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 May 6, 2015 - 4:57 PM EDT
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Callon Petroleum Company Announces First Quarter 2015 Results and Increases Annual Production Guidance

NATCHEZ, Miss., May 6, 2015 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three month period ended March 31, 2015. Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located within the Investors (Events and Presentations) section of the site.

The Company highlighted financial and operating results for the first quarter of 2015:

  • Net daily production of 8,567 barrels of oil equivalent per day ("BOE/d"), an increase of 18% over the fourth quarter of 2014, comprised of 83% oil volume
  • Lease operating costs, including workovers, of $9.03 per barrel of oil equivalent ("BOE"), a decrease of 20% compared to the fourth quarter of 2014
  • Adjusted EBITDA, a non-GAAP financial measure(i), of $26.7 million
  • Adjusted income available to common shareholders, a non-GAAP financial measure(i), of $0.00 per diluted share based on total average diluted shares outstanding of 57.5 million shares
  • Financial flexibility enhanced by the completion of a common equity offering for $65.6 million in net proceeds and reaffirmation of the $250 million borrowing base under its credit facility

"We are pleased to report another quarter of record Permian production at over 8,500 barrels of oil per day, up nearly 20% over last quarter, thanks to a variety of operational successes including placing nine new horizontal wells on production," commented Fred Callon, Chairman and Chief Executive Officer. "We continue to enjoy strong well performance from multiple producing zones, including recent Lower Spraberry wells in Midland County, and Wolfcamp B wells in the Southern Midland Basin at our well-established East Bloxom development and steadily improving Garrison Draw field. In addition, our drilling program continues to benefit from incremental capital cost reductions which put us on a path to realize a 30% decrease in total completed well costs in the second half of 2015 compared to 2014 levels. As we progress into 2015 and beyond, we plan to overlay this competitive cost structure on an operating plan that will include the shifting of capital to the Lower Spraberry zone, enhancing our capital efficiency and production growth potential."

Operating and Financial Results

The following table presents summary information for the periods indicated, and are followed by the Company's financial statements.













Three Months Ended



March 31, 2015


December 31, 2014


March 31, 2014

Net production:










   Oil (MBbls)



638



529



332

   Natural gas (MMcf)



801



839



363

   Total production (MBOE)



771



669



392

   Average daily production (BOE/d)



8,567



7,270



4,355

   % oil (BOE basis)



83%



79%



85%

Oil and natural gas revenues (in thousands):










   Oil revenue


$

27,909


$

34,409


$

30,909

   Natural gas revenue



2,482



4,009



2,376

      Total, excluding impact of cash-settled derivatives


$

30,391


$

38,418


$

33,285

   Impact of cash-settled derivatives



10,343



7,068



(875)

      Total, including impact of cash-settled derivatives


$

40,734


$

45,486


$

32,410













Three Months Ended

Additional per BOE data:


March 31, 2015


December 31, 2014


March 31, 2014

   Sales price, excluding impact of cash-settled derivatives


$

39.42


$

57.44


$

84.91

   Sales price, including impact of cash-settled derivatives



52.83



68.01



82.68











   Lease operating expense


$

9.03


$

11.23


$

10.79

   Production taxes



2.94



3.80



4.89

   Depletion, depreciation and amortization



23.48



27.05



26.88

   Adjusted G&A - total (a)



6.15



5.89



11.47

   Adjusted G&A - cash component (b)



5.37



4.35



9.99


(a)

Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(b)

Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization.

Total Revenue. For the quarter ended March 31, 2015, Callon reported total revenues of $30.4 million, excluding the $10.3 million impact of settled derivative contracts, comprised of oil revenues of $27.9 million and natural gas revenues of $2.5 million. Average daily production for the quarter was 8,567 BOE/d compared to average daily production of 7,270 BOE/d in the fourth quarter of 2014. Average realized prices, including and excluding the effects of hedging, are detailed below.

Hedging impacts. For the quarter ended March 31, 2015, Callon recognized the following hedging-related items:










In Thousands


Per Unit

Natural gas derivatives







Net gain on settlements


$

391


$

0.49

Net loss on fair value adjustments



(125)




   Total gain


$

266











Oil derivatives







Net gain on settlements


$

9,952


$

15.60

Net loss on fair value adjustments



(7,789)




   Total gain


$

2,163











Total derivatives







Net gain on settlements


$

10,343


$

13.41

Net loss on fair value adjustments



(7,914)




   Total gain on derivative contracts


$

2,429




Average realized prices, including and excluding the impact of cash settled derivatives during the first quarter, were as follows:







Three Months Ended



March 31, 2015

Average realized sales price:




   Oil (per Bbl) (excluding impact of cash-settled derivatives)


$

43.74

      Impact of cash-settled derivatives



15.60

   Oil (per Bbl) (including impact of cash-settled derivatives)


$

59.34





   Natural gas (perMcf) (excluding impact of cash-settled derivatives)


$

3.10

      Impact of cash-settled derivatives



0.49

   Natural gas (per Mcf) (including impact of cash-settled derivatives)


$

3.59





   Total (per BOE) (excluding impact of cash-settled derivatives)


$

39.42

      Impact of cash-settled derivatives



13.41

   Total (per BOE) (including impact of cash-settled derivatives)


$

52.83

Lease Operating Expenses, including workover expense ("LOE"). LOE for the three months ended March 31, 2015 was $9.03 per BOE, compared to LOE of $11.23 per BOE in the fourth quarter of 2014. Higher production volumes and lower workover expenses contributed to the 20% per BOE decrease in the first quarter.

Production Taxes, including ad valorem taxes. Production taxes were $2.94 per BOE in the first quarter of 2015, representing approximately 7.5% of total revenue before the impact of derivative settlements. While severance taxes correlate directly with commodity prices, ad valorem taxes are linked to underlying assessed property values, which are based on historical prices and which have increased with the additional horizontal wells placed onto production in our Garrison Draw, East Bloxom and Carpe Diem fields. Consequently, adjustments to this tax rate lag changes in commodity prices. As property values are adjusted downward over time in a lower commodity price environment, we expect this component to trend down.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended March 31, 2015 was $23.48 per BOE compared to $27.05 per BOE in the fourth quarter of 2014, with the decrease in per unit DD&A being attributable to our increase in proved reserves relative to our depreciable asset base and reductions in assumed future development costs.

General and Administrative, net of amounts capitalized ("G&A"). G&A excluding certain non-recurring items and non-cash incentive share-based compensation valuation adjustments ("Adjusted G&A", a non-GAAP measure(i)) was $4.7 million, or $6.15 per BOE, for the current period compared to $3.9 million, or $5.89 per BOE, for the fourth quarter of 2014. The cash component of Adjusted G&A, which excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization, was $4.1 million, or $5.37 per BOE, compared to $2.9 million or $4.35 per BOE for the fourth quarter of 2014. G&A and Adjusted G&A for the first quarter of 2015 are calculated as follows:



















Recurring


Non-Recurring




G&A expenses:


Cash


Non-Cash


Cash


Non-Cash


Total

   Cash G&A


$

4,137


$


$


$


$

4,137

   Restricted stock share-based compensation





479







479

   Change in the fair value of liability share-based awards





2,578







2,578

   Corporate depreciation & amortization





129







129

   Threatened proxy contest







111





111

   Early retirement expenses







3,553



1,115



4,668

Total G&A expense:


$

4,137


$

3,186


$

3,664


$

1,115


$

12,102

Adjusted G&A:
















   Less: Change in the fair value of liability share-based awards














$

(2,578)

   Less: Early retirement expenses















(4,668)

   Less: Threatened proxy context expenses















(111)

Adjusted G&A - total















4,745

   Restricted stock share-based compensation















(479)

   Corporate depreciation & amortization















(129)

Adjusted G&A - cash component














$

4,137

The Company recorded a one-time expense related to the early retirement of approximately 20% of its employee base with the reductions occurring in the Natchez and Houston offices. The Company expects the initiative will reduce future Adjusted G&A (including expensed and capitalized amounts) by approximately $5 million per year, starting in the second quarter of 2015.

Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $12.2 million in the first quarter of 2015 and Adjusted income available to common shareholders ("Adjusted Income"), a non-GAAP measure(i), of $0.1 million, or $0.00 per diluted share.

The following tables reconcile to the related GAAP measure the Company's income (loss) available to common stockholders to Adjusted Income and the Company's net income (loss) to Adjusted EBITDA:













Three Months Ended



March 31, 2015


December 31, 2014


March 31, 2014

Income (loss) available to common stockholders


$

(12,171)


$

16,988


$

(111)

   Net loss (gain) on derivatives, net of settlements



5,144



(14,249)



1,065

   Rig termination fee



2,367





   Change in the fair value of share-based awards



1,676



(1,713)



1,726

   Early retirement expenses



3,034





1,601

   Withdrawn proxy contest expenses



72



65



775

   Gain on sale of other property and equipment







(702)

   Loss on early redemption of debt





1,985



Adjusted income


$

122


$

3,076


$

4,354

Adjusted income per fully diluted common share


$

0.00


$

0.05


$

0.11

 














Three Months Ended



March 31, 2015


December 31, 2014


March 31, 2014

Net income (loss)


$

(10,197)


$

18,962


$

1,863

   Net loss (gain) on derivatives, net of settlements



7,914



(21,921)



1,639

   Change in the fair value of share-based awards



2,059



(1,941)



3,101

   Early retirement expenses



4,668





2,463

   Rig termination fee



3,641





   Loss on early redemption of debt





3,054



   Withdrawn proxy contest expenses



111



100



1,193

   Acquisition expense



3



668



   Income tax expense (benefit)



(5,077)



10,504



1,341

   Interest expense



4,858



4,765



977

   Depreciation, depletion and amortization



18,546



18,521



10,598

   Accretion expense



209



223



228

Adjusted EBITDA


$

26,735


$

32,935


$

23,403

Adjusted EBITDA per diluted share


$

0.47


$

0.59


$

0.58

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the first quarter of 2015 was $19.0 million or $0.33 per diluted share, and is reconciled to operating cash flow in the following table:













Three Months Ended



March 31, 2015


December 31, 2014


March 31, 2014

Cash flows from operating activities:










Net income (loss)


$

(10,197)


$

18,962


$

1,863

Adjustments to reconcile net income (loss) to cash provided by operating activities:










   Depreciation, depletion and amortization



18,546



18,521



10,598

   Accretion expense



209



223



228

   Amortization of non-cash debt related items



781



779



119

   Amortization of deferred credit





(54)



(433)

   Deferred income tax (benefit) expense



(5,077)



10,504



1,341

   Net loss (gain) on derivatives, net of settlements



7,914



(21,921)



1,639

   Loss on early debt extinguishment





3,054



   Rig termination fee



3,641





   Gain on sale of other property and equipment







(1,080)

   Non-cash expense related to equity share-based awards



86



692



996

   Change in the fair value of liability share-based awards



3,088



(2,635)



3,483

Discretionary cash flow


$

18,991


$

28,125


$

18,754











Discretionary cash flow per diluted share


$

0.33


$

0.50


$

0.47

Weighted average dilutive shares outstanding



57,479



56,257



40,328











   Changes in working capital



(5,988)



9,090



2,908

   Payments to settle asset retirement obligations



258



(525)



(26)

   Payments to settle vested liability share-based awards










   related to early retirements



(3,538)





   Payments to settle vested liability share-based awards



(3,599)





(1,669)

Net cash provided by operating activities


$

6,124


$

36,690


$

19,967

Operations Update

The following table summarizes the Company's drilling activity for the three months ended March 31, 2015:
















Drilled


Completed (a)


Awaiting Completion



Gross


Net


Gross


Net


Gross


Net

Southern Midland Basin













Horizontal wells


6


5.8


7


6.8


2


2.0

   Total


6


5.8


7


6.8


2


2.0

Central Midland Basin













Vertical wells




1


0.4



Horizontal wells


4


2.0


3


1.3


1


0.7

   Total


4


2.0


4


1.7


1


0.7














Total vertical wells




1


0.4



Total horizontal wells


10


7.8


10


8.1


3


2.7

   Total


10


7.8


11


8.5


3


2.7



(a)

Completions include wells drilled prior to 2015.

For the three months ended March 31, 2015, the Company paid a total of $65.1 million of operational capital expenditures, including facilities, on a cash basis. These operational capital expenditures, inclusive of amounts paid for capital expenditures accrued at year-end, are detailed below:
















Three Months Ended March 31, 2015



Operational Capital Expenditures


Capitalized Interest


Capitalized G&A


Total Capital Expenditures

Cash basis


$

65,070


$

2,889


$

2,821


$

70,780

Timing adjustments (a)



(7,809)



(57)





(7,866)

Non-cash items







2,145



2,145

Accrual (GAAP) basis


$

57,261


$

2,832


$

4,966


$

65,059



(a)

Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period.

The Company has updated its operational capital guidance, on an accrual basis, that was established at $150 million to $165 million earlier this year. The update guidance of $160 million to $165 million reflects a higher than expected pace of drilling and completion due to operational efficiencies, combined with additional capital that has been budgeted to fund anticipated non-consenting working interest partners during the year. These increases are offset by higher than anticipated capital cost reductions realized to date. The revised operational guidance does not include any further assumed well costs reductions above those received to date. Callon currently anticipates drilling 26.9 net horizontal wells in 2015, an increase of approximately three net wells over previous estimates. As part of the new operational plan, the Company also plans to reallocate a portion of capital to drill an increased proportion of Lower Spraberry horizontal wells, targeting the drilling of 9.1 net wells during the year.

Full-Year 2015 Updated Guidance:








Full Year 2015



Previous


Updated

Total production (BOE/d)


8,000 - 8,400


8,800 - 9,300

% oil


79% - 81%


79% - 81%

Expenses (per BOE)





LOE, including workovers


$8.75 - $9.50


$8.50 - $9.50

Production taxes, including ad valorem


$3.00 - $3.50


$2.75 - $3.25

Adjusted G&A (a)


$5.75 - $6.25


$5.50 - $5.75

   Adjusted G&A - Cash Component (b)


$4.89 - $5.31


$4.00 - $4.75

Second Quarter 2015 Guidance:








First Quarter


Second Quarter



2015 Actual


2015 Guidance

Total production (BOE/d)


8,567


8,800 - 9,100

% oil


83%


78% - 81%

Expenses (per BOE)





LOE, including workovers


$9.03


$9.00 - $9.70

Production taxes, including ad valorem


$2.94


$2.75 - $3.25

Adjusted G&A (a)


$6.15


$5.50 - $5.75

   Adjusted G&A - Cash Component (b)


$5.37


$4.00 - $4.75



(a)

Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within the Non-GAAP financial measures and reconciliations section of this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(b)

Excludes share-settled stock-based compensation expense and corporate depreciation and amortization.

Hedge Portfolio Summary:

























For the Three Months Ended



June 30,


September 30,


December 31,


March 31,


June 30,


September 30,


December 31,

Oil contracts


2015


2015


2015


2016


2016


2016


2016

Swap contracts:






















   Total volume (MBbls)



409



520



442



91



91



92



92

   Weighted average price per Bbl


$

70.79


$

67.22


$

64.93


$

63.50


$

63.50


$

63.50


$

63.50

Swap contracts (Midland basis






















Differentials):






















   Volume (MBbls)



400



382



327









   Weighted average price per Bbl


$

(2.40)


$

(2.39)


$

(2.38)


$


$


$


$

Collar contracts combined with






















short puts (three-way collar):






















   Volume (MBbls)









91



91



92



92

    Weighted average price per Bbl






















      Ceiling (short call)


$


$


$


$

70.00


$

70.00


$

70.00


$

70.00

      Floor (long put)


$


$


$


$

60.00


$

60.00


$

60.00


$

60.00

      Short put


$


$


$


$

45.00


$

45.00


$

45.00


$

45.00

























For the Three Months Ended



June 30,


September 30,


December 31,


March 31,


June 30,


September 30,


December 31,

Natural gas contracts


2015


2015


2015


2016


2016


2016


2016

Collar contracts combined with






















short puts (three-way collar):






















   Volume (BBtu)



227



207



161









    Weighted average price per MMBtu






















      Ceiling (short call)


$

4.32


$

4.32


$

4.32


$


$


$


$

      Floor (long put)


$

3.85


$

3.85


$

3.85


$


$


$


$

      Short put


$

3.25


$

3.25


$

3.25


$


$


$


$

Swap contracts:






















   Total volume (BBtu)



237



219



228









   Weighted average price per MMBtu


$

3.98


$

3.98


$

3.96


$


$


$


$

Short call contracts:






















   Short call volume (BBtu)



109



110



111









   Short call price per MMBtu


$

5.00


$

5.00


$

5.00


$


$


$


$

i. See "Non-GAAP Financial Measures and Reconciliations" included within this release for related disclosures and calculations

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures as "discretionary cash flow," "Adjusted Income," "Adjusted G&A" and "Adjusted EBITDA." These measures, detailed below, 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.

  • 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. Discretionary cash flow and discretionary cash flow per diluted share are calculated using net income (loss) adjusted for certain items including depreciation, depletion and amortization, the impact of financial derivatives (including the mark-to-market effects, net of cash settlements and premiums paid or received related to our financial derivatives), remaining asset retirement obligations related to our divested offshore properties, restructuring and other non-recurring costs, deferred income taxes and other non-cash income items.
  • Callon believes that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table below details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.
  • We believe that the non-GAAP measure of Adjusted income available to common shareholders ("Adjusted Income") and Adjusted Income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted Income and Adjusted Income per diluted share below were computed in accordance with GAAP.
  • We calculate Adjusted Earnings before Interest, Income Taxes, Depreciation, Depletion and Amortization ("Adjusted EBITDA") as Adjusted income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, we believe that Adjusted EBITDA provides additional information with respect to our performance or ability to meet its future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA we present may not be comparable to similarly titled measures of other companies.

 

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share values and share data)














March 31, 2015


December 31, 2014

ASSETS






Current assets:






Cash and cash equivalents

$

2,144


$

968

Accounts receivable


31,930



30,198

Fair value of derivatives


19,160



27,850

Other current assets


989



1,441

Total current assets


54,223



60,457

Oil and natural gas properties, full cost accounting method:






   Evaluated properties


2,140,937



2,077,985

   Less accumulated depreciation, depletion and amortization


(1,496,454)



(1,478,355)

   Net oil and natural gas properties


644,483



599,630

   Unevaluated properties


142,867



142,525

Total oil and natural gas properties


787,350



742,155

Other property and equipment, net


8,046



7,118

Restricted investments


3,292



3,810

Deferred tax asset


47,238



44,688

Deferred financing costs


17,432



18,200

Other assets, net


456



342

Total assets

$

918,037


$

876,770

LIABILITIES AND STOCKHOLDERS' EQUITY






Current liabilities:






Accounts payable and accrued liabilities

$

68,271


$

76,753

Accrued interest


5,853



5,993

Cash-settled restricted stock unit awards


6,473



3,856

Asset retirement obligations


5,047



4,747

Deferred tax liability


3,687



6,214

Fair value of derivatives


473



1,249

Total current liabilities


89,804



98,812

Senior secured revolving credit facility


37,000



35,000

Secured second lien term loan


300,000



300,000

Asset retirement obligations


1,262



1,927

Cash-settled restricted stock unit awards


2,300



7,175

Other long-term liabilities


120



121

Total liabilities


430,486



443,035

Stockholders' equity:






Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively


16



16

Common stock, $0.01 par value, 110,000,000 shares authorized; 65,860,729 and 55,225,288 shares outstanding, respectively


659



552

Capital in excess of par value


592,042



526,162

Accumulated deficit


(105,166)



(92,995)

Total stockholders' equity


487,551



433,735

Total liabilities and stockholders' equity

$

918,037


$

876,770

 

 

Callon Petroleum Company

Consolidated Statements of Operations

(in thousands, except per share data)

















Three Months Ended March 31,




2015



2014

Operating revenues:







   Oil sales


$

27,909


$

30,909

   Natural gas sales



2,482



2,376

Total operating revenues



30,391



33,285

Operating expenses:







   Lease operating expenses



6,959



4,230

   Production taxes



2,265



1,917

   Depreciation, depletion and amortization



18,104



10,538

   General and administrative



12,102



10,807

   Accretion expense



209



228

   Rig termination fee



3,641



   Gain on sale of other property and equipment





(1,080)

Total operating expenses



43,280



26,640

   Income (loss) from operations



(12,889)



6,645

Other (income) expenses:







   Interest expense



4,858



977

   (Gain) loss on derivative contracts



(2,429)



2,513

   Other income



(44)



(49)

Total other expenses



2,385



3,441

   Income (loss) before income taxes



(15,274)



3,204

      Income tax expense (benefit)



(5,077)



1,341

      Net income (loss)



(10,197)



1,863

      Preferred stock dividends



(1,974)



(1,974)

  Loss available to common stockholders


$

(12,171)


$

(111)

  Loss per common share:







   Basic


$

(0.21)


$

(0.00)

   Diluted


$

(0.21)


$

(0.00)

   Shares used in computing loss per common share:







   Basic



57,479



40,328

   Diluted



57,479



40,328

 

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(in thousands)










Three Months Ended March 31,




2015



2014

Cash flows from operating activities:







Net income (loss)


$

(10,197)


$

1,863

Adjustments to reconcile net income (loss) to cash provided by operating activities:







   Depreciation, depletion and amortization



18,546



10,598

   Accretion expense



209



228

   Amortization of non-cash debt related items



781



119

   Amortization of deferred credit





(433)

   Deferred income tax (benefit) expense



(5,077)



1,341

   Net loss on derivatives, net of settlements



7,914



1,639

   Gain on sale of other property and equipment





(1,080)

   Non-cash expense related to equity share-based awards



86



996

   Change in the fair value of liability share-based awards



3,088



3,483

   Payments to settle asset retirement obligations



258



(26)

   Changes in current assets and liabilities:







      Accounts receivable



(2,125)



(2,928)

      Other current assets



452



707

      Current liabilities



(355)



5,155

   Payments to settle vested liability share-based awards related to early retirements



(3,538)



   Payments to settle vested liability share-based awards



(3,599)



(1,669)

   Change in other assets, net



(319)



(26)

      Net cash provided by operating activities



6,124



19,967

Cash flows from investing activities:







Capital expenditures



(70,780)



(65,760)

Proceeds from sales of mineral interest and equipment



272



2,226

     Net cash used in investing activities



(70,508)



(63,534)

Cash flows from financing activities:







Borrowings on credit facility



60,000



46,000

Payments on credit facility



(58,000)



Payment of deferred financing costs



(12)



(1,729)

Issuance of common stock



65,546



Payment of preferred stock dividends



(1,974)



(1,974)

      Net cash provided by financing activities



65,560



42,297

Net change in cash and cash equivalents



1,176



(1,270)

   Balance, beginning of period



968



3,012

   Balance, end of period


$

2,144


$

1,742

Earnings Call Information

The Company will host a conference call on Thursday, May 7, 2015 to discuss first quarter 2015 financial and operating results.

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


Date/Time:

Thursday, May 7, 2015, at 8:00 a.m. Central Time (9:00 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 using the following numbers:

Toll Free:                

1-888-349-0096

Canada Toll Free:     

1-855-669-9657

International:             

1-412-902-0125

Request to join:          

Callon Petroleum Company Earnings call

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 Petroleum Company 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 under the "News" 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, 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
Chief Financial Officer, Senior Vice President and Treasurer
1-800-451-1294

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-first-quarter-2015-results-and-increases-annual-production-guidance-300079032.html

SOURCE Callon Petroleum Company


Source: PR Newswire (May 6, 2015 - 4:57 PM EDT)

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