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 SEPTEMBER 30, 2000 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 November 3, 2000, there were 13,327,675 shares of the Registrant's Common Stock, par value $0.01 per share, outstanding. CALLON PETROLEUM COMPANY TABLE OF CONTENTS
PAGE NO. -------- PART I. FINANCIAL INFORMATION Consolidated Balance Sheets as of September 30, 2000 and December 31, 1999 3 Consolidated Statements of Operations for Each of the Three and Nine Months in the Periods Ended September 30, 2000 and September 30, 1999 4 Consolidated Statements of Cash Flows for Each of the Nine Months in the Periods Ended September 30, 2000 and September 30, 1999 5 Notes to Consolidated Financial Statements 6 Management's Discussion and Analysis of Financial Condition and Results of Operations 9 Quantitative and Qualitative Disclosures about Market Risk 16 PART II. OTHER INFORMATION 17
2 CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31, 2000 1999 ------------- ------------- (UNAUDITED) ASSETS Current assets: Cash and cash equivalents $ 10,268 $ 34,671 Accounts receivable 8,347 5,362 Other current assets 1,372 1,004 ------------- ------------- Total current assets 19,987 41,037 ------------- ------------- Oil and gas properties, full cost accounting method: Evaluated properties 558,166 511,689 Less accumulated depreciation, depletion and amortization (374,401) (361,758) ------------- ------------- 183,765 149,931 Unevaluated properties excluded from amortization 61,517 44,434 ------------- ------------- Total oil and gas properties 245,282 194,365 ------------- ------------- Pipeline and other facilities 5,618 5,860 Other property and equipment, net 1,722 1,450 Deferred tax asset 10,607 14,995 Long-term gas balancing receivable 404 243 Other assets, net 1,459 1,927 ------------- ------------- Total assets $ 285,079 $ 259,877 ============= ============= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $ 11,852 $ 16,786 Undistributed oil and gas revenues 1,762 2,082 Accrued net profits payable 1,847 1,676 ------------- ------------- Total current liabilities 15,461 20,544 ------------- ------------- Long-term debt 126,250 100,250 Deferred revenue on sale of production payment interest 8,454 12,080 Accrued retirement benefits 1,941 2,107 Long-term gas balancing payable 522 516 ------------- ------------- Total liabilities 152,628 135,497 ------------- ------------- Stockholders' equity: Preferred stock, $0.01 par value, 2,500,000 shares authorized; 1,006,461 shares of Convertible Exchangeable Preferred Stock, Series A, issued and outstanding at September 30, 2000 and 1,045,461 shares outstanding at December 31, 1999 with a liquidation preference of $25,161,525 at September 30, 2000 10 11 Common stock, $0.01 par value, 20,000,000 shares authorized; 12,373,688 and 12,239,238 outstanding at September 30, 2000 and at December 31, 1999, respectively 124 122 Treasury stock (99,078 shares at cost) (1,183) (1,183) Capital in excess of par value 150,567 149,425 Accumulated deficit (17,067) (23,995) ------------- ------------- Total stockholders' equity 132,451 124,380 ------------- ------------- Total liabilities and stockholders' equity $ 285,079 $ 259,877 ============= =============
The accompanying notes are an integral part of these financial statements. 3 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------------- ----------------------------- 2000 1999 2000 1999 ------------- ------------- ------------- ------------- Revenues: Oil and gas sales $ 15,960 $ 10,240 $ 39,720 $ 26,777 Interest and other 462 344 1,536 1,212 ------------- ------------- ------------- ------------- Total revenues 16,422 10,584 41,256 27,989 ------------- ------------- ------------- ------------- Costs and expenses: Lease operating expenses 2,295 1,803 6,449 5,289 Depreciation, depletion and amortization 4,568 4,284 12,885 12,236 General and administrative 992 999 2,964 3,439 Interest 2,103 1,900 5,949 4,371 ------------- ------------- ------------- ------------- Total costs and expenses 9,958 8,986 28,247 25,335 ------------- ------------- ------------- ------------- Income from operations 6,464 1,598 13,009 2,654 Income tax expense 2,197 543 4,423 902 ------------- ------------- ------------- ------------- Net income 4,267 1,055 8,586 1,752 Preferred stock dividends 553 555 1,658 1,942 ------------- ------------- ------------- ------------- Net income (loss) available to common shares $ 3,714 $ 500 $ 6,928 $ (190) ============= ============= ============= ============= Net income (loss) per common share: Basic $ 0.30 $ 0.06 $ 0.57 $ (0.02) ============= ============= ============= ============= Diluted $ 0.29 $ 0.06 $ 0.56 $ (0.02) ============= ============= ============= ============= Shares used in computing net income (loss) per common share: Basic 12,228 8,459 12,185 8,465 ============= ============= ============= ============= Diluted 14,968 8,567 12,476 8,465 ============= ============= ============= =============
The accompanying notes are an integral part of these financial statements. 4 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (IN THOUSANDS)
NINE MONTHS ENDED -------------------------------- SEPTEMBER 30, SEPTEMBER 30, 2000 1999 -------------- -------------- Cash flows from operating activities: Net income $ 8,586 $ 1,752 Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization 13,207 12,612 Amortization of deferred costs 704 464 Amortization of deferred production payment revenue (3,626) (1,470) Deferred income tax expense 4,423 902 Noncash charge related to compensation plans 907 206 Changes in current assets and liabilities: Accounts receivable (2,985) (2,391) Other current assets (368) (281) Current liabilities (1,527) (199) Change in gas balancing receivable (161) (17) Change in gas balancing payable 6 47 Change in other long-term liabilities (166) (162) Change in other assets, net (271) (1,535) -------------- -------------- Cash provided (used) by operating activities 18,729 9,928 -------------- -------------- Cash flows from investing activities: Capital expenditures (68,531) (33,870) Cash proceeds from sale of mineral interests 821 -- -------------- -------------- Cash provided (used) by investing activities (67,710) (33,870) -------------- -------------- Cash flows from financing activities: Payment on debt -- (35,500) Increase in debt 26,000 64,500 Equity issued related to employee stock plans 236 121 Purchase of treasury shares -- (262) Common stock cancelled -- (1,615) Cash dividends on preferred stock (1,658) (1,667) -------------- -------------- Cash provided (used) by financing activities 24,578 25,577 -------------- -------------- Net increase (decrease) in cash and cash equivalents (24,403) 1,635 Cash and cash equivalents: Balance, beginning of period 34,671 6,300 -------------- -------------- Balance, end of period $ 10,268 $ 7,935 ============== ==============
The accompanying notes are an integral part of these financial statements. 5 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2000 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, 1999 included in the Company's Annual Report on Form 10-K dated March 23, 2000. 2. PER SHARE AMOUNTS 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 or loss per common share 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). The earnings per share computation for the nine-month period ended September 30, 1999 excluded all stock options from the computation of diluted loss per share because they were antidilutive. The conversion of the preferred stock was not included in the calculation, except for the quarter ended September 30, 2000, 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 NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------------- ----------------------------- 2000 1999 2000 1999 ------------- ------------- ------------- ------------- (a) Net income (loss) available for common stock $ 3,714 $ 500 $ 6,928 $ (190) Preferred dividends assuming conversion of preferred stock (if dilutive) $ 553 $ -- $ -- $ -- (b) Income available for common stock assuming conversion of preferred stock (if dilutive) $ 4,267 $ 500 $ 6,928 $ (190) (c) Weighted average shares outstanding 12,228 8,459 12,185 8,465 Dilutive impact of stock options 414 108 291 -- Convertible preferred stock (if dilutive) 2,236 -- -- -- (d) Total diluted shares 14,968 8,567 12,476 $8,465 Basic income (loss) per share (a/c) $ 0.30 $ 0.06 $ 0.57 $(0.02) Diluted income (loss) per share (b/d) $ 0.29 $ 0.06 $ 0.56 $(0.02)
6 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 $2.8 million and $0.9 million related to these financial instruments were recognized as a reduction of oil and gas revenue in the first nine months of 2000 and 1999, respectively. As of September 30, 2000, the Company had open natural gas collar contracts with a third party whereby minimum floor prices and maximum ceiling prices are contracted and applied to related contract volumes. This agreement is for gas volumes of 200,000 Mcf for the month of October 2000 at a ceiling price of $2.75 and floor price of $2.50. The Company had no open crude oil contracts at September 30, 2000. 4. STOCKHOLDERS' EQUITY During the first quarter of 1999, certain preferred stockholders, through private transactions, converted 210,350 shares of Preferred Stock into 502,632 shares of the Company's Common Stock. In addition, 5,000 shares of Preferred Stock were converted during the first quarter of 2000 and 34,000 shares of Preferred Stock were converted in the third quarter of 2000 to the Company's Common Stock at the conversion rate. In October 2000, preferred shareholders, through private transactions, converted 405,600 shares of the Company's Preferred Stock into 947,462 shares of the Company's Common Stock. Any non-cash premiums negotiated in excess of the conversion rate were recorded as additional preferred stock dividends and excluded from the Consolidated Statements of Cash Flows. The Company granted 533,000 stock options to employees on March 23, 2000 and 120,000 stock options to directors on July 25, 2000 at $10.50 per share. The March 23, 2000 grant was subject to shareholder approval of an amendment to the 1996 Stock Incentive Plan. The amendment, which was approved on May 9, 2000 at the Annual Meeting of Shareholders, increased the number of shares reserved for issuance under the 1996 plan. The excess of the market price over the exercise price on the approval date of the amendment is amortized over the three-year vesting period of the options. 5. STOCKHOLDER RIGHTS PLAN The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the Company's stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers, squeeze-outs, open market accumulations, and other abusive tactics to gain control without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, the Company declared a dividend of one right ("Right") on each share of the Company's Common Stock. Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B 7 Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a share. The Rights are not currently exercisable and will become exercisable only in the event a person or group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15 percent or more (one existing stockholder was granted an exception for up to 21 percent) of the Company's Common Stock. After the Rights become exercisable, each Right will also entitle its holder to purchase a number of common shares of the Company having a market value of twice the exercise price. The dividend distribution was made to stockholders of record at the close of business on April 10, 2000. The Rights will expire on March 30, 2010. 6. LONG-TERM DEBT The existing Credit Facility matured at the end of October 2000. The Company negotiated a new Credit Facility on October 30, 2000 whereby the Company secured more favorable terms, including maturity and the size of the borrowing base than it currently had through its existing Credit Facility. The maturity date of the new Credit Facility is October 31, 2001. The amount outstanding under the Credit Facility at September 30, 2000, approximately $26.1 million, has been reclassified as long-term on the balance sheet to reflect the maturity date of the new Credit Facility. The new Credit Facility is for $75 million with an initial borrowing base of $50 million. The Company completed the sale of its $32 million Senior Subordinated Notes due 2005, which were priced to yield 11 percent on October 26, 2000 and has granted the underwriters the right to purchase up to an additional $4.8 million aggregate principal amount of notes to cover over-allotments. The Company netted approximately $30.6 million from the offering after deducting the underwriters' discount and offering expenses. Approximately $20.8 million of the net proceeds from the offering were used to purchase the Company's outstanding 10% Senior Subordinated Notes due 2001 in conjunction with a tender offer. In addition, the Company has initiated a redemption of all of its 10% Senior Subordinated Notes due 2001 not tendered in the offer. 7. NEW ACCOUNTING STANDARDS In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards that require every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If those criteria are met, the instruments are treated as hedges under SFAS No. 133 creating volatility in equity through changes in other comprehensive income due to the marking to market of the hedging contracts. We will adopt SFAS No. 133 on January 1, 2001. We currently have no derivative instruments or hedging contracts, which extend past December 31, 2000, other than the volumetric production payment, which qualifies for the normal sales exception under SFAS 133. However, we may enter into new hedging arrangements prior to December 31, 2000. Depending upon the nature of any future hedging arrangements, the adoption of SFAS 133 may create volatility in our results of operations and/or stockholders' equity. 8 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 contains 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 during the nine months ending September 30, 2000 decreased by $24.4 million and net cash flows from operations before working capital changes totaled $24.2 million. Net capital expenditures from the cash flow statement for the period 9 totaled $67.7 million. These funds were expended in exploration, drilling and completion of oil and gas properties. At September 30, 2000, the Company had working capital of $4.5 million. The existing Credit Facility matured at the end of October 2000. The Company negotiated a new Credit Facility on October 30, 2000 whereby the Company secured more favorable terms, including maturity and the size of the borrowing base than it currently had through its existing Credit Facility. The maturity date of the new Credit Facility is October 31, 2001. The amount outstanding under the Credit Facility at September 30, 2000 has been reclassified as long-term on the balance sheet to reflect the maturity date of the new Credit Facility. The new Credit Facility is for $75 million with an initial borrowing base of $50 million. The Company completed the sale of its $32 million Senior Subordinated Notes due 2005, which were priced to yield 11 percent on October 26, 2000 and has granted the underwriters the right to purchase up to an additional $4.8 million aggregate principal amount of notes to cover over-allotments. The Company netted approximately $30.6 million from the offering after deducting the underwriters' discount and offering expenses. Approximately $20.8 million of the net proceeds from the offering were used to purchase the Company's outstanding 10% Senior Subordinated Notes due 2001 in conjunction with a tender offer. In addition, the Company has initiated a redemption of all of its 10% Senior Subordinated Notes due 2001 not tendered in the offer. CAPITAL EXPENDITURES Capital expenditures for exploration and development costs related to oil and gas properties totaled approximately $64.1 million in the first nine months of 2000. The Company incurred approximately $25.5 million in the Gulf of Mexico Shelf area primarily in the development of the 1999 discoveries at South Marsh Island 261 and East Cameron 275. Included in these expenditures as exploration costs, were approximately $7.3 million related to three unsuccessful Gulf of Mexico Shelf prospects evaluated during the first six months of 2000. The Gulf of Mexico Deepwater area expenditures accounted for the remainder of the total capital expended, with two unsuccessful exploration projects totaling $7.1 million and the balance for additional delineation drilling at the Company's Medusa discovery and the drilling of a test well at the Entrada prospect in the first half of 2000. The Company also began drilling operation on its Cumberland prospect in September 2000 and announced in early November 2000 that the well was unsuccessful. Interest and general and administrative costs allocable directly to exploration and development projects were approximately $8.1 million for the first nine months of 2000. The Entrada prospect test well, located on Garden Banks Block 782, discussed above reached total depth in April 2000. Several sidetrack wells were then drilled; however, future delineation drilling and testing will be required to quantify the impact the Entrada discovery will have on the Company. As evaluation is not complete, costs incurred related to Entrada are included in unevaluated properties as of September 30, 2000. As a result of the recent successes by the Company in the Gulf of Mexico Deepwater area, the Company is faced with increased costs to develop these significant proved undeveloped reserves. Substantially all of the future development costs will be incurred in 2001 and beyond. The Company is currently evaluating various financing alternatives to address these issues. While management believes there are a number of financing sources available to the Company, no assurances can be made that the Company will be able to fund these development costs. 10 For the remainder of the year, the Company will continue evaluating property acquisitions and drilling opportunities. The Company has budgeted up to $13.1 million in capital expenditures for the remainder of 2000. The major portion of the capital expenditure budget will be used to drill development and exploratory wells to increase total proved reserves and increase production for the Company. The Company currently estimates that its budget for the remainder of 2000 can be financed with available cash, projected cash flow from operations and the Company's Credit Facility. 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 ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------- ------------------------------- 2000(a)(b) 1999(a)(b) 2000(a)(b) 1999(a)(b) ----------- ----------- ----------- ----------- Production volumes: Oil (MBbls) 56 81 186 257 Gas (MMcf) 3,950 3,996 10,956 10,839 Total production (MMcfe) 4,285 4,481 12,072 12,379 Average daily production (MMcfe) 46.6 48.7 44.1 45.3 Average sales price:(a) Oil (Bbls) $29.37 $12.27 $ 27.42 $ 12.06 Gas (Mcf) 3.63 2.31 3.16 2.18 Total (Mcfe) 3.72 2.29 3.29 2.16 Average costs (per Mcfe): Lease operating (excluding severance taxes) $ 0.49 $ 0.34 $ 0.48 $ 0.36 Severance taxes 0.05 0.06 0.06 0.06 Depreciation, depletion and amortization 1.05 0.96 1.05 0.99 General and administrative (net of management fees) 0.23 0.22 0.25 0.28
(a) Includes hedging gains and losses. (b) Includes volumes of 587 MMcf for the quarter ended September 30, 2000 and 1,747 MMcf for the nine months ended September 30, 2000 at an average price of $2.08 per Mcf associated with a volumetric production payment. Also includes volumes of 587 MMcf for the quarter ended September 30, 1999 and 708 MMcf for the nine months ended September 30, 1999 at the same average price. 11 COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000 AND THE THREE MONTHS ENDED SEPTEMBER 30, 1999. Oil and Gas Production and Revenues Total oil and gas revenues increased 57% from $10.2 million in the third quarter of 1999 to $16.0 million in the third quarter of 2000. Oil and gas prices were significantly higher when compared to the same period in 1999. Total production for the third quarter was less than anticipated due to down time at Mobile Block 864 Area (compressor repairs) and Main Pass 36 (downtime to recomplete a new production zone). East Cameron 275 was shut-in in mid September 2000 due to the outside-operated production facility (repairs and maintenance) being unavailable to process our production. Production from East Cameron 275 should resume in mid November 2000; however fourth quarter results will be impacted by this well being off production as well as downtime at Mobile Block 864 caused by the compressor repair. Gas production during the third quarter of 2000 totaled 4.0 billion cubic feet and generated $14.3 million in revenues compared to 4.0 billion cubic feet and $9.2 million in revenues during the same period in 1999. The average sales price for the third quarter of 2000 averaged $3.63 per thousand cubic feet compared to $2.31 per thousand cubic feet at this time last year. When compared to the same quarter last year, the Company's gas production remained stable as a result of new production at East Cameron 275, South Marsh Island 261, and Vermilion 130 which was offset by production declines in some of the Company's older producing properties and the depletion of Main Pass 31 and Main Pass 36. The production declines were expected and considered normal. Oil production during the third quarter of 2000 totaled 55,700 barrels and generated $1.6 million in revenues compared to 81,000 barrels and $1.0 million in revenues for the same period in 1999. Average oil prices received in the third quarter of 2000 were $29.37 compared to $12.27 in 1999. The strong oil prices received in the third quarter of 2000 offset the decrease in production, which was expected and considered normal. See the table below for variances by major producing property. 12 The following table summarizes oil and gas production from the Company's major producing properties for the comparable periods.
OIL PRODUCTION GAS PRODUCTION (BBLS) (MCF) ----------------------------- ----------------------------- THREE MONTHS ENDED THREE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, 2000 1999 2000 1999 ------------- ------------- ------------- ------------- Mobile Block 864 Area 0 0 1,202,600 1,465,000 Chandeleur Block 40 0 0 83,700 163,000 Main Pass 163 Area 0 0 294,200 477,000 Main Pass 164/165 0 0 37,200 0 North Dauphin Island 0 0 76,200 110,000 Eugene Island 335 3,900 6,000 170,900 326,000 Vermilion 130 0 0 127,100 0 Main Pass 26 4,400 7,000 53,400 146,000 Main Pass 31 0 5,000 0 175,000 Main Pass 36 300 10,000 6,000 302,000 High Island Block A-494 0 0 123,400 553,000 Escambia Minerals 24,400 38,000 38,800 63,000 East Cameron 275 4,000 0 424,700 0 South Marsh Island 261 3,500 0 1,199,000 0 Other properties 15,200 15,000 113,200 216,000 ------------- ------------- ------------- ------------- Total 55,700 81,000 3,950,400 3,996,000 ============= ============= ============= =============
Lease Operating Expenses Lease operating expenses, including severance taxes, for the three-month period ending September 30, 2000 were $2.3 million compared to $1.8 million for the same period in 1999 and reflect the increased costs related to new production. Production declines related to older properties that have relatively fixed operating costs also contributed to the higher per Mcf costs. Depreciation, Depletion and Amortization Depreciation, depletion and amortization for the three months ending September 30, 2000 and 1999 was $4.6 million and $4.3 million, respectively. A higher average rate in the third quarter of 2000 resulted in the increase. General and Administrative General and administrative expense remained constant at $1.0 million for the three months ended September 30, 2000 as compared to the quarter ended September 30, 1999. Interest Expense Interest expense increased from $1.9 million during the three months ended September 30, 1999 to $2.1 million during the three months ended September 30, 2000 reflecting the increase in the Company's long-term debt. 13 COMPARISON OF RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 AND THE NINE MONTHS ENDED SEPTEMBER 30, 1999. Oil and Gas Production and Revenues Total oil and gas revenues increased 48% from $26.8 million in the first nine months of 1999 to $39.7 million for the same period in 2000. Oil and gas prices were significantly higher when compared to 1999. Gas production during the first nine months of 2000 totaled 11.0 billion cubic feet and generated $34.8 million in revenues compared to 10.8 billion cubic feet and $23.7 million in revenues during the same period in 1999. The average sales price for the first nine months of 2000 averaged $3.16 per thousand cubic feet compared to $2.18 per thousand cubic feet for the first nine months of 1999. When compared to the same period last year, the Company's gas production remained stable as a result of new production at East Cameron 275, South Marsh Island 261, and Vermilion 130 which was offset by production declines in some of the Company's older producing properties and the depletion of Main Pass 31 and Main Pass 36. The production declines were expected and considered normal. Oil production during the first nine months of 2000 totaled 186,100 barrels and generated $5.1 million in revenues compared to 257,000 barrels and $3.1 million in revenues for the same period in 1999. Average oil prices received in the first nine months of 2000 were $27.42 compared to $12.06 in 1999. The strong oil prices received in the first nine months of 2000 partially offset the decrease in production, which was expected and considered normal. See the table below for variances by major producing property. The following table summarizes oil and gas production from the Company's major producing properties for the comparable periods.
OIL PRODUCTION GAS PRODUCTION (BBLS) (MCF) --------------------------- --------------------------- NINE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, 2000 1999 2000 1999 ------------ ------------ ------------ ------------ Mobile Block 864 Area 0 0 4,017,600 4,018,000 Chandeleur Block 40 0 0 277,600 672,000 Main Pass 163 Area 0 0 899,800 1,537,000 Main Pass 164/165 0 0 149,400 0 North Dauphin Island 0 0 235,300 373,000 Eugene Island 335 14,600 20,000 628,100 832,000 Vermilion 130 0 0 417,300 0 Main Pass 26 13,800 41,000 242,900 723,000 Main Pass 31 0 32,000 0 1,083,000 Main Pass 36 5,100 10,000 128,000 302,000 High Island Block A-494 0 0 571,900 553,000 Escambia Minerals 81,800 108,000 144,300 190,000 Kemah 3,200 0 193,700 0 East Cameron 275 15,000 0 1,064,700 0 South Marsh Island 261 3,500 0 1,622,200 0 Other properties 49,100 46,000 362,800 556,000 ------------ ------------ ------------ ------------ Total 186,100 257,000 10,955,600 10,839,000 ============ ============ ============ ============
14 Lease Operating Expenses Lease operating expenses, including severance taxes, for the nine-month period ending September 30, 2000 were $6.4 million compared to $5.3 million for the same period in 1999 and reflect the increased costs associated with expenses related to new production. Depreciation, Depletion and Amortization Depreciation, depletion and amortization for the nine months ending September 30, 2000 and 1999 was $12.9 million and $12.2 million, respectively. A higher average rate in 2000 resulted in the increase. General and Administrative General and administrative expense decreased from $3.4 million for the nine months ended September 30, 1999 to $3.0 million for the nine months ended September 30, 2000. This decrease is primarily the result of severance benefits paid in 1999 related to personnel reductions that were effective June 1, 1999. Interest Expense Interest expense increased from $4.4 million during the nine months ended September 30, 1999 to $5.9 million during the nine months ended September 30, 2000 reflecting the increase in the Company's long-term debt. 15 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 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 the 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 from the Company. The Company enters into these various agreements from time to time to reduce the effects of volatile oil and gas prices and does 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 September 30, 2000. Approximately $2.8 million related to hedging was recognized as a reduction in oil and gas revenue in the first nine months of 2000. There have been no significant changes in market risks faced by the Company since the end of 1999. In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards that require every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If those criteria are met, the instruments are treated as hedges under SFAS No. 133 creating volatility in equity through changes in other comprehensive income due to the marking to market of the hedging contracts. We will adopt SFAS No. 133 on January 1, 2001. We currently have no derivative instruments or hedging contracts, which extend past December 31, 2000, other than the volumetric production payment, which qualifies for the normal sales exception under SFAS 133. However, we may enter into new hedging arrangements prior to December 31, 2000. Depending upon the nature of any future hedging arrangements, the adoption of SFAS 133 may create volatility in our results of operations and/or stockholders' equity. 16 CALLON PETROLEUM COMPANY PART II. OTHER INFORMATION ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None. 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 period 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, 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) 17 4.4 Indenture for Convertible Debentures (incorporated by reference from Exhibit 4.4 of the Company's Registration Statement on Form S-1, 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, filed November 22, 1996, Reg. No. 333-15501) 4.6 Form of Note Indenture for the Company's 10% Senior Subordinated Notes due 2001 (incorporated by reference from Exhibit 4.6 of the Company's Registration Statement on Form S-1, filed November 22, 1996, Reg. No. 333-15501) 4.7 Form of Note Indenture for the Company's 10.25% Senior Subordinated Notes due 2004 (incorporated by reference from Exhibit 4.10 of the Company's Registration Statement on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 4.8 Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 4 of the Company's 8-K filed April 6, 2000) 4.9 Subordinated Indenture for the Company dated October 26, 2000 (incorporated by reference from Exhibit 4.1 of the Company's Current Report on Form 8-K dated October 24, 2000) 4.10 Supplemental Indenture for the Company's 11% Senior Subordinated Notes due 2005 (incorporated by reference from Exhibit 4.2 of the Company's Current Report on Form 8-K dated October 24, 2000) 10. Material contracts 10.1 Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by reference from Appendix I of the Company's Definitive Proxy Statement on Schedule 14A filed March 28, 2000) 10.2 Credit Agreement dated as of October 30, 2000 between the Company and First Union National Bank, as administrative agent for the lenders 11. Statement re computation of per share earnings* 15. Letter re unaudited interim financial information* 18 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 The Company filed an 8-K on September 28, 2000 regarding a press release describing the Tender Offer for Subordinated Notes due 2001 and an intention to sell additional Subordinated Notes due 2005. *Inapplicable to this filing 19 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: November 10, 2000 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) 20 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION - ------- ----------- 10.2 Credit Agreement dated as of October 30, 2000 between the Company and First Union National Bank, as administrative agent for the lenders 27 Financial Data Schedule