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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003
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 [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [ ] No [X]
As of November 10, 2003, there were 13,979,721 shares of the Registrant's Common
Stock, par value $0.01 per share, outstanding.
CALLON PETROLEUM COMPANY
TABLE OF CONTENTS
PAGE NO.
--------
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets as of September 30, 2003
and December 31, 2002 3
Consolidated Statements of Operations for Each of the
Three and Nine Months in the Periods Ended September 30, 2003
and September 30, 2002 4
Consolidated Statements of Cash Flows for Each of the
Nine Months in the Periods Ended September 30, 2003
and September 30, 2002 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 15
Item 3. Quantitative and Qualitative Disclosures about Market Risk 22
Item 4. Controls and Procedures 23
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K 24
2
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- -------------
(UNAUDITED) (NOTE 1)
ASSETS
Current assets:
Cash and cash equivalents $ 1,295 $ 5,807
Accounts receivable 6,047 10,875
Advance to operators 2,479 57
Other current assets 1,290 513
------------- -------------
Total current assets 11,111 17,252
------------- -------------
Oil and gas properties, full cost accounting method:
Evaluated properties 821,547 762,918
Less accumulated depreciation, depletion and amortization (439,515) (426,254)
------------- -------------
382,032 336,664
Unevaluated properties excluded from amortization 34,802 40,997
------------- -------------
Total oil and gas properties 416,834 377,661
------------- -------------
Pipeline and other facilities, net -- 853
Other property and equipment, net 1,641 1,890
Deferred tax asset 9,210 8,767
Long-term gas balancing receivable 1,020 761
Restricted investments 7,034 --
Other assets, net 2,182 3,429
------------- -------------
Total assets $ 449,032 $ 410,613
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 13,948 $ 12,498
Undistributed oil and gas revenues 1,065 1,109
Accrued net profits interest payable 2,000 1,707
Asset retirement obligations-current 6,574 --
Current maturities of long-term debt 134,734 1,320
------------- -------------
Total current liabilities 158,321 16,634
------------- -------------
Long-term debt-excluding current maturities 124,416 248,269
Accounts payable and accrued liabilities to be refinanced -- 3,861
Asset retirement obligations-long-term 24,458 --
Other long-term liabilities 2,009 889
------------- -------------
Total liabilities 309,204 269,653
------------- -------------
Stockholders' equity:
Preferred Stock, $.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, $.01 par value, 20,000,000 shares authorized; 13,968,368 and
13,900,466 shares outstanding at September 30, 2003 and at
December 31, 2002, respectively 140 139
Capital in excess of par value 158,669 158,370
Unearned compensation restricted stock (478) (826)
Accumulated other comprehensive income (loss) -- (469)
Retained earnings (deficit) (18,509) (16,260)
------------- -------------
Total stockholders' equity 139,828 140,960
------------- -------------
Total liabilities and stockholders' equity $ 449,032 $ 410,613
============= =============
The accompanying notes are an integral part of these financial statements.
3
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- --------------------
2003 2002 2003 2002
-------- -------- -------- --------
Operating revenues:
Oil and gas sales $ 15,082 $ 15,763 $ 54,759 $ 42,121
-------- -------- -------- --------
Total operating revenues 15,082 15,763 54,759 42,121
-------- -------- -------- --------
Operating expenses:
Lease operating expenses 2,659 2,832 8,003 8,201
Depreciation, depletion and amortization 6,416 6,763 20,769 18,840
General and administrative 1,068 1,070 3,704 3,508
Accretion expense 772 -- 2,214 --
(Gain) loss on mark-to-market commodity derivative contracts (199) 18 335 788
-------- -------- -------- --------
Total operating expenses 10,716 10,683 35,025 31,337
-------- -------- -------- --------
Income from operations 4,366 5,080 19,734 10,784
-------- -------- -------- --------
Other (income) expenses:
Interest expense 7,554 7,103 22,225 18,736
Other income (70) (23) (226) (845)
Gain on sale of pipeline -- -- -- (2,454)
Gain on sale of Enron derivatives -- -- -- (2,479)
-------- -------- -------- --------
Total other (income) expenses 7,484 7,080 21,999 12,958
-------- -------- -------- --------
Income (loss) before income taxes (3,118) (2,000) (2,265) (2,174)
Income tax expense (benefit) (1,092) (700) (793) (761)
-------- -------- -------- --------
Income (loss) before cumulative effect of change in
accounting principle (2,026) (1,300) (1,472) (1,413)
Cumulative effect of change in accounting principle, net of tax -- -- 181 --
-------- -------- -------- --------
Net income (loss) (2,026) (1,300) (1,291) (1,413)
Preferred stock dividends 320 320 958 958
-------- -------- -------- --------
Net income (loss) available to common shares $ (2,346) $ (1,620) $ (2,249) $ (2,371)
======== ======== ======== ========
Net income (loss) per common share:
Basic
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (0.17) $ (0.12) $ (0.18) $ (0.18)
Cumulative effect of change in accounting principle, net of tax -- -- 0.01 --
-------- -------- -------- --------
Net income (loss) available to common $ (0.17) $ (0.12) $ (0.17) $ (0.18)
======== ======== ======== ========
Diluted
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (0.17) $ (0.12) $ (0.18) $ (0.18)
Cumulative effect of change in accounting principle, net of tax -- -- 0.01 --
-------- -------- -------- --------
Net income (loss) available to common $ (0.17) $ (0.12) $ (0.17) $ (0.18)
======== ======== ======== ========
Shares used in computing net income (loss):
Basic 13,679 13,377 13,640 13,342
======== ======== ======== ========
Diluted 13,679 13,377 13,640 13,342
======== ======== ======== ========
The accompanying notes are an integral part of these financial statements.
4
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
NINE MONTHS ENDED
------------------------------
SEPTEMBER 30, SEPTEMBER 30,
2003 2002
------------- -------------
Cash flows from operating activities:
Net income (loss) $ (1,291) $ (1,413)
Adjustments to reconcile net income (loss) to cash provided by operating
activities:
Depreciation, depletion and amortization 21,560 19,353
Accretion expense 2,214 --
Amortization of deferred financing costs 4,783 3,902
Amortization of deferred production payment revenue -- (2,406)
Non-cash derivative income -- (7,438)
Non-cash mark-to-market commodity derivative contracts 374 788
Deferred income tax expense (benefit) (793) (761)
Cumulative effect of change in accounting principle (181) --
Non-cash charge related to compensation plans 612 1,015
Gain on sale of pipeline -- (2,454)
Changes in current assets and liabilities:
Accounts receivable 2,511 (948)
Advance to operators (2,422) --
Other current assets (430) (60)
Investment in put contracts -- (1,012)
Current liabilities 5,223 (1,420)
Change in gas balancing receivable (259) (363)
Change in gas balancing payable (347) (159)
Change in other long-term liabilities (11) 71
Change in other assets, net (346) (2,261)
------------- -------------
Cash provided (used) by operating activities 31,197 4,434
------------- -------------
Cash flows from investing activities:
Capital expenditures (39,326) (51,060)
Proceeds from sale of pipeline and other facilities 1,500 6,784
Proceeds from sale of mineral interests 781 1,578
------------- -------------
Cash provided (used) by investing activities (37,045) (42,698)
------------- -------------
Cash flows from financing activities:
Change in accounts payable and accrued liabilities to be refinanced (3,861) (9,558)
Increase in debt 11,000 109,900
Payments on debt (4,000) (58,085)
Deferred financing cost -- (2,291)
Equity issued related to employee stock plans 128 79
Capital leases (973) (790)
Cash dividends on preferred stock (958) (958)
------------- -------------
Cash provided (used) by financing activities 1,336 38,297
------------- -------------
Net increase (decrease) in cash and cash equivalents (4,512) 33
Cash and cash equivalents:
Balance, beginning of period 5,807 6,887
------------- -------------
Balance, end of period $ 1,295 $ 6,920
============= =============
The accompanying notes are an integral part of these financial statements.
5
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2003
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" or "Callon") 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, 2002 included in the Company's Annual
Report on Form 10-K dated March 27, 2003. The results of operations for
the three-month and nine-month periods ended September 30, 2003 are not
necessarily indicative of future financial results.
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. At September 30, 2003, the Company had $3.0
million of availability under its Credit Facility with Wachovia Bank,
National Association, as Administrative Agent (the "Credit Facility").
The Credit Facility matures June 30, 2004 and accordingly, the balance
outstanding under the Credit Facility on September 30, 2003 of $72
million is classified as a current liability on the Company's
Consolidated Balance Sheet as of September 30, 2003. The Company plans
to enter into negotiations to secure a new Credit Facility. In
addition, the Company is currently evaluating alternatives for
refinancing some or all of the Senior Notes and Senior Subordinated
Notes, of which $61 million mature in 2004. However, the Company
anticipates that the cash flow from the deepwater discoveries and
borrowing capacity provided by the associated proved producing reserves
being integrated into the borrowing base of the Company's Credit
Facility will provide funds for future exploration and development
activities, as well as provide a portion of the resources necessary to
fund repayment of the Notes upon maturity.
In September 2003, Callon announced that it signed an agreement to
participate in the formation of a limited liability company (LLC),
which will own a 75% undivided ownership interest in the deepwater
production spar located at the Company's Medusa field. The Company will
contribute its 15% undivided ownership interest in the spar to the LLC
and will receive a 10% ownership interest in the LLC. The LLC will earn
a tariff based upon production volume throughput. Two main conditions
must be satisfied for closing of this transaction to occur. The first
is that the spar production facility shall have met certain operational
criteria. The second is securing non-recourse financing for at least
one-half of the spar's cost. The agreement is with Murphy Exploration &
Production Company - USA and Oceaneering International, Inc. If the
transaction closes as currently structured, Callon expects to realize
cash proceeds of approximately $25 million from the transfer of its 15%
undivided ownership in the spar to the LLC. The value of Callon's 10%
ownership interest in the LLC is expected to be $8.4 million. Closing
of this transaction is expected to occur in the fourth quarter of 2003.
The Medusa spar is moored in over 2,200 feet of water in the Gulf of
Mexico at Mississippi
6
Canyon Block 582. It is in the final stages before the commencement of
production operations, initially from six wells.
Non-discretionary capital expenditures planned for the fourth quarter
of 2003 include the development of the Medusa and Habanero deepwater
discoveries, currently scheduled to begin production in November and
December of 2003, respectively. The Company anticipates that cash flow
generated during 2003, the current availability under the Credit
Facility and the sale of its interest in the spar facility will provide
necessary capital to complete the development of these discoveries and
fund other discretionary projects.
Beginning in October 2002, the Company received a series of inquiries
from the SEC regarding its Annual Report on Form 10-K for the year
ended December 31, 2001 requesting supplemental information concerning
operations in the Gulf of Mexico. The comment letters requested
information about the procedures used to classify the deepwater
reserves as proved and requested that the Company's financial
statements be restated to reflect the removal of the reserves
attributable to the Boomslang discovery as proved for all prior periods
during which such reserves were reported as proved. The Company has
reviewed the SEC comments with its independent petroleum reserve
engineers, Huddleston & Co., Inc. of Houston, Texas. Both Huddleston &
Co. and Callon believe that such deepwater reserves are properly
classified as proved. Discussions with the SEC are ongoing at this
time.
ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 143, Accounting for
Asset Retirement Obligations, ("SFAS 143") effective for fiscal years
beginning after June 15, 2002. As more fully discussed in Note 2 to the
consolidated financial statements included in Callon's 2002 Annual
Report, SFAS 143 essentially requires entities to record the fair value
of a liability for legal obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs.
Callon adopted the statement on January 1, 2003 resulting in a
cumulative effect of accounting change of $181,000, net of tax. See
Note 6.
In December 2002, the FASB issued SFAS No. 148, Accounting for
Stock-Based Compensation-Transition and Disclosure - an amendment of
FASB Statement No. 123 ("SFAS 148"). This statement provides
alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based compensation, along
with the requirement of disclosure in both annual and interim financial
statements about the method of accounting for stock-based compensation
and the effect on reported results. See Note 7.
7
In January 2003, the FASB issued Interpretation No. 46, "Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research
Bulletin (ARB) 51" ("FIN 46"). FIN 46 addresses consolidation by
business enterprises of variable interest entities ("VIEs"). The
primary objective of FIN 46 is to provide guidance on the
identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such
entities are known as VIEs. This guidance applies immediately to VIEs
created after January 31, 2003, and October 1, 2003 for VIEs existing
prior to February 1, 2003. The Company believes there will be no impact
on the financial statements as a result of the adoption of FIN 46.
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 period. 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 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 calculation for the three-month
and nine-month periods ended September 30, 2003 and 2002 due to the
antidilutive effect on income or loss per share. In addition, below are
the stock options, warrants and restricted stock that were not included
in the calculation for the three-month and nine-month periods ended
September 30, 2003 and 2002 due to the antidilutive effect on loss per
share.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
Stock options 75 -- 46 6
Warrants 424 477 423 355
Restricted Stock 257 98 240 105
8
A reconciliation of the basic and diluted earnings per share
computation is as follows (in thousands, except per share amounts):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
(a) Net income (loss) available
to common shares $ (2,346) $ (1,620) $ (2,249) $ (2,371)
Preferred dividends assuming
conversion of preferred stock
(if dilutive) -- -- -- --
-------- -------- -------- --------
(b) Income (loss) available to common
shares assuming conversion of
preferred stock (if dilutive) $ (2,346) $ (1,620) $ (2,249) $ (2,371)
======== ======== ======== ========
(c) Weighted average shares outstanding 13,679 13,377 13,640 13,342
Dilutive impact of stock options -- -- -- --
Dilutive impact of warrants -- -- -- --
Dilutive impact of restricted stock -- -- -- --
Convertible preferred stock
(if dilutive) -- -- -- --
-------- -------- -------- --------
(d) Total diluted shares 13,679 13,377 13,640 13,342
======== ======== ======== ========
Basic income (loss) per share (a/c) $ (0.17) $ (0.12) $ (0.17) $ (0.18)
Diluted income (loss) per share (b/d) $ (0.17) $ (0.12) $ (0.17) $ (0.18)
3. DERIVATIVES
The Company periodically uses derivative financial instruments to
manage oil and gas price risk. Settlements of gains and losses on
commodity price contracts are generally based upon the difference
between the contract price or prices specified in the derivative
instrument and a NYMEX price or other cash or futures index price.
In 2003 and 2002, the Company purchased and sold various derivatives
including put options and call options and elected not to designate
these derivative financial instruments as accounting hedges and
accordingly, accounted for these contracts under mark-to-market
accounting. In the third quarter of 2003 and 2002, the Company
recognized a gain of $13,331 and a loss of $18,500, respectively, to
record changes in fair value of these contracts. Year-to-date losses
were $466,538 and $788,450, respectively, through September 30, 2003
and 2002. There were no derivatives of this type remaining at September
30, 2003.
During 2002, the Company entered into no-cost natural gas collar
contracts in effect for February 2003 through October 2003. Remaining
open collar contracts at September 30, 2003 are for volumes of 250,000
Mcf for the month of October, with an average ceiling price of $4.76
and a floor price of $3.50. These contracts are accounted for as cash
flow hedges under SFAS 133. The Company recognized a loss of $318,750
and $2,932,000 in oil and gas sales related to the maturity of such
collars in the three-month and nine-month periods ended September 30,
2003, respectively. The fair value of remaining collar contracts at
September 30, 2003 was zero.
9
During 2003, the Company entered into additional no-cost natural gas
collar contracts in effect for May 2003 through October 2003. These
agreements were for volumes of 200,000 Mcf per month with a ceiling
price of $5.80 and a floor price of $5.00. The company elected not to
designate these derivative financial instruments as accounting hedges
and accordingly, accounted for these contracts under mark-to-market
accounting. For the three-month and nine-month periods ended September
30, 2003, the Company recognized a gain of approximately $205,200 and
$131,600, respectively. The fair value of these collar contracts at
September 30, 2003 was a current asset of $91,600.
In 2001, the Company entered into derivative contracts for 2002
production with Enron North America Corp. ("Enron"). In the fourth
quarter of 2001, the Company charged to expense (non-cash) $9.2 million
representing the fair market value of these derivatives as of September
30, 2001. As the contracts matured, the Company recorded non-cash
revenue each month. For the three-month and nine-month period ended
September 30, 2002, the Company recorded approximately $2.2 million and
$7.4 million, respectively, as non-cash oil and gas revenues. Also, in
the second quarter of 2002, the Company completed the sale of its
claims against Enron for $2.5 million and reported a pre-tax gain of
that amount.
Subsequent to September 30, 2003, Callon entered into a natural gas
collar in effect for December 2003 through March 2004 for 100,000 Mcf
per month. This collar has a floor of $5.25 per Mcf and a ceiling of
$7.25 per Mcf.
10
4. LONG-TERM DEBT
Long-term debt consisted of the following at:
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- -------------
(IN THOUSANDS)
Credit Facility (due June 30, 2004) $ 72,000 $ 65,000
Senior Notes, net of discount (due March 31, 2005) 89,319 87,020
10.125% Senior Subordinated Notes
net of discount (due July 31, 2004) 21,320 20,086
10.25% Senior Subordinated Notes
(due September 15, 2004) 40,000 40,000
11% Senior Subordinated Notes
(due December 15, 2005) 33,000 33,000
Capital lease 3,511 4,483
------------- -------------
Total debt 259,150 249,589
Less current portion:
Credit Facility 72,000 --
10.125% Senior Subordinated Notes 21,320 --
10.25% Senior Subordinated Notes 40,000 --
Capital lease 1,414 1,320
------------- -------------
Total current portion 134,734 1,320
------------- -------------
Long-term debt $ 124,416 $ 248,269
============= =============
Borrowings outstanding at September 30, 2003 under the Credit Facility
totaled $72.0 million with $3.0 million of borrowings available. The
borrowing base under the Credit Facility, which is re-determined
periodically, is based on an amount established by the bank group
after its evaluation of our proved oil and gas reserve values. The
Credit Facility has a maturity date of June 30, 2004 and is classified
as a current liability.
11
5. COMPREHENSIVE INCOME
A recap of the Company's comprehensive income (loss) is detailed below
(in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
Net income (loss) $ (2,026) $ (1,300) $ (1,291) $ (1,413)
Other comprehensive income (loss):
Change in unrealized derivatives'
fair value 554 (73) 469 16
Amortization of Enron derivatives -- (1,417) -- (4,835)
-------- -------- -------- --------
Total comprehensive income (loss) $ (1,472) $ (2,790) $ (822) $ (6,232)
======== ======== ======== ========
6. ASSET RETIREMENT OBLIGATIONS
As discussed in Note 1, the Company adopted SFAS 143 on January 1,
2003. The impact of adopting the statement resulted in a gain of
$181,000, net of tax, which is reported as a cumulative effect of
change in accounting principle.
Approximately $30.3 million was recorded as the present value of asset
retirement obligations on January 1, 2003 with the adoption of SFAS 143
related to the Company's oil and gas properties. Changes to the present
value of the asset retirement obligations due to the passage of time
are recorded as accretion expense in the Consolidated Statements of
Operations.
Assets, primarily U.S. Government securities, of approximately $7.0
million at September 30, 2003, are recorded as restricted investments.
These assets are held in abandonment trusts dedicated to pay future
abandonment costs of oil and gas properties in which the Company has
sold a net profits interest. If there is any excess of trust assets
over abandonment costs, the excess will be distributed to the net
profits interest owners.
The following table summarizes the activity for the Company's asset
retirement obligation for the nine-month period ended September 30,
2003:
NINE MONTHS ENDED
SEPTEMBER 30, 2003
------------------
Asset retirement obligation at beginning of period $ --
Liability recognized in transition 30,251
Accretion expense 2,214
Net profits interest accretion 337
Liabilities incurred 837
Liabilities settled (1,368)
Revisions to Estimate (1,239)
----------
Asset retirement obligation at end of period 31,032
Less: current asset retirement obligation (6,574)
----------
Long-term asset retirement obligation $ 24,458
==========
12
Pro forma net income and earnings per share are not presented for the
three and nine months ended September 30, 2002 because the pro forma
application of SFAS 143 to the prior period would not result in pro
forma net income and earnings per share materially different from the
actual amounts reported for the period in the accompanying Consolidated
Statements of Operations.
7. STOCK-BASED COMPENSATION
The Company has various stock plans ("the Plans") under which employees
and non-employee members of the Board of Directors of the Company and
its subsidiaries have been or may be granted certain equity
compensation. The Company has compensatory stock option plans in place
whereby participants have been or may be granted rights to purchase
shares of common stock of Callon. The Company accounts for stock- based
compensation in accordance with APB Opinion No. 25.
The Company's pro forma net income (loss) and net income (loss) per
share of common stock for the three-month and nine-month periods ended
September 30, 2003 and 2002, had compensation costs been recorded using
the fair value method in accordance with SFAS 123 - "Accounting for
Stock-Based Compensation," as amended by SFAS 148 - "Accounting for
Stock-Based Compensation-Transition and Disclosure - an amendment of
FASB Statement No. 123," are presented below pursuant to the disclosure
requirement of SFAS 148 (in thousands except per share data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- ----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Net income (loss) available to common-
as reported $ (2,346) $ (1,620) $ (2,249) $ (2,371)
Add: Stock-based compensation expense
included in net income as reported,
net of tax -- 68 17 260
Deduct: Total stock-based compensation
expense under fair value based method,
net of tax (36) (221) (165) (782)
--------- --------- --------- ---------
Net income (loss) available to common-
pro forma $ (2,382) $ (1,773) $ (2,397) $ (2,893)
========= ========= ========= =========
Net income (loss) per share available to common:
Basic-as reported $ (0.17) $ (0.12) $ (0.17) $ (0.18)
Basic-pro forma $ (0.17) $ (0.13) $ (0.18) $ (0.22)
Diluted-as reported $ (0.17) $ (0.12) $ (0.17) $ (0.18)
Diluted-pro forma $ (0.17) $ (0.13) $ (0.18) $ (0.22)
13
8. SALE OF PIPELINES AND OTHER FACILITIES
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 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.
In August 2003, Callon completed the sale of its Mr. Gus production
facility located in the Main Pass 163 Area. The Company received $1.5
million and the purchaser assumed all costs, estimated to be $1.0
million, associated with demobilization of the facility upon depletion
of the Main Pass 163 field. The Company entered into a charter lease
with the purchaser of the facility for a daily rental of $2,500 which
is cancelable at the Company's option after February, 2004. The
proceeds of the sale were treated as a reduction of the full cost pool.
14
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, 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, 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. At September 30, 2003, the
15
Company had $3.0 million of availability under its Credit Facility. Net cash and
cash equivalents during the nine months ended September 30, 2003 decreased by
$4.5 million and cash provided by operating activities totaled $31.2 million.
Net capital expenditures for the period totaled $37.0 million.
In 2002, the lenders under the Company's Credit Facility agreed to increase
availability under the revolving borrowing base from $50 million to $75 million.
The Credit Facility matures June 30, 2004 and accordingly, the balance
outstanding under the Credit Facility on September 30, 2003 of $72 million is
classified as a current liability on the Company's Consolidated Balance Sheet as
of September 30, 2003. The Company plans to enter into negotiations to secure a
new Credit Facility. In addition, the Company is currently evaluating
alternatives for refinancing some or all of the Senior Notes and Senior
Subordinated Notes, of which $61 million mature in 2004. However, the Company
anticipates that the cash flow from the deepwater discoveries and borrowing
capacity provided by the associated proved producing reserves being integrated
into the borrowing base of the Company's Credit Facility will provide funds for
future exploration and development activities, as well as provide a portion of
the resources necessary to fund repayment of the Notes upon maturity.
In September 2003, Callon announced that it signed an agreement to participate
in the formation of a limited liability company (LLC), which will own a 75%
undivided ownership interest in the deepwater production spar located at the
Company's Medusa field. The Company will contribute its 15% undivided ownership
interest in the spar to the LLC and will receive a 10% ownership interest in the
LLC. The LLC will earn a tariff based upon production volume throughput. Two
main conditions must be satisfied for closing of this transaction to occur. The
first is that the spar production facility shall have met certain operational
criteria. The second is securing non-recourse financing for at least one-half of
the spar's cost. The agreement is with Murphy Exploration & Production Company -
USA and Oceaneering International, Inc. If the transaction closes as currently
structured, Callon expects to realize cash proceeds of approximately $25 million
from the transfer of its 15% undivided ownership in the spar to the LLC. The
value of Callon's 10% ownership interest in the LLC is expected to be $8.4
million. Closing of this transaction is expected to occur in the fourth quarter
of 2003. The Medusa spar is moored in over 2,200 feet of water in the Gulf of
Mexico at Mississippi Canyon Block 582. It is in the final stages before the
commencement of production operations, initially from six wells.
Non-discretionary capital expenditures planned for the fourth quarter of 2003
include the development of the Medusa and Habanero deepwater discoveries,
currently scheduled to begin production in November and December of 2003,
respectively. The Company anticipates that cash flow generated during 2003, the
current availability under the Credit Facility and the sale of its interest in
the spar facility will provide necessary capital to complete the development of
these discoveries and fund other discretionary projects.
The completion of the Company's deepwater discoveries requires the construction
of expensive production facilities and pipelines, including the transportation,
installation and hookup of production facilities and the use of sub sea
completion techniques. The Company cannot estimate the timing of the
construction and hookup 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
16
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 may require the Company to
reduce future anticipated capital expenditures or seek additional sources of
liquidity to finance capital expenditures.
Beginning in October 2002, the Company received a series of inquiries from the
SEC regarding its Annual Report on Form 10-K for the year ended December 31,
2001 requesting supplemental information concerning operations in the Gulf of
Mexico. The comment letters requested information about the procedures used to
classify the deepwater reserves as proved and requested that the Company's
financial statements be restated to reflect the removal of the reserves
attributable to the Boomslang discovery as proved for all prior periods during
which such reserves were reported as proved. The Company has reviewed the SEC
comments with its independent petroleum reserve engineers, Huddleston & Co.,
Inc. of Houston, Texas. Both Huddleston & Co. and Callon believe that such
deepwater reserves are properly classified as proved. Discussions with the SEC
are ongoing at this time.
The following table describes our outstanding contractual obligations (in
thousands) as of September 30, 2003:
CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE
OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS
- ----------- ---------- ---------- ---------- ---------- ----------
Credit Facility $ 72,000 $ 72,000 $ -- $ -- $ --
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) 4,917 1,915 1,628 625 749
---------- ---------- ---------- ---------- ----------
$ 267,832 $ 136,830 $ 129,628 $ 625 $ 749
========== ========== ========== ========== ==========
CAPITAL EXPENDITURES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $39 million in the first nine months of
2003. The Company incurred approximately $23 million in the Gulf of Mexico
Deepwater Area primarily for development costs at the Company's Habanero and
Medusa discoveries. Interest of approximately $3.7 million and general and
administrative costs allocable directly to exploration and development projects
of approximately $6.4 million were capitalized for the first nine months of
2003. The Company's Gulf of Mexico Shelf Area expenditures account for the
remainder of the total capital expended.
The Company has forecast up to $15 million in capital expenditures for the
remainder of 2003. The major portion of the capital expenditure budget will be
used for development of the Company's Medusa and Habanero discoveries and the
drilling of a deepwater prospect. Discretionary projects of approximately $3
million may be added based on liquidity and other considerations.
17
RESULTS OF OPERATIONS
The following table sets forth certain unaudited operating information with
respect to the Company's oil and gas operations for the periods indicated:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- ---------------------
2003 2002 2003 2002
-------- -------- -------- --------
Net production : (b)
Oil (MBbls) 49 56 140 170
Gas (MMcf) 2,772 3,768 9,365 10,362
Total production (MMcfe) 3,068 4,104 10,206 11,382
Average daily production (MMcfe) 33.3 44.6 37.4 41.7
Average sales price: (a)(b)
Oil (Bbls) $ 26.76 $ 24.60 $ 28.15 $ 22.29
Gas (Mcf) $ 4.97 $ 3.24 $ 5.43 $ 2.98
Total (Mcfe) $ 4.92 $ 3.31 $ 5.37 $ 3.05
Oil and gas revenues:
Gas revenue $ 13,763 $ 14,380 $ 50,814 $ 38,325
Oil revenue 1,319 1,383 3,945 3,796
-------- -------- -------- --------
Total $ 15,082 $ 15,763 $ 54,759 $ 42,121
======== ======== ======== ========
Oil and gas production costs:
Lease operating expense $ 2,659 $ 2,832 $ 8,003 $ 8,201
Additional per Mcfe data:
Sale price $ 4.92 $ 3.31 $ 5.37 $ 3.05
Lease operating expense 0.87 0.69 0.78 0.72
-------- -------- -------- --------
Operating margin $ 4.05 $ 2.62 $ 4.59 $ 2.33
======== ======== ======== ========
Depletion, depreciation and amortization $ 2.09 $ 1.64 $ 2.03 $ 1.64
General and administrative $ 0.35 $ 0.26 $ 0.36 $ 0.31
(net of management fees)
(a) Includes hedging gains and losses.
(b) Includes volumes of 6 MMcf for the three-month period ended September 30,
2002 and 1,160 MMcf for the nine-month period ended September 30, 2002, at
an average price of $2.08 per Mcf associated with a volumetric production
payment.
18
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30,
2003 AND THE THREE MONTHS ENDED SEPTEMBER 30, 2002.
Oil and Gas Production and Revenues
Total oil and gas revenues decreased 4% from $15.8 million in the third quarter
of 2002 to $15.1 million in the third quarter of 2003. The decrease was due to
$2.2 million of non-cash revenue in 2002 related to the Enron derivatives
discussed in Note 3 to the Consolidated Financial Statements. Without this
non-cash item, revenues were $13.6 million for the third quarter of 2002
compared to $15.1 for the third quarter of 2003. The increase for the third
quarter of 2003 was due to higher realized prices for oil and gas which were
partially offset by lower production volumes.
Total production for the third quarter of 2003 decreased by 25% versus the third
quarter of 2002.
Gas production during the third quarter of 2003 totaled 2.8 Bcf and generated
$13.8 million in revenues compared to 3.8 Bcf and $12.2 million in revenues
during the same period in 2002. The average gas prices for the third quarter of
2003 were $4.97 per Mcf compared to $3.24 per Mcf for the same period last year.
The decrease in production was primarily due to downtime associated with
compressor repairs at the Mobile 952/953/955 fields and the depletion of the
lowest productive zone in the East Cameron 294 field during the third quarter of
2003. The well at East Cameron 294 was returned to production after a
recompletion to a behind pipe zone. Also, the sale of North and Northwest
Dauphin Island fields in the fourth quarter of 2002 and the normal and expected
declines in production from other properties contributed to the variance.
Oil production during the third quarter of 2003 totaled 49,000 barrels and
generated $1.3 million in revenues compared to 56,000 barrels and $1.4 million
in revenues for the same period in 2002. Average oil prices received in the
third quarter of 2003 were $26.76 per barrel compared to $24.60 per barrel in
2002. The decrease in production in the third quarter of 2003 compared to the
third quarter of 2002 was due primarily to normal and expected declines in
production from older properties.
Lease Operating Expenses
Lease operating expenses for the three-month period ending September 30, 2003
decreased to $2.7 million compared to $2.8 million for the same period in 2002.
The 6% decrease was due primarily to the sale of the North and Northwest Dauphin
Island fields in the fourth quarter of 2002.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three months ending September
30, 2003 and 2002 were $6.4 million and $6.8 million, respectively. The 5%
decrease was due to lower production volumes for the third quarter of 2003
compared to the same period last year. However, the decrease in depletion caused
by lower production was partially offset by a higher per unit depletion rate
resulting from a decrease in estimated proved reserves. The decrease in
estimated reserves was caused by a downward reserve revision for the Company's
Boomslang field on Ewing Bank 994 at the end of 2002.
19
Accretion Expense
Accretion expense of $772,000 represents accretion for Callon's asset retirement
obligations for the third quarter of 2003.
General and Administrative
General and administrative expenses, net of amounts capitalized, remained
constant at $1.1 million for the three-month periods ended September 30, 2003
and September 30, 2002.
Interest Expense
Interest expense increased by 6% to $7.6 million during the three months ended
September 30, 2003 from $7.1 million during the three months ended September 30,
2002. This is a result of higher debt levels.
COMPARISON OF RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003
AND THE NINE MONTHS ENDED SEPTEMBER 30, 2002.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 30% from $42.1 million in the first nine
months of 2002 to $54.8 million in the first nine months of 2003. Realized oil
and gas prices were substantially higher when compared to the same period in
2002 and accounted for the increase in revenue. Gas revenues for the first nine
months of 2002 included $7.4 million of non-cash revenue related to the Enron
derivatives discussed in Note 3 to the Consolidated Financial Statements.
Total production for the first nine months of 2003 decreased by 10% versus the
first nine months of 2002.
Gas production during the first nine months of 2003 totaled 9.4 Bcf and
generated $50.8 million in revenues compared to 10.4 Bcf and $30.9 million in
revenues during the same period in 2002. Average gas prices for the first nine
months of 2003 were $5.43 per Mcf compared to $2.98 per Mcf during the same
period last year. The decrease in production was primarily due to the depletion
of the lowest productive zone of the East Cameron 294 field. The well at East
Cameron 294 was returned to production after a recompletion to a behind pipe
zone in the third quarter of 2003. Also, the sale of North and Northwest Dauphin
Island fields in the fourth quarter of 2002 and the normal and expected declines
in production from other properties contributed to the variance.
Oil production during the first nine months of 2003 totaled 140,000 barrels and
generated $3.9 million in revenues compared to 170,000 barrels and $3.8 million
in revenues for the same period in 2002. Average oil prices received in the
first nine months of 2003 were $28.15 per barrel compared to $22.29 per barrel
in the first nine months of 2002. The decrease in production was primarily due
to downtime for maintenance to the facility and equipment at the Big Escambia
Creek Field operated by ExxonMobil Corporation and normal and expected declines
in production from older properties.
20
Lease Operating Expenses
Lease operating expenses, for the nine-month period ending September 30, 2003
decreased slightly by 2% to $8.0 million compared to $8.2 million for the same
period in 2002. The sale of North and Northwest Dauphin Island fields in the
fourth quarter of 2002 reduced lease operating expenses for this period.
However, this was offset by increased lease operating expenses for the Mobile
Block 864 area due to the implementation of the accelerated production program
in the second quarter of 2002.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the nine months ending September
30, 2003 and 2002 were $20.7 million and $18.8 million, respectively. The 10%
increase was due primarily to the downward reserve revisions for the Company's
Boomslang field at Ewing Bank 994 at the end of 2002. This decrease in estimated
proved reserves increased the depletable cost per unit of production.
Accretion Expense
Accretion expense of $2.2 million represents accretion for Callon's asset
retirement obligations for the nine-month period ended September 30, 2003.
General and Administrative
General and administrative expenses, net of amounts capitalized, increased by 6%
to $3.7 million during the nine months ended September 30, 2003 from $3.5
million during the nine months ended September 30, 2002. The increase was
primarily due to legal fees and directors' and officers' insurance expense.
Interest Expense
Interest expense increased by 19% to $22.2 million during the nine months ended
September 30, 2003 from $18.7 million during the nine months ended September 30,
2002. This is a result of higher debt levels.
21
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. The prices for oil and gas remain extremely volatile and
sometimes experience large fluctuations as a result of relatively small changes
in supply, weather conditions, economic conditions and government actions. From
time to time, the Company enters into derivative financial instruments (forward
sales or swaps) to hedge oil and gas price risks for the production volumes to
which the hedge relates. The hedges reduce the Company's exposure on the hedged
volumes to decreases in commodity prices and limit the benefit the Company might
otherwise have received from any increases in commodity prices on the hedged
volumes. The Company from time to time has acquired puts which reduce the
Company's exposure to decreases in commodity prices while allowing realization
of the full benefit from any increases in commodity prices.
The Company also enters into price "collars" to reduce the risk of changes in
oil and gas prices. Under these arrangements, no payments are due by either
party so long as the market price is above the floor price set in the collar and
below the ceiling. If the price falls below the floor, the counter-party to the
collar pays the difference to the Company and if the price is above the ceiling,
the counter-party receives the difference from the Company.
The Company enters into these various agreements from time to time to reduce the
effects of volatile oil and gas prices and does not enter into hedge
transactions for speculative purposes. However, certain of the Company's
positions may not be designated as hedges for accounting purposes.
See Note 3 to the Consolidated Financial Statements for a description of the
Company's hedged position at September 30, 2003. There have been no significant
changes in market risks faced by the Company since the end of 2002.
22
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures. Based on their evaluation as
of the end of the period covered by 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-15(e) and 15d-15(e) 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.
There were no changes in the Company's internal control over financial reporting
that occurred during the Company's last fiscal quarter that have materially
affected, or are reasonably likely to materially affect, the Company's internal
control over financial reporting.
23
CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a.) Exhibits
2. Plan of acquisition, reorganization, arrangement, liquidation
or succession*
3. Articles of Incorporation and By-Laws
3.1 Certificate of Incorporation of the Company, as
amended (incorporated by reference from Exhibit 3.1
of the Company's Registration Statement on Form S-4,
filed August 4, 1994, Reg. No. 33-82408)
3.2 Certificate of Merger of Callon Consolidated
Partners, L. P. with and into the Company dated
September 16, 1994 (incorporated by reference from
Exhibit 3.2 of the Company's Report on Form 10-K for
the fiscal year ended December 31, 1994, 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 Common 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, filed November
13, 1995, Reg. No. 33-96700)
4.3 Designation for Convertible, Exchangeable Preferred
Stock, Series A (incorporated by reference from
Exhibit
24
4.3 of the Company's Registration Statement on Form
S-1, 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 99.1 of the Company's
Registration Statement on Form 8-A, 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
25
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
(incorporated by reference to Exhibit 4.13 of the
Company's Form 10-Q for the period ended June 30,
2002, File No. 001-14039)
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)
8. Opinion re Tax matters*
9. Voting Trust Agreement*
10. Material contracts*
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*
31. Certifications
31.1 Certification of Chief Executive Officer pursuant to
Rule 13(a)-14(a)
31.2 Certification of Chief Financial Officer pursuant to
Rule 13(a)-14(a)
32. Section 1350 Certifications
26
32.1 Certification of Chief Executive Officer pursuant to
Rule 13(a)- 14(b)
32.2 Certification of Chief Financial Officer pursuant to
Rule 13(a)-14(b)
99. Additional exhibits*
(b) Reports on Form 8-K
Current Report on Form 8-K dated August 11, 2003, reporting Item 12.
Results of Operations and Financial Condition
Current Report on Form 8-K dated September 3, 2003, reporting Item 9.
Regulation FD Disclosure
*Inapplicable to this filing
27
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 12, 2003 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)
28
EXHIBIT INDEX
EXHIBIT NUMBER TITLE OF DOCUMENT
- -------------- -----------------
2. Plan of acquisition, reorganization, arrangement, liquidation
or succession*
3. Articles of Incorporation and By-Laws
3.1 Certificate of Incorporation of the Company, as
amended (incorporated by reference from Exhibit 3.1
of the Company's Registration Statement on Form S-4,
filed August 4, 1994, Reg. No. 33-82408)
3.2 Certificate of Merger of Callon Consolidated
Partners, L. P. with and into the Company dated
September 16, 1994 (incorporated by reference from
Exhibit 3.2 of the Company's Report on Form 10-K for
the fiscal year ended December 31, 1994, 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 Common 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, filed November
13, 1995, Reg. No. 33-96700)
4.3 Designation for Convertible, Exchangeable Preferred
Stock, Series A (incorporated by reference from
Exhibit 4.3 of the Company's Registration Statement
on Form S-1, 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
29
EXHIBIT NUMBER TITLE OF DOCUMENT
- -------------- -----------------
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 99.1 of the Company's
Registration Statement on Form 8-A, 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
(incorporated by reference to Exhibit 4.13 of the
30
EXHIBIT NUMBER TITLE OF DOCUMENT
- -------------- -----------------
Company's Form 10-Q for the period ended June 30,
2002, File No. 001-14039)
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)
8. Opinion re Tax matters*
9. Voting Trust Agreement*
11. Material contracts*
12. 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*
31. Certifications
31.1 Certification of Chief Executive Officer pursuant to
Rule 13(a)-14(a)
31.2 Certification of Chief Financial Officer pursuant to
Rule 13(a)-14(a)
32. Section 1350 Certifications
32.1 Certification of Chief Executive Officer pursuant to
Rule 13(a)- 14(b)
32.2 Certification of Chief Financial Officer pursuant to
Rule 13(a)-14(b)
99. Additional exhibits*
31