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SandRidge Energy, Inc. Reports Financial and Operational Results for Third Quarter and First Nine Months of 2013

  SandRidge Energy, Inc. Reports Financial and Operational Results for Third
                    Quarter and First Nine Months of 2013

Increases 2013 Production Guidance by 300 MBoe to 33.6 MMBoe

Mississippian Production Averaged 47.9 MBoe per Day in the Third Quarter, a
59% Increase Year-Over-Year

Decreased Mississippian Lease Operating Expense to $7.02 per Boe in the Third
Quarter, a 22% Decrease Year-Over-Year

Delivered 104 Mississippian Wells with an Average 30-day IP of 307 Boe per Day
during the Third Quarter, YTD Average 30-day IP of 339 Boe per Day

Initiated Development of Chester and Stacked Mississippian Formations

Issues 2014 Guidance

- Estimated 2014 Total Production of 36.3 MMBoe, 12% Organic Growth

- Estimated Mississippian Production of 22.8 MMBoe, 35% Growth

- Planned Capital Expenditures of $1.5 Billion

PR Newswire

OKLAHOMA CITY, Nov. 5, 2013

OKLAHOMA CITY, Nov. 5, 2013 /PRNewswire/ -- SandRidge Energy, Inc. (NYSE: SD)
today reported financial and operational results for the quarter and nine
months ended September 30, 2013 andprovided an update on the execution of its
2013 development plan.

(Logo: http://photos.prnewswire.com/prnh/20120416/DA88110LOGO)

James Bennett, SandRidge's Chief Executive Officer and President, commented,
"Over the last couple of quarters, we have pursued several key themes
operationally – being more efficient with our capital, consistent
Mississippian production growth, reducing our costs, and identifying new
opportunities. We believe we are hitting the mark on all of these. Through
successful high grading efforts and operational improvements, we have
increased Mississippian production from the second quarter even while reducing
our rig count by 15%, again delivering more production for less capital. As a
result, we are increasing full year production guidance for the second quarter
in a row without increasing budgeted capital expenditures and while continuing
to lower other expenses. As our Mississippian rig count ramps back up over the
next few quarters, we are confident that we will be able to grow production
there by approximately 35% in 2014, which will contribute to 12%
year-over-year organic growth for the company and tangible organic cash flow
growth. Finally, the inventory of new opportunities within our Mid-Continent
asset base continues to expand as we identify new formations and stacked pays
and see encouraging results in our appraisal areas."

Key Financial Results

Third Quarter

  oAdjusted EBITDA of $252 million for third quarter 2013 compared to $297
    million in third quarter 2012. Pro forma for the sale of the company's
    Permian assets in the first quarter of 2013, adjusted EBITDA was $182
    million for third quarter 2012.
  oAdjusted operating cash flow of $235 million for third quarter 2013
    compared to $281 million in third quarter 2012.
  oNet loss applicable to common stockholders of $87 million, or $0.18 per
    diluted share, for third quarter 2013 compared to net loss applicable to
    common stockholders of $184 million, or $0.39 per diluted share, in third
    quarter 2012.
  oAdjusted net income of $40.4 million, or $0.07 per diluted share, for
    third quarter 2013 compared to adjusted net income of $29.6 million, or
    $0.05 per diluted share, in third quarter 2012.

Nine Months

  oAdjusted EBITDA of $790 million for the first nine months of 2013 compared
    to $752 million in the first nine months of 2012. Pro forma for
    acquisitions and divestitures, adjusted EBITDA was $740 million for the
    first nine months of 2013 compared to $522 million in the first nine
    months of 2012.
  oAdjusted operating cash flow of $593 million for the first nine months of
    2013 compared to $655 million in the first nine months of 2012.
  oNet loss applicable to common stockholders of $615 million, or $1.28 per
    diluted share, for the first nine months of 2013 compared to net income
    available to common stockholders of $388 million, or $0.80 per diluted
    share, in the first nine months of 2012.
  oAdjusted net income of $89.3 million, or $0.16 per diluted share, for the
    first nine months of 2013 compared to adjusted net income of $87.6
    million, or $0.16 per diluted share, in the first nine months of 2012.

Adjusted net income, adjusted EBITDA and adjusted operating cash flow are
non-GAAP financial measures. Each measure is defined and reconciled to the
most directly comparable GAAP measure under "Non-GAAP Financial Measures"
beginning on page 12.

Highlights

Mississippian Development Program

  oMississippian production averaged 47.9 MBoe per day in the third quarter,
    a 1% sequential increase, and a 59% increase year-over-year
  oOperated an average of 22 rigs in the third quarter, 15% fewer rigs than
    in the second quarter, and 31% fewer rigs than in the first quarter
  oDeferred 12 high volume wells in the third quarter due to production
    outperforming gas infrastructure capacity. An accelerated take-away
    project was placed in operation on October 22, 2013. Of the 12 deferred
    wells, four were put to sales after the project was complete, currently
    delivering an average per well rate of895 Boe per day (48% oil). The
    eight remaining wells are scheduled to come on line over the next few
    months

Multi-pay Initiatives

  o53 Middle Mississippian wells drilled YTD have delivered an average 30-day
    IP of 363 Boe per day
  oFour Horizontal Chester wells drilled YTD have delivered an average 30-day
    IP of 274 Boe per day, supporting additional horizontal Chester
    development in 2014
  oFive Lower Mississippian wells drilled YTD have delivered an average
    30-day IP of 240 Boe per day
  oSame section test wells in the Upper and Lower Mississippian formations
    outperformed expectations in Harper County, Kansas. The Upper well
    delivered a 30-day IP of 456 Boe per day, and the Lower well delivered a
    30-day IP of 319 Boe per day. Multiple offsetting wells are scheduled for
    2014
  oLaunched a multi-section development of stacked Mississippian pay in Grant
    County, Oklahoma, after Upper and Lower Mississippian test wells delivered
    average 30-day IPs over 400 Boe per day
  oInitiated a nine well Woodford test program. Three wells have been
    completed to date. Two wells delivered test oil rates of 68 Bbls per day
    and 37 Bbls per day, and one well has produced only water. Strong industry
    results and key takeaways from these first tests support further testing

Appraisal Program

  oAn Upper Mississippian test well in Kay County extended the Eastern
    boundary of the company's Mississippian play with a 1,000 Boe per day test
    rate. Three additional wells are scheduled in the fourth quarter to
    delineate the surrounding leasehold
  oA vertical appraisal well discovered commercial pay in the Marmaton
    formation in Comanche County, Kansas. The well delivered a 30-day IP of
    496 Boe per day. A second delineation well confirmed additional pay, and
    supports future multi-well horizontal development

Capital Efficiency and Cost Improvements

  oIndustry leading quarterly average Mississippian well cost of $2.95
    million
  oFor the first nine months of 2013, drilled 340 horizontal wells and
    associated infrastructure and spent $647 million, versus drilling 271
    horizontal wells and associated infrastructure and spending $676 million
    in the first nine months of 2012
  oMississippian producer to disposal well ratio increased to 30:1 for the
    third quarter of 2013 through continued optimization and design
    improvements of current system
  oDeveloped and employing new low cost disposal wells. The new design is
    expected to save approximately $1 millionover the previous design and is
    slated for areas outside the company's current infrastructure
  oImplemented new centralized production battery design to serve multi-well
    pad developments, yielding a savings of $100,000 per horizontal well
  oMississippian lease operating expense was $7.02 per Boe during the third
    quarter, a 5% sequential decrease and a 22% year-over-year decrease

Offshore

  oLicensed 25 blocks of WAZ 3D seismic data over Bullwinkle and its adjacent
    Miocene producing subsalt fields in Green Canyon to further analyze
    Miocene reservoirs beneath the Bullwinkle platform. Initiated meetings
    with potential industry partners to secure a suitable partner to test the
    objectives
  oProcuring 9 blocks of WAZ 3D seismic data in and around South Pass 60 to
    further analyze 3-way closure subsalt prospect. Initiated contacts with
    potential industry partners to explore a joint venture opportunity

Financial

  oAdjusted G&A run-rate of $144 million during the third quarter
  oCurrent liquidity of $1.65 billion with cash balance of approximately $900
    million
  oAt September 30, no borrowings were outstanding under the credit facility
    and the leverage ratio was 2.35x

2014 Guidance

  o12% organic production growth, adjusted for the 2013 Permian divestiture
  o24% organic liquids growth, adjusted for the 2013 Permian divestiture
  oCapital expenditures of $1.5 billion
  oAverage 25 rigs in the Mississippian play and drill approximately 430
    wells
  oContinue appraisal drilling and stacked pay tests
  oMidpoint for LOE unit cost represents a 9% year-over-year reduction
  oMidpoint for G&A unit cost represents a 22% year-over-year reduction

Presentation slides to be viewed in conjunction with certain of the above
operational highlights will be available on the company's website,
www.sandridgeenergy.com, under Investor Relations/Presentations & Events on
November 6, 2013 at 7:00 am CST. Additional 2013 and 2014 Guidance detail is
available on the company's website under Investor Relations/Guidance.

Drilling and Operational Activities

Mississippian Play. During the third quarter of 2013, SandRidge drilled 91
horizontal wells: 67 in Oklahoma and 24 in Kansas. SandRidge also drilled
three disposal wells during the quarter. The company averaged 22 horizontal
rigs operating in the play: 17 in Oklahoma and five in Kansas. Additionally,
the company averaged one rig drilling disposal wells. For the fourth quarter
of 2013, the company plans to average 23 horizontal rigs in the Mississippian
play: 17 in Oklahoma and six in Kansas. The company's Mississippian assets
produced 47.9 MBoe per day during the third quarter (48% oil).

Gulf of Mexico / Gulf Coast. During the third quarter of 2013, SandRidge
drilled and completed two wells, one in High Island Block 31L, and the other
in Green Canyon Block 108. Additionally, SandRidge performed three
recompletions and participated in two non-operated recompletions during the
quarter. The company's Gulf of Mexico and Gulf Coast assets produced 26.4 MBoe
per day during the quarter (50% oil). Approximately 181,000 Boe was deferred
in the quarter due to pipeline curtailments and delays in securing a work
barge to clear paraffin from the oil export line of Vermillion 371.

Permian Basin. In the company's Permian properties, 56 wells were drilled
during the third quarter of 2013. SandRidge plans to utilize three rigs and
expects to drill approximately 210 wells in 2013. The company's Permian Basin
assets produced 6.5 MBoe per day during the quarter (96% oil).

Other Operating Areas. During the third quarter, SandRidge's other West Texas
properties produced approximately 6.8 MBoe per day (99% natural gas).
Additionally, its other Mid-Continent assets produced 2.0 MBoe per day in the
quarter (80% natural gas).

Royalty Trusts. At September 30, 2013, the company was obligated to drill 32
development wells for SandRidge Mississippian Trust II ("SDR") and 251
development wells for SandRidge Permian Trust ("PER"). The company expects to
complete its drilling obligation for SDR in the second quarter of 2014 and for
PER in the fourth quarter of 2014. The company completed its drilling
obligation to SandRidge Mississippian Trust I ("SDT") in the second quarter of
2013.

Operational and Financial Statistics

Information regarding the company's production, pricing, costs and earnings is
presented below:

                                Three Months Ended      Nine Months Ended
                                September 30,           September 30,
                                2013        2012        2013        2012
Production
Oil (MBbl) ^(1)                 3,949       4,943       12,510      12,925
Natural gas (MMcf)              25,788      27,184      78,342      64,832
Oil equivalent (MBoe)           8,247       9,473       25,567      23,730
Daily production (MBoed)        89.6        103.0       93.7        86.6
Average price per unit
Realized oil price per barrel   $ 95.71    $ 84.50    $ 90.18    $ 86.25
- as reported ^(1)
Realized impact of derivatives  (5.30)      7.34        0.93        3.39
per barrel ^(1)
Net realized price per barrel   $ 90.41    $ 91.84    $ 91.11    $  89.64
^(1)
Realized natural gas price per  $  3.15   $  2.60   $  3.36   $  2.23
Mcf - as reported
Realized impact of derivatives  0.30        (0.37)      0.08        0.08
per Mcf
Net realized price per Mcf      $  3.45   $  2.23   $  3.44   $  2.31
Realized price per Boe - as     $ 55.68    $ 51.54    $ 54.43    $ 53.07
reported
Net realized price per Boe -
including impact of             $ 54.08    $ 54.32    $ 55.11    $ 55.14
derivatives
Average cost per Boe
Lease operating                $ 14.10    $ 14.47    $ 14.30    $ 14.45
Production taxes                1.07        1.37        0.97        1.53
General and administrative
  General and administrative,
  excluding stock-based         4.01        3.90        8.35        5.30
  compensation ^(2)
  Stock-based compensation      0.84        1.04        3.10        1.40
  ^(3)
Depletion ^(4)                  17.72       18.49       18.07       17.36
Lease operating cost per Boe
Mississippian                   $  7.02   $  9.05   $  7.77   $  9.32
Offshore                        25.71       23.61       23.09       22.91
Earnings per share
(Loss) earnings per share
applicable to common
stockholders
  Basic                         $  (0.18)  $  (0.39)  $  (1.28)  $  0.87
  Diluted                       (0.18)      (0.39)      (1.28)      0.80
Adjusted net income per share
available to common
stockholders
  Basic                         $  0.05   $  0.03   $  0.10   $  0.10
  Diluted                       0.07        0.05        0.16        0.16
Weighted average number of
common shares outstanding (in
thousands)
  Basic                         483,582     476,037     480,209     445,991
  Diluted ^(5)                  573,716     566,551     571,354     537,300

^(1) Includes NGLs.
     Includes transaction costs, legal settlements, severance, annual
     incentive plan adoption effect and consent solicitation costs totaling
^(2) $2.7 million and $102.2 million for the three and nine-month periods
     ended September 30, 2013, respectively. Includes transaction costs
     totaling $0.6 million and $13.7 million for the three and nine-month
     periods ended September 30, 2012, respectively.
     Three and nine-month periods ended September 30, 2013 include $1.7
^(3) million and $54.7 million, respectively, for the acceleration of
     certain stock awards.
     Includes accretion of
^(4) asset retirement
     obligation.
^(5) Includes shares considered antidilutive for calculating earnings per
     share in accordance with GAAP for certain periods presented.



Discussion of Third Quarter 2013 Financial Results

Oil and natural gas revenue decreased 6% to $459 million in the third quarter
of 2013 from $488 million in the same period of 2012 primarily as a result of
a 13% decrease in total production due to the Permian divestiture that closed
during the first quarter of 2013. Excluding the impact of the Permian
divestiture, production grew approximately 13% as result of continued
development of the company's properties in the Mississippian play.
Mississippian production accounted for 53% of the company's total production
in third quarter 2013 compared to 30% in third quarter 2012. Realized reported
prices, which exclude the impact of derivative settlements, were $95.71 per
barrel and $3.15 per Mcf during the third quarter of 2013 compared to $84.50
per barrel and $2.60 per Mcf during the same period in 2012.

Third quarter 2013 production expense was $14.10 per Boe compared to third
quarter 2012 production expense of $14.47 per Boe. The decrease was primarily
attributable to improving efficiencies in SandRidge's primary onshore
operations in the Mississippian play where production expense decreased 22%
year-over-year from $9.05 to $7.02 per Boe.

General and administrative expenses totaled $40 million in the third quarter
of 2013 and included approximately $4 million of severance costs and consent
solicitation costs (annualized pro forma run-rate of $144 million),
representing a sequential decrease of 20% from the previous quarter general
and administrative expenses, excluding charges for severance, transactions,
consent solicitation and changes to incentive plans.

Capital Expenditures

The table below summarizes the company's capital expenditures for the three
and nine-month periods ended September 30, 2013 and 2012:

                                Three Months Ended    Nine Months Ended
                                September 30,         September 30,
                                2013       2012       2013         2012
                                (in thousands)
Drilling and production
    Mid-Continent               $188,374   $240,642   $  647,019  $  676,078
    Permian Basin               44,309     181,072    155,903      524,378
    Gulf of Mexico/Gulf Coast   47,708     51,045     161,700      104,377
    WTO/Tertiary/Other          -          4,576      -            20,749
                                280,391    477,335    964,622      1,325,582
Leasehold and seismic
    Mid-Continent               13,526     19,790     52,611       164,415
    Permian Basin               -          4,267      -            12,908
    Gulf of Mexico/Gulf Coast  723        2,963      2,072        12,892
    WTO/Tertiary/Other          1,370      110        3,832        2,283
                                15,619     27,130     58,515       192,498
Inventory                       (3,351)    (4,274)    (14,384)     (8,001)
Total exploration and           292,659    500,191    1,008,753    1,510,079
development
Drilling and oil field          3,142      14,571     4,657        28,323
services
Midstream                       16,551     20,229     46,883       61,958
Other - general                10,230     25,067     38,159       91,410
Total capital expenditures,     322,582    560,058    1,098,452    1,691,770
excluding acquisitions
Acquisitions                    6,925      75,444     15,527       837,019
Total capital expenditures      $329,507   $635,502   $1,113,979   $2,528,789
Plugging and abandonment        $ 35,243  $ 39,491  $  107,560  $  
                                                                   64,633



Derivative Contracts

The table below sets forth the company's consolidated oil and natural gas
price and basis swaps and collars for the fourth quarter of 2013 and the years
2014 and 2015 as of November 1, 2013 and include contracts that have been
novated to or the benefits of which have been conveyed to SandRidge sponsored
royalty trusts. Since August 1, 2013, the company has added approximately 4.2
million barrels of oil swaps at an average price of $92.64 per barrel across
the periods presented in the table below.

                          Quarter Ending  Year Ending
                          12/31/2013      12/31/2014  12/31/2015
Oil (MMBbls):
 Swap Volume              3.49            8.81        7.98
 Swap                     $99.48          $92.98      $86.13
 Collar Volume            0.04            -           -
 Collar: High            $102.50         -           -
 Collar: Low             $80.00          -           -
 Three-way Collar Volume  -               8.21        2.92
 Call Price              -               $100.00     $103.13
 Put Price               -               $90.20      $90.82
 Short Put Price         -               $70.00      $73.13
Natural Gas (Bcf):
 Swap Volume              12.42           -           -
 Swap                     $4.11           -           -
 Collar Volume            1.72            0.94        1.01
 Collar: High            $6.71           $7.78       $8.55
 Collar: Low             $3.78           $4.00       $4.00



Balance Sheet

The company's capital structure at September 30, 2013 and December 31, 2012 is
presented below:

                                       September 30,        December 31,
                                       2013                  2012
                                       (in thousands)
Cash and cash equivalents              $     920,257     $    309,766
Current maturities of long-term debt   $         -  $        -
Long-term debt (net of current
maturities)
  Senior credit facility               -                     -
  Senior Notes
   9.875% Senior Notes due 2016, net   -                     356,657
   8.0% Senior Notes due 2018          -                     750,000
   8.75% Senior Notes due 2020, net    444,580               444,127
   7.5% Senior Notes due 2021          1,179,027             1,179,328
   8.125% Senior Notes due 2022        750,000               750,000
   7.5% Senior Notes due 2023, net     821,177               820,971
    Total debt                       3,194,784             4,301,083
Stockholders' equity
  Preferred stock                      8                     8
  Common stock                         483                   476
  Additional paid-in capital           5,287,792             5,228,019
  Treasury stock, at cost              (8,763)               (8,602)
  Accumulated deficit                  (3,465,661)           (2,851,048)
   Total SandRidge Energy, Inc.        1,813,859             2,368,853
   stockholders' equity
  Noncontrolling interest              1,371,689             1,493,602
Total capitalization                   $   6,380,332      $  8,163,538



During the third quarter of 2013, the company's debt, net of cash balances,
increased by approximately $175 million as a result of funding the company's
drilling program. On November 1, 2013, the company had no amount drawn under
its $775 million senior credit facility and approximately $900 million of
cash, leaving approximately $1.65 billion of available liquidity. The company
was in compliance with all applicable covenants contained in its debt
agreements during the nine months ended September 30, 2013 and through and as
of the date of this release.

2013 Operational Guidance Update

The company is updating certain 2013 guidance provided on August 6, 2013. The
company is updating its liquids production guidance to reflect oil and natural
gas liquids separately. Estimated total production has increased from 33.3
MMBoe to 33.6 MMBoe due to improved well performance in the company's
Mississippian and Permian assets as well as minimal hurricane related downtime
in the company's offshore assets, partly offset by offshore pipeline
curtailments. G&A guidance presented for 2013 excludes one-time items.
Additional 2013 Guidance detail is available on the company's website,
www.sandridgeenergy.com, under Investor Relations/Guidance.

                                            Year Ending December 31, 2013
                                            Projection as of  Projection as of
                                            August 6, 2013    November 5, 2013
Production
     Oil (MMBbls)                                             14.2
     Natural Gas Liquids (MMBbls)                             2.2
     Total Liquids (MMBbls)                 16.3              16.5
     Natural Gas (Bcf)                      102.0             102.6
     Total (MMBoe)                          33.3              33.6
Price Realization
     Oil (differential below NYMEX WTI)     $9.50             $0.50
     ^(1)
     Natural Gas Liquids (realized % of                       33%
     NYMEX WTI)
     Natural Gas (differential below NYMEX  $0.45             $0.40
     Henry Hub)
Costs per Boe
     Lifting                               $14.50 - $16.50   $14.50 - $16.50
     Production Taxes                       1.00 - 1.20       0.95 - 1.05
     DD&A - oil & gas                       17.10 - 18.90     17.10 - 18.90
     DD&A - other                           2.00 - 2.20       1.80 - 2.00
     Total DD&A                             $19.10 - $21.10   $18.90 - $20.90
     G&A - cash                             4.05 - 4.50       4.00 - 4.45
     G&A - stock                            1.05 - 1.20       0.85 - 0.95
     Total G&A                              $5.10 - $5.70     $4.85 - $5.40
     Interest Expense                       $8.10 - $9.10     $7.80 - $8.65
EBITDA from Oilfield Services, Midstream    $20               $25
and Other ($ in millions) ^(2)
Adjusted Net Income Attributable to
Noncontrolling Interest ($ in millions)     $140              $130
^(3)
P&A Cash Cost ($ in millions)               $120              $120
Corporate Tax Rate ^(4)                     0%                0%
Deferral Rate                               0%                0%
Capital Expenditures ($ in millions)
     Exploration and Production             $1,230            $1,230
     Land and Seismic                       100               100
     Total Exploration and Production       $1,330            $1,330
     Oil Field Services                     15                10
     Midstream and Other                    105               110
     Total Capital Expenditures (excluding  $1,450            $1,450
     acquisitions)

^(1)  Projection as of August 6, 2013,
      includes NGLs.
      EBITDA from Oilfield Services, Midstream and Other is a non-GAAP
      financial measure as it excludes from net income interest expense,
      income tax expense and depreciation, depletion and amortization. The
      most directly comparable GAAP measure for EBITDA from Oilfield Services,
^(2)  Midstream and Other is Net Income from Oilfield Services, Midstream and
      Other. Information to reconcile this non-GAAP financial measure to the
      most directly comparable GAAP financial measure is not available at this
      time, as management is unable to forecast the excluded items for future
      periods and/or does not forecast the excluded items on a segment basis.
      Adjusted Net Income Attributable to Noncontrolling Interest is a
      non-GAAP financial measure as it excludes gain or loss due to changes in
      the fair value of derivative contracts and gain or loss on sale of
      assets. The most directly comparable GAAP measure for Adjusted Net
^(3) Income Attributable to Noncontrolling Interest is Net Income
      Attributable to Noncontrolling Interest. Information to reconcile this
      non-GAAP financial measure to the most directly comparable GAAP
      financial measure is not available at this time, as management is unable
      to forecast the excluded items for future periods.
      As a result of the Permian divestiture, the company expects to incur
^(4)  cash income taxes of approximately $7 million in 2013 with a
      corresponding expense included in Net Income.



2014 Operational Guidance

The company is initiating 2014 guidance with total production of 36.3 MMBoe,
or 12% organic growth, and capital expenditures of $1.5 billion. Production
growth is being driven by the company's Mississippian assets where it
anticipates generating 35% year-over-year growth. The company plans to spend
approximately $920 million on Mid-Continent/Mississippian focus area drilling
and approximately $45 million on appraisal drilling outside its focus acreage.
The company expects to begin the year with 23 rigs and ramp up to 26 by
mid-year and to drill approximately 430 horizontal wells in its focus area in
2014. The company also plans to spend approximately $115 million on Gulf of
Mexico drilling and recompletions, anticipating a production decline of 15% -
20% year-over-year. Additionally, the company plans to spend approximately
$110 million on its Permian assets to satisfy the drilling obligation to
SandRidge Permian Trust and grow annual production by approximately 10%. In
total, SandRidge expects to spend approximately $140 million related to
royalty trust drilling obligations in 2014 and anticipates that it will have
all drilling obligations completed by the end of 2014. Additional 2014
Guidance detail is available on the company's website,
www.sandridgeenergy.com, under Investor Relations/Guidance.

                                                      Year Ending December 31,
                                                      2014
                                                      Projection as of
                                                      November 5, 2013
Production
       Oil (MMBbls)                                   15.4
       Natural Gas Liquids (MMBbls)                   3.9
       Total Liquids (MMBbls)                         19.3
       Natural Gas (Bcf)                              102.0
       Total (MMBoe)                                  36.3
Price Realization
       Oil (differential below NYMEX WTI)             $1.00
       Natural Gas Liquids (realized % of NYMEX WTI)  34%
       Natural Gas (differential below NYMEX Henry    $0.70
       Hub)
Costs per Boe
       Lifting                                       $13.15 - $15.15
       Production Taxes                               0.95 - 1.15
       DD&A - oil & gas                               16.80 - 18.80
       DD&A - other                                   1.80 - 2.00
       Total DD&A                                     $18.60 - $20.80
       G&A - cash                                     2.90 - 3.20
       G&A - stock                                    0.85 - 1.05
       Total G&A                                      $3.75 - $4.25
       Interest Expense                               $7.00 - $8.00
EBITDA from Oilfield Services, Midstream and Other    $25
($ in millions) ^(1)
Adjusted Net Income Attributable to Noncontrolling    $120
Interest ($ in millions) ^(2)
P&A Cash Cost ($ in millions)                         $60
Corporate Tax Rate                                    0%
Deferral Rate                                         0%
Capital Expenditures ($ in millions)
       Exploration and Production                     $1,265
       Land and Seismic                               110
       Total Exploration and Production               $1,375
       Oil Field Services                             15
       Midstream and Other                            110
       Total Capital Expenditures (excluding          $1,500
       acquisitions)

      EBITDA from Oilfield Services, Midstream and Other is a non-GAAP
      financial measure as it excludes from net income interest expense,
      income tax expense and depreciation, depletion and amortization. The
      most directly comparable GAAP measure for EBITDA from Oilfield Services,
^(1)  Midstream and Other is Net Income from Oilfield Services, Midstream and
      Other. Information to reconcile this non-GAAP financial measure to the
      most directly comparable GAAP financial measure is not available at this
      time, as management is unable to forecast the excluded items for future
      periods and/or does not forecast the excluded items on a segment basis.
      Adjusted Net Income Attributable to Noncontrolling Interest is a
      non-GAAP financial measure as it excludes gain or lossdue to changes in
      fair value ofderivative contracts and gain or loss on sale of assets.
      The most directly comparable GAAP measure for Adjusted Net Income
^(2) Attributable to Noncontrolling Interest is Net Income Attributable to
      Noncontrolling Interest. Information to reconcile this non-GAAP
      financial measure to the most directly comparable GAAP financial measure
      is not available at this time, as management is unable to forecast the
      excluded items for future periods.



Non-GAAP Financial Measures

Adjusted operating cash flow, adjusted EBITDA, adjusted net income and
adjusted net income attributable to noncontrolling interest are non-GAAP
financial measures.

The company defines adjusted operating cash flow as net cash provided by
operating activities before changes in operating assets and liabilities and
adjusted for cash (paid) received on financing derivatives. It defines EBITDA
as net (loss) income before income tax expense (benefit), interest expense and
depreciation, depletion and amortization and accretion of asset retirement
obligations. Adjusted EBITDA, as presented herein, is EBITDA excluding asset
impairment, interest income, (gains) losses on early settlements of derivative
contracts, non-cash losses due to amendment of derivative contracts, non-cash
losses due to contractual maturity of financing derivative contracts, loss on
sale of assets, transaction costs, legal settlements, consent solicitation
costs, effect of annual incentive plan adoption, severance, bargain purchase
gain, loss on extinguishment of debt and other various non-cash items
(including non-cash portion of noncontrolling interest, stock-based
compensation and losses (gains) due to changes in fair value of derivative
contracts).

Adjusted operating cash flow and adjusted EBITDA are supplemental financial
measures used by the company's management and by securities analysts,
investors, lenders, rating agencies and others who follow the industry as an
indicator of the company's ability to internally fund exploration and
development activities and to service or incur additional debt. The company
also uses these measures because adjusted operating cash flow and adjusted
EBITDA relate to the timing of cash receipts and disbursements that the
company may not control and may not relate to the period in which the
operating activities occurred. Further, adjusted operating cash flow and
adjusted EBITDA allow the company to compare its operating performance and
return on capital with those of other companies without regard to financing
methods and capital structure. These measures should not be considered in
isolation or as a substitute for net cash provided by operating activities
prepared in accordance with generally accepted accounting principles ("GAAP").
Adjusted EBITDA should not be considered as a substitute for net income,
operating income, cash flows from operating activities or any other measure of
financial performance or liquidity presented in accordance with GAAP. Adjusted
EBITDA excludes some, but not all, items that affect net income and operating
income and these measures may vary among other companies. Therefore, the
company's adjusted EBITDA may not be comparable to similarly titled measures
used by other companies.

Management also uses the supplemental financial measure of adjusted net
income, which excludes tax expense (benefit) resulting from divestiture
(acquisition), asset impairment, losses (gains) due to changes in fair value
of derivative contracts, (gains) losses on early settlements of derivative
contracts, non-cash losses due to amendment of derivative contracts, non-cash
losses due to contractual maturity of financing derivative contracts,
transaction costs, legal settlements, consent solicitation costs, effect of
annual incentive plan adoption, financing commitment fees, bargain purchase
gain, loss on extinguishment of debt, severance and loss on sale of assets
from (loss applicable) income available to common stockholders. Management
uses this financial measure as an indicator of the company's operational
trends and performance relative to other oil and natural gas companies and
believes it is more comparable to earnings estimates provided by securities
analysts. Adjusted net income is not a measure of financial performance under
GAAP and should not be considered a substitute for (loss applicable) income
available to common stockholders.

The supplemental measure of adjusted net income attributable to noncontrolling
interest is used by the company's management to measure the impact on the
company's financial results of the ownership by third parties of interests in
the company's less than wholly-owned consolidated subsidiaries. Adjusted net
income attributable to noncontrolling interest excludes the portion of losses
(gains) due to changes in fair value of derivative contracts, legal settlement
and (gain) loss on sale of assets attributable to third party ownership in
less than wholly-owned consolidated subsidiaries from net income attributable
to noncontrolling interest. Adjusted net income attributable to noncontrolling
interest is not a measure of financial performance under GAAP and should not
be considered a substitute for net income attributable to noncontrolling
interest.

The tables below reconcile the most directly comparable GAAP financial
measures to adjusted operating cash flow, EBITDA and adjusted EBITDA, adjusted
net income, and adjusted net income attributable to noncontrolling interest.



Reconciliation of Net Cash Provided by Operating Activities to Adjusted
Operating Cash Flow
                             Three Months Ended September  Nine Months Ended
                             30,                           September 30,
                             2013             2012         2013      2012 ^(1)
                             (in thousands)
Net cash provided by         $210,324         $166,524     $595,007  $584,230
operating activities
Add (deduct)
  Cash (paid) received on    (629)            6,609        5,099     (38,703)
  financing derivatives
  Changes in operating       25,737           108,290      (6,868)   109,908
  assets and liabilities
Adjusted operating cash      $235,432         $281,423     $593,238  $655,435
flow

^(1) Includes retrospective application of acquisition purchase price
     adjustments recorded in fourth quarter of 2012.



Reconciliation of Net (Loss) Income to EBITDA and Adjusted EBITDA
                                 Three Months Ended      Nine Months Ended
                                 September 30,           September 30,
                                 2013        2012        2013        2012 ^(1)
                                 (in thousands)
Net (loss) income                $ (73,193)  $(170,419)  $(572,969)  $ 429,475
Adjusted for
 Income tax expense (benefit)    2,363       172         7,300       (100,374)
 Interest expense ^(2)           61,793      84,403      212,436     224,076
 Depreciation and amortization   15,270      16,497      46,628      46,357
 - other
 Depreciation and depletion -    137,639     166,126     434,068     392,452
 oil and natural gas
 Accretion of asset retirement   8,472       9,053       28,051      19,625
 obligations
EBITDA                           152,344     105,832     155,514     1,011,611
 Asset impairment                687         -           16,330      -
 Interest income                 (408)       (476)       (1,587)     (1,016)
 Stock-based compensation        5,135       9,125       22,769      30,700
 Losses (gains) due to changes
 in fair value on derivative     119,605     220,433     56,085      (234,705)
 contracts
 Gains on early settlements of   -           (2,115)     (323)       (59,465)
 derivative contracts
 Losses on early settlements of  -           -           29,623      -
 derivative contracts - Permian
 Non-cash losses due to
 amendment of derivative         -           -           -           117,108
 contracts
 Non-cash losses due to
 contractual maturity of         707         3,055       667         6,866
 financing derivative contracts
 Other non-cash (income)         (328)       (931)       2,119       (2,183)
 expense
 Loss on sale of assets ^(3)     539         375         398,364     3,755
 Transaction costs               589         681         2,218       15,276
 Legal settlements               -           -           1,081       -
 Consent solicitation fees       1,516       -           22,335      -
 Effect of Annual Incentive      -           -           14,735      -
 Plan adoption
 Severance                       2,258       -           120,375     -
 Bargain purchase gain           -           -           -           (122,696)
 Loss on extinguishment of debt  -           3,056       82,005      3,056
 Non-cash portion of             (30,174)    (41,545)    (132,095)   (16,692)
 noncontrolling interest ^(4)
Adjusted EBITDA                  $252,470    $ 297,490   $ 790,215   $ 751,615
Less: EBITDA attributable to
 Permian properties sold         -           (115,744)   (50,574)    (345,858)
 Tertiary properties sold        -           -           -           (7,996)
Add: EBITDA attributable to
(1/1 to date of acquisition)
 Dynamic Offshore                -           -           -           107,647
 Gulf of Mexico Properties       -           -           -           16,251
Pro forma adjusted EBITDA        $252,470    $ 181,746   $ 739,641   $ 521,659

^(1) Includes retrospective application of acquisition purchase price
     adjustments recorded in fourth quarter of 2012.
     Excludes gaindue to changes in fair value of interest rate swaps of $2.0
     million for the three-month period ended September 30, 2012. Excludes
^(2) gainsdue to changes in fair value ofinterest rate swaps of $2.4 million
     and $5.6 million for the nine-month periods ended September 30, 2013 and
     2012, respectively.
     Includes loss on sale of Permian oil and natural gas assets of
^(3) approximately $398.9 million for the nine-month period ended September
     30, 2013.
     Represents depreciation and depletion, loss on sale of Permian
^(4) Properties,(gains) lossesdue to changes in fair value ofcommodity
     derivative contracts, legal settlement and income tax expense
     attributable to noncontrolling interests.



Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA
                                Three Months Ended      Nine Months Ended
                                September 30,           September 30,
                                2013         2012       2013        2012 ^(1)
                                (in thousands)
Net cash provided by            $210,324     $166,524   $595,007    $584,230
operating activities
Changes in operating assets     25,737       108,290    (6,868)     109,908
and liabilities
Interest expense ^(2)           61,793       84,403     212,436     224,076
Gains on early settlements of   -            (2,115)    (323)       (33,165)
derivative contracts
Losses on early settlements
of derivative contracts -       -            -          29,623      -
Permian
Transaction costs               589          681        2,218       15,276
Legal settlements               -            -          1,081       -
Consent solicitation costs      1,516        -          22,335      -
Effect of Annual Incentive      -            -          14,735      -
Plan adoption
Severance                       598          -          65,685      -
Noncontrolling interest - SDT   (8,841)      (13,933)   (32,109)    (41,174)
^(3)
Noncontrolling interest - SDR   (15,648)     (16,537)   (52,664)    (29,407)
^(3)
Noncontrolling interest - PER   (21,908)     (21,794)   (56,751)    (57,897)
^(3)
Noncontrolling interest -       31           51         36          160
Other ^(3)
Other non-cash items            (1,721)      (8,080)    (4,226)     (20,392)
Adjusted EBITDA                 $252,470     $297,490   $790,215    $751,615

^(1) Includes retrospective application of acquisition purchase price
     adjustments recorded in fourth quarter of 2012.
     Excludes gaindue to changes in fair value ofinterest rate swaps of $2.0
     million for the three-month period ended September 30, 2012. Excludes
^(2) gainsdue to changes in fair value ofinterest rate swaps of $2.4 million
     and $5.6 million for the nine-month periods ended September 30, 2013 and
     2012, respectively.
     Excludes depreciation and depletion, loss on sale of Permian Properties,
^(3) (gains) lossesdue to changes in fair value ofcommodity derivative
     contracts, legal settlement and income tax expense attributable to
     noncontrolling interests.



Reconciliation of (Loss Applicable) Income Available to Common Stockholders to
Adjusted Net Income
                            Three Months Ended         Nine Months Ended
                            September 30,              September 30,
                            2013          2012         2013         2012 ^(1)
                            (in thousands except per share data)
(Loss applicable) income
available to common         $(87,074)     $(184,301)   $(614,613)   $387,830
stockholders
Tax expense (benefit)
resulting from divestiture  687           -            4,702        (100,288)
(acquisition)
Asset impairment            687           -            16,330       -
Losses (gains) due to
changes in fair value of    103,179       195,422      39,297       (213,905)
derivative contracts ^(2)
Gains on early settlements  -             (2,115)      (323)        (59,465)
of derivative contracts
Losses on early
settlements of derivative   -             -            29,623       -
contracts - Permian
Non-cash losses due to
amendment of derivative     -             -            -            117,108
contracts
Non-cash losses due to
contractual maturity of     707           3,055        667          6,866
financing derivative
contracts
Loss on sale of assets      575           375          326,660      3,755
^(2)
Transaction costs           589           681          2,218        15,276
Legal settlements ^(2)      -             -            729          -
Consent solicitation costs  1,516         -            22,335       -
Effect of Annual Incentive  -             -            14,735       -
Plan adoption
Severance                   2,258         -            120,375      -
Financing commitment fees   -             -            -            10,875
Bargain purchase gain       -             -            -            (122,696)
Loss on extinguishment of   -             3,056        82,005       3,056
debt
Other non-cash income       -             (658)        (154)        (2,443)
Effect of income taxes      3,359         217          3,057        (47)
Adjusted net income
available to common         26,483        15,732       47,643       45,922
stockholders
Preferred stock dividends   13,881        13,881       41,644       41,644
Total adjusted net income   $ 40,364      $  29,613   $  89,287   $ 87,566
Weighted average number of
common shares outstanding
        Basic               483,582       476,037      480,209      445,991
        Diluted ^(3)        573,716       566,551      571,354      537,300
Total adjusted net income
        Per share - basic   $   0.05    $   0.03  $   0.10  $   0.10
        Per share -         $   0.07    $   0.05  $   0.16  $   0.16
        diluted

^(1) Includes retrospective application of acquisition purchase price
     adjustments recorded in fourth quarter of 2012.
^(2) Excludes amounts attributable to noncontrolling interests.
     Weighted average fully diluted common shares outstanding for certain
^(3) periods presented includes shares that are considered antidilutive for
     calculating earnings per share in accordance with GAAP.



Reconciliation of Net Income Attributable to Noncontrolling Interest to
Adjusted Net Income Attributable to Noncontrolling Interest
                                    Three Months Ended     Nine Months Ended
                                    September 30,          September 30,
                                    2013         2012      2013      2012
                                    (in thousands)
Net income attributable to          $16,191      $10,668   $ 9,393  $111,626
noncontrolling interest
(Gain) loss on sale of assets -     (36)         -         71,704    -
Permian
Legal settlement                    -            -         352       -
Losses (gains) due to changes in    16,426       25,011    16,788    (20,800)
fair value of derivative contracts
      Adjusted net income
      attributable to               $32,581      $35,679   $98,237   $ 90,826
      noncontrolling interest



Conference Call Information

The company will host a conference call to discuss these results on Wednesday,
November 6, 2013 at 8:00 am CST. The telephone number to access the conference
call from within the U.S. is 866-318-8618 and from outside the U.S. is
617-399-5137. The passcode for the call is 47127609. An audio replay of the
call will be available from November 6, 2013 until 11:59 pm CST on December 5,
2013. The number to access the conference call replay from within the U.S. is
888-286-8010 and from outside the U.S. is 617-801-6888. The passcode for the
replay is 17857539.

A live audio webcast of the conference call will also be available via
SandRidge's website, www.sandridgeenergy.com, under Investor
Relations/Presentations & Events. The webcast will be archived for replay on
the company's website for 30 days.

Conference Participation

SandRidge Energy, Inc. will participate in the following upcoming events:

  oNovember 14, 2013 – UBS Boston Energy Mini-Conference; Boston, MA
  oDecember 11, 2013 – Capital One Southcoast 2013 December Energy
    Conference; New Orleans, LA
  oJanuary 9, 2014 – Goldman Sachs 2014 Global Energy Conference; Miami, FL

At 8:00 am Central Time on the day of each presentation, the corresponding
slides and any webcast information will be accessible on the Investor
Relations portion of the company's websiteat www.sandridgeenergy.com. Please
check the website for updates regularly as this schedule is subject to change.
Also, please note that SandRidge Energy, Inc. intends for its website to be
used as a reliable source of information for all future events in which it may
participate as well as updated presentations regarding the company. Slides and
webcasts (where applicable) will be archived and available for at least 30
days after each use or presentation.

Fourth Quarter and Year End 2013 Earnings Release and Conference Call

February 27, 2014 (Thursday) – Earnings press release after market close
February 28, 2014 (Friday) – Earnings conference call at 8:00 am Central



SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(in thousands, except per share data)
                        Three Months Ended         Nine Months Ended September
                        September 30,              30,
                        2013         2012          2013            2012^(1)
                        (Unaudited)
Revenues
 Oil and natural gas    $459,211     $ 488,252     $1,391,510      $1,259,375
 Drilling and services  16,149       27,760        49,597          90,701
 Midstream and          14,624       10,708        42,854          27,866
 marketing
 Construction contract  -            -             23,253          -
 Other                  3,619        6,078         11,066          14,925
   Total revenues       493,603      532,798       1,518,280       1,392,867
Expenses
 Production             116,317      137,033       365,629         342,824
 Production taxes       8,816        12,967        24,819          36,222
 Cost of sales          13,773       15,666        45,438          52,468
 Midstream and          13,224       10,674        39,954          27,187
 marketing
 Construction contract  -            -             23,253          -
 Depreciation and
 depletion - oil and    137,639      166,126       434,068         392,452
 natural gas
 Depreciation and       15,270       16,497        46,628          46,357
 amortization - other
 Accretion of asset     8,472        9,053         28,051          19,625
 retirement obligations
 Impairment             687          -             16,330          -
 General and            39,970       46,781        292,675         158,798
 administrative
 Loss (gain) on         132,808      193,497       70,051          (221,707)
 derivative contracts
 Loss on sale of assets 539          375           398,364         3,755
   Total expenses       487,515      608,669       1,785,260       857,981
   Income (loss) from   6,088        (75,871)      (266,980)       534,886
   operations
Other income (expense)
 Interest expense       (61,385)     (81,894)      (208,454)       (217,428)
 Bargain purchase gain  -            -             -               122,696
 Loss on extinguishment -            (3,056)       (82,005)        (3,056)
 of debt
 Other income, net      658          1,242         1,163           3,629
   Total other expense  (60,727)     (83,708)      (289,296)       (94,159)
(Loss) income before    (54,639)     (159,579)     (556,276)       440,727
income taxes
Income tax expense      2,363        173           7,300           (100,373)
(benefit)
Net (loss) income       (57,002)     (159,752)     (563,576)       541,100
Less: net income
attributable to         16,191       10,668        9,393           111,626
noncontrolling interest
Net (loss) income
attributable to         (73,193)     (170,420)     (572,969)       429,474
SandRidge Energy, Inc.
Preferred stock         13,881       13,881        41,644          41,644
dividends
   (Loss applicable)
   income available to
   SandRidge Energy,    $ (87,074)   $(184,301)    $ (614,613)    $  387,830
   Inc. common
   stockholders
(Loss) earnings per
share
 Basic                  $  (0.18)  $   (0.39)  $            $   
                                                   (1.28)          0.87
 Diluted                $  (0.18)  $   (0.39)  $            $   
                                                   (1.28)          0.80
Weighted average number
of common shares
outstanding
 Basic                  483,582      476,037       480,209         445,991
 Diluted                483,582      476,037       480,209         537,300

^(1) Includes retrospective application of acquisition purchase price
     adjustments recorded in fourth quarter of 2012.



SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except per share data)
                                             September 30,     December 31,
                                             2013              2012
                                             (Unaudited)
ASSETS
Current assets
Cash and cash equivalents                    $    920,257  $    309,766
Accounts receivable, net                     390,882           445,506
Derivative contracts                         8,306             71,022
Costs in excess of billings and contract     6,276             11,229
loss
Prepaid expenses                             37,857            31,319
Restricted deposit                           -                 255,000
Other current assets                         39,684            19,043
         Total current assets                1,403,262         1,142,885
Oil and natural gas properties, using full
cost method of accounting
 Proved                                     10,663,810        12,262,921
 Unproved                                    529,032           865,863
 Less: accumulated depreciation, depletion   (5,643,158)       (5,231,182)
 and impairment
                                             5,549,684         7,897,602
Other property, plant and equipment, net     576,390           582,375
Derivative contracts                         15,478            23,617
Other assets                                 124,630           144,252
         Total assets                        $   7,669,444   $  9,790,731
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses        $    774,115  $    766,544
Billings and contract loss in excess of      -                 15,546
costs incurred
Derivative contracts                         36,471            14,860
Asset retirement obligations                 71,446            118,504
Deposit on pending sale                     -                 255,000
         Total current liabilities           882,032           1,170,454
Long-term debt                               3,194,784         4,301,083
Derivative contracts                         24,542            59,787
Asset retirement obligations                 358,301           379,906
Other long-term obligations                  24,237            17,046
         Total liabilities                   4,483,896         5,928,276
Commitments and contingencies
Equity
SandRidge Energy, Inc. stockholders' equity
Preferred stock, $0.001 par value, 50,000
shares authorized
 8.5% Convertible perpetual preferred stock;
 2,650 shares issued and outstanding at
 September 30, 2013 and December 31, 2012;   3                 3
 aggregate liquidation preference of
 $265,000
 6.0% Convertible perpetual preferred stock;
 2,000 shares issued and outstanding at
 September 30, 2013 and December 31, 2012;   2                 2
 aggregate liquidation preference of
 $200,000
 7.0% Convertible perpetual preferred stock;
 3,000 shares issued and outstanding at
 September 30, 2013 and December 31, 2012;   3                 3
 aggregate liquidation preference of
 $300,000
 Common stock, $0.001 par value, 800,000
 shares authorized; 491,805 issued and
 490,536outstanding at September 30, 2013   483               476
 and 491,578 issued and 490,359 outstanding
 at December 31, 2012
Additional paid-in capital                   5,292,792         5,233,019
Additional paid-in capital - stockholder     (5,000)           (5,000)
receivable
Treasury stock, at cost                      (8,763)           (8,602)
Accumulated deficit                          (3,465,661)       (2,851,048)
         Total SandRidge Energy, Inc.        1,813,859         2,368,853
         stockholders' equity
Noncontrolling interest                      1,371,689         1,493,602
         Total equity                        3,185,548         3,862,455
         Total liabilities and equity        $   7,669,444   $  9,790,731



SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)
                                             Nine Months Ended September 30,
                                             2013             2012^(1)
                                             (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
 Net (loss) income                           $ (563,576)      $ 541,100
 Adjustments to reconcile net (loss) income
 to net cash provided by operating
 activities
    Depreciation, depletion and amortization 480,696          438,809
    Accretion of asset retirement            28,051           19,625
    obligations
    Impairment                               16,330           -
    Debt issuance costs amortization         7,730            11,348
    Amortization of discount, net of         913              1,940
    premium, on long-term debt
    Bargain purchase gain                    -                (122,696)
    Loss on extinguishment of debt           82,005           3,056
    Deferred income tax provision (benefit)  4,702            (100,288)
    Loss (gain) due to change in fair value  56,085           (234,705)
    of derivative contracts
    Loss due to amendment of derivative      -                117,108
    contracts
    Gain due to contractual maturity of      (3,963)          (17,783)
    financing derivative contracts
    Loss on sale of assets                   398,364          3,755
    Stock-based compensation                 79,317           33,128
    Other                                    1,485            (259)
    Changes in operating assets and          6,868            (109,908)
    liabilities
                   Net cash provided by      595,007          584,230
                   operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
 Capital expenditures for property, plant    (1,163,539)      (1,625,737)
 and equipment
 Acquisitions of assets                      (15,527)         (837,019)
 Proceeds from sale of assets                2,567,355        422,171
                   Net cash provided by
                   (used in) investing       1,388,289        (2,040,585)
                   activities
CASH FLOWS FROM FINANCING ACTIVITIES
 Proceeds from borrowings                    -                1,850,344
 Repayments of borrowings                    (1,115,500)      (366,029)
 Premium on debt redemption                  (61,997)         (825)
 Debt issuance costs                         (91)             (48,220)
 Proceeds from issuance of royalty trust     -                587,086
 units
 Proceeds from sale of royalty trust units   28,985           123,548
 Noncontrolling interest distributions       (153,002)        (127,023)
 Stock-based compensation excess tax benefit (4)              8
 Purchase of treasury stock                  (31,270)         (12,807)
 Dividends paid - preferred                  (45,025)         (45,025)
 Cash received (paid) on settlement of       5,099            (38,703)
 financing derivative contracts
                   Net cash (used in)
                   provided by financing     (1,372,805)      1,922,354
                   activities
NET INCREASE IN CASH AND CASH EQUIVALENTS    610,491          465,999
CASH AND CASH EQUIVALENTS, beginning of year 309,766          207,681
CASH AND CASH EQUIVALENTS, end of period     $ 920,257       $ 673,680
Supplemental Disclosure of Cash Flow
Information
 Cash paid for interest, net of amounts      $ (248,233)      $ (181,386)
 capitalized
 Cash paid for income taxes                  $   (2,911)    $   (1,324)
Supplemental Disclosure of Noncash Investing
and Financing Activities
 Deposit on pending sale                     $ (255,000)      $       -
 Change in accrued capital expenditures      $  (65,087)     $  66,033
 Adjustment to oil and natural gas           $         $  10,000
 properties for estimated contract loss     -
 Asset retirement costs capitalized          $    4,145    $   5,363
 Common stock issued in connection with      $         $ 542,138
 acquisition                                 -

^(1) Includes retrospective application of acquisition purchase price
     adjustments recorded in fourth quarter of 2012.



For further information, please contact:

Investor Relations
SandRidge Energy, Inc.
123 Robert S. Kerr Avenue
Oklahoma City, OK 73102-6406
(405) 429-5515

Cautionary Note to Investors - This press release includes "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933,
as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended, including, but not limited to, the information appearing under the
heading "Operational Guidance." These statements express a belief, expectation
or intention and are generally accompanied by words that convey projected
future events or outcomes. The forward-looking statements include projections
and estimates of net income and EBITDA, drilling plans, oil and natural gas
production, derivative transactions, pricing differentials, operating costs,
general and administrative costs, capital spending, plugging and abandonment
costs, tax rates, liquidity, and descriptions of our development plans and
appraisal programs. We have based these forward-looking statements on our
current expectations and assumptions and analyses made by us in light of our
experience and our perception of historical trends, current conditions and
expected future developments, as well as other factors we believe are
appropriate under the circumstances. However, whether actual results and
developments will conform with our expectations and predictions is subject to
a number of risks and uncertainties, including the volatility of oil and
natural gas prices, our success in discovering, estimating, developing and
replacing oil and natural gas reserves, actual decline curves and the actual
effect of adding compression to gas wells, the availability and terms of
capital, the ability of counterparties to transactions with us to meet their
obligations, our timely execution of hedge transactions, credit conditions of
global capital markets, changes in economic conditions, the amount and timing
of future development costs, the availability and demand for alternative
energy sources, regulatory changes, including those related to carbon dioxide
and greenhouse gas emissions, and other factors, many of which are beyond our
control. We refer you to the discussion of risk factors in (a) Part I, Item 1A
- "Risk Factors" of our Annual Report on Form 10-K for the year ended December
31, 2012 and (b) comparable "risk factors" sections of our Quarterly Reports
on Form 10-Q filed thereafter. All of the forward-looking statements made in
this press release are qualified by these cautionary statements. The actual
results or developments anticipated may not be realized or, even if
substantially realized, they may not have the expected consequences to or
effects on our company or our business or operations. Such statements are not
guarantees of future performance and actual results or developments may differ
materially from those projected in the forward-looking statements. We
undertake no obligation to update or revise any forward-looking statements.

SandRidge Energy, Inc. is an oil and natural gas company headquartered in
Oklahoma City, Oklahoma with its principal focus on exploration and
production. SandRidge and its subsidiaries also own and operate gas gathering
and processing facilities and conduct marketing operations. In addition,
Lariat Services, Inc., a wholly-owned subsidiary of SandRidge, owns and
operates a drilling rig and related oil field services business. SandRidge
focuses its exploration and production activities in the Mid-Continent, Gulf
of Mexico, West Texas and Gulf Coast regions. SandRidge's internet address is
www.sandridgeenergy.com.

SOURCE SandRidge Energy, Inc.

Website: http://www.sandridgeenergy.com
 
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