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Callon Petroleum Company Announces Second Quarter 2014 Financial and Operating Results

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SOURCE Callon Petroleum Company

NATCHEZ, Miss., Aug. 6, 2014 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and six month periods ended June 30, 2014.

Callon Petroleum Company Logo

The Company highlighted financial and operating results for the second quarter of 2014:

  • Net daily production of 5,280 barrels of oil equivalent per day ("BOE/d"), a sequential increase of 21% over the first quarter of 2014, comprised of 84% oil volume
  • Adjusted EBITDA, a non-GAAP financial measure, of $27.8 million (See "Non-GAAP Financial Measures and Reconciliations" discussed below)
  • Net income available to common shareholders of $0.07 per diluted share and adjusted income available to common shareholders ("Adjusted income"), a non-GAAP financial measure, of $0.14 per diluted share. Adjusted income excludes certain items that the Company believes affect the comparability of operating results, and are generally non-recurring items or items whose timing and/or amount cannot be reasonably estimated (See "Non-GAAP Financial Measures and Reconciliations" below)

Callon also highlighted recent operational activity and corporate developments (production data presented on a "two-stream" basis):

  • Six (gross) horizontal wells drilled and nine (gross) horizontal wells completed in the second quarter of 2014, targeting three discrete Wolfcamp shale zones
  • Two Wolfcamp B wells in Callon's newest development area at the Carpe Diem field in Midland County, the Kendra Kristen 1121 and Kendra Kristen 1122, produced at peak 24-hour rates of 1,163 BOE/d (6,566' completed lateral) and 1,176 BOE/d (6,582' completed lateral), respectively
  • Average peak 24-hour rates of 866 BOE/d per well (average 4,965' completed lateral) from a three-well pad targeting the Lower Wolfcamp B in Reagan County at the Taylor Draw field
  • First Lower Spraberry horizontal well spud in Midland County, expanding drilling in the Midland Basin to four targeted benches
  • Drilling of first horizontal well (planned 9,400' completed lateral) targeting the Wolfcamp B on recently acquired acreage in Upton County commenced in partnership with offsetting operator
  • Additional drilling rig scheduled for delivery in the fourth quarter of 2014 to accelerate horizontal development, targeting approximately 40 (gross) operated, horizontal well completions in 2015

Fred Callon, Chairman and CEO commented, "We are pleased to announce another solid quarter of execution of our horizontal drilling program, resulting in a three-fold increase in Permian production since the first quarter of 2013 and a continued decrease in lease operating expense. We look forward to building upon this success with the application of this execution capability across an expanded set of drilling opportunities with the addition of a drilling rig later this year. Based on our current plans, we expect to have over 80 operated horizontal wells producing by the end of next year, firmly establishing Callon as a leading operator in the Midland Basin."

Operating and Financial Results

Total Revenue. For the quarter ended June 30, 2014, Callon reported total revenues of $40.5 million, comprised of oil revenues of $37.7 million and natural gas revenues of $2.8 million. Average daily production for the quarter was 5,280 BOE/d compared to average daily production of 4,355 BOE/d in the first quarter of 2014. Average realized prices were $93.10 per barrel of oil and $6.17 per Mcf of natural gas in the second quarter of 2014, representing a weighted average of $84.30 per BOE produced.

Lease Operating Expenses, including workover expense ("LOE"). LOE for the three months ended June 30, 2014 was $9.08 per BOE, compared to LOE of $10.78 per BOE in the first quarter of 2014, which was within the range of published guidance.

Production Taxes, including ad valorem taxes. Production taxes were $4.71 per BOE in the second quarter of 2014. Production taxes were lower than published guidance.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended June 30, 2014 was $24.96 per BOE compared to $26.88 per BOE in the first quarter of 2014, with the decrease in per unit DD&A being attributable to increased estimated proved reserves relative to our depreciable asset base (the full cost pool).

General and Administrative, net of amounts capitalized ("G&A"). G&A for the three months ended June 30, 2014 was $9.6 million compared to $10.8 million in the first quarter of 2014. G&A excluding certain non-recurring items and non-cash valuation adjustments ("Adjusted G&A", a non-GAAP measure) was $4.9 million for the current period and $4.5 million for the first quarter of 2014. Adjusted G&A for the second quarter of 2014 excluded $4.7 million of expense related to the following items:

  • $0.1 million in non-recurring, cash expense related to a withdrawn proxy contest
  • $4.6 million in non-cash expense related to the mark-to-market adjustment of performance-based phantom stock incentive awards

Interest Expense. Interest expense incurred during the three months ended June 30, 2014 increased to $1.8 million compared to $1.0 million in the first quarter of 2014, primarily due to an increase in interest expense related to the increase in the balance of our Credit Facility, additional interest in connection with our Second Lien Facility and first quarter 2014 amortization of deferred credit in the amount of $0.4 million related to the Senior Notes. Offsetting these increases was a decrease in interest expense resulting from the full redemption of the Senior Notes completed on April 11, 2014.

Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $2.8 million in the second quarter of 2014 and Adjusted income, a non-GAAP measure, of $5.7 million, or $0.14 per diluted share, which excludes (net of tax effects): (a) $5.0 million in expenses related to the non-cash, mark-to-market valuation of the Company's derivative positions and phantom stock equity awards, (b) $2.1 million gain on early redemption of our Senior Notes, and (c) $0.1 million of non-recurring G&A expenses. The Company's effective tax rate for the second quarter was 45% due to non-deductible executive compensation expense and state income taxes.

For a definition of Adjusted income and a reconciliation of income (loss) available to common shareholders to Adjusted income, see "Non-GAAP Financial Measures and Reconciliations" below. No adjustments have been made to Adjusted income for non-recurring items, such as the increased income statement tax rate described above.

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure, for the second quarter of 2014 was $23.5 million, an increase of $4.8 million, or 26%, over the first quarter of 2014 of $18.7 million. The second quarter of 2014 included $1.4 million for retained asset retirement obligation expenditures related to Gulf of Mexico properties that were sold in the fourth quarter of 2013. Excluding this expenditure for discontinued operations, discretionary cash flow from continuing operations was $24.9 million or $0.60 per diluted share.

For a definition of discretionary cash flow and reconciliation to net cash flow provided from operating activities, see "Non-GAAP Financial and Reconciliations" below. No adjustments have been made to discretionary cash flow for non-recurring cash items, such as the asset retirement obligation expenditures described above.

Capital Expenditures

The following table summarizes the Company's drilling activity in the Permian Basin for the three months ended June 30, 2014:
















Drilled


Completed


Awaiting Completion



Gross


Net


Gross


Net


Gross


Net

Southern Midland Basin













Horizontal wells


5


4.8


7


6.3


4


3.8

Total


5


4.8


7


6.3


4


3.8














Central Midland Basin













Vertical wells


1


0.4


1


0.4


1


0.4

Horizontal wells


1


0.9


2


1.7


-


-

Total


2


1.3


3


2.1


1


0.4














Total vertical wells


1


0.4


1


0.4


1


0.4

Total horizontal wells


6


5.7


9


8.0


4


3.8














Total


7


6.1


10


8.4


5


4.2

 

Callon's total capital expenditures for the second quarter of 2014 are detailed below (in thousands):








Three Months Ended




June 30, 2014

Operational capital expenditures


$

57,747

Capitalized G&A and interest



2,617

   Total capital expenditures, excluding acquisitions



60,364





Acquisitions



1,095

   Total capital expenditures


$

61,459

 

Our updated 2014 operational capital expenditure budget approximates $215 million, excluding acquisitions and capitalized expenses. This budgeted amount includes plans to drill up to 30 gross (25.3 net) horizontal and seven gross (4.7 net) vertical wells, while completing 31 gross (26.7 net) horizontal and five gross (3.3 net) vertical wells. Our initial operational capital expenditure budget was established at $185 million and has been subsequently increased for the items below.

In the first half of 2014, we began testing larger horizontal well completion designs in an effort to improve production rates and the amount of recoverable resources. Based on satisfactory drilling, completion and well performance to date, we believe that our enhanced completion designs create the potential for increased total returns on capital after adjusting for incremental costs of approximately $0.5 million to $0.8 million per completion depending on the depth of the well. While we continue to monitor the effectiveness of our enhanced completion designs, we increased our 2014 operational budget to include the incremental change in costs for the completion designs by approximately $10 million for this initiative.

In addition, we recently commenced the drilling of a horizontal well in partnership with a large public company on our recently acquired acreage in Upton County. This non-operated well, in which we own a 57% working interest, is estimated to cost approximately $5.5 million on a net basis.

As discussed above, we signed an agreement for a drilling rig to be used in an expanded horizontal development program. We currently forecast that this initiative will add approximately $9 million to our initial operating capital expenditure budget in 2014.

The remaining difference, approximately $5.5 million, is primarily due to a higher number of scheduled completions resulting from modifications to our original drilling schedule. We currently intend to complete 26.7 net horizontal wells relative to 24.7 net wells in our previous forecast.

Third Quarter and Full Year 2014 Guidance

The following third quarter guidance assumes the drilling of eight gross (6.6 net) horizontal wells and the completion of seven gross (5.9 net) horizontal wells. Full year guidance, previously provided on May 8, 2014, has been updated for third quarter 2014 guidance and actual results for 2014 to date.








3rd Quarter 2014


Full Year






Total production (BOE/d)


5,450 - 5,650


5,250 - 5,350

% oil


79% - 81%


80% - 83%






Expenses (per BOE)





LOE, including workovers


$9.00 - $10.00


$9.00 - $10.00

Production taxes, including ad valorem


$4.50 - $4.75


$4.60 - $4.80

Adjusted G&A (a)


$9.25 - $10.25


$9.00 - $10.00

 

(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.

Listed below are the outstanding hedges for the second half of 2014 and calendar year 2015.










For the Six
Months Ending
December 31,


For the Year
Ending
December 31,

Oil contracts


2014


2015

Collar contracts combined with short puts (three-way collar):







   Volume (MBbls)



-



317

   Price per Bbl







      Ceiling (short call)



-


$

99.10

      Floor (long put)



-


$

90.00

      Short put



-


$

75.00

Swap contracts:







   Total volume (MBbls)



304



-

   Weighted average price per Bbl


$

95.10



-

Put spreads:







   Volume (MBbls)



-



276

   Long put price per Bbl



-


$

90.00

   Short put price per Bbl



-


$

75.00

Swap contracts combined with short put:







   Volume (MBbls)



184



-

   Swap price per Bbl


$

93.35



-

   Short put price per Bbl


$

70.00



-










For the Six
Months Ending
December 31,


For the Year
Ending
December 31,

Natural gas contracts


2014


2015

Call contracts:







   Volume (MMBtu)



230



-

      Short call price per MMBtu (a)


$

4.75



-

      Long call price per MMBtu (a)


$

4.75



-

Swap contracts combined with short calls:







   Swap volume (MMBtu)



368



-

   Swap price per MMBtu


$

4.25



-

   Short call volume (MMBtu)



-



438

   Short call price per MMBtu



-


$

5.00

 

(a)

Offsetting contracts.

 

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.
  • We believe that the non-GAAP measure of 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.
  • 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 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.

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













Three Months Ended



June 30, 2014


March 31, 2014


Change

Discretionary cash flow (a)


$

23,543


$

18,728


$

4,815

Net working capital changes and other changes



(7,913)



1,239



(9,152)

Net cash flow provided by operating activities (a)


$

15,630


$

19,967


$

(4,337)

 

(a)

Includes $1,443 and $26 of asset retirement obligations related to discontinued Gulf of Mexico operations in the three month periods ended June 30 and March, 2014, respectively.

 

 























Three Months Ended June 30,



Six Months Ended June 30,



2014


2013


Change


2014


2013


Change

Discretionary cash flow (a)


$

23,543


$

10,281


$

13,262


$

42,271


$

21,589


$

20,682

Net working capital changes and other changes



(7,913)



(2,919)



(4,994)



(6,674)



(1,352)



(5,322)

Net cash flow provided by operating activities (a)


$

15,630


$

7,362


$

8,268


$

35,597


$

20,237


$

15,360

 

(a)

Includes $1,443 and $1,469 of asset retirement obligations related to discontinued Gulf of Mexico operations in the three and six month periods ended June 30, 2014, respectively.

The following tables reconcile income (loss) available to common stockholders to Adjusted income (in thousands; reconciling items are reflected net of tax):














Three Months Ended June 30,



2014


2013


Change

Income available to common stockholders


$

2,767


$

78


$

2,689

Net (gain) loss on derivative contracts, net of settlements



1,975



(837)



2,813

Phantom stock mark-to-market, net of settlements



2,982



(427)



3,409

Withdrawn proxy contest expenses



85



-



85

Gain on early redemption of debt



(2,083)



-



(2,083)

Adjusted income (loss)


$

5,726


$

(1,186)


$

6,912

Adjusted income (loss) per fully diluted common share


$

0.14


$

(0.03)


$

0.17

 














Six Months Ended June 30,



2014


2013


Change

Income (loss) available to common stockholders


$

2,656


$

(722)


$

3,378

Net (gain) loss on derivative contracts, net of settlements



3,041



(161)



3,202

Phantom stock mark-to-market, net of settlements



4,707



(554)



5,261

Early retirement expense



1,601



-



1,601

Withdrawn proxy contest expenses



860



-



860

Gain on sale of equipment



(702)



-



(702)

Gain on early redemption of debt



(2,083)



-



(2,083)

Adjusted income (loss)


$

10,080


$

(1,437)


$

11,517

Adjusted income (loss) per fully diluted common share


$

0.24


$

(0.04)


$

0.28

The following tables reconcile net income (loss) to Adjusted EBITDA (in thousands) for the periods indicated:














Three Months Ended June 30,



2014


2013


Change

Net income


$

4,740


$

758


$

3,982

Net pre-tax adjustments to arrive at Adjusted income



4,551



(1,264)



5,815

Income tax expense



4,128



663



3,465

Interest expense



1,825



1,537



288

Depreciation, depletion and amortization



12,378



11,012



1,366

Accretion expense



173



533



(360)

Adjusted EBITDA


$

27,795


$

13,239


$

14,556

 














Six Months Ended June 30,



2014


2013


Change

Net income (loss)


$

6,603


$

(42)


$

6,645

Net pre-tax adjustments to arrive at Adjusted income



11,421



(1,100)



12,521

Income tax expense



5,469



494



4,975

Interest expense



2,802



3,052



(250)

Depreciation, depletion and amortization



22,976



22,405



571

Accretion expense



401



1,098



(697)

Adjusted EBITDA


$

49,672


$

25,907


$

23,765

The following tables reconcile total G&A to Adjusted G&A (in thousands) for the periods indicated:













Three Months Ended



June 30, 2014


March 31, 2014


Change

Total G&A


$

9,639


$

10,807


$

(1,168)

   Withdrawn proxy contest



(130)



(1,193)



1,063

   Accelerated vesting of outstanding equity awards for early retirement of employees



 

-



 

(2,463)



 

2,463

   Mark-to-market valuation adjustment of performance-based phantom stock incentive awards



 

(4,587)



 

(2,655)



 

(1,932)

Adjusted G&A


$

4,922


$

4,496


$

426

 













Three Months Ended June 30,



2014


2013


Change

Total G&A


$

9,639


$

4,545


$

5,094

   Withdrawn proxy contest



(130)



-



(130)

   Mark-to-market valuation adjustment of performance-based phantom stock incentive awards



(4,587)



657



(5,244)

Adjusted G&A


$

4,922


$

5,202


$

(280)

 













Six Months Ended June 30,



2014


2013


Change

Total G&A


$

20,446


$

8,284


$

12,162

   Withdrawn proxy contest



(1,323)



-



(1,323)

   Accelerated vesting of outstanding equity awards for early retirement of employees



(2,463)



-



(2,463)

   Mark-to-market valuation adjustment of performance-based phantom stock incentive awards



(7,242)



852



(8,094)

Adjusted G&A


$

9,418


$

9,136


$

282

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
















Three Months Ended June 30,



2014


2013


Change


% Change

Net production:












   Oil (MBbls)



405



198



207


105%

   Natural gas (MMcf)



452



787



(335)


(43)%

   Total production (MBOE)



480



329



151


46%

   Average daily production (BOE/d)



5,280



3,615



1,665


46%

   % oil (BOE basis)



84%



60%



-


-

Average realized sales price:












   Oil (Bbl)


$

93.10


$

96.27


$

(3.17)


(3)%

   Natural gas (Mcf) (includes NGLs)



6.17



4.70



1.47


31%

   Total (BOE)


$

84.30


$

69.18


$

15.12


22%

Oil and natural gas revenues (in thousands):












   Oil revenue


$

37,710


$

19,061


$

18,649


98%

   Natural gas revenue



2,792



3,699



(907)


(25)%

   Total


$

40,502


$

22,760


$

17,742


78%

Additional per BOE data:












   Sales price


$

84.30


$

69.18


$

15.12


22%

      Lease operating expense



9.08



15.98



(6.90)


(43)%

      Production taxes



4.71



2.47



2.24


91%

   Operating margin


$

70.50


$

50.73


$

19.77


39%

Other expenses per BOE:












Depletion, depreciation and amortization


$

24.96


$

32.38


$

(7.42)


(23)%

Adjusted G&A (a)



10.25



15.81



(5.56)


(35)%

 
















Six Months Ended June 30,



2014


2013


Change


% Change

Net production:












   Oil (MBbls)



737



404



333


82%

   Natural gas (MMcf)



816



1,525



(709)


(47)%

   Total production (MBOE)



873



658



215


33%

   Average daily production (BOE/d)



4,823



3,596



1,227


34%

   % oil (BOE basis)



84%



61%



-


-

Average realized sales price:












   Oil (Bbl)


$

93.11


$

95.55


$

(2.44)


(3)%

   Natural gas (Mcf) (includes NGLs)



6.34



4.39



1.95


44%

   Total (BOE)


$

84.53


$

68.85


$

15.68


23%

Oil and natural gas revenues (in thousands):












   Oil revenue


$

68,619


$

38,601


$

30,018


78%

   Natural gas revenue



5,168



6,700



(1,532)


(23)%

   Total


$

73,787


$

45,301


$

28,486


63%

Additional per BOE data:












   Sales price


$

84.53


$

68.85


$

15.68


23%

      Lease operating expense



9.84



16.47



(6.63)


(40)%

      Production taxes



4.79



2.32



2.47


107%

   Operating margin


$

69.90


$

50.06


$

19.84


40%

Other expenses per BOE:












Depletion, depreciation and amortization


$

25.79


$

32.97


$

(7.19)


(22)%

Adjusted G&A (a)



10.79



13.88



(3.09)


(22)%

 

(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.

 

Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)








June 30, 2014


December 31, 2013

ASSETS

Unaudited




Current assets:






Cash and cash equivalents

$

1,172


$

3,012

Accounts receivable


26,951



20,586

Deferred tax asset


5,846



3,843

Other current assets


1,798



2,123

Total current assets


35,767



29,564

Oil and natural gas properties, full cost accounting method:






Evaluated properties


1,844,691



1,701,577

Less accumulated depreciation, depletion and amortization


(1,444,169)



(1,420,612)

Net oil and natural gas properties


400,522



280,965

Unevaluated properties


36,957



43,222

Total oil and natural gas properties


437,479



324,187

Other property and equipment, net


7,388



7,255

Restricted investments


3,806



3,806

Deferred tax asset


50,421



57,765

Other assets, net


5,057



1,376

Total assets

$

539,918


$

423,953

LIABILITIES AND STOCKHOLDERS' EQUITY






Current liabilities:






Accounts payable and accrued liabilities

$

61,028


$

53,464

Market-based restricted stock unit awards


6,683



4,173

Asset retirement obligations


2,846



4,120

Fair value of derivatives


5,306



1,036

Total current liabilities


75,863



62,793

13% senior notes:






   Principal outstanding


-



48,481

   Deferred credit, net of accumulated amortization of $0 and $26,239, respectively


-



5,267

Total 13% senior notes


-



53,748

Senior secured revolving credit facility


84,000



22,000

Second lien term loan facility


82,500



-

Asset retirement obligations


2,752



2,612

Market-based restricted stock unit awards


10,717



3,409

Other long-term liabilities


1,497



297

Total liabilities


257,329



144,859

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 and 60,000,000 shares authorized; 40,785,751 and 40,345,456 shares outstanding, respectively


408



404

Capital in excess of par value


402,375



401,540

Accumulated deficit


(120,210)



(122,866)

Total stockholders' equity


282,589



279,094

Total liabilities and stockholders' equity

$

539,918


$

423,953

 

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
















Three Months Ended June 30,


Six Months Ended June 30,



2014


2013


2014


2013

Operating revenues:













   Oil sales


$

37,710


$

19,061


$

68,619


$

38,601

   Natural gas sales



2,792



3,699



5,168



6,700

Total operating revenues



40,502



22,760



73,787



45,301

Operating expenses:













   Lease operating expenses



4,363



5,259



8,593



10,836

   Production taxes



2,265



812



4,182



1,532

   Depreciation, depletion and amortization



11,982



10,654



22,520



21,696

   General and administrative



9,639



4,545



20,446



8,284

   Accretion expense



173



533



401



1,098

   Gain on sale of other property and equipment



-



-



(1,080)



-

Total operating expenses



28,422



21,803



55,062



43,446

   Income from operations



12,080



957



18,725



1,855

Other (income) expenses:













   Interest expense



1,825



1,537



2,802



3,052

   Gain on early extinguishment of debt



(3,205)



-



(3,205)



-

   Loss (gain) on derivative contracts



4,685



(1,981)



7,198



(1,563)

   Other (income) expense



(93)



(44)



(142)



(89)

Total other expenses



3,212



(488)



6,653



1,400

   Income before income taxes



8,868



1,445



12,072



455

      Income tax expense



4,128



663



5,469



494

      Income (loss) before equity in earnings of Medusa Spar  LLC



4,740



782



6,603



(39)

   Loss from Medusa Spar LLC



-



(24)



-



(3)

      Net income (loss)



4,740



758



6,603



(42)

      Preferred stock dividends



(1,973)



(680)



(3,947)



(680)

  Income (loss) available to common stockholders


$

2,767


$

78


$

2,656


$

(722)

  Income (loss) per common share:













   Basic


$

0.07


$

0.00


$

0.07


$

(0.02)

   Diluted


$

0.07


$

0.00


$

0.06


$

(0.02)

   Shares used in computing income (loss) per common share:













   Basic



40,606



40,089



40,467



39,941

   Diluted



41,605



40,323



41,652



39,941

 

Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)










Six Months Ended June 30,



2014


2013

Cash flows from operating activities:







Net income


$

6,603


$

(42)

Adjustments to reconcile net income to cash provided by operating activities:







   Depreciation, depletion and amortization



22,976



22,405

   Accretion expense



401



1,098

   Amortization of non-cash debt related items



298



228

   Amortization of deferred credit



(433)



(1,615)

   Equity in earnings of Medusa Spar LLC



-



3

   Deferred income tax expense



5,469



494

   Net loss (gain) on derivatives, net of settlements



4,677



(249)

   Gain on sale of other property and equipment



(1,080)



-

   Non-cash gain for early debt extinguishment



(3,205)



-

   Non-cash expense related to equity share-based awards



(36)



734

   Change in the fair value of liability share-based awards



8,070



(852)

   Payments to settle asset retirement obligations



(1,469)



(615)

   Changes in current assets and liabilities:







      Accounts receivable



(5,268)



789

      Other current assets



265



598

      Current liabilities



2,014



(324)

   Payments to settle vested liability share-based awards



(3,469)



(239)

   Change in other long-term liabilities



-



(386)

   Change in other assets, net



(216)



(1,790)

      Net cash provided by operating activities



35,597



20,237

Cash flows from investing activities:







Capital expenditures



(127,219)



(58,385)

Acquisition



-



(11,000)

Proceeds from sales of mineral interest and equipment



2,267



1,389

Distribution from Medusa Spar LLC



-



616

     Net cash used in investing activities



(124,952)



(67,380)

Cash flows from financing activities:







Borrowings on debt



150,000



31,000

Payment of deferred financing costs



(2,928)



-

Payments on debt



(55,610)



(41,000)

Issuance of preferred stock



-



70,090

Payment of preferred stock dividends



(3,947)



(680)

      Net cash provided by financing activities



87,515



59,410

Net change in cash and cash equivalents



(1,840)



12,267

   Balance, beginning of period



3,012



1,139

   Balance, end of period


$

1,172


$

13,406

Earnings Call Information

The Company will host a conference call on Thursday, August 7, 2014 to discuss second quarter financial and operating results.

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

Date/Time:

Thursday, August 7, 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:

1-877-415-3183

International Call-in Number:

1-857-244-7326

Participant Passcode:

51538939

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, the Company's 2014 and 2015 guidance, capital budget, 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
Chief Financial Officer, Senior Vice President and Treasurer
1-800-451-1294 

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