Callon Petroleum Company Reports Results For The First Quarter of 2013

Natchez, MS (May 9, 2013) - Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three-month period ended March 31, 2013.

The Company highlighted the recent operational activity and first quarter financial results:

• Program development of Wolfcamp shale in southern Midland Basin yielding cost efficiencies and opportunities to accelerate completion schedule.
• Third East Bloxom horizontal Wolfcamp B well recently producing 1,003 barrels of oil equivalent per day ("boepd") during flowback period.
• Revenue of $22.5 million from daily production of 3,644 boepd, or $68.72 per barrel of oil equivalent ("boe") produced. Daily production from Permian Basin operations was 1,584 boepd for the first quarter.
• Net income of $0.00 per diluted share, excluding the impact of mark-to-market derivative positions. On a GAAP basis, net loss per diluted share of $0.02, including the mark-to-market adjustment.
• Discretionary cash flow, a non-GAAP financial measure, of $0.28 per diluted share.

Fred Callon, Chairman and CEO commented, "We are very pleased with the initial impact of our program development initiatives in the southern Midland Basin from both a production and capital efficiency standpoint. Continued success with these efforts will enable Callon to increase proved reserves and cash flow throughout 2013, forming a foundation that provides the flexibility to pursue additional drilling opportunities in the central and northern portions of the basin."

Operations Update

Southern Midland. The Company's horizontal drilling program remains focused on pad-drilling development in the East Bloxom and Taylor Draw fields. The following table provides a summary of Callon's production results to date and near-term completion plans for the southern Midland Basin.

East Bloxom

						Initial Production (boepd)
Well (Completed)		Target Zone		Lateral Length		24-Hour Rate		30-Day Peak Rate
Neal 321H (3Q12)		Wolfcamp B		7,430'		827 (94% oil)		600 (94% oil)
Neal 651H (4Q12)		Wolfcamp B		7,113'		780 (92% oil)		553 (92% oil)
Neal 343H (2Q13)		Wolfcamp B		6,323'		1,003 (93% oil)*		t.b.d.
Neal 342H (2Q13)		Wolfcamp B		7,288'		Completing
Neal 341H		Wolfcamp A		7,142'		Drilled/3Q13 completion
* Most recent available rate (during flowback)

Taylor Draw

						Initial Production (boepd)
Well (Completed)		Target Zone		Lateral Length		24-Hour Rate		30-Day Peak Rate
Pembrook 9121  (1Q13)		Wolfcamp B		5,142'		500 (98% oil)		253 (81% oil)
Weatherby 2H		Wolfcamp B		5,876'		Drilled/2Q13 completion
Weatherby 1H		Lower WC B		5,482'		Drilled/2Q13 completion
Schwartz 1H		Wolfcamp B		5,368'		Drilled/3Q13 completion
Weatherby 3H		Wolfcamp B		6,000'**		Drilling/3Q13 completion
** Planned lateral length

After the Weatherby 3H has been drilled, the horizontal program will return to the East Bloxom field for the drilling of the next three-well pad development.

Based on recent results, the Company believes it can drill and complete horizontal wells targeting the Wolfcamp shale for a total cost of $6 to $7 million per well depending on lateral length and location. These costs reflect a significant reduction in drilling days, which are currently 15 to 20 days in duration through cementing. From a completion perspective, Callon estimates it has reduced its capital costs by $800 thousand per well from changes to its suite of service providers in late 2012. Importantly, the Company is in the final stages of establishing the required water handling infrastructure in the East Bloxom and Taylor Draw fields to handle "batch" completions of its wells. This completion capability should mitigate the current practice of temporarily shutting-in horizontal wells producing from the same drilling pad as a safety precaution.

Central Midland. During the three months ended March 31, 2013 in the Pecan Acres field, the Company recompleted one vertical well uphole into shallower zones above the Atoka formation and fracture stimulated one vertical well targeting 10 zones down to the Woodford interval. The Company believes that the production data from these additional wells support the continued drilling of deeper Wolfberry wells at both the Pecan Acres and Carpe Diem fields, with estimated ultimate reserve recovery of 125 to 150 thousand boe per well.

In addition, there has been a significant increase in horizontal Wolfcamp shale drilling in the areas surrounding Callon's acreage position in Ector and Midland Counties. The Company is currently developing plans for the drilling of a horizontal evaluation well in the Carpe Diem field.

Northern Midland. During the three months ended March 31, 2013, Callon completed a horizontal well targeting the Mississippian lime zone in Borden County. Following a delay caused by stuck coiled tubing during fracture stimulation, the well had a 24-hour peak oil production rate of 136 boepd while simultaneously producing 2,000 barrels of water per day.  Subsequently, the oil production rate declined while maintaining a high water production rate.  The Company recently set a mechanical plug in an effort to isolate an oil producing zone in the Mississippian formation that is believed to be above the source of the water production. Based on Callon's petrophysical interpretation of well logs from its Borden County acreage and the performance of offsetting industry wells, the Company believes there is a large in-place resource in the Mississippian formation on its acreage position and will continue to pursue development of this resource potential with both vertical and horizontal drilling concepts.

Gulf of Mexico. The Company's interest in the Medusa field, its remaining deepwater property, produced an average of 1,163 boepd during the three months ended March 31, 2013. Approximately 88% of Medusa's production was crude oil that receives Mars pricing. Callon's shelf properties produced at an average rate of 811 boepd in the first quarter. The East Cameron 257 field is finishing pipeline repairs and is expected to return to production this month after being shut-in since the fourth quarter of 2011. Additionally, the Company's only remaining operated shelf property, Mobile Bay 908, is in the process of being plugged and abandoned.

Summary Financial Results

Operating Revenues. Operating revenues for the three months ended March 31, 2013 include oil and natural gas sales of $22.5 million from average production of 3,644 Boe per day. These results compare with oil and natural gas sales of $29.3 million from average production of 4,308 Boe per day during the comparable 2012 period.

Crude Oil Revenue. Crude oil revenues decreased 24% to $19.5 million for the three months ended March 31, 2013 compared to revenues of $25.7 million for the same period of 2012. Contributing to the decrease in crude oil revenue was an 11% decrease in commodity prices compounded by a 15% decrease in production. The decrease in production was primarily attributable to the sale of our deepwater Habanero field in the fourth quarter of 2012, which produced 33 MBbls during the first quarter of 2012. Partially offsetting the sale and other normal declines in our Gulf of Mexico and other properties was a 23 MBbls increase in production from newly producing wells on our Permian properties. In addition, the average price realized for our crude oil volumes for the quarter decreased to $94.85 per barrel compared to $106.84 for the same period of 2012.

Natural Gas Revenue. Natural gas revenues of $3.0 million decreased 15% during the three months ended March 31, 2013 as compared to natural gas revenues of $3.5 million for the same period of 2012. The decline primarily relates to an 18% decrease in natural gas production, primarily attributable to the sale of our deepwater Habanero field in the fourth quarter of 2012, which produced 54 million cubic feet ("MMcf") of natural gas during the first quarter of 2012 as well as other normal and expected declines in our Gulf of Mexico properties. These production decreases were partially offset by a 14 MMcf increase in natural gas production from our Haynesville well, which was shut-in for 70 days during the first quarter of 2012 due to well interference from an offsetting well, and to a 30 MMcf increase in the Permian. Also offsetting these production declines was a 4% increase in the average price realized, which rose to $4.07 per thousand cubic feet of natural gas ("Mcf") from $3.92 per Mcf for the same period in 2012.

Lease Operating Expenses. Lease operating expenses ("LOE") for the three months ended March 31, 2013 decreased by 30% to $5.8 million compared to $8.2 million for the same period in 2012, which was primarily due to $2.9 million of workover costs in the prior year associated with our Haynesville well for which we had no similar costs in the current period.  The additional LOE from our growing Permian operations was partially offset by a reduction in LOE associated with the sale of our Habanero deepwater property in December 2012.

Production Taxes. Production taxes remained relatively flat for the three months ended March 31, 2013 as compared to the same period of 2012, though increased 17% on a per Boe basis.  The increase relates to an increase of onshore production subject to these taxes while our offshore production is exempt from production taxes.

General and Administrative Expenses. General and administrative expenses, net of amounts capitalized, decreased to $3.7 million for the three months ended March 31, 2013 from $5.0 million for the same period of 2012. The decrease primarily consists of a $0.9 million downward revision for the mark-to-market adjustment of certain liability-based incentive compensation instruments. We also recorded a $0.4 million reduction to our performance-based incentive compensation accrual during the first quarter of 2013.

Interest Expense. Interest expense incurred during the three months ended March 31, 2013 decreased $1.1 million or 41% to $1.5 million compared to $2.6 million for the same period of 2012. The decrease in interest expense is primarily related to a $0.9 million increase in capitalized interest resulting from a higher average unevaluated property balance for the three months ended March 31, 2013 compared to the corresponding period of 2012. Also contributing to the decrease is $0.3 million lower interest expense related to our senior notes following a $10 million principal redemption during the second quarter of 2012, which was partially offset by an additional $0.1 million interest expense related to additional draws on our credit facility in 2013 compared to the corresponding period of the prior year.

Net Income. For the three months ended March 31, 2013, the Company reported a net loss of $0.8 million and $0.02 loss per diluted share, compared to net income and diluted earnings per share of $0.5 million and $0.01, respectively for the same period of 2012. Excluding the after-tax losses related to mark-to-market derivative positions, Callon reported net income of $0.1 million and earnings per share of $0.00 for the first quarter of 2013.

Discretionary Cash Flow. Discretionary cash flow for the three months ended March 31, 2013 totaled $11.3 million compared to $13.3 million during the comparable prior year period. Net cash flow provided by operating activities, as defined by U.S. GAAP, was $12.9 million for the three months ended March 31, 2013, and $10.4 million for the comparable prior year period. (See "Non-GAAP Financial Measures" that follows and the accompanying reconciliation of discretionary cash flow, a non-GAAP measure, to net cash flow provided by operating activities.)

Capital Expenditures. Callon's capital expenditures for the three months ended March 31, 2013 included the following amounts (in millions):

Southern Midland Basin		$	22
Northern Midland Basin		3
Leasehold acquisitions and seismic		1
Capitalized interest		1
Capitalized general and administrative costs allocated directly to exploration and development projects		3
Total capital expenditures		$	30

The following table summarizes drilled and completed wells through March 31, 2013:

		Drilled						Completed
		Gross			Net			Gross			Net
Southern portion:
Vertical wells		-			-			-			-
Horizontal wells		4			3.95			1			1
Total southern portion		4			3.95			1			1
Central portion:
Vertical wells		1			0.42			2			1.39
Horizontal wells		-			-			-			-
Total central portion		1			0.42			2			1.39
Northern portion:
Vertical wells		-			-			-			-
Horizontal wells		-			-			1			0.75
Total northern portion		-			-			1			0.75
Total		5			4.37			4			3.14

Liquidity. At May 6, 2013, the Company's total liquidity position was $38.8 million comprised of a cash balance of $1.8 million and borrowing availability of $37.0 million under its revolving credit facility with a current borrowing base of $75 million that was established in April 2013.

Earnings Call Information

The Company will host a conference call on Friday, May 10, 2013 to discuss first quarter 2013 financial and operating results. 

Please join Callon Petroleum Company via the Internet for a webcast of the conference call:

Date/Time:           Friday, May 10, 2013, at 9:00 a. m. Central Time (10:00 a.m. Eastern Time)
Webcast:               Live webcast will be available at www.callon.com in the "Investors" section of the website.

Alternatively, you may join by telephone:

Call-in number: 877-317-6789 (Toll-free)

An archive of the conference call webcast will also be available at www.callon.com in the "Investors" section of the website.

Presentation slides that will be discussed during the conference call will be available on the Company's website at www.callon.com in the "Events and Presentations" section.

Non-GAAP Financial Measures

This news release refers to non-GAAP financial measures as "discretionary cash flow". Callon believes that the non-GAAP measure of discretionary cash flow is useful as an indicator of an oil and gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt. The Company also has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred.

Reconciliation of Non-GAAP Financial Measures:

The following table reconciles net cash flow provided by operating activities to discretionary cash flow (in thousands):

The following table reconciles income available to common shares to adjusted income (in thousands; reconciling items are reflected net of tax):

The following table presents summary information for the three months ended March 31, 2013, and are followed by the Company's financial statements.

CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts)
		Three Months Ended March 31,
		2013				2012
Operating revenues:
Crude oil sales		$	19,540			$	25,749
Natural gas sales		3,001				3,545
Total operating revenues		22,541				29,294
Operating expenses:
Lease operating expenses		5,758				8,237
Production taxes		539				547
Depreciation, depletion and amortization		11,042				12,189
General and administrative		3,739				5,031
Accretion expense		565				574
Total operating expenses		21,643				26,578
Income from operations		898				2,716
Other (income) expenses:
Interest expense		1,515				2,577
Loss (gain) on derivative contracts		418				(70		)
Other income, net		(45		)		(305		)
Total other expenses, net		1,888				2,202
Income (loss) before income taxes		(990		)		514
Income tax expense (benefit)		(169		)		144
Income (loss) before equity in earnings of Medusa Spar LLC		(821		)		370
Equity in earnings of Medusa Spar LLC		21				118
Net income (loss) available to common shares		$	(800	)		$	488
Net income (loss) per common share:
Basic		$	(0.02	)		$	0.01
Diluted		$	(0.02	)		$	0.01
Shares used in computing net income (loss) per common share:
Basic		39,793				39,351
Diluted		39,793				40,254

CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
		Three Months Ended March 31,
		2013				2012
Cash flows from operating activities:
Net (loss) income		$	(800	)		$	488
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion and amortization		11,393				12,486
Accretion expense		565				574
Amortization of non-cash debt related items		111				122
Amortization of deferred credit		(799		)		(811		)
Equity in earnings of Medusa Spar LLC		(21		)		(118		)
Deferred income tax (benefit) expense		(169		)		144
Unrealized loss (gain) on derivative contracts		1,039				(299		)
Non-cash expense related to equity share-based awards		580				442
Change in the fair value of liability share-based awards		(195		)		907
Payments to settle asset retirement obligations		(396		)		(630		)
Changes in current assets and liabilities:
Accounts receivable		1,333				(3,177		)
Other current assets		857				1,075
Current liabilities		158				(730		)
Change in natural gas balancing receivable		(63		)		1
Change in natural gas balancing payable		10				50
Change in other long-term liabilities		(206		)		-
Change in other assets, net		(522		)		(174		)
Cash provided by operating activities		$	12,875			$	10,350
Cash flows from investing activities:
Capital expenditures		(30,089		)		(45,481		)
Proceeds from sale of mineral interest and equipment		114				506
Distribution from Medusa Spar LLC		340				758
Cash used in investing activities		$	(29,635	)		$	(44,217	)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility		17,000				-
Taxes paid related to exercise of employee stock options		-				(2		)
Cash provided by (used in) financing activities		$	17,000			$	(2	)
Net change in cash and cash equivalents		240				(33,869		)
Beginning of period cash and cash equivalents		1,139				43,795
End of period cash and cash equivalents		$	1,379			$	9,926

Callon Petroleum Company is engaged in the acquisition, development, exploration and operation of oil and gas properties in Texas, Louisiana and the offshore waters of the Gulf of Mexico.

This news release is posted on the company's website at www.callon.com and will be archived there for subsequent review. It can be accessed from the 'News Releases" link on the top of the homepage.

This news release contains projections forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding our reserves as well as statements including the words "believe," "expect," "plans" and words of similar meaning.  These projections and statements reflect the Company's current views with respect to future events and financial performance.  No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors.  Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and gas prices, ability to drill and complete wells, operational, regulatory and environment risks, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K, available on our website or the SEC's website at www.sec.gov.

For further information contact
Rodger W. Smith, 1-800-451-1294

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