UNITED STATES
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 THE QUARTER ENDED JUNE 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 August 7, 2003, there were 13,968,368 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 June 30, 2003
and December 31, 2002 3
Consolidated Statements of Operations for Each of the
Three and Six Months in the Periods Ended June 30, 2003
and June 30, 2002 4
Consolidated Statements of Cash Flows for Each of the
Six Months in the Periods Ended June 30, 2003 and
June 30, 2002 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 13
Item 3. Quantitative and Qualitative Disclosures about Market Risk 20
Item 4. Controls and Procedures 21
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of the Security Holders 22
Item 6. Exhibits and Reports on Form 8-K 22
2
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31,
2003 2002
------------ ------------
ASSETS (UNAUDITED) (NOTE 1)
Current assets:
Cash and cash equivalents $ 4,927 $ 5,807
Accounts receivable 9,468 10,875
Other current assets 2,105 570
------------ ------------
Total current assets 16,500 17,252
------------ ------------
Oil and gas properties, full cost accounting method:
Evaluated properties 810,285 762,918
Less accumulated depreciation, depletion and amortization (433,108) (426,254)
------------ ------------
377,177 336,664
Unevaluated properties excluded from amortization 34,713 40,997
------------ ------------
Total oil and gas properties 411,890 377,661
------------ ------------
Pipeline and other facilities, net 803 853
Other property and equipment, net 1,748 1,890
Deferred tax asset 8,416 8,767
Long-term gas balancing receivable 1,076 761
Restricted investments 7,016 --
Other assets, net 2,638 3,429
------------ ------------
Total assets $ 450,087 $ 410,613
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 14,313 $ 12,498
Undistributed oil and gas revenues 1,749 1,109
Accrued net profits interest payable 2,320 1,707
Asset retirement obligations-current 10,093 --
Current maturities of long-term debt 71,378 1,320
------------ ------------
Total current liabilities 99,853 16,634
------------ ------------
Long-term debt-excluding current maturities 184,874 248,269
Accounts payable and accrued liabilities to be refinanced -- 3,861
Asset retirement obligations-long-term 21,868 --
Other long-term liabilities 2,127 889
------------ ------------
Total liabilities 308,722 269,653
------------ ------------
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; 13,931,607 and
13,900,466 shares outstanding at June 30, 2003 and at December 31, 2002,
respectively 139 139
Capital in excess of par value 158,522 158,370
Unearned compensation restricted stock (585) (826)
Accumulated other comprehensive income (loss) (554) (469)
Retained earnings (deficit) (16,163) (16,260)
------------ ------------
Total stockholders' equity 141,365 140,960
------------ ------------
Total liabilities and stockholders' equity $ 450,087 $ 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------- --------------------
2003 2002 2003 2002
-------- -------- -------- --------
Operating revenues:
Oil and gas sales $ 18,409 $ 15,304 $ 39,677 $ 26,358
-------- -------- -------- --------
Total operating revenues 18,409 15,304 39,677 26,358
-------- -------- -------- --------
Operating expenses:
Lease operating expenses 2,512 2,805 5,344 5,369
Depreciation, depletion and amortization 6,951 6,489 14,353 12,077
General and administrative 1,401 1,299 2,636 2,438
Accretion expense 727 -- 1,442 --
Loss on mark-to-market commodity derivative contracts 396 382 534 770
-------- -------- -------- --------
Total operating expenses 11,987 10,975 24,309 20,654
-------- -------- -------- --------
Income from operations 6,422 4,329 15,368 5,704
-------- -------- -------- --------
Other (income) expenses:
Interest expense 7,490 5,913 14,671 11,633
Other income (73) (252) (156) (822)
Gain on sale of pipeline -- (2,454) -- (2,454)
Gain on sale of Enron derivatives -- (2,479) -- (2,479)
-------- -------- -------- --------
Total other (income) expenses 7,417 728 14,515 5,878
-------- -------- -------- --------
Income (loss) before income taxes (995) 3,601 853 (174)
Income tax expense (benefit) (348) 1,260 299 (61)
-------- -------- -------- --------
Income (loss) before cumulative effect of change in
accounting principle (647) 2,341 554 (113)
Cumulative effect of change in accounting principle, net of tax -- -- 181 --
-------- -------- -------- --------
Net income (loss) (647) 2,341 735 (113)
Preferred stock dividends 319 319 638 638
-------- -------- -------- --------
Net income (loss) available to common shares $ (966) $ 2,022 $ 97 $ (751)
======== ======== ======== ========
Net income (loss) per common share:
Basic
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (0.07) $ 0.15 $ (0.01) $ (0.06)
Cumulative effect of change in accounting principle, net of tax -- -- 0.01 --
-------- -------- -------- --------
Net income (loss) available to common $ (0.07) $ 0.15 $ 0.00 $ (0.06)
======== ======== ======== ========
Diluted
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (0.07) $ 0.15 $ (0.01) $ (0.06)
Cumulative effect of change in accounting principle, net of tax -- -- 0.01 --
-------- -------- -------- --------
Net income (loss) available to common $ (0.07) $ 0.15 $ 0.00 $ (0.06)
======== ======== ======== ========
Shares used in computing net income (loss):
Basic 13,640 13,334 13,620 13,325
======== ======== ======== ========
Diluted 13,640 13,744 14,286 13,325
======== ======== ======== ========
The accompanying notes are an integral part of these financial statements.
4
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
SIX MONTHS ENDED
--------------------
JUNE 30, JUNE 30,
2003 2002
-------- --------
Cash flows from operating activities:
Net income (loss) $ 735 $ (113)
Adjustments to reconcile net income (loss) to cash provided by operating
activities:
Depreciation, depletion and amortization 14,902 13,028
Accretion expense 1,442 --
Amortization of deferred financing costs 3,123 1,762
Amortization of deferred production payment revenue -- (2,406)
Non-cash derivative income -- (5,258)
Non-cash mark-to-market commodity derivative contracts 534 770
Deferred income tax expense 299 (61)
Cumulative effect of change in accounting principle (181) --
Non-cash charge related to compensation plans 417 620
Gain on sale of pipeline -- (2,454)
Changes in current assets and liabilities:
Accounts receivable (353) (933)
Other current assets (1,367) (916)
Current liabilities 5,272 (1,529)
Change in gas balancing receivable (315) (275)
Change in gas balancing payable (357) (161)
Change in other long-term liabilities (7) 74
Change in other assets, net (271) (319)
-------- --------
Cash provided (used) by operating activities 23,873 1,829
-------- --------
Cash flows from investing activities:
Capital expenditures (24,675) (37,684)
Proceeds from sale of pipeline -- 6,784
Proceeds from sale of mineral interests -- 1,578
-------- --------
Cash provided (used) by investing activities (24,675) (29,322)
-------- --------
Cash flows from financing activities:
Change in accounts payable and accrued liabilities to be refinanced (3,861) (7,358)
Increase in debt 9,000 44,900
Payments on debt (4,000) --
Deferred financing cost -- (966)
Equity issued related to employee stock plans 62 16
Capital leases (641) (468)
Cash dividends on preferred stock (638) (638)
-------- --------
Cash provided (used) by financing activities (78) 35,486
-------- --------
Net increase (decrease) in cash and cash equivalents (880) 7,993
Cash and cash equivalents:
Balance, beginning of period 5,807 6,887
-------- --------
Balance, end of period $ 4,927 $ 14,880
======== ========
The accompanying notes are an integral part of these financial statements.
5
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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 six-month periods ended June 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 June 30, 2003, the Company had $5.0 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 June 30, 2003 of $70 million
is classified as a current liability on the Company's Consolidated
Balance Sheet as of June 30, 2003. The Company plans to enter into
negotiations to secure a new Credit Facility. The Company also is
reviewing financing alternatives that address the maturity of all its
debt.
Non-discretionary capital expenditures planned for the second half of
2003 include the development of the Medusa and Habanero deepwater
discoveries, currently scheduled to begin production in October 2003.
The Company anticipates that cash flow generated during 2003 and the
current availability under the Credit Facility will provide necessary
capital to complete the development of these discoveries and fund other
discretionary projects. The Company is also considering alternate
funding for the costs associated with development of the deepwater
discoveries.
The Company anticipates that the cash flow from these 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.
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
6
information about the procedures used to classify the deepwater
reserves as proved and requested that the financials 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 employee 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.
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 July 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 six-month periods ended June 30, 2003 and 2002 due to the
antidilutive effect on income or loss per share.
7
A reconciliation of the basic and diluted earnings per share
computation is as follows (in thousands, except per share amounts):
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ---------------------
2003 2002 2003 2002
--------- --------- --------- ---------
(a) Net income (loss) available
to common shares $ (966) $ 2,022 $ 97 $ (751)
Preferred dividends assuming
conversion of preferred stock
(if dilutive) -- -- -- --
--------- --------- --------- ---------
(b) Income (loss) available to common
shares assuming conversion of
preferred stock (if dilutive) $ (966) $ 2,022 $ 97 $ (751)
========= ========= ========= =========
(c) Weighted average shares outstanding 13,640 13,334 13,620 13,325
Dilutive impact of stock options -- -- 28 --
Dilutive impact of warrants -- 319 423 --
Dilutive impact of restricted stock -- 91 215 --
Convertible preferred stock
(if dilutive) -- -- -- --
--------- --------- --------- ---------
(d) Total diluted shares 13,640 13,744 14,286 13,325
========= ========= ========= =========
Basic income (loss) per share (a/c) $ (0.07) $ 0.15 $ 0.00 $ (0.06)
Diluted income (loss) per share (b/d) $ (0.07) $ 0.15 $ 0.00 $ (0.06)
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 second quarter of 2003 and 2002, the Company
recognized charges to expense of $171,023 and $381,950, respectively,
to record changes in fair value of these contracts. Year-to-date losses
were $479,869 and $769,950, respectively, through June 30, 2003 and
2002. There were no derivatives of this type remaining at June 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 June 30, 2003 are for volumes of 250,000 Mcf
per month from July through 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
$770,900 and $2,613,250 in oil and gas sales related to the maturity of
such collars in the three-month and six-month periods ended June 30,
2003, respectively. The fair value of remaining collar contracts at
June 30, 2003 is recorded in the balance sheet as a current liability
of $852,650.
8
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 six-month periods ended June 30,
2003, the Company recognized a loss of approximately $224,000 and
$53,600, respectively, to record the change in the fair value of these
contracts. The fair value of these collar contracts at June 30, 2003
was a current liability of $53,600.
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 six-month periods ended
June 30, 2002, the Company recorded approximately $2.3 million and $5.3
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.
9
4. LONG-TERM DEBT
Long-term debt consisted of the following at:
JUNE 30, DECEMBER 31,
2003 2002
-------- -----------
(IN THOUSANDS)
Credit Facility (due June 30, 2004) $ 70,000 $ 65,000
Senior Notes, net of discount (due March 31, 2005) 88,521 87,020
10.125% Senior Subordinated Notes
net of discount (due July 31, 2004) 20,889 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 3,842 4,483
-------- --------
256,252 249,589
Less: current portion 71,378 1,320
-------- --------
Long-term debt $184,874 $248,269
======== ========
Borrowings outstanding at June 30, 2003 under the Credit Facility
totaled $70.0 million with $5.0 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 has been reclassified
as a current liability.
5. COMPREHENSIVE INCOME
A recap of the Company's comprehensive income (loss) is detailed below
(in thousands):
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2003 2002 2003 2002
------- ------- ------- -------
Net income (loss) $ (647) $ 2,341 $ 735 $ (113)
Other comprehensive income (loss):
Change in unrealized derivatives'
fair value 162 88 (85) 88
Amortization of Enron derivatives -- (1,504) -- (3,418)
------- ------- ------- -------
Total comprehensive income (loss) $ (485) $ 925 $ 650 $(3,443)
======= ======= ======= =======
10
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 June 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 six-month period ended June 30, 2003:
SIX MONTHS ENDED
JUNE 30, 2003
----------------
Asset retirement obligation at beginning of period $ --
Liability recognized in transition 30,251
Accretion expense 1,442
Net profits interest accretion 172
Liabilities incurred 112
Liabilities settled (16)
--------
Asset retirement obligation at end of period 31,961
Less: current asset retirement obligation (10,093)
--------
Long-term asset retirement obligation $ 21,868
========
Pro forma net income and earnings per share are not presented for the
three and six months ended June 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.
11
The Company's pro forma net income (loss) and net income (loss) per
share of common stock for the three-month and six-month periods ended
June 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ---------------------
2003 2002 2003 2002
--------- --------- -------- ---------
Net income (loss) available to common-
as reported $ (966) $ 2,022 $ 97 $ (751)
Add: Stock-based compensation expense
included in net income as reported, net of tax 7 96 17 192
Deduct: Total stock-based compensation
expense under fair value based method, net of tax (60) (289) (129) (561)
--------- --------- ------- ---------
Net income (loss) available to common-
pro forma $ (1,019) $ 1,829 $ (15) $ (1,120)
========= ========= ======= =========
Net income (loss) per share available to common:
Basic-as reported $ (0.07) $ 0.15 $ 0.00 $ (0.06)
Basic-pro forma $ (0.07) $ 0.14 $ 0.00 $ (0.08)
Diluted-as reported $ (0.07) $ 0.15 $ 0.00 $ (0.06)
Diluted-pro forma $ (0.07) $ 0.13 $ 0.00 $ (0.08)
8. 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 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.
12
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. At June 30, 2003, the Company had $5.0 million of availability under
its Credit Facility. Net cash and cash equivalents during the six months ended
13
June 30, 2003 decreased by $0.9 million and cash provided by operating
activities totaled $23.9 million. Net capital expenditures for the period
totaled $24.7 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 June 30, 2003 of $70 million is
classified as a current liability on the Company's Consolidated Balance Sheet as
of June 30, 2003. The Company plans to enter into negotiations to secure a new
Credit Facility. The Company also is reviewing financing alternatives that
address the maturity of all its debt.
Non-discretionary capital expenditures planned for the second half of 2003
include the development of the Medusa and Habanero deepwater discoveries,
currently scheduled to begin production in October 2003. The Company anticipates
that cash flow generated during 2003 and the current availability under the
Credit Facility will provide necessary capital to complete the development of
these discoveries and fund other discretionary projects. The Company is also
considering alternate funding for the costs associated with development of the
deepwater discoveries.
The Company anticipates that the cash flow from these 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.
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 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, which may not be available.
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 financials 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.
14
The following table describes our outstanding contractual obligations (in
thousands) as of June 30, 2003:
CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE
OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS
-------- --------- --------- --------- ----------
Credit Facility $ 70,000 $ 70,000 $ -- $ -- $ --
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) 5,412 1,940 1,995 674 803
-------- -------- -------- -------- --------
$266,327 $ 71,940 $192,910 $ 674 $ 803
======== ======== ======== ======== ========
CAPITAL EXPENDITURES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $24.7 million in the first six months of
2003. The Company incurred approximately $13.3 million in the Gulf of Mexico
Deepwater Area primarily for development costs at the Company's Habanero and
Medusa discoveries. Interest of approximately $2.5 million and general and
administrative costs allocable directly to exploration and development projects
of approximately $4.4 million were capitalized for the first six months of 2003.
The Gulf of Mexico Shelf Area expenditures account for the remainder of the
total capital expended and were primarily associated with the Ship Shoal Blocks
28/35 development.
For the remainder of the year, the Company will continue evaluating property
acquisitions and drilling opportunities. The Company has forecast up to $31
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 three deepwater prospects of
which two are located in the Medusa area. Discretionary projects of
approximately $5 million may be added based on liquidity and other
considerations.
15
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- --------------------
2003 2002 2003 2002
--------- ------- -------- ------
Production volumes: (b)
Oil (MBbls) 46 60 91 114
Gas (MMcf) 3,166 3,565 6,593 6,594
Total production (MMcfe) 3,441 3,925 7,138 7,278
Average daily production (MMcfe) 37.8 43.1 39.4 40.2
Average sales price: (a)(b)
Oil (Bbls) $ 26.59 $ 23.41 $ 28.93 $21.16
Gas (Mcf) 5.44 3.25 5.62 2.83
Total (Mcfe) 5.35 3.31 5.56 2.90
Average costs (per Mcfe):
Lease operating expenses $ 0.73 $ 0.72 $ 0.75 $ 0.73
Depletion 2.01 1.64 2.00 1.64
General and administrative (net of management fees) 0.41 0.33 0.37 0.33
(a) Includes hedging gains and losses.
(b) Includes volumes of 580 MMcf for the three-month period ended June
30, 2002 and 1,154 MMcf for the six-month period ended June 30,
2002, at an average price of $2.08 per Mcf associated with a
volumetric production payment.
16
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2003 AND
THE THREE MONTHS ENDED JUNE 30, 2002.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 20% from $15.3 million in the second
quarter of 2002 to $18.4 million in the second quarter of 2003. Oil and gas
prices were substantially higher when compared to the same period in 2002 and
accounted for the increase in revenue. Oil and gas revenues for the second
quarter of 2002 included $2.3 million related to the Enron derivatives referred
to in Note 3 to the Consolidated Financial Statements.
Total production for the second quarter of 2003 decreased by 12% versus the
second quarter of 2002.
Gas production during the second quarter of 2003 totaled 3.2 Bcf and generated
$17.2 million in revenues compared to 3.6 Bcf and $13.9 million in revenues
during the same period in 2002. The average gas prices for the second quarter of
2003 averaged $5.44 per Mcf compared to $3.25 per Mcf for the same period last
year. The decrease in production in the second quarter of 2003 compared to the
second quarter of 2002 was due primarily to the sale of the North and Northwest
Dauphin Island fields in the fourth quarter of 2002 and normal and expected
declines in production from older properties.
Oil production during the second quarter of 2003 totaled 46,000 barrels and
generated $1.2 million in revenues compared to 60,000 barrels and $1.4 million
in revenues for the same period in 2002. Average oil prices received in the
second quarter of 2003 were $26.59 per barrel compared to $23.41 per barrel in
2002. The decrease in production in the second quarter of 2003 compared to the
second quarter of 2002 was due primarily 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.
Lease Operating Expenses
Lease operating expenses, for the three-month period ending June 30, 2003
decreased to $2.5 million compared to $2.8 million for the same period in 2002.
The 10% 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 June 30,
2003 and 2002 were $7.0 million and $6.5 million, respectively. The 7% increase
was due primarily to the downward reserve revisions at Boomslang at the end of
2002. This decrease in estimated proved reserves, over which depletable costs
are amortized, increased the per unit depletion rate.
Accretion Expense
Accretion expense of $727,000 represents accretion for Callon's asset retirement
obligations for the second quarter of 2003.
17
General and Administrative
General and administrative expenses, net of amounts capitalized, increased
slightly to $1.4 million from $1.3 million for the three-month periods ended
June 30, 2003 and June 30, 2002, respectively. The 8% increase was primarily due
to legal fees and directors' and officers' insurance expense.
Interest Expense
Interest expense increased by 26% to $7.5 million during the three months ended
June 30, 2003 from $5.9 million during the three months ended June 30, 2002.
This is a result of higher debt levels.
COMPARISON OF RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2003 AND
THE SIX MONTHS ENDED JUNE 30, 2002.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 50% from $26.4 million in the first half of
2002 to $39.7 million in the first half of 2003. Oil and gas prices were
substantially higher when compared to the same period in 2002 and accounted for
the increase in revenue. Oil and gas revenues for the first half of 2002
included $5.3 million related to the Enron derivatives referred to in Note 3 to
the Consolidated Financial Statements.
Total production for the first half of 2003 decreased by 2% versus the first
half of 2002.
Gas production during the first half of 2003 totaled 6.6 Bcf and generated $37.1
million in revenues compared to 6.6 Bcf and $23.9 million in revenues during the
same period in 2002. Average gas prices received for the first half of 2003
averaged $5.62 per Mcf compared to $2.83 per Mcf during the same period last
year.
Oil production during the first half of 2003 totaled 91,000 barrels and
generated $2.6 million in revenues compared to 114,000 barrels and $2.4 million
in revenues for the same period in 2002. Average oil prices received in the
first half of 2003 were $28.93 per barrel compared to $21.16 per barrel in the
first half 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.
Lease Operating Expenses
Lease operating expenses, for the six-month period ending June 30, 2003
decreased slightly by 1% to $5.3 million compared to $5.4 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 acceleration program in the
second quarter of 2002.
18
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the six months ending June 30, 2003
and 2002 were $14.4 million and $12.1 million, respectively. The 19% increase
was due primarily to the downward reserve revisions at Boomslang at the end of
2002. This decrease in estimated proved reserves, over which depletable costs
are amortized, increased the per unit depletion rate.
Accretion Expense
Accretion expense of $1.4 million represents accretion for Callon's asset
retirement obligations for the six-month period ended June 30, 2003.
General and Administrative
General and administrative expenses, net of amounts capitalized, increased by 8%
to $2.6 million during the six months ended June 30, 2003 from $2.4 million
during the six months ended June 30, 2002. The increase was primarily due to
legal fees and directors' and officers' insurance expense.
Interest Expense
Interest expense increased by 26% to $14.7 million during the six months ended
June 30, 2003 from $11.6 million during the six months ended June 30, 2002. This
is a result of higher debt levels.
19
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 June 30, 2003. There have been no significant
changes in market risks faced by the Company since the end of 2002.
20
ITEM 4. CONTROLS AND PROCEDURES
(a) 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.
(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.
21
CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
The Company held its annual meeting of shareholders on May 2, 2003. At the
annual meeting, the Class III directors of the board of directors of the Company
were elected to hold office until the Company's 2006 annual meeting of
shareholders. The votes cast for each of the Class III directors proposed by the
Company's definitive proxy statement on Schedule 14A, out of a total of
13,919,457 shares outstanding, were as follows:
AGAINST or
FOR WITHHELD ABSTAIN
---------- ---------- -------
Fred L. Callon 12,408,294 290,671 --
Dennis W. Christian 12,320,979 377,986 --
The shareholders of the Company also approved the appointment of Ernst & Young
LLP as the Company's independent auditors for 2003. There were 12,492,249 votes
in favor of approving the appointment of Ernst & Young LLP as the Company's
independent auditors, 99,893 votes against or withheld and 106,823 abstentions.
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
22
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 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)
23
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
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)
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*
24
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*
(b) Reports on Form 8-K
Current Report on Form 8-K dated May 13, 2003, reporting Item 12.
Results of Operations and Financial Condition
*Inapplicable to this filing
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CALLON PETROLEUM COMPANY
Date: August 11, 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)
26
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)
27
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
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)
28
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)
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*
29