Callon Petroleum Company Reports Full-Year And Fourth Quarter 2013 Results

Natchez, MS (March 12, 2014) - Callon Petroleum Company CPE ("Callon" or the "Company") today reported results of operations for the three-month and twelve-month periods ended December 31, 2013.

The Company highlighted financial results for the fourth quarter of 2013:

• Revenue of $26.5 million from daily production of 3,848 barrels of oil equivalent per day ("BOE/d") of production, or $74.99 per BOE produced
• Fully diluted net income of $0.03 per share, which includes a $3.7 million gain related to the retirement of debt, a $0.1 million gain related to a non-cash, mark-to-market of the Company's derivative positions and a $1.7 million loss related to the impairment of offshore equipment
• Discretionary cash flow, a non-GAAP financial measure, of $0.39 per diluted share. (See "Non-GAAP Financial Measures" discussed and reconciled below)

Callon also highlighted recent operational activity:

• The Neal 652 Upper Wolfcamp B well in Upton County, with a 8,595' lateral (31 stages), achieved a peak 24-hour initial production rate of 1,395 BOE/d (86% oil) and a peak 26-day average rate of 1,013 BOE/d (79% oil) to date
• Three additional Wolfcamp B wells producing under natural pressure, including the Company's first two horizontal wells in Midland County
• The acquisition of 1,280 net acres in Upton County

Fred Callon, Chairman and CEO commented, "We are proud of the strategic achievements made in 2013, as well as our operational results in the Permian Basin. We have completed our transition to an onshore operator and continue to make progress in reducing our cost of capital. Importantly, our success in the Permian Basin has allowed us to replace our former offshore assets with long-lived oil reserves and production at attractive finding and development costs. We look forward to another year of robust growth in Permian production and continue to seek opportunities to expand our operational presence in the basin."

Operating and Financial Results

Oil and Natural Gas Revenues.  Total revenue for the fourth quarter of 2013 was $26.5 million compared to $28.7 million for the fourth quarter of 2012, a decrease of 8%. The reduction in revenue was mainly attributable to a net decrease in production, which was primarily related to the sale of our offshore fields, partially offset by the growth in Permian production. Also contributing to the decline was production downtime at our key producing Permian Basin fields in the fourth quarter of 2013 due to severe winter weather that caused electricity outages and extended curtailment of trucking capacity to transport production offtake. Total revenue for the full year 2013 was $102.6 million compared to $110.7 million in 2012. This decrease was primarily due to lower production resulting from the sale of the offshore properties, partially offset by the growth in Permian production. Also contributing to the decline was downtime at the Medusa field in early 2013 and a production shut-in at the Mobile Bay 908 property.

Lease Operating Expenses ("LOE").  LOE for the fourth quarter of 2013 totaled $4.0 million, or $11.33 per BOE, compared to $11.32 per BOE in the fourth quarter of 2012. LOE for the full year 2013 totaled $19.8 million, or $14.00 per BOE, a 5% decrease per BOE over the full year 2012 metric of $14.81 per BOE. This per unit decrease was primarily due to remediation work performed on our Haynesville wells during 2012, for which we had no similar costs in 2013, and the sale of our offshore properties and Haynesville field.

Production Taxes.  Production taxes for the fourth quarter of 2013 totaled $1.3 million, or $3.62 per BOE, a 3% increase per BOE over the fourth quarter of 2012 metric of $3.53 per BOE. Production taxes for the full year 2013 totaled $4.1 million, or $2.92 per BOE, a 42% increase per BOE over the full year 2012 metric of $2.05 per BOE. These increases were primarily due to an increased proportion of onshore production subject to these taxes relative to offshore production, which was predominantly exempt from production taxes.

Depreciation, Depletion and Amortization ("DD&A").  DD&A for the fourth quarter of 2013 totaled $10.4 million, or $29.36 per BOE, compared to $13.7 million, or $33.42 per BOE, in the fourth quarter of 2012. DD&A for the full year 2013 totaled $44.0 million, or $31.12 per BOE, compared to $49.7 million, or $31.56 per BOE, for the full year 2012. These per unit decreases were the result of increases in our estimated proved reserves relative to our depreciable asset base.

General and Administrative, net of amounts capitalized ("G&A").  G&A for the fourth quarter of 2013 totaled $6.4 million ($3.5 million cash), compared to $4.5 million ($4.2 million cash) in the fourth quarter of 2012. G&A for the full year 2013 totaled to $20.5 million ($14.1 million cash) compared to $20.4 million ($15.7 million cash) for the full year 2012. These increases in total G&A expense were due to an increase in non-cash charges related to share-based, incentive compensation instruments, which were offset by a decrease in cash G&A expenses and non-recurring employee-related expenses, including early retirement and severance expense incurred in 2012. The cash component of total G&A expense was $9.86 per BOE in the fourth quarter of 2013 and $9.99 per BOE for the full year 2013.

Interest Expense.  Interest expense for the fourth quarter of 2013 totaled $1.6 million, a decrease of $0.4 million over the fourth quarter of 2012 of $2.0 million. Interest expense for the full year 2013 totaled $6.1 million, a decrease over the full year 2012 of $9.1 million. The decreases relate primarily to additional capitalized interest versus 2012, reduced interest payments attributable to the redemption of the Company's Senior Notes in December 2013 and additional deferred credit amortization recognized in 2013 compared with 2012. The additional capitalized interest was related to a higher balance period-over-period in average unevaluated oil and natural gas properties.

Gain on Early Extinguishment of Debt.  For the fourth quarter and full year 2013, the Company recognized a net gain of $3.7 million on the early extinguishment of debt, including the recognition of $5.3 million of deferred credit accelerated amortization, offset by $1.6 million of redemption expenses.

Gain/Loss on Derivative Instruments.  For the fourth quarter of 2013, the Company recorded a net gain of $0.7 million related to cash settlements during the three-month period and a non-cash, mark-to-market derivative gain of $0.1 million related to outstanding derivative contracts. Similarly, for the year ended December 31, 2013, the Company recorded a net gain of $1.4 million related to cash settlements during the twelve-month period and also recognized non-cash, mark-to-market losses of $2.7 million related to outstanding derivative contracts. The Company elects not to designate its derivatives contracts as hedges resulting in both the gains and losses on cash settlements and the mark-to-market adjustment related to unsettled derivatives being recognized in current earnings.

Discretionary Cash Flow.  Discretionary cash flow (non-GAAP) for the fourth quarter of 2013 was $15.8 million, a decrease of $1.1 million, or 6%, over the fourth quarter of 2012 of $16.9 million. Discretionary cash flow (non-GAAP) for the full year 2013 was $56.6 million, an increase of $1.1 million, or 2%, over the full year 2012 of $55.5 million. For a definition of discretionary cash flow and reconciliation to net cash flow provided from operating activities, see "Non-GAAP Financial Measures and Reconciliations" below.

Net Income.  The Company reported net income of $1.3 million in the fourth quarter of 2013 compared to a net loss of $0.4 million in the fourth quarter of 2012. For the full year 2013, the Company reported a net loss of $0.3 million compared to net income of $2.7 million for the full year 2012. Excluding certain non-cash items and their tax effect in the fourth quarters of 2013 and 2012, adjusted net income (non-GAAP) was $0.0 million, or $0.00 per diluted share, and $0.5 million, or $0.01 per diluted share, respectively. Excluding certain non-cash items and their tax effect for the years ending December 31, 2013 and 2012, adjusted net loss (non-GAAP) was $0.2 million, or $0.00 per diluted share, and adjusted net income was $1.5 million, or $0.04 per diluted share, respectively. For a definition of adjusted net income and a reconciliation of net income to adjusted net income, see "Non-GAAP Financial Measures and Reconciliations" below.

2013 Capital Expenditures

Callon's total capital expenditures on a cash basis for the twelve months ended December 31, 2013 were $171 million and included the following amounts (in millions):

Southern Midland Basin		$	111
Central Midland Basin		20
Northern Midland Basin		7
Other		7
Total capital expenditures		145
Capitalized general and administrative costs allocated directly to exploration and development projects		11
Capitalized interest		4
Total capitalized expenses		15
Total operational expenditures		160
Acquisitions		11
Total capital expenditures, including acquisitions		$	171

 

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

		Drilled						Completed (a)						Awaiting Completion
		Gross			Net			Gross			Net			Gross			Net
Southern Midland Basin
Vertical wells		1			1.0			1			1.0			-			-
Horizontal wells		17			15.5			15			13.5			3			3.0
Total		18			16.5			16			14.5			3			3.0
Central Midland Basin
Vertical wells		5			3.0			7			4.4			-			-
Horizontal wells		2			1.7			-			-			2			1.7
Total		7			4.7			7			4.4			2			1.7
Northern Midland Basin
Vertical wells		1			1.0			2			1.8			-			-
Horizontal wells		-			-			1			0.8			-			-
Total		1			1.0			3			2.5			-			-
Total		26			22.2			26			21.4			5			4.7
Total vertical wells		7			5.0			10			7.1			-			-
Total horizontal wells		19			17.2			16			14.3			5			4.7
Total		26			22.2			26			21.4			5			4.7

(a) Completions include wells drilled prior to 2013.

Operational Update

Callon completed the acquisition of 1,280 net acres in the Southern Midland Basin in February 2014 for total consideration of $7.0 million. This acreage is in close proximity to the East Bloxom field, providing the opportunity to leverage technical knowledge, as well as existing operations and infrastructure.

The Company placed four horizontal wells on production in the first quarter of 2014 and is currently in various stages of completing five additional horizontal wells.

At the East Bloxom field in Upton County, the Neal 652 had a peak 24-hour initial production rate of 1,395 BOE/d (86% oil) and a peak 26-day average rate of 1,013 BOE/d (79% oil) through March 10, 2014. The Neal 653, which was completed from the same pad, has recently been placed on artificial lift after producing under natural pressure for approximately 50 days. Both of these wells were completed in the Upper Wolfcamp B with lateral lengths of approximately 8,500'. In addition, the Company is currently completing three additional wells from a single pad in two distinct target zones, including a Wolfcamp A well and two Upper Wolfcamp B wells.

In Midland County, the Company's initial two horizontal Wolfcamp B wells in the Central Midland Basin were placed on production in early February at the Carpe Diem field. These wells have been producing under natural pressure since that time and are now being placed on artificial lift.

In Reagan County, two Lower Wolfcamp B wells with average lateral lengths of approximately 8,250' at the Garrison Draw field have been fracture stimulated and plugs are currently being drilled out.

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures as "discretionary cash flow" and "adjusted net income."

• 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.
• Adjusted net income and adjusted net income per diluted share, which excludes (1) impairments, (2) the unsettled portion of the changes in fair value related to our commodity derivatives, (3) loss (gain) on retirement of debt and (4) related income tax effect. The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined.

These measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

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 tables present summary information for the three and twelve-month periods ended December 31, 2013, and are followed by the Company's financial statements.

	Three Months Ended December 31,
	2013				2012				Change				% Change
Net production:
Oil (MBbls)	250				261				(11		)		(4	)%
Natural gas (MMcf)	622				893				271				30	%
Total production (MBOE)	354				410				(57		)		(14	)%
Permian (BOE/d)	2,978				1,840				1,138				54	%
Offshore and other (BOE/d)	870				2,617				(1,747		)		(76	)%
Average daily production (BOE/d)	3,848				4,457				(609		)		(14	)%
Average realized sales price:
Oil (Bbl)	$	93.38			$	94.55			$	(1.17	)		(1	)%
Natural gas (Mcf)	5.03				4.45				0.58				13	%
Total BOE	74.99				69.94				5.05				7	%
Oil and natural gas revenues (in thousands):
Oil revenue	$	23,345			$	24,701			$	(1,356	)		(5	)%
Natural gas revenue	3,126				3,975				(849		)		(21	)%
Total	$	26,471			$	28,676			$	(2,205	)		(8	)%
Additional per BOE data:
Sales price	$	74.99			$	69.94			$	5.05			7	%
Lease operating expense	(11.33		)		(11.32		)		(0.01		)		-	%
Production taxes	(3.62		)		(3.53		)		(0.09		)		(3	)%
Operating margin	$	60.04			$	55.09			$	4.95			9	%
Other expenses per BOE:
Depletion, depreciation and amortization	$	29.36			$	33.42			$	(4.06	)		(12	)%
General and administrative (cash component)	9.86				10.30				(0.44		)		(4	)%
General and administrative (non-cash component)	8.34				0.70				7.64				1,091	%
Below is a reconciliation of the average NYMEX price to the average realized sales price per Bbl of oil and Mcf of natural gas:
Average NYMEX oil price ($/Bbl)	$	97.42			$	88.13			$	9.29			11	%
Basis differential and quality adjustments (a)	(3.88		)		6.78				(10.66		)		(157	)%
Transportation	(0.16		)		(0.73		)		0.57				(78	)%
Hedging (b)	-				0.37				(0.37		)		(100	)%
Average realized oil price ($/Bbl)	$	93.38			$	94.55			$	(1.17	)		(1	)%
Average NYMEX natural gas price ($/MMBtu)	$	3.86			$	3.54			$	0.32			9	%
Basis differential and quality adjustments (c)	1.17				0.91				0.26				29	%
Average realized natural gas price ($/Mcf)	$	5.03			$	4.45			$	0.58			13	%

1. Oil prices for production from our two divested deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production, prior to the sale of Medusa in December 2013, and Argus Bonita WTI differential for Habanero production, prior to the sale of Habanero during December 2012.
2. The Company discontinued hedge accounting beginning with derivative contracts executed on January 1, 2012. Consequently, the gain or loss on derivative contracts, settled is now included in the statement of operations within loss (gain) on derivative contracts. The amounts reported above reflect the realized portion of derivative contracts designated as cash flow hedges.
3. Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian Basin production.

	For the Year Ended December 31,
	2013				2012				Change				% Change
Net production:
Oil (MBbls)	911				977				(66		)		(7	)%
Natural gas (MMcf)	3,011				3,588				(577		)		(16	)%
Total production (MBOE)	1,413				1,575				(162		)		(10	)%
Permian (BOE/d)	2,227				1,613				614				38	%
Offshore and other (BOE/d)	1,644				2,690				(1,046		)		(39	)%
Average daily production (BOE/d)	3,871				4,303				(432		)		(10	)%
Average realized sales price (see below):
Oil (Bbl)	$	97.65			$	98.86			$	(1.21	)		(1	)%
Natural gas (Mcf)	4.52				3.94				0.58				15	%
Total (BOE)	72.59				70.31				2.28				3	%
Oil and natural gas revenues (in thousands):
Oil revenue	$	88,960			$	96,584			$	(7,624	)		(8	)%
Natural gas revenue	13,609				14,149				(540		)		(4	)%
Total	$	102,569			$	110,733			$	(8,164	)		(7	)%
Additional per BOE data:
Sales price	$	72.59			$	70.31			$	2.28			3	%
Lease operating expense	(14.00		)		(14.81		)		0.81				5	%
Production taxes	(2.92		)		(2.05		)		(0.87		)		(42	)%
Operating margin	$	55.67			$	53.45			$	2.22			4	%
Other expenses per BOE:
Depletion, depreciation and amortization	$	31.12			$	31.56			$	(0.44	)		(1	)%
General and administrative (cash component)	9.99				9.97				0.02				-	%
General and administrative (non-cash component)	4.54				2.96				1.58				53	%
Below is a reconciliation of the average NYMEX price to the average realized sales price per Bbl of oil and Mcf of natural gas:
Average NYMEX oil price ($/Bbl)	$	97.96			$	94.19			$	3.77			4	%
Basis differential and quality adjustments (a)	0.12				3.97				(3.85		)		(97	)%
Transportation	(0.43		)		(0.75		)		0.32				43	%
Hedging (b)	-				1.45				(1.45		)		100	%
Average realized oil price ($/Bbl)	$	97.65			$	98.86			$	(1.21	)		(1	)%
Average NYMEX natural gas price ($/MMBtu)	$	3.73			$	2.82			$	0.91			32	%
Basis differential and quality adjustments (c)	0.79				1.12				(0.33		)		(29	)%
Average realized natural gas price ($/Mcf)	$	4.52			$	3.94			$	0.58			15	%

1. Oil prices for production from our two divested deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production, prior to the sale of Medusa in December 2013, and Argus Bonita WTI differential for Habanero production, prior to the sale of Habanero during December 2012.
2. The Company discontinued hedge accounting beginning with derivative contracts executed on January 1, 2012. Consequently, the gain or loss on derivative contracts, settled is now included in the statement of operations within loss (gain) on derivative contracts. The amounts reported above reflect the realized portion of derivative contracts designated as cash flow hedges.
3. Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian Basin production.

 

CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (In thousands, except share data)
	For the Year Ended December, 31
	2013				2012
ASSETS
Current assets:
Cash and cash equivalents	$	3,012			$	1,139
Accounts receivable	20,586				15,608
Fair market value of derivatives	60				1,674
Deferred tax asset, current	3,843				-
Other current assets	2,063				1,502
Total current assets	29,564				19,923
Oil and natural gas properties, full-cost accounting method:
Evaluated properties	1,701,577				1,497,010
Less accumulated depreciation, depletion and amortization	(1,420,612		)		(1,296,265		)
Net oil and natural gas properties	280,965				200,745
Unevaluated properties excluded from amortization	43,222				68,776
Total oil and natural gas properties	324,187				269,521
Other property and equipment, net	7,255				10,058
Restricted investments	3,806				3,798
Investment in Medusa Spar LLC	-				8,568
Deferred tax asset	57,765				64,383
Other assets, net	1,376				1,922
Total assets	$	423,953			$	378,173
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	57,637			$	36,016
Asset retirement obligations	4,120				2,336
Fair market value of derivatives	1,036				125
Total current liabilities	62,793				38,477
13% Senior Notes:
Principal outstanding	48,481				96,961
Deferred credit, net of accumulated amortization of $20,814 and $17,800, respectively	5,267				13,707
Total 13% Senior Notes	53,748				110,668
Credit facility	22,000				10,000
Asset retirement obligations	2,612				10,965
Other long-term liabilities	3,706				2,092
Total liabilities	144,859				172,202
Stockholders' equity:
Preferred Stock, series A cumulative, $.01 par value and $50.00 liquidation preference, 2,500 shares authorized; 1,579 and 0 shares outstanding, respectively	16				-
Common Stock, $.01 par value, 60,000 shares authorized; 40,345 and 39,801 shares outstanding at December 31, 2013 and 2012, respectively	404				398
Capital in excess of par value	401,540				328,116
Retained deficit	(122,866		)		(122,543		)
Total stockholders' equity	279,094				205,971
Total liabilities and stockholders' equity	$	423,953			$	378,173

 

CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts)
	For the Year Ended December 31,
	2013				2012
Operating revenues:
Oil sales	$	88,960			$	96,584
Natural gas sales	13,609				14,149
Total operating revenues	102,569				110,733
Operating expenses:
Lease operating expenses	19,779				23,330
Production taxes	4,133				3,224
Depreciation, depletion and amortization	43,967				49,701
General and administrative	20,534				20,358
Accretion expense	1,785				2,253
Impairment of other property and equipment	1,707				1,177
Total operating expenses	91,905				100,043
Income from operations	10,664				10,690
Other (income) expenses:
Interest expense	6,094				9,108
Gain on early extinguishment of debt	(3,696		)		(1,366		)
Loss (gain) on derivative contracts	1,360				(1,717		)
Other income	(485		)		(79		)
Total other expenses	3,273				5,946
Income before income taxes	7,391				4,744
Income tax expense (benefit)	3,104				2,223
Income before equity in earnings of Medusa Spar LLC	4,287				2,521
Equity in earnings of Medusa Spar LLC, net of tax	17				226
Net income	4,304				2,747
Preferred stock dividends	(4,627		)		-
Income (loss) available to common shareholders	$	(323	)		$	2,747
Income (loss) per common share:
Basic	$	(0.01	)		$	0.07
Diluted	$	(0.01	)		$	0.07
Shares used in computing income per common share:
Basic	40,133				39,522
Diluted	40,133				40,337

 

 

Earnings Call Information

The Company will host a conference call on Thursday, March 13, 2014 to discuss fourth quarter and full-year 2013 financial and operating results.

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

Date/Time:           Thursday, March 13, 2014, at 1:00 p.m. Central Time (2:00 p.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:

Toll Free Call-in number:               1-877-280-4961
International Call-in Number:          1-857-244-7318
Participant Passcode:                   13357138

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

About Callon Petroleum

Callon is an independent energy company focused on the acquisition, development, exploration, and operation of oil and gas properties in the Permian Basin in West Texas.

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.

Cautionary Statement Regarding Forward Looking Statements

This news release contains 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 wells anticipated to be drilled, future increases in production, reserve quantities and the present value thereof, the Company's 2014 guidance, the  implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "plans" and words of similar meaning. These 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:
Joe Gatto
Senior Vice President
1-800-451-1294

 

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