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 June 30, 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 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 August 4, 2006, there were 20,646,573 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

 

 

CALLON PETROLEUM COMPANY

TABLE OF CONTENTS

		Page No.
Part I. Financial Information
Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005			3
Consolidated Statements of Operations for Each of the Three and Six Months in the Periods Ended June 30, 2006 and June 30, 2005			4
Consolidated Statements of Cash Flows for Each of the Six Months in the Periods Ended June 30, 2006 and June 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			22
Item 4. Controls and Procedures			22
Part II. Other Information
Item 4. Submission of Matters to a Vote of the Security Holders			23
Item 6. Exhibits			23
Certification of CEO and CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except share data)

		June 30,				December 31,
		2006				2005
		(Unaudited)				(Note 1)
ASSETS
Current assets:
Cash and cash equivalents		$	1,046			$	2,565
Accounts receivable			27,461				33,195
Deferred tax asset			9,768				26,770
Restricted investments			4,200				4,110
Fair market value of derivatives			4,382				889
Other current assets			1,755				1,998
Total current assets			48,612				69,527
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,010,963				937,698
Less accumulated depreciation, depletion and amortization			(568,026	)			(539,399	)
			442,937				398,299
Unevaluated properties excluded from amortization			58,987				49,065
Total oil and gas properties			501,924				447,364
Other property and equipment, net			1,741				1,605
Long-term gas balancing receivable			660				403
Restricted investments-long-term			1,896				1,858
Investment in Medusa Spar LLC			12,510				11,389
Other assets, net			1,962				1,630
Total assets		$	569,305			$	533,776
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	35,845			$	39,323
Fair market value of derivatives			1,119				1,247
Undistributed oil and gas revenues			1,294				721
Asset retirement obligations-current			22,783				21,660
Current maturities of long-term debt			229				263
Total current liabilities			61,270				63,214
Long-term debt			196,641				188,813
Asset retirement obligations-long-term			25,833				16,613
Deferred tax liability			28,044				31,633
Accrued liabilities to be refinanced			—				5,000
Other long-term liabilities			774				455
Total liabilities			312,562				305,728
Stockholders’ equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value, 30,000,000 shares authorized; 20,578,205 and 19,357,138 shares outstanding at June 30, 2006 and December 31, 2005, respectively			206				194
Capital in excess of par value			218,345				220,360
Unearned compensation restricted stock			—				(3,334	)
Other comprehensive income			1,963				(331	)
Retained earnings			36,229				11,159
Total stockholders’ equity			256,743				228,048
Total liabilities and stockholders’ equity		$	569,305			$	533,776

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

Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited)
(In thousands, except per share amounts)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Operating revenues:
Oil and gas sales		$	47,057			$	41,668			$	92,638			$	84,680
Operating expenses:
Lease operating expenses			7,365				6,197				13,270				12,733
Depreciation, depletion and amortization			14,791				13,671				28,627				29,079
General and administrative			1,924				2,801				3,650				4,495
Accretion expense			1,331				770				2,750				1,631
Derivative expense			30				533				120				912
Total operating expenses			25,441				23,972				48,417				48,850
Income from operations			21,616				17,696				44,221				35,830
Other (income) expenses:
Interest expense			4,128				4,265				8,276				8,834
Other (income)			(670	)			(96	)			(1,000	)			(298	)
Total other (income) expenses			3,458				4,169				7,276				8,536
Income before income taxes			18,158				13,527				36,945				27,294
Income tax expense			6,294				4,735				12,844				9,553
Income before Medusa Spar LLC			11,864				8,792				24,101				17,741
Income from Medusa Spar LLC net of tax			439				519				969				1,045
Net income			12,303				9,311				25,070				18,786
Preferred stock dividends			—				—				—				318
Net income available to common shares		$	12,303			$	9,311			$	25,070			$	18,468
Net income per common share:
Basic		$	0.61			$	0.52			$	1.26			$	1.04
Diluted		$	0.57			$	0.46			$	1.17			$	0.92
Shares used in computing net income:
Basic			20,314				17,736				19,855				17,703
Diluted			21,448				20,345				21,388				20,511

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

Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited)
(In thousands)

		Six Months Ended
		June 30,				June 30,
		2006				2005
Cash flows from operating activities:
Net income		$	25,070			$	18,786
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization			28,996				29,403
Accretion expense			2,750				1,631
Amortization of deferred financing costs			1,106				998
Non-cash derivative expense			120				912
Income from investment in Medusa Spar LLC			(969	)			(1,045	)
Deferred income tax expense			12,844				9,553
Non-cash charge related to compensation plans			267				1,600
Excess tax benefits from share-based payment arrangements			(1,304	)			—
Changes in current assets and liabilities:
Accounts receivable			1,282				(1,669	)
Other current assets			243				(1,072	)
Current liabilities			5,579				(5,132	)
Change in gas balancing receivable			(257	)			54
Change in gas balancing payable			103				(118	)
Change in other long-term liabilities			216				(7	)
Change in other assets, net			(704	)			(341	)
Cash provided by operating activities			75,342				53,553
Cash flows from investing activities:
Capital expenditures			(80,015	)			(32,566	)
Distribution from Medusa Spar LLC			370				266
Cash used by investing activities			(79,645	)			(32,300	)
Cash flows from financing activities:
Change in accrued liabilities to be refinanced			(5,000	)			—
Increase in debt			39,000				7,000
Payments on debt			(32,000	)			(12,000	)
Issuance of common stock			—				2
Equity issued related to employee stock plans			(381	)			(154	)
Excess tax benefits from share-based payment arrangements			1,304				—
Capital leases			(139	)			(326	)
Cash dividends on preferred stock			—				(318	)
Cash provided (used) by financing activities			2,784				(5,796	)
Net increase (decrease) in cash and cash equivalents			(1,519	)			15,457
Cash and cash equivalents:
Balance, beginning of period			2,565				3,266
Balance, end of period		$	1,046			$	18,723

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

CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 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, 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 six-month periods ended June 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 Company’s 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.
		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 six-month periods ended June 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 $1.3 million of excess tax benefits classified as a financing cash inflow for the six-month period ended June 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 six months ended June 30, 2006 due to the fact that all options were exercised through net-share settlements.
		For the three-month period ended June 30, 2006, we recorded stock-based compensation expense of $234,000, of which $125,000 was included in general and administrative expenses and $109,000 was capitalized to oil and gas properties. For the six-month period ended June 30, 2006, we recorded stock-based compensation expense of $468,000, of which $250,000 was included in general and administrative expenses and $218,000 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 1,423,300 at June 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 six-month periods ended June 30, 2005 (in thousands, except per share amounts):

		Three Months Ended				Six Months Ended
		June 30, 2005				June 30, 2005
Net income available to common-as reported		$	9,311			$	18,468
Add: Stock-based compensation expense included in net income as reported, net of tax			770				962
Deduct: Total stock-based compensation expense under fair value based method, net of tax			(833	)			(1,063	)
Net income available to common-pro forma		$	9,248			$	18,367
Net income per share available to common:
Basic-as reported		$	0.52			$	1.04
Basic-pro forma		$	0.52			$	1.04
Diluted-as reported		$	0.46			$	0.92
Diluted-pro forma		$	0.45			$	0.91

		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.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Dividend yield			—				—				—				—
Expected volatility			—				38.2	%			38.9	%			39.4	%
Risk-free interest rate			—				4.1	%			4.6	%			4.2	%
Expected life of option (in years)			—				5				5				4
Weighted-average grant-date fair value			—				5.34				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 June 30, 2006.

		At June 30, 2006, there was $266,000 of unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted-average period of 2.5 years.
		The following table represents stock option activity for the six months ended June 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			(411,833	)			10.55
Forfeited			—				—
Outstanding options at end of period			808,725				10.05			4.27 Yrs.
Outstanding exercisable at end of period			763,725			$	9.60			3.97 Yrs.

		The aggregate intrinsic value of options outstanding was $7.5 million and the aggregate intrinsic value of options exercisable was $7.4 million. Total intrinsic value of options exercised was $3.7 million for the six months ended June 30, 2006.
		The following table summarizes our nonvested stock option activity for the six months ended June 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, which ends in the third quarter of 2009. 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 June 30, 2006, we had unearned stock-based compensation of $2.9 million associated with these awards.
		The following table represents unvested restricted stock activity for the six months ended June 30, 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

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 in 2005 for the 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								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
(a) Net income available to common shares		$	12,303			$	9,311			$	25,070			$	18,468
Preferred dividends assuming conversion of preferred stock (if dilutive)			—				—				—				318
(b) Income available to common shares assuming conversion of preferred stock (if dilutive)		$	12,303			$	9,311			$	25,070			$	18,786
(c) Weighted average shares outstanding			20,314				17,736				19,855				17,703
Dilutive impact of stock options			247				284				294				299
Dilutive impact of warrants			775				1,177				1,133				1,222
Dilutive impact of restricted stock			112				44				106				57
Convertible preferred stock (if dilutive)			—				1,104				—				1,230
(d) Total diluted shares			21,448				20,345				21,388				20,511
Basic income per share (a¸c)		$	0.61			$	0.52			$	1.26			$	1.04
Diluted income per share (b¸d)		$	0.57			$	0.46			$	1.17			$	0.92
Stock options and warrants excluded due to the exercise price being greater than the stock price (in thousands)			15				40				15				30

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 contacts are also recorded within derivative expense (income).

		Cash settlements on effective cash flow hedges during the three-month period ended June 30, 2006 resulted in an increase in oil and gas sales of $1.8 million compared to a reduction of oil and gas sales of $1.8 million for the same period in 2005. The six-month periods ended June 30, 2006 and 2005 resulted in an increase in oil and gas sales of $2.5 million and a reduction of oil and gas sales of $4.6 million, respectively.
		The Company recognized derivative expense of $30,000 and $533,000 for the three-month periods ended June 30, 2006 and 2005, respectively, and derivative expense of $120,000 and $912,000 for the six-month periods ended June 30, 2006 and 2005, respectively, relating to the amortization of derivative contract premiums.
		As of June 30, 2006, the fair value of the outstanding gas derivative contracts was a current asset of $4.4 million and the fair value of the outstanding oil derivative contracts was a current liability of $1.1 million and a long-term liability of $214,000.
		Listed in the table below are the outstanding derivative contracts as of June 30, 2006:

     Collars

								Average				Average
		Volumes per				Quantity		Floor				Ceiling
Product		Month				Type		Price				Price				Period
Oil			30,000			Bbls		$	60.00			$	77.10			07/06—12/06
Oil			30,000			Bbls		$	60.00			$	81.75			07/06—12/06
Oil			25,000			Bbls		$	65.00			$	83.30			01/07—12/07
Natural Gas			100,000			MMBtu		$	8.00			$	10.30			07/06—09/06
Natural Gas			600,000			MMBtu		$	8.00			$	9.30			07/06—12/06

5.

Long-Term Debt

Long-term debt consisted of the following at:

		June 30,				December 31,
		2006				2005
		(In thousands)
Senior Secured Credit Facility
(matures July 31, 2007)		$	7,000			$	—
9.75% Senior Notes (due 2010), net of discount			188,874				187,941
Capital lease			996				1,135
Total debt			196,870				189,076
Less current portion:
Capital lease			229				263
Long-term debt		$	196,641			$	188,813

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 June 30, 2006, there was $7 million outstanding under the facility with a weighted average interest rate of 7.1% 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								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Net income		$	12,303			$	9,311			$	25,070			$	18,786
Other comprehensive income (loss):
Change in fair value of derivatives			1,019				1,856				2,294				(2,993	)
Total comprehensive income		$	13,322			$	11,167			$	27,364			$	15,793

7.

Asset Retirement Obligations

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

		Six Months Ended
		June 30, 2006
Asset retirement obligation at beginning of period		$	38,273
Accretion expense			2,750
Liabilities incurred			1,109
Liabilities settled			(4,834	)
Revisions to estimate			11,318
Asset retirement obligation at end of period			48,616
Less: current asset retirement obligation			(22,783	)
Long-term asset retirement obligation		$	25,833

		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.
		Assets, primarily U.S. Government securities, of approximately $6.1 million at June 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 released interpretation No. 48, Accounting for Uncertainty in Income Taxes, (“FIN 48”). 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.

		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 June 30, 2006, we had net cash and cash equivalents of $1 million and $63 million of availability under our senior secured credit facility. Cash provided from operating activities during the six-month period ended June 30, 2006 totaled $75 million, a 40% increase when compared to 2005. The increase was primarily attributable to oil and gas prices. Net capital expenditures from the cash flow statement for the six-month period ended June 30, 2006 totaled $80 million.
		Production of our 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 and 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 is expected to exceed 2005.
		Our capital expenditure plans for 2006, including capitalized interest and general and administrative expenses, will require $150 million of funding. We expect that cash flow generated from operations during 2006 and current availability under our senior secured credit facility, if necessary, will provide the capital necessary to fund these planned capital expenditures as well as our asset retirement obligations which are expected to be approximately $30 million. See the Capital Expenditures section below for a more detailed discussion of our capital expenditures for 2006.
		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 June 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 lenders for our senior secured credit facility have approved in principle a three-year maturity date extension to July 31, 2010. The closing of the transaction is subject to the drafting of a restated and amended credit facility which is expected to occur in August 2006.
		The following table describes our outstanding contractual obligations (in thousands) as of June 30, 2006:

						Less Than				One-Three				Four-Five				After-Five
Contractual Obligations		Total				One Year				Years				Years				Years
Senior Secured Credit Facility		$	7,000			$	—			$	7,000			$	—			$	—
9.75% Senior Notes			200,000				—				—				200,000				—
Capital Lease (future minimum payments)			1,477				383				514				448				132
Throughput Commitments:
Medusa Spar LLC			10,708				3,528				5,160				2,020				—
Medusa Oil Pipeline			503				155				159				107				82
		$	219,688			$	4,066			$	12,833			$	202,575			$	214

		Capital Expenditures
		Capital expenditures from the cash flow statement were $80 million for the six months ended June 30, 2006. Of this amount approximately $71 million was for exploration and development costs related to oil and gas properties and the remaining $9 million was for plugging and abandonment activities.
		Included in the $71 million for exploration and development costs related to oil and gas properties was approximately $46 million of costs for the Gulf of Mexico Shelf Area which included the drilling costs of eight wells and completion and development of our discoveries. Four of the eight wells were successful, one was unsuccessful and three were in progress. In the Onshore Louisiana area we spent $8 million, which was associated with the drilling and beginning stage of completion for our Prairie Beach discovery. Interest of approximately $3 million and general and administrative costs allocable directly to exploration and development projects of approximately $4 million were capitalized for the first six 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 $79 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 $21 million in the second half 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								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Net production :
Oil (MBbls)			443				590				958				1,230
Gas (MMcf)			2,581				2,313				4,530				5,060
Total production (MMcfe)			5,239				5,850				10,281				12,443
Average daily production (MMcfe)			57.6				64.3				56.8				68.7
Average sales price:
Oil (Bbls) (a)		$	59.99			$	41.53			$	56.74			$	39.41
Gas (Mcf)			7.93				7.43				8.44				7.15
Total (Mcfe)			8.98				7.12				9.01				6.81
Oil and gas revenues:
Oil revenue		$	26,580			$	24,484			$	54,379			$	48,493
Gas revenue			20,477				17,184				38,259				36,187
Total		$	47,057			$	41,668			$	92,638			$	84,680
Oil and gas production costs:
Lease operating expense		$	7,365			$	6,197			$	13,270			$	12,733
Additional per Mcfe data:
Sales price		$	8.98			$	7.12			$	9.01			$	6.81
Lease operating expense			1.41				1.06				1.29				1.02
Operating margin		$	7.57			$	6.06			$	7.72			$	5.79
Depletion, depreciation and amortization		$	2.82			$	2.34			$	2.78			$	2.34
General and administrative (net of management fees)		$	0.37			$	0.48			$	0.36			$	0.36

(a)

Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:

Average NYMEX oil price		$	70.70			$	53.17			$	67.09			$	51.51
Basis differential and quality adjustments			(7.83	)			(7.37	)			(7.93	)			(6.89	)
Transportation			(1.29	)			(1.28	)			(1.28	)			(1.30	)
Hedging			(1.59	)			(2.99	)			(1.14	)			(3.91	)
Average realized oil price		$	59.99			$	41.53			$	56.74			$	39.41

		Comparison of Results of Operations for the Three Months Ended June 30, 2006 and the Three Months Ended June 30, 2005.
		Oil and Gas Production and Revenues
		Total oil and gas revenues increased 13% to $47.1 million in the second quarter of 2006 from $41.7 million in the second quarter of 2005. The increase was primarily due to higher product prices. Total production on an equivalent basis for the second quarter of 2006 decreased by 10% versus the second quarter of 2005.
		Gas production during the second quarter of 2006 totaled 2.6 Bcf and generated $20.5 million in revenues compared to 2.3 Bcf and $17.2 million in revenues during the same period in 2005. The average gas price after hedging impact for the second quarter of 2006 was $7.93 per Mcf compared to $7.43 per Mcf for the same period last year. The 12% 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 and West Cameron Block 295. 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 second quarter of 2006 totaled 443,000 barrels and generated $26.6 million in revenues compared to 590,000 barrels and $24.5 million in revenues for the same period in 2005. The average oil price received after hedging impact in the second quarter of 2006 was $59.99 per barrel compared to $41.53 per barrel in the second quarter of 2005. The decrease in production for the second quarter of 2006 compared to the second quarter of 2005 was primarily due to normal and expected declines in production from our Habanero Field and older properties.

		Lease Operating Expenses
		Lease operating expenses were $7.4 million for the three-month period ended June 30, 2006, an increase of $1.2 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 a decrease in throughput charges for Habanero resulting from lower production.
		Depreciation, Depletion and Amortization
		Depreciation, depletion and amortization for the three months ended June 30, 2006 and 2005 was $14.8 million and $13.7 million, respectively. The 8% increase was primarily due to a higher depletion rate resulting from higher cost associated with exploration and development in the Gulf of Mexico.
		Accretion Expense
		Accretion expense for the three-month periods ended June 30, 2006 and 2005 of $1.3 million and $770,000, 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 estimates. See Note 7 to the Consolidated Financial Statements.

		General and Administrative
		General and administrative expenses, net of amounts capitalized, were $1.9 million and $2.8 million for the three-month periods ended June 30, 2006 and 2005, respectively. The 31% decrease was primarily due to non-cash charges totaling $928,000 that were 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.
		Interest Expense
		Interest expense decreased by 3% to $4.1 million during the three months ended June 30, 2006 from $4.3 million during the three months ended June 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 $6.3 million and $4.7 million for the three-month periods ended June 30, 2006 and 2005, respectively. The increase was due to an increase in income before income taxes.

		Comparison of Results of Operations for the Six Months Ended June 30, 2006 and the Six Months Ended June 30, 2005.
		Oil and Gas Production and Revenues
		Total oil and gas revenues increased 9% to $92.6 million in the first half of 2006 from $84.7 million in the first half of 2005. The increase was primarily due to higher product prices. Total production on an equivalent basis for the first half of 2006 decreased by 17% versus the first half of 2005.
		Gas production during the six-months ended June 30, 2006 totaled 4.5 Bcf and generated $38.3 million in revenues compared to 5.1 Bcf and $36.2 million in revenues during the same period in 2005. The average gas price after hedging impact for the first half of 2006 was $8.44 per Mcf compared to $7.15 per Mcf for the same period last year. The decrease in production was primarily due to normal and expected declines 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 at East Cameron Block 90, North Padre Island Block 913, High Island Block 73 and West Cameron Block 295.
		Oil production during the six-months ended June 30, 2006 totaled 958,000 barrels and generated $54.4 million in revenues compared to 1,230,000 barrels and $48.5 million in revenues for the same period in 2005. The average oil price received after hedging impact in the first half of 2006 was $56.74 per barrel compared to $39.41 per barrel in the first half of 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 $13.3 million for the six-month period ended June 30, 2006, an increase of $537,000 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 six-months ended June 30, 2006 and 2005 was $28.6 million and $29.1 million, respectively. The 2% decrease was primarily due to lower production volumes for the first half of 2006 compared to the same period last year. The decrease was partially offset by a higher depletion rate primarily due to higher cost associated with exploration and development in the Gulf of Mexico.
		Accretion Expense
		Accretion expense for the six-month period ended June 30, 2006 and 2005 of $2.8 million and $1.6 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 $3.7 million and $4.5 million for the six-month periods ended June 30, 2006 and 2005, respectively. The 19% decrease was primarily due to non-cash charges totaling $928,000 that were 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.
		Interest Expense
		Interest expense decreased by 6% to $8.3 million during the six months ended June 30, 2006 from $8.8 million during the six months ended June 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 $12.8 million and $9.6 million for the six-month periods ended June 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 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 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 June 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 June 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 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS

The Company held its annual meeting of shareholders on May 4, 2006. At the annual meeting, two Class III directors of the board of directors of the Company were elected to hold office until the Company’s annual meeting of shareholders in 2009 or until their respective successors have been duly elected and qualified. The votes cast for each of the directors proposed in the Company’s definitive proxy statement on Schedule 14A, out of a total of 19,516,239 shares outstanding on the record date for the annual meeting, were as follows:

						For				Withheld
Fred L. Callon		Class III					15,685,582				1,892,353
L. Richard Flury		Class III					15,742,161				1,835,774

There were no abstentions, votes against or broker non-votes cast with respect to the election of directors.

The shareholders of the Company ratified the appointment of Ernst & Young LLP as the Company’s independent registered public accounting firm for 2006. There were 17,550,825 votes in favor and 27,110 votes against or abstained. There were no votes withheld or broker non-votes with respect to the ratification of the appointment of Ernst & Young LLP.

The shareholders of the Company also approved and ratified the Callon Petroleum Company 2006 Stock Incentive Plan. There were 8,591,032 votes in favor and 6,078,128 votes against or abstained.

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.

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)

Exhibit Number		Title of Document
			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