SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
FORM 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR QUARTER ENDED MARCH 31, 2002 COMMISSION FILE NUMBER 001-14039
CALLON PETROLEUM COMPANY
------------------------
(Exact name of Registrant as specified in its charter)
DELAWARE 64-0844345
------------------------------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
200 NORTH CANAL STREET
NATCHEZ, MISSISSIPPI 39120
--------------------------
(Address of principal executive offices)(Zip code)
(601) 442-1601
--------------
(Registrant's telephone number,
including area code)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X . No .
--- ---
As of May 8, 2002, there were 13,439,149 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 March 31, 2002
and December 31, 2001 3
Consolidated Statements of Operations for Each of the
Three Months in the Periods Ended March 31, 2002
and March 31, 2001 4
Consolidated Statements of Cash Flows for Each of the
Three Months in the Periods Ended March 31, 2002 and
March 31, 2001 5
Notes to Consolidated Financial Statements 6
Management's Discussion and Analysis of
Financial Condition and Results of Operations 10
Quantitative and Qualitative Disclosures about Market Risk 14
PART II. OTHER INFORMATION 15
2
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
MARCH 31, DECEMBER 31,
2002 2001
--------- --------------
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents $ 3,579 $ 6,887
Accounts receivable 5,194 5,908
Other current assets 657 209
--------- --------------
Total current assets 9,430 13,004
--------- --------------
Oil and gas properties, full cost accounting method:
Evaluated properties 728,458 704,937
Less accumulated depreciation, depletion and amortization (404,843) (399,339)
--------- --------------
323,615 305,598
Unevaluated properties excluded from amortization 40,751 37,560
--------- --------------
Total oil and gas properties 364,366 343,158
--------- --------------
Pipeline and other facilities, net 5,279 5,364
Other property and equipment, net 2,315 2,455
Deferred tax asset 6,750 4,399
Long-term gas balancing receivable 475 473
Other assets, net 2,925 3,242
--------- --------------
Total assets $ 391,540 $ 372,095
========= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 5,302 $ 9,985
Undistributed oil and gas revenues 1,042 1,131
Accrued net profits interest payable 1,427 1,501
Accounts payable and accrued liabilities to be refinanced 9,566 9,558
Current maturities of long-term debt 66,498 37,345
--------- --------------
Total current liabilities 83,835 59,520
--------- --------------
Long-term debt-excluding current maturities 157,989 157,366
Capital leases 4,055 4,367
Deferred revenue on sale of production payment 1,214 2,406
Accrued retirement benefits 136 137
Long-term gas balancing payable 937 1,075
--------- --------------
Total liabilities 248,166 224,871
--------- --------------
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; 13,424,216 and
13,397,706 shares outstanding at March 31, 2002 and at December 31, 2001,
respectively 134 134
Treasury stock (99,078 shares at cost) (1,183) (1,183)
Unearned compensation restricted stock (1,012) --
Capital in excess of par value 157,456 155,608
Accumulated other comprehensive income 4,058 5,971
Retained earnings (deficit) (16,085) (13,312)
--------- --------------
Total stockholders' equity 143,374 147,224
--------- --------------
Total liabilities and stockholders' equity $ 391,540 $ 372,095
========= ==============
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
MARCH 31,
--------------------
2002 2001
-------- --------
Revenues:
Oil and gas sales $ 11,054 $ 20,177
Loss on mark-to-market commodity
derivative contracts (388) --
Interest and other 570 635
-------- --------
Total revenues 11,236 20,812
-------- --------
Costs and expenses:
Lease operating expenses 2,564 2,673
Depreciation, depletion and amortization 5,588 4,897
General and administrative 1,139 1,123
Interest 5,720 2,621
-------- --------
Total costs and expenses 15,011 11,314
-------- --------
Income (loss) from operations (3,775) 9,498
Income tax expense (benefit) (1,321) 3,324
-------- --------
Net income (loss) (2,454) 6,174
Preferred stock dividends 319 319
-------- --------
Net income (loss) available to common shares $ (2,773) $ 5,855
======== ========
Net income (loss) per common share:
Basic $ (0.21) $ 0.44
======== ========
Diluted $ (0.21) $ 0.41
======== ========
Shares used in computing net income (loss) per common share:
Basic 13,315 13,253
======== ========
Diluted 13,315 14,908
======== ========
The accompanying notes are an integral part of these financial statements.
4
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
THREE MONTHS ENDED
----------------------
MARCH 31, MARCH 31,
2002 2001
--------- ---------
Cash flows from operating activities:
Net income (loss) $ (2,454) $ 6,174
Adjustments to reconcile net income (loss) to cash provided by operating
activities:
Depreciation, depletion and amortization 5,765 5,027
Amortization of deferred costs 1,128 369
Amortization of deferred production payment revenue (1,192) (1,191)
Non-cash derivative income (2,943) (243)
Mark-to-market commodity derivative contracts 388 --
Deferred income tax expense (1,321) 3,324
Non-cash charge related to compensation plans 242 240
Changes in current assets and liabilities:
Accounts receivable 714 110
Advance to operators -- (127)
Other current assets (836) (87)
Current liabilities (4,260) (8,439)
Change in gas balancing receivable (2) 22
Change in gas balancing payable (138) 530
Change in other long-term liabilities (1) (1)
Change in other assets, net (188) (213)
--------- ---------
Cash provided (used) by operating activities (5,098) 5,495
--------- ---------
Cash flows from investing activities:
Capital expenditures (26,748) (24,071)
--------- ---------
Cash provided (used) by investing activities (26,748) (24,071)
--------- ---------
Cash flows from financing activities:
Change in accounts payable and accrued liabilities to be refinanced -- 7,296
Increase in debt 29,000 6,000
Equity issued related to employee stock plans 16 179
Capital leases (159) --
Cash dividends on preferred stock (319) (319)
--------- ---------
Cash provided (used) by financing activities 28,538 13,156
--------- ---------
Net increase (decrease) in cash and cash equivalents (3,308) (5,420)
Cash and cash equivalents:
Balance, beginning of period 6,887 11,876
--------- ---------
Balance, end of period $ 3,579 $ 6,456
========= =========
The accompanying notes are an integral part of these financial statements.
5
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2002
1. BASIS OF PRESENTATION
The financial information presented as of any date other than December
31, has been prepared from the books and records without audit.
Financial information as of December 31, has been derived from the
audited financial statements of the Company, but does not include all
disclosures required by generally accepted accounting principles. In
the opinion of management, all adjustments, consisting only of normal
recurring adjustments, necessary for the fair presentation of the
financial information for the periods indicated, have been included.
For further information regarding the Company's accounting policies,
refer to the Consolidated Financial Statements and related notes for
the year ended December 31, 2001 included in the Company's Annual
Report on Form 10-K dated March 29, 2002.
As discussed in the Company's Annual Report on Form 10-K dated March
29, 2002, the $36.0 million of the 10.125% Senior Subordinated Notes
(the "Notes") will mature on September 15, 2002. When these Notes are
extended or redeemed, maturity of the Company's $75 million Credit
Facility with First Union National Bank (the "Credit Facility"),
currently scheduled for July 31, 2002, can be extended until July 31,
2004. The Company is currently evaluating options for redeeming the
Notes. These options include, but are not limited to, (i) negotiated
extensions of the maturity of a portion of these Notes, (ii) increased
availability under the Credit Facility and (iii) the issuance of
additional senior notes.
Capital commitments in 2002 include non-discretionary capital
expenditures and the redemption or extension of the $36.0 million of
Notes. Capital expenditures include completion of the Medusa deepwater
discovery, currently scheduled to begin production late in the fourth
quarter of 2002. The Company expects that, in addition to cash flow
generated during 2002 and current availability under the Credit
Facility, approximately $27 million of additional funding will be
required to finance the Company's capital commitments. The Company
expects these requirements to be met through the options discussed
above. As of early May 2002, the Company has obtained a commitment from
holders of approximately $15.9 million of the Notes to extend the
maturity of the Notes until 2004.
The Company anticipates that these funding sources will provide
necessary capital to enable the Company to continue its operational
activities until such time as production from the Medusa discovery
begins. At that time, the Company anticipates that the Medusa reserves
and production will be integrated into the borrowing base of the
Company's Credit Facility and will provide additional available
borrowing capacity. This increase in borrowing capacity as well as
significant additional cash flow from the new production will provide
funds for future discretionary capital expenditures.
Effective January 1, 2001, the Company adopted Statement of Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended ("SFAS 133"). SFAS 133 establishes accounting
and reporting standards requiring that derivative instruments,
including certain derivative instruments embedded in other contracts,
be recorded in the balance sheet as either an asset or a liability
measured at its fair value. Changes in the value of derivatives that
qualify as
6
cash flow hedges to the extent effective are reported in other
comprehensive income, a component of stockholders' equity, until
realized. See Note 3.
2. PER SHARE AMOUNTS
Basic earnings per common share were computed by dividing net income by
the weighted average number of shares of common stock outstanding
during the quarter. Diluted earnings or loss per common share were
determined on a weighted average basis using common shares issued and
outstanding adjusted for the effect of stock options considered common
stock equivalents computed using the treasury stock method and the
effect of the convertible preferred stock (if dilutive). The earnings
per share computation for the three-month period ended March 31, 2001
includes the conversion of preferred stock in the computation of
diluted income per share because they were dilutive. The conversion of
the preferred stock was not included in the calculation for the quarter
ended March 31, 2002 due to their antidilutive effect on diluted income
or loss per share.
A reconciliation of the basic and diluted earnings per share
computation is as follows (in thousands, except per share amounts):
THREE MONTHS ENDED
MARCH 31,
---------------------------
2002 2001
--------- -------
(a) Net income (loss) available
for common stock $ (2,733) $ 5,855
Preferred dividends assuming conversion
of preferred stock (if dilutive) $ -- $ 319
(b) Income (loss) available for common stock
assuming conversion of preferred
stock (if dilutive) $ (2,733) $ 6,174
(c) Weighted average shares outstanding 13,315 13,253
Dilutive impact of stock options -- 290
Convertible preferred stock (if dilutive) -- 1,365
(d) Total diluted shares 13,315 14,908
Stock options and warrants excluded due to
antidilutive impact 2,598 150
Basic income (loss) per share (a/c) $ (0.21) $ 0.44
Diluted income (loss) per share (b/d) $ (0.21) $ 0.41
3. DERIVATIVES
The Company periodically uses derivative financial instruments to
manage oil and gas price risk.
In March 2002, the Company purchased put options, which established an
average floor price of $2.65 per Mcf on 6.1 Bcf of production from
April 2002 through September 2002. The Company elected not to designate
these derivative financial instruments as accounting hedges and
accordingly, accounted for these contracts under mark-to-market
accounting. The Company recognized an unrealized loss of approximately
$388,000 in the first quarter of 2002 related to these derivative
contracts. Fair value of these puts is $443,000 at March 31, 2002.
In April 2001, the Company entered into derivative contracts for 2002
production with Enron North America Corp. ("Enron derivatives"). Enron
North America Corp. filed for protection
7
under the bankruptcy laws in late 2001. As a result of the credit risk
associated with these Enron derivatives, hedge accounting was not
available due to ineffectiveness as of September 30, 2001 and the
contracts as of December 31, 2001 have been marked to the market. In
the fourth quarter of 2001, the Company charged to expense (non-cash)
$9.2 million related to these Enron derivatives. The Company has no
other contracts with Enron or its subsidiaries.
The $5,971,000 (net of tax) recorded in other comprehensive income at
December 31, 2001 is related to the fair value as of September 30, 2001
of the natural gas collar contracts with Enron North America Corp.,
which mature in 2002. As the contracts mature in 2002, the Company will
record non-cash revenue each month, offsetting the amounts in other
comprehensive income related to the derivatives. The Company recorded
approximately $2.9 million related to these Enron derivatives in the
first quarter of 2002 as oil and gas revenue.
The Company has no other derivative contracts.
4. LONG-TERM DEBT
Approximately $7.3 million at March 31, 2001 related to long-term
assets, primarily oil and gas properties, were financed subsequent to
quarter-end with long-term debt and have been reclassified as
long-term. The 2002 amount of $9.6 million is included in current
liabilities to correspond to the maturity of the Credit Facility.
5. COMPREHENSIVE INCOME
An analysis of the Company's comprehensive income is detailed below (in
thousands):
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2002 MARCH 31, 2001
------------------ ------------------
Net income (loss) $ (2,454) $ 6,174
Other comprehensive income (loss):
Cumulative effect of change in
accounting principle $ -- $ (3,764)
Change in unrealized derivatives'
fair value -- 3,199
Amortization of Enron derivatives (1,913) --
------------------ ------------------
(1,913) (565)
------------------ ------------------
Total comprehensive income $ (4,367) $ 5,609
================== ==================
6. 2002 STOCK PLAN
In February 2002, the Board of Directors of the Company approved and
adopted the 2002 Stock Incentive Plan (the "2002 Plan"). Pursuant to
the 2002 Plan, 350,000 shares of common stock have been reserved for
issuance upon the exercise of options or for grants of stock options,
stock appreciation rights or units, bonus stock, or performance shares
or units.
In the first quarter of 2002, the Company awarded 300,000 shares of
restricted stock from the 2002 Plan to certain officers and employees
to be issued as vested. These shares will vest over a three-year period
(one third in each year) beginning in November 2002. The deferred
compensation portion of this grant will be amortized to expense over
the vesting period.
8
7. SUBSEQUENT EVENT-SALE OF PIPELINES
In May 2002, the Company completed the sale of its natural gas pipeline
at the North Dauphin Island field in Mobile Bay as well as its interest
in a pipeline that is currently not in use, in the Mobile 908 Area. The
Company received $7.0 million and the pipelines had a net book value of
$4.3 million.
9
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This report includes "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. All statements other than statements of historical facts included in
this report, including statements regarding the Company's financial position,
adequacy of resources, estimated reserve quantities, business strategies, plans,
objectives and expectations for future operations and covenant compliance, are
forward-looking statements. The Company can give no assurances that the
assumptions upon which such forward-looking statements are based will prove to
have been correct. Important factors that could cause actual results to differ
materially from the Company's expectations ("Cautionary Statements") are
disclosed below, in the section "Risk Factors" included in the Company's Form
10-K, elsewhere in this report and from time to time in other filings made by
the Company with the Securities and Exchange Commission. All subsequent written
and oral forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified by the Cautionary Statements.
GENERAL
The Company's revenues, profitability and future growth and the carrying value
of its oil and gas properties are substantially dependent on prevailing prices
of oil and gas and its ability to find, develop and acquire additional oil and
gas reserves that are economically recoverable. The Company's ability to
maintain or increase its borrowing capacity and to obtain additional capital on
attractive terms is also influenced by oil and gas prices. Prices for oil and
gas are subject to large fluctuations in response to relatively minor changes in
the supply of and demand for oil and gas, market uncertainty and a variety of
additional factors beyond the control of the Company. These factors include
weather conditions in the United States, the condition of the United States
economy, the actions of the Organization of Petroleum Exporting Countries,
governmental regulations, political stability in the Middle East and elsewhere,
the foreign supply of oil and gas, the price of foreign imports and the
availability of alternate fuel sources. Any substantial and extended decline in
the price of oil or gas would have an adverse effect on the Company's carrying
value of its proved reserves, borrowing capacity, revenues, profitability and
cash flows from operations. The Company uses derivative financial instruments
for price protection purposes on a limited amount of its future production and
does not use them for trading purposes.
The following discussion is intended to assist in an understanding of the
Company's historical financial positions and results of operations. The
Company's historical financial statements and notes thereto included elsewhere
in this quarterly report contains detailed information that should be referred
to in conjunction with the following discussion.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of capital are its cash flows from operations,
borrowings from financial institutions and the sale of debt and equity
securities. Net cash and cash equivalents during the three months ended March
31, 2002 decreased by $3.3 million and net cash flows from operations before
working capital changes totaled $.8 million. Net capital expenditures from the
cash flow statement for the period totaled $26.7 million.
10
As discussed in the Company's Annual Report on Form 10-K dated March 29, 2002,
the $36.0 million of Notes will mature on September 15, 2002. When these Notes
are extended or redeemed, maturity of the Credit Facility, currently scheduled
for July 31, 2002, can be extended until July 31, 2004. The Company is currently
evaluating options for redeeming the Notes. These options include, but are not
limited to, (i) negotiated extensions of the maturity of a portion of these
Notes, (ii) increased availability under the Credit Facility and (iii) the
issuance of additional senior notes.
Capital commitments in 2002 include non-discretionary capital expenditures and
the redemption or extension of the $36.0 million of Notes. Capital expenditures
include completion of the Medusa deepwater discovery, currently scheduled to
begin production late in the fourth quarter of 2002. The Company expects that,
in addition to cash flow generated during 2002 and current availability under
the Credit Facility, approximately $27 million of additional funding will be
required to finance the Company's capital commitments. The Company expects these
requirements to be met through the options discussed above. As of early May
2002, the Company has obtained a commitment from holders of approximately $15.9
million of the Notes to extend the maturity of the Notes until 2004.
The Company anticipates that these funding sources will provide necessary
capital to enable the Company to continue its operational activities until such
time as production from the Medusa discovery begins. At that time, the Company
anticipates that the Medusa reserves and production will be integrated into the
borrowing base of the Company's Credit Facility and will provide additional
available borrowing capacity. This increase in borrowing capacity as well as
significant additional cash flow from the new production will provide funds for
future discretionary capital expenditures.
At March 31, 2002, the Company had working capital of $1.7 million, excluding
current maturities of long-term debt and liabilities to be refinanced.
CAPITAL EXPENDITURES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $26.7 million in the first three months of
2002. The Company incurred approximately $11.4 million in the Gulf of Mexico
Shelf Area, including $5.1 million related to the production facility under
construction in the first quarter of 2002 in the Mobile Block 952/953/955 area.
The Gulf of Mexico Deepwater area expenditures accounted for the remainder of
the total capital expended, primarily for additional development costs for
production facilities at the Company's Medusa discovery. Interest and general
and administrative costs allocable directly to exploration and development
projects were approximately $3.9 million for the first three months of 2002.
For the remainder of the year, the Company will continue evaluating property
acquisitions and drilling opportunities. The Company has forecasted up to $25.9
million in capital expenditures for the remainder of 2002. The major portion of
the capital expenditure budget will be used for development of the Company's
Medusa discovery.
11
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
MARCH 31,
--------------------------
2002(a)(b) 2001(a)(b)
---------- ---------
Production volumes:
Oil (MBbls) 54 51
Gas (MMcf) 3,029 3,444
Total production (MMcfe) 3,353 3,751
Average daily production (MMcfe) 37.3 41.7
Average sales price: (a)
Oil (Bbls) $ 18.65 $ 26.62
Gas (Mcf) 2.34 5.46
Total (Mcfe) 2.42 5.38
Average costs (per Mcfe):
Lease operating (excluding severance taxes) $ 0.69 $ 0.61
Severance taxes 0.07 0.11
Depletion 1.64 1.28
General and administrative (net of management fees) 0.34 0.30
(a) Includes hedging gains and losses.
(b) Includes volumes of 574 MMcf for both three-month periods ended March 31,
2001 and 2002 at an average price of $2.08 per Mcf associated with a
volumetric production payment.
12
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2002
AND THE THREE MONTHS ENDED MARCH 31, 2001.
Oil and Gas Production and Revenues
Total oil and gas revenues decreased 45% from $20.2 million in the first quarter
of 2001 to $11.1 million in the first quarter of 2002. Both oil and gas prices
were substantially lower when compared to the same period in 2001. Oil and gas
revenues include approximately $2.9 million related to the Enron derivatives as
described in Note 3 to the Consolidated Financial Statements. Average sales
price in this discussion do not include the oil and gas sales associated with
these Enron derivatives.
Total production for the first quarter of 2002 declined by 11% versus the first
quarter of 2001. Production decreases at Mobile Bay Block 952/953/955, due to
downtime associated with the installation of a new production facility, and at
East Cameron 275, were partially offset by production from new discoveries at
High Island A-494 and East Cameron 294.
Gas production during the first quarter of 2002 totaled 3.0 Bcf and generated
$6.9 million in revenues compared to 3.4 Bcf and $18.8 million in revenues
during the same period in 2001. The average sales price for the first quarter of
2002 averaged $2.35 per Mcf compared to $5.46 per Mcf at this time last year.
Production decreases at Mobile Bay Block 952/953/955, due to downtime associated
with the installation of a new production facility, and at East Cameron 275,
were partially offset by production from new discoveries at High Island A-494
and East Cameron 294.
Oil production during the first quarter of 2002 totaled 54,000 barrels and
generated $1.0 million in revenues compared to 51,000 barrels and $1.4 million
in revenues for the same period in 2001. Average oil prices received in the
first quarter of 2002 were $18.65 compared to $26.62 in 2001.
Lease Operating Expenses
Lease operating expenses, for the three-month period ending March 31, 2002 were
$2.6 million compared to $2.7 million for the same period in 2001.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three months ending March 31,
2002 and 2001 were $5.6 million and $4.9 million, respectively. This increase is
primarily due to a higher average rate in the first quarter of 2002.
General and Administrative
General and administrative expense, net of amounts capitalized, remained
constant at $1.1 million for both three month periods ended March 31, 2002 and
March 31, 2001.
Interest Expense
Interest expense increased to $5.7 million during the three months ended March
31, 2002 from $2.6 million during the three months ended March 31, 2001. An
increase in the Company's long-term debt contributed to the greater interest
expense.
13
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's revenues are derived from the sale of its crude oil and natural
gas production. In recent months, the prices for oil and gas have increased;
however, they remain extremely volatile and sometimes experience large
fluctuations as a result of relatively small changes in supplies, weather
conditions, economic conditions and government actions. From time to time, the
Company enters into derivative financial instruments (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 March 31, 2002. There have been no significant
changes in market risks faced by the Company since the end of 2001.
14
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 period ended
December 31, 1994, File No. 000-25192)
3.3 Bylaws of the Company (incorporated by reference from
Exhibit 3.2 of the Company's Registration Statement on
Form S-4, filed August 4, 1994, Reg. No. 33-82408)
4. Instruments defining the rights of security holders,
including indentures
4.1 Specimen stock certificate (incorporated by reference
from Exhibit 4.1 of the Company's Registration
Statement on Form S-4, filed August 4, 1994, Reg. No.
33-82408)
4.2 Specimen Preferred Stock Certificate (incorporated by
reference from Exhibit 4.2 of the Company's
Registration Statement on Form S-1, Reg. No. 33-96700)
4.3 Designation for Convertible Exchangeable Preferred
Stock, Series A (incorporated by reference from Exhibit
4.3 of the Company's Registration Statement on Form
S-1/A, filed November 13, 1995, Reg. No. 33-96700)
4.4 Indenture for Convertible Debentures (incorporated by
reference from Exhibit 4.4 of the Company's
Registration Statement on Form S-1, filed November 13,
1995, Reg. No. 33-96700)
15
4.5 Certificate of Correction on Designation of Series A
Preferred Stock (incorporated by reference from Exhibit
4.4 of the Company's Registration Statement on Form
S-1, filed November 22, 1996, Reg. No. 333-15501)
4.6 Indenture for the Company's 10.125% Senior Subordinated
Notes due 2002 dated as of July 31, 1997 (incorporated
by reference from Exhibit 4.1 of the Company's
Registration Statement on Form S-4, filed September 25,
1997, Reg. No. 333-36395)
4.7 Form of Note Indenture for the Company's 10.25% Senior
Subordinated Notes due 2004 (incorporated by reference
from Exhibit 4.10 of the Company's Registration
Statement on Form S-2, filed June 14, 1999, Reg. No.
333-80579)
4.8 Rights Agreement between Callon Petroleum Company and
American Stock Transfer & Trust Company, Rights Agent,
dated March 30, 2000 (incorporated by reference from
Exhibit 4 of the Company's 8-K filed April 6, 2000,
File No. 001-14039)
4.9 Subordinated Indenture for the Company dated October
26, 2000 (incorporated by reference from Exhibit 4.1 of
the Company's Current Report on Form 8-K dated October
24, 2000, File No.001-14039)
4.10 Supplemental Indenture for the Company's 11% Senior
Subordinated Notes due 2005 (incorporated by reference
from Exhibit 4.2 of the Company's Current Report on
Form 8-K dated October 24, 2000, File No.001-14039)
4.11 Warrant dated as of June 29, 2001 entitling Duke
Capital Partners, LLC to purchase common stock from the
Company. (incorporated by reference to Exhibit 4.11 of
the Company's Quarterly Report on Form 10-Q for the
period ended June 30, 2001, File No. 001-14039)
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*
16
23. Consents of experts and counsel*
24. Power of attorney*
99. Additional exhibits*
(b) Reports on Form 8-K
None
- ----------
*Inapplicable to this filing
17
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: May 13, 2002 By: /s/ John S. Weatherly
--------------- ----------------------------
John S. Weatherly, Senior
Vice President and Chief
Financial Officer (on behalf
of the registrant and as the
principal financial officer)
18