UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

For the Quarterly Period Ended September 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.)

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 November 5, 2008, there were 21,614,515 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

 

 

CALLON PETROLEUM COMPANY

TABLE OF CONTENTS

				Page No.
Part I.		Financial Information
		Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007			3
		Consolidated Statements of Operations for Each of the Three and Nine Months in the Periods Ended September 30, 2008 and September 30, 2007			4
		Consolidated Statements of Cash Flows for Each of the Three and Nine Months in the Periods Ended September 30, 2008 and September 30, 2007			5
		Notes to Consolidated Financial Statements			6
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			14
Item 3.		Quantitative and Qualitative Disclosures about Market Risk			25
Item 4.		Controls and Procedures			25
Part II.		Other Information
Item 1A.		Risk Factors			26
Item 6.		Exhibits			26
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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

		September 30,				December 31,
		2008				2007
		(Unaudited)				(Note 1)
ASSETS
Current assets:
Cash and cash equivalents		$	101,549			$	53,250
Accounts receivable			50,148				22,073
Restricted investments			—				100
Fair market value of derivatives			5,066				—
Other current assets			3,498				6,592
Total current assets			160,261				82,015
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,345,841				1,349,904
Less accumulated depreciation, depletion and amortization			(780,134	)			(738,374	)
			565,707				611,530
Unevaluated properties excluded from amortization			51,401				70,176
Total oil and gas properties			617,108				681,706
Other property and equipment, net			2,547				1,986
Restricted investments			4,733				4,525
Investment in Medusa Spar LLC			12,679				12,673
Other assets, net			4,934				9,577
Total assets		$	802,262			$	792,482
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	112,295			$	37,180
Advances from joint interest owners			12,966				518
Asset retirement obligations			3,935				9,810
Fair market value of derivatives			1,345				5,205
Total current liabilities			130,541				52,713
Long-term debt			272,227				392,012
Asset retirement obligations			36,187				27,027
Deferred tax liability			43,998				32,190
Other long-term liabilities			2,995				1,465
Total liabilities			485,948				505,407
Stockholders’ equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value, 30,000,000 shares authorized; 21,611,847 and 20,891,145 shares outstanding at September 30, 2008 and December 31, 2007, respectively			216				209
Capital in excess of par value			226,639				223,336
Other comprehensive income			3,905				(3,383	)
Retained earnings			85,554				66,913
Total stockholders’ equity			316,314				287,075
Total liabilities and stockholders’ equity		$	802,262			$	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								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Operating revenues:
Oil sales		$	20,366			$	15,912			$	74,016			$	48,058
Gas sales			12,417				21,957				51,756				78,769
Total operating revenues			32,783				37,869				125,772				126,827
Operating expenses:
Lease operating expenses			3,701				5,338				13,749				20,550
Depreciation, depletion and amortization			11,513				15,931				41,760				56,597
General and administrative			1,451				2,606				7,046				7,098
Accretion expense			1,092				904				3,076				2,959
Derivative expense			1,386				—				1,386				—
Total operating expenses			19,143				24,779				67,017				87,204
Income from operations			13,640				13,090				58,755				39,623
Other (income) expenses:
Interest expense			5,014				10,148				19,709				23,905
Loss on early extinguishment of debt			—				—				11,871				—
Other (income) expense			(89	)			(387	)			(940	)			(814	)
Total other (income) expenses			4,925				9,761				30,640				23,091
Income before income taxes			8,715				3,329				28,115				16,532
Income tax expense			2,919				1,165				9,731				6,283
Income before Medusa Spar LLC			5,796				2,164				18,384				10,249
Income from Medusa Spar LLC, net of tax			60				104				257				403
Net income		$	5,856			$	2,268			$	18,641			$	10,652
Net income per common share:
Basic		$	0.27			$	0.11			$	0.88			$	0.51
Diluted		$	0.27			$	0.11			$	0.85			$	0.50
Shares used in computing net income per common share:
Basic			21,460				20,800				21,078				20,728
Diluted			22,028				21,230				21,893				21,220

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

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

		Nine Months Ended
		September 30,								September 30,
		2008								2007
Cash flows from operating activities:
Net income		$	18,641							$	10,652
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization			42,333								57,270
Accretion expense			3,076								2,959
Amortization of deferred financing costs			2,308								2,153
Non-cash loss on early extinguishment of debt			5,598								—
Equity in earnings of Medusa Spar LLC			(257	)							(403	)
Non-cash derivative expense			690								—
Deferred income tax expense			9,731								6,283
Non-cash charge related to compensation plans			1,026								490
Excess tax benefits from share-based payment arrangements			(1,985	)							—
Changes in current assets and liabilities:
Accounts receivable			13,094								7,891
Other current assets			3,094								(413	)
Current liabilities			26,039								896
Change in gas balancing receivable			806								(160	)
Change in gas balancing payable			356								564
Change in other long-term liabilities			1,174								(7	)
Change in other assets, net			(949	)							1,745
Cash provided by operating activities			124,775								89,920
Cash flows from investing activities:
Capital expenditures			(123,626	)							(106,899	)
Entrada acquisition			—								(150,000	)
Proceeds from sale of Entrada working interest			167,493								—
Distribution from Medusa Spar LLC			389								559
Cash provided by (used in) investing activities			44,256								(256,340	)
Cash flows from financing activities:
Change in accrued liabilities to be refinanced			—								10,000
Increases in debt			94,435								213,000
Payments on debt			(216,000	)							(48,000	)
Deferred financing costs			—								(6,429	)
Equity issued related to employee stock plans			(1,152	)							—
Excess tax benefits from share-based payment arrangements			1,985								—
Capital leases			—								(872	)
Cash (used in) provided by financing activities			(120,732	)							167,699
Net increase in cash and cash equivalents			48,299								1,279
Cash and cash equivalents:
Balance, beginning of period			53,250								1,896
Balance, end of period		$	101,549							$	3,175

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

CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 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 nine-month periods ended September 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								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
(a) Net income		$	5,856			$	2,268			$	18,641			$	10,652
(b) Weighted average shares outstanding			21,460				20,800				21,078				20,728
Dilutive impact of stock options			171				136				207				142
Dilutive impact of warrants			260				292				437				308
Dilutive impact of restricted stock			137				2				171				42
(c) Weighted average shares outstanding
for diluted net income per share			22,028				21,230				21,893				21,220
Basic net income per share (a¸b)		$	0.27			$	0.11			$	0.88			$	0.51
Diluted net income per share (a¸c)		$	0.27			$	0.11			$	0.85			$	0.50
Stock options excluded due to the exercise price being greater than the average stock price			—				104				—				92

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 nine-month periods ended September 30, 2008 resulted in a decrease in oil and gas sales of $4.6 million and $12.4 million, respectively. For the three-month and nine-month periods ended September 30, 2007 cash settlements on effective oil and gas cash flow hedges resulted in an increase in oil and gas sales of $3.4 million and $7.0 million, respectively.
		Cash settlements on ineffective derivative contracts were recorded as derivative expense in the amount of $695,000 for the three-month and nine-month periods ended September 30, 2008. These contracts were deemed ineffective as a result of a shortfall in production volumes due to downtime from hurricane activity in the third quarter of 2008.
		As a result of continued downtime to oil and gas transmission lines and facilities owned by third parties due to damages caused by Hurricanes Gustav and Ike, some of our derivative contracts for October and November 2008 have been deemed ineffective. As a result of the probable shortfall in production volumes, Callon recognized a non-cash derivative expense of $691,000 for the three-month and nine-month periods ended September 30, 2008 to reclassify the unrealized loss on these contracts, which was included in other comprehensive (loss) to earnings.
		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 September 30, 2008:
		Collars

								Average				Average
		Volumes per				Quantity		Floor				Ceiling
Product		Month				Type		Price				Price				Period
Oil			30,000			Bbls		$	65.00			$	81.50			10/08-12/08
Oil			30,000			Bbls		$	110.00			$	175.75			01/09-12/09
Natural Gas			175,000			MMBtu		$	7.50			$	9.60			10/08-12/08
Natural Gas			100,000			MMBtu		$	8.00			$	11.13			10/08-12/08
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

10/08-12/08

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

		September 30,				December 31,
		2008				2007
		(In thousands)
Senior Secured Credit Facility (matures September 25, 2012)		$	—			$	—
9.75% Senior Notes (due 2010), net of discount			193,792				192,012
Senior Revolving Credit Facility (due 2014)			—				200,000
Callon Entrada Credit Facility (due 2014)			78,435				—
Total long-term debt		$	272,227			$	392,012

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 the Union Bank of California (“UBOC”) as issuing lender. The initial borrowing base, which will be reviewed and redetermined semi-annually, is $70 million. Borrowings under the credit agreement are secured by mortgages covering the Company’s major fields excluding Entrada. As of September 30, 2008, there were no borrowings under the agreement; however Callon had a letter of credit outstanding in the amount of $15 million to secure the drilling rig, Ocean Victory, for the development of Entrada. As a result, $55 million was available for future borrowings under the credit agreement as of September 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 Callon’s 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 a portion of the 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 September 30, 2008, $78.4 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								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Net income		$	5,856			$	2,268			$	18,641			$	10,652
Other comprehensive income:
Change in fair value of derivatives			18,082				(1,968	)			7,288				(7,809	)
Total comprehensive income		$	23,938			$	300			$	25,929			$	2,843

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

		Nine Months Ended
		September 30, 2008
Asset retirement obligations at beginning of period		$	36,837
Accretion expense			3,076
Liabilities incurred			838
Liabilities settled			(4,782	)
Revisions to estimate			4,153
Asset retirement obligations at end of period			40,122
Less: current asset retirement obligations			(3,935	)
Long-term asset retirement obligations		$	36,187

		Assets, primarily U.S. Government securities, of approximately $4.7 million at September 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 September 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		$	—			$	—			$	6,661			$	6,661
Derivative liabilities			—				—				(1,345	)			(1,345	)
Total		$	—			$	—			$	5,316			$	5,316

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 nine-month period ended September 30, 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 September 30, 2008 (in thousands):

		Derivatives
Balance at January 1, 2008		$	(5,205	)
Total gains or losses (realized or unrealized):
Included in earnings			691
Included in other comprehensive (income) loss			(3,215	)
Purchases, issuances and settlements			13,045
Balance at September 30, 2008		$	5,316
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of September 30, 2008		$	(691	)

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. Oil and gas prices have declined significantly since the end of the quarter. This will reduce our cash flows from operations. To mitigate the impact of lower oil and gas prices on our cash flows, we have entered into hedges covering approximately 9% of our anticipated 2009 production (on an Mcfe basis). If a global recession occurs, commodity prices may be depressed for an extended period of time, which could alter our acquisition and exploration plans, and adversely affect our growth strategy. 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.

The financial markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. Our exposure to the disruptions in the financial markets includes our credit facilities, ability to access the capital markets, investments and hedge counterparty exposure.

Our second amended and restated senior secured credit agreement with Union Bank of California (“UBOC”) is committed until 2012. If the disruption in the financial markets continues for an extended period of time, replacement of our credit facility may be more expensive. In addition, the borrowing base under our credit facility is subject to periodic review by our lenders. Difficulties in the credit markets may cause the banks to be more restrictive when re-calculating our borrowing base.

Our wholly-owned subsidiary, 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 its 50% share of costs to develop the Entrada Field. The credit agreement is fully collateralized by the Entrada Field and CIECO Entrada is also a 50% working interest owner in the field. As of September 30, 2008 CIECO Entrada had loaned us $78 million under the agreement and $72 million remained to be borrowed. The outstanding loans under the credit agreement bear interest at LIBOR plus 375 basis points. The costs to borrow funds in the current disrupted financial markets to finance any portion of our share of the development costs would exceed the costs of the CIECO Entrada financing.

We have outstanding $200 million of senior notes due 2010. We plan to refinance these notes during 2009. Continued disruptions in the credit markets may make such refinancing more expensive.

Our cash and cash equivalents, which total approximately $101.5 million, are invested in overnight money market funds. Our hedge counterparties are major financial institutions and lenders under our credit facility. If one of these counterparties were not to perform, we could suffer losses. Our major purchasers having been doing business with us over the past several years and we have had no major disagreements or defaults in payment terms. However, if one of these purchasers were not to perform, we could suffer losses.

In the past we have accessed the equity markets to finance our growth. Our stock price, as well as the price of our competitors, has declined substantially over the last several months. In addition, the disruption in the financial markets has made it unlikely that we will be able to access the equity markets at any price, unless conditions improve dramatically. Until these conditions improve, we are unlikely to access the public equity markets, which may limit our ability to pursue our growth strategy.

Third Quarter Hurricane Activity

During the third quarter of 2008, we encountered two major Hurricanes, Gustav and Ike, causing substantial downtime at Medusa and Habanero. Minimal damage was incurred at the fields; however the transmission lines, which are owned by third parties, were damaged and repairs are being performed at this time. Medusa and Habanero accounted for approximately 60% of our production prior to hurricanes. As of October 30, 2008, the Medusa field was granted permission by the Minerals Management Service (“MMS”) to flare 5.0 million cubic feet of gas per day

until the gas transmission line is repaired, which is scheduled for mid to late November. This allows the Medusa field to produce approximately 7,000 barrels of oil per day until the gas transmission line is put back in service. Production from Habanero is scheduled to be back online by mid November.

Liquidity and Capital Resources

Our primary sources of capital are cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. On September 30, 2008, we had cash and cash equivalents of $102 million and $55 million of availability under our UBOC senior secured credit agreement. Cash provided from operating activities during the nine-month period ended September 30, 2008 totaled $125 million, a 39% increase when compared to the corresponding period in 2007.

On September 25, 2008, we completed a $250 million second amended and restated senior secured credit agreement with UBOC as issuing lender, which matures September 25, 2012. The initial borrowing base, which will be reviewed and redetermined semi-annually, is $70 million. Borrowings under the credit agreement are secured by mortgages covering our major fields excluding Entrada. As of September 30, 2008, there were no borrowings under the agreement; however we had a letter of credit outstanding in the amount of $15 million to secure the drilling rig, Ocean Victory, for the development of Entrada. As a result, $55 million was available for future borrowings under the credit agreement as of September 30, 2008.

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, 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. 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 a portion of the 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 September 30, 2008, $78 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 agreement, 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 capital expenditures projection is comprised primarily of Entrada Field development costs, our largest asset and the major operational focus for the year, plus a limited exploration and development program. The two well Entrada development plan is currently projected to require total estimated gross expenditures in the range of $440 million to $460 million, of which 50% will be our share. Between $325 million and $350 million of these gross costs will be incurred in 2008 or $163 million to $175 million net to us. Our credit agreement with CIECO Entrada provides that they will finance our share of the development costs up to $150 million. This loan amount was intended to cover our 50% share of the original capital expenditure estimate of $300 million to complete the project. The increase in development costs was due to a failed mooring system which was required by the MMS, two hurricanes, higher fuel costs and unanticipated subsurface mechanical problems. These higher costs do not impair the project. As of September 30, 2008, CIECO Entrada had loaned us $78 million under our agreement and $72 million remained available. Our share of total costs in excess of the $150 million loan will be funded by available cash, cash flow from operations and draws under our UBOC credit agreement, if needed.

Our capital expenditure budget for 2008, excluding our Entrada Field development, will require approximately $50 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 credit agreement, if necessary, 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 UBOC credit agreement contains covenants for maintenance of certain financial ratios. We were in compliance with these covenants at September 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 September 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 (1)			78,435				—				78,435				—				—
Throughput Commitments:
Medusa Oil Pipeline			224				48				104				42				30
		$	278,659			$	48			$	278,539			$	42			$	30

Capital Expenditures

Capital expenditures on an accrual basis were $144 million for the nine-months ended September 30, 2008. Included in the $144 million were $107 million of costs incurred for the development of our Entrada Field. In addition, we incurred $14 million for the drilling and completion of a development well at our Medusa Field and $4 million for drilling and completion activities in the Gulf of Mexico Shelf Area. Interest of approximately $5 million and general and administrative costs allocable directly to exploration and development projects of approximately $9 million were capitalized for the first nine 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 $65 million and $78 million and include:

	•		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 $3 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 fully retired and the LLC has no other long-term liability. 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								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Net production :
Oil (MBbls)			205				223				780				774
Gas (MMcf)			1,153				2,840				4,913				9,883
Total production (MMcfe)			2,383				4,179				9,593				14,527
Average daily production (MMcfe)			25.9				45.4				35.0				53.2
Average sales price:
Oil (Bbls) (a)		$	99.40			$	71.29			$	94.89			$	62.09
Gas (Mcf)			10.77				7.73				10.53				7.97
Total (Mcfe)			13.76				9.06				13.11				8.73
Oil and gas revenues:
Oil revenue		$	20,366			$	15,912			$	74,016			$	48,058
Gas revenue			12,417				21,957				51,756				78,769
Total		$	32,783			$	37,869			$	125,772			$	126,827
Oil and gas production costs:
Lease operating expenses		$	3,701			$	5,338			$	13,749			$	20,550
Additional per Mcfe data:
Sales price		$	13.76			$	9.06			$	13.11			$	8.73
Lease operating expense			1.55				1.28				1.43				1.41
Operating margin		$	12.21			$	7.78			$	11.68			$	7.32
Depletion, depreciation and amortization		$	4.83			$	3.81			$	4.35			$	3.90
General and administrative (net of management fees)		$	0.61			$	0.62			$	0.73			$	0.49
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
Average NYMEX oil price		$	117.98			$	75.37			$	113.29			$	66.21
Basis differential and quality adjustments			1.32				(2.96	)			(3.07	)			(4.45	)
Transportation			(1.34	)			(1.12	)			(1.30	)			(1.13	)
Hedging			(18.56	)			—				(14.03	)			1.46
Average realized oil price		$	99.40			$	71.29			$	94.89			$	62.09

Total oil and gas revenues were $32.8 million in the third quarter of 2008 compared to $37.9 million in the third quarter of 2007. Total production on an equivalent basis for the third quarter of 2008 decreased by 43% compared to the third quarter of 2007. Of the 43% decrease, 28% was a result of hurricane downtime. However, oil and gas prices on a Mcfe basis increased 52% compared to 2007.

Gas production during the third quarter of 2008 totaled 1.2 billion cubic feet (Bcf) and generated $12.4 million in revenues compared to 2.8 Bcf and $22.0 million in revenues during the same period in 2007. The average gas price after hedging impact for the third quarter of 2008 was $10.77 per thousand cubic feet of natural gas (“Mcf”) compared to $7.73 per Mcf for the same period in 2007. The 59% decrease in 2008 production was comprised of approximately 35% due to a lower number of producing wells, 19% from downtime resulting from Hurricanes Gustav and Ike and 5% resulting from normal and expected declines in production from our older properties. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair.

Oil production during the third quarter of 2008 totaled 205,000 barrels and generated $20.4 million in revenues compared to 223,000 barrels and $15.9 million in revenues for the same period in 2007. The average oil price received after hedging impact in the third quarter of 2008 was $99.40 per barrel compared to $71.29 per barrel in the third quarter of 2007. The 8% decrease in 2008 production was primarily attributable to downtime in the third quarter related to Hurricanes Gustav and Ike.

Lease operating expenses were $3.7 million for the three-month period ended September 30, 2008, a 31% decrease when compared to the same period in 2007. The decrease was primarily due to a lower number of producing wells and downtime in the third quarter of 2008 caused by Hurricanes Gustav and Ike resulting in lower throughput charges. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair.

Depreciation, depletion and amortization for the three-month periods ended September 30, 2008 and 2007 was $11.5 million and $15.9 million, respectively. The 28% decrease was primarily due to lower production volumes which was slightly offset by a higher depletion rate.

Accretion expense for the three-month periods ended September 30, 2008 and 2007 of $1.1 million and $0.9 million, respectively, represents accretion of our asset retirement obligations. See Note 6 to the Consolidated Financial Statements.

General and administrative expenses, net of amounts capitalized, were $1.5 million and $2.6 million for the three-month periods ended September 30, 2008 and 2007, respectively. The 44% decrease was primarily the result of overhead fees received as operator of the Entrada Field, which were recorded as a reduction to general and administrative expenses.

Interest expense decreased to $5.0 million during the three-month period ended September 30, 2008, compared to $10.1 million during the three months ended September 30, 2007. The 51% decrease was due to the retirement of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 4 for more details.

Income tax expense was $2.9 million and $1.2 million for the three-month periods ended September 30, 2008 and 2007, respectively. The increase was primarily due to an increase in income before income taxes.

Total oil and gas revenues were $125.8 million in the first nine-months of 2008 compared to $126.8 million in the same period in 2007. Total production on an equivalent basis during the nine-month period ended September 30, 2008 decreased by 34% compared to the nine-month period ended September 30, 2007. Of the 34% decrease, 8% was a result of hurricane downtime. However, oil and gas prices on a Mcfe basis increased 50% compared to the same period in 2007.

Gas production during the first nine months of 2008 totaled 4.9 Bcf and generated $51.8 million in revenues compared to 9.9 Bcf and $78.8 million in revenues during the same period in 2007. The average gas price after hedging impact for the nine-month period ended September 30, 2008 was $10.53 per Mcf compared to $7.97 per Mcf for the same period last year. The 50% decrease in 2008 production was primarily due to the sale of our Mobile Bay Field on Blocks 952, 953, and 955, effective May 1, 2007, a lower number of producing wells, downtime resulting from Hurricanes Gustav and Ike and normal and expected declines in production from our older properties. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair.

Oil production during the nine-months ended September 30, 2008 totaled 780,000 barrels and generated $74.0 million in revenues compared to 774,000 barrels and $48.1 million in revenues for

the same period in 2007. The average oil price received after hedging impact for the nine-month period ended September 30, 2008 was $94.89 per barrel compared to $62.09 per barrel during the same period in 2007.

Lease operating expenses were $13.7 million for the nine-month period ended September 30, 2008, a 33% decrease when compared to the same period in 2007. The decrease was primarily due to the sale of the Mobile Bay Field on blocks 952, 953 and 955 effective May 1, 2007, a lower number of producing wells and downtime in the third quarter of 2008 caused by Hurricanes Gustav and Ike resulting in lower throughput charges. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair.

Depreciation, depletion and amortization for the nine-month period ended September 30, 2008 and 2007 was $41.8 million and $56.6 million, respectively. The 26% decrease was primarily due to lower production volumes which was slightly offset by a higher depletion rate.

Accretion expense for the nine-month periods ended September 30, 2008 and 2007 of $3.1 and $3.0 million, respectively, represents accretion of our asset retirement obligations. See Note 6 to the Consolidated Financial Statements.

General and administrative expenses, net of amounts capitalized, were $7.0 million and $7.1 million for the nine-month periods ended September 30, 2008 and 2007, respectively. Increased staffing cost was offset by overhead fees received as operator of the Entrada Field, which were recorded as a reduction to general and administrative expense.

Interest expense decreased to $19.7 million during the nine-month period ended September 30, 2008, compared to $23.9 million during the nine-month period ended September 30, 2007. This decrease was due to retirement of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 4 for more details.

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 tax expense was $9.7 million and $6.3 million for the nine-month periods ended September 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 September 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 September 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 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, 2007, other than the following:

Oil and gas prices have recently declined substantially. If there is a sustained economic downturn or recession in the United States or globally, oil and natural gas prices may continue to fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

Many economists are predicting that the United States will experience an economic downturn or a recession. The reduced economic activity associated with an economic downturn or recession may reduce the demand for, and so the prices we receive for, our oil and natural gas production. A sustained reduction in the prices we receive for our oil and natural gas production will have a material adverse effect on our results of operations. For example, for the quarter ending September 30, 2008, a 10% reduction in the price we received for oil would have reduced our revenues by approximately $2.0 million and a 10% reduction in the price of natural gas would have reduced our revenues by approximately $1.2 million.

We are experiencing unprecedented disruption in the U.S. and international financial markets. The current disruption in the financial markets has made it unlikely that we could successfully issue common stock or debt securities to fund our growth in the near future. In addition, the current market for bank credit facilities is unfavorable to borrowers. If the disruption in the financial markets continues for a substantial period of time, our ability to fund growth will be adversely affected.

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

Second Amended and Restated Credit Agreement dated as of September 25, 2008, by and among Callon Petroleum Company, the “Lenders” described therein, Regions Bank, as Syndication Agent, Capital One, N.A., as Documentation Agent, and Union Bank of California, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on October 1, 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)
	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

Second Amended and Restated Credit Agreement dated as of September 25, 2008, by and among Callon Petroleum Company, the “Lenders” described therein, Regions Bank, as Syndication Agent, Capital One, N.A., as Documentation Agent, and Union Bank of California, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on October 1, 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