Callon Petroleum (CPE) 10-Q 2005 Q3 Quarterly report

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, 2005

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. Yesþ Noo

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yesþ No

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yeso Noþ

As of November 4, 2005, there were 19,266,381 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, 2005 and December 31, 2004	3
	Consolidated Statements of Operations for Each of the Three and Nine Months in the Periods Ended September 30, 2005 and September 30, 2004	4
	Consolidated Statements of Cash Flows for Each of the Nine Months in the Periods Ended September 30, 2005 and September 30, 2004	5
	Notes to Consolidated Financial Statements	6
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	25
	Item 4. Controls and Procedures	25
Part II.	Other Information
	Item 6. Exhibits	26
Certification of CEO & CFO Pursuant to Rule 13(a)-14(a)
Certification of CEO & CFO Pursuant to Rule 13(a)-14(b)

2

Callon Petroleum Company

Consolidated Balance Sheets
(In thousands, except share data)

	September 30,			December 31,
	2005			2004
	(Unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	25,797		$	3,266
Accounts receivable		12,033			14,928
Deferred tax asset-current		13,560			5,676
Restricted investments-current		3,008			2,055
Fair market value of derivatives		—			1,570
Other current assets		839			581
Total current assets		55,237			28,076
Oil and gas properties, full-cost accounting method:
Evaluated properties		899,929			862,101
Less accumulated depreciation, depletion and amortization		(532,845	)		(494,453	)
		367,084			367,648
Unevaluated properties excluded from amortization		57,671			39,042
Total oil and gas properties		424,755			406,690
Other property and equipment, net		1,639			1,541
Deferred tax asset		—			2,986
Long-term gas balancing receivable		711			725
Restricted investments		4,989			5,687
Investment in Medusa Spar LLC		11,311			9,787
Other assets, net		1,888			2,031
Total assets	$	500,530		$	457,523
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	29,106		$	15,728
Fair market value of derivatives		10,400			2,993
Undistributed oil and gas revenues		1,367			1,162
Accrued net profits interest payable		—			1,927
Suspended Medusa oil royalties (See Note 8)		—			5,430
Asset retirement obligations-current		16,244			13,300
Current maturities of long-term debt		328			576
Total current liabilities		57,445			41,116
Long-term debt		188,429			192,351
Asset retirement obligations		20,551			24,982
Deferred tax liability		14,406			—
Other long-term liabilities		677			762
Total liabilities		281,508			259,211
Stockholders’ equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized; 0 and 596,671 shares of Convertible Exchangeable Preferred Stock, Series A, issued and outstanding at September 30, 2005 and December 31, 2004.		—			6
Common Stock, $.01 par value, 30,000,000 shares authorized; 19,264,084 and 17,616,596 shares outstanding at September 30, 2005 and December 31, 2004, respectively		193			176
Capital in excess of par value		220,227			220,664
Unearned compensation restricted stock		(3,631	)		(5,352	)
Accumulated other comprehensive loss		(4,619	)		(1,883	)
Retained earnings (deficit)		6,852			(15,299	)
Total stockholders’ equity		219,022			198,312
Total liabilities and stockholders’ equity	$	500,530		$	457,523

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,
	2005			2004		2005			2004
Operating revenues:
Oil and gas sales	$	31,722		$	25,138	$	116,402		$	94,663
Operating expenses:
Lease operating expenses		5,649			5,771		18,382			17,062
Depreciation, depletion and amortization		9,313			10,147		38,392			36,458
General and administrative		1,598			1,509		6,093			6,839
Accretion expense		864			825		2,495			2,555
Derivative expense		5,606			1,519		6,518			1,608
Total operating expenses		23,030			19,771		71,880			64,522
Income from operations		8,692			5,367		44,522			30,141
Other (income) expenses:
Interest expense		4,050			4,511		12,884			15,838
Other (income) expense		(352	)		65		(650	)		(311	)
Loss on early extinguishment of debt		—			532		—			3,004
Total other (income) expenses		3,698			5,108		12,234			18,531
Income before income taxes		4,994			259		32,288			11,610
Income tax expense		1,558			—		11,111			—
Income before Medusa Spar LLC		3,436			259		21,177			11,610
Income from Medusa Spar LLC, net of tax		247			287		1,292			768
Net income		3,683			546		22,469			12,378
Preferred stock dividends		—			317		318			955
Net income available to common shares	$	3,683		$	229	$	22,151		$	11,423
Net income per common share:
Basic	$	0.19		$	0.01	$	1.23		$	0.75
Diluted	$	0.17		$	0.01	$	1.09		$	0.74
Shares used in computing net income:
Basic		19,132			17,552		17,998			15,192
Diluted		21,235			18,815		20,545			16,762

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,
	2005			2004
Cash flows from operating activities:
Net income	$	22,469		$	12,378
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization		38,908			36,993
Accretion expense		2,495			2,555
Amortization of deferred financing costs		1,529			1,451
Non-cash loss on extinguishment of debt		—			2,910
Non-cash derivative expense		5,092			597
Income from investment in Medusa Spar LLC		(1,292	)		(768	)
Deferred income tax expense		11,111			—
Non-cash charge related to compensation plans		1,561			815
Changes in current assets and liabilities:
Accounts receivable		4,132			1,911
Other current assets		(279	)		(19	)
Current liabilities		797			(2,297	)
Change in gas balancing receivable		14			470
Change in gas balancing payable		(89	)		197
Change in other long-term liabilities		4			(16	)
Change in other assets, net		(361	)		(2,508	)
Cash provided by operating activities		86,091			54,669
Cash flows from investing activities:
Capital expenditures		(57,382	)		(43,284	)
Distribution from Medusa Spar LLC		464			233
Cash used by investing activities		(56,918	)		(43,051	)
Cash flows from financing activities:
Change in accounts payable and accrued liabilities to be refinanced		—			2,800
Increase in debt		7,000			82,000
Payments on debt		(12,000	)		(202,915	)
Restricted cash		—			63,345
Debt issuance cost		—			(984	)
Issuance of common stock		2			44,050
Buyout of preferred stock		(637	)		—
Equity issued related to employee stock plans		(241	)		229
Capital leases		(448	)		(1,067	)
Cash dividends on preferred stock		(318	)		(955	)
Cash used by financing activities		(6,642	)		(13,497	)
Net increase (decrease) in cash and cash equivalents		22,531			(1,879	)
Cash and cash equivalents:
Balance, beginning of period		3,266			8,700
Balance, end of period	$	25,797		$	6,821

The accompanying notes are an integral part of these financial statements.

5

CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2005

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, 2004 has been derived from the audited financial statements of the Company, but does not include all disclosures required by U.S. 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, 2004 included in the Company’s Annual Report on Form 10-K filed March 10, 2005. The results of operations for the three-month and nine-month periods ended September 30, 2005 are not necessarily indicative of future financial results.
	Accounting Pronouncements
	On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised 2004), (“SFAS 123R”) “Share-Based Payment”, which is a revision of Statement of Financial Accounting Standards No. 123, (“SFAS 123”) “Accounting for Stock-Based Compensation”. SFAS 123R supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.
	In April 2005, the Securities and Exchange Commission (“SEC”) delayed the effective date of SFAS 123R for public companies to no later than the beginning of the first fiscal year beginning after June 15, 2005. Early adoption will be permitted in periods in which financial statements have not yet been issued. SFAS 123R permits public companies to adopt its requirements using one of two methods below:

• A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS 123R for all share-based payments granted after the effective date and (b) based on the requirements of SFAS 123 for all awards granted to employees prior to the effective date of SFAS 123R that remain unvested on the effective date; or

• A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

6

As a result of the revised adoption date, the Company expects to adopt SFAS 123R on January 1, 2006 using the modified prospective method.

As permitted by SFAS 123, the Company currently accounts for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method could have a significant impact on future results of operations, although it will have no impact on our overall financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had we adopted SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS 123 as described in the disclosure of pro forma net income and earnings per share below under Stock-Based Compensation.

In September 2004, the SEC issued Staff Accounting Bulletin (“SAB”) No. 106, which expressed the SEC views regarding the application of Statement of Financial Accounting Standards No. 143 (“SFAS No. 143”) “Accounting for Asset Retirement Obligations”, by oil and gas producing companies following the full-cost accounting method. SAB No. 106 specifies that subsequent to the adoption of SFAS No. 143 an oil and gas company following the full-cost method of accounting should include assets recorded in connection with the recognition of an asset retirement obligation pursuant to SFAS No. 143 as part of the costs subject to the full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test. The Company adopted the provisions of SAB No. 106 in the first quarter of 2005, which had no impact on the Company’s results of operations or financial position.

Stock-Based Compensation

The Company has various stock plans (“Plans”) under which employees of the Company and its subsidiaries and non-employee members of the Board of Directors of the Company 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.

7

The Company’s pro forma net income and net income per share of common stock for the three-month and nine-month periods ended September 30, 2005 and 2004, had compensation costs been recorded using the fair value method in accordance with SFAS No. 123 – “Accounting for Stock-Based Compensation,” as amended by Statement of Financial Accounting Standards No. 148 (“SFAS No. 148”) – “Accounting for Stock-Based Compensation-Transition and Disclosure – an amendment of SFAS No. 123,” are presented below pursuant to the disclosure requirements of SFAS No. 148 (in thousands except per share data):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income available to common shares as reported	$	3,683		$	229		$	22,151		$	11,423
Add: Stock-based compensation expense included in net income as reported, net of tax		157			156			1,119			156
Deduct: Total stock-based compensation expense under fair value based method, net of tax		(207	)		(226	)		(1,270	)		(319	)
Net income available to common shares pro forma	$	3,633		$	159		$	22,000		$	11,260
Net income per share available to common:
Basic-as reported	$	0.19		$	0.01		$	1.23		$	0.75
Basic-pro forma	$	0.19		$	0.01		$	1.22		$	0.74
Diluted-as reported	$	0.17		$	0.01		$	1.09		$	0.74
Diluted-pro forma	$	0.17		$	0.01		$	1.09		$	0.73

In the second quarter of 2005, a non-cash charge in the amount of $928,000 was recognized for the accelerated vesting of performance shares for an executive officer and two directors of the Company, two of whom are deceased.

2.

Per Share Amounts

Basic net income per common share was computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share was 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).

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,
	2005		2004		2005		2004
(a) Net income available to common shares	$	3,683	$	229	$	22,151	$	11,423
Preferred dividends assuming conversion of preferred stock (if dilutive)		—		—		318		955
(b) Income available to common shares assuming conversion of  preferred stock (if dilutive)	$	3,683	$	229	$	22,469	$	12,378
(c) Weighted average shares outstanding		19,132		17,552		17,998		15,192
Dilutive impact of stock options		410		234		333		220
Dilutive impact of warrants		1,523		1,028		1,309		805
Dilutive impact of restricted stock		76		1		62		91
Convertible preferred stock (if dilutive)		94		—		843		454
(d) Total diluted shares		21,235		18,815		20,545		16,762
Basic income per share (a¸c)	$	0.19	$	0.01	$	1.23	$	0.75
Diluted income per share (b¸d)	$	0.17	$	0.01	$	1.09	$	0.74
Stock options and warrants excluded due to the exercise price being greater than the stock price (in thousands)		—		65		12		536

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.
	The Company’s derivative contracts that are accounted for as cash flow hedges under Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), “Accounting for Derivative Instruments and Hedging Activities,” are recorded at fair market value and the changes in fair value are recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as derivative expense (income). The cash settlements on these contacts are also recorded within derivative expense (income).

9

Cash settlements on effective cash flow hedges during the three-month periods ended September 30, 2005 and 2004 resulted in a reduction of oil and gas sales of $3.6 million and $4.0 million, respectively. For the nine-month periods ended September 30, 2005 and 2004, cash settlements on effective cash flow hedges reduced oil and gas sales in the amount of $8.3 million and $7.2 million, respectively.

Cash settlements on ineffective derivative contracts were recorded as derivative expense in the amount of $1.4 million and $716,000 for the three-month and nine-month periods ended September 30, 2005 and 2004, respectively. These contracts were deemed ineffective as a result of a shortfall in production volumes due to downtime from the tropical storm activity in the third quarter of 2005 and 2004.

As a result of continued downtime due to damages caused by Hurricanes Katrina and Rita to oil and gas transmission lines and facilities owned by third parties, some of our derivative contracts for October and November 2005 have been deemed ineffective. Due to the fact that it is probable that the shortfall in production volumes will continue in October and November, we recognized a non-cash derivative expense of $3.8 million for the three-month and nine-month periods ended September 30, 2005 to reclassify the unrealized loss on these contracts, which was included in other comprehensive (loss) to earnings. A similar charge of $731,000 was recognized for the three-month and nine-month periods ended September 30, 2004 due to a production shortfall caused by Hurricane Ivan.

The following table summarizes derivative expense for the periods presented (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Amortization of derivative contract premiums	$	394	$	—	$	1,306	$	—
Change in fair value and settlements of ineffective derivative contracts		5,212		1,447		5,212		1,447
Change in fair value and settlements of non-designated derivative contracts		—		72		—		161
	$	5,606	$	1,519	$	6,518	$	1,608

The fair value of the outstanding oil and gas derivative contracts at September 30, 2005 was a current liability of $10.4 million.

10

Listed in the table below are the outstanding derivative contracts as of September 30, 2005:

Swaps

	Volumes per		Quantity	Average
Product	Month		Type	Price		Period
Oil		15,000	Bbls	$	55.00		10/05-06/06

Puts

				Average
	Volumes per		Quantity	Floor
Product	Month		Type	Price		Period
Oil		7,000	Bbls	$	35.00		10/05-12/05
Natural Gas		390,000	MMBtu	$	5.00		10/05
Natural Gas		100,000	MMBtu	$	5.00		10/05-12/05

Collars

				Average		Average
	Volumes per		Quantity	Floor		Ceiling
Product	Month		Type	Price		Price		Period
Oil		30,000	Bbls	$	32.50	$	40.00		10/05-12/05
Oil		15,000	Bbls	$	35.00	$	43.50		10/05-12/05
Oil		15,333	Bbls	$	40.00	$	50.00		10/05-12/05
Oil		15,000	Bbls	$	40.00	$	54.00		10/05-12/05
Oil		30,000	Bbls	$	60.00	$	77.10		01/06-12/06
Natural Gas		300,000	MMBtu	$	5.50	$	7.75		10/05
Natural Gas		100,000	MMBtu	$	8.50	$	12.16		10/05-09/06
Natural Gas		200,000	MMBtu	$	10.00	$	16.00		11/05-03/06

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4.	Long-Term Debt
	Long-term debt consisted of the following at:

	September 30,		December 31,
	2005		2004
	(In thousands)
Senior Secured Credit Facility (matures July 31, 2007)	$	—	$	5,000
9.75% Senior Notes (due 2010), net of discount		187,493		186,216
Capital lease		1,264		1,711
Total debt		188,757		192,927
Less current portion:
Capital lease		328		576
Long-term debt	$	188,429	$	192,351

On June 15, 2004, the Company closed on a three-year senior secured credit facility underwritten by Union Bank of California, N.A. The credit facility had an initial borrowing base of $60 million, which was increased to $70 million in the second quarter of 2005. The borrowing base is reviewed and redetermined semi-annually and can be increased to a maximum of $175 million. Borrowings under the credit facility are secured by mortgages covering the Company’s five largest fields. As of September 30, 2005, there were no borrowings outstanding under the facility; however, Callon had an aggregate of $7.5 million in outstanding letters of credit issued under the credit facility. These letters of credit secure obligations under the outstanding hedging contracts described in Note 3 to the Consolidated Financial Statements. The outstanding letters of credit reduce the amount available for borrowings under the credit facility. As a result, $62.5 million was available for future borrowings under the credit facility as of September 30, 2005.

As a result of refinancing a portion of the Company’s debt in the first nine months of 2004, a loss on early extinguishment of debt in the amount of $3.0 million was recognized. See Note 5 of Callon’s Consolidated Financial Statements for the year ended December 31, 2004 included in the Company’s Annual Report on Form 10-K filed March 10, 2005 for a more detailed description of the Company’s long-term debt.

Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million 9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantors are minor.

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5.	Income Taxes
	The Company follows the asset and liability method of accounting for deferred income taxes prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible temporary timing differences, capital and operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance is provided for that portion of the deferred tax asset for which it is deemed more likely than not that the deferred tax asset will not be realized.
	SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is more likely than not that a deferred tax asset is recoverable. The Company incurred losses in 2002 and 2003 and had losses on an aggregate basis for the three-year period ended December 31, 2003. Because of these cumulative losses the Company established a valuation allowance of $11.5 million against the Company’s deferred tax asset as of December 31, 2003.
	As a result of production from the Company’s first two deepwater projects starting in November 2003, as well as refinancing its highest cost debt in 2004, the Company achieved profitable operations and had income on an aggregate basis for the three-year period ended December 31, 2004. As a result, the Company reversed the valuation allowance, which had a balance of $7.0 million as of December 31, 2004.
	During the first nine months of 2004, the Company revised the valuation allowance as a result of current year ordinary income, the impact of which was included in the Company’s effective tax rate and resulted in no net income tax expense (benefit) for the period. The Company had income tax expense of $11.1 million in the first nine months of 2005.

6.	Comprehensive Income
	A summary of the Company’s comprehensive income (loss) is detailed below (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005			2004
Net income	$	3,683	$	546		$	22,469		$	12,378
Other comprehensive income (loss):
Change in fair value of effective cash flow hedges		257		(4,291	)		(2,736	)		(8,230	)
Total comprehensive income	$	3,940	$	(3,745	)	$	19,733		$	4,148

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7.	Asset Retirement Obligations
	In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations”, effective for fiscal years beginning after June 15, 2002. As more fully discussed in Note 2 to the Consolidated Financial Statements for the year ended December 31, 2004, included in Callon’s Annual Report on Form 10-K filed March 10, 2005, SFAS No. 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. 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 $8.0 million at September 30, 2005, 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 had sold a net profits interest (“NPI”). In September 2005, Callon purchased the NPI’s which included the abandonment trusts. See Note 10 to the Consolidated Financial Statements for more detail on the NPI transaction.
	The following table summarizes the activity for the Company’s asset retirement obligation for the nine-month period ended September 30, 2005:

	Nine Months Ended
	September 30, 2005
Asset retirement obligation at beginning of period	$	38,282
Accretion expense		2,495
Net profits interest accretion		331
Liabilities incurred		1,150
Liabilities settled		(5,183	)
Revisions to estimate		(280	)
Asset retirement obligation at end of period		36,795
Less: current asset retirement obligation		(16,244	)
Long-term asset retirement obligation	$	20,551

8.

Suspended Medusa Oil Royalties

In March 2005, pursuant to the Deepwater Royalty Relief Act, the Company was required to retroactively pay royalties for 2004 oil production to the Minerals Management Service (“MMS”) on the Medusa deepwater property, which were accrued during 2004, in the amount of $5.4 million. In addition, the Company is required to make monthly royalty payments in 2005. See Note 7 of Callon’s Consolidated Financial Statements for the year ended December 31, 2004 included in the Company’s Annual Report on Form 10-K filed March 10, 2005 for a more detailed description of the Deepwater Royalty Relief Act.

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9.

Redemption of all Outstanding Shares of Preferred Stock

On June 13, 2005, Callon called for redemption all of the Company’s outstanding shares of $2.125 Convertible Exchange Preferred Stock, Series A. A notice of redemption and letter of transmittal was mailed to all holders of record as of the close of business on June 10, 2005. Between June 13, 2005 and June 30, 2005, 180,173 shares of preferred stock were converted into 409,496 shares of the Company’s common stock. Subsequent to June 30, 2005, 392,935 shares of preferred stock were converted into 893,076 shares of the Company’s common stock. In addition, 23,563 shares of the Company’s preferred stock were redeemed for $606,000 on July 14, 2005.

10.

Net Profits Interest

From 1989 through 1994, the Company entered into separate agreements to purchase certain oil and gas properties, and in simultaneous transactions, entered into agreements to sell overriding royalty interest (“ORRI”) in the acquired properties. These ORRI are in the form of NPI’s equal to a significant percentage of the excess gross proceeds over costs, as defined by the agreements, from the acquired oil and gas properties. In September 2005, the Company purchased the NPI’s for $5 million before intervening operations. Included in the transaction were the abandonment trusts which were established at the inception of the NPI’s for future plugging and abandonment liabilities. See Note 11 of Callon’s Consolidated Financial Statements for the year ended December 31, 2004 included in the Company’s Annual Report on Form 10-K filed March 10, 2005 for a more detailed description of the NPI’s.

15

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 our financial position, adequacy of resources, estimated reserve quantities, business strategies, plans, objectives and expectations for future operations and covenant compliance, are forward-looking statements. We 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 our expectations (“Cautionary Statements”) are disclosed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K for our most recent fiscal year, elsewhere in this report and from time to time in other filings made by us with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified by the Cautionary Statements.

General

Our revenues, profitability, future growth and the carrying value of our oil and gas properties are substantially dependent on prevailing prices of oil and gas, our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable and our ability to develop existing proved undeveloped reserves. Our ability to maintain or increase our 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 our control. 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 carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. We use derivative financial instruments for price protection purposes on a limited amount of our future production, but do not use derivative financial instruments for trading purposes.

As a result of the tropical storms and hurricanes in the third quarter of 2005, we have incurred downtime which has continued into the fourth quarter of 2005. This downtime resulted in some of our derivative contracts being deemed ineffective due to the production shortfall. See Note 3 to the Consolidated Financial Statements for more detail on our derivative contracts.

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The following discussion is intended to assist in an understanding of our historical financial position and results of operations. Our 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

Our primary sources of capital are cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. On September 30, 2005, we had net cash and cash equivalents of $25.8 million and $62.5 million of availability under our senior secured credit facility. Cash provided from operating activities during the nine-month period ended September 30, 2005 totaled $86.1 million. Cash provided by operating activities for 2005 has increased compared to 2004, primarily due to increased oil and gas prices. Net capital expenditures from the cash flow statement for the nine-month period ended September 30, 2005 totaled $57.4 million. Dividends paid on preferred stock were $318,000 for the nine-month period ended September 30, 2005.

On June 13, 2005, we called for redemption all of our outstanding shares of $2.125 Convertible Exchange Preferred Stock, Series A. A notice of redemption and letter of transmittal was mailed to all holders of record as of the close of business on June 10, 2005. Between June 13, 2005 and June 30, 2005, 180,173 shares of preferred stock had been converted into 409,496 shares of our common stock. Subsequent to June 30, 2005, 392,935 shares of preferred stock were converted into 893,076 shares of our common stock. In addition, 23,563 shares of our preferred stock were redeemed for $606,000 on July 14, 2005. As a result of the redemption, we will benefit from an annual cash savings of $1.3 million in future dividend payments.

On June 15, 2004, we closed on a three-year senior secured credit facility underwritten by Union Bank of California, N.A. The credit facility had an initial borrowing base of $60 million, which was increased to $70 million in the second quarter of 2005. The borrowing base is reviewed and redetermined semi-annually and can be increased to a maximum of $175 million. As of September 30, 2005, there were no borrowings outstanding under the facility; however, we had an aggregate of $7.5 million in outstanding letters of credit issued under the credit facility. These letters of credit secure obligations under the outstanding hedging contracts described in Note 3 to the Consolidated Financial Statements. The outstanding letters of credit reduce the amount available for borrowings under the credit facility. As a result, $62.5 million was available for future borrowings under the credit facility as of September 30, 2005.

The Indenture governing our 9.75% Senior Notes due 2010 and our senior secured credit facility contain various covenants, including restrictions on additional indebtedness and payment of cash dividends. In addition, our senior secured credit facility contains covenants for maintenance of certain financial ratios. We were in compliance with these covenants at September 30, 2005. See Note 5 of the Consolidated Financial Statements for the year ended December 31, 2004 included in our Annual Report on Form 10-K filed March 10, 2005 for a more detailed discussion of long-term debt.

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Our capital expenditure plans for 2005, including capitalized interest and general and administrative expenses, will require $90.0 million of funding. We anticipate that cash flow generated from operations during 2005 and current availability under our senior secured credit facility, if necessary, will provide the $96.0 million of capital necessary to fund these planned capital expenditures as well as our asset retirement obligations. See the Capital Expenditures section below for a more detailed discussion of our capital expenditures for 2005.

The following table describes our outstanding contractual obligations (in thousands) as of September 30, 2005:

Contractual			Less Than		One-Three		Four-Five		After-Five
Obligations	Total		One Year		Years		Years		Years
Senior Secured Credit Facility	$	—	$	—	$	—	$	—	$	—
9.75% Senior Notes		200,000		—		—		—		200,000
Capital Lease (future minimum payments)		1,891		517		625		449		300
Throughput Commitments:
Medusa Spar		13,680		3,940		5,908		3,832		—
Medusa Oil Pipeline		669		218		217		117		117
	$	216,240	$	4,675	$	6,750	$	4,398	$	200,417

Capital Expenditures

Capital expenditures from the cash flow statement for exploration and development costs related to oil and gas properties totaled approximately $57 million for the nine months ended September 30, 2005. We incurred approximately $6 million in costs in the Gulf of Mexico Deepwater Area related primarily to the drilling and completion of a development well at North Medusa. Interest of approximately $4 million and general and administrative costs allocable directly to exploration and development projects of approximately $5 million were capitalized for the first nine months of 2005. Our Gulf of Mexico Shelf Area expenditures accounted for approximately $29 million of total capital expenditures for the nine-months ended September 30, 2005, which included the drilling of six wells, two of which will be completed in the fourth quarter, the completion of a 2004 shelf well and the rework of three existing shelf wells. The remainder of the capital expended includes the acquisition of seismic and leases and the purchase of the NPI’s as further discussed in Note 10 to the Consolidated Financial Statements.

Capital expenditures for the remainder of 2005 are forecast to be approximately $33 million and include:

• the completion and development of six shelf wells;

• the non-discretionary drilling of exploratory wells;

• the acquisition of seismic and leases; and

• capitalized interest and general and administrative costs.

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Third Quarter Hurricane Activity

During the third quarter of 2005, we encountered five tropical storms and hurricanes which have caused all of our fields located in the Gulf of Mexico area to be shut-in at various times during the quarter. In addition, Hurricanes Katrina and Rita, being the most devastating of these tropical weather systems, caused substantial downtime which is still on-going and is primarily due to damage incurred to oil and gas transmission lines and production facilities owned by third parties. Repairs are being made; however, timing for resuming production from all fields is still unknown.

Our major fields, Medusa, Habanero and Mobile Bay Blocks 863, 864, 907, 952, 953 and 955, incurred damage; but the fields are being repaired and will be ready to go online as soon as the third party transmission lines and production facilities are repaired. Our properties are insured and we expect to get reimbursed for most of our costs incurred for damage repairs, less our $250,000 deductible per occurrence. We estimated that our cost to repair the hurricane damages will be approximately $4.0 million. As of September 30, 2005, we expensed approximately $116,000 and $130,000 for Hurricane’s Katrina and Rita, respectively.

Production from these fields represented approximately 80% of our production for the six months ended June 30, 2005. Prior to Hurricane Katrina our average daily production rate was over 60 MMcfe. Our current daily production rate is approximately 13 MMcfe and a return to full production is not expected until the first quarter of 2006.

Off-Balance Sheet Arrangements

In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which now owns a 75% undivided ownership interest in the deepwater Spar production facilities on our Medusa field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the production facility to Medusa Spar LLC in return for approximately $25 million in cash and a 10% ownership interest in the LLC. The LLC will earn a tariff based upon production volume throughput from the Medusa area. We are obligated to process our share of production from the Medusa field and any future discoveries in the area through the Spar production facilities. This arrangement allows us to defer the cost of the Spar production facility over the life of the Medusa field. Our cash proceeds were used to reduce the balance outstanding under our senior secured credit facility. The LLC used $83.7 million of cash proceeds from non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the Spar. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our 10% ownership interest in the LLC under the equity method.

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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,
	2005			2004			2005			2004
Net production :
Oil (MBbls)		382			376			1,613			1,354
Gas (MMcf)		1,510			2,405			6,570			8,924
Total production (MMcfe)		3,804			4,659			16,246			17,050
Average daily production (MMcfe)		41.3			50.6			59.5			62.2
Average sales price:
Oil (Bbls) (a)	$	46.16		$	27.83		$	41.01		$	29.63
Gas (Mcf)		9.32			6.11			7.65			6.11
Total (Mcfe)		8.34			5.40			7.16			5.55
Oil and gas revenues:
Oil revenue	$	17,649		$	10,457		$	66,142		$	40,120
Gas revenue		14,073			14,681			50,260			54,543
Total	$	31,722		$	25,138		$	116,402		$	94,663
Oil and gas production costs:
Lease operating expense	$	5,649		$	5,771		$	18,382		$	17,062
Additional per Mcfe data:
Sale price	$	8.34		$	5.40		$	7.16		$	5.55
Lease operating expense		1.49			1.24			1.13			1.00
Operating margin	$	6.85		$	4.16		$	6.03		$	4.55
Depletion, depreciation and amortization	$	2.45		$	2.18		$	2.36		$	2.14
General and administrative (net of management fees)	$	0.42		$	0.32		$	0.38		$	0.40
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
Average NYMEX oil price	$	63.19		$	43.87		$	55.40		$	39.11
Basis differential and quality adjustments		(6.98	)		(4.77	)		(8.04	)		(3.40	)
Transportation		(1.25	)		(1.27	)		(1.28	)		(1.27	)
Hedging		(8.80	)		(10.00	)		(5.07	)		(4.81	)
Average realized oil price	$	46.16		$	27.83		$	41.01		$	29.63

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Comparison of Results of Operations for the Three Months Ended September 30, 2005 and the Three Months Ended September 30, 2004.

Oil and Gas Production and Revenues

Total oil and gas revenues increased 26% to $31.7 million in the third quarter of 2005 from $25.1 million in the third quarter of 2004. The increase was due to higher product prices. Total production on an equivalent basis for the third quarter of 2005 decreased by 18% versus the third quarter of 2004.

Gas production during the third quarter of 2005 totaled 1.5 Bcf and generated $14.1 million in revenues compared to 2.4 Bcf and $14.7 million in revenues during the same period in 2004. The average gas price after hedging impact for the third quarter of 2005 was $9.32 per Mcf compared to $6.11 per Mcf for the same period last year. The decrease in production was primarily due to downtime in the third quarter related to tropical storm and hurricane activity and normal and expected decline in production from our Mobile Bay area fields and older properties. The decrease was partially offset by production from our new wells at High Island Block 119.

Oil production during the third quarter of 2005 totaled 382,000 barrels and generated $17.6 million in revenues compared to 376,000 barrels and $10.5 million in revenues for the same period in 2004. The average oil price received after hedging impact in the third quarter of 2005 was $46.16 per barrel compared to $27.83 per barrel in the third quarter of 2004. The increase in production for the third quarter of 2005 compared to the third quarter of 2004 was due to higher production from Medusa, which was partially offset by downtime associated with the third quarter tropical storm and hurricane activity.

Lease Operating Expenses

Lease operating expenses were $5.6 million for the three-month period ended September 30, 2005, a decrease of $122,000 compared to the same period in 2004.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended September 30, 2005 and 2004 was $9.3 million and $10.1 million, respectively. The 8% decrease was primarily due to lower production volumes for the third quarter of 2005 compared to the same period last year. The decrease was partially offset by a higher average depletion rate.

Accretion Expense

Accretion expense for the three-month periods ended September 30, 2005 and 2004 of $864,000 and $825,000, respectively, represents accretion of our asset retirement obligations. The increase was due to the addition of plugging and abandonment obligations. See Note 7 to the Consolidated Financial Statements.

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General and Administrative

General and administrative expenses, net of amounts capitalized, were $1.6 million and $1.5 million for the three-month periods ended September 30, 2005 and 2004, respectively. The 6% increase was primarily due to reduced capitalized overhead in the third quarter of 2005.

Interest Expense

Interest expense decreased by 10% to $4.1 million during the three months ended September 30, 2005 from $4.5 million during the three months ended September 30, 2004. This decrease is primarily attributable to an equity offering which was completed in the second quarter of 2004 in which a portion of the proceeds were used to redeem $33 million of 11% Senior Subordinated Notes due December 15, 2005 in the third quarter of 2004.

Loss on Early Extinguishment of Debt

A loss of $532,000 was recognized during the three-month period ended September 30, 2004 in connection with the write-off of unamortized deferred financing costs associated with the early extinguishment of the $33 million of 11% Senior Subordinated Notes due December 15, 2005.

Income Taxes

Income tax expense was $1.6 million for the three-month period ended September 30, 2005 compared to zero for the same period last year. The increase was due to an increase in income before income taxes and no reversal of valuation allowance in the third quarter of 2005.

A valuation allowance of $11.5 million was established against our deferred tax asset as of December 31, 2003. We revised the valuation allowance in the third quarter of 2004 by the amount of income tax expense resulting from third quarter ordinary income, the impact of which was included in our effective tax rate and resulted in no net income tax expense (benefit) for the third quarter of 2004. At year-end 2004, the remaining balance in the valuation allowance was reversed. See Note 5 to the Consolidated Financial Statements for a detailed discussion of the valuation allowance.

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Comparison of Results of Operations for the Nine Months Ended September 30, 2005 and the Nine Months Ended September 30, 2004.

Oil and Gas Production and Revenues

Total oil and gas revenues increased 23% to $116.4 million during the first nine months of 2005 from $94.7 million for the same period in 2004. The increase was due to higher product prices. Total production on an equivalent basis for the nine months ended September 30, 2005 decreased by 5% compared to the nine months ended September 30, 2004.

Gas production during the first nine months of 2005 totaled 6.6 Bcf and generated $50.3 million in revenues compared to 8.9 Bcf and $54.5 million in revenues during the same period in 2004. The average gas price after hedging impact for the nine-month period ended September 30, 2005 was $7.65 per Mcf compared to $6.11 per Mcf for the same period last year. The decrease in production was primarily due to downtime in the third quarter related tropical storm and hurricane activity and normal and expected decline in production from our Mobile Bay area fields and older properties. The decrease was partially offset by higher production from Medusa and production from our new wells at High Island Block 119.

Oil production during the nine-month period ended September 30, 2005 totaled 1,613,000 barrels and generated $66.1 million in revenues compared to 1,354,000 barrels and $40.1 million in revenues for the same period in 2004. The average oil price received after hedging impact in the nine-month period ended September 30, 2005 was $41.01 per barrel compared to $29.63 per barrel in the same period last year. The increase in production for the nine-month period ending September 30, 2005 compared to the same period in 2004 was due to the higher production from Medusa, which was partially offset by downtime associated with the third quarter tropical storm and hurricane activity.

Lease Operating Expenses

Lease operating expenses for the nine-month period ended September 30, 2005 increased to $18.4 million compared to $17.1 million for the same period in 2004. The 8% increase was primarily due to lease operating expenses related to our deepwater property, Medusa, which had higher throughput charges as a result of higher production rates and the addition of our High Island Block 119 field, which began producing in the third quarter of 2004.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the nine months ended September 30, 2005 and 2004 was $38.4 million and $36.5 million, respectively. The 5% increase was due to a higher average depletion rate.

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Accretion Expense

Accretion expense for the nine-month periods ended September 30, 2005 and 2004 of $2.5 million and $2.6 million, respectively, represents accretion of our asset retirement obligations. The decrease was due to the settlement of plugging and abandonment obligations. See Note 7 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses, net of amounts capitalized, were $6.1 million and $6.8 million for the nine-month periods ended September 30, 2005 and 2004, respectively. The 11% decrease resulted from a charge of $2.6 million that was incurred in the first quarter of 2004 for the early retirement of two executive officers of the Company. The decrease was partially offset by reduced capitalized overhead in the first nine months of 2005 and a non-cash charge during the second quarter of 2005 for the accelerated vesting of performance shares in the amount of $928,000 for an executive officer and two directors of the Company, two of whom are deceased.

Interest Expense

Interest expense decreased by 19% to $12.9 million during the nine months ended September 30, 2005 from $15.8 million during the nine months ended September 30, 2004. This decrease is primarily attributable to an equity offering which was completed in the second quarter of 2004 in which a portion of the proceeds were used to redeem $33 million of 11% Senior Subordinated Notes due December 15, 2005 in the third quarter of 2004.

Loss on Early Extinguishment of Debt

A loss of $3.0 million was recognized during the nine month period ended September 30, 2004 for the write-off of unamortized deferred financing costs and bond discounts associated with the early extinguishment of the $22.9 million of 10.125% Senior Subordinated Notes due July 31, 2004, the $40 million of 10.25% Senior Subordinated Notes due September 15, 2004, the $33 million of 11% Senior Subordinated Notes due December 15, 2005 and the remaining $10 million of 12% senior loans due in 2005 plus a 1% pre-payment premium.

Income Taxes

Income tax expense was $11.1 million for the nine-month period ended September 30, 2005 compared to zero for the same period last year. The increase was due to an increase in income before income taxes and no reversal of valuation allowance in the first nine months of 2005.

A valuation allowance of $11.5 million was established against our deferred tax asset as of December 31, 2003. We revised the valuation allowance in the first nine months of 2004 by the amount of income tax expense resulting from the nine-month period ended September 30, 2004 ordinary income, the impact of which was included in our effective tax rate and resulted in no net income tax expense (benefit) for the first nine months of 2004. At year-end 2004, the remaining balance in the valuation allowance was reversed. See Note 5 to the Consolidated Financial Statements for a detailed discussion of the valuation allowance.

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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 to manage oil and gas price risk.

The Company utilizes fixed price “swaps”, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices.

The Company utilizes 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 and below the ceiling price set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counter-party receives the difference from the Company.

Callon has purchased “puts” as another form of derivative financial instrument which reduces the Company’s exposure to decreases in oil and gas prices while allowing realization of the full benefit from any increases in oil and gas prices. If the price falls below the puts, the counter-party pays the difference to 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 derivative transactions for speculative purposes. However, certain of the Company’s derivative 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 outstanding derivative contracts at September 30, 2005. There have been no significant changes in market risks faced by the Company since the end of 2004.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Based on his evaluation as of the end of the period covered by this Quarterly Report on Form 10-Q, the Company’s principal executive and financial officer has 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.

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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.

CALLON PETROLEUM COMPANY

PART II. OTHER INFORMATION

Item 6. EXHIBITS

Exhibits

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 Annual Report on Form 10-K for the year ended December 31, 2003 filed March 15, 2004, File No. 001-14039)
3.2	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	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)
4.3	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)

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4.4	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)
4.5	Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under the Company’s $185 million amended and restated Senior Unsecured Credit Agreement, dated December 23, 2003, to purchase common stock from the Company (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)
4.6	Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004, between Callon Petroleum Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2004, File No. 001-14039)

31. Certifications

31.1 Certification of Chief Executive and Financial Officer pursuant to Rule 13(a)-14(a)

32. Section 1350 Certifications

32.1 Certification of Chief Executive and Financial Officer pursuant to Rule 13(a)-14(b)

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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 8, 2005	By: /s/ Fred L. Callon
	Fred L. Callon, President and Chief
	Executive Officer (on behalf of the
	registrant and as the principal financial
	officer)

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Exhibit Index

Exhibit Number Title of Document

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 Annual Report on Form 10-K for the year ended December 31, 2003 filed March 15, 2004, File No. 001-14039)
3.2	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	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)
4.3	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)
4.4	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)

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4.5	Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under the Company’s $185 million amended and restated Senior Unsecured Credit Agreement, dated December 23, 2003, to purchase common stock from the Company (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)
4.6	Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004, between Callon Petroleum Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2004, File No. 001-14039)

31. Certifications

31.1 Certification of Chief Executive and Financial Officer pursuant to Rule 13(a)-14(a)

32. Section 1350 Certifications

32.1 Certification of Chief Executive and Financial Officer pursuant to Rule 13(a)– 14(b)

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