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, 2006

CALLON PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

Delaware		64-0844345
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

200 North Canal Street
Natchez, Mississippi 39120
(Address of principal executive offices)(Zip code)

(601) 442-1601
(Registrant’s telephone number,
including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definitions of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (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). Yes o No þ

As of November 3, 2006, there were 20,747,773 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, 2006 and December 31, 2005			3
				Consolidated Statements of Operations for Each of the Three and Nine Months in the Periods Ended September 30, 2006 and September 30, 2005			4
				Consolidated Statements of Cash Flows for Each of the Nine Months in the Periods Ended September 30, 2006 and September 30, 2005			5
				Notes to Consolidated Financial Statements			6
				Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
				Item 3. Quantitative and Qualitative Disclosures about Market Risk			23
				Item 4. Controls and Procedures			23
Part II.				Other Information
				Item 6. Exhibits			24
Certification Pursuant to Section 302
Certification Pursuant to Section 906

Callon Petroleum Company

		September 30,				December 31,
		2006				2005
		(Unaudited)				(Note 1)
ASSETS
Current assets:
Cash and cash equivalents		$	2,946			$	2,565
Accounts receivable			30,962				33,195
Deferred tax asset			—				26,770
Restricted investments			—				4,110
Fair market value of derivatives			14,014				889
Other current assets			2,685				1,998
Total current assets			50,607				69,527
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,043,542				937,698
Less accumulated depreciation, depletion and amortization			(582,999	)			(539,399	)
			460,543				398,299
Unevaluated properties excluded from amortization			60,825				49,065
Total oil and gas properties			521,368				447,364
Other property and equipment, net			1,773				1,605
Long-term gas balancing receivable			534				403
Restricted investments-long-term			6,172				1,858
Investment in Medusa Spar LLC			12,560				11,389
Other assets, net			5,864				1,630
Total assets		$	598,878			$	533,776
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	44,109			$	39,323
Fair market value of derivatives			—				1,247
Undistributed oil and gas revenues			1,107				721
Asset retirement obligations-current			5,499				21,660
Current maturities of long-term debt			221				263
Total current liabilities			50,936				63,214
Long-term debt			202,075				188,813
Asset retirement obligations-long-term			33,973				16,613
Deferred tax liability			27,463				31,633
Accrued liabilities to be refinanced			7,000				5,000
Other long-term liabilities			605				455
Total liabilities			322,052				305,728
Stockholders’ equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value, 30,000,000 shares authorized; 20,742,213 and 19,357,138 shares outstanding at September 30, 2006 and December 31, 2005, respectively			207				194
Capital in excess of par value			220,325				220,360
Unearned compensation restricted stock			—				(3,334	)
Other comprehensive income			10,435				(331	)
Retained earnings			45,859				11,159
Total stockholders’ equity			276,826				228,048
Total liabilities and stockholders’ equity		$	598,878			$	533,776

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

Callon Petroleum Company

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Operating revenues:
Oil and gas sales		$	44,878			$	31,722			$	137,516			$	116,402
Operating expenses:
Lease operating expenses			8,070				5,649				21,340				18,382
Depreciation, depletion and amortization			14,973				9,313				43,600				38,392
General and administrative			2,908				1,598				6,558				6,093
Accretion expense			1,082				864				3,832				2,495
Derivative expense			30				5,606				150				6,518
Total operating expenses			27,063				23,030				75,480				71,880
Income from operations			17,815				8,692				62,036				44,522
Other (income) expenses:
Interest expense			4,027				4,050				12,303				12,884
Other (income)			(354	)			(352	)			(1,354	)			(650	)
Total other (income) expenses			3,673				3,698				10,949				12,234
Income before income taxes			14,142				4,994				51,087				32,288
Income tax expense			4,856				1,558				17,700				11,111
Income before Medusa Spar LLC			9,286				3,436				33,387				21,177
Income from Medusa Spar LLC, net of tax			344				247				1,313				1,292
Net income			9,630				3,683				34,700				22,469
Preferred stock dividends			—				—				—				318
Net income available to common shares		$	9,630			$	3,683			$	34,700			$	22,151
Net income per common share:
Basic		$	0.47			$	0.19			$	1.74			$	1.23
Diluted		$	0.45			$	0.17			$	1.64			$	1.09
Shares used in computing net income:
Basic			20,650				19,132				19,919				17,998
Diluted			21,326				21,235				21,154				20,545

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

Callon Petroleum Company

		Nine Months Ended
		September 30,				September 30,
		2006				2005
Cash flows from operating activities:
Net income		$	34,700			$	22,469
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization			44,105				38,908
Accretion expense			3,832				2,495
Amortization of deferred financing costs			1,667				1,529
Non-cash derivative expense			150				5,092
Income from investment in Medusa Spar LLC			(1,313	)			(1,292	)
Deferred income tax expense			17,700				11,111
Non-cash charge related to compensation plans			718				1,561
Excess tax benefits from share-based payment arrangements			(1,449	)			—
Changes in current assets and liabilities:
Accounts receivable			4,569				4,132
Other current assets			(687	)			(279	)
Current liabilities			5,404				797
Change in gas balancing receivable			(131	)			14
Change in gas balancing payable			149				(89	)
Change in other long-term liabilities			1				4
Change in other assets, net			(2,692	)			(361	)
Cash provided by operating activities			106,723				86,091
Cash flows from investing activities:
Capital expenditures			(122,002	)			(57,382	)
Distribution from Medusa Spar LLC			849				464
Cash used by investing activities			(121,153	)			(56,918	)
Cash flows from financing activities:
Change in accrued liabilities to be refinanced			2,000				—
Increase in debt			63,000				7,000
Payments on debt			(51,000	)			(12,000	)
Issuance of common stock			—				2
Buyout of preferred stock			—				(637	)
Equity issued related to employee stock plans			(438	)			(241	)
Excess tax benefits from share-based payment arrangements			1,449				—
Capital leases			(200	)			(448	)
Cash dividends on preferred stock			—				(318	)
Cash provided (used) by financing activities			14,811				(6,642	)
Net increase in cash and cash equivalents			381				22,531
Cash and cash equivalents:
Balance, beginning of period			2,565				3,266
Balance, end of period		$	2,946			$	25,797

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

CALLON PETROLEUM COMPANY

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, 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, 2005 included in the Company’s Annual Report on Form 10-K filed March 15, 2006. The results of operations for the three-month and nine-month periods ended September 30, 2006 are not necessarily indicative of future financial results.
2.		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. For further discussion of the Plans, refer to Note 11 of the Consolidated Financial Statements for the year ended December 31, 2005 included in the Company’s Annual Report on Form 10-K filed March 15, 2006.
		On March 9, 2006, the Board of Directors of the Company approved the 2006 Stock Incentive Plan (“2006 Plan”). The 2006 Plan was approved by the shareholders at the May 4, 2006 annual meeting. Pursuant to the 2006 Plan, 500,000 shares of common stock shall be reserved for issuance upon exercise of stock options, restricted stock or other stock-based awards.
		In August 2006, the Board of Directors approved the award of 520,000 shares of restricted stock from the 1996 Stock Incentive Plan. Of the 520,000 shares, 20,000 shares were granted to non-employee members of the Board of Directors and vested immediately. The remaining 500,000 shares were issued to employees of the Company with 20% vesting immediately and the remaining 80% vesting ratably over the next four years.
		Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123 (revised 2004) (“SFAS 123R”), “Share-Based 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 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 Standard No. 123 (“SFAS 123”) “Accounting for Stock-Based Compensation,” and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact of adopting the new standard.
		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 and nine-month periods ended September 30, 2006 was immaterial.
		SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. The $1.4 million of excess tax benefits classified as a financing cash inflow for the nine-month period ended September 30, 2006 would have been classified as an operating cash flow had the Company not adopted SFAS 123R. There were no cash proceeds from the exercise of stock options for the nine months ended September 30, 2006 due to the fact that all options were exercised through net-share settlements.
		For the three-month period ended September 30, 2006, we recorded stock-based compensation expense of $2.3 million, of which $1.2 million was included in general and administrative expenses and $1.1 million was capitalized to oil and gas properties. For the nine-month period ended September 30, 2006, we recorded stock-based compensation expense of $2.8 million, of which $1.5 million was included in general and administrative expenses and $1.3 million 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 535,666 at September 30, 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-month and nine-month periods ended September 30, 2005 (in thousands, except per share amounts):

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

Stock Options

The Company uses the Black-Scholes option pricing model to estimate the fair value of stock-based awards with the following weighted-average assumptions for the indicated periods.

		Nine Months Ended
		September 30,
		2006				2005
Dividend yield			—				—
Expected volatility			38.9	%			39.4	%
Risk-free interest rate			4.6	%			4.2	%
Expected life of option (in years)			5				4
Weighted-average grant-date fair value		$	7.72			$	5.59
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. There were no stock options granted during the three months ended September 30, 2006 and 2005.

		At September 30, 2006, there was $249,000 of unrecognized compensation cost related to nonvested stock options, which is expected to be recognized over a weighted-average period of 2.3 years.
		The following table represents stock option activity for the nine months ended September 30, 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			(480,333	)			10.66
Forfeited			—				—
Outstanding options at end of period			740,225			$	9.93			4.31 Yrs.
Outstanding exercisable at end of period			695,225			$	9.44			4.01 Yrs.

		The aggregate intrinsic value of options outstanding was $2.9 million and the aggregate intrinsic value of options exercisable was $2.9 million. Total intrinsic value of options exercised was $4.1 million for the nine months ended September 30, 2006.
		The following table summarizes our nonvested stock option activity for the nine months ended September 30, 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			(9,000	)			16.71
Forfeited			—				—
Nonvested stock options at end of period			45,000			$	17.57

		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. The compensation expense for these awards was determined based on the market price of our stock at the date of grant applied to the total numbers of shares that were anticipated to fully vest. As of September 30, 2006, there was $8.7 million of unrecognized compensation cost associated with these awards.
		The following table represents unvested restricted stock activity for the nine months ended September 30, 2006:

		Number of				Weighted-Average
		Shares				Grant Price
Outstanding shares at beginning of period			272,000			$	13.66
Granted			520,000				15.83
Vested			(188,000	)			15.04
Forfeited			(4,200	)			13.82
Outstanding shares at end of period			599,800			$	15.10

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. In addition, an adjustment was included for the nine-month period ended September 30, 2005 for the dilutive effect of the convertible preferred stock.

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,
		2006				2005				2006				2005
(a) Net income available to common Shares		$	9,630			$	3,683			$	34,700			$	22,151
Preferred dividends assuming Conversion of preferred stock (if dilutive)			—				—				—				318
(b) Income available to common shares assuming conversion of preferred stock (if dilutive)		$	9,630			$	3,683			$	34,700			$	22,469
(c) Weighted average shares outstanding			20,650				19,132				19,919				17,998
Dilutive impact of stock options			193				410				258				333
Dilutive impact of warrants			443				1,523				894				1,309
Dilutive impact of restricted stock			40				76				83				62
Convertible preferred stock (if dilutive)			—				94				—				843
(d) Total diluted shares			21,326				21,235				21,154				20,545
Basic income per share (a¸c)		$	0.47			$	0.19			$	1.74			$	1.23
Diluted income per share (b¸d)		$	0.45			$	0.17			$	1.64			$	1.09
Stock options and warrants excluded due to the exercise price being greater than the stock price (in thousands)			30				—				27				12

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 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 contracts are also recorded within derivative expense (income).

		Cash settlements on effective cash flow hedges during the three-month period ended September 30, 2006 resulted in an increase in oil and gas sales of $3.2 million compared to a reduction of oil and gas sales of $3.6 million for the same period in 2005. The nine-month periods ended September 30, 2006 and 2005 included an increase in oil and gas sales of $5.7 million and a reduction of oil and gas sales of $8.3 million, respectively, for cash settlements on effective cash flow hedges.
		The Company recognized derivative expense of $30,000 and $150,000 for the three-month and nine-month periods ended September 30, 2006 and $5.6 million and $6.5 million for the three-month and nine-month periods ended September 30, 2005, respectively.

		Included in derivative expense for the three-month and nine-month periods ended September 30, 2005 were cash settlements on ineffective derivative contracts of $1.4 million and $716,000, respectively. These contracts were deemed ineffective as a result of a shortfall in production volumes due to downtime resulting from damages caused by Hurricanes Katrina and Rita in the third quarter of 2005. In addition, continued downtime resulting from damages to oil and gas transmission lines and facilities owned by third parties caused some of our derivative contracts for October and November 2005 to be deemed ineffective. Due to the fact that it was probable that the shortfall in production volumes would continue in October and November, we recognized a non-cash derivative expense of $3.8 million in the three-month period ended September 30, 2005 to reclassify the unrealized loss on these contracts, which was included in other comprehensive income (loss), to earnings.
		As of September 30, 2006, the fair value of the outstanding oil and gas derivative contracts was a current asset of $14.0 million and a long-term asset of $2.0 million.
		Listed in the table below are the outstanding derivative contracts as of September 30, 2006:

Collars

								Average				Average
		Volumes per				Quantity		Floor				Ceiling
Product		Month				Type		Price				Price				Period
Oil			30,000			Bbls		$	60.00			$	77.10				10/06-12/06
Oil			30,000			Bbls		$	60.00			$	81.75				10/06-12/06
Oil			25,000			Bbls		$	65.00			$	83.30				01/07-12/07
Oil			25,000			Bbls		$	65.00			$	94.20				01/07-12/07
Natural Gas			600,000			MMBtu		$	8.00			$	9.30				10/06-12/06
Natural Gas			300,000			MMBtu		$	7.00			$	13.10				10/06-12/06
Natural Gas			600,000			MMBtu		$	8.00			$	12.70				01/07-12/07

5. Long-Term Debt

Long-term debt consisted of the following at:

		September 30,				December 31,
		2006				2005
		(In thousands)
Senior Secured Credit Facility (matures July 31, 2010)		$	12,000			$	—
9.75% Senior Notes (due 2010), net of discount			189,361				187,941
Capital lease			935				1,135
Total debt			202,296				189,076
Less current portion:
Capital lease			221				263
Long-term debt		$	202,075			$	188,813

On August 31, 2006, the Company closed on a four-year amended and restated senior secured credit facility with Union Bank of California, N.A. The credit facility includes more favorable borrowing rates and financing flexibility. The initial borrowing base is $75 million, which will be 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 major fields. As of September 30, 2006, there was $12 million outstanding under the facility with a weighted average interest rate of 6.96% and $63 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
		September 30,								September 30,
		2006				2005				2006				2005
Net income		$	9,630			$	3,683			$	34,700			$	22,469
Other comprehensive income (loss):
Change in fair value of derivatives			8,472				257				10,766				(2,736	)
Total comprehensive income		$	18,102			$	3,940			$	45,466			$	19,733

7.

Asset Retirement Obligations

The following table summarizes the activity for the Company’s asset retirement obligation for the nine-month period ended September 30, 2006:

		Nine Months Ended
		September 30, 2006
Asset retirement obligation at beginning of period		$	38,273
Accretion expense			3,832
Liabilities incurred			1,390
Liabilities settled			(16,411	)
Revisions to estimate			12,388
Asset retirement obligation at end of period			39,472
Less: current asset retirement obligation			(5,499	)
Long-term asset retirement obligation		$	33,973

		The upward revisions to estimate were primarily due to a sharp increase in industry service costs 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.
		Assets, primarily U.S. Government securities, of approximately $6.2 million at September 30, 2006, are recorded as restricted investments. These assets are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and gas properties.
8.		Accounting Pronouncements
		In June 2006, the Financial Accounting Standards Board (“FASB”) released interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position must meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. The effective date for FIN 48 is fiscal years beginning after December 15, 2006. The Company is currently reviewing the provisions of FIN 48 and has not yet determined the impact of adoption.
		In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, (“SFAS 157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The Company is currently reviewing the provisions of SFAS 157 and has not yet determined the impact of adoption.
		In September 2006, the Securities and Exchange Commission issued SAB No. 108, (“SAB 108”), Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. The guidance in SAB 108 is effective for fiscal years ending after November 15, 2006.

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.

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, 2006, we had net cash and cash equivalents of $3 million and $63 million of availability under our senior secured credit facility. Cash provided from operating activities during the nine-month period ended September 30, 2006 totaled $107 million, a 24% increase when compared to 2005. The increase was primarily attributable to higher oil and gas prices. Net capital expenditures from the cash flow statement for the nine-month period ended September 30, 2006 totaled $122 million.

We are experiencing downhole mechanical problems at the A-1 well in the Medusa field. This will have a negative impact on our cash flow for the fourth quarter of 2006 and possibly into the first quarter of 2007 depending on the nature of the problem and the timing of repairs. However, production of our reserves during 2006, despite the problem at Medusa, is projected to be higher than that experienced during 2005 due to 11 new discoveries that have commenced production during 2006 or are scheduled to commence initial production during the remainder of 2006. Additionally, 2005 production was negatively impacted by tropical weather conditions. Given the current pricing environment for oil and natural gas and the higher production volumes, our cash provided by operating activities for 2006 is expected to exceed the amount realized during 2005.

Our capital expenditure plans for 2006, including capitalized interest and general and administrative expenses, will require approximately $150 million of funding. We expect that cash flows generated from operations during 2006 and current availability under our senior secured credit facility will provide the capital necessary to fund these planned capital expenditures as well as our asset retirement obligations which are expected to be approximately $14 million. See the Capital Expenditures section below for a more detailed discussion of our capital expenditures for 2006.

On August 31, 2006, we closed on a four-year amended and restated senior secured credit facility with Union Bank of California, N.A. The credit facility includes more favorable borrowing rates and financing flexibility. The initial borrowing base is $75 million which will be 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 our major fields.

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

The following table describes our outstanding contractual obligations (in thousands) as of September 30, 2006:

Contractual						Less Than				One-Three				Four-Five				After-Five
Obligations		Total				One Year				Years				Years				Years
Senior Secured Credit Facility		$	12,000			$	—			$	—			$	12,000			$	—
9.75% Senior Notes			200,000				—				—				200,000				—
Capital Lease (future minimum payments)			1,374				366				485				447				76
Throughput Commitments:
Medusa Spar LLC			9,740				3,328				5,388				1,024				—
Medusa Oil Pipeline			452				130				146				104				72
		$	223,566			$	3,824			$	6,019			$	213,575			$	148

Capital Expenditures

Capital expenditures from the cash flow statement were $122 million for the nine months ended September 30, 2006. Of this amount approximately $110 million was for exploration and development costs related to oil and gas properties and the remaining $12 million was for plugging and abandonment activities.

Included in the $110 million for exploration and development costs related to oil and gas properties was approximately $69 million of costs for the Gulf of Mexico Shelf Area, which included drilling costs associated with nine wells and completion and development of our discoveries. Five of the nine wells were successful, two were unsuccessful and two were in progress as of September 30, 2006. In the onshore Louisiana area we spent $12 million, which was associated with the drilling and completion of our Prairie Beach discovery as well as the drilling of two exploratory wells which are in progress. Interest of approximately $5 million and general and administrative costs allocable directly to exploration and development projects of approximately $7 million were capitalized for the first nine months of 2006. The remainder of the capital expended includes the acquisition of seismic and leases and costs related to our Gulf of Mexico deepwater area.

Capital expenditures for the remainder of 2006 are forecast to be approximately $40 million and include:

	•		the completion and development of our 2006 discoveries, including development wells;
	•		the non-discretionary drilling of exploratory wells;
	•		the acquisition of seismic and leases; and
	•		capitalized interest and general and administrative costs.

In addition, we are projecting to spend $2 million in the fourth quarter of 2006 for 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 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.

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,
		2006				2005				2006				2005
Net production :
Oil (MBbls)			381				382				1,340				1,613
Gas (MMcf)			2,710				1,510				7,241				6,570
Total production (MMcfe)			4,998				3,804				15,278				16,246
Average daily production (MMcfe)			54.3				41.3				56.0				59.5
Average sales price:
Oil (Bbls) (a)		$	62.31			$	46.16			$	58.33			$	41.01
Gas (Mcf)			7.79				9.32				8.20				7.65
Total (Mcfe)			8.98				8.34				9.00				7.16
Oil and gas revenues:
Oil revenue		$	23,754			$	17,649			$	78,133			$	66,142
Gas revenue			21,124				14,073				59,383				50,260
Total		$	44,878			$	31,722			$	137,516			$	116,402
Oil and gas production costs:
Lease operating expense		$	8,070			$	5,649			$	21,340			$	18,382
Additional per Mcfe data:
Sales price		$	8.98			$	8.34			$	9.00			$	7.16
Lease operating expense			1.61				1.49				1.40				1.13
Operating margin		$	7.37			$	6.85			$	7.60			$	6.03
Depletion, depreciation and amortization		$	3.00			$	2.45			$	2.85			$	2.36
General and administrative (net of management fees)		$	0.58			$	0.42			$	0.43			$	0.38
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
Average NYMEX oil price		$	70.51			$	63.19			$	68.23			$	55.40
Basis differential and quality adjustments			(6.91	)			(6.98	)			(7.81	)			(8.04	)
Transportation			(1.29	)			(1.25	)			(1.28	)			(1.28	)
Hedging			—				(8.80	)			(0.81	)			(5.07	)
Average realized oil price		$	62.31			$	46.16			$	58.33			$	41.01

Oil and Gas Production and Revenues

Total oil and gas revenues increased 41% to $44.9 million in the third quarter of 2006 from $31.7 million in the third quarter of 2005. The increase was primarily due to higher gas production and oil prices. Total production on an equivalent basis for the third quarter of 2006 increased by 31% versus the third quarter of 2005, which included downtime for tropical storms and hurricane activity.

Gas production during the third quarter of 2006 totaled 2.7 Bcf and generated $21.1 million in revenues compared to 1.5 Bcf and $14.1 million in revenues during the same period in 2005. The average gas price after hedging impact for the third quarter of 2006 was $7.79 per Mcf compared to $9.32 per Mcf for the same period last year. The 80% increase in production was primarily due to production from our new wells at East Cameron Block 90, North Padre Island Block 913, High Island Block 73, Brazos Block 405 and West Cameron Block 295 and third quarter 2005 production being negatively impacted by tropical weather conditions. The increase was partially offset by normal and expected declines in production from our Habanero, High Island Block 119 and Mobile Bay area fields and older properties.

Oil production during the third quarter of 2006 totaled 381,000 barrels and generated $23.8 million in revenues compared to 382,000 barrels and $17.6 million in revenues for the same period in 2005. The average oil price received after hedging impact in the third quarter of 2006 was $62.31 per barrel compared to $46.16 per barrel in the third quarter of 2005. Production was flat for the third quarter of 2006 compared to the third quarter of 2005, which was negatively impacted by tropical weather conditions.

Lease Operating Expenses

Lease operating expenses were $8.1 million for the three-month period ended September 30, 2006, an increase of $2.4 million compared to the same period in 2005. The increase was primarily due to new wells coming on line, higher costs for fuel and marine transportation and an increase in insurance rates for our policies which were renewed on April 1, 2006. In the third quarter of 2006, we incurred higher throughput charges at Medusa due to an increase in production as compared to the third quarter of 2005 where production was negatively impacted by tropical weather conditions. In addition, we incurred approximately $1.4 million for pipeline repairs at our South Marsh Island Block 261 field during the third quarter of 2006.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended September 30, 2006 and 2005 was $15.0 million and $9.3 million, respectively. The 61% increase was due to higher production volumes and a higher depletion rate resulting from higher costs associated with our exploration and development activities in the Gulf of Mexico.

Accretion Expense

Accretion expense for the three-month periods ended September 30, 2006 and 2005 of $1.1 million and $864,000, respectively, represents accretion of our asset retirement obligations. The increase was primarily due to the addition of plugging and abandonment obligations associated

with new discoveries and an increase in plugging and abandonment cost estimates. See Note 7 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses, net of amounts capitalized, were $2.9 million and $1.6 million for the three-month periods ended September 30, 2006 and 2005, respectively. The 82% increase was primarily due to non-cash charges of approximately $1.1 million that were recognized in the third quarter of 2006 for the vesting of 20% of restricted shares issued as part of the 2006 restricted stock award. See Note 2 for more details.

Interest Expense

Interest expense was flat at $4.0 million during the three months ended September 30, 2006 compared to $4.1 million during the three months ended September 30, 2005.

Income Taxes

Income tax expense was $4.9 million and $1.6 million for the three-month periods ended September 30, 2006 and 2005, respectively. The increase was primarily due to an increase in income before income taxes.

Oil and Gas Production and Revenues

Total oil and gas revenues increased 18% to $137.5 million in the first nine months of 2006 from $116.4 million in the first nine months of 2005. The increase was primarily due to higher product prices. Total production on an equivalent basis for the nine months ended September 30, 2006 decreased by 6% versus 2005.

Gas production during the nine months ended September 30, 2006 totaled 7.2 Bcf and generated $59.4 million in revenues compared to 6.6 Bcf and $50.3 million in revenues during the same period in 2005. The average gas price after hedging impact for the nine months ended September 30, 2006 was $8.20 per Mcf compared to $7.65 per Mcf for the same period last year. The 10% increase in production was primarily due to new producing wells at East Cameron Block 90, North Padre Island Block 913, High Island Block 73, Brazos Block 405 and West Cameron Block 295, and 2005 production being negatively impacted by tropical weather conditions. The increase was partially offset by the normal and expected declines in production from our Habanero, High Island Block 119, and Mobile Bay area fields and older properties.

Oil production during the nine months ended September 30, 2006 totaled 1,340,000 barrels and generated $78.1 million in revenues compared to 1,613,000 barrels and $66.1 million in revenues for the same period in 2005. The average oil price received after hedging impact in the first nine months of 2006 was $58.33 per barrel compared to $41.01 per barrel in the first nine months 2005. The decrease in production was primarily due to normal and expected declines in production from our Habanero Field and older properties.

Lease Operating Expenses

Lease operating expenses were $21.3 million for the nine-month period ended September 30, 2006, an increase of $3.0 million compared to the same period in 2005. The increase was primarily due to new wells coming on line, higher costs for fuel and marine transportation and an increase in insurance rates for our policies which were renewed on April 1, 2006. The increase was partially offset by the shut-in of our Main Pass Block 163 Field after the first quarter of 2005, which became uneconomic and is being plugged and abandoned, and a decrease in throughput charges for Habanero resulting from lower production.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the nine-months ended September 30, 2006 and 2005 was $43.6 million and $38.4 million, respectively. The 14% increase was a result of a higher depletion rate primarily due to higher costs associated with exploration and development in the Gulf of Mexico.

Accretion Expense

Accretion expense for the nine-month period ended September 30, 2006 and 2005 of $3.8 million and $2.5 million, respectively, represents accretion of our asset retirement obligations. The increase was primarily due to the addition of plugging and abandonment obligations associated with new discoveries and an increase in plugging and abandonment estimates. See Note 7 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses, net of amounts capitalized, were $6.6 million and $6.1 million for the nine-month periods ended September 30, 2006 and 2005, respectively. The increase was partially due to non-cash charges of approximately $1.1 million recognized in the third quarter of 2006 resulting from the vesting of 20% of restricted shares issued as part of the 2006 restricted stock award. These non-cash charges was offset by non-cash charges of $1.0 million we recognized in the second quarter of 2005 for the accelerated vesting of performance shares pursuant to the terms of the plan due to death or disability for an executive officer and two directors of the Company. See Note 2 for more details on the 2006 restricted stock award.

Interest Expense

Interest expense decreased by 5% to $12.3 million during the nine months ended September 30, 2006 from $12.9 million during the nine months ended September 30, 2005. This decrease is primarily attributable to an increase in capitalized interest resulting from an increase in our investment in unevaluated properties over the last year due to expanded exploration activities.

Income Taxes

Income tax expense was $17.7 million and $11.1 million for the nine-month periods ended September 30, 2006 and 2005, respectively. The increase was due to an increase in income before income taxes.

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 may utilize 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 may utilize price “collars” to reduce the risk of changes in oil and gas prices. Under these arrangements, no payments are due by either party as 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 may purchase “puts” which reduce 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 floor, 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 4 to the Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts at September 30, 2006. There have been no significant changes in market risks faced by the Company since the end of 2005.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. 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”)) were effective as of September 30, 2006.

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		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)

	4.4		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)
	4.5		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 Section 302 of the Sarbanes-Oxley Act of 2002

32.

Section 1350 Certifications

32.1

Certification of Chief Executive and Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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 7, 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)

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		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)
	4.4		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)

4.5

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 Section 302 of the Sarbanes-Oxley Act of 2002

32.

Section 1350 Certifications

32.1

Certification of Chief Executive and Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002