SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ______________________________________________________ FORM 10-Q QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For Quarter Ended June 30, 1999 Commission File Number 0-25192 CALLON PETROLEUM COMPANY ------------------------------------------------------ (Exact name of Registrant as specified in its charter) 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 offices)(Zip code) (601) 442-1601 --------------------------------------------------- (Registrant's telephone number,including area code) Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ---- ---- As of August 10, 1999, there were 8,557,906 shares of the Registrant's Common Stock, par value $0.01 per share, outstanding. CALLON PETROLEUM COMPANY INDEX Page No. Part I. Financial Information Consolidated Balance Sheets as of June 30, 1999 and December 31, 1998 3-4 Consolidated Statements of Operations for Each of the three and six-months in the periods ended June 30, 1999 and June 30, 1998 5 Consolidated Statements of Cash Flows for Each of the six-months in the periods ended June 30, 1999 and June 30, 1998 6 Notes to Consolidated Financial Statements 7-8 Management's Discussion and Analysis of Financial Condition and Results of Operations 9-14 Part II. Other Information 15 Callon Petroleum Company Consolidated Balance Sheets (In thousands, except per share data) June 30, December 31, 1999 1998 --------- --------- (Unaudited) ASSETS Current assets: Cash and cash equivalents $ 7,334 $ 6,300 Accounts receivable 5,287 6,024 Other current assets 939 1,924 --------- --------- Total current assets 13,560 14,248 --------- --------- Oil and gas properties, full cost accounting method: Evaluated properties 484,202 444,579 Less accumulated depreciation, depletion and amortization (353,144) (345,353) --------- --------- 131,058 99,226 Unevaluated properties excluded from amortization 42,509 42,679 --------- --------- Total oil and gas properties 173,567 141,905 --------- --------- Pipeline and other facilities 6,021 6,182 Other property and equipment, net 1,556 1,753 Deferred tax asset 15,989 16,348 Long-term gas balancing receivable 224 199 Other assets, net 909 1,017 --------- --------- Total assets $ 211,826 $ 181,652 ========= ========= The accompanying notes are an integral part of the financial statements. Callon Petroleum Company Consolidated Balance Sheets (In thousands, except per share data) June 30, December 31, 1999 1998 --------- --------- (Unaudited) LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $ 8,913 $ 11,257 Deferred revenue on sale of production payment interest - current portion 4,844 -- Undistributed oil and gas revenues 2,029 1,720 Accrued net profits payable 250 129 --------- --------- Total current liabilities 16,036 13,106 --------- --------- Accounts payable and accrued liabilities to be refinanced 1,763 3,000 Long-term debt 99,250 78,250 Deferred revenue on sale of production payment interest 9,671 -- Accrued retirement benefits 2,215 2,323 Long-term gas balancing payable 491 489 --------- --------- Total liabilities 129,426 97,168 --------- --------- 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 at June 30, 1999 10 13 Common stock, $0.01 par value, 20,000,000 shares authorized; 8,545,517 and 8,178,406 outstanding at June 30, 1999 and at December 31, 1998, respectively 86 82 Treasury stock (98,578 shares at cost) (1,177) (915) Capital in excess of par value 108,296 109,429 Retained earnings (deficit) (24,815) (24,125) --------- --------- Total stockholders' equity 82,400 84,484 --------- --------- Total liabilities and stockholders' equity $ 211,826 $ 181,652 ========= ========= The accompanying notes are an integral part of the financial statements. Callon Petroleum Company Consolidated Statements Of Operations (Unaudited) (In thousands, except per share amounts) Three Months Ended Six Months Ended June 30, June 30, June 30, June 30, 1999 1998 1999 1998 ------- ------- ------- ------- Revenues: Oil and gas sales $ 8,568 $ 9,277 $16,537 $20,322 Interest and other 463 456 868 903 ------- ------- ------- ------- Total revenues 9,031 9,733 17,405 21,225 ------- ------- ------- ------- Costs and expenses: Lease operating expenses 1,878 2,148 3,486 4,089 Depreciation, depletion and amortization 3,989 4,896 7,952 10,466 General and administrative 1,379 1,230 2,440 2,732 Interest 1,444 332 2,471 983 ------- ------- ------- ------- Total costs and expenses 8,690 8,606 16,349 18,270 ------- ------- ------- ------- Income from operations 341 1,127 1,056 2,955 Income tax expense 116 380 359 1,001 ------- ------- ------- ------- Net income 225 747 697 1,954 Preferred stock dividends 555 699 1,386 1,398 ------- ------- ------- ------- Net income (loss) available to common shares $ (330) $ 48 $ (689) $ 556 ======= ======= ======= ======= Net income (loss) per common share: Basic $ (0.04) $ 0.01 $ (0.08) $ 0.07 Diluted $ (0.04) $ 0.01 $ (0.08) $ 0.07 Shares used in computing net income (loss) per common share: Basic 8,447 8,028 8,462 8,021 Diluted 8,447 8,247 8,462 8,233 The accompanying notes are an integral part of these financial statements. Callon Petroleum Company Consolidated Statements Of Cash Flows (Unaudited) (In thousands) Six Months Ended June 30, June 30, 1999 1998 -------- -------- Cash flows from operating activities: Net income $ 697 $ 1,954 Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization 8,210 10,722 Amortization of deferred costs 276 318 Amortization of deferred production payment revenue (252) -- Deferred income tax expense 359 1,001 Noncash compensation related to compensations plans 141 1,033 Changes in current assets and liabilities: Accounts receivable 737 1,344 Other current assets 985 (430) Current liabilities (1,532) 357 Changes in gas balancing receivable (25) 20 Changes in gas balancing payable 2 (52) Change in other long-term liabilities (108) -- Change in other assets, net (168) (82) ------- -------- Cash provided (used) by operating activities 9,322 16,185 ------- -------- Cash flows from investing activities: Capital expenditures (25,129) (23,733) Cash proceeds from sale of mineral interests -- 10,211 Cash proceeds from sale of mineral interest burdened by a net profits interest -- 19,957 ------- -------- Cash provided (used) by investing activities (25,129) 6,435 ------- -------- Cash flows from financing activities: Decrease in accounts payable and accrued liabilities to be refinanced (1,237) -- Increase in debt 21,000 -- Equity issued related to employee stock plans 66 249 Purchase of treasury shares (262) -- Common stock cancelled (1,615) (145) Dividends on preferred stock (1,111) (1,398) ------- -------- Cash provided (used) by financing activities 16,841 (1,294) ------- -------- Net increase (decrease) in cash and cash equivalents 1,034 21,326 Cash and cash equivalents: Balance, beginning of period 6,300 15,597 ------- -------- Balance, end of period $ 7,334 $ 36,923 ======= ======== The accompanying notes are an integral part of these financial statements CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 1999 1. Basis of Presentation The financial information presented as of any date other than December 31, has been prepared from the books and records without audit. Financial information as of December 31, has been derived from the audited financial statements of the Company, but does not include all disclosures required by generally accepted accounting principles. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary for the fair presentation of the financial information for the period indicated, have been included. For further information regarding the Company's accounting policies, refer to the Consolidated Financial Statements and related notes for the year ended December 31, 1998 included in the Company's Annual Report on Form 10-K dated March 29, 1999. 2. 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. 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 quarter. Diluted earnings per common share for 1998 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 and the effect of the convertible preferred stock (if dilutive). In the 1999 earnings per share computations, all stock 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 calculation due to their antidilutive effect on diluted income or loss per share. A reconciliation of the basic and diluted earnings per share computation is as follows (in thousands, except per share amounts): Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 ------ ------ ------ ------ (a) Net income (loss) available for common shares $ (330) $ 48 $ (689) $ 556 (b) Weighted average shares outstanding 8,447 8,028 8,462 8,021 (c) Dilutive impact of stock options -- 219 -- 212 (d) Total diluted shares 8,447 8,247 8,462 8,233 Stock options excluded as antidilutive 34 -- 39 -- Basic earnings (loss) per share (a/b) $(0.04) $ 0.01 $(0.08) $ 0.07 Diluted earnings (loss) per share (a/d) $(0.04) $ 0.01 $(0.08) $ 0.07 3. Hedging Contracts The Company periodically uses derivative financial instruments to manage oil and gas price risks. 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 and are reported as a component of oil and gas revenues. Gains or losses attributable to the termination of a swap contract are deferred and recognized in revenue when the oil and gas is sold. Approximately $730,000 and $763,000 was recognized as additional oil and gas revenue in the first six months of 1999 and 1998, respectively. As of June 30, 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 450,000 Mcf per month through November 1999 at (on average) a ceiling price of $2.35 and floor price of $2.02. In addition, the Company had open oil collar contracts averaging 25,000 barrels per month at (on average) a ceiling of $16.22 and a floor of $13.85 from April 1999 through December 1999. Also at June 30, 1999 the Company had open forward natural gas swap contracts of 200,000 Mcf per month from July 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 July 1999 through September 1999. 4. Preferred Stock During the first quarter of 1999 certain preferred stockholders through private transactions, agreed to convert 210,350 shares of Preferred Stock into 502,632 shares of the Company's Common Stock. Any noncash premium negotiated in excess of the conversion rate was recorded as additional preferred stock dividends and excluded from the Consolidated Statements of Cash Flows. 5. Senior Subordinated Notes On July 14, 1999 the Company issued $40 million of 10.25% Senior Subordinated Notes due 2004. Interest is payable quarterly beginning September 15, 1999. The net proceeds to the Company, after costs of the transaction, were used to repay the outstanding balance on the Credit Facility. 6. Deferred Revenue on Sale of Production Payment Interest In June 1999, the Company acquired a working interest in the Mobile Block 864 Area in which the Company already owned an interest. Concurrent with this acquisition, the seller received a volumetric production payment, valued at approximately $14.8 million, from production attributable to a portion of the Company's interest in the area over a three and a quarter year period. The Company deferred the revenue associated with the sale of this production payment interest because a substantial obligation for future performance existed. Under the terms of the sale, the Company was obligated to deliver the production volumes free and clear of royalties, lease operating expenses, production taxes and all capital costs. The production payment was recorded at the present value of the volumetric production committed to the seller at market value and, beginning in June 1999, is amortized to oil and gas sales on the units-of-production method as associated hydrocarbons are delivered. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Forward Looking Statements This report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this report regarding the Company's financial position, adequacy of resources, estimated reserve quantities, business strategies, plans, objectives and expectations for future operations and covenant compliance, are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to have been correct. Important factors that could cause actual results to differ materially from the Company's expectations ("Cautionary Statements") are disclosed below, in the section "Risk Factors" included in the Company's Form 10-K, elsewhere in this report and from time to time in other filings made by the Company with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified by the Cautionary Statements. General The Company's revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas and its ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. The Company's ability to maintain or increase its borrowing capacity and to obtain additional capital on attractive terms is also influenced by oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulations, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternate fuel sources. Any substantial and extended decline in the price of oil or gas would have an adverse effect on the Company's carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. The Company uses derivative financial instruments for price protection purposes on a limited amount of its future production and does not use them for trading purposes. The following discussion is intended to assist in an understanding of the Company's historical financial position and results of operations. The Company's historical financial statements and notes thereto included elsewhere in this quarterly report contain detailed information that should be referred to in conjunction with the following discussion. Liquidity and Capital Resources The Company's primary sources of capital are its cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Net cash and cash equivalents increased during the six months ending June 30, 1999 by $1.0 million. Net cash flow from operations before working capital changes for the period totaled $9.4 million. Net capital expenditures for the period totaled $25.1 million. These funds were primarily expended in drilling and completion of six wells and the completion of three additional wells. Increases in cash flows from financing activities during the six-month period included $21.0 million borrowed against the credit facility. Decreases for the same period included a $1.2 million reduction in accounts payable and accrued liabilities to be refinanced, $1.6 million related to the surrender and cancellation of common stock in satisfaction of payroll taxes related to performance share awards previously issued pursuant to the Company's Stock Incentive Plans and $1.1 million was paid to the preferred stockholders as dividends. On July 15, 1999, the Company announced its offering of $40 million Senior Subordinated Notes due 2004 at a yield of 10.25 percent. The net proceeds from the offering (approximately $38.4 million), together with cash flows and borrowings under its credit facility, will be used to fund the Company's remaining 1999 capital expenditure budget and a portion of its 2000 capital expenditure budget. Pending the use of the net proceeds, the Company repaid amounts under its credit facility, which may be reborrowed at a later date. For the balance of the year, the Company will continue evaluating property acquisitions and drilling opportunities. The Company's current total capital expenditure budget for 1999 is $66.8 million (which includes a $14.8 million non-cash production payment). The remaining capital expenditure budget for 1999 is approximately $27 million. Approximately $15 million is associated with the drilling of six exploratory wells to evaluate acreage in the Company's prospect inventory. The balance of the budget amount is allocated to completion costs for successful wells and potential lease acquisitions. The capital budget will be financed with available cash, projected cash flow from operations and unused capacity under the Company's credit facility. Disclosure About Market Risks The Company's revenues are derived from the sale of its crude oil and natural gas production. In recent months, the prices for oil and gas have increased; however, they remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to hedge oil and gas price risks for the production volumes to which the hedge relates. The hedges reduce the Company's exposure on the hedged volumes to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices on the hedged volumes. The Company also enters into price "collars" to reduce the risk of changes in oil and gas prices. Under these arrangements, no payments are due by either party so long as the market price is above the floor price 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 the Company and if the price is above the ceiling, the counter-party receives the difference. We enter into these various agreements to reduce the effects of volatile oil and gas prices and do not enter into hedge transactions for speculative purposes. See Note 3 to the Consolidated Financial Statements for a description of the Company's hedged position at June 30, 1999. Approximately $730,000 related to hedging was recognized as additional oil and gas revenue in the first six months of 1999. There have been no significant changes in market risks faced by the Company since the end of 1998. Year 2000 Compliance There have not been any significant developments nor significant additional risks identified since the end of 1998. The Company continues to focus efforts on identifying and solving the many threats to its business posed by the Year 2000 issue. These risks are generally divided into three areas, (1) failure of our financial and administrative systems, (2) failure of the embedded systems which control our automated production facilities and (3) failure of our suppliers and purchasers to correct their Year 2000 problems. The Company believes that its financial accounting software and the embedded systems affecting its automated production facilities are in compliance. The Company continues to correspond with our suppliers and purchasers to access compliance. Since we are unable to independently verify that they are taking appropriate steps to remedy problems, no assurances can be made that the Company may not encounter adverse effects caused by the Year 2000 problems. Although the Company does not separately account for its internal costs incurred for its Year 2000 compliance efforts, consisting mainly of payroll and related benefits for our information systems personnel, we are still projecting the compliance costs to be less than $200,000. Results of Operations The following table sets forth certain unaudited operating information with respect to the Company's oil and gas operations for the periods indicated. Three Months Six Months Ended June 30, Ended June 30, 1999 1998 1999 1998 ----- ----- ----- ----- Production volumes: Oil (MBbls) 86 82 176 193 Gas (MMcf) 3,474 3,640 6,843 7,676 Total (MMcfe) 3,989 4,129 7,898 8,835 Average sales price: (a) Oil (Bbl) $12.46 $11.98 $11.96 $13.06 Gas (Mcf) 2.16 2.28 2.11 2.32 Total (Mcfe) 2.15 2.25 2.09 2.30 Average costs (per Mcfe): Lease operating (excluding severance taxes) $ 0.41 $ 0.46 $ 0.38 $ 0.39 Severance taxes 0.06 0.06 0.06 0.07 Depreciation, depletion and amortization 1.00 1.19 1.01 1.18 General and administrative (net of management fees) 0.35 0.30 0.31 0.31 _____ (a) Includes hedging gains and losses. Comparison of Results of Operations for the Three Months Ended June 30, 1999 and the Three Months Ended June 30, 1998. Oil and Gas Production and Revenues Total oil and gas revenues decreased 8% from $9.3 million in 1998 to $8.6 million. When compared to the same period last year, oil production and prices were higher while gas production and prices were lower. Oil production during the second quarter of 1999 totaled 86,000 barrels and generated $1.1 million in revenues compared to 82,000 barrels and $1.0 million in revenues for the same period in 1998. Second quarter average daily production increased from 896 barrels per day in 1998 to 942 barrels per day in 1999. When the second quarter of 1999 production is compared to the same period in 1998, the increases from Main Pass 26 and Eugene Island 335 totaling 28,000 barrels is partially offset by the 17,000 barrel loss from Black Bay, which was sold in May 1998. Gas production during the second quarter of 1999 totaled 3.5 billion cubic feet and generated $7.5 million in revenues compared to 3.6 billion cubic feet and $8.3 million in revenues during the same period in 1998. The average sales price for the second quarter of 1999 averaged $2.16 per thousand cubic feet compared to $2.28 per thousand cubic feet at this time last year. When compared to the same quarter last year, the Company has added gas production from new discoveries at Main Pass 26 and Eugene Island 335 but has experienced reduced production from several Shallow Miocene wells which normally have a steep decline curve. Except for the increase at Main Pass 31, which was the result of a recompletion, other properties continue to experience normal and expected declines. The following table summarizes oil and gas production from the Company's major producing properties for the comparable periods. Oil Production Gas Production (Barrels) (Mcf) Three Months Ended Three Months Ended June 30, June 30, 1999 1998 1999 1998 ------- ------- --------- --------- Mobile Block 864 Area -- -- 1,290,000 1,390,000 Chandeleur Block 40 -- -- 207,000 682,000 Main Pass 163 Area -- -- 398,000 531,000 Main Pass 26 18,000 -- 342,000 -- Eugene Island 335 10,000 -- 316,000 -- Main Pass 31 11,000 11,000 429,000 304,000 Main Pass 164/165 -- -- 133,000 305,000 North Dauphin Island Field -- -- 121,000 180,000 Black Bay -- 17,000 -- -- Escambia Mineral properties 34,000 37,000 60,000 61,000 Other properties 13,000 17,000 178,000 187,000 ------- ------- --------- --------- Total 86,000 82,000 3,474,000 3,640,000 ======= ======= ========= ========= Lease Operating Expenses Lease operating expenses, including severance taxes, for the three-month period ending June 30, 1999 were $1.9 million compared to $2.1 million for the same period in 1998. This reduction is attributable to the sale of Black Bay in May 1998. Depreciation, Depletion and Amortization Depreciation, depletion and amortization for the three months ending June 30, 1999 and 1998 was $4.0 million and $4.9 million, respectively, reflecting the overall decrease in production. During the three months ended June 30, 1999 and 1998, the rate on a per unit basis was $1.00 and $1.19, respectively. The reduction in the rate was a result of the ceiling test writedown in December 1998. General and Administrative General and administrative expense for the three months ended June 30, 1999 was $1.4 million compared to $1.2 million for the three months ended June 30, 1998. This expense increase is generally attributable to severance benefits related to personnel reductions effective June 1, 1999 and reduced overhead recoveries through management fees and operating fees from Black Bay, which was sold in May 1998. Interest Expense Interest expense increased from $332,000 during the three months ended June 30, 1998 to $1.4 million during the three months ended June 30, 1999 reflecting the increase in the Company's long-term debt. The Company capitalizes a portion of the total interest charges as additional property costs associated with its drilling and exploration activities. Income Taxes Income taxes were provided at the expected statutory rate of 34% of net income. Comparison of Results of Operations for the Six Months Ended June 30, 1999 and the Six Months Ended June 30, 1998. Oil and Gas Production and Revenues For the six months ended June 30, 1999, total oil and gas revenues decreased by $3.8 million, or 19%, to $16.5 million when compared to $20.3 million for the same period in 1998. When compared to the same period last year, both oil and gas production and prices declined. For the six months ending June 30, 1999, oil production and oil revenues decreased to 176,000 barrels and $2.1 million, respectively. For the comparable period in 1998, oil production was 193,000 barrels while revenues totaled $2.5 million. Oil prices during the first six months of 1999 averaged $11.96, compared to $13.06 for the same period in 1998. When the production in the first six months in 1999 is compared to the same period in 1998, the increases from new discoveries at Main Pass 26 and Eugene Island 335 totaling 49,000 barrels was offset by the 57,000 barrel loss from Black Bay, which was sold in May 1998. A normal decline was experienced at the Escambia Mineral property. Natural gas production and revenue for the six-month period ending June 30, 1999 were 6.8 billion cubic feet and $14.4 million, respectively, decreasing from 7.7 billion cubic feet and gas revenues of $17.8 million in the first six months of 1998. The average sales price for natural gas in the first six months in 1999 was $2.11 per thousand cubic feet, a $0.21 per thousand cubic feet decrease over the same period in 1998. When compared to the same six- month period last year, the Company added gas production from new discoveries at Main Pass 26 and Eugene Island 335 but has experienced reduced production from several Shallow Miocene wells which normally have a steep decline curve. Except for the increase at Main Pass 31, which is the result of a recompletion, other properties continue to experience normal and expected declines. The following table summarizes oil and gas production from the Company's major producing properties for the comparable periods. Oil Production Gas Production (Barrels) (Mcf) Six Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 ------- ------- --------- --------- Mobile Block 864 Area -- -- 2,553,000 2,904,000 Chandeleur Block 40 -- -- 509,000 1,461,000 Main Pass 163 Area -- -- 727,000 1,190,000 Main Pass 26 35,000 -- 578,000 -- Eugene Island 335 14,000 -- 505,000 -- Main Pass 31 27,000 27,000 907,000 648,000 Main Pass 164/165 -- -- 332,000 616,000 North Dauphin Island Field -- -- 263,000 403,000 Black Bay -- 57,000 -- -- Escambia Mineral properties 71,000 80,000 127,000 135,000 Other properties 29,000 29,000 342,000 319,000 ------- ------- --------- --------- Total 176,000 193,000 6,843,000 7,676,000 ======= ======= ========= ========= Lease Operating Expenses Lease operating expenses, excluding severance taxes, for the first half of 1999 decreased 14% to $3.0 million from $3.5 million for the 1998 comparable period. This decrease is primarily the result of the sale of Black Bay in May 1998. Severance taxes were $0.5 million for the 1999 period and compares to $0.6 million for the same six-month period in 1998. Depreciation, Depletion and Amortization Depreciation, depletion and amortization for the first six months of 1999 was $8.0 million, or $1.01 per thousand cubic feet equivalent. For the same period in 1998, the total was $10.5 million and $1.18 per thousand cubic feet equivalent. This decline is primarily a result of lower production volumes in the period and a reduction in the rate as a result of the ceiling test writedown in December 1998. General and Administrative During the first six months of 1999, general and administrative expenses decreased by 11% to $2.4 million when compared to $2.7 million for the six-month period in 1998. While expenses associated with personnel reductions were incurred during the first six months of 1999, there were no expenses associated with bonuses under the incentive compensation plan and amortization of expenses associated with the vesting of performance shares which were incurred during the first half of 1998. Interest Expense Interest expense during the first half of 1999 was $2.5 million compared to $1.0 million for the first half of 1998 as a result of the increase in the Company's long-term debt. The Company capitalizes a portion of the total interest charges as additional property costs associated with its drilling and exploration activities. Income Taxes Income taxes were provided at the expected statutory rate of 34% of net income. CALLON PETROLEUM COMPANY PART II. OTHER INFORMATION Item 4. Submission of Matters to a Vote of Security Holders. The Company's annual meeting was held on April 29, 1999, at which three Class II directors were elected and the appointment of Arthur Andersen LLP as the Company's independent public accountants for the year ending December 31,1999 was ratified. The nominees for director were Messrs. John S. Callon, B. F. Weatherly and Leif Dons. Mr. Callon received 7,444,273 votes for, 17,251 votes against or withheld and no votes abstained. Mr. Weatherly received 7,445,791 votes for, 15,733 votes against or withheld and no votes abstained. Mr. Dons received 7,445,644 votes for, 15,880 votes against or withheld and no votes abstained. The ratification of Arthur Andersen LLP received 7,447,820 votes for, 6,713 votes against or withheld and 6,991 votes abstained. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 2. Plan of acquisition, reorganization, arrangement, liquidation or succession* 3. Articles of Incorporation and By-Laws 3.1 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) 3.2 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) 3.3 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. Instruments defining the rights of security holders, including indentures 4.1 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) 4.2 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) 4.3 Designation for Convertible Exchangeable Preferred Stock, Series A (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) 4.4 Indenture for Convertible Debentures (incorporated by reference from Exhibit 4.4 of the Company's Registration Statement on Form S-1/A, filed November 13, 1995, Reg. No. 33-96700) 4.5 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) 4.6 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) 4.7 Form of Note Indenture (incorporated by reference from Exhibit 4.10 of the Company's Registration Statement on Form S-2/A, filed June 25, 1999, Reg. No. 333-80579) 10. Material contracts 10.1 Purchase and Sale Agreement between Callon Petroleum Operating Company and Murphy Exploration Company, dated May 26, 1999 (incorporated by reference from Exhibit 10.11 on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 11. Statement re computation of per share earnings 11.1 Computation of Per Share Earnings 15. Letter re unaudited interim financial information* 18. Letter re change in accounting principles* 19. Report furnished to security holders* 22. Published report regarding matters submitted to vote of security holders* 23. Consents of experts and counsel* 24. Power of attorney* 27. Financial Data Schedule 99. Additional exhibits* (b) Reports on Form 8-K None - ------------- *Inapplicable to this filing SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CALLON PETROLEUM COMPANY Date August 11, 1999 By /s/ John S. Weatherly ------------------------------ John S. Weatherly, Senior Vice President and Chief Financial Officer (on behalf of the registrant and as the principal financial officer) Exhibit 11.1 CALLON PETROLEUM COMPANY COMPUTATION OF PER SHARE EARNINGS (In thousands, except per share data) Three Months Ended Six Months Ended June 30, June 30, ---------------- ----------------- 1999 1998 1999 1998 ------ ------ ------ ------ Net income $ 225 $ 747 $ 697 $1,954 Preferred stock dividends 555 699 1,386 1,398 ------ ------ ------ ------ Net income (loss) available to common shares $ (330) $ 48 $ (689) $ 556 ====== ====== ======= ====== Net income (loss) per common share: Basic $(0.04) $ 0.01 $(0.08) $ 0.07 Diluted $(0.04) $ 0.01 $(0.08) $ 0.07 Shares used in computing net income (loss) per common share: Basic 8,447 8,028 8,462 8,021 Dilutive impact of stock options -- 219 -- 212 ------ ------ ------ ------ Diluted 8,447 8,247 8,462 8,233 ====== ====== ====== ====== Stock options excluded as antidilutive 34 -- 39 -- ====== ====== ====== ====== Note: 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 quarter. Diluted earnings per common share for 1998 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 and the effect of the convertible preferred stock (if dilutive). In the 1999 earnings per share computations, all stock 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 calculation due to their antidilutive effect on diluted income or loss per share.