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, 2002 COMMISSION FILE NUMBER 001-14039
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 5, 2002, there were 13,472,538 shares of the Registrant's Common
Stock, par value $0.01 per share, outstanding.
CALLON PETROLEUM COMPANY
TABLE OF CONTENTS
<Table>
<Caption>
PAGE NO.
--------
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets as of June 30, 2002
and December 31, 2001 3
Consolidated Statements of Operations for Each of the
Three and Six Months in the Periods Ended June 30, 2002
and June 30, 2001 4
Consolidated Statements of Cash Flows for Each of the
Three and Six Months in the Periods Ended June 30, 2002 and
June 30, 2001 5
Notes to Consolidated Financial Statements 6
Management's Discussion and Analysis of
Financial Condition and Results of Operations 10
Quantitative and Qualitative Disclosures about Market Risk 15
PART II. OTHER INFORMATION 16
</Table>
2
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2002 2001
------------ ------------
ASSETS (UNAUDITED)
------
Current assets:
Cash and cash equivalents $ 14,880 $ 6,887
Accounts receivable 6,841 5,908
Other current assets 491 209
------------ ------------
Total current assets 22,212 13,004
------------ ------------
Oil and gas properties, full cost accounting method:
Evaluated properties 739,899 704,937
Less accumulated depreciation, depletion and amortization (411,285) (399,339)
------------ ------------
328,614 305,598
Unevaluated properties excluded from amortization 38,596 37,560
------------ ------------
Total oil and gas properties 367,210 343,158
------------ ------------
Pipeline and other facilities 903 5,364
Other property and equipment, net 2,220 2,455
Deferred tax asset 6,253 4,399
Other assets, net 3,291 3,715
------------ ------------
Total assets $ 402,089 $ 372,095
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 8,746 $ 9,985
Undistributed oil and gas revenues 1,101 1,131
Accrued net profits interest payable 1,336 1,501
Accounts payable and accrued liabilities to be refinanced -- 9,558
Current maturities of long-term debt 1,302 37,345
------------ ------------
Total current liabilities 12,485 59,520
------------ ------------
Long-term debt-excluding current maturities 237,162 157,366
Accounts payable and accrued liabilities to be refinanced 2,200 --
Capital leases 3,842 4,367
Deferred revenue on sale of production payment -- 2,406
Other long-term liabilities 1,125 1,212
------------ ------------
Total liabilities 256,814 224,871
------------ ------------
Stockholders' equity:
Preferred stock, $0.01 par value, 2,500,000 shares authorized; 600,861 shares of 6 6
Convertible Exchangeable Preferred Stock, Series A, issued and outstanding
with a liquidation preference of $15,021,525
Common stock, $0.01 par value, 20,000,000 shares authorized; 13,439,149 and
13,397,706 shares outstanding at June 30, 2002 and December 31, 2001 134 134
Treasury stock (99,078 shares at cost) (1,183) (1,183)
Unearned restricted stock compensation (915) --
Capital in excess of par value 158,654 155,608
Accumulated other comprehensive income 2,642 5,971
Retained earnings (deficit) (14,063) (13,312)
------------ ------------
Total stockholders' equity 145,275 147,224
------------ ------------
Total liabilities and stockholders' equity $ 402,089 $ 372,095
============ ============
</Table>
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)
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Revenues:
Oil and gas sales $ 15,304 $ 17,066 $ 26,358 $ 37,243
Loss on mark-to-market commodity
derivative contracts (382) -- (770) --
Interest and other 252 646 822 1,281
Gain on sale of pipeline 2,454 -- 2,454 --
Gain on sale of Enron derivatives 2,479 -- 2,479 --
----------- ----------- ----------- -----------
Total revenues 20,107 17,712 31,343 38,524
----------- ----------- ----------- -----------
Costs and expenses:
Lease operating expenses 2,805 3,052 5,369 5,725
Depreciation, depletion and amortization 6,489 5,154 12,077 10,051
General and administrative 1,299 1,579 2,438 2,702
Interest 5,913 2,613 11,633 5,234
----------- ----------- ----------- -----------
Total costs and expenses 16,506 12,398 31,517 23,712
----------- ----------- ----------- -----------
Income (loss) from operations 3,601 5,314 (174) 14,812
Income tax expense (benefit) 1,260 1,860 (61) 5,184
----------- ----------- ----------- -----------
Net income (loss) 2,341 3,454 (113) 9,628
Preferred stock dividends 319 319 638 638
----------- ----------- ----------- -----------
Net income (loss) available to common shares $ 2,022 $ 3,135 $ (751) $ 8,990
=========== =========== =========== ===========
Net income (loss) per common share:
Basic $ 0.15 $ 0.24 $ (0.06) $ 0.68
=========== =========== =========== ===========
Diluted $ 0.15 $ 0.23 $ (0.06) $ 0.65
=========== =========== =========== ===========
Shares used in computing net income (loss) per common share:
Basic 13,334 13,258 13,325 13,255
=========== =========== =========== ===========
Diluted 13,744 13,427 13,325 14,853
=========== =========== =========== ===========
</Table>
The accompanying notes are an integral part of these financial statements.
4
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
<Table>
<Caption>
SIX MONTHS ENDED
-----------------------------
JUNE 30, JUNE 30,
2002 2001
------------ ------------
Cash flows from operating activities:
Net income (loss) $ (113) $ 9,628
Adjustments to reconcile net income to cash provided by operating
activities:
Depreciation, depletion and amortization 12,420 10,341
Amortization of deferred costs 2,370 814
Non-cash derivative income (5,258) (446)
Mark-to-market commodity derivative contracts 770 --
Deferred income tax expense (benefit) (61) 5,184
Non-cash charge related to compensation plans 620 474
Gain on sale of pipeline (2,454) --
Changes in current assets and liabilities:
Accounts receivable (933) 1,320
Advance to operators -- (321)
Other current assets (87) (21)
Investment in put contracts (829) --
Current liabilities (1,529) (4,123)
Deferred production payment revenue (2,406) (2,395)
Change in gas balancing receivable (275) 15
Change in gas balancing payable (161) 686
Change in other long-term liabilities 74 (1)
Change in other assets, net (319) (1,039)
------------ ------------
Cash provided (used) by operating activities 1,829 20,116
------------ ------------
Cash flows from investing activities:
Capital expenditures (37,684) (54,427)
Proceeds from sale of pipeline 6,784 --
Proceeds from sale of mineral interests 1,578 927
------------ ------------
Cash provided (used) by investing activities (29,322) (53,500)
------------ ------------
Cash flows from financing activities:
Change in accounts payable and accrued liabilities to be refinanced (7,358) 8,900
Increase in debt 44,900 21,000
Deferred financing cost (966) --
Equity issued related to employee stock plans 16 179
Payment on capital leases (468) --
Dividends on preferred stock (638) (638)
------------ ------------
Cash provided (used) by financing activities 35,486 29,441
------------ ------------
Net increase (decrease) in cash and cash equivalents 7,993 (3,943)
Cash and cash equivalents:
Balance, beginning of period 6,887 11,876
------------ ------------
Balance, end of period $ 14,880 $ 7,933
============ ============
</Table>
The accompanying notes are an integral part of these financial statements.
5
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002
1. GENERAL
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 periods 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, 2001 included in the Company's Annual
Report on Form 10-K dated March 29, 2002.
In the Company's Annual Report on Form 10-K dated March 29, 2002, the
Company discussed its alternatives involving the $36.0 million of the
10.125% Senior Subordinated Notes (the "Notes") that will mature on
September 15, 2002 and increasing the availability of the Company's $75
million Credit Facility with First Union National Bank (the "Credit
Facility"). On July 9, 2002, the Company announced that the lenders
under the Credit Facility have agreed to increase availability under
the revolving borrowing base from $50 million to $75 million. In
addition, the holders of $15.9 million of the $36.0 million of the
Notes have consented to an extension of such Notes until July 31, 2004.
The Company is in ongoing negotiations for similar extensions with the
holders of $11.5 million of the Notes.
Non-discretionary capital expenditures include completion of the Medusa
deepwater discovery, currently scheduled to begin production in the
first quarter of 2003. The Company anticipates that cash flow generated
during 2002 and current availability under the Credit Facility will
provide necessary capital to enable the Company to continue its
operational activities until such time as production from the Medusa
discovery begins. At that time, the Company anticipates that the Medusa
reserves and production will be integrated into the borrowing base of
the Company's Credit Facility and will provide additional available
borrowing capacity. This increase in borrowing capacity as well as
significant additional cash flow from the new production will provide
funds for future discretionary capital expenditures.
Effective January 1, 2001, the Company adopted Statement of Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended ("SFAS 133"). SFAS 133 establishes accounting
and reporting standards requiring that derivative instruments,
including certain derivative instruments embedded in other contracts,
be recorded in the balance sheet as either an asset or a liability
measured at its fair value. Changes in the value of derivatives that
qualify as cash flow hedges to the extent effective are reported in
other comprehensive income, a component of stockholders' equity, until
realized. See Note 3.
2. PER SHARE AMOUNTS
Basic earnings per common share were computed by dividing net income 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, warrants, and
non-vested restricted stock
6
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 six-month period ended June
30, 2001 includes the conversion of preferred stock in the computation
of diluted income per share because they were dilutive. The conversion
of the preferred stock was not included in the calculations for the
quarter ended June 30, 2001 or in any calculation for 2002 due to their
antidilutive effect on diluted income or loss per share.
Stock options, warrants, and non-vested restricted stock representing
approximately 2,339,000 and 182,500 shares for the quarters ended June
30, 2002 and 2001 as well as 2,701,000 and 175,000 shares for the
six-month periods ended June 30, 2002 and 2001 were not dilutive and
therefore were not included in the computations of diluted income per
share.
A reconciliation of the basic and diluted earnings per share
computation is as follows (in thousands, except per share amounts):
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- -----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(a) Net income (loss) available
for common shares $ 2,022 $ 3,135 $ (751) $ 8,990
Preferred dividends assuming
conversion of preferred stock
(if dilutive) $ -- $ -- $ -- $ 638
(b) Income (loss) available for common
shares assuming conversion of
preferred stock (if dilutive) $ 2,022 $ 3,135 $ (751) $ 9,628
(c) Weighted average shares outstanding 13,334 13,258 13,325 13,255
Dilutive impact of options and warrants 319 169 -- 232
Dilutive impact of restricted stock 91 -- -- --
Convertible preferred stock
(if dilutive) -- -- -- 1,366
(d) Total diluted shares 13,744 13,427 13,325 14,853
Basic income (loss) per share (a/c) $ 0.15 $ 0.24 $ (0.06) $ 0.68
Diluted income (loss) per share (b/d) $ 0.15 $ 0.23 $ (0.06) $ 0.65
</Table>
7
3. DERIVATIVES
The Company periodically uses derivative financial instruments to
manage oil and gas price risk.
In March 2002, the Company purchased put options, which established an
average floor price of $2.65 per Mcf on 6.1 Bcf of production from
April 2002 through September 2002. The Company elected not to designate
these derivative financial instruments as accounting hedges and
accordingly, accounted for these contracts under mark-to-market
accounting. The Company recognized a loss of approximately $381,950 in
the second quarter of 2002 related to these derivative contracts.
Year-to-date loss is $769,950 through June 30, 2002. Fair value of
these puts is $58,800 at June 30, 2002.
In the second quarter of 2002, the Company entered into no cost natural
gas collar contracts in effect for March 2003 through October 2003.
These agreements are for volumes of 150,000 Mcf per month with an
average ceiling price of $4.80 and a floor price of $3.50. These
contracts are accounted for as cash flow hedges under SFAS 133. The
fair value of these collar contracts at June 30, 2002, recorded in the
balance sheet is $136,108 and $88,470 (net of tax) as other
comprehensive income.
In April 2001, the Company entered into derivative contracts for 2002
production with Enron North America Corp. ("Enron derivatives"). Enron
North America Corp. filed for protection under the bankruptcy laws in
late 2001. As a result of the credit risk associated with these Enron
derivatives; hedge accounting was not available due to ineffectiveness
as of September 30, 2001. As of December 31, 2001 the contracts have
been marked to the market. In the fourth quarter of 2001, the Company
charged to expense (non-cash) $9.2 million related to these Enron
derivatives. The Company has no other contracts with Enron or its
subsidiaries.
The $5,971,000 (net of tax) recorded in other comprehensive income at
December 31, 2001 is related to the fair value as of September 30, 2001
of the natural gas collar contracts with Enron North America Corp.,
which mature in 2002. As the contracts mature in 2002, the Company will
record non-cash revenue each month, offsetting the amounts in other
comprehensive income (net of tax) related to the derivatives. The
Company recorded approximately $2.9 million related to these Enron
derivatives in the first quarter of 2002 and $2.3 million in the second
quarter of 2002 as oil and gas revenue.
In the second quarter of 2002, the Company completed the sale of its
claims against Enron for hedging transactions for $2.5 million in cash.
In the fourth quarter of 2001, Callon reported a non-cash charge for
the total value of these claims. As a result of the sale, the company
reported a pre-tax gain of $2.5 million in the second quarter of 2002.
The Company has no other derivative contracts.
4. LONG-TERM DEBT
As discussed in Note 1, on June 30, 2002 the Company amended the Credit
Facility to increase availability under the revolving borrowing base
from $50 million to $75 million under a dual tranche loan. The Tranche
A revolver bears interest at .25% to .75% above a defined base rate
depending on utilization of the borrowing base or at the option of the
Company, LIBOR plus 2% to 2.5% based on utilization of the borrowing
base and has a maximum aggregate credit amount of $45 million. The
Tranche B part of the facility will bear interest at 15% and has an
aggregate maximum credit amount
8
of $30 million. The maturity date of the Credit Facility is June 30,
2004 and the $75 million borrowing base is subject to semi-annual
re-determinations in April and October of each year. The amended Credit
Facility contains substantially the same covenants as the original
Credit Facility.
In addition, the holders of $15.9 million out of $36.0 million of the
Company's 10.125% Senior Subordinated Notes due September 15, 2002 (the
"Notes") have consented to an extension of such Notes until July 31,
2004. The Company granted 190,980 warrants with a fair market value of
approximately $965,000 to purchase Common Stock of the Company and
consent fees in the amount of $1.6 million to the holders of the notes
that granted the extensions. The warrants have a maturity of five years
and an exercise price of $0.01. The Company is in ongoing negotiations
for similar extensions with the holders of $11.5 million of the Notes.
The $20.1 million in Notes that have not agreed, at this time, to the
extension of the maturity date discussed above are classified as
long-term to reflect the maturity of the new Credit Facility which will
be used to refinance the remaining Notes not extended.
The Company accounted for the extension of the $15.9 million in Notes
described above as an extinguishment of the Notes and the issuance of
new securities recorded at a fair value of $13.4 million. The net loss
on extinguishment, including the warrants and fees paid described above
was not significant. Costs deferred with the extensions will be
amortized through July of 2004.
5. COMPREHENSIVE INCOME
An analysis of comprehensive income is detailed below (in thousands):
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------------- ----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Net income (loss) $ 2,341 $ 3,454 $ (113) $ 9,628
Other comprehensive income (loss):
Cumulative effect of change in
accounting principle -- -- -- (3,764)
Change in unrealized derivatives'
fair value 88 5,151 88 8,350
Amortization of Enron derivatives (1,504) -- (3,418) --
------------ ------------ ------------ ------------
Total Comprehensive Income $ 925 $ 8,605 $ (3,443) $ 14,214
------------ ------------ ------------ ------------
</Table>
6. 2002 STOCK PLAN
In February 2002, the Board of Directors of the Company approved and
adopted the 2002 Stock Incentive Plan (the "2002 Plan"). Pursuant to
the 2002 Plan, 350,000 shares of common stock have been reserved for
issuance upon the exercise of options or for grants of stock options,
stock appreciation rights or units, bonus stock, or performance shares
or units.
In the first quarter of 2002, the Company awarded 300,000 shares of
restricted stock from the 1996 and the 2002 Plan to certain officers
and employees to be issued as vested. These shares generally will vest
over a three-year period (one-third in each year) beginning in November
2002. The deferred compensation portion of this grant will be amortized
to expense over the vesting period.
9
7. SALE OF PIPELINES
In May 2002, the Company completed the sale of its natural gas pipeline
at the North Dauphin Island field in Mobile Bay as well as its interest
in a pipeline that is currently not in use, in the Mobile 908 Area. The
Company received $7.0 million ($6.8 million after interim operations
allocations) and the pipelines had a net book value of $4.3 million.
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, including statements 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, 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 and its ability to develop existing
proved undeveloped reserves. 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 but, does not use derivative financial
instruments for trading purposes.
The following discussion is intended to assist in an understanding of the
Company's historical financial positions and results of operations. The
Company's historical financial statements and notes thereto included
10
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 six months ended June 30,
2002 increased by $8.0 million and net cash flows from operations before working
capital changes totaled $8.3 million. Net capital expenditures from the cash
flow statement for the period totaled $37.7 million. These funds were primarily
expended in exploration, drilling and completion of oil and gas properties.
At June 30, 2002, the Company had working capital of $11.0 million excluding
current maturities of long-term debt.
As discussed in the Company's Annual Report on Form 10-K dated March 29, 2002,
the Company discussed its options with respect to the $36.0 million of the
10.125% Senior Subordinated Notes (the "Notes") that will mature on September
15, 2002 and increasing the availability of the Company's $75 million Credit
Facility with First Union National Bank (the "Credit Facility"). On July 9,
2002, the Company announced that the lenders under the Credit Facility have
agreed to increase availability under the revolving borrowing base from $50
million to $75 million. In addition, the holders of $15.9 million of the $36.0
million of the Notes have consented to an extension of such Notes until July 31,
2004. The Company granted 190,980 warrants with a fair market value of
approximately $965,000 to purchase Common Stock of the Company and consent fees
in the amount of $1.6 million to the holders of the notes that granted the
extensions. The Company is in ongoing negotiations for similar extensions with
the holders of $11.5 million of the Notes.
Non-discretionary capital expenditures include completion of the Medusa
deepwater discovery, currently scheduled to begin production in the first
quarter of 2003. The Company anticipates that cash flow generated during 2002
and current availability under the Credit Facility will provide necessary
capital to enable the Company to continue its operational activities until such
time as production from the Medusa discovery begins. At that time, the Company
anticipates that the Medusa reserves and production will be integrated into the
borrowing base of the Company's Credit Facility and will provide additional
available borrowing capacity. This increase in borrowing capacity as well as
significant additional cash flow from the new production will provide funds for
future discretionary capital expenditures.
In May 2001, the Company initiated a combination of offerings of equity and
senior notes to investors with proceeds to be used to call certain of the
Company's subordinated debt, repay borrowings under its senior secured credit
facility and to finance capital expenditures. Subsequently, the Company withdrew
its offer to sell the senior notes and the equity sale was terminated.
Approximately $358,000 of costs associated with the withdrawn offering was
expensed during the quarter.
In early July of 2001, the Company closed a $95 million multiple advance term
loan with a private lender. The Company drew $45 million on July 3, 2001 and
paid down its revolving Credit Facility. The Company subsequently drew the
remaining $50 million in late 2001. Under the terms of the agreement, Callon
also issued warrants for the purchase, at a nominal exercise price, of 265,210
shares of its common stock to the lender and conveyed an overriding royalty
interest equal to 2% of the company's net interest in four of its deepwater
discoveries. All amounts under the loan must be drawn before June 30, 2002. This
senior debt will mature March 31, 2005 and contains restrictions on certain
types of future indebtedness and dividends on common stock.
11
CAPITAL EXPENDITURES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $36.1 million in the first six months of
2002. The Company incurred approximately $15.8 million in the Gulf of Mexico
Shelf Area, including $6.9 million related to the production facility under
construction in the first quarter of 2002 in the Mobile Block 952/953/955 area.
The Gulf of Mexico Deepwater area expenditures accounted for the remainder of
the total capital expended, primarily for additional development costs for
production facilities at the Company's Medusa discovery. Interest and general
and administrative costs allocable directly to exploration and development
projects were approximately $7.7 million for the first six months of 2002.
For the remainder of the year, the Company will continue evaluating property
acquisitions and drilling opportunities. The Company has forecasted up to $25.8
million in capital expenditures, including capitalized interest and capitalized
general and administrative expenses, for the remainder of 2002. The major
portion of the capital expenditure budget will be used for development of the
Company's Medusa discovery and developmental drilling at Boomslang.
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.
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- ----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Production volumes: (b)
Oil (MBbls) 60 69 114 120
Gas (MMcf) 3,565 3,536 6,594 6,980
Total production (MMcfe) 3,925 3,950 7,278 7,701
Average daily production (MMcfe) 43.1 43.4 40.2 42.5
Average sales price: (a)(b)
Oil (Bbls) $ 23.41 $ 24.70 $ 21.16 $ 25.52
Gas (Mcf) 3.25 4.34 2.83 4.90
Total (Mcfe) 3.31 4.32 2.90 4.84
Average costs (per Mcfe):
Lease operating (excluding severance taxes) $ 0.66 $ 0.70 $ 0.67 $ 0.67
Severance taxes 0.06 0.08 0.06 0.08
Depletion 1.64 1.28 1.64 1.28
General and administrative (net of management fees) 0.33 0.40 0.33 0.35
</Table>
(a) Includes hedging gains and losses.
12
(b) Includes volumes of 580 MMcf for both three month periods ended June
30, 2002 and 2001 and 1,154 MMcf for both six month periods ended June
30, 2002 and 2001, respectively, at an average price of $2.08 per Mcf
associated with a volumetric production payment.
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2002 AND
THE THREE MONTHS ENDED JUNE 30, 2001.
Oil and Gas Production and Revenues
Total oil and gas revenues decreased 10% from $17.1 million in the second
quarter of 2001 to $15.3 million in the second quarter of 2002. Gas prices were
much lower while oil prices declined slightly when compared to the same period
in 2001. Total production for the second quarter of 2002 decreased by 1% versus
the second quarter of 2001.
Gas production during the second quarter of 2002 totaled 3.6 billion cubic feet
and generated $11.6 million in revenues compared to 3.5 billion cubic feet and
$15.3 million in revenues during the same period in 2001. The average sales
price for the second quarter of 2002 averaged $3.25 per thousand cubic feet
compared to $4.34 per thousand cubic feet for the second quarter of 2001. The
Company's gas production increased slightly when compared to the same quarter
last year.
Oil production during the second quarter of 2002 totaled 60,000 barrels and
generated $1.4 million in revenues compared to 69,000 barrels and $1.7 million
in revenues for the same period in 2001. Average oil prices received in the
second quarter of 2002 were $23.41 compared to $24.70 in 2001. The decline in
production was primarily due to expected production declines in some of the
Company's older producing properties.
Lease Operating Expenses
Lease operating expenses, including severance taxes, for the three-month period
ending June 30, 2002 were $2.8 million compared to $3.1 million for the same
period in 2001.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three months ending June 30,
2002 and 2001 were $6.5 and $5.2 million, respectively. This increase is
primarily due to a higher average rate in the second quarter of 2002 as a result
of an increase in the amortization base due to higher drilling costs in
combination with reserve additions being less than expected in 2001.
General and Administrative
General and administrative expense decreased to $1.3 million for the three
months ended June 30, 2002 as compared to $1.6 million for the three months
ended June 30, 2001. This decrease was due primarily to the expense category
being higher in 2001 due to expenses incurred related to the withdrawn debt
offering in the second quarter of 2001.
13
Interest Expense
Interest expense increased from $2.6 million during the three months ended June
30, 2001 to $5.9 million during the three months ended June 30, 2002. An
increase in the Company's long-term debt contributed to the greater interest
expense.
COMPARISON OF RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2002 AND
THE SIX MONTHS ENDED JUNE 30, 2001.
Oil and Gas Production and Revenues
Total oil and gas revenues decreased 29% from $37.2 million in the first six
months of 2001 to $26.4 million in the first six months of 2002. Gas prices were
substantially lower and oil prices declined as well when compared to the same
period in 2001. Total production for the first six months of 2002 decreased by
5% versus the first six months of 2001.
Gas production during the first six months of 2002 totaled 6.6 billion cubic
feet and generated $18.5 million in revenues compared to 7.0 billion cubic feet
and $34.2 million in revenues during the same period in 2001. The average sales
price for the first six months of 2002 averaged $2.83 per thousand cubic feet
compared to $4.90 per thousand cubic feet for the first six months of 2001. The
Company's gas production decreased slightly when compared to the same period
last year as a result of expected and normal declines in maturing properties.
Oil production during the first six months of 2002 totaled 114,000 barrels and
generated $2.4 million in revenues compared to 120,000 barrels and $3.1 million
in revenues for the same period in 2001. Average oil prices received in the
first six months of 2002 were $21.16 compared to $25.52 in 2001. The decline in
production was primarily due to expected production declines in some of the
Company's older producing properties.
Lease Operating Expenses
Lease operating expenses, including severance taxes, for the six-month period
ending June 30, 2002 were $5.4 million compared to $5.7 million for the same
period in 2001.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the six months ending June 30, 2002
and 2001 were $12.1 and $10.1 million, respectively. This increase is primarily
due to a higher average rate in the first six months of 2002 as a result of an
increase in the amortization base due to higher drilling costs in combination
with reserve additions being less than expected in 2001.
General and Administrative
General and administrative expense decreased to $2.4 million for the six months
ended June 30, 2002 as compared to $2.7 million for the six months ended June
30, 2001. This decrease was, in part, due to the expense category being higher
in 2001 due to expenses incurred related to the withdrawn debt offering in the
second quarter of 2001.
14
Interest Expense
Interest expense increased from $5.2 million during the six months ended June
30, 2001 to $11.6 million during the six months ended June 30, 2002. An increase
in the Company's long-term debt contributed to the greater interest expense.
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 decreased;
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. The Company enters into
derivative financial instruments to hedge oil and gas price risks for the
production volumes to which the hedge relates. The derivatives 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 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 June 30, 2002. There have been no significant
changes in market risks faced by the Company since the end of 2001.
15
CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
In June 2002, holders of the Company's 10.125% Senior Subordinated Notes due
2002 ("2002 Notes") issued pursuant to the Indenture between the Company and
American Stock Transfer & Trust Company dated July 31, 1997, as amended, agreed
to amend $15.9 million in aggregate principal amount of 2002 Notes to extend the
maturity of such 2002 Notes until July 31, 2004. On June 7, 2002, in
consideration for agreeing to extend the maturity of their 2002 Notes, holders
of the 2002 Notes that agreed to extend were issued warrants to purchase 190,980
shares of the Company's common stock at an exercise price of $.01 per share. The
warrants are exercisable for five years from the date of issuance. The issuance
of the warrants was exempt pursuant to Section 4(2) of the Securities Act of
1933.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
The Company held its annual meeting on May 8, 2002. At the annual meeting, the
Class II directors of the board of directors of the Company were elected to hold
office until the Company's 2005 annual meeting of stockholders. The votes cast
for each of the Class II directors proposed by the Company's definitive proxy
statement on Schedule 14A, out of a total of 13,424,216 shares outstanding, were
as follows:
<Table>
<Caption>
AGAINST or
FOR WITHHELD ABSTAIN
------------ ------------ ------------
John S. Callon 10,908,881 590,006 --
Leif Dons 11,301,653 197,234 --
B.F. Weatherly 11,278,978 219,909 --
</Table>
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
16
(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, File No. 000-25192)
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)
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 Indenture for the Company's 10.125% Senior
Subordinated Notes due 2002 dated as of July
31, 1997 (incorporated by reference from
Exhibit 4.1 of the Company's Registration
Statement on Form S-4, filed September 25,
1997, Reg. No. 333-36395)
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)
17
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, File
No. 001-14039)
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,
File No. 001-14039)
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, File No. 001-14039)
4.11 Warrant dated as of June 29, 2001 entitling
Duke Capital Partners, LLC to purchase
common stock from the Company. (incorporated
by reference to Exhibit 4.11 of the
Company's Quarterly Report on Form 10-Q for
the period ended June 30, 2001, File No.
001-14039)
4.12 First Supplemental Indenture, dated June 26,
2002, to Indenture between Callon Petroleum
Company and American Stock Transfer & Trust
Company dated July 31, 1997. (incorporated
by reference to Exhibit 4.1 of the Company's
Current Report on Form 8-K dated June 26,
2002, File No. 001-14039)
4.13 Form of Warrant entitling certain holders of
the Company's 10.125% Senior Subordinated
Notes due 2002 to purchase common stock from
the Company.
10. Material contracts
10.1 First Amended and Restated Credit Agreement
dated as of June 30, 2002, among Callon
Petroleum Company, each of the lenders that
is a signatory thereto, Wachovia Bank
National Association, as administrative
agent, and Union Bank of California, N.A.,
as documentation agent.
11. Statement re 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*
18
24. Power of attorney*
99. Additional exhibits*
(b) Reports on Form 8-K
Current Report dated June 26, 2002, reporting Item 5. Other
Events
Current Report dated June 28, 2002, reporting Item 4. Change
in Registrant's Certifying Accountants
- ----------
* 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: August 14, 2002 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
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
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,
File No. 000-25192)
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)
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 Indenture for the Company's 10.125% Senior Subordinated Notes
due 2002 dated as of July 31, 1997 (incorporated by reference
from Exhibit 4.1 of the Company's Registration Statement on
Form S-4, filed September 25, 1997, Reg. No. 333-36395)
</Table>
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
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, File No. 001-14039)
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, File No.
001-14039)
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, File No. 001-14039)
4.11 Warrant dated as of June 29, 2001 entitling Duke Capital
Partners, LLC to purchase common stock from the Company.
(incorporated by reference to Exhibit 4.11 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30,
2001, File No. 001-14039)
4.12 First Supplemental Indenture, dated June 26, 2002, to
Indenture between Callon Petroleum Company and American Stock
Transfer & Trust Company dated July 31, 1997. (incorporated by
reference to Exhibit 4.1 of the Company's Current Report on
Form 8-K dated June 26, 2002, File No. 001-14039)
4.13 Form of Warrant entitling certain holders of the Company's
10.125% Senior Subordinated Notes due 2002 to purchase common
stock from the Company.
10. Material contracts
10.1 First Amended and Restated Credit Agreement dated as of June
30, 2002, among Callon Petroleum Company, each of the lenders
that is a signatory thereto, Wachovia Bank National
Association, as administrative agent, and Union Bank of
California, N.A., as documentation agent.
11. Statement re 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*
</Table>
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
22. Published report regarding matters submitted to vote of security
holders*
23. Consents of experts and counsel*
24. Power of attorney*
99. Additional exhibits*
</Table>
- ----------
* Inapplicable to this filing
- ----------