Callon Petroleum Co - Quarter Report: 2011 March (Form 10-Q)

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended March 31, 2011
	or
¨	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from__________ to__________

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 x

No ¨

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 ¨

No ¨

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 ¨	Accelerated filer x

Non-accelerated filer ¨	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 ¨

No x

As of May 2, 2011 there were outstanding 39,113,126 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	13

Item 3. Quantitative and Qualitative Disclosures about Market Risk	19

Item 4. Controls and Procedures	19

Part II. Other Information

Item 1. Legal Proceedings	20

Item 1A. Risk Factors	20

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	20

Item 3. Defaults Upon Senior Securities	20

Item 4. Removed and Reserved	20

Item 5. Other Information	20

Item 6. Exhibits	21

Part 1. Financial Information

Item 1. Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except share data)

	March 31, 2011			December 31, 2010
ASSETS	(Unaudited)
Current assets:
Cash and cash equivalents	$	54,482		$	17,436
Accounts receivable		10,424			10,728
Other current assets		1,247			2,180
Total current assets		66,153			30,344

Oil and gas properties, full-cost accounting method:
Evaluated properties		1,333,509			1,316,677
Less accumulated depreciation, depletion and amortization		(1,165,685	)		(1,155,915	)
Net oil and gas properties		167,824			160,762
Unevaluated properties excluded from amortization		8,662			8,106
Total oil and gas properties		176,486			168,868

Other property and equipment, net		3,800			3,370
Restricted investments		4,082			4,044
Investment in Medusa Spar LLC		10,214			10,424
Other assets, net		1,019			1,276
Total assets	$	261,754		$	218,326

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	19,727		$	17,702
Asset retirement obligations		2,405			2,822
Fair market value of derivatives		2,937			937
Total current liabilities		25,069			21,461

13% Senior Notes
Principal outstanding		106,961			137,961
Deferred credit, net of accumulated amortization of $10,790 and $3,964, respectively		20,717			27,543
Total 13% Senior Notes		127,678			165,504

Asset retirement obligations		13,146			13,103
Other long-term liabilities		3,441			2,448
Total liabilities		169,334			202,516

Stockholders' equity:
Preferred Stock, $.01 par value, 2,500,000 shares authorized;		-			-
Common Stock, $.01 par value, 60,000,000 shares authorized; 39,135,887 and 28,984,125 shares outstanding at March 31, 2011 and December 31, 2010, respectively		391			290
Capital in excess of par value		322,464			248,160
Other comprehensive loss		(10,519	)		(8,560	)
Retained earnings (deficit)		(219,916	)		(224,080	)
Total stockholders' equity		92,420			15,810
Total liabilities and stockholders' equity	$	261,754		$	218,326

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,
	2011			2010
Operating revenues:
Oil sales	$	18,804		$	16,663
Gas sales		6,645			6,722
Total operating revenues		25,449			23,385

Operating expenses:
Lease operating expenses		5,045			4,648
Depreciation, depletion and amortization		9,776			6,813
General and administrative		4,224			4,304
Accretion expense		615			580
Total operating expenses		19,660			16,345
Income from operations		5,789			7,040

Other (income) expenses:
Interest expense		3,492			3,594
Gain on early extinguishment of debt, net		(1,942	)		-
Other (income) expense		172			(361	)
Total other expenses		1,722			3,233

Income before income taxes		4,067			3,807
Income tax expense		-			-
Income before equity in earnings of Medusa Spar LLC		4,067			3,807
Equity in earnings of Medusa Spar LLC		97			116
Net income available to common shares	$	4,164		$	3,923

Net income per common share:
Basic	$	0.12		$	0.14
Diluted	$	0.12		$	0.13

Shares used in computing net income per common share:
Basic		33,744			28,738
Diluted		34,539			29,229

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

Callon Petroleum Company

Consolidated Statements of Cash Flows (Unaudited)

(in thousands)

	Three-Months Ended March 31,
	2011			2010
Cash flows from operating activities:
Net income	$	4,164		$	3,923
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion and amortization		10,001			6,989
Accretion expense		615			580
Amortization of non-cash debt related items		104			137
Amortization of deferred credit		(822	)		(889	)
Gain on early extinguishment of debt		(1,942	)		-
Equity in earnings of Medusa Spar LLC		(97	)		(116	)
Deferred income tax expense		1,982			1,332
Valuation allowance		(1,982	)		(1,332	)
Non-cash derivative expense due to hedge ineffectiveness		41			-
Non-cash charge related to compensation plans		776			643
Payments to settle asset retirement obligations		(71	)		(118	)
Changes in current assets and liabilities:
Accounts receivable		(110	)		47,081
Other current assets		933			585
Current liabilities		(256	)		(2,850	)
Change in gas balancing receivable		182			(44	)
Change in gas balancing payable		69			87
Change in other long-term liabilities		-			(115	)
Change in other assets, net		(130	)		(343	)
Cash provided by operating activities		13,457			55,550

Cash flows from investing activities:
Capital expenditures		(18,170	)		(6,856	)
Investment in restricted assets for plugging and abandonment		(38	)		(262	)
Proceeds from sale of mineral interest		2,787			-
Distribution from Medusa Spar LLC		307			473
Cash used in investing activities		(15,114	)		(6,645	)

Cash flows from financing activities:
Payments on senior secured credit facility		-			(10,000	)
Redemption of 13% senior notes		(35,062	)		-
Issuance of common stock		73,765			-
Cash provided by (used in) financing activities		38,703			(10,000	)

Net change in cash and cash equivalents		37,046			38,905
Cash and cash equivalents:
Balance, beginning of period		17,436			3,635
Less: Cash held by subsidiary deconsolidated at January 1, 2010		-			(311	)
Balance, end of period	$	54,482		$	42,229

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

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(all amounts in thousands, except per-share and per-hedge data)

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business and Basis of Presentation	6. Fair Value Measurements
2. Earnings per Share	7. Equity Transactions
3. Other Comprehensive Income (Loss)	8. Income Taxes
4. Borrowings	9. Asset Retirement Obligations
5. Derivative Instruments and Hedging Activities

Note 1 - Description of Business and Basis of Presentation

Description of Business

Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. The 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.

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 (“US GAAP”), (2) the Securities 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, 2010. The balance sheet at December 31, 2010 has been derived from the audited financial statements at that date.

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, 2011.

Unless otherwise indicated, all amounts contained in the notes to the consolidated financial statements are presented in thousands, with the exception of years, per-share and per-hedge amounts.

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(all amounts in thousands, except per-share and per-hedge data)

Note 2 - Earnings per Share

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

	Three-Months Ended March 31,
	2011		2010

(a) Net income	$	4,164	$	3,923

(b) Weighted average shares outstanding		33,744		28,738
Dilutive impact of stock options		28		37
Dilutive impact of restricted stock		767		454

(c) Weighted average shares outstanding
for diluted net income per share		34,539		29,229

Basic net income per share (a¸b)	$	0.12	$	0.14
Diluted net income per share (a¸c)	$	0.12	$	0.13
The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive:

Stock options		92		478
Warrants		-		365
Restricted stock		-		277

Note 3 - Comprehensive Income (Loss)

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

	Three-Months Ended March 31,
	2011			2010

Net income	$	4,164		$	3,923
Other comprehensive income (loss):
Change in fair value of derivatives		(1,959	)		190
Total other comprehensive income	$	2,205		$	4,113

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(all amounts in thousands, except per-share and per-hedge data)

Note 4 – Borrowings

The Company’s borrowings consisted of the following at:

	March 31, 2011		December 31, 2010
Principal components:
Credit Facility	$	-	$	-
13% Senior Notes due 2016, principal		106,961		137,961
Total principal outstanding		106,961		137,961

Non-cash components:
13% Senior Notes due 2016 unamortized deferred credit		20,717		27,543
Total carrying value of borrowings	$	127,678	$	165,504

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, which matures on September 25, 2012, provides for a $100,000 facility. Amounts borrowed under the Credit Facility may not exceed a borrowing base which is reviewed and re-determined on a semi-annual basis using second and fourth quarter financial results. The borrowing base was $30,000 at December 31, 2010 and March 31, 2011. During May 2011, Regions Bank approved a $45,000 borrowing base, which represents a $15,000 or 50% increase over the Company’s previous $30,000 borrowing base, and is secured by mortgages covering the Company’s major oil fields. As of March 31, 2011, the interest rate on the facility was 6%, defined in the agreement as 4% above a defined index rate, and in no event will the interest rate be less than 6%. Simultaneous with the May 2011 increase in the borrowing base, Regions Bank also approved a reduction in the interest rate on the facility from the previous floor of 6% to 3%, which is calculated as the London Interbank Offered Rate (“LIBOR”), with a minimum of 0.5%, plus a tiered rate ranging from 2.5% to 3.0%, which is based on the amount drawn on the facility. In addition, the credit facility continues to carry a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly.

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

During the fourth quarter of 2009, the Company exchanged approximately 92% of the principal amount, or $183,948, of the Company’s 9.75% Senior Notes (“Old Notes”) for $137,961 of Senior Notes. The exchange resulted in a 25% reduction in the principal amount of the Old Notes, 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 into 10 shares of common stock The Senior Notes’ 13% interest coupon is payable on the last day of each quarter. 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.

Upon issuing the Senior Notes during November 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 $31,507 difference between the adjusted carrying amount of the Old Notes and the principal of the Senior Notes was recorded as a deferred credit, which is being amortized as a reduction of 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:

Gross Carrying Amount				Accumulated Amortization at March 31, 2011(1)				Carrying Value at March 31, 2011				Amortization Recorded during 2011 as a Reduction of Interest Expense(1)				Estimated Amortization Expected to be Recorded during the Remainder of 2011
$	31,507			$	10,790			$	20,717			$	822			$	2,333

(1)

Amortization recorded during 2011 excludes $6,004 of accelerated amortization related to the March 2011 early redemption of $31,000 principal of notes discussed below, which is recorded in the Statement of Operations as part of the “Gain on early extinguishment of debt.” The Accumulated Amortization at March 31, 2011 includes the $6,004 of accelerated amortization.

On March 19, 2011, using a portion of the proceeds from the Company’s recent equity offering discussed in Note 7, the Company redeemed Senior Notes with a carrying value of $37,004, including $6,004 of the Notes’ deferred credit, in exchange for $35,062, comprised of the $31,000 principal of the notes, the $4,030 call premium and $32 of redemption expenses, which resulted in a $1,942 net gain on the early extinguishment of debt.

Restrictive Covenants

The Indenture governing our Senior Notes and the Company’s Credit Facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at March 31, 2011.

Note 5 - 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 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 speculative 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 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.

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(all amounts in thousands, except per-share and per-hedge data)

Settlements and Financial Statement Presentation

Settlements of the Company’s oil and gas collar derivative contracts are based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange (“NYMEX”) price. The estimated fair value of these collar contracts is based upon closing exchange prices on NYMEX and the time value of options. See Note 6, “Fair Value Measurements.”

The Company’s derivative contracts 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. 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 as of March 31, 2011:

Product

Product Type

Volumes per Month

Quantity Type

Average Floor Price per Hedge

Average Ceiling Price per Hedge

Period

Oil

Collar

Bbls

75.00

101.85

Apr11 - Dec11

Oil

Collar

Bbls

80.00

102.00

Apr11 - Dec11

Oil

Collar

Bbls

75.00

94.50

Apr11 - Dec11

Oil

Collar

Bbls

90.00

122.00

Apr11 - Dec11

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:

	Three-Months ended March 31,
	2011			2010
Amount of gain (loss) reclassified from OCI into income (effective portion)	$	(101	)	$	17
Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing)		(41	)		-

Subsequent event

During April 2011, the Company executed additional hedges as follows:

Product

Product Type

Volumes per Month

Quantity Type

Average Floor Price per Hedge

Average Ceiling Price per Hedge

Period

Oil

Collar

Bbls

90.00

122.00

Jan12 - Dec12

Oil

Collar

Bbls

95.00

125.00

Jan12 - Dec12

Note 6 - 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.

Fair Value of Financial Instruments

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

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. 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 carrying and fair values at:

	March 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value

13% Senior Notes due 2016 (1)	$	127,678	$	118,727	$	165,504	$	140,030

(1) Fair value is calculated only in relation to the $106,961 and $137,961 principal outstanding of the 13% Senior Notes at the dates indicated above, respectively. The remaining $20,717 and $27,543, respectively, which the Company has recorded as a deferred credit, is excluded from the fair value calculation, and will be recognized in earnings as a reduction of interest expense over the remaining amortization period. See Note 4 for additional information.

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 and crude oil basis swaps. As disclosed in Note 5, the Company’s hedge portfolio includes only collar contracts. The fair value of these derivatives is calculated using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that these inputs primarily fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. For additional information, see Note 5.

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

As of March 31, 2011	Balance Sheet Presentation	Level 1		Level 2			Level 3		Total
Liabilities
Derivative financial instruments - current	Fair market value of derivatives	$	-	$	2,937		$	-	$	2,937
Derivative financial instruments - non-current	Other long-term liabilities		-
Total		$	-	$	(2,937	)	$	-	$	(2,937	)

As of December 31, 2010	Balance Sheet Presentation	Level 1		Level 2			Level 3		Total
Liabilities
Derivative financial instruments - current	Fair market value of derivatives	$	-	$	937		$	-	$	937
Derivative financial instruments - non-current	Other long-term liabilities		-		-			-		-
Total		$	-	$	(937	)	$	-	$	(937	)

The derivative fair values above are based on analysis of each contract. Derivative liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists.

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(all amounts in thousands, except per-share and per-hedge data)

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:

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 through March 31, 2011 were Level 3 fair value measurements. See Note 9, Asset Retirement Obligations, which provides a summary of changes in the ARO liability.

Note 7 – Equity Transactions

During February, 2011, the Company received $73,765 in net proceeds through the public offering of 10,100 shares of its common stock, which included the issuance of 1,100 shares pursuant to the underwriters’ over-allotment option. As discussed in Note 4, the Company used a portion of the proceeds to redeem $31,000 principal or 22% of its Senior Notes. The remaining proceeds are intended for general corporate purposes including the accelerated development of the Company’s Permian Basin and other onshore assets.

Note 8 - 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, 2011			December 31, 2010
Deferred tax asset:
Federal net operating loss carryforward	$	79,788		$	79,680
Statutory depletion carryforward		6,242			6,140
Alternative minimum tax credit carryforward		208			208
Asset retirement obligations		3,966			4,018
Other		15,901			16,807
Deferred tax asset before valuation allowance		106,105			106,853
Less: Valuation allowance		(83,943	)		(85,222	)
Total deferred tax asset		22,162			21,631
Deferred tax liability:
Oil and gas properties		22,162			21,631
Total deferred tax liability		22,162			21,631
Net deferred tax asset	$	-		$	-

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Following an impairment of oil and gas properties recorded during the fourth quarter of 2008, the Company remains in a three-year cumulative loss position as of March 31, 2011. Accordingly, the Company continues to carry a full valuation allowance against its net deferred tax assets, which will affect the Company’s effective tax rate in future periods to the extent these deferred tax assets are recognized.

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(all amounts in thousands, except per-share and per-hedge data)

Note 9 - Asset Retirement Obligations

The following table summarizes the Company’s asset retirement obligations activity for the three-months ended March 31, 2011:

Asset retirement obligations at January 1, 2011	$	15,925
Accretion expense		615
Liabilities incurred		9
Liabilities settled		(1,634	)
Revisions to estimate		636
Asset retirement obligations at end of period		15,551
Less: current asset retirement obligations		(2,405	)
Long-term asset retirement obligations at March 31, 2011	$	13,146

Liabilities settled primarily relate to properties sold during the period for which the related asset retirement obligations were assumed by the purchaser, and also includes individual properties, primarily located in the Gulf of Mexico, plugged and abandoned during the period.

Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets as restricted investments were $4,481 at March 31, 2011 and included $399 recorded as current and $4,082 recorded as long-term at quarter end. These investments include primarily U.S. Government securities, and are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and gas properties.

Special Note Regarding Forward Looking Statements

All statements, other than historical fact or present financial information, may be deemed to be 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. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

· the timing and extent of changes in market conditions and prices for commodities (including regional basis differentials);

· our ability to transport our production to the most favorable markets or at all;

· the timing and extent of our success in discovering, developing, producing and estimating reserves;

· our ability to fund our planned capital investments;

· the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic

fracturing, the climate and over-the-counter derivatives;

· the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services;

· our future property acquisition or divestiture activities;

· the effects of weather;

· increased competition;

· the financial impact of accounting regulations and critical accounting policies;

· the comparative cost of alternative fuels;

· conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed;

· credit risk relating to the risk of loss as a result of non-performance by our counterparties; and

· any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”).

We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A our Annual Report on Form 10-K for the year ended December 31, 2010 (the “2010 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”).

Should one or more of the risks or uncertainties described above or elsewhere in our 2010 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Callon Petroleum Company

Management's Diescussion and Analysis of Financial Condition and Results of Operations

Item 2. Management's Diescussion and Analysis of Financial Condition and Results of Operations

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, 2010 (“Annual Report”), which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. When appropriate, the Company also updates its risk factors in Part II, Item 1A of this filing.

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

During the first quarter of 2011, we reported net income and fully diluted earnings per share of $4.2 million and $0.12, respectively, compared to net income and diluted earnings per share of $3.9 million and $0.13, respectively for the same period of 2010. These results are discussed in greater detail within the “Results of Operations” section included below. Key accomplishments to date in 2011 include:

Successfully completed a public offering of 10.1 million shares during February 2011 for which the Company received $73.8 million in net proceeds. While approximately 47% of the proceeds were used to reduce the Company’s debt outstanding, the remaining proceeds will be used to both fund the company’s development of its onshore assets and are available should the Company identify an attractive acquisition opportunity.

Redeemed during March 2011 $31 million of principal of the Senior Notes resulting in a net gain on the early extinguishment of debt of approximately $2.0 million. This redemption reduced the principal of the Company’s debt outstanding by approximately 22% to $107 million, and will reduce future interest expense by approximately $3.2 million during 2011 and by $4.0 million for each full year through the Notes’ maturity in 2016.

Increased the Credit Facility borrowing base to $45 million, representing a $15 million or 50% increase over the previously approved $30 million borrowing base. Simultaneously received a reduction in the Credit Facility’s interest rate from a minimum of 6% to 3%.

Our success in these areas allows us to continue executing on our strategy to shift our operational focus from the offshore Gulf of Mexico to developing longer life, lower risk onshore properties. Our onshore properties along with the cash flow from our Gulf of Mexico operations have not only dramatically re-shaped our portfolio and outlook, but we believe well positioned us to continue diversifying our portfolio by building profitable growth opportunities onshore. Highlights of our onshore development program include:

Onshore – Permian Basin

We currently own approximately 8,800 net acres in the Permian Basin, of which approximately 80% is prospective for the Wolfberry. We operate substantially all of the production and development of these properties, which are located in Crockett, Ector, Midland and Upton Counties, Texas. As of December 31, 2010, the properties included estimated proved reserves of 4.5 MMBoe producing approximately 550 Boe per day (“Boe/d”) from 33 gross wells, and the acreage had the potential for an additional 132 wells based on 40-acre spacing.

During the first three months of 2011, we fracture stimulated and placed on production six of the nine wells that were drilled as of December 31, 2010 and awaiting fracture stimulation services. We also drilled an additional eight wells during the first three months of 2011 at a total cost, including completion costs, of approximately $15.9 million, which was included in our 2011 capital expenditures budget designed to fund the drilling of up to 41 gross wells (39, net wells).

Early in 2011, we entered into an agreement with our fracture stimulation service provider to perform a minimum of three well stimulations per month through April 2011, which increases to four well stimulations per month in May 2011 and through the end of the year. Either party to the agreement may cancel the agreement without penalty with at least 30 days notice. Due to high wind conditions for much of April which caused operational delays throughout the Permian Basin, our fracture stimulation service provider requested approval to schedule only 2 wells for stimulation in the month of April. We expect to fracture stimulate eight or nine additional wells during the second quarter of 2011. As our fracture stimulation provider builds additional capacity in the Permian Basin, we hope to secure up to five well stimulations per month beginning August, 2011.

In order to reach the base of the Atoka formation, we have adjusted the depth of our wells by up to an additional 500 feet, which we believe to be prospective in the area. Utilizing the two drilling rigs presently active along with contracting a third rig in the third quarter, we plan to drill an additional 33wells during 2011.

Onshore – Shale Gas (Haynesville Shale)

We own a 69% working interest in a 624-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana. Our multi-year development plan for this property includes drilling and operating a total of seven horizontal wells, the first of which was placed on production in September 2010. As of March 31, 2011, this well was producing 4,200 Mcfe per day. We have no drilling obligations in our Haynesville Shale position, and currently plan to mobilize a rig to the area once natural gas prices warrant continued development of the remaining six planned gross horizontal wells.

We continue to monitor the changing regulatory environment, particularly the passing of the recent Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Bill”) of 2010, including its section 1504 that is applicable to “resource extraction issuers” (i.e. oil and gas companies). Among a broad spectrum of the Bill’s provisions aimed at reforming the United States’ financial system in an effort to reduce systemic risk, the Bill contains various corporate governance and disclosure provisions. While it is too soon to fully evaluate the impact the new legislation will have on our operations and profitability, we do not currently believe that its Section 1504 will materially affect our operations or profitability. We will continue to monitor the regulatory environment in our effort to proactively respond to the relevant changes.

Callon Petroleum Company

Management's Diescussion 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. Cash and cash equivalents increased by approximately $37.1 million during the three month period ending March 31, 2011 to $54.5 million compared to $17.4 million at December 31, 2010. The increase in liquidity is primarily attributable to receipt of $73.8 million from the previously discussed equity offering of 10.1 million shares of common stock offset by approximately $35 million used to repurchase $31 million principal of outstanding Senior Notes.

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 (“the Credit Facility”) matures on September 25, 2012, and provides for a $100 million facility with a current borrowing base of $45 million approved by Regions Bank in May 2011, which represents a $15 million or 50% increase over the previous $30 million borrowing base. As of March 31, 2011, the interest rate on the facility was 6%, defined in the agreement as 4% above a defined index rate, and in no event will the interest rate be less than 6%. Simultaneous with the May 2011 increase in the borrowing base, Regions Bank also approved a reduction in the interest rate on the facility from the previous floor of 6% to 3%, which is calculated as LIBOR, with a minimum of 0.5%, plus a tiered rate ranging from 2.5% to 3.0%, which is based on the amount drawn on the facility. In addition, the credit facility continues to carry a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly. No amounts were outstanding under the amended facility as of March 31, 2011.

At March 31, 2011, we had approximately $107.0 million of 13% Senior Notes outstanding with interest payable quarterly, a $31 million decrease from amounts outstanding at December 31, 2010 following the early redemption previously discussed. The principal reduction in our Senior Notes will reduce 2011 interest expense by approximately $3.2 million and each full-year thereafter by approximately $4.0 million.

2011 Budget and Capital Expenditures. For 2011, we designed a flexible capital expenditures spending program that can be funded from cash on hand, inclusive of the proceeds received from the previously discussed equity offering, and cash flows from operations. This budget projects $107 million of capital expenditures and is primarily focused on the accelerated development of our Permian Basin oil properties, and includes drilling and completing up to 41 wells on this property. This budget also includes all anticipated plugging and abandonment, capitalized interest and certain overhead costs related to acquiring, exploring and developing oil and gas properties.

In addition to cash on hand, should we identify an attractive strategic opportunity or acquisition, we currently have $45 million of borrowing capacity available under our Credit Facility. 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, interest payments, and operating requirements for 2011.

Summary cash flow information is provided as follows:

Operating Activities. For the three-months ended March 31, 2011, net cash provided by operating activities was $13.5 million, compared to $55.6 million for the same period in 2010. Cash flow from operations in the first quarter of 2010 included a $44.8 million recoupment of royalties paid to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE;” formerly the Minerals Management Service), and related interest of $7.9 million. Excluding this $52.7 million related to the BOEMRE royalty recoupment, cash flow provided by operating activities increased period-over-period by approximately 370% or $10.6 million primarily as a result of a 7% increase in the average realized sales price on an equivalent basis and a 2% increase in total production on an equivalent basis.

Investing Activities. For the three-months ended March 31, 2011, net cash used in investing activities was $15.1 million as compared to $6.6 million for the same period in 2010. The $8.5 million increase in net cash used in investing activities is primarily attributable to an increase in capital expenditure spending, and relates to drilling activity on our Permian Basin acreage, which was partially offset by $2.8 million in proceeds received for the sale of certain mineral interests.

Financing Activities. For the three-months ended March 31, 2011, net cash provided by financing activities was $38.7 million compared to cash used by financing activities of $10 million during the same period of 2010. The 2011 net cash provided by financing activities included $73.8 million of net proceeds from an equity offering offset by approximately $35.1 million used to redeem a $31 million principal portion of our outstanding Senior Notes and to pay the $4.0 million call premium and other redemption expenses. The 2010 expenditures related to the $10 million repayment of outstanding borrowings under the Credit Facility.

Callon Petroleum Company

Management's Diescussion 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,
	2011			2010			Change			% Change
Net production:
Oil (MBbls)		201			223			(22	)		(10	)%
Gas (MMcf)		1,342			1,166			176			15	%
Total production (Mboe)		424			417			7			2	%
Average daily production (MBoe)		4.7			4.6			0.1			2	%

Average realized sales price (a):
Oil (Bbl)	$	93.78		$	74.78		$	19.00			25	%
Gas (Mcf)		4.95			5.76			(0.81	)		(14	)%
Total (Boe)		59.99			56.03			3.96			7	%

Oil and gas revenues (in thousands):
Oil revenue	$	18,804		$	16,663		$	2,141			13	%
Gas revenue		6,645			6,722			(77	)		(1	)%
Total	$	25,449		$	23,385		$	2,064			9	%

Additional per Boe data:
Sales price	$	59.99		$	56.03		$	3.96			7	%
Lease operating expense		(11.89	)		(11.14	)		(0.75	)		7	%
Operating margin	$	48.10		$	44.90		$	3.20			7	%

Other expenses per Boe:
Depletion, depreciation and amortization	$	23.05		$	16.33		$	6.72			41	%
General and administrative	$	9.96		$	10.31		$	(0.35	)		(4	)%

(a) Below is a reconciliation of the average NYMEX price to the average realized sales price:

Average NYMEX price per barrel of oil	$	94.11		$	78.72		$	15.39			20	%
Basis differential and quality adjustments		1.28			(2.75	)		4.03		nm
Transportation		(1.11	)		(1.19	)		0.08			(7	)%
Hedging		(0.50	)		-			(0.50	)		100	%
Average realized price per barrel of oil	$	93.78		$	74.78		$	19.00			25	%

Average NYMEX price per thousand cubic feet of natural gas (“Mcf”)	$	4.20		$	5.04			(0.84	)		(17	)%
Basis differential and quality adjustments		0.75			0.72			0.03			4	%
Hedging		-			-			-			0	%
Average realized price per Mcf of gas	$	4.95		$	5.76		$	(0.81	)		(14	)%

nm – Not Meaningful

Callon Petroleum Company

Management's Diescussion and Analysis of Financial Condition and Results of Operations

Revenues

The following table is intended to reconcile the change in crude oil, natural gas and total revenue for the respective three-month periods presented by reflecting the effect of changes in volume, changes in the underlying commodity prices and the impact of our hedge program.

	Crude Oil			Natural Gas			Total

Revenues for the three-months 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 increase		-			17			17
Net increase (decrease) in 2010		711			(2,141	)		(1,430	)

Revenues for the three-months ended March 31, 2010	$	16,663		$	6,722		$	23,385

Volume increase (decrease)		(1,670	)		1,014			(656	)
Price increase (decrease)		3,912			(1,108	)		2,804
Impact of hedges increase (decrease)		(101	)		17			(84	)
Net increase (decrease) in 2011		2,140			(77	)		2,064

Revenues for the three-months ended March 31, 2011	$	18,804		$	6,645		$	25,449

Total Revenue

Total oil and gas revenues of $25.4 million for the three-months ended March 31, 2011 increased $2.1 million or 9% from the same period of 2010 principally driven by an increases in pricing on an equivalent unit basis. Compared to the first quarter of 2010, and on an equivalent basis, the average price realized by the Company increased 7%.

Oil Revenue

Oil revenues increased 13% to $18.8 million for the three-months ended March 31, 2011 compared to revenues of $16.7 million for the same period of 2010. Contributing to the increase in oil revenue was an increase in commodity prices, partially offset by production declines. The average price realized increased 25% to $93.78 per barrel compared to $74.78 for the same period of 2010. Conversely, production declined 10% to 201 thousand barrels (“MBbls”) during the first quarter of 2011 compared to production of 223 MBbls during the same period in 2010. The decrease in 2010 production was attributable to normal and expected declines in production from our legacy offshore properties, partially offset by increasing production from our Permian Basin properties.

Gas Revenue

Gas revenues of $6.6 million were relatively flat for the three-months ended March 31, 2011 as compared to gas revenues of $6.7 million for the same period of 2010. The 15% production increase was offset almost entirely by a 14% decrease in commodity prices. The production increase is primarily due to production from our Haynesville Shale gas well, which was placed on production during September 2010, and due to the production for East Cameron #2 well, which was shut-in during the first quarter of 2010 for repairs and did not returned to production until December 2010. These production increases were partially offset by normal and expected declines in other legacy offshore properties. Offsetting the increases in production was a 14% decrease in the average realized gas price, which fell to $4.95 per Mcf for the first quarter of 2011 from $5.76 per Mcf realized during the same period of 2010.

Callon Petroleum Company

Management's Diescussion and Analysis of Financial Condition and Results of Operations

Expenses

	Three-Months ended March 31,
	2011		Per Boe		2010		Per Boe		Year $ Change			Year % Change
Lease operating expenses	$	5,045	$	11.89	$	4,648	$	11.14	$	397			9	%
Depreciation, depletion and amortization		9,776		23.05		6,813		16.33		2,963			43	%
General and administrative, net		4,224		9.96		4,304		10.31		(80	)		(2	)%
Accretion expense		615		1.45		580		1.39		35			6	%

Lease Operating Expenses

Lease operating expenses (“LOE”) increased by 9% to $5.0 million for the three-month period ended March 31, 2011 compared to $4.6 million for the same period in 2010. The increase was primarily due to an approximate $0.3 million and $0.2 million increase in LOE related to the expanded development of our Permian Basin properties and our new Haynesville Shale gas well, respectively. LOE also increased approximately $0.2 million related to our East Cameron Well #2, which was shut-in for repairs during the same period of 2010. Our legacy properties experienced a mix of LOE immaterial increases and decreases that, when combined with the changes discussed, resulted in the net increase reported.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) for the three-months ended March 31, 2011 increased 43% to $9.8 million compared to $6.8 million for the same period of 2010. The additional DD&A relates primarily to a 41% rate increase, which is driven by the costs associated with the Company’s strategic shift towards developing lower-risk, onshore reserves, which, on a per unit basis, have higher development costs than those for our offshore reserves. The remaining portion of the increase relates to the 2% period-over-period increase in production.

General and Administrative

General and administrative expenses, net of amounts capitalized, decreased to $4.2 million for the three-months ended March 31, 2011 from $4.3 million for the same period of 2010.

Accretion Expense

Accretion expense related to our asset retirement obligation increased 6% for the three-months ended March 31, 2011 compared to the same period of 2010. Accretion expense correlates directionally with the Company’s asset retirement obligation (“ARO”). At March 31, 2011, our asset retirement obligation of $15.5 million was slightly higher than the $14.0 million ARO at March 31, 2010. See Note 9 for additional information regarding the Company’s ARO.

Callon Petroleum Company

Management's Diescussion and Analysis of Financial Condition and Results of Operations

Other

	Three-Months ended September 30,
	2011			2010			$ Change			% Change
Interest expense	$	3,492		$	3,594		$	(102	)		(3	)%
Gain on early extinguishment of debt, net		(1,942	)		-			(1,942	)		100	%
Other (income) expense		172			(361	)		533			(148	)%

Interest Expense

Interest expense on Callon’s debt obligations decreased 3% to $3.5 million for the three-months ended March 31, 2011 compared to $3.6 million for the same period of 2010. The decrease relates to the redemption of $31 million principal of Senior Notes during March 2011. This early redemption reduced interest expense by approximately $0.1 million for the current quarter compared to the same period of 2010.

Gain on Early Extinguishment of Debt

During March 2011, using a portion of the proceeds from the Company’s recent equity offering discussed in Note 7, the Company redeemed Senior Notes with a carrying value of $37 million, including $6.0 million of the Notes’ deferred credit, in exchange for $35.1 million, comprised of the $31 million principal of the notes, the $4.0 million call premium and miscellaneous redemption expenses, which resulted in a $1.9 million net gain on the early extinguishment of debt.

Other Income

Other expense of $0.2 million for the three months-ended March 31, 2011 decreased approximately $0.6 million compared to other income of $0.4 million for the same period of 2010. The decrease was primarily related to approximately $0.3 million of interest received during 2010 related to the recoupment of royalties from the BOEMRE, for which we had no similar interest income during 2011. Additionally, during the current period, we incurred approximately $0.2 million of expenses related to the final wind down of an unconsolidated subsidiary.

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 applicable 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 5 to the Consolidated Financial Statements for a description of the Company's outstanding derivative contracts at March 31, 2011.

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, 2011.

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

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

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

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)

3.4

Certificate of Amendment to the Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.4 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, 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 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

Underwriting Agreement dated as of February 10, 2011 between Callon Petroleum Company and Johnson Rice & Company L.L.C., as representative of the several underwriters named therein (incorporated by reference from Exhibit 1.1 of the Company’s Report on Form 8-K filed February11, 2011)

10.2

Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference from Exhibit 10.1 of the Company’s Report on Form 8-K filed March18, 2011)

10.3

Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Callon Petroleum Company and the Executive Officers (incorporated by reference from Exhibit 10.2 of the Company’s Report on Form 8-K filed March18, 2011).

10.4

Second Amendment to the Third Amended and Restated Credit Agreement dated May 9, 2011 among Callon Petroleum Company and Regions Bank (filed with this Form 10-Q for the period ended March 31, 2011).

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

Exhibit
Number		Description

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

10. Material Contracts

10.4

Second Amendment to the Third Amended and Restated Credit Agreement dated May 9, 2011 among Callon Petroleum Company and Regions Bank

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.


			Callon Petroleum Company
By:			/s/ Fred L. Callon
			Fred L. Callon
Date: May 10, 2011			President and Chief Executive Officer



By:			/s/ B.F. Weatherly
			B.F. Weatherly
Date: May 10, 2011			Executive Vice President and Chief Financial Officer