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CORRESP
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CORRESP

 December 13, 2013

Mr. H. Roger Schwall

 Assistant Director

Division of Corporation Finance

 U.S. Securities and Exchange
Commission

 100 F Street, N.E.

 Washington, D.C. 20549-3628

Re:
SandRidge Energy, Inc.

Form 10-K for the Fiscal Year Ended December 31, 2012

Filed March 1, 2013

Form 10-Q for the Fiscal Quarter ended March 31, 2013

Filed May 8, 2013

Definitive Proxy Statement on Schedule 14A

Filed May 29, 2013

Response Letter August 21, 2013

File No. 001-33784

 Dear Mr. Schwall,

SandRidge Energy, Inc. (the “Company” or “SandRidge”) hereby submits this letter in response to the written
comments of the staff (the “Staff”) of the U.S. Securities and Exchange Commission (the “Commission”), dated November 13, 2013 (the “Comment Letter”), with respect to the Form 10-K for the
fiscal year ended December 31, 2012 filed by SandRidge with the Commission on March 1, 2013 (the “2012 Form 10-K”); the Form 10-Q for the fiscal quarter ended March 31, 2013 filed by SandRidge with the Commission on
May 8, 2013; the Definitive Proxy Statement on Schedule 14A filed by SandRidge with the Commission on May 29, 2013; and the Response Letter filed by the Company with the Commission on August 21, 2013.

Set forth below is the heading and text of each comment set forth in the Comment Letter, followed by our response thereto. As noted in its
responses below, the Company undertakes to include certain disclosure in its Form 10-K for the fiscal year ended December 31, 2013 (the “2013 Form 10-K”) and, to the extent applicable, in other future filings. Capitalized terms used
but not otherwise defined herein have the respective meanings ascribed to them in the 2012 Form 10-K.

 Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

  Page
 2

 Form 10-K for the Fiscal Year ended December 31, 2012

General

 1. We note your response to comment 23 from
our letter to you dated July 30, 2013. While Mr. Ward’s employment with the Company was terminated effective June 28, 2013, the non-competition provisions remain operative into the future. Please tell us what consideration you
have given to discussing these provisions in another part of your filing, such as in the risk factor entitled “Competition in the oil and natural gas industry is intense…”

Response

 The terms of
Mr. Ward’s former employment agreement with the Company expressly provide that the noncompetition provisions of the agreement would not survive any termination of Mr. Ward’s employment without cause. Because Mr. Ward’s
employment was terminated by the Company without cause, effective June 28, 2013, he has not been prohibited from competing with the Company since such time. However, the Company does not view Mr. Ward’s ability to compete with the
Company as a risk to the Company’s business operations any more than any other owner or operator of oil and natural gas assets in the Mississippian formation or anywhere else the Company conducts its business operations, and the Company
believes its existing disclosures adequately address such risks. Therefore, the Company does not believe it is necessary to specifically address Mr. Ward’s ability to compete with the Company in its filings with the SEC.

Item 1: Business, page 1

 Business Segments and
Primary Operations, page 4

 West Texas Overthrust, page 6

2. We have read your response to prior comment one and are unclear as to whether you have recorded your shortfall liability at a rate of $0.25 per Mcf or
have also factored in the incremental payment of $0.70 per Mcf that will be due if you are unable to make up the current shortfall with excess deliveries in subsequent years. Please explain your accounting policy for each component and if you are
not recording the shortfall at the full rate of $0.95 per Mcf, please explain the basis for assuming that future excess deliveries will occur and be sufficient to avoid the additional payment imposed under your contractual arrangement.

Response

 The 30-year treating
agreement is a service arrangement which is assessed each reporting period to determine whether any obligation has been incurred at that time. Upon determination that an obligation has been incurred, such as when the annual minimum CO2 delivery requirement is not met, an analysis of the loss contingency guidance in FASB ASC 450-20 is performed to determine the probability of incurred losses and a reasonable estimate for accrual.
Liabilities for such annual delivery shortfalls have been calculated using a rate of $0.25 per Mcf, the rate used in the treating agreement to calculate the fee if minimum annual delivery threshholds are not met.

 Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

  Page
 3

 As noted within FASB ASC 450-20-25-2 with respect to loss contingencies, accrual of probable
losses is required when such losses are reasonably estimable and relate to the current or a prior period, with disclosure being preferable to accrual if it is not probable that a liability has been incurred at the date of the financial statements
because those losses relate to a future period rather than the current or a prior period. The Company further notes that underdelivered volumes in one annual period may be made up in any subsequent annual period, reducing or eliminating cumulative
shortfalls at such time. Because the $0.70 per Mcf end-of-contract penalty is payable at the end of the contract (in 2042) and is applicable to net cumulative shortfalls only, if any, over the term of the 30-year agreement, the Company is unable to
determine whether payment of the $0.70 per Mcf penalty is probable. Moreover, under the terms of the contract, the $0.70 per Mcf penalty rate is not applicable to annual delivery shortfalls. The Company will record estimated end-of-contract penalty
amounts due resulting from “past transactions or events,” if any, at a rate of $0.70 per Mcf when payment of such amounts becomes probable and reasonably estimable. In the Company’s 2012 Form 10-K, liabilities for which the Company
has determined payment is probable have been disclosed and, additionally, the Company has stated that it is unable to estimate additional amounts it may be required to pay under the agreement (for quantities of CO2 beyond those future deliveries that have been assessed as probable of occurring). Accordingly, the Company submits that this disclosure is compliant with FASB ASC 450-20-50-3 and 4.

Due to (i) the length of time remaining in the term of the treating agreement, (ii) the sensitivity of drilling activity to market
prices for natural gas, and (iii) provisions within the treating agreement allowing annual delivery shortfalls to be recouped in subsequent periods within the term of the agreement, the Company is not able to estimate a meaningful range of loss
and believes that disclosure of a maximum loss would be misleading to investors, as the facts do not support a specific amount as reasonably possible. As noted in the Company’s previous response to the Staff’s Comments, the Company
included revised disclosure in its quarterly reports on Form 10-Q for the fiscal quarters ending June 30, 2013 (the “Second Quarter Form 10-Q”) and September 30, 2013 (the “Third Quarter Form 10-Q” and, collectively
with the Second Quarter Form 10-Q, the “Second and Third Quarter Forms 10-Q”) setting forth total CO2 quantities required to be delivered under the contract, the quantity of CO2 the Company estimates will remain to be delivered after 2013, fee rates for annual shortfalls and end-of-contract shortfalls, and other information that a reader may consider in its own analysis
if the reader desires to project a liability range.

 Reserve Quantities, PV-10 and Standardized Measure, page 10

3. We note from your response to prior comment three that you have determined the separate disclosure of your natural gas liquids (NGLs) reserves for the
years ending 2011 and 2010 is not warranted based on your assessment using guidance contained in FASB ASC paragraph 932-235-50-4(a) and the Glossary under FASB ASC paragraph 932-235-20. Based on the information presented on page F-65, we note NGLs
represent approximately 12.4% of total proved liquids reserves reported therein as “oil” as of December 31, 2011, and that the “oil” quantities that you have disclosed are approximately 14.2% higher than you would have
reported had NGLs been reported separately.

 Furthermore, the table presented with Item 1202(a)(1) of Regulation S-K contemplates
reserve disclosure for product types other than crude oil and natural gas, e.g. “Product A.” NGLs represent a separate product type and therefore, consideration should also be given in assessing their disclosure based on the requirement to
disclose separately material reserves as per Item 1202(a)(4) of Regulation S-K. In your response, you note that NGLs comprised 6% and 9% of total proved reserves at December 31, 2011 and 2010, respectively.

 Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

  Page
 4

 Based on the information contained in your filing and as provided in your response, we believe the
quantities attributable to your natural gas liquids reserves for the periods ending 2011 and 2010 should be reported separately. Please revise the disclosure throughout your filing to provide separate disclosure of your natural gas liquid reserves
for each of the last three years.

 Response

The Company will update its disclosures in future filings, beginning with its 2013 Form 10-K, to provide separate disclosure of natural gas
liquids reserves for each of the years presented, when such reserves are material. For the avoidance of doubt, the Company will show natural gas liquids reserves separately for the years 2011 and 2012 in its 2013 Form 10-K. Included below for the
Staff’s information is the referenced table as updated for presentation in its 2013 Form 10-K.

 Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

  Page
 5

December 31,

    2013

2012

2011

 Estimated Proved Reserves(1)

 Developed

 Oil (MMBbls)

136.6

101.6

 NGL (MMBbls)

33.8

17.1

 Natural gas (Bcf)(2)

896.7

670.4

 Total proved developed (MMBoe)

319.9

230.4

 Undeveloped

 Oil (MMBbls)

125.4

112.9

 NGL (MMBbls)

34.2

13.2

 Natural gas (Bcf)(2)

518.3

684.7

 Total proved undeveloped (MMBoe)

246.0

240.2

 Total Proved

 Oil (MMBbls)

262.0

214.5

 NGL (MMBbls)

68.0

30.3

 Natural gas (Bcf)(2)

1,415.0

1,355.1

 Total proved (MMBoe)(3)

565.9

470.6

 PV-10 (in millions)(4)

$

$
7,488.4

$
6,875.9

 Standardized Measure of Discounted Net Cash Flows
(in millions)(3)(5)

$

$
5,840.4

$
5,216.3

(1)
The Company’s estimated proved reserves and the future net revenues, PV-10 and Standardized Measure were determined using a 12-month average price for oil and natural gas. The prices used in the Company’s
external and internal reserve reports yield weighted average wellhead prices, which are based on index prices and adjusted for transportation and regional price differentials. The index prices and the equivalent weighted average wellhead prices are
shown in the table below.

Index prices

Weighted average
wellhead prices

Oil
(per Bbl)

Natural gas
(per Mcf)

Oil
(per Bbl)(a)

NGL
(per Bbl)

Natural gas
(per Mcf)

 December 31, 2013

$

$

$

$

$

 December 31, 2012

$
91.21

$
2.76

$
91.65

$
32.64

$
2.29

 December 31, 2011

$
92.71

$
4.12

$
91.35

$
46.33

$
4.06

(a)
At December 31, 2012, the weighted average wellhead oil price is higher than the index price as a result of favorable location differentials for production in the Gulf of Mexico.

(2)
The Company’s production from the WTO contains natural gas that is high in CO2 content. These amounts are net of CO2 volumes that exceed pipeline quality specifications.

(3)
At December 31, 2013, 2012 and 2011, estimated total proved reserves attributable to noncontrolling interests were approximately XX.X, 38.2 and 26.4 MMBoe, respectively, and Standardized Measure attributable to
noncontrolling interests were approximately $XXX.X million, $952.7 million and $932.8 million, respectively. See “Note XX—Supplemental Information on Oil and Natural Gas Producing Activities” in Item 8 of this report for
additional information regarding reserve and Standardized Measure amounts attributable to noncontrolling interests.

 Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

  Page
 6

(4)
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per
annum to reflect timing of future cash flows and using 12-month average prices for the years ended December 31, 2013, 2012 and 2011. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net
revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of the Company’s oil and natural gas properties. PV-10 is used by the industry and by the Company’s management as an arbitrary reserve asset value
measure to compare against past reserve bases and the reserve bases of other business entities that is not dependent on the taxpaying status of the entity. The following table provides a reconciliation of the Company’s Standardized Measure to
PV-10:

December 31,

    2013

2012

2011

(In millions)

 Standardized Measure of Discounted Net Cash Flows

$

$
5,840.4

$
5,216.3

 Present value of future income tax discounted at 10%

1,648.0

1,659.6

 PV-10

$

$
7,488.4

$
6,875.9

(5)
Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, and income tax expenses, discounted at
10% per annum to reflect timing of future cash flows and using the same pricing assumptions used to calculate PV-10. Standardized Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes.

Production and Price History, page 14

 4. We note
from your response to prior comment five that you have determined the separate disclosure of information relating to your natural gas liquids (NGLs) as final products sold under Items 1204(a) and 1204(b)(1) of Regulation S-K is not warranted. Your
determination is based on an application of the 10% “significance” criteria from FASB ASC 932-235-20. However, as there is no quantitative threshold referenced under Items 1204(a) and 1204(b)(1) of Regulation S-K for the disclosure by
final product sold, we are not in a position to agree with your assessment. Under your circumstances, the lack of separate disclosure of the produced volume is inconsistent with your separate disclosure of NGL reserves for the same period.
Therefore, please revise your disclosure to include the volumes produced and the average sales price received for your natural gas liquids as separate product types within your current tables.

Response

 The Company will update
its disclosures in future filings, beginning with its 2013 Form 10-K, to include the volumes produced and the average sales price received for natural gas liquids as separate product types within the referenced tables, for any periods for which
natural gas liquids reserves have been shown separately. Included below for the Staff’s information is the referenced table updated for presentation in its 2013 Form 10-K.

 Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

  Page
 7

Year Ended December 31,

    2013

2012

2011

 Production Data

 Oil (MBbls)

15,868

9,992

 NGL (MBbls)

2,094

1,838

 Natural gas (MMcf)

93,549

69,306

 Total volumes (MBoe)

33,553

23,381

 Average daily total volumes (MBoe/d)

91.7

64.1

 Average Prices(1)

 Oil (per Bbl)

$

$
91.79

$
90.31

 NGL (per Bbl)

$

$
33.10

$
44.58

 Natural gas (per Mcf)

$

$
2.49

$
3.50

 Total (per Boe)

$

$
52.43

$
52.47

(