-----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, KOnKTsQydLIM1Lb9L5/fyRK5FQQRbN7e0vggByKyYUCHjGCHsx/cvH3x6biBXIgY FXE7N/tzOZqAW1rC1fWcKw== 0000950129-99-002650.txt : 19990615 0000950129-99-002650.hdr.sgml : 19990615 ACCESSION NUMBER: 0000950129-99-002650 CONFORMED SUBMISSION TYPE: S-2 PUBLIC DOCUMENT COUNT: 6 FILED AS OF DATE: 19990614 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: S-2 SEC ACT: SEC FILE NUMBER: 333-80579 FILM NUMBER: 99645345 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 S-2 1 CALLON PETROLEUM COMPANY 1 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JUNE 14, 1999 REGISTRATION NO. 333- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM S-2 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 --------------------- CALLON PETROLEUM COMPANY (Exact name of registrant as specified in its charter) DELAWARE 1311 64-0844345 (State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer incorporation or organization) Classification Code Number) Identification No.)
200 NORTH CANAL STREET, NATCHEZ, MISSISSIPPI 39120 TELEPHONE: (601) 442-1601 (Address, including zip code, and telephone number including area code, of registrant's principal executive offices) JOHN S. WEATHERLY 200 NORTH CANAL STREET, NATCHEZ, MISSISSIPPI 39120 TELEPHONE: (601) 442-1601 (Name, address, including zip code, and telephone number including area code, of agent for service) Copy to: BUTLER & BINION, L.L.P. VINSON & ELKINS, L.L.P. 1000 LOUISIANA, SUITE 1600 2300 FIRST CITY TOWER HOUSTON, TEXAS 77002 1001 FANNIN ATTN: GEORGE G. YOUNG III HOUSTON, TEXAS 77002 TELEPHONE: (713) 237-3605 ATTN: T. MARK KELLY TELECOPY : (713) 237-3202 TELEPHONE: (713) 758-4592 TELECOPY: (713) 615-5531
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO PUBLIC: As soon as practicable after the effective date of the Registration Statement. If any securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1993 check the following box. [ ] If the registrant elects to deliver its latest annual report to security holders, or a complete and legal facsimile thereof, pursuant to Item 11(a)(1) of this Form, check the following box. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ________ If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ________ If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ________ If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] CALCULATION OF REGISTRATION FEE
- --------------------------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------------------------- PROPOSED MAXIMUM PROPOSED MAXIMUM TITLE OF EACH CLASS OF AMOUNT TO BE OFFERING PRICE AGGREGATE AMOUNT OF SECURITIES TO BE REGISTERED REGISTERED PER UNIT(1) OFFERING PRICE(1) REGISTRATION FEE(2) - --------------------------------------------------------------------------------------------------------------------------------- Senior Subordinated Notes due 2004......................... 40,000 $1,000 $40,000,000 $11,120 - --------------------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------------------
(1) Estimated solely for purposes of calculating the registration fee. (2) Pursuant to Rule 457(a), the registration fee has been calculated solely on the basis of the proposed maximum aggregate offering price of the Senior Subordinated Notes being registered hereby. The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 SUBJECT TO COMPLETION, DATED JUNE 14, 1999 $40,000,000 CALLON PETROLEUM COMPANY [CALLON PETROLEUM COMPANY LOGO] % SENIOR SUBORDINATED NOTES DUE 2004 ------------------------ INVESTING IN THE NOTES INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON PAGE 9. ------------------------ TERMS OF NOTES - - MATURITY September 15, 2004. - - INTEREST Fixed annual rate of %. We will pay interest on the notes on March 15, June 15, September 15 and December 15 of each year. The first interest payment will be made on September 15, 1999, which will represent interest accrued from , 1999. - - TRADING We have applied to list the notes on the New York Stock Exchange under the symbol " ." - - OPTIONAL REDEMPTION We may redeem the notes at any time on or after March 15, 2001 at 100% of their principal amount plus accrued and unpaid interest. - - RANKING The notes are subordinated in right of payment to all of our senior debt and to the obligations of our subsidiaries. The notes rank equally with our existing and future senior subordinated indebtedness. The notes are senior to our outstanding preferred stock. - - CHANGE OF CONTROL If a change of control occurs, we must offer to repurchase the notes at 101% of their principal amount plus accrued and unpaid interest. ------------------------
PER NOTE TOTAL ------------------- ------------------- Public offering price....................................... 100% $40,000,000 Underwriting discount....................................... % $ Proceeds, before expenses................................... % $
The underwriters expect to deliver the notes in book-entry form only through the facilities of The Depository Trust Company against payment in New York, New York on , 1999. Neither the Securities and Exchange Commission nor any state securities regulators have approved or disapproved these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. ------------------------ A.G. EDWARDS & SONS, INC. MORGAN KEEGAN & COMPANY, INC. Prospectus dated , 1999 THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES, AND WE ARE NOT SOLICITING AN OFFER TO BUY THESE SECURITIES, IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. 3 [MAP SHOWING PRINCIPAL AREAS OF OPERATIONS IN THE GULF OF MEXICO. MAP DIVIDES THE GULF INTO THE SHALLOW MIOCENE AREA, OCS AREA AND DEEP WATER AREA.] CORPORATE PROFILE - Geographic concentration in the Gulf of Mexico. - Estimated net proved reserves of 183.3 Bcfe with a discounted present value of $173.9 million as of June 1, 1999. - Average daily net production of 43.4 MMcfe during the first quarter of 1999, 86% of which was natural gas. - Reserve life of 12.1 years. 215% RESERVE GROWTH - Between January 1, 1996 and June 1, 1999, estimated net proved reserves increased 215% from 58.3 Bcfe to 183.3 Bcfe. SIGNIFICANT DEEP WATER SUCCESS - In September 1998, we announced a discovery on our Boomslang prospect, and in February 1999, we announced a discovery on our Habanero prospect. - These discoveries represent the largest discoveries in our history and have added estimated net proved reserves of 86.8 Bcfe at a cost to us of $10.2 million to drill. SUBSTANTIAL INVENTORY OF PROSPECTS - As of June 1, 1999, we had an inventory of 39 exploratory prospects, all of which have been defined by seismic data and interpretation. 2 4 PROSPECTUS SUMMARY This summary highlights selected information from this document but does not contain all of the information you need to consider in making your investment decision. To understand all of the terms of this offering and for a more complete understanding of our business, you should carefully read this entire document and the documents incorporated by reference in this document, particularly the section entitled "Risk Factors." When we use the terms "Callon," "we," "us" or "our," we are referring to Callon Petroleum Company together with its consolidated subsidiaries and predecessors, unless the context otherwise requires. If you are not familiar with the ownership of oil and gas properties or the way in which quantities and values of oil and gas reserves are described, please read "Glossary of Oil and Gas Terms" included in this document. THE COMPANY Callon has been engaged in the exploration, development, acquisition and production of oil and gas in the Gulf Coast region since 1950. Our properties and operations are geographically concentrated in the offshore waters of the Gulf of Mexico where we have substantial experience. As of June 1, 1999, we had estimated net proved reserves of 183.3 Bcfe which had a discounted present value of $173.9 million. Reserves comprising 72% of this discounted present value were classified as proved developed. Average daily net production during the first quarter of 1999 was 43.4 MMcfe, of which 86% was natural gas. We operate wells representing 82% of this production. Net proved reserves as of June 1, 1999 divided by our production from the four quarters ended March 31, 1999, sometimes referred to as our "reserve life," was 12.1 years. Our reserves and production have grown rapidly since 1996 as a result of exploration and development drilling, as well as property acquisitions. Between January 1, 1996 and June 1, 1999, estimated net proved reserves increased 215%, and average daily net production increased 70% from the first quarter of 1996 to the first quarter of 1999. BUSINESS STRATEGY Our goals are to increase reserves, production, cash flow and earnings at low reserve replacement costs. We seek to achieve these goals through the following strategies: - Assemble and explore a balanced portfolio of projects in the Gulf of Mexico composed of: Controlling working interests in projects with low exploration risk and low drilling and completion costs targeting reserve deposits of between 3 and 10 Bcf in the shallow Miocene area at depths of less than 4,000 feet; Significant working interests in projects with higher exploration risk and higher drilling and completion costs targeting reserve deposits of between 10 and 100 Bcfe in the outer continental shelf ("OCS") area at depths of between 7,000 and 17,000 feet; and Small working interests in projects with high exploration risk and high drilling and completion costs targeting large reserve deposits in the deep water area of the Gulf of Mexico. - Acquire at low costs, additional working interests, gathering systems, pipelines, production facilities and other infrastructure in areas in which we operate. Ownership of these facilities enables us to reduce the costs of completing wells and to control the timing of the development of our properties. - Utilize the latest available technology. Our geoscientists and petroleum engineers have developed an expertise with advanced technologies, including 3-D seismic interpretation and computer-aided exploration. In addition, we have developed a proprietary, inexpensive, high-resolution 2-D seismic data processing and interpretation technique to target shallow Miocene formations. - Maintain financial flexibility. We seek to maintain a substantial unused borrowing capacity under our bank credit facility by periodically refinancing our bank debt in the capital markets by issuing both debt and equity securities. 3 5 EXPLORATION OPERATIONS We explore for oil and gas in the state and federal waters of the Gulf of Mexico. Since 1996, we have drilled nine gross (5.3 net) productive exploration wells and eight gross (3.2 net) dry holes in the Gulf of Mexico for a gross success rate of 53% (62% net). We have also drilled five gross (2.9 net) development wells in the Gulf of Mexico, all of which were successful. On June 1, 1999, we had two gross (1.2 net) exploration wells in the OCS area in progress, and had an inventory of 39 exploration prospects. Our principal areas of exploration are summarized below. For a more complete description see "Business and Properties." Shallow Miocene Area. In the shallow Miocene area, we explore for gas deposits using 3-D and conventional 2-D seismic technology, as well as a proprietary high-resolution 2-D seismic technology which better defines reservoir thickness and continuity. We have an average working interest in productive wells in the shallow Miocene area of 83%, all of which we operate. Since 1996, we have drilled three gross (2.7 net) exploration wells, of which two gross (2.0 net) were productive, and two gross (1.5 net) development wells, both of which were productive. Our drilling activities in the shallow Miocene area have added 11.2 Bcf of estimated net proved reserves at a cost to us of $9.5 million to drill and complete. We have acquired an extensive infrastructure of production platforms, gathering systems and pipelines located in our shallow Miocene area. These facilities reduce the development costs of our successful wells and reduce the time necessary to begin production from successful wells. In 1997, we also acquired 52.5 Bcf of estimated net proved reserves in the Mobile Block 864 area for a total acquisition cost of $48.7 million. As described under "Recent Developments," we have acquired additional interests in this area. We currently have an inventory of four exploration prospects in this area, two of which we expect to drill before year-end 1999. Outer Continental Shelf Area. We explore for oil and gas deposits in the OCS area of the Gulf of Mexico using the latest in 3-D seismic technology. The wells drilled in this area are more expensive than the shallow Miocene wells and target larger oil and gas deposits. Our weighted average working interest in productive wells in the OCS area is 65.4%. Since 1996, we have added 28.6 Bcfe of estimated net proved reserves at a cost to us of $28.3 million to drill and complete. Since 1996, we have drilled 12 gross (5.3 net) exploration wells in this area, of which five gross (2.8 net) were productive and had two exploration wells in progress on June 1, 1999. We also drilled three gross (1.4 net) development wells, all of which were successful. We currently have an inventory of 21 exploration prospects in this area, 10 of which we expect to drill before year-end 2000. Deep Water Area. We allocate a portion of our capital expenditure budget to the exploration of deep water regions in the Gulf of Mexico. These wells are expensive to drill and complete and target large reserve deposits. These wells are usually located far from production facilities and may require long lead times to construct pipelines and other facilities necessary to begin production. To reduce the risks associated with the high cost of these wells, we explore these prospects with experienced joint venture partners, including Shell Deepwater Development, Inc. and Murphy Exploration and Production, Inc., as operators. We have drilled two wells in our deep water area, both of which were successful. In September 1998, we announced a discovery on our "Boomslang" prospect, and in February 1999, we announced a discovery on our "Habanero" prospect. These discoveries represent the largest discoveries in our history and have added estimated net proved reserves of 86.8 Bcfe at a cost to us of $10.2 million to drill. Costs to complete these wells cannot be determined until we drill several related prospects. We currently have an inventory of 14 deep water exploration prospects, four of which we expect to drill before year-end 2000. 4 6 RECENT DEVELOPMENTS On June 11, 1999, we acquired Murphy's working interests in nine blocks in the shallow Miocene area in which we also have an interest. Included in the acquisition is a 13.1% working interest in four producing wells in the Mobile Block 864 unit and a 38.6% average working interest in three additional producing wells. Murphy will receive a production payment entitling it to 7.6 Bcf of gas from production attributable to the wells over three and a quarter years. Through this acquisition, we also gained control over exploration of 58,000 gross acres. After giving effect to the acquisition as if it had occurred on January 1, 1999, our average daily net production would have increased by 5.3 MMcf, or 12.2%, during the first quarter of 1999. In February 1999, we announced a discovery on our Habanero prospect in the deep water area. This well was drilled in 1,800 feet of water to a total measured depth of 21,158 feet. We have an 11.3% working interest in this well, which had estimated net proved reserves as of June 1, 1999 of 50.9 Bcfe. In January 1999, we announced a discovery on our Snapper prospect in the OCS area. This well was drilled in 210 feet of water to a total measured depth of 8,800 feet. We have a 50.0% working interest in this well, which added 5.0 Bcfe of estimated net proved reserves as of June 1, 1999. In September 1998, we announced a discovery on our Boomslang prospect in the deep water area. This well was drilled in 900 feet of water to a total measured depth of 13,200 feet. We have a 35.0% working interest in this well, which had estimated net proved reserves as of June 1, 1999 of 35.9 Bcfe. SIGNIFICANT PROPERTIES The following table provides information about estimated net proved reserves attributable to our principal operating areas as of June 1, 1999. Estimated net quantities of proved oil and gas reserves and the discounted present value of the reserves were estimated by our independent reserve engineers.
ESTIMATED NET PROVED RESERVES PERCENT ------------------------------ DISCOUNTED TOTAL GAS OIL TOTAL PRESENT VALUE DISCOUNTED (MMCF) (MBBLS) (MMCFE) ($000) PRESENT VALUE -------- -------- -------- ------------- ------------- Shallow Miocene area................... 57,906 -- 57,906 $ 71,135 40.9% OCS area............................... 20,839 951 26,546 38,156 21.9% Deep water area........................ 20,829 10,994 86,791 48,987 28.2% Other areas............................ 5,399 1,106 12,034 15,639 9.0% ------- ------ ------- -------- ----- Total........................ 104,973 13,051 183,277 $173,917 100.0% ======= ====== ======= ======== =====
PRINCIPAL OFFICE Our principal executive offices are located at 200 North Canal Street, Natchez, Mississippi 39120 and our telephone number is (601) 442-1601. 5 7 THE OFFERING Securities Offered......... $40,000,000 principal amount of % Senior Subordinated Notes due 2004. Maturity................... September 15, 2004. Interest Payment Dates..... March 15, June 15, September 15 and December 15. The first interest payment will be September 15, 1999, which will represent interest accrued from , 1999. Optional Redemption........ On or after March 15, 2001, we may redeem all or a portion of the notes at 100% of their principal amount plus accrued and unpaid interest. Ranking.................... The notes: - are unsecured; - rank junior to our current and future senior debt, including debt we may incur under our bank credit facility, and the liabilities of our subsidiaries; - rank equally with our existing and future senior subordinated debt; and - are senior to our outstanding preferred stock. Assuming we had issued the notes and applied the proceeds as intended as of March 31, 1999, we would have had no senior indebtedness and $100.2 million of senior subordinated indebtedness, including the notes. Also, our subsidiaries had $12.0 million of liabilities on their balance sheets at March 31, 1999. Restrictive Covenants...... The indenture governing the notes will, among other things, limit our ability and the ability of our subsidiaries to: - incur additional indebtedness; - place liens on our assets; - make dividend payments on our common stock or repurchase any of our capital stock; - enter into affiliate transactions; and - merge, consolidate and sell substantially all of our assets. The covenants are fully described under "Description of the Notes -- Certain Covenants." Change of Control.......... If a change in control occurs, we must offer to repurchase the notes at 101% of their principal amount plus accrued and unpaid interest. For a description of the change of control provisions, see "Description of the Notes -- Change of Control." Use of Proceeds............ The net proceeds we receive from the sale of the notes, together with our cash flows and borrowings under our bank credit facility, will be used to fund our remaining 1999 capital expenditure budget and a portion of our 2000 capital expenditure budget. Pending this use of the net proceeds, we will repay amounts under our bank credit facility, which may be reborrowed at a later date, and invest in short-term interest-bearing liquid investments. Trading.................... We have applied to list the notes on the New York Stock Exchange under the symbol " ". 6 8 SUMMARY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS) The following is our summary financial data. For further information that will help you better understand the summary data, see "Selected Financial Data."
THREE MONTHS ENDED MARCH 31, YEARS ENDED DECEMBER 31, ------------------- ------------------------------ 1999 1998 1998 1997 1996 -------- -------- -------- -------- -------- (UNAUDITED) STATEMENT OF OPERATIONS DATA: Revenues: Oil and gas sales..................... $ 7,969 $ 11,045 $ 35,624 $ 42,130 $ 25,764 Interest and other.................... 405 447 2,094 1,508 946 -------- -------- -------- -------- -------- Total revenues................ 8,374 11,492 37,718 43,638 26,710 -------- -------- -------- -------- -------- Costs and expenses: Lease operating expenses.............. 1,608 1,941 7,817 8,123 7,562 Depreciation, depletion and amortization....................... 3,963 5,570 19,284 16,488 9,832 General and administrative............ 1,061 1,502 5,285 4,433 3,495 Interest.............................. 1,027 651 1,925 1,957 313 Accelerated vesting and retirement benefits........................... -- -- 5,761 -- -- Impairment of oil and gas properties......................... -- -- 43,500 -- -- -------- -------- -------- -------- -------- Total costs and expenses...... 7,659 9,664 83,572 31,001 21,202 -------- -------- -------- -------- -------- Income (loss) from operations........... 715 1,828 (45,854) 12,637 5,508 Income tax expense (benefit).......... 243 621 (15,100) 4,200 50 -------- -------- -------- -------- -------- Net income (loss)....................... 472 1,207 (30,754) 8,437 5,458 Preferred stock dividends............... 831 699 2,779 2,795 2,795 -------- -------- -------- -------- -------- Net income (loss) available to common shares................................ $ (359) $ 508 $(33,533) $ 5,642 $ 2,663 ======== ======== ======== ======== ======== Net income (loss) per common share: Basic................................. $ (.04) $ .06 $ (4.17) $ .91 $ .46 Diluted............................... $ (.04) $ .06 $ (4.17) $ .88 $ .45 STATEMENT OF CASH FLOWS DATA: Cash provided by operating activities... $ 2,965 $ 9,147 $ 29,721 $ 27,337 $ 14,323 Cash used in investing activities....... 13,730 12,397 54,196 85,159 36,063 Cash provided by (used in) financing activities............................ 8,615 (673) 15,178 65,750 25,144 BALANCE SHEET DATA (END OF PERIOD): Working capital......................... $ 576 $ 7,880 $ 1,142 $ 12,719 $ 4,878 Oil and gas properties, net............. 151,963 111,213 141,905 150,494 82,489 Total assets............................ 188,457 191,615 181,652 190,421 118,520 Total debt.............................. 92,231 60,250 81,250 60,250 24,250 Stockholders' equity.................... 82,730 114,788 84,484 113,701 77,864 OTHER FINANCIAL DATA: Capital expenditures, net............... $ 13,730 $ 12,397 $ 54,196 $ 85,159 $ 36,063 EBITDA.................................. $ 6,116 $ 8,974 $ 27,564 $ 33,209 $ 16,138 Ratio of EBITDA to interest expense..... 10.7x 12.9x 14.3x 17.0x 51.6x Ratio of earnings to fixed charges...... -- 1.7x -- 3.3x 8.8x Ratio of total debt to EBITDA........... 3.7x 1.9x 2.9x 1.8x 1.5x
7 9 SUMMARY OPERATING AND RESERVE DATA The following is our summary operating and reserve data. For further information that will help you better understand the summary data, see "Selected Financial Data."
THREE MONTHS ENDED MARCH 31, YEARS ENDED DECEMBER 31, --------------- -------------------------- 1999 1998 1998 1997 1996 ------ ------ ------- ------- ------ (UNAUDITED) PRODUCTION: Oil (MBbls)..................................... 90 112 310 462 585 Gas (MMcf)...................................... 3,369 4,036 14,036 13,114 6,269 Total production (MMcfe)........................ 3,909 4,706 15,894 15,887 9,781 AVERAGE SALES PRICE: Oil (per Bbl)................................... $11.49 $13.85 $ 12.41 $ 18.63 $18.27 Gas (per Mcf)................................... 2.06 2.35 2.26 2.56 2.40 Total production (per Mcfe)..................... 2.04 2.35 2.24 2.65 2.63 AVERAGE COSTS (PER MCFE): Lease operating expenses (excluding severance taxes)........................................ $ .35 $ .34 $ .44 $ .42 $ .57 Severance taxes................................. .06 .07 .06 .09 .20 Depreciation, depletion and amortization........ 1.01 1.18 1.19 1.04 1.01 General and administrative (net of management fees)... .27 .32 .33 .28 .36
DECEMBER 31, JUNE 1, ------------------------------ 1999 1998 1997 1996 -------- -------- -------- -------- ESTIMATED NET PROVED RESERVES: Oil (MBbls)........................................ 13,051 6,898 3,402 3,819 Gas (MMcf)......................................... 104,973 88,030 88,738 50,424 Gas equivalent (MMcfe)............................. 183,277 129,418 109,150 73,338 Estimated future net cash flows before income taxes (000s)........................................... $280,980 $152,552 $209,260 $216,154 Discounted present value (000s).................... $173,917 $ 99,751 $136,448 $160,171 OTHER RESERVE DATA: Reserve replacement costs ($/Mcfe)................. $ .58 $ 1.29 $ 1.45 $ .73 Reserve life (years)............................... 12.1 8.1 6.9 7.5
8 10 RISK FACTORS You should carefully consider all of the information we have included in this document and the documents we have included or incorporated by reference before purchasing our notes. OUR SIGNIFICANT DEBT LEVELS AND OUR DEBT COVENANTS MAY LIMIT OUR FUTURE FLEXIBILITY IN OBTAINING ADDITIONAL FINANCING AND IN PURSUING BUSINESS OPPORTUNITIES. Assuming we had issued the notes and applied the proceeds as described in "Use of Proceeds" as of March 31, 1999, we would have had approximately $100.2 million in long-term debt. The level of our indebtedness will have important effects on our future operations, including: - A portion of our cash flow will be used to pay interest and principal on our debt and will not be available for other purposes. - Our bank credit facility contains financial tests which we must satisfy in order to continue to borrow funds under the facility. Failure to meet these tests may be a default under our bank credit facility. - Covenants in the notes and in our existing senior subordinated notes require us to meet financial tests in order to borrow additional money, which may have the effect of limiting our flexibility in reacting to changes in our business and our ability to fund future operations and acquisitions. - Our ability to obtain additional financing for capital expenditures and other purposes may be limited. We have included a more thorough discussion of the covenants in our bank credit facility and existing senior subordinated notes under "Description of Bank Credit Facility and Other Indebtedness." THERE MAY NOT BE SUFFICIENT ASSETS TO PAY AMOUNTS OWED ON THE NOTES IF A DEFAULT OCCURS. The notes will be subordinated to our current and future senior debt. In addition, the notes will rank equally with our existing and future senior subordinated indebtedness and will be subordinated to the obligations of our subsidiaries. Upon a liquidation or in a bankruptcy or other similar proceeding, the holders of our senior debt will be entitled to be paid in full before any payment may be made to the holders of the notes. In addition, creditors of our subsidiaries will be paid prior to any use of our subsidiaries' assets to make payments on the notes. As a result, the holders of notes may receive less, proportionately, than the holders of senior debt. We cannot make any assurances that we will have sufficient assets to pay amounts due on the notes. Our indenture for the notes permits us to incur additional debt in the future, including the entire amount that will be available for borrowing under our bank credit facility. THERE MAY NOT BE A LIQUID MARKET FOR RESALE OF THE NOTES. The notes will be new securities for which currently there is no trading market. Even though we have applied to list the notes on the New York Stock Exchange, we cannot assure you that a market for the notes will develop, or that the market will have sufficient liquidity to enable resale of the notes. WE MAY NOT BE ABLE TO REPURCHASE NOTES UPON A CHANGE OF CONTROL. If a change of control occurs, each holder of the notes will have the right to require us to repurchase all or any part of that holder's notes as described under "Description of the Notes -- Change of Control." Our bank credit facility prohibits the repurchase of the notes. In order to repurchase the notes, we would be required to repay our debt under our bank credit facility or obtain consents from our bank lenders. If we cannot repay the bank credit facility or obtain the consents, we would not be able to repurchase the notes. Also, we may not have sufficient funds available or be able to obtain the financing necessary to repurchase the notes. If a change of control occurs and we do not offer to repurchase the notes or if we do not repurchase the notes when we are required to, an event of default will occur under the indenture governing the notes, 9 11 which would also be a default under our bank credit facility and other senior subordinated notes. Each of these defaults could have a material adverse effect on us and the holders of the notes. OIL AND GAS PRICES ARE VOLATILE AND HAVE BEEN DEPRESSED RECENTLY. Our success is highly dependent on prices for oil and gas, which are extremely volatile. Beginning in 1997 and continuing through earlier this year, the prices we received for our production generally declined, especially for oil. Oil prices have recently recovered, but remain low by historic standards. Any additional substantial or extended decline in the price of oil or gas would have a material adverse effect on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on factors we cannot control such as weather, economic conditions and government actions. Prices of oil and gas will affect the following aspects of our business: - our revenues, cash flows and earnings; - our ability to attract capital to finance our operations and the cost of the capital; - the amount we are allowed to borrow under our bank credit facility; - the value of our oil and gas properties; and - the profit or loss we incur in exploring for and developing our reserves. WE MAY BE UNABLE TO REPLACE RESERVES WHICH WE HAVE PRODUCED. Our future success depends upon our ability to find, develop and acquire oil and gas reserves that are economically recoverable. As is generally the case in the Gulf Coast region, our producing properties usually have high initial production rates, followed by a steep decline in production. As a result, we must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We must do this even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance these activities. Without successful exploration or acquisition activities, our reserves, production and revenues will decline rapidly. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost. OUR FOCUS ON EXPLORATORY PROJECTS INCREASES THE RISKS INHERENT IN OUR OIL AND GAS ACTIVITIES. Our business strategy focuses on replacing reserves through exploration, where the risks are greater than in acquisitions and development drilling. Although we have been successful in exploration in the past, we cannot assure you that we will continue to increase reserves through exploration. WE DO NOT CONTROL ALL OF OUR OPERATIONS, ESPECIALLY OUR DEEP WATER OPERATIONS. We do not operate all of our properties and have limited influence over the operations of some of these properties, particularly our deep water projects. Our lack of control could result in the following: - the operator may initiate exploration or development on a faster or slower pace than we prefer; - the operator may propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which may mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid our share of exploration costs; and - if an operator refuses to initiate a project, we may be unable to pursue the project. Any of these events could reduce the value of our properties. COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT OPERATIONS. Exploration in the Gulf of Mexico has recently received renewed interest, especially among major and large independent oil companies. The acquisition of exploration prospects, producing properties and 10 12 production facilities in the Gulf of Mexico is highly competitive. Factors which affect our ability to successfully compete are: - our access to the capital necessary to drill wells and acquire properties; - our access to seismic, geological and other information, and our ability to retain the personnel necessary to properly evaluate such information; - the location of, and our ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production; and - the standards we establish for the minimum projected return on an investment of our capital. Our competitors include major integrated oil companies and large independent energy companies, many of which have greater financial and other resources. WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE UNABLE TO RAISE CAPITAL. We will be required to make substantial capital expenditures to develop our existing reserves, and to discover new oil and gas reserves. Historically, we have financed these expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from the sale of debt and equity securities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Capital Expenditures" for a discussion of our capital budget. We cannot assure you that we will be able to raise capital in the future. We also make offers to acquire oil and gas properties in the ordinary course of our business. If these offers are accepted, our capital needs may increase substantially. INFORMATION IN THIS PROSPECTUS REGARDING OUR PROSPECTS REFLECTS OUR CURRENT INTENT AND IS SUBJECT TO CHANGE. We describe our current prospects and our plans to explore these prospects in this prospectus. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect which will require substantial additional seismic data processing and interpretation. Whether we ultimately drill a prospect may depend on the following factors: - receipt of additional seismic data or the reprocessing of existing data; - material changes in oil or gas prices or the costs and availability of drilling rigs; - success or failure of wells drilled in similar formations or which would use the same production facilities; - availability and cost of capital; - changes in the estimates of the costs to drill or complete wells; - our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; and - decisions of our joint working interest owners. We will continue to gather data about our prospects, and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all. You should understand that our plans regarding our prospects are subject to change. YOU SHOULD NOT PLACE UNDUE RELIANCE ON RESERVE INFORMATION BECAUSE RESERVE INFORMATION REPRESENTS ESTIMATES. 11 13 Estimating quantities of proved reserves is inherently imprecise and involves uncertainties and factors beyond our control. The reserve data in this prospectus represent only estimates. Such estimates are based upon assumptions about future production levels, future oil and gas prices and future operating costs. As a result, the quantity of proved reserves may be subject to downward or upward adjustment. In addition, estimates of the economically recoverable oil and gas reserves, classifications of such reserves, and estimates of future net cash flows, prepared by different engineers or by the same engineers at different times, may vary substantially. Information about reserves constitutes forward-looking information. See "Forward-Looking Statements" for information regarding forward-looking information. WEATHER, UNEXPECTED SUBSURFACE CONDITIONS, AND OTHER UNFORESEEN OPERATING HAZARDS MAY ADVERSELY IMPACT OUR ABILITY TO CONDUCT BUSINESS. There are many operating hazards in exploring for and producing oil and gas, including: - our drilling operations may encounter unexpected formations or pressures which could cause damage to equipment or personal injury; - we may experience equipment failure which curtails or stops production; and - we could experience blowouts or other damages to the productive formations which may require a well to be re-drilled or other corrective action to be taken. In addition, any of the foregoing may result in environmental damages for which we will be liable. Moreover, a substantial portion of our operations are offshore and are subject to a variety of risks peculiar to the marine environment such as hurricanes and other adverse weather conditions. Offshore operations are also subject to more extensive governmental regulation. We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations. THE RECENT DEPRESSED FINANCIAL CONDITIONS IN THE OIL AND GAS INDUSTRY MAY CHANGE EXPLORATION AND DEVELOPMENT PLANS OR CAUSE DIFFICULTIES IN FINANCING ACTIVITIES. The recent low prices for oil and gas have limited the access of many independent oil and gas companies to the capital necessary to finance activities. Most oil companies have substantially reduced their capital budgets for 1999 and 2000. As a result, the decision not to drill or complete a well may be made based on a lack of available capital rather than the quality of the project. For projects operated by others, we may be unable to control decisions regarding drilling and completion operations even if those decisions are made based on capital constraints. In addition, some of the other working interest owners of our wells may be unwilling or unable to pay their share of the costs of projects as they become due. At worst, a working interest owner may declare bankruptcy and refuse or be unable to pay its share of the cost of a project. In such cases, we could be required to pay other working interest owner's share of the costs. WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT FROM PRICE INCREASES. Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by hedging a portion of our production. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Financial Instruments" for a discussion of our hedging practices. In a typical hedge transaction, we will have the right to receive from the other parties 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, we are required to pay the other parties this difference multiplied by the quantity hedged. We are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price 12 14 regardless of whether we have 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 us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY AND COULD NEGATIVELY IMPACT PRODUCTION. Our 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 that we acquire permits before commencing drilling; - restrict the substances that can be released into the environment in connection with drilling and production activities; - limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; and - require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells. Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Moreover, we do 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, we may be subject to liability or we may be required to cease production from properties in the event of environmental damages. FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION. The ability to market oil and gas from our wells depends upon numerous factors beyond our control. These factors include: - the extent of domestic production and imports of oil and gas; - the proximity of the gas production to gas pipelines; - the availability of pipeline capacity; - the demand for oil and gas by utilities and other end users; - the availability of alternative fuel sources; - the effects of inclement weather; - state and federal regulation of oil and gas marketing; and - federal regulation of gas sold or transported in interstate commerce. Because of these factors, we may be unable to market all of the oil or gas we produce. In addition, we may be unable to obtain favorable prices for the oil and gas we produce. WE FACE A THREAT OF BUSINESS DISRUPTION FROM THE YEAR 2000 ISSUE. The year 2000 issue refers to the inability of computer and other information technology systems to properly process date and time information, stemming from the outdated programming practice of using two digits rather than four to represent the year in a date. The consequence of the year 2000 issue is that 13 15 computer and embedded processing systems are at risk of malfunctioning, particularly during the transition from 1999 to 2000. The effects of the year 2000 issue are exacerbated by the interdependence of computer and telecommunications systems throughout the world. This interdependence also exists among Callon and our vendors, customers and business partners, as well as with regulators in the United States. Our operations are highly dependant on automation. The risks to us associated with the year 2000 issue fall into three general areas: - Failure of our financial and administrative systems which could result in our receiving incorrect information upon which we base decisions; - Failure of the embedded systems which control our highly automated production facilities; and - Failure of our suppliers and purchasers to correct their year 2000 problems. For a description of the steps we have taken to address the year 2000 issue, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Year 2000 Compliance." FORWARD-LOOKING STATEMENTS In this prospectus, we have made many forward-looking statements. We cannot assure you that the plans, intentions or expectations upon which our forward-looking statements are based will occur. Our forward-looking statements are subject to risks, uncertainties and assumptions, including those discussed elsewhere in this prospectus and the documents that are incorporated by reference into this prospectus. Some of the risks which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include: - the volatility of oil and natural gas prices; - the uncertainty of estimates of oil and natural gas reserves; - the impact of competition; - difficulties encountered during the exploration for and production of oil and natural gas; - the difficulties encountered in delivering oil and natural gas to commercial markets; - changes in customer demand; - the uncertainty of our ability to attract capital; - changes in the extensive government regulations regarding the oil and natural gas business; and - compliance with environmental regulations. The information contained in this prospectus, including the information set forth under the heading "Risk Factors," identifies additional factors that could affect our operating results and performance. We urge you to carefully consider those factors. Our forward-looking statements are expressly qualified in their entirety by this cautionary statement. 14 16 USE OF PROCEEDS We expect to receive approximately $ million of net proceeds from this offering after deducting the underwriters' discount and estimated offering expenses. We intend to use all of the net proceeds, together with our cash flows and borrowings under our bank credit facility, to fund our remaining 1999 capital expenditure budget, estimated to be $35.4 million, and a portion of our 2000 capital expenditure budget. For a more detailed description of our capital expenditure budget, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Pending the use of funds to pay capital expenditures, we will use the net proceeds from the sale of the notes to repay borrowings under our bank credit facility. To the extent proceeds are in excess of amounts outstanding under our bank credit facility, we will invest in short-term, interest-bearing, liquid investments. As of June 1, 1999, borrowings of $35.1 million were outstanding under our bank credit facility, with a weighted average interest rate of 6.57%. CAPITALIZATION The following table sets forth our capitalization, as of March 31, 1999, and as adjusted to give effect to the sale of the notes and the application of the estimated net proceeds. For a description of the application of the net proceeds, see "Use of Proceeds." You should read this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and notes thereto included and incorporated by reference in this document. As of June 1, 1999, the outstanding balance under our bank credit facility was $35.1 million.
MARCH 31, 1999 --------------------- AS HISTORICAL ADJUSTED ---------- -------- (IN THOUSANDS) Cash and cash equivalents................................... $ 4,150 $ ======== ======== Long-term debt: Credit facility........................................... $ 26,100 $ 10% senior subordinated notes............................. 24,150 10.125% senior subordinated notes......................... 36,000 The notes offered hereby.................................. -- Stockholders' equity: Preferred stock, $0.01 par value, 2,500,000 shares authorized; 1,045,461 shares of Convertible Exchangeable Preferred Stock, Series A issued and outstanding with a liquidation preference of $26,136,525............................................ 10 10 Common stock, $0.01 par value, 20,000,000 shares authorized; 8,545,517 shares outstanding............... 85 85 Treasury stock (98,577 shares at cost).................... (1,177) (1,177) Capital in excess of par value............................ 108,296 108,296 Retained earnings (deficit)............................... (24,484) (24,484) -------- -------- Total stockholders' equity........................ 82,730 82,730 -------- -------- Total capitalization.............................. $168,980 $ ======== ========
15 17 SELECTED FINANCIAL DATA The following table shows selected financial data for the five years ended December 31, 1998 and for the three months ended March 31, 1999 and 1998. The financial data for each of the three years in the period ended December 31, 1998 has been derived from our audited consolidated financial statements for these periods which are included and incorporated by reference in this prospectus. The financial data for the years ended December 31, 1995 and 1994 have been derived from our audited financial statements. The financial data for each of the three-month periods ended March 31, 1999 and 1998 has been derived from our unaudited consolidated financial statements for these periods which are also included in this prospectus. You should read this data in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and notes thereto included and incorporated by reference in this document. The selected financial data is not necessarily indicative of our future results. The following information will help you to better understand the selected and summary financial data. - Callon was formed on September 16, 1994. Historical information prior to September 16, 1994 includes financial and operating information of our predecessors. - EBITDA is earnings before interest expense, income tax expense, depreciation, depletion, amortization and other non-cash charges. EBITDA is presented because it is a widely accepted financial indication of a company's ability to service and incur debt. EBITDA should not be considered as an alternative to earnings (loss) as an indicator of our operating performance or to cash flow as a measure of liquidity. - EBITDA, used in the debt to EBITDA ratio and the EBITDA to interest expense ratio, is calculated using EBITDA for the immediately preceding four quarters. Interest expense, used in the EBITDA to interest expense ratio, is calculated using interest expense for the immediately preceding four quarters. - For purposes of computing the ratio of earnings to fixed charges, "earnings" are composed of the following: - consolidated earnings or loss from continuing operations before tax, excluding undistributed equity earnings of affiliated companies; plus - fixed charges, excluding capitalized interest. Fixed charges are comprised of the following: - interest expense on indebtedness and capitalized interest; - amortization of debt issuance costs, discounts and premiums; and - that portion of capital lease expense which is deemed to be representative of an interest factor. Earnings did not cover fixed charges by $262,000 in the first quarter of 1999, $45.9 million in 1998 and $313,000 in 1994. - We use the full-cost method of accounting. Under this method of accounting, our net capitalized costs to acquire, explore and develop oil and gas properties may not exceed the standardized measure of our proved reserves. If these capitalized costs exceed the standardized measure, the excess is charged to expense. As a result of the significant decline in oil and gas prices, we recorded a non-cash impairment expense related to our oil and gas properties in the amount of $43.5 million ($28.7 million after-tax) during the fourth quarter of 1998. The process used to calculate the standardized measure is described under "Glossary of Oil and Gas Terms." 16 18
THREE MONTHS ENDED MARCH 31, YEARS ENDED DECEMBER 31, ------------------- -------------------------------------------------- 1999 1998 1998 1997 1996 1995 1994 -------- -------- -------- -------- -------- ------- ------- (UNAUDITED) (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS) STATEMENT OF OPERATIONS DATA: Revenues: Oil and gas sales.......... $ 7,969 $ 11,045 $ 35,624 $ 42,130 $ 25,764 $23,210 $13,948 Interest and other......... 405 447 2,094 1,508 946 627 171 -------- -------- -------- -------- -------- ------- ------- Total revenues........ 8,374 11,492 37,718 43,638 26,710 23,837 14,119 -------- -------- -------- -------- -------- ------- ------- Costs and expenses: Lease operating expenses... 1,608 1,941 7,817 8,123 7,562 6,732 4,042 Depreciation, depletion and amortization............. 3,963 5,570 19,284 16,488 9,832 10,376 6,049 General and administrative........... 1,061 1,502 5,285 4,433 3,495 3,880 3,717 Interest................... 1,027 651 1,925 1,957 313 1,794 624 Accelerated vesting and retirement benefits...... -- -- 5,761 -- -- -- -- Impairment of oil and gas properties............... -- -- 43,500 -- -- -- -- -------- -------- -------- -------- -------- ------- ------- Total costs and expenses............ 7,659 9,664 83,572 31,001 21,202 22,782 14,432 -------- -------- -------- -------- -------- ------- ------- Income (loss) from operations................. 715 1,828 (45,854) 12,637 5,508 1,055 (313) Income tax expense (benefit)................ 243 621 (15,100) 4,200 50 -- (200) -------- -------- -------- -------- -------- ------- ------- Net income (loss)............ 472 1,207 (30,754) 8,437 5,458 1,055 (113) Preferred stock dividends.... 831 699 2,779 2,795 2,795 256 -- -------- -------- -------- -------- -------- ------- ------- Net income (loss) available to common shares........... $ (359) $ 508 $(33,533) $ 5,642 $ 2,663 $ 799 $ (113) ======== ======== ======== ======== ======== ======= ======= Net income (loss) per common share: Basic...................... $ (.04) $ .06 $ (4.17) $ .91 $ .46 $ .14 $ (.03) Diluted.................... $ (.04) $ .06 $ (4.17) $ .88 $ .45 $ .14 $ (.03) Shares used in computing net income (loss) per common share: Basic...................... 8,477 8,015 8,034 6,194 5,835 5,755 4,346 Diluted.................... 8,477 8,221 8,034 6,422 5,952 5,755 4,346 STATEMENT OF CASH FLOWS DATA: Cash provided by operating activities................. $ 2,965 $ 9,147 $ 29,721 $ 27,337 $ 14,323 $ 9,452 $ 5,347 Cash used in investing activities................. 13,730 12,397 54,196 85,159 36,063 24,237 6,423 Cash provided by (used in) financing activities....... 8,615 (673) 15,178 65,750 25,144 11,765 3,916 BALANCE SHEET DATA (END OF PERIOD): Working capital.............. $ 576 $ 7,880 $ 1,142 $ 12,719 $ 4,878 $ 4,712 $ 1,896 Oil and gas properties, net........................ 151,963 111,213 141,905 150,494 82,489 57,765 43,920 Total assets................. 188,457 191,615 181,652 190,421 118,520 83,867 73,786 Total debt................... 92,231 60,250 81,250 60,250 24,250 100 15,363 Stockholders' equity......... 82,730 114,788 84,484 113,701 77,864 75,129 43,431 OTHER FINANCIAL DATA: Capital expenditures, net.... $ 13,730 $ 12,397 $ 54,196 $ 85,159 $ 36,063 $24,237 $10,412 EBITDA....................... $ 6,116 $ 8,974 $ 27,564 $ 33,209 $ 16,138 $13,582 $ 6,727 Ratio of EBITDA to interest expense.................... 10.7x 12.9x 14.3x 17.0x 51.6x 7.6x 10.8x Ratio of earnings to fixed charges.................... -- 1.7x -- 3.3x 8.8x 1.6x -- Ratio of total debt to EBITDA..................... 3.7x 1.9x 2.9x 1.8x 1.5x .0x 2.9x
17 19 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS Our results of operations are primarily influenced by the prices we receive for oil and gas production and the costs we incur to produce oil and gas. The following table shows information about our prices and costs. Prices shown below include the effects of our hedging activities.
THREE MONTHS ENDED MARCH 31, YEARS ENDED DECEMBER 31, --------------- -------------------------- 1999 1998 1998 1997 1996 ------ ------ ------- ------- ------ PRODUCTION: Oil (MBbls)................................... 90 112 310 462 585 Gas (MMcf).................................... 3,369 4,036 14,036 13,114 6,269 Total production (MMcfe)...................... 3,909 4,706 15,894 15,887 9,781 AVERAGE SALES PRICE: Oil (per Bbl)................................. $11.49 $13.85 $ 12.41 $ 18.63 $18.27 Gas (per Mcf)................................. 2.06 2.35 2.26 2.56 2.40 Total production (per Mcfe)................... 2.04 2.35 2.24 2.65 2.63 AVERAGE COSTS (PER MCFE): Lease operating expenses (excluding severance taxes)..................................... $ .35 $ .34 $ .44 $ .42 $ .57 Severance taxes............................... .06 .07 .06 .09 .20 Depreciation, depletion and amortization...... 1.01 1.18 1.19 1.04 1.01 General and administrative (net of management fees)...................................... .27 .32 .33 .28 .36
Since 1996, we have completed several acquisitions that have significantly affected our results of operations. Through a series of four transactions, we acquired 52.5 Bcf of estimated net proved reserves in the Mobile Block 864 area for a total acquisition cost of $48.7 million. In June 1999, in exchange for a production payment, we acquired Murphy's interest in several wells and undeveloped acreage in this area which, prior to exploration and development activities, has added an additional 15.6 Bcf of estimated net proved reserves. Our results in 1998 were also affected by the sale of our Black Bay Complex properties which are located in Louisiana state waters. We sold these properties in April 1998 for $9.4 million, the proceeds of which were used to repay amounts outstanding under our revolving credit facility. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our results of operations in the future. Comparison of Results of Operations for the Three Months Ended March 31, 1999 and 1998 Our oil and gas revenues for the first three months of 1999 were $8.0 million, a 28% reduction from $11.0 million for the same period in 1998. On a Mcfe basis, our first quarter 1999 production decreased 17% from 4.7 Bcfe in 1998 to 3.9 Bcfe in 1999. Our revenues were further reduced by the 13% reduction in average sales price per Mcfe. Oil production during the first quarter of 1999 totaled 90.0 MBbls and generated $1.0 million in revenues compared to 112.0 MBbls and $1.5 million in revenues for the same period in 1998. The reduction in revenues during the 1999 period resulted from a 17% reduction in the average sales price received and a 20% lower production rate. Average oil prices, including the effects of hedging, received in the first quarter of 1999 were $11.49 compared to $13.85 in the first quarter of 1998. The first quarter average daily oil production decreased from 1.2 MBbls per day in 1998 to 1.0 MBbls per day in 1999. 18 20 Approximately 442.0 Bbls per day of the reduced production was attributable to the sale of the Black Bay Complex which was partially offset by the addition of approximately 22.0 MBbls of oil from our discoveries in the OCS area. Other properties also experienced a natural decline in production. Gas production volumes during the first quarter of 1998 totaled 4.0 Bcf and generated $9.5 million in revenues compared with 3.4 Bcf and $6.9 million in revenues during the same period in 1999. The first quarter average daily gas production decreased from 44.8 MMcf per day in 1998 to 37.4 MMcf per day in 1999. The average sales price (including the effects of hedging) for the first quarter of 1999 was $2.06 per Mcf compared with $2.35 per Mcf for the same period of 1998. The reduced production volumes were caused by the expected decline curves of our shallow Miocene and OCS properties. Lease operating expenses, including severance taxes, for the three-month period ended March 31, 1999 were $1.6 million, a decrease from the $1.9 million for the three-month period ended March 31, 1998. On a per Mcfe basis, these combined expenses remained at $0.41 as a result of lower production volumes and proportionate decreases in field operating costs. Depreciation, depletion and amortization for the three month periods ended March 31, 1999 and 1998 were $4.0 million and $5.6 million, respectively. This decrease reflects decreased production volumes and a lower overall rate per Mcfe, primarily as a result of a fourth quarter 1998 full-cost ceiling impairment. For the three-month period ended March 31, 1999, the per Mcfe amount was $1.01 compared to $1.18 for the same period in 1998. General and administrative expenses for the three-month period ended March 31, 1999 were $1.0 million compared to $1.5 million for the three-month period ended March 31, 1998. This reduction was attributable to the fact that first quarter 1999 expenses did not include any charges for bonuses under the incentive compensation plan nor amortization of expenses associated with the vesting of performance shares. On a per Mcfe basis, general and administrative expenses decreased from $0.32 in the first quarter of 1998 to $0.27 in the first quarter of 1999. Interest expense for the first quarter of 1999 increased as a result of increased long-term debt when compared to the first quarter debt level in 1998. For the period ended March 31, 1999, interest expense was $1.0 million compared to $0.7 million for the first quarter of 1998, net of interest capitalized as property costs. Income taxes were provided at the expected statutory rate of 34% of net income for both periods. Preferred stock dividends were $0.8 million for the first quarter of 1999 as compared to $0.7 million for the first quarter of 1998. During the first quarter of 1999, several preferred stockholders, through private transactions, agreed to convert 210,350 shares of series A preferred stock into 502,632 shares of our common stock. Of these shares of common stock, 24,507 were, as a result of private negotiations between us and the holders, issued in excess of the conversion rate. These additional shares are treated as a non-cash dividend on the preferred stock for accounting purposes and were valued by taking the market value of the shares on the date of conversion. Cash dividends on the series A preferred stock will be lower in future quarters since the number of shares outstanding has been reduced. Comparison of Results of Operations for the Years Ended December 31, 1998 and 1997 Our oil and gas revenues for 1998 were $35.6 million, a 15% reduction from $42.1 million in 1997. On a Mcfe basis, our 1998 production was the same as that reported for 1997. The reduction in our revenues was attributable to the 15% reduction in average sales price (including the effects of hedging) per Mcfe. Oil revenues declined from $8.6 million to $3.8 million. This decline was caused in part by reduced oil production, which declined from 462.0 MBbls in 1997 to 310.0 MBbls in 1998 and a decline in average sales prices (including the effects of hedging) from $18.63 in 1997 to $12.41 in 1998. Approximately 5% of the reduced production was attributable to the sale of the Black Bay Complex in 1998, and the remainder was attributable to normal production declines. 19 21 Our gas revenues for 1998 were $31.8 million, a reduction of 5% from 1997 revenues of $33.5 million. Gas production in 1998 was 14.0 Bcf, an increase of 7% over 1997 production of 13.1 Bcf. The increase in production was attributable to the beginning of production from exploration successes in 1998. The increases in production were more than offset by a reduction in average prices (including the effects of hedging) from $2.56 per Mcf in 1997 to $2.26 in 1998. Our lease operating expenses, including severance taxes, decreased from $8.1 million in 1997 to $7.8 million in 1998. This decrease was attributable to reduced severance taxes which declined from $1.4 million in 1997 to $0.9 million in 1998 because more of our production was from federal waters where we do not incur severance taxes. The other components of operating expenses increased from $6.7 million in 1997 to $6.9 million in 1998 as a result of a full year of costs associated with acquisitions in the fourth quarter of 1997 partially offset by a reduction due to the sale of the Black Bay Complex. Depreciation, depletion and amortization increased as a higher rate was applied to a relatively constant production volume. Total charges increased from $16.5 million, or $1.04 per Mcfe, in 1997 to $19.3 million, or $1.19 per Mcfe in 1998. The increase in the noncash charge per Mcfe reflects the increase in investment in evaluated oil and gas properties during 1998. Our general and administrative expenses for 1998 were $5.3 million, or $.33 per Mcfe, compared to $4.4 million, or $.28 per Mcfe, in 1997. This 19% increase is primarily the result of the loss of Black Bay management fees, which previously reduced general and administrative expenses, and slightly higher normal corporate expenses. Interest expense was $1.9 million for 1998 and $2.0 million for 1997. In December 1998, we recorded a charge of $5.8 million attributable to the accelerated vesting of the remaining performance shares previously granted under our stock option plans and of retirement benefits. Under the full-cost method of accounting, the net capitalized costs of proved oil and gas properties are subject to a "ceiling test," which limits such costs to the discounted present value, net of related tax effects, of proved reserves. If capitalized costs exceed this limit, the excess is charged to expense. During the fourth quarter of 1998, we recorded a noncash impairment provision related to oil and gas properties in the amount of $43.5 million ($28.7 million after-tax) primarily due to the significant decline in oil and gas prices. Our 1998 results included a deferred income tax benefit of $15.1 million primarily due to the $14.8 million deferred income tax benefit related to impairment of oil and gas properties recorded in 1998. We expect to realize this benefit for tax purposes in future years by utilizing our net operating loss and statutory depletion carryforwards. We have evaluated the potential realization of the deferred income tax benefit recorded above in light of our reserve quantity estimates, our long-term outlook for oil and gas prices and our expected level of other future expenses. We believe it is more likely than not, based upon this evaluation, that we will realize the recorded deferred income tax asset. However, we cannot assure you that such asset will ultimately be realized. Comparison of Results of Operations for the Years Ended December 31, 1997 and 1996 Our total oil and gas revenues increased $16.4 million, or 63%, during 1997 to $42.1 million compared to $25.8 million in 1996. This increase in oil and gas revenues was the result of increased gas production volumes and increased average sales prices (including the effects of hedging) for both oil and gas. Our oil revenues for 1997 were $8.6 million based on production volume of 462.0 MBbls sold at an average sales price of $18.63 per Bbl. For 1996, our revenues were $10.7 million based on 585.0 MBbls of oil sold at an average sales price (including the effects of hedging) of $18.27. The $2.1 million decline in oil revenues was largely attributed to normal production declines from several of our oil producing properties, as well as the divestiture of certain non-core properties. Our gas revenues for 1997 were $33.5 million from production volumes of 13.1 Bcf of gas sold at an average sales price of $2.56 per Mcf. For 1996, our revenues were $15.1 million from the production of 20 22 6.3 Bcf of gas sold at an average sales price (including the effects of hedging) of $2.40. The 109% increase in production volume was largely attributed to our 1996 discoveries in the OCS and shallow Miocene areas. Lease operating expenses, including severance taxes, increased from $7.6 million in 1996 to $8.1 million in 1997. Separately, severance taxes declined from $1.9 million in 1996 to $1.4 million in 1997 as a result of lower production on properties subject to severance taxes. Other operating expenses increased from $5.6 million in 1996 to $6.7 million in 1997 as a result of the new offshore producing properties. On a per Mcfe basis, these combined expenses decreased from $0.77 in 1996 to $0.51 in 1997. Depreciation, depletion and amortization for 1997 totaled $16.5 million, or $1.04 per Mcfe. For the same period in 1996, these expenses totaled $9.8 million, or $1.01 per Mcfe. Our general and administrative expenses for 1997 were $4.4 million, a 27% increase from the $3.5 million in 1996 as a result of expanded levels of operations and production. On a per Mcfe basis, these expenses decreased from $.36 in 1996 to $.28 in 1997. Interest expense for 1997 was $2.0 million. The substantial increase from the $.3 million in 1996 was reflective of the issuance of notes in November 1996 and July 1997. Income tax expense for 1997 was $4.2 million. This amount represented the approximate statutory income tax rate, as adjusted for expected future utilization of our net operating losses and depletion carryovers. For 1996, the statutory income tax was $1.9 million, which was primarily offset by a reduction in the deferred tax asset valuation allowance. LIQUIDITY AND CAPITAL RESOURCES Capital Sources Our primary sources of capital are cash flows from operations, borrowings under our bank credit facility, and sales of debt and equity securities. Cash flow from operations before working capital changes for the first quarter of 1999 and 1998 totaled $5.1 million and $8.3 million, respectively. During the first three months of 1999, borrowings under our credit facility increased by $8.0 million. Borrowings under the credit facility increased $18.0 million during 1998. Also during 1998, we sold properties in the Black Bay Complex for net cash proceeds of $9.4 million, which was used to reduce the amount outstanding under our credit facility. Bank credit facility. Borrowings under the bank credit facility are secured by mortgages covering substantially all of our producing oil and gas properties. The credit facility provides for a borrowing base which is adjusted periodically on the basis of the discounted present value attributable to our proved producing oil and gas reserves, as determined by the bank. The credit facility currently provides for a $50.0 million borrowing base. The borrowing base is currently being reevaluated with the bank. We expect that upon the closing of the sale of the notes, the borrowing base will be decreased. We may borrow, pay, reborrow and repay under the credit facility until October 31, 2000, on which date we must repay in full all amounts then outstanding. At June 1, 1999, the amount available to be borrowed under our credit facility was $14.9 million. See "Description of Bank Credit Facility and Other Indebtedness -- Bank Credit Facility" for more information about the credit facility. Material sales of debt and equity securities. In November 1996, we issued $24.2 million of 10% senior subordinated notes and in July 1997, we issued $36 million of 10.125% senior subordinated notes for total net proceeds of $58.4 million. The proceeds of the note offerings were used to repay outstanding amounts under the bank credit facility. See "Description of Bank Credit Facility and Other Indebtedness -- Outstanding Notes" for additional information about our outstanding notes. On November 25, 1997, we sold 1.8 million shares of our common stock to the public for total net proceeds of $29.3 million. We used a portion of the proceeds to repay indebtedness incurred to finance the purchase of properties in the shallow Miocene area and the balance to fund a portion of our 1998 capital expenditure budget. 21 23 Capital Expenditures Capital expenditures for the first three months of 1999 and for the year 1998 were $14.0 million and $64.1 million, respectively. The 1999 amounts were used primarily to drill and complete four wells, and to complete two previously drilled wells. The 1998 amount included $9.5 million for the acquisition of producing properties and equipment, $47.0 million for property development and drilling activities and $7.3 million for the acquisition of oil and gas properties for exploration. Our capital expenditure budget for the last three quarters of 1999 is $35.4 million. The major portion of the capital expenditure budget will be used to drill and complete seven exploration wells. The total estimated 1999 dry hole costs to drill these wells are $12.2 million, and the total costs to complete these wells are $11.6 million. The timing and cost to drill these wells will depend upon numerous factors, many of which are beyond our control. In addition, we have a non-cash expenditure related to the acquisition of Murphy's interest in Mobile Block 864. We acquired Murphy's interest for approximately $15.0 million, financed by a volumetric production payment. We make offers for producing properties in the ordinary course of our business. If we were to purchase a producing property, our capital budget could change materially. Financial Instruments We periodically use derivative financial instruments to hedge oil and gas price risks. In a typical hedge transaction, we will have the right to receive from counterparties 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, we are required to pay the counterparties the difference multiplied by the quantity hedged. We are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. If there are significant reductions in production at times when the floating price exceeds the fixed price, we could be required to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. We also enter into price "collars" to reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the difference. We enter into hedge transactions to reduce the effect of volatile oil and gas prices, and do not enter into hedge transactions for speculative purposes. As of March 31, 1999, we had hedged approximately 483.0 MMcf per month through September 1999, representing 39.0% of our estimated gas production during this period, pursuant to price collars, with an average NYMEX floor price of $1.85 per MMBtu (NYMEX) and an average ceiling price of $2.12 per MMBtu. Also at March 31, 1999, we had open forward natural gas swap contracts of 200 MMcf per month from April 1999 through September 1999, representing 16.0% of our estimated gas production during this period, at a fixed contract average price of $2.35. In addition, we had oil price collar contracts for 24.2 MBbls per month from April 1999 through December 1999, representing 78.0% of our estimated oil production during this period, at a ceiling price of $16.15 and a floor of $13.78. We also had crude oil swap contracts of 10 MBbls per month with a fixed contract price of $14.10 per month from April 1999 through June 1999, representing 34.0% of our estimated oil production during this period. YEAR 2000 COMPLIANCE Three years ago, we began our efforts to address the threats to our business posed by the year 2000 issue. For a description of the business disruption risks we face from the year 2000 issue, see "Risk Factors." Overseeing the year 2000 project is the Callon Year 2000 Project Committee which meets on a 22 24 periodic basis to review project status, provide necessary management input and resolve project issues on a timely basis. A formal review is presented to our board of directors periodically. Our plan is divided into three phases. Phase one involves a physical inventory of all hardware, software and devices containing date-oriented firmware. Phase two requires that we prioritize issues, obtain or devise solutions and make repairs or replace equipment as necessary. The third phase of the plan calls for the development of contingency plans to address, among other things, the failure of our business partners to adequately address their year 2000 problems. We have completed phase one and have substantially completed phase two. We are continuing to work on phase three and expect completion in the third quarter of 1999. Accounting systems. Our core financial accounting software is maintained by one major vendor of oil and gas industry software. The vendor has indicated that it believes our system is year 2000 compliant. Embedded chips. A substantial portion of our exploration and production facilities are automated. These facilities rely on one or more "embedded chips" to control and measure flow rates, pressures, emissions and other critical functions. Failure of embedded chips may cause production to stop, spills of hydrocarbons or other materials and other problems. This problem is complicated because many of the embedded chips are linked in systems, where the failure of one part of the system will adversely affect the entire facility. We believe we have identified all of the embedded systems affecting our material facilities, tested them for year 2000 compliance and made appropriate remediation. We therefore do not expect that our embedded systems will suffer material interruptions caused by year 2000 related failures of our systems. It must be noted, however, that our facilities have numerous embedded chips many of which are not easy to locate. In addition, while we believe the testing of chips will uncover year 2000 failures, until the year 2000 occurs, there is no way to be sure that the repairs we made will work, or that all of the embedded chips which must work together in systems will function properly. Because of the complexity of the year 2000 problem, we cannot assure you that we will not have a material business interruption caused by the year 2000 problem. Vendors and customers. We could be adversely affected if our suppliers, customers or other business partners experience year 2000 failures. For example, if our electrical supplier fails to deliver electricity to our facilities or if refineries are unable to receive our oil production, we will suffer losses. We have requested information from all of our material business partners regarding their year 2000 readiness. It appears that all of our material business partners are aware of the year 2000 issues and are attempting to uncover and remedy potential failures. Where we were not satisfied with the results of our inquiries, we are attempting to develop contingency plans. However, we do not believe contingency plans will protect us from loss if there are material year 2000 failures of our business partners. Additionally, we are unable to independently verify that our business partners are, in fact, taking appropriate steps to remedy problems. Accordingly, no assurances can be made that year 2000 failures will not adversely affect our business. Estimated compliance costs. Our total costs incurred to date and estimated remaining costs for consultants, software and hardware applications for the year 2000 project are less than $200,000. We do not separately account for the internal costs incurred for our year 2000 compliance efforts, which consist principally of payroll and related benefits for our informations system personnel. Risks of non-compliance. The most reasonably likely "worst case" impact of the year 2000 issue on our operations could be: - hydrocarbon spills or other accidents which could result in environmental pollution, personal injuries or loss of life; - equipment failures which could curtail, delay or cancel our operations; - impairment of our ability to deliver our production to, or receive payment from, third parties gathering and/or purchasing our production from affected facilities; 23 25 - impairment of the ability of third-party suppliers or service companies to provide needed materials or services to our planned or ongoing operations, thereby necessitating deferral or shut-in of our operations; and - our inability to execute financial transactions with our banks or other third parties whose systems fail or malfunction. We have no reason to believe that any of these contingencies will occur or that our principal vendors, customers and business partners will not be year 2000 compliant. DISCLOSURES ABOUT MARKET RISKS Our revenues are derived from the sale of our oil and natural gas. The prices of oil and gas are extremely volatile, and experience large fluctuations as a result of relatively small changes in supplies. For a description of the effects of the volatility of oil and gas prices on our operations, see "Risk Factors." From time to time we enter into arrangements to reduce the effect of changes in oil and gas prices upon our revenues as described above under "Liquidity and Capital Resources -- Financial Instruments." 24 26 BUSINESS AND PROPERTIES Callon has been engaged in the exploration, development, acquisition and production of oil and gas in the Gulf Coast region since 1950. Our properties and operations are geographically concentrated in the offshore waters of the Gulf of Mexico where we have substantial experience. As of June 1, 1999, we had estimated net proved reserves of 183.3 Bcfe which had a discounted present value of $173.9 million. Reserves comprising 72% of this discounted present value were classified as proved developed. Average daily net production during the first quarter of 1999 was 43.4 MMcfe, of which 86% was natural gas. We operate wells representing 82% of this production. Net proved reserves as of June 1, 1999 divided by our production from the four quarters ended March 31, 1999, sometimes referred to as our "reserve life," was 12.1 years. Our reserves and production have grown rapidly since 1996 as a result of exploration and development drilling, as well as property acquisitions. Between January 1, 1996 and June 1, 1999, estimated net proved reserves increased 215%, and average daily net production increased 70% from the first quarter of 1996 to the first quarter of 1999. Our activities are concentrated in the Gulf of Mexico, where we conduct operations in three areas: - The shallow Miocene area, where we have controlling working interests in projects with low exploration risk and low drilling and completion costs, targeting reserve deposits of between 3 and 10 Bcf at depths of less than 4,000 feet. Wells are typically drilled from existing platforms or near existing pipelines so that they can be brought on line quickly and inexpensively. We have an average net working interest of 83% in, and operate all of, our shallow Miocene wells. - The outer continental shelf area, where we have significant working interests in projects with higher exploration risk and higher drilling and completion costs, targeting reserve deposits of between 10 and 100 Bcfe at depths of between 7,000 and 17,000 feet. We have a weighted average net working interest of 65.4%, and operate wells representing 61.5% of our estimated net proved reserves, in the OCS area. - The deep water area, where we have small working interests in projects with high exploration risk and high drilling and completion costs, targeting large reserve deposits. We do not operate wells in the deep water area, and we intend to own less than a 15.0% interest in our deep water wells. 25 27 The following table provides information about our estimated net proved reserves in these areas as of June 1, 1999.
PERCENT ESTIMATED NET PROVED RESERVES DISCOUNTED TOTAL ------------------------------ PRESENT DISCOUNTED PRIMARY GAS OIL TOTAL VALUE PRESENT AREA NAME OPERATOR (MMCF) (MBBLS) (MMCFE) ($000) VALUE - --------- ----------- -------- -------- -------- ---------- ---------- SHALLOW MIOCENE AREA: Mobile Block 864 Area............. Callon 52,719 -- 52,719 $ 66,607 38.3% Chandeleur Block 40............... Callon 3,739 -- 3,739 3,456 2.0% Other............................. Callon 1,448 -- 1,448 1,072 0.6% ------- ------ ------- -------- ----- Total................... 57,906 -- 57,906 71,135 40.9% ------- ------ ------- -------- ----- OCS AREA: BRETON SOUND: Main Pass 26 SL 15827............. Callon 5,180 363 7,355 9,374 5.4% Main Pass 31 SL 12002............. Callon 1,619 32 1,813 3,313 1.9% Main Pass 36 SL 14964 "Garfield"..................... Callon 4,183 161 5,149 7,550 4.3% Other Breton Sound................ Callon 714 217 2,018 1,909 1.1% ------- ------ ------- -------- ----- Total Breton Sound........ 11,696 773 16,335 22,146 12.7% ------- ------ ------- -------- ----- OTHER OCS: High Island Block A-494 "Snapper"...................... PetroQuest 4,953 -- 4,953 7,723 4.4% Eugene Island Block 335........... Murphy 3,003 174 4,050 6,698 3.9% Vermilion Block 130............... Murphy 1,187 4 1,208 1,589 0.9% ------- ------ ------- -------- ----- Total Other OCS........... 9,143 178 10,211 16,010 9.2% ------- ------ ------- -------- ----- Total................... 20,839 951 26,546 38,156 21.9% ------- ------ ------- -------- ----- DEEP WATER AREA: Ewing Bank Block 994 "Boomslang".. Murphy 8,282 4,601 35,889 14,341 8.2% Garden Banks Block 341 "Habanero"..................... Shell 12,547 6,393 50,902 34,646 19.9% ------- ------ ------- -------- ----- Total................... 20,829 10,994 86,791 48,987 28.2% ------- ------ ------- -------- ----- OTHER AREAS......................... Various 5,399 1,106 12,034 15,639 9.0% ------- ------ ------- -------- ----- Total................... 104,973 13,051 183,277 $173,917 100.0% ======= ====== ======= ======== =====
SHALLOW MIOCENE PROPERTIES In the shallow Miocene area, we explore for gas deposits using 3-D and conventional 2-D seismic technology, as well as a proprietary high-resolution 2-D seismic technology which better defines reservoir thickness and continuity. We have an average working interest in productive wells in the shallow Miocene area of 83.0%, all of which we operate. Since 1996, we have drilled three gross (2.7 net) exploration wells, of which two gross (2.0 net) were productive, and two gross (1.5 net) development wells, both of which were productive. Our drilling activities in the shallow Miocene area have added 11.2 Bcf of estimated net proved reserves at a cost to us of $9.5 million to drill and complete. We have acquired an extensive infrastructure of production platforms, gathering systems and pipelines located in our shallow Miocene area. These facilities reduce the development costs of our successful wells and reduce the time necessary to begin production from successful wells. In 1997, we also acquired 52.5 Bcf of estimated net proved reserves in the Mobile Block 864 area for a total acquisition cost of $48.7 million. We have acquired additional interests in this area. We currently have an inventory of four exploration prospects in this area, two of which we expect to drill before year-end 1999. We own 110,000 gross (94,000 net) acres in 18 federal blocks and various state leases in the shallow Miocene area, and have an average 83.0% net working interest in 21 producing wells which had average net daily production of 24.8 MMcf during the first quarter of 1999. Since 1996, we have acquired 3,000 26 28 miles of seismic data in this area. The following is a description of the current areas in which we have activities in the shallow Miocene area. Mobile Block 864 Area The Mobile Block 864 area is located offshore Alabama in federal waters. During 1997, we consummated four acquisitions of producing properties and developed and undeveloped acreage in this area for a total of $48.7 million. In June 1999, we acquired additional interests in the area in exchange for a production payment requiring us to deliver 7.6 Bcf of gas over the next three and one quarter years. In total, we own an average 81.6% working interest in nine blocks. Production from a reservoir that underlies four of the blocks has been unitized. We now own a 66.4% working interest in the four well unit and the unit production facilities. We also own a 100% working interest in three additional producing wells in this area. We are the operator of the Mobile Block 864 unit. Estimated net proved reserves at June 1, 1999 were 57.9 Bcf with a discounted present value of $67.0 million. Net average daily production during the first quarter of 1999 was 14.0 MMcf. Production from three wells in the area is currently constrained by the compression of the unit production facilities. We plan to upgrade the facilities to increase production capacity during 1999. Chandeleur Block 40 Chandeleur Block 40 is located offshore Louisiana in federal waters. In December 1995, we acquired an additional working interest in Chandeleur Block 40, increasing our interest to 52.3%. When we assumed operations of the field, two wells were producing 5.5 MMcf per day of gas from the 3,800-foot sand. In February 1996, we shut-in one well and successfully reworked the other and increased average field production to 10.5 MMcf per day of natural gas. During the fourth quarter of 1996, we drilled a development well in the field. The well resulted in a field extension which added 5.0 Bcf in estimated net proved reserves as of December 31, 1996. We are the operator of Chandeleur Block 40. Estimated net proved reserves at June 1, 1999 were 3.7 Bcf with a discounted present value of $3.5 million. Net average daily production during the first quarter of 1999 was 3.4 MMcf. OUTER CONTINENTAL SHELF PROPERTIES We explore for oil and gas deposits in the OCS area of the Gulf of Mexico using the latest in 3-D seismic technology. The wells drilled in this area are more expensive than the shallow Miocene wells and target larger oil and gas deposits. Our weighted average working interest in productive wells in the OCS area is 65.4%. Since 1996, we have added 28.6 Bcfe of estimated net proved reserves at a cost to us of $28.3 million to drill and complete. Since 1996, we have drilled 12 gross (5.3 net) exploration wells in this area, of which five gross (2.8 net) were productive. We also drilled three gross (1.4 net) development wells, all of which were successful, and had two exploration wells in progress on June 1, 1999. We currently have an inventory of 21 exploration prospects in this area, 10 of which we expect to drill before year-end 2000. We own 169,000 gross (61,000 net acres) in 32 federal blocks and various state leases in the OCS area, including the Breton Sound, and have an average 75% working interest in 19 producing wells which during March 1999 had average net daily production of 16.7 MMcfe. Since 1996, we have acquired 450 square miles of 3-D seismic data in this area. The following is a description of the current areas in which we have activities in the OCS. Breton Sound Area The Breton Sound area, located in Louisiana state waters, has been a significant operating area for us since 1997. We have acquired an extensive infrastructure of pipelines, platforms and other production facilities in this area. We own an 84.2% weighted average working interest in 13 wells in this area, all of which we operate, producing from depths of between 6,000 and 13,000 feet. Nine of these wells are 27 29 burdened by an 80.8% net profits interest held by an institutional investor. During March 1999, net average daily production from this area was 13.8 MMcfe. Our Garfield well is scheduled to commence production by late June 1999. The following is a description of several of our properties in this area: Main Pass 26/SL 15827. We negotiated a farm-in agreement in 1998 for a 97.0% working interest after identifying a prospect on the Main Pass 26 Block based upon a seismic survey we completed in 1996. In August 1998, we drilled a well to a depth of 10,450 feet. The SL 15827 well was producing during March 1999 at a net average daily rate of 3.7 MMcf and 229.0 Bbls of oil. Estimated net proved reserves attributable to this well as of June 1, 1999 were 7.4 Bcfe with a discounted present value of $9.4 million. We operate this well. Main Pass 31/SL 12002. Based upon a 1996 seismic survey that we completed, we negotiated two separate farm-in agreements for a 100.0% working interest covering a prospect on Main Pass Block 31. In August 1997, the SL 12002 was drilled to a vertical depth of 10,900 feet. We completed the well and placed it on production in December 1997 after flowlines were laid to a facility we operate at Main Pass Block 32. The well produced 1.9 Bcf and 72.0 MBbls of condensate before being recompleted in the fourth quarter of 1998. The well was brought back on-line during the first quarter of 1999 and produced at net average daily rates of 6.9 MMcf and 227.0 Bbls per day. Estimated net proved reserves attributable to this well as of June 1, 1999 were 1.8 Bcfe with a discounted present value of $3.3 million. We operate this well. Main Pass 36/SL 14964 "Garfield." We acquired a 50.0% working interest in a prospect on Main Pass Block 36 from Conoco in July 1998. In August 1998, we completed the Garfield well, which has 40 feet of net gas pay in three zones from 13,300 feet to 16,500 feet and was tested at 14.0 MMcf and 900.0 Bbls of condensate per day. Production is scheduled to begin in June 1999. Estimated net proved reserves attributable to this well as of June 1, 1999 were 5.1 Bcfe with a discounted present value of $7.6 million. We operate this well. Other OCS Areas In 1997 we expanded our operations in the OCS area beyond Breton Sound primarily through an exploration joint venture with Murphy Exploration and Production, Inc. Since 1996, we have generally limited our working interests in these prospects to 25.0%. Recently, however, we have sought to increase our interests in these prospects and, in some cases, acquire operations. Estimated net proved reserves at June 1, 1999 were 10.2 Bcfe with a discounted present value of $16.0 million. Net average daily production during the first quarter of 1999 was 2.9 MMcfe. The following is a description of several of the significant properties we own in the OCS area outside of Breton Sound. High Island Block A-494, "Snapper." In January 1999, we announced a discovery on our Snapper prospect, which was drilled to a total depth of 8,800 feet. We own a 50.0% working interest in this well, which we purchased in 1998 from PetroQuest Energy Inc., the operator. The well is scheduled to begin production by mid-June through production facilities designed to handle 15.0 MMcf per day. Estimated net proved reserves attributable to this well at June 1, 1999 were 5.0 Bcf with a discounted present value of $7.7 million. Eugene Island Block 335. In 1997, we drilled three wells on Eugene Island Block 335, which we acquired in an OCS lease sale. We own a 20.0% working interest in the wells, which are operated by Murphy. During March of 1999, the three wells produced at a net average daily rate of 2.5 MMcfe. Estimated net proved reserves attributable to these wells at June 1, 1999 were 4.1 Bcfe with a discounted present value of $6.7 million. Vermilion Block 130. In March 1998, we drilled a successful well on this block, which we acquired in an OCS lease sale, to a total depth of 14,134 feet. We own a 25.0% working interest in this well, which is operated by Murphy. During the first quarter of 1999, the well produced at a net 28 30 average daily rate of 0.4 MMcfe from one of three proved zones. Estimated net proved reserves attributable to this well at June 1, 1999 were 1.2 Bcfe with a discounted present value of $1.6 million. DEEP WATER PROPERTIES We allocate a portion of our capital expenditure budget to the exploration of deep water regions in the Gulf of Mexico. These wells are expensive to drill and complete and target large reserve deposits. These wells are usually located far from production facilities and may require long lead times to construct pipelines and other facilities necessary to begin producing reserves we discover. To reduce the risks associated with the high cost of these wells, we explore these prospects with experienced joint venture partners, including Shell Deepwater Development, Inc. and Murphy Exploration and Production, Inc. as operators. We have drilled two wells in our deep water area, both of which were successful. In September 1998, we announced a discovery on our "Boomslang" prospect, and in February 1999, we announced a discovery on our "Habanero" prospect. These discoveries represent the largest discoveries in our history and have added estimated net proved reserves of 86.8 Bcfe at a cost to us of $10.2 million to drill. Costs to complete these wells cannot be determined until we drill several related prospects. We currently have an inventory of 14 deep water exploration prospects, four of which we expect to drill before year-end 2000. We own 127,000 gross (23,000 net) acres in 22 blocks in the deep water areas of the Gulf of Mexico. The following is a description of the two deep water prospects which have been drilled to date, both of which were successful and represent the largest discoveries in our history. Ewing Bank Block 994 "Boomslang." In September 1998, we announced a discovery on our Boomslang prospect which we acquired in an OCS lease sale. This well was drilled in 900 feet of water to a total depth of 13,200 feet. We own a 35.0% working interest in the well, which is operated by Murphy. Estimated net proved reserves at June 1, 1999 were 35.9 Bcfe, with a discounted present value of $14.3 million. Prior to designing production facilities for Boomslang, we plan to drill the Sidewinder prospect. See "Exploration and Development Activities -- Deep Water Area" for a description of the Sidewinder prospect. Garden Banks Block 341 "Habanero." In February 1999, we announced a discovery on our Habanero prospect which we acquired from Shell in exchange for other interests we held on the block. This well was drilled in 1,800 feet of water to a total depth of 21,158 feet. We own an 11.3% working interest in the well, which is operated by Shell. Estimated net proved reserves at June 1, 1999 were 50.9 Bcfe, with a discounted present value of $34.6 million. Prior to designing production facilities for Habanero, we plan to drill the South Moccasin prospect. See "Exploration and Development Activities -- Deep Water Area," for a description of the South Moccasin prospect. OTHER PROPERTIES We own various small royalty and working interests in several onshore areas, which as of June 1, 1999 had total net proved reserves of 12.0 Bcfe with a discounted present value of $15.6 million. Over 50% of these reserves and their related discounted present value were attributable to our interest in the Big Escambia Creek gas field located in south Alabama which is operated by Exxon. EXPLORATION AND DEVELOPMENT ACTIVITIES The following is a summary of our anticipated drilling plans through 2000. We continually review our drilling plans in light of changing circumstances. Factors which may cause us to change our drilling plans are described under "Risk Factors." Shallow Miocene Area We currently have an inventory of four exploration prospects in this area. We expect to drill two of these prospects, Mobile Block 953 #2 and Mobile Block 908 #4, before year-end 1999. We currently have not scheduled any drilling activities for the shallow Miocene area in 2000. Total estimated gross drilling 29 31 costs are estimated to be $2.1 million ($2.0 million net) and estimated gross completion costs are $7.3 million ($6.3 million net) for these two wells. Mobile Block 953 #2. This shallow Miocene prospect is scheduled to drill in June 1999 in 70 feet of water. Production from the prospect will be handled by our Mobile 864 Unit which is located nearby. Net costs to drill this prospect will be $1.1 million. We own a 100.0% working interest in the prospect, which will target reserve deposits at 2,250 feet. We will be the operator of this well. Mobile Block 908 #4. This shallow Miocene prospect is scheduled to drill in July 1999 in 70 feet of water. The prospect is adjacent to our Mobile 864 Unit through which production will be handled. Net costs to drill this prospect will be $0.9 million. We own an 89.0% working interest in the prospect, which will target reserve deposits at 2,250 feet. We will be the operator of this well. OCS Area We currently have an inventory of 21 exploration prospects in this area. We expect to drill three of these prospects, Eugene Island Block 59, Ship Shoal Block 319 and South Marsh Island Block 261, before year-end 1999, and an additional seven prospects before year-end 2000. Total estimated gross drilling costs are $45.6 million ($11.6 million net) and estimated gross completion costs are $217.6 million ($56.9 million net) for these 10 wells. Eugene Island Block 59. We are currently drilling a well on this block located in 15 feet of water, offshore Louisiana. Net costs to drill this well are estimated to be $1.0 million. We own a 20.0% working interest in this well which is targeting reserve deposits at 16,500 feet. Murphy is the operator of this well. Ship Shoal Block 319. We expect to drill a well on this prospect, located in 300 feet of water offshore Louisiana, in the fourth quarter of 1999. Net costs to drill this well, which is targeting reserve deposits at 9,000 feet, are estimated to be $0.6 million. We currently own a 25.0% working interest in the block. We are negotiating a farm-in of the remaining interest in the block under which we would own a 100% working interest in the block and become operator. South Marsh Island Block 261. We currently have three drilling prospects on South Marsh Island Block 261, all of which are located in 30 feet of water. We expect to begin drilling the first of these three wells in the fourth quarter of 1999 for estimated costs of $1.8 million per well. We own a 100.0% working interest in and will operate these wells, but we may bring in an industry partner and reduce our interest to approximately 50.0%. The wells will target reserve deposits at 7,500 feet. In addition, we drilled our "Parodi" prospect located on Main Pass Block 32, SL 15543, in 1998 to a total depth of 15,305 feet and encountered a potentially productive reservoir. Completion efforts encountered mechanical difficulties. Based on additional seismic data, we plan to drill from the existing well bore to a higher structural location in the reservoir. We currently own a 92.4% working interest. We have not scheduled any further drilling activities on this well until we secure an industry partner to participate in the drilling operations estimated to cost $2.9 million gross. We will operate the well and retain an approximate 50.0% working interest. Deep Water Area We currently have an inventory of 14 exploration prospects in this area. We expect to drill two of these prospects, Sidewinder and Medusa, before year-end 1999 and two of these prospects, South Moccasin and Anvil, before year-end 2000. Total estimated gross drilling costs are $84.0 million ($12.4 million net) for these four wells. Costs to complete the wells will depend on the reserves discovered and the decisions made by us and our partners in these prospects regarding the appropriate production facilities to construct. Sidewinder. Prior to designing production facilities for the Boomslang prospect on Ewing Bank Block 994, we plan to drill the Sidewinder prospect, located in 1,200 feet of water on Ewing Bank Block 995 and Green Canyon Blocks 24 and 25 immediately to the southeast of Boomslang. We own a 15.0% working 30 32 interest in this prospect which is scheduled to be drilled in the fourth quarter of 1999. We are targeting reserves at a depth of approximately 16,000 feet. Murphy is the operator of this well. Estimated net costs to drill this well are $3.0 million. Medusa. The Medusa prospect is located in 2,300 feet of water on Mississippi Canyon Blocks 538 and 582. We own a 25.0% working interest in this prospect which is scheduled to be drilled in the fourth quarter of 1999. We are targeting reserves at a depth of approximately 13,000 feet. Murphy is the operator of this well. Estimated net costs to drill this well are $4.3 million. South Moccasin. Prior to designing production facilities for the Habanero prospect on Garden Banks Block 341, we plan to drill the South Moccasin prospect, located in 1,800 feet of water on Garden Banks Blocks 297 adjacent to our Habanero discovery. We own a 12.5% working interest in this prospect which is scheduled to be drilled in 2000. We are targeting reserves at a depth of approximately 22,000 feet. Estimated net costs to drill this well are $2.1 million. Anvil. Anvil is located in 5,500 feet of water on Mississippi Canyon Blocks 815/816. We own a 10.0% working interest in this prospect which is scheduled to be drilled in 2000. We are targeting reserves at a depth of approximately 17,250 feet. Vastar is the operator of this well. Estimated net costs to drill this well are $3.0 million. OCS Lease Sales In March 1999, we, along with our joint venture partners, bid on 13 deepwater blocks and were the apparent high bidder on nine blocks. Seven of the nine blocks have been awarded and the remaining two should be awarded within the next several months. Our net cost to acquire these blocks is $3.7 million. OIL AND GAS RESERVES The following table sets forth certain information about our estimated net proved reserves as of the dates set forth below. These estimates were prepared by Huddleston & Co., Inc., our independent reserve engineers.
DECEMBER 31, JUNE 1, ------------------------------ 1999 1998 1997 1996 -------- -------- -------- -------- Proved developed: Oil (Bbls)....................................... 1,988 2,079 2,976 3,385 Gas (Mcf)........................................ 83,878 76,895 88,010 49,491 Proved undeveloped: Oil (Bbls)....................................... 11,063 4,819 426 434 Gas (Mcf)........................................ 21,095 11,135 728 933 Total proved: Oil (Bbls)....................................... 13,051 6,898 3,402 3,819 Gas (Mcf)........................................ 104,973 88,030 88,738 50,424 Estimated future net cash flows before income taxes (000s)........................................... $280,980 $152,552 $209,260 $216,154 ======== ======== ======== ======== Discounted present value (000s).................... $173,917 $ 99,751 $136,448 $160,171 ======== ======== ======== ========
Huddleston & Co., Inc., our independent reserve engineers, prepared the estimates of the proved reserves 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 1996, 1997 and 1998 and on June 1 of 1999, without escalation, and were otherwise prepared in accordance with the SEC regulations regarding disclosure of oil and gas reserve information. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control or the control of the reserve engineers. Reserve engineering is a subjective 31 33 process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve or cash flow estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. 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. We have not filed any reports with other federal agencies which contain an estimate of total proved net oil and gas reserves. PRODUCTIVE WELLS AND DRILLING ACTIVITY The following table sets forth the wells we drilled and completed during the periods indicated. All but three of these wells were drilled in the federal and state waters of the Gulf of Mexico.
FIVE MONTHS YEARS ENDED DECEMBER 31, ENDED ----------------------------------------------- JUNE 1, 1999 1998 1997 1996 ------------- ------------- ------------- ------------- GROSS NET GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- ---- ----- ---- Development: Oil........................... -- -- 2 .40 -- -- 1 .09 Gas........................... -- -- -- -- 1 1.00 2 1.52 Non-Productive................ -- -- -- -- -- -- -- -- -- ---- -- ---- -- ---- -- ---- Total................. -- -- 2 .40 1 1.00 3 1.61 == ==== == ==== == ==== == ==== Exploration: Oil........................... 1 .11 1 .35 -- -- -- -- Gas........................... 3 1.78 3 2.14 2 1.20 1 1.00 Non-Productive................ -- -- 2 1.25 6 1.91 -- -- -- ---- -- ---- -- ---- -- ---- Total................. 4 1.89 6 3.74 8 3.11 1 1.00 == ==== == ==== == ==== == ====
We owned working and royalty interests in approximately 289 gross (7.4 net) producing oil and 316 gross (26.9 net) producing gas wells as of June 1, 1999. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas reserves on a Mcfe basis. However, substantially all of our wells produce both oil and gas. At June 1, 1999, we had two exploratory gas wells in progress. LEASEHOLD ACREAGE The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage at June 1, 1999.
LEASEHOLD ACREAGE ----------------------------------- DEVELOPED UNDEVELOPED ---------------- ---------------- LOCATION GROSS NET GROSS NET - -------- ------- ------ ------- ------ Shallow Miocene area..................................... 87,439 75,269 22,275 18,819 OCS area................................................. 20,286 9,501 149,110 51,892 Deep water area.......................................... 11,520 2,664 115,200 20,592 Other.................................................... 8,612 4,070 4,480 2,256 ------- ------ ------- ------ Total.......................................... 127,857 91,504 291,065 93,559 ======= ====== ======= ======
As of June 1, 1999, we also owned various royalty and overriding royalty interests in 1,336 net developed acres and 6,862 net undeveloped acres. In addition, we owned 5,464 net developed and 134,536 net undeveloped mineral acres. 32 34 MAJOR CUSTOMERS For the year ended December 31, 1998, Dynegy Marketing & Trade, PG&E Energy Trading Corp., and Columbia Energy Services purchased 23%, 26% and 22%, respectively, of our natural gas and oil production. All three customers purchased production primarily from Callon-owned interests in federal outer continental shelf leases, Chandeleur Block 40, Main Pass 163, Main Pass 164/165, Mobile Block 864 and Mobile Block 952/955 fields. Because of the nature of oil and gas operations and the marketing of production, we believe that the loss of these customers would not have a significant adverse impact on our ability to sell our production. TITLE TO PROPERTIES We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following: - royalty interests and other burdens under oil and gas leases; - 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; - interests which entitle a person to receive a portion of our production after we have received a specified amount of production; - 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; and - pooling, unitization and communitization agreements, declarations and orders; and easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind owned by us. CORPORATE OFFICES Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain owned or leased field offices in the area of the major fields in which we operate properties or have a significant interest. Replacement of any of our leased offices would not result in material expenditures as alternative locations to our leased space are anticipated to be readily available. EMPLOYEES We had 109 employees as of March 31, 1999, none of whom are currently represented by a union. We believe that we have good relations with our employees. We employ eight petroleum engineers and four petroleum geoscientists. LITIGATION We are a defendant in various legal proceedings and claims which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material affect on our financial position or results of operations. 33 35 FEDERAL REGULATIONS Our operations are subject to regulation by federal and state government. These regulations apply to: - the sale and transportation of oil and gas we produce; - the conduct of our operations on federal, state and Indian leases; and - the effect our operations may have on the environment. Each of these categories is discussed below. Sales and Transportation of Oil and Gas. Prior to January 1, 1993, prices for natural gas were subject to extensive regulation by the federal government. Effective January 1, 1993, the federal government repealed these regulations. Thus, we can sell all of our gas production at market prices, subject to applicable contract provisions. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission ("FERC"). Historically, large interstate natural gas pipelines would purchase gas supplies from producers in the field and would sell to local distributors and industrial customers under long-term contracts. Because the pipelines controlled the market for natural gas, producers could not get their product to the market, and the market could not buy gas direct from the producers without going through the pipelines. Since 1985, the FERC has implemented regulations intended to increase competition and make natural gas transportation, including transportation offshore, more accessible to gas buyers and sellers by requiring pipelines to separate or "unbundle" their transportation services from their activities in buying and selling natural gas. On April 26, 1992, the FERC promulgated Order 636, an extensive set of regulations requiring all interstate pipelines to restructure their services. The intent of Order 636 is to provide equal access and transportation services for all gas supplies from all regulated pipelines. Order 636 has fostered robust competition among all facets of the natural gas transportation industry by and among producers, transporters, marketers and consumers. While Order 636 does not directly regulate natural gas producers such as Callon, it does affect how we get our production to market. The courts have largely affirmed the significant features of Order 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify the regulations. In particular, the FERC has recently begun a broad review of its transportation regulations, including: - how its regulations operate in conjunction with state proposals for retail gas marketing restructuring; - whether to eliminate cost-of-service based rates for short-term transportation; - whether to allocate all short-term capacity on the basis of competitive auctions; and - whether changes to its long-term transportation service policies may be appropriate to avoid a market bias toward short-term contracts. We do not believe that we will be affected by any action taken by the courts or by the FERC materially differently than other natural gas producers and marketers with which we compete. Although to date the FERC has imposed light-handed regulation on off-shore gathering facilities, it has the authority to exercise jurisdiction over gathering facilities, if necessary, to permit non-discriminatory access to service. Much of our production comes from the OCS, and we rely upon our own gas gathering facilities as well as gas gathering services provided by others, both of which could be subject to FERC scrutiny in the future. We can sell crude oil and condensate at market prices not subject at this time to price controls. The price that we receive from the sale of these products will be affected by its quality and the cost of 34 36 transporting the products to market. The rates, terms, and conditions applicable to the interstate transportation of oil and related products by pipelines are also regulated by the FERC. In 1995, the FERC implemented rules that provide a simplified, generally applicable method of regulating oil pipeline rates by use of an index for setting rate ceilings. We do not believe that these rules affect us any differently than other producers and marketers with which we compete. With respect to the transportation of oil and condensate offshore in federal waters, the FERC requires that all pipelines provide open and non- discriminatory access to both owner and non-owner shippers. Federal, State or Indian Leases. In the event we conduct operations on federal, state or Indian oil and gas leases (including our offshore leases), our operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes and royalty requirements. In addition, we must obtain permits issued by the Bureau of Land Management ("BLM") or Minerals Management Service ("MMS") or other appropriate federal or state agencies to conduct our operations offshore or onshore on federal or Indian lands. Federal leases, in addition to relatively standard terms, require compliance with detailed MMS and BLM regulations and orders, which are subject to change. In addition to permits required by other federal agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS or BLM prior to commencement of offshore or onshore drilling. The MMS has promulgated regulations requiring offshore production facilities to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has approved other regulations governing plugging and various obligations of offshore lessees, and the MMS generally requires that lessees have a substantial net worth or post bonds or other acceptable assurances that such obligations will be met. Under certain circumstances, the MMS may require the suspension or termination of any of our operations on federal leases. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and operations. The Mineral Leasing Act of 1920 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 provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and gas leases. Because we are a publicly-traded company with limited control over the ownership of our equity interests, it is possible that holders of our equity interests may be citizens of foreign countries which at some time in the future might be determined to be non-reciprocal. STATE REGULATIONS Most states regulate the production and sale of oil and natural 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. In addition, the rates which we can charge for gas produced, consumed and transported in any one state, the transportation of gas in the state, and the costs of construction and operation of a pipeline in the state may be impacted by state rules and regulations. The impact of such requirements and regulations would not be any more adverse to us than they would be to other similar owners or operators conducting business in the state. 35 37 ENVIRONMENTAL REGULATIONS General. Our activities are subject to existing federal, state and local environmental laws and regulations. These laws and regulations govern the environmental condition of properties, the disposal and release of production wastes, oil spills, air emissions and occupational safety. - Environmental Condition of Properties. We own or lease numerous properties that have been used for production of oil and gas for many years. Although we have utilized operating and disposal practices standard in the industry at the time, hydrocarbons or other solid wastes or hazardous wastes may have been disposed or released on or under these properties. In addition, many of these properties have been operated by third parties. We have had no control over treatment by third parties of hydrocarbons or other solid wastes and the manner in which they disposed of or released these substances. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time and will most likely continue to place further restrictions on oil and gas field operations. Under any such new laws, we 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). We could also be required to perform remedial plugging operations to prevent future contamination. - Production Wastes. We generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state laws. It is possible that wastes generated by our 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 comparable state laws. Any designation of these currently exempt wastes as "hazardous wastes" would subject our wastes to more rigorous and costly disposal requirements. Our operations are also potentially subject to the federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), which imposes liability without regard to fault or legality of the original conduct on persons for a release of a "hazardous substance" into the environment. These persons include the owner and operator of a site and persons that disposed or arranged for the disposal of the hazardous substances found at a site. Persons found responsible under CERCLA may be liable for the costs of actions conducted at sites by the U.S. Environmental Protection Agency and, in some cases, third parties in response to threats to the public or environment. Neither Callon nor its predecessors have been designated as a potentially responsible party by the EPA under CERCLA with respect to any such site. - Oil Pollution. There are a variety of regulations imposed on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters, including the Oil Pollution Act of 1990 (the "OPA"). A "responsible party" includes the lessee or permittee of an offshore lease and the owner or operator of associated drilling and production platforms. Liability is assigned to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, few defenses exist to the liability imposed by the OPA. We are required to provide evidence of financial ability under the OPA and recently adopted MMS rules to cover potential liabilities associated with a potential spill. The OPA and MMS rules require responsible parties for offshore facilities in the OCS and in some state waters that have a worst case oil spill potential of more than 1,000 barrels to provide financial assurance in amounts of $35 million under OPA rules and $10 million under MMS rules. This financial assurance amount may be increased to $150 million if warranted by specific risks posed by the operations or if the worst case oil spill potential at the facility exceeds regulatory threshold levels. We currently comply with these OPA and MMS requirements and do not anticipate that we will experience difficulty in satisfying any future requirements for demonstrating financial responsibility. - Air Emissions. Our operations are subject to local, state and federal laws and regulations for the control of emissions from sources of air pollution. Failure to comply strictly with air laws, 36 38 regulations or permits generally may result in the payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require that we temporarily or permanently cease production operations at specific facilities or that we forego construction or operation of certain air emission sources. We believe that in such cases we would have enough existing capacity to continue our operations without a material adverse effect on any particular producing field. - OSHA. Our operations are subject to worker safety and health requirements under the federal Occupational Safety and Health Act and comparable state laws. Under these laws, we are required to organize and/or disclose information about hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We believe that absent the occurrence of an extraordinary event, compliance with existing laws and regulations relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or existing assets and operations. We cannot predict what effect additional environmental regulation, legislation or enforcement policies, and claims for damages resulting from our operations could have on our activities. Although we believe that compliance with environmental regulations will not have a material adverse effect, risks of substantial costs and liabilities are inherent in oil and gas production operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as stricter or reinterpreted environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production, would result in substantial costs and liabilities to Callon. We cannot predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, these proposals might have on our operations. 37 39 MANAGEMENT Our certificate of incorporation currently provides for a board of directors divided into three classes of nearly equal size, designated as Class I, Class II and Class III. Directors are elected to serve three-year terms. INFORMATION ABOUT OUR DIRECTORS AND EXECUTIVE OFFICERS The following is information about our directors and executive officers.
POSITION NAME AGE SINCE PRESENT POSITION - ---- --- -------- ---------------- John S. Callon........................ 79 1994 Director, Class II; Chairman of the Board Fred L. Callon........................ 49 1994 Director, Class III; President; Chief Executive Officer Dennis W. Christian................... 52 1994 Director, Class III; Senior Vice President; Chief Operating Officer John S. Weatherly..................... 47 1994 Senior Vice President and Chief Financial Officer James O. Bassi........................ 45 1997 Vice President; Controller Thomas E. Schwager.................... 48 1997 Vice President H. Michael Tatum...................... 70 1994 Vice President; Secretary Kathy G. Tilley....................... 53 1996 Vice President Stephen F. Woodcock................... 47 1997 Vice President Rodger W. Smith....................... 50 1999 Treasurer Leif Dons............................. 49 1999 Director, Class II Robert A. Stanger..................... 59 1995 Director, Class I John C. Wallace....................... 60 1994 Director, Class I B. F. Weatherly....................... 55 1994 Director, Class II Richard O. Wilson..................... 69 1995 Director, Class I
The following is a brief description of the background and principal occupation of each director and executive officer: JOHN S. CALLON is our Chairman of the Board of Directors. Effective January 2, 1997, John S. Callon resigned as our Chief Executive Officer, a position he had held since 1980. Mr. Callon founded our company in 1950, and has held an executive office with us 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. FRED L. CALLON is our President and Chief Executive Officer. Prior to January 1997, he was our President and Chief Operating Officer, a position which he had held since 1984. Before that, he was employed by us in various positions 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 before joining us, 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. DENNIS W. CHRISTIAN is our Senior Vice President and Chief Operating Officer. Prior to January 1997, he was our Senior Vice President of Operations and Acquisitions and had held that or similar positions with us since 1981. Prior to joining us, 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. 38 40 JOHN S. WEATHERLY is our Senior Vice President and Chief Financial Officer. Prior to April 1996, he was our Vice President, Chief Financial Officer and Treasurer and had held those positions since 1983. Prior to joining us in 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. JAMES O. BASSI is our Vice President and Controller. Prior to being appointed to that position in November 1997, he was our Corporate Controller from June 1997 and prior thereto was our Manager of the accounting department of Callon and Callon Petroleum Operating. Mr. Bassi has been employed by Callon and its predecessors for over ten years. Prior to his employment with us, 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. THOMAS E. SCHWAGER is our Vice President of Engineering and Operations. Prior to being appointed to that position in November 1997, he had held engineering positions with us since 1981. Prior to joining us, Mr. Schwager held various engineering positions with Exxon Company USA in Louisiana and Texas. He received his B.S. degree in petroleum engineering from Louisiana State University in 1972. He is a registered professional engineer in the state of Louisiana and is a member of the Society of Petroleum Engineers. H. MICHAEL TATUM is our Vice President and Secretary, and is responsible for management of administrative matters. Mr. Tatum has held this position with us 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 our Vice President of Acquisitions and New Ventures, a position she has held since April 1996. She was first employed by us in December 1989 as manager of acquisitions and prior thereto, held that or similar positions as a consultant to us since 1981. Ms. Tilley received her B. A. degree in economics from Louisiana State University in 1967. STEPHEN F. WOODCOCK is our Vice President of Exploration. He was appointed to that position in November 1997. He has been employed by us since 1995, serving as manager of geology and geophysics. Before that, he was manager of geophysics for CNG Producing Company and division geophysicist for Amoco Production Company. Mr. Woodcock received his Masters degree in geophysics from Oregon State University in 1975. RODGER W. SMITH is our Treasurer. Prior to being appointed to that position in April, 1999, he was our Manager of Budget and Analysis. Before that, Mr. Smith was Manager of exploration and production accounting and has been employed by Callon and its predecessors since 1983. Prior to his employment with us, he was employed by International Paper Company as a plant controller. He received his B.S. degree in accounting from the University of Southern Mississippi in 1973. LEIF DONS has since 1997 been Senior Vice President, Business Development of Fred. Olsen Energy ASA, a publicly held Norwegian company engaged in the offshore energy service industry. From 1992 until 1997, Mr. Dons was employed by Kvaerner ASA in various positions, including the fields of international operations and the commercialization of new technology, and as resident country manager responsible for Israel and Palestine. From 1983 until 1991, he served as the managing director of Norwegian Oil Consortium A/S & Co., an oil company with producing properties in Norway. He negotiated the sale of that company in 1991. From 1973 until 1983, Mr. Dons held various positions as an analyst, staff engineer and economist at the Pulp and Paper Research Institute, Norway and Saga Petroleum ASA. Mr. Dons received a Master of Science degree in engineering from the Norwegian Institute of Technology in 1973. 39 41 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 and Lybrand in Canada in 1963, after which he joined Baring Brothers & Co., Limited in London, England. For more than the last eleven years, he has served as Chairman of Fred. Olsen Ltd., a London-based corporation which he joined in 1968, and which specializes in the business of shipping and property development. He is a director of Fred. Olsen Energy ASA, a publicly held Norwegian service company engaged in the offshore energy service industry; Harland & Wolff PLC, Belfast, a shipbuilding yard for the offshore oil and gas industry; and Ganger Rolf ASA and Bonheur ASA, Oslo, both publicly-traded shipping companies. He is also an executive officer of NOCO Management, Ltd., a general partner of NOCO Enterprises, L.P. and of other companies associated with Fred. Olsen Interests. B. F. WEATHERLY is a principal of Amerimark Capital Group, Houston, Texas, an investment banking firm and a general partner of CapSource Fund, L. P., Jackson Mississippi, an investment fund. He is an executive officer of NOCO Management Ltd., the general partner of NOCO Enterprises, L.P. 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 formerly associated with Fred. Olsen Interests. He holds a Master of Accountancy degree from 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 is an Offshore Consultant. In his 42 years of working in offshore drilling and construction, he spent two years with Zapata Offshore and 21 years with Brown & Root, Inc. working in various managerial capacities in the Gulf of Mexico, Venezuela, Trinidad, Brazil, the Netherlands, the United Kingdom and Mexico. He was a director and senior group vice president of Brown & Root, Inc. and senior vice president of Halliburton, Inc. For the last 18 years he has been associated with the Fred. Olsen Interests where he served as Chairman of OGC International PLC, Dolphin A/S and Dolphin Drilling Ltd., and Belmont Constructors, Inc. Since the sale of OGC International PLC to Halliburton, Inc. in 1997, he has been a consultant to Brown & Root, Inc. on oil and gas projects in Brazil, Bolivia, Mexico and Ecuador. 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. All of our officers and directors are United States citizens, except Mr. Wallace, who is a citizen of Canada, and Mr. Dons, who is a citizen of Norway. BENEFICIAL OWNERSHIP OF OUR COMMON AND PREFERRED STOCK The following table shows the ownership of our common stock and series A preferred stock by the following: - our five most highly compensated executive officers; - all of our directors; - all of our executive officers and directors as a group; and - anyone who is known by us to beneficially own 5% or more of our outstanding common stock or preferred stock; 40 42 Based on SEC rules, shares of common stock which an individual or group has the right to acquire within 60 days pursuant to the exercise of options or warrants are deemed to be outstanding for the purpose of computing the percentage ownership of such individual or group. These shares are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person show on this table. Unless otherwise indicated, each person named in the following table has the sole power to vote and dispose of the shares listed next to their name. Information in the tables and accompanying text has been obtained from filings made with the SEC or, in the case of our directors and executive officers, has been provided by such individuals. Unless otherwise indicated, the information provided below is based on information available to us as of May 15, 1999.
COMMON STOCK PREFERRED STOCK ---------------------- ---------------------- NAME AND ADDRESS NUMBER OF NUMBER OF OF BENEFICIAL OWNERS SHARES PERCENTAGE SHARES PERCENTAGE - -------------------- --------- ---------- --------- ---------- EXECUTIVE OFFICERS: John S. Callon.................................. 303,926 3.52% 0 -- Fred L. Callon.................................. 791,346 9.10% 0 -- Dennis W. Christian............................. 161,185 1.86% 0 -- John S. Weatherly............................... 149,660 1.73% 0 -- Thomas E. Schwager.............................. 47,652 * 0 -- Kathy G. Tilley................................. 102,980 1.19% 0 -- NON-EMPLOYEE DIRECTORS: Leif Dons....................................... 0 -- 0 -- Robert A. Stanger............................... 40,856 * 0 -- John C. Wallace................................. 2,004,779 23.35% 0 -- B.F. Weatherly.................................. 147,664 1.72% 0 -- Richard O. Wilson............................... 67,877 * 1,000 * ALL DIRECTORS AND EXECUTIVE OFFICERS AS A GROUP (15 PERSONS).................................... 3,847,462 44.82% 1,000 * CERTAIN BENEFICIAL OWNERS: Fred. Olsen Energy ASA.......................... 1,839,386 21.52% 0 -- Fred. Olsensgate 2 0152 Oslo, Norway State Street Research & Management Company...... 827,400 9.68% 0 -- One Financial Center, 30th Floor Boston, Massachusetts 02111-2690 The Guardian Life Insurance Company of America...................................... 748,060 8.27% 220,000 21.04% 201 Park Avenue South New York, New York 10003 Brinson Partners, Inc........................... 554,000 6.48% 0 -- 209 South LaSalle Chicago, Illinois 60604-1295 UBS AG.......................................... 554,000 6.48% 0 -- Bahnhofstrasse 45 8021, Zurich, Switzerland Dimensional Fund Advisors Inc................... 505,800 5.92% 0 -- 1299 Ocean Avenue, 11th Floor Santa Monica, California 90401
- --------------- * Under 1%. 41 43 JOHN S. CALLON. The shares beneficially owned by John S. Callon include 105,000 shares held in a family limited partnership and 90,000 shares subject to options under our 1994 Stock Incentive Plan. The shares beneficially owned by John S. Callon do not include 58,500 shares owned by John S. Callon's wife over which he disclaims beneficial ownership. NOCO Enterprises, L.P. Fred. Olsen Energy ASA and Fred. Olsen Ltd. as of May 15, 1999, owned 107,297, 1,839,386 and 14,971 shares of common stock, respectively. John S. Callon, who is party to an agreement regulating the voting and transfer of common shares with NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. disclaims beneficial ownership of the NOCO Enterprises, L.P. Fred. Olsen Energy ASA and Fred. Olsen Ltd. shares. FRED L. CALLON. The shares beneficially owned by Fred L. Callon include 268,012 shares held as custodian for certain minor Callon family members; 78,430 shares held as trustee of certain Callon family trusts; 57,442 shares held as trustee of shares held by the Callon Petroleum Company Employee Savings and Protection Plan; 80,000 shares subject to options under our 1994 Stock Incentive Plan and 75,000 shares subject to options under our 1996 Stock Incentive Plan. The shares beneficially owned by Fred L. Callon do not include 25,037 shares owned by Fred L. Callon's wife over which he disclaims beneficial ownership. NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd., as of May 15, 1999, owned 107,297, 1,839,386 and 14,971 shares of common stock, respectively. Fred L. Callon, who is party to an agreement regulating the voting and transfer of common shares with NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. disclaims beneficial ownership of the NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. shares. DENNIS W. CHRISTIAN. The shares beneficially owned by Dennis W. Christian include 60,000 shares subject to options under our 1994 Stock Incentive Plan and 69,500 shares subject to options under our 1996 Stock Incentive Plan. JOHN S. WEATHERLY. The shares beneficially owned by John S. Weatherly include 217 shares held as custodian for his minor children; 60,000 shares subject to options under our 1994 Stock Incentive Plan and 61,500 shares subject to options under our 1996 Stock Incentive Plan. THOMAS E. SCHWAGER. The shares beneficially owned by Thomas E. Schwager include 20,000 shares subject to options under our 1994 Stock Incentive Plan and 13,200 shares subject to options under our 1996 Stock Incentive Plan. KATHY G. TILLEY. The shares beneficially owned by Kathy G. Tilley include 30,000 shares subject to options under our 1994 Stock Incentive Plan and 48,000 shares subject to options under our 1996 Stock Incentive Plan. ROBERT A. STANGER. The shares beneficially owned by Robert A. Stanger include 20,000 shares subject to options under our 1994 Stock Incentive Plan and 20,000 shares subject to options under our 1996 Stock Incentive Plan. JOHN C. WALLACE. The shares beneficially owned by John C. Wallace include 107,297 shares owned by NOCO Enterprises, L.P.; 14,971 shares owned by Fred. Olsen Ltd.; 1,839,386 shares owned by Fred. Olsen Energy ASA; 20,000 shares subject to options under our 1994 Stock Incentive Plan and 20,000 shares subject to options under our 1996 Stock Incentive Plan. See "Fred. Olsen Energy ASA" below. B.F. WEATHERLY. The shares beneficially owned by B.F. Weatherly include 107,297 shares owned by NOCO Enterprises, LP; 20,000 shares subject to options under our 1994 Stock Incentive Plan and 20,000 shares subject to options under our 1996 Stock Incentive Plan. See "Fred. Olsen Energy ASA" below. RICHARD O. WILSON. The shares beneficially owned by Richard O. Wilson include 25,604 shares held in a family limited partnership; 2,273 shares issuable upon conversion of 1,000 shares of series A preferred stock held in the family partnership; 20,000 shares subject to options under our 1994 Stock Incentive Plan and 20,000 shares subject to options under our 1996 Stock Incentive Plan. 42 44 ALL DIRECTORS AND EXECUTIVE OFFICERS. The shares beneficially owned by all of our directors and executive officers as a group include 465,000 shares subject to options under our 1994 Stock Incentive Plan exercisable within 60 days; 408,700 shares subject to options under our 1996 Stock Incentive Plan exercisable within 60 days; and 148,203 shares awarded as performance shares or restricted stock which vested in February, 1999. FRED. OLSEN ENERGY ASA. The following information and the information in the foregoing table is based on information disclosed on a Schedule 13D dated August 20, 1997 and as otherwise disclosed to us by Fred. Olsen Energy ASA. Fred. Olsen Energy ASA has the sole power to vote and the sole power to dispose of 1,839,386 shares of our common stock. Ganger Rolf ASA, a public joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 28.81% of the outstanding capital stock of Fred. Olsen Energy ASA and Bonheur ASA, a public joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 28.81% of the outstanding capital stock of Fred. Olsen Energy ASA, together have the power to direct the vote and disposition of the shares of our common stock owned by Fred. Olsen Energy ASA. AS Quatro, a joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 1.66% of the outstanding capital stock of Ganger Rolf ASA and 42.10% of the outstanding capital stock of Bonheur ASA and AS Cinco, a joint stock company organized and existing under the laws of the Kingdom of Norway and the owner of 11.99% of the outstanding capital stock of Ganger Rolf ASA, each disclaims beneficial ownership of the shares of our common stock owned by Fred. Olsen Energy ASA. John C. Wallace, one of our directors, is a director of Fred. Olsen Energy ASA and a director of Ganger Rolf ASA, Bonheur ASA, AS Quatro and AS Cinco and, as a result, may by deemed to share the power to vote and dispose of, and therefore be a beneficial owner of the shares of common stock owned by Fred. Olsen Energy ASA. The principal business address and principal executive offices of Ganger Rolf ASA, Bonheur ASA, AS Quatro and AS Cinco are located at Fred. Olsensgate 2, 0152 Oslo, Norway. STATE STREET RESEARCH & MANAGEMENT COMPANY. The following information and the information in the foregoing table is based upon a Schedule 13G, filed with the SEC on February 8, 1999 by State Street Research & Management Company. State Street Research & Management Company has sole voting power with respect to 700,400 shares of common stock and sole dispositive power with respect to all of the shares it beneficially owns. THE GUARDIAN LIFE INSURANCE COMPANY OF AMERICA. The following information and the information in the foregoing table is based upon a Schedule 13G/A, filed with the SEC on February 11, 1998, by The Guardian Life Insurance Company of America and certain of its affiliates. The common stock beneficially owned by The Guardian Life Insurance Company of America includes 500,060 shares issuable upon conversion of 220,000 shares of series A preferred stock. BRINSON PARTNERS, INC. The following information and the information in the foregoing table is based on a Schedule 13G, filed with the SEC on February 11, 1999, by UBS AG and Brinson Partners, Inc. Both UBS AG and Brinson Partners, Inc. possess shared voting and dispositive power with respect to the shares beneficially owned by them. DIMENSIONAL FUND ADVISORS INC. The information in the foregoing table is based upon a Schedule 13G, filed with the SEC on February 11, 1999, by Dimensional Fund Advisors Inc. STOCKHOLDERS' AGREEMENT In connection with the formation of Callon in 1994, certain members of the Callon family (including John S. Callon and Fred L. Callon) and NOCO Enterprises, L.P. entered into a stockholders' agreement, which was subsequently amended to include Fred. Olsen Energy ASA and Fred. Olsen Ltd. Under the stockholders' agreement, which is dated September 16, 1994, the members of the Callon family, on the one hand and NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. on the other hand, each elect two directors to Callon's board of directors. Specifically, in the stockholders' agreement, the members of the Callon family, NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. agree to use their best efforts, including voting the shares of common stock which they own, to cause 43 45 Callon's board of directors to be composed of at least four members. Two of these members are selected by the members of the Callon family and two of these members are selected by NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. The stockholders' agreement also contains restrictions on transfer of shares of common stock owned by the members of the Callon family, NOCO Enterprises, L.P. Fred. Olsen Energy ASA and Fred. Olsen Ltd. and prohibits the members of the Callon family, NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. from taking certain actions which would result in certain changes of control or fundamental changes, without the consent of the other party. The Callon family, NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. own an aggregate of 43.91% of our common stock. DESCRIPTION OF THE NOTES We will issue % Senior Subordinated Notes due 2004 under an indenture between us and American Stock Transfer & Trust Company, as trustee. The following description is a summary of selected provisions of the indenture and the notes. We have not restated the indenture in its entirety. We filed the form of the indenture as an exhibit to our registration statement. You should read the indenture because the indenture, and not this description, will control your rights as a holder of the notes. You can find the definitions of certain terms used in this description under the subheading "Certain Definitions." Unless otherwise specifically noted in the following discussion, references to "Callon," "we" or "us" means Callon Petroleum Company without its Subsidiaries. In the summary below, we have included references to the applicable section numbers of the indenture so that you can easily locate these provisions. Capitalized terms used in the summary have the meanings specified in the indenture. The notes represent our direct unsecured obligations and rank equally with all our existing senior subordinated notes. The notes are subordinated to our Senior Indebtedness as discussed under the subheading "Subordination" and are structurally subordinated to all liabilities of our Subsidiaries. Assuming we had issued the notes and applied the proceeds as intended as of March 31, 1999, we would have had $100.2 million of Senior Indebtedness. As of March 31, 1999, our Subsidiaries had liabilities of $12.0 million, excluding guarantees of Senior Indebtedness. The indenture will permit us to incur additional Senior Indebtedness subject only to certain limitations described under the subheading "Certain Covenants -- Incurrence of Indebtedness." Our Credit Facility constitutes Senior Indebtedness. All indebtedness under our Credit Facility is secured by substantially all of our and our Subsidiaries' producing oil and gas properties. As of the date of the indenture, all of our Subsidiaries will be "Restricted Subsidiaries." However, under the circumstances described in the definition of "Unrestricted Subsidiaries," located under the subheading "Certain Definitions," we will be permitted to designate certain of our Subsidiaries as "Unrestricted Subsidiaries." Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. PRINCIPAL, INTEREST, AND MATURITY OF THE NOTES We will issue notes with a maximum aggregate principal amount of $40,000,000. The notes will mature on September 15, 2004, unless we elect to redeem them earlier. Interest on the notes will accrue at the rate of % per annum, and we will pay interest quarterly on the 15th day of March, June, September and December, commencing on September 15, 1999. We will make each interest payment to the holders of record of the notes on the 1st day of March, June, September and December immediately preceding such interest payment. Interest on the notes will accrue from the date of original issuance and, thereafter, from the date we most recently paid interest. 44 46 REGISTRATION, TRANSFER, AND PAYMENT OF INTEREST AND PRINCIPAL Book-Entry Notes We will issue the notes in the form of a global note that will be deposited with The Depository Trust Company, New York, New York ("DTC"). This means that we will not issue certificates to each holder. One global note will be issued to DTC which will keep an electronic record of its participants whose clients have purchased the notes. The participant will then keep a record of its clients who purchased the notes. Unless a global note is exchanged in whole or in part for a certificated note, a global note may not be transferred; except that DTC, its nominees, and their successors may transfer a global note as a whole to one another. DTC and its participants will show beneficial interests in and make transfers of beneficial interests in global notes only through their records. We, the trustee and the paying agent will not maintain, review or supervise these records. [Sections 308 and 312] The laws of some states require that certain persons take physical delivery in definitive form of securities which they own. If these laws apply, they may limit the ability to transfer beneficial interests in the global note. DTC will hold the notes through its nominee, Cede & Co. We will wire principal and interest payments either directly to Cede & Co. or to the trustee or other paying agent for payment to Cede & Co. We, the trustee and the paying agent will treat Cede & Co. as the owner of the global notes for all purposes and will have no direct responsibility if Cede & Co. fails to distribute those payments to owners of beneficial interest in the global notes. [Section 308] It is DTC's current practice, upon receipt of any payment of principal or interest, to credit participants' accounts on the payment date according to their holdings of beneficial interests in the global notes as shown on DTC's records. In addition, it is DTC's current practice to assign any consenting or voting rights to participants whose accounts are credited with notes on a record date by using an omnibus proxy. Customary practices between participants and owners of beneficial interests will govern payments by participants to owners of beneficial interests in the global notes and voting by participants, as is the case with notes held for the account of customers registered in "street name." However, those payments will be the responsibility of the participants and not of DTC, the trustee, the paying agent or us. We will issue certificated notes in exchange for a global note with the same terms in authorized denominations only if: - DTC notifies us that it is unwilling or unable to continue as depositary and we have not appointed a successor depositary within 90 days; or - DTC requests an exchange and an event of default has occurred and is continuing. [Section 312] Certificated Notes If we issue certificated notes, they will be registered in the name of the holder of the note. The notes may be transferred or exchanged, pursuant to administrative procedures in the indenture, without the payment of any service charge (other than any tax or other governmental charge) by contacting the trustee. [Section 305] Principal of, interest and any premium on certificated notes will be paid at designated places. Payment may be made by check mailed (or at our option, by wire transfer) to the persons in whose names the notes are registered on the days specified in the indenture. [Section 1001] About DTC DTC has provided us the following information: DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking law, a member of the United States Federal Reserve System, a "clearing corporation" within the meaning of the New York 45 47 Uniform Commercial Code and a "clearing agency" registered under the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds securities that its participants deposit with DTC. DTC also records the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for participants' accounts. This eliminates the need to exchange certificates. Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC's book-entry system is also used by other organizations such as securities brokers and dealers, banks and trust companies that work through a participant. The rules that apply to DTC and it participants are on file with the SEC. DTC is owned by a number of its participants and by the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. SUBORDINATION The payment of principal, premium and interest, if any, on the notes will be subordinated to the prior payment in full of all of our Senior Indebtedness. [Section 1301] The holders of Senior Indebtedness will be able to receive payment in full of all amounts due in respect of Senior Indebtedness, before the holders of notes will be able to receive any payment with respect to the notes, other than payments in the form of Permitted Junior Securities, and payments made pursuant to the terms described under the subheading "Consolidation, Merger and Sale of Assets," if there is a distribution to our creditors: - in our liquidation or dissolution; - in a bankruptcy, reorganization, insolvency, receivership or similar proceeding relating to us, our creditors or our property; - in an assignment for the benefit of our creditors; or - in any marshalling of our assets and liabilities. [Section 1302] We also may not make any payment in respect of the notes, other than payments of Permitted Junior Securities, if: - a Payment Event of Default on Specified Senior Indebtedness occurs and is continuing beyond any applicable grace period; or - any other default occurs and is continuing on Specified Senior Indebtedness that permits holders of the Specified Senior Indebtedness to accelerate its maturity, and we receive or the trustee receives a notice of such default (a "Payment Blockage Notice") from the holders of any Specified Senior Indebtedness. We will resume making payments on the notes and any missed payments: - in the case of a Payment Event of Default, upon the date that we cure or obtain the waiver of such default; and - in case of a Non-payment Event of Default, the earlier of the date that we cure or obtain the waiver of such Non-payment Event of Default or 179 days after the date on which we receive or the trustee receives the applicable Payment Blockage Notice, or the date on which the holders that initiated the Payment Blockage Notice terminate the payment blockage period, unless the maturity of any Specified Senior Indebtedness has been accelerated. No new Payment Blockage Notice may be delivered unless and until 360 consecutive days have elapsed since the effectiveness of the immediately prior Payment Blockage Notice. No Non-payment 46 48 Event of Default that existed or was continuing on the date of delivery of any Payment Blockage Notice to us or the trustee can be made the basis for a subsequent Payment Blockage Notice. [Section 1303] Any payments that we fail to make on the notes when due or within an applicable grace period will constitute an Event of Default under the indenture that entitles holders of the notes to accelerate the maturity of the notes. [Sections 501 and 502] If the trustee or any holder of a note receives any payment or property prohibited by the subordination provisions of the indenture, the payment and property must be paid over to us or the person making payments to our creditors. [Sections 1302 and 1303] As a result of the subordination provisions described above, in the event of our bankruptcy, liquidation or reorganization, holders of the notes may recover less ratably than our creditors that are holders of Senior Indebtedness. See "Risk Factors." The subordination provisions described above will not apply to the notes upon a legal or covenant defeasance described under the subheading "Legal Defeasance and Covenant Defeasance." CERTAIN COVENANTS Restricted Payments We will not, and will not permit any of our Restricted Subsidiaries to, directly or indirectly: - declare or pay any dividend or make any other payment or distribution on account of our or any of our or our Restricted Subsidiaries' capital stock (other than dividends or distributions payable solely in shares of our capital stock); or - purchase, redeem or retire any of our or our Restricted Subsidiaries' capital stock or any warrants, rights or options to purchase or acquire any shares of such capital stock (all such payments and other actions set forth in the two clauses above being collectively referred to as "Restricted Payments"), if, at the time of and after giving effect to such Restricted Payment: - an Event of Default would have occurred; or - such Restricted Payment, together with the aggregate amount of all other Restricted Payments (excluding Permitted Restricted Payments) made by us and our Restricted Subsidiaries after the date of the Indenture, would exceed the sum of: (1) 50% of our Consolidated Net Income subsequent to , 1999, with 100% reduction for a loss; plus (2) the cumulative net proceeds received by us from the issuance and sale after the date of the indenture of our capital stock, including in such net proceeds the face amount of any indebtedness that has been converted into our common stock after the date of the indenture. So long as no Event of Default has occurred and is continuing, the preceding provisions will not prohibit: - Restricted Payments in an aggregate amount not to exceed $10 million; - the payment of regular periodic dividends on shares of our series A preferred stock or other series of our preferred stock; and - the repurchase, redemption, other acquisition or retirement of any shares of any class of our or any of our Restricted Subsidiaries' capital stock in exchange for, or out of the aggregate net cash proceeds of a substantially concurrent issuance and sale (other than to a Restricted Subsidiary) of shares of our common stock. 47 49 All such payments and other actions set forth in the three clauses above being collectively referred to as "Permitted Restricted Payments." Permitted Restricted Payments shall not reduce the amount that would otherwise be available for Restricted Payments, except in the case of dividends declared or paid on shares of our preferred stock (other than the series A preferred stock) which dividends will reduce the amount available under clauses (1) and (2) above. The amount of any Restricted Payments payable in property will be the fair market value of such property as determined by our board of directors. [Section 1006] Incurrence of Indebtedness We will not, and will not permit any of our Restricted Subsidiaries to, create, incur, assume, guarantee or become liable ("incur"), with respect to any Indebtedness for Money Borrowed, including Acquired Indebtedness but excluding Permitted Indebtedness, if, immediately after we incur such debt (including giving effect to the retirement of any existing Indebtedness for Money Borrowed from the proceeds of such additional Indebtedness for Money Borrowed): - the ratio of: (1) the aggregate amount of our and our Restricted Subsidiaries' outstanding Indebtedness for Money Borrowed as of the end of our immediately preceding fiscal quarter, determined on a consolidated basis under GAAP, to (2) the Consolidated EBITDA for our immediately preceding four fiscal quarters, would exceed 10.0 to 1.0; or - the ratio of: (1) Consolidated EBITDA for our immediately preceding four fiscal quarters, to (2) Consolidated Interest Expense for our immediately preceding four fiscal quarters, would be less than 1.1 to 1.0. We will also not permit any Restricted Subsidiary to incur any Indebtedness for Money Borrowed, except to us or another Restricted Subsidiary, that is expressly subordinate in right of payment to any other Indebtedness for Money Borrowed of such Restricted Subsidiary. [Section 1007] Liens We will not, and will not permit any of our Restricted Subsidiaries to, directly or indirectly, create, incur, assume or suffer to exist any Lien on any asset now owned or hereafter acquired of any kind to secure any Pari Passu Indebtedness or Subordinated Indebtedness, unless, - the Lien is a Permitted Lien; or - prior to, or at the same time that we incur a Lien, we directly secure the notes equally and ratably, provided that: (1) if such secured indebtedness is Pari Passu Indebtedness, the Lien securing such Pari Passu Indebtedness is subordinate to, or pari passu with, the Lien securing the notes; and (2) if such secured indebtedness is Subordinate Indebtedness, the Lien securing such Subordinated Indebtedness is subordinate to the Lien securing the notes at least to the same extent as such Subordinated Indebtedness is subordinated to the notes. This covenant does not apply to any Lien securing Acquired Indebtedness, provided that any such Lien extends only to the properties or assets that were subject to such Lien prior to the acquisition by us or such Restricted Subsidiary and we did not create, incur or assume any such Lien in contemplation of such transaction. [Section 1008] 48 50 Ranking of Future Indebtedness We will not incur or permit to remain outstanding any Indebtedness for Money Borrowed, including Acquired Indebtedness and Permitted Indebtedness, which is expressly subordinate to any Senior Indebtedness, other than Subordinated Indebtedness or Pari Passu Indebtedness. The incurrence of any unsecured Senior Indebtedness is not, because of its unsecured status, deemed to be subordinate in right of payment to any secured Senior Indebtedness. [Section 1013] Dividend and Other Payment Restrictions Affecting Subsidiaries We will not, and will not permit any of our Restricted Subsidiaries to, directly or indirectly, create or cause any encumbrance or restriction on the ability of any Restricted Subsidiary to: - pay dividends in cash or make any other distribution on its capital stock to us or any other Restricted Subsidiary; - pay any indebtedness owed to us or any other Restricted Subsidiary; - make loans, advances or capital contributions to us or any other Restricted Subsidiary; or - transfer any of its properties to us or another Restricted Subsidiary. However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of: - an agreement governing Acquired Indebtedness of any acquired Person that becomes a Restricted Subsidiary, provided, than any restriction or encumbrance under such agreement existed at the time of acquisition, was not put in place in anticipation of such acquisition, and is not applicable to any Person other than the Person or property of the Person so acquired; - customary provisions of any of our or our Restricted Subsidiaries' leases or licenses relating to the property covered that we or a Restricted Subsidiary entered into in the ordinary course of business; - applicable law; - the indenture, the Credit Facility or other indebtedness or other agreements existing on the date of original issuance of the notes; - an agreement entered into for the sale or disposition of the stock, business or properties of a Restricted Subsidiary; - purchase money obligations, but only to the extent such purchase money obligations restrict or prohibit the transfer of the property so acquired; - customary non-assignment provisions in installment purchase contracts; - the requirements of a lender or purchaser of any indebtedness of a Restricted Subsidiary in connection with a financing of the acquisition of property, including the purchase of asset portfolios and the underwriting or origination of mortgage loans, by such Restricted Subsidiary to the extent such restriction applies to the transfer to us or any other Restricted Subsidiary of such property acquired after the date of the indenture; - an agreement that extends, refinances, renews or replaces any agreement described in the foregoing clauses; and - Liens containing customary limitations on the transfer of collateral which are not prohibited as described in the "Liens" covenant and do not restrict the ability of a Restricted Subsidiary to transfer any of its property or assets to us or another Restricted Subsidiary. [Section 1014] 49 51 Transactions with Affiliates We will not, and will not permit any of our Restricted Subsidiaries to, enter into any transaction or series of related transactions involving payments in excess of $50,000, with any of our Affiliates, other than ourselves or a Restricted Subsidiary, unless our board of directors: - determines that the transaction is on terms that are no less favorable to us or the relevant Restricted Subsidiary than would be available at such time in a comparable transaction in arm's length dealings with an unrelated person; and - the board of directors adopts a resolution evidencing such determination. The preceding paragraph will not apply to: - Restricted Payments that are permitted by the provisions of the Indenture described above under "Restricted Payments;" - fees and compensation paid to, and indemnity provided on behalf of, our and our Restricted Subsidiaries' officers, directors, employees or consultants; or - payments for goods and services purchased in the ordinary course of business on an arm's length basis. [Section 1015] Change of Control Upon the occurrence of a Change of Control, we are obligated to make an offer to purchase all of the outstanding notes for a purchase price equal to 101% of the principal amount of the notes plus accrued and unpaid interest, if any, on the notes to the date the offer is consummated. We are required to purchase all notes tendered and not withdrawn. In order to effect the Change of Control offer, we must mail to each holder of the notes a notice of the Change of Control offer no later than 30 days after the Change of Control occurs. We must consummate the offer on a business day not less than 30 days nor more than 60 days after the mailing of the notice of the Change of Control. We are required to keep the offer open for at least 20 business days. The notice governs the terms of the offer and states the procedures that holders of notes must follow to accept the offer. We will not be required to make a Change of Control offer upon a Change of Control if a third party makes a Change of Control offer that meets the requirements of the indenture, and purchases all notes validly tendered and not withdrawn under the Change of Control offer. The definition of Change of Control includes a phrase relating to the sale, lease, transfer, conveyance or other disposition of "all or substantially all" of our and our Restricted Subsidiaries' assets taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase their notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of our and our Restricted Subsidiaries' assets taken as a whole may be uncertain. We will comply with Rule 14e-1 under the Exchange Act and any other securities laws and regulations, to the extent these laws or regulations are applicable, in connection with the repurchase of the notes as a result of a Change of Control. REPORTS As long as we are a reporting company under the Securities Exchange Act of 1934, we will furnish holders of the notes with our annual reports containing audited consolidated financial statements and our interim reports containing our quarterly unaudited consolidated summary financial data. If we cease to be a reporting company, we will furnish holders of the notes with our audited consolidated financial statements and our quarterly unaudited consolidated summary financial statements. [Section 704] 50 52 EVENTS OF DEFAULT AND REMEDIES Each of the following is an Event of Default: - failure to pay any interest on the notes when due for 30 days, whether or not prohibited by the subordination provisions of the indenture; - failure to pay the principal of (or premium, if any, on) the notes when due as provided in the indenture, whether or not prohibited by the subordination provisions of the indenture; - failure to perform, or a breach of, any other covenant set forth in the indenture for 30 days after receipt of written notice from the trustee or holders of at lest 25% in aggregate principal amount of the outstanding notes specifying the default and requiring that we remedy such default; - failure to pay at Stated Maturity of our or any Restricted Subsidiaries' Indebtedness for Money Borrowed having an outstanding principal amount due at Stated Maturity greater than $2.5 million for a period of 30 days beyond any applicable grace period; - an event of default as defined in any mortgage, indenture or instrument of ours or a Restricted Subsidiary that has resulted in acceleration of Indebtedness for Money Borrowed which, together with the principal amount of any other Indebtedness for Money Borrowed so accelerated, exceeds $2.5 million at any time, and we do not cure or obtain the waiver of such default and such acceleration is not rescinded or annulled within 30 days from the occurrence of such acceleration; - certain events of insolvency, receivership or reorganization of us or any Material Subsidiary; and - failure by us or any Material Subsidiary to satisfy a final judgment for the payment of money in excess of $2.5 million for a period of 30 days without a stay of execution. [Section 501] If an Event of Default arising from certain events of insolvency, receivership or reorganization occurs and is continuing, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, - the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all the notes to be due and payable immediately; and - the trustee, upon the request of the holders of not less than 25% in aggregate principal amount of the then outstanding notes, shall declare all of the notes to be due and payable. [Section 502] After a declaration of acceleration under the indenture, but before the trustee obtains a judgment for payment of the money due, the holders of a majority in aggregate principal amount of the outstanding notes may rescind such declaration by written notice to us and the trustee, if: - we have paid or deposited with the trustee a sum sufficient to pay: (1) all sums paid or advanced by the trustee under the indenture and the reasonable compensation, expenses, disbursements and advances of the trustee, its agents and counsel; (2) all overdue interest on the notes; (3) the principal of any notes which have become due otherwise than by such declaration of acceleration and interest at the rate borne by the notes; and (4) to the extent that payment of such interest is lawful, interest upon overdue interest and principal at the rate borne by the notes (without duplication); - the rescission would not conflict with any judgment of a court of competent jurisdiction; and - we have cured or obtained the waiver of all Events of Default, other than the nonpayment of principal of (or premium, if any, on) or interest on the notes that has become due solely by such declaration of acceleration. [Section 502] 51 53 A Holder of a note may institute proceedings for the enforcement of the payment of the principal, premium, if any, and interest on such note on or after the respective due dates expressed in such note. No Holder of any note will have any right to institute any other proceedings with respect to the indenture, unless: - such holder has notified the trustee of a continuing Event of Default; - the holders of at least 25% in aggregate principal amount of the outstanding notes have made written request and offered reasonable indemnity to the trustee to institute such proceedings as trustee under the indenture; - the trustee has not received directions inconsistent with such written request by holders of a majority in aggregate principal amount of the outstanding notes; and - the trustee has failed to institute such proceedings within 60 days of receipt of such notice. [Section 507 and 508] If a default or Event of Default occurs and is continuing and is known to the trustee, the trustee shall mail to each holder of notes notice of the default or Event of Default within 90 days after the occurrence of such default or Event of Default. The trustee may withhold from holders of the notes notice of any continuing Event of Default, except an Event of Default relating to the payment of principal (premium, if any) or interest, if it determines in good faith that withholding notice is in their interest. [Section 602] The holders of a majority in aggregate principal amount of the notes then outstanding may on behalf of the holders of all of the notes waive any existing Event of Default and its consequences, except a continuing Event of Default in the payment of principal of (or premium, if any, on) or interest on the notes or of a provision of the indenture that cannot be modified or amended without the consent of the holder of each note affected as described below under the subheading "Modification of Indenture; Waiver of Covenants." [Section 513] We are required to deliver to the Trustee annual and quarterly statements regarding compliance with the indenture. Upon becoming aware of any default or Event of Default, we are required to deliver to the trustee a statement specifying such default or Event of Default. [Section 1011] REDEMPTION AT OPTION OF THE COMPANY We may redeem the notes, in whole or part, at 100% of their principal amount plus accrued interest, on or after March 15, 2001 by giving not less than 30 nor more than 60 days' notice to the holders. If we elect to redeem less than all of the notes, the trustee will select which notes, or portions of notes not to be less than $1,000, to redeem. On the redemption date, interest will cease to accrue on the notes or portions of notes called for redemption. [Article 11] MODIFICATION OF INDENTURE; WAIVER OF COVENANTS We generally may amend the indenture with the written consent of a majority in principal amount of the outstanding notes. [Section 902] The holders of a majority in principal amount of the outstanding notes may also waive our compliance with certain covenants. [Section 1012] We must, however, obtain the consent of each holder of notes affected by an amendment or waiver which does any of the following: - changes the maturity date of the principal of, or the due date of any installment of interest on, any note; - reduces the principal of, or the rate of interest on, any note; - changes the place of payment or the currency in which any portion of the principal of (or premium, if any, on), or interest on, any note is payable; - impairs the right to institute suit for enforcement of any such payment; 52 54 - reduces the percentage of holders of the outstanding notes necessary to modify the indenture; - modifies the foregoing requirements or reduces the percentage of outstanding notes necessary to waive any past default or certain covenants; or - reduces the relative ranking of the notes. [Section 902] CONSOLIDATION, MERGER AND SALE OF ASSETS The indenture generally permits a consolidation, merger, or sale of all or substantially all of our assets to another entity, subject to our obligation to offer to repurchase the notes in the case of a transaction that is a Change of Control as long as it does not cause a default or an Event of Default. If this happens, the remaining or acquiring entity: - if other than us, must be formed in a U.S. jurisdiction and must assume our obligations under the indenture; and - we must be able to incur $1.00 of Indebtedness for Money Borrowed in compliance with the incurrance of indebtedness covenant in the indenture immediately after the merger. [Section 801] LEGAL DEFEASANCE AND COVENANT DEFEASANCE Legal Defeasance As long as we take steps to ensure that you will receive all of your payments under the notes and are able to transfer the notes, we can elect to legally release ourselves from any obligations on the notes (called "legal defeasance") other than: - the rights of holders of outstanding notes to receive payment in respect of the principal of (and premium, if any) and interest on such notes when such payments are due; - our obligation to replace any temporary notes, register the transfer or exchange of any notes, replace mutilated, destroyed, lost or stolen notes and maintain an office or agency for payments in respect of the notes; - the rights, powers, trusts, duties and immunities of the trustee; and - the legal defeasance provisions of the indenture. [Section 1202] To accomplish legal defeasance, the following must occur: - We must irrevocably deposit in trust for the benefit of all holders of notes money and/or U.S. government or U.S. government agency notes or bonds that will generate enough cash to make interest, principal and any other payments on the notes on their various due dates. - There must be a change in current U.S. federal tax law or an IRS ruling that lets us make that deposit without causing you to be taxed on the notes any differently than if we did not make the deposit and just repaid the notes ourselves. (Under current U.S. federal tax law, the deposit and our legal release from the securities would be treated as though we took back your notes and gave you your share of the cash and notes or bonds deposited in trust. In that event, you could recognize gain or loss on the notes you give back to us.) - We must deliver to the trustee a legal opinion of our counsel confirming the tax law change described above and that all of the conditions to legal defeasance in the indenture have been fulfilled. We will not be able to achieve legal defeasance if there is a continuing Event of Default under the indenture or if doing so would violate any other material agreements to which we are a party. If we ever did accomplish legal defeasance, as described above, you would have to rely solely on the trust deposit for 53 55 repayment on the notes. You could not look to us for repayment in the unlikely event of any shortfall. [Section 1204] Covenant Defeasance Under current U.S. federal tax law, we can make the same type of deposit described above and be released from certain covenants relating to the notes. The release from these covenants is called "covenant defeasance." In that event, you would lose the protection of these covenants but would gain the protection of having money and securities set aside in trust to repay the notes. [Section 1203] In order to achieve covenant defeasance, we must do the following: - deposit in trust for the benefit of all holders of the notes money and/or U.S. government or U.S. government agency notes or bonds that will generate enough cash to make interest, principal and any other payments on the notes on their various due dates. - deliver to the trustee a legal opinion of our counsel confirming that under current U.S. federal tax law we may make that deposit without causing you to be taxed on the notes any differently than if we did not make the deposit and just repaid the notes ourselves. The opinion must also state that all of the conditions to covenant defeasance in the indenture have been fulfilled. We will not be able to achieve covenant defeasance if there is a continuing Event of Default under the indenture or if doing so would violate any other material agreements to which we are a party. The indenture describes the covenants that we may fail to comply with without causing an Event of Default if we accomplish covenant defeasance. [Section 1204] If we elect to make a deposit resulting in covenant defeasance, the amount of money and/or U.S. government obligations deposited in trust should be sufficient to pay amounts due on the notes at the time of their maturity. However, if the maturity of the notes is accelerated due to the occurrence of an Event of Default, the amount in trust may not be sufficient to pay all amounts due on the notes. We will remain liable for the shortfall as described in the indenture. [Article 12] SATISFACTION AND DISCHARGE OF THE INDENTURE We will have no further obligations under the indenture as to all outstanding notes, other than surviving rights of registration of transfers of the notes, when: - all notes have been delivered to the trustee for cancellation; or all notes have become due and payable or, within one year, will become due and payable or be redeemed and we have deposited with the trustee funds sufficient to pay interest, principal and any other payments on all outstanding notes on their various due dates; - we have paid all other sums then due and payable under the indenture by us; and - we have delivered to the trustee an officers' certificate and an opinion of counsel, which, taken together, state that we have complied with all conditions precedent under the indenture relating to the satisfaction and discharge of the indenture. [Sections 401 and 402] GOVERNING LAW Legal interpretations of the indenture and notes will be made using the laws of the State of New York. [Section 113] CONCERNING THE TRUSTEE American Stock Transfer & Trust Company will act as trustee under the indenture. The indenture provides for indemnification of the trustee by us under certain circumstances. [Section 607] 54 56 The indenture limits the rights of the trustee to obtain payments of claims in certain cases if it becomes our creditor. While the trustee is permitted to engage in other transactions, if the trustee acquires any conflicting interests governed by the Trust Indenture Act of 1939, the trustee must either eliminate such conflict or resign. [Section 613 and 614] The trustee is the transfer agent and registrar for our common stock and series A preferred stock. Also, the trustee is the trustee under our 2001 Indenture and 2002 Indenture. CERTAIN DEFINITIONS Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided. (Section 101) "Acquired Indebtedness" means Indebtedness for Money Borrowed of a Person existing at the time such Person becomes a Restricted Subsidiary or assumed in connection with the acquisition by us or a Restricted Subsidiary of assets from such Person, and not incurred in connection with, or in anticipation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to be incurred on the date of the related acquisition of assets from any Person or the date the acquired Person becomes a Restricted Subsidiary. "Affiliate" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, "control", when used with respect to any specified Person, means the power to direct the management and policies of such Person, directly or, indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms "controlling" and "controlled" have meanings correlative to the foregoing. "Average Life" means, with respect to any Indebtedness for Money Borrowed, as at any date of determination the quotient obtained by dividing: - the sum of the products of: (1) the number of years (and any parts thereof from the date of determination to the date or dates of each successive scheduled principal payment (including, without limitation, any sinking fund or mandatory redemption payment requirements) of such Indebtedness for Money Borrowed multiplied by; (2) the amount of each such principal payment; by - the sum of all such principal payments. "Capitalized Lease Obligation" means, as to any Person, the obligations of such Person to pay rent or other amounts under the lease of (or other agreement conveying the right to use) real or personal property which obligations are required to be classified and accounted for as capital lease obligations on a balance sheet of such Person under GAAP and, for purposes of the indenture, the amount of such obligations at any date shall be the capital amount thereof at such date, determined in accordance with GAAP. "Change of Control" means the occurrence of any of the following: - the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of our and our Restricted Subsidiaries' assets taken as a whole to any "person" (as such term is used in Section 13(d)(3) of the Securities Exchange Act of 1934); - the adoption of a plan relating to our liquidation or dissolution; - the consummation of any transaction (including, without limitation, any purchase, sale, acquisition, disposition, merger or consolidation) the result of which is that any "person" (as defined above) becomes the "beneficial owner" (as such term is described in Rule 13d-3 and Rule 13d-5 under the 55 57 Securities Exchange Act of 1934), directly or indirectly, of more than 50% of the aggregate voting power of all classes of our Voting Stock, provided that the sale of our Voting Stock, preferred stock, or rights to acquire our Voting Stock or preferred stock to an underwriter in connection with a firm commitment underwriting shall not constitute a Change of Control; or - the first day on which a majority of the members of our board of directors are not Continuing Directors. "Consolidated EBITDA" means, for any period, determined in accordance with GAAP on a consolidated basis for us and our Restricted Subsidiaries, the sum of Consolidated Net Income, plus depreciation, depletion, amortization and other non-cash charges, income tax expense, and Consolidated Interest Expense, for such period, each as deducted in determining such Consolidated Net Income. "Consolidated Interest Expense" means, for any period, the interest expense for such period, which is required to be shown as such on both our and our Restricted Subsidiaries' financial statements, on a consolidated basis, prepared in accordance with GAAP. "Consolidated Net Income" means, for any period, the amount of our and our Restricted Subsidiaries' consolidated net income (loss) for such period, determined in accordance with GAAP; provided, however, that there shall be included in Consolidated Net Income any net extraordinary gains or losses for such period (less all fees and expenses related thereto); and, provided, further, that there shall not be included in Consolidated Net Income: - any net income (loss) of a Restricted Subsidiary for any portion of such period during which it was not a Consolidated Subsidiary; - any net income (loss) of businesses, properties or assets acquired or disposed of (by way of merger, consolidation, purchase, sale or otherwise) by us or any Restricted Subsidiary for any portion of such period prior to the acquisition thereof or subsequent to the disposition thereof; or - any net income for such period resulting from transfers of assets received by us or any Restricted Subsidiary from an Unrestricted Subsidiary. "Consolidated Subsidiary" means a Restricted Subsidiary the financial statements of which are consolidated with our financial statements. "Continuing Directors" means, as of any date of determination, any member of our board of directors who: - was a member of our board of directors on the date of the indenture; or - was nominated for election or elected to our board of directors with the approval of a majority of the Continuing Directors who were members of our board at the time of their nomination or election. "Credit Facility" means that certain Amended and Restated Credit Agreement, dated as of October 31, 1996, among us, Callon Petroleum Operating Company, Callon Offshore Production, Inc., the several banks and other financial institutions from time to time parties thereto (the "Banks"), and The Chase Manhattan Bank, as agent for the Banks, as the same may be amended, modified, supplemented, extended, restated, replaced, renewed or refinanced from time to time. "Event of Default" has the meaning specified under "Events of Default and Remedies." "GAAP" means United States generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles board of the American Institute of Certified Public Accountants and statements' and pronouncements of the Financial Accounting Standards Board in effect on the date of the indenture. 56 58 "Indebtedness for Money Borrowed" means any of the following of our or any Restricted Subsidiary's obligations: - any obligation, contingent or otherwise, for borrowed money or for the deferred purchase price of property, assets, securities or services (including, without limitation, any interest accruing subsequent to an Event of Default; - all obligations (including the notes) evidenced by bonds, notes, debentures or other similar instruments; - all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), except any such obligation that constitutes a trade payable and an accrued liability arising in the ordinary course of business, if and to the extent any of the foregoing indebtedness would appear as a liability upon a balance sheet prepared in accordance with GAAP; - all Capitalized Lease Obligations; - our liabilities actually due and payable under bankers acceptances and letters of credit; - all indebtedness of the type referred to in the preceding five clauses secured by (or for which the holder of such indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien upon or security interest in our or any Restricted Subsidiary's property (including, without limitation, accounts and contract rights), even though neither we nor any Restricted Subsidiary has assumed or become liable for the payment of such indebtedness; and - any guarantee or endorsement (other than for collection or deposit in the ordinary course of business) or discount with recourse of, or other agreement, contingent or otherwise, to purchase, repurchase, or otherwise acquire, to supply, or advance funds or become liable with respect to, any indebtedness or any obligation of the type referred to in any of the preceding six clauses, regardless of whether such obligation would appear on a balance sheet. Provided, however, that Indebtedness for Money Borrowed shall not include: - Production Payments and Reserve Sales; - any liability for gas balancing incurred in the ordinary course of business; - our or a Restricted Subsidiary's accounts payable or other obligations in the ordinary course of business in connection with the obtaining of goods or services; and - any liability under any and all: (1) employment or consulting agreements or employee benefit plans or arrangements; and (2) futures contracts, forward contracts, swap, cap or collar contracts, option contracts, or other similar derivative agreements. "Lien" means any mortgage, charge, pledge, lien (statutory or other), security interest, hypothecation, assignment for security, claim, or preference or priority or other encumbrance or similar agreement or preferential arrangement of any kind or nature whatsoever (including, without limitation, any agreement to give or grant a Lien or any lease, conditional sale or other title retention agreement having substantially the same economic effect as any of the foregoing) upon or with respect to any property of any kind. A Person shall be deemed to own subject to a Lien any property which such Person has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement. 57 59 "Material Subsidiary" means any Restricted Subsidiary whose assets or revenues comprise at least five percent (5%) of our and our Restricted Subsidiaries' assets or revenues on a consolidated basis as of the end of, or for, our most recently completed fiscal quarter, as determined from time to time. "Non-payment Event of Default" means any event (other than a Payment Event of Default), the occurrence of which (with or without notice or the passage of time) entitles one or more Persons to accelerate the maturity of any Specified Senior Indebtedness. "Pari Passu Indebtedness" means any of our Indebtedness for Money Borrowed that is pari passu in right of payment to the notes. "Payment Event of Default" means any default in the payment or required prepayment of principal of (or premium, if any, on) or interest on any Specified Senior Indebtedness when due (whether at final maturity, upon scheduled installment; upon acceleration or otherwise). "Permitted Indebtedness" means any of the following: - Indebtedness for Money Borrowed outstanding on the date of the indenture (and not repaid or defeased with the proceeds of the offering of the notes); - Our Indebtedness for Money Borrowed to a Restricted Subsidiary and Indebtedness for Money Borrowed of a Restricted Subsidiary to us or a Restricted Subsidiary; provided, however, that upon any event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any subsequent transfer of any such Indebtedness for Money Borrowed (except to us or a Restricted Subsidiary), such Indebtedness for Money Borrowed shall be deemed, in each case, to be incurred and shall be treated as an incurrence for purposes of the "Incurrence of Indebtedness" covenant at the time the Restricted Subsidiary in question ceased to be a Restricted Subsidiary; - any guarantee of Senior Indebtedness incurred in compliance with the "Incurrence of Indebtedness" covenant, by us or a Restricted Subsidiary; and - any renewals, substitutions, refinancings or replacements (each, for purposes of this clause, a "refinancing") by us or a Restricted Subsidiary of any Indebtedness for Money Borrowed outstanding on the date of the indenture (and not repaid or defeased with the proceeds of the offering of the notes), including any successive refinancings by us or such Restricted Subsidiary, so long as: (1) any such new Indebtedness for Money Borrowed shall be in a principal amount that does not exceed the principal amount (or, if such Indebtedness for Money Borrowed being refinanced provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount as of the date of determination) so refinanced plus the amount of any premium required to be paid in connection with such refinancing pursuant to the terms of the Indebtedness for Money Borrowed refinanced or the amount of any premium reasonably determined by us or such Restricted Subsidiary as necessary to accomplish such refinancing, plus the amount of our or such Restricted Subsidiary's expenses incurred in connection with such refinancing; and (2) in the case of any refinancing of our Indebtedness for Money Borrowed that is not Senior Indebtedness, such new Indebtedness for Money Borrowed is either pari passu with the notes or subordinated to the notes at least to the same extent as the Indebtedness being refinanced; and (3) such new Indebtedness for Money Borrowed has an Average Life equal to or longer than the Average Life of the Indebtedness for Money Borrowed being refinanced and a final Stated Maturity equal to or later than the final Stated Maturity of the Indebtedness for Money Borrowed being refinanced. 58 60 "Permitted Junior Securities" means any of our or any successor obligor's equity securities or subordinated debt securities with respect to the Senior Indebtedness provided for by a plan of reorganization or readjustment that, in the case of any such subordinated debt securities, are subordinated in right of payment to all Senior Indebtedness that may at the time be outstanding to substantially the same degree as, or to a greater extent than, the notes are so subordinated as provided in the indenture. "Permitted Liens" means any of the following types of Liens: - Liens existing as of the date the notes are first issued (except to the extent such Liens secure any Pari Passu Indebtedness or Subordinated Indebtedness that is repaid or defeased with proceeds of the offering of the notes), and any renewal, extension or refinancing of any such Lien provided that thereafter such Lien extends only to the properties that were subject to such Lien prior to the renewal, extension or refinancing thereof; - Liens securing the notes; and - Liens in favor of us. "Person" means any individual, corporation, partnership, joint venture, association, joint stock company, limited liability company, trust, unincorporated organization or government or any agency or political subdivision thereof. "Production Payments and Reserve Sales" means the grant or transfer to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), master limited partnership interest or other interest in oil and gas properties, which reserves the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard and/or subject to the obligation of the grantor or transferor to indemnify for environmental matters. "Restricted Subsidiary" means any Subsidiary, whether existing on or after the date of the Indenture, unless such Subsidiary is an Unrestricted Subsidiary or is designated as an Unrestricted Subsidiary pursuant to the terms of the indenture; "Senior Indebtedness" means the principal amount of, and interest on and all other amounts due on or in connection with: - any of our Indebtedness for Money Borrowed, whether now outstanding or hereafter created, incurred, assumed or guaranteed, unless in the instrument creating or evidencing such Indebtedness for Money Borrowed or pursuant to which such Indebtedness for Money Borrowed is outstanding it is provided that such indebtedness is subordinate in right of payment or in rights upon liquidation to any other of our Indebtedness for Money Borrowed; and - all renewals, extensions and refundings of any such indebtedness. "Specified Senior Indebtedness" means: - all of our Senior Indebtedness in respect of the Credit Facility and any renewals, amendments, extensions, supplements, modifications, deferrals, refinancings, or replacements (each, for purposes of this definition, a "refinancing") thereof by us, including any successive refinancings thereof by us; and - any other Senior Indebtedness and any refinancings thereof by us having a principal amount of at least $5 million as of the date of determination and provided that the agreements, indentures or other instruments evidencing such Senior Indebtedness or pursuant to which such Senior 59 61 Indebtedness was issued specifically designates such Senior Indebtedness as "Specified Senior Indebtedness" for purposes of the indenture. For purposes of this definition, a refinancing of any Specified Senior Indebtedness shall be treated as Specified Senior Indebtedness only if the Senior Indebtedness issued in such refinancing ranks or would rank pari passu with the Specified Senior Indebtedness refinanced and only if the Senior Indebtedness issued in such refinancing is permitted by the covenant described under "Certain Covenants -- Limitation of Indebtedness for Money Borrowed." "Stated Maturity" with respect to any note or any installment of principal thereof or interest thereon means the date established by the Indenture as the fixed date on which the principal of such note or such installment of principal or interest is due and payable, and, when used with respect to any other Indebtedness for Money Borrowed or any installment of interest thereon, means the date specified in the instrument evidencing or governing such Indebtedness for Money Borrowed as the fixed date on which the principal of such Indebtedness for Money Borrowed or such installment of interest is due and payable. "Subordinated Indebtedness" means our Indebtedness for Money Borrowed which is expressly subordinated in right of payment to the notes, including, without limitation, the convertible debentures described under "Description of Capital Stock -- Convertible Debentures." "Subsidiary" means any corporation of which at the time of determination we or one or more Subsidiaries own or control directly or indirectly more than 50% of the Voting Stock. "2001 Indenture" means that certain indenture dated as of November 27, 1996 between Callon and American Stock Transfer & Trust Company, as trustee, as the same may have been amended or supplemented from time to time prior to the date hereof. "2002 Indenture" means that certain indenture dated as of July 31, 1997 between Callon and American Stock Transfer & Trust Company, as trustee, as the same may have been amended or supplemented from time to time prior to the date hereof. "Unrestricted Subsidiary" means: - any Subsidiary that at the time of determination will be designated an Unrestricted Subsidiary by the board of directors as provided below; and - any Subsidiary of an Unrestricted Subsidiary. The board of directors may designate any Subsidiary as an Unrestricted Subsidiary so long as neither we nor any Restricted Subsidiary is directly or indirectly liable pursuant to the terms of any Indebtedness for Money Borrowed of such Subsidiary or have any assets or properties which are subject to any Lien securing any Indebtedness for Money Borrowed of such Subsidiary. Any such designation by the board of directors shall be evidenced to the trustee by filing a board resolution with the trustee giving effect to such designation. The board of directors may designate any Unrestricted Subsidiary as a Restricted Subsidiary if, immediately after giving effect to such designation: - no Event of Default shall have occurred and be continuing; and - we could occur $l.00 of additional Indebtedness for Money Borrowed (other than Permitted Indebtedness) under the "Incurrence of Indebtedness" covenant. "Voting Stock" means stock, interests, participations, rights in or other equivalents in the equity interests (however designated) with respect to a corporation having general voting power under ordinary circumstances to elect at least a majority of the board of directors, managers or trustees of such corporation, provided that, for the purposes hereof, stock which carries only the right to vote conditionally on the happening of an event shall not be considered Voting Stock whether or not such event shall have happened. 60 62 DESCRIPTION OF BANK CREDIT FACILITY AND OTHER INDEBTEDNESS BANK CREDIT FACILITY Borrowings under our bank credit facility are secured by mortgages covering substantially all of our producing oil and gas properties. Currently, the credit facility provides for a $50 million borrowing base which is adjusted periodically on the basis of a discounted present value of future net cash flows attributable to our proved producing oil and gas reserves. Our borrowing base is currently being evaluated by our bank and we expect our borrowing base to be reduced in connection with the offering of the notes. Under our bank credit facility, the interest rate is equal to the lender's prime rate plus 0.125% but increases to prime plus 0.50% if we borrow more than 50% of our borrowing base. At our option, we may fix the interest rate on all or a portion of the outstanding principal balance at 1.125% above a defined "Eurodollar" rate for periods up to six months which increases to 1.5% if we borrow more than 50% of our borrowing base. The weighted average interest rate for the total debt outstanding at December 31, 1998 and 1997 was 6.68% and 8.50%, respectively. Under the credit facility, a quarterly commitment fee of 0.25% is assessed on the unused portion of the borrowing base which increases to 0.375% if we borrow more than 50% of our borrowing base. We may borrow, pay, reborrow and repay under the credit facility until October 31, 2000, on which date we must repay in full all amounts then outstanding. Borrowings under the bank credit facility are guaranteed by our material subsidiaries. The bank credit facility has several customary covenants including, but not limited to, covenants that limit our ability to: - repurchase capital stock; - guaranty borrowings or borrow additional funds; - prepay other indebtedness; - merge; - sell property; - engage in transactions with our affiliates; - hedge our production; and - make acquisitions. We are also required by the bank to maintain several financial ratios and conditions so that the bank can monitor our financial stability. OUTSTANDING NOTES On November 27, 1996, we sold $24.2 million aggregate principal amount of 10% senior subordinated notes due December 15, 2001. Payments of principal, interest and premium, if any, under these notes are subordinate to all of our existing and future senior indebtedness. These notes rank equally with the notes offered in this prospectus. The 10% senior subordinated notes are not entitled to the benefit of any mandatory sinking fund payments and are subject to redemption at anytime on or after December 15, 1997, at our option, at par plus accrued and unpaid interest to the date fixed for redemption. On July 31, 1997, we sold $36 million aggregate principal amount of our 10.125% Series A Senior Subordinated Notes due September 15, 2002 through a private placement transaction. On September 10, 1997, we commenced an offer to exchange the notes for a like principal amount of 10.125% Series B Senior Subordinated Notes due September 15, 2002. The form and terms of the series B notes are identical in all material respects to the terms of the series A notes, except the series A notes have certain transfer restrictions and provisions relating to registration rights. Payments of principal, interest and premium, if any, under the series A and series B notes are subordinate to all of our existing and future senior indebtedness and rank equally with the notes offered in this prospectus. The series A and series B notes are not entitled to the benefit of any mandatory sinking fund payments and are subject to 61 63 redemption at anytime on or after September 15, 2000, at our option, at par plus accrued and unpaid interest to the date fixed for redemption. Our outstanding notes contain covenants substantially similar to the notes. However, several covenants contained in the indenture for the 10.125% notes are more restrictive than covenants contained in the indenture for the 10% notes and the notes offered in this document. If we violate these covenants we may trigger cross-default and cross-acceleration provisions contained in the indentures for the 10% notes and the notes. See "Description of the Notes -- Certain Covenants." DESCRIPTION OF CAPITAL STOCK COMMON STOCK We are authorized to issue up to 20,000,000 shares of common stock, $0.01 par value. As of March 31, 1999, 8,545,517 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. 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 our securities. In the event of our liquidation, dissolution or winding up, holders of common stock are entitled to share equally and ratably in all of the assets remaining, if any, after satisfaction of all our debts and liabilities, 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 We are authorized to issue 2,500,000 shares of preferred stock, $0.01 par value per share. Our 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 our voluntary liquidation, dissolution or winding up of our affairs, conversions rights and voting powers. We have 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 In November 1995, we issued and sold 1,315,500 shares of series A preferred stock. 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 ours ranking junior to the series A preferred stock, nor may any common stock or any other stock of ours ranking junior to or on a parity with the series A preferred stock be redeemed, purchased or otherwise acquired for any consideration by us (except by conversion into or exchange for stock of Callon 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. From time to time, we may 62 64 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 our best interests. 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. We or our successor may elect to distribute cash to such holders in lieu of common stock at an equal value. Exchange. The series A preferred stock may be exchanged at our option 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 we 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 our directors 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, we 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. In a December 1998 private transaction, a preferred stockholder elected to convert 59,689 shares of preferred stock into 136,867 shares of our common stock. Subsequent to December 31, 1998, several other preferred stockholders, through private transactions, converted 210,350 shares of preferred stock into 502,632 shares of our common stock under similar terms. CONVERTIBLE DEBENTURES At our option, the series A preferred stock may be converted into convertible debentures. The convertible debentures, if issued, will be issued under an indenture between Callon and Bank One, Columbus, NA, as trustee, a copy of which is filed as an exhibit to our Form 10-K for fiscal year 1996. General. The convertible debentures will be our unsecured, subordinated obligations, limited in aggregate principal amount to the aggregate liquidation preference of the series A preferred stock and will mature on December 31, 2010. We must 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. From time to time we may reduce the conversion price in order that certain stock-related distributions which may be made by us to our 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 Callon, including the notes. During the continuation of any default in the payment of principal, interest or premium on any senior indebtedness, no payment with respect to the principal, 63 65 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 our option 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: - failure to pay principal or premium, if any, on any convertible debenture when due at maturity, upon redemption or otherwise; - failure to pay an interest on any convertible debenture when due and continuing for 30 days; - breach of such indenture or convertible debentures by us; - certain events in bankruptcy, insolvency or reorganization; - default on indebtedness (other than non-recourse indebtedness) resulting in more than $7,500,000 becoming due and payable prior to its maturity; or - a judgment or decree entered against us involving a liability of $7,500,000 or more. UNDERWRITING We have entered into an underwriting agreement with the underwriters for the offering named below. Subject to certain conditions, each underwriter has severally agreed to purchase the principal amount of notes indicated in the following table.
PRINCIPAL AMOUNT UNDERWRITERS OF NOTES - ------------ ---------------- A.G. Edwards & Sons, Inc.................................... $ Morgan Keegan & Company, Inc................................ ----------- Total............................................. $40,000,000 ===========
Notes sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any notes sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price of up to % of the principal amount of the notes. Any such securities dealers may resell any notes purchased from the underwriters to other brokers or dealers at a discount from the initial public offering price up to % per note from the initial public offering price. If all the notes are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The notes are a new issue of securities with no established trading market. We have applied for listing of the notes on the New York Stock Exchange. We have been advised by the underwriters that the underwriters intend to make a market in the notes but are not obligated to do so and may discontinue market making at any time without notice. No assurance can be given as to the liquidity of the trading market for the notes. In connection with the offering, the underwriters may purchase and sell notes in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater amount of notes than they are required to purchase in the offering. Stabilizing transactions consist of certain bids or purchases made for the purpose of preventing or retarding a decline in the market price of the notes while the offering is in progress. 64 66 The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the underwriters have repurchased notes sold by or for the account of such underwriter in stabilizing or short covering transactions. These activities by the underwriters may stabilize, maintain or otherwise affect the market price of the notes. As a result, the price of the notes may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. These transactions may be effected in the over-the-counter market or otherwise. We have agreed to indemnify the several underwriters against various liabilities, including liabilities under the Securities Act of 1933. We estimate that the expenses of the offering, excluding underwriting discounts and commissions, will be approximately $300,000. VALIDITY OF THE NOTES Our lawyers, Butler & Binion, L.L.P., Houston, Texas, will issue opinions about the validity of the notes for us. Certain legal matters will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas. EXPERTS The audited consolidated financial statements as of December 31, 1998, and for the three years in the period ended December 31, 1998, included elsewhere in this registration statement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. The information appearing in this prospectus regarding our quantities 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. WHERE YOU CAN FIND MORE INFORMATION We file annual, quarterly and special reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SEC's web site at http://www.sec.gov. You may also read and copy any document we file at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549, and at the regional offices of the SEC located at 7 World Trade Center, Suite 1300, New York, New York 10048 and at 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. You may obtain information on the operation of the SEC's public reference room in Washington, D.C. by calling the SEC at 1-800-SEC-0330. We also file such information with the New York Stock Exchange. Such reports, proxy statements and other information may be read and copied at 30 Broad Street, New York, New York 10005. The SEC allows us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this prospectus, and information that we file later with the SEC will automatically update and supersede this information. We incorporate by reference the documents listed below and any further filings made with the SEC under Sections 13(a), 13(c), 14, or 65 67 15(d) of the Securities Exchange Act of 1934 (the "Exchange Act") until we sell all of the securities or we terminate this offering: - Our Annual Report on Form 10-K for the year ended December 31, 1998; - Our Quarterly Report on Form 10-Q for the quarter ended March 31, 1999; and - Our Current Reports on Form 8-K, filed on February 3, 1999 and March 3, 1999. You may request a copy of these filings at no cost, by writing or telephoning us at the following address: H. Michael Tatum 200 North Canal Street Natchez, MS 39120 1 (800) 451-1294 You should rely only on the information incorporated by reference or provided in this prospectus or any prospectus supplement. We have not authorized anyone else to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of those documents. 66 68 GLOSSARY OF OIL AND GAS TERMS TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS - BBL -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons. - BCF -- One billion cubic feet of natural gas. - BCFE -- One billion cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf. - MBBL -- One thousand Bbl. - MCF -- One thousand cubic feet of natural gas. - MCFE -- One thousand cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf. - MMCF -- One million cubic feet of natural gas. - MMCFE -- One million cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf. TERMS USED TO DESCRIBE OUR INTERESTS IN WELLS AND ACREAGE - GROSS OIL AND GAS WELLS OR ACRES -- Our gross wells or gross acres represents the total number of wells or acres in which we own a working interest. - NET OIL AND GAS WELLS OR ACRES -- Determined by multiplying "gross" oil and natural gas wells or acres by the working interest that we own in such wells or acres represented by the underlying properties. TERMS USED TO ASSIGN A PRESENT VALUE TO OUR RESERVES - STANDARDIZED MEASURE OF PROVED RESERVES -- The present value, discounted at 10%, of the pre-tax future net cash flows attributable to estimated net proved reserves. We calculate this amount by assuming that we will sell the oil and gas production attributable to the proved reserves estimated in our independent engineer's reserve report for the prices we received for the production on the date of the report, unless we had a contract to sell the production for a different price. We also assume that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. The assumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes using rates in effect on the date of the report are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of our proved reserves. The standardized measure of our proved reserves is disclosed in our financial statements at note 12. - DISCOUNTED PRESENT VALUE -- The discounted present value of proved reserves is identical to the standardized measure, except that estimated future income taxes are not deducted in calculating future net cash flows. We disclose the discounted present value without deducting estimated income taxes to provide what we believe is a better basis for comparison of our reserves to other producers who may have different tax rates. TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES - PROVED RESERVES -- The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. 67 69 The Securities and Exchange Commission definition of proved oil and gas reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows: PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (b) Reserves which can be produced economically through application of improved recovery, techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. - PROVED DEVELOPED RESERVES -- Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. - PROVED UNDEVELOPED RESERVES -- Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. TERMS WHICH DESCRIBE THE COST TO ACQUIRE OUR RESERVES - RESERVE REPLACEMENT COSTS -- Our reserve replacement costs compare the amount we spent to explore for oil and gas and to drill and complete wells during a period, with the increases in reserves during the period. This amount is calculated by dividing the net change in our evaluated oil and property costs during a period by the change in proved reserves plus production over the same period. TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES - RESERVE LIFE -- A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve life equals the estimated net proved reserves attributable to a property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated. TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF OUR OIL AND GAS PROPERTIES - ROYALTY INTEREST -- A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no 68 70 right to consent to or approve the operation and development of the property, while the owners of the working interest have the exclusive right to exploit the mineral on the land. Working interest -- A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property. TERMS USED TO DESCRIBE SEISMIC OPERATIONS - Seismic data - Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations. - 2-D seismic data - 2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data. - 3-D seismic - 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated. 69 71 INDEX TO FINANCIAL STATEMENTS
PAGE ---- Report of Independent Public Accountants.................... F-2 Consolidated Balance Sheets as of December 31, 1998, December 31, 1997 and March 31, 1999...................... F-3 Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 1998 and the Three Months Ended March 31, 1999 and 1998...................... F-4 Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 1998 and the Three Months Ended March 31, 1999..................... F-5 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 1998 and the Three Months Ended March 31, 1999 and 1998...................... F-6 Notes to Consolidated Financial Statements.................. F-7
F-1 72 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, 1998 and 1997, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Callon Petroleum Company and subsidiaries, as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. /s/ ARTHUR ANDERSEN LLP New Orleans, Louisiana, February 19, 1999 F-2 73 CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) ASSETS
DECEMBER 31, MARCH 31, --------------------- 1999 1998 1997 ------------ --------- --------- (UNAUDITED) Current assets: Cash and cash equivalents............................... $ 4,150 $ 6,300 $ 15,597 Accounts receivable..................................... 5,688 6,024 12,168 Other current assets.................................... 1,648 1,924 723 --------- --------- --------- Total current assets............................ 11,486 14,248 28,488 --------- --------- --------- Oil and gas properties, full-cost accounting method: Evaluated properties.................................... 462,871 444,579 398,046 Less accumulated depreciation, depletion and amortization......................................... (349,236) (345,353) (282,891) --------- --------- --------- 113,635 99,226 115,155 Unevaluated properties excluded from amortization....... 38,328 42,679 35,339 --------- --------- --------- Total oil and gas properties.................... 151,963 141,905 150,494 --------- --------- --------- Pipeline and other facilities, net........................ 6,102 6,182 6,504 Other property and equipment, net......................... 1,676 1,753 1,938 Deferred tax asset........................................ 16,105 16,348 1,248 Long-term gas balancing receivable........................ 191 199 242 Other assets, net......................................... 934 1,017 1,507 --------- --------- --------- Total assets.................................... $ 188,457 $ 181,652 $ 190,421 ========= ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities................ $ 8,673 $ 11,257 $ 12,389 Undistributed oil and gas revenues...................... 1,874 1,720 2,259 Accrued net profits interest payable.................... 363 129 1,121 --------- --------- --------- Total current liabilities....................... 10,910 13,106 15,769 --------- --------- --------- Accounts payable and accrued liabilities to be refinanced.............................................. 5,981 3,000 -- Long-term debt............................................ 86,250 78,250 60,250 Accrued retirement benefits............................... 2,269 2,323 297 Long-term gas balancing payable........................... 317 489 404 --------- --------- --------- Total liabilities............................... 105,727 97,168 76,720 --------- --------- --------- Stockholders' equity: Preferred Stock, $.01 par value; 2,500,000 shares authorized; 1,045,461 shares of Convertible Exchangeable Preferred Stock, Series A issued and outstanding at March 31, 1999 and 1,255,811 and 1,315,500 outstanding at December 31, 1998 and 1997, respectively, with a liquidation preference of $26,136,525 at March 31, 1999........................ 10 13 13 Common Stock, $.01 par value; 20,000,000 shares authorized; 8,545,517, 8,178,406 and 7,855,216 shares outstanding at March 31, 1999, December 1998 and 1997, respectively................................... 85 82 79 Treasury stock (98,577 shares at cost).................. (1,177) (915) -- Unearned compensation -- restricted stock............... -- -- (2,232) Capital in excess of par value.......................... 108,296 109,429 106,433 Retained earnings (deficit)............................. (24,484) (24,125) 9,408 --------- --------- --------- Total stockholders' equity...................... 82,730 84,484 113,701 --------- --------- --------- Total liabilities and stockholders' equity...... $ 188,457 $ 181,652 $ 190,421 ========= ========= =========
The accompanying notes are an integral part of these financial statements. F-3 74 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED MARCH 31, YEARS ENDED DECEMBER 31, ---------------- ---------------------------- 1999 1998 1998 1997 1996 ------ ------- -------- ------- ------- (UNAUDITED) Revenues: Oil and gas sales.......................... $7,969 $11,045 $ 35,624 $42,130 $25,764 Interest and other......................... 405 447 2,094 1,508 946 ------ ------- -------- ------- ------- Total revenues..................... 8,374 11,492 37,718 43,638 26,710 ------ ------- -------- ------- ------- Cost and expenses: Lease operating expenses................... 1,608 1,941 7,817 8,123 7,562 Depreciation, depletion and amortization... 3,963 5,570 19,284 16,488 9,832 General and administrative................. 1,061 1,502 5,285 4,433 3,495 Interest................................... 1,027 651 1,925 1,957 313 Accelerated vesting and retirement benefits................................ -- -- 5,761 -- -- Impairment of oil and gas properties....... -- -- 43,500 -- -- ------ ------- -------- ------- ------- Total costs and expenses........... 7,659 9,664 83,572 31,001 21,202 ------ ------- -------- ------- ------- Income (loss) from operations................ 715 1,828 (45,854) 12,637 5,508 Income tax expense (benefit)............... 243 621 (15,100) 4,200 50 ------ ------- -------- ------- ------- Net income (loss)............................ 472 1,207 (30,754) 8,437 5,458 Preferred stock dividends.................... 831 699 2,779 2,795 2,795 ------ ------- -------- ------- ------- Net income (loss) available to common shares..................................... $ (359) $ 508 $(33,533) $ 5,642 $ 2,663 ====== ======= ======== ======= ======= Net income (loss) per common share: Basic...................................... $ (.04) $ .06 $ (4.17) $ .91 $ .46 ====== ======= ======== ======= ======= Diluted.................................... $ (.04) $ .06 $ (4.17) $ .88 $ .45 ====== ======= ======== ======= ======= Shares used in computing net income (loss) per common share: Basic...................................... 8,477 8,015 8,034 6,194 5,835 ====== ======= ======== ======= ======= Diluted.................................... 8,477 8,221 8,034 6,422 5,952 ====== ======= ======== ======= =======
The accompanying notes are an integral part of these financial statements. F-4 75 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
UNEARNED COMPENSATION CAPITAL IN RETAINED PREFERRED COMMON TREASURY RESTRICTED EXCESS OF EARNINGS STOCK STOCK STOCK STOCK PAR VALUE (DEFICIT) --------- ------ -------- ------------ ---------- --------- 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......................... -- -- -- -- -- 8,437 Sale of common stock............... -- 19 -- -- 29,249 -- Preferred stock dividends.......... -- -- -- -- -- (2,795) Tax benefits related to stock compensation plans.............. -- -- -- -- 36 -- Shares issued pursuant to employee benefit and option plan......... -- -- -- -- 392 -- Restricted stock plan.............. -- 2 -- (3,153) 2,729 -- Earned portion of restricted stock........................... -- -- -- 921 -- -- --- --- ------- ------- -------- -------- Balances, December 31, 1997.......... 13 79 -- (2,232) 106,433 9,408 Net income (loss).................. -- -- -- -- -- (30,754) Preferred stock dividends.......... -- -- -- -- 15 (2,779) Shares issued pursuant to employee benefit and option plan......... -- -- -- -- 235 -- Employee stock purchase plan....... -- -- -- -- 163 -- Restricted stock plan.............. -- 2 -- (2,731) 2,584 -- Earned portion of restricted stock........................... -- -- -- 4,963 -- -- Conversion of preferred shares to common.......................... -- 1 -- -- (1) -- Stock buyback plan................. -- -- (915) -- -- -- --- --- ------- ------- -------- -------- Balances, December 31, 1998.......... 13 82 (915) -- 109,429 (24,125) Net income (loss).................. -- -- -- -- -- 472 Preferred stock dividends.......... -- -- -- -- 276 (831) Shares issued pursuant to employee benefit and option plan......... -- -- -- -- 141 -- Employee stock purchase plan....... -- -- -- -- 66 -- Restricted stock plan.............. -- (2) -- -- (1,613) -- Earned portion of restricted stock........................... -- -- -- -- -- Conversion of preferred shares to common.......................... (3) 5 -- -- (3) -- Stock buyback plan................. -- -- (262) -- -- -- --- --- ------- ------- -------- -------- Balances, March 31, 1999 (Unaudited)........................ $10 $85 $(1,177) $ -- $108,296 $(24,484) === === ======= ======= ======== ========
The accompanying notes are an integral part of these financial statements. F-5 76 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
THREE MONTHS ENDED MARCH 31, YEARS ENDED DECEMBER 31, ------------------- ------------------------------ 1999 1998 1998 1997 1996 -------- -------- -------- -------- -------- (UNAUDITED) Cash flows from operating activities: Net income (loss)............................... $ 472 $ 1,207 $(30,754) $ 8,437 $ 5,458 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization..... 4,093 5,697 19,791 16,924 10,131 Impairment of oil and gas properties......... -- -- 43,500 -- -- Amortization of deferred costs............... 141 164 619 467 114 Deferred income tax expense (benefit)........ 243 621 (15,100) 4,200 50 Noncash compensation related to stock compensation plans......................... 140 634 7,583 1,224 72 Changes in current assets and liabilities: Accounts receivable........................ 336 1,946 6,144 493 (4,332) Other current assets....................... 276 (1,004) (1,201) (207) (278) Current liabilities........................ (2,462) (65) (860) (3,809) 4,049 Change in gas balancing receivable........... 8 (23) 43 418 (41) Change in gas balancing payable.............. (172) 52 85 14 (42) Change in other long-term liabilities........ (52) -- -- 249 (28) Change in other assets, net.................. (58) (82) (129) (1,073) (830) -------- -------- -------- -------- -------- Cash provided (used) by operating activities................................. 2,965 9,147 29,721 27,337 14,323 -------- -------- -------- -------- -------- Cash flows from investing activities: Capital expenditures............................ (13,884) (12,736) (64,105) (89,609) (37,637) Cash proceeds from sale of mineral interests.... 154 339 9,909 4,450 1,574 -------- -------- -------- -------- -------- Cash provided (used) by investing activities................................. (13,730) (12,397) (54,196) (85,159) (36,063) -------- -------- -------- -------- -------- Cash flows from financing activities: Change in accrued liabilities for capital expenditures................................. -- -- (2,396) 3,610 3,346 Increase in accounts payable and accrued liabilities to be refinanced................. 2,981 -- 3,000 -- -- Equity issued related to employee stock plans... 66 171 414 90 -- Purchase of treasury shares..................... (262) -- (915) -- -- Payments on debt................................ -- -- -- (49,200) (25,850) Proceeds from debt issuance..................... 8,000 -- 18,000 85,200 50,000 Common stock canceled........................... (1,615) (145) (130) (422) -- Sale of common stock............................ -- -- -- 29,267 -- Increase (decrease) in accrued preferred stock dividends payable............................ -- -- (16) -- 443 Dividends on preferred stock.................... (555) (699) (2,779) (2,795) (2,795) -------- -------- -------- -------- -------- Cash provided (used) by financing activities................................. 8,615 (673) 15,178 65,750 25,144 -------- -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents..................................... (2,150) (3,923) (9,297) 7,928 3,404 Cash and cash equivalents: Balance, beginning of period.................... 6,300 15,597 15,597 7,669 4,265 -------- -------- -------- -------- -------- Balance, end of period.......................... $ 4,150 $ 11,674 $ 6,300 $ 15,597 $ 7,669 ======== ======== ======== ======== ========
The accompanying notes are an integral part of these financial statements. F-6 77 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (INFORMATION WITH RESPECT TO THE PERIODS ENDING MARCH 31, 1999 AND 1998 IS UNAUDITED.) 1. ORGANIZATION Callon Petroleum 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 and combination of several related entities (referred to herein collectively as the "Constituent Entities"). The combination of the businesses and properties of the Constituent Entities with the Company was completed on September 16, 1994 (the "Consolidation"). As a result of the Consolidation, all of the businesses and properties of the Constituent Entities are owned (directly or indirectly) by the Company. Certain registration rights were granted to the stockholders of certain of the Constituent Entities. 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, Texas and offshore Gulf of Mexico. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation and Reporting The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. 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 June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 ("FAS 133"), Accounting for Derivative Instruments and Hedging Activities. The Statement establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. FAS 133 is effective for fiscal years beginning after June 15, 1999, with earlier application permitted. The Company has not yet determined the timing or method of the adoption of FAS 133 and thus cannot quantify the impact of adoption. However, the Statement will create volatility in equity through other comprehensive income. 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 was effective for the Company in 1998. The Company does not have any items of other comprehensive income. Also in 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 F-7 78 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the way that public business enterprises report information about operating segments in annual financial statements and requires that those enterprises report selected information about operating segments in interim financial reports issued to shareholders. The Company has only one operating segment and thus separate segment disclosure is not required. 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 capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and gas properties as well as other directly identifiable general and administrative costs associated with such activities. Costs associated with unevaluated properties are excluded from amortization. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold or management determines these costs have been impaired. Costs of properties, including future development and net future site restoration, dismantlement and abandonment costs, which have proved reserves and those which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. If the total capitalized costs of oil and gas properties, net of amortization, exceed the sum of (1) the estimated future net revenues from proved reserves at current prices and discounted at 10% and (2) the lower of cost or market of unevaluated properties (the full-cost ceiling amount), net of tax effects, then such excess is charged to expense during the period in which the excess occurs. See Note 8. 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 December 31, 1998 and 1997 and March 31, 1999, 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 and other facilities is provided using the straight-line method over estimated lives of 15 to 27 years. 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. F-8 79 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Accounts Receivable Accounts receivable consists primarily of accrued oil and gas production receivable. The balance in the reserve for doubtful accounts included in accounts receivable is $38,000, $38,000 and $36,000 at March 31, 1999, December 31, 1998 and 1997, respectively. Net recoveries were $2,000 in 1998 and net charge offs were $357,000 and $88,000 in 1997 and 1996. There were no provisions to expense in the three year period ended December 31, 1998 and the three month period ending March 31, 1999. For the year ended December 31, 1998, three companies purchased 23%, 26% and 22%, respectively of the Company's natural gas and oil production. All three customers purchased production primarily from Callon owned interests in Federal OCS leases, CB40, MP163, MP 164/165, MB 864 and MB 952/955 fields. Because of the nature of oil and gas operations and the marketing of production, the Company believes that the loss of these customers would not have a significant adverse impact on the Company's ability to sell its production. Statements of Cash Flows For purposes of the Consolidated Financial Statements, 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, 1998. During the years ended December 31, 1998, 1997 and 1996, the Company made cash payments of $6,229,000, $4,167,000, and $251,000, respectively, for interest charged on its indebtedness and $1,663,000 for the three months ended March 31, 1999. Per Share Amounts In February 1997, the Financial Accounting Standards Board issued Statement No. 128 ("FAS 128"), Earnings per Share, which generally simplified the manner in which earnings per share are determined. The Company adopted FAS 128 effective December 15, 1997. In accordance with FAS 128, the Company's previously reported earnings per share for 1996 were restated. The effect of this accounting change on previously reported earnings per share (EPS) data was as follows:
1996 ---- Primary EPS as reported..................................... $.45 Effect of FAS 128........................................... .01 ---- Basic EPS as restated....................................... $.46 ==== Fully diluted EPS as reported............................... $.43 Effect of FAS 128........................................... .02 ---- Diluted EPS as restated..................................... $.45 ====
Basic earnings or loss per common share were computed by dividing net income or loss by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share for the years 1997 and 1996 were determined 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. In 1998, all options were excluded from the computation of diluted loss per share because they were antidilutive. The conversion of the preferred stock was not included in any annual calculation due to their antidilutive effect on diluted income or loss per share. F-9 80 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A reconciliation of the basic and diluted per share computation is as follows (in thousands, except per share amounts):
THREE MONTHS ENDED MARCH 31, YEARS ENDED DECEMBER 31, ------------------ ---------------------------- 1999 1998 1998 1997 1996 ------- ------- -------- ------ ------ (a) Net income (loss) available for common stock.................................. $ (359) $ 508 $(33,533) $5,642 $2,663 (b) Weighted average shares outstanding.... 8,477 8,015 8,034 6,194 5,835 (c) Dilutive impact of stock options....... -- 206 -- 228 117 (d) Total diluted shares................... 8,477 8,221 8,034 6,422 5,952 Stock options excluded due to antidilutive impact.................... 44 -- 163 -- -- Basic earnings (loss) per share(a/b)... $ (.04) $ .06 $ (4.17) $ .91 $ .46 Diluted earnings (loss) per share(a/d)............................... $ (.04) $ .06 $ (4.17) $ .88 $ .45
Fair Value of Financial Instruments Fair value of cash, cash equivalents, accounts receivable, accounts payable and long-term debt approximates book value at December 31, 1998 and 1997 and March 31, 1999. Fair value of long-term debt (specifically the 10% and the 10.125% senior subordinated notes) was based on quoted market value. The calculation of the fair market value of the outstanding hedging contracts (see Note 6) as of December 31, 1998 indicated a $1.4 million market value benefit to the Company based on market prices at that date. Accounts Payable and Accrued Liabilities -- Long-Term Approximately $3,000,000 and $6,000,000 of current accounts payable and accrued liabilities at December 31, 1998 and March 31, 1999, respectively, related to long-term assets, primarily oil and gas properties that were financed subsequent to year-end with long-term debt and therefore have been reclassified as long-term. 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. The F-10 81 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Company's management determined that no valuation allowance was necessary in 1998 and 1997. Accordingly, the Company has recorded a deferred tax asset at December 31, 1998 and 1997 as follows:
DECEMBER 31, ----------------- 1998 1997 ------- ------- (IN THOUSANDS) Federal net operating loss carryforward..................... $ 7,916 $ 3,531 Statutory depletion carryforward............................ 4,083 4,062 Temporary differences: Oil and gas properties.................................... 3,979 (4,943) Pipeline and other facilities............................. (2,164) (2,277) Non-oil and gas property.................................. (101) (86) Other..................................................... 2,635 961 ------- ------- Total tax asset............................................. 16,348 1,248 Valuation allowance......................................... -- -- ------- ------- Net tax asset............................................... $16,348 $ 1,248 ======= =======
At December 31, 1998, the Company had, for federal tax reporting purposes, net operating loss carryforwards ("NOL") of $22.6 million which expire in 2000 through 2012. Approximately $5.0 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. 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, --------------------------- 1998 1997 1996 -------- ------ ------- (IN THOUSANDS) Computed expense (benefit) at the expected statutory rate.................................................. $(15,590) $4,296 $ 1,910 Change in valuation allowance........................... -- -- (1,760) Other................................................... 490 (96) (100) -------- ------ ------- Deferred income tax expense (benefit)................... $(15,100) $4,200 $ 50 ======== ====== =======
4. ACQUISITIONS On June 26, 1997 the Company purchased an 18.8% working interest in the Mobile Block 864 Area from Elf Exploration, Inc. The Company's net purchase price was approximately $11.8 million. The Company further increased its ownership in this area by purchasing Chevron U.S.A. Inc.'s interest in the Mobile Block 864 Area for $18.8 million in November 1997. The Company, together with an industry partner, was the high bidder on 18 offshore tracts at the Outer Continental Shelf ("OCS") Lease Sale #157 and #161, held during 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 $15.2 million. F-11 82 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. LONG-TERM DEBT Long-term debt consisted of the following at:
DECEMBER 31, MARCH 31, ----------------- 1999 1998 1997 --------- ------- ------- (IN THOUSANDS) Credit Facility......................................... $26,100 $18,100 $ 100 10% Senior Subordinated Notes........................... 24,150 24,150 24,150 10.125% Senior Subordinated Notes....................... 36,000 36,000 36,000 ------- ------- ------- 86,250 78,250 60,250 Less: current portion................................... -- -- -- ------- ------- ------- $86,250 $78,250 $60,250 ======= ======= =======
Borrowings under the Credit Facility, with Chase Manhattan Bank, are secured by mortgages covering substantially all of the Company's producing oil and gas properties. Currently, the Credit Facility provides for a $50 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 the lender's prime rate plus 0.125% (prime plus 0.50% if utilized percentage of borrowing base is greater than 50%). The Company, at its option, may fix the interest rate on all or a portion of the outstanding principal balance at 1.125% above a defined "Eurodollar" rate for periods up to six months (1.5% above if utilized percentage of borrowing base is greater than 50%). The weighted average interest rate for the total debt outstanding at March 31, 1999, December 31, 1998 and 1997 was 6.50%, 6.68% and 8.50%, 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 million of its 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 of the transaction were used to repay the outstanding balance under the Credit Facility and fund a portion of the Company's capital expenditure budget. On September 10, 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 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. 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 F-12 83 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 subordinated debt contain various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. The Company is in compliance with these covenants at December 31, 1998 and March 31, 1999. 6. HEDGING CONTRACTS 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 production is sold. Approximately $1,886,000 and $2,466,000 was recognized as additional oil and gas revenue in 1998 and 1997 and recognized a reduction in revenue of $2,757,000 in 1996 as a result of such agreements. For the three months ended March 31, 1999 and 1998, approximately $1,004,000 and $583,000 was recognized as additional oil and gas revenue, respectively. At March 31, 1999, the Company had 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 1999 are for average gas volumes of 483,333 Mcf per month through September 1999 at (on average) a ceiling price of $2.12 and floor price of $1.85. In addition, the Company had open oil collar contracts averaging 24,167 barrels per month at (on average) a ceiling of $16.15 and a floor of $13.78 from April 1999 through December 1999. Also at March 31, 1999 the Company had open forward natural gas swap contracts of 200,000 Mcf per month from April 1999 through September 1999 with a fixed contract price of $2.35. In addition, the Company had open forward crude oil swap contracts of 10,000 barrels per month with a fixed contract price of $14.10 per month from April 1999 through June 1999. 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 March 31, 1999, total estimated site restoration, dismantlement and abandonment costs were approximately $6,000,000, 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. The Company, as part of the Consolidation, entered into Registration Rights Agreements whereby the former stockholders of certain of the Constituent Entities are entitled to require the Company to register Common Stock of the Company owned by them with the Securities and Exchange Commission for sale to the public in a firm commitment public offering and generally to include shares owned by them, at no cost, in registration statements filed by the Company. Costs of the offering will not include discounts and commissions, which will be paid by the respective sellers of the Common Stock. F-13 84 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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.
THREE MONTHS ENDED YEARS ENDED DECEMBER 31, MARCH 31, ------------------------------ 1999 1998 1997 1996 ------------ -------- -------- -------- (IN THOUSANDS) Capitalized costs incurred: Evaluated Properties -- Beginning of period balance................ $444,579 $398,046 $322,970 $304,737 Property acquisition costs................. 348 9,464 51,751 2,999 Exploration costs.......................... 15,905 42,617 13,620 8,732 Development costs.......................... 1,885 4,361 14,155 8,076 Sale of mineral interest................... 154 (9,909) (4,450) (1,574) -------- -------- -------- -------- End of period balance...................... $462,871 $444,579 $398,046 $322,970 ======== ======== ======== ======== Unevaluated Properties (excluded from the full-cost pool) -- Beginning of period balance................ $ 42,679 $ 35,339 $ 26,235 $ 10,171 Additions.................................. 1,891 11,156 16,924 20,640 Capitalized interest and general administrative costs..................... 1,613 8,955 5,163 1,883 Transfer to evaluated...................... (7,855) (12,771) (12,983) (6,459) -------- -------- -------- -------- End of period balance...................... 38,328 $ 42,679 $ 35,339 $ 26,235 ======== ======== ======== ======== Accumulated depreciation, depletion and amortization -- Beginning of period balance................ $345,353 $282,891 $266,716 $257,143 Provision charged to expense............... 3,883 18,962 16,175 9,573 Impairment of oil and gas properties....... -- 43,500 -- -- -------- -------- -------- -------- End of period balance...................... $349,236 $345,353 $282,891 $266,716 ======== ======== ======== ========
Unevaluated property costs, primarily lease acquisition costs incurred at federal and state lease sales and unevaluated drilling costs being excluded from the amortizable evaluated property base as of December 31, 1998 consisted of $17.9 million incurred in 1998, $8.2 million incurred in 1997 and $16.6 million incurred in 1996 and prior. These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The majority of these costs will be evaluated over the next five year period. Depreciation, depletion and amortization per unit-of-production (equivalent barrel of oil) amounted to $7.16, $6.11, and $5.87 for the years ended December 31, 1998, 1997 and 1996, respectively, and $5.96 and $6.99 for the three months ended March 31, 1999 and 1998, respectively. Impairment of Oil and Gas Properties Under full-cost accounting rules, the capitalized costs of proved oil and gas properties are subject to a "ceiling test", which limits such costs to the estimated present value net of related tax effects, discounted at a 10 percent interest rate, of future net cash flows from proved reserves, based on current economic and F-14 85 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) operating conditions (PV-10). If capitalized costs exceed this limit, the excess is charged to expense. During the fourth quarter of 1998, the Company recorded a noncash impairment provision related to oil and gas properties in the amount of $43.5 million ($28.7 million after-tax) primarily due to the significant decline in oil and gas prices. 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 prices of $170,000,000 ($150,000,000 net as of closing dates) and in simultaneous transactions, entered into agreements to sell overriding royalty interests ("ORRI") in the acquired properties. These ORRI are in the form of net profits interests ("NPI") equal to a significant percentage of the excess of gross proceeds over production costs, as defined, from the acquired oil and gas properties. A net deficit incurred in any month can be carried forward to subsequent months until such deficit is fully recovered. The Company has the right to abandon the purchased oil and gas properties if it deems the properties to be uneconomical. The Company has, pursuant to the purchase agreements, created abandonment trusts whereby funds are provided out of gross production proceeds from the properties for the estimated amount of future abandonment obligations related to the working interests owned by the Company. The Trusts are administered by unrelated third party trustees for the benefit of the Company's working interest in each property. The Trust agreements limit their funds to be disbursed for the satisfaction of abandonment obligations. Any funds remaining in the Trusts after all restoration, dismantlement and abandonment obligations have been met will be distributed to the owners of the properties in the same ratio as contributions to the Trusts. The Trusts' assets are excluded from the Consolidated Balance Sheets of the Company because the Company does not control the Trusts. Estimated future revenues and costs associated with the NPI and the Trusts are also excluded from the oil and gas reserve disclosures at Note 12. As of December 31, 1998 and 1997 the Trusts' assets (all cash and investments) totaled $6,360,000 and $19,300,000, respectively and $6,000,000 at March 31, 1999, 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. The trust asset decrease in 1998 was the result of a sale of an oil and gas property and the related trust. 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 owner's shares. However, revenues and production costs associated with the acquired properties reflected in the accompanying Consolidated Statements of Operations represent only the Company's share, after reduction for the NPI. F-15 86 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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: 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 $468,000, $438,000, and $241,000 in the years 1998, 1997 and 1996, respectively. 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 were granted in 1994 and 1995 and all such options could be exercised as of December 31, 1996. During 1997, there were no other options granted and 9,000 shares were exercised at an average price of $17.94. These options have an expiration date 10 years from date of grant. In 1998, 20,000 non-employee director options were granted under the plan, vesting 100% in November 1998. 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 same types of awards as the 1994 Plan and is limited to a maximum of 1,200,000 shares (as amended from the original 900,000 shares) of common stock that may be subject to outstanding awards. During 1998, 1997 and 1996, the Company granted stock options to purchase 205,000, 20,000 and 530,000 shares, respectively, of Common Stock under the plan. All of such options were granted at an exercise price equal to the fair market value of the Common Stock on the date of grant. Terms of the options granted in 1998 provide that 25% of the options become exercisable each year beginning August of 1998 and each succeeding January. Terms of the plan for 450,000 options granted in 1996 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. Had compensation cost for these F-16 87 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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:
YEARS ENDED DECEMBER 31, -------------------------------- 1998 1997 1996 ---------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net income (loss): As reported............................................ $(33,533) $5,642 $2,663 Pro Forma.............................................. (34,421) 4,977 2,411 Basic earnings (loss) per share: As reported............................................ (4.17) .91 .46 Pro Forma.............................................. (4.28) .80 .41 Diluted earnings (loss) per share: As reported............................................ (4.17) .88 .45 Pro Forma.............................................. (4.28) .77 .41
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 above 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, 1998, 1997 and 1996 and changes during the years then ended is presented in the table and narrative below:
1998 1997 1996 --------------------- --------------------- --------------------- WTD WTD WTD AVG AVG AVG SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE ---------- -------- ---------- -------- ---------- -------- Outstanding, beginning of year........................ 1,041,000 $11.19 1,030,000 $11.10 490,000 $10.01 Granted..................... 225,000 10.08 20,000 15.31 550,000 12.06 Exercised................... -- -- (9,000) 10.00 -- -- Forfeited................... -- -- -- -- (10,000) 10.00 Expired..................... -- -- -- -- -- -- ---------- ------ ---------- ------ ---------- ------ Outstanding, end of year...... 1,266,000 $11.00 1,041,000 $11.19 1,030,000 $11.10 ========== ====== ========== ====== ========== ====== Exercisable, end of year...... 802,250 $10.90 621,000 $10.65 500,000 $10.16 ========== ====== ========== ====== ========== ====== Weighted average fair value of options granted............. $ 4.31 $ 6.30 $ 4.96 ========== ========== ==========
The options outstanding at December 31, 1998 have exercise prices ranging from $9.47 to $16.38 with a remaining weighted average contractual life of 7.06 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 1998, 1997 and 1996.
1998 1997 1996 ---- ---- ---- Risk free interest rate..................................... 5.1% 6.8% 6.5% Expected life (years)....................................... 7.0 4.0 4.9 Expected volatility......................................... 28.8% 41.1% 34.7% Expected dividends.......................................... -- -- --
F-17 88 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company 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 was being amortized as compensation expense on a straight-line basis over the vesting period. An additional 25,000 shares were issued under the 1994 Plan in 1997 and 165,500 shares were issued to certain key employees other than the Company's Executive officers in 1998. Approximately $4,963,000 in 1998, $714,000 in 1997 and $208,000 in 1996 of compensation cost were charged to expense related to the restricted shares granted. In December 1998, the Company approved the accelerated vesting of all performance shares. As a result, an additional charge of $3,469,000 which represents the future unamortized expense related to unvested shares at the date the acceleration of vesting occurred, was expensed in 1998. In addition, the Company recorded a provision of approximately $2.3 million for retirement benefits approved in December of 1998. 11. EQUITY TRANSACTIONS 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. On November 25, 1997, the Company completed a public offering of 1,840,000 shares of Common Stock at a price to the public of $17.00. This offering resulted in the Company receiving cash proceeds of $29,267,000, net of offering costs and underwriting discount. The Company used a portion of the proceeds to repay indebtedness incurred to finance the purchase of Chevron U.S.A. Inc.'s interest in Mobile Block 864 Area (see Note 4) and the remaining proceeds were used to fund a portion of the 1998 capital expenditures budget. In a December 1998 private transaction, a preferred stockholder elected to convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's Common Stock. During the first quarter of 1999 certain preferred stockholder's through private transactions, agreed to convert 210,350 shares of Preferred Stock into 502,632 shares of the Company's Common Stock. Any premium negotiated in excess of the conversion rate was recorded as additional preferred stock dividends. F-18 89 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) The Company's proved oil and gas reserves at December 31, 1998, 1997 and 1996 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. 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
YEARS ENDED DECEMBER 31, -------------------------- 1998 1997 1996 ------- ------- ------ Proved developed and undeveloped reserves: Crude Oil (MBbls): Beginning of period.................................... 3,402 3,819 4,766 Revisions to previous estimates........................ (99) (151) (50) Purchase of reserves in place.......................... 162 -- -- Sales of reserves in place............................. (1,531) (78) (312) Extensions and discoveries............................. 5,274 274 -- Production............................................. (310) (462) (585) ------- ------- ------ End of period.......................................... 6,898 3,402 3,819 ======= ======= ====== Natural Gas (MMcf): Beginning of period.................................... 88,738 50,424 29,667 Revisions to previous estimates........................ (8,631) (11,174) (1,688) Purchase of reserves in place.......................... 4,414 52,485 7,391 Sales of reserves in place............................. (684) (164) (228) Extensions and discoveries............................. 18,229 10,281 21,551 Production............................................. (14,036) (13,114) (6,269) ------- ------- ------ End of period.......................................... 88,030 88,738 50,424 ======= ======= ====== Proved developed reserves: Crude Oil (MBbls): Beginning of period.................................... 2,976 3,385 3,890 ======= ======= ====== End of period.......................................... 1,774 2,976 3,385 ======= ======= ====== Natural Gas (MMcf): Beginning of period.................................... 88,010 49,491 20,408 ======= ======= ====== End of period.......................................... 76,895 88,010 49,491 ======= ======= ======
F-19 90 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. The resulting net future cash flows have been discounted to their present values based on a 10% annual discount factor. STANDARDIZED MEASURE
DECEMBER 31, ------------------------------ 1998 1997 1996 -------- -------- -------- (IN THOUSANDS) Future cash inflows......................................... $256,325 $285,953 $285,727 Future costs -- Production................................................ (67,192) (63,709) (59,584) Development............................................... (36,581) (12,984) (9,989) -------- -------- -------- Future net inflows before income taxes...................... 152,552 209,260 216,154 Future income taxes......................................... -- (32,781) (49,438) -------- -------- -------- Future net cash flows....................................... 152,552 176,479 166,716 10% discount factor......................................... (52,801) (48,400) (36,547) -------- -------- -------- Standardized measure of discounted future net cash flows.... $ 99,751 $128,079 $130,169 ======== ======== ========
CHANGES IN STANDARDIZED MEASURE
YEARS ENDED DECEMBER 31, ------------------------------ 1998 1997 1996 -------- -------- -------- (IN THOUSANDS) Standardized measure -- beginning of period................. $128,079 $130,169 $ 63,764 Sales and transfers, net of production costs................ (27,807) (34,006) (18,202) Net change in sales and transfer prices, net of production costs..................................................... (33,029) (66,880) 32,268 Exchange and sale of in place reserves...................... (4,445) (2,428) (877) Purchases, extensions, discoveries, and improved recovery, net of future production and development costs............ 24,294 90,550 79,983 Revisions of quantity estimates............................. (9,409) (13,751) (3,907) Accretions of discount...................................... 13,645 16,017 6,376 Net change in income taxes.................................. 7,926 21,633 (30,000) Changes in production rates, timing and other............... 497 (13,225) 764 -------- -------- -------- Standardized measure -- end of period....................... $ 99,751 $128,079 $130,169 ======== ======== ========
F-20 91 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER ------- ------- ------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) 1998 Total revenues.......................................... $11,492 $9,733 $9,339 $ 7,154 Total costs and expenses................................ 9,664 8,606 7,919 57,383 Income taxes expense (benefit).......................... 621 380 487 (16,588) Net income (loss)....................................... 1,207 747 933 (33,641) Net income (loss) per share -- basic.................... .06 .01 .03 (4.27) Net income (loss) per share -- diluted.................. .06 .01 .03 (4.27) 1997 Total revenues.......................................... $12,781 $8,758 $9,201 $ 12,898 Total costs and expenses................................ 7,366 6,971 7,394 9,270 Income taxes expense.................................... 1,733 578 615 1,274 Net income.............................................. 3,682 1,209 1,192 2,354 Net income (loss) per share -- basic.................... .50 .08 .08 .25 Net income (loss) per share -- diluted.................. .39 .08 .08 .24
F-21 92 [Photograph of the Ocean Concord, the drilling rig that drilled the Habanero prospect.] 93 - --------------------------------------------------------- - --------------------------------------------------------- WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT CONTAINED IN THIS PROSPECTUS. YOU MUST NOT RELY ON ANY UNAUTHORIZED INFORMATION OR REPRESENTATIONS. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR SALE OF THE NOTES MEANS THAT INFORMATION CONTAINED IN THIS PROSPECTUS IS CORRECT AFTER THE DATE OF THIS PROSPECTUS. THIS PROSPECTUS IS NOT AN OFFER TO SELL OR SOLICITATION OF AN OFFER TO BUY THESE NOTES IN ANY CIRCUMSTANCES UNDER WHICH THE OFFER OR SOLICITATION IS UNLAWFUL. ------------------------ TABLE OF CONTENTS
PAGE ---- Prospectus Summary...................... Risk Factors............................ Forward-Looking Statements.............. Use of Proceeds......................... Capitalization.......................... Selected Financial Data................. Management's Discussion and Analysis of Financial Condition and Results of Operations............................ Business and Properties................. Management.............................. Beneficial Ownership of Our Common and Preferred Stock....................... Description of the Notes................ Description of Bank Credit Facility and Other Indebtedness.................... Description of Capital Stock............ Underwriting............................ Validity of the Notes................... Experts................................. Where You Can Find More Information..... Glossary of Oil and Gas Terms........... Index to Financial Statements........... F-1
- --------------------------------------------------------- - --------------------------------------------------------- - --------------------------------------------------------- - --------------------------------------------------------- $40,000,000 LOGO CALLON PETROLEUM COMPANY % SENIOR SUBORDINATED NOTES DUE 2004 ------------------------ PROSPECTUS ------------------------ A.G. EDWARDS & SONS, INC. MORGAN KEEGAN & COMPANY, INC. , 1999 - --------------------------------------------------------- - --------------------------------------------------------- 94 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION The following table sets forth the estimated expenses, other than underwriting commissions, payable by the Registrant in connection with the issuance and distribution of the securities being registered hereby. Securities Act registration fee............................. $ * National Association of Securities Dealers, Inc. filing fee....................................................... * Printing costs.............................................. * Legal fees & expenses....................................... * Accounting fees & expenses.................................. * Engineering fees and expenses............................... * Trustee & Registrar fees.................................... * Miscellaneous............................................... * ------- TOTAL............................................. $ * =======
- --------------- * To be completed by amendment. All of the foregoing estimated costs, expenses and fees will be borne by the Company. ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS Section 145 of the Delaware General Corporation Law ("Delaware Law") permits, subject to certain conditions, a corporation to indemnify its directors, officers, employees and agents against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such director, officer, employee or agent in connection with threatened, pending or completed actions, suits and proceeding (other than actions by or in the right of the corporation) in or to which any of such persons is a party or is threatened to be made a party. Article 8 of the Company's Certificate of Incorporation, as amended, and Article VII, Section 7.9, of the Company's Bylaws provide that the Company may indemnify its directors, officers, employees and agents to the fullest extent permitted by Delaware Law. ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
EXHIBIT NUMBER DESCRIPTION ------- ----------- 1. -- Underwriting Agreement 1.1 -- Form of Underwriting Agreement** 2. -- Plan of acquisition, reorganization, arrangement, liquidation or succession* 4. -- Instruments defining the rights of security holders, including indentures 4.1 -- Certificate of Incorporation of the Company, as amended (incorporated by reference from Exhibit 3.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.2 -- Certificate of Merger of Callon Consolidated Partners, L.P. with and into the Company dated September 16, 1994 (incorporated by reference from Exhibit 3.2 of the Company's Report on Form 10-K for the fiscal year ended December 31, 1994.
II-1 95
EXHIBIT NUMBER DESCRIPTION ------- ----------- 4.3 -- Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.4 -- Specimen Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.5 -- Specimen Preferred Stock Certificate (incorporated by reference from Exhibit 4.2 of the Company's Registration Statement on Form S-1/A, filed November 13, 1995, Reg. No. 33-96700) 4.6 -- Designation for Series A Preferred Stock (incorporated by reference from Exhibit 4.3 of the Company's Registration Statement on Form S-1/A, filed November 13, 1995, Reg. No. 33-96700) 4.7 -- Indenture for Convertible Debentures (incorporated by reference form Exhibit 4.4 of the Company's Registration Statement on Form S-1/A, filed November 13, 1995, Reg. No. 33-96700) 4.8 -- Certificate of Correction on Designation of Series A Preferred Stock (incorporated by reference from Exhibit 4.4 of the Company's Registration Statement on Form S-1/A, filed November 22, 1996, Reg. No. 333-15501) 4.9 -- Form of Note Indenture (incorporated by reference from Exhibit 4.6 of the Company's Registration Statement on Form S-1/A filed November 22, 1996, Reg. No. 333-15501) 4.10 -- Form of Notes Indenture** 4.11 -- Form of Global Certificate (included in Exhibit 4.10)** 5. -- Opinion re legality 5.1 -- Form of Opinion of Butler & Binion, L.L.P. 8. -- Opinion re tax matters* 9. -- Voting Trust Agreement 9.1 -- Stockholders' Agreement dated September 16, 1994 among the Company, the Callon Stockholders and NOCO Enterprises, L.P. (incorporated by reference from Exhibit 9.1 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10. -- Material Contracts 10.1 -- Registration Rights Agreement dated September 16, 1994 between the Company and NOCO Enterprises, L.P. (incorporated by reference from Exhibit 10.2 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.2 -- Registration Rights Agreement dated September 16, 1994 between the Company and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.3 -- Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from Exhibit 10.5 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.4 -- Credit Agreement dated October 14, 1994 by and between the Company, Callon Petroleum Operating Company and Internationale Nederlanden (U.S.) Capital Corporation (incorporated by reference from Exhibit 99.1 of the Company's Report on form 10-Q for the quarter ended September 30, 1994) 10.5 -- Third Amendment dated February 22, 1996, to Credit Agreement by and among Callon Petroleum Operating Company, Callon Petroleum Company and Internationale Nederlanden (U.S.) Capital Corporation (incorporated by reference from Exhibit 10.9 of the Company's Form 10-K for the fiscal year ended December 31, 1995)
II-2 96
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.6 -- Consulting Agreement between the Company and John S. Callon dated June 19, 1996 (incorporated by reference from Exhibit 10.10 of the Company's Registration Statement on Form S-1, filed November 5, 1996, Reg. No. 333-15501) 10.7 -- Employment Agreement effective September 1, 1996, between the Company and Fred L. Callon (incorporated by reference from Exhibit 10.4 of the Company's Registration Statement on Form S-1/A, filed November 14, 1996, Reg. No. 333-15501) 10.8 -- Employment Agreement effective September 1, 1996, between the Company and Dennis W. Christian (incorporated by reference from Exhibit 10.7 of the Company's Registration Statement on Form S-1/A, filed November 14, 1996, Reg. No. 333-15501) 10.9 -- Employment Agreement effective September 1, 1996, between the Company and John S. Weatherly (incorporated by reference from Exhibit 10.8 of the Company's Registration Statement on Form S-1/A, filed November 14, 1996, Reg. No. 333-15501) 10.10 -- Callon Petroleum Company's Amended 1996 Stock Incentive Plan (incorporated by reference from Exhibit 4.4 of the Post-Effective Amendment No. 1 to the Company's Registration Statement on Form S-8, filed February 5, 1996, Reg. No. 333-29537) 10.11 -- Purchase and Sale Agreement between Callon Petroleum Operating Company and Murphy Exploration & Production Company, dated May 26, 1999 11. -- Statement re computation of per share earnings* 12. -- Statement re computation of ratios* 13. -- Annual report to security holders, Form 10-Q or quarterly report to security holders* 15. -- Letter re unaudited interim financial information* 16. -- Letter re change in certifying accountant* 21. -- Subsidiaries of the registrant 21.1 -- Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 23. -- Consents of experts and counsel 23.1 -- Consent of Arthur Andersen LLP 23.2 -- Consent of Huddleston & Co., Inc. 23.3 -- Consent of Butler & Binion, L.L.P. (included in their opinion filed as Exhibit 5.1) 24. -- Power of attorney (contained on the signature page of this Registration Statement) 25. -- Statement of Eligibility of Trustee 25.1 -- Form of Statement of Eligibility of Trustee 26. -- Invitation for Competitive Bids* 27. -- Financial Data Schedule* 99. -- Additional exhibits*
- --------------- * Inapplicable to this filing. ** To be filed by amendment. II-3 97 ITEM 17. UNDERTAKINGS The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant's annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. The undersigned registrant hereby undertakes to deliver or cause to be delivered with the prospectus, to each person to whom the prospectus is sent or given, the latest annual report to security holders that is incorporated by reference in the prospectus and furnished pursuant to and meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of 1934; and, where interim financial information required to be presented by Article 3 of Regulation S-X are not set forth in the prospectus, to deliver, or cause to be delivered to each person to whom the prospectus is sent or given, the latest quarterly report that is specifically incorporated by reference in the prospectus to provide such interim financial information. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. The undersigned registrant hereby undertakes that: (1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497 (h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (2) For the purpose determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. II-4 98 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-2 and has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Natchez, State of Mississippi, on June 9, 1999. CALLON PETROLEUM COMPANY By: /s/ FRED L. CALLON ---------------------------------- Fred L. Callon President and Chief Executive Officer POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints John S. Callon, Fred L. Callon and John S. Weatherly, and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him in his name, place and stead, in any and all capacities, to sign any and all amendments (including amendments that register additional securities of the same class to be declared effective in accordance with Rule 462(b) promulgated under the Securities Act of 1933 and post-effective amendments) to this Registration Statement, and to file the same, with all exhibits hereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.
NAME TITLE DATE ---- ----- ---- /s/ JOHN S. CALLON Chairman of the Board, June 9, 1999 - ----------------------------------------------------- Director John S. Callon /s/ FRED L. CALLON President, Chief Executive June 9, 1999 - ----------------------------------------------------- Officer, Director Fred L. Callon (Principal Executive Officer) /s/ DENNIS W. CHRISTIAN Chief Operating Officer, June 9, 1999 - ----------------------------------------------------- Senior Vice President, Dennis W. Christian Director /s/ JOHN S. WEATHERLY Senior Vice President and June 9, 1999 - ----------------------------------------------------- Chief Financial Officer John S. Weatherly (Principal Financial Officer) /s/ JAMES O. BASSI Vice President, Controller June 9, 1999 - ----------------------------------------------------- and Principal Accounting James O. Bassi Officer (Principal Accounting Officer)
II-5 99
NAME TITLE DATE ---- ----- ---- /s/ ROBERT A. STANGER Director June 9, 1999 - ----------------------------------------------------- Robert A. Stanger /s/ JOHN C. WALLACE Director June 9, 1999 - ----------------------------------------------------- John C. Wallace /s/ B. F. WEATHERLY Director June 9, 1999 - ----------------------------------------------------- B. F. Weatherly /s/ RICHARD O. WILSON Director June 9, 1999 - ----------------------------------------------------- Richard O. Wilson /s/ LEIF DONS Director June 9, 1999 - ----------------------------------------------------- Leif Dons
II-6 100 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------- ----------- 1. -- Underwriting Agreement 1.1 -- Form of Underwriting Agreement** 2. -- Plan of acquisition, reorganization, arrangement, liquidation or succession* 4. -- Instruments defining the rights of security holders, including indentures 4.1 -- Certificate of Incorporation of the Company, as amended (incorporated by reference from Exhibit 3.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.2 -- Certificate of Merger of Callon Consolidated Partners, L.P. with and into the Company dated September 16, 1994 (incorporated by reference from Exhibit 3.2 of the Company's Report on Form 10-K for the fiscal year ended December 31, 1994. 4.3 -- Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.4 -- Specimen Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.5 -- Specimen Preferred Stock Certificate (incorporated by reference from Exhibit 4.2 of the Company's Registration Statement on Form S-1/A, filed November 13, 1995, Reg. No. 33-96700) 4.6 -- Designation for Series A Preferred Stock (incorporated by reference from Exhibit 4.3 of the Company's Registration Statement on Form S-1/A, filed November 13, 1995, Reg. No. 33-96700) 4.7 -- Indenture for Convertible Debentures (incorporated by reference form Exhibit 4.4 of the Company's Registration Statement on Form S-1/A, filed November 13, 1995, Reg. No. 33-96700) 4.8 -- Certificate of Correction on Designation of Series A Preferred Stock (incorporated by reference from Exhibit 4.4 of the Company's Registration Statement on Form S-1/A, filed November 22, 1996, Reg. No. 333-15501) 4.9 -- Form of Note Indenture (incorporated by reference from Exhibit 4.6 of the Company's Registration Statement on Form S-1/A filed November 22, 1996, Reg. No. 333-15501) 4.10 -- Form of Notes Indenture** 4.11 -- Form of Global Certificate (included in Exhibit 4.10)** 5. -- Opinion re legality 5.1 -- Form of Opinion of Butler & Binion, L.L.P. 8. -- Opinion re tax matters* 9. -- Voting Trust Agreement 9.1 -- Stockholders' Agreement dated September 16, 1994 among the Company, the Callon Stockholders and NOCO Enterprises, L.P. (incorporated by reference from Exhibit 9.1 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10. -- Material Contracts
101
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.1 -- Registration Rights Agreement dated September 16, 1994 between the Company and NOCO Enterprises, L.P. (incorporated by reference from Exhibit 10.2 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.2 -- Registration Rights Agreement dated September 16, 1994 between the Company and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.3 -- Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from Exhibit 10.5 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.4 -- Credit Agreement dated October 14, 1994 by and between the Company, Callon Petroleum Operating Company and Internationale Nederlanden (U.S.) Capital Corporation (incorporated by reference from Exhibit 99.1 of the Company's Report on form 10-Q for the quarter ended September 30, 1994) 10.5 -- Third Amendment dated February 22, 1996, to Credit Agreement by and among Callon Petroleum Operating Company, Callon Petroleum Company and Internationale Nederlanden (U.S.) Capital Corporation (incorporated by reference from Exhibit 10.9 of the Company's Form 10-K for the fiscal year ended December 31, 1995) 10.6 -- Consulting Agreement between the Company and John S. Callon dated June 19, 1996 (incorporated by reference from Exhibit 10.10 of the Company's Registration Statement on Form S-1, filed November 5, 1996, Reg. No. 333-15501) 10.7 -- Employment Agreement effective September 1, 1996, between the Company and Fred L. Callon (incorporated by reference from Exhibit 10.4 of the Company's Registration Statement on Form S-1/A, filed November 14, 1996, Reg. No. 333-15501) 10.8 -- Employment Agreement effective September 1, 1996, between the Company and Dennis W. Christian (incorporated by reference from Exhibit 10.7 of the Company's Registration Statement on Form S-1/A, filed November 14, 1996, Reg. No. 333-15501) 10.9 -- Employment Agreement effective September 1, 1996, between the Company and John S. Weatherly (incorporated by reference from Exhibit 10.8 of the Company's Registration Statement on Form S-1/A, filed November 14, 1996, Reg. No. 333-15501) 10.10 -- Callon Petroleum Company's Amended 1996 Stock Incentive Plan (incorporated by reference from Exhibit 4.4 of the Post-Effective Amendment No. 1 to the Company's Registration Statement on Form S-8, filed February 5, 1996, Reg. No. 333-29537) 10.11 -- Purchase and Sale Agreement between Callon Petroleum Operating Company and Murphy Exploration & Production Company, dated May 26, 1999 11. -- Statement re computation of per share earnings* 12. -- Statement re computation of ratios* 13. -- Annual report to security holders, Form 10-Q or quarterly report to security holders* 15. -- Letter re unaudited interim financial information* 16. -- Letter re change in certifying accountant*
102
EXHIBIT NUMBER DESCRIPTION ------- ----------- 21. -- Subsidiaries of the registrant 21.1 -- Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 23. -- Consents of experts and counsel 23.1 -- Consent of Arthur Andersen LLP 23.2 -- Consent of Huddleston & Co., Inc. 23.3 -- Consent of Butler & Binion, L.L.P. (included in their opinion filed as Exhibit 5.1) 24. -- Power of attorney (contained on the signature page of this Registration Statement) 25. -- Statement of Eligibility of Trustee 25.1 -- Form of Statement of Eligibility of Trustee 26. -- Invitation for Competitive Bids* 27. -- Financial Data Schedule* 99. -- Additional exhibits*
- --------------- * Inapplicable to this filing. ** To be filed by amendment. EX-5.1 2 FORM OF OPINION OF BUTLER & BINION, L.L.P. 1 EXHIBIT 5.1 [BUTLER & BINION, L.L.P. LETTERHEAD] June 11, 1999 Callon Petroleum Company 200 North Canal Street Natchez, Mississippi 39120 Re: Registration and sale of $40,000,000 of __% Senior Subordinated Notes due 2004 of Callon Petroleum Company Gentlemen: We have acted as counsel for Callon Petroleum Company, a Delaware corporation (the "Company"), in connection with the registration and sale of $40,000,000 in ___% Senior Subordinated Notes due 2004 ("Notes") of the Company to be sold by the Company in a public offering. We have made such inquiries and examined such documents as we have considered necessary or appropriate for the purposes of giving the opinion hereinafter set forth, including the examination of executed or conformed counterparts, or copies certified or otherwise proved to our satisfaction of the following: (i) the Certificate of Incorporation of the Company, as amended and the Certificate of Merger of Callon Consolidated Partners, L.P. with and into the Company dated September 16, 1994; (ii) the Certificate of Designations for the Company's $2.125 Convertible Exchangeable Preferred Stock, Series A, filed with the Delaware Secretary of State on November 22, 1995, and corrected by that certain Certificate of Correction filed with the Delaware Secretary of State on November 27, 1995; (iii) the Bylaws of the Company as of the date of this opinion; (iv) the Registration Statement on Form S-2 of the Company, including the related prospectus to be filed with the Securities and Exchange Commission on or about June 11, 1999, as amended (the "Registration Statement"); (v) the Indenture ("Indenture") between the Company and American Stock Transfer & Trust Company, as Trustee ("Trustee"), pursuant to which the Notes will be issued; and 2 Callon Petroleum Company June 11, 1999 Page -2- (vi) such other documents, corporate records, certificates and other instruments as we have deemed necessary or appropriate for the purpose of this opinion. We have assumed the genuineness and authenticity of all signatures on all original documents, the authenticity of all documents submitted to us as originals, the conformity to originals of all documents submitted to us as copies and the due authorization, execution, delivery or recordation of all documents where due authorization, execution, delivery or recordation are prerequisites to the effectiveness thereof. Capitalized terms used herein and not otherwise defined are used as defined in the Registration Statement. Based upon the foregoing, and having regard for such legal considerations as we deem relevant, we are of the opinion that: (i) The Company is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware pursuant to the Delaware General Corporation Law; (ii) The Notes to be sold by the Company pursuant to the Registration Statement have been duly authorized for issuance, and when executed by the Company, authenticated by the Trustee and delivered and sold in accordance with the provisions of the Registration Statement, will be legally issued and binding obligations of the Company enforceable in accordance with their terms and entitled to the benefits of the Indenture (except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws now or hereafter in effect affecting the rights of creditors generally). We hereby consent to the filing of this opinion as an Exhibit to the Registration Statement and to the references to us under the caption "Legal Matters" in the prospectus forming a part of the Registration Statement. Very truly yours, /s/ BUTLER & BINION, L.L.P. BUTLER & BINION, L.L.P. EX-10.11 3 PURCHASE AND SALE AGREEMENT DATED 5/26/99 1 EXHIBIT 10.11 PURCHASE AND SALE AGREEMENT BY AND BETWEEN MURPHY EXPLORATION & PRODUCTION COMPANY AND CALLON PETROLEUM OPERATING COMPANY 2 TABLE OF CONTENTS RECITALS............................................................................................1 ARTICLE IAGREEMENT TO BUY AND SELL..................................................................1 1.1 Agreement to Sell the Subject Property............................................1 1.2 Assumption of Obligations.........................................................4 1.3 Reservation of Rights and Interests...............................................4 ARTICLE IIPURCHASE AND SALE.........................................................................5 2.1 Transfer of the Subject Property..................................................5 2.2 Purchase Price....................................................................5 2.3 Determination of the Closing Amount and the Final Settlement Statement...........5 ARTICLE III.REPRESENTATIONS OF SELLER...............................................................7 3.1 Existence.........................................................................7 3.2 Power.............................................................................7 3.3 Authorization.....................................................................8 3.4 Broker............................................................................8 3.5 Litigation........................................................................8 3.6 Preferential Rights Approvals and Consents........................................8 3.7 Title.............................................................................9 3.8 Due Execution and Enforceability..................................................9 3.9 Lease Maintenance.................................................................9 3.10 Other Maintenance.................................................................9 3.11 Equipment.........................................................................9 3.12 Compliance with Laws..............................................................9 3.13 Environmental.....................................................................9 3.14 Contracts........................................................................10 3.15 Adverse Changes..................................................................10 3.16 Taxes............................................................................10 3.17. Agreements to Sell or Mortgage...................................................10 3.18. Take-or-Pay and Other Settlements................................................10 3.19. Production Payments and Calls on Production......................................11
- i - 3 ARTICLE IVREPRESENTATIONS OF PURCHASER.............................................................11 4.1 Existence........................................................................11 4.2 Power............................................................................11 4.3 Authorization....................................................................11 4.4 Independent Evaluation and Review................................................11 4.5 Further Distribution.............................................................12 4.6 Brokers..........................................................................12 4.7 Litigation.......................................................................12 ARTICLE VTITLE MATTERS.............................................................................12 5.1 Title Examination Period.........................................................12 5.2 Title Defects....................................................................12 5.3 Remedies for Title Defects.......................................................13 ARTICLE VIPRE-CLOSING TRANSACTIONS.................................................................13 6.1 Operation of the Subject Property Pending the Closing Date.......................13 6.2 Casualty Insurance...............................................................14 6.3 Permissions......................................................................14 6.4 Copies of Contracts..............................................................14 ARTICLE VIISELLER'S CONDITIONS OF CLOSING..........................................................14 7.1 Representations..................................................................14 7.2 Performance......................................................................14 7.3 Pending Matters..................................................................14 7.4 Certificates.....................................................................15 7.5 Opinions.........................................................................15 7.6 Encumbrance or Impairment of Security............................................15 ARTICLE VIIIPURCHASER'S CONDITIONS OF CLOSING......................................................15 8.1 Representations..................................................................15 8.2 Performance......................................................................15 8.3 Pending Matters..................................................................16 8.4 Approval of Contracts............................................................16 8.5 Environmental Condition..........................................................16 8.6 Certificates.....................................................................16 8.7 Opinions.........................................................................16
- ii - 4 ARTICLE IXCLOSING..................................................................................16 9.1 Time and Place of Closing........................................................16 9.2 Closing Obligations..............................................................17 ARTICLE XPOST-CLOSING OBLIGATIONS..................................................................18 10.1 Receipts and Credits.............................................................18 10.2 Indemnity........................................................................18 10.3 Further Assurances...............................................................20 ARTICLE XITERMINATION..............................................................................20 11.1 Right of Termination.............................................................20 11.2 Effect of Termination............................................................20 ARTICLE XIITAXES...................................................................................21 12.1 Sales Taxes......................................................................21 12.2 Other Taxes......................................................................21 12.3 Cooperation......................................................................21 ARTICLE XIIIINDEPENDENT INVESTIGATION AND DISCLAIMER...............................................21 ARTICLE XIVPRODUCTION PAYMENT.....................................................................22 14.1 Definition of Purchaser's Property...............................................22 14.2 Delivery of Gas..................................................................22 14.3 Delivery Points..................................................................22 14.4 Balancing and Alternative Payment................................................23 A. Imbalances..............................................................23 B. Alternative Payment.....................................................23 14.5 Purchaser Grants a First Priority Security Interest..............................24 ARTICLE XVMISCELLANEOUS............................................................................24 15.1 Governing Law....................................................................24 15.2 Entire Agreement.................................................................24 15.3 Waiver...........................................................................25 15.4 Captions.........................................................................25 15.5 Notices..........................................................................25 15.6 Expenses.........................................................................26
- iii - 5 15.7 Severability.....................................................................26 15.8 Publicity........................................................................26 15.9 Consequential Damages............................................................26 15.10 Survival.........................................................................26 15.11 Successors and Assigns...........................................................26 15.12 Counterparts.......................................................................26 15.13 Binding Arbitration................................................................26 15.14 Well information.................................................................27
- iv - 6 PURCHASE AND SALE AGREEMENT United States of America ss. Outer Continental Shelf Lands ss. KNOW ALL MEN BY THESE PRESENTS: Offshore Alabama ss. This Purchase and Sale Agreement (the "Agreement") dated this 26th day of May, 1999, and effective as of 7:00 a.m. on April 1, 1999 (the "Effective Date"), is made by MURPHY EXPLORATION & PRODUCTION COMPANY, whose address is 131 South Robertson Street, New Orleans, LA 70112 (hereinafter called "SELLER") in favor of CALLON PETROLEUM OPERATING COMPANY whose address is 200 North Canal Street, P. O. Box 1287, Natchez, Mississippi 39120 (hereinafter called "PURCHASER"). RECITALS Whereas, Seller desires to sell and Purchaser desires to purchase certain oil and gas properties and related rights on the terms and conditions provided in this Agreement; Now, therefore, in consideration of the premises and the respective promises, representations, warranties, covenants, agreements and conditions contained herein, Seller and Purchaser hereby agree as follows: ARTICLE I AGREEMENT TO BUY AND SELL 1.1 Agreement to Sell the Subject Property. Seller hereby agrees to sell and Purchaser hereby agrees to buy, subject to the terms, conditions, representations and warranties contained in this Agreement, all of Seller's rights, title and interest, subject to certain reservations as hereinafter set forth, in the following properties (hereinafter the "Subject Property"), as follows: A. The oil, gas and mineral leases described in Exhibit "A" (the "Leases"), together with all of Seller's rights in respect of any pooled, communitized or unitized acreage of which any such interest is a part, together with all right, title, interest, (or operating rights, where Applicable) tenements, - 1 - 7 hereditaments, appurtenances, benefits and privileges of Seller attributable to the foregoing, including without limitation all of Seller's rights in and to that certain Mobile 864 Unit, as more specifically described on Exhibit "A", less and except any reservation of deep rights and/or overriding royalty interest described in Exhibit "A." B. The oil, condensate or natural gas well(s) located on the Subject Property, whether producing, operating, shut-in or temporarily abandoned (the "Wells"), as identified on Exhibit "B" attached hereto. C. Subject to the provisions of Article 2.2 and Article XIV which provide, among other things, that Seller shall receive as consideration a Production Payment to be delivered in kind, the severed crude oil, natural gas, casing head gas, drip gasoline, natural gasoline, petroleum, natural gas liquids, condensate, products, liquids and other hydrocarbons and other minerals or materials of every kind and description produced from the Subject Property on and after the Effective Date (collectively, the "Substances"). D. The currently existing physical facilities or interests therein, well protectors, the platforms, production equipment, compressors, separating facilities, metering facilities, pumping units, departing pipelines (other than the MAGGP referred to in subsection H hereinafter), gathering lines, equipment and fixtures of every type and description to the extent that the same are used or held for use in connection with the ownership of the Subject Property described in Paragraphs A, B, and C above, whether located on or off such Subject Property, including, without limitation, all casing and tubulars in the Wells, (collectively the "Facilities"), and including, but not limited to, the assets listed on Exhibit "B" attached hereto. - 2 - 8 The leases, easements, privileges, rights-of-way agreements, licenses, permits orders, authorizations or other agreements relating to the use or ownership of surface or subsurface properties and structures that are used or held for use in connection with the exploration for and production of the Substances, identified on Exhibit "C" attached hereto. F. The (i) lease and land files, filings with regulatory agencies, design files, shallow hazard survey, other documents and instruments that relate to the properties described in paragraphs A through E above and which are in the possession or under the control of Seller, (ii) production and other technical data, excluding seismic data, that are owned by Seller and relate to the Subject Property or the Wells except to the extent transfer of same is restricted or prohibited by agreement with a third party; and (iii) all other books, records and files containing financial, title or information that are in possession or under the control of Seller and relate to the properties described in Paragraphs A through E above. Seller shall provide a list of files to be transferred and such list shall be signed by both parties as stipulated in that certain Minerals Management Service ("MMS") memorandum No. --- 5210 dated June 26, 1996. Notwithstanding the foregoing, Seller shall be entitled to keep the originals of all files, records, data and other documents ("Records") relating to Mobile Block 863 and copies of all Records relating ------- to the balance of all other blocks which comprise the Subject Property. Purchaser shall provide such copies to Seller at Purchaser's own expense. Upon request of Seller, for a period of up to ten (10) years Purchaser shall provide Seller access to the originals of any such Records and Contracts (as defined below) relating to the Subject - 3 - 9 Property at Purchaser's offices during normal business hours. G. The contracts, commitments, agreements and arrangements that relate to the properties described in Paragraph A through E above and to any period of time after the Effective Date, including the production, storage, treatment, transportation, processing, purchase, sale or other disposal of Substances therefrom or in connection therewith and any and all amendments, ratifications or extension of the foregoing, as identified on Exhibit "D" attached hereto (the "Contracts"), together with all rights of Seller thereunder to audit the records of any party thereto and receive refunds of any nature thereunder, relating to periods on or after the Effective Date. H. Notwithstanding the above, Seller hereby excludes from this transaction its undivided 17.9274% working interest in that certain 12-inch, approximately 7.6 mile Mobile Area Gas Gathering Pipeline (the "MAGGP"), which extends from the Mobile 908 Platform (located on OCS-G 5071) to an interconnection with Chandeleur Pipe Line Company at or near Mobile Bock 861 "A" Platform. 1.2 Assumption of Obligations. The sale of Seller's interest in the Properties shall be subject to, and Purchaser shall assume, the terms, conditions and obligations of the interest conveyed pursuant to this Agreement in the Leases and Contracts including all existing lease burdens (including, but not limited to, royalties or similar burdens), and duties imposed by governmental regulation, but not including any insurance contracts held by Seller, including the assumption by Purchaser of Seller's share of all plugging and abandonment liabilities of the Subject Property, the Facilities and the Wells. Through March, 1999, Seller represents that it has certain gas imbalances, as follows: over-delivered in the amounts of 20,074 MCF in Mobile Block 952, 953 and 955; and 16,076 MCF under-delivered in the Mobile 864 Unit, for a total net amount of 3,998 MCF over-delivered (per Operator's - 4 - 10 latest gas balance statement). Purchaser assumes any liabilities regarding this imbalance and holds Seller harmless against any future claim for such imbalance. 1.3 Reservation of Rights and Interests. Seller shall reserve unto itself certain deep rights and the overriding royalty interests in certain Leases as set forth below in and to all of the oil, gas and other substances produced, saved and marketed from or attributable to the Leases. The overriding royalty interests shall be computed and paid at the same time and in the same manner as the lessor royalty under the terms of said Leases. Said overriding royalty shall be free and clear of all costs and expenses of both drilling and production operations, but shall bear its proportionate share of severance, production, excise and other like taxes applicable to the interest. Seller shall have the right from time to time upon thirty (30) days notice to Purchaser, to take its reserved overriding royalty interest in kind, which shall be delivered free of cost to certain sales points as provided in Article XIV hereof. The Assignments attached hereto as Exhibits "E-1" through "E-10", shall contain the following reservations: (a) Seller shall assign all of its operating rights from surface down to 4,200 feet subsea, retaining unto Seller all right, title and interest and operating rights as to all depths below 4,200 feet subsea in OCS-G 5748, Mobile Block 863; (b) Seller shall assign all right, title and interest in all depths, retaining unto Seller a 10% of 8/8ths overriding royalty interest, proportionately reduced as to Seller's operating rights interest, as to depths below 4,200 feet subsea in OCS-G 7844, OCS-G 5071, OCS-G 5755, OCS-G 5756 and OCS-G 5757, Mobile Blocks 907, 908, 952, 953 and 955 respectively; (c) Seller shall assign all right, title and interest in all depths, retaining unto Seller a net 6.00% of 8/8ths overriding royalty interest in OCS-G 18125 and OCS-G 18126, Mobile Blocks 997 and 998 respectively; (d) Seller shall assign all right, title and interest in all depths, retaining unto Seller a net 5.50% of 8/8ths overriding royalty interest in OCS-G 19888, Mobile Block 999; - 5 - 11 (e) Seller shall assign all right, title and interest in and to the Mobile Block 864 Unit with no reservations. ARTICLE II PURCHASE AND SALE 2.1 Transfer of the Subject Property. Subject to the terms and conditions of this Agreement, on or before June 8, 1999, at 10:00 a.m. Central Time ("Closing Date") Seller shall sell and Purchaser shall purchase and assume the obligation to pay the Purchase Price as set forth in Article 2.2, as adjusted hereunder, for all of Seller's right, title, and interest (or operating rights, where applicable) in and to the Subject Property effective as of the Effective Date. 2.2 Purchase Price. The "Purchase Price" for all of Seller's right, title and interest in and to the Subject Property shall be the agreement and firm obligation by Purchaser to deliver to Seller from the Purchaser's Property (as defined in Section 14.1) a fixed daily volume of Purchaser's first gas produced from Purchaser's Property of 6.375 MMCFD at 14.73 psi ("Production Payment") net to Seller for each day in the period commencing on the Effective Date until July 1, 2002 ("Satisfaction Date"), and the assumption by Purchaser as of the Effective Date of all of Seller's liability for the plugging and abandonment of the Subject Property, the Facilities and the Wells. The delivery of said Production Payment shall be further subject to the provisions of Article XIV. 2.3 Determination of the Closing Amount and the Final Settlement Statement. At or in connection with the Closing, the following accounting shall be effected between Seller and Purchaser. (a) All oil, gas and other hydrocarbons produced prior to the Effective Date (irrespective of whether payment for the same has been made or received) which is attributable to Seller's interest in the Subject Property shall be and remain the property of Seller. All oil, gas and other hydrocarbons produced after the Effective Date (irrespective of whether payment for the same has been made or received) which is attributable to Seller's interest in the Subject Property shall be the property of Purchaser. All costs, expenses, taxes (subject to Article XII) and disbursements, incurred prior to the Effective Date, regardless of when due or payable, shall - 6 - 12 be and remain the obligation of Seller. All costs, expenses, taxes (subject to Article XII) and disbursements, incurred subsequent to the Effective Date, regardless of when due or payable, shall be the obligation of Purchaser. (b) Interim Period. (i) Gas Sales - During the period between the Effective Date and May 31, 1999 (the "Interim Period"), Seller shall continue to nominate and market the gas production attributable to the Subject Properties. Seller shall pay all royalties due on such gas and shall retain the net proceeds associated with volumes up to the net daily Production Payment volume of 6.375 MMCFD. All volumes sold by or credited to the Seller during the Interim Period shall be credited against the volumes due under the Production Payment. During the Interim Period, Purchaser shall nominate and market all of the gas production attributable to Purchaser's interest prior to this transaction and pay all royalties due on that interest (ii) Costs Seller and Purchaser acknowledge that their respective joint interest billing prepared in connection with the Subject Property for the month of April 1999 shall be a combination of costs that were incurred both prior to the Effective Date and costs that were incurred after the Effective Date. Both Seller and Purchaser agree to pay the other party's April 1999 joint interest billing when due. No joint interest billing shall be sent to the other party after the April 1999 billing. Any invoice from Purchaser received by Seller after Seller has processed the joint interest billing for April will be handled in the Final Settlement Statement. Settlement of all costs, expenses, taxes (subject to Article XII) and disbursements shall be handled in connection with the Final Settlement Statement referred to below. Purchaser shall assume all regulatory and production reporting beginning with the production month of May 1999. (c) At least three (3) business days prior to the Closing, Seller shall cause to be prepared an unaudited settlement statement (the "Preliminary Settlement Statement") setting forth an estimation of the volume of gas due for the Interim Period which shall be computed as the differential between the net volumes Seller sold and the net daily Production Payment volume of 6.375 MMCFD. The differential volume shall be valued at the gas price (exclusive of transportation costs to the delivery point as defined in Article 14.3) received by the Seller during the Interim Period. Purchaser shall pay, at Closing that estimated net amount, which shall be referred to hereinafter as the "Closing Amount". - 7 - 13 (d) As soon as practicable after the Closing, but not later than sixty (60) days thereafter, Seller and Purchaser shall agree on, in accordance with generally accepted accounting principles, a statement (the "Final Settlement Statement") setting forth each adjustment that was estimated as of the Closing and a settlement of all costs, expenses, taxes (subject to Article XII), and disbursements due to each party based on the Effective Date, after giving effect to this subsection (d) and subsections (e), (f) and (g) of this Section 2.3. As soon as practicable after receipt of the Final Settlement Statement but not later than 30 days after such receipt, Purchaser shall deliver to Seller a written report containing any changes that Purchaser proposes be made to the Final Settlement Statement. The parties shall undertake to agree with respect to the amounts due pursuant to such Final Settlement Statement no later than 90 days after the Closing Date. If the Final Settlement Statement reveals that either party owes a sum of money to the other, then the party owing same shall promptly pay to the other party such sum by cashier's or certified check or other guaranteed funds. Purchaser shall have the right to one audit of Seller's accounts and records relating to this Agreement at Purchaser's sole cost and expense. (e) Ad valorem taxes, if any, assessed in the jurisdiction in which the Property is located which are payable in arrears, shall be included in the Final Settlement Statement on a prorated basis based on 1998 taxes. (f) All prepaid charges other than for insurance applicable to periods following the Effective Date and prepaid rentals or royalties paid under the Lease or any contracts for periods subsequent to the Effective Date shall be prorated as of the Effective Date and the pro rata share of Purchaser shall be included in the Final Settlement Statement. (g) Purchaser shall pay all sales, use or transfer taxes that may be or become due on account of the sale and purchase herein provided for. (h) Notwithstanding anything contained herein to the contrary, in the event Closing has not occurred by May 24, 1999, Purchaser and Seller shall each nominate and market their respective gas from the Subject Property for the month of June, the sale of which shall be accounted for in the same manner as the Closing Amount. - 8 - 14 ARTICLE III. REPRESENTATIONS OF SELLER Seller represents and warrants to Purchaser that: 3.1 Existence. Seller is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware, and is duly qualified to carry on its business on the Outer Continental Shelf. 3.2 Power. Seller has the corporate power to enter into and perform this Agreement and the transactions contemplated hereby, subject to rights to consent by, required notices to, and filings with or other actions by governmental entities where the same are customarily obtained subsequent to the assignment of oil and gas interests and leases. The execution, delivery and performance of this Agreement by Seller, and the transactions contemplated hereby, will not violate (i) any provision of the certificates of incorporation or bylaws of Seller, (ii) any material agreement or instrument to which Seller is a party or by which Seller is bound, (iii) any judgment, order, ruling, or decree applicable to Seller as a party in interest, or (iv) any law, rule or regulation applicable to Seller. 3.3 Authorization. The execution, delivery and performance of this Agreement and the transactions contemplated hereby have been duly and validly authorized by all requisite corporate action on the part of Seller. This Agreement has been duly executed and delivered on behalf of Seller, and at the Closing all documents and instruments required hereunder to be executed and delivered by Seller shall be duly executed and delivered. This Agreement does, and such documents and instruments executed as the result hereof shall, constitute legal, valid and binding obligations of Seller enforceable in accordance with their terms, subject, however, to the effect of bankruptcy, insolvency, reorganization, moratorium and similar laws from time to time in effect relating to the rights and remedies of creditors, as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 3.4 Broker. Seller has not incurred any liability, contingent or otherwise for broker's or finder's fees relating to the transaction contemplated by this Agreement for which Purchaser shall have any responsibility whatsoever. - 9 - 15 3.5 Litigation. There is no litigation proceeding pending or any order, injunction or decree outstanding, against or relating to Seller or the Subject Property that, if adversely determined would have a material adverse effect upon the Subject Property or the continued operation of the Subject Property. To Seller's knowledge, there is no litigation or proceeding threatened nor is Seller in violation of any applicable law, regulation, ordinance, or any other applicable requirement of any governmental body or court, which violation would have a material adverse effect upon the Subject Property or the continued operation of the Subject Property, and no notice has been received by Seller alleging any such violation. 3.6 Preferential Rights Approvals and Consents. Purchaser acknowledges that the Leases or portions thereof may be subject to a) governmental approval; b) preferential rights to purchase; or c) other forms of consent. Seller has disclosed to Purchaser, to the best of its knowledge, all of the Leases which may be subject to preferential rights to purchase and consents and Seller shall use its best efforts (with reasonable cooperation from Purchaser) to obtain resolution of same prior to Closing. The process of obtaining governmental approval or other consents may continue after Closing and shall be the joint responsibility of Seller and Purchaser. 3.7 Title. Seller owns Good and Marketable Title (as defined below) to the Subject Property. 3.8 Due Execution and Enforceability. There are no bankruptcy, insolvency, reorganization, receivership or arrangement proceedings pending, being contemplated by, or to the knowledge of Seller, threatened against Seller. 3.9 Lease Maintenance. The Leases set forth on Exhibit "A" are in full force and effect as to all lands and depths described in such Leases. 3.10 Other Maintenance. All rents and royalties and other payments due with respect to the Subject Property have been properly and timely paid, and all liabilities of any kind or nature incurred with respect to the Subject Property have been paid before delinquency; neither Seller nor to Seller's knowledge any prior owners of the Subject Property have received any notice of default or claimed default with respect to any obligations with respect to the Subject Property or any part thereof. - 10 - 16 3.11 Equipment. To Seller's knowledge, all Wells, Facilities, and other equipment that constitute part of the Subject Property are in good repair and working condition and have been designed, installed and maintained in accordance with good industry standards and all applicable legal requirements. 3.12 Compliance with Laws. To Seller's knowledge, all operations relating to the Subject Property have been conducted in accordance with all laws, orders, rules and regulations of all governmental authorities having or asserting jurisdiction relating to the ownership and operation thereof, including the production of all Substances attributable thereto. All necessary governmental certificates, consents, permits, licenses or other authorizations with regard to the ownership or, to Seller's knowledge, operation of the Subject Property have been obtained and no violations exist or have been recorded in respect of such licenses, permits or authorizations. 3.13 Environmental. Seller has obtained all permits, licenses and other authorizations that are required under federal, state and local laws with respect to pollution or protection of the environment relating to the Subject Property, including laws relating to actual or threatened emissions, discharges or releases of pollutants, raw materials, products, contaminants or hazardous or toxic materials or wastes into ambient air, surface water, groundwater or land, or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants or hazardous or toxic materials or wastes, the failure of which to obtain would materially affect the value, use or operation of any of the Subject Property; and to the best of Seller's knowledge third parties operating the Subject Property are in compliance in all material respects with all terms and conditions of such laws, permits, licenses and authorizations, and also are in compliance in all material respects with all other limitations, restrictions, conditions, standards, prohibitions, requirements, obligations, schedules and timetables contained in such laws or contained in any regulation, code, plan, order, decree, judgement, notice or demand letter issued, entered, promulgated or approved thereunder relating to the Subject Property, the failure with which to comply would materially affect the value, use or operation of any of the Subject Property; and Seller has not (and to Seller's knowledge and belief no third party operator has) received notice of any violation of or investigation relating to any federal, state or - 11 - 17 local laws with respect to pollution or protection of the environment relating to the Subject Property. Within no later than ten (10) days prior to Closing, Seller shall furnish Purchaser copies of all environmental studies and reports prepared or obtained by Seller relating to the Subject Property. 3.14 Contracts. Seller has performed in all material respects all obligations required to be performed by it and is not in default, or alleged to be in default, in any material respect under any of the Contracts. 3.15 Adverse Changes. Since the Effective Date, (i) the Subject Property, viewed as a whole, has not experienced any material adverse change or material reduction in the rate of production of Substances, other than changes in the ordinary course of operation, changes that result from depletion in the ordinary course of operation, and changes that result from variances in markets for the Substances, and (ii) none of the Subject Property has suffered any material destruction, damage or loss. 3.16 Taxes. All ad valorem, property, occupation, severance, production, gathering, pipeline, gross production, windfall profit, Btu, energy, excise and other taxes, governmental charges and assessments imposed or assessed with respect to, measured by, charged against or attributable to the Subject Property have been duly paid. 3.17. Agreements to Sell or Mortgage. Except for potential preferential rights to purchase, Seller has not agreed to sell or encumber the Subject Property to any party other than Purchaser. 3.18. Take-or-Pay and Other Settlements. To the best of Seller's knowledge, there are no take-or-pay settlements or gas sales contract buy-downs or buy-outs that will affect the Subject Property after the Effective Time, for which Purchaser will have any responsibility whatsoever or for which Purchaser will owe any additional royalty after the Effective Time or which will adversely affect Purchaser in any way. 3.19. Production Payments and Calls on Production. Except for the Production Payment to be granted by Purchaser to Seller herein, the Subject Property is not subject to any production payments and/or to any call on production. - 12 - 18 ARTICLE IV REPRESENTATIONS OF PURCHASER Purchaser represents and warrants to Seller that: 4.1 Existence. Purchaser is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware, and is duly qualified to carry on its business on the Outer Continental Shelf. 4.2 Power. Purchaser has the corporate power to enter into and perform this Agreement and the transactions contemplated hereby, subject to rights to consent by, required notices to, and filings with or other actions by governmental entities where the same are customarily obtained subsequent to the assignment of oil and gas interests and leases. The execution, delivery and performance of this Agreement by Purchaser, and the transactions contemplated hereby, will not violate (i) any provision of the certificates of incorporation or bylaws of Purchaser, (ii) any material agreement or instrument to which Purchaser is a party or by which Purchaser is bound, (iii) any judgment, order, ruling, or decree applicable to Purchaser as a party in interest, or (iv) any law, rule or regulation applicable to Purchaser. 4.3 Authorization. The execution, delivery and performance of this Agreement and the transactions contemplated hereby have been duly and validly authorized by all requisite corporate action on the part of Purchaser. This Agreement has been duly executed and delivered on behalf of Purchaser, and at the Closing all documents and instruments required hereunder to be executed and delivered by Purchaser shall have been duly executed and delivered. This Agreement does, and such documents and instruments shall, constitute legal, valid and binding obligations of Purchaser enforceable in accordance with their terms, subject, however, to the effect of bankruptcy, insolvency, reorganization, moratorium and similar laws from time to time in effect relating to the rights and remedies of creditors, as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.4 Independent Evaluation and Review. Purchaser acknowledges that Purchaser is an experienced and knowledgeable investor in the oil and gas business. Purchaser also acknowledges that other than as expressly set out in this Agreement and the Assignment, Seller has made no representations or warranties as to the accuracy or completeness of any information supplied to - 13 - 19 Purchaser, or as to title to the Subject Property. Based on such acknowledgments, in entering into and performing this Agreement, Purchaser has relied and will rely solely upon Sellers Representations and warranties, its independent investigation of, and judgment with respect to, the Subject Property, its condition, value and Seller's title thereto. 4.5 Further Distribution. Purchaser is acquiring the Property for its own account and not with a view to, or for offer or resale in connection with, a distribution thereof within the meaning of the Securities Act of 1933 and the rules and regulations pertaining to it or a distribution thereof in violation of any applicable securities laws. 4.6 Brokers. Purchaser has incurred no liability, contingent or otherwise, for broker's or finder's fees relating to the transactions contemplated by this Agreement for which Seller shall have any responsibility whatsoever. 4.7 Litigation. There is no litigation or other proceeding pending or to Purchaser's knowledge threatened, or any order, injunction or decree outstanding against or relating to Purchaser which would prevent Purchaser from entering into this Agreement. ARTICLE V TITLE MATTERS 5.1 Title Examination Period. During the period commencing with the execution date of this Agreement and concluding three (3) business days prior to the Closing Date, Seller shall provide Purchaser and/or its representatives access to and or use its best efforts to cause the operator of any portion of the Subject Property to allow Purchaser access to (i) all abstracts of title, title opinions, title files, ownership maps, lease files, assignments, divisions orders, operating records, agreements and other books, records, contracts, correspondence, maps, data, reports, documents and information of Seller pertaining to the Subject Property, and (ii) the Subject Property in order to conduct inspections thereof. 5.2 Title Defects. The Subject Property shall be deemed to have a "Title Defect" if Seller has less than Good and Marketable Title to any of the Subject Property. As used herein, the term "Good and Marketable Title" - 14 - 20 means such record and beneficial title to Seller that: (i) entitles Seller to receive not less than the percentage set forth in Exhibit "A" hereto as the "Net Revenue Interest" of all hydrocarbons produced, saved and marketed from the Subject Property, any Well, or any unit of which the Subject Property is a part and that are allocated to such Subject Property, all without reduction, suspension or termination of such interest throughout the duration of the life of such Subject Property, except as specifically set forth in Exhibit "A", and (ii) obligates Seller to bear not more than that percentage set forth in Exhibit "A" hereto as the "Working Interest" of the costs and expenses relating to the maintenance, development and operation of such Subject Property, Well or unit, without increase throughout the duration of the life of such Subject Property, except as specifically set forth in Exhibit "A". 5.3 Remedies for Title Defects. Seller shall have the right, but not the obligation, to cure any Title Defect at its expense that it has received timely notice from Purchaser. In the event Seller is unable to cure any such Title Defect on or before three (3) days prior to the Closing Date, Purchaser and Seller shall: (i) postpone the date of Closing by a mutually agreeable time period to permit Seller to cure the Title Defect, or (ii) meet and mutually agree to an adjustment of the Purchase Price as remedy for the Title Defect(s). If the Purchaser and Seller cannot mutually agree in good faith to an adjustment of the Purchase Price, then either party may terminate this Agreement by written notice with no further obligation on the part of the Purchaser or Seller. ARTICLE VI PRE-CLOSING TRANSACTIONS 6.1 Operation of the Subject Property Pending the Closing Date. (a) Prior to the Closing Date, Seller agrees, unless specifically waived by Purchaser in writing: (i) to pay timely all costs and expenses incurred in connection with the Subject Property; (ii) not enter into any material new agreements or amend or terminate any material existing agreements relating to the Subject Property; (iii) not encumber, sell, or otherwise dispose of any of the Subject Property other than in the ordinary course of business; (iv) not abandon any well included in the Subject Property or release or abandon any portion of the Lease included in the Subject Property; (v) not waive, compromise or settle any material right or claim that - 15 - 21 would materially adversely affect the ownership or operation of the Subject Property after the Closing Date; (vi) maintain insurance now in force with respect to the Subject Property; and (vii) use reasonable efforts to cause the Leases and Contracts to be kept in full force and effect and perform and comply with all of the material covenants and conditions contained in same. (b) Seller shall not propose any operation under the terms of any applicable operating agreement after the date of this Agreement and prior to Closing. Provided, however, in the event Closing does not occur on this transaction, Seller retains all of its rights under the applicable operating agreements in regard to any such proposed operation. In connection with any operation proposed by a party other than Seller or Purchaser, Seller shall furnish Purchaser any data and other information furnished to Seller which has not already been furnished to Purchaser under any such operating agreement by the party proposing such operation. Purchaser shall then elect whether to consent to such proposed operation and Seller shall be bound by Purchaser's decision to consent or not to such operation. 6.2 Casualty Insurance. Purchaser shall assume the risk of any change in the condition of the Property from the Effective Date until Closing. Should any of the wells producing from the Land covered by or constituting part of the Property be destroyed, lost or cease to produce because of blowout, fire, storm, casing collapse, Act of God or other casualty pending the Closing Date, such event shall not constitute a title defect nor shall Purchaser be relieved of its obligation to close hereunder but shall be entitled to receive an assignment of any insurance claims or causes of action that Seller may be entitled to assert or pursue against insurers or operators or third parties who may be liable if the casualty was the result of the operator's or such third party's negligence. 6.3 Permissions. Purchaser shall obtain all applicable local, state and federal governmental and agency permissions, approvals and consents as may be required to consummate the sale contemplated hereunder (including those permissions, approvals, and consents which are customarily obtained after the assignment of an oil and gas lease or interest), including but not limited to approvals from the MMS. 6.4 Copies of Contracts. Prior to the Closing, Seller shall have made available to Purchaser true copies of all of the Contracts in its possession or under its control. - 16 - 22 ARTICLE VII SELLER'S CONDITIONS OF CLOSING Seller's obligation to consummate the transaction provided for herein is subject to satisfaction or waiver by Seller of the following conditions: 7.1 Representations. The representations and warranties of Purchaser contained in Article IV shall be true and correct in all material respects on the date of Closing as though made on and as of that date. 7.2 Performance. Purchaser shall have performed in all material respects the obligations, covenants and agreements hereunder to be performed by it at or prior to the Closing. 7.3 Pending Matters. No suit, action or other proceeding by a third party or a governmental authority shall be pending or threatened which seeks substantial damages from Seller in connection with, or seeks to restrain, enjoin or otherwise prohibit, the consummation of the transactions contemplated by this Agreement. 7.4 Certificates. Purchaser shall have delivered to Seller a certificate by an officer of Purchaser, dated the date of Closing, certifying on behalf of Purchaser that the conditions set forth in Sections 7.1 and 7.2 have been fulfilled. 7.5 Opinions. Purchaser shall have delivered to Seller a legal opinion dated as of Closing, in form and substance satisfactory to Seller, to the effect that: (i) it is a corporation organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to carry on its business in the States of Louisiana and Alabama and to own properties under the jurisdiction of the MMS; (ii) the execution, delivery and performance of this Agreement and the transactions contemplated hereby have been duly and validly authorized by all requisite action on the part of Purchaser; and (iii) this Agreement and all documents and instruments executed by Purchaser at Closing have been duly executed and delivered on behalf of Purchaser and constitute legal, valid and binding obligations of Purchaser enforceable in accordance with their terms. - 17 - 23 In giving this legal opinion, counsel for Purchaser may rely upon certificates of governmental officials and of the respective officers, general partners and individuals, as appropriate, as to matters of fact, and may qualify the legal opinion with such other assumptions and exceptions as are reasonable under the circumstances. 7.6 Encumbrance or Impairment of Security. As of Closing, there shall be no mortgage or other encumbrance of any kind on the volumes of gas that Purchaser is obligated to deliver to Seller identified as the Production Payment which would take priority over, or in any manner impair, the first priority of the security interest to be granted under Section 14.5. ARTICLE VIII PURCHASER'S CONDITIONS OF CLOSING Purchaser's obligation to consummate the transactions provided for herein is subject to the satisfaction or waiver by Purchaser of the following conditions: 8.1 Representations. The representations and warranties of Seller contained in Article III shall be true and correct in all material respects on the date of Closing as though made on and as of that date. 8.2 Performance. Seller shall have performed in all material respects the obligations, covenants and agreements hereunder to be performed by it at or prior to the Closing. 8.3 Pending Matters. No suit, action or other proceeding by a third party or a governmental authority shall be pending or threatened which seeks substantial damages from Purchaser in connection with, or seeks to restrain, enjoin or otherwise prohibit, the consummation of the transactions contemplated by this Agreement. 8.4 Approval of Contracts. Purchaser shall have approved the terms and provisions of all of the Contracts. - 18 - 24 8.5 Environmental Condition. Purchaser shall be satisfied with the environmental condition of the Subject Property. 8.6 Certificates. Seller shall have delivered to Purchaser a certificate by an officer of Seller, dated the date of Closing, certifying on behalf of Seller that the conditions set forth in Sections 8.1 and 8.2 have been fulfilled. 8.7 Opinions. Seller shall have delivered to Purchaser a legal opinion dated as of Closing, in form and substance satisfactory to Purchaser, to the effect that: (i) it is a corporation organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to carry on its business in the States of Louisiana and Alabama and to own properties under the jurisdiction of the MMS; (ii) the execution, delivery and performance of this Agreement and the transactions contemplated hereby have been duly and validly authorized by all requisite action on the part of Seller; and (iii) this Agreement and all documents and instruments executed by Seller at Closing have been duly executed and delivered on behalf of Seller and constitute legal, valid and binding obligations of Seller enforceable in accordance with their terms. In giving this legal opinion, counsel for Seller may rely upon certificates of governmental officials and of the respective officers, general partners and individuals, as appropriate, as to matters of fact, and may qualify the legal opinion with such other assumptions and exceptions as are reasonable under the circumstances. ARTICLE IX CLOSING 9.1 Time and Place of Closing. If the conditions of Closing have been satisfied or waived, the consummation of the transactions contemplated hereby (the "Closing") shall be held as soon as possible, but not later than, 10:00 a.m. (C.D.T.) on the Closing Date at Seller's offices, or other mutually acceptable location. 9.2 Closing Obligations. At the Closing: - 19 - 25 (a) Seller shall execute, acknowledge and deliver appropriate Assignments of Record Title Interest or Operating Rights, where applicable, to convey title to the Subject Property to Purchaser with special limited warranty of title (in sufficient counterparts to facilitate recording), in the form of Exhibit "E-1" through "E-10", attached hereto. (b) Seller shall execute such other instruments, including without limitation, Change of Operator forms, and take such other action as may be necessary to carry out its obligations under this Agreement; (c) Purchaser shall pay the Closing Amount, if any; (d) Seller shall deliver to Purchaser possession of the Subject Property, including without limitation those materials referenced in Section 1.1 G. herein, provided, however, in regard to files, delivery shall be within thirty (30) days after Closing. (e) Purchaser shall execute, acknowledge and accept the said Assignments executed by Seller. Purchaser shall execute such other instruments including, but not limited to the Financing Statement pursuant to Article 14.5 and take such other action as may be necessary to carry out its obligations under this Agreement; (f) In the event Seller is responsible at the time of the Closing for the disbursement of proceeds from production from the Subject Property to third parties and in the event Purchaser requires additional time after the Closing to assume this responsibility from Seller in order to avoid any interruption in the payments to third parties as the result of sale of the Subject Property, Seller and Purchaser shall enter into a mutually acceptable letter agreement, the terms of which will provide for Seller to retain responsibility for disbursement of proceeds for a period not to exceed ninety (90) days from the first day of the month nearest to the Closing Date. Such letter agreement shall contain provisions consistent with those normally used by Seller under similar circumstances in the usual conduct of its business; - 20 - 26 (g) Purchaser is satisfied with the condition of the Subject Property. ARTICLE X POST-CLOSING OBLIGATIONS 10.1 Receipts and Credits. All monies, proceeds, receipts, credits and income attributable to Seller's interest in the Subject Property for all periods of time subsequent to the Effective Date shall be the sole property and entitlement of the Purchaser, and, to the extent received by Seller after the Closing, Seller shall fully disclose, account for and transmit same to Purchaser promptly. All monies, proceeds, receipts and income attributable to Seller's interest in the Subject Property for all periods of time prior to the Effective Date shall be the sole property and entitlement of Seller and, to the extent received by Purchaser, Purchaser shall fully disclose, account for and transmit same to Seller promptly. All costs, expenses, taxes (subject to Article XII) and disbursements, attributable to periods of time prior to Effective Date, regardless of when due or payable,, shall be the sole obligation of Seller and Seller shall promptly pay, or if paid by Purchaser, promptly reimburse Purchaser for same. All costs, expenses, taxes (subject to Article XII) and disbursements, attributable to periods of time subsequent to the Effective Date, regardless of when due or payable, shall be the sole obligation of the Purchaser, and if paid by Seller, Seller shall be promptly reimbursed by the Purchaser. All uncollected accounts receivable attributable to the Subject Property, after the Effective Date, shall be assigned to Purchaser. To the extent the provisions of this Section 10.1 may be interpreted to conflict with the provisions of Section 12.2 below, the provisions of Section 12.2 shall be deemed to control. 10.2 Indemnity. If Closing occurs: (I) PURCHASER SHALL ASSUME AS OF THE EFFECTIVE DATE ALL OBLIGATIONS AND LIABILITIES ARISING AFTER THAT DATE RELATING TO THE OWNERSHIP OR USE OF THE SUBJECT PROPERTY, INCLUDING BUT NOT LIMITED TO RECLAMATION AND THE PLUGGING AND ABANDONMENT OF ALL WELLS AND ALL ENVIRONMENTAL OBLIGATIONS, LIABILITIES AND DUTIES WITH RESPECT TO THE SUBJECT PROPERTY, REGARDLESS OF WHETHER SUCH ENVIRONMENTAL OBLIGATIONS, - 21 - 27 LIABILITIES AND DUTIES RELATE TO THE PERIOD PRIOR TO OR AFTER THE EFFECTIVE DATE. THE RECLAMATION AND PLUGGING AND ABANDONMENT SHALL BE PERFORMED IN A GOOD AND WORKMANLIKE MANNER AND IN ACCORDANCE WITH ALL APPLICABLE LAWS, RULES OR REGULATIONS. (II) PURCHASER SHALL FULLY PROTECT, INDEMNIFY AND DEFEND SELLER, ITS OFFICERS, AGENTS AND/OR EMPLOYEES AND HOLD THEM HARMLESS FROM ANY AND ALL CLAIMS, LOSSES, DAMAGES, DEMANDS, SUITS, CAUSES OF ACTION AND LIABILITIES (INCLUDING REASONABLE ATTORNEY'S FEES, COSTS OF LITIGATION AND/OR INVESTIGATION AND OTHER COSTS ASSOCIATED THEREWITH) (COLLECTIVELY REFERRED TO HEREAFTER AS "CLAIMS") OF EVERY KIND ARISING OUT OF OR CONNECTED, DIRECTLY OR INDIRECTLY, WITH THE OWNERSHIP, OPERATION OR ABANDONMENT OF THE SUBJECT PROPERTY, OR ANY PART THEREOF, AFTER THE EFFECTIVE DATE REGARDLESS OF CAUSE OR OF SELLER'S NEGLIGENCE OR FAULT, WHETHER IMPOSED BY STATUTE, RULE OR REGULATION OR STRICT LIABILITY OF SELLER, ITS OFFICERS, AGENTS AND/OR EMPLOYEES. (III) PURCHASER SHALL FULLY PROTECT, INDEMNIFY AND DEFEND SELLER, ITS OFFICERS, AGENTS AND/OR EMPLOYEES AND HOLD THEM HARMLESS FROM ANY AND ALL CLAIMS FOR POLLUTION AND/OR ENVIRONMENTAL DAMAGE OF ANY KIND, ANY FINES OR PENALTIES ASSESSED ON ACCOUNT OF SUCH DAMAGE, CAUSED BY, ARISING OUT OF, OR IN ANY WAY INCIDENTAL TO THE OWNERSHIP OR OPERATION OF THE SUBJECT PROPERTY, IF SUCH CLAIMS ARE ASSERTED SUBSEQUENT TO THE EFFECTIVE DATE, REGARDLESS OF WHEN THE ACT OR OMISSION GIVING RISE THERETO OCCURRED AND REGARDLESS OF WHETHER OR NOT ARISING FROM, INCIDENTAL TO OR THE RESULT OF SELLER'S NEGLIGENCE OR FAULT, OR WHETHER OR NOT ANY LIABILITY IS IMPOSED UPON SELLER AS A RESULT OF ANY STATUTE, RULE OR REGULATION OR STRICT LIABILITY OF SELLER, ITS OFFICERS, AGENTS OR EMPLOYEES, INCLUDING WITHOUT LIMITATION LIABILITY UNDER THE COMPREHENSIVE ENVIRONMENTAL RECOVERY, COMPENSATION AND LIABILITY ACT, 42 U.S.C. ss.9601 ET SEQ. EXCEPT AS EXPRESSLY PROVIDED IN THIS AGREEMENT THE SUBJECT PROPERTY TO BE ASSIGNED PURSUANT TO SECTION 1.1 HEREOF ARE TO BE ASSIGNED AS IS, AND SELLER MAKES NO WARRANTY, EXPRESS OR IMPLIED IN FACT OR BY LAW, WHETHER OF TITLE, OPERATING CONDITION, SAFETY, COMPLIANCE WITH GOVERNMENT REGULATIONS, MERCHANTABILITY, FITNESS FOR ANY PARTICULAR PURPOSES, CONDITION OR OTHERWISE, CONCERNING ANY OF SUCH ASSETS. ALL WELLS, PERSONAL PROPERTY, - 22 - 28 MACHINERY, EQUIPMENT AND FACILITIES THEREIN, THEREON AND APPURTENANT THERETO TO BE CONVEYED BY SELLER AND ACCEPTED BY PURCHASER PRECISELY AND ONLY "AS IS, WHERE IS" AND SELLER DOES NOT WARRANT THEM TO BE FREE FROM REDHIBITORY VICES OR DEFECTS NOR WILL SELLER WARRANT AGAINST EVICTION THEREFROM. It is the intention of the parties that the Purchaser's indemnity of Seller shall not extend to any Claims, demands or causes of action known to Seller as of the Effective Date. The foregoing indemnification shall not apply to Claims whensoever asserted by Seller's employees for injuries suffered with respect to the Subject Property prior to said Effective Date. 10.3 Further Assurances. After Closing, Seller and Purchaser agree to take such further actions and to execute, acknowledge and deliver all such further documents that are necessary or useful in carrying out the purposes of this Agreement or of any document delivered pursuant hereto. ARTICLE XI TERMINATION 11.1 Right of Termination. This Agreement and the transactions contemplated hereby may be terminated at any time at or prior to the Closing: (a) By mutual consent of the parties; or (b) By either party if the Closing shall not have occurred as hereinabove provided, due to the failure of the other party to meet a material condition to Closing. (c) By Purchaser or Seller pursuant to Article V; (d) By either Party if any court or governmental agency shall have issued an order, judgment or decree or taken any other action challenging, delaying, restraining, enjoining, prohibiting or invalidating the consummation of any of the transactions contemplated herein. - 23 - 29 11.2 Effect of Termination. If this Agreement is terminated pursuant to this Article, this Agreement shall become void and of no further force or effect and each party shall bear alone its respective costs and expenses incurred prior to such termination and neither party shall be liable to the other for any actual, consequential, or incidental damages, including, but not limited to, lost profits. Upon any termination of this Agreement pursuant to this Article, Seller shall be free to immediately enjoy all existing rights of ownership of the Subject Property and to sell, transfer, encumber or otherwise dispose of Seller's interest in the Subject Property to any party without any restrictions under this Agreement. ARTICLE XII TAXES 12.1 Sales Taxes. The Purchase Price provided for hereunder is net of any sales taxes or other transfer taxes in connection with the sale of Seller's interest in the Subject Property. Purchaser shall be liable for any sales tax or other transfer tax, as well as any applicable conveyance, transfer and recording fees, and real estate transfer stamps or taxes imposed on the transfer of Seller's interest in the Subject Property pursuant to this Agreement. Purchaser shall defend, indemnify and hold harmless Seller with respect to the payment of any of those taxes including any interest or penalties assessed thereon. 12.2 Other Taxes. All production, severance, excise, conservation fees and other such similar taxes or fees relating to production of oil, gas and condensate attributable to Seller's interest in the Subject Property prior to the Effective Date shall be paid by Seller, and all such taxes relating to such production on or after the Effective Date shall be paid by Purchaser. 12.3 Cooperation. Each party to this Agreement shall: (a) Provide the other party with reasonable access to all relevant documents, data and other information which may be required by the other party for the purpose of preparing tax returns and responding to any audit by any taxing jurisdiction. Each party to this Agreement shall cooperate with all reasonable requests of the other party made in connection - 24 - 30 with contesting the imposition of taxes. Notwithstanding anything to the contrary in this Agreement, neither party to this Agreement shall be required at any time to disclose to the other party any tax returns or other confidential tax information. (b) Cooperate with the other party to provide information required by the Internal Revenue Service on asset sales and acquisitions. ARTICLE XIII INDEPENDENT INVESTIGATION AND DISCLAIMER Purchaser acknowledges that in making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Purchaser has relied solely on the basis of its own independent investigation of the Subject Property, and upon the representations, warranties and covenants in this Agreement. Accordingly, Purchaser acknowledges that Seller has not made, AND SELLER HEREBY EXPRESSLY DISCLAIMS AND NEGATES, ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, AT COMMON LAW, BY STATUTE, OR OTHERWISE RELATING TO (i) THE CONDITION OF THE SUBJECT PROPERTY (INCLUDING WITHOUT LIMITATION, ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, OF FITNESS FOR A PARTICULAR PURPOSE, OR OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS) AND (ii) ANY INFORMATION, DATA OR OTHER MATERIALS (WRITTEN OR ORAL) FURNISHED TO PURCHASER BY OR ON BEHALF OF SELLER (INCLUDING, WITHOUT LIMITATION, THE EXISTENCE OR EXTENT OF OIL, GAS OR OTHER MINERAL RESERVES, THE RECOVERABILITY OF OR THE COST OF RECOVERING ANY SUCH RESERVES, THE VALUE OF SUCH RESERVES, ANY PRODUCT PRICING ASSUMPTIONS, PRESENT OR PAST PRODUCTION RATES, COMPLIANCE WITH LEASE TERMS, THE CONDITION OF ANY WELL, AND THE ABILITY TO SELL OIL OR GAS PRODUCTION AFTER CLOSING); provided, however, that the foregoing disclaimer and negation of representations and warranties shall not affect or impair the representations and warranties of Seller set forth in Article III hereof. ARTICLE XIV PRODUCTION PAYMENT 14.1 Definition of Purchaser's Property. Subject to Purchaser's obligation to make cash payments and/or alternate source gas deliveries under - 25 - 31 Article 14.4, the Production Payment shall be delivered from the Purchaser's ,or its successors or assigns, working interest in Mobile Blocks 863, 864, 907, 908, 952, 953, 955, 997, 998 and 999 as reflected on Exhibit "F" ("Purchaser's Property"). 14.2 Delivery of Gas. Purchaser shall deliver in kind from Purchaser's first gas produced from the Purchaser's Property a fixed daily volume of gas net to Seller equal to 6.375 MMCFD ("Production Payment") free and clear of leasehold costs, MMS royalty, overriding royalties or any other burdens whatsoever attributable to Purchaser's Property, including all operating, processing and transportation costs to the delivery points. 14.3 Delivery Points. Purchaser shall deliver Seller's gas volumes, at Seller's option upon reasonable notice, into the MAGGP or Mobile Area Gathering System ("MAGS"). Delivery shall be made and title shall pass from Purchaser to Seller at the inlet flange of the applicable pipeline at Mobile 908 or other mutually agreeable delivery point. In the event that other pipeline connections are made by Purchaser to production facilities covered by this agreement, Purchaser shall notify Seller. Seller shall have the ongoing option to take its gas into these new delivery points at no additional cost for the use of Purchaser's connection to the new delivery point. 14.4 Balancing and Alternative Payment. A. Imbalances: Any imbalances which occur between quantities actually delivered to Seller by Purchaser in satisfaction of the Production Payment and the volume due Seller as the Production Payment shall be accounted for as follows: Within twenty five (25) days after the end of the month, Purchaser shall furnish a statement (the "Production Balancing Statement"). The Production Balancing Statement shall provide an accounting on a monthly basis of the quantities of gas, expressed in MCFs, that Seller is entitled to receive and the quantities of gas actually delivered for Seller's account. The net difference from the - 26 - 32 Production Balancing Statement shall be settled in gas by the end of the second month following the production month in which the imbalance occurs. B. Alternative Payment: For any monthly period for which Purchaser is unable to deliver sufficient volumes from Purchaser's Property equal to the Production Payment for reasons beyond Purchaser's control, Purchaser shall so notify Seller. Purchaser shall then to the extent the Production Payment volumes plus any imbalances are under-delivered, and only to that extent, at Purchaser's option, do one of the following: (i) deliver in kind to Seller sufficient gas volumes to equal the daily fixed Production Payment plus any imbalance volumes, with such volumes coming from the Texas Eastern East Louisiana Pool or another pipeline pool acceptable to Seller, or (ii) deliver the cash value of the under-delivered volumes (Production Payment under-delivery along with the value of any existing under-delivery) by the 25th day of the month following the month for which the Production Payment was due. The cash value shall be determined by using the Gas Daily Midpoint average for the month in which the Production Payment was due or the under-delivery occurred using the table titled "Daily Price Survey" utilizing the Louisiana-South Onshore, Texas E (ELA), for each respective month. MCF shall be converted to BTU for such purposes by using the then existing BTU value of gas from Purchaser's Property or if there is no existing production from Purchaser's Property, the last BTU value prior to cessation of production. (iii) If at Satisfaction Date, the Purchaser has not paid, either in kind or cash, the full payment due under Section 2.2, Purchaser shall make such payment - 27 - 33 within thirty (30) days of Satisfaction Date under the same terms as 14.4 B. (i) or 14.4 B. (ii). It is the intention of the parties that the Production Payment be made monthly in gas, and that the cash out option only be applicable when physical production from Producer's Property is insufficient to support the Production Payment. 14.5 Purchaser Grants a First Priority Security Interest. The Purchaser hereby grants a first priority security interest in Purchaser's share of first gas produced from Purchaser's Property (as described on Exhibit "F") in a recordable form which is attached hereto as Exhibit "G," Financing Statement, to secure the Purchaser's payment obligations and all other obligations hereunder. This granting of a security interest is deemed to be a Security Agreement under the Uniform Commercial Code, and Seller shall have all of the rights and remedies afforded by the Uniform Commercial Code as adopted by the State of Alabama. Furthermore, Purchaser agrees not to mortgage or otherwise encumber in any manner the amount of gas that Purchaser is obligated to deliver to Seller identified as the Production Payment during the period of time from the Effective Date through the Satisfaction Date as set out in Article 2.2. ARTICLE XV MISCELLANEOUS 15.1 Governing Law. This Agreement and all assignments and other instruments executed in accordance with it shall be governed by and interpreted in accordance with the laws of the United States of America and the State of Alabama. 15.2 Entire Agreement. This Agreement constitutes the entire agreement between the parties and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties. No supplement, amendment, alteration, modification, waiver or termination of this Agreement shall be binding unless executed in writing by the parties hereto. - 28 - 34 15.3 Waiver. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided. 15.4 Captions. The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement. 15.5 Notices. Any notice provided or permitted to be given under this Agreement shall be in writing, and may be sent by personal delivery, facsimile machine or by depositing same in the United States mail, addressed to the party to be notified, postage prepaid, and registered or certified with a return receipt requested. Notices deposited in the mail in the manner hereinabove described shall be deemed to have been given and received upon the date of delivery as shown on the return receipt (or upon the date of attempted delivery where delivery is refused). Notice served in any other manner shall be deemed to have been given and received only if and when actually received by the addressee (confirmation of such receipt by confirmed facsimile transmission being deemed receipt of communications sent by telecopy or other facsimile means),and when delivered and receipt for, if hand-delivered, sent by express courier or delivery service. For purposes of this notice, the designated representatives and addresses of the parties shall be as set forth below, or at such other address and number as either Party shall have previously designated by written notice to the other Party in the manner hereinabove set forth: If to Seller: Murphy Exploration & Production Company 131 South Robertson Street New Orleans, LA 70112 ATTENTION: Mr. Steve Jones Telecopy No.: (504) 561-2551 If to Purchaser: Callon Petroleum Operating Company P. O. Box 1287 200 North Canal Street Natchez, MS 39121 ATTENTION: Ms. Dee Newman Telecopy No.: 601-446-1362 - 29 - 35 15.6 Expenses. Except as otherwise provided herein, each party shall be solely responsible for all expenses incurred by it in connection with this transaction (including, without limitation, fees and expenses of its own counsel and accountants). 15.7 Severability. If any term or other provision of this Agreement is held invalid, illegal or incapable of being enforced under any rule of law, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in a materially adverse manner with respect to either party. 15.8 Publicity. Seller and Purchaser shall consult with each other with regard to all publicity and other releases issued at or prior to the Closing concerning this Agreement and the transactions contemplated hereby and, except as required by applicable law or the applicable rules or regulations of any governmental body or stock exchange, neither party shall issue any publicity or other releases without the prior written consent of the other party. 15.9 Consequential Damages. The parties waive any rights to incidental or consequential damages resulting from a breach of this Agreement, including, without limitation, loss of profits. 15.10 Survival. The representations, warranties, covenants and obligations of the parties under Article III, Article IV, Article IX, Article XI and Article XII of this Agreement shall survive the Closing. 15.11 Successors and Assigns. This Agreement shall be a covenant running with the land and shall enure to the benefit of and be binding upon the Purchaser and Seller and their successors and assigns. 15.12 Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument. - 30 - 36 15.13 Binding Arbitration. In the event of any dispute between the parties hereto after Closing as to the provisions hereof, the documents executed or actions taken as a consequence of such execution, the parties hereby agree that any such matter shall be submitted to binding arbitration pursuant to the Louisiana Arbitration statute (R.S. 9:4201) and each party shall appoint one arbitrator with the two arbitrators so selected appointing a third. In the event the two arbitrators are unable to agree upon the third, the third arbitrator shall be appointed by the senior judge of the United States District Court for the Eastern District of Louisiana. 15.14 Well information. Upon request by Seller, Purchaser shall provide to Seller in a timely manner all daily drilling reports, well information, data and logs pertaining to any wells drilled or reworked on the Subject Property. IN WITNESS WHEREOF, the parties hereto have caused this Purchase and Sale Agreement to be duly executed on this 26th day of May, 1999, but effective as of the Effective Date. SELLER: PURCHASER: MURPHY EXPLORATION & CALLON PETROLEUM OPERATING COMPANY PRODUCTION COMPANY By: /s/ John C. Higgins By: /s/ Dennis W. Christian ----------------------------- -------------------------------- John C. Higgins Dennis W. Christian Sr. Vice President Chief Operating Officer - 31 - - 1 - Purchase & Sale Agmt. D:\DATA\MURPHYPUR-AG16.WPD EX-23.1 4 CONSENT OF ARTHUR ANDERSEN LLP 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the use of our report dated February 19, 1999 on the financial statements of Callon Petroleum Company (and to all references to our Firm) included in or made a part of this registration statement on Form S-2 of Callon Petroleum Company. /s/ ARTHUR ANDERSEN LLP New Orleans, Louisiana June 11, 1999 EX-23.2 5 CONSENT OF HUDDLESTON & CO., INC. 1 Huddleston & Co., Letterhead June 11, 1999 CONSENT OF INDEPENDENT PETROLEUM AND GEOLOGICAL ENGINEERS The undersigned hereby consents to the use in the Prospectus constituting part of this Registration Statement on Form S-2 of our reserve reports relating to the oil and gas reserves of Callon Petroleum Company at December 31, 1998, and June 1, 1999. We also consent to the references to us under the heading "Experts" and elsewhere in such Prospectus. HUDDLESTON & CO., INC. Peter D. Huddleston, P.E. Peter D. Huddleston, P.E. President PDH:smr EX-25 6 STATEMENT OF ELIGIBILITY OF TRUSTEE 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------- FORM T-1 STATEMENT OF ELIGIBILITY AND QUALIFICATION UNDER THE TRUST INDENTURE ACT OF 1939 OF A CORPORATION DESIGNATED TO ACT AS TRUSTEE ---------------------- AMERICAN STOCK TRANSFER & TRUST COMPANY (Exact name of trustee as specified in its charter) New York 13-3439945 (State of incorporation (I.R.S. employer if not a national bank) identification No.) 40 Wall Street 10005 New York, New York (Zip Code) (Address of trustee's principal executive offices) ---------------------- CALLON PETROLEUM COMPANY (Exact name of obligor as specified in its character) Delaware 64-0844345 (State or other jurisdiction of (I.R.S. employer incorporation or organization) identification No.) 200 North Canal Street Natchez, Mississippi 39120 (Address of principal executive (Zip Code) offices) ------------------------------------------------------------------ % SENIOR SUBORDINATED NOTES DUE 2004 (Title of the Indenture Securities) 2 -2- GENERAL 1. General Information. Furnish the following information as to the trustee: a. Name and address of each examining or supervising authority to which it is subject. New York State Banking Department, Albany, New York b. Whether it is authorized to exercise corporate trust powers. The Trustee is authorized to exercise corporate trust powers. 2. Affiliations with Obligor and Underwriters. If the obligor or any underwriter for the obligor is an affiliate of the trustee, describe each such affiliation. None. 3. Voting Securities of the Trustee. Furnish the following information as to each class of voting securities of the trustee: As of June 8, 1999 --------------------------------------------------------------------------- COL. A COL. B --------------------------------------------------------------------------- Title of Class Amount Outstanding --------------------------------------------------------------------------- Common Shares - par value $600 per share. 1,000 shares 4. Trusteeships under Other Indentures. American Stock and Trust Company is the trustee under certain Indentures dated as of November 27, 1996 and July 31, 1997 in terms of which the obligor issued certain 10% and 10.125% Senior Subordinate Notes all of which rank PARI PASSU with the Indenture Securities currently being issued. 3 -3- 5. Interlocking Directorates and Similar Relationships with the Obligor or Underwriters. None. 6. Voting Securities of the Trustee Owned by the Obligor or its Officials. None. 7. Voting Securities of the Trustee Owned by Underwriters or their Officials. None. 8. Securities of the Obligor Owned or Held by the Trustee. None. 9. Securities of Underwriters Owned or Held by the Trustee. None. 10. Ownership or Holdings by the Trustee of Voting Securities of Certain Affiliates or Security Holders of the Obligor. None. 11. Ownership or Holdings by the Trustee of any Securities of a Person Owning 50 Percent or More of the Voting Securities of the Obligor. None. 12. Indebtedness of the Obligor to the Trustee. None. 13. Defaults by the Obligor. None. 14. Affiliations with the Underwriters. None. 4 -4- 15. Foreign Trustee. Not applicable. 16. List of Exhibits. T-1.1 - A copy of the Organization Certificate of American Stock Transfer & Trust Company, as amended to date including authority to commence business and exercise trust powers was filed in connection with the Registration Statement of Live Entertainment, Inc., File No. 33-54654, and is incorporated herein by reference. T-1.4 - A copy of the By-Laws of American Stock Transfer & Trust Company, as amended to date was filed in connection with the Registration Statement of Live Entertainment, Inc., File No. 33-54654, and is incorporated herein by reference. T-1.6 - The consent of the Trustee required by Section 312(b) of the Trust Indenture Act of 1939. Exhibit A. T-1.7 - A copy of the latest report of condition of the Trustee published pursuant to law or the requirements of its supervising or examining authority. - Exhibit B. ------------------------------ SIGNATURE Pursuant to the requirements of the Trust Indenture Act of 1939 the Trustee, American Stock Transfer & Trust Company, a corporation organized and existing under the laws of the State of New York, has duly caused this statement of eligibility and qualification to be signed on its behalf by the undersigned, thereunto duly authorized, all in the City of New York, and State of New York, on the 8th day of June, 1999. AMERICAN STOCK TRANSFER & TRUST COMPANY Trustee By: /s/ Herbert J. Lemmer ------------------------------ Vice President 5 EXHIBIT A Securities and Exchange Commission Washington, DC 20549 Gentlemen: Pursuant to the provisions of Section 321 (b) of the Trust Indenture Act of 1939, and subject to the limitations therein contained, American Stock Transfer & Trust Company hereby consents that reports of examinations of said corporation by Federal, State, Territorial or District authorities may be furnished by such authorities to you upon request therefor. Very truly yours, AMERICAN STOCK TRANSFER & TRUST COMPANY By: /s/ Herbert J. Lemmer ------------------------------ Vice President 6 EXHIBIT B AMERICAN STOCK TRANSFER & TRUST COMPANY 40 WALL ST. NEW YORK, NY 10005 CONSOLIDATED REPORT OF CONDITION AND INCOME FOR A BANK WITH DOMESTIC OFFICES ONLY AND TOTAL ASSETS OF LESS THAN $100 MILLION REPORT AT CLOSE OF BUSINESS ON DECEMBER 31, 1998 All schedules are to be reported in thousands of dollars. Unless otherwise indicated, report the amount outstanding as of the last business day of the quarter. SCHEDULE RC - BALANCE SHEET
DOLLAR AMOUNTS IN THOUSANDS - -------------------------------------------------------------------------------- ASSETS 1. Cash and balances due from depository institutions: a. Noninterest-bearing balances and currency and coin 191 b. Interest-bearing balances 2. Securities: a. Held-to-maturity securities (from Schedule RC-B, column A) b. Available-for-sale securities (from Schedule RC-B, column D) 9,486 3. Federal funds sold and securities purchased under agreements to resell 4. Loans and lease financing receivables: a. Loans and leases, net of unearned income (from Schedule RC-C) b. LESS: Allowance for loan and lease losses c. LESS: Allocated transfer risk reserve d. Loans and leases, net of unearned income, allowance, and reserve (item 4.a minus 4.b and 4.c 5. Trading assets 6. Premises and fixed assets (including capitalized leases) 4,136 7. Other real estate owned (from Schedule RC-M) 8. Investments in unconsolidated subsidiaries and associated companies (from Schedule RC-M) 9. Customers' liability to this bank on acceptances outstanding 10. Intangible assets (from Schedule RC-M) 11. Other assets (from Schedule RC-F) 6,386 12. a. Total assets (sum of items 1 through 11) 20,199 b. Losses deferred pursuant to 12 U.S.C. 1823 (j) c. Total assets and losses deferred pursuant to 12 U.S.C. 1823 (j) (sum of items 12.a and 12.b) 20,199
7 SCHEDULE RC - CONTINUED
DOLLAR AMOUNTS IN THOUSANDS - -------------------------------------------------------------------------------- LIABILITIES 13. Deposits: a. In domestic offices (sum of totals of columns A and C from Schedule RC-E) (1) Noninterest-bearing (2) Interest-bearing b. In foreign offices, Edge and Agreement subsidiaries, and IBFs (1) Noninterest-bearing (2) Interest-bearing 14. Federal funds purchased and securities sold under agreements to repurchase 15. a. Demand notes issued to the U.S. Treasury b. Trading liabilities 16. Other borrowed money (includes mortgage indebtedness and obligations under capitalized leases): a. With a remaining maturity of one year or less b. With a remaining maturity of more than one year through three years c. With a remaining maturity of more than three years 17. Not applicable 18. Bank's liability on acceptances executed and outstanding 19. Subordinated notes and debentures 20. Other liabilities (from Schedule RC-G) 7,490 21. Total liabilities (sum of items 13 through 20) 7,490 22. Not applicable EQUITY CAPITAL 23. Perpetual preferred stock and related surplus 24. Common stock 600 25. Surplus (exclude all surplus related to preferred stock) 9,289 26. a. Undivided profits and capital reserves 2,820 b. Net unrealized holding gains (losses) on available-for-sale securities 27. Cumulative foreign currency translation adjustments 28. a. Total equity capital (sum of items 23 through 27) 12,709 b. Losses deferred pursuant to 12 U.S.C. 1823(j) c. Total equity capital and losses deferred pursuant to 12 U.S.C. 1823(j) (sum of items 28.a and 28.b) 12,709 29. Total liabilities, equity capital, and losses deferred pursuant to 12 U.S.C.. 1823 (j) (sum of items 21 and 28.c) 20,199
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