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~~ March 31, 2006

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 a large accelerated filer, an accelerated filer, ~~(as defined~~or a non-accelerated filer. See definitions of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange ~~Act Rule 12b-2). Yes~~þ NoAct. (Check one):


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o

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,~~May 5, 2006, there were ~~19,266,381~~20,313,141 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except share data)


	September 30,			December 31,			March 31,			December 31,
	2005			2004			2006			2005
	(Unaudited)			(Note 1)			(Unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	25,797		$	3,266		$	5,139		$	2,565
Accounts receivable		12,033			14,928			30,683			33,195
Deferred tax asset-current		13,560			5,676
Restricted investments-current		3,008			2,055
Deferred tax asset								37,788			26,770
Restricted investments								4,152			4,110
Fair market value of derivatives		—			1,570			2,165			889
Other current assets		839			581			1,077			1,998

Total current assets		55,237			28,076			81,004			69,527


Oil and gas properties, full-cost accounting method:
Evaluated properties		899,929			862,101			985,614			937,698
Less accumulated depreciation, depletion and amortization		(532,845	)		(494,453	)		(553,235	)		(539,399	)

		367,084			367,648			432,379			398,299

Unevaluated properties excluded from amortization		57,671			39,042			55,013			49,065

Total oil and gas properties		424,755			406,690			487,392			447,364


Other property and equipment, net		1,639			1,541			1,618			1,605
Deferred tax asset		—			2,986
Long-term gas balancing receivable		711			725			723			403
Restricted investments		4,989			5,687
Restricted investments-long-term								1,877			1,858
Investment in Medusa Spar LLC		11,311			9,787			11,835			11,389
Other assets, net		1,888			2,031			1,515			1,630

Total assets	$	500,530		$	457,523		$	585,964		$	533,776

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	29,106		$	15,728		$	44,798		$	39,323
Fair market value of derivatives		10,400			2,993			653			1,247
Undistributed oil and gas revenues		1,367			1,162			1,176			721
Accrued net profits interest payable		—			1,927
Suspended Medusa oil royalties (See Note 8)		—			5,430
Asset retirement obligations-current		16,244			13,300
Asset retirement obligations								27,040			21,660
Current maturities of long-term debt		328			576			236			263

Total current liabilities		57,445			41,116			73,903			63,214


Long-term debt		188,429			192,351			194,218			188,813
Asset retirement obligations		20,551			24,982
Asset retirement obligations-long-term								25,298			16,613
Deferred tax liability		14,406			—			49,018			31,633
Accrued liabilities to be refinanced								—			5,000
Other long-term liabilities		677			762			458			455

Total liabilities		281,508			259,211			342,895			305,728

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
Preferred Stock, $.01 par value, 2,500,000 shares authorized;								—			—
Common Stock, $.01 par value, 30,000,000 shares authorized; 20,293,779 and 19,357,138 shares outstanding at March 31, 2006 and December 31, 2005, respectively								203			194
Capital in excess of par value		220,227			220,664			217,996			220,360
Unearned compensation restricted stock		(3,631	)		(5,352	)		—			(3,334	)
Accumulated other comprehensive loss		(4,619	)		(1,883	)
Retained earnings (deficit)		6,852			(15,299	)
Other comprehensive income (loss)								944			(331	)
Retained earnings								23,926			11,159

Total stockholders’ equity		219,022			198,312			243,069			228,048

Total liabilities and stockholders’ equity	$	500,530		$	457,523		$	585,964		$	533,776

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited)

(In thousands, except per share amounts)


	Three Months Ended					Nine Months Ended						Three Months Ended
	September 30,					September 30,						March 31,
	2005			2004		2005			2004			2006			2005
Operating revenues:
Oil and gas sales	$	31,722		$	25,138	$	116,402		$	94,663
Oil sales												$	27,799		$	24,009
Gas sales													17,782			19,003

Total operating revenues													45,581			43,012


Operating expenses:
Lease operating expenses		5,649			5,771		18,382			17,062			5,905			6,536
Depreciation, depletion and amortization		9,313			10,147		38,392			36,458			13,836			15,408
General and administrative		1,598			1,509		6,093			6,839			1,726			1,694
Accretion expense		864			825		2,495			2,555			1,419			861
Derivative expense		5,606			1,519		6,518			1,608			90			379

Total operating expenses		23,030			19,771		71,880			64,522			22,976			24,878


Income from operations		8,692			5,367		44,522			30,141			22,605			18,134


Other (income) expenses:
Interest expense		4,050			4,511		12,884			15,838			4,148			4,569
Other (income) expense		(352	)		65		(650	)		(311	)		(330	)		(202	)
Loss on early extinguishment of debt		—			532		—			3,004

Total other (income) expenses		3,698			5,108		12,234			18,531			3,818			4,367


Income before income taxes		4,994			259		32,288			11,610			18,787			13,767
Income tax expense		1,558			—		11,111			—			6,550			4,818


Income before Medusa Spar LLC		3,436			259		21,177			11,610			12,237			8,949
Income from Medusa Spar LLC, net of tax		247			287		1,292			768			530			526


Net income		3,683			546		22,469			12,378			12,767			9,475
Preferred stock dividends		—			317		318			955			—			318

Net income available to common shares	$	3,683		$	229	$	22,151		$	11,423		$	12,767		$	9,157


Net income per common share:
Basic	$	0.19		$	0.01	$	1.23		$	0.75		$	0.66		$	0.52

Diluted	$	0.17		$	0.01	$	1.09		$	0.74		$	0.60		$	0.46


Shares used in computing net income:
Basic		19,132			17,552		17,998			15,192			19,396			17,671

Diluted		21,235			18,815		20,545			16,762			21,329			20,678

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited)

(In thousands)


	Nine Months Ended						Three Months Ended
	September 30,			September 30,			March 31,			March 31,
	2005			2004			2006			2005
Cash flows from operating activities:
Net income	$	22,469		$	12,378		$	12,767		$	9,475
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization		38,908			36,993			14,018			15,543
Accretion expense		2,495			2,555			1,419			861
Amortization of deferred financing costs		1,529			1,451			546			490
Non-cash loss on extinguishment of debt		—			2,910
Non-cash derivative expense		5,092			597			90			379
Income from investment in Medusa Spar LLC		(1,292	)		(768	)		(530	)		(526	)
Deferred income tax expense		11,111			—			6,550			4,818
Non-cash charge related to compensation plans		1,561			815			115			374
Excess tax benefits from share-based payment arrangements								(1,195	)		—
Changes in current assets and liabilities:
Accounts receivable		4,132			1,911			1,212			(6,965	)
Other current assets		(279	)		(19	)		922			265
Current liabilities		797			(2,297	)		5,483			(3,334	)
Change in gas balancing receivable		14			470			(320	)		88
Change in gas balancing payable		(89	)		197			(2	)		(68	)
Change in other long-term liabilities		4			(16	)		5			4
Change in other assets, net		(361	)		(2,508	)		(64	)		(73	)

Cash provided by operating activities		86,091			54,669			41,016			21,331


Cash flows from investing activities:
Capital expenditures		(57,382	)		(43,284	)		(39,507	)		(16,206	)
Distribution from Medusa Spar LLC		464			233			370			116

Cash used by investing activities		(56,918	)		(43,051	)		(39,137	)		(16,090	)

Cash flows from financing activities:
Change in accounts payable and accrued liabilities to be refinanced		—			2,800
Change in accrued liabilities to be refinanced								(5,000	)		—
Increase in debt		7,000			82,000			14,000			3,000
Payments on debt		(12,000	)		(202,915	)		(9,000	)		(8,000	)
Restricted cash		—			63,345
Debt issuance cost		—			(984	)
Issuance of common stock		2			44,050			—			1
Buyout of preferred stock		(637	)		—
Equity issued related to employee stock plans		(241	)		229			(418	)		(87	)
Excess tax benefits from share-based payment arrangements								1,195			—
Capital leases		(448	)		(1,067	)		(82	)		(208	)
Cash dividends on preferred stock		(318	)		(955	)		—			(318	)

Cash used by financing activities		(6,642	)		(13,497	)
Cash provided (used) by financing activities								695			(5,612	)

Net increase (decrease) in cash and cash equivalents		22,531			(1,879	)		2,574			(371	)
Cash and cash equivalents:
Balance, beginning of period		3,266			8,700			2,565			3,266

Balance, end of period	$	25,797		$	6,821		$	5,139		$	2,895

CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
~~September 30, 2005~~

March 31, 2006

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~~2005 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~~2005 included in the Company’s Annual Report on Form 10-K filed March ~~10, 2005.~~15, 2006. The results of operations for the three-month ~~and nine-month periods~~period ended ~~September 30, 2005~~March 31, 2006 are not necessarily indicative of future financial results.

2.		~~Accounting Pronouncements~~Stock-Based Compensation

		OnThe 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. For further discussion of the Company’s Plans, refer to Note 11 of the Consolidated Financial Statements for the year ended December ~~16, 2004,~~31, 2005 included in the ~~Financial Accounting Standards Board (“FASB”) issued~~Company’s Annual Report on Form 10-K filed March 15, 2006.

		Effective January 1, 2006, the Company adopted Statement of Financial Accounting ~~Standards~~Standard No. 123 (revised 2004), (“SFAS 123R”) “Share-Based ~~Payment”, which is a revision~~Payment,” utilizing the modified prospective approach. Prior to the adoption of SFAS 123R we accounted for stock option grants in accordance with Accounting Principals Board Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic value method) and, accordingly, recognized no compensation expense for stock option grants.

		Under the modified prospective approach, SFAS 123R applies to new awards, unvested awards as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified, repurchased or cancelled. Under the modified prospective approach, compensation cost recognized in the first quarter of 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of Statement of Financial Accounting ~~Standards~~Standard No. 123 (“SFAS 123”) “Accounting for Stock-Based ~~Compensation”. SFAS 123R supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees”,~~Compensation,” 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)~~subsequent to January 1, 2006, based on the ~~requirements~~grant-date fair value estimated in accordance with the provisions of SFAS ~~123 for all awards granted~~123R. Prior periods were not restated to ~~employees prior to~~reflect the ~~effective date~~impact of ~~SFAS 123R that remain unvested on~~adopting 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.new standard.

~~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 a result of most of the Company’s stock-based compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes, net income and basic and diluted earnings per share for the three-month period ended March 31, 2006 was immaterial.

		We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options. In accordance with SFAS 123R, for the three months ended March 31, 2006, we revised our consolidated statements of cash flows presentation to report the tax benefits from the exercise of stock options as financing cash flows. For the three months ended March 31, 2006, $1.2 million of tax benefits were reported as financing cash flows rather than operating cash flows. There were no cash proceeds from the exercise of stock options for the three months ended March 31, 2006 due to the fact that all options were exercised through net-share settlements.

		For the three month period ended March 31, 2006, we recorded compensation expense of $217,000, $108,000 of which was included in general and administrative expenses and $109,000 of which was capitalized to oil and gas properties. Shares available for future stock option or restricted stock grants to employees and directors under existing plans were 916,974 at March 31, 2006.

		The following table illustrates the effect on operating results and per share information had the Company accounted for stock-based compensation in accordance with SFAS 123 for the three months ended March 31, 2005 (in thousands, except per share amounts):

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.


	Three Months Ended
	March 31, 2005
Net income available to common shares as reported	$	9,157
Add: Stock-based compensation expense included in net income as reported, net of tax		191
Deduct: Total stock-based compensation expense under fair value based method, net of tax		(230	)

Net income available to common shares pro forma	$	9,118


Net income per share available to common:
Basic-as reported	$	0.52
Basic-pro forma	$	0.52

Diluted-as reported	$	0.46
Diluted-pro forma	$	0.46

Stock Options

The ~~Company’s pro forma net income and net income per share of common stock for~~Company uses the ~~three-month and nine-month periods ended September 30, 2005 and 2004, had compensation costs been recorded using~~Black-Scholes option pricing model to estimate the fair value ~~method~~of stock-based awards with the following weighted-average assumptions for the indicated periods.


	Three Months Ended
	March 31,
	2006			2005
Dividend yield		—			—
Expected volatility		38.9	%		42.4	%
Risk-free interest rate		4.6	%		4.4	%
Expected life of option (in years)		5			4
Weighted-average grant-date fair value		7.72			6.19
Forfeiture rate		7.5	%		—

The assumptions above are based on multiple factors, including historical exercise patterns of employees with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns and the historical volatility of our stock price.

At March 31, 2006, there was $284,000 of unrecognized compensation cost related to stock option share-based payments, which is expected to be recognized over a weighted-average period of 2.8 years.

The following table represents stock option activity for the three months ended March 31, 2006:


						Weighted-Average
	Number of			Weighted-Average		Remaining
	Shares			Exercise Price		Contract Life
Outstanding options at beginning of period		1,205,558		$	10.11
Granted		15,000			18.69
Exercised		(384,650	)		10.65
Forfeited		—			—


Outstanding options at end of period		835,908			10.02	4.48 Yrs.


Outstanding exercisable at end of period		787,908		$	9.55	4.17 Yrs.

The aggregate intrinsic value of options outstanding was $9.2 million and the aggregate intrinsic value of options exercisable was $9.0 million. Total intrinsic value of options exercised was $3.4 million for the three months ended March 31, 2006.

The following table summarizes our nonvested stock option activity for the three months ended March 31, 2006.


	Number of			Weighted-Average
	Shares			Exercise Price

Nonvested stock options at beginning of period		39,000		$	16.94
Granted		15,000			18.69
Vested		(6,000	)		15.21
Forfeited		—			—


Nonvested stock options at end of period		48,000		$	17.70

Restricted Stock

The Plans allow for the issuance of restricted stock awards. The unearned stock-based compensation related to these awards is being amortized to compensation expense over the vesting period, which ends in ~~accordance with SFAS No. 123 – “Accounting~~the third quarter of 2009. The share based expense for ~~Stock-Based Compensation,” as amended by Statement~~these awards was determined based on the market price of ~~Financial Accounting Standards No. 148 (“SFAS No. 148”) – “Accounting for Stock-Based Compensation-Transition and Disclosure – an amendment~~our stock at the date of ~~SFAS No. 123,” are presented below pursuant~~grant applied to the ~~disclosure requirements~~total numbers of ~~SFAS No. 148 (in thousands except per share data):~~shares that were anticipated to fully vest. As of March 31, 2006, we have unearned stock-based compensation of $3.1 million associated with these awards.

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~~The following table represents restricted stock activity for the ~~accelerated vesting of performance shares for an executive officer and two directors of the Company, two of whom are deceased.~~three months ended March 31, 2006.


	Number of		Weighted-Average
	Shares		Grant Price
Outstanding shares at beginning of period		272,000	$	13.66
Granted		—		—
Vested		—		—
Forfeited		—		—


Outstanding shares at end of period		272,000	$	13.66


		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				Three Months Ended
	September 30,				September 30,				March 31,
	2005		2004		2005		2004		2006		2005
(a) Net income available to common shares	$	3,683	$	229	$	22,151	$	11,423	$	12,767	$	9,157
Preferred dividends assuming conversion of preferred stock (if dilutive)		—		—		318		955		—		318

(b) Income available to common shares assuming conversion of preferred stock (if dilutive)	$	3,683	$	229	$	22,469	$	12,378	$	12,767	$	9,475


(c) Weighted average shares outstanding		19,132		17,552		17,998		15,192		19,396		17,671
Dilutive impact of stock options		410		234		333		220		342		315
Dilutive impact of warrants		1,523		1,028		1,309		805		1,491		1,267
Dilutive impact of restricted stock		76		1		62		91		100		69
Convertible preferred stock (if dilutive)		94		—		843		454		—		1,356

(d) Total diluted shares		21,235		18,815		20,545		16,762		21,329		20,678


Basic income per share (a¸c)	$	0.19	$	0.01	$	1.23	$	0.75	$	0.66	$	0.52
Diluted income per share (b¸d)	$	0.17	$	0.01	$	1.09	$	0.74	$	0.60	$	0.46

Stock options and warrants excluded due to the exercise price being greater than the stock price (in thousands)		—		65		12		536		15		25


		Cash settlements on effective cash flow hedges during the three-month periods ended ~~September 30,~~March 31, 2006 and 2005 ~~and 2004~~ resulted in an increase in oil and gas sales of $724,000 and a reduction of oil and gas sales of ~~$3.6 million and $4.0~~$2.9 million, respectively. ~~For the nine-month periods ended September 30, 2005~~Derivative expense of $90,000 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~~$379,000 for the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2006 and 2005, ~~and 2004, respectively. These contracts were deemed ineffective as a result~~respectively, represents the amortization of ~~a shortfall in production volumes due to downtime from the tropical storm activity in the third quarter of 2005 and 2004.~~derivative contract premiums.

		As ~~a result~~ of ~~continued downtime due to damages caused by Hurricanes Katrina and Rita to oil and~~March 31, 2006, the fair value of the outstanding gas ~~transmission lines and facilities owned by third parties, some of our~~ derivative contracts ~~for October~~was a current asset of $2.2 million and ~~November 2005 have been deemed ineffective. Due to~~ the ~~fact that it is probable that~~fair value of the ~~shortfall in production volumes will continue in October and November, we recognized~~outstanding oil contracts was a ~~non-cash derivative expense~~current liability 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.$653,000.

		~~The following~~Listed in the table ~~summarizes~~below are the outstanding derivative ~~expense for the periods presented (in thousands):~~contracts as of March 31, 2006:

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.~~

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.

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~~On June 15, 2004, the Company ~~achieved profitable operations and~~closed on a three-year senior secured credit facility underwritten by Union Bank of California, N.A. The credit facility 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~~initial borrowing base of ~~$7.0~~$60 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~~increased to $70 million in the ~~first nine months~~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 March 31, 2006, there was $5 million outstanding under the facility with a weighted average interest rate of 6.38% and $65 million available for future borrowings.

6.		Comprehensive Income

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


	Three Months Ended					Nine Months Ended						Three Months Ended
	September 30,					September 30,						March 31,
	2005		2004			2005			2004			2006		2005
Net income	$	3,683	$	546		$	22,469		$	12,378		$	12,767	$	9,475
Other comprehensive income (loss):
Change in fair value of effective cash flow hedges		257		(4,291	)		(2,736	)		(8,230	)		1,275		(4,849	)

Total comprehensive income	$	3,940	$	(3,745	)	$	19,733		$	4,148		$	14,042	$	4,626

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~~three-month period ended ~~September 30, 2005:~~March 31, 2006:


	Nine Months Ended			Three Months Ended
	September 30, 2005			March 31, 2006
Asset retirement obligation at beginning of period	$	38,282		$	38,273
Accretion expense		2,495			1,419
Net profits interest accretion		331
Liabilities incurred		1,150			1,109
Liabilities settled		(5,183	)		—
Revisions to estimate		(280	)		11,537

Asset retirement obligation at end of period		36,795			52,338
Less: current asset retirement obligation		(16,244	)		(27,040	)

Long-term asset retirement obligation	$	20,551		$	25,298

8.		~~Suspended Medusa Oil Royalties~~The upward revisions to estimate were primarily due to a sharp increase in industry service cost for the Gulf of Mexico region experienced in the first quarter of 2006, principally as a result of the weather patterns during the second half of 2005.

		InAssets, primarily U.S. Government securities, of approximately $6.0 million at March ~~2005, pursuant~~31, 2006, are recorded as restricted investments. These assets are held in abandonment trusts dedicated to ~~the Deepwater Royalty Relief Act, the Company was required to retroactively~~ pay ~~royalties~~future abandonment costs 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.

9.		~~Redemption of all Outstanding Shares of Preferred Stock~~

		~~On June 13, 2005, Callon called for redemption all~~several 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.

1513

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.

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,~~March 31, 2006, we had net cash and cash equivalents of ~~$25.8~~$5 million and ~~$62.5~~$65 million of availability under our senior secured credit facility. Cash provided from operating activities during the ~~nine-month~~three-month period ended ~~September 30, 2005~~March 31, 2006 totaled ~~$86.1~~$41 million. Cash provided by operating activities ~~for 2005 has~~during the first quarter of 2006 increased 92% compared to ~~2004, primarily~~2005, due to increased oil and gas prices. Net capital expenditures from the cash flow statement for the ~~nine-month~~three-month period ended ~~September 30, 2005~~March 31, 2006 totaled ~~$57.4~~$40 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~~Production of our ~~outstanding shares~~reserves during 2006, without weather-related downtime, is projected to be higher than 2005 due to 10 new discoveries scheduled to commence initial production during 2006 which are expected to offset traditional declines from our current producing properties. Given the current pricing environment for oil and natural gas and the higher production volumes, our cash provided by operating activities for 2006 should exceed 2005.

Our capital expenditure plans for 2006, including capitalized interest and general and administrative expenses, will require $150 million of ~~$2.125 Convertible Exchange Preferred Stock, Series A. A notice of redemption~~funding. We expect that cash flow generated from operations during 2006 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 ofcurrent availability under 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~~if necessary, will provide the $177 million of ~~California, N.A. The credit facility had an initial borrowing base~~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 $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 availableour capital expenditures 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.~~2006.

The ~~Indenture~~Indentures 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.~~March 31, 2006. See Note 5 of the Consolidated Financial Statements for the year ended December 31, ~~2004~~2005 included in our Annual Report on Form 10-K filed March ~~10, 2005~~15, 2006 for a more detailed discussion of long-term debt.

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:~~March 31, 2006:


Contractual			Less Than		One-Three		Four-Five		After-Five				Less Than		One-Three		Four-Five		After-Five
Obligations	Total		One Year		Years		Years		Years		Total		One Year		Years		Years		Years
Senior Secured Credit Facility	$	—	$	—	$	—	$	—	$	—	$	5,000	$	—	$	5,000	$	—	$	—
9.75% Senior Notes		200,000		—		—		—		200,000		200,000		—		—		200,000		—
Capital Lease (future minimum payments)		1,891		517		625		449		300		1,581		401		542		449		189
Throughput Commitments:
Medusa Spar		13,680		3,940		5,908		3,832		—		11,776		3,772		5,160		2,844		—
Medusa Oil Pipeline		669		218		217		117		117		555		181		172		110		92

	$	216,240	$	4,675	$	6,750	$	4,398	$	200,417	$	218,912	$	4,354	$	10,874	$	203,403	$	281

Capital Expenditures

Capital expenditures from the cash flow statement for exploration and development costs related to oil and gas properties totaled approximately ~~$57~~$40 million for the ~~nine~~three months ended ~~September 30, 2005.~~March 31, 2006. We incurred approximately $6$27 million in costs in the Gulf of Mexico ~~Deepwater~~Shelf Area related primarily to the drilling of five wells, four successful and one in progress, and completion and development of ~~a development well at North Medusa.~~seven discoveries. In the Onshore Louisiana area we incurred $5 million, which was associated with the drilling and beginning stage of completion for our Prairie Beach discovery. Interest of approximately $4$2 million and general and administrative costs allocable directly to exploration and development projects of approximately $5$2 million were capitalized for the first ~~nine~~three 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.2006. The remainder of the capital expended includes the acquisition of seismic and leases and ~~the purchase~~costs incurred in our Gulf of ~~the NPI’s as further discussed in Note 10 to the Consolidated Financial Statements.~~Mexico deepwater area.

Capital expenditures for the remainder of ~~2005~~2006 are forecast to be approximately ~~$33~~$110 million and include:

	•		the completion and development of ~~six shelf wells;~~our 2005 and 2006 discoveries;

	•		the non-discretionary drilling of exploratory wells;

	•		the acquisition of seismic and leases; and

	•		capitalized interest and general and administrative costs.

~~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~~we are projecting to ~~damage incurred to oil and gas transmission lines and production facilities owned by third parties. Repairs are being made; however, timing~~spend $27 million 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.asset retirement obligations.

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~~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~~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.~~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.

1916

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						Three Months Ended
	September 30,						September 30,						March 31,
	2005			2004			2005			2004			2006			2005
Net production :
Oil (MBbls)		382			376			1,613			1,354			515			641
Gas (MMcf)		1,510			2,405			6,570			8,924			1,950			2,748
Total production (MMcfe)		3,804			4,659			16,246			17,050			5,042			6,593
Average daily production (MMcfe)		41.3			50.6			59.5			62.2			56.0			73.3

Average sales price:
Oil (Bbls) (a)	$	46.16		$	27.83		$	41.01		$	29.63		$	53.95		$	37.46
Gas (Mcf)		9.32			6.11			7.65			6.11			9.12			6.92
Total (Mcfe)		8.34			5.40			7.16			5.55			9.04			6.52

Oil and gas revenues:
Oil revenue	$	17,649		$	10,457		$	66,142		$	40,120		$	27,799		$	24,009
Gas revenue		14,073			14,681			50,260			54,543			17,782			19,003

Total	$	31,722		$	25,138		$	116,402		$	94,663		$	45,581		$	43,012


Oil and gas production costs:
Lease operating expense	$	5,649		$	5,771		$	18,382		$	17,062		$	5,905		$	6,536

Additional per Mcfe data:
Sale price	$	8.34		$	5.40		$	7.16		$	5.55
Sales price													$	9.04		$	6.52
Lease operating expense		1.49			1.24			1.13			1.00			1.17			0.99

Operating margin	$	6.85		$	4.16		$	6.03		$	4.55		$	7.87		$	5.53


Depletion, depreciation and amortization	$	2.45		$	2.18		$	2.36		$	2.14		$	2.74		$	2.34
General and administrative (net of management fees)	$	0.42		$	0.32		$	0.38		$	0.40
General and administrative													$	0.34		$	0.26

(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		$	63.48		$	49.85
Basis differential and quality adjustments		(6.98	)		(4.77	)		(8.04	)		(3.40	)		(7.52	)		(6.33	)
Transportation		(1.25	)		(1.27	)		(1.28	)		(1.27	)		(1.27	)		(1.31	)
Hedging		(8.80	)		(10.00	)		(5.07	)		(4.81	)		(0.74	)		(4.75	)

Average realized oil price	$	46.16		$	27.83		$	41.01		$	29.63		$	53.95		$	37.46

Comparison of Results of Operations for the Three Months Ended ~~September 30, 2005~~March 31, 2006 and the Three Months Ended ~~September 30, 2004.~~March 31, 2005.

Oil and Gas Production and Revenues

Total oil and gas revenues increased ~~26%~~6% to ~~$31.7~~$45.6 million in the ~~third~~first quarter of ~~2005~~2006 from ~~$25.1~~$43.0 million in the ~~third~~first quarter of ~~2004.~~2005. The increase was due to higher product prices. Total production on an equivalent basis for the ~~third~~first quarter of ~~2005~~2006 decreased by ~~18%~~24% versus the ~~third~~first quarter of ~~2004.~~2005.

Gas production during the ~~third~~first quarter of ~~2005~~2006 totaled ~~1.5~~2.0 Bcf and generated ~~$14.1~~$17.8 million in revenues compared to ~~2.4~~2.7 Bcf and ~~$14.7~~$19.0 million in revenues during the same period in ~~2004.~~2005. The average gas price after hedging impact for the ~~third~~first quarter of ~~2005~~2006 was ~~$9.32~~$9.12 per Mcf compared to ~~$6.11~~$6.92 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 Habanero, High Island Block 119, and Mobile Bay area fields and older properties. The decrease was partially offset by production from our new ~~wells~~well at ~~High Island Block 119.~~East Cameron 90. In addition, initial production from several of our new discoveries was delayed until the second quarter due to weather and equipment availability.

Oil production during the ~~third~~first quarter of ~~2005~~2006 totaled ~~382,000~~515,000 barrels and generated ~~$17.6~~$27.8 million in revenues compared to ~~376,000~~641,000 barrels and ~~$10.5~~$24.0 million in revenues for the same period in ~~2004.~~2005. The average oil price received after hedging impact in the ~~third~~first quarter of 2006 was $53.95 per barrel compared to $37.46 per barrel in the first quarter of 2005. The decrease in production for the first quarter of 2006 compared to the first quarter of 2005 was ~~$46.16 per barrel compared~~primarily due to ~~$27.83 per barrel in the third quarter of 2004. The increase~~normal and expected decline 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~~our Habanero Field and ~~hurricane activity.~~older properties.

Lease Operating Expenses

Lease operating expenses were ~~$5.6~~$5.9 million for the three-month period ended ~~September 30, 2005,~~March 31, 2006, a decrease of ~~$122,000~~$600,000 compared to the same period in ~~2004.~~2005. The decrease was primarily due to the shut-in of our Main Pass 163 Field after the first quarter of 2005, which became uneconomic and is awaiting plugging and abandonment, and a decrease in through-put charges for Habanero resulting from lower production.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended ~~September 30,~~March 31, 2006 and 2005 ~~and 2004~~ was ~~$9.3~~$13.8 million and ~~$10.1~~$15.4 million, respectively. The 8%10% decrease was primarily due to lower production volumes for the ~~third~~first quarter of ~~2005~~2006 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~~period ended ~~September 30,~~March 31, 2006 and 2005 of $1.4 million and ~~2004 of $864,000 and $825,000,~~$861,000, respectively, represents accretion of our asset retirement obligations. The increase was due to the addition of plugging and abandonment ~~obligations.~~obligations associated with new discoveries. See Note 78 to the Consolidated Financial Statements.

2118

General and Administrative

General and administrative expenses, net of amounts capitalized, were ~~$1.6 million and $1.5~~$1.7 million for ~~the~~both three-month periods ended ~~September 30, 2005~~March 31, 2006 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%~~9% to $4.1 million during the three months ended ~~September 30, 2005~~March 31, 2006 from ~~$4.5~~$4.6 million during the three months ended ~~September 30, 2004.~~March 31, 2005. This decrease is primarily attributable to an ~~equity offering which was completed~~increase in capitalized interest resulting from an increase in our investment in unevaluated properties over the ~~second quarter of 2004~~last year due to an increase 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.our exploration program activities.

Income Taxes

Income tax expense was ~~$1.6~~$6.6 million and $4.8 million for the three-month ~~period~~periods ended ~~September 30,~~March 31, 2006 and 2005, ~~compared to zero for the same period last year.~~respectively. 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.taxes.

~~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.

~~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.

2419

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”~~��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 34 to the Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts at ~~September 30, 2005.~~March 31, 2006. There have been no significant changes in market risks faced by the Company since the end of ~~2004.~~2005.

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~~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~~were effective as of March 31, 2006 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.

CALLON PETROLEUM COMPANY

PART II. OTHER INFORMATION

Item 6. EXHIBITS

Exhibits

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)

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)

2621

	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)

10.

Material Contracts

10.1

2006 Stock Incentive Plan

31.

Certifications

31.1

Certification of Chief Executive and Financial Officer pursuant to ~~Rule 13(a)-14(a)~~Section 302 of the Sarbanes-Oxley Act of 2002

32.

Section 1350 Certifications

32.1

Certification of Chief Executive and Financial Officer pursuant to ~~Rule 13(a)-14(b)~~Section 906 of the Sarbanes-Oxley Act of 2002

2722

Exhibit Index


~~Exhibit Number~~		Exhibit NumberTitle of Document

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)

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)

2924

	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)

10.

Material Contracts

10.1

2006 Stock Incentive Plan

31.

Certifications

31.1

Certification of Chief Executive and Financial Officer pursuant to ~~Rule 13(a)-14(a)~~Section 302 of the Sarbanes-Oxley Act of 2002

32.

Section 1350 Certifications

32.1

Certification of Chief Executive and Financial Officer pursuant to ~~Rule 13(a)– 14(b)~~Section 906 of the Sarbanes-Oxley Act of 2002

3025


		Page No.
Part I.	Financial Information

	Consolidated Balance Sheets as of ~~September 30, 2005~~March 31, 2006 and December 31, ~~2004~~2005		3

	Consolidated Statements of Operations for ~~Each of~~ the Three ~~and Nine~~ Months in the Periods Ended ~~September 30,~~March 31, 2006 and March 31, 2005 ~~and September 30, 2004~~		4

	Consolidated Statements of Cash Flows for ~~Each of~~ the ~~Nine~~Three Months in the Periods Ended ~~September 30,~~March 31, 2006 and March 31, 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	14

	Item 3. Quantitative and Qualitative Disclosures about Market Risk	25	20

	Item 4. Controls and Procedures	25	20

Part II.	Other Information

	Item 6. Exhibits	26	21
~~Certification of CEO & CFO Pursuant to Rule 13(a)-14(a)~~2006 Stock Incentive Plan
Certification of ~~CEO & CFO~~Chief Executive and Chief Financial Officer Pursuant to ~~Rule 13(a)-14(b)~~Section 302
Certification of Chief Executive and Chief Financial Officer Pursuant to Section 906

3.4.		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


				Average		Average						Average	Average
	Volumes per		Quantity	Floor		Ceiling				Volumes per	Quantity	Floor	Ceiling
Product	Month		Type	Price		Price		Period		Month	Type	Price	Price	Period
Oil		30,000	Bbls	$	32.50	$	40.00		10/05-12/05	30,000	Bbls	$60.00	$77.10	04/06-12/06
Oil		15,000	Bbls	$	35.00	$	43.50		10/05-12/05	30,000	Bbls	$60.00	$81.75	04/06-12/06
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	100,000	MMBtu	$ 8.00	$10.40	04/06-06/06
Natural Gas		100,000	MMBtu	$	8.50	$	12.16		10/05-09/06	100,000	MMBtu	$ 8.00	$10.30	07/06-09/06
Natural Gas		200,000	MMBtu	$	10.00	$	16.00		11/05-03/06	600,000	MMBtu	$ 8.00	$ 9.30	04/06-12/06


		CALLON PETROLEUM COMPANY

Date: ~~November~~May 8, ~~2005~~2006		By: /s/ Fred L. Callon

		Fred L. Callon, President and Chief
		Executive Officer (on behalf of the
		registrant and as the principal financial
		officer)

2.3.		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~~method. In addition, an adjustment was included in 2005 for the effect of the convertible preferred ~~stock (if dilutive).~~stock.

4.5.		Long-Term Debt

		Long-term debt consisted of the following at: