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, 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 November 7, 2002, there were 13,906,666 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 September 30, 2002
and December 31, 2001 3
Consolidated Statements of Operations for Each of the
Three and Nine Months in the Periods Ended September 30, 2002
and September 30, 2001 4
Consolidated Statements of Cash Flows for Each of the
Nine Months in the Periods Ended September 30, 2002 and
September 30, 2001 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 10
Item 3. Quantitative and Qualitative Disclosures about Market Risk 16
Item 4. Controls and Procedures 17
PART II. OTHER INFORMATION
Item 2. Changes in Securities and Use of Proceeds 18
Item 6. Exhibits and Reports on Form 8-K 18
</Table>
2
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<Table>
<Caption>
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- ------------
ASSETS (UNAUDITED)
------
Current assets:
Cash and cash equivalents $ 6,920 $ 6,887
Accounts receivable 6,856 5,908
Other current assets 517 209
--------- ---------
Total current assets 14,293 13,004
--------- ---------
Oil and gas properties, full cost accounting method:
Evaluated properties 751,119 704,937
Less accumulated depreciation, depletion and amortization (418,023) (399,339)
--------- ---------
333,096 305,598
Unevaluated properties excluded from amortization 40,747 37,560
--------- ---------
Total oil and gas properties 373,843 343,158
--------- ---------
Pipeline and other facilities 878 5,364
Other property and equipment, net 2,055 2,455
Deferred tax asset 7,755 4,399
Other assets, net 4,751 3,715
--------- ---------
Total assets $ 403,575 $ 372,095
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable and accrued liabilities $ 8,258 $ 9,985
Undistributed oil and gas revenues 1,111 1,131
Accrued net profits interest payable 1,298 1,501
Accounts payable and accrued liabilities to be refinanced -- 9,558
Current maturities of long-term debt 1,311 37,345
--------- ---------
Total current liabilities 11,978 59,520
--------- ---------
Long-term debt-excluding current maturities 244,027 157,366
Capital leases 3,511 4,367
Deferred revenue on sale of production payment -- 2,406
Other long-term liabilities 1,124 1,212
--------- ---------
Total liabilities 260,640 224,871
--------- ---------
Stockholders' equity:
Preferred stock, $0.01 par value, 2,500,000 shares authorized; 600,861 shares of
Convertible Exchangeable Preferred Stock, Series A, issued and outstanding with
a liquidation preference of $15,021,525 6 6
Common stock, $0.01 par value, 20,000,000 shares authorized; 13,879,998 and
13,397,706 shares outstanding at September 30, 2002 and December 31, 2001 139 134
Unearned restricted stock compensation (984) --
Capital in excess of par value 158,305 154,425
Accumulated other comprehensive income 1,152 5,971
Retained earnings (deficit) (15,683) (13,312)
--------- ---------
Total stockholders' equity 142,935 147,224
--------- ---------
Total liabilities and stockholders' equity $ 403,575 $ 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- --------------------
2002 2001 2002 2001
-------- -------- -------- --------
Revenues:
Oil and gas sales $ 15,763 $ 12,404 $ 42,121 $ 49,647
Loss on mark-to-market commodity
derivative contracts (18) -- (788) --
Interest and other 23 311 845 1,592
Gain on sale of pipeline -- -- 2,454 --
Gain on sale of Enron derivatives -- -- 2,479 --
-------- -------- -------- --------
Total revenues 15,768 12,715 47,111 51,239
-------- -------- -------- --------
Costs and expenses:
Lease operating expenses 2,832 3,238 8,201 8,963
Depreciation, depletion and amortization 6,763 4,722 18,840 14,773
General and administrative 1,070 843 3,508 3,545
Interest 7,103 3,508 18,736 8,742
-------- -------- -------- --------
Total costs and expenses 17,768 12,311 49,285 36,023
-------- -------- -------- --------
Income (loss) from operations (2,000) 404 (2,174) 15,216
Income tax expense (benefit) (700) 142 (761) 5,326
-------- -------- -------- --------
Net income (loss) (1,300) 262 (1,413) 9,890
Preferred stock dividends 320 320 958 958
-------- -------- -------- --------
Net income (loss) available to common shares $ (1,620) $ (58) $ (2,371) $ 8,932
======== ======== ======== ========
Net income (loss) per common share:
Basic $ (0.12) $ 0.00 $ (0.18) $ 0.67
======== ======== ======== ========
Diluted $ (0.12) $ 0.00 $ (0.18) $ 0.67
======== ======== ======== ========
Shares used in computing net income (loss)
per common share:
Basic 13,377 13,284 13,342 13,265
======== ======== ======== ========
Diluted 13,377 13,284 13,342 13,412
======== ======== ======== ========
</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>
NINE MONTHS ENDED
---------------------------------
SEPTEMBER 30, SEPTEMBER 30,
2002 2001
------------- -------------
Cash flows from operating activities:
Net income (loss) $ (1,413) $9,890
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization 19,353 15,232
Amortization of deferred costs 3,902 1,610
Non-cash derivative income (7,438) --
Mark-to-market commodity derivative contracts 788 --
Deferred income tax expense (benefit) (761) 5,326
Non-cash charge related to compensation plans 1,015 714
Gain on sale of pipeline (2,454) --
Changes in current assets and liabilities:
Accounts receivable (948) 2,521
Advance to operators -- 1,131
Other current assets (60) 35
Investment in put contracts (1,012) --
Current liabilities (1,420) (655)
Deferred production payment revenue (2,406) (3,613)
Change in gas balancing receivable (363) 76
Change in gas balancing payable (159) 322
Change in other long-term liabilities 71 (1,746)
Change in other assets, net (2,261) (957)
----------------- -----------------
Cash provided (used) by operating activities 4,434 29,886
----------------- -----------------
Cash flows from investing activities:
Capital expenditures (51,060) (85,254)
Proceeds from sale of pipeline 6,784 --
Proceeds from sale of mineral interests 1,578 1,195
----------------- -----------------
Cash provided (used) by investing activities (42,698) (84,059)
----------------- -----------------
Cash flows from financing activities:
Change in accounts payable and accrued liabilities to be refinanced (9,558) 6,155
Payment on debt (58,085) (39,000)
Increase in debt 109,900 85,000
Debt issuance cost (2,291) (2,375)
Equity issued related to employee stock plans 79 358
Payment on capital leases (790) --
Dividends on preferred stock (958) (958)
----------------- -----------------
Cash provided (used) by financing activities 38,297 49,180
----------------- -----------------
Net increase (decrease) in cash and cash equivalents 33 (4,993)
Cash and cash equivalents:
Balance, beginning of period 6,887 11,876
----------------- -----------------
Balance, end of period $6,920 $6,883
================= =================
</Table>
The accompanying notes are an integral part of these financial statements.
5
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2002
1. GENERAL
The financial information presented as of any date other than December
31, has been prepared from the books and records of Callon Petroleum
Company (the "Company") 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 with respect to the $36.0 million of
the Company's 10.125% Senior Subordinated Notes (the "Notes") that
matured on September 15, 2002 and its options for 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 agreed to
increase availability under the revolving borrowing base of the Credit
Facility from $50 million to $75 million. In addition, the holders of
$22.9 million of the $36.0 million of the Notes consented to an
extension of such Notes until July 31, 2004. The holders of the Notes
that did not consent to the extension were paid on the maturity date in
September 2002.
Non-discretionary capital expenditures include completion of the Medusa
deepwater discovery, currently scheduled to begin production in the
first half of 2003. The Company anticipates that cash flow 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 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,
warrants, and non-vested
6
restricted stock considered common stock equivalents computed using the
treasury stock method and the effect of the convertible preferred stock
(if dilutive).
The conversion of the preferred stock was not included in the
calculations for the quarters or the nine months ended September 30,
2002 and 2001 due to their antidilutive effect on diluted income or
loss per share.
Stock options, warrants and non-vested restricted stock representing
approximately 3,241,000 and 2,303,000 shares for the quarters ended
September 30, 2002 and 2001 as well as 2,924,000 and 713,000 shares for
the nine-month periods ended September 30, 2002 and 2001 were not
dilutive and therefore 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- --------------------
2002 2001 2002 2001
--------- --------- --------- --------
(a) Net income (loss) available
for common shares $ (1,620) $ (58) $ (2,371) $ 8,932
Preferred dividends assuming
conversion of preferred stock
(if dilutive) -- -- -- --
(b) Income (loss) available for common
shares assuming conversion of
preferred stock (if dilutive) $ (1,620) $ (58) $ (2,371) $ 8,932
(c) Weighted average shares outstanding 13,377 13,284 13,342 13,265
Dilutive impact of options and warrants -- -- -- 147
Dilutive impact of restricted stock -- -- -- --
Convertible preferred stock
(if dilutive) -- -- -- --
(d) Total diluted shares 13,377 13,284 13,342 13,412
Basic income (loss) per share (a divided by c) $ (0.12) $ 0.00 $ (0.18) $ 0.67
Diluted income (loss) per share (b divided by d) $ (0.12) $ 0.00 $ (0.18) $ 0.67
</Table>
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 $58,800 in the third
quarter of 2002 related to these derivative contracts. Year-to-date
charges to income were $828,750 through September 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
7
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 September 30, 2002,
recorded on the balance sheet is $24,480 and $15,912 (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. In the fourth quarter of 2001, the Company
recorded a non-cash charge to expense of $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 $2.2 million related to these Enron
derivatives in the third quarter of 2002 and $7.4 million for the nine
months ended September 30, 2002 as oil and gas revenue.
In the second quarter of 2002, the Company completed the sale of its
claim against Enron for hedging transactions for $2.5 million in cash.
As a result of the sale, the Company reported a pre-tax gain of $2.5
million in the second quarter of 2002.
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
range of interest rates on the Tranche A revolver was 3.36% to 5.00%
for the nine months ended September 30, 2002. The Tranche B part of the
facility will bear interest at 15% and has an aggregate maximum credit
amount 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 $22.9 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 274,980 warrants (with a fair market value of
approximately $1.3 million) to purchase Common Stock of the Company and
paid consent fees in the amount of $2.3 million to the holders of the
Notes that granted the extensions. The warrants have a term of five
years and an exercise price of $0.01. The holders of the Notes that did
not consent to the extension were paid on the maturity date in
September 2002. In late September 2002, approximately 107,000 warrants
were exercised by the holders of the Notes.
8
The Company accounted for the extension of the $22.9 million in Notes
described above as an extinguishment of the Notes and the issuance of
new securities recorded at a fair value of $19.3 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- ---------------------
2002 2001 2002 2001
-------- --------- -------- --------
Net income (loss) $ (1,300) $ 262 $ (1,413) $ 9,890
Other comprehensive income (loss):
Cumulative effect of change in
accounting principle -- -- -- (3,764)
Change in unrealized derivatives'
fair value (73) 2,048 16 10,398
Amortization of Enron derivatives (1,417) -- (4,835) --
-------- -------- -------- --------
Total Comprehensive Income $ (2,790) $ 2,310 $ (6,232) $ 16,524
======== ======== ======== ========
</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 2002, the Company awarded 300,000 shares of restricted stock from
the 1996 and the 2002 Plan and 70,500 from treasury shares 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.
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.
9
ITEM 2. 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 entitled "Risk Factors" included in the
Company's Annual Report on Form 10-K for the Company's most recent fiscal year,
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 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 during the nine months ended September
30, 2002 increased by $33,000 and net cash flows from operations before working
capital changes totaled $13.0 million. Net capital expenditures from the cash
flow statement for the period totaled $51.1 million. These funds were primarily
expended in, drilling and completion of oil and gas properties.
10
At September 30, 2002, the Company had working capital of $3.6 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 alternative courses of action with respect to the
$36.0 million of the Company's 10.125% Senior Subordinated Notes (the "Notes")
that matured 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 agreed to increase availability under the revolving
borrowing base from $50 million to $75 million. In addition, the holders of
$22.9 million of the $36.0 million of the Notes consented to an extension of
such Notes until July 31, 2004. The Company granted 274,980 warrants with a fair
market value of approximately $1.3 million to purchase Common Stock of the
Company and paid consent fees in the amount of $2.3 million to the holders of
the Notes that granted the extensions. The holders of the Notes that did not
consent to the extension were paid on the maturity date of the Notes in
September 2002. In late September 2002, approximately 107,000 warrants were
exercised by the holders of the Notes.
Non-discretionary capital expenditures include completion of the Medusa
deepwater discovery, currently scheduled to begin production in the first half
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.
Following Medusa, both the Boomslang and Habanero deepwater discoveries are
scheduled for development and are projected to begin initial production in the
second half of 2003. Once producing, these two deepwater discoveries are
projected to have the same positive impact on borrowing capacity as Medusa.
A development well is currently being drilled on the Boomslang discovery which
will provide the production take point. Production from Boomslang is projected
to be handled via a sub sea completion and tie-back to existing infrastructure
in the area and should commence in the fourth quarter of 2003. Habanero will be
produced by the existing delineation well and an additional well to be drilled
in the first half of 2003. A sub sea completion will be routed into one of the
operator's existing facilities and initial production is expected in late summer
of 2003.
The completion of the Company's deepwater discoveries will require the
construction of expensive production facilities and pipelines, including the
transportation and installation of production facilities and the use of sub sea
completion techniques. The Company cannot estimate the timing of the
construction of these facilities with certainty. The operators completing these
discoveries will possibly face inclement weather and other unfavorable
environmental conditions, delays in fabrication and delivery of necessary
equipment, and other unforeseen circumstances that may delay completion of these
properties. Long-term delays in the completion of these deepwater projects that
prevent the commencement of production from such discoveries could have a
material adverse effect on the Company's financial position and result of
operations. Such a delay would require the Company to reduce future anticipated
capital expenditures or seek additional sources of liquidity to finance capital
expenditures, which may not be available.
11
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 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 second quarter of 2001.
In early July 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. This
senior debt will mature March 31, 2005 and contains restrictions on certain
types of future indebtedness and dividends on common stock.
The following table describes our outstanding contractual obligations (in
thousands) as of September 30, 2002:
<Table>
<Caption>
CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE
OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS
- ----------- --------- --------- --------- --------- ----------
Credit Facility $65,000 $ -- $65,000 $ -- $ --
Senior Notes 95,000 -- 95,000 -- --
10.125% Senior
Subordinated Debt 22,915 -- 22,915 -- --
10.25% Senior
Subordinated Debt 40,000 -- 40,000 -- --
11% Senior Subordinated Debt 33,000 -- -- 33,000 --
Capital lease (future minimum payments) 6,963 2,046 3,026 883 1,008
</Table>
CAPITAL EXPENDITURES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $49.5 million in the first nine months of
2002. The Company incurred approximately $19.9 million in the Gulf of Mexico
Shelf Area, including $8.3 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 of
approximately $4.1 million and general and administrative costs allocable
directly to exploration and development projects of approximately $7.4 million
were capitalized for the first nine 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 $18.0
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.
12
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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -------------------
2002 2001 2002 2001
-------- -------- -------- --------
Production volumes:
Oil (MBbls) 56 76 170 196
Gas (MMcf) 3,768 3,258 10,362 10,238
Total production (MMcfe) 4,104 3,713 11,382 11,414
Average daily production (MMcfe) 44.6 40.4 41.7 41.8
Average sales price: (a)
Oil (Bbls) $ 24.60 $ 24.28 $ 22.29 $ 25.04
Gas (Mcf) 3.24 3.38 2.98 4.41
Total (Mcfe) 3.31 3.46 3.05 4.39
Average costs (per Mcfe):
Lease operating (excluding severance taxes) $ 0.61 $ 0.74 $ 0.65 $ 0.66
Severance taxes 0.08 0.13 0.07 0.12
Depletion 1.64 1.25 1.64 1.27
General and administrative (net of management fees) 0.26 0.23 0.31 0.31
</Table>
(a) Includes hedging gains and losses.
13
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30,
2002 AND THE THREE MONTHS ENDED SEPTEMBER 30, 2001.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 27% from $12.4 million in the third quarter
of 2001 to $15.8 million in the third quarter of 2002. Gas prices were lower
while oil prices increased slightly when compared to the same period in 2001.
Total production for the third quarter of 2002 increased by 11% versus the third
quarter of 2001.
Gas production during the third quarter of 2002 totaled 3.8 billion cubic feet
and generated $12.2 million in revenues compared to 3.3 billion cubic feet and
$11.0 million in revenues during the same period in 2001. The average sales
price for the third quarter of 2002 averaged $3.24 per thousand cubic feet
compared to $3.38 per thousand cubic feet for the third quarter of 2001. The
Company's gas production increased 15% when compared to the same quarter last
year primarily due to increased production as a result of the acceleration
projects in the Mobile Block 864 Area.
Oil production during the third quarter of 2002 totaled 56,000 barrels and
generated $1.4 million in revenues compared to 76,000 barrels and $1.8 million
in revenues for the same period in 2001. Average oil prices received in the
third quarter of 2002 were $24.60 compared to $24.28 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 September 30, 2002 were $2.8 million compared to $3.2 million for the
same period in 2001. The decrease was due primarily to two properties with
higher per unit of production operating expenses ending production in early
2002.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three months ending September
30, 2002 and 2001 were $6.8 and $4.7 million, respectively. This increase is
primarily due to a higher average rate in the third 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, net of amounts capitalized, increased to
$1.1 million for the three months ended September 30, 2002 as compared to
$843,000 for the three months ended September 30, 2001. This increase was due
primarily to a reduction of accrued bonus compensation in the last half of 2001.
Interest Expense
Interest expense, net of amounts capitalized, increased from $3.5 million during
the three months ended September 30, 2001 to $7.1 million during the three
months ended September 30, 2002. An increase in the Company's long-term debt
combined with higher interest rates associated with the Credit Facility and the
extended Notes contributed to the greater interest expense.
14
COMPARISON OF RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002
AND THE NINE MONTHS ENDED SEPTEMBER 30, 2001.
Oil and Gas Production and Revenues
Total oil and gas revenues decreased 15% from $ 49.6 million in the first nine
months of 2001 to $42.1 million in the first nine 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 nine months of 2002
decreased slightly versus the first nine months of 2001.
Gas production during the first nine months of 2002 totaled 10.4 billion cubic
feet and generated $30.9 million in revenues compared to 10.2 billion cubic feet
and $45.1 million in revenues during the same period in 2001. The average sales
price for the first nine months of 2002 averaged $2.98 per thousand cubic feet
compared to $ 4.41 per thousand cubic feet for the first nine months of 2001.
The Company's gas production increased slightly when compared to the same period
last year.
Oil production during the first nine months of 2002 totaled 170,000 barrels and
generated $3.8 million in revenues compared to 196,000 barrels and $ 4.9 million
in revenues for the same period in 2001. Average oil prices received in the
first nine months of 2002 were $22.29 compared to $ 25.04 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 nine-month period
ending September 30, 2002 were $8.2 million compared to $ 9.0 million for the
same period in 2001. The decrease was due primarily to two properties with
higher per unit of production operating expenses ending production in early
2002.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the nine months ending September
30, 2002 and 2001 were $18.8 and $ 14.8 million, respectively. This increase is
primarily due to a higher average rate in the first nine 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, net of amounts capitalized, remained
constant at $3.5 million for the nine months ended September 30, 2002 and 2001.
Interest Expense
Interest expense, net of amounts capitalized, increased from $8.7 million during
the nine months ended September 30, 2001 to $18.7 million during the nine months
ended September 30, 2002. An increase in the Company's long-term debt combined
with higher interest rates associated with the Credit Facility and the extended
Notes contributed to the greater interest expense.
15
ITEM 3. 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. 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 September 30, 2002. There have been no significant
changes in market risks faced by the Company since the end of 2001.
16
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures. Based on their
evaluation as of a date within 90 days of the filing date of this Quarterly
Report on Form 10-Q, the Company's principal executive officer and principal
financial officer have concluded that the Company's disclosure controls and
procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities
Exchange Act of 1934 (the "Exchange Act")) are effective to ensure that
information required to be disclosed by the Company in reports that it files or
submits under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the rules and forms of the Securities and
Exchange Commission.
(b) Changes in Internal Controls. There were no significant changes in
the Company's internal controls or in other factors that could significantly
affect these controls subsequent to the date of their evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
17
CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
In 2002, holders of the Company's 10.125% Senior Subordinated Notes due 2002
(the "Notes") issued pursuant to the Indenture between the Company and American
Stock Transfer & Trust Company dated July 31, 1997, as amended, agreed to amend
$22.9 million in aggregate principal amount of 2002 Notes to extend the maturity
of such Notes until July 31, 2004. In consideration for agreeing to extend the
maturity of their Notes, holders of the Notes that agreed to extend were issued
warrants to purchase 274,980 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 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, 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)
18
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)
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
19
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.
4.14 Second Supplemental Indenture, dated September 16,
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
September 16, 2002, File No. 001-14039)
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*
24. Power of attorney*
99. Additional exhibits*
<Table>
<Caption>
EXHIBIT NUMBER TITLE OF DOCUMENT
- -------------- -----------------
99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
</Table>
20
(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
Current Report dated August 14, 2002, reporting Item 9.
Regulation FD Disclosure
Current Report dated September 16, 2002, reporting Item 5.
Other Events
Current Report dated October 1, 2002, reporting Item 9.
Regulation FD Disclosure
- ----------
*Inapplicable to this filing
21
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 11 , 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)
22
CERTIFICATIONS
I, Fred L. Callon, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Callon
Petroleum Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) Designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this quarterly report (the "Evaluation Date"); and
(c) Presented in this quarterly report our conclusions about
the effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 11, 2002
-----------------
By: /s/ Fred L. Callon
------------------
Fred L. Callon, President and Chief Executive Officer
(Principal Executive Officer)
CERTIFICATIONS
I, John S. Weatherly, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Callon
Petroleum Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) Designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this quarterly report (the "Evaluation Date"); and
(c) Presented in this quarterly report our conclusions about
the effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 11, 2002
-----------------
By: /s/ John S. Weatherly
---------------------
John S. Weatherly, Senior Vice President
and Chief Financial Officer
(Principal Financial Officer)
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT NUMBER TITLE OF DOCUMENT
- -------------- -----------------
99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
</Table>