UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

þ		Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

o		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number 001-14039

CALLON PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		64-0844345 (I.R.S. Employer Identification No.)
200 North Canal Street Natchez, Mississippi (Address of principal executive offices)		39120 (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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o     No o

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

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		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 Rule 12b-2 of the Exchange Act).

Yes o     No þ

As of May 5, 2010 there were outstanding 28,762,343 shares of the Registrant’s common stock, par value $0.01 per share.

 

 

Table of Contents

Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets (Unaudited)			3
Consolidated Statements of Operations (Unaudited)			4
Consolidated Statements of Cash Flows (Unaudited)			5
Notes to Consolidated Financial Statements (Unaudited)			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			16
Item 3. Quantitative and Qualitative Disclosures about Market Risk			24
Item 4. Controls and Procedures			24
Part II. Other Information
Item 1. Legal Proceedings			25
Item 1A. Risk Factors			25
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			26
Item 3. Defaults Upon Senior Securities			26
Item 4. Removed and Reserved			26
Item 5. Other Information			26
Item 6. Exhibits			27
EX-31.1
EX-31.2
EX-32

Part 1. Financial Information

Item 1. Financial Statements

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

		March 31, 2010				December 31, 2009
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	42,229			$	3,635
Accounts receivable			15,087				20,798
Accounts receivable — MMS royalty recoupment (See Note 3)			7,927				51,534
Fair market value of derivatives			637				145
Other current assets			987				1,572
Total current assets			66,867				77,684
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,234,825				1,593,884
Less accumulated depreciation, depletion and amortization			(1,130,942	)			(1,488,718	)
Net oil and gas properties			103,883				105,166
Unevaluated properties excluded from amortization			27,714				25,442
Total oil and gas properties			131,597				130,608
Other property and equipment, net			2,528				2,508
Restricted investments			4,327				4,065
Investment in Medusa Spar LLC			11,180				11,537
Other assets, net			1,819				1,589
Total assets		$	218,318			$	227,991
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities		$	8,575			$	12,887
Asset retirement obligations			3,613				4,002
9.75% Senior Notes, net of $174 and $232 discount, respectively			15,878				15,820
Fair market value of derivatives			302				—
			28,368				32,709
Callon Entrada non-recourse credit facility (See Note 2)			—				84,847
Total current liabilities			28,368				117,556
13% Senior Notes (See Note 6)
Principal outstanding			137,961				137,961
Deferred credit, net of accumulated amortization of $1,183 and $294, respectively			30,324				31,213
Total 13% Senior Notes			168,285				169,174
Senior secured revolving credit facility			—				10,000
Asset retirement obligations			10,425				10,648
Other long-term liabilities			1,908				1,467
Total liabilities			208,986				308,845
Stockholders’ equity (deficit):
Preferred Stock, $.01 par value, 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value, 60,000,000 shares authorized; 28,776,331 and 28,742,926 shares outstanding at March 31, 2010 and December 31, 2009, respectively			288				287
Capital in excess of par value			244,818				243,898
Other comprehensive loss			(7,288	)			(7,478	)
Retained (deficit) earnings			(228,486	)			(317,561	)
Total stockholders’ equity (deficit)			9,332				(80,854	)
Total liabilities and stockholders’ equity (deficit)		$	218,318			$	227,991

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

Callon Petroleum Company
Consolidated Statements of Operations (Unaudited)
(in thousands, except per share data)

		Three Months Ended March 31,
		2010				2009
Operating revenues:
Oil sales		$	16,663			$	15,952
Gas sales			6,722				8,863
Total operating revenues			23,385				24,815
Operating expenses:
Lease operating expenses			4,648				4,039
Depreciation, depletion and amortization			6,813				9,413
General and administrative			4,304				1,819
Accretion expense			580				1,038
Total operating expenses			16,345				16,309
Income from operations			7,040				8,506
Other (income) expenses:
Interest expense			3,594				4,782
Callon Entrada non-recourse credit facility interest expense (See Note 2)			—				1,556
Other income			(361	)			(95	)
Total other (income) expenses			3,233				6,243
Income before income taxes			3,807				2,263
Income tax benefit			—				(24	)
Income before equity in earnings of Medusa Spar LLC			3,807				2,287
Equity in earnings of Medusa Spar LLC			116				117
Net income available to common shares		$	3,923			$	2,404
Net income per common share:
Basic		$	0.14			$	0.11
Diluted		$	0.13			$	0.11
Shares used in computing net income per common share:
Basic			28,738				21,607
Diluted			29,229				21,607

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

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

		Three Months Ended March 31,
		2010				2009
Cash flows from operating activities:
Net income		$	3,923			$	2,404
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization			6,989				9,629
Accretion expense			580				1,038
Amortization of non-cash debt related items			137				731
Amortization of deferred credit			(889	)			—
Equity in earnings of Medusa Spar LLC			(116	)			(117	)
Deferred income tax expense			—				(24	)
Non-cash charge related to compensation plans			643				569
Changes in current assets and liabilities:
Accounts receivable			47,081				5,761
Other current assets			585				912
Current liabilities			(2,850	)			(19,614	)
Change in gas balancing receivable			(44	)			319
Change in gas balancing payable			87				30
Change in other long-term liabilities			(115	)			618
Change in other assets, net			(343	)			(10	)
Cash provided by operating activities			55,668				2,246
Cash flows from investing activities:
Capital expenditures			(6,974	)			(19,295	)
MMS bond for plugging and abandonment			(262	)			—
Distribution from Medusa Spar LLC			473				574
Cash used in investing activities			(6,763	)			(18,721	)
Cash flows from financing activities:
Payments on senior secured credit facility			(10,000	)			—
Cash used in financing activities			(10,000	)			—
Net change in cash and cash equivalents			38,905				(16,475	)
Cash and cash equivalents:
Balance, beginning of period			3,635				17,126
Less: Cash held by subsidiary deconsolidated at January 1, 2010			(311	)			—
Balance, end of period		$	42,229			$	651

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

Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.		Description of Business and Basis of Presentation
2.		Deconsolidation of Callon Entrada
3.		Minerals Management Service Royalty Recoupment
4.		Earnings per Share
5.		Comprehensive Income (Loss)
6.		Borrowings
7.		Derivative Instruments and Hedging Activities
8.		Fair Value Measurements
9.		Income Taxes
10.		Asset Retirement Obligations

Note 1 — Description of Business and Basis of Presentation

Description of Business

     Callon Petroleum Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

     Callon is engaged in the acquisition, development, exploration and operation of oil and gas properties. The Company’s properties and operations are geographically concentrated onshore in Louisiana and Texas and the offshore waters of the Gulf of Mexico.

Basis of Presentation

     These interim financial statements of the Company have been prepared in accordance with (1) accounting principles generally accepted in the United States, (2) the Security and Exchange Commission’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

     In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments (including normal recurring adjustments) necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2010.

     All amounts contained in the notes to the consolidated financial statements are presented in thousands, with the exception of years, per-share, per-note and per-hedge amounts. Certain reclassifications have been made to conform prior year financial information to the current period presentation.

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

Note 2 — Deconsolidation of Callon Entrada

     In April 2008, Callon completed the sale of a 50% working interest in the Entrada Field to CIECO Energy (US) Limited (“CIECO”) effective January 1, 2008. At closing, CIECO paid Callon $155,000, and reimbursed the Company $12,600 for 50% of Entrada capital expenditures incurred prior to the closing date. In addition, as part of the purchase and sale agreement, CIECO agreed to loan Callon Entrada, a wholly owned subsidiary of the Company, up to $150,000 plus interest expense incurred up to $12,000, for its share of the development costs for the Entrada project. Based on the terms of the credit agreement with CIECO Energy (Entrada) LLC (“CIECO Entrada”), the debt was to be repaid solely from assets, primarily production, from the Entrada field. All assets of Callon Entrada, and its stock, are pledged to CIECO Entrada under the Callon Entrada credit agreement, and neither Callon nor its subsidiaries (other than Callon Entrada) guaranteed the Callon Entrada credit facility.

     Prior to January 1, 2010, the Company was required to consolidate the financial statements and results of operations of Callon Entrada, and as such, Callon Entrada’s non-recourse credit facility was reflected in a separate line item in Callon’s 2009 consolidated financial statements.

     In June 2009, the FASB issued an accounting standard which became effective for the first annual reporting period that begins after November 15, 2009 (with early adoption prohibited), and which amended US GAAP as follows:

	•		to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a Variable Interest Entity (“VIE”), identifying the primary beneficiary of a VIE;
	•		to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur;
	•		to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE;
	•		to amend certain guidance for determining whether an entity is a VIE;
	•		to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur;
	•		to eliminate the exception for troubled debt restructuring regarding VIE reconsideration; and
	•		to require advanced disclosures that will provide users of financial statements with more transparent information about an enterprise’s involvement in a VIE.

     The Company adopted the pronouncement for consolidation of variable interest entities on January 1, 2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, which is detailed below, the Company concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary and as a result, Callon Entrada is deconsolidated from the Company’s consolidated financial statements as of January 1, 2010. The Company included additional disclosures related to the deconsolidation of Callon Entrada in its Form 10-K for the year-ended December 31, 2009. Key events considered in this analysis include the following:

     Default on non-recourse debt and CIECO’s acceleration rights exercised: As a result of abandoning the Entrada project in November 2008, prior to completion, Callon Entrada’s only source of payment is the proceeds from the sale of equipment purchased but not used for the Entrada project. On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain alleged events of default occurred under the credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. The notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon Entrada credit agreement to accelerate payment of the principal and interest due, and to invoke its rights to the surplus equipment related to the Entrada project, including the proceeds from the sale of the equipment and the ability to control the decisions related to the sale of the equipment. Based on the advice of legal counsel, Callon believes that it and its other subsidiaries are not otherwise obligated to repay the principal, accrued interest or any other amount which may become due under the Callon Entrada credit facility.

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

Abandonment obligations satisfied: Callon guaranteed Callon Entrada’s payment of all amounts to plug and abandon the wells and related facilities and for a breach of law, rule or regulation (including environmental laws) and for any losses of CIECO Entrada attributable to gross negligence of Callon Entrada. The well for which Callon Entrada was responsible was plugged and abandoned in the fourth of quarter of 2008, and the Minerals Management Service (“MMS”) confirmed to Callon during September 2009 that Callon had satisfied all if its abandonment obligations related to this project.

     No ability to control future actions of Callon Entrada: As of December 31, 2009, the wind down of the Entrada project was complete, all of the costs related to the Entrada project were paid, and subsequent to the lease expiration June 1, 2009, control of the property reverted to the MMS. The sale of remaining equipment purchased for the Entrada project remains ongoing, and the Company believes that the amount of future operating costs of Callon Entrada, for which the Company would be responsible for, is insignificant and is limited to minimal storage fees for the surplus equipment while the equipment is being liquidated.

     As a result of the events described above, the Company lost its power to direct the only remaining activities that affect Callon Entrada’s future economic performance. Below is a condensed balance sheet of Callon presented to demonstrate the effect of deconsolidation on the financial statements at January 1, 2010:

		Callon				Callon				Callon
		Consolidated				Entrada				Consolidated
		at 12/31/09				Deconsolidated				at 1/1/2010
Balance Sheet (in thousands)
Total current assets		$	77,684			$	(1,767	)		$	75,917
Total oil and gas properties			130,608				—				130,608
Other property and equipment			2,508				—				2,508
Other assets			17,191				—				17,191
Total assets		$	227,991			$	(1,767	)		$	226,224
Other current liabilities		$	16,889			$	(2,015	)		$	14,874
9.75% Senior Notes, due December 2010			15,820				—				15,820
Callon Entrada non-recourse credit facility			84,847				(84,847	)			—
Total current liabilities			117,556				(86,862	)			30,694
Total long-term debt			179,174				—				179,174
Total other long-term liabilities			12,115				—				12,115
Total stockholders’ equity (deficit)			(80,854	)			85,095				4,241
Total liabilities and stockholders’ equity (deficit)		$	227,991			$	(1,767	)		$	226,224

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

Note 3 — Minerals Management Service (“MMS”) Royalty Recoupment

     In November 2009 the Company filed for a recoupment of royalties paid in the amount of $44,787 from inception-to-date production at the Company’s Medusa field. As of December 31, 2009, Callon accrued the royalty recoupment of $44,787 and estimated interest of $7,681. The Company received the recoupment of principal in January 2010, and expects to receive during the second quarter of 2010 interest of $7,927, which includes additional accrued interest for the three-months ended March 31, 2010.

Note 4 — Earnings per Share

     The following table sets forth the computation of basic and diluted earnings per share:

		Three Months Ended March 31,
		2010				2009
(a) Net income		$	3,923			$	2,404
(b) Weighted average shares outstanding			28,738				21,607
Dilutive impact of stock options			37				—
Dilutive impact of restricted stock			454				—
(c) Weighted average shares outstanding for diluted net income per share			29,229				21,607
Basic net income per share (a¸b)		$	0.14			$	0.11
Diluted net income per share (a¸c)		$	0.13			$	0.11

     The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive:

Stock options			266				503
Warrants			365				365
Restricted stock			277				509

Note 5 — Comprehensive Income (Loss)

     The components of comprehensive income (loss), net of related taxes, are as follows:

		Three Months Ended March 31,
		2010				2009
Net income		$	3,923			$	2,404
Other comprehensive loss:
Change in fair value of derivatives			190				(6,923	)
Total comprehensive income (loss)		$	4,113			$	(4,519	)

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

Note 6 — Borrowings

The Company’s borrowings consisted of the following at:

		March 31, 2010				December 31, 2009
Principal components:
Senior secured revolving credit facility		$	—			$	10,000
9.75% Senior Notes due 2010, principal (1)			16,052				16,052
13% Senior Notes due 2016, principal			137,961				137,961
Callon Entrada non-recourse credit facility (2)			—				84,847
Total principal outstanding			154,013				248,860
Non-cash components:
9.75% Senior Notes, due 2010 unamortized discount			(174	)			(232	)
13% Senior Notes due 2016 unamortized deferred credit			30,324				31,213
Total carrying value		$	184,163			$	279,841

Senior Secured Revolving Credit Facility (the “Credit Facility”)

     In January 2010, the Company amended its Credit Facility agreement to include Regions Bank as the sole arranger and administrative agent. The third amended and restated Credit Facility agreement, which matures on September 25, 2012, provides for a $100,000 facility with an initial borrowing base of $20,000, which will be reviewed and re-determined on a semi-annual basis during the second and fourth quarters. The third amended and restated Credit Facility bears interest at 4% above a defined base rate and in no event will the interest rate be less than 6%. As of March 31, 2010, the interest rate on the facility was 6%. In addition, a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly.

     Simultaneously with the execution of the third amended and restated Credit Facility agreement, the Company repaid the $10,000 outstanding draw under the second amended and restated senior secured credit agreement, which was outstanding as of December 31, 2009.

9.75% Senior Notes (“Old Notes”) (Due December 2010)

     During the fourth quarter of 2009, Callon commenced an exchange offer for any and all of its outstanding Old Notes. Holders of approximately 92% of the Old Notes tendered their Old Notes in the exchange offer. The principal amount of the remaining Old Notes was $16,052 at March 31, 2010 and is due in 2010. The Company recorded an unamortized discount of $174 and $232 at March 31, 2010 and December 31, 2009, respectively. During March 2010, the Company announced its intension to redeem all remaining Old Notes by April 30, 2010 (the “Redemption Date”) at a redemption price of 101% of their principal amount, plus accrued and unpaid interest to the Redemption Date. Pursuant to the terms of the debt agreement, the Company mailed a notice of redemption to all registered holders of the Notes, and has posted the notice with the responsible transfer agent.

Subsequent event

     On April 30, 2010, the Company completed its publically announced plans to redeem the $16,052 remaining outstanding Old Notes for $16,343, which included the 1% call premium and $130 of accrued interest through the repurchase date. The Company also recognized $179 of additional interest expense related to the accelerated amortization of the remaining discount and debt issuance costs related to the Old Notes. As of April 30, 2010, no Old Notes remain outstanding.

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit

     As described above, during the fourth quarter of 2009, the Company exchanged approximately 92% of the principal amount, or $183,948, of the Old Notes for $137,961 of Senior Notes. The exchange resulted in a 25% reduction in the principal amount of the Old Notes tendered, and included a 3.25% increase in the coupon rate from 9.75% to 13%. In addition, holders of the tendered notes received 3,794 shares of common stock and 311 shares of Convertible Preferred Stock which was valued on November 24, 2009 in the amount of $11,527, and recorded as an increase to stockholders’ equity. On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock following shareholder approval and the filing of an amendment to the Company’s charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion. The Senior Notes’ 13% interest coupon is payable on the last day of each quarter.

     Upon issuing the Senior Notes during December 2009, the Company reduced the carrying amount of the Old Notes by the fair value of the common and preferred stock issued in the amount of $11,527. The difference between the adjusted carrying amount of the Old Notes and the face value of the Senior Notes was recorded as a deferred credit, which is being amortized as a credit to interest expense over the life of the Senior Notes at an 8.5% effective interest rate. The following table summarizes the Company’s deferred credit balance at March 31, 2010:

						Amortization		Estimated
						Recorded during		Amortization
		Accumulated				2010 as a		Expected to be
Gross Carrying		Amortization at		Carrying Value at		Reduction of		Recorded for the
Amount		March 31, 2010		March 31, 2010		Interest Expense		Remainder of 2010
$31,507		$1,183		$30,324		$889		$2,706

     Certain of the Company’s subsidiaries guarantee the Company’s obligations under the Senior Notes. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantors are minor.

Restrictive Covenants

     The Indenture governing our Senior Notes and the Company’s senior secured credit facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s senior secured credit facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at March 31, 2010.

Note 7 — Derivative Instruments and Hedging Activities

Objectives and Strategies for Using Derivative Instruments

     The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company utilizes primarily collars and swap derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for trading purposes.

Counterparty Risk

     The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the Company’s risk in this area, counterparties to the Company’s commodity derivative instruments include a large, well-known financial institution and a large, well-known oil and gas company. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices.

     The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a transfer or terminate the arrangement.

Settlements and Financial Statement Presentation

     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. The derivative contracts are carried at fair value in the 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.”

     The Company’s derivative contracts that are designated as cash flow hedges, and are recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity (deficit). The cash settlements on contracts for future production are recorded as an increase or decrease in oil and gas sales. Both changes in fair value and cash settlements of ineffective derivative contracts are recognized as derivative expense (income).

     Listed in the table below are the outstanding oil and gas derivative contracts, consisting entirely of collars, as of March 31, 2010:

Average

Average

Floor Price

Ceiling Price

Product

Volumes per Month

Quantity Type

per Hedge

per Hedge

Period

Natural Gas

75

MMbtu

$

5.00

$

8.30

Apr 10 - Dec 10

Oil

20

Bbls

$

70.00

$

91.50

Apr 10 - Dec 10

     The tables below present the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to oil and gas sales:

		For the Three-Months
		ended March 31,
		2010				2009
Amount of gain reclassified from OCI into income (effective portion)			17				7,858
Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing)			—				—

Subsequent event

During April 2010, the Company executed additional oil hedge collars as follows:

						Average		Average
						Floor Price		Ceiling Price
Product		Volumes per Month		Quantity Type		per Hedge		per Hedge		Period
Oil		10		Bbls		$75.00		$101.50		May 10 - Dec 10
Oil		10		Bbls		$75.00		$101.85		Jan 11 - Dec 11
Oil		5		Bbls		$80.00		$102.00		Jan 11 - Dec 11

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

Note 8 — Fair Value Measurements

     The fair value hierarchy outlined in the relevant accounting guidance gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

     Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

     Commodity Derivative Instruments. Callon’s derivative policy allows for commodity derivative instruments to consist of collars and natural gas basis swaps, though at March 31, 2010 the Company’s portfolio included only collars. The fair values of the Company’s derivative instruments are not actively quoted in the open market and are valued using forward commodity price curves. Consequently, the Company estimates the fair values of derivative instruments using internal discounted cash flow calculations based upon forward commodity price curves, and is corroborated by quotes obtained from counterparties to the agreements. These valuations include primarily Level 3 inputs. For additional information, see Note 7, Derivative Instruments and Hedging Activities, of this Form 10-Q.

     The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:

As of March 31, 2010		Level 1				Level 2				Level 3				Total
Assets
Derivative financial instruments		$	—			$	—			$	637			$	637
Liabilities
Derivative financial instruments		$	—			$	—			$	302			$	302
Total		$	—			$	—			$	335			$	335

As of December 31, 2009		Level 1				Level 2				Level 3				Total
Assets
Derivative financial instruments		$	—			$	—			$	145			$	145
Liabilities
Derivative financial instruments		$	—			$	—			$	—			$	—
Total		$	—			$	—			$	145			$	145

     The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 7, Derivative Instruments and Hedging Activities, of this Form 10-Q for a discussion of net amounts recorded on the Consolidated Balance Sheet at March 31, 2010.

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

The following table presents the Company’s assets and liabilities measured at fair value on a recurring basis using significant, unobserved inputs (Level 3):

		Derivatives
Balance at January 1, 2010		$	145
Total gains or losses (realized or unrealized):
Included in earnings			17
Included in other comprehensive (income) loss			190
Purchases, issuances and settlements			(17	)
Balance at March 31, 2010		$	335
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of March 31, 2010		$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

     Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

     Cash, Cash Equivalents, Short-Term Investments, Accounts Receivable and Accounts Payable. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.

     Asset Retirement Obligations Incurred in Current Period. Callon estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as (1) the existence of a legal obligation for an ARO, (2) amounts and timing of settlements, (3) the credit-adjusted risk-free rate to be used and (4) inflation rates. AROs incurred in the current period were Level 3 fair value measurements. See Note 10, Asset Retirement Obligations, of this Form 10-Q, which provides a summary of changes in the ARO liability.

     Debt. The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet. The fair value of Callon’s fixed-rate debt is based upon estimates provided by an independent investment banking firm, which is a Level 2 fair value measurement. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The following table summarizes the respective fair values at:

		March 31, 2010								December 31, 2009
		Carrying								Carrying
		Value				Fair Value				Value				Fair Value
Senior secured revolving credit facility		$	—			$	—			$	10,000			$	10,000
9.75% Senior Notes due 2010, net of unamortized discount			15,878				15,771				15,820				15,249
13% Senior Notes due 2016			168,285				117,267				169,174				103,471
Callon Entrada credit facility; non-recourse			—				—				84,847				—
Total		$	184,163			$	133,038			$	279,841			$	128,720

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share, per-note and per-hedge data)

Note 9 — Income Taxes

     The following table presents Callon’s net unrecognized tax benefits relating to its reported net losses and other temporary differences from operations :

		March 31, 2010				December 31, 2009
Deferred tax asset:
Federal net operating loss carryforwards		$	94,432			$	94,125
Statutory depletion carryforwards			4,905				4,895
Alternative minimum tax credit carryforward			383				383
Asset retirement obligations			3,399				3,704
Other			4,240				34,170
Deferred tax asset before valuation allowance			107,359				137,277
Less: Valuation allowance			(85,224	)			(116,676	)
Total deferred tax asset			22,135				20,601
Deferred tax liability:
Oil and gas properties			11,117				9,555
Other			11,018				11,046
Total deferred tax liability			22,135				20,601
Net deferred tax asset		$	—			$	—

     As of January 1, 2010 and as previously disclosed in Note 2, Callon Entrada has been deconsolidated from the Company’s consolidated financial statements, resulting in a $30,330 decrease in deferred tax assets and a corresponding reduction in the valuation allowance.

     As previously disclosed in Note 6 of the Company’s 2009 Form 10-K, the Company recorded a full valuation allowance against its net deferred tax assets. Consequently, the Company’s effective tax rate will be affected in future periods to the extent these deferred tax assets are recognized. The Company continues to assess whether or not deferred tax assets can be recognized based on current and expected future operating results and other factors.

Note 10 — Asset Retirement Obligations

The following table summarizes the Company’s asset retirement obligations activity for the three-months ended March 31, 2010:

Asset retirement obligations at beginning of period		$	14,650
Accretion expense			580
Liabilities incurred			—
Liabilities settled			(1	)
Revisions to estimate			(1,191	)
Asset retirement obligations at end of period			14,038
Less: current asset retirement obligations			(3,613	)
Long-term asset retirement obligations		$	10,425

     Liabilities settled primarily relate to individual properties plugged and abandoned during the period. Most of the activity related to Gulf of Mexico properties.

     Restricted assets to be used to pay plugging and abandonment costs, primarily U.S. Government securities, of approximately $4,327 at March 31, 2010, 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.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Certain statements in this Current Report on Form 10-Q (or otherwise made by or on the behalf of Callon Petroleum) contain various forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the Private Securities Litigation Reform Act of 1995. Such statements represent management’s beliefs and assumptions concerning future events. When used in this document and in documents incorporated by reference, forward-looking statements include, without limitation, statements regarding financial forecasts or projections, our expectations, beliefs, intentions or future strategies that are signified by the words “expects,” “anticipates,” “intends,” “believes” or similar language. These forward-looking statements are subject to risks, uncertainties and assumptions that could cause our actual results and the timing of certain events to differ materially from those expressed in the forward-looking statements. All forward-looking statements included in this Report are based on information available to us on the date of this Report. It is routine for our internal projections and expectations to change as the year or each quarter in the year progress, and therefore it should be clearly understood that the internal projections, beliefs and assumptions upon which we base our expectations may change prior to the end of each quarter or the year. Although these expectations may change, we may not inform you if they do. Our policy is generally to provide our expectations only once per quarter, and not to update that information until the next quarter.

Many important factors, in addition to those discussed in this Report, could cause our results to differ materially from those expressed in the forward-looking statements. Some of the potential factors that could affect our results are described below within Management’s Discussion and Analysis of Financial Condition and Results of Operations. In light of these risks and uncertainties, and others not described in this Report, the forward-looking events discussed in this Report might not occur, might occur at a different time, or might cause effects of a different magnitude or direction than presently anticipated.

General

          The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009 (“Annual Report”), which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results.

          Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-Q.

          We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico. During 2009, we took steps to change our operational focus to lower risk, onshore exploration and development activities.

Overview and Outlook

          Building on our transition in 2009, during the first quarter of 2010, we continue to show improving quarter-over-quarter results of operations with net income and fully diluted earnings per share of $3.9 million and $0.13, respectively, compared to $2.4 million and $0.11, respectively for the same three-month period of 2009.

          In an effort to position ourselves for future growth, we continue to focus on strengthening our balance sheet by improving our liquidity. We made significant progress during the first quarter of 2010:

	•		We received $44.8 million in January 2010 for recoupment of deepwater royalty payments to the MMS. We expect to receive an additional payment from the MMS related to accrued interest of approximately $7.9 million during the second quarter of 2010.
	•		We successfully completed a $100 million amended revolving credit facility, with a borrowing base of $20 million.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

•

After successfully restructuring our 9.75% Senior Notes due December 2010 (the “Old Notes”) during the fourth quarter of 2009, we completed on April 30, 2010 the repayment of the remaining $16.1 million outstanding Old Notes. The restructuring reduced by 25% the principal balance and extend the notes’ maturity from 2010 to 2016 in exchange for a 3.25% increase in the coupon rate and for additional equity consideration.

          Our success in these areas allows us to shift our operational focus from the offshore Gulf of Mexico to developing longer life, lower risk onshore properties. Our new onshore properties along with the strong cash flow from our Gulf of Mexico operations have already begun to re-shape our portfolio and outlook, and we are well positioned to continue the pursuit of diversifying our portfolio by building profitable growth opportunities onshore. During 2010, we began to develop the properties we acquired during late 2009:

	•		During the fourth quarter of 2009, we acquired interests in properties producing from the Wolfberry formation in Crockett, Ector, Midland and Upton Counties, Texas. The acquisition included year-end proven reserves of 1.6 MMBoe, 22 existing wells producing 350 Boe per day and upside from a multi-year inventory of drilling opportunities. During 2010, we plan to accelerate the development of this asset by drilling 23 to 26 wells, which when completed, are expected to significantly increase our current Permian Basin production from 350 Boe per day to 1,000 Boe per day. We now operate substantially all of the production and development of these properties.
	•		Also during the fourth quarter of 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana. We plan to drill a total of seven horizontal wells, which we will operate, on this property, with the first well to be drilled during 2010. We expect to spud the first well by mid-year, and have it completed and producing in the fourth quarter of 2010.

     Also highlighting the continued successful execution of our long-term strategy, on April 23, 2010 the New York Stock Exchange (“NYSE”) removed Callon from its “Watch List” and affirmed that we are now considered a “company back in compliance” with the NYSE’s quantitative continued listing standards.

     In our effort to continue to conduct safe operations, and in an effort to evaluate any potential affect on our planned production, we continue to monitor the status of the recent oil spill that occurred off the Louisiana coast. Based on the information currently available, we see neither an immediate safety concern for those operating on our offshore facilities, nor a threat to our planned production levels.

Deconsolidation of Callon Entrada

          As more fully discussed in Note 2, Deconsolidation of Callon Entrada, included in Item I, Part I of this filing, in June 2009, the FASB issued an accounting standard which became effective for the first annual reporting period that begins after November 15, 2009 (with early adoption prohibited), and which amended US GAAP in several ways, which are disclosed in Note 2 included in Part I, Item 1 of this filing. We adopted this pronouncement on January 1, 2010.

          Upon adoption and as a result of the amendments described above, we reevaluated our interest in Callon Entrada, and based on the evaluation performed, we concluded that a VIE reconsideration event had taken place. Our reconsideration analysis resulted in the determination that Callon Entrada is a VIE for which we are not the primary beneficiary. Consequently, effective January 1, 2010, Callon Entrada was deconsolidated from our consolidated financial statements.

          The deconsolidation of Callon Entrada resulted in the removal of approximately $1.8 million of current assets, $2.0 million of current liabilities, $30 million of deferred tax assets, $30 million of valuation allowance and approximately $84.8 million of non-recourse debt and the related obligation for the cumulative amount of interest. Retained earnings increased by $85.1 million as a cumulative effect of change related to this accounting standard. No gain was recognized in the statement of operations. See Note 2 of Part I, Item I — Consolidated Financial Statements.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources

          Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Net cash and cash equivalents increased by $38.6 million during the three months-ended March 31, 2010 to $42.2 million compared to $3.6 million at December 31, 2009. Cash provided from operating activities in the first quarter of 2010 totaled $55.6 million, an increase of $53.4 million compared to the same quarter of 2009. The increase in liquidity is primarily attributable to receipt of the $44.8 million MMS royalty recoupment.

          During 2009, we recorded a receivable attributable to a recoupment of royalty payments we previously made on our deep water property, Medusa. Following the decisions resulting from several court cases, it was determined that the MMS was not entitled to receive these royalty payments, and accordingly refunded the payments previously made. We received the principal payment of $44.8 million in January 2010, and expect to receive a payment of approximately $7.9 million during the second quarter of 2010 representing interest on the amounts previously withheld.

          In January 2010, we amended our Senior Secured Credit Agreement to include Regions Bank as the sole arranger and administrative agent. The third amended and restated senior secured credit agreement, which matures on September 25, 2012, provides for a $100 million facility with an initial borrowing base of $20 million, which will be reviewed and re-determined on a semi-annual basis. The third amended and restated credit facility bears interest at 4% above a defined base rate and in no event will the interest rate be less than 6%. As of March 31, 2010, the interest rate on the facility was 6%. In addition, a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly. Simultaneously with the execution of the third amended and restated senior secured credit agreement, we repaid the $10 million outstanding on the borrowing base under the second amended and restated senior secured credit agreement, which was outstanding as of December 31, 2009. No amounts were outstanding under the amended facility as of March 31, 2010.

          During the fourth quarter of 2009, we completed an exchange offer for our outstanding 9.75% Senior Notes due December 2010 (“Old Notes”). Holders of approximately 92% of the 9.75% Old Notes tendered their notes in the exchange offer, and received in their place the 13% Senior Notes (“Senior Notes”). The exchange offer included a 25% decrease in the principal amount exchanged, increased the coupon rate to 13% and included equity consideration. In addition, holders who tendered Old Notes consented to amend the indenture governing the Old Notes, eliminating substantially all of the indenture’s restrictive covenants.

          At March 31, 2010, $137.9 million and $16.1 million of the Senior Notes and Old Notes, respectively, remain outstanding. In addition and as previously discussed, on April 30, 2010, we used a portion of the proceeds received from the MMS recoupment to retire the remaining Old Notes for 101% of par and pay accrued interest. The 13% interest on the Senior Notes is payable quarterly.

          2010 Budget and Capital Expenditures. For 2010, we designed a flexible capital spending program that can be funded from cash on hand and cashflows from operations. Our preliminary base capital program includes an accelerated development program of our Permian Basin crude oil assets as well as exploiting our Haynesville Shale gas play.

          Including plugging and abandonment, capitalized interest and general and administrative costs our 2010 capital budget approximates $63 million.

          In addition, should we identify an attractive strategic opportunity or acquisition, we have a $20 million borrowing base available under our credit facility. However, depending on commodity prices and other economic conditions that develop during the current year, this base capital program may be adjusted upward or downward.

          Planned capital expenditures for 2010 include, in addition to other less significant items, drilling and completing up to 26 wells in the Permian Basin and drilling one well in the Haynesville Shale gas play.

          We believe that our cash on hand and operating cash flow along with our credit facility, if needed, will be adequate to meet our capital, debt repayment, and operating requirements for 2010. We fund our day-to-day

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

operating expenses and capital expenditures from operating cash flow, supplemented as needed by borrowings under our credit facility.

Summary cash flow information is provided as follows:

Operating Activities. During the three-months ended March 31, 2010, net cash provided by operating activities was $55.7 million, a $53.4 million increase from $2.3 million for the same period in 2009. The increase in net cash provided by operating activities was primarily attributable to receipt of the $44.8 million MMS royalty recoupment and higher commodity prices on an equivalent basis.

Investing Activities. During the three-months ended March 31, 2010, net cash used in investing activities was $6.8 million as compared to $18.7 million for the same period in 2009. The $11.9 million decrease in net cash used in investing activities, primarily attributable to a $12.3 million decrease in capital expenditures, relates to wind-down costs paid in 2009 for the Callon Entrada project offset by 2010 capital expenditures related to drilling new wells in the Permian Basin.

Financing Activities. During the three-months ended March 31, 2010, net cash used in financing activities was $10.0 million compared to $0 for the same period in 2009. The 2010 expenditure related to the repayment of all outstanding borrowings under the senior secured revolving credit agreement prior to its being amended to include Regions Bank as the sole arranger and administrative agent.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 March 31,
		2010				2009				Change				% Change
Net production (a):
Oil (MBbls)			223				263				(40	)			-15	%
Gas (MMcf)			1,166				1,447				(281	)			-19	%
Total production (MMcfe)			2,505				3,026				(521	)			-17	%
Average daily production (MMcfe)			27.8				33.6				(5.8	)			-17	%
Average sales price:
Oil (Bbls) (b)		$	74.78			$	60.59			$	14.19				23	%
Gas (Mcf)			5.76				6.13				(0.37	)			-6	%
Total (Mcfe)			9.34				8.20				1.14				14	%
Oil and gas revenues (a):
Oil revenue		$	16,663			$	15,952			$	711				4	%
Gas revenue			6,722				8,863				(2,141	)			-24	%
Total		$	23,385			$	24,815			$	(1,430	)			-6	%
Additional per Mcfe data:
Sales price		$	9.34			$	8.20			$	1.14				14	%
Lease operating expense			(1.86	)			(1.33	)			(0.53	)			40	%
Operating margin		$	7.48			$	6.87			$	0.61				9	%
Other expenses (a):
Depletion, depreciation and amortization		$	2.72			$	3.11			$	(0.39	)			-13	%
General and administrative (net of management fees)			1.72				0.60				1.12				186	%
(a) Amounts are in thousands
(b) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
Average NYMEX oil price (b)		$	78.72			$	43.08			$	35.64				83	%
Basis differential and quality adjustments			(2.75	)			(4.01	)			1.26				-31	%
Transportation			(1.19	)			(1.35	)			0.16				-12	%
Hedging			—				22.87				(22.87	)			-100	%
Average realized oil price		$	74.78			$	60.59			$	14.19				23	%

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Comparison of Results of Operations for the Three Months Ended March 30, 2010 and 2009.

Revenues

		Crude Oil				Natural Gas				Total
Revenues for the quarter ended March 31, 2008		$	25,096			$	19,864			$	44,960
Volume increase (decrease)			(2,286	)			(6,123	)			(8,409	)
Price increase (decrease)			(12,880	)			(6,713	)			(19,593	)
Impact of hedges increase			6,023				1,835				7,858
Net increase (decrease) in 2009			(9,144	)			(11,001	)			(20,145	)
Revenues for the quarter ended March 31, 2009		$	15,952			$	8,863			$	24,815
Volume increase (decrease)			(2,449	)			(1,717	)			(4,166	)
Price increase (decrease)			3,160				(441	)			2,719
Impact of hedges			—				17				17
Net increase (decrease) in 2010			711				(2,141	)			(1,430	)
Revenue for the quarter ended March 31, 2010		$	16,663			$	6,722			$	23,385

          Total oil and gas revenues of $23.4 million for the three-months ended March 31, 2010 decreased $1.4 million or 6% from the same period of 2009. Compared to the first quarter of 2009, total production on an equivalent basis for the first quarter of 2010 decreased by 17%, and the average period gas prices decreased 6%. These declines were partially offset by a 23% increase in average period oil prices.

          Gas revenues of $6.7 million declined by 24% for the three-months ended March 31, 2010 when compared to gas revenues of $8.9 million for the same period of 2009. The decrease was caused by both a 19% decline in production coupled with a 6% decline in price. Gas production during the first quarter of 2010 declined to 1.2 billion cubic feet (Bcf) compared to 1.4 Bcf during the same period in 2009. Additionally, the average gas price after hedging was $5.76 per thousand cubic feet of natural gas (“Mcf”) compared to $6.13 per Mcf for the same period in 2009. Approximately 12% of the 19% decrease in 2010 production was due to the host facility for East Cameron #2 well being shut-in due to a fire. Production for East Cameron #2 is expected to be restored in the fourth quarter of 2010. The remaining 7% decrease was due to normal and expected declines from our legacy properties.

          Oil revenues increased 4% to $16.7 million for the three-months ended March 31, 2010 compared to revenues of $16.0 million for the same period of 2009. Contributing to the increase was an increase in commodity prices, partially offset by a decrease in production. The average price received after hedging increased 23% to $74.78 per barrel compared to $60.59 for the same period of 2009. Conversely, production declined 15% to 223 thousand barrels during the first quarter of 2010 compared to production of 263 thousand barrels during the same period in 2009. The decrease in 2010 production was attributable to normal and expected declines in production from our legacy properties, partially offset by production from the Permian Basin properties we acquired during the fourth quarter of 2009.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operating Expenses

		Three-Months ended March 31,
						Per								Per				Year $				Year %
		2010				Mcfe				2009				Mcfe				Change				Change
Lease operating expenses		$	4,648			$	1.86			$	4,039			$	1.33			$	609				15	%
Depreciation, depletion and amortization			6,813				2.72				9,413				3.11				(2,600	)			-28	%
General and administrative			4,304				1.72				1,819				0.60				2,485				137	%
Accretion expense			580				0.23				1,038				0.34				(458	)			-44	%

Lease Operating Expenses

          Lease operating expenses (“LOE”) increased by 15% to $4.6 million for the three-month period ended March 31, 2010 compared to $4.0 million for the same period in 2009. The increase was primarily due to the $0.6 million of LOE related to our acquisition of Exl Permian Basin properties and a $0.3 million increase in insurance rates due to adding additional coverage to our program designed to better protect the company from damage caused by severe weather. These increases were offset by $0.2 million decline in LOE and a $0.1 million decline in severance taxes paid due to lower production of certain properties.

Depreciation, Depletion and Amortization

          Depreciation, depletion and amortization (“DD&A”) for the three-months ended March 31, 2010 decreased 28% to $6.8 million compared to $9.4 million for the same period of 2009. A lower DD&A rate and lower production levels reduced expenses by approximately $1.0 million and $1.4 million, respectively. The Company’s rate decreased as a result of the downward revision during the second quarter of 2009 of the cost estimates for plugging and abandonment of the Entrada field and an increase in the December 31, 2009 proved reserves.

General and Administrative

          General and administrative expenses, net of amounts capitalized, increased to $4.3 million for the three-months ended March 31, 2010 from $1.8 million for the same period of 2009. Our performance-based incentive program runs from April to March, and adjustments to our accruals are recorded during the first quarter of the year subsequent to the issuance of final year-end financials. During the first quarter of 2009, we recorded a 75% reduction in incentive-based compensation related to our actual 2008 results. These results, which were negatively affected by the decline in oil and gas prices, the abandonment of the Entrada project and worsening broader economic conditions, were lower than the performance goals set for fiscal year 2008. Conversely, the increase experienced during first quarter of 2010 relates primarily to a 21% increase in incentive-based compensation related to exceeding performance goals set for fiscal year 2009. Also contributing to the period-over-period increase is (1) a valuation adjustment to mark to their fair value share-based awards issued in a prior year that will vest in the future, (2) additional employee-related costs, including non-recurring early retirement expenses, and (3) costs associated with adding new employees, including relocation and similar costs.

Accretion Expense

          Accretion expense related to our asset retirement obligation for the three-months ended March 31, 2010 decreased 44% to $0.6 million from $1.0 million during the same period of 2009. As the Company’s asset retirement obligation decreases, so too does the related accretion expense. At March 31, 2010, our asset retirement obligation of $14.0 million was significantly lower when compared to the March 31, 2009 balance of $41.7 million. See Note 10 included within the Consolidated Financial Statement found in Item 1, Part I of this filing.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Other

		Three-Months ended March 31,
		2010				2009				$ Change				% Change
Interest expense			3,594				4,782				(1,188	)			-25	%
Callon Entrada non-recourse credit facility interest expense (1)			—				1,556				(1,556	)			-100	%
Other (income) expense			(361	)			(95	)			(266	)			280	%
Income tax expense			—				(24	)			24				-100	%
Equity in earnings of Medusa Spar LLC			116				117				(1	)			-1	%

Interest Expense

          Interest expense on Callon related debt obligations decreased 25% to $3.6 million for the three-months ended March 31, 2010 compared to $4.8 million for the same period of 2009. The decrease was primarily due to the amortization of $0.9 million of our deferred credit related to the Senior Note, which is recorded as a decrease to interest expense. Also reducing interest expense was a reduction in the amount of discount amortization recognized related to our 9.75% Old Notes, 92% of which were exchanged during 2009, and a reduced amount of interest capitalized during the current period compared to the same period of 2009.

Other Income

          Other income for the three months-ended March 31, 2010 increased $0.3 million to $0.4 million compared to the same period of the prior year. The increase was primarily related to interest income earned on a higher average balance of cash and cash equivalents held during the period. Cash and cash equivalents increased due to the receipt of the MMS royalty recoupment and from an increase operating cash flows due to higher period-over-period oil commodity prices.

Income Tax Benefit

          Income tax expense was negligible for the three-months ended March 31, 2010 and 2009 despite an approximate $1.5 million increase in pre-tax income. Income tax expense remained flat due to tax benefits recognized related to carry-forward tax losses. While we established a full valuation allowance at December 31, 2008, we revise the valuation allowance each subsequent quarter to take advantage of our net deferred tax asset by using it to offset current period income.

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, under certain circumstances some 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 March 31, 2009.

Item 4. 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 March 31, 2009.

          There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

          Callon Petroleum Company is involved in various lawsuits incidental to our business. While the outcome of these lawsuits and proceedings cannot be predicted with certainty, it is the opinion of our management, based on current information and legal advice, that the ultimate disposition of these suits will not have a material effect on our financial position or results of operations.

Item 1A. Risk Factors.

          The following risk factor in our Form 10-K for the year ending December 31, 2009, is revised as follows to include a description of action taken by the Environmental Protection Agency on March 23, 2010.

          Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and gas we produce.

          On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources.

          In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA announced that it will be proposing a rule to extend this reporting obligation to oil and gas facilities, including onshore and offshore oil and gas production facilities.

          Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

          The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions, and the Obama Administration has indicated its support for legislation to reduce greenhouse emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to accumulate the required data and/or reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Removed and Reserved

Item 5. Other Information

None.

Item 6. Exhibits

Index of Exhibits

Certain portions of the exhibits described below have been omitted. The Company has filed and requested confidential treatment for non-public information with the Securities and Exchange Commission.

The following exhibits are filed as part of this Form 10-Q.

Exhibit
Number						Description
	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)
			3.3			Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)
	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			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)
			4.3			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)
			4.4			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)
			4.5			Second Supplemental Indenture for the Company’s 9.75% Senior Notes due 2010, dated November 24, 2009, between Callon Petroleum Company and American Stock Transfer & Trust Company

Exhibit
Number						Description
			4.6			Indenture for the Company’s 13.00% Senior Notes due 2016, dated November 24, 2009, between Callon Petroleum Company, the subsidiary guarantors described therein, Regions Bank and American Stock Transfer & Trust Company (incorporated by reference to Exhibit T3C to the Company’s Form T3, filed November 19, 2009, File No. 022-28916)
	10.					Material Contracts
			10.1			Third Amended and Restated Credit Agreement dated January 29, 2010, by and among Callon Petroleum Company, the “Lenders” described therein, Regions Bank, as Administrative Agent, Documentation Agent and Syndication Agent (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed February 3, 2010, File No. 001-14039)
	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 and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*		Filed herewith
†		Management contract or compensatory plan or arrangement
#		Cancelled agreement referenced in this Form 10-Q

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.