SandRidge Energy, Inc. Updates Shareholders on Operations and Reports Financial Results for Fourth Quarter and Full Year 2013

    SandRidge Energy, Inc. Updates Shareholders on Operations and Reports
           Financial Results for Fourth Quarter and Full Year 2013

Exceeded 2013 Production Guidance with Lower than Projected Capital
Expenditures

- Produced 33.8 MMBoe, 1% more than guidance of 33.6 MMBoe

- Spent $1.424 Billion, 2% less than guidance of $1.450 Billion

Increased Mid-Continent Production 8% to 51.7 MBoe per Day from the Previous
Quarter, 44% Above the Fourth Quarter of 2012

Delivered 80 Mid-Continent Wells with an Average 30-day IP of 386 Boe per Day
during the Fourth Quarter; 2013 Average 30-day IP was 366 Boe per Day

Successful Appraisal Program Adds Sumner County, Kansas to the Focus Area

Increased PUD Type Curve: Oil EUR Up 10% and Boe EUR Up 3%

434% Reserve Replacement and All-in Finding and Development Cost of $11.72 per
Boe, Based on Retained Properties

PR Newswire

OKLAHOMA CITY, Feb. 27, 2014

OKLAHOMA CITY, Feb. 27, 2014 /PRNewswire/ -- SandRidge Energy, Inc. (NYSE: SD)
today announced financial and operational results for the quarter and year
ended December 31, 2013. Additionally, presentation slides will be available
on the company's website, www.sandridgeenergy.com, under Investor
Relations/Events at 7am EST on February 28.

SandRidge Energy, Inc. logo.

James Bennett, SandRidge's Chief Executive Officer and President, commented,
"I'm pleased to report our changes at SandRidge are yielding strong economic
results for our shareholders. We're executing, having new successes, and the
teams are working on innovationsto dramatically improve already strong
returns. With our advantaged infrastructure and focus, we can economically do
what others can't in the Mid-Continent, where multi-zone horizontal drilling
is still a new approach in this oily basin.

"We are already producing from six oil rich zones in the Mid-Continent focus
area. Consistent execution and continued improvements have increased our
Mississippian type curve EUR by 3% over 2012, while reserve replacement was
434%. As an example of appraisal success, we've now added Sumner County,
Kansas, where we have over 100,000 acres, to our focus area.  We look forward
to giving more detail on all of this, introducing our three year production
outlook as well as discussing our ideas to unlock the value of our water
disposal business, at our New York City analyst day March 4."

Key Financial Results

Fourth Quarter

  oPro forma for divestitures and net of Noncontrolling Interest, adjusted
    EBITDA was $166 million in
    the fourth quarter of 2013 compared to $130 million in the fourth quarter
    of 2012. Adjusted
    EBITDA, net of Noncontrolling Interest, was $229 million for fourth
    quarter 2013 compared to
    $318 million in fourth quarter 2012.
  oAdjusted operating cash flow of $218 million for fourth quarter 2013
    compared to $259 million in fourth quarter 2012.
  oAdjusted net income of $14.9 million, or $0.03 per diluted share, for
    fourth quarter 2013 compared to adjusted net income of $35.3 million, or
    $0.06 per diluted share, in fourth quarter 2012.

Full Year

  oPro forma for divestitures and net of Noncontrolling Interest, adjusted
    EBITDA was $609 million
    for 2013 compared to $365 million for 2012. Adjusted EBITDA, net of
    Noncontrolling Interest, was
    $1,020 million for 2013 compared to $1,070 million in 2012.
  oAdjusted operating cash flow of $812 million for 2013 compared to $915
    million in 2012.
  oAdjusted net income of $103.9 million, or $0.18 per diluted share, for
    2013 compared to adjusted net income of $124.3 million, or $0.23 per
    diluted share, in 2012.

Adjusted net income available to common stockholders, adjusted EBITDA, pro
forma adjusted EBITDA and 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 11.

Highlights

David Lawler, SandRidge's Chief Operating Officer, commented, "Our
Mid-Continent business units delivered another exceptional quarter. In
addition to bringing 80 horizontal wells online for a record average low of
$2.9 million each, we achieved our lowest Mid-Continent operating cost to
dateat $6.91 per Boe. The reduction in capital expenditures is linked
primarily to redesigned well site facilities and synchronized pad drilling.
Beyond these leading metrics, our appraisal program expanded our focus area to
Sumner County, Kansas. Five wells drilled in the area produced an average
30-day IP of 601 Boe per day, or 90% above year-end 2013 Type Curve. The new
development area consists of 117,000 net acres, and we plan to drill 45 wells
there in 2014. The Chester horizontal program continued to exceed expectations
with two additional wells delivering an average 30-day IP of 726 Boe per day
at 85% oil. SandRidge is the first mover of horizontal Chester development
targeting oil, and we plan to rapidly accelerate this program in 2014. By the
end of the second quarter, we anticipate 12 additional wells will be online.
Furthermore, our second tranche of Woodford test wells showed a marked
improvement over the first tranche. Of the two new wells, one delivered a
30-day IP of 96 Boe per day at 67% oil, and the second delivered a 30-day IP
of 190 Boe per day at 85% oil."

Fourth Quarter Operational Highlights

  oAdded new focus area in Sumner County, Kansas

       oFive appraisal wells in the area delivered 601 Boe per day 30-day
         IPs, ~2x type curve
       oAdded 117,000 acres to focus area through appraisal drilling success

  oNotable 30-day IP results during the fourth quarter

       oThree wells greater than 1,000 Boe per day with an average of 1,401
         Boe per day
       oTwo Chester wells averaged 726 Boe per day (85% oil)
       o80 Mid-Continent wells averaged 386 Boe per day

  oTwo new Woodford wells: Enhanced understanding yields improving results

       oFirst well had a 30-day IP of 96 Boe per day (67% oil)
       oSecond well had a 30-day IP of 190 Boe per day (85% oil)

  oReduced fourth quarter average Mid-Continent well cost to $2.9 million
  oReduced fourth quarter Mid-Continent LOE to $6.91 per Boe

Full Year Operational Highlights

  o2013 year-end reserve metrics (based on retained properties only which
    excludes divested Gulf of Mexico and Permian properties)

       o10% increase in Mississippian PUD type curve oil EUR to 118 Mbo and
         3% increase in overall EUR to 380 MBoe
       oAdded 117 MMBoe through the drillbit with 520% drillbit reserve
         replacement
       o434% reserve replacement overall with all-in F&D of $11.72 per Boe
       o41% increase in consolidated SEC PV-10 reserves value to $4.1 billion
       o25% increase in consolidated proved reserves to 377 MMBoe
       o29% increase in consolidated proved liquids reserves of 173 MMBbls
       o63% of total reserves are proved developed reserves, 68% of value is
         proved developed
       oProved reserves/production ratio of 16.7 years

  oNotable 30-day IP results during 2013

       o17 wells greater than 1,000 Boe per day with an average of 1,342 Boe
         per day

  oReduced average full-year Mid-Continent well cost by 11% to $3.1 million
  oReduced full-year Mid-Continent LOE by 14% to $7.53 per Boe
  oProducer to disposal well ratio improved from 7x in 2012 to 16x in 2013.
    Additionally, SWD capex as a percent of Mid-Continent capex decreased from
    24% to 12% year-over-year.
  oDrilled 28 disposal wells in 2013 and exited the year disposing
    approximately 935,000 gross barrels of water per day

Financial / Other Highlights

  oPro forma Adjusted EBITDA grew 67% year-over-year to $609 million
  oClosed sale of Gulf of Mexico business on February 25, 2014 for $750
    million, subject to customary adjustments
  oPro forma for the Gulf of Mexico sale, year-end liquidity of $2.3 billion
    ($1.55 billion of cash) and a 2.7x leverage ratio
  o94% of liquids production hedged and 65% of natural gas production hedged
    in 2014

Drilling and Operational Activities

Mid-Continent. During the fourth quarter of 2013, SandRidge drilled 94
horizontal wells: 66 in Oklahoma and 28 in Kansas. SandRidge also drilled
eight 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. The company's
Mid-Continent assets produced 51.7 MBoe per day during the fourth quarter (49%
liquids).

Gulf of Mexico / Gulf Coast. The company's Gulf of Mexico and Gulf Coast
assets produced 23 MBoe per day during the fourth quarter of 2013 (53%
liquids).

Permian Basin. In the company's Permian properties, 49 wells were drilled
during the fourth quarter of 2013, all for SandRidge Permian Trust. The
company's Permian Basin assets produced 6.2 MBoe per day during the quarter
(96% liquids).

Other Operating Areas. During the fourth quarter, SandRidge's legacy West
Texas properties produced approximately 6.3 MBoe per day (99% natural gas).
Additionally, its legacy Mid-Continent assets produced 1.9 MBoe per day in the
quarter (79% natural gas).

Royalty Trusts. At December 31, 2013, the company was obligated to drill 22
development wells for SandRidge Mississippian Trust II ("SDR") and 205
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.

Analysis of Changes in Consolidated Proved Reserves

While producing 34 million barrels of oil equivalent (MMBoe) in 2013
(including 11.2 MMBoe of production associated with divested assets in the
Gulf of Mexico, Gulf Coast, and Permian Basin), SandRidge added 119 MMBoe to
proved reserves during 2013 from discoveries and extensions. Horizontal
drilling in the Mississippian play contributed 107 MMBoe of the additions.

The company's overall reserve additions were 100 MMBoe, after taking into
account positive pricing revisions of 17 MMBoe and negative revisions of
previous estimates of 36 MMBoe. The negative revisions are primarily linked to
the company's ongoing efforts to high grade its drilling plan. Numerous
additional high quality drilling locations replaced certain former PUD
locations in the company's five year drilling plan and resulted in an improved
type curve. Because the company no longer anticipates drilling these locations
within five years, it removed them from the PUD classification, resulting in a
majority of the negative revisions. The company's PUD type curve includes a
10% improved oil EUR to 118 MBo and, overall, a 3% increase to 380 MBoe.

Considering only those assets retained by the company after the Gulf sale, the
company achieved reserve replacement of 434%, primarily due to continued
successful execution of horizontal drilling programs in the Mississippian
play. SandRidge's all-in finding and development cost for retained assets was
$11.72 per barrel of oil equivalent.



SEC Reserves  Oil        NGL       Liquids    Gas        Net Resv    PV-10
and Value     (MBbls)    (MBbls)   (MBbls)    (MMcf)     (MBoe)^(1)  (in
                                                                     thousands)^(2)
Year End                                                             $  
2012 ($91.21 262,045    67,994    330,039    1,415,042  565,880     7,488,444
/ $2.76)
Sales         (131,769)  (29,067)  (160,836)  (228,229)  (198,874)
Acquisitions  43         13        56         363        117
Production    (14,279)   (2,291)   (16,570)   (103,233)  (33,776)
Extensions    40,570     18,686    59,256     359,918    119,242
Revisions - (12,560)   15        (12,545)   (141,156)  (36,071)
Performance
Revisions -
Pricing /     (1,409)    3,702     2,293      87,724     16,913
Differentials
Year End                                                             $  
2013 ($93.42 142,641    59,052    201,693    1,390,429  433,431     5,191,635
/ $3.67)
Southern
Division Sale (26,332)   (2,569)   (28,901)   (167,375)  (56,797)    (1,088,872)
Adjustments
Pro Forma     116,309    56,483    172,792    1,223,054  376,634     $  
Year End 2013                                                        4,102,763
Pro Forma
Year End
2013: Proved  56%        60%       57%        69%        63%         68%
Developed as
a percent of
Total Proved

^(1) Includes approximately 29,922 MBoe and 38,230 MBoe attributable to
     noncontrolling interests at December 31, 2013 and 2012, respectively.
     Includes PV-10 attributable to noncontrolling interests of approximately
^(2) $783 million and $955 million at December 31, 2013 and 2012,
     respectively.

Standardized Measure of Discounted Net Cash Flows to PV-10 Reconciliation

                                     Year End
                                             Sale           Pro Forma
                                     2013    Adjustment     2013        2012
                                     (in millions)
Standardized measure of discounted   $4,018  $    (843)  $  3,175  $5,840
net cash flows ^(1)(2)
Present value of future net income   1,174   (246)          928         1,648
tax expense discounted at 10%
PV-10 ^(3)                           $5,192  $  (1,089)   $  4,103  $7,488

     Includes approximately $782 million and $953 million attributable to
^(1) SandRidge noncontrolling interests at December 31, 2013 and 2012,
     respectively.
     Sale adjustment represents an allocation of the Company's Standardized
^(2) Measure to the sale properties based on PV-10 attributable to sale
     properties relative to the Company's total PV-10.
     Includes approximately $783 million and $955 million attributable to
^(3) SandRidge noncontrolling interests at December 31, 2013 and 2012,
     respectively.

Operational and Financial Statistics

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

                           Three Months Ended December  Year Ended December
                           31,                          31,
                           2013            2012         2013        2012
Production
Oil (MBbl)                 3,377           4,451        14,279      15,868
NGL (MBbl)                 683             586          2,291       2,094
Natural gas (MMcf)         24,891          28,717       103,233     93,549
Oil equivalent (MBoe)      8,209           9,823        33,776      33,553
Daily production (MBoed)   89.2            106.8        92.5        91.7
Average price per unit
Oil price per barrel - as  $ 94.96        $ 88.15     $ 97.58    $ 91.79
reported
Impact of derivatives per  2.12            10.63        1.32        5.74
barrel
Net price per barrel       $ 97.08        $ 98.78     $ 98.90    $ 97.53
NGL price per barrel - as  $ 36.74        $ 31.96     $ 35.16    $ 33.10
reported
Impact of derivatives per  -               -            -           -
barrel
Net price per barrel       $ 36.74        $ 31.96     $ 35.16    $ 33.10
Natural gas price per Mcf  $ 3.33          $ 3.09       $ 3.36      $ 2.49
- as reported
Impact of derivatives per  0.23            (0.30)       0.10        (0.03)
Mcf
Net price per Mcf          $   3.56      $  2.79    $  3.46   $  2.46
Price per Boe - as         $ 49.17        $ 50.89     $ 53.89    $ 52.43
reported
Net price per Boe -
including impact of        $ 50.73        $ 59.96      $ 54.79     $ 55.04
derivatives
Average cost per Boe
Lease operating ^(1)       $ 18.37        $ 13.67     $ 15.29    $ 14.22
Production taxes           0.91            1.12         0.96        1.41
General and
administrative
 General and
 administrative,           $  3.87       $  7.45     $ 7.26      $  5.93
 excluding stock-based
 compensation
 Stock-based compensation  0.73            0.98         2.52        1.28
 Total general and         $  4.60       $  8.43     $ 9.78      $  7.21
 administrative
General and
administrative - adjusted
 General and
 administrative,           $  3.49       $  4.62     $ 4.14      $   4.64
 excluding stock-based
 compensation ^(2)
 Stock-based compensation  0.63            0.98         0.88        1.28
 ^(3)
 Total general and
 administrative -          $  4.12       $  5.60     $ 5.02      $   5.92
 adjusted
Depletion ^(4)             $ 17.35         $ 18.83      $ 17.90    $  17.79
Lease operating cost per
Boe
Mid-Continent              $  6.91       $  7.55     $  7.53   $   8.75
Offshore                   30.27           19.71        24.60       $ 21.77
Earnings per share
Earnings (loss) per share
applicable to common
stockholders
 Basic                     $  0.01       $  (0.63)   $  (1.27)  $  0.19
 Diluted                   0.01            (0.63)       (1.27)      0.19
Adjusted net income per
share available to common
stockholders
 Basic                     $  0.00       $  0.04    $  0.10   $  0.15
 Diluted                   0.03            0.06         0.18        0.23
Weighted average number
of common shares
outstanding (in
thousands)
 Basic                     483,936         476,241      481,148     453,595
 Diluted ^(5)              574,832         566,664      571,801     546,148

^(1) Includes shortfall penalties related to CO[2 ]delivery requirement.
     Excludes transaction costs, legal settlements, severance, annual
     incentive plan adoption effect and consent solicitation costs totaling
     $3.2 million and $105.4 million for the three-month period and year ended
^(2) December 31, 2013, respectively. Excludes transaction costs, legal
     settlements and consent solicitation costs totaling $27.8 million and
     $43.1 million for the three-month period and year ended December 31,
     2012, respectively.
     Three-month period and year ended December 31, 2013 exclude $0.8 million
^(3) and $55.5 million, respectively, for the acceleration of certain stock
     awards.
^(4) Includes accretion of asset retirement obligation.
^(5) Includes shares considered antidilutive for calculating earnings per
     share in accordance with GAAP for certain periods presented.

Discussion of 2013 Financial Results

Fourth Quarter

Oil and natural gas revenue decreased 14% to $429 million in the fourth
quarter of 2013 from $500 million in the same period of 2012 primarily as a
result of a 16% decrease in total production due to the Permian divestiture
that closed during the first quarter of 2013. Reported prices, which exclude
the impact of derivative settlements, were $94.96 per barrel of oil and $3.33
per Mcf of natural gas during the fourth quarter of 2013 compared to $88.15
per barrel and $3.09 per Mcf in the same period of 2012.

During the fourth quarter of 2013, production expense was $18.37 per Boe
compared to $13.67 per Boe in the fourth quarter of 2012. The increase was
primarily due to an accrual of 2013 shortfall penalties related to the
Company's CO[2] delivery requirement in the WTO. In SandRidge's Mid-Continent
operations, fourth quarter production expense decreased 8% year-over-year to
$6.91 from $7.55 per Boe as a result of continued efficiency improvements.

Full Year

Oil and natural gas revenue increased 3% to $1,820 million in 2013 from $1,759
million in 2012 as a result of increases in average prices received for oil
and natural gas production. Realized reported prices increased to $97.58 per
barrel of oil and $3.36 per Mcf during 2013 compared to $91.79 per barrel and
$2.49 per Mcf in 2012. Total 2013 production was consistent with 2012. The
table below presents 2013 and 2012 production by area.

                           2013          2012
                           (MBoe)        (MBoe)
Mid-Continent              17,027  50%   10,149  30%
Gulf of Mexico/Gulf Coast  10,082  30%   8,110   24%
Permian Basin              3,366   10%   10,963  33%
Other                      3,301   10%   4,331   13%
                           33,776  100%  33,553  100%

Production expense for 2013 was $15.29 per Boe compared to 2012 production
expense of $14.22 per Boe due primarily to WTO CO[2] shortfall delivery
penalties. In the company's Mid-Continent operations, 2013 production expense
decreased 14% year-over-year to $7.53 from $8.75 per Boe.

Capital Expenditures

The table below summarizes the company's capital expenditures for the
three-month period and year ended December 31, 2013 and 2012:

                               Three Months Ended    Year Ended December 31,
                               December 31,
                               2013       2012       2013         2012
                               (in thousands)
Drilling and production
     Mid-Continent             $197,145   $251,108   $  844,167  $  927,186
     Permian Basin             36,574     120,667    192,477      645,045
     Gulf of Mexico/Gulf       30,968     65,081     192,668      169,458
     Coast
     WTO/Tertiary/Other        -          1,621      -            22,370
                               264,687    438,477    1,229,312    1,764,059
Leasehold and seismic
     Mid-Continent             48,263     10,024     100,874      156,961
     Permian Basin             493        2,555      14           15,463
     Gulf of Mexico/Gulf       2,377      3,205      4,449        16,097
     Coast
     WTO/Tertiary/Other        1,375      24         5,686        2,307
                               52,508     15,808     111,023      190,828
Inventory                      (7,563)    4,060      (21,947)     (3,941)
Total exploration and          309,632    458,345    1,318,388    1,950,946
development
Drilling and oil field         2,468      302        7,125        27,527
services
Midstream                      8,823      18,454     55,706       80,413
Other - general               4,505      23,688     42,664       115,096
Total capital expenditures,    325,428    500,789    1,423,883    2,173,982
excluding acquisitions
Acquisitions                   1,501      (13,758)   17,028       840,740
Total capital expenditures     $326,929   $487,031   $1,440,911   $3,014,722
Plugging and abandonment       $ 26,066  $ 19,728  $  133,626  $   84,361

Derivative Contracts

The table below sets forth the company's consolidated oil and natural gas
price swaps and collars for the years 2014 and 2015 as of February 25, 2014
and include contracts that have been novated to or the benefits of which have
been conveyed to SandRidge sponsored royalty trusts.

                         Quarter Ending
                         3/31/2014   6/30/2014   9/30/2014  12/31/2014
Oil (MMBbls):
 Swap Volume             1.36        0.74        1.01       1.19
 Swap                    $95.85      $100.56     $99.41     $98.80
 Three-way Collar Volume 1.96        1.93        2.07       2.07
 Call Price             $100.00     $100.00     $100.00    $100.00
 Put Price              $90.21      $90.22      $90.20     $90.20
 Short Put Price        $70.00      $70.00      $70.00     $70.00
Natural Gas (Bcf):
 Swap Volume             14.68       13.65       13.80      11.04
 Swap                    $4.23       $4.25       $4.25      $4.31
 Collar Volume           0.23        0.23        0.24       0.24
 Collar: High           $7.78       $7.78       $7.78      $7.78
 Collar: Low            $4.00       $4.00       $4.00      $4.00
                         Year Ending
                         12/31/2014  12/31/2015
Oil (MMBbls):
 Swap Volume             4.29        5.31
 Swap                    $98.31      $92.55
 Three-way Collar Volume 8.03        2.92
 Call Price             $100.00     $103.13
 Put Price              $90.21      $90.82
 Short Put Price        $70.00      $73.13
Natural Gas (Bcf):
 Swap Volume             53.17       15.40
 Swap                    $4.26       $4.50
 Collar Volume           0.94        1.01
 Collar: High           $7.78       $8.55
 Collar: Low            $4.00       $4.00

Balance Sheet

The company's capital structure at December 31, 2013 and December 31, 2012 is
presented below (in thousands):

                                    December 31,           December 31,
                                    2013                   2012
                                    (in thousands)
Cash and cash equivalents           $      814,663    $   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,     -                      356,657
  net
  8.0% Senior Notes due 2018        -                      750,000
  8.75% Senior Notes due 2020, net  444,736                444,127
  7.5% Senior Notes due 2021        1,178,922              1,179,328
  8.125% Senior Notes due 2022      750,000                750,000
  7.5% Senior Notes due 2023, net   821,249                820,971
   Total debt                     3,194,907              4,301,083
Stockholders' equity
 Preferred stock                    8                      8
 Common stock                       483                    476
 Additional paid-in capital         5,294,551              5,228,019
 Treasury stock, at cost            (8,770)                (8,602)
 Accumulated deficit                (3,460,462)            (2,851,048)
  Total SandRidge Energy, Inc.      1,825,810              2,368,853
  stockholders' equity
 Noncontrolling interest            1,349,817              1,493,602
Total capitalization                $    6,370,534     $  8,163,538

During the fourth quarter of 2013, the company's debt, net of cash balances,
increased by approximately $105 million as a result of funding the company's
drilling program. On February 25, 2014, the company had no amount drawn under
its $775 million senior credit facility and, due to the closing of the Gulf of
Mexico sale, approximately $1.35 billion of cash, leaving approximately $2.1
billion of available liquidity. The company was in compliance with all
applicable covenants contained in its debt agreements during 2013 and through
and as of the date of this release.

2014 Operational Guidance: The company is updating its 2014 guidance to
include adjusted EBITDA attributable to noncontrolling interest.

                                           Projection as of  Projection as of
                                           January 7, 2014   February 27, 2014
Production
     Oil (MMBbls)                          11.9              11.9
     Natural Gas Liquids (MMBbls)          3.6               3.6
      Total Liquids (MMBbls)             15.5              15.5
     Natural Gas (Bcf)                     83.0              83.0
      Total (MMBoe)                      29.3              29.3
Price Realization
     Oil (differential below NYMEX WTI)    $2.50             $2.50
     Natural Gas Liquids (realized % of    33%               33%
     NYMEX WTI)
     Natural Gas (differential below NYMEX $1.00             $1.00
     Henry Hub)
Costs per Boe
     Lifting                              $11.15 - $13.15   $11.15 - $13.15
     Production Taxes                      1.15 - 1.35       1.15 - 1.35
     DD&A - oil & gas                      15.60 - 17.60     15.60 - 17.60
     DD&A - other                          2.20 - 2.40       2.20 - 2.40
     Total DD&A                            $17.80 - $20.00   $17.80 - $20.00
     G&A - cash                            3.60 - 4.00       3.60 - 4.00
     G&A - stock                           0.65 - 0.80       0.65 - 0.80
     Total G&A                             $4.25 - $4.80     $4.25 - $4.80
EBITDA from Oilfield Services, Midstream   $20               $20
and Other ($ in millions)^(1)
Adjusted Net Income Attributable to
Noncontrolling Interest ($ in              $120              $120
millions)^(2)
Adjusted EBITDA Attributable to
Noncontrolling Interest ($ in                                $155
millions)^(3)
Corporate Tax Rate                         0%                0%
Deferral Rate                              0%                0%
Capital Expenditures ($ in millions)
     Exploration and Production            $1,230            $1,230
     Land and Seismic                      120               120
     Total Exploration and Production      $1,350            $1,350
     Oil Field Services                    15                15
     Midstream and Other                   110               110
     Total Capital Expenditures (excluding $1,475            $1,475
     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 loss due to changes in
      fair value of derivative 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.
      Adjusted EBITDA Attributable to Noncontrolling Interest is a non-GAAP
      financial measure as it excludes from net income interest expense,
      income tax expense, depreciation, depletion and amortization, gain or
      loss due to changes in fair value of derivative contracts and gain or
^(3) loss on sale of assets. The most directly comparable GAAP measure for
      Adjusted EBITDA 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, pro forma adjusted EBITDA,
adjusted net income, adjusted net income attributable to noncontrolling
interest and pro forma liquidity 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 received (paid) on financing derivatives. It defines EBITDA
as net income (loss) before income tax (benefit) expense, 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, (gain) loss on derivative contracts net of cash
received on settlement of derivative contracts, loss (gain) 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 and stock-based compensation). Pro forma
adjusted EBITDA, as presented herein, is adjusted EBITDA excluding adjusted
EBITDA attributable to properties or subsidiaries sold during the period or to
be sold in future periods.

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 (benefit) expense resulting from
divestiture/acquisition, asset impairment, (gain) loss on derivative contracts
net of cash received on settlement of derivative contracts, loss (gain) on
sale of assets, 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 other
non-cash items from income available (loss applicable) 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 income
available (loss applicable) 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 (gain)
loss on derivative contracts net of cash received on settlement of derivative
contracts, legal settlement and loss on sale of assets attributable to third
party ownership in less than wholly-owned consolidated subsidiaries from net
income (loss) 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 supplemental measure of pro forma liquidity as presented herein is cash
and cash equivalents adjusted for expected proceeds upon sale of properties or
subsidiaries and funds available to be drawn under the company's senior credit
facility and is used by the company's management to measure the company's
ability to meet its future capital funding needs.

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

Reconciliation of Net Cash Provided by Operating Activities to Operating Cash
Flow
                          Three Months Ended December  Year Ended December 31,
                          31,
                          2013            2012         2013          2012
                          (in thousands)
Net cash provided by      $273,623        $198,930     $868,630      $783,160
operating activities
Add (deduct)
  Cash received (paid)
  on financing            1,561           4,185        6,660         (34,518)
  derivatives
  Changes in operating    (56,813)        56,198       (63,681)      166,100
  assets and liabilities
Adjusted operating cash   $218,371        $259,313     $811,609      $914,742
flow



Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA
                              Three Months Ended      Year Ended December 31,
                              December 31,
                              2013         2012       2013         2012
                              (in thousands)
Net income (loss)             $       $      $        $     
                              19,080      (287,904)  (553,889)   141,571
Adjusted for
 Income tax (benefit)         (1,616)      12         5,684        (100,362)
 expense
 Interest expense ^(1)        62,155       88,793     274,591      312,869
 Depreciation and             15,508       15,729     62,136       60,805
 amortization - other
 Depreciation and depletion   133,664      175,577    567,732      568,029
 - oil and natural gas
 Accretion of asset           8,726        9,371      36,777       28,996
 retirement obligations
EBITDA                        237,517      1,578      393,031      1,011,908
 Asset impairment             9,950        314,723    26,280       316,004
 Interest income              (375)        (450)      (1,962)      (1,466)
 Stock-based compensation     4,582        8,982      27,351       39,682
 (Gain) loss on derivative    (22,928)     (19,712)   47,123       (241,419)
 contracts
 Cash received on settlement
 of derivative contracts      12,780       43,058     31,499       100,328
 ^(2)
 Other non-cash expense       465          (2,151)    189          (9,966)
 (income)
 Loss (gain) on sale of       722          (666)      399,086      3,089
 assets ^(3)
 Transaction costs            37           369        2,255        15,645
 Legal settlements            (5,689)      25,000     (4,608)      25,000
 Consent solicitation costs   499          2,420      22,834       2,420
 Effect of Annual Incentive   -            -          14,735       -
 Plan adoption
 Severance                    2,130        -          122,505      -
 Bargain purchase gain        -            -          -            (122,696)
 Loss on extinguishment of    -            19         82,005       3,075
 debt
 Non-cash portion of
 noncontrolling interest      (10,575)     (54,955)   (142,670)    (71,647)
 ^(4)
Adjusted EBITDA               $        $      $         $   
                              229,115     318,215   1,019,653   1,069,957
Pro forma adjustments
 Less EBITDA attributable to
      Permian properties      -            (89,879)   (50,574)     (435,738)
      sold
      Tertiary properties     -            -          -            (7,996)
      sold
      Gulf of Mexico          (63,099)     (97,862)   (360,045)    (260,742)
      properties sold (2014)
Pro Forma Adjusted EBITDA     $        $      $       $     
                              166,016     130,474   609,034      365,481

     Excludes non-cash gains on interest rate swaps of $2.4 million for the
^(1) three-month period ended December 31, 2012 and $2.4 million and $8.1
     million for the years ended December 31, 2013 and 2012, respectively.
^(2) Excludes amounts (paid) received on early settlement of derivative
     contracts.
^(3) Includes loss on sale of Permian oil and natural gas assets of
     approximately $398.9 million for the year ended December 31, 2013.
     Represents depreciation and depletion, loss on sale of Permian
^(4) Properties, (gain) loss on commodity derivative contracts net of cash
     received on settlement, legal settlement and income tax expense
     attributable to noncontrolling interests.



Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA
                         Three Months Ended December  Year Ended December 31,
                         31,
                         2013            2012         2013         2012
                         (in thousands)
Net cash provided by     $273,623        $198,930     $  868,630  $  783,160
operating activities
Changes in operating     (56,813)        56,198       (63,681)     166,100
assets and liabilities
Interest expense ^(1)    62,155          88,793       274,591      312,869
Cash received on early
settlement of            -               -            -            (33,165)
derivative contracts
Cash paid on early
settlement of            -               -            29,623       -
derivative contracts -
Permian
Transaction costs        37              369          2,255        15,645
Legal settlements        (5,689)         25,000       (4,608)      25,000
Consent solicitation     499             2,420        22,834       2,420
costs
Effect of Annual         -               -            14,735       -
Incentive Plan adoption
Severance                1,319           -            67,004       -
Noncontrolling interest  (7,275)         (13,416)     (39,384)     (54,590)
- SDT ^(2)
Noncontrolling interest  (13,708)        (16,348)     (66,372)     (45,755)
- SDR ^(2)
Noncontrolling interest  (21,167)        (18,667)     (77,918)     (76,564)
- PER ^(2)
Noncontrolling interest  1,558           103          1,594        263
- Other ^(2)
Other non-cash items     (5,424)         (5,167)      (9,650)      (25,426)
Adjusted EBITDA          $229,115        $318,215     $1,019,653   $1,069,957

     Excludes non-cash gains on interest rate swaps of $2.4 million for the
^(1) three-month period ended December 31, 2012 and $2.4 million and $8.1
     million for the years ended December 31, 2013 and 2012, respectively.
     Excludes depreciation and depletion, loss on sale of Permian Properties,
^(2) (gain) loss on derivative contracts net of cash received on settlement,
     legal settlement and income tax expense attributable to noncontrolling
     interests.







Reconciliation of Income Available (Loss Applicable) to Common Stockholders to
Adjusted Net Income Available to Common Stockholders
                              Three Months Ended       Year Ended December 31,
                              December 31,
                              2013        2012         2013         2012
                              (in thousands except per share data)
Income available (loss
applicable) to common         $ 5,198     $(301,785)   $(609,414)   $ 86,046
stockholders
Tax (benefit) expense
resulting from                (860)       -            3,842        (100,288)
divestiture/acquisition
Asset impairment ^(1)         9,950       278,385      26,280       279,666
(Gain) loss on derivative     (21,449)    (17,447)     31,942       (207,505)
contracts ^(1)
Cash received (paid) on
settlement of derivative      12,723      37,984       31,313       84,405
contracts ^(1)
Loss (gain) on sale of        722         (666)        327,382      3,089
assets ^(1)
Transaction costs             37          369          2,255        15,645
Legal settlements ^(1)        (5,689)     25,000       (4,960)      25,000
Consent solicitation costs    499         2,420        22,834       2,420
Effect of Annual Incentive    -           -            14,735       -
Plan adoption
Severance                     2,130       -            122,505      -
Financing commitment fees     -           -            -            10,875
Bargain purchase gain         -           -            -            (122,696)
Loss on extinguishment of     -           19           82,005       3,075
debt
Other non-cash income         (2,203)     (2,886)      (4,752)      (10,961)
Effect of income taxes        (52)        13           2,359        42
Adjusted net income
available to common           1,006       21,406       48,326       68,813
stockholders
Preferred stock dividends     13,882      13,881       55,525       55,525
Total adjusted net income     $14,888     $  35,287   $ 103,851    $124,338
Weighted average number of
common shares outstanding
         Basic                483,936     476,241      481,148      453,595
         Diluted ^(2)         574,832     566,664      571,801      546,148
Total adjusted net income
         Per share - basic    $  0.00   $   0.04  $   0.10  $   0.15
         Per share -          $  0.03   $   0.06  $   0.18  $   0.23
         diluted

^(1) Excludes amounts attributable to noncontrolling interests.
     Weighted average fully diluted common shares outstanding for certain
^(2) periods presented includes shares that are considered antidilutive for
     calculating earnings per share in accordance with GAAP.





Reconciliation of Net Income (Loss) Attributable to Noncontrolling Interest to
Adjusted Net Income Attributable to Noncontrolling Interest
                            Three Months Ended      Year Ended December 31,
                            December 31,
                            2013       2012         2013            2012
                            (in thousands)
Net income (loss)
attributable to             $30,017    $ (6,626)    $ 39,410        $105,000
noncontrolling interest
Asset impairment            -          36,338       -               36,338
Loss on sale of assets -    -          -            71,704          -
Permian
Legal settlements           -          -            352             -
(Gain) loss on derivative   (1,479)    (2,265)      15,181          (33,914)
contracts
Cash received on
settlement of derivative    57         5,074        186             15,923
contracts
    Adjusted net income
    attributable to         $28,595    $32,521      $126,833        $123,347
    noncontrolling
    interest





Reconciliation of Cash and Cash Equivalents to Pro Forma Liquidity
                                                       December 31, 2013
                                                       (in thousands)
Cash and cash equivalents                              $        814,663
Estimated net sale proceeds - Gulf of Mexico           736,714
Properties
Pro forma cash and cash equivalents                    $      1,551,377
Availability under Senior Credit Facility ^(1)         745,900
Pro forma liquidity                                    $      2,297,277

^(1) Reduced by letters of credit totaling $29.1 million.

Conference Call Information

The company will host a conference call to discuss these results on Friday,
February 28, 2014 at 8:00 am CST. The telephone number to access the
conference call from within the U.S. is 866-953-6858 and from outside the U.S.
is 617-399-3482. The passcode for the call is 62015603. An audio replay of the
call will be available from February 28, 2014 until 11:59 pm CST on March 28,
2014. 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 34029572.

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

7^th Annual Investor/Analyst Meeting

  oMarch 4, 2014 (Tuesday), 8:00 am EST, at the New York Stock Exchange

Conference Participation

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

  oMarch 25, 2014 – Howard Weil 42^nd Annual Energy Conference; New Orleans,
    LA
  oApril 7, 2014 – IPAA's 20^th Annual OGIS New York; NYC, NY
  oMay 13, 2014 – 2014 Barclays High Yield Conference; Phoenix, AZ

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.

First Quarter 2014 Earnings Release and Conference Call

May 7, 2014 (Wednesday) – Earnings press release after market close
May 8, 2014 (Thursday) – Earnings conference call at 8:00 am CST

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(in thousands, except per share data)
                       Three Months Ended December  Years Ended December 31,
                       31,
                       2013          2012           2013           2012
                       (Unaudited)
Revenues
 Oil, natural gas and  $         $          $            $ 1,759,282
 NGL                   428,768       499,907        1,820,278
 Drilling and services 16,989        25,932         66,586         116,633
 Midstream and         15,450        12,620         58,304         40,486
 marketing
 Construction contract 96            796,323        23,349         796,323
 Other                 3,805         3,316          14,871         18,241
   Total revenues      465,108       1,338,098      1,983,388      2,730,965
Expenses
 Production            150,798       134,330        516,427        477,154
 Production taxes      7,473         10,988         32,292         47,210
 Cost of sales         11,680        15,759         57,118         68,227
 Midstream and         13,690        12,482         53,644         39,669
 marketing
 Construction contract 96            796,323        23,349         796,323
 Depreciation and
 depletion - oil and   133,664       175,577        567,732        568,029
 natural gas
 Depreciation and      15,508        15,729         62,136         60,805
 amortization - other
 Accretion of asset
 retirement            8,726         9,371          36,777         28,996
 obligations
 Impairment            9,950         314,723        26,280         316,004
 General and           37,750        82,884         330,425        241,682
 administrative
 (Gain) loss on        (22,928)      (19,712)       47,123         (241,419)
 derivative contracts
 Loss (gain) on sale   722           (666)          399,086        3,089
 of assets
   Total expenses      367,129       1,547,788      2,152,389      2,405,769
   Income (loss) from  97,979        (209,690)      (169,001)      325,196
   operations
Other income (expense)
 Interest expense      (61,780)      (85,921)       (270,234)      (303,349)
 Bargain purchase gain -             -              -              122,696
 Loss on
 extinguishment of     -             (19)           (82,005)       (3,075)
 debt
 Other income, net     11,282        1,112          12,445         4,741
   Total other expense (50,498)      (84,828)       (339,794)      (178,987)
Income (loss) before   47,481        (294,518)      (508,795)      146,209
income taxes
Income tax (benefit)   (1,616)       12             5,684          (100,362)
expense
Net income (loss)      49,097        (294,530)      (514,479)      246,571
 Less: net income
 (loss) attributable   30,017        (6,626)        39,410         105,000
 to noncontrolling
 interest
Net income (loss)
attributable to        19,080        (287,904)      (553,889)      141,571
SandRidge Energy, Inc.
Preferred stock        13,882        13,881         55,525         55,525
dividends
   Income available
   (loss applicable)
   to SandRidge        $        $           $           $  
   Energy, Inc.common 5,198        (301,785)     (609,414)     86,046
   stockholders
Earnings (loss) per
share
 Basic                 $        $        $        $    
                        0.01       (0.63)         (1.27)         0.19
 Diluted               $        $        $        $    
                        0.01       (0.63)         (1.27)         0.19
Weighted average
number of common
shares outstanding
 Basic                 483,936       476,179        481,148        453,595
 Diluted               483,936       476,179        481,148        456,015



SandRidge Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands, except per share data)
                                                 December 31,
                                                 2013              2012
ASSETS
Current assets
Cash and cash equivalents                        $             $    
                                                 814,663           309,766
Accounts receivable, net                         349,218           445,506
Derivative contracts                             12,779            71,022
Costs in excess of billings and contract loss    4,079             11,229
Prepaid expenses                                 39,253            31,319
Restricted deposit                               -                 255,000
Other current assets                             21,831            19,043
 Total current assets                        1,241,823         1,142,885
Oil and natural gas properties, using full cost
method of accounting
    Proved (includes development and project
    costs excluded from amortization of $45.6
    million and $72.4 million at December 31,    10,972,816        12,262,921
    2013 and 2012, respectively)
    Unproved                                     531,606           865,863
    Less: accumulated depreciation, depletion    (5,762,969)       (5,231,182)
    and impairment
                                                 5,741,453         7,897,602
Other property, plant and equipment, net         566,222           582,375
Derivative contracts                             14,126            23,617
Other assets                                     121,171           144,252
 Total assets                                $   7,684,795  $  
                                                                   9,790,731
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses            $             $    
                                                 812,488           766,544
Billings and contract loss in excess of costs    -                 15,546
incurred
Derivative contracts                             34,267            14,860
Asset retirement obligations                     87,063            118,504
Deposit on pending sale                         -                 255,000
 Total current liabilities                   933,818           1,170,454
Long-term debt                                   3,194,907         4,301,083
Derivative contracts                             20,564            59,787
Asset retirement obligations                     337,054           379,906
Other long-term obligations                      22,825            17,046
 Total liabilities                           4,509,168         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
    December 31,2013 and December 31, 2012;
    aggregate liquidation preference of          3                 3
    $265,000
    6.0% Convertible perpetual preferred stock;
    2,000 shares issued and outstanding at
    December 31, 2013 and December 31, 2012;
    aggregate liquidation preference of          2                 2
    $200,000
    7.0% Convertible perpetual preferred stock;
    3,000 shares issued and outstanding at
    December 31, 2013 and December 31, 2012;
    aggregate liquidation preference of          3                 3
    $300,000
Common stock, $0.001 par value, 800,000 shares
authorized; 491,609 issued and 490,290
outstanding atDecember 31, 2013 and 491,578
issued and 490,359 outstanding at December 31,   483               476
2012
Additional paid-in capital                       5,298,301         5,233,019
Additional paid-in capital - stockholder         (3,750)           (5,000)
receivable
Treasury stock, at cost                          (8,770)           (8,602)
Accumulated deficit                              (3,460,462)       (2,851,048)
 Total SandRidge Energy, Inc.               1,825,810         2,368,853
stockholders' equity
Noncontrolling interest                          1,349,817         1,493,602
 Total equity                               3,175,627         3,862,455
 Total liabilities and equity               $   7,684,795  $  
                                                                   9,790,731







SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)
                                                     Years Ended December 31,
                                                     2013          2012
CASH FLOWS FROM OPERATING ACTIVITIES
 Net (loss) income                                   $ (514,479)   $ 246,571
 Adjustments to reconcile net (loss) income to net
 cash provided by operating activities
    Depreciation, depletion and amortization         629,868       628,834
    Accretion of asset retirement obligations        36,777        28,996
    Impairment                                       26,280        316,004
    Debt issuance costs amortization                 10,091        14,388
    Amortization of discount, net of premium, on     1,036         2,592
    long-term debt
    Bargain purchase gain                            -             (122,696)
    Loss on extinguishment of debt                   82,005        3,075
    Deferred income tax provision (benefit)          3,842         (100,288)
    Loss (gain) on derivative contracts              47,123        (241,419)
    Cash (paid) received on settlement of derivative (5,879)       125,932
    contracts
    Loss on sale of assets                           399,086       3,089
    Stock-based compensation                         85,270        42,795
    Other                                            3,929         1,387
    Changes in operating assets and liabilities
    increasing (decreasing) cash
         Receivables                                 90,048        (141,534)
         Cost in excess of billings and contract     (8,396)       (89,003)
         loss, net
         Prepaid expenses                            (7,934)       (5,952)
         Other current assets                        810           (1,586)
         Other assets and liabilities, net           5,777         34,447
         Accounts payable and accrued expenses       116,999       121,889
         Asset retirement obligations                (133,623)     (84,361)
                  Net cash provided by operating     868,630       783,160
                  activities
CASH FLOWS FROM INVESTING ACTIVITIES
 Capital expenditures for property, plant and        (1,496,731)   (2,146,372)
 equipment
 Acquisitions of assets                              (17,028)      (840,740)
 Proceeds from sale of assets                        2,584,115     431,167
                  Net cash provided by (used in)     1,070,356     (2,555,945)
                  investing 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)      (844)
 Debt issuance costs                                 (91)          (48,538)
 Proceeds from issuance of royalty trust units       -             587,086
 Proceeds from the sale of royalty trust units       28,985        139,360
 Noncontrolling interest distributions               (206,470)     (181,727)
 Noncontrolling interest contributions               1,579         -
 Stock-based compensation excess tax benefit         (4)           (16)
 Purchase of treasury stock                          (32,976)      (14,723)
 Dividends paid - preferred                          (55,525)      (55,525)
 Cash received on shareholder receivable             1,250         -
 Cash received (paid) on settlement of financing     6,660         (34,518)
 derivative contracts
                  Net cash (used in) provided by     (1,434,089)   1,874,870
                  financing activities
NET INCREASE IN CASH AND CASH EQUIVALENTS            504,897       102,085
CASH AND CASH EQUIVALENTS, beginning of year         309,766       207,681
CASH AND CASH EQUIVALENTS, end of year               $ 814,663    $ 309,766
Supplemental Disclosure of Cash Flow Information
 Cash paid for interest, net of amounts capitalized  $ (274,850)   $ (257,152)
 Cash paid for income taxes                          (4,610)       (1,324)
Supplemental Disclosure of Noncash Investing and
Financing Activities
 Deposit on pending sale                             $ (255,000)   $ 255,000
 Change in accrued capital expenditures              72,848        (27,610)
 Adjustment to oil and natural gas properties for    -             50,000
 contract loss
 Asset retirement costs capitalized                  5,078         7,479
 Common stock issued in connection with acquisition  -             542,138



For further information, please contact:

Duane M. Grubert
EVP – Investor Relations and Strategy
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 natural 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.

The SEC permits oil and natural gas companies, in their filings with the SEC,
to disclose only proved, probable and possible reserves, as each is defined by
the SEC. At times we use the term "EUR" (estimated ultimate recovery) to refer
to estimates that the SEC's guidelines prohibit us from including in filings
with the SEC. These estimates are by their nature more speculative than
estimates of proved, probable or possible reserves and, accordingly, are
subject to substantially greater risk of being actually realized by the
company. For a discussion of the company's proved reserves, as calculated
under current SEC rules, we refer you to the company's Annual Report on Form
10-K referenced above, which is available on our website at
www.sandridgeenergy.com and at the SEC's website at www.sec.gov.

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 region
of the United States. SandRidge's internet address is www.sandridgeenergy.com.

Logo - http://photos.prnewswire.com/prnh/20120416/DA88110LOGO

SOURCE SandRidge Energy, Inc.

Website: http://www.sandridgeenergy.com
 
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