(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company 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 5, 2009, there were 21,703,705 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, 2009 and December 31, 2008			3
		Consolidated Statements of Operations for Each of the Three and Six Months in the Periods Ended June 30, 2009 and June 30, 2008			4
		Consolidated Statements of Cash Flows for Each of the Six Months in the Periods Ended June 30, 2009 and June 30, 2008			5
		Notes to Consolidated Financial Statements			6
		Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
		Item 3. Quantitative and Qualitative Disclosures about Market Risk			29
		Item 4. Controls and Procedures			29
Part II.		Other Information
		Item 1A. Risk Factors			30
		Item 6. Exhibits			30
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Callon Petroleum Company

		June 30,				December 31,
		2009				2008
		(Unaudited)				(Note 1)
ASSETS
Current assets:
Cash and cash equivalents		$	735			$	17,126
Accounts receivable			19,528				44,290
Fair market value of derivatives			7,064				21,780
Other current assets			1,971				1,103
Total current assets			29,298				84,299
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,587,007				1,581,698
Less accumulated depreciation, depletion and amortization			(1,473,139	)			(1,455,275	)
			113,868				126,423
Unevaluated properties excluded from amortization			26,147				32,829
Total oil and gas properties			140,015				159,252
Other property and equipment, net			2,392				2,536
Restricted investments			4,784				4,759
Investment in Medusa Spar LLC			11,926				12,577
Other assets, net			2,327				2,667
Total assets		$	190,742			$	266,090
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities		$	11,379			$	76,516
Asset retirement obligations			22,374				9,151
			33,753				85,667
Callon Entrada non-recourse credit facility (See Note 1)			82,841				—
Total current liabilities			116,594				85,667
9.75% Senior Notes			195,729				194,420
Callon Entrada non-recourse credit facility (See Note 1)			—				78,435
Senior secured credit facility			5,000				—
Total long-term debt			200,729				272,855
Asset retirement obligations			12,631				33,043
Callon Entrada non-recourse credit facility interest payable (See Note 1)			—				2,719
Other long-term liabilities			1,503				1,610
Total liabilities			331,457				395,894
Stockholders’ equity (deficit):
Preferred Stock, $.01 par value, 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value, 30,000,000 shares authorized; 21,676,067 and 21,621,142 shares outstanding at June 30, 2009 and December 31, 2008, respectively			217				216
Capital in excess of par value			230,150				227,803
Other comprehensive income (loss)			(581	)			14,157
Retained (deficit) earnings			(370,501	)			(371,980	)
Total stockholders’ equity (deficit)			(140,715	)			(129,804	)
Total liabilities and stockholders’ equity (deficit)		$	190,742			$	266,090

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

Callon Petroleum Company

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Operating revenues:
Oil sales		$	18,971			$	28,554			$	34,923			$	53,650
Gas sales			6,054				19,475				14,917				39,339
Total operating revenues			25,025				48,029				49,840				92,989
Operating expenses:
Lease operating expenses			4,656				4,870				8,695				10,048
Depreciation, depletion and amortization			8,452				15,218				17,865				30,247
General and administrative			5,391				2,943				7,210				5,595
Accretion expense			795				952				1,833				1,984
Total operating expenses			19,294				23,983				35,603				47,874
Income from operations			5,731				24,046				14,237				45,115
Other (income) expenses:
Interest expense			4,854				4,434				9,636				14,374
Callon Entrada non-recourse credit facility interest expense (See Note 1)			1,935				321				3,491				321
Other (income) expense			61				(379	)			(34	)			(851	)
Loss on early extinguishment of debt			—				11,871				—				11,871
Total other (income) expenses			6,850				16,247				13,093				25,715
Income (loss) before income taxes			(1,119	)			7,799				1,144				19,400
Income tax expense			24				2,730				—				6,812
Income (loss) before equity in earnings of Medusa Spar LLC			(1,143	)			5,069				1,144				12,588
Equity in earnings of Medusa Spar LLC			218				84				335				197
Net income (loss) available to common shares		$	(925	)		$	5,153			$	1,479			$	12,785
Net income (loss) per common share:
Basic		$	(0.04	)		$	0.25			$	0.07			$	0.61
Diluted		$	(0.04	)		$	0.23			$	0.07			$	0.58
Shares used in computing net income per common share:
Basic			21,645				20,966				21,626				20,919
Diluted			21,645				22,074				21,626				21,859

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

Callon Petroleum Company

		Six Months Ended
		June 30,				June 30,
		2009				2008
Cash flows from operating activities:
Net income		$	1,479			$	12,785
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization			18,285				30,615
Accretion expense			1,833				1,984
Amortization of deferred financing costs			1,481				1,580
Callon Entrada non-recourse credit facility non-cash interest expense			1,687				—
Non-cash loss on early extinguishment of debt			—				5,598
Equity in earnings of Medusa Spar LLC			(335	)			(197	)
Deferred income tax expense			—				6,812
Non-cash charge related to compensation plans			1,184				1,546
Excess tax benefits from share-based payment arrangements			—				(1,435	)
Changes in current assets and liabilities:
Accounts receivable			6,441				(2,470	)
Other current assets			(868	)			3,226
Current liabilities			(28,993	)			3,482
Change in gas balancing receivable			155				732
Change in gas balancing payable			(123	)			359
Change in other long-term liabilities			16				(6	)
Change in other assets, net			(189	)			(702	)
Cash provided by operating activities			2,053				63,909
Cash flows from investing activities:
Capital expenditures			(24,430	)			(78,441	)
Proceeds from sale of mineral interests			—				167,493
Distribution from Medusa Spar LLC			986				108
Cash (used in) provided by investing activities			(23,444	)			89,160
Cash flows from financing activities:
Proceeds from senior secured credit facility			9,337				51,435
Payments on senior secured credit facility			(4,337	)			(216,000	)
Equity issued related to stock incentive plans			—				(1,133	)
Excess tax benefits from share-based payment arrangements			—				1,435
Cash provided by (used in) financing activities			5,000				(164,263	)
Net decrease in cash and cash equivalents			(16,391	)			(11,194	)
Cash and cash equivalents:
Balance, beginning of period			17,126				53,250
Balance, end of period		$	735			$	42,056

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

CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009

1.

Callon Entrada Non-Recourse Credit Facility

A wholly-owned subsidiary of Callon Petroleum Company (the “Company” or “Callon”), Callon Entrada Company (“Callon Entrada”), entered into a credit agreement with CIECO Energy (Entrada) LLC, (“CIECO Entrada”) pursuant to which Callon Entrada was entitled to borrow up to $150 million, plus interest expense incurred of up to $12 million, to finance the development of the Entrada project prior to the abandonment in November 2008. The debt was to be repaid by production from the Entrada field. As a result of abandoning the project and the lease expiring June 1, 2009, Callon Entrada’s only source of payment is from the sale of equipment purchased but not used for the Entrada project. The agreement bears interest at six-month LIBOR (as in effect on the first day of each interest period) plus 375 basis points and is subject to customary representations, warranties, covenants and events of default. The interest rate increased by 400 basis points as of April 2, 2009 due to a notice of default received from CIECO Entrada which is discussed below. As of June 30, 2009, $78.4 million of principal and $4.4 million of interest were outstanding under this facility.

On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain alleged events of default occurred under the non-recourse credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. The notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon Entrada non-recourse credit agreement to accelerate payment of the principal and interest due. The acceleration of payment causes the principal and interest balances under the Callon Entrada non-recourse credit agreement to be reclassified as of June 30, 2009 to current liabilities from long-term liabilities under U.S. generally accepted accounting principles (“GAAP”). Under GAAP the Company is currently required to consolidate the financial statements and results of operations of Callon Entrada. Callon Entrada’s non-recourse liability is reflected in a separate line item in the consolidated financial statements. The assets of Callon Entrada, including the stock, are pledged to CIECO Entrada and are shown in the consolidating condensed financial statements below. Based on the advice of counsel, the Company believes that Callon and its subsidiaries (other than Callon Entrada) did not guarantee and are not otherwise obligated to repay the principal, accrued interest or any other amount which may become due under the Callon Entrada credit facility. However, Callon has entered into a customary indemnification agreement pursuant to which it agrees to indemnify the lenders under the Callon Entrada credit facility against Callon Entrada’s misappropriation of funds, non-performance of certain covenants, excluding the events of default discussed above, and similar matters. In addition, Callon also guaranteed the obligations of Callon Entrada to fund its proportionate share of any operating costs related to the Entrada project that Callon Entrada may, from time to time, expressly approve under the Entrada joint operating agreement. Callon also has guaranteed Callon Entrada’s payment of all amounts to plug and abandon wells and related facilities for a breach of law, rule or regulation (including environmental laws) and for any losses of CIECO Entrada attributable to gross negligence of Callon Entrada. The well for which Callon Entrada is responsible for was plugged and abandoned in the fourth of quarter of 2008 and the Company believes that there are no additional costs related to abandoning that well.

Prior to abandonment of the Entrada project, CIECO Entrada failed to fund two loan requests totaling $40 million under the Callon Entrada non-recourse credit agreement. These loan requests were to cover Callon Entrada’s share of the cost incurred to develop the Entrada field up to the suspension of the project. Such amounts were subsequently funded by the Company. The Company continues to discuss with CIECO its failure to fund the $40 million in loan requests. No assurances can be made regarding the outcome of discussions. The Company does not believe that we have waived any of our rights under the agreements with CIECO Entrada or its parent, CIECO Energy (U.S.) LLC (“CIECO”).

As of June 30, 2009, the wind down of the Entrada project was substantially complete and substantially all of the costs had been paid. The lease expired June 1, 2009 and reverted to the Minerals Management Service. In addition, the sale of equipment purchased for the Entrada project, but not used, is in progress. As of June 2009, Callon Entrada has collected $1.8 million in sales proceeds from the sale of equipment, net to its interest, which was applied to unpaid interest expense as required under the Callon Entrada non-recourse credit facility. The Company believes that the amount of future operating costs of Callon Entrada, for which the Company would be responsible for, is not significant.

Below are consolidating condensed financial statements of Callon Petroleum Company presented to demonstrate that Callon Entrada does not have sufficient assets available to pay down the balance owed under the Callon Entrada non-recourse credit facility as a result of the abandonment and reversion of this lease of the Entrada project.

Callon Petroleum Company Consolidating Condensed Financial Information
as of and for the Six Months ended June 30, 2009

						Callon
		Callon				and Other				Callon
		Entrada				Subsidiaries				Consolidated
Balance Sheet (in thousands)
Total current assets		$	1,238			$	28,060			$	29,298
Total oil and gas properties			—				140,015				140,015
Other property and equipment			—				2,392				2,392
Other assets			—				19,037				19,037
Total assets		$	1,238			$	189,504			$	190,742
Other current liabilities		$	2,842			$	30,911			$	33,753
Callon Entrada non-recourse credit facility			82,841				—				82,841
Total current liabilities			85,683				30,911				116,594
Total long-term debt			—				200,729				200,729
Total other long-term liabilities			—				14,134				14,134
Total stockholder’s equity (deficit)			(84,445	)			(56,270	)			(140,715	)
Total liabilities and stockholders’ equity (deficit)		$	1,238			$	189,504			$	190,742

						Callon
		Callon				and Other				Callon
		Entrada				Subsidiaries				Consolidated
Statement of Operations (in thousands)
Total operating revenues		$	—			$	49,840			$	49,840
Total operating expenses			56				35,547				35,603
Income from operations			(56	)			14,293				14,237
Interest expense			3,491				9,636				13,127
Other (income) expenses			(6	)			(28	)			(34	)
Income (loss) before income taxes			(3,541	)			4,685				1,144
Income tax expense			—				—				—
Income (loss) before equity in earnings of Medusa Spar LLC			(3,541	)			4,685				1,144
Equity in earnings of Medusa Spar LLC			—				335				335
Net (loss) income		$	(3,541	)		$	5,020			$	1,479

						Callon
		Callon				and Other				Callon
		Entrada				Subsidiaries				Consolidated
Statement of Cash Flows (in thousands)
Net cash (used in) provided by operating activities		$	(5,057	)		$	7,110			$	2,053
Net cash used in investing activities			—				(23,444	)			(23,444	)
Net cash provided by financing activities			—				5,000				5,000
Net decrease in cash and cash equivalents			(5,057	)			(11,334	)			(16,391	)
Cash and cash equivalents at beginning of the period			5,218				11,908				17,126
Cash and cash equivalents at end of the period		$	161			$	574			$	735

2.

General

The financial information presented as of any date other than December 31, 2008 has been prepared from the books and records of the Company without audit. Financial information as of December 31, 2008 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, 2008 included in the Company’s Annual Report on Form 10-K filed March 19, 2009. The results of operations for the three-month and six-month periods ended June 30, 2009 are not necessarily indicative of future financial results.

3.

Net Income Per Share

Basic net income per 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 stock options and restricted stock considered common stock equivalents computed using the treasury stock method.

A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
(a) Net income (loss)		$	(925	)		$	5,153			$	1,479			$	12,785
(b) Weighted average shares outstanding			21,645				20,966				21,626				20,919
Dilutive impact of stock options			—				253				—				225
Dilutive impact of warrants			—				599				—				526
Dilutive impact of restricted stock			—				256				—				189
(c) Weighted average shares outstanding for diluted net income per share			21,645				22,074				21,626				21,859
Basic net income (loss) per share (a/b)		$	(0.04	)		$	0.25			$	0.07			$	0.61
Diluted net income (loss) per share (a/c)		$	(0.04	)		$	0.23			$	0.07			$	0.58
Shares excluded due to the exercise / grant price being greater than the average share price
Stock options			1,003				—				1,003				—
Warrants			365				—				365				—
Restricted stock			634				—				634				—

4.

Long-Term Debt

Long-term debt consisted of the following at:

		June 30,				December 31,
		2009				2008
		(In thousands)
Senior Secured Credit Facility (matures September 25, 2012)		$	5,000			$	—
9.75% Senior Notes (due 2010), net of discount			195,729				194,420
Callon Entrada non-recourse credit agreement			—				78,435
Total long-term debt		$	200,729			$	272,855

Senior Secured Credit Facility. On September 25, 2008, the Company completed a $250 million second amended and restated senior secured credit agreement, which matures on September 25, 2012, with Union Bank N.A. (“Union Bank”) as administrative agent and

issuing lender. On March 19, 2009, the Company entered into the first amendment of the Second Amended and Restated Credit Agreement (“the Amendment”) which states that a default under the Callon Entrada non-recourse credit facility (described in Note 1) would not constitute a default under the Company’s senior secured credit facility. The Amendment set the borrowing base at $48 million and implemented a Monthly Commitment Reduction (MCR) commencing on June 1, 2009 in the amount of $4.33 million per month. The borrowing base and MCR are both subject to re-determination August 1, 2009 and quarterly thereafter. As of August 1, 2009, the Company had received a preliminary notice from Union Bank that the redetermined borrowing base would be approximately $35.0 million with the MCR increasing to approximately $4.7 million. Borrowings under the credit agreement are secured by mortgages covering the Company’s major fields excluding the Entrada field. As of June 30, 2009, there was $5 million outstanding under the agreement with a weighted average interest rate of 2.05% and $38.7 million, subject to MCR, available for future borrowings under the senior secured credit agreement.

On April 1, 2009, Diamond Offshore Drilling, Inc. (“Diamond”) called on an outstanding letter of credit for CIECO’s share of the settlement for the termination of the Ocean Victory drilling contract in the amount of $7.3 million. Callon paid its share, in the amount of $7.3 million, in March 2009. The remaining balance of the letter of credit was cancelled on April 2, 2009 by Diamond. The Company continues to discuss with CIECO its failure to fund the settlement for the termination of the drilling contract. The $7.3 million due from CIECO for their share of the settlement for the termination of the drilling contract is included in accounts receivable at June 30, 2009.

Fair Value of Debt. The fair value of the 9.75% senior notes due in December 2010 is determined at the end of each reporting period using inputs based upon quoted prices for such instruments in active markets. At June 30, 2009, the estimated fair value of the 9.75% senior notes was $100 million.

Early Extinguishment of Debt. On April 8, 2008, the Company completed the sale of a 50% working interest in the Entrada Field to CIECO Entrada for a purchase price of $175 million with a cash payment of $155 million at closing and the additional $20 million payable after the achievement of certain production milestones. Simultaneously with the closing of the CIECO transaction, the Company used the proceeds from the sale, cash on hand and a draw of $16 million from the senior secured credit agreement, to extinguish a $200 million senior secured revolving credit agreement, which was secured by a lien on the Entrada properties. Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, Callon incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash charge of $5.6 million related to the amortization expense associated with the deferred financing costs related to the credit facility.

5.

Derivatives

The Company periodically uses derivative financial instruments to manage oil and gas price risk on a limited amount of its future production and does not use these instruments for

trading purposes. Settlements of oil and gas derivative contracts are generally based on the difference between the contract price or prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. Such derivative contracts are accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS 133”) as amended.

The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 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 (deficit). The cash settlements on contracts for future production 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 oil and gas cash flow hedges during the three-month and six-month periods ended June 30, 2009 resulted in an increase in oil and gas sales of $4.5 million and $12.4 million, respectively. For the three-month and six-month periods ended June 30, 2008 cash settlements on effective oil and gas cash flow hedges resulted in a decrease in oil and gas sales of $6.0 million and $7.8 million, respectively.

The Company’s derivative contracts are carried at fair value on our consolidated balance sheet under the caption “Fair Market Value of Derivatives”. The oil and gas derivative contracts are settled based upon reported prices on NYMEX. The estimated fair value of these contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. See Note 7, “Fair Value Measurements.”

Listed in the table below are the outstanding oil and gas derivative contracts as of June 30, 2009:

Collars

										Average				Average
		Volumes per				Quantity				Floor				Ceiling
Product		Month				Type				Price				Price				Period
Oil			30,000			Bbls				$	110.00			$	175.75				07/09-12/09
Natural Gas			100,000			MMbtu				$	4.50			$	6.30				10/09-12/09
Natural Gas			75,000			MMbtu				$	5.00			$	8.30				01/10-12/10

6.

Comprehensive Income (Loss)

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Net income (loss)		$	(925	)		$	5,153			$	1,479			$	12,785
Other comprehensive income (loss):
Change in fair value of derivatives			(7,815	)			(8,579	)			(14,738	)			(10,794	)
Total comprehensive income (loss)		$	(8,740	)		$	(3,426	)		$	(13,259	)		$	1,991

7.

Fair Value Measurements

Statement of Financial Accounting Standards No. 157, (“SFAS 157”), “Fair Value Measurements” defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS 157 establishes a fair value hierarchy which consists of three broad levels that prioritize the inputs to valuation techniques used to measure fair value.

	•		Level 1 valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.
	•		Level 2 valuations rely on quoted market information for the calculation of fair market value.
	•		Level 3 valuations are internal estimates and have the lowest priority.

Per SFAS 157, the Company has classified its derivatives into these levels depending upon the data relied on to determine the fair values of the derivative instruments. The fair values of collars and natural gas basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves or quotes obtained from counterparties to the agreements and are designated as Level 3. The following table summarizes the valuation of our assets and liabilities measured at fair value on a recurring basis at June 30, 2009 (in thousands):

		Fair Value Measurements Using
		Quoted				Significant
		Prices in				Other			Significant
		Active				Observable			Unobservable				Assets
		Markets				Inputs			Inputs				(Liabilities)
		(Level 1)				(Level 2)			(Level 3)				At Fair Value
Derivative assets		$	—			$	—		$	7,064			$	7,064
Derivative liabilities			—				—			(22	)			(22	)
Total		$	—			$	—		$	7,042			$	7,042

The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the six-month period ended June 30, 2009. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in management’s judgment, reflect the assumptions a marketplace participant would have used at June 30, 2009 (in thousands):

		Derivatives
Balance at January 1, 2009		$	21,780
Total gains or losses (realized or unrealized):
Included in earnings			12,392
Included in other comprehensive (income) loss			(14,738	)
Purchases, issuances and settlements			(12,392	)
Balance at June 30, 2009		$	7,042
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of June 30, 2009		$	—

8.

Income Taxes

Below is an analysis of deferred income taxes as of June 30, 2009 and December 31, 2008.

		June 30,				December 31,
		2009				2008
		(In thousands)
Deferred tax asset:
Federal net operating loss carryforwards		$	107,072			$	68,432
State net operating loss carryforwards			55,188				45,939
Statutory depletion carryforwards			4,575				4,561
Alternative minimum tax credit carryforward			375				375
Asset retirement obligations			10,577				13,102
Oil and gas properties			—				58,061
Other			30,426				2,241
Valuation allowance			(187,920	)			(174,062	)
Total deferred tax asset			20,293				18,649
Deferred tax liability:
Oil and gas properties			6,833				—
Other			13,460				18,649
Total deferred tax liability			20,293				18,649
Net deferred tax asset		$	—			$	—

The Company follows the asset and liability method of accounting for deferred income taxes prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible temporary timing differences, capital and operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance is provided for that portion of the asset, for which it is deemed more likely than not, that it, will not be realized.

As discussed in Notes 5 of the Consolidated Financial Statements for the year ended December 31, 2008 included in the Company’s Annual Report on Form 10-K filed March 19, 2009, the Company established a valuation allowance of $174 million as of December 31, 2008. The Company’s tax net operating loss carryforwards increased during the period, due primarily to the abandonment of the Entrada lease which loss had previously been recognized for financial reporting purposes, unrealized hedging losses and other activity generated additional net deferred tax assets of $14 million during the six months ended June 30, 2009 requiring additional valuation allowance of the same amount.

9.

Asset Retirement Obligations

The following table summarizes the activity for the Company’s asset retirement obligations:

		Six Months Ended
		June 30, 2009
Asset retirement obligations at beginning of period		$	42,194
Accretion expense			1,833
Liabilities incurred			—
Liabilities settled			(4,250	)
Revisions to estimate			(4,772	)
Asset retirement obligations at end of period			35,005
Less: current asset retirement obligations			(22,374	)
Long-term asset retirement obligations		$	12,631

Assets, primarily U.S. government securities, of approximately $4.8 million at June 30, 2009, 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.

10.

Accounting Pronouncements

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 141R as amended, “Business Combinations”, (“SFAS 141R”). The objective of SFAS 141R is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, SFAS 141R establishes principles and requirements for how the acquirer (a) recognizes and measurers in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for business combinations with an acquisition date on or after the beginning of annual reporting period beginning on or after December 15, 2008. The Company adopted SFAS 141(R) on January 1, 2009 with no impact to its financial statements.

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 as amended, “Noncontrolling Interest in Consolidated Financial Statement”, (SFAS 160”). The objective of SFAS 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for first year and interim periods within the fiscal year, beginning on or after December 15, 2008. The Company adopted SFAS 160 on January 1, 2009 with no impact to its financial statements.

Effective January 1, 2009, the Company adopted Statement of Financial Accounting Standard No. 161, “Disclosures about Derivative Instruments and Hedging Activities” — an amendment of SFAS Statement No. 133 (“SFAS 161”). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Under SFAS 161, entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 must be applied prospectively to all derivative instruments and non-derivative instruments that are designated and qualify as hedging instruments and related hedged items accounted for under SFAS No 133 for all financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company adopted SFAS No. 161 on January 1, 2009 and has added certain additional disclosures to its financial statements.

In December 2008, the SEC unanimously approved amendments to revise its oil and gas reserves estimation and disclosure requirements. The amendments, among other things;

	•		allows the use of new technologies to determine proved reserves;
	•		permits the optional disclosure of probable and possible reserves;
	•		modifies the prices used to estimate reserves for SEC disclosure purposed to a 12 month average price instead of a period-end price; and
	•		requires that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party.

The revised rules are effective January 1, 2010. The new requirements have no impact on the Company’s 2009 interim financial statements, but the requirements will be effective for the Company’s year-end 2009 financial statements and its 2009 Annual Report on Form 10-K for the year ended December 31, 2009.

In June 2008, FASB issued FASB Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”. This FASB Staff Position (“FSP”) addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in FASB Statement No. 128, “Earning per Share”. The Company adopted this FSP on January 1, 2009 with no impact to its financial statements.

In May 2008, the FASB issued FASB Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments that may not be settled in cash upon conversion (including partial cash settlement). This clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by APB Opinion No. 14, Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants. Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company adopted this FSP on January 1, 2009 with no impact to its financial statements.

In May 2009, the FASB issued Statement of Financial Accounting Standard No. 165, “Subsequent Events” (“SFAS 165”). The objective of SFAS 165 is to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 is effective for interim and annual financial periods ending after June 15, 2009. Accordingly, the Company adopted SFAS as of the quarter ended June 30, 2009 with limited impact to its financial statements. The Company has evaluated subsequent events through August 10, 2009

In April 2009, the FASB issued FASB Staff Position No. FAS 141 (R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141R”). FSP 141R amends and clarifies SFAS 141R to address application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP 141R is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the fires annual reporting period beginning on or after December 15, 2008. Accordingly, the Company adopted FSP 141R as of the quarter ended June 30, 2009 with no impact to the Company’s financial statements.

In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments”. This FASB Staff Position amends FASB Statement of Financial Accounting Standard No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FASB Staff Position also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. Accordingly, the Company adopted this FASB Staff Position as of the quarter ended June 30, 2009 with limited impact to the Company’s financial statements.

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

The following discussion is intended to assist in an understanding of our financial condition and results of operations. Our consolidated financial statements and notes thereto contain detailed information that should be referred to in conjunction with the following discussion. See Item 8 “Financial Statements and Supplementary Data.”

We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. In the past several years, our activities have been focused in the shelf and deepwater areas of the Gulf of Mexico. Production from wells in this area is characterized by high initial production rates and steep decline curves. Accordingly, we are required to make material expenditures to purchase proved oil and gas reserves and to explore for and discover reserves to replace those produced.

Disruptions in Capital Markets. The capital markets are experiencing significant disruptions, and many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our primary exposure to the current credit market crisis includes our senior secured credit facility, 9.75% senior notes due December 2010 and counterparty nonperformance risks.

Our senior secured credit facility was committed in the amount of $70 million as of December 31, 2008. Subsequent to December 31, 2008, our borrowing base redetermination was completed and reduced to $48 million due to lower commodity prices and reserves. In addition, a Monthly Commitment Reduction (“MCR”) was implemented commencing June 1, 2009 in the amount of $4.33 million per month. As of August 1, 2009, we received a preliminary notice that our redetermined borrowing base would be approximately $35.0 million with the MCR increasing to approximately $4.7 million. If not extended, the senior secured credit facility matures in September 25, 2012. Should current credit market tightening be prolonged for several years, future extensions of our senior secured credit facility may contain terms that are less favorable than those of our current credit facility. The amounts which may be outstanding under our senior secured credit facility are limited by a borrowing base, which is established by our lenders and based on the value of our proved reserves using prices, costs and

other assumptions determined by our lenders. Continued disruptions in the capital markets could cause our lenders to be more restrictive in calculating our borrowing base. See Note 4 to the Consolidated Financial Statements.

We have outstanding $200 million of 9.75% senior notes due in December 2010. We are actively evaluating several options for a restructuring of our balance sheet and are hopeful to achieve resolution before our 9.75% senior notes become a current liability in December 2009. No assurances can be made as to the results of these efforts. Continued disruptions in the capital markets could make it more difficult or expensive to refinance or restructure these notes when they come due.

Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. At June 30, 2009, our open commodity derivative instruments were in a net receivable position with a fair value of $7.0 million. All of our commodity derivative instruments are with a major financial institution. Should the financial counterparty not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss.

We sell our production to a variety of purchasers. Some of these parties may experience liquidity problems. Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit; however, we do not have all of our trade credit enhanced through guarantees or credit support.

Impairment of Oil and Gas Properties. If oil and gas prices decrease further or remain depressed for extended periods of time, we may be required to take additional writedowns of the carrying value of our oil and gas properties. We may be required to writedown the carrying value of our oil and gas properties when oil and gas prices are low or if we have substantial downward adjustments to our estimated net proved reserves, increases in our estimates of development costs or deterioration in our exploration results. Under the full-cost method which we use to account for our oil and gas properties, the net capitalized costs of our oil and gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period end oil and gas prices or prices as of the date of our auditor’s report, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly, based on prices in effect as of the end of each quarter or at the time of reporting our results. Once incurred, a writedown of oil and gas properties is not reversible at a later date, even if prices increase.

Reduced Prices for Oil and Gas Production. The United States and world economies are currently in a recession which could last through 2009 and perhaps longer. Both oil and gas prices have undergone significant decline during the second half of 2008 and into 2009 as a result of the reduced economic activity brought on by the recession. Continued lower commodity prices will reduce our cash flows from operations. To mitigate the impact of lower commodity prices on our cash flows, we have entered into crude oil and natural gas commodity derivative contracts for 2009. See Note 5 to our Consolidated Financial Statements. Depending on the length of the current recession, commodity prices may stay depressed or decline further, thereby causing a prolonged downturn, which would further reduce our cash flows from operations. This could cause us to alter our business plans including reducing or delaying our exploration and development program spending and other cost reduction initiatives.

Abandonment of the Entrada Project. In late November 2008, we and our joint working interest owner, CIECO Entrada, decided to abandon the Entrada project. Under the terms of our agreements with CIECO Entrada, Callon Entrada is responsible for its share of the costs to plug and abandon the Entrada project, which we estimate to be $46 million, $23 million net to Callon Entrada. As of June 30, 2009 the wind down of the Entrada project was substantially complete and most of the costs had been paid. In addition, prior to abandonment of the project, CIECO Entrada failed to fund two loan requests totaling $40 million under the Callon Entrada non-recourse credit agreement with CIECO Entrada. CIECO Entrada also failed to fund its working interest share of a settlement payment in the amount of $7.3 million to terminate a drilling contract for the Entrada project. Callon has paid its share of the settlement payment.

We continue to discuss with CIECO Entrada its failure to fund $40 million in loan requests and its share of a settlement payment to terminate a drilling contract. No assurances can be made regarding the outcome of these discussions. We do not believe that we have waived any of our rights under the agreements with CIECO Entrada or its parent, CIECO.

The Callon Entrada Non-Recourse Credit Facility. The Callon Entrada non-recourse credit facility is a direct obligation of Callon Entrada, an indirect, wholly-owned subsidiary of Callon Petroleum Company. The Callon Entrada non-recourse credit facility is secured by a lien on the assets of Callon Entrada which generally are comprised of the Entrada Field and related equipment. Neither Callon Petroleum Company nor any other subsidiary of Callon Petroleum Company guaranteed or otherwise agreed to pay the principal or interest payments due on the Callon Entrada non-recourse credit facility, so such facility is non-recourse to Callon Petroleum Company and its other subsidiaries.

On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain alleged events of default occurred under the Callon Entrada non-recourse credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. The lenders under our senior secured credit facility have amended the Second Amended and Restated Credit Agreement dated September 25, 2008 to state that a default under the Callon Entrada non-recourse credit facility is not a default under their facility. In addition, this amendment eliminates a possible cross default with regard to our 9.75% senior notes due in December 2010. Accordingly, we do not believe that a default under the Callon Entrada non-recourse credit agreement will have a material negative impact on our financial position, results of operations and cash flows. See Note 1 to the Consolidated Financial Statements.

Other Events

On March 16, 2009, we were notified by the New York Stock Exchange that we had fallen below one of the NYSE’s continued listing standards. We received this notification pursuant to Rule 802.01B(I) of the NYSE Listed Company Manual because our average market capitalization has been less than $75 million over a 30-day trading period and our last reported stockholder’s equity was less than $75 million.

We submitted a plan with the NYSE on April 30, 2009, which demonstrated our ability to achieve compliance with Rule 802.01B(I) within an 18 month cure period. On June 12, 2009, the NYSE accepted the plan and our common stock will continue to be listed on the NYSE during the cure period, subject to ongoing monitoring and our compliance with other NYSE continued listing requirements.

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, 2009, we had cash and cash equivalents of $735,000 and $38.7 million of availability under our senior secured credit agreement. Cash provided by operating activities during the six-month period ended June 30, 2009 totaled $2.1 million, a 97% decrease when compared to the corresponding period in 2008. The decrease in liquidity is attributable to the reduction of accounts payable during the first half of 2009, lower commodity prices and lower production rates on an equivalent basis.

On September 25, 2008, we completed a $250 million second amended and restated senior secured credit agreement with Union Bank as issuing lender, which matures September 25, 2012. We received preliminary notice from Union Bank that the borrowing base and MCR, which are still under review as of August 1, 2009, are approximately $35.0 million and $4.7 million, respectively. Borrowings under the credit agreement are secured by mortgages covering our major fields excluding Entrada. As of June 30, 2009, there was $5.0 outstanding under the agreement with $38.7 million, subject to MCR, available for future borrowings. See Note 4 to the Consolidated Financial Statements.

On April 1, 2009, Diamond Offshore Drilling, Inc. (“Diamond”) called on the outstanding letter of credit for CIECO Energy (US) Limited’s (“CIECO”) share of the settlement for the termination of the Ocean Victory drilling contract in the amount of $7.3 million. We paid our share, in the amount of $7.3 million, in March 2009. The remaining balance of the letter of credit was cancelled on April 2, 2009 by Diamond. We continue to discuss with CIECO its failure to fund the settlement for the termination of the drilling contract. The $7.3 million due from CIECO for their share of the settlement for the termination of the drilling contract is recorded as a receivable as of June 30, 2009.

Due to the uncertain economic and commodity price environment, we have designed a flexible capital spending program that will be responsive to conditions that develop during 2009. Our preliminary base capital program, including plugging and abandonment, for 2009 is $75 million, which is relatively flat with the 2008 budget of $71 million, excluding the Entrada project. The program includes $50 million for the acquisition of proved oil and gas properties with development and exploitation upside. However, depending on commodity prices and other economic conditions we experience in 2009, this base capital program may be adjusted up or down. See “Capital Expenditures” for more detail on our capital expenditure forecast for 2009.

We expect that the 2009 budget will be funded primarily from cash flows from operations, cash on hand, and borrowings under our senior secured credit facility and/or other financing. We would expect an increase in our senior secured credit facility borrowing base upon executing an acquisition. We will evaluate the level of capital spending throughout the year based on commodity prices, cash flows from operations and property acquisitions and divestitures.

Inflation has not had a material impact on us and is not expected to have a material impact on us in the immediate future.

The Callon Entrada non-recourse credit facility, which has a balance of $82.4 million, is a direct obligation of Callon Entrada, an indirect, wholly-owned subsidiary of Callon Petroleum Company. The Callon Entrada non-recourse credit facility is secured by a lien on the stock of Callon Entrada and the assets of Callon Entrada which generally are comprised of the Entrada Field and related equipment. On June 1, 2009 the lease expired and reverted to the Minerals Management Service. At June 30, 2009, there was no value included on the balance sheet for the lease or related equipment. Neither Callon Petroleum Company nor any other subsidiary of Callon Petroleum Company guaranteed or otherwise agreed to pay the principal or interest payments due on the Callon Entrada non-recourse credit facility, so such facility is non-recourse to Callon Petroleum Company and its other subsidiaries.

On April 2, 2009, Callon Entrada received a notice of default from CIECO Entrada advising Callon Entrada that certain events of default occurred under the non-recourse credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. This notice of default invoked CIECO’s Entrada rights under the Callon Entrada non-recourse credit agreement to accelerate payment of the principal and interest due. The acceleration of payment causes the principal and interest balances under the Callon Entrada non-recourse credit agreement to be reclassified as current liabilities from long-term liabilities under U.S. generally accepted accounting principles (“GAAP”). Under GAAP, we are currently required to consolidate the financial statements and results of operations of Callon Entrada which results in Callon Entrada’s non-recourse liability being reflected in a separate line item in the consolidated financial statements. See Note 1 to the Consolidated Financial Statements for more information regarding the deficiency in assets of Callon Entrada with which to repay the non-recourse credit facility.

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 agreement contains covenants for maintenance of certain financial ratios. We were in compliance with these covenants at June 30, 2009. See Note 7 of the Consolidated Financial Statements for the year ended December 31, 2008 included in our Annual Report on Form 10-K filed March 19, 2009 for a more detailed discussion of long-term debt.

The following table describes our outstanding contractual obligations (in thousands) as of June 30, 2009:

Contractual						Less Than				One-Three				Four-Five				After-Five
Obligations		Total				One Year				Years				Years				Years
Senior Secured Credit Facility		$	5,000			$	—			$	5,000			$	—			$	—
9.75% Senior Notes			200,000				—				200,000				—				—
Throughput Commitments:
Medusa Oil Pipeline			188				56				81				31				20
		$	205,188			$	56			$	205,081			$	31			$	20

Capital Expenditures

Capital expenditures on an accrual basis were $7.7 million for the six-months ended June 30, 2009. Included in this amount was capitalized interest of approximately $1.7 million and capitalized general and administrative costs allocable directly to exploration and development projects of approximately $4.4 million. The remainder of the capital expended primarily includes the cost of seismic data, leases and plugging and abandonment costs.

Capital expenditures for the remainder of 2009 are projected to be $60.5 million and include:

	•		proved producing property acquisitions;
	•		development costs on our legacy properties;
	•		the cost of seismic data and leases; and
	•		capitalized interest and general and administrative costs.

In addition, we are projecting to spend $6.8 million for the remainder of 2009 for asset retirement obligations.

Off-Balance Sheet Arrangements

We have a 10% ownership interest in Medusa Spar LLC (“LLC”), which is a limited liability company that 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 the LLC in return for approximately $25 million in cash and a 10% ownership interest in the LLC. The LLC earns 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 allowed us to defer the cost of the Spar production facility over the life of the Medusa Field. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation. 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,
		2009				2008				2009				2008
Net production :
Oil (MBbls)			263				286				526				575
Gas (MMcf)			1,433				1,668				2,880				3,759
Total production (MMcfe)			3,010				3,382				6,036				7,211
Average daily production (MMcfe)			33.1				37.2				33.3				39.6
Average sales price:
Oil (Bbls) (a)		$	72.22			$	99.99			$	66.39			$	93.27
Gas (Mcf)			4.22				11.67				5.18				10.46
Total (Mcfe)			8.32				14.20				8.26				12.90
Oil and gas revenues:
Oil revenue		$	18,971			$	28,554			$	34,923			$	53,650
Gas revenue			6,054				19,475				14,917				39,339
Total		$	25,025			$	48,029			$	49,840			$	92,989
Oil and gas production costs:
Lease operating expenses		$	4,656			$	4,870			$	8,695			$	10,048
Additional per Mcfe data:
Sales price		$	8.32			$	14.20			$	8.26			$	12.90
Lease operating expense			1.55				1.44				1.44				1.39
Operating margin		$	6.77			$	12.76			$	6.82			$	11.51
Depletion, depreciation and amortization		$	2.81			$	4.50			$	2.96			$	4.19
General and administrative (net of management fees)		$	1.79			$	0.87			$	1.19			$	0.78
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
Average NYMEX oil price		$	59.62			$	123.98			$	51.35			$	110.94
Basis differential and quality adjustments			(3.30	)			(4.06	)			(3.68	)			(3.95	)
Transportation			(1.36	)			(1.34	)			(1.35	)			(1.30	)
Hedging			17.26				(18.59	)			20.07				(12.42	)
Average realized oil price		$	72.22			$	99.99			$	66.39			$	93.27

Comparison of Results of Operations for the Three Months Ended June 30, 2009 and the Three Months Ended June 30, 2008.

Oil and Gas Production and Revenues

Total oil and gas revenues were $25.0 million in the second quarter of 2009 compared to $48.0 million in the second quarter of 2008. Total production on an equivalent basis for the second quarter of 2009 decreased by 12% compared to the second quarter of 2008 and oil and gas prices on a Mcfe basis for the second quarter of 2009 decreased 41% compared to 2008.

Gas production during the second quarter of 2009 totaled 1.4 billion cubic feet (Bcf) and generated $6.1 million in revenues compared to 1.7 Bcf and $19.5 million in revenues during the same period in 2008. The average gas price after hedging impact for the second quarter of 2009 was $4.22 per thousand cubic feet of natural gas (“Mcf”) compared to $11.67 per Mcf for the same period in 2008. Approximately 14% of the 15% decrease in 2009 production was due to a lower number of producing wells, with the remaining 1% resulting from normal and expected declines in production from our older properties. Four of our gas wells were shut-in during 2008 due to early water production and are now scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, which management has determined uneconomic to repair.

Oil production during the second quarter of 2009 totaled 263,000 barrels and generated $19.0 million in revenues compared to 286,000 barrels and $28.6 million in revenues for the same period in 2008. The average oil price received after hedging impact in the second quarter of 2009 was $72.22 per barrel compared to $99.99 per barrel in the second quarter of 2008. The 8% decrease in 2009 production was attributable to normal and expected declines in production and our High Island Block A-540, described above.

Lease Operating Expenses

Lease operating expenses were $4.7 million for the three-month period ended June 30, 2009, a 4% decrease when compared to the same period in 2008. The decrease was primarily due to a lower number of producing wells. Four of our gas wells were shut-in during 2008 due to early water production and are now scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, which management determined uneconomic to repair.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three-month period ended June 30, 2009 and 2008 was $8.5 million and $15.2 million, respectively. The 44% decrease was due to lower production volumes as well as a lower depletion rate resulting from the full-cost ceiling writedown which was recorded in the fourth quarter of 2008.

Accretion Expense

Accretion expense was $795,000 and $952,000 for the three-month periods ended June 30, 2009 and 2008 and represents accretion of our asset retirement obligations. See Note 9 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses, net of amounts capitalized, were $5.4 million and $2.9 million for the three-month period ended June 30, 2009 and 2008, respectively. The 83% increase was primary due to the $2.2 million of nonrecurring expenses for staffing reductions and retirements which were incurred during the second quarter of 2009.

Interest Expense

Interest expense on Callon related debt obligations increased to $4.9 million during the three-month period ended June 30, 2009, compared to $4.4 million during the three-month period ended June 30, 2008. The increase is due to a larger outstanding loan balance for our senior secured credit facility. See Note 4 to the Consolidated Financial Statements for details.

Callon Entrada Non- Recourse Credit Facility Interest Expense

The Callon Entrada non-recourse credit facility incurred interest expense for the three-month periods ended June 30, 2009 and 2008 of $1.9 million and $321,000, respectively. The increase was due to a larger outstanding loan balance for the three-month period ended June 30, 2009 and an increase in the interest rate due to the notice of default received from CIECO on April 2, 2009. See Note 1 to the Consolidated Financial Statements for details.

Loss on Early Extinguishment of Debt

Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, Callon incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash charge of $5.6 million in the second quarter of 2008 related to the amortization expense associated with the deferred financing costs related to the credit facility. See Note 4 to the Consolidated Financial Statements.

Income Taxes

Income tax expense was $24,000 and $2.7 million for the three-month periods ended June 30, 2009 and 2008, respectively. We established a valuation allowance of $174 million as of December 31, 2008. We revised the valuation allowance in the second quarter of 2009 as a result of current year ordinary income, the impact of which is included in our effective tax rate. See Note 8 to the Consolidated Financial Statements.

Comparison of Results of Operations for the Six Months Ended June 30, 2009 and the Six Months Ended June 30, 2008.

Oil and Gas Production and Revenues

Total oil and gas revenues were $49.8 million in the first six-months of 2009 compared to $93.0 million in the same period in 2008. Total production on an equivalent basis during the six-month period ended June 30, 2009 decreased by 17% compared to the six-month period ended June 30, 2008 and oil and gas prices on a Mcfe basis for the same period of 2009 decreased 36% compared to 2008.

Gas production during the first half of 2009 totaled 2.9 billion cubic feet (Bcf) and generated $14.9 million in revenues compared to 3.8 Bcf and $39.3 million in revenues during the same period in 2008. The average gas price after hedging impact for the six-month period ended June 30, 2009 was $5.18 per Mcf compared to $10.46 per Mcf for the same period in 2008. Approximately 21% of the 24% decrease in 2009 production was due to a lower number of producing wells, with the remaining 3% resulting from normal and expected declines in production from our older properties. Four of our gas wells were shut-in during 2008 due to early water production and are now scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, which management has determined uneconomic to repair.

Oil production during the six-months ended June 30, 2009 totaled 526,000 barrels and generated $34.9 million in revenues compared to 575,000 barrels and $53.7 million in revenues for the same period in 2008. The average oil price received after hedging impact for the six-month period ended June 30, 2009 was $66.39 per barrel compared to $93.27 per barrel during the same period in 2008. The 9% decrease in 2009 production was attributable to normal and expected declines in production and our High Island Block A-540, described above.

Lease Operating Expenses

Lease operating expenses were $8.7 million for the six-month period ended June 30, 2009, a 13% decrease when compared to the same period in 2008. The decrease was primarily due to a lower number of producing wells. Four of our gas wells were shut-in during 2008 due to early water production and are now scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, which management determined uneconomic to repair.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the six-month period ended June 30, 2009 and 2008 was $17.9 million and $30.2 million, respectively. The 41% decrease was due to lower production volumes as well as a lower depletion rate resulting from the full-cost ceiling writedown which was recorded in the fourth quarter of 2008.

Accretion Expense

Accretion expense was $1.8 million and $2.0 million for the six-month periods ended June 30, 2009 and 2008 and represents accretion of our asset retirement obligations. See Note 9 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses, net of amounts capitalized, were $7.2 million and $5.6 million for the six-month period ended June 30, 2009 and 2008, respectively. The 29% increase was

primarily due to the $2.2 million of nonrecurring expenses for staffing reductions and retirements. The increase was slightly offset by the adjustment recorded in the first quarter for 75% of the incentive compensation pool which was not awarded, due to current industry conditions and its impact on our recent performance.

Interest Expense

Interest expense due to Callon related debt obligations decreased to $9.6 million during the six-month period ended June 30, 2009, compared to $14.4 million during the six-month period ended June 30, 2008. The 33% decrease was due to the retirement in April 2008 of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 4 to the Consolidated Financial Statements for details.

Callon Entrada Non- Recourse Credit Facility Interest Expense

Callon Entrada non-recourse credit facility incurred interest expense for the six-month periods ended June 30, 2009 and 2008 of $3.5 million and $321,000, respectively. The increase was due to a larger outstanding loan balance for the six-month period ended June 30, 2009 and an increase in the interest rate due to the notice of default received from CIECO on April 2, 2009. See Note 1 to the Consolidated Financial Statements for details.

Loss on Early Extinguishment of Debt

Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, Callon incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash charge of $5.6 million in the second quarter of 2008 related to the amortization expense associated with the deferred financing costs related to the credit facility. See Note 4 to the Consolidated Financial Statements.

Income Taxes

Income tax expense was zero and $6.8 million for the six-month periods ended June 30, 2009 and 2008, respectively. We established a valuation allowance of $174 million as of December 31, 2008. We revised the valuation allowance in the second half of 2009 as a result of current year ordinary income, the impact of which is included in our effective tax rate. See Note 8 to the Consolidated Financial Statements.

Item 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price 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 5 to the Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts at June 30, 2009.

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 principal financial officers have 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, 2009.

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 1A. RISK FACTORS

There have been no material changes from the Risk Factors disclosed in Item 1. of our Annual Report on Form 10-K for the year ended December 31, 2008.

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)
	4.6		Supplemental Indenture dated April 4, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on April 9, 2008)

10.

Material Contracts

	10.1		Callon Petroleum Company Nonqualified Stock Option Award Agreement, dated June 1, 2009, between Callon Petroleum Company and Steven B. Hinchman
	10.2		Callon Petroleum Company Performance Share Award Agreement, dated June 1, 2009, between Callon Petroleum Company and Steven B. Hinchman

31.

Certifications

	31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.

Section 1350 Certifications

	32.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2		Certification of Chief 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)
	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)
	4.6		Supplemental Indenture dated April 4, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on April 9, 2008)

10.

Material Contracts

	10.1		Callon Petroleum Company Nonqualified Stock Option Award Agreement, dated June 1, 2009, between Callon Petroleum Company and Steven B. Hinchman
	10.2		Callon Petroleum Company Performance Share Award Agreement, dated June 1, 2009, between Callon Petroleum Company and Steven B. Hinchman

31.

Certifications

	31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.

Section 1350 Certifications

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