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, 2008		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.)

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, a non-accelerated filer, or a smaller reporting company. See the 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
				(Do not check if a smaller reporting company)

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, 2008, there were 21,543,497 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, 2008 and December 31, 2007			3
Consolidated Statements of Operations for Each of the Three and Six Months in the Periods Ended June 30, 2008 and June 30, 2007			4
Consolidated Statements of Cash Flows for Each of the Six Months in the Periods Ended June 30, 2008 and June 30, 2007			5
Notes to Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			13
Item 3. Quantitative and Qualitative Disclosures about Market Risk			21
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 Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

Callon Petroleum Company

Consolidated Balance Sheets
(In thousands, except share data)

		June 30,				December 31,
		2008				2007
		(Unaudited)				(Note 1)
ASSETS
Current assets:
Cash and cash equivalents		$	42,056			$	53,250
Accounts receivable			41,956				22,073
Deferred tax asset			22,707				—
Restricted investments			—				100
Other current assets			3,366				6,592
Total current assets			110,085				82,015
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,272,005				1,349,904
Less accumulated depreciation, depletion and amortization			(768,621	)			(738,374	)
			503,384				611,530
Unevaluated properties excluded from amortization			54,514				70,176
Total oil and gas properties			557,898				681,706
Other property and equipment, net			2,130				1,986
Restricted investments			4,704				4,525
Investment in Medusa Spar LLC			12,869				12,673
Other assets, net			3,378				9,577
Total assets		$	691,064			$	792,482
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	57,363			$	37,698
Asset retirement obligations			6,738				9,810
Fair market value of derivatives			21,358				5,205
Total current liabilities			85,459				52,713
Long-term debt			228,617				392,012
Asset retirement obligations			28,355				27,027
Deferred tax liability			54,568				32,190
Other long-term liabilities			2,272				1,465
Total liabilities			399,271				505,407
Stockholders’ equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value, 30,000,000 shares authorized; 21,152,090 and 20,891,145 shares outstanding at June 30, 2008 and December 31, 2007, respectively			211				209
Capital in excess of par value			226,061				223,336
Other comprehensive income			(14,177	)			(3,383	)
Retained earnings			79,698				66,913
Total stockholders’ equity			291,793				287,075
Total liabilities and stockholders’ equity		$	691,064			$	792,482

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

Callon Petroleum Company

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Operating revenues:
Oil sales		$	28,554			$	16,178			$	53,650			$	32,146
Gas sales			19,475				27,296				39,339				56,812
Total operating revenues			48,029				43,474				92,989				88,958
Operating expenses:
Lease operating expenses			4,870				8,613				10,048				15,212
Depreciation, depletion and amortization			15,218				18,819				30,247				40,666
General and administrative			2,943				2,271				5,595				4,492
Accretion expense			952				943				1,984				2,055
Total operating expenses			23,983				30,646				47,874				62,425
Income from operations			24,046				12,828				45,115				26,533
Other (income) expenses:
Interest expense			4,755				9,172				14,695				13,757
Other income			(379	)			(102	)			(851	)			(427	)
Loss on early extinguishment of debt			11,871				—				11,871				—
Total other (income) expenses			16,247				9,070				25,715				13,330
Income before income taxes			7,799				3,758				19,400				13,203
Income tax expense			2,730				1,315				6,812				5,118
Income before Medusa Spar LLC			5,069				2,443				12,588				8,085
Income from Medusa Spar LLC, net of tax			84				138				197				299
Net income		$	5,153			$	2,581			$	12,785			$	8,384
Net income per common share:
Basic		$	0.25			$	0.12			$	0.61			$	0.40
Diluted		$	0.23			$	0.12			$	0.58			$	0.39
Shares used in computing net income per common share:
Basic			20,966				20,726				20,919				20,724
Diluted			22,074				21,302				21,859				21,248

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

Callon Petroleum Company

Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)

		Six Months Ended
		June 30,				June 30,
		2008				2007
Cash flows from operating activities:
Net income		$	12,785			$	8,384
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization			30,615				41,095
Accretion expense			1,984				2,055
Amortization of deferred financing costs			1,580				1,314
Non-cash loss on early extinguishment of debt			5,598				—
Equity in earnings of Medusa Spar LLC			(197	)			(299	)
Deferred income tax expense			6,812				5,118
Non-cash charge related to compensation plans			1,546				725
Excess tax benefits from share-based payment arrangements			(1,435	)			—
Changes in current assets and liabilities:
Accounts receivable			(2,470	)			6,340
Other current assets			3,226				(929	)
Current liabilities			3,482				6,980
Change in gas balancing receivable			732				(10	)
Change in gas balancing payable			359				437
Change in other long-term liabilities			(6	)			(5	)
Change in other assets, net			(702	)			(1,049	)
Cash provided by operating activities			63,909				70,156
Cash flows from investing activities:
Capital expenditures			(78,441	)			(50,911	)
Entrada acquisition			—				(150,000	)
Proceeds from sale of mineral interests			167,493				—
Distribution from Medusa Spar LLC			108				430
Cash provided by (used) in investing activities			89,160				(200,481	)
Cash flows from financing activities:
Increases in debt			51,435				211,000
Payments on debt			(216,000	)			(46,000	)
Deferred financing costs			—				(6,429	)
Equity issued related to employee stock plans			(1,133	)			—
Excess tax benefits from share-based payment arrangements			1,435				—
Capital leases			—				(872	)
Cash (used) in provided by financing activities			(164,263	)			157,699
Net (decrease) increase in cash and cash equivalents			(11,194	)			27,374
Cash and cash equivalents:
Balance, beginning of period			53,250				1,896
Balance, end of period		$	42,056			$	29,270

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

CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2008

1.		General
		The financial information presented as of any date other than December 31, 2007 has been prepared from the books and records of Callon Petroleum Company (the “Company” or “Callon”) without audit. Financial information as of December 31, 2007 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, 2007 included in the Company’s Annual Report on Form 10-K filed March 17, 2008. The results of operations for the three-month and six-month periods ended June 30, 2008 are not necessarily indicative of future financial results.
2.		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,
		2008				2007				2008				2007
(a) Net income		$	5,153			$	2,581			$	12,785			$	8,384
(b) Weighted average shares outstanding			20,966				20,726				20,919				20,724
Dilutive impact of stock options			253				150				225				144
Dilutive impact of warrants			599				335				526				317
Dilutive impact of restricted stock			256				91				189				63
(c) Weighted average shares outstanding for diluted net income per share			22,074				21,302				21,859				21,248
Basic net income per share (a¸b)		$	0.25			$	0.12			$	0.61			$	0.40
Diluted net income per share (a¸c)		$	0.23			$	0.12			$	0.58			$	0.39
Stock options excluded due to the exercise price being greater than the average stock price			—				77				—				73

3.		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 No. 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. 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, 2008 resulted in a decrease in oil and gas sales of $6.0 million and $7.8 million, respectively. For the three-month and six-month periods ended June 30, 2007 cash settlements on effective oil and gas cash flow hedges resulted in an increase in oil and gas sales of $823,000 and $3.6 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 8, “Fair Value Measurements”.
		Listed in the table below are the outstanding oil and gas derivative contracts as of June 30, 2008:

		Collars

										Average				Average
		Volumes per				Quantity				Floor				Ceiling
Product		Month				Type				Price				Price				Period
Oil			30,000			Bbls				$	65.00			$	81.50				07/08-12/08
Oil			30,000			Bbls				$	110.00			$	175.75				01/09-12/09
Natural Gas			175,000			MMBtu				$	7.50			$	9.60				07/08-12/08
Natural Gas			100,000			MMBtu				$	8.00			$	11.13				07/08-12/08
Natural Gas			100,000			MMBtu				$	11.00			$	20.00				01/09-03/09

		Swaps

Volumes per

Quantity

Average

Product

Month

Type

Price

Period

Oil

15,000

Bbls

$

91.00

07/08-12/08

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

		June 30,				December 31,
		2008				2007
		(In thousands)
Senior Secured Credit Facility (matures July 31, 2010)		$	—				$	—
9.75% Senior Notes (due 2010), net of discount			193,182					192,012
Senior Revolving Credit Facility (due 2014)			—					200,000
Callon Entrada Credit Facility (due 2014)			35,435					—
Total long-term debt		$	228,617				$	392,012

		On August 30, 2006, the Company closed on a four-year amended and restated senior secured credit facility with the Union Bank of California (“UBOC”). The borrowing base, which is reviewed and redetermined semi-annually, was $50 million at June 30, 2008. Borrowings under the credit facility are secured by mortgages covering the Company’s major fields. As of June 30, 2008, there were no borrowings under the facility; however Callon had a letter of credit outstanding in the amount of $15 million to secure a drilling rig for the development of Entrada. As a result, $35 million was available for future borrowings under the credit facility as of June 30, 2008.
		On April 18, 2007, Callon closed the Entrada acquisition contemporaneous with a seven-year $200 million senior revolving credit facility arranged by Merrill Lynch Capital Corporation, which was secured by a lien on the Entrada properties. The Company borrowed the full commitment amount under the facility at closing to cover the required $150 million payment to BP Exploration and Production Company (“BP”), and expenses and fees related to the transaction, and the balance was used to pay down the Company’s UBOC senior secured credit facility. Callon’s UBOC senior secured credit facility was amended to allow for this transaction.
		On April 8, 2008, Callon extinguished the $200 million senior revolving credit facility. The retirement was made with cash on hand, a $16 million draw under the UBOC credit facility and proceeds from the sale of a 50% working interest in our Entrada Field to CIECO Energy (US) Limited (“CIECO”). Due to the early extinguishment of this credit facility, Callon incurred expenses of $11.9 million, consisting of $6.3 million in 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. These amounts are included in “Loss on early extinguishment of debt” in the accompanying Consolidated Statements of Operations.
		In addition, a wholly-owned subsidiary of Callon, Callon Entrada Company (“Callon Entrada”), entered into a credit agreement with CIECO Energy (Entrada) LLC, (“CIECO Entrada”) pursuant to which Callon Entrada may borrow up to $150 million plus interest expense incurred of up to $12 million to finance the development of the Entrada project. The Callon Entrada credit facility is fully collateralized by the Entrada Field. 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 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 attributable to gross negligence of Callon Entrada.
		The Callon Entrada credit facility bears interest at six-month LIBOR (as in effect on the first day of each interest period) plus 375 basis points and requires semi-annual payments of principal and interest derived from estimated cash flow from the Entrada project. These payments will begin six months after the date of initial production from the Entrada project. The Callon Entrada credit facility matures within five years of first production from the property, and is subject to customary representations, warranties, covenants and events of default. As of June 30, 2008, $35.4 million was outstanding under this facility.
5.		Comprehensive Income
		A summary of the Company’s comprehensive income is detailed below (in thousands, net of tax):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Net income		$	5,153			$	2,581			$	12,785			$	8,384
Other comprehensive income (loss):
Change in fair value of derivatives			(8,579	)			80				(10,794	)			(5,841	)
Total comprehensive income (loss)		$	(3,426	)		$	2,661			$	1,991			$	2,543

6.		Asset Retirement Obligations
		The following table summarizes the activity for the Company’s asset retirement obligations:

		Six Months Ended
		June 30, 2008
Asset retirement obligations at beginning of period		$	36,837
Accretion expense			1,984
Liabilities incurred			838
Liabilities settled			(4,700	)
Revisions to estimate			134
Asset retirement obligations at end of period			35,093
Less: current asset retirement obligations			(6,738	)
Long-term asset retirement obligations		$	28,355

		Assets, primarily U.S. Government securities, of approximately $4.7 million at June 30, 2008, 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.
7.		Entrada Divestiture
		On April 8, 2008, Callon completed the sale of a 50% working interest in the Entrada Field to CIECO effective January 1, 2008. At closing, CIECO paid Callon $155 million and reimbursed Callon $12.6 million for 50% of Entrada capital expenditures incurred prior to the closing date. In addition, CIECO agreed to fund half of a $40 million future contingent payment owed by Callon to BP Exploration and Production Company, the former majority interest owner of the field. Callon has retained a 50% working interest and will continue as operator of the field. The Company did not recognize a gain or loss on this transaction.
		In addition, a wholly-owned subsidiary of Callon, Callon Entrada, entered into a credit agreement with CIECO Entrada, pursuant to which Callon Entrada may borrow up to $150 million plus interest expense incurred of up to $12 million to finance the development of the Entrada project. See Note 4.
		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 UBOC credit facility, to extinguish the $200 million senior secured revolving credit facility, 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.
8.		Fair Value Measurements
		Effective January 1, 2008, the Company adopted Statement of Financial Accounting Standards No. 157, (“SFAS 157”), “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS 157 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, 2008 (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		$	—			$	—			$	—			$	—
Derivative liabilities			—				—				(21,358	)			(21,358	)
Total		$	—			$	—			$	(21,358	)		$	(21,358	)

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 first half of 2008. 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, 2008 (in thousands):

		Derivatives
Balance at January 1, 2008		$	(5,205	)
Total gains or losses (realized or unrealized):
Included in earnings			—
Included in other comprehensive income (loss)			(23,987	)
Purchases, issuances and settlements			7,834
Balance at June 30, 2008		$	(21,358	)
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of June 30, 2008		$	—

The Company also adopted Statement of Financial Accounting Standards No. 159, (“SFAS 159”), “The Fair Value Option for Financial Assets and Financial Liabilities,” on January 1, 2008, which permits entities to choose to measure various financial instruments and certain other items at fair value. The adoption of SFAS 159 did not have an impact on the Company’s financial statements.

9.		Accounting Pronouncements
		In March 2008, the FASB issued Statement of Financial Accounting Standards 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 Statement 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. The new disclosure standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. Callon is currently evaluating the impact that SFAS 161 will have on its 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

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, 2008, we had cash and cash equivalents of $42 million and $35 million of availability under our UBOC senior secured credit facility. Cash provided from operating activities during the six-month period ended June 30, 2008 totaled $64 million, a 9% decrease when compared to the corresponding period in 2007.

On April 8, 2008, we completed the sale of a 50% working interest in the Entrada Field to CIECO Energy (US) Limited (“CIECO”), a subsidiary of Tokyo-based ITOCHU Corporation. At closing, CIECO paid $155 million and reimbursed us $12.6 million for 50% of Entrada capital development expenditures incurred prior to the closing date. In addition, CIECO agreed to fund half of a $40 million future contingent payment owed by us to BP Exploration and Production Company, the former majority interest owner of the field. We have retained a 50% working interest and will continue as operator of the field. We did not recognize a gain or loss on the transaction.

In addition, a wholly-owned subsidiary of Callon, Callon Entrada Company (“Callon Entrada”), entered into a credit agreement with CIECO Energy (Entrada) LLC, pursuant to which Callon Entrada may borrow up to $150 million plus interest expense incurred of up to $12 million to finance the development of the Entrada project. The Callon Entrada credit facility is fully collateralized by the Entrada Field. However, we have entered into a customary indemnification agreement pursuant to which we agree to indemnify the lenders under the Callon Entrada credit facility against Callon Entrada’s misappropriation of funds, non-performance of certain covenants and similar matters. In addition, we also guaranteed the obligations of Callon Entrada to fund its proportionate operating cost related to the Entrada project that Callon Entrada may, from time to time, expressly approve under the Entrada joint operating agreement. We also 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 attributable to gross negligence of Callon Entrada.

The Callon Entrada credit facility bears interest at six-month LIBOR (as in effect on the first day of each interest period) plus 375 basis points and requires semi-annual payments of principal and interest derived from estimated cash flow from the Entrada project. These payments will begin six months after the date of initial production from the Entrada project. The Callon Entrada credit facility matures within five years of first production from the property, and is subject to customary representations, warranties, covenants and events of default. As of June 30, 2008, $35.4 million was outstanding under this facility.

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 UBOC credit facility, to extinguish the $200 million senior secured revolving credit facility, 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.

For 2008, our projection for capital expenditures is comprised primarily of the development costs of our Entrada Field, which is our largest asset and the major operational focus for the year, plus a limited exploration and development program. The Entrada development is currently projected to require total expenditures in the range of $360 million to $380 million of which 50% will be our share of the estimated gross expenditures, between $290 million and $310 million of these costs will be incurred in 2008. Our credit agreement with CIECO Energy (Entrada) LLC provides that they will finance our share of the development costs up to $150 million. The balance of our share of total costs in excess of the $150 million will be funded by our cash flow from operations.

Our remaining capital expenditure budget for 2008, excluding our Entrada Field development, will require approximately $70 million of funding, which includes asset retirement obligations, capitalized interest and general and administrative expenses. We expect that available cash and cash flows generated from operations during 2008, along with current availability under our UBOC senior secured credit facility, will provide the capital necessary to fund these capital expenditures. See “Capital Expenditures” below for a more detailed discussion of our anticipated capital expenditures for 2008.

The Indenture governing our 9.75% Senior Notes due 2010 and our Senior Secured Credit Facility with UBOC 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, 2008. See Note 7 of the Consolidated Financial Statements for the year ended December 31, 2007 included in our Annual Report on Form 10-K filed March 17, 2008 for a more detailed discussion of long-term debt.

The following table describes our outstanding contractual obligations (in thousands) as of June 30, 2008:

Contractual						Less Than				One-Three				Four-Five				After-Five
Obligations		Total				One Year				Years				Years				Years
Senior Secured Credit Facility		$	—			$	—			$	—			$	—			$	—
9.75% Senior Notes			200,000				—				200,000				—				—
Callon Entrada Credit Facility			35,435				—				—				—				35,435
Throughput Commitments:
Medusa Oil Pipeline			255				66				107				48				34
		$	235,690			$	66			$	200,107			$	48			$	35,469

Capital Expenditures

Capital expenditures on an accrual basis were $77 million for the six-months ended June 30, 2008. Included in the $77 million were $49 million of costs incurred for the development of our Entrada Field. In addition, we incurred $13 million for the drilling and completion of a development well at our Medusa Field and $2 million for drilling and completion activities in the Gulf of Mexico Shelf Area. Interest of approximately $4 million and general and administrative costs allocable directly to exploration and development projects of approximately $5 million were capitalized for the first six months of 2008. The remainder of the capital expended primarily includes the acquisition of seismic data, leases and plugging and abandonment costs.

Capital expenditures for the remainder of 2008 are projected to be between $131 million and $141 million and include:

	•		development wells and discretionary drilling of exploratory wells;
	•		Entrada development costs;
	•		the acquisition of seismic data and leases; and
	•		capitalized interest and general and administrative costs.

In addition, we are projecting to spend $7 million for the remainder of 2008 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 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. During the second quarter of 2008, the non-recourse financing was retired. 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,
		2008				2007				2008				2007
Net production :
Oil (MBbls)			286				263				575				551
Gas (MMcf)			1,668				3,341				3,759				7,043
Total production (MMcfe)			3,382				4,920				7,211				10,348
Average daily production (MMcfe)			37.2				54.1				39.6				57.2
Average sales price:
Oil (Bbls) (a)		$	99.99			$	61.47			$	93.27			$	58.36
Gas (Mcf)			11.67				8.17				10.46				8.07
Total (Mcfe)			14.20				8.84				12.90				8.60
Oil and gas revenues:
Oil revenue		$	28,554			$	16,178			$	53,650			$	32,146
Gas revenue			19,475				27,296				39,339				56,812
Total		$	48,029			$	43,474			$	92,989			$	88,958
Oil and gas production costs:
Lease operating expenses		$	4,870			$	8,613			$	10,048			$	15,212
Additional per Mcfe data:
Sales price		$	14.20			$	8.84			$	12.90			$	8.60
Lease operating expense			1.44				1.75				1.39				1.47
Operating margin		$	12.76			$	7.09			$	11.51			$	7.13
Depletion, depreciation and amortization		$	4.50			$	3.83			$	4.19			$	3.93
General and administrative (net of management fees)		$	0.87			$	0.46			$	0.78			$	0.43

Average NYMEX oil price		$	123.98			$	65.00			$	110.94			$	61.63
Basis differential and quality adjustments			(4.06	)			(2.85	)			(3.95	)			(4.18	)
Transportation			(1.34	)			(1.14	)			(1.30	)			(1.14	)
Hedging			(18.59	)			0.46				(12.42	)			2.05
Average realized oil price		$	99.99			$	61.47			$	93.27			$	58.36

Comparison of Results of Operations for the Three Months Ended June 30, 2008 and the Three Months Ended June 30, 2007.

Oil and Gas Production and Revenues

Total oil and gas revenues were $48.0 million in the second quarter of 2008 compared to $43.5 million in the second quarter of 2007. Total production on an equivalent basis for the second quarter of 2008 decreased by 31% compared to the second quarter of 2007. However, oil and gas prices on a Mcfe basis increased 61% compared to 2007.

Gas production during the second quarter of 2008 totaled 1.7 billion cubic feet (Bcf) and generated $19.5 million in revenues compared to 3.3 Bcf and $27.3 million in revenues during the same period in 2007. The average gas price after hedging impact for the second quarter of 2008 was $11.67 per thousand cubic feet of natural gas (“Mcf”) compared to $8.17 per Mcf for the same period in 2007. The 50% decrease in 2008 production was primarily attributable to the sale of our Mobile Bay 952,953,955 Field; early water production from our High Island Block 165, North Padre Island Block 913 and Prairie Beach fields; an obstruction in the flowline at High Island Block A-540 causing the field to be shut-in in mid-April 2008; and expected declines in production from our remaining properties.

Oil production during the second quarter of 2008 totaled 286,000 barrels and generated $28.6 million in revenues compared to 263,000 barrels and $16.2 million in revenues for the same period in 2007. The average oil price received after hedging impact in the second quarter of 2008 was $99.99 per barrel compared to $61.47 per barrel in the second quarter of 2007.

Lease Operating Expenses

Lease operating expenses were $4.9 million for the three-month period ended June 30, 2008, a 43% decrease when compared to the same period in 2007. The decrease was primarily due to the sale of the Mobile Bay 952, 953, 955 Field, the shut-in of our Prairie Beach Field, lower thru-put charges at High Island Block 165 and reduced insurance costs for the Medusa Spar.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three-month periods ended June 30, 2008 and 2007 was $15.2 million and $18.8 million, respectively. The 19% decrease was primarily due to lower production volumes and a higher depletion rate.

Accretion Expense

Accretion expense for the three-month periods ended June 30, 2008 and 2007 of $952,000 and $943,000, respectively, represents accretion of our asset retirement obligations. See Note 6 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses, net of amounts capitalized, were $2.9 million and $2.3 million for the three-month periods ended June 30, 2008 and 2007, respectively. The 30% increase was primarily the result of increased staffing costs.

Interest Expense

Interest expense decreased to $4.8 million during the three-month period ended June 30, 2008, compared to $9.2 million during the three months ended June 30, 2007. The 48% decrease was due to retirement of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 4 for more 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 related to the amortization expense associated with the deferred financing costs related to the credit facility. See Note 4.

Income Taxes

Income tax expense was $2.7 million and $1.3 million for the three-month periods ended June 30, 2008 and 2007, respectively. The increase was primarily due to an increase in income before income taxes.

Comparison of Results of Operations for the Six Months Ended June 30, 2008 and the Six Months Ended June 30, 2007.

Oil and Gas Production and Revenues

Total oil and gas revenues were $93.0 million in the first six-months of 2008 compared to $89.0 million in the same period in 2007. Total production on an equivalent basis during the six-month period ended June 30, 2008 decreased by 30% compared to the six-month period ended June 30, 2007. However, oil and gas prices on a Mcfe basis increased 50% compared to the same period in 2007.

Gas production during the first half of 2008 totaled 3.8 billion cubic feet (“Bcf”) and generated $39.3 million in revenues compared to 7.0 Bcf and $56.8 million in revenues during the same period in 2007. The average gas price after hedging impact for the six-month period ended June 30, 2008 was $10.46 per Mcf compared to $8.07 per Mcf for the same period last year. The 47% decrease in 2008 production was primarily attributable to the sale of our Mobile Bay 952,953,955 Field; early water production from our High Island Block 165, North Padre Island Block 913 and Prairie Beach Fields; an obstruction in the flowline at High Island Block A-540 causing the field to be shut-in in mid-April 2008; and expected declines in production from our remaining properties.

Oil production during the six-months ended June 30, 2008 totaled 575,000 barrels and generated $53.7 million in revenues compared to 551,000 barrels and $32.1 million in revenues for the same period in 2007. The average oil price received after hedging impact for the six-month period ended June 30, 2008 was $93.27 per barrel compared to $58.36 per barrel during the same period in 2007.

Lease Operating Expenses

Lease operating expenses were $10.0 million for the six-month period ended June 30, 2008, a 34% decrease when compared to the same period in 2007. The decrease was primarily due to the sale of the Mobile Bay 952,953,955 Field effective May 1, 2007, the shut-in of our North Padre Island Block 913 and Prairie Beach Fields, lower thru-put charges at High Island 165 and reduced insurance costs for the Medusa Spar.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the six-month period ended June 30, 2008 and 2007 was $30.2 million and $40.7 million, respectively. The 26% decrease was primarily due to lower production volumes and a higher depletion rate.

Accretion Expense

Accretion expense for the six-month periods ended June 30, 2008 and 2007 of $2.0 and $2.1 million, respectively, represents accretion of our asset retirement obligations. See Note 6 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses, net of amounts capitalized, were $5.6 million and $4.5 million for the six-month periods ended June 30, 2008 and 2007, respectively. The 25% increase was primarily the result of increased staffing costs.

Interest Expense

Interest expense increased to $14.7 million during the six-month period ended June 30, 2008, compared to $13.8 million during the six-month period ended June 30, 2007. This increase was due to the debt associated with the Entrada acquisition in April 2007. This debt was retired on April 8, 2008, which will result in decreased interest expense for the remainder of 2008 compared to 2007. See Note 4 for more 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 related to the amortization expense associated with the deferred financing costs related to the credit facility. See Note 4.

Income Taxes

Income tax expense was $6.8 million and $5.1 million for the six-month periods ended June 30, 2008 and 2007, respectively. The increase was primarily due to an increase in income before income taxes.

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 3 to the Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts at June 30, 2008.

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, 2008.

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 1, 2008. At the annual meeting, one Class I director and two Class II directors of the board of directors of the Company were elected to hold office until the Company’s annual meeting of shareholders in 2010 and 2011, respectively, or until their respective successors have been duly elected and qualified. The votes cast for the directors proposed in the Company’s definitive proxy statement on Schedule 14A, out of a total of 20,941,779 shares outstanding on the record date for the annual meeting, were as follows:

				For				Withheld
Larry D. McVay		Class I			17,809,892				324,634
B.F. Weatherly		Class II			16,258,251				1,876,275
Richard O. Wilson		Class II			17,722,072				412,454

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

The shareholders of the Company ratified the appointment of Ernst & Young LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2008. There were 17,640,026 votes in favor and 494,498 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.

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		Credit Agreement between Callon Entrada and CIECO Energy (Entrada) LLC dated April 4, 2008 (incorporated by reference to Exhibit 10.3 of the Company’s Report on Form 8-K filed on April 9, 2008)
	10.2		Indemnity Agreement dated April 4, 2008 (incorporated by reference to Exhibit 10.4 of the Company’s Report on Form 8-K filed on April 9, 2008)
	10.3		Non-Recourse Guaranty dated April 4, 2008 (incorporated by reference to Exhibit 10.5 of the Company’s Report on Form 8-K filed on April 9, 2008)

	10.4		Amendment to UBOC credit facility dated April 4, 2008 (incorporated by reference to Exhibit 10.6 of the Company’s Report on Form 8-K filed on April 9, 2008)
	10.5		Severance Compensation Agreement dated April 18, 2008 by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on April 23, 2008)
	10.6		Form of Severance Compensation Agreement dated April 18, 2008 by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed on April 23, 2008)

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)

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)
	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		Credit Agreement between Callon Entrada and CIECO Energy (Entrada) LLC dated April 4, 2008 (incorporated by reference to Exhibit 10.3 of the Company’s Report on Form 8-K filed on April 9, 2008)
	10.2		Indemnity Agreement dated April 4, 2008 (incorporated by reference to Exhibit 10.4 of the Company’s Report on Form 8-K filed on April 9, 2008)
	10.3		Non-Recourse Guaranty dated April 4, 2008 (incorporated by reference to Exhibit 10.5 of the Company’s Report on Form 8-K filed on April 9, 2008)
	10.4		Amendment to UBOC credit facility dated April 4, 2008 (incorporated by reference to Exhibit 10.6 of the Company’s Report on Form 8-K filed on April 9, 2008)
	10.5		Severance Compensation Agreement dated April 18, 2008 by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on April 23, 2008)
	10.6		Form of Severance Compensation Agreement dated April 18, 2008 by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed on April 23, 2008)

Exhibit Number				Title of Document

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