Subsidiary is an Unrestricted Subsidiary or is designated as an Unrestricted Subsidiary pursuant to the terms of the Indenture. "Senior Indebtedness" means the principal amount of, and interest on and all other amounts due on or in connection with, (1) any Indebtedness for Money Borrowed of the Company, whether now outstanding or 58 hereafter created, incurred, assumed or guaranteed, unless in the instrument creating or evidencing such Indebtedness for Money Borrowed or pursuant to which such Indebtedness for Money Borrowed is outstanding it is provided that such indebtedness is subordinate in right of payment or in rights upon liquidation to any other Indebtedness for Money Borrowed of the Company and (2) all renewals, extensions and refundings of any such indebtedness. "Specified Senior Indebtedness" means (a) all Senior Indebtedness of the Company in respect of the Credit Facility and any renewals, amendments, extensions, supplements, modifications, deferrals, refinancings, or replacements (each, for purposes of this definition, a "refinancing") thereof by the Company, including any successive refinancings thereof by the Company and (b) any other Senior Indebtedness and any refinancings thereof by the Company having a principal amount of at least $5 million as of the date of determination and provided that the agreements, indentures or other instruments evidencing such Senior Indebtedness or pursuant to which such Senior Indebtedness was issued specifically designates such Senior Indebtedness as "Specified Senior Indebtedness" for purposes of the Indenture. For purposes of this definition, a refinancing of any Specified Senior Indebtedness shall be treated as Specified Senior Indebtedness only if the Senior Indebtedness issued in such refinancing ranks or would rank PARI PASSU with the Specified Senior Indebtedness refinanced and only if the Senior Indebtedness issued in such refinancing is permitted by the covenant described under "Certain Covenants -- Limitation of Indebtedness for Money Borrowed." "Stated Maturity" with respect to any Note or any installment of principal thereof or interest thereon means the date established by the Indenture as the fixed date on which the principal of such Note or such installment of principal or interest is due and payable, and, when used with respect to any other Indebtedness for Money Borrowed or any installment of interest thereon, means the date specified in the instrument evidencing or governing such Indebtedness for Money Borrowed as the fixed date on which the principal of such Indebtedness for Money Borrowed or such installment of interest is due and payable. "Subordinated Indebtedness" means Indebtedness for Money Borrowed of the Company which is expressly subordinated in right of payment to the Notes, including, without limitation, the Convertible Debentures. "Subsidiary" means any Corporation of which at the time of determination the Company or one or more Subsidiaries owns or controls directly or indirectly more than 50% of the Voting Stock. "Unrestricted Subsidiary" means (i) any Subsidiary that at the time of determination will be designated an Unrestricted Subsidiary by the Board of Directors as provided below and (ii) any Subsidiary of an Unrestricted Subsidiary. The Board of Directors may designate any Subsidiary as an Unrestricted Subsidiary so long as neither the Company nor any Restricted Subsidiary is directly or indirectly liable pursuant to the terms of any Indebtedness for Money Borrowed of such Subsidiary or has any assets or properties which are subject to any Lien securing any Indebtedness for Money Borrowed of such Subsidiary. Any such designation by the Board of Directors shall be evidenced to the Trustee by filing a Board Resolution with the Trustee giving effect to such designation. The Board of Directors may designate any Unrestricted Subsidiary as a Restricted Subsidiary if, immediately after giving effect to such designation, (i) no Event of Default shall have occurred and be continuing and (ii) the Company could occur $1.00 of additional Indebtedness for Money Borrowed (other than Permitted Indebtedness) under the "Limitation on Indebtedness for Money Borrowed" covenant. "Voting Stock" means stock, interests, participations, rights in or other equivalents in the equity interests (however designated) with respect to a Corporation having general voting power under ordinary circumstances to elect at least a majority of the board of directors, managers or trustees of such Corporation, PROVIDED that, for the purposes hereof, stock which carries only the right to vote conditionally on the happening of an event shall not be considered Voting Stock whether or not such event shall have happened. 59 DESCRIPTION OF OUTSTANDING SECURITIES AND DEBT INSTRUMENTS COMMON STOCK The Company is authorized by its Charter to issue up to 20,000,000 shares of Common Stock, $0.01 par value. As of October 25, 1996, 5,754,863 shares of Common Stock were issued and outstanding. Holders of Common Stock are entitled to one vote per share in the election of directors and on all other matters submitted to a vote of stockholders. Such holders do not have the right to cumulate their votes in the election of directors. Holders of Common Stock have no redemption or conversion rights and no preemptive or other rights to subscribe for securities of the Company. In the event of a liquidation, dissolution or winding up of the Company, holders of Common Stock are entitled to share equally and ratably in all of the assets remaining, if any, after satisfaction of all debts and liabilities of the Company, and of the preferential rights of any series of preferred stock then outstanding. The outstanding shares of Common Stock are validly issued, fully paid and nonassessable. Holders of Common Stock are entitled to receive dividends when, as and if declared by the Board of Directors out of funds legally available therefor. American Stock Transfer & Trust Company is transfer agent and registrar for the Common Stock. PREFERRED STOCK The Company is authorized by its Charter to issue 2,500,000 shares of preferred stock, $0.01 par value per share. The Board of Directors has the authority to divide the preferred stock into one or more series and to fix and determine the relative rights and preferences of the shares of each such series, including dividend rates, terms of redemption, sinking funds, the amount payable in the event of voluntary liquidation, dissolution or winding up of the affairs of the Company, conversions rights and voting powers. The Company has authorized the issuance of the Convertible Exchangeable Preferred Stock, Series A, consisting of up to 1,380,000 shares of preferred stock ("Series A Preferred Stock"). SERIES A PREFERRED STOCK In November 1995, the Company issued and sold 1,315,500 shares of its Series A Preferred Stock. The following description of the Series A Preferred Stock is qualified in its entirety by the Certificate of Designations dated November 22, 1995, a copy of which is filed as an exhibit to the Registration Statement of which this Prospectus is a part. DIVIDEND RIGHTS. Holders of the Series A Preferred Stock are entitled to an annual cash dividend of $2.125 per share, payable quarterly. If dividends are not paid in full on all outstanding shares of the Series A Preferred Stock and any other security ranking on parity with the Series A Preferred Stock, dividends declared on the Series A Preferred Stock and such other parity stock are paid pro rata. Unless full cumulative dividends on all outstanding shares of Series A Preferred Stock have been paid, no dividends (other than in Common Stock or other stock ranking junior to the Series A Preferred Stock) may be paid, or any other distributions made, on the Common Stock or on any other stock of the Company ranking junior to the Series A Preferred Stock, nor may any Common Stock or any other stock of the Company ranking junior to or on a parity with the Series A Preferred Stock be redeemed, purchased or otherwise acquired for any consideration by the Company (except by conversion into or exchange for stock of the Company ranking junior to the Series A Preferred Stock). CONVERSION. The Series A Preferred Stock is convertible at any time prior to being called for redemption into Common Stock at a rate of approximately 2.273 shares of Common Stock for each share of Series A Preferred Stock, subject to adjustment for certain antidilutive events. The Company from time to time may reduce the conversion price by any amount for a period of at least 20 days if the Board of Directors determines that such reduction is in the best interests of the Company. In the event of certain changes in control or fundamental changes, holders of Series A Preferred Stock have the right to convert all of their Series A Preferred Stock into Common Stock at a rate equal to the average of the last reported sales prices of the Common Stock for the five business days ending on the last business day preceding the date of the change in control or fundamental change. The Company or its successor may elect to distribute cash to such holders in lieu of Common Stock at an equal value. 60 EXCHANGE. The Series A Preferred Stock may be exchanged at the option of the Company for Convertible Debentures beginning on January 15, 1998 at the rate of $25 principal amount of Convertible Debentures for each share of Preferred Stock, provided that all accrued and unpaid dividends have been paid and certain other conditions are met. REDEMPTION. On or after December 31, 1998 the Company may from time to time redeem the Series A Preferred Stock at an initial redemption price of $26.488. On December 31 of each year thereafter and until December 31, 2005, the redemption price decreases. On December 31, 2005 and thereafter, the redemption price shall remain at $25. VOTING RIGHTS. The holders of Series A Preferred Stock have no voting rights, except as otherwise provided by law. However, if dividend payments are in arrears in an amount equal to or exceeding six quarterly dividends, the number of directors of the Company will be increased by two and the holders of the Series A Preferred Stock (voting separately as a class) will be entitled to elect the additional two directors until all dividends have been paid. In addition, the Company may not create, issue or increase the authorized number of shares of any class or series of stock ranking senior to the Series A Preferred Stock or alter, change or repeal any of the powers, rights or preferences of the holders of the Series A Preferred Stock as to adversely affect such powers, rights or preferences. CONVERTIBLE DEBENTURES The Convertible Debentures will be issued under an indenture between the Company and Bank One, Columbus, NA, as trustee, a copy of which is filed as an exhibit to the Registration Statement of which this Prospectus is a part. The statements below are summaries of certain provisions of such indenture and the Convertible Debentures, do not purport to be complete and are qualified in their entirety by such reference. GENERAL. The Convertible Debentures will be unsecured, subordinated obligations of the Company, limited in aggregate principal amount to the aggregate liquidation preference of the Series A Preferred Stock and will mature on December 31, 2010. The Company will pay interest on the Convertible Debentures semiannually following the issue thereof at the rate of 8.5% per annum. The Convertible Debentures are to be issued in fully registered form, without coupons, in denominations of $25 or any integral multiple thereof. CONVERSION. The Convertible Debentures will be convertible at any time after issue and prior to being called for redemption into Common Stock at the conversion rate in effect on the Series A Preferred Stock at the date of exchange, subject to adjustment for certain antidilutive events. The Company from time to time may reduce the conversion price in order that certain stock-related distributions which may be made by the Company to its shareholders will not be taxable. Each holder of a Convertible Debenture will be entitled to conversion rights identical in substance to the rights applicable to holders of Series A Preferred Stock in the event of a change in control or fundamental change. SUBORDINATION. Payment of principal of (and premium, if any) and interest on the Convertible Debentures will be subordinated and junior in right of payment to the prior payment in full of all senior indebtedness of the Company, including the Notes. During the continuation of any default in the payment of principal, interest or premium on any senior indebtedness, no payment with respect to the principal, interest or premium (if any) on the Convertible Debentures may be made until such default on the senior indebtedness shall have been cured or waived or shall have ceased to exist. REDEMPTION. On or after December 31, 1998, the Convertible Debentures may be redeemed at the option of the Company at a redemption price (expressed as percentages of principal amount) of 105.95%. On December 31 of each year thereafter and until December 31, 2005, the redemption price decreases. On December 31, 2005 and thereafter, the redemption price shall remain at 100.00%. EVENTS OF DEFAULT. Upon an Event of Default, the Trustee or the holders of at least 25% in aggregate principal amount of the outstanding Convertible Debentures may accelerate the maturity of all Convertible Debentures, subject to certain conditions. An Event of Default is defined in the indenture generally as (i) failure to pay principal or premium, if any, on any Convertible Debenture when due at maturity, upon 61 redemption or otherwise; (ii) failure to pay an interest on any Convertible Debenture when due and continuing for 30 days; (iii) breach of such indenture or Convertible Debentures by the Company; (iv) certain events in bankruptcy, insolvency or reorganization; (v) default on indebtedness (other than non- recourse indebtedness) resulting in more than $7,500,000 becoming due and payable prior to its maturity; or (vi) a judgment or decree entered against the Company involving a liability of $7,500,000 or more. CREDIT FACILITY Effective October 31, 1996, the Company amended and restated its Credit Facility which is secured by mortgages covering substantially all of the Company's producing oil and gas properties. The Credit Facility provides for borrowings of a maximum of the lesser of $50 million and a Borrowing Base determined periodically on the basis of a discounted present value attributable to the Company's proven producing oil and gas reserves. Through May 15, 1997, the Credit Facility provides a $30 million Borrowing Base. Pursuant to the Credit Facility, depending upon the percentage of the unused portion of the Borrowing Base, the interest rate is equal to either Prime or Prime plus 0.50%. Prime is the prime commercial lending rate announced from time to time by the lender. The Company, at its option, may fix the interest rate on all or a portion of the outstanding principal balance at either 1.00% or 1.375% above an agreement-defined "Eurodollar" rate, depending upon the percentage of the unused portion of the Borrowing Base, for periods of up to six months. The weighted average interest rate for the total debt outstanding at November 5, 1996 was 6.375%. Under the Credit Facility, a commitment fee of .25% or .375% per annum on the unused portion of the Borrowing Base (depending upon the percentage of the unused portion of the Borrowing Base) is payable quarterly. The Company may borrow, pay, reborrow and repay under the Credit Facility until October 31, 2000, on which date the Company must repay in full all amounts then outstanding. Borrowings under the Credit Facility are guaranteed by certain of the Company's subsidiaries. The Credit Facility has certain customary covenants including, but not limited to, covenants with respect to the following matters: (i) limitation on restricted payments, distributions and investments; (ii) limitations on guarantees and indebtedness; (iii) limitation on prepayments of subordinated indebtedness; (iv) limitation on prepayments of additional indebtedness; (v) limitation on mergers and issuances of securities; (vi) limitation on sales of property; (vii) limitation on transactions with affiliates; (viii) limitation on derivative contracts; (ix) limitation on acquisitions, new businesses and margin stock; and (x) limitation with respect to certain prohibited types of contracts and multi-employer ERISA plans. The Company is also required to maintain certain financial ratios and conditions, including without limitation an EBITDA to debt service coverage ratio, a net worth requirement and a funded debt to capitalization ratio. 62 UNDERWRITING Subject to the terms and conditions of the Underwriting Agreement between the Company and Morgan Keegan & Company, Inc. ("the Underwriter"), the Company has agreed to sell to the Underwriter, and the Underwriter has agreed to purchase from the Company, Notes in the aggregate principal amount of $21,000,000. The Underwriter proposes to offer the Notes being purchased by it directly to the public at the initial public offering price set forth on the cover page of this Prospectus and in part to certain securities dealers, which are members of the National Association of Securities Dealers, Inc., at such price less concessions as it may determine within its discretion. After the initial public offering, the public offering price and concession may be changed. Under the terms and conditions of the Underwriting Agreement, the Underwriter is obligated to purchase all of the Notes if any are purchased. The Company has granted the Underwriter an option exercisable for 30 days after the date of this Prospectus to purchase up to an additional $3,150,000 aggregate principal amount of the Notes, at the purchase price per Note set forth on the cover page of this Prospectus, solely to cover overallotments, if any, in the sale of the Notes. The Company has agreed to indemnify the Underwriter against certain liabilities which may be incurred in connection with the Offering, including certain liabilities under the Securities Act or to contribute to payments the Underwriter may be required to make in respect of such liabilities. The Notes are a new issue of securities with no established trading market. The Company has been advised by the Underwriter that the Underwriter intends to make a market for the Notes but is not obligated to do so and may discontinue market making at any time without notice. No assurance can be given as to the liquidity of, or the trading market for, the Notes. In November 1995, the Underwriter acted as an underwriter of the Series A Preferred Stock for which it received a customary underwriting discount. LEGAL MATTERS The validity of the Notes will be passed upon by Butler & Binion, L.L.P., Houston, Texas. Certain legal matters with respect to such securities will be passed upon for the Underwriter by Vinson & Elkins L.L.P., Houston, Texas. EXPERTS The audited historical financial statements of the Company included in this Prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving such report. The information appearing in this Prospectus regarding quantities of reserves of oil and gas and the future net cash flows and the present values thereof from such reserves is based on estimates of such reserves and present values prepared by Huddleston & Co., Inc., an independent petroleum and geological engineering firm. 63 GLOSSARY The following definitions shall apply to the technical terms used in this Prospectus. "Bbls" means barrels. "Bbls/d" means barrels per day. "Bcf" means billion cubic feet. "Bcfe" means billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids. "Gross" means the number of wells or acres in which the Company has an interest. "MBbls" means thousands of barrels. "Mcf" means thousands of cubic feet. Gas volumes are stated at the legal pressure base of the state or area in which the reserves are located at 60 degrees Fahrenheit. "Mcf/d" means thousand cubic feet per day. "Mcfe" means one thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids. "MMBbls" means millions of barrels. "MMBtu" means a million British thermal units. A British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 59.5 to 60.5 degrees Fahrenheit under specified conditions. "MMcf" means millions of cubic feet. "MMcfe" means one million cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids. "Net" is determined by multiplying gross wells or acres by the Company's working interest in such wells or acres. "PV-10 Value" means the present value, discounted at 10%, of future net cash flows from estimated proved reserves, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions). "Reserve Replacement Costs," expressed in dollars per Mcfe, is calculated by dividing the amount of total capital expenditures for oil and gas activities by the amount of proved reserves added during the same period (including the effect on proved reserves of reserve revisions). 64 INDEX TO FINANCIAL STATEMENTS PAGE ---- CALLON PETROLEUM COMPANY (historical): Report of Independent Public Accountants.................... F-2 Consolidated Balance Sheets as of September 30, 1996 and December 31, 1995 and 1994..... F-3 Consolidated Statements of Operations for the Nine Months Ended September 30, 1996 and 1995 and for the Years Ended December 31, 1995, 1994 and 1993........................... F-4 Consolidated Statements of Stockholders' Equity for the Nine Months Ended September 30, 1996 and for the Years Ended December 31, 1995, 1994 and 1993.................. F-5 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 1996 and 1995 and for the Years Ended December 31, 1995 and 1994.............. F-6 Notes to Consolidated Financial Statements..................... F-7 CALLON PETROLEUM COMPANY (pro forma): Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 1995........ F-20 Notes to Pro Forma Consolidated Financial Statement............ F-21 F-1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Callon Petroleum Company: We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1995. 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 Callon Petroleum Company and subsidiaries, as of December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. As discussed in Note 3 to the consolidated financial statements, effective January 1, 1993 the Company changed its method of accounting for income taxes. ARTHUR ANDERSEN LLP New Orleans, Louisiana February 23, 1996 F-2 CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31, SEPTEMBER 30, -------------------------- 1996 1995 1994 ------------- ------------ ------------ (UNAUDITED) ASSETS Current assets: Cash and cash equivalents.......... $ 8,709 $ 4,265 $ 7,285 Accounts receivable, trade......... 8,401 8,329 8,895 Other current assets............... 149 238 21 ------------- ------------ ------------ Total current assets.......... 17,259 12,832 16,201 ------------- ------------ ------------ Oil and gas properties, full cost accounting method: Evaluated properties............... 308,178 304,737 285,976 Less accumulated depreciation, depletion and amortization....... (264,658) (257,143) (246,975) ------------- ------------ ------------ 43,520 47,594 39,001 Unevaluated properties excluded from amortization................ 24,895 10,171 4,919 ------------- ------------ ------------ Total oil and gas properties................. 68,415 57,765 43,920 ------------- ------------ ------------ Pipeline and other facilities, net...... 6,695 5,371 5,579 Other property and equipment, net....... 1,620 1,633 1,633 Deferred tax asset...................... 5,462 5,462 5,462 Long-term gas balancing receivable...... 435 619 734 Other assets, net....................... 37 185 257 ------------- ------------ ------------ Total assets.................. $ 99,923 $ 83,867 $ 73,786 ============= ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable, trade............ $ 14,054 $ 8,077 $ 10,391 Deferred income.................... 237 43 43 Current maturities of long-term debt............................. -- -- 3,871 ------------- ------------ ------------ Total current liabilities..... 14,291 8,120 14,305 ------------- ------------ ------------ Long-term debt.......................... 8,950 100 15,363 Deferred income......................... 61 86 128 Long-term gas balancing payable......... 353 432 559 ------------- ------------ ------------ Total liabilities............. 23,655 8,738 30,355 ------------- ------------ ------------ Stockholders' equity: Preferred Stock, $0.01 par value, 2,500,000 shares authorized; 1,315,500 shares of Convertible Exchangeable Preferred Stock, Series A issued and outstanding with a liquidation preference of $32,887,500 (Note 11)............ 13 13 -- Common Stock, $0.01 par value; 20,000,000 shares authorized; 5,754,863 at September 30, 1996 and 5,754,529 shares outstanding at December 31, 1995............. 58 58 58 Capital in excess of par value..... 73,955 73,955 43,069 Retained earnings.................. 2,242 1,103 304 ------------- ------------ ------------ Total stockholders' equity....... 76,268 75,129 43,431 ------------- ------------ ------------ Total liabilities & stockholders' equity....... $ 99,923 $ 83,867 $ 73,786 ============= ============ ============
The accompanying notes are an integral part of these financial statements. F-3 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1996 1995 1995 1994 1993 --------- --------- --------- --------- --------- (UNAUDITED) Revenues: Oil and gas sales..................... $ 18,578 $ 17,400 $ 23,210 $ 13,948 $ 10,048 Interest and other.................... 537 501 627 171 230 --------- --------- --------- --------- --------- Total revenues................... 19,115 17,901 23,837 14,119 10,278 --------- --------- --------- --------- --------- Costs and expenses: Lease operating expenses.............. 5,646 5,201 6,732 4,042 3,713 Depreciation, depletion and amortization....................... 7,697 7,929 10,376 6,049 3,411 General and administrative............ 2,352 2,960 3,880 3,717 2,350 Interest.............................. 184 1,441 1,794 624 196 --------- --------- --------- --------- --------- Total costs and expenses......... 15,879 17,531 22,782 14,432 9,670 --------- --------- --------- --------- --------- Income (loss) from operations........... 3,236 370 1,055 (313) 608 Income tax expense (benefit).......... -- -- -- (200) 113 --------- --------- --------- --------- --------- Income (loss) before cumulative effect of change in accounting principle..... 3,236 370 1,055 (113) 495 Cumulative effect of change in accounting principle (Note 3)......... -- -- -- -- 5,262 --------- --------- --------- --------- --------- Net income (loss)....................... 3,236 370 1,055 (113) 5,757 Preferred stock dividends............... 2,097 -- 256 -- -- --------- --------- --------- --------- --------- Net income (loss) available to common shares................................ $ 1,139 $ 370 $ 799 $ (113) $ 5,757 ========= ========= ========= ========= ========= Pro forma adjustment (unaudited): Provision for income taxes (Note 3)... -- -- -- -- 100 --------- --------- --------- --------- --------- Pro forma net income (loss)........... $ 1,139 $ 370 $ 799 $ (113) $ 5,657 ========= ========= ========= ========= ========= Income (loss) per common share: Income (loss) per share before change in accounting principle............ $ .20 $ .06 $ .14 $ (.03) $ .13 ========= ========= ========= ========= ========= Cumulative effect of change in accounting principle............... $ -- $ -- $ -- $ -- $ 1.40 ========= ========= ========= ========= ========= Pro forma............................. $ .20 $ .06 $ .14 $ (.03) $ 1.50 ========= ========= ========= ========= ========= Weighted average common shares outstanding........................... 5,755 5,754 5,755 4,346 3,769 ========= ========= ========= ========= =========
The accompanying notes are an integral part of these financial statements. F-4 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
CAPITAL IN CAPITAL PREFERRED COMMON EXCESS OF RETAINED ACCOUNTS STOCK STOCK PAR VALUE EARNINGS -------- --------- ------ ---------- -------- Balances, December 31, 1992............. $ 22,711 $ -- $-- $ -- $ -- Net income.............................. 5,757 -- -- -- -- Provision for income taxes (Note 3)..... 113 -- -- -- -- Distributions........................... (1,411) -- -- -- -- -------- --------- ------ ---------- -------- Balances, December 31, 1993............. 27,170 -- -- -- -- Pre consolidation income (loss)......... (417) -- -- -- -- Distributions........................... (1,191) -- -- -- -- Consolidation (Note 1).................. (25,562) -- 58 43,069 -- Post consolidation income............... -- -- -- -- 304 -------- --------- ------ ---------- -------- Balances, December 31, 1994............. -- -- 58 43,069 304 Net income.............................. -- -- -- -- 1,055 Sale of preferred stock (Note 11)....... -- 13 -- 30,886 -- Preferred stock dividends............... -- -- -- -- (256) -------- --------- ------ ---------- -------- Balances, December 31, 1995............. -- 13 58 73,955 1,103 Net income (Unaudited).................. -- -- -- -- 3,236 Preferred stock dividends (Unaudited)... -- -- -- -- (2,097) -------- --------- ------ ---------- -------- Balances, September 30, 1996 (Unaudited)........................... $ -- $ 13 $ 58 $ 73,955 $ 2,242 ======== ========= ====== ========== ========
The accompanying notes are an integral part of these financial statements. F-5 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, ---------------------- --------------------------------- 1996 1995 1995 1994 1993 ---------- ---------- ---------- ---------- --------- (UNAUDITED) Cash flows from operating activities: Net income (loss).................. $ 3,236 $ 370 $ 1,055 $ (113) $ 5,757 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization............... 7,913 8,131 10,600 6,328 3,657 Amortization of deferred costs...................... 201 -- 133 88 35 Cumulative effect of change in accounting principle....... -- -- -- -- (5,262) Income tax expense (benefit).................. -- -- -- (200) 113 ---------- ---------- ---------- ---------- --------- 11,350 8,501 11,788 6,103 4,300 Changes in current assets & liabilities: Accounts receivable, trade................... (72) 2,063 566 565 2,165 Other current assets....... 89 (39) (217) (8) (23) Accounts payable, trade.... 5,534 (1,563) (2,314) (1,242) (2,171) Deferred income............ 194 -- -- -- -- Change in gas balancing receivable................. 184 163 115 (148) 25 Change in gas balancing payable.................... (79) (130) (127) 210 108 Change in deferred income..... (25) (32) (42) (43) 143 Change in other assets, net... (53) (229) (61) (90) 188 ---------- ---------- ---------- ---------- --------- Cash provided by operating activities................. 17,122 8,734 9,708 5,347 4,735 ---------- ---------- ---------- ---------- --------- Cash flows from investing activities: Capital expenditures............... (20,402) (16,860) (24,323) (10,420) (4,096) Equity issued to purchase CN cash (Note 4)........................ -- -- -- 3,989 -- Cash proceeds from sale of mineral interests....................... 528 80 86 8 1,386 ---------- ---------- ---------- ---------- --------- Cash used in investing activities................. (19,874) (16,780) (24,237) (6,423) (2,710) ---------- ---------- ---------- ---------- --------- Cash flows from financing activities: Payments on debt................... -- (2,383) (25,134) (20,627) (2,783) Increase in debt................... 8,850 6,000 6,000 25,734 2,499 Dividends/distributions paid....... -- -- -- (1,191) (1,411) Sale of preferred stock............ -- -- 30,899 -- -- Increase in accrued preferred stock dividends payable............... 443 -- -- -- -- Dividends on preferred stock....... (2,097) -- (256) -- -- ---------- ---------- ---------- ---------- --------- Cash provided by (used in) financing activities....... 7,196 3,617 11,509 3,916 (1,695) ---------- ---------- ---------- ---------- --------- Net increase (decrease) in cash and cash equivalents................... 4,444 (4,429) (3,020) 2,840 330 Cash and cash equivalents: Balance, beginning of period....... 4,265 7,285 7,285 4,445 4,115 ---------- ---------- ---------- ---------- --------- Balance, end of period............. $ 8,709 $ 2,856 $ 4,265 $ 7,285 $ 4,445 ========== ========== ========== ========== =========
The accompanying notes are an integral part of these financial statements. F-6 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (INFORMATION WITH RESPECT TO SEPTEMBER 30, 1996 AND 1995 IS UNAUDITED) 1. ORGANIZATION AND BASIS OF PRESENTATION Callon Petroleum Company, formerly Callon Petroleum Holding Company, (the "Company") was organized under the laws of the state of Delaware in March, 1994 to serve as the surviving entity in the consolidation to combine the businesses and properties of Callon Consolidated Partners, L.P. ("CCP"), Callon Petroleum Operating Company ("CPOC") and CN Resources ("CN"), directly or indirectly, with the Company. CPOC was the general partner of CCP, and CN was a general partnership between CPOC and NOCO Enterprises, L. P. ("NOCO"), a limited partnership owned by private investors (CPOC, CCP and CN are referred to collectively as the "Constituent Entities"). The combination of the businesses and properties of the Constituent Entities with the Company was effected in three simultaneous transactions on September 16, 1994 (collectively, the "Consolidation"): (i) CCP was merged (the "Merger") into the Company and each unit of limited partner interest in CCP ("Units") was converted into the right to receive one-third of a share of Common Stock of the Company ("Common Stock"). Subject to compliance with certain requirements, any holder of less than 100 Units could elect to receive, in lieu of shares of Common Stock, $4.50 in cash per Unit owned. CCP unitholders received 1,877,493 shares of Common Stock of the Company. (ii) Holders of capital stock of CPOC exchanged such capital stock for an aggregate of 1,892,278 shares of Common Stock of the Company, resulting in CPOC becoming a wholly owned subsidiary of the Company (the "Share Exchange"). (iii) NOCO exchanged its partnership interest for 1,984,758 shares of Common Stock of the Company, resulting in CN becoming directly and indirectly wholly owned by the Company (the "CN Exchange"). See Note 4. As a result of the Consolidation, all of the businesses and properties of the Constituent Entities are owned (directly or indirectly) by the Company, and the former stockholders of CPOC, partners of CCP and NOCO have become stockholders of the Company. Certain registration rights were granted to the holders of the capital stock of CPOC and NOCO. See Note 7. The Company and its predecessors have been engaged in the acquisition, development and exploration of crude oil and natural gas since 1950. The Company's properties are geographically concentrated in Louisiana, Alabama and offshore Gulf of Mexico. BASIS OF PREPARATION The accompanying Consolidated Financial Statements of the Company reflect the combination of CPOC, CCP, and CPOC's interest in CN as a reorganization of entities under common control (accounted for similar to a "pooling of interest"). NOCO's interest in CN was recorded as a purchase effective at the date of the Consolidation (September 16, 1994), thus amounts related to the CN Exchange are included from the date of the purchase for the periods presented in the Consolidated Financial Statements. CPOC made no direct investment in CN, therefore the inclusion of 100% of the assets and liabilities of CN in the Consolidated Balance Sheet, as of the purchase date, are attributable to NOCO's interest in CN. Because no revenues or expenses, as of the date of the Consolidation, were attributable to CPOC's interest in CN until NOCO had received a preferential return on its investment, all of the revenues and expenses of CN through September 16, 1994, are also attributable to NOCO. See Note 4 for pro forma information. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND REPORTING The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, CPOC. CPOC also has subsidiaries which are Callon Offshore Production, Inc., Mississippi Marketing, Inc. F-7 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) and Callon Exploration Company. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform with presentation in the current year. Reclassifications relate primarily to operator overhead reimbursements (previously included in "Management Fees and Other") which are shown as a reduction of production expenses and general and administrative expenses. This change in presentation more clearly reflects industry practice for reporting operator overhead reimbursements. 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 period. Actual results could differ from those estimates. ACCOUNTING PRONOUNCEMENTS In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121 ("FAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", which was adopted by the Company for the fiscal year ending December 31, 1996. The effect of adopting FAS 121 was not material to the Company's financial position or results of operations. In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123 ("FAS 123"), "Accounting for Stock-Based Compensation", effective for the Company at December 31, 1996. Under FAS 123, companies can either record expenses based on the fair value of stock-based compensation upon issuance or elect to remain under the current "APB Opinion No. 25" method, whereby no compensation cost is recognized upon grant, and make disclosures as if FAS 123 had been applied. The Company anticipates it will continue to account for its stock-based compensation plans under APB Opinion No. 25. PROPERTY AND EQUIPMENT The Company follows the full cost method of accounting for oil and gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and gas reserves, including certain overhead costs, are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to exploration and development activities. Payroll and general and administrative costs include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and gas properties as well as other directly identifiable general and administrative costs associated with such activities. Costs associated with unevaluated properties are excluded from amortization. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold or management determines these costs have been impaired. Costs of properties, including future development and net future site restoration, dismantlement and abandonment costs, which have proved reserves and those which have been determined to be worthless are depleted using the unit-of-production method based on proved reserves. If the total capitalized costs of oil and gas properties, net of amortization, exceed the sum of (1) the estimated future net revenues from proved reserves at current prices and discounted at 10% and (2) the cost of unevaluated properties (the full cost ceiling amount), then such excess is charged to expense during the period in which the excess occurs. Upon the acquisition or discovery of oil and gas properties, management estimates the future net costs to be incurred to dismantle, abandon and restore the property using geological, engineering and regulatory data available. Such cost estimates are periodically updated for changes in conditions and requirements. Such estimated amounts are considered as part of the full cost pool subject to amortization upon acquisition F-8 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) or discovery. Such costs are capitalized, as oil and gas properties, as the actual restoration, dismantlement and abandonment activities take place. As of December 31, 1995 and 1994, estimated future site restoration, dismantlement and abandonment costs, net of related salvage value and amounts funded by abandonment trusts (see Notes 7 and 9) were not material. Depreciation of other property and equipment is provided using the straight-line method over estimated lives of three to 20 years. Depreciation of the pipeline facilities is provided using the straight-line method over a 27 year estimated life. NATURAL GAS IMBALANCES Natural gas imbalances occur when a producer sells natural gas disproportionate to his ownership share of the total gas production from a property as a result of pipeline curtailments, contract differences or election by some producers not to sell their gas currently. These imbalances are made up through allocations of future production from the property. The Company follows an entitlement method of accounting for its proportionate share of gas production on a well by well basis, recording a receivable to the extent that a well is in an "undertake" position and conversely recording a liability to the extent that a well is in an "overtake" position. DERIVATIVES The Company uses derivative financial instruments (see Note 6) for price protection purposes on a limited amount of its future production and does not use them for trading purposes. Such derivatives are accounted for on an accrual basis and amounts paid or received under the agreements are recognized as oil and gas sales in the period in which they accrue. RESERVE FOR DOUBTFUL ACCOUNTS The balance in the reserve for doubtful accounts included in accounts receivable is $481,000 and $479,000 at December 31, 1995 and 1994, and $393,000 at September 30, 1996. Net charge offs were $181,000 in 1994 and $53,000 in 1993, and net recoveries were $2,000 in 1995. There were no provisions to expense in the three-year period ended December 31, 1995 or the nine months ended September 30, 1996. Net charge offs were $88,000 for the nine months ended September 30, 1996 and net recoveries were $2,000 for the nine months ended September 30, 1995. STATEMENTS OF CASH FLOWS For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company paid no federal income taxes for the three years ended December 31, 1995. During the years ended December 31, 1995, 1994 and 1993, the Company made cash payments of $1,910,000, $377,000 and $182,000, respectively, for interest charged on its indebtedness, and $72,000 for the nine months ended September 30, 1996. PER SHARE AMOUNTS Per share amounts are calculated on a weighted average basis in accordance with the shares issued in the Consolidation described in Note 1. The options discussed in Note 10 have no effect on these calculations in 1995. The preferred stock issued in 1995 (Note 11) is not a common stock equivalent and is not included in the calculations of per share amounts, and due to their antidilutive effect on earnings per share, dual presentation of per share amounts is not necessary. F-9 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 3. INCOME TAXES Effective January 1, 1993, the Company adopted the provisions of Financial Accounting Standards Board Statement No. 109 ("FAS 109") "Accounting for Income Taxes". The statement provides for the recognition of a deferred tax asset for deductible temporary timing differences, capital and operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a "valuation allowance". The valuation allowance is provided for that portion of the asset, for which it is deemed more likely than not, that it will not be realized. The adoption of this change in accounting principle resulted in the recording of a deferred tax asset at December 31, 1995, 1994 and 1993 as follows: 1995 1994 1993 --------- --------- --------- (IN THOUSANDS) Federal net operating loss carryforward.......................... $ 3,563 $ 2,072 $ 1,835 Federal capital loss carryforward....... -- -- 1,377 Statutory depletion carryforward........ 3,987 4,085 3,885 Temporary differences: Oil and gas properties............. 874 2,817 2,542 Pipeline facilities................ (1,880) (1,953) -- Non-oil and gas property........... 23 28 440 Other.............................. 655 724 525 --------- --------- --------- Total tax asset......................... 7,222 7,773 10,604 Valuation allowance..................... (1,760) (2,311) (5,342) --------- --------- --------- Net tax asset........................... $ 5,462 $ 5,462 $ 5,262 ========= ========= ========= At December 31, 1995, the Company had, for tax reporting purposes, operating loss carryforwards ("NOL") of $10.2 million which expire in 1999 through 2010. Such carryovers are subject to limitations on utilization as a result of ownership changes which occurred in CPOC's common stock prior to the Consolidation and ownership changes as a result of the Consolidation. Additionally, the Company had available for tax reporting purposes $11.4 million in statutory depletion deductions which can be carried forward for an indefinite period. As a result of the combination of the Company and CCP there was a change in the tax status of the Company; therefore, the Company was able to reduce the valuation allowance at January 1, 1993 by $5,262,000. This reduction is shown as a "cumulative effect of change in accounting principle" in the December 31, 1993 Consolidated Statement of Operations. The net asset represents the statutory depletion carryforward (which has an unlimited carryforward period) and the portion of the federal net operating loss carryforward that the Company's management believes will be utilized. All other temporary differences are offset by the valuation allowance, which represents that portion of the asset that management believes is more likely than not, that it will not be realized. During 1994, additional statutory depletion was estimated which has been reflected as a reduction of the income tax provision and an addition to the deferred tax asset in the amount of $200,000, resulting in an effective tax rate of (63)%. At December 31, 1995, the difference between the Company's effective tax rate and the statutory rate of 35% is attributed to the following: refinement of prior estimates of statutory depletion, 14%; reduction in the valuation allowance, (52)%; and other nondeductible items, 3%. The income tax amounts on the Consolidated Statements of Stockholders' Equity in 1993 reflect the historical accounting treatment of income taxes of one of the Constituent Entities. Such accounting treatment was discontinued in 1994 due to the effect of the Consolidation. F-10 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The pro forma provision for income taxes relates to the income of CCP prior to the Consolidation as if such income was taxed as a corporation. Pro forma tax adjustments were provided only to the extent CCP had income, thus none was recorded in 1994. 4. ACQUISITIONS On September 14, 1994, (with an effective date of September 16, 1994) the unitholders of CCP, stockholders of CPOC, and the partners of CN completed the Consolidation as described in Note 1. Net assets purchased (excluding cash of $3,989,000) was $13,847,000 of which oil and gas property, including pipeline facilities, and debt amounted to $24,506,000 and $11,436,000, respectively. Such amounts represent non-cash transactions and therefore are not included in the Consolidated Statements of Cash Flows. On December 29, 1995, CPOC purchased a 66.67% working interest in Chandeleur Block 40 (the "CB 40 Acquisition") from Amerada Hess Corporation and, in a simultaneous transaction under a pre-existing agreement, sold one-third of the acquired interest to an industry partner. The Company's net purchase price of $6 million was funded from existing cash on hand. The following information represents unaudited pro forma results of the Company for the years ended December 31, 1995, 1994 and 1993 and includes both the purchase of CN and the CB 40 Acquisition, presented as if the purchase of CN had occurred at the beginning of 1994 and 1993, and the CB 40 Acquisition presented as if it had occurred at the beginning of 1995 and 1994. PRO FORMA (UNAUDITED) ------------------------------- 1995 1994 1993 --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Total revenues.......................... $ 25,237 $ 29,132 $ 40,050 ========= ========= ========= Net income before cumulative effect of change in accounting principle........ $ 1,179 $ 3,703 $ 4,833 ========= ========= ========= Net income per common share............. $ .20 $ .64 $ .84 ========= ========= ========= Weighted average common shares outstanding........................... 5,755 5,755 5,755 ========= ========= ========= Pro forma common shares outstanding used in the above calculations include shares of the Company issued as a result of the Merger of CCP and the Share Exchange in addition to the shares of the Company issued in the CN Exchange. The Company, together with Murphy Exploration and Production, Inc., ("Murphy") was the high bidder on 12 offshore tracts at the Outer Continental Shelf ("OCS") Lease Sale #157, held April 24, 1996 in New Orleans, Louisiana, and conducted by the U.S. Department of the Interior through its Minerals Management Service ("MMS"). The Company holds a 25% working interest in the leases and its share of the total lease costs was approximately $11.4 million. On September 25, 1996, the Company and Murphy submitted bids on six additional offshore leases encompassing approximately 35,000 acres at the OCS Lease Sale #161, held in New Orleans, Louisiana by the MMS. If the bids are approved and the leases are awarded, the Company's share of the costs will be $3.8 million, of which $.8 million had been paid as of September 30, 1996. The Company will own a 25% working interest in the awarded leases. F-11 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. NOTES PAYABLE Notes payable consisted of the following at: DECEMBER 31, SEPTEMBER 30, -------------------- 1996 1995 1994 ------------- --------- --------- (UNAUDITED) (IN THOUSANDS) Credit Facility...................... $ 8,950 $ 100 $ 19,000 Building Mortgage, at prime, as defined plus 2% (9.75% at December 31, 1994)....... -- -- 234 ------------- --------- --------- 8,950 100 19,234 Less: current portion................ -- -- 3,871 ------------- --------- --------- $ 8,950 $ 100 $ 15,363 ============= ========= ========= On October 14, 1994, CPOC entered into a definitive credit agreement with a commercial lender providing for a credit facility of up to $30,000,000. Currently, the credit facility provides the Company with a minimum borrowing base of $15,000,000 through December 31, 1996. The purpose for obtaining this credit facility was to refinance existing indebtedness incurred primarily through acquisitions of oil and gas properties prior to, and assumed by the Company as a result of, the Consolidation (See Note 1). The interest rate in the agreement is the average published prime rate of three major U.S. banks. The Company, at its option, may fix the rate on all or a portion of the outstanding balance at 1.375% above an agreement defined "Eurodollar" rate for periods of up to six months. The weighted average rate for the total debt outstanding at September 30, 1996 and December 31, 1995 was 6.875% and 9.25%, respectively. A commitment fee of one half of 1% per annum on the unused portion of the borrowing base is payable quarterly. Principal payments are payable on the last day of each month, commencing January 31, 1997, in a manner intended to repay the debt in full on June 30, 1999. Borrowings under the credit facility are secured by a mortgage of substantially all of the Company's and its subsidiaries' oil and gas properties. The credit facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. The Company changed its commercial lender and entered into a new definitive credit agreement on October 31, 1996. The new credit facility provides for borrowing of up to $50,000,000 with an initial borrowing base of $30,000,000. The interest rate, fees, terms and covenants of the new credit agreement are similar to and, in most cases, are more favorable than the 1994 credit agreement. The maturity date of the new credit facility is October 31, 2000. 6. HEDGING CONTRACTS The Company hedges with third parties certain of its crude oil and natural gas production in various swap agreement contracts. The contracts are tied to published market prices for crude oil and natural gas and are settled monthly based on the differences between contract prices and the average defined market price for that month applied to the related contract volume. As of September 30, 1996, December 31, 1995 and December 31, 1994 the Company's open forward sales position (all expiring in 1996) was as follows:
SEPTEMBER 30, 1996 DECEMBER 31, 1995 DECEMBER 31, 1994 ------------------ ------------------- ------------------- OIL GAS OIL GAS OIL GAS (BBLS) (MMBTU) (BBLS) (MMBTU) (BBLS) (MMBTU) ------- ------- ------ --------- ------- -------- Volumes.............................. 180,000 -- -- 1,200,000 192,000 3,800,000 Average Price per Unit............... $ 23.33 -- -- $ 1.75 $ 18.24 $ 2.30
In addition, as of December 31, 1995, the Company has entered into collar agreements with third parties whereby minimum floor prices and maximum ceiling prices are contracted and applied to related F-12 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) contract volumes. These agreements in effect for 1996 and the first quarter of 1997 are for average oil volumes of 23,750 barrels per month at a ceiling price of $19.38 and floor of $16.75 and for average gas volumes of 130,000 MCF's per month at a ceiling price of $2.28 and floor of $1.80. At September 30, 1996, the Company had collar agreements for average oil volumes of 40,000 barrels per month for the fourth quarter of 1996 at a ceiling price of $19.59 and floor of $17.25 and average gas volumes of 100,000 MCF's per month at a ceiling price of $2.20 and floor of $1.75 through the first quarter of 1997. During 1994, the Company recognized revenue under the swap agreements of $1,227,000 and $1,724,000 on a Historical and a Pro forma basis respectively, and $2,466,000 for the twelve months ended December 31, 1995. The Company recognized a reduction in revenue of $2,048,000 for the nine months ended September 30, 1996 under the hedging agreements. The calculation of the fair market value of the hedging contracts indicates a $413,800 market value liability to the Company as of December 31, 1995 based on market prices at that date. 7. COMMITMENTS AND CONTINGENCIES As operator, the Company has guaranteed, through its debt facilities, certain letters of credit in the amount of $253,000. These letters of credit are primarily issued to various state oil and gas regulatory agencies to ensure compliance with various regulations on operated properties. As described in Note 9, abandonment trusts (the "Trusts") have been established for future abandonment obligations of those oil and gas properties of the Company burdened by a net profits interest. The management of the Company believes the Trusts will be sufficient to offset those future abandonment liabilities; however, the Company is responsible for any abandonment expenses in excess of the Trusts' balances. As of December 31, 1995, total estimated site restoration, dismantlement and abandonment costs were approximately $21,395,000, net of expected salvage value. Substantially all such costs are expected to be funded through the Trusts' funds, all of which will be accessible to the Company when abandonment work begins. In addition as a working interest owner and/or operator of oil and gas properties, the Company is responsible for the cost of abandonment of such properties, see Note 2. The Consolidation described in Note 1 provides that the former stockholders of CPOC, as a result of the Share Exchange, may be issued additional shares of the Company's Common Stock ("Contingent Shares"). The Contingent Shares are attributable to the value of specified oil and gas properties, which were owned by CPOC and were in the early stages of development at the date of the Consolidation. The amount of Contingent Shares, if any, to be issued will be determined based on a valuation of these specified oil and gas properties at December 31, 1996. Also, as part of the Consolidation, the Company entered into Registration Rights Agreements whereby the former stockholders of CPOC and NOCO are entitled to require the Company to register Common Stock of the Company owned by them with the Securities and Exchange Commission for sale to the public in a firm commitment public offering and generally to include shares owned by them, at no cost, in registration statements filed by the Company. Costs of the offering will not include discounts and commissions, which will be paid by the respective sellers of the Common Stock. F-13 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. OIL AND GAS PROPERTIES The following table sets forth cost information relating to the Company's oil and gas activities:
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ---------------------------------- 1996 1995 1994 1993 ------------- ---------- ---------- ---------- (UNAUDITED) Capitalized costs incurred: (IN THOUSANDS) Beginning of period balance........ $ 304,737 $ 285,976 $ 260,971 $ 258,554 Property acquisition............... 2,153 14,017 23,037 2,550 Exploration and development........ 1,816 4,830 1,976 1,253 Sale of mineral interests.......... (528 ) (86) (8) (1,386) ------------- ---------- ---------- ---------- End of period balance.............. $ 308,178 $ 304,737 $ 285,976 $ 260,971 ============= ========== ========== ========== Accumulated depreciation, depletion and amortization: Beginning of period balance........ $ 257,143 $ 246,975 $ 240,926 $ 237,515 Provision for depreciation, depletion and amortization....... 7,515 10,168 6,049 3,411 ------------- ---------- ---------- ---------- End of period balance.............. $ 264,658 $ 257,143 $ 246,975 $ 240,926 ============= ========== ========== ==========
Depreciation, depletion and amortization per unit-of-production (equivalent barrel of oil) amounted to $5.95, $5.80 and $5.29 for the years ended December 31, 1995, 1994 and 1993, respectively, and $6.02 and $5.79 for the nine months ended September 30, 1996 and 1995, respectively. 9. NET PROFITS INTEREST Since 1989, the Constituent Entities have entered into separate agreements to purchase certain oil and gas properties with gross contract acquisition price of $170,000,000 ($150,000,000 net as of closing dates) and in simultaneous transactions, entered into agreements to sell overriding royalty interests ("ORRI") in the acquired properties. These ORRI are in the form of net profits interests ("NPI") equal to a significant percentage of the excess of gross proceeds over production costs, as defined, from the acquired oil and gas properties. A net deficit incurred in any month can be carried forward to subsequent months until such deficit is fully recovered. The Company has the right to abandon the purchased oil and gas properties if it deems the properties to be uneconomical. The Company has, pursuant to the purchase agreements, created abandonment trusts whereby funds are provided out of gross production proceeds from the properties for the estimated amount of future abandonment obligations related to the working interests owned by the Company. The Trusts are administered by unrelated third party trustees for the benefit of the Company's working interest in each property. The Trust agreements limit their funds to be disbursed for the satisfaction of abandonment obligations. Any funds remaining in the Trusts after all restoration, dismantlement and abandonment obligations have been met will be distributed to the owners of the properties in the same ratio as contributions to the Trusts. The Trusts' assets are excluded from the Consolidated Balance Sheets of the Company because the Company does not control the Trusts. Estimated future revenues and costs associated with the NPI and the Trusts are also excluded from the oil and gas reserve disclosures at Note 12. As of December 31, 1995 and 1994 the Trusts' assets (all cash and investments) totaled $16,100,000 and $14,208,000, respectively, all of which will be available to the Company to pay its portion, as working interest owner, of the restoration, dismantlement and abandonment costs discussed at Note 7. F-14 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At the time of acquisition of properties by the Company, the property owners estimated the future costs to be incurred for site restoration, dismantlement and abandonment, net of salvage value. A portion of the amounts necessary to pay such estimated costs was deposited in the Trusts upon acquisition of the properties, and the remainder is deposited from time to time out of the proceeds from production. The determination of the amount deposited upon the acquisition of the properties and the amount to be deposited as proceeds from production was based on numerous factors, including the estimated reserves of the properties. The amounts deposited in the Trusts upon acquisition of the properties was capitalized by the Company as oil and gas properties. As operator, the Company receives all of the revenues and incurs all of the production costs for the purchased oil and gas properties but retains only that portion applicable to its net ownership share. As a result, the payables and receivables associated with operating the properties included in the Company's Consolidated Balance Sheets include both the Company's and all other outside owner's shares. However, revenues and production costs associated with the acquired properties reflected in the accompanying Consolidated Statements of Operations represent only the Company's share, after reduction for the NPI. At December 31, 1995 and 1994 the amounts payable to the NPI owners included in the accounts payable in the accompanying Consolidated Balance Sheets were approximately $2,836,000 and $2,087,000, respectively, and $6,203,000 at September 30, 1996. 10. EMPLOYEE BENEFIT PLANS The Company has adopted a series of incentive compensation plans designed to align the interest of the executives and employees with those of its stockholders. The following is a brief description of each plan: o The Savings and Protection Plan, provides employees with the option to defer receipt of a portion of their compensation and the Company may, at its discretion, match a portion of the employee's deferral. The Company may also elect, at its discretion, to contribute a non- matching amount to employees. The amounts held under the Savings and Protection Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested immediately upon participation in the Savings and Protection Plan. The total amounts contributed by the Company were $176,000, $154,000 and $151,000 in the years 1995, 1994 and 1993, respectively. o The 1994 Stock Incentive Plan (the "Plan") provides for 600,000 shares of Common Stock to be reserved for issuance pursuant to such Plan. Under the Plan the Company may grant both stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options, as well as performance shares. No options will be granted at an exercise price of less than fair market value of the Common Stock on the date of grant. During 1994 the Company granted options to purchase a total of 460,000 shares of Common Stock pursuant to the Plan at $10 per share. In 1995, the Company granted 30,000 additional options under the Plan at an average exercise price of $10.08 per share. All such options could be exercised after January 1, 1996 and have an expiration date ten years from date of grant. On August 23, 1996,the Board of Directors of the Company approved and adopted the 1996 Plan, and granted stock options to purchase an aggregate 450,000 shares of Common Stock to the Company's executive officers and senior management under the 1996 Plan, subject to stockholder approval of the 1996 Plan. All of such options were granted at an exercise price of $12 per share, the fair market value of the Common Stock on the date of grant, and 20% of each option becomes exercisable on January 1 of each succeeding year, beginning January 1, 1997. Unvested options are subject to forfeiture upon certain termination of employment events. The Compensation Committee also awarded performance shares totaling 225,000 shares under the 1996 Plan to the Company's executive officers on August 23, 1996, subject to stockholder approval of the F-15 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 1996 Plan. All of the performance shares granted vest in whole on January 1, 2001, and are subject to forfeiture upon certain termination of employment events. The Company has no other formal benefit plans. 11. PREFERRED STOCK In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible Exchangeable Preferred Stock, Series A (the "Preferred Stock"). Annual dividends are $2.125 per share and are cumulative. The net proceeds of the $.01 par value stock after underwriters discount and expense was $30,899,000. Each share has a liquidation preference of $25.00, plus accrued and unpaid dividends. Dividends on the Preferred Stock are cumulative from the date of issuance and are payable quarterly, commencing January 15, 1996. The Preferred Stock is convertible at any time, at the option of the holders thereof, unless previously redeemed, into shares of Common Stock of the Company at an initial conversion price of $11 per share of Common Stock, subject to adjustments under certain conditions. The Preferred Stock is redeemable at any time on or after December 31, 1998, in whole or in part at the option of the Company at a redemption price of $26.488 per share beginning at December 31, 1998 and at premiums declining to the $25.00 liquidation preference by the year 2005 and thereafter, plus accrued and unpaid dividends. The Preferred Stock is also exchangeable, in whole, but not in part, at the option of the Company on or after January 15, 1998 for the Company's 8.5% Convertible Subordinated Debentures due 2010 (the "Debentures") at a rate of $25.00 principal amount of Debentures for each share of Preferred Stock. The Debentures will be convertible into Common Stock of the Company on the same terms as the Preferred Stock and will pay interest semi-annually. The Company used approximately $21.5 million of the net proceeds from the sale of the Preferred Stock to repay outstanding indebtedness under its primary credit facility (See Note 5), which indebtedness was incurred to finance certain acquisitions of properties. The Company is using the excess of the net proceeds from the sale of the Preferred Stock over the amount used to repay indebtedness, together with internally generated cash flows to acquire, develop and explore oil and gas properties. 12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) The Company's proved oil and gas reserves at December 31, 1995, have been estimated by independent petroleum consultants in accordance with guidelines established by the Securities and Exchange Commission ("SEC"). Accordingly, the following reserve estimates are based upon existing economic and operating conditions. There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represent estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company's oil and gas properties or the cost that would be incurred to obtain equivalent reserves. F-16 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are located in the United States, are as follows: YEAR ENDED DECEMBER 31, ------------------------------- 1995 1994 1993 --------- --------- --------- Proved developed and undeveloped reserves: Crude Oil (MBbls): Beginning of period................ 4,424 2,842 3,324 Revisions to previous estimates.... (441) (303) (248) Purchase of reserves in place...... 1,363 2,245 -- Sales of reserves in place......... (2) (3) (4) Extensions and discoveries......... 16 7 139 Production......................... (594) (364) (369) --------- --------- --------- End of Period...................... 4,766 4,424 2,842 ========= ========= ========= Natural Gas (MMcf): Beginning of period................ 24,102 14,167 10,947 Revisions to previous estimates.... (976) (2,793) 1,404 Purchase of reserves in place...... 12,985 16,757 3,701 Sales of reserves in place......... (22) (39) (305) Extensions and discoveries......... 271 85 79 Production......................... (6,693) (4,075) (1,659) --------- --------- --------- End of Period...................... 29,667 24,102 14,167 ========= ========= ========= Proved developed reserves: Crude Oil (MBbls): Beginning of period................ 3,309 2,084 2,569 ========= ========= ========= End of Period...................... 3,890 3,309 2,084 ========= ========= ========= Natural Gas (MMcf): Beginning of period................ 20,582 11,366 9,753 ========= ========= ========= End of Period...................... 20,408 20,582 11,366 ========= ========= ========= STANDARDIZED MEASURE The Company's standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves which follows was computed using reserve valuations based on regulations prescribed by the SEC. These regulations provide that the oil, condensate and gas price structure utilized to project future net cash flows reflects current prices at each date presented and have been escalated only when known and determinable price changes are provided by contract and law. Future production, development and net abandonment costs are based on current costs without escalation. No future income taxes were provided on the future net inflows as tax credits (including carryovers) and other permanent differences are expected to be higher than the estimated future income taxes calculated using the appropriate statutory rates. The resulting net future cash flows have been discounted to their present values based on a 10% annual discount factor. F-17 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (UNAUDITED) YEAR ENDED DECEMBER 31, ---------------------------------- 1995 1994 1993 ---------- ---------- ---------- (IN THOUSANDS) Future cash inflows..................... $ 157,240 $ 115,659 $ 70,320 Future costs -- Production......................... (50,236) (43,579) (27,805) Development and net abandonment.... (11,274) (12,603) (6,701) ---------- ---------- ---------- Future net inflows before income taxes................................. 95,730 59,477 35,814 Future income taxes..................... -- -- -- ---------- ---------- ---------- Future net cash flows................... 95,730 59,477 35,814 10% discount factor..................... (31,966) (18,094) (13,260) ---------- ---------- ---------- Standardized measure of discounted future net cash flows................. $ 63,764 $ 41,383 $ 22,554 ========== ========== ========== CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES (UNAUDITED) YEAR ENDED DECEMBER 31, -------------------------------- 1995 1994 1993 ---------- --------- --------- (IN THOUSANDS) Standardized measure -- beginning of period................................ $ 41,383 $ 22,554 $ 25,296 Sales and transfers, net of production costs................................. (12,477) (9,815) (5,811) Net change in sales and transfer prices, net of production costs............... 11,519 1,368 (5,496) Exchange and sale of in place reserves.............................. (23) (48) (326) Purchases, extensions, discoveries, and improved recovery, net of future production and development costs...... 28,204 26,376 7,090 Revisions of quantity estimates......... (4,242) (6,297) 461 Accretions of discount.................. 2,963 1,488 1,957 Changes in production rates, timing and other................................. (3,563) 5,757 (617) ---------- --------- --------- Standardized measure -- end of period... $ 63,764 $ 41,383 $ 22,554 ========== ========= ========= F-18 CALLON PETROLEUM COMPANY PRO FORMA CONSOLIDATED FINANCIAL STATEMENT The following unaudited pro forma financial statement presents the results of operations of Callon Petroleum Company (the "Company"). Such unaudited pro forma combined information is based on the historical results of operations of the Company and the effect of the issuance by the Company of 1,315,500 shares of $2.125 Convertible Exchangeable Preferred Stock, Series A on November 28, 1995. On December 29, 1995, Callon Petroleum Operating Company, a wholly owned subsidiary of the Company purchased a 66.67% working interest in Chandeleur Block 40 (the "CB 40 Acquisition") and, in a simultaneous transaction, sold one-third of the acquired interest to a third party. The Company's net purchase price of $6 million was funded from existing cash on hand. See Note 1 in the Notes to Pro Forma Consolidated Financial Statement for the basis of presentation of the above described events in this Pro Forma Consolidated Financial Statement of the Company. F-19 CALLON PETROLEUM COMPANY PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)
YEAR ENDED DECEMBER 31, 1995 ---------------------------------------------------------- ADJUSTMENTS ---------------------------------------------------------- PREFERRED HISTORICAL STOCK CB 40 PRO FORMA COMPANY OFFERING ACQUISITION AS ADJUSTED ---------- --------- ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Revenues: Oil and gas sales.................. $ 23,210 $ -- $ 1,400(d) $24,610 Interest........................... 627 -- -- 627 ---------- --------- ----------- ----------- Total revenues................ 23,837 -- 1,400 25,237 ---------- --------- ----------- ----------- Expenses: Production costs................... 6,732 -- 295(d) 7,027 Depreciation, depletion and amortization..................... 10,376 -- 521(d) 10,897 General and administrative......... 3,880 -- -- 3,880 Interest........................... 1,794 (1,794)(b) -- -- ---------- --------- ----------- ----------- Total expenses................ 22,782 (1,794) 816 21,804 ---------- --------- ----------- ----------- Income from operations.................. 1,055 1,794 584 3,433 Provision for income taxes.............. -- 628(a) 204(a) 832 ---------- --------- ----------- ----------- Net income.............................. 1,055 1,166 380 2,601 Preferred stock dividends............... 256 2,539(c) -- 2,795 ---------- --------- ----------- ----------- Net income (loss) available to common shares................................ $ 799 $ (1,373) $ 380 $ (194) ========== ========= =========== =========== Net income (loss) per common share...... $ (0.03) =========== Weighted average common shares outstanding........................... 5,755 ===========
See Notes to Pro Forma Consolidated Financial Statement. F-20 NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENT (UNAUDITED) 1. BASIS OF PRESENTATION The Company was formed in 1994 to succeed to the business and properties of a group of companies engaged in the exploration, development and operations of oil and gas properties. The Company subsequently issued 1,315,500 shares of $2.125 Convertible Exchangeable Preferred Stock, Series A on November 28, 1995. On December 29, 1995, Callon Petroleum Operating Company, a wholly owned subsidiary of the Company, purchased a 66.67% working interest in Chandeleur Block (the "CB 40 Acquisition") and, in simultaneous transaction under a preexisting agreement, sold one-third of the acquired interest to a third party. The Company's net purchase price of $6 million was funded from existing cash on hand. The accompanying Pro Forma Consolidated Statement of Operations of the Company for the year ended December 31, 1995, reflects the sale of the 1,315,500 shares of Preferred Stock of the Company and the CB 40 Acquisition in each case as if such transactions occurred at the beginning of the period presented. The Pro Forma Consolidated Statement of Operations is based on the assumptions set forth in the notes to such statement. Such pro forma information should be read in conjunction with the related financial information of the Company and is not necessarily indicative of the results which would actually have occurred had the transactions been in effect on the date or for the period indicated or which may occur in the future. 2. PRO FORMA ADJUSTMENTS Pro Forma entries necessary to adjust the historical financial statement of the Company are as follows: (a) To record a provision for Federal income taxes at a corporate statutory rate of 35% of the combined pro forma income before taxes. (b) Reflects a reduction of interest expense related to the use of Preferred Stock offering proceeds to repay debt as if the offering had occurred on January 1, 1995 for the year ended December 31, 1995. No adjustment has been made to reflect the potential interest income from the investment of the excess proceeds from the offering over the amount of debt repaid and the CB 40 Acquisition. (c) Represents preferred stock dividends computed at the dividend rate of $2.125 per share on the 1,315,500 preferred shares as if the offering was completed on January 1, 1995 for the year ended December 31, 1995. (d) To reflect the purchase of the CB 40 Acquisition and the related results of operations including an adjustment for depletion as described in Note 1. F-21 ================================================================================ NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN THIS PROSPECTUS IN CONNECTION WITH THE OFFER CONTAINED HEREIN AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR THE UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL, OR A SOLICITATION OF AN OFFER TO BUY, THE NOTES OFFERED HEREBY BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER IS NOT AUTHORIZED, OR IN WHICH THE PERSON MAKING SUCH OFFER IS NOT QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF. ------------------------ TABLE OF CONTENTS PAGE ----- Available Information................... 2 Prospectus Summary...................... 3 Risk Factors............................ 8 The Company............................. 12 Use of Proceeds......................... 13 Capitalization.......................... 14 Selected Financial Data................. 15 Management's Discussion and Analysis of Financial Condition and Results of Operations............................ 17 Business and Properties................. 23 Management.............................. 35 Principal Stockholders.................. 43 Description of Notes.................... 45 Description of Outstanding Securities and Debt Instruments.................. 60 Underwriting............................ 63 Legal Matters........................... 63 Experts................................. 63 Glossary................................ 64 Index to Financial Statements........... F-1 ================================================================================ $21,000,000 [LOGO FOR CALLON] CALLON PETROLEUM COMPANY 10% SENIOR SUBORDINATED NOTES DUE 2001 PROSPECTUS MORGAN KEEGAN & COMPANY, INC. ================================================================================ -----END PRIVACY-ENHANCED MESSAGE-----