-----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, ICUSZqaV2oA19P/dwwVoMNTpieQGcJBprgjuydcIOf7Fwtd/iXNb0TWzb9rFBZYz d33CSBLDgu2VwSi/aQmwJQ== 0000890566-97-002553.txt : 19971126 0000890566-97-002553.hdr.sgml : 19971126 ACCESSION NUMBER: 0000890566-97-002553 CONFORMED SUBMISSION TYPE: 424B1 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19971125 SROS: NONE 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: SEC FILE NUMBER: 333-39401 FILM NUMBER: 97727845 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 Statement No. 333-39401 PROSPECTUS 1,600,000 SHARES [LOGO] CALLON PETROLEUM COMPANY COMMON STOCK ------------------------ All 1,600,000 shares (the "Shares") of Common Stock, par value $.01 per share (the "Common Stock"), of Callon Petroleum Company ("Callon" or the "Company") offered hereby (the "Offering") are being sold by the Company. The Common Stock is traded on the Nasdaq National Market ("Nasdaq") under the symbol "CLNP." On November 24, 1997, the last sale price of the Common Stock as reported on Nasdaq was $18 1/2 per share. See "Price Range of Common Stock and Dividend Policy." SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN MATTERS THAT SHOULD BE CONSIDERED BY POTENTIAL INVESTORS. 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. UNDERWRITING PROCEEDS TO PRICE TO PUBLIC DISCOUNT(1) COMPANY(2) --------------- --------------------- ------------------------ Per share.... $17.00 $0.935 $16.065 Total(3)..... $27,200,000 $1,496,000 $25,704,000 - ------------ (1) The Company has agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended (the "Securities Act"). See "Underwriting." (2) Before deducting estimated offering expenses of $500,000 payable by the Company. (3) The Company has granted the Underwriters an over-allotment option, exercisable for 30 days from the date of this Prospectus, to purchase up to an additional 240,000 shares of Common Stock from the Company solely to cover over-allotments. If all such shares are purchased by the Underwriters, the total Price to Public, Underwriting Discount and Proceeds to Company will be $31,280,000, $1,720,400 and $29,559,600, respectively. See "Underwriting." ------------------------ The Shares are offered by the Underwriters, subject to prior sale, when, as and if issued to and accepted by them, and subject to certain other conditions. The Underwriters reserve 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 Shares will be made on or about December 1, 1997. ------------------------ MORGAN KEEGAN & COMPANY, INC. A.G. EDWARDS & SONS, INC. HOWARD, WEIL, LABOUISSE, FRIEDRICHS INCORPORATED JEFFERIES & COMPANY, INC. The date of this Prospectus is November 25, 1997. CERTAIN PERSONS PARTICIPATING IN THE OFFERING MAY ENGAGE IN TRANSACTIONS THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK, INCLUDING OVER-ALLOTMENT, STABILIZING TRANSACTIONS, SYNDICATE SHORT COVERING TRANSACTIONS AND IMPOSING PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING." IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON STOCK ON THE NASDAQ NATIONAL MARKET IN ACCORDANCE WITH RULE 103 OF REGULATION M UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED (THE "EXCHANGE ACT"). SEE "UNDERWRITING." 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 UNDERWRITERS' OVER-ALLOTMENT OPTION WILL NOT BE EXERCISED. UNLESS OTHERWISE INDICATED, PRO FORMA INFORMATION GIVES EFFECT TO THE ELF ACQUISITION (AS DEFINED), THE CHEVRON ACQUISITION (AS DEFINED) AND THE OFFERING AS IF THEY OCCURRED ON THE DATE OR AS OF THE BEGINNING OF THE EARLIEST PRO FORMA PERIOD INDICATED. CERTAIN TERMS RELATING TO THE OIL AND GAS INDUSTRY ARE DEFINED IN "GLOSSARY." THE COMPANY Callon Petroleum Company has been engaged in the acquisition, development, exploration and production of oil and gas since 1950. The Company's properties are geographically concentrated offshore in the Gulf of Mexico and onshore in Louisiana and Alabama. As of October 31, 1997, on a pro forma basis, the Company had estimated net proved reserves of 118.0 Bcfe with a PV-10 Value of $194.2 million, representing increases of 61% and 21%, respectively, from December 31, 1996. Approximately 93% of these pro forma reserves are proved developed. Average daily production during the first nine months of 1997 was 42.1 MMcfe/d, representing an increase of 54% over the first nine months of 1996. Since 1995, the Company has increasingly supplemented its acquisition of producing properties with exploration and development drilling in the Gulf of Mexico. Between January 1, 1995 and October 31, 1997, Callon accomplished the following: o Increased pro forma estimated net proved reserves to 118.0 Bcfe from 50.6 Bcfe at a Reserve Replacement Cost of $1.07 per Mcfe. o Increased the pro forma PV-10 Value of estimated net proved reserves to $194.2 million from $41.4 million. o Completed 14 acquisitions of properties with estimated net proved reserves of 80.4 Bcfe for a total acquisition cost of $68.4 million, or $0.85 per Mcfe, on a pro forma basis. o Spent $14.2 million to drill and complete 3 exploratory wells and 12 development wells, which added estimated net proved reserves of 27.8 Bcf. o Assembled an inventory of 37 exploration prospects in the Gulf of Mexico which remain to be drilled. o Increased EBITDA to $16.1 million in 1996 from $6.7 million in 1994. For the first nine months of 1997, EBITDA rose 90% to $21.9 million compared with the first nine months of 1996. o Increased earnings per share to $0.45 in 1996 compared to a loss of $0.03 per share in 1994. Earnings per share for the first nine months of 1997 rose 215% to $0.63 compared with the first nine months of 1996. BUSINESS STRATEGY The Company's objective is to enhance shareholder value through sustained growth in its reserve base, production levels, and resulting cash flow from operations. In furtherance of this strategy, the Company (i) acquires properties with exploration and development potential; (ii) utilizes advanced technology, including proprietary high resolution, shallow focus seismic technology and the latest available 3-D seismic surveys; (iii) balances lower risk, shallow target exploration in the Shallow Miocene Trend and similar geologic areas with higher risk, large target exploration; and (iv) acquires properties which provide it with the ability to control or significantly influence operations. 3 EXPLORATION AND DEVELOPMENT ACTIVITIES The Company currently conducts its exploration and development activities in three areas, the Shallow Miocene Trend, the Main Pass Block 32/35 Area and in various areas in a joint venture with Murphy Oil Corporation ("Murphy"). THE SHALLOW MIOCENE TREND. The Company conducts exploration and development activities in the Shallow Miocene Trend in the Gulf of Mexico, where it seeks oil and gas deposits located near existing production facilities at true vertical depths of between 1,800 and 6,000 feet. Relatively low exploration and development costs and high initial production rates characterize successful wells in this area. The Company has successfully used high-resolution, shallow focused seismic techniques to explore for and develop these shallow gas deposits. These seismic techniques utilize high-definition two dimensional seismic lines shot in a tight grid, with spacing as close as 50 meters. The Company has developed a proprietary method of processing and interpreting this data which the Company believes gives it a competitive advantage over other companies exploring in the Shallow Miocene Trend. During 1996, the Company completed four proprietary high-resolution seismic surveys over an eight block area contiguous to Chandeleur Block 40. Based on these surveys, between October 1996 and July 1997, the Company drilled 2 gross (1.5 net) successful development wells, 2 gross (2.0 net) successful exploratory wells and one unsuccessful (0.7 net) development well in this area for a drilling success rate of 80%. Primarily as a result of these wells, the Company's average daily production for the first nine months of 1997 increased to 42.1 MMcfe/d, a 54% increase over the same period of 1996. The Company intends to use this high-resolution seismic technique to confirm 3-D seismic surveys of shallow gas prospects on its Brazos Blocks 582 and 610 in the Gulf of Mexico. Through year end 1998, the Company's budget includes drilling 3 gross (2.4 net) exploration wells and 2 gross (1.2 net) development wells in the Shallow Miocene Trend and Brazos Blocks 582 and 610, for a total net dry hole cost of $10.9 million, excluding completion and development costs. MAIN PASS 32/35 AREA. In the Main Pass Block 32/35 Area, the Company owns and operates 14 producing wells in a field located in shallow Louisiana-state waters which produce from true vertical depths of between 6,000 and 9,000 feet. In November 1996, the Company completed a 36 square-mile 3-D seismic survey covering its Main Pass Block 35 field and adjoining acreage. Based upon this data, the Company farmed-in and successfully drilled a development well to a total depth of 10,900 feet in August 1997, which added estimated net proved reserves as of October 31, 1997 of 7.7 Bcfe. The Company also acquired additional acreage in this area and entered into a joint venture agreement with Burlington Resources Oil & Gas Company to drill eight prospects identified by the 3-D seismic survey at true vertical depths of between 13,000 and 15,000 feet. The Company will operate and has retained an approximate 42.4% working interest in wells drilled on these prospects. Through 1998, the Company's budget includes drilling 7 gross (3.0 net) exploration wells and 3 gross (0.9 net) development wells in the Main Pass Block 32/35 Area for a total net dry hole cost of $11.4 million, excluding completion and development costs. THE MURPHY JOINT VENTURE. The Company has also entered into an agreement with Murphy to jointly explore 32 blocks in the Gulf of Mexico, primarily in shallow waters seeking deposits to true vertical depths of 17,500 feet. In September 1997, the Company and Murphy drilled a successful exploration well on Eugene Island Block 335 to a total vertical depth of 6,094 feet. As of October 31, 1997, the Eugene Island Block 335 field had estimated proved reserves of 5.8 Bcfe, net to Callon. During November 1997, the Company drilled a successful sidetrack well to a measured depth of 6,330 feet. The Company is currently drilling a third well in the field. The Company and Murphy have generated an additional 18 prospects in the shallow waters of the Gulf of Mexico, to explore for oil and gas deposits at true vertical depths of between 8,000 and 17,500 feet. The Company owns either a 20% or 25% working interest in each of these prospects. The Company's budget through 1998 includes the drilling of 8 gross (1.9 net) exploration wells and one gross (0.2 net) development well on eight of these prospects, for a total net dry hole cost of $8.9 million, excluding completion and development costs. 4 The Company and Murphy have also acquired acreage and generated five prospects in the deep waters of the Gulf of Mexico. The Company plans to drill an exploration well with Murphy in 900 feet of water during the fourth quarter of 1997. Estimated dry hole costs to drill this well are $2.2 million, net to Callon. In total, the Company's current capital budget through fiscal 1998 of $85.6 million contemplates the drilling of 6 gross (2.2 net) development wells and 19 gross (7.5 net) exploratory wells, at an estimated net dry hole cost to the Company of $33.4 million and $52.2 million in completion and development costs. These drilling operations will be financed through cash flows from operations, the net proceeds of this Offering, the proceeds of property sales and borrowings under the Company's credit facility with a commercial bank ("Credit Facility"). The Company's Credit Facility had an available borrowing base of $40 million as of September 30, 1997. See "Use of Proceeds." RECENT DEVELOPMENTS During 1997, the Company focused its acquisition efforts in the Shallow Miocene Trend in the Mobile Block 864 Area located offshore Alabama. During the first nine months of 1997, Callon consummated three acquisitions in this area and in October 1997 agreed to acquire properties also located in this area from Chevron U.S.A. Inc. In October 1997, the Company also entered into a letter of intent to sell properties in its Black Bay Complex. RECENT ACQUISITIONS. In June 1997, the Company closed an $11.8 million acquisition from Elf Exploration, Inc. (the "Elf Acquisition") for their interest in three adjoining blocks located in the Shallow Miocene Trend in federal waters in the Mobile Block 864 Area. In August 1997, for $7.5 million Callon acquired from Koch Exploration Company (the "Koch Acquisition") an interest in two wells producing from the Shallow Miocene Trend adjoining the blocks acquired in the Elf Acquisition. Additionally, in September 1997, at a purchase price of $10.6 million the Company acquired from Santa Fe Energy Resources, Inc. additional interests in the properties acquired in the Koch Acquisition, along with an interest in a well in a nearby block. In total, the Company spent $29.9 million to acquire properties in the Mobile Block 864 Area which as of October 31, 1997, had estimated net proved reserves of 32 Bcfe. The Company's average net daily production during September 1997 from this area was 6.9 MMcf/d. In October 1997, the Company agreed to purchase 61% of Chevron U.S.A. Inc.'s interest in the Mobile Block 864 Area for $21 million, effective July 1, 1997 (the "Chevron Acquisition"). As of October 31, 1997, estimated net proved reserves attributable to the Chevron Acquisition were 18.6 Bcfe. The Chevron Acquisition closed on November 7, 1997 for a net acquisition cost of $18.8 million. As a result of this acquisition, the Company will have acquired an average 55.4% working interest in seven blocks, a 53.3% working interest in the Mobile Block 864 Area unit and the unit production facilities, a 66.7% working interest in two producing wells and a 50% working interest in another well. The Company became the operator of the unit representing approximately 57% of its estimated net proved reserves in the Mobile Block 864 Area as of October 31, 1997 on an Mcfe basis, and related production facilities. The Company has identified two development prospects and one exploration prospect in the Mobile Block 864 Area. Following the Chevron Acquisition, the Company plans to conduct an extensive shallow focus, high-resolution seismic survey over the area to refine its development plans and to explore for additional prospects. Production from the area is currently limited by the capacity of the production facilities, which the Company intends to increase during 1998. SALE OF BLACK BAY COMPLEX. The Company has entered into a letter of intent to sell its interest in the Black Bay Complex which will net the Company an estimated $11.4 million (including amounts released to the Company previously placed in escrow to cover abandonment costs). 5 THE OFFERING Common Stock offered by the Company.....1,600,000 shares Common Stock to be outstanding after the Offering..........................7,628,994(1) Use of Proceeds.........................The net proceeds of the Offering will be utilized to repay indebtedness incurred to finance the Chevron Acquisition and to fund a portion of the Company's 1997 and 1998 capital expenditure budget. Prior to the utilization of the net proceeds, the Company will invest such funds in short-term investments. Nasdaq Symbol..........................."CLNP" - ------------ (1) Excludes 1,044,000 shares of Common Stock issuable upon exercise of stock options outstanding as of September 30, 1997, at a weighted average exercise price of $11.19. Also excludes 2,990,132 shares reserved for issuance pursuant to the Company's $2.125 Convertible Preferred Stock with a conversion price of $11 per share. Includes 225,000 performance shares issued under the Callon Petroleum Company 1996 Stock Incentive Plan which do not vest until January 1, 2001 and 25,000 restricted shares issued in 1997 under the Callon Petroleum Company 1994 Stock Incentive Plan which vest 20% annually beginning January 2, 1998. 6 SUMMARY CONSOLIDATED FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE DATA)
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, ---------------------------------------- --------------------------------------------- 1997 1996 1996 1995 1994 ---------------------------- --------- ---------------------- --------- --------- PRO FORMA PRO AS ADJUSTED(1) HISTORICAL FORMA(1) HISTORICAL -------------- ---------- -------- ---------- STATEMENT OF OPERATIONS DATA(2): Revenues: Oil and gas sales.............. $ 36,058 $ 29,578 $ 18,578 $38,954 $ 25,764 $ 23,210 $ 13,948 Interest and other............. 1,162 1,162 537 946 946 627 171 -------------- ---------- --------- -------- ---------- --------- --------- Total revenues............. 37,220 30,740 19,115 39,900 26,710 23,837 14,119 -------------- ---------- --------- -------- ---------- --------- --------- Costs and Expenses: Lease operating expenses....... 6,219 6,235 5,646 8,102 7,562 6,732 4,042 Depreciation, depletion and amortization................. 14,169 11,288 7,697 14,744 9,832 10,376 6,049 General and administrative..... 3,263 3,263 2,352 3,495 3,495 3,880 3,717 Interest....................... 1,496 945 184 1,861 313 1,794 624 -------------- ---------- --------- -------- ---------- --------- --------- Total costs and expenses................. 25,147 21,731 15,879 28,202 21,202 22,782 14,432 -------------- ---------- --------- -------- ---------- --------- --------- Income (loss) from operations....... 12,073 9,009 3,236 11,698 5,508 1,055 (313) Provision (benefit) for income taxes............................. 4,225 2,926 -- 4,094 50 -- (200) -------------- ---------- --------- -------- ---------- --------- --------- Net income (loss)................... 7,848 6,083 3,236 7,604 5,458 1,055 (113) Preferred stock dividends........... 2,097 2,097 2,097 2,795 2,795 256 -- -------------- ---------- --------- -------- ---------- --------- --------- Net income (loss) available to common shares..................... $ 5,751 $ 3,986 $ 1,139 $ 4,809 $ 2,663 $ 799 $ (113) ============== ========== ========= ======== ========== ========= ========= Net income (loss) per common share: Primary........................ $ 0.72 $ 0.63 $ 0.20 $ 0.64 $ 0.45 $ 0.14 $ (0.03) ============== ========== ========= ======== ========== ========= ========= Assuming full dilution......... $ 0.71 $ 0.62 $ 0.20 $ 0.62 $ 0.43 $ 0.14 $ (0.03) ============== ========== ========= ======== ========== ========= ========= Shares used in computing earnings per common share: Primary........................ 7,932 6,332 5,755 7,552 5,952 5,755 4,346 ============== ========== ========= ======== ========== ========= ========= Assuming full dilution......... 11,030 6,440 5,755 7,735 6,135 5,755 4,346 ============== ========== ========= ======== ========== ========= ========= BALANCE SHEET DATA(2): Working capital..................... $ 10,038 $ 3,626 $ 2,968 N/A $ 4,878 $ 4,712 $ 1,896 Oil and gas properties, net......... 146,088 127,296 68,415 N/A 82,489 57,765 43,920 Total assets........................ 181,554 156,350 99,923 N/A 118,520 83,867 73,786 Total debt.......................... 60,250 60,250 8,950 N/A 24,250 100 19,234 Total stockholders' equity.......... 108,086 82,882 76,268 N/A 77,864 75,129 43,431 OTHER FINANCIAL DATA(2): Capital expenditures, net........... $ 75,429 $ 56,629 $ 19,874 N/A $ 36,063 $ 24,237 $ 10,412 EBITDA(3)........................... 28,377 21,882 11,534 N/A 16,066 13,582 6,727 Cash provided by operating activities........................ 26,253 20,308 17,122 N/A 14,323 9,452 5,347
(FOOTNOTES ON FOLLOWING PAGE) 7 - ------------ (1) Pro forma information gives effect to the Elf Acquisition and the Chevron Acquisition as if they occurred as of the beginning of the earliest pro forma period presented. Pro forma, as adjusted information gives effect to the Elf Acquisition, the Chevron Acquisition and the Offering as if they occurred on September 30, 1997. (2) 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." (3) EBITDA is earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is a financial measure commonly used in the Company's industry and should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income and may vary among companies, the EBITDA presented above may not be comparable to similarly titled measures of other companies. 8 SUMMARY OPERATING AND RESERVE DATA(1)
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, ---------------------------------- --------------------------------------------- 1997 1996 1996 1995 1994 ---------------------- --------- ---------------------- --------- --------- PRO PRO FORMA(2) HISTORICAL FORMA(2) HISTORICAL -------- ---------- -------- ---------- PRODUCTION DATA: Oil (MBbls)......................... 351 351 451 585 585 594 364 Gas (MMcf).......................... 12,276 9,394 4,784 11,459 6,269 6,694 4,076 Total production (MMcfe)............ 14,379 11,497 7,490 14,970 9,781 10,261 6,260 AVERAGE SALES PRICE: Oil (per Bbl)....................... $ 18.83 $ 18.83 $ 18.05 $ 18.27 $ 18.27 $ 16.68 $ 15.63 Gas (per Mcf)....................... 2.40 2.45 2.18 2.47 2.40 1.96 2.00 Total production (per Mcfe)......... 2.51 2.57 2.48 2.60 2.63 2.24 2.21 OTHER OPERATING DATA PER MCFE: Average sales price................. $ 2.51 $ 2.57 $ 2.48 $ 2.60 $ 2.63 $ 2.24 $ 2.21 Lease operating expenses............ 0.36 0.45 0.56 0.41 0.57 0.49 0.49 Severance taxes..................... 0.07 0.09 0.20 0.13 0.20 0.17 0.16 -------- ---------- --------- -------- ---------- --------- --------- Gross margin........................ $ 2.08 $ 2.03 $ 1.72 $ 2.06 $ 1.86 $ 1.58 $ 1.56 ======== ========== ========= ======== ========== ========= ========= OCTOBER 31, 1997 DECEMBER 31, ------------------------- -------------------------------- PRO FORMA(3) HISTORICAL(4) 1996(5) 1995 1994 -------- ------------- ---------- --------- --------- RESERVE REPLACEMENT COSTS(6)............ $ 1.07 $ 1.10 $ 0.74 $ 1.05 $ 0.97 ESTIMATED NET PROVED RESERVES: Oil (MBbls)........................ 3,909 3,909 3,819 4,766 4,424 Gas (MMcf)......................... 94,523 75,912 50,424 29,667 24,102 Gas equivalent (MMcfe)............. 117,977 99,366 73,338 58,263 50,646 PV-10 Value (000s)................. $194,172 $ 158,056 $ 160,171 $ 63,764 $ 41,383
- ------------ (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) Pro forma information gives effect to the Elf Acquisition and the Chevron Acquisition as if they occurred on the date or as of the beginning of the earliest pro forma period indicated. (3) Gives effect to the Chevron Acquisition as if it occurred on October 31, 1997. (4) Future net cash flows attributable to the Company's estimated proved reserves and the present value of such cash flows were based on an average gas price of $3.09 per Mcf and an average oil price of $20.09 per Bbl at October 31, 1997. The average price received for production in the first nine months of 1997 was $2.41 per Mcf for gas and $18.95 per Bbl for oil, without the effects of hedging. (5) Future net cash flows attributable to the Company's estimated proved reserves and the present value of such cash flows were based on an average gas price of $3.88 per Mcf and an average oil price of $23.58 per Bbl at December 31, 1996. The average price received for production in 1996 was $2.63 per Mcf for gas and $20.55 per Bbl for oil, without the effects of hedging. (6) See "Glossary." 9 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 BUDGET ESTIMATES, 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 INVESTORS SHOULD CAREFULLY CONSIDER, TOGETHER WITH OTHER INFORMATION IN THIS PROSPECTUS, THE FOLLOWING FACTORS THAT AFFECT THE COMPANY. VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION 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. In addition, the marketability of the Company's production depends upon the availability and capacity of gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand all could adversely affect the Company's ability to produce and market its oil and natural gas. If market factors were to change dramatically, the financial impact on the Company could be substantial. The availability of markets and the volatility of product prices are beyond the control of the Company and represent a significant risk. 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, certain of the Company's wells 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. 10 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. 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 Securities and Exchange Commission (the "Commission"), 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 11 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 includes drilling 6 gross (2.2 net) development wells and 19 gross (7.5 net) exploratory wells through fiscal 1998. The estimated cost, net to the Company, to drill and complete these wells is approximately $85.6 million with dry hole costs of approximately $33.4 million. The drilling of several unsuccessful wells in this area could have a material adverse effect on the Company. 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. SHORTAGES OF RIGS, EQUIPMENT, SUPPLIES AND PERSONNEL There is a general shortage of drilling rigs, equipment and supplies which the Company believes may intensify. The costs and delivery times of rigs, equipment and supplies are substantially greater than in prior periods and are currently escalating. Shortages of drilling rigs, equipment or supplies could delay and adversely affect the Company's exploration and development operations, which could have a material adverse effect on its financial condition and results of operations. The demand for, and wage rates of, qualified rig crews have begun to rise in the drilling industry in response to the increasing number of active rigs in service. Such shortages have in the past occurred in the industry in times of increasing demand for drilling services. If the number of active drilling rigs continues to increase, the oil and gas industry may experience shortages of qualified personnel to operate drilling rigs, which could delay the Company's drilling operations and adversely affect the Company's financial condition and results of operations. 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, proceeds from bank borrowings and issuance of debt and equity securities. The Company's total capital expenditure budget for drilling and completion costs through fiscal 1998 is approximately $85.6 million, and could be reduced depending on the success of the Company's drilling activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Expenditures." The Company makes unsolicited offers for the acquisition of oil and gas properties in the normal course of business. In the event that any such offers are accepted, the amount or composition of the Company's capital expenditure budget could be revised significantly. 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 12 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. Approximately 29% of the Company's estimated oil production for the last three months of 1997 is hedged at a New York Mercantile Exchange ("NYMEX") floor price of $18.00 per Bbl and a ceiling price of $24.00 per Bbl (NYMEX). In addition, from October 1997 through March 1998, the Company has hedged 48% of its estimated natural gas equivalent production at an average floor price of $2.31 per MMBtu (NYMEX) and an average ceiling price of $3.03 per MMBtu (NYMEX). 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 may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells, 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. The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on the operating costs of the Company, as well as on the oil and gas industry in general. 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. Moreover, 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 and accidental 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 and accidental environmental damages is available at a reasonable cost. Accordingly, the Company may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of its properties in the event of certain environmental damages. See "Business and Properties -- Environmental Regulations." 13 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"), NOCO Enterprises, L.P., a limited partnership owned by a consortium of European institutional investors ("NOCO"), and Fred. Olsen Energy ASA, a Norwegian public joint-stock company ("F.O. Energy"), who collectively and beneficially own over 60% of the outstanding Common Stock, are parties to a stockholders' agreement (the "Stockholders' Agreement") pursuant to which members of the Callon Family, NOCO and F.O. Energy agree (the Callon family as one party, and NOCO and F.O. Energy as the other party) (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, NOCO and F.O. Energy will be able to control the election of at least four directors of the Company. See "Principal Stockholders -- Stockholders' Agreement." SHARES ELIGIBLE FOR FUTURE SALE Each of the Company and its directors and executive officers, the Callon Family, NOCO and F.O. Energy has agreed not to dispose of any shares of Common Stock for a period of 90 days from the date of this Prospectus without the consent of Morgan Keegan & Company, Inc. Following such period and subject to the volume and other limitations of Rule 144 under the Securities Act, all of the shares of Common Stock beneficially owned by directors and officers of the Company will be eligible for public sale. Moreover, the Company may issue shares of Common Stock in the future. Sales of substantial amounts of Common Stock in the public market, or the perception of the availability of shares for sale, could adversely affect the prevailing market price of the Common Stock and could impair the Company's ability to raise capital through the sale of its securities. 14 THE COMPANY The Company was formed under Delaware law in 1994 to succeed to the business and properties of Callon Petroleum Operating Company, an independent energy company owned by members of the Callon Family ("Callon Petroleum Operating"), 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 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 from this Offering will be $25.2 million ($29.1 million if the Underwriters' over-allotment option is exercised in full), after deducting the underwriting discount and estimated offering expenses. The Company intends to use such net proceeds to pay $18,800,000 of indebtedness incurred to finance the Chevron Acquisition and to fund a portion of its 1997 and 1998 capital expenditure budget. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Prior to the utilization of such funds, the Company will invest in short-term investments. As of November 15, 1997, $18,900,000 was outstanding under the Credit Facility with a rate of 8.50%. 15 PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY The Common Stock is traded on Nasdaq under the symbol "CLNP." The following table sets forth the high and low sale prices per share of the Common Stock as reported on Nasdaq for the periods indicated. HIGH LOW ---- ---- 1995: 1st Quarter........................ $11 $ 9 1/2 2nd Quarter........................ 10 1/2 9 3rd Quarter........................ 12 1/4 9 1/4 4th Quarter........................ 11 9 1/32 1996: 1st Quarter........................ 10 1/2 9 1/2 2nd Quarter........................ 14 1/4 10 3rd Quarter........................ 13 1/2 10 3/4 4th Quarter........................ 19 1/8 12 1/2 1997: 1st Quarter........................ 19 1/2 12 1/2 2nd Quarter........................ 16 3/8 13 1/4 3rd Quarter........................ 19 3/8 15 4th Quarter (through November 24)............................... 22 17 3/4 On November 24, 1997, the last sale price of the Common Stock as reported on Nasdaq was $18 1/2 per share. On September 30, 1997, there were approximately 7,761 stockholders of record of the Common Stock. The Company has not paid dividends on the Common Stock and does not intend to in the near future. The Company intends to reinvest its cash flow into acquisitions, development and exploration. The Credit Facility prohibits payment of dividends of the Common Stock. 16 CAPITALIZATION The following table sets forth the capitalization of the Company as of September 30, 1997 and as adjusted to give effect to the Chevron Acquisition and the sale of the Shares offered by the Company hereby and the application of the net proceeds 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, 1997 ---------------------------- PRO FORMA HISTORICAL AS ADJUSTED(1) ---------- -------------- (IN THOUSANDS) Cash and cash equivalents............... $ 5,939 $ 12,351 ========== ============== Long-term debt: Credit Facility.................... $ 100 $ 100 10% Senior Subordinated Notes due 2001.............................. 24,150 24,150 10.125% Senior Subordinated Notes due 2002(2)....................... 36,000 36,000 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, 6,028,994 shares outstanding, 7,628,994 as adjusted(3).......... 60 76 Unearned Compensation -- Restricted Stock(4).......................... (2,410) (2,410) Capital in excess of par value..... 77,467 102,655 Retained earnings.................. 7,752 7,752 ---------- -------------- Total stockholders' equity......... 82,882 108,086 ---------- -------------- Total capitalization............... $ 143,132 $168,336 ========== ============== - ------------ (1) Pro forma information gives effect to the Chevron Acquisition as if it occurred on September 30, 1997. (2) On July 31, 1997, the Company issued $36.0 million aggregate principal amount of its 10.125% Series A Senior Subordinated Notes due 2002 ("Series A Notes") in a private placement. Until November 10, 1997, the Series A Notes are exchangeable for $36.0 million aggregate principal amount of the Company's 10.125% Series B Senior Subordinated Notes due 2002 that have been registered under the Securities Act. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." (3) Excludes 1,044,000 shares of Common Stock issuable upon exercise of stock options outstanding as of September 30, 1997, at a weighted average exercise price of $11.19. Also excludes 2,990,132 shares reserved for issuance pursuant to the Company's $2.125 Convertible Preferred Stock with a conversion price of $11 per share. Includes 225,000 performance shares issued under the Callon Petroleum Company 1996 Stock Incentive Plan which do not vest until January 1, 2001, and 25,000 restricted shares issued in 1997 under the Callon Petroleum Company 1994 Stock Incentive Plan which vest 20% annually beginning January 2, 1998. (4) Represents the unearned portion of restricted stock awards under the Company's 1996 Stock Incentive Plan. This unearned portion is being amortized as compensation expense on a straight-line basis over the related vesting period. 17 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 data for each of the five years in the period ended December 31, 1996 have been derived from the audited Consolidated Financial Statements of the Company for such periods. The financial data for the nine-month periods ended September 30, 1997 and 1996 has been derived from the Company's Unaudited Consolidated Financial Statements. The data 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 pro forma financial information is based upon, and should be read in conjunction with, the Unaudited Pro Forma Consolidated Financial Statements, including the Notes thereto, appearing elsewhere in this Prospectus. The following data is not necessarily indicative of future results for the Company.
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------------------------- -------------------------------------------- 1997 1996 1996 1995 1994 -------------------------- --------- --------------------- --------- --------- PRO FORMA(1) PRO AS ADJUSTED HISTORICAL FORMA(1) HISTORICAL ----------- ------------ -------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA(2): Revenues: Oil and gas sales................... $ 36,058 $ 29,578 $ 18,578 $38,954 $ 25,764 $ 23,210 $ 13,948 Interest and other.................. 1,162 1,162 537 946 946 627 171 ----------- ------------ --------- -------- ---------- --------- --------- Total revenues...................... 37,220 30,740 19,115 39,900 26,710 23,837 14,119 Costs and Expenses: Lease operating expenses............ 6,219 6,235 5,646 8,102 7,562 6,732 4,042 Depreciation, depletion and amortization...................... 14,169 11,288 7,697 14,744 9,832 10,376 6,049 General and administrative.......... 3,263 3,263 2,352 3,495 3,495 3,880 3,717 Interest............................ 1,496 945 184 1,861 313 1,794 624 ----------- ------------ --------- -------- ---------- --------- --------- Total costs and expenses....... 25,147 21,731 15,879 28,202 21,202 22,782 14,432 ----------- ------------ --------- -------- ---------- --------- --------- Income (loss) from operations........... 12,073 9,009 3,236 11,698 5,508 1,055 (313) Provision (benefit) for income taxes................................. 4,225 2,926 -- 4,094 50 -- (200) ----------- ------------ --------- -------- ---------- --------- --------- Income (loss) before cumulative effect of change in accounting principle..... 7,848 6,083 3,236 7,604 5,458 1,055 (113) Cumulative effect of change in accounting principle.................. -- -- -- -- -- -- -- ----------- ------------ --------- -------- ---------- --------- --------- Net income (loss)....................... 7,848 6,083 3,236 7,604 5,458 1,055 (113) Preferred stock dividends............... 2,097 2,097 2,097 2,795 2,795 256 -- ----------- ------------ --------- -------- ---------- --------- --------- Net income (loss) available to common shares................................ 5,751 3,986 1,139 4,809 2,663 799 (113) ----------- ------------ --------- -------- ---------- --------- --------- Pro forma adjustment (unaudited): Provision for income taxes.......... -- -- -- -- -- -- -- ----------- ------------ --------- -------- ---------- --------- --------- Pro forma net income (loss)............. $ 5,751 $ 3,986 $ 1,139 $ 4,809 $ 2,663 $ 799 $ (113) =========== ============ ========= ======== ========== ========= ========= Net income (loss) per common share: Primary............................. $ 0.72 $ 0.63 $ 0.20 $ 0.64 $ 0.45 $ 0.14 $ (0.03) =========== ============ ========= ======== ========== ========= ========= Assuming full dilution.............. $ 0.71 $ 0.62 $ 0.20 $ 0.62 $ 0.43 $ 0.14 $ (0.03) =========== ============ ========= ======== ========== ========= ========= Shares used in computing earnings per common share: Primary............................. 7,932 6,332 5,755 7,552 5,952 5,755 4,346 =========== ============ ========= ======== ========== ========= ========= Assuming full dilution.............. 11,030 6,440 5,755 7,735 6,135 5,755 4,346 =========== ============ ========= ======== ========== ========= =========
1993 1992 --------- --------- STATEMENT OF OPERATIONS DATA(2): Revenues: Oil and gas sales................... $ 10,048 $ 10,015 Interest and other.................. 230 232 --------- --------- Total revenues...................... 10,278 10,247 Costs and Expenses: Lease operating expenses............ 3,713 3,702 Depreciation, depletion and amortization...................... 3,411 3,360 General and administrative.......... 2,350 1,848 Interest............................ 196 160 --------- --------- Total costs and expenses....... 9,670 9,070 --------- --------- Income (loss) from operations........... 608 1,177 Provision (benefit) for income taxes................................. 113 235 --------- --------- Income (loss) before cumulative effect of change in accounting principle..... 495 942 Cumulative effect of change in accounting principle.................. 5,262 -- --------- --------- Net income (loss)....................... 5,757 942 Preferred stock dividends............... -- -- --------- --------- Net income (loss) available to common shares................................ 5,757 942 --------- --------- Pro forma adjustment (unaudited): Provision for income taxes.......... 100 145 --------- --------- Pro forma net income (loss)............. $ 5,657 $ 797 ========= ========= Net income (loss) per common share: Primary............................. $ 1.53 $ 0.25 ========= ========= Assuming full dilution.............. $ 1.53 $ 0.25 ========= ========= Shares used in computing earnings per common share: Primary............................. 3,769 3,769 ========= ========= Assuming full dilution.............. 3,769 3,769 ========= ========= (TABLE CONTINUED ON FOLLOWING PAGE) 18
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------------------------- -------------------------------------------- 1997 1996 1996 1995 1994 -------------------------- --------- --------------------- --------- --------- PRO FORMA(1) PRO AS ADJUSTED HISTORICAL FORMA(1) HISTORICAL ----------- ------------ -------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) BALANCE SHEET DATA(2): Working capital..................... $ 10,038 $ 3,626 $ 2,968 N/A $ 4,878 $ 4,712 $ 1,896 Oil and gas properties, net......... 146,088 127,296 68,415 N/A 82,489 57,765 43,920 Total assets........................ 181,554 156,350 99,923 N/A 118,520 83,867 73,786 Total debt.......................... 60,250 60,250 8,950 N/A 24,250 100 19,234 Total stockholders' equity.......... 108,086 82,882 76,268 N/A 77,864 75,129 43,431 OTHER FINANCIAL DATA(2): Capital expenditures, net........... $ 75,429 $ 56,629 $ 19,874 N/A $ 36,063 $ 24,237 $ 10,412 EBITDA(3)........................... 28,377 21,882 11,534 N/A 16,066 13,582 6,727 Cash provided by operating activities........................ 26,253 20,308 17,122 N/A 14,323 9,452 5,347
1993 1992 --------- --------- BALANCE SHEET DATA(2): Working capital..................... $ (687) $ (1,011) Oil and gas properties, net......... 21,000 22,138 Total assets........................ 39,825 35,570 Total debt.......................... 2,691 2,975 Total stockholders' equity.......... 27,170 22,711 OTHER FINANCIAL DATA(2): Capital expenditures, net........... $ 2,710 $ 3,817 EBITDA(3)........................... 4,496 4,949 Cash provided by operating activities........................ 4,735 2,031 - ------------ (1) Pro forma information gives effect to the Elf Acquisition and the Chevron Acquisition as if they occurred as of the beginning of the earliest pro forma period presented. Pro forma, as adjusted information gives effect to the Elf Acquisition, the Chevron Acquisition and the Offering as if they occurred on September 30, 1997. (2) 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." (3) EBITDA is earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is a financial measure commonly used in the Company's industry and should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income and may vary among companies, the EBITDA presented above may not be comparable to similarly titled measures of other companies. 19 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL 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 depreciated, depleted and amortized by a charge 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 write-down of oil and gas properties is not reversible at a later date even if oil or natural gas prices increase. The Company has not had a ceiling test write-down since 1986. 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, -------------------- ------------------------------- 1997 1996 1996 1995 1994 --------- --------- --------- --------- --------- Production: Oil (MBbls)..................... 351 451 585 594 364 Gas (MMcf)...................... 9,394 4,784 6,269 6,694 4,076 Total production (MMcfe)........ 11,497 7,490 9,781 10,261 6,260 Average Sales Price: Oil (per Bbl)................... $ 18.83 $ 18.05 $ 18.27 $ 16.68 $ 15.63 Gas (per Mcf)................... 2.45 2.18 2.40 1.96 2.00 Total production (per Mcfe)..... 2.57 2.48 2.63 2.24 2.21 Average Costs (per Mcfe): Lease operating expenses (excluding severance taxes)... $ 0.45 $ 0.56 $ 0.57 $ 0.49 $ 0.49 Severance taxes................. 0.09 0.20 0.20 0.17 0.16 Depreciation, depletion and amortization.................. 0.98 1.03 1.01 1.01 0.97 General and administrative (net of management fees)........... 0.28 0.31 0.36 0.38 0.59
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, -------------------- ------------------------------- 1997 1996 1996 1995 1994 --------- --------- --------- --------- --------- (MMCFE) (MMCFE) Production attributable to: Main Pass 163 Area.............. 3,333 122 463 -- -- Chandeleur Block 40............. 3,094 1,158 1,385 144 37 Big Escambia Creek.............. 650 578 739 390 -- Black Bay Complex............... 803 914 1,208 1,351 603 North Dauphin Island Field...... 1,132 2,514 3,069 5,102 2,524 --------- --------- --------- --------- --------- 9,012 5,286 6,864 6,987 3,164 Other properties................ 2,485 2,204 2,917 3,274 3,096 --------- --------- --------- --------- --------- Total...................... 11,497 7,490 9,781 10,261 6,260 ========= ========= ========= ========= =========
20 NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH THE NINE MONTHS ENDED SEPTEMBER 30, 1996 For the nine months ended September 30, 1997, total oil and gas revenues increased by $11 million, or 59%, to $29.6 million compared to $18.6 million for the same period in 1996. For the nine months ended September 30, 1997, oil production and revenues decreased to 351 MBbls and $6.6 million, respectively. For the comparable period in 1996, oil production was 451 MBbls while revenues totaled $8.1 million. Oil prices during the first nine months of 1997 averaged $18.83, compared to $18.05 for the same period in 1996. Although prices were higher, the loss of production from the properties which were sold and the decline in other non-core properties caused the overall decline in oil revenues. Natural gas production and revenues for the nine-month period ended September 30, 1997 were 9.39 Bcf and $23 million, respectively, increasing from 4.78 Bcf and gas revenues of $10.4 million in the first nine months of 1996. The average sales price for natural gas in the first nine months of 1997 was $2.45 per Mcf, a $0.27 per Mcf increase over the same period in 1996. The combination of increased prices and production volumes generated the 120% increase in total gas revenues. Lease operating expenses, excluding severance taxes, for the first nine months of 1997 increased by 24% to $5.2 million from $4.2 million for the comparable period in 1996. This increase is primarily the result of expenses associated with new producing properties. Severance taxes decreased by 29% to $1.1 million during the first nine months of 1997 from $1.5 million for the same period in 1996 as a result of production declines in the Company's onshore properties and property sales and a higher portion of the Company's production coming from federal offshore leases, which are not subject to severance taxes. Depreciation, depletion and amortization for the first nine months of 1997 was $11.3 million, or $0.98 per Mcfe. For the same period in 1996, the total was $7.7 million and $1.03 per Mcfe. During the first nine months of 1997, general and administrative expenses increased by 39% to $3.3 million compared to $2.4 million for the nine-month period ended September 30, 1996. Increased compensation expense related to stock plans and a reduction in management fees as a result of property sales, combined to produce this overall increase. Interest expense during the first three quarters of 1997 was $945,000 compared to $184,000 for the first three quarters of 1996 as a result of the increase in the Company's long-term debt. YEAR ENDED DECEMBER 31, 1996 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1995 Oil and gas sales increased $2.6 million, or 11%, during 1996 to $25.8 million compared to $23.2 million in 1995. While oil and gas production volumes for 1996 were lower than those reported in 1995, substantial price increases for both oil and gas more than offset the loss in revenues. The average sales price per Bbl sold in 1996 increased to $18.27, compared to $16.68 for 1995. The average sales price per Mcf of gas sold increased from $1.96 in 1995 to $2.40 in 1996. Oil production for 1996 decreased slightly to 585 MBbls from the 594 MBbls produced in 1995. This reduction was primarily attributable to the implementation of the required environmental protection program (zero discharge) at the Black Bay Complex, the Company's largest single oil producing prospect. During this process, several producing wells were shut-in while various new equipment was installed. In addition, several wells were temporarily shut-in while repairs were conducted on the service lines. Therefore, average daily production for 1996 dropped to 1,599 Bbls/d compared to 1,629 Bbls/d in 1995. Gas production for 1996 was 6.3 Bcf, a decrease from the 6.7 Bcf reported in 1995. This reduction was primarily attributable to the loss of production from the North Dauphin Island Field where problems with excess water content in the gas sales stream were encountered early in the year requiring the installation of a dehydrator and removal of water from the lines. Extraneous water production from the #2A well led to the shut-in of the well and the natural decline of the reservoir pressure. Also during the year, this field incurred a lower production rate due to compressor inefficiencies which led to a compressor restaging program that was completed in late September. 21 Lease operating expenses, including severance taxes, increased from $6.7 million in 1995 to $7.6 million in 1996. A large portion of this increase, $600,000, was attributable to normal expenses associated with new property additions. Other expenses included the installation of a dehydrator and the workover expenses at the North Dauphin Island Field. Depreciation, depletion and amortization expense for 1996 was $9.8 million compared to $10.4 million for 1995. When compared on a per unit-of-production basis, the expense incurred was $1.01 per Mcfe produced for each of the two years. General and administrative expenses declined from $3.9 million for 1995 to $3.5 million for 1996, as a result of the Company's continued efforts to improve operational efficiencies. Interest expense decreased from $1.8 million in 1995 to $313,000 in 1996. This expense reduction corresponds with the smaller average monthly outstanding balance on the long-term debt of the Company for 1996 when compared to 1995. During the fourth quarter of 1995, the Company used $21.5 million of the proceeds from the sale of preferred stock to reduce its long-term debt. During the course of 1996, additional funds advanced under the Company's line of credit were repaid in November with the proceeds from the issuance of $24.2 million of the Company's 10% Senior Subordinated Notes due 2001 (the "10% Notes"). The average outstanding balance in long-term debt during 1996 was $5.3 million. The recorded income tax expense for 1996 was $50,000. The computed provision for income taxes at the Company's expected statutory rate was $1.9 million, which was primarily offset by a reduction in the deferred tax asset valuation allowance as a result of the Company's ability to utilize its net operating losses and depletion carryovers. 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 was 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. ("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 Bbl sold also increased by $1.05 in 1995 from 1994 prices, resulting in a total $4.3 million increase in oil revenues. Total gas production increased 2.6 Bcf to 6.7 Bcf in 1995 from 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 $0.04 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 an 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. 22 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 carry forward and other temporary differences which the Company believes will not be utilized. LIQUIDITY AND CAPITAL RESOURCES CAPITAL SOURCES The Company's primary sources of capital are its cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Cash provided from operations during 1996 totaled $14.3 million. During 1996, the Company borrowed $12.9 million from financial institutions and repaid such borrowing with the proceeds from the sale of $24.2 million of its 10% Notes completed in November 1996. At December 31, 1996, the Company had working capital in the amount of $4.9 million. Net cash provided by operating activities for the nine months ended September 30, 1997 totaled $20.3 million. During the first nine months of 1997, a total of $61 million was paid for capital expenditures, $18.5 million for debt repayments and $2.1 million was paid as dividends to the preferred stockholders. Effective October 31, 1996, the Company entered into a new Credit Facility with Chase Manhattan Bank. 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 or a borrowing base ("Borrowing Base") of $30 million which is adjusted periodically on the basis of a discounted present value of future net cash flows attributable to the Company's proved producing oil and gas reserves. 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 December 31, 1996 was 8.25%. 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. At September 30, 1997, the unpaid balance due on the Credit Facility was $100,000. On November 27, 1996, the Company issued $24.2 million of its 10% Notes. The Company used the proceeds to pay down the Credit Facility and for other corporate purposes. Interest on the 10% Notes is payable quarterly and began on March 15, 1997. The 10% Notes are 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 10% Notes are general unsecured obligations of the Company, subordinated in right of payment to all existing and future indebtedness of the Company and rank PARI PASSU with the 10.125% Senior Subordinated Notes due 2002. The Credit Facility and the indenture for the 10% Notes contain various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. On July 31, 1997, the Company issued $36 million of its 10.125% Series A Senior Subordinated Notes due 2002 in a private placement for net proceeds of $34.8 million. The Company used $18.5 million of the net proceeds to repay borrowings under the Credit Facility and the remaining net proceeds have been allocated to the Company's capital expenditure budget. On September 10, 1997, pursuant to a Registration Agreement dated July 31, 1997, the Company commenced an offer to exchange the Series A Notes for a like principal amount of 10.125% Series B Senior Subordinated Notes due 2002 (the "Series B Notes" and, together with the Series A Notes, the "10.125% Notes"). The form and terms of the Series B Notes are identical in all material respects to the form and terms of the Series A Notes, except for certain transfer restrictions and provisions relating to registration rights. The exchange offer was completed on 23 November 10, 1997 and $36 million principal amount of Series A Notes were exchanged for $36 million principal amount of Series B Notes. Interest on the 10.125% Notes is payable quarterly, on March 15, June 15, September 15, and December 15 of each year. The 10.125% Notes are redeemable at the option of the Company in whole or in part, at any time on or after September 15, 2000. The 10.125% Notes are general unsecured obligations of the Company, subordinated in right of payment to all existing and future indebtedness of the Company and rank PARI PASSU with the 10% Notes. The Credit Facility and the indenture for the 10.125% Notes contain various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. 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 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 had in effect hedges of gas equivalent to approximately 16% of its production at a floor price per MMBtu of $1.75 (NYMEX) and a ceiling price per MMBtu of $2.20 (NYMEX). In addition, the Company was 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 (NYMEX) and a ceiling price per Bbl of $19.59 (NYMEX). During the third quarter of 1996, the Company terminated hedges attributable to its fourth quarter 1996 production at a profit, which had the effect of increasing fourth quarter oil and gas revenues by $180,000. The Company is currently a party to hedges that will be in effect for the last three months of 1997 representing approximately 29% of its estimated oil production, at a floor price of $18.00 per Bbl (NYMEX) and a ceiling price per Bbl of $24.00 (NYMEX). In addition, from October 1997 through March 1998, the Company has open hedging positions covering 48% of its estimated natural gas equivalent production at an average floor price of $2.31 per MMBtu (NYMEX) and an average ceiling price of $3.03 per MMBtu (NYMEX). In addition, the Company has realized gains of $290,000 from termination of swap contracts relating to December 1997 and January 1998 natural gas production. CAPITAL EXPENDITURES Capital expenditures for 1996 totaled $36.1 million which included $19.2 million of lease acquisitions, $2.7 million for the acquisition of producing properties and equipment and $14.2 million for property development and drilling activities on its properties. During the first nine months of 1997, capital expenditures were $61 million. Of such amount, approximately $24 million was expended on drilling, development and exploration activities and $37 million on acquisitions of producing properties, undeveloped mineral interests and seismic information attributable to future drilling sites. The Company focuses on exploration and development drilling. The Company's capital budget through fiscal 1998 contemplates the drilling of 6 gross (2.2 net) development wells and 19 gross (7.5 net) exploratory wells, at an estimated net cost to the Company to drill and complete of $85.6 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. The Company had available borrowings under its Credit Facility of $40 million as of September 30, 1997. See "Use of Proceeds." If the Company's initial drilling operations are not successful, the Company may redeploy its remaining capital budget to other activities. See "Risk Factors -- Substantial Capital Requirements." ACCOUNTING POLICIES In February 1997, the Financial Accounting Standards Board issued Statement No. 128 ("FAS 128"), "Earnings Per Share," which simplifies the computation of earnings per share. FAS 128 is effective for financial statements issued for periods ending after December 15, 1997 and requires restatement for all prior period earnings per share data presented. The Company intends to comply with FAS 128. Also in early 1997, the Financial Accounting Standards Board issued Statement No. 129 ("FAS 129"), "Disclosure of Information about Capital Structure" effective for financial statements 24 issued for periods ending after December 15, 1997. The Company believes it is in compliance with the provisions of this statement. In June 1997, the Financial Accounting Standards Board issued Statement No. 130 ("FAS 130"), "Reporting Comprehensive Income." FAS 130 establishes standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. FAS 130 is effective for fiscal years beginning after December 15, 1997. The Company intends to comply with the provisions of FAS 130. Also in mid-1997, the Financial Accounting Standards Board issued Statement No. 131 ("FAS 131"), "Disclosures about Segments of an Enterprise and Related Information." FAS 131 establishes standards for the way that public businesses report information about operating segments in annual financial statements and requires those enterprises report selected information about operating segments in interim financial reports issued to shareholders. FAS 131 is effective for fiscal years beginning after December 15, 1997. The Company intends to comply with the provisions of FAS 131. 25 BUSINESS AND PROPERTIES THE COMPANY Callon Petroleum Company has been engaged in the acquisition, development, exploration and production of oil and gas since 1950. The Company's properties are geographically concentrated offshore in the Gulf of Mexico and onshore in Louisiana and Alabama. As of October 31, 1997, on a pro forma basis, the Company had estimated net proved reserves of 118 Bcfe with a PV-10 Value of $194.2 million, representing increases of 61% and 21%, respectively, from December 31, 1996. Approximately 93% of these pro forma reserves are proved developed. Average daily production during the first nine months of 1997 was 42.1 MMcfe/d, representing an increase of 54% over the first nine months of 1996. Since 1995, the Company has increasingly supplemented its acquisition of producing properties with exploration and development drilling in the Gulf of Mexico. Between January 1, 1995 and October 31, 1997, Callon accomplished the following: o Increased pro forma estimated net proved reserves to 118 Bcfe from 50.6 Bcfe at a Reserve Replacement Cost of $1.07 per Mcfe. o Increased the pro forma PV-10 Value of estimated net proved reserves to $194.2 million from $41.4 million. o Completed 14 acquisitions of properties with estimated net proved reserves of 80.4 Bcfe for a total acquisition cost of $68.4 million, or $0.85 per Mcfe, on a pro forma basis. o Spent $14.2 million to drill and complete 3 exploratory wells and 12 development wells, which added estimated net proved reserves of 27.8 Bcf. o Assembled an inventory of 37 exploration prospects in the Gulf of Mexico which remain to be drilled. o Increased EBITDA to $16.1 million in 1996 from $6.7 million in 1994. For the first nine months of 1997, EBITDA rose 90% to $21.9 million compared with the first nine months of 1996. o Increased earnings per share to $0.45 in 1996 compared to a loss of $0.03 per share in 1994. Earnings per share for the first nine months of 1997 rose 215% to $0.63 compared with the first nine months of 1996. BUSINESS STRATEGY The Company's objective is to enhance shareholder value through sustained growth in its reserve base, production levels, and resulting cash flow from operations. In furtherance of this strategy, the Company (i) acquires properties with exploration and development potential; (ii) utilizes advanced technology, including proprietary high resolution, shallow focus seismic technology and the latest available 3-D seismic surveys; (iii) balances lower risk, shallow target exploration in the Shallow Miocene Trend and similar geologic areas with higher risk, large target exploration; and (iv) acquires properties which provide it with the ability to control or significantly influence operations. EXPLORATION AND DEVELOPMENT ACTIVITIES The Company currently conducts its exploration and development activities in three areas, the Shallow Miocene Trend, the Main Pass Block 32/35 Area and in various areas in a joint venture with Murphy Oil Corporation. THE SHALLOW MIOCENE TREND. The Company conducts exploration and development activities in the Shallow Miocene Trend in the Gulf of Mexico, where it seeks oil and gas deposits located near existing production facilities at true vertical depths of between 1,800 and 6,000 feet. Relatively low exploration and development costs and high initial production rates characterize successful wells in this area. The Company has successfully used high-resolution, shallow focused seismic techniques to explore for and develop these 26 shallow gas deposits. These seismic techniques utilize high-definition two dimensional seismic lines shot in a tight grid, with spacing as close as 50 meters. The Company has developed a proprietary method of processing and interpreting this data which the Company believes gives it a competitive advantage over other companies exploring in the Shallow Miocene Trend. During 1996, the Company completed four proprietary high-resolution seismic surveys over an eight block area contiguous to Chandeleur Block 40. Based on these surveys, between October 1996 and July 1997, the Company drilled 2 gross (1.5 net) successful development wells, 2 gross (2.0 net) successful exploratory wells and one unsuccessful (0.7 net) development well in this area for a drilling success rate of 80%. Primarily as a result of these wells, the Company's average daily production for the first nine months of 1997 increased to 42.1 MMcfe/d, a 54% increase over the same period of 1996. The Company intends to use this high-resolution seismic technique to confirm 3-D seismic surveys of shallow gas prospects on its Brazos Blocks 582 and 610 in the Gulf of Mexico. Through year end 1998, the Company's budget includes drilling 3 gross (2.4 net) exploration wells and 2 gross (1.2 net) development wells in the Shallow Miocene Trend and Brazos Blocks 582 and 610, for a total net dry hole cost of $10.9 million, excluding completion and development costs. MAIN PASS 32/35 AREA. In the Main Pass Block 32/35 Area, the Company owns and operates 14 producing wells in a field located in shallow Louisiana-state waters which produce from true vertical depths of between 6,000 and 9,000 feet. In November 1996, the Company completed a 36 square-mile 3-D seismic survey covering its Main Pass Block 35 field and adjoining acreage. Based upon this data, the Company farmed-in and successfully drilled a development well to a total depth of 10,900 feet in August 1997, which added estimated net proved reserves as of October 31, 1997 of 7.7 Bcfe. The Company also acquired additional acreage in this area and entered into a joint venture agreement with Burlington Resources Oil & Gas Company to drill eight prospects identified by the 3-D seismic survey at true vertical depths of between 13,000 and 15,000 feet. The Company will operate and has retained an approximate 42.4% working interest in wells drilled on these prospects. Through 1998, the Company's budget includes drilling 7 gross (3.0 net) exploration wells and 3 gross (0.9 net) development wells in the Main Pass Block 32/35 Area for a total net dry hole cost of $11.4 million, excluding completion and development costs. THE MURPHY JOINT VENTURE. The Company has also entered into an agreement with Murphy to jointly explore 32 blocks in the Gulf of Mexico, primarily in shallow waters seeking deposits to true vertical depths of 17,500 feet. In September 1997, the Company and Murphy drilled a successful exploration well on Eugene Island Block 335 to a total vertical depth of 6,094 feet. As of October 31, 1997, the Eugene Island Block 335 field had estimated proved reserves of 5.8 Bcfe, net to Callon. During November 1997, the Company drilled a successful sidetrack well to a measured depth of 6,330 feet. The Company is currently drilling a third well in the field. The Company and Murphy have generated an additional 18 prospects in the shallow waters of the Gulf of Mexico, to explore for oil and gas deposits at true vertical depths of between 8,000 and 17,500 feet. The Company owns either a 20% or 25% working interest in each of these prospects. The Company's budget through 1998 includes the drilling of 8 gross (1.9 net) exploration wells and one gross (0.2 net) development well on eight of these prospects, for a total net dry hole cost of $8.9 million, excluding completion and development costs. The Company and Murphy have also acquired acreage and generated five prospects in the deep waters of the Gulf of Mexico. The Company plans to drill an exploration well with Murphy in 900 feet of water during the fourth quarter of 1997. Estimated dry hole costs to drill this well are $2.2 million, net to Callon. In total, the Company's current capital budget through fiscal 1998 of $85.6 million contemplates the drilling of 6 gross (2.2 net) development wells and 19 gross (7.5 net) exploratory wells, at an estimated net dry hole cost to the Company of $33.4 million and $52.2 million in completion and development costs. These drilling operations will be financed through cash flows from operations, the net proceeds of this Offering, the proceeds of property sales and borrowings under the Company's Credit Facility. The Company's Credit Facility had an available borrowing base of $40 million as of September 30, 1997. See "Use of Proceeds." 27 RECENT DEVELOPMENTS During 1997, the Company focused its acquisition efforts in the Shallow Miocene Trend in the Mobile Block 864 Area located offshore Alabama. During the first nine months of 1997, Callon consummated three acquisitions in this area and in October 1997 agreed to acquire properties also located in this area from Chevron U.S.A. Inc. In October 1997, the Company also entered into a letter of intent to sell properties in its Black Bay Complex. RECENT ACQUISITIONS. In June 1997, the Company closed an $11.8 million acquisition from Elf Exploration, Inc. for their interest in three adjoining blocks located in the Shallow Miocene Trend in federal waters in the Mobile Block 864 Area. In August 1997, for $7.5 million Callon acquired from Koch Exploration Company an interest in two wells producing from the Shallow Miocene Trend adjoining the blocks acquired in the Elf Acquisition. Additionally, in September 1997, at a purchase price of $10.6 million the Company acquired from Santa Fe Energy Resources, Inc. additional interests in the properties acquired in the Koch Acquisition, along with an interest in a well in a nearby block. In total, the Company spent $29.9 million to acquire properties in the Mobile Block 864 Area which as of October 31, 1997, had estimated net proved reserves of 32 Bcfe. The Company's average net daily production during September 1997 from this area was 6.9 MMcf/d. In October 1997, the Company agreed to purchase 61% of Chevron U.S.A. Inc.'s interest in the Mobile Block 864 Area for $21 million, effective July 1, 1997. As of October 31, 1997, estimated net proved reserves attributable to the Chevron Acquisition were 18.6 Bcfe. The Chevron Acquisition closed on November 7, 1997 for a net acquisition cost of $18.8 million. As a result of this acquisition, the Company will have acquired an average 55.4% working interest in seven blocks, a 53.3% working interest in the Mobile Block 864 Area unit and the unit production facilities, a 66.7% working interest in two producing wells and a 50% working interest in another well. The Company became the operator of the unit representing approximately 57% of its estimated net proved reserves in the Mobile Block 864 Area as of October 31, 1997 on an Mcfe basis, and related production facilities. The Company has identified two development prospects and one exploration prospect in the Mobile Block 864 Area. Following the Chevron Acquisition, the Company plans to conduct an extensive shallow focus, high-resolution seismic survey over the area to refine its development plans and to explore for additional prospects. Production from the area is currently limited by the capacity of the production facilities, which the Company intends to increase during 1998. SALE OF BLACK BAY COMPLEX. The Company has entered into a letter of intent to sell its interest in the Black Bay Complex which will net the Company an estimated $11.4 million (including amounts released to the Company previously placed in escrow to cover abandonment costs). 28 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 five largest producing fields and for all other properties combined at October 31, 1997 on a pro forma basis giving effect to the Chevron Acquisition.
ESTIMATED NET PROVED --------------------------------------------- PERCENT PV-10 TOTAL OIL GAS TOTAL PRIMARY VALUE PV-10 RESERVES RESERVES RESERVES FIELD NAME/LOCATION OPERATOR(S) ($000)(1) VALUE (MBBLS) (MMCF) (MMCFE) - ------------------------------------- ----------- ---------- --------- -------- -------- -------- Mobile Block 864 Area................ Various(2) $ 91,230 46.98% -- 50,620 50,620 Federal Waters Chandeleur Block 40.................. Callon 26,321 13.56% -- 12,518 12,518 Federal Waters Main Pass 32/35 Area................. Callon 17,818 9.18% 262 6,084 7,656 Louisiana State Waters Main Pass 163 Area................... Callon 15,723 8.10% -- 11,028 11,028 Federal Waters Big Escambia Creek................... Exxon USA 11,747 6.05% 961 2,425 8,191 Southeast Alabama Other properties..................... Various 31,333 16.13% 2,686 11,848 27,964 ---------- --------- -------- -------- -------- Total........................... $ 194,172 100.00% 3,909 94,523 117,977 ========== ========= ======== ======== ========
- ------------ (1) Future net cash flows attributable to the Company's estimated proved reserves and the present value of such cash flows were based on an average gas price of $3.09 per Mcf and an average oil price of $20.09 per Bbl at October 31, 1997. The average price received for production in the first nine months of 1997 was $2.41 per Mcf for gas and $18.95 per Bbl for oil, without the effects of hedging. (2) Following the Chevron Acquisition, the Company became operator of five wells in the Mobile Block 864 Area, representing 57% of the Company's estimated net proved reserves on an Mcfe basis as of October 31, 1997. MOBILE BLOCK 864 AREA The Mobile Block 864 area is located offshore Alabama in the federal waters of the OCS. During the first nine months of 1997, the Company consummated three acquisitions in this area and, in October 1997, agreed to acquire additional interests in producing properties from Chevron. In total, the Company has acquired an average 55.4% working interest in seven blocks, a 53.3% working interest in the Mobile Block 864 Area unit and the unit production facilities, a 66.7% working interest in two producing wells and a 50% working interest in another well. During September 1997, the unit and three wells averaged gross daily production of 36.1 MMcf from reservoirs in the Shallow Miocene Trend at depths ranging from 2,400 to 2,700 feet. Pro forma for the Chevron Acquisition, the Mobile Block 864 Area had estimated net proved reserves at October 31, 1997 of 50.6 Bcf and a PV-10 value of $91.2 million. Net average daily production during September 1997, on a pro forma basis giving effect to the Chevron Acquisition, was 16.5 MMcf. Following the acquisition from Chevron, the Company was appointed operator of the Mobile Block 864 Area unit. Production from three wells in the area is currently constrained by the capacity of the unit production facilities. The Company plans to add compression facilities to the existing platform to increase productive capacity during 1998. The Company has also identified two development prospects and one exploration prospect in this area using available 3-D seismic. Following the acquisition from Chevron, the Company plans to conduct an extensive shallow focus, high-resolution seismic survey over the area to refine its development plans and to explore for additional prospects during 1998. CHANDELEUR BLOCK 40 The Company and an institutional investor purchased a 33.3% working (27.8% net revenue) interest in Chandeleur Block 40 in 1994 located in the Shallow Miocene Trend. On December 29, 1995, Callon 29 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 to an industry partner for $3 million. The Company currently holds a combined 52.3% working (43.6% net revenue) interest in this property. The field's remaining proved reserves are estimated to be 12.5 Bcf of natural gas (net to the Company) as of October 31, 1997. When the Company assumed operations of the field, two wells were producing 5.5 MMcf/d of natural gas from the 3,800 foot sand. In February 1996, the Company shut-in one well and successfully reworked the other and increased average field production to 10.5 MMcf/d of natural gas. During the fourth quarter of 1996, the Company drilled a development well in the field. For the nine months ended September 30, 1997, the well was producing an average of 19.7 MMcf/d. The well resulted in a field extension which added 6 Bcf in estimated net proved reserves to the Company as of December 31, 1996. Total field production averaged approximately 26.0 MMcf/d during the first nine months of 1997. MAIN PASS 32/35 AREA In the Main Pass 32/35 Area, the Company owns and operates 14 producing wells in a field located in shallow Louisiana-state waters which produces oil and gas from reservoirs at depths of between 6,000 and 9,000 feet. In November 1996, the Company completed a 36 square-mile seismic survey covering its Main Pass Block 35 field and adjoining acreage. Based upon this data, the Company negotiated two separate farm-in agreements for a 100% working interest covering a prospect with reserve potential updip from existing production in a Cib Carst reservoir on Main Pass Block 31. In August 1997, the SL 12002 #1 was drilled to a total vertical depth of 10,900 feet, completed in a laminated pay section between 10,590 and 10,602 feet and tested at rates up to 7.5 MMcf/d with 334 barrels of condensate. The main pay section lies between 10,536 and 10,566 feet and has not been tested. The Company expects to place the SL 12002 #1 on production in December 1997 after flowlines are laid to a Company-operated production facility at Main Pass Block 32. The SL 12002 #1 had proved reserves at October 31, 1997 of 7.7 Bcfe and a PV-10 value of $17.8 million. MAIN PASS 163 AREA In two separate transactions during 1996, Callon acquired a 100% working interest in Chandeleur Block 41 and Main Pass Blocks 159, 160, 161 and 163 located in the Shallow Miocene Trend. The acquisition initially included five wells producing 4 MMcf/d, as well as production facilities at Main Pass 163 capable of handling 90 MMcf/d. Based upon interpretation of seismic data acquired and processed by Callon, an exploratory well was drilled on Main Pass Block 163 during the fourth quarter of 1996. For the nine months ending September 30, 1997, the well produced an average of 10.5 MMcf/d. A development well was also drilled during the fourth quarter of 1996 on Main Pass Block 161 and produced an average of 1.3 MMcf/d during the first nine months of 1997. During the second quarter of 1997, the Company drilled a successful well on Chandeleur Block 41 and production commenced in July 1997. Total production from the Main Pass 163 Area averaged approximately 15.5 MMcf/d for the first nine months of 1997. The Main Pass 163 Area wells produce from Shallow Miocene reservoirs at approximate depths of 3,300 feet. Proved reserves at October 31, 1997 attributable to this area were 11.0 Bcf, representing 7.25% of the Company's total PV-10 Value. BIG ESCAMBIA CREEK On June 29, 1995, the Company purchased an average working interest of 6.0% (6.6% net revenue interest), subject to a 10% reduction after payout, in nine wells and a 2.9% average royalty interest in another six wells. The gross average daily production for these wells during August 1997 was 3 MBbls of condensate, 1.7 MBbls of natural gas liquids, 9.1 MMcf of residue natural gas and 391 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. 30 RESERVES The following table sets forth certain information about the estimated net proved reserves of the Company as of the dates set forth below.
OCTOBER 31, 1997 DECEMBER 31, ---------------------------- -------------------------------- PRO FORMA(1) HISTORICAL(2) 1996(3) 1995 1994 ------------ ------------- ---------- --------- --------- Proved developed: Oil (MBbls)..................... 3,245 3,245 3,385 3,890 3,309 Gas (MMcf)...................... 90,254 71,643 49,491 20,408 20,582 Proved undeveloped: Oil (MBbls)..................... 664 664 434 876 1,115 Gas (MMcf)...................... 4,269 4,269 933 9,259 3,520 Total proved: Oil (MBbls)..................... 3,909 3,909 3,819 4,766 4,424 Gas (MMcf)...................... 94,523 75,912 50,424 29,667 24,102 Estimated pre-tax future net cash flows (000s)....................... $271,602 $ 217,966 $ 216,154 $ 95,730 $ 59,477 ============ ============= ========== ========= ========= PV-10 Value (000s)................... $194,172 $ 158,056 $ 160,171 $ 63,764 $ 41,383 ============ ============= ========== ========= =========
- ------------ (1) Gives effect to the Chevron Acquisition as if it occurred on October 31, 1997. (2) Future net cash flows attributable to the Company's estimated proved reserves and the present value of such cash flows were based on an average gas price of $3.09 per Mcf and an average oil price of $20.09 per Bbl at October 31, 1997. The average price received for production in the first nine months of 1997 was $2.41 per Mcf for gas and $18.95 per Bbl for oil, without the effects of hedging. (3) Future net cash flows attributable to the Company's estimated proved reserves and the present value of such cash flows were based on an average gas price of $3.88 per Mcf and an average oil price of $23.58 per Bbl at December 31, 1996. The average price received for production in 1996 was $2.63 per Mcf for gas and $20.55 per Bbl for oil, without the effects of hedging. 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 Commission 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, 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." 31 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, ---------------------------------- --------------------------------------------- 1997 1996 1996 1995 1994 ---------------------- --------- ---------------------- --------- --------- PRO PRO FORMA(1) HISTORICAL FORMA(1) HISTORICAL -------- ---------- -------- ---------- Production Data: Oil (MBbls)..................... 351 351 451 585 585 594 364 Gas (MMcf)...................... 12,276 9,394 4,784 11,459 6,269 6,694 4,076 Total production (MMcfe)........ 14,379 11,497 7,490 14,970 9,781 10,261 6,260
- ------------ (1) Pro forma information gives effect to the Elf Acquisition and the Chevron Acquisition as if they occurred at the beginning of the earliest pro forma period indicated. The following table sets forth the Company's average sales prices, operating data and capital expenditures for the periods indicated.
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, -------------------- ------------------------------- 1997 1996 1996 1995 1994 --------- --------- --------- --------- --------- Average Sales Price Per Unit: Oil (per Bbl)................... $ 18.83 $ 18.05 $ 18.27 $ 16.68 $ 15.63 Gas (per Mcf)................... 2.45 2.18 2.40 1.96 2.00 Total production (per Mcfe)..... 2.57 2.48 2.63 2.24 2.21 Other Operating Data per Mcfe: Average sales price............. $ 2.57 $ 2.48 $ 2.63 $ 2.24 $ 2.21 Lease operating expenses........ 0.45 0.56 0.57 0.49 0.49 Severance taxes................. 0.09 0.20 0.20 0.17 0.16 --------- --------- --------- --------- --------- Gross margin.................... $ 2.03 $ 1.72 $ 1.86 $ 1.58 $ 1.56 ========= ========= ========= ========= ========= Capital expenditures (net)(000s)..... $ 56,629 $ 19,874 $ 36,063 $ 24,237 $ 10,412 ========= ========= ========= ========= =========
32 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, ----------------------------------------------- 1996 1995 1994(1) ------------- ------------ ------------ GROSS NET GROSS NET GROSS NET ----- ---- ----- --- ----- --- Development: Oil............................. 1 .09 6 .65 7 .36 Gas............................. 2 1.52 1 .13 -- -- Non-Productive.................. -- -- -- -- 6 .42 ----- ---- ----- --- ----- --- Total...................... 3 1.61 7 .78 13 .78 ===== ==== ===== === ===== === Exploration: Oil............................. -- -- 1 .24 -- -- Gas............................. 1 1.0 -- -- -- -- Non-Productive.................. -- -- -- -- 1 .24 ----- ---- ----- --- ----- --- Total...................... 1 1.0 1 .24 1 .24 ===== ==== ===== === ===== ===
- ------------ (1) Drilling results prior to September 16, 1994 represent the combined drilling results of the Company's predecessors. During the ten months ended October 31, 1997 the Company drilled eight gas wells. Two development wells (2.0 net) and one exploratory well (0.2 net) were productive. One development well (0.7 net) and four exploratory wells (1.0 net) were non-productive. On October 31, 1997 the Company was drilling one development gas well (0.2 net) and two (0.6 net) exploratory gas wells. The Company owned working and royalty interests in approximately 894 gross (35.9 net) producing oil and 316 gross (21.2 net) producing gas wells as of December 31, 1996. A well is categorized as an oil 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 developed and undeveloped (gross and net) leasehold acreage of the Company as of December 31, 1996. LEASEHOLD ACREAGE ------------------------------------------ DEVELOPED UNDEVELOPED -------------------- -------------------- STATE GROSS NET GROSS NET - --------------------------------- --------- --------- --------- --------- Alabama.......................... 13,136 12,210 944 190 California....................... -- -- 480 480 Louisiana........................ 46,958 5,321 8,766 6,268 Michigan......................... 4,273 185 -- -- Mississippi...................... 3,323 1,433 564 564 Oklahoma......................... 8,987 973 -- -- Texas............................ 12,390 761 -- -- Utah............................. 2,560 295 -- -- Federal Waters................... 54,962 34,553 96,075 24,019 --------- --------- --------- --------- Total....................... 146,589 55,731 106,829 31,521 ========= ========= ========= ========= As of December 31, 1996, the Company owned various royalty and overriding royalty interests in 1,366 net developed acres and 6,953 undeveloped acres. In addition, the Company owned 5,464 developed and 134,536 undeveloped mineral acres. 33 MAJOR CUSTOMERS For the nine months ended September 30, 1997, Sonat Gas Marketing Co. L.P. ("Sonat Gas"), PG&E Energy Trading Corp. ("PG&E"), and Williams Energy Services, Inc. ("Williams Energy") purchased 20%, 30%, and 10%, respectively, of the Company's natural gas production. Williams Energy purchased natural gas from the North Dauphin Island Field, and Sonat Gas and PG&E purchased natural gas primarily from Callon-owned interests in federal OCS leases, Chandeleur Block 40, Main Pass 163, and Main Pass 164/165 fields. Because of the nature of the oil and gas operations and the marketing of production, the Company believes that the loss of these customers would not have a significant adverse impact on the Company's ability to sell its products. 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 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, which are owned or leased. EMPLOYEES The Company had 140 employees as of September 30, 1997, none of whom are currently represented by a union. The Company considers itself to have good relations with its employees. The Company employs ten 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. The Company's competitive position for acquiring 34 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 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 Company's sales of natural gas are affected by the availability, terms and cost of transportation. 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 increase competition within the gas industry by making 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 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 and 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. 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. 35 In subsequent orders, the FERC and the appellate court have substantially upheld the requirements imposed by Order No. 636, although numerous court appeals in which parties have sought review of separate FERC orders implementing Order No. 636 on individual pipeline systems are still pending. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The FERC has announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology to establish the rates interstate pipelines may charge for their services. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While the changes being considered would affect the Company only indirectly, they are intended to further enhance competition in natural gas markets. The Company cannot predict what further action the FERC will take on these matters; however, the Company does not believe that it will be affected by any action taken materially differently than other natural gas producers. The Outer Continental Shelf Lands Act ("OCSLA") requires that all pipelines operating on or across the OCS provide open and non-discriminatory access. The FERC has the authority to exercise jurisdiction under the OCSLA over gatherers, if necessary to permit open and non-discriminatory access. 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 indexing system for setting transportation rate ceilings. In certain circumstances, the new rules permit oil pipelines to establish rates using traditional cost of service and other methods of rate making. The effect that these new rules may have on the cost of moving the Company's products to market cannot yet be determined. 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, in the case of the Company's OCS leases in federal waters, Minerals Management Service ("MMS") or other appropriate federal or state agencies. The Company's OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions on various production-related activities, including restricting the flaring or venting of natural gas. In addition, the MMS has proposed to amend its regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. While the MMS recently withdrew proposed changes to the way it values natural gas for royalty payments, informal discussions of the issue are continuing among the MMS and industry officials. It is uncertain whether and what changes may be proposed in the future regarding natural gas royalty valuation. In addition, the MMS has recently announced its intention to issue a proposed rule that would require all but the smallest producers to be capable of reporting production information electronically by the end of 1998. The Company cannot predict what action the MMS will take on this matter, nor can it 36 predict at this stage of the proceeding how the Company might be affected by this proposed amendment to the MMS' royalty regulations. 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 owns certain natural gas pipeline facilities that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both state and federal levels in the post-Order No. 636 environment. 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. 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, are also subject to stringent environmental regulation by state and federal authorities including the U.S. Environmental Protection Agency ("EPA"). Risks are inherent in oil and gas exploration and production operations, and no assurance can be given that significant costs and liabilities will not be incurred in connection with environmental compliance issues; nevertheless, the Company believes 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 adverse effect upon the capital expenditures, earnings or the competitive position of the Company or its operations. The Company cannot predict what effect future 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. SOLID AND HAZARDOUS WASTE. The Company currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil 37 and gas. Although the Company believes it has utilized operating and waste 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 or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or 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 and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, it is possible that certain wastes generated by the Company's oil and gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes" under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and 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 disposal site where a release occurred and any company that disposed or arranged for the disposal of the hazardous substance released at the 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 its operations, the Company 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. 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 United States waters. A "responsible party" includes the owner or operator of an onshore facility, vessel or pipeline, 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 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 failure to comply with OPA requirements may subject a responsible party to civil or even criminal liability. 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. Certain legislative amendments to the OPA that were enacted in 1996 require owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10 million in specified state waters to $35 million in federal OCS waters, with higher amounts, up to $150 million in certain limited circumstances, where the MMS believes such a level is justified by the risks posed by the quantity or quality of oil that is handled by the facility. On March 25, 1997, the MMS promulgated a proposed rule implementing these OPA financial responsibility requirements. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether the financial responsibility requirements under the OPA amendments or the proposed rule will result in the imposition of substantial additional annual costs to the Company in the 38 future or otherwise materially adversely affect the Company. The impact of the financial responsibility requirements 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. PROHIBITION ON DISCHARGES OF PRODUCED WATER. In connection with its exploration and production operations offshore Louisiana, the Company is subject to a state-wide prohibition, effective July 1, 1997, against the discharge of produced water into state coastal waters. However, the Company has received an extension of time for complying with this prohibition until September 30, 1998 for its facilities at Chandeleur Block 25 and Main Pass Block 35, and until October 31, 1998 for its facilities at Black Bay Complex. The Company believes that it will be in compliance with the prohibition prior to expiration of the applicable deadlines. 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 may result in the payment of civil penalties and, in extreme cases, the shutdown of air emission sources. 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 the Company to organize and/or disclose information about hazardous materials used or produced in the Company's operations. The Company believes that it is in substantial compliance with these applicable requirements. 39 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 2000, 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........... 47 Director; President; Chief Executive Officer (Class III) John S. Callon........... 77 Director; Chairman of the Board (Class II) Dennis W. Christian...... 51 Director; Senior Vice President; Chief Operating Officer (Class III) Robert A. Stanger........ 57 Director (Class I) John C. Wallace.......... 59 Director (Class I) B.F. Weatherly........... 53 Director (Class II) Richard O. Wilson........ 67 Director (Class I) John S. Weatherly........ 45 Senior Vice President; Chief Financial Officer; Treasurer H. Michael Tatum......... 68 Vice President; Secretary Kathy G. Tilley.......... 52 Vice President James O. Bassi........... 43 Corporate Controller 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 Executive Officer of the Company and Callon Petroleum Operating. Prior to January 1997, he was President and Chief Operating Officer of the Company and had 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 of the Company and Callon Petroleum Operating. Effective January 2, 1997, John S. Callon retired from his position as Chief Executive Officer of the Company. 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 and Chief Operating Officer for the Company and Callon Petroleum Operating. Prior to January 1997, he was Senior Vice President of Operations and Acquisitions and had 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. 40 Robert A. Stanger has been the managing general partner since 1978 of Robert A. Stanger & Company, 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 and Electric Lightwaves, Inc., Seattle, Washington, a regional fiber optic telephone company. 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 and the New York Society of Security Analysts. John C. Wallace 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 Fred. Olsen Energy ASA, Oslo, a publicly held energy service company, Harland & Wolff PLC, Belfast, Ganger Rolf ASA and Bonheur ASA, Oslo, publicly-traded shipping companies. He is an executive officer of NOCO Management, Ltd., the general partner of NOCO and a director of 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 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. Richard O. Wilson for the past eleven 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 and recently acquired by Halliburton, Inc. After 13 years, Mr. Wilson has retired from the chairmanship 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 Rice University. Mr. Wilson is a Fellow in the American Society of Civil Engineers and a member of the Institute of Petroleum, London, England. 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 had 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. 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. 41 James O. Bassi is Corporate Controller of the Company and Callon Petroleum Operating. Prior to being appointed to that position in June, 1997, he was Manager of the Accounting Department for the Company and Callon Petroleum Operating. Mr. Bassi has been employed by the Company and its predecessors for a total of nine years. Prior to his employment by Callon Petroleum Operating, he was employed by Arthur Andersen LLP. He received his B.S. degree in accounting in 1976 from Mississippi State University. He is a member of the American Institute of Certified Public Accountants and the Mississippi Society of Certified Public Accountants. 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 a 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. 42 PRINCIPAL STOCKHOLDERS The following table sets forth, as of September 30, 1997, 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) all executive officers, 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 Commission 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 NATURE OF ADDRESS OF BENEFICIAL PERCENT BENEFICIAL PERCENT BENEFICIAL OWNER(S) OWNERSHIP OF CLASS OWNERSHIP OF CLASS - ---------------------------------------- ---------- -------- ---------- -------- DIRECTORS: John S. Callon..................... 317,040(2) 5.18% -- -- Fred L. Callon..................... 733,768(3) 11.98 -- -- Dennis W. Christian................ 129,000(4) 2.11 -- -- Robert A. Stanger.................. 20,856(5) * -- -- John C. Wallace.................... 2,007,883(6) 33.30 -- -- B.F. Weatherly..................... 165,739(7) 2.74 -- -- Richard O. Wilson.................. 169,145(8) 2.80 1,000 * EXECUTIVE OFFICERS: John S. Weatherly.................. 123,896(9) 2.01 -- -- H. Michael Tatum................... 43,000(10) * Kathy G. Tilley.................... 86,147(11) 1.41 -- -- James O. Bassi..................... 15,600(12) * DIRECTORS AND EXECUTIVE OFFICERS AS A GROUP (11 PERSONS).................... 3,521,330(13) 53.94 1,000 * CERTAIN BENEFICIAL OWNERS: Fred. Olsen Energy ASA............. 1,839,386(14) 30.51 -- -- Fred. Olsensgate 2 0152 Oslo, Norway Wellington Management Company...... 607,704(15) 9.22 247,690 18.83 75 State Street Boston, Massachusetts 02109
- ------------ * Less than 1% (1) Unless otherwise indicated, each of the above persons may be deemed to have sole voting and dispositive power with respect to such shares. (2) Of the 317,040 shares beneficially owned by John S. Callon, 97,040 are owned directly by him and he has sole voting and dispositive power over such shares, 105,000 shares are held in a family limited partnership, 90,000 shares are subject to options under the Company's 1994 Plan exercisable within 60 days and 25,000 shares are subject to a restricted stock agreement and vest 20% annually beginning January 2, 1998. Shares indicated as owned by John S. Callon do not include shares of Common Stock owned by NOCO and F.O. Energy 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 Stockholder's Agreement among the Callon Family and NOCO dated September 16, 1994, and subsequently amended to include F.O. Energy, John S. Callon and the other members of the Callon Family have the right of first refusal to acquire (FOOTNOTES CONTINUED ON FOLLOWING PAGE) 43 shares of Common Stock proposed to be sold by NOCO or F.O. Energy 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 or F.O. Energy shares. (3) Of the 733,768 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 shares are subject to options under the 1994 Plan exercisable within 60 days; 15,000 shares are subject to options under the 1996 Plan exercisable within 60 days; 60,000 shares represent performance shares issued under the 1996 Plan which do not vest until January 1, 2001; and 30,766 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 F.O. Energy 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 or F.O. Energy 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 these shares. (4) 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, and 55,000 shares represent performance shares awarded under the 1996 Plan which do not vest until January 1, 2001. (5) Includes 15,000 shares subject to options under the 1994 Plan and 5,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days. (6) Includes 3,125 shares owned directly by John C. Wallace, 15,000 shares subject to options under the 1994 Plan and 5,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days, and 145,372 shares owned by NOCO and 1,839,386 shares owned by F.O. Energy. See note (14) below. (7) Includes 367 shares owned directly by B.F. Weatherly, 15,000 shares subject to options under the 1994 Plan and 5,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days, and 145,372 shares owned by NOCO. See note (14) below. (8) Includes 1,500 shares owned directly by Richard O. Wilson, 15,000 shares subject to options under the 1994 Plan and 5,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days, 2,273 shares issuable upon conversion of 1,000 shares of Series A Preferred Stock and 145,372 shares owned by NOCO. See note (14) below. (9) Includes 217 shares which are held by Mr. Weatherly as custodian for his minor children, 60,000 shares subject to options under the 1994 Plan, 13,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days, and 50,000 shares represent a performance share award under the 1996 Plan which do not vest until January 1, 2001. (10) Includes 25,000 shares subject to options under the 1994 Plan, 3,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days, and 15,000 Shares represent a performance share award under the 1996 Plan which do not vest until January 1, 2001. (11) Includes 30,000 shares subject to options under the 1994 Plan, 11,000 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days and 45,000 shares represent a performance share award under the 1996 Plan which do not vest until January 1, 2001. (12) Includes 11,000 shares subject to options under the 1994 Plan and 4,600 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days. (13) Includes 416,000 shares subject to options under the 1994 Plan, 80,600 shares subject to options under the 1996 Plan, all of which are exercisable within 60 days, 225,000 shares represent performance share awards under the 1996 Plan which do not vest until January 1, 2001 and 25,000 shares subject to a restricted stock agreement. (14) As of August 11, 1997, NOCO Enterprises, L.P. distributed 1,839,386 shares of Common Stock to its sole limited partner, NOCO Holdings, L.P. ("NOCO Holdings") and NOCO Holdings distributed (FOOTNOTES CONTINUED ON FOLLOWING PAGE) 44 those shares to its general partner and to certain of its limited partners. The general partner of NOCO Holdings distributed the shares of Common Stock it received to Fred. Olsen Finance Limited, a limited partner of NOCO Holdings, and all of the limited partners of NOCO Holdings exchanged their shares of Common Stock for shares in F.O. Energy and Fred. Olsen Energy II AS. Subsequently, Fred. Olsen Energy II AS merged with F.O. Energy. As disclosed on a Schedule 13D dated August 20, 1997, F.O. Energy has the sole power to vote and the sole power to dispose of 1,839,386 shares of Common Stock of the Company. Ganger Rolf ASA, a public joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 100% of the outstanding capital stock of F.O. Energy ("Ganger Rolf") and Bonheur ASA, a public joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 49.0% of the outstanding capital stock of Ganger Rolf ("Bonheur"), each have the power to direct the vote and disposition of the shares of Common Stock of the Company owned by F.O. Energy. AIS Quatro, a joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 6.7% of the outstanding capital stock of Ganger Rolf and 23.0% of the outstanding capital stock of Bonheur ("Quatro") and AIS Cinco, a joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 6.9% of the outstanding capital stock of Ganger Rolf and 23.0% of the outstanding capital stock of Bonheur, each disclaims beneficial ownership of the shares of Common Stock of the Company owned by F.O. Energy. John C. Wallace, a director of the Company, is a director of F.O. Energy and a director of Ganger Rolf, Bonheur, Quatro and Cinco and as a result, may be deemed to share the power to vote and dispose of, and therefore be a beneficial owner of the shares of Common Stock owned by F.O. Energy. The principal business address and principal executive offices of Ganger Rolf, Bonheur, Quatro and Cinco are located at Fred. Olsensgate 2, 0152 Oslo, Norway and the address of John C. Wallace is 65 Vincent Square, London England SWIP 2RY. In connection with F.O. Energy's acquisition of the shares of Common Stock of the Company, F.O. Energy has become a party to the Stockholders' Agreement. See " -- Stockholders' Agreement". Because of the Stockholders' Agreement, NOCO and certain of its affiliates, F.O. Energy, Ganger Rolf, Bonheur, Quatro and Cinco and members of the Callon Family may be deemed to be a "group" for purposes of beneficial ownership under Commission regulations. If such a group were deemed to exist, it would beneficially own over 60% of the Common Stock. (15) Includes 563,000 shares issuable upon conversion of 247,690 shares of Series A Preferred Stock. STOCKHOLDERS' AGREEMENT Pursuant to the Stockholders' Agreement among the Callon Family, NOCO and F.O. Energy, the Callon Family, on the one hand, and NOCO and F.O. Energy, on the other, each elect two directors to the Company's Board of Directors. Specifically, the Stockholders' Agreement provides that the Callon Family, on the one hand, and NOCO and F.O. Energy, on the other, 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 and F.O. Energy. The Stockholders' Agreement also contains restrictions on transfer of shares of Common Stock owned by the Callon Family, NOCO and F.O. Energy and prohibits the Callon Family, NOCO and F.O. Energy from taking certain actions which would result in certain changes of control or fundamental changes, without the consent of the other party. As a result of the Stockholders' Agreement, the Callon Family, on the one hand, and the Callon Family, NOCO and F.O. Energy on the other, may be deemed to form a "group" for purposes of beneficial ownership under Commission regulations. The Callon Family disclaims beneficial ownership of the Common Stock owned by NOCO and F.O. Energy. 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, F.O. Energy and the Callon Family were deemed to be a group, it would beneficially own more than 60% of the outstanding Common Stock. 45 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 September 30, 1997, 6,028,994 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 Company's Form 10-K for fiscal year ended December 31, 1995. 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. 46 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. See "-- Convertible Debentures," below. 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 Company may, at its option, exchange its Convertible Debentures for its Series A Preferred Stock. If issued, 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 Company's Form 10-K for fiscal year 1996. 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. 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 47 (i) failure to pay principal or premium, if any, on any Convertible Debenture when due at maturity, upon 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 an initial Borrowing Base of $30 million which is adjusted periodically on the basis of a discounted present value attributable to the Company's proven producing oil and gas reserves. 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 September 30, 1997 was 8.50%. 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. 10% NOTES On November 27, 1996, the Company issued $24,150,000 aggregate principal amount of 10% Senior Subordinated Notes due December 15, 2001 (the "10% Notes"). The Company used the proceeds to reduce borrowings under the Credit Facility and for other corporate purposes. Interest is payable quarterly on March 15, June 15, September 15 and December 15 of each year. The 10% Notes are 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 10% Notes are general unsecured obligations of the Company, subordinated in right of payment to all existing and future indebtedness of the Company. See "Notes to Consolidated Financial Statements -- Note 5." 10.125% NOTES On July 31, 1997, the Company issued $36 million of its 10.125% Series A Senior Subordinated Notes due 2002 in a private placement for net proceeds of $34.8 million. The Company used $18.5 million of the net proceeds to repay borrowings under the Credit Facility and the remaining net proceeds have been allocated to the Company's capital expenditure budget. On September 10, 1997, pursuant to a Registration Agreement dated July 31, 1997, the Company commenced an offer to exchange the Series A Notes for a like principal amount of 10.125% Series B Senior Subordinated Notes due 2002 (the "Series B Notes" and, together with the Series A Notes, the "10.125% Notes"). The form and terms of the Series B Notes are 48 identical in all material respects to the terms of the Series A Notes, except for certain transfer restrictions and provisions relating to registration rights. The exchange offer was completed on November 10, 1997, and $36 million principal amount of Series A Notes were exchanged for $36 million principal amount of Series B Notes. Interest on the 10.125% Notes is payable quarterly, on March 15, June 15, September 15, and December 15 of each year. The 10.125% Notes are redeemable at the option of the Company in whole or in part, at any time on or after September 15, 2000. The 10.125% Notes are general unsecured obligations of the Company, subordinated in right of payment to all existing and future indebtedness of the Company and rank PARI PASSU with the 10% Notes. The Credit Facility and the indenture for the 10.125% Notes contain various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. 49 UNDERWRITING Subject to the terms and conditions of the Underwriting Agreement among the Company and the Underwriters named below (the "Underwriting Agreement"), the Company has agreed to sell to each of such Underwriters named below, and each of such Underwriters has severally agreed to purchase from the Company, the respective number of shares of Common Stock set forth opposite its name below. NUMBER OF UNDERWRITERS SHARES - ------------------------------------- --------- Morgan Keegan & Company, Inc......... 400,000 A.G. Edwards & Sons, Inc............. 400,000 Howard, Weil, Labouisse, Friedrichs Incorporated....................... 400,000 Jefferies & Company, Inc............. 400,000 --------- Total........................... 1,600,000 ========= Under the terms and conditions of the Underwriting Agreement, the underwriters are committed to take and pay for all of the shares of Common Stock offered hereby, if any are taken. The Underwriters propose to offer the shares of Common Stock in part 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 at such price less a concession of $0.48 per share. The Underwriters may allow, and such dealers may allow, a concession not in excess of $0.10 per share to certain brokers and dealers. After the shares of Common Stock are released for sale to the public, the offering price and other selling terms may from time to time be varied by the Underwriters. The Company has granted the Underwriters an option exercisable for 30 days after the date of this Prospectus to purchase up to an aggregate of 240,000 additional shares of Common Stock solely to cover over-allotments, if any. If the Underwriters exercise their over-allotment option, the Underwriters have severally agreed, subject to certain conditions, to purchase approximately the same percentage thereof that the number of shares of Common Stock to be purchased by each of them, as shown in the table above, bears to the 1,600,000 shares of Common Stock. The Company has agreed in the Underwriting Agreement not to offer, sell, contract to sell, grant any option to purchase or otherwise dispose of any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock, subject to certain limited exceptions, for a period of 90 days after the date of this Prospectus without the prior written consent of Morgan Keegan & Company, Inc. In addition, the Company's directors and executive officers, NOCO and F.O. Energy have agreed not to sell, contract to sell, grant any option to purchase or otherwise dispose of any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock, other than as gifts, pledges and certain other transfers to persons who agree to the same restrictions for a period of 90 days after the date of this Prospectus without the prior written consent of Morgan Keegan & Company, Inc. In connection with this Offering, the Underwriters may engage in transactions that stabilize, maintain or otherwise affect the market price of the Common Stock. Such transactions may include stabilization transactions pursuant to which the Underwriters may bid for or purchase Common Stock for the purpose of stabilizing its market price. The Underwriters also may create a short position for the account of the Underwriters by selling more Common Stock in connection with the Offering than they are committed to purchase from the Company, and in such case the Underwriters may purchase Common Stock in the open market following completion of the Offering to cover all or a portion of such short position. The Underwriters may also cover all or a portion of such short position by exercising the Underwriters' over-allotment option referred to above. In addition, the Underwriters may impose "penalty bids"whereby selling concessions allowed to syndicate members or other broker-dealers for the Shares sold in the Offering for their account may be reclaimed by the syndicate if such Shares are repurchased by the syndicate in stabilizing or covering transactions. Any of the transactions described in this paragraph may result in the maintenance of the price of the Common Stock at a level above that which might otherwise prevail in the 50 open market. The imposition of a penalty bid might also affect the price of the Common Stock to the extent that it could discourage resales of the security. Neither the Company nor any of the Underwriters makes any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the Common Stock. In addition, neither the Company nor any of the Underwriters make any representation that the Underwriters will engage in such transactions or that such transactions, once commenced, will not be discontinued without notice. In connection with this Offering, the Underwriters or their respective affiliates and selling group members (if any) who are qualified market makers on Nasdaq may engage in "passive market making" in the Common Stock on Nasdaq in accordance with Rule 103 of Regulation M under the Exchange Act. Rule 103 permits, upon the satisfaction of certain conditions, underwriters and selling group members participating in a distribution that are also Nasdaq market makers in the security being distributed (or a related security) to engage in limited market making transactions during the period when Regulation M under the Exchange Act would otherwise prohibit such activity. Rule 103 prohibits underwriters and selling group members engaged in passive market making generally from entering a bid or effecting a purchase at a price that exceeds the highest bid for those securities displayed on Nasdaq by a market maker that is not participating in the distribution. Under Rule 103, each underwriter or selling group member engaged in passive market making is subject to a daily net purchase limitation equal to 30% of such entity's average daily trading volume during the two full consecutive calendar months immediately preceding the date of the filing of the registration statement under the Securities Act pertaining to the security to be distributed (or such related security). The Company has agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act or to contribute to payments the Underwriters may be required to make in respect of such liabilities. LEGAL MATTERS Certain legal matters with respect to the Common Stock offered hereby have been passed upon for the Company by Butler & Binion, L.L.P., Houston, Texas. Certain legal matters will be passed upon for the Underwriters by Vinson & Elkins L.L.P., Houston, Texas. EXPERTS The historical financial statements of the Company as of December 31, 1995 and 1996, and for each of the three years in the period ended December 31, 1996, included in this Prospectus have been audited by Arthur Andersen LLP, independent public accountants, as stated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. The statement of revenues and direct operating expenses of the working interest in Mobile Block 864 Area acquired by Callon Petroleum Operating for the year ended December 31, 1996 included in this Prospectus has been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given upon the authority of said firm as experts in accounting and auditing. The statement of revenues and direct operating expenses of 61% of Chevron U.S.A. Inc.'s working interest in Mobile 864 Unit Outer Continental Shelf acquired by Callon Petroleum Operating Company for each of the three years in the period ended December 31, 1996 included in this Prospectus has been so included in reliance on the report of Price Waterhouse LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting. The information appearing in this Prospectus regarding quantities of reserves of oil and gas and 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. 51 AVAILABLE INFORMATION The Company is subject to the informational requirements of the Exchange Act, and in accordance therewith files reports, proxy statements and other information with the Commission. Such reports and other information may be inspected and copied at the public reference facilities of the Commission, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, as well as at the following Regional Offices: 7 World Trade Center, Suite 1300, New York, New York 10048, and Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such materials can be obtained from the Commission by mail at prescribed rates. Requests should be directed to the Commission's Public Reference Section, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. The Commission also maintains a website at http://www.sec.gov that contains reports, proxy statements, and other information. Callon's Common Stock is listed on the Nasdaq Stock Market. Reports, proxy and information statements and other information relating to Callon can be inspected at the offices of 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-2 (the "Registration Statement") filed by the Company with the Commission under the Securities Act. This Prospectus does not contain all the information set forth in the Registration Statement, certain parts of which are omitted in accordance with the rules and regulations of the Commission, and reference is hereby made to the Registration Statement and to the exhibits relating thereto for further information with respect to the Company and the Notes. Any statements contained herein concerning the provisions of any document are not necessarily complete, and, in each instance, reference is made to a copy of such document filed as an exhibit to the Registration Statement or otherwise filed with the Commission. Each such statement is qualified in its entirety by such reference. INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The following documents filed by the Company with the Commission pursuant to the Exchange Act (file number 0-25192) are incorporated herein by reference, except as superseded or modified herein: (i) The Company's Annual Report on Form 10-K for the year ended December 31, 1996; (ii) The Company's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 1997, June 30, 1997 and September 30, 1997; (iii) The Company's Current Report on Form 8-K filed January 15, 1997; the Company's Current Report on Form 8-K filed July 11, 1997 as amended by the Company's Current Report on Form 8-K/A filed August 8, 1997; and the Company's Current Report on Form 8-K filed August 8, 1997; and the Company's Current Report on Form 8-K filed November 4, 1997 as amended by the Company's Current Report on Form 8-K/A filed November 21, 1997; and (iv) The Company's Registration Statement on Form 8-B filed October 3, 1994. All reports and other documents subsequently filed by the Company pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this Prospectus and prior to the termination of this Offering shall be deemed to be incorporated by reference herein and to be a part hereof from the date of filing of such reports and documents. Any statement contained herein or in a document incorporated or deemed to be incorporated herein by reference shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained in this Prospectus or in any subsequently filed document (which is deemed to be incorporated by reference herein) modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. To the extent the information relating to the Company contained in this Prospectus summarizes, is based upon or refers to, information and financial statements contained in one or more of the documents incorporated by reference herein, the information contained herein is qualified in its entirety by reference to such document, and it should be read in conjunction therewith. 52 The Company will provide, without charge, to each person to whom a copy of this Prospectus is delivered, on the written or oral request of such person, a copy of any or all of the documents incorporated herein by reference (other than exhibits thereto, unless such exhibits are specifically incorporated by reference into the information that this Prospectus incorporates). Written or telephone requests for such copies should be directed to the Company's principal office: Callon Petroleum Company, 200 North Canal Street, Natchez, Mississippi 39120, (601) 442-1601. 53 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 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. "MMCF/D" means millions of cubic feet per day. "MMCFE" means million cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids. "MMCFE/D" means million cubic feet equivalent per day. "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 pre-tax, 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). 54 INDEX TO FINANCIAL STATEMENTS PAGE ---- Callon Petroleum Company (historical): Report of Independent Public Accountants.................... F-2 Consolidated Balance Sheets as of September 30, 1997 and December 31, 1996 and 1995..... F-3 Consolidated Statements of Operations for the Nine Months Ended September 30, 1997 and 1996 and for the Years Ended December 31, 1996, 1995 and 1994........................... F-4 Consolidated Statements of Stockholders' Equity for the Nine Months Ended September 30, 1997 and for the Years Ended December 31, 1996, 1995 and 1994........................... F-5 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 1997 and 1996 and for the Years Ended December 31, 1996, 1995 and 1994........ F-6 Notes to Consolidated Financial Statements..................... F-7 Callon Petroleum Company (pro forma): Introduction.................... F-21 Unaudited Pro Forma Condensed Consolidated Balance Sheet as of September 30, 1997.......... F-22 Unaudited Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 1996............. F-23 Unaudited Pro Forma Consolidated Statement of Operations for the Nine Months Ended September 30, 1997........................... F-24 Notes to Unaudited Pro Forma Consolidated Financial Statements..................... F-25 Elf Acquisition Report of Independent Auditors....................... F-26 Statement of Revenues and Direct Operating Expenses for the Year Ended December 31, 1996........ F-27 Notes to Statement of Revenues and Direct Operating Expenses....................... F-28 Chevron Acquisition Report of Independent Accountants.................... F-30 Statement of Revenues and Direct Operating Expenses for the Years Ended December 31, 1996, 1995 and 1994........................... F-31 Notes to Statement of Revenues and Direct Operating Expenses....................... F-32 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, 1996 and 1995, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP New Orleans, Louisiana February 19, 1997 F-2 CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31, SEPTEMBER 30, -------------------------- 1997 1996 1995 ------------- ------------ ------------ (UNAUDITED) ASSETS Current assets: Cash and cash equivalents....... $ 5,939 $ 7,669 $ 4,265 Accounts receivable............. 9,621 12,661 8,329 Other current assets............ 738 516 238 ------------- ------------ ------------ Total current assets....... 16,298 20,846 12,832 ------------- ------------ ------------ Oil and gas properties, full cost accounting method: Evaluated properties............ 374,113 322,970 304,737 Less accumulated depreciation, depletion and amortization.... (277,771) (266,716) (257,143) ------------- ------------ ------------ 96,342 56,254 47,594 Unevaluated properties excluded from amortization............. 30,954 26,235 10,171 ------------- ------------ ------------ Total oil and gas properties................. 127,296 82,489 57,765 ------------- ------------ ------------ Pipeline and other facilities, net... 6,585 6,618 5,371 Other property and equipment, net.... 1,841 1,594 1,633 Deferred tax asset................... 2,486 5,412 5,462 Long-term gas balancing receivable... 246 660 619 Other assets, net.................... 1,598 901 185 ------------- ------------ ------------ Total assets............... $ 156,350 $ 118,520 $ 83,867 ============= ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities..................... $ 8,203 $ 8,273 $ 3,131 Undistributed oil and gas revenues........................ 2,434 2,260 2,153 Accrued net profits interest payable (Note 9)................ 2,035 5,435 2,836 ------------- ------------ ------------ Total current liabilities................ 12,672 15,968 8,120 ------------- ------------ ------------ Long-term debt....................... 60,250 24,250 100 Deferred income...................... 233 48 86 Long-term gas balancing payable...... 313 390 432 ------------- ------------ ------------ Total liabilities.......... 73,468 40,656 8,738 ------------- ------------ ------------ 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 13 Common Stock, $0.01 par value; 20,000,000 shares authorized; 6,028,994 at September 30, 1997 and 5,758,667 and 5,754,529 shares outstanding at December 31, 1996 and 1995, respectively.................. 60 58 58 Unearned compensation -- restricted stock.............. (2,410) -- -- Capital in excess of par value......................... 77,467 74,027 73,955 Retained earnings............... 7,752 3,766 1,103 ------------- ------------ ------------ Total stockholders' equity..................... 82,882 77,864 75,129 ------------- ------------ ------------ Total liabilities and stockholders' equity.... $ 156,350 $ 118,520 $ 83,867 ============= ============ ============
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, -------------------- ------------------------------- 1997 1996 1996 1995 1994 --------- --------- --------- --------- --------- (UNAUDITED) Revenues: Oil and gas sales............... $ 29,578 $ 18,578 $ 25,764 $ 23,210 $ 13,948 Interest and other.............. 1,162 537 946 627 171 --------- --------- --------- --------- --------- Total revenues............. 30,740 19,115 26,710 23,837 14,119 --------- --------- --------- --------- --------- Costs and expenses: Lease operating expenses........ 6,235 5,646 7,562 6,732 4,042 Depreciation, depletion and amortization.................. 11,288 7,697 9,832 10,376 6,049 General and administrative...... 3,263 2,352 3,495 3,880 3,717 Interest........................ 945 184 313 1,794 624 --------- --------- --------- --------- --------- Total costs and expenses... 21,731 15,879 21,202 22,782 14,432 --------- --------- --------- --------- --------- Income (loss) from operations........ 9,009 3,236 5,508 1,055 (313) Income tax expense (benefit).... 2,926 -- 50 -- (200) --------- --------- --------- --------- --------- Net income (loss).................... 6,083 3,236 5,458 1,055 (113) Preferred stock dividends............ 2,097 2,097 2,795 256 -- --------- --------- --------- --------- --------- Net income (loss) available to common shares............................. $ 3,986 $ 1,139 $ 2,663 $ 799 $ (113) ========= ========= ========= ========= ========= Net income (loss) per common share: Primary......................... $ 0.63 $ 0.20 $ 0.45 $ 0.14 $ (0.03) ========= ========= ========= ========= ========= Assuming full dilution.......... $ 0.62 $ 0.20 $ 0.43 $ 0.14 $ (0.03) ========= ========= ========= ========= ========= Shares used in computing net income (loss) per common share: Primary......................... 6,332 5,755 5,952 5,755 4,346 ========= ========= ========= ========= ========= Assuming full dilution.......... 6,440 5,755 6,135 5,755 4,346 ========= ========= ========= ========= =========
The accompanying notes are an integral part of these financial statements. F-4 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
UNEARNED COMPENSATION CAPITAL IN CAPITAL PREFERRED COMMON RESTRICTED EXCESS OF RETAINED ACCOUNTS STOCK STOCK STOCK PAR VALUES EARNINGS --------- ---------- ------- ------------- ---------- --------- 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........................... -- -- -- -- -- 5,458 Preferred stock dividends............ -- -- -- -- -- (2,795) Shares issued pursuant to employee benefit plan....................... -- -- -- -- 72 -- --------- ---------- ------- ------------- ---------- --------- Balances, December 31, 1996.......... -- 13 58 -- 74,027 3,766 Net income (Unaudited)............... -- -- -- -- -- 6,083 Preferred stock dividends (Unaudited)........................ -- -- -- -- -- (2,097) Shares issued pursuant to employee benefit plan (Unaudited)........... -- -- -- -- 289 -- Restricted stock issued to officers (Unaudited)........................ -- -- 2 (3,153) 3,151 -- Unearned compensation -- restricted stock -- (Unaudited)............... -- -- -- 743 -- -- --------- ---------- ------- ------------- ---------- --------- Balances, September 30, 1997 (Unaudited)........................ $ -- $ 13 $ 60 $ (2,410) $ 77,467 $ 7,752 ========= ========== ======= ============= ========== =========
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, ---------------------- ---------------------------------- 1997 1996 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- (UNAUDITED) Cash flows from operating activities: Net income (loss).................. $ 6,083 $ 3,236 $ 5,458 $ 1,055 $ (113) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization............... 11,607 7,913 10,131 10,600 6,328 Amortization of deferred costs...................... 321 201 114 133 88 Deferred income tax expense (benefit).................. 2,926 -- 50 -- (200) Noncash compensation related to stock plans............. 973 -- 72 -- -- Changes in current assets and liabilities: Accounts receivable...... 3,040 (72) (4,332) 566 565 Other current assets..... (222) 89 (278) (217) (8) Current liabilities...... (3,924) 5,728 4,049 (2,570) (1,242) Change in gas balancing receivable................. 414 184 (41) 115 (148) Change in gas balancing payable.................... (77) (79) (42) (127) 210 Change in other long-term liabilities................ 185 (25) (28) (42) (43) Change in other assets, net... (1,018) (53) (830) (61) (90) ---------- ---------- ---------- ---------- ---------- Cash provided by operating activities................. 20,308 17,122 14,323 9,452 5,347 ---------- ---------- ---------- ---------- ---------- Cash flows from investing activities: Capital expenditures............... (61,034) (20,402) (37,637) (24,323) (10,420) Equity issued to purchase CN cash (Note 4)......................... -- -- -- -- 3,989 Cash proceeds from sale of mineral interests........................ 4,405 528 1,574 86 8 ---------- ---------- ---------- ---------- ---------- Cash used in investing activities....................... (56,629) (19,874) (36,063) (24,237) (6,423) ---------- ---------- ---------- ---------- ---------- Cash flows from financing activities: Equity issued by conversion of stock options.................... 60 -- -- -- -- Payments on debt................... (18,500) -- (25,850) (25,134) (20,627) Proceeds from debt issuance........ 54,500 8,850 50,000 6,000 25,734 Dividends/distributions paid....... -- -- -- -- (1,191) Sale of preferred stock............ -- -- -- 30,899 -- Increase in accrued preferred stock dividends payable................ -- 443 443 256 -- Dividends on preferred stock....... (2,097) (2,097) (2,795) (256) -- Change in accrued liabilities for capital expenditures............. 628 -- 3,346 -- -- ---------- ---------- ---------- ---------- ---------- Cash provided by financing activities....................... 34,591 7,196 25,144 11,765 3,916 ---------- ---------- ---------- ---------- ---------- Net increase (decrease) in cash and cash equivalents........................... (1,730) 4,444 3,404 (3,020) 2,840 Cash and cash equivalents: Balance, beginning of period....... 7,669 4,265 4,265 7,285 4,445 ---------- ---------- ---------- ---------- ---------- Balance, end of period............. $ 5,939 $ 8,709 $ 7,669 $ 4,265 $ 7,285 ========== ========== ========== ========== ==========
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, 1997 AND 1996 IS UNAUDITED) 1. ORGANIZATION AND BASIS OF PRESENTATION ORGANIZATION 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 partner 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 PRESENTATION 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. F-7 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. and Callon Exploration Company. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to presentation in the current year. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting 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". FAS 121 was adopted by the Company on January 1, 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 will continue to account for its stock-based compensation plans under APB Opinion No. 25. See Note 10. In June 1997, the Financial Accounting Standards Board issued Statement No. 130 ("FAS 130"), Reporting Comprehensive Income. FAS 130 establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. FAS 130 is effective for fiscal years beginning after December 15, 1997. The Company intends to comply with the provisions of FAS 130. 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, interest capitalized on unevaluated leases 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 F-8 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 or discovery. Such costs are capitalized as oil and gas properties as the actual restoration, dismantlement and abandonment activities take place. As of September 30, 1997, December 31, 1996 and 1995, 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 twenty years. Depreciation of the pipeline facilities is provided using the straight-line method over a 27 year estimated life. NATURAL GAS IMBALANCES 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 $302,000, $393,000 and $481,000 at September 30, 1997, December 31, 1996 and 1995 respectively. Net charge offs were $88,000 and $181,000 in 1996 and 1994 and net recoveries were $2,000 in 1995. There were no provisions to expense in the three year period ended December 31, 1996 or the nine months ended September 30, 1997. Net charge offs were $91,000 and $88,000 for the nine months ended September 30, 1997 and 1996, respectively. 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, 1996. During the years ended December 31, 1996, 1995 and 1994, the Company made cash payments of $250,807, $1,910,000 and $377,000, respectively, for interest charged on its indebtedness, and $2,538,000 for the nine months ended September 30, 1997. PER SHARE AMOUNTS Per share amounts are calculated on a weighted average basis using common shares issued and outstanding, adjusted for the effect of stock options considered common stock equivalents computed using the treasury stock method. The conversion of preferred stock was not included in any current year or prior calculations due to their antidilutive effect on fully diluted earnings per share. F-9 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In February 1997, the Financial Accounting Standards Board issued Statement No. 128 ("FAS 128"), "Earnings Per Share", which simplifies the computation of earnings per share. FAS 128 is effective for financial statements issued for periods ending after December 15, 1997 and requires restatement for all prior period earnings per share data presented. Accordingly, basic earnings per share and diluted earnings per share calculated in accordance with FAS 128 were $0.63 and $0.62 per share, respectively, for the first nine months of 1997 and $0.20 and $0.20 per share, respectively, for the first nine months of 1996. Also in early 1997, the Financial Accounting Standards Board issued Statement No. 129 ("FAS 129"). "Disclosure of Information about Capital Structure" effective for financial statements issued for periods ending after December 15, 1997. The Company believes it is in compliance with the provisions of this statement. FAIR VALUE OF FINANCIAL INSTRUMENTS Fair value of cash, cash equivalents, accounts receivable, accounts payable and long-term debt approximate book value at September 30, 1997 and December 31, 1996. Fair value of long-term debt (specifically the senior subordinated notes) is based on quoted market value. 3. INCOME TAXES The Company follows the asset and liability method of accounting for deferred income taxes prescribed by 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. Accordingly, the Company has recorded a deferred tax asset at December 31, 1996, 1995 and 1994 as follows: DECEMBER 31, ------------------------------- 1996 1995 1994 --------- --------- --------- (IN THOUSANDS) Federal net operating loss carryforward.......................... $ 3,441 $ 3,563 $ 2,072 Statutory depletion carryforward........ 4,089 3,987 4,085 Temporary differences: Oil and gas properties............. (680) 874 2,817 Pipeline and other facilities...... (2,316) (1,880) (1,953) Non-oil and gas property........... (20) 23 28 Other.............................. 898 655 724 --------- --------- --------- Total tax asset......................... 5,412 7,222 7,773 Valuation allowance..................... -- (1,760) (2,311) --------- --------- --------- Net tax asset........................... $ 5,412 $ 5,462 $ 5,462 ========= ========= ========= At December 31, 1996, the Company had, for tax reporting purposes, operating loss carryforwards ("NOL") of $9.8 million which expire in 2000 through 2011. Approximately $4.7 million of 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 $11.7 million in statutory depletion deductions which can be carried forward for an indefinite period. F-10 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The provision for income taxes at the Company's effective tax rate differed from the provision for income taxes at the statutory rate as follows: DECEMBER 31, ------------------------------- 1996 1995 1994 --------- --------- --------- (IN THOUSANDS) Computed expense (benefit) at the expected statutory rate............ $ 1,910 $ 369 $ (110) Change in valuation allowance........ (1,760) (551) (94) Other................................ (100) 182 4 --------- --------- --------- Income tax expense (benefit)......... $ 50 $ -- $ (200) ========= ========= ========= 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 and 1994 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 the CB 40 Acquisition presented as if it had occurred at the beginning of 1995 and 1994. PRO FORMA (UNAUDITED) -------------------- 1995 1994 --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Total revenues....................... $ 25,207 $ 29,132 Net income before cumulative effect of change in accounting principle.......................... $ 804 $ 3,703 Net income per common share.......... $ 0.14 $ 0.64 Weighted average shares outstanding........................ 5,755 5,755 Pro forma 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 an industry partner, 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 the same industry partner submitted bids and were awarded six additional offshore leases at the OCS Lease Sale #161, held in New Orleans, Louisiana by the MMS. The Company's share of the costs was $3.8 million. The Company owns a 25% working interest in the leases. F-11 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) On June 26, 1997 the Company purchased an 18.8% working interest in Mobile Area Blocks 863 and 907 and a 35% working interest in Mobile Area Block 908 from Elf Exploration, Inc. The Company's net purchase price of approximately $11.8 million was funded from the Company's credit facility. In October 1997, the Company agreed to purchase 61% of Chevron U.S.A. Inc.'s interest in the Mobile Block 864 Area for $21 million, effective July 1, 1997. The acquisition closed November 7, 1997 for a net acquisition cost of $18.8 million and was funded from the Company's Credit Facility. 5. LONG-TERM DEBT Long-term Debt consisted of the following at: DECEMBER 31, SEPTEMBER 30, -------------------- 1997 1996 1995 ------------- --------- --------- (UNAUDITED) (IN THOUSANDS) Credit Facility...................... $ 100 $ 100 $ 100 10% Senior Subordinated Notes........ 24,150 24,150 -- 10.125% Senior Subordinated Notes.... 36,000 -- -- Less current portion............ -- -- -- ------------- --------- --------- $60,250 $ 24,250 $ 100 ============= ========= ========= Effective October 31, 1996, the Company entered into a new Credit Facility with Chase Manhattan Bank. 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 or a $30 million borrowing base ("Borrowing Base") which is adjusted periodically on the basis of a discounted present value of future net cash flows attributable to the Company's proved producing oil and gas reserves. 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 September 30, 1997 and December 31, 1996 was 8.50% and 8.25%, respectively. 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. On November 27, 1996, the Company issued $24,150,000 of 10% Senior Subordinated Notes that will mature December 15, 2001. The Company used the proceeds to reduce borrowings under the Credit Facility and for other corporate purposes. Interest is payable quarterly beginning March 15, 1997. The notes are 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 are general unsecured obligations of the Company, subordinated in right of payment to all existing and future indebtedness of the Company. On July 31, 1997 the Company issued $36,000,000 of 10.125% Series A Senior Subordinated Notes due 2002. Interest is payable quarterly beginning September 15, 1997. The Senior Subordinated Notes were offered through a private placement transaction. The net proceeds to the Company, after costs of the transaction, were used to repay the outstanding balance on Callon's Credit Facility and will fund a portion of the remaining capital expenditure budget. Pursuant to a Registration Agreement, on November 10, 1997, F-12 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) these Series A 10.125% Notes were exchanged for $36 million aggregate principal amount of the Company's 10.125% Series B Senior Subordinated Notes due 2002 that have been registered under the Securities Act. The Credit Facility and the subordinated debt contain various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. This Company is in compliance with these covenants at September 30, 1997. 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. The Company had no open forward sales position related to this type of contract as of December 31, 1996 and September 30, 1997. At September 30, 1997 the Company had outstanding a call option for 250,000 Mcf per month from December 1997 through February 1998 at $3.00 per Mcf. As of December 31, 1996, the Company has open collar contracts with third parties whereby minimum floor prices and maximum ceiling prices are contracted and applied to related contract volumes. These agreements in effect for 1997 are for average oil volumes of 15,000 barrels per month at (on average) a ceiling price of $23.33 and floor of $18.00 and for average gas volumes of 583,000 Mcf per month in the first quarter of 1997 at (on average) a ceiling price of $3.36 and floor of $2.88. As of September 30, 1997, oil contracts averaged volumes of 10,000 barrels per month at (on average) a ceiling of $24.00 and a floor of $18.00 through 1997. Gas contracts included gas volumes of 700,000 Mcf per month at (on average) a ceiling price of $3.03 and a floor of $2.31 through March 1998. During 1994, the Company recognized revenue under swap agreements of $1,227,000 and $1,724,000 on Historical and Pro forma basis respectively, and $2,466,000 for the twelve months ended December 31, 1995. The Company recognized a reduction in revenue of $2,757,195 for the year ended December 31, 1996 under all contracts. During the first nine months of 1997, the Company recognized an increase in revenues of $328,975 for all contracts. The calculation of the fair market value of the outstanding contracts as of December 31, 1996 indicates a $308,400 market value benefit to the Company based on market prices at that date. As of September 30, 1997 the calculation of the fair market value of the outstanding contracts indicates a $646,008 market value liability to the Company based on market prices at that date. 7. COMMITMENTS AND CONTINGENCIES 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, 1996, total estimated site restoration, dismantlement and abandonment costs were approximately $23,000,000, 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. 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 F-13 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 8. OIL AND GAS PROPERTIES The following table discloses certain financial data relating to the Company's oil and gas activities, all of which are located in the United States.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ---------------------------------- 1997 1996 1995 1994 ------------- ---------- ---------- ---------- (UNAUDITED) (IN THOUSANDS) Capitalized costs incurred: Evaluated Properties -- Beginning of period balance..... $ 322,970 $ 304,737 $ 285,976 $ 260,971 Property acquisition costs...... 32,341 2,999 14,017 23,037 Exploration costs............... 11,831 8,732 785 798 Development costs............... 11,376 8,076 4,045 1,178 Sale of mineral interest........ (4,405) (1,574) (86) (8) ------------- ---------- ---------- ---------- End of period balance........... $ 374,113 $ 322,970 $ 304,737 $ 285,976 ============= ========== ========== ========== Unevaluated Properties -- Beginning of period balance..... $ 26,235 $ 10,171 $ 4,919 $ 955 Additions, net of transfers to evaluated... 3,169 15,714 5,252 3,964 Capitalized interest............ 1,550 350 -- -- ------------- ---------- ---------- ---------- End of period balance........... $ 30,954 $ 26,235 $ 10,171 $ 4,919 ============= ========== ========== ========== Accumulated depreciation, depletion and amortization -- Beginning of period balance..... $ 266,716 $ 257,143 $ 246,975 $ 240,926 Provision charged to expense.... 11,055 9,573 10,168 6,049 ------------- ---------- ---------- ---------- End of period balance........... $ 277,771 $ 266,716 $ 257,143 $ 246,975 ============= ========== ========== ==========
Depreciation, depletion and amortization per unit-of-production (equivalent barrel of oil) amounted to $5.87, $5.95, and $5.80 for the years ended December 31, 1996, 1995 and 1994, respectively, and $5.77 and $6.02 for the nine months ended September 30, 1997 and 1996, 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 F-14 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 September 30, 1997, December 31, 1996 and 1995 the Trusts' assets (all cash and investments) totaled $18,800,000, $18,200,000 and $16,100,000, 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. 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 were 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 owners' 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. 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 with cash and Company Common Stock. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company Common Stock 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, including the value of the common stock contributed, were $241,000, $176,000 and $154,000 in the years 1996, 1995 and 1994, respectively. o The 1994 Stock Incentive Plan (the "1994 Plan") provides for 600,000 shares of Common Stock to be reserved for issuance pursuant to such plan. Under the 1994 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. A total of 500,000 options are outstanding and all such options could be exercised as of December 31, 1996. These options have an expiration date 10 years from date of grant. o On August 23, 1996, the Board of Directors of the Company approved and adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996 Plan"). The 1996 Plan provides for the F-15 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) same types of awards as the 1994 Plan and is limited to a maximum of 900,000 shares of common stock that may be subject to outstanding awards. The Company granted stock options to purchase an aggregate 530,000 shares of Common Stock under the 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. Terms of the plan for 450,000 options provide that 20% of the options become exercisable on January 1 of each succeeding year, beginning January 1, 1997. Non-employee director options aggregating 80,000 shares vest 25% at each succeeding annual meeting of directors following each annual stockholders' meeting, beginning in 1997. Unvested options are subject to forfeiture upon certain termination of employment events and expire 10 years from date of grant. The Company accounts for the options issued pursuant to the stock incentive plans under APB Opinion No. 25, under which no compensation cost has been recognized (see Note 2). Had compensation cost for these plans been determined consistent with FAS 123, the Company's net income and earnings per common share would have been reduced to the following pro forma amounts: YEAR ENDED DECEMBER 31, ------------------------------- 1996 1995 1994 --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net income (loss): As Reported........................ $ 2,663 $ 799 $ (113) Pro Forma.......................... 2,411 677 (113) Primary per share: As Reported........................ 0.45 0.14 (0.03) Pro Forma.......................... 0.41 0.12 (0.03) Fully diluted per share: As Reported........................ 0.43 0.14 (0.03) Pro Forma.......................... 0.39 0.12 (0.03) Because the Statement 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. A summary of the status of the Company's two stock option plans at December 31, 1996, 1995 and 1994 and changes during the years then ended is presented in the table and narrative below:
1996 1995 1994 -------------------- ------------------- ------------------- WTD AVG WTD AVG WTD AVG EX EX EX SHARES PRICE SHARES PRICE SHARES PRICE --------- ------- -------- ------- -------- ------- Outstanding, beginning of year.......... 490,000 $10.01 460,000 $10.00 -- $ -- Granted............................ 550,000 12.06 30,000 10.08 460,000 10.00 Exercised.......................... -- -- -- -- -- -- Forfeited.......................... (10,000) 10.00 -- -- -- -- Expired............................ -- -- -- -- -- -- --------- ------- -------- ------- -------- ------- Outstanding, end of year................ 1,030,000 $11.10 490,000 $10.01 460,000 $10.00 ========= ======= ======== ======= ======== ======= Exercisable, end of year................ 500,000 $10.16 490,000 $10.01 -- $ -- ========= ======= ======== ======= ======== ======= Weighted average fair value of options granted............................... $ 4.96 $ 4.05 $ 4.53 ========= ======== ========
F-16 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The options outstanding at December 31, 1996 have exercise prices ranging from $9.75 to $13.75 with a remaining weighted average contractual life of 5.98 years. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for options granted during 1996, 1995 and 1994. WEIGHTED AVERAGE ASSUMPTIONS DECEMBER 31, ------------------------------- 1996 1995 1994 --------- --------- --------- Risk-free interest rate................. 6.5% 6.6% 6.0% Expected life (years)................... 4.9 5.0 5.0 Expected volatility..................... 34.7% 32.0% 41.3% Expected dividends...................... -- -- -- The Company also awarded 225,000 performance shares under the 1996 Plan to the Company's executive officers on August 23, 1996. During June 1997, the Company's stockholders approved the performance share awards and the related common stock was issued. The issuance was recorded at the fair market value of the shares on their date of grant, with a corresponding charge to stockholders' equity representing the unearned portion of the award. 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. The unearned portion is being amortized as compensation expense on a straight-line basis over the vesting period. Approximately $208,000 of compensation cost was charged to expense in 1996 related to the restricted shares granted. An additional 25,000 shares was issued under the 1994 Plan in 1997. The Company has no other formal benefit plans. F-17 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) The Company's proved oil and gas reserves at December 31, 1996, 1995 and 1994 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-18 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ESTIMATED RESERVES Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are located onshore and offshore in the continental United States, are as follows: RESERVE QUANTITIES YEAR ENDED DECEMBER 31, ------------------------------- 1996 1995 1994 --------- --------- --------- Proved developed and undeveloped reserves: Crude Oil (MBbls): Beginning of period............. 4,766 4,424 2,842 Revisions to previous estimates..................... (50) (441) (303) Purchase of reserves in place... -- 1,363 2,245 Sales of reserves in place...... (312) (2) (3) Extensions and discoveries...... -- 16 7 Production...................... (585) (594) (364) --------- --------- --------- End of period................... 3,819 4,766 4,424 ========= ========= ========= Natural Gas (MMcf): Beginning of period............. 29,667 24,102 14,167 Revisions to previous estimates..................... (1,688) (976) (2,793) Purchase of reserves in place... 7,391 12,985 16,757 Sales of reserves in place...... (228) (22) (39) Extensions and discoveries...... 21,551 271 85 Production...................... (6,269) (6,693) (4,075) --------- --------- --------- End of period................... 50,424 29,667 24,102 ========= ========= ========= Proved developed reserves: Crude Oil (MBbls): Beginning of period............. 3,890 3,309 2,084 ========= ========= ========= End of period................... 3,385 3,890 3,309 ========= ========= ========= Natural Gas (MMcf): Beginning of period............. 20,408 20,582 11,366 ========= ========= ========= End of period................... 49,491 20,408 20,582 ========= ========= ========= F-19 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STANDARDIZED MEASURE The following tables present the Company's standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves and were 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. In 1995 and 1994, no future income taxes were provided on the future net inflows as tax credits (including carryovers) and other permanent differences were 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. STANDARDIZED MEASURE YEAR ENDED DECEMBER 31, ---------------------------------- 1996 1995 1994 ---------- ---------- ---------- (IN THOUSANDS) Future cash inflows.................. $ 285,727 $ 157,240 $ 115,659 Future costs -- Production...................... (59,584) (50,236) (43,579) Development and net abandonment................... (9,989) (11,274) (12,603) ---------- ---------- ---------- Future net inflows before income taxes.............................. 216,154 95,730 59,477 Future income taxes.................. (49,438) -- -- ---------- ---------- ---------- Future net cash flows................ 166,716 95,730 59,477 10% discount factor.................. (36,547) (31,966) (18,094) ---------- ---------- ---------- Standardized measure of discounted future net cash flows.............. $ 130,169 $ 63,764 $ 41,383 ========== ========== ========== CHANGES IN STANDARDIZED MEASURE YEAR ENDED DECEMBER 31, ---------------------------------- 1996 1995 1994 ---------- ---------- ---------- (IN THOUSANDS) Standardized measure -- beginning of period............................. $ 63,764 $ 41,383 $ 22,554 Sales and transfers, net of production costs................... (18,202) (12,477) (9,815) Net change in sales and transfer prices, net of production costs.... 32,268 11,519 1,368 Exchange and sale of in place of reserves........................... (877) (23) (48) Purchases, extensions, discoveries, and improved recovery, net of future production and development costs.............................. 79,983 28,204 26,376 Revisions of quantity estimates...... (3,907) (4,242) (6,297) Accretions of discount............... 6,376 2,963 1,488 Net change in income taxes........... (30,000) -- -- Changes in production rates, timing and other.......................... 764 (3,563) 5,757 ---------- ---------- ---------- Standardized measure -- end of period............................. $ 130,169 $ 63,764 $ 41,383 ========== ========== ========== F-20 CALLON PETROLEUM COMPANY UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS INTRODUCTION The following unaudited pro forma financial statements are based on the historical balance sheet and results of operations of Callon Petroleum Company after giving pro forma effect to (i) the recent acquisitions described below and (2) the Offering, as if such acquisitions and the Offering had occurred on September 30, 1997, and at the beginning of the earliest period presented. On June 26, 1997, Callon Petroleum Operating Company, a wholly owned subsidiary of the Company purchased a working interest in the Mobile Area Block 864 Unit from Elf Exploration, Inc. (the "Elf Acquisition") The Company's net purchase price was $11.8 million. In October 1997, the Company agreed to purchase 61% of Chevron U.S.A, Inc.'s interest in the Mobile Block Area (the "Chevron Acquisition") for $21 million effective July 1, 1997. The Chevron Acquisition closed on November 7, 1997 for a net purchase price of $18.8 million. See Note 1 in the Notes to Pro Forma Consolidated Financial Statements for the basis of presentation of the above events in the Pro Forma Consolidated Financial Statements of the Company. F-21 CALLON PETROLEUM COMPANY UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET SEPTEMBER 30, 1997 (IN THOUSANDS)
PRO FORMA PRO FORMA HISTORICAL ADJUSTMENTS AS ADJUSTED ---------- ----------- ----------- ASSETS Current assets.......................... $ 16,298 $ 6,412(f) $ 22,710 Net oil and gas properties (full cost method)............................... 127,296 18,792(f) 146,088 Other assets............................ 12,756 12,756 ---------- ----------- ----------- Total assets....................... $ 156,350 $25,204 $ 181,554 ========== =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities..................... $ 12,672 $-- $ 12,672 Long-term debt.......................... 60,250 -- 60,250 Other liabilities....................... 546 -- 546 Stockholders' equity.................... 82,882 25,204(f) 108,086 ---------- ----------- ----------- Total liabilities and stockholders' equity........................... $ 156,350 $25,204 $ 181,554 ========== =========== ===========
See Notes to Unaudited Pro Forma Consolidated Financial Statements F-22 CALLON PETROLEUM COMPANY UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 1996 (IN THOUSANDS, EXCEPT PER SHARE DATA)
HISTORICAL ELF CHEVRON PRO FORMA PRO FORMA COMPANY ACQUISITION ACQUISITION ADJUSTMENTS AS ADJUSTED ---------- ----------- ------------ ----------- ------------ Revenues: Oil and gas sales............... $ 25,764 $ 4,455(a) $ 8,735(b) $ -- $ 38,954 Interest and other.............. 946 -- -- -- 946 ---------- ----------- ------------ ----------- ------------ Total revenues............. 26,710 4,455 8,735 -- 39,900 ---------- ----------- ------------ ----------- ------------ Expenses: Lease operating expenses........ 7,562 245(a) 295(b) -- 8,102 Depreciation, depletion and amortization.................. 9,832 -- -- 4,912(d) 14,744 General and administrative...... 3,495 -- -- -- 3,495 Interest........................ 313 -- -- 1,548(c) 1,861 ---------- ----------- ------------ ----------- ------------ Total costs and expenses... 21,202 245 295 6,460 28,202 ---------- ----------- ------------ ----------- ------------ Income from operations............... 5,508 4,210 8,440 (6,460) 11,698 Income tax expense................... 50 -- -- 4,044(e) 4,094 ---------- ----------- ------------ ----------- ------------ Net income........................... 5,458 4,210 8,440 (10,504) 7,604 Preferred stock dividends............ 2,795 -- -- -- 2,795 ---------- ----------- ------------ ----------- ------------ Net income available to common shares............................. $ 2,663 $ 4,210 $ 8,440 $ (10,504) $ 4,809 ========== =========== ============ =========== ============ Net income per common share: Primary......................... $ 0.45 $ 0.64 ========== ============ Assuming full dilution.......... $ 0.43 $ 0.62 ========== ============ Shares used in computing net income per common share: Primary......................... 5,952 7,552 ========== ============ Assuming full dilution.......... 6,135 7,735 ========== ============
See Notes to Unaudited Pro Forma Consolidated Financial Statements F-23 CALLON PETROLEUM COMPANY UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 1997 (IN THOUSANDS, EXCEPT PER SHARE DATA)
HISTORICAL ELF CHEVRON PRO FORMA PRO FORMA COMPANY ACQUISITION ACQUISITION ADJUSTMENTS AS ADJUSTED ---------- ----------- ------------ ----------- ------------ Revenues: Oil and gas sales............... $ 29,578 $ 1,813(a) $4,667(b) $-- $ 36,058 Interest and other.............. 1,162 -- -- -- 1,162 ---------- ----------- ------------ ----------- ------------ Total revenues............. 30,740 1,813 4,667 -- 37,220 ---------- ----------- ------------ ----------- ------------ Expenses: Lease operating expenses........ 6,235 (69)(a) 53(b) -- 6,219 Depreciation, depletion and amortization.................. 11,288 -- -- 2,881(d) 14,169 General and administrative...... 3,263 -- -- -- 3,263 Interest........................ 945 -- -- 551(c) 1,496 ---------- ----------- ------------ ----------- ------------ Total costs and expenses... 21,731 (69) 53 3,432 25,147 ---------- ----------- ------------ ----------- ------------ Income from operations............... 9,009 1,882 4,614 (3,432) 12,073 Income tax expense................... 2,926 -- -- 1,299(e) 4,225 ---------- ----------- ------------ ----------- ------------ Net income........................... 6,083 1,882 4,614 (4,731) 7,848 Preferred stock dividends............ 2,097 -- -- -- 2,097 ---------- ----------- ------------ ----------- ------------ Net income available to common shares............................. $ 3,986 $ 1,882 $4,614 $(4,731) $ 5,751 ========== =========== ============ =========== ============ Net income per common share: Primary......................... $ 0.63 $ 0.72 ========== ============ Assuming full dilution.......... $ 0.62 $ 0.71 ========== ============ Shares used in computing net income per common share: Primary......................... 6,332 7,932 ========== ============ Assuming full dilution.......... 6,440 11,030 ========== ============
See Notes to Unaudited Pro Forma Consolidated Financial Statements F-24 CALLON PETROLEUM COMPANY NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION On June 26, 1997, Callon Petroleum Operating Company, a wholly owned subsidiary of Callon Petroleum Company (the "Company"), purchased an 18.8% working interest in the Mobile Area Block 864 Unit from Elf Exploration, Inc. (the "Elf Acquisition"). The Company's net purchase price was $11.8 million. In October 1997, the Company agreed to purchase 61% of Chevron U.S.A. Inc.'s interest in the Mobile Block 864 Area (the "Chevron Acquisition") for $21 million effective July 1, 1997. The Chevron Acquisition closed on November 7, 1997 for a net purchase price of $18.8 million. The Company utilized borrowings under its existing Credit Facility to complete the Chevron Acquisition. The accompanying Pro Forma Consolidated Statements of Operations of the Company for the year ended December 31, 1996 and the nine months ended September 30, 1997 give effect to the Elf Acquisition, the Chevron Acquisition and the sale of Common Stock offered hereby and the application of the proceeds therefrom, as if the transactions occurred at the beginning of the earliest period presented. The accompanying Pro Forma Consolidated Balance Sheet at September 30, 1997 gives effect to the Chevron Acquisition and the sale of the Common Stock offered hereby and the application of the proceeds therefrom, as if the transactions occurred on September 30, 1997. The Pro Forma Consolidated Statements of Operations and Balance Sheet are based on the assumptions set forth in the notes to such statements. 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 transaction 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 statements of the Company are as follows: (a) To reflect the Elf Acquisition and the related results of operations as described in Note 1. (b) To reflect the Chevron Acquisition and the related results of operations as described in Note 1. (c) To reflect an increase in interest expense related to borrowing made to complete the Elf Acquisition and the Chevron Acquisition as if the transactions, less the effect of the net proceeds of the sale of the Common Stock offered hereby, had occurred at the beginning of the year ended December 31, 1996. The estimated interest rate used was 8.5%. A one-eighth change in this estimated rate would have the effect of $23,000 for the year ended December 31, 1996 and $8,000 for the nine months ended September 30, 1997. (d) To adjust the provision for depreciation, depletion and amortization of the combined full cost pool based on the purchase of the Elf Acquisition and the Chevron Acquisition as described in Note 1. (e) To record a provision for Federal income taxes at a corporate statutory rate of 35% on pro forma income as a result of the acquisitions described in Note 1. (f) Reflects the use of the proceeds to complete the sale of the Common Stock as a result of the Offering and the Chevron Acquisition as if both occurred at September 30, 1997. F-25 REPORT OF INDEPENDENT AUDITORS Stockholders and Board of Directors Callon Petroleum Company We have audited the accompanying statement of revenues and direct operating expenses of the working interest in Mobile Area Block 864 Unit (the "Property") acquired by Callon Petroleum Operating Company (the "Company"), a wholly owned subsidiary of Callon Petroleum Company, from Elf Exploration, Inc. (see Note 1 to the accompanying statement) for the year ended December 31, 1996. This statement is the responsibility of the Company's management. Our responsibility is to express an opinion on this statement based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of revenues and direct operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of revenues and direct operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement presentation. We believe that our audit provides a reasonable basis for our opinion. The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and is not intended to be a complete presentation of revenues and expenses of the Property. In our opinion, the statement of revenues and direct operating expenses referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Property for the year ended December 31, 1996, in conformity with generally accepted accounting principles. ERNST & YOUNG LLP July 24, 1997 Houston, Texas F-26 CALLON PETROLEUM COMPANY STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY SIX MONTHS YEAR ENDED ENDED DECEMBER 31, 1996 JUNE 30, 1997 ----------------- -------------- (UNAUDITED) (IN THOUSANDS) Oil and gas revenues................. $ 4,455 $1,813 Direct operating expenses............ 245 (69) -------- -------------- Revenues in excess of direct operating expenses................... $ 4,210 $1,882 ======== ============== See accompanying notes F-27 CALLON PETROLEUM COMPANY NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY DECEMBER 31, 1996 1. BASIS OF PRESENTATION Callon Petroleum Operating Company (the "Company"), a wholly owned subsidiary of Callon Petroleum Company, acquired a working interest in Mobile Area Block 864 Unit (the "Property") from Elf Exploration, Inc. (the "Seller"). The closing date of the acquisition was June 26, 1997, and the net purchase price was $11.8 million. The accompanying statement of revenues and direct operating expenses, which is prepared on the accrual basis of accounting, related only to the working interest in the producing oil and gas property acquired and may not be representative of future operations. The statement includes revenues and direct operating expenses, including production and ad valorem taxes, for the entire period presented. The statement does not include federal and state income taxes, interest, depletion, depreciation and amortization, or general and administrative expenses because such amounts would not be indicative of those expenses which would be incurred by the Company. Presentation of complete historical financial statements for the year ended December 31, 1996 and the six months ended June 30, 1997 is not practicable because the Property was not accounted for as a separate entity; therefore, such statements are not available. Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. The preparation of the statement of revenues and direct operating expenses in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the statement and accompanying notes. Actual results could differ from those estimates. The unaudited statement of revenues and direct operating expenses for the six-month period ended June 30, 1997, in the opinion of management, was prepared on a basis consistent with the audited statement of revenues and direct operating expenses and includes all adjustments necessary to present fairly the results of the period. 2. SUPPLEMENTAL INFORMATION ON OIL AND GAS RESERVES (UNAUDITED) There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Therefore, actual production, revenues, and development and operating expenses may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties, and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities may differ materially from the amounts estimated. F-28 CALLON PETROLEUM COMPANY NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY -- (CONTINUED) The following reserve data, prepared by the Company, represents estimates of proved natural gas reserves of the Property, which is located in the United States. There are no oil reserves associated with the Property. 1996 --------- NATURAL GAS (MMCF) Proved reserves: Beginning of period...... 11,842 Production............... 1,795 --------- End of period............ 10,047 ========= Proved developed reserves: Beginning of period...... 11,842 End of period............ 10,047 The estimated standardized measure of discounted future net cash flows relating to proved reserves of the Property at December 31, 1996 is shown below and should not be construed as the current market value. No deductions were made for general overhead, depletion, depreciation and amortization, debt service, or any indirect costs. Since the Property is not a separate tax-paying entity, the standardized measure of discounted future net cash flows for the Property is presented before deduction of income taxes. 1996 -------------- (IN THOUSANDS) Future cash inflows........... $ 38,680 Future production costs....... (3,241) -------------- Future net cash flows before income taxes................ 35,439 10% annual discount for estimated timing of cash flows....................... (10,186) -------------- Standardized measure of discounted future net cash flows relating to proved reserves before income taxes....................... $ 25,253 ============== Changes in the standardized measure of discounted future net cash flows relating to proved reserves of the Property are shown below. 1996 -------------- (IN THOUSANDS) Balances at beginning of period...................... $ 16,643 Increase (decrease) in discounted future net cash flows: Sales and transfers of natural gas produced, net of production costs.................. (4,210) Accretion of discount.... 1,419 Net change in sales price and production costs... 11,401 -------------- Balance at end of period...... $ 25,253 ============== The weighted average prices of natural gas at December 31, 1995 and 1996 used in the calculation of the standardized measure of discounted future net cash flows were $2.28 and $3.85 per Mcf, respectively. F-29 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Callon Petroleum Company We have audited the accompanying statement of revenues and direct operating expenses of 61% of Chevron U.S.A. Inc.'s working interest in Mobile 864 Unit Outer Continental Shelf (the "Property") acquired by Callon Petroleum Operating Company (the "Company"), a wholly owned subsidiary of Callon Petroleum Company, for each of the three years in the period ended December 31, 1996. This statement is the responsibility of the Company's management. Our responsibility is to express an opinion on this statement based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of revenues and direct operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of revenues and direct operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statement of revenues and direct operating expenses. We believe that our audit provides a reasonable basis for our opinion. The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission (for inclusion in the registration statement on Form S-2 of Callon Petroleum Company) as described in Note 1 and is not intended to be a complete presentation of the Property's revenues and expenses. In our opinion, the statement of revenues and direct operating expenses referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Property described in Note 1 for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. PRICE WATERHOUSE LLP San Francisco, California November 21, 1997 F-30 STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY (IN THOUSANDS)
FOR THE NINE MONTHS ENDED DECEMBER 31, SEPTEMBER 30, ------------------------------- 1997 1996 1995 1994 ------------- --------- --------- --------- (UNAUDITED) Oil and gas revenues.................... $ 4,667 $ 8,735 $ 6,612 $ 11,596 Direct operating expenses............... 53 295 334 209 ------------- --------- --------- --------- Revenues in excess of direct operating expenses.............................. $ 4,614 $ 8,440 $ 6,278 $ 11,387 ============= ========= ========= =========
See accompanying notes. F-31 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY 1. BASIS OF PRESENTATION Callon Petroleum Operating Company (the "Company"), a wholly owned subsidiary of Callon Petroleum Company, agreed in October 1997 to acquire 61% of Chevron U.S.A. Inc.'s working interest in Mobile 864 Unit Outer Continental Shelf which includes the twelve-inch Mobile 908 Area Gathering Pipeline (the "Property") for $21 million, effective July 1, 1997. The acquisition closed on November 7, 1997 for a net acquisition cost of $18.8 million. The accompanying statement of revenues and direct operating expenses relates only to the working interest in the producing oil and gas property acquired and may not be representative of future operations. The statement includes revenues from natural gas sales and direct operating expenses for each of the periods presented. The statement does not include federal and state income taxes, interest, depletion, depreciation and amortization or general and administrative expenses because such amounts would not be indicative of those expenses which would be incurred by the Company. Presentation of complete historical financial statements for each of the three years ended December 31, 1996 and the nine months ended September 30, 1997 is not practicable because the Property was not accounted for as a separate entity; therefore, such statements are not available. Revenues in the accompanying statement of revenues and direct operating expenses are recognized on the entitlement method. The accompanying statement has been prepared on the accrual basis in accordance with generally accepted accounting principles. Preparation of the statement in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the statement and accompanying notes. Actual results could differ from those estimates. The interim revenues and direct operating expenses for the nine months ended September 30, 1997 are unaudited; however, in the opinion of the Company, the interim revenues and direct operating expenses include all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the results for the interim period. 2. COMMITMENTS AND CONTINGENCIES In the normal course of business the Company is subject to possible loss contingencies arising from federal, state and local environmental, health and safety laws and regulations, joint venture audit claims and third party litigation. There are no matters which, in the opinion of management, will have a material adverse effect on the revenues and direct operating expenses of the Property. 3. RELATED PARTY TRANSACTIONS The Property was not operated as a separate entity for the periods presented in the accompanying statement, but was included in the operations of Chevron U.S.A. Inc. Effective September 1, 1996, all revenues from production were transferred to an equity affiliate of Chevron Corporation, the parent of Chevron U.S.A. Inc., at approximate market prices. 4. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) The Property's proved oil and gas reserves at December 31, 1996, 1995 and 1994 have been estimated by the Company's independent petroleum consultants in accordance with guidelines established by the Securities and Exchange Commission ("SEC"). 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 Property or the cost that would be incurred to obtain equivalent reserves. F-32 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY -- (CONTINUED) ESTIMATED RESERVES Changes in the estimated net quantities of natural gas reserves are as follows: GAS NET PROVED RESERVES OF NATURAL GAS (MMCF) - ------------------------------------- ------- PROVED DEVELOPED AND UNDEVELOPED RESRVES AT: December 31, 1993.................... 34,396 Production........................... (6,237) ------- December 31, 1994.................... 28,159 Production........................... (3,964) ------- December 31, 1995.................... 24,195 Production........................... (3,394) ------- December 31, 1996.................... 20,801 ======= PROVED DEVELOPED RESERVES AT: December 31, 1994.................... 28,159 December 31, 1995.................... 24,195 December 31, 1996.................... 20,801 STANDARDIZED MEASURE The following tables present the Property's standardized measure of discounted future net cash flows and changes therein relating to proved reserves and were computed using reserve valuations based on regulations prescribed by the SEC. These regulations provide that the gas price structure utilized to project future net cash flows reflects current prices at each date presented. Future production, development and net abandonment costs are based on current costs without escalation. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pre-tax net cash flows, less the tax basis of related assets. The resulting net future cash flows have been discounted to their present values based on a 10% annual discount factor (in thousands). STANDARDIZED MEASURE DECEMBER 31, ---------------------------------- 1996 1995 1994 ---------- ---------- ---------- Future cash inflows.................. $ 81,746 $ 55,406 $ 49,280 Future production and development costs.............................. (3,902) (4,344) (4,607) Future income taxes.................. (18,739) (6,412) (1,978) ---------- ---------- ---------- Future net cash flows undiscounted... 59,105 44,650 42,695 10% annual discount for estimated timing of cash flows............... (20,286) (15,496) (14,953) ---------- ---------- ---------- Standardized measure of discounted future net cash flows.............. $ 38,819 $ 29,154 $ 27,742 ========== ========== ========== F-33 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY -- (CONTINUED) CHANGES IN STANDARDIZED MEASURE DECEMBER 31, -------------------------------- 1996 1995 1994 --------- --------- ---------- Standardized measure of discounted future net cash flows at beginning of period.......................... $ 29,154 $ 27,742 $ 40,759 Changes resulting from: Sales of natural gas produced, net of production costs....... (8,440) (6,278) (11,387) Net changes in sales prices, net of production costs........... 22,892 7,689 (9,038) Accretion of discount........... 3,334 2,902 4,498 Net changes in income taxes..... (8,121) (2,901) 2,910 --------- --------- ---------- Standardized measure of discounted future net cash flows at end of period............................. $ 38,819 $ 29,154 $ 27,742 ========= ========= ========== F-34 NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS IN CONNECTION WITH THIS OFFERING OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS. ANY INFORMATION OR REPRESENTATION NOT HEREIN CONTAINED IF GIVEN OR MADE, MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL, OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES OFFERED BY THIS PROSPECTUS, NOR DOES IT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY THE SECURITIES BY ANY PERSON IN ANY JURISDICTION WHERE SUCH OFFER OR SOLICITIATION 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. THE DELIVERY OF THIS PROSPECTUS SHALL NOT, UNDER ANY CIRCUMSTANCES, CREATE ANY 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 ----- Prospectus Summary................... 3 Risk Factors......................... 10 The Company.......................... 15 Use of Proceeds...................... 15 Price Range of Common Stock and Dividend Policy.................... 16 Capitalization....................... 17 Selected Financial Data.............. 18 Management's Discussion and Analysis of Financial Condition and Results of Operations...................... 20 Business and Properties.............. 26 Management........................... 40 Principal Stockholders............... 43 Description of Outstanding Securities and Debt Instruments............... 46 Underwriting......................... 50 Legal Matters........................ 51 Experts.............................. 51 Available Information................ 52 Incorporation of Certain Documents by Reference.......................... 52 Glossary............................. 54 Index to Financial Statements........ F-1 1,600,000 SHARES CALLON PETROLEUM COMPANY COMMON STOCK ------------------- PROSPECTUS ------------------- MORGAN KEEGAN & COMPANY, INC. A.G. EDWARDS & SONS, INC. HOWARD, WEIL, LABOUISSE, FRIEDRICHS INCORPORATED JEFFERIES & COMPANY, INC. November 25, 1997 -----END PRIVACY-ENHANCED MESSAGE-----