Callon Petroleum Company : Callon Petroleum Company Reports Full Year And Fourth Quarter 2012 Results, Announces 2013 Capital

  Callon Petroleum Company : Callon Petroleum Company Reports Full Year And
   Fourth Quarter 2012 Results, Announces 2013 Capital Budget And Provides
                              Operational Update

Natchez, MS (March14, 2013) - Callon Petroleum Company (NYSE: CPE)  ("Callon" 
or the "Company") today reported results of operations for the three-month and
12-month periods ended December31, 2012.

The Company highlighted full-year 2012 and recent operational activity:

  oIncreased Permian production by 67% and Permian proved reserves by 24%
    over 2011.
  oReplaced 222% of its total 2012 production from additions of Permian
    reserves.
  oContinued strong performance from its horizontal Wolfcamp B wells in Upton
    county, with average production of 390 Boe per day per well over the first
    five months of production, excluding downtime.
  oSignificant improvement in drilling efficiency for long-lateral horizontal
    wells, completing the drilling of its last three horizontal Wolfcamp wells
    in an average 21 days.

Callon also highlighted financial results for the fourth quarter of 2012:

  oRevenue of $28.7 million from daily production of 4,457 barrels of oil
    equivalent ("Boe") of production, or $69.94 per Boe produced.
  oFully diluted net loss of $(0.01) per share, which includes a $0.3 million
    charge related to a non-cash, mark-to-market of the Company's derivative
    positions and a $1.2 million impairment related to acquired assets.
  oDiscretionary cash flow, a non-GAAP financial measure, of $0.42 per
    diluted share. See "Non-GAAP Financial Measures" discussed and reconciled
    below.

Fred Callon, Chairman and CEO  commented, "Our Permian operations continue  to 
deliver growth in both  reserves and production, and  are positioned to  drive 
growth in total Company metrics. We will be focusing on program development of
our de-risked, horizontal locations in the  southern Midland basin in 2013  to 
deliver repeatable growth following a year of resource capture and  evaluation 
in 2012. In  addition, we  will be  optimizing our  vertical drilling  program 
through the  targeting  of  additional deeper  zones  that  have  demonstrated 
encouraging production  results.  Our  continued evaluation  of  our  northern 
Midland assets will continue in parallel  with this base level of activity  as 
we finalize our plans for additional drilling in this area."

Operational Update

Southern  Midland.  The  Company  continues  to  execute  on  the   horizontal 
development of its southern Midland basin acreage position following  drilling 
success in 2012. Callon  is building upon the  strong production results  from 
its first two horizontal, Wolfcamp B shale wells at its East Bloxom field  and 
has commenced  program development  of the  area utilizing  pad drilling  with 
planned batch completions  also starting  in 2013. The  Company drilled  three 
horizontal Wolfcamp shale  wells from  a single pad  in the  first quarter  of 
2013, with two  targeting the  Wolfcamp B and  one targeting  the Wolfcamp  A. 
These wells were drilled in an average of 21 days and are expected to carry  a 
total cost of $6.5 million per well once they are completed.

Callon is extending its horizontal Wolfcamp development program to the  Taylor 
Draw field in southern  Reagan county where  it is in  the process of  flowing 
back the  Pembrook 9121  #1H. In  addition, the  Company's horizontal  rig  is 
currently drilling a four-well  package from a single  pad at this field.  All 
five of these wells are targeting the Wolfcamp B shale.

The Company's 2013  vertical drilling program  is set to  resume at the  Pecan 
Acres field where its three recent  wells have produced at an average  initial 
rate of  224 Boe  per day  and an  average 30-day  rate of  166 Boe  per  day. 
Separately, Callon's tests  of deep zones,  below the Atoka  to the  Woodford, 
have demonstrated  encouraging results,  with incremental  initial  production 
rates of approximately 100 Boe per day from these isolated zones. These deeper
targets will be included in  Callon's ongoing vertical development efforts  in 
the Pecan Acres and Carpe Diem fields in Midland county. Given recent reported
results from offsetting  horizontal Wolfcamp wells,  which confirmed  Callon's 
technical interpretation  of this  area, the  Company is  advancing plans  for 
horizontal development of these two fields.

Northern Midland. Callon  has drilled  two horizontal wells  and one  vertical 
well to  date in  Borden county  as part  of its  initial evaluation  of  this 
contiguous leasehold position of over 14,650 net acres.

The first exploration well targeting the  Cline shale, the Vickie Newton  3801 
#1H, produced  a cumulative  1,232 barrels  of oil,  with a  peak rate  of  97 
barrels of oil per day, and  has been temporarily abandoned. The Company  will 
continue to monitor industry activity for new technical data that may  benefit 
future evaluation efforts before additional exploration drilling of the  Cline 
shale is pursued. This activity includes  two horizontal Cline shale wells  in 
the process of drilling approximately 10 miles south of the Company's  acreage 
position.

Callon's second horizontal  exploration well  in Borden  county targeting  the 
Mississippian lime,  the Shirly  Newton 2301  #1H, is  currently flowing  back 
after a delay in the completion  process caused by stuck coiled tubing  during 
the drill-out of plugs after  stimulation. The well is producing  hydrocarbons 
and continues to  clean-up during  the early stages  of flow-back  operations. 
Callon will continue to evaluate the results of this well and ongoing industry
activity on  offsetting acreage  as it  develops its  drilling plans  for  the 
Mississippian lime in the second half of 2013.

The Company is  finalizing the  completion design for  a multi-stage  fracture 
stimulation of  the vertical  well that  was drilled  in late  2012 in  Borden 
County to test  several prospective  zones and to  provide core  data for  the 
area. Based on the production results from this well, the Shirly Newton  4801, 
Callon should  be positioned  to assess  the potential  for expanded  vertical 
development of its Borden county acreage.  In addition, the Company has  begun 
the assessment of its acreage in Lynn  County as part of its ongoing  drilling 
and evaluation program in the northern Midland basin.

Deepwater Gulf of  Mexico. Following  the closing of  the sale  of its  11.25% 
working interest in the  Habanero field, the  Company's remaining position  in 
the deepwater Gulf of Mexico  is a 15% working  interest in the Medusa  field. 
Following several months of partner discussions and technical evaluation,  the 
operator has sanctioned a subsea development program that is targeted to begin
by early 2014. Callon has  begun to fund long-lead  time items related to  the 
development and will  have the option  to participate  in all or  part of  the 
program once the drilling  schedule is confirmed and  total program costs  are 
finalized.

2012 Estimated  Proved Reserves.  The Company  ended 2012  with estimated  net 
proved reserves of 14,072 MBoe, representing a 12% decrease over 2011 year-end
estimated net proved reserves of 15,928 MBoe.The decrease is primarily due to
the sale of the Company's interest in the Habanero field (1,372 Mboe) and  the 
downward revision of Haynesville shale undeveloped reserves at year-end  2012 
(1,813 Mboe),  which  were  reduced  due to  low  natural  gas  prices.  These 
decreases were partially offset by the  Company's development of a portion  of 
its Permian basin, on which it proved up a total of 26 oil wells during  2012 
and added 3,194 MBoe of proved reserves.

                                                 MBoe
Total proved reserves at December 31, 2011     15,928
Less Habanero reserves                         (1,372 )
Adjusted proved reserves at December 31, 2011  14,556
Purchase of reserves in place                      57
Extensions and discoveries                      3,194
Revisions of Haynesville natural gas reserves  (1,813 )
Revisions, other                                 (481 )
Production (excluding Habanero production)     (1,441 )
Total proved reserves at December 31, 2012     14,072

The benchmark prices for 2012, using SEC guidelines, were $94.74 per barrel of
oil  and  $2.76  per  MMBtu  of   natural  gas.  After  adjusting  for   basis 
differentials and  natural gas  Btu content,  the Company's  average  realized 
prices over the remaining life of  the proved reserves were $94.68 per  barrel 
of oil and  $4.81 per Mcf  of natural gas  for year-end 2012,  as compared  to 
$98.98 per barrel of oil and $5.60  per Mcf of natural gas for year-end  2011. 
The commodity prices reflected above for  2012 resulted in a present value  of 
pre-tax future net cash  flows discounted at 10%  (PV-10) of $250 million  for 
the Company's  proved reserves,  compared to  $310 million  at year-end  2011. 
PV-10 is a non-GAAP measure. See  "Non-GAAP Financial Measures" below for  the 
Company's definition and reconciliation of  PV-10 to the Standardized  Measure 
(GAAP).

Financial Update

Total revenue for  the fourth quarter  of 2012 was  $28.7 million compared  to 
$31.8 million for the fourth quarter of 2011, a decrease of 10%. Total revenue
for the full year 2012 was $110.7 million compared to $127.6 million in  2011. 
This year-over-year decrease  was due to  a decrease in  commodity prices  and 
production downtime  primarily  at  our two  deepwater  fields,  Habanero  and 
Medusa, as well as our Haynesville  well. Production declines were offset  by 
production from our new Permian wells, 22 vertical and two horizontal, brought
onto production during 2012.

Lease operating expenses, including production taxes, gathering and ad valorem
taxes, for the fourth quarter of 2012 totaled $6.1 million, or $14.85 per Boe,
a 58% increase per Boe over the fourth quarter of 2011 of $9.40 per Boe. Lease
operating expenses for the full year 2012 totaled $26.6 million, or $16.86 per
Boe, a 53% increase per  Boe over the full year  2011 of $11.04 per Boe.  This 
year-over-year increase was primarily due to significant growth in the  number 
of wells now producing in our Permian basin properties as well as  remediation 
work performed during 2012 on our Haynesville well as a result of interference
from the fracture stimulation of an offset well.

Depreciation, depletion  and  amortization  for the  fourth  quarter  of  2012 
totaled $13.7 million, or $33.42 per Boe, compared to $13.0 million, or $30.28
per  Boe,  in  the  fourth  quarter  of  2011.  Depreciation,  depletion   and 
amortization for the full year 2012 totaled $49.7 million, or $31.56 per  Boe, 
compared to $48.7 million, or $26.42 per Boe, for the full year 2011. The $1.0
million increase in  DD&A expense  for the year  ended December  31, 2012  was 
primarily a result of planned exploration and development expenditures related
to our onshore reserve development in the Permian basin area.

General and administrative  expenses for  the fourth quarter  of 2012  totaled 
$4.5 million, or $11.00 per Boe, compared to $5.1 million, or $12.03 per  Boe, 
in the fourth  quarter of 2011.  General and administrative  expenses for  the 
full year 2012 totaled  to $20.4 million,  or $12.93 per  Boe, as compared  to 
$16.6 million, or $9.03 per Boe, for the full year 2011. Of this $3.7  million 
year-over-year increase,  $1.6  million  was  due  to  non-recurring  employee 
expenses including early retirement and severance expense for which we had  no 
expense during  2011.  Additionally,  we incurred  an  increase  in  non-cash 
charges  of  $1.2  million  related  to  incentive  compensation   share-based 
instruments awarded during 2012. The remaining increase relates primarily to
higher compensation-related  expenses  including  the  costs  associated  with 
hiring staff to support our onshore growth and 100%-operated Permian position,
as well as relocation and related costs.

As a result  of its  derivative activities, the  Company incurred  a net  cash 
settlement gain of $0.7 million in the fourth quarter of 2012. As a result  of 
forward oil and  natural gas  price changes, the  Company recognized  non-cash 
unrealized mark-to-market derivative  losses of  $0.3 million  for the  fourth 
quarter of  2012. The  Company realized  a net  cash settlement  gain of  $1.5 
million for the  year ended December  31, 2012.  In addition, as  a result  of 
forward oil and  natural gas  price changes, the  Company recognized  non-cash 
unrealized mark-to-market derivative  gains of  $1.7 million  during the  year 
ended December  31, 2012.  As  previously announced,  the Company  elected  to 
discontinue hedge accounting for its  derivative contracts beginning with  all 
agreements executed subsequent  to December  31, 2011, resulting  in both  the 
realized and unrealized components of its derivative activity being recognized
in current earnings. Prior to 2012, the Company's unrealized gains and  losses 
associated with its derivative contracts,  which were designated as cash  flow 
hedges, were recorded as a component of comprehensive income.

Discretionary cash flow (non-GAAP)  for the fourth quarter  of 2012 was  $16.9 
million, a decrease of $4.4 million, or  21%, over the fourth quarter of  2011 
of $21.3 million. Discretionary  cash flow (non-GAAP) for  the full year  2012 
was $55.5 million, a  decrease of $22.8  million, or 29%,  over the full  year 
2011 of  $78.3  million. For  a  definition  of discretionary  cash  flow  and 
reconciliation to  net  cash  flow provided  from  operating  activities,  see 
"Non-GAAP Financial Measures" below.

The Company reported a net loss of $0.4 million in the fourth quarter of  2012 
compared to net income of $74.0 million in the fourth quarter of 2011. For the
full year 2012, the  Company reported net income  of $2.7 million compared  to 
net income  of  $106.4  million for  the  full  year 2011.  The  2011  results 
benefited from the  full reversal of  a $69.3 million  deferred tax  valuation 
allowance. Excluding  certain non-cash  items  and their  tax effect  in  the 
fourth quarters of  2012 and  2011, adjusted  net income  (non-GAAP) was  $0.5 
million, or $0.01 per diluted share,  and $73.9 million, or $1.85 per  diluted 
share, respectively. Excluding certain non-cash items and their tax effect for
the years ending December  31, 2012 and 2011,  adjusted net income  (non-GAAP) 
was $1.5 million, or $0.04 per diluted share, and $101.9 million, or $2.64 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" below.

2012 Capital Expenditures and 2013 Capital Budget

Callon's total capital expenditures for the twelve months ended December 31,
2012 were $146.5 million and included the following amounts (in millions):

Southern Midland basin                                                $  70.3
Northern Midland basin                                                   21.4
Leasehold acquisitions and seismic                                       37.2
Plugging and abandonment costs in the Gulf of Mexico                      2.3
Capitalized interest                                                      2.0
Capitalized general and administrative costs allocated directly to
exploration and development projects                                     13.3
Total capital expenditures                                            $ 146.5

The following table summarizes drilled and completed wells through December
31, 2012:

               Property                   Drilling     Completion
                                         Gross   Net   Gross   Net
Southern Midland basin vertical wells      15   10.7     22   16.0
Southern Midland basin horizontal wells     3    2.8      2    2.0
Total                                      18   13.5     24   18.0
               Property                   Drilling     Completion
                                         Gross   Net   Gross   Net
Northern Midland basin vertical wells       1    0.8      -      -
Northern Midland basin horizontal wells     2    1.8      1    1.0
Total                                       3    2.6      1    1.0

Our 2013 capital budget has been established at $125 million with over 90%  of 
our  budgeted   operating   expenditures  (including   drilling,   completion, 
infrastructure, and plugging and abandonment)  allocated to our Midland  basin 
operations. The 15% decrease in total  capital from 2011 reflects our  primary 
focus on drilling and completion activities  in the Permian basin and  reduced 
emphasis on acreage  acquisitions that  were budgeted  in 2012  to expand  the 
Company's presence in the basin.  Our budget includes further exploration  and 
development  of  our   Permian  basin  properties   with  plans  to   complete 
approximately 26 gross  wells including  14 horizontal wells  and 12  vertical 
wells. Components of the 2013 capital budget include (in millions):

Midland basin                                $  97
Gulf of Mexico                                  10
Total projected operations budget              107
Capitalized general and administrative costs    14
Capitalized interest and other                   4
Total projected capital expenditures budget  $ 125

Liquidity and Hedging Update

At December31, 2012 the Company's liquidity was $56.1 million comprised of  a 
cash balance of  $1.1 million and  available borrowing base  of $55.0  million 
under its revolving credit  facility. On June 20,  2012, the credit  facility 
was increased to $200 million with an associated borrowing base of $60 million
and a maturity of  July 31, 2014. Subsequently,  in October 2012, the  credit 
facility was further amended to increase the borrowing base to $80 million and
extend the maturity to March 15, 2016. The lending group was also expanded  to 
five financial institutions at that time.  Following the sale of our  interest 
in the deepwater Habanero field, the borrowing base was revised to $65 million
as of December 31, 2012. The borrowing  base is scheduled to be reviewed  and 
re-determined in April 2013.

Subsequent to  December  31, 2012,  the  Company restructured  its  crude  oil 
collars covering  40,000 barrels  per month  for the  year 2013,  starting  in 
February 2013. As a result of this transaction, the Company has hedged  40,000 
barrels per month for 2013 under a fixed price swap set at $101.30 per  barrel 
(NYMEX). In addition, the Company has hedged 30,000 barrels per month for 2014
under a fixed price swap  set at $93.35 per  barrel (NYMEX). The Company  also 
sold a crude oil put at $70 per  barrel for 30,000 barrels per month for  2014 
as part of the oil hedge program restructuring.

Earnings Call Information

The Company will host a conference call on Friday, March 15, 2013 to discuss
fourth quarter and full year 2012 financial and operating results. Management
will also provide an operational update, and discuss its outlook for 2013
during the call.

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

Date/Time: Friday, March 15, 2013, at 10:00 a. m. Central Time
(11:00 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," "PV-10 value" and "adjusted net income."

  oCallon 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.
  oAdjusted net income and adjusted net income per diluted share, which
    excludes (1) impairments, (2) unrealized (gain) loss on 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.
  oPV-10 value is the present value of future net pre-tax cash flows
    attributable to estimated net proved reserves, discounted at 10% per
    annum. PV-10 value is computed on the same basis as standardized measure,
    a GAAP financial measure, but does not include a provision for future
    income taxes. We believe PV-10 value to be an important measure for
    evaluating the relative significance of our oil and gas properties,
    because it excludes income taxes which may vary materially among
    companies. PV-10 is not, however, a substitute for standardized measure.

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.

Reconciliation of Non-GAAP Financial Measures:

The following table reconciles the PV-10 value to the standardized measure (in
thousands):

                         2012         2011       $ Change    % Change
PV-10 Value           $ 250,097    $ 309,890    $ (59,793 )   (19 )%
Future income taxes     (18,949 )    (39,533 )     20,584      52 %
Standardized measure  $ 231,148    $ 270,357    $ (39,209 )   (15 )%

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

                      Three Months Ended                  Twelve Months Ended
                         December 31,                         December 31,
                 2012        2011       Change        2012       2011       Change
Discretionary
cash flow     $ 16,891    $ 21,313    $  (4,422 )  $ 55,486    $ 78,309   $ (22,823 )
Net working
capital
changes and
other changes   (6,986 )       (75 )     (6,911 )    (4,196 )       858      (5,054 )
Net cash flow
provided by
operating
activities    $  9,905    $ 21,238    $ (11,333 )  $ 51,290    $ 79,167   $ (27,877 )

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

                            For the Three Months Ended    For the Year Ended
                                   December 31,              December 31,
                                2012          2011        2012        2011
Net (loss) income
available to common shares  $    (435 )   $   73,951    $ 2,747    $ 106,396
Less: Unrealized
derivative gains                  169              -     (1,116 )          -
Less: Gain on early
redemption of debt                  -              -       (888 )     (1,262 )
Plus: Impairment (gain)
related to acquired assets        765            (10 )      765       (3,277 )
Adjusted net income         $     499     $   73,941    $ 1,508    $ 101,857
Adjusted net income fully
diluted earnings per share  $    0.01     $     1.85    $  0.04    $    2.64

The following tables present summary information for the three and
twelve-month periods ended December31, 2012, and are followed by the
Company's financial statements.

                                      Three Months Ended December 31,
                                     2012        2011       Change    % Change
Net production:
Crude oil (MBbls)                      261         250          11       4 %
Natural gas (MMcf)                     893       1,067        (174 )   (16 )%
Total production (MBoe)                410         428         (18 )    (4 )%
Average daily production (Boe)       4,457       4,652        (195 )    (4 )%
Average realized sales price:
Crude oil (Bbl)                   $  94.63    $ 105.96    $ (11.33 )   (11 )%
Natural gas (Mcf)                     4.45        4.95       (0.50 )   (10 )%
Total (Boe)                          69.94       74.33       (4.39 )    (6 )%
Crude oil and natural gas
revenues (in thousands):
Crude oil revenue                 $ 24,701    $ 26,534    $ (1,833 )    (7 )%
Natural gas revenue                  3,975       5,278      (1,303 )   (25 )%
Total                             $ 28,676    $ 31,812    $ (3,136 )   (10 )%
Additional per Boe data:
Sales price                       $  69.94    $  74.33    $  (4.39 )    (6 )%
Lease operating expense             (14.85 )     (9.40 )     (5.45 )   (58 )%
Operating margin                  $  55.09    $  64.93    $  (9.84 )   (15 )%
Other expenses per Boe:
Depletion, depreciation and
amortization                      $  33.42    $  30.28    $   3.14      10 %
General and administrative (net
of management fees)                  11.00       12.03       (1.03 )    (9 )%

                                For the Year Ended December 31,
                           2012            2011           Change      % Change
Net production:
Crude oil (MBbls)             977             996             (19 )     (2 )%
Natural gas (MMcf)          3,588           5,081          (1,493 )    (29 )%
Total production
(MBoe)                      1,575           1,843            (268 )    (15 )%
Average daily
production (Boe/d)          4,303           5,049            (746 )    (15 )%
Average realized
sales price (a):
Crude oil (Bbl)       $     98.86     $    101.34     $     (2.48 )     (2 )%
Natural gas (Mcf)            3.94            5.25           (1.31 )    (25 )%
Total (Boe)                 70.31           69.26            1.05        2 %
Crude oil and natural
gas revenues (in
thousands):
Crude oil revenue     $    96,584     $   100,962     $    (4,378 )     (4 )%
Natural gas revenue        14,149          26,682         (12,533 )    (47 )%
Total                 $   110,733     $   127,644     $   (16,911 )    (13 )%
Additional per Boe
data:
Sales price           $     70.31     $     69.26     $      1.05        2 %
Lease operating
expense                    (16.86 )        (11.04 )         (5.82 )    (53 )%
Operating margin      $     53.45     $     58.22     $     (4.77 )     (8 )%
Other expenses per
Boe:
Depletion,
depreciation and                                                        19 %
amortization          $     31.56     $     26.42     $      5.14
General and
administrative (net
of management fees)         12.93            9.03            3.90       43 %
(a) Below is a reconciliation of the average NYMEX price to the average
realized sales price per Bbl of oil and price per Mcf of natural gas:
Average NYMEX oil
price ($/Bbl)         $     94.19     $     95.14     $     (0.95 )     (1 )%
Basis differential
and quality
adjustments                  3.97            7.58           (3.61 )    (48 )%
Transportation              (0.75 )         (1.00 )          0.25       25 %
Hedging                      1.45           (0.38 )          1.83      482 %
Average realized oil
price ($/Bbl)         $     98.86     $    101.34     $     (2.48 )     (2 )%
Average NYMEX gas
price ($/MMBtu)       $      2.82     $      4.03     $     (1.21 )    (30 )%
Basis differential
and quality
adjustments                  1.12            1.22           (0.10 )     (8 )%
Average realized gas
price ($/Mcf)         $      3.94     $      5.25     $     (1.31 )    (25 )%

                           CALLON PETROLEUM COMPANY
                         CONSOLIDATED BALANCE SHEETS
                      (In thousands, except share data)
                                                           December 31,
                                                        2012          2011
ASSETS
Current assets:
Cash and cash equivalents                           $    1,139    $   43,795
Accounts receivable                                     15,608        15,181
Fair market value of derivatives                         1,674         2,499
Other current assets                                     1,502         1,601
Total current assets                                    19,923        63,076
Crude oil and natural gas properties, full-cost
accounting method:
Evaluated properties                                 1,497,010     1,421,640
Less accumulated depreciation, depletion and
amortization                                        (1,296,265 )  (1,208,331 )
Net oil and natural gas properties                     200,745       213,309
Unevaluated properties excluded from amortization       68,776         2,603
Total oil and natural gas properties                   269,521       215,912
Other property and equipment, net                       10,058        10,512
Restricted investments                                   3,798         3,790
Investment in Medusa Spar LLC                            8,568         9,956
Deferred tax asset                                      64,383        65,743
Other assets, net                                        1,922           718
Total assets                                        $  378,173    $  369,707
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities            $   36,016    $   26,057
Asset retirement obligations                             2,336         1,260
Fair market value of derivatives                           125             -
Total current liabilities                               38,477        27,317
13% Senior Notes:
Principal outstanding                                   96,961       106,961
Deferred credit, net of accumulated amortization of
$17,800 and $13,123, respectively                       13,707        18,384
Total 13% Senior Notes                                 110,668       125,345
Senior secured revolving credit facility                10,000             -
Asset retirement obligations                            10,965        12,678
Other long-term liabilities                              2,092         3,165
Total liabilities                                      172,202       168,505
Stockholders' equity:
Preferred Stock, $.01 par value, 2,500,000 shares
authorized;                                                  -             -
Common Stock, $.01 par value, 60,000,000 shares
authorized; 39,800,548 and 39,398,416 shares
outstanding at December 31, 2012 and 2011,
respectively                                               398           394
Capital in excess of par value                         328,116       324,474
Other comprehensive income                                   -         1,624
Retained deficit                                      (122,543 )    (125,290 )
Total stockholders' equity                             205,971       201,202
Total liabilities and stockholders' equity          $  378,173    $  369,707

                           CALLON PETROLEUM COMPANY
                    CONSOLIDATED STATEMENTS OF OPERATIONS
                   (In thousands, except per share amounts)
                                               For the year ended December 31,
                                                    2012             2011
Operating revenues:
Crude oil sales                                $     96,584     $   100,962
Natural gas sales                                    14,149          26,682
Total operating revenues                            110,733         127,644
Operating expenses:
Lease operating expenses                             26,554          20,347
Depreciation, depletion and amortization             49,701          48,701
General and administrative                           20,358          16,636
Accretion expense                                     2,253           2,338
Impairment of other property and equipment            1,177               -
Total operating expenses                            100,043          88,022
Income from operations                               10,690          39,622
Other (income) expenses:
Interest expense                                      9,108          11,717
Gain on early extinguishment of debt                 (1,366 )        (1,942 )
Gain on acquired assets                                   -          (5,041 )
Gain on derivative contracts                         (1,717 )             -
Other income, net                                       (79 )        (1,426 )
Total other expenses, net                             5,946           3,308
Income before income taxes                            4,744          36,314
Income tax expense (benefit)                          2,223         (69,283 )
Income before equity in earnings of Medusa
Spar LLC                                              2,521         105,597
Equity in earnings of Medusa Spar LLC                   226             799
Net income available to common shares          $      2,747     $   106,396
Net income per common share:
Basic                                          $       0.07     $      2.81
Diluted                                        $       0.07     $      2.76
Shares used in computing net income per common
share:
Basic                                                39,522          37,908
Diluted                                              40,337          38,582

                           CALLON PETROLEUM COMPANY
                    CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (In thousands)
                                               For the year ended December 31,
                                                    2012             2011
Cash flows from operating activities:
Net income                                     $      2,747     $   106,396
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion and amortization             51,043          49,753
Accretion expense                                     2,253           2,338
Amortization of non-cash debt related items             402             461
Amortization of deferred credit                      (3,086 )        (3,155 )
Equity in earnings of Medusa Spar LLC                  (226 )          (799 )
Deferred income tax expense                           2,223          10,928
Valuation allowance                                       -         (80,211 )
Unrealized gain on derivative contracts              (1,683 )             -
Impairment of other property and equipment            1,176               -
Gain on acquired assets                                   -          (4,995 )
Non-cash gain for early debt extinguishment          (1,366 )        (1,942 )
Non-cash expense related to equity share-based
awards                                                1,697           1,337
Change in the fair value of liability
share-based awards                                    1,620             761
Payments to settle asset retirement
obligations                                          (1,314 )        (2,563 )
Changes in current assets and liabilities:
Accounts receivable                                    (883 )        (3,734 )
Other current assets                                    100             180
Current liabilities                                   1,753           4,695
Payments to settle vested liability
share-based awards                                   (3,383 )             -
Change in natural gas balancing receivable               51             252
Change in natural gas balancing payable                (102 )          (115 )
Change in other long-term liabilities                   205             100
Change in other assets, net                          (1,937 )          (520 )
Cash provided by operating activities          $     51,290     $    79,167
Cash flows from investing activities:
Capital expenditures                               (133,299 )      (100,243 )
Acquisitions                                         (2,075 )             -
Proceeds from sale of mineral interests and
equipment                                            39,936           7,615
Investment in restricted assets related to
plugging and abandonment                                  -            (150 )
Distribution from Medusa Spar LLC                     1,735           1,267
Cash used in investing activities              $    (93,703 )   $   (91,511 )
Cash flows from financing activities:
Borrowings on senior secured revolving credit
facility                                             53,000               -
Payments on senior secured revolving credit
facility                                            (43,000 )             -
Redemption of 13% senior notes                      (10,225 )       (35,062 )
Issuance of common stock                                  -          73,765
Taxes paid related to exercise of employee
stock options                                           (18 )             -
Cash (used in) provided by financing
activities                                     $       (243 )   $    38,703
Net change in cash and cash equivalents             (42,656 )        26,359
Cash and cash equivalents:
Balance, beginning of period                         43,795          17,436
Balance, end of period                         $      1,139     $    43,795

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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Source: Callon Petroleum Company via Thomson Reuters ONE
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