SANDRIDGE ENERGY INC

Regulatory Filings • Aug 21, 2013

CORRESP 1 filename1.htm CORRESP

August 21, 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

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 July 30, 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 certain information on the Company’s website.

Set forth below is the heading and text of each comment set forth in the Comment Letter, followed by our response thereto. In addition, on August 8, 2013, the Company filed with the Commission its Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013 (the “Second Quarter Form 10-Q” ). The proposed disclosure set forth below in response to certain of the comments was included in the Second Quarter Form 10-Q. The Company undertakes to include similar disclosure in its future annual reports on Form 10-K and quarterly reports on Form 10-Q 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, or, in the case of disclosures included in the Second Quarter Form 10-Q, the respective meanings ascribed to them therein.

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

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 2

Business, page 1

Business Segments and Primary Operations, page 4

West Texas Overthrust, page 6

1. Please revise your disclosure to discuss and quantify (i) the annual amount of natural gas that you would be required to deliver to meet the carbon dioxide delivery requirement, (ii) the annual carbon dioxide delivery requirement, and (iii) the liquidated damages per 1,000 standard cubic feet of carbon dioxide not delivered. Alternatively, provide the information necessary to understand the potential impact to earnings and liquidity if it is reasonably possible that you will be unable to meet your long-term contractual obligations under the treating agreement. Please also disclose the relationship between the natural gas input and carbon dioxide output, and the methodology that liquidation damages are calculated to comply with Item 1207 of Regulation S-K.

Response

We acknowledge the Staff’s comment. Set forth below is proposed disclosure which we believe responds to the Staff’s comment. We undertake to include this disclosure (updated appropriately) in future annual reports on Form 10-K and quarterly reports on Form 10-Q. We also note for the Staff that this disclosure was included in Note 11 on page 33 of the Second Quarter Form 10-Q.

In conjunction with the Century Plant construction agreement, the Company entered into a 30-year treating agreement with Occidental for the removal of CO 2 from the Company’s delivered production volumes. Under the agreement, the Company must deliver a total of approximately 3,200 Bcf of CO 2 during the agreement period; it is expected that after 2013 approximately 3,000 Bcf of CO 2 will remain to be delivered. The company pays Occidental $0.25 per Mcf to the extent minimum annual CO 2 volume requirements are not met, and, at the end of 2042, the Company is required to pay Occidental $0.70 per Mcf for total undelivered CO 2 volumes, net of any CO 2 delivered in excess of any given year’s applicable minimum volumes. Based on current projected natural gas production levels the Company expects to accrue between approximately $29.5 million and $36.0 million at December 31, 2013 for amounts related to the Company’s anticipated shortfall in meeting its 2013 annual delivery obligations. Due to the sensitivity of drilling activity to market prices for natural gas, the Company is unable to estimate additional amounts it may be required to pay under the agreement in subsequent periods; however, if natural gas prices remain low, drilling activity will likely also remain low, which would result in additional shortfall payments in future periods.

With respect to the last sentence of the Staff’s comment, the Company notes that there is no constant relationship between the quantity of natural gas delivered at the Century Plant for treatment and the amount of carbon dioxide delivered to Occidental with respect to such natural gas. Rather, the natural gas stream’s carbon dioxide content varies from well to well. We note for the Staff’s information, that since 2007, the high CO 2 content natural gas produced by the Company in the Piñon Field has contained, on average 65.7% carbon dioxide, ranging from a low of 63.1% to a high of 68.7%.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 3

Although the Company is providing additional disclosure regarding the Occidental treating agreement in response to the Staff’s comment, as indicated above, the Company notes that Item 1207 of Regulation S-K directs a registrant to disclose fixed and determinable quantities of oil or gas that it is committed to deliver under existing contracts or agreements. Under the Company’s treating agreement with Occidental, the Company’s delivery obligation is for the delivery of specified volumes of carbon dioxide and not for the delivery of specified volumes of natural gas. Therefore, Item 1207 by its terms does not apply to the annual payments made by the Company to Occidental pertaining to underdelivery of carbon dioxide.

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

2. You state “the Company estimates that approximately 80% of its current proved undeveloped reserves will be developed by the end of 2014 and all of its current proved undeveloped reserves will be developed by the end of 2016.” For purposes of determining the five year period, Item 1203(d) of Regulation S-K identifies the initial disclosure and date thereof as the starting reference date. Please tell us if any of your proved undeveloped volumes disclosed as of December 31, 2012 will take more than five years since initial disclosure to develop.

Response

We note the Staff’s comment and confirm that none of the Company’s proved undeveloped oil and natural gas reserves disclosed as of December 31, 2012 are expected to take more than five years since initial disclosure to develop.

3. The footnote to the reserves disclosure on pages 10 and F-65 states that prior to 2012, NGLs did not comprise a significant portion of total proved reserves and were included with oil reserves. Please tell us the net quantities of NGLs for 2011 and 2010 and explain how you have determined disclosure of these quantities was not warranted per the requirements set forth in FASB ASC 932-235-50-4.

Response

The Company’s proved NGL reserves were 6% and 9% of total proved reserves at December 31, 2011 and 2010, respectively. FASB ASC 932-235-50-4 provides that “reserve quantity information shall be disclosed separately for natural gas liquids” if significant. The definition of significant oil and gas producing activities found in FASB ASC 932-235-20 states that an entity is regarded as having significant oil and gas producing activities if (a) revenues from, (b) results of operations for or (c) identifiable assets of oil and gas producing activities are 10% or more of the entity’s total respective revenue, results of operations or identifiable assets. By applying the same 10% criteria to determine the significance of NGL reserves to the Company’s total reserves, the Company determined NGL reserves at December 31, 2011 and 2010 were not significant on the basis of their percentage of total reserves and were therefore not required to be separately disclosed for these periods.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 4

Proved Undeveloped Reserves, page 12

4. Item 1203(b) of Regulation S-K requests that registrants “[d]isclose material changes in proved undeveloped reserves that occurred during the year, including proved undeveloped reserves converted into proved developed reserves.” It appears you have disclosed only the PUD volumes that you converted to proved developed status. Please expand your disclosure to provide a reconciliation of the material changes in the net quantities of your proved undeveloped reserves due to revisions, extensions/discoveries, acquisition/divestiture and improved recovery.

Response

We acknowledge the Staff’s comment and note that the balance of the Company’s proved undeveloped reserves did not change materially from December 31, 2011 to December 31, 2012 (they increased from approximately 240 MMBoe at December 31, 2011 to approximately 246 MMBoe at December 31, 2012, a change of only 2.5%). However, the Company included disclosure of proved undeveloped reserves converted to proved developed status during the year, in response to Item 1203(b) of Regulation S-K, which specifically calls for such disclosure. Given the overall absence of a material change in the balance of proved undeveloped reserves year over year, we submit that Item 1203(b) does not require more detailed disclosure, nor does it call for a reconciliation of changes in the net quantities of proved undeveloped reserves due to the specific factors noted in the Staff’s comment. In future annual reports on Form 10-K, we will undertake to include disclosure of changes to proved undeveloped reserves due to revisions, extensions/discoveries, acquisition/divestiture and improved recovery, to the extent such factors cause material changes in the Company’s proved undeveloped reserves.

Production and Price History, page 14

5. Your disclosure of the production and average sales price on page 14 and elsewhere in this Form 10-K excludes separate disclosure of information relating to natural gas liquids. As Items 1204(a) and 1204(b)(1) of Regulation S-K require separate disclosure by final product sold or produced, please advise or revise your disclosure to provide separate disclosure relating to natural gas liquids.

Response

The Company’s NGL production was 6%, 8% and 8% of total production for the years ended December 31, 2012, 2011 and 2010, respectively. The Company applied the 10% “significance” criteria from FASB ASC 932-235-20 described above (see response to Comment 3) to determine the significance of NGL production to the Company’s total production, and concluded that NGL production for the years ended December 31, 2012, 2011 and 2010 was not significant based on the percentages it constituted of total production and was therefore not separately disclosed.

Developed and Undeveloped Acreage, page 15

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 5

6. We note from the disclosure on page 15 that a significant percentage of the Company’s net undeveloped acreage will expire in 2013 and 2014. Please tell us the net amounts by product of your December 31, 2012 proved undeveloped oil and gas reserves assigned to locations on acreage scheduled to expire in 2013 and in 2014. Also tell us if all such proved undeveloped locations are included in a development plan adopted by management as of December 31, 2012 indicating that these locations are scheduled to be drilled prior to lease expiration.

Response

Approximately 97% of the Company’s net undeveloped acreage scheduled to expire in 2013 and 2014 are leases in the states of Texas, Oklahoma and Kansas. Approximately 99% of the expiring Texas leases are in the West Texas Overthrust. The Company had no proved undeveloped oil and natural gas reserves assigned to these locations at December 31, 2012 due to depressed natural gas index prices. The proved undeveloped oil and gas reserves assigned to Oklahoma and Kansas acreage scheduled to expire in 2013 and 2014 constituted approximately 1.3% of the Company’s total net proved oil and gas reserves at December 31, 2012. All locations associated with these reserves are scheduled to be drilled prior to lease expiration.

Risk Factors

“Unless the Company replaces its oil and natural gas reserves ,” page 35

7. Please expand this risk factor to discuss the impact of the February 2013 sale of the Permian Basin properties.

Response

We acknowledge the Staff’s comment. Set forth below is disclosure included on page 75 of the Second Quarter Form 10-Q under the heading “Item 1B. Risk Factors.” (revisions to disclosures in the 2012 Form 10-K underlined), which we believe responds to the Staff’s comment. We undertake to include this disclosure, as appropriate, in future annual reports on Form 10-K.

Unless the Company replaces its oil and natural gas reserves, its reserves and production will decline, which would adversely affect the Company’s business, financial condition and results of operations.

In February 2013, the Company closed the sale of the Permian Properties, which accounted for 21% of the Company’s total production in the fourth quarter of 2012 and 35% of the Company’s reserves at December 31, 2012. The Company’s future oil and natural gas reserves and production, and therefore its cash flow and income, are highly dependent on its success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, find or acquire additional reserves to replace its current and future production at acceptable costs, which could adversely affect its business, financial condition and results of operations.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 6

“The Company’s development and exploration operations require substantial capital ,” page 37

8. Please provide context for this risk factor by quantifying the amount of your capital expenditures in the recent past financed from asset sales and sales of equity and debt, as compared to those capital expenditures financed from cash generated from operations. Similarly, quantify the amount of capital expenditure that the Company “expects” to finance from asset sales and other financing arrangements and sales of equity and debt, as compared to those capital expenditures expected to be financed from cash generated from operations.

Response

We note to the Staff that, just as the Company has multiple sources of cash, it also has various funding needs in addition to its capital expenditures, such as general and administrative costs, lease operating expenses, interest expense and taxes. Further, the Company considers its various cash inflows to be fungible and does not allocate specific cash inflows or potential specific sources of cash to specific expenses. Therefore, the Company is unable to quantify the amount of recent past, or expected future, capital expenditures that have been financed through asset sales or capital markets transactions, as compared to cash generated from operations or other sources of cash. We also note that the discussion of cash flows in the MD&A section of the 2012 Form 10-K provides detail on the various sources of the Company’s cash.

Management’s Discussion and Analysis, page 61

Results by Segment, page 62

9. We see that you have disclosed on page 64 average prices related to your oil and natural gas production reflecting the impact of derivative contract settlements. Tell us the extent to which the derivatives utilized in computing these measures included instruments that entailed some cost (e.g. premiums) to acquire, or instruments that reflected terms or provisions that were effected by amendment for cost prior to or in conjunction with settlement; please quantify the effects of any such cost recovery on the average prices that you have disclosed.

Response

In computing “Average prices – including impact of derivative contract settlements,” the Company has included only cash gains or losses incurred with the settlement of derivative contracts reaching contractual maturity within the corresponding period. No costs, including premiums, were incurred by the Company to acquire any such derivative contract or to amend any such derivative contract in conjunction with settlement.

Liquidity and Capital Resources, page 73

10. We note that you depend on funding commitments from third parties for drilling carries to fund your capital expenditures. Please quantify the amount you receive from these third parties. Additionally, please discuss whether you expect these amounts to remain stable in the near future or, if not, why and to what extent these amounts could fluctuate.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 7

Response

The Company notes that the amounts received from third parties for drilling carries, along with the amounts utilized, remaining commitments and periods during which such drilling carries are to be funded, are disclosed in Note 3 to the financial statements on page F-22 of the 2012 Form 10-K. The amounts received from third parties for drilling carries fluctuates depending on how much of the Company’s drilling occurs within the areas of mutual interest associated with the carries. The Company currently expects its drilling carries in 2013 to be consistent with amounts received in respect of 2012.

Contractual Obligations and Off-Balance Sheet Arrangements, page 78

11. Notwithstanding your textual disclosure at the bottom of page 78, tell us why you have not included your development agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II, and your treating agreement, in your tabular presentation of contractual obligations pursuant to Item 303(a)(5) of Regulation S-K. Please also expand your disclosure to clarify the extent to which your table of contractual obligations includes amounts under these agreements.

Response

We acknowledge the Staff’s comment and note that Item 303(a)(5) of Regulation S-K sets forth specific categories of contractual obligations to be disclosed, as well as information regarding the commitments that must be disclosed with respect to each category. These categories are: Long-Term Debt Obligations, Capital Lease Obligations, Operating Lease Obligations, Purchase Obligations and Other Long-Term Liabilities Reflected on the Registrant’s Balance Sheet under GAAP. After considering the nature and terms of the drilling commitments to SandRidge Mississippian Trust I, SandRidge Permian Trust and SandRidge Mississippian Trust II, the Company determined the commitments did not fall within any of the specified categories. The Company’s obligations under the relevant development agreements are to drill the number of oil and natural gas wells necessary to deliver to each trust a minimum aggregate net revenue interest. The Company is not obliged to spend a minimum level of capital. However, given the significance of the capital expenditures that would be necessary to fulfill the Company’s drilling obligations to the royalty trusts, the Company elected to provide supplementary disclosure regarding the drilling commitments in order to provide investors with the amount the Company estimated at the time of filing would be incurred to fulfill such commitments. Because these commitments are not properly disclosable in the table of material obligations, the Company believes narrative disclosure is appropriate.

With reference to the CO 2 delivery commitment under the treating agreement with Occidental, after considering the nature and terms of the agreement, the Company determined any future amounts due also do not fall within any of the categories specified for disclosure by Item 303(a)(5). Further, due to the sensitivity of drilling activity to market prices for natural gas, the Company is unable to estimate additional amounts it may be required to pay under the agreement in the future. The Company directs the Staff’s attention to its response to Comment 1 set forth above, which provides additional information and proposed additional disclosures about the treating agreement with Occidental.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 8

12. Please quantify the payments that would be required under your CO 2 supply arrangement if you are unable to deliver natural gas for processing and describe the factors that are reasonably likely to impact this obligation.

Response

The Company directs the Staff’s attention to its response to Comment 1 set forth above, which addresses this comment.

Financial Statements

Note 1—Summary of Significant Accounting Policies, page F-9

Revenue Recognition and Natural Gas Balancing, page F-13

13. We note that you account for your two construction contracts under the completed-contract method of accounting, although you record contract gains or losses as development costs within oil and natural gas properties, as part of the full cost pool. We understand from your disclosures on pages F-34 and F-42 that these contracts pertain to the Century Plant and associated compression and pipeline facilities that you constructed for Occidental Petroleum Corporation during 2012 in exchange for $796.3 million and an agreement to either provide specific quantities of CO 2 over a thirty-year period by supplying natural gas for processing, or to provide financial compensation in the event you unable to deliver natural gas for processing. Please address the following points:

• Please explain how you determined it was appropriate to record contract losses amounting to $180 million as additions to the full cost pool rather than to expense these amounts as would ordinarily be required to comply with FASB ASC 605-35-25-45. Please clarify the nature and extent of any ownership interest in the facilities you have retained. It should be clear how you determined that contract losses had the characteristics of assets, were properly accounted for under the full cost method apart from the revenues and other expenses incurred in completing the contract, and why you believe incurring costs to perform under the contract are properly considered to have been undertaken for your own account, as would generally be anticipated under Rule 4-10(c)(2) of Regulation S-X.

• Submit the analysis that you performed in determining that you were unable to make reasonably dependable estimates in selecting the completed contract method of accounting for these construction contracts, rather than the percentage of completion method, based on the criteria in FASB ASC 605-35-25-56 through 66. Given that you received payment for construction according to the percentage of completion, also explain your perspective on the financial reporting implications of applying your method in comparison to the percentage of completion method.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 9

• Since your agreement to provide 3,200 Bcf of CO 2 to Occidental Petroleum Corporation was entered into in conjunction with these two construction contracts, it is unclear why you have neither disclosed nor recognized a liability for the value of the CO 2 that you must provide as part of your contract accounting. Tell us how the value of the CO 2 compares to the payments required if you do not deliver natural gas for processing, and explain your reasons for deferring recognition.

Response

We acknowledge the Staff’s comment and note that the construction agreement to build the Century Plant, entered into with Occidental in June 2008, was for the construction of the plant and associated compression and pipeline facilities by the Company for Occidental for an agreed upon contract price of $800 million, plus the cost of any subsequently agreed-upon revisions. In conjunction with the construction agreement, the Company entered into a separate, at market 30-year treating agreement under which Occidental, as owner and operator of the plant, agreed to remove CO 2 from the Company’s delivered natural gas production volumes. The Company retains the methane and liquid hydrocarbons after the natural gas is processed and Occidental retains all of the extracted CO 2 . The Company has no use for CO 2 , which is costly to dispose of. There is currently no market for CO 2 at this processing point in West Texas. Under this treating agreement, the Company’s delivery obligation is for the delivery of CO 2 volumes and not for the delivery of natural gas for processing. The Company is obligated to compensate Occidental in the event the Company is unable to provide Occidental with specified volumes of CO 2.

• Due to the high-CO 2 content of the Company’s reserves in the Piñon Field and the absence of adequate processing capacity in the Piñon area, construction of a large-scale processing facility, such as the Century Plant, was necessary for the development of the Company’s natural gas reserves in that area. The Company entered into the construction agreement and the treating agreement solely for the purpose of developing its Piñon Field reserves. Without the arrangement with Occidental, the Company would not have been able to develop and produce its reserves with a high-CO 2 content. Rule 4-10 of Regulation S-X defines “development costs” as “costs incurred to obtain access to proved reserves for extracting, treating, gathering and storing the oil and gas.” The Company believes that any costs in excess of the reimbursed amounts under the construction agreement incurred by the Company are “development costs” and, therefore, the Company determined such costs should be capitalized in accordance with Rule 4-10(c)(2) of Regulation S-X, and amortized, as appropriate. The Company has not retained any ownership interest in the facilities comprising the Century Plant or the associated compression and pipeline facilities.

Alternatively, under the full cost accounting method, the Company could have capitalized the Century Plant construction costs within its full cost pool as incurred and credited reimbursements from Occidental to the full cost pool as received, with any unreimbursed costs remaining in the pool upon completion of the plant’s construction. The Company submits that, while both treatments result in the capitalization of costs incurred in excess of costs reimbursed being included in the full cost pool, the Company’s use of the completed contract method in this instance provides financial statement users more visibility into the costs incurred and borne by the Company in connection with the arrangement.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 10

• The completed contract method was determined to be the appropriate method of accounting due to the Company’s limited experience with construction projects, especially a project of this magnitude and the size and scope contemplated for the Century Plant, which was the first facility of this type constructed in the United States with significant capacity and the technological advances to provide efficiencies in gas treating contemplated by the Company and Occidental. Accordingly, the Company determined the project lacked dependable estimates of contract revenues and costs in accordance with FASB ASC 605-35-25-63. Periodic reimbursements to the Company were based on an estimate of progress toward physical completion of the Century Plant, as a percentage of the total contract price. Because any costs in excess of the reimbursed amounts on the project met the definition of a “development cost” under Rule 4-10 of Regulation S-X and therefore met the criteria for capitalization to the full cost pool, there was no impact to reported net income in the statement of operations and therefore no significant financial reporting implications of applying the completed contract method.

• Paragraph 35 of FASB Concepts Statement No. 6 states that “liabilities are probable future sacrifices of economic benefits arising from present obligations of a particular entity to transfer assets or provide services to other entities in the future as a result of past transactions or events.” Under this definition, the probable sacrifice of economic benefits in the future is required to have resulted from “past transactions or events” in order to meet the definition of a liability. In addition, as noted within FASB ASC 450-20-25-2 with respect to loss contingencies, accrual of losses is required when they 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.

14. We note your disclosure on page F-13 indicating that you recognize revenues and expenses under day work and footage drilling contracts as services are performed and that fees received for mobilization and the costs of mobilization are recognized “...over the term of the related drilling contract.” Although it appears your approach generally corresponds to the percentage of completion method, we would like to understand how your accounting differs when the terms of your drilling contracts do not correspond precisely with the time spent drilling.

Please identify any instances in which the contract dates utilized in defining the terms relied upon as a basis for recognizing mobilization fees preceded or extended beyond the dates that drilling services were actually provided for each year covered by your report, describe the extent to which those periods did not coincide, and quantify where applicable the difference that would arise if recognition were more precisely aligned with contract performance. Tell us the manner by which you have reviewed and confirmed through observation or inspection the acceptability of the input or output measures utilized to determine the percentage of completion in accordance with FASB ASC 605-35-25-78.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 11

Response

We acknowledge the Staff’s comment and note that, while our drilling contracts may cover a range from one month to two years, as stated in our disclosure on page F-13 of the 2012 Form 10-K, each contract could cover anywhere from just one to numerous wells actually drilled, creating the possibility for multiple mobilization charges over the life of each contract. As stated, revenue and expenses for drilling are recognized as services are performed, either by days worked or by footage drilled. As for mobilization, our contracts state, “mobilization is due and payable in full at the time the rig is rigged up or positioned at the well site ready to spud.” Thus, we recognize the revenue and expenses for each mobilization in full at the time the mobilization is completed, as they occur over the term of the contract. Mobilization fees recognized during 2012, 2011 and 2010 were approximately $12.0 million, $13.1 million and $4.2 million, respectively.

The Company proposes to disclose the following clarification to the description of our policy in future annual filings:

Mobilization fees received and costs incurred to mobilize rigs from one market to another are recognized at the time mobilization services are performed.

15. We note your disclosure on page 67, under Drilling and Oil Field Services Segment, stating that you record revenues related to services performed for third-parties, including third-party working interests in wells that you operate. Tell us how you determined that your accounting does not conflict with the guidance in Rule 4-10(c)(6)(iv)(C) of Regulation S-X, stating that “no income may be recognized for contractual services performed on behalf of investors in oil and gas producing activities managed by the registrant or an affiliate.”

Response

We note that we believe that the applicable guidance is found in Rule 4-10(c)(6)(iv)(B) of Regulation S-X, and not Rule 4-10(c)(6)(iv)(C), because the Company’s acquisition of its ownership interest in the properties was at least one year prior to the date of the service contract and came about through transactions unrelated to the service contract. Further, the ownership interest in the properties is unaffected by the service contract. Accordingly, we submit that the referenced disclosure is accurate and compliant with applicable guidance.

Further, the Company submits that Rule 4-10(c)(6)(iv)(C) is not applicable to the Company’s facts and circumstances as the referenced rule is in contemplation of a property’s sponsor or owner also providing contract services to manage other parties’ investment, such as contemplated by Rule 4-10(c)(6)(iv)(C)(iii) (e.g. when a registrant has organized and manages a limited partnership). Accordingly, the Company does not believe it has met criteria (C) since the Company does not receive an interest in the underlying property upon which the services are performed. Additionally, the Company is the operator, but not the manager, of the properties upon which the contractual services are performed.

Note 7—Property, Plant and Equipment, page F-32

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 12

16. We note from the Form 8-K that you filed on May 8, 2013, Note 2(c), that you estimate you would have “incurred an impairment from full cost ceiling limitations of approximately $102.6 million” during the first quarter of 2013, although you provided no adjustment because this is not recurring. Please clarify the basis for this disclosure and explain why a full cost ceiling write-down was not recorded in historical financial statements for this period.

Response

The pro forma condensed statement of operations for the three months ended March 31, 2013 included in the Form 8-K filed by the Company on May 8, 2013 was prepared by adjusting the historical statement of operations of the Company on a pro forma basis to give effect to the sale of the Permian Properties to Sheridan Holding Company II, LLC and the use of a portion of the sale proceeds to fund the March 2013 redemption of SandRidge’s 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018. The Company’s historical results were also adjusted to give effect to (i) the Company’s acquisition of oil and natural gas properties from Hunt Oil Company, Hunt Chieftain Development, L.P., and Hunt Oil Company of Louisiana, Inc., (ii) the acquisition of Dynamic Offshore Resources, LLC by SandRidge and SandRidge’s issuance of $750.0 million aggregate principal amount of 8.125% Senior Notes due 2022 to partially fund the acquisition of Dynamic, and (iii) the conveyance of royalty interests in certain oil and natural gas properties to SandRidge Mississippian Trust II by SandRidge, as if each of those transactions occurred on January 1, 2012.

In preparing the pro forma condensed statement of operations, the Company prepared a pro forma full cost pool ceiling limitation calculation to determine if the cumulative impact of the transactions noted above would result in a limitation. Based on that calculation and including the pro forma effects of the applicable transactions noted above, as if those transactions occurred on January 1, 2012, the Company estimated that it would have incurred an impairment from full cost ceiling limitations. The impairment was not reflected in the pro forma condensed statement of operations. In accordance with Article 11-02 (5) of Regulation S-X, material nonrecurring charges directly attributable to the transaction(s) were omitted from the statement of operations. The Company disclosed the impairment as a nonrecurring charge for this period in a footnote to the pro forma statement of operations.

As discussed above, for purposes of the pro forma condensed statement of operations for the three months ended March 31, 2013 included in the Form 8-K filed by the Company on May 8, 2013, the impairment from full cost ceiling limitations was estimated based on a calculation that included the pro forma effects of the transactions noted above, as if they occurred on January 1, 2012. The Company’s historical financial statements for the fiscal quarter ended March 31, 2013, as shown in the Form 10-Q for the fiscal quarter ended March 31, 2013 filed by the Company on May 8, 2013, do not include an impairment from full cost ceiling limitations because the calculation performed at the end of such quarter, based on actual results for the quarter, did not indicate that the Company had incurred such an impairment, because as of such date total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes, did not exceed the ceiling limitation.

Note 14—Derivatives, page F-37

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 13

17. We note that you have disaggregated your measures of gain and loss on derivatives into measures described as “realized” and “unrealized” in the table on page F-39, although your accompanying narrative indicates you are presenting “cash settlements and valuation gain and loss.” Tell us how you determined the realized and unrealized gains and losses so that we may understand how your method complies with FASB ASC 815-10-35-2. For example, if realized gains do not reflect only the change in fair value during the period of settlement, identify the specific elements reflected in each measure (e.g. premiums paid, change in fair value from period-to-period, and settlement proceeds/payments).

Given that you have a similar presentation on page 66, with realized gain or loss attributed to early settlements, amended contracts, and settlements at maturity, please also explain your rationale for differentiating these categories in your presentation and describe any corresponding accounting distinctions. Please also explain the inconsistent labeling of these amounts in your disclosures and how the measures would be properly regarded as valuation gain and loss.

Response

The Company has not designated any of its derivative contracts as hedging instruments and, therefore, recognizes changes in the fair value of its derivative contracts currently in earnings as described in FASB ASC 815-10-35-2. For reporting purposes, the Company defines unrealized gains or losses as gains or losses incurred as a result of periodically adjusting the recorded market value of derivatives contracts that have not reached contractual maturity or have not been settled. The Company defines realized gains or losses as gains or losses incurred as a result of contract termination, either at contracted maturity dates or prior to contracted maturity dates due to early settlements or amendments. The Company notes that realized and unrealized gain and loss are terms (i) understood in the energy and other sectors and (ii) used within ASC 815.

To further clarify the components of the Company’s realized gains, we differentiated and presented separately the realized gains resulting from derivative contracts that were settled in different manners, as follows:

• For derivative contracts settled prior to contractual maturity dates, realized gains or losses reflect the change in fair value for the period from the date the Company entered the contract to its settlement, less any fees paid in association with early termination, and the resulting cash receipt from, or payment to, the contract counterparties.

• The Company considers an amendment to the terms of a derivatives contract to be equivalent to the settlement of an existing contract and entry into a new contract. For derivatives contracts with terms that have been amended by the Company, realized gains or losses reflect only the change in fair value during the period from the date the Company originally entered the contracts to the date the terms of those contracts were amended. In the event no funds were paid to, or received from, counterparties at the time of amendment, the non-cash effects of these realized gains or losses are reflected as positive (loss) or negative (gain) adjustments to net income for the purpose of calculating Net Cash Provided by Operating Activities on the Company’s Statement of Cash Flows.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 14

• For derivative contracts settled upon maturity in accordance with the terms of contracts as originally negotiated, realized gains or losses reflect the change in fair value for the period from the date the Company entered into the contracts to their respective settlements at contractual maturity and the resulting cash receipt from or payment to the contract counterparties.

18. Tell us why you have identified realized loss on amended derivative contracts in the amount of $117 million as a positive adjustment in your 2012 reconciliation of net income to operating cash flows on page F-8.

Response

The Company acknowledges the Staff’s comment and submits that the Company’s total net realized gain from commodity derivatives for 2012 includes a non-cash loss of $117 million related to the amendment of the terms of certain derivative contracts and directs the Staff’s attention to its response to Comment 17 set forth above.

Note 25 Supplemental Information on Oil and Natural Gas Producing Activities, page F-62

Oil and Natural Gas Reserve Quantities (Unaudited), page F-63

19. Please refer to the requirements set forth in FASB ASC 932-235-50-5. Revise the disclosure on page F-64 relating to the 2010, 2011 and 2012 revisions of previous estimates to provide the net quantities associated with a change in economic factors separately from the changes resulting from new information obtained from development drilling and well performance.

Response

The Company acknowledges the Staff’s comment and notes that FASB ASC 932-235-50-5 provides that “Changes resulting from all of the following shall be shown separately with appropriate explanation of significant changes,” with six distinct categories being listed, one of which is as follows:

a. Revisions of previous estimates . Revisions represent changes in previous estimates of proved reserves, either upward or downward, resulting from new information (except for an increase in proved acreage normally obtained) from development drilling and production history or resulting from a change in economic factors.

The Company has presented separately each category applicable to its proved oil and gas reserve quantities. With respect to (a) above, the Company notes that the requirement to show items separately from one another applies to the six distinct categories and not within a single category. Therefore, the Company does not believe ASC 932-235-50-5 requires disclosure of separate items within the “Revisions of previous estimates” category. Accordingly, the Company submits that its current disclosures are accurate and compliant with applicable guidance.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 15

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

Note 2—Acquisitions and Divestitures, page 10

2013 Divestitures, page 13

20. We note from the Form 8-K that you filed on March 1, 2013 that you sold assets in the Permian Basin which were held by SandRidge Exploration and Production LLC, an entity that you have identified in disclosure and Exhibit 21 to your annual report as a wholly-owned subsidiary. Please explain how you computed the loss allocated to the noncontrolling interest mentioned under this heading, and explain how you have properly identified SandRidge Exploration and Production LLC as a wholly-owned subsidiary with a minority interest.

Response

The noncontrolling interests to which the loss on the sale of the Permian Properties was allocated are associated with the Company’s consolidated variable interest entities. The Company consolidates the activities of these entities and reports as noncontrolling interest amounts attributable to their third-party ownership interests. Because the Company has one cost center under the full cost method of accounting, all of the oil and gas properties of the consolidated Company are included in one full cost pool, and all consolidated entities with oil and gas properties included in the pool share in the loss on sale of the Permian Properties. The Company allocated the loss on the sale of the Permian Properties to each of the consolidated entities with oil and gas properties based upon the entities’ pro rata share of the total full cost pool net book value. The Company believes this method of allocation is systematic and rational. As consolidated variable interest entities are considered partially owned subsidiaries with noncontrolling interest for reporting purposes subsequent to their consolidation, a portion of the loss attributable to each variable interest entity was allocated to its noncontrolling interests based upon the percentage of the noncontrolling interest ownership of such consolidated variable interest entity.

21. We note that you allocated net book value to the Permian Properties based on the relative fair value of proved reserves associated with these properties and the oil and natural gas properties that you retained. Please explain to us why you did not allocate capitalized costs under the same methodology as used to compute amortization, pursuant to the guidance in Rule 4-10(c)(6)(i) of Regulation S-X. In this regard, please describe the “substantial economic differences” that you identified as the basis for your accounting with details sufficient to understand why you regard these differences as substantial. Please also tell us how the loss you recorded compares to the loss or gain that you would have recorded had you allocated costs using the amortization methodology.

Response

In conjunction with the sale of the Permian Properties, the Company performed an analysis to determine whether there were substantial economic differences between the sold Permian Properties and all of the Company’s oil and natural gas properties that it did not sell (retained properties) in order to further determine, pursuant to Rule 4-10(c)(6)(i) of Regulation S-X, whether the gain or loss recorded on disposal should be based upon an allocation of

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 16

capitalized costs using the same basis used to compute amortization or an allocation using the relative fair value of the properties. The analysis performed indicated a fair value per Boe of $12.56 for reserves sold and a fair value per Boe of $10.32 for reserves retained. This $2.24 per Boe difference (approximately 18% of the fair value per Boe of reserves sold or 22% of the fair value of reserves retained) was viewed by the Company’s management to be a substantial economic difference.

If the Company had calculated the gain or loss recorded on disposal using an allocation of capitalized costs based on the amortization methodology, the loss recorded would have been reduced from $399.1 million to $88 million, including $15 million attributable to noncontrolling interests, and the Company’s depletion rate would have increased by approximately 5%. Additionally, use of the amortization methodology would have resulted in a larger value assigned to the Company’s remaining full cost pool which would have resulted in additional expense from a ceiling test write down at March 31, 2013.

Liquidity and Capital Resources, page 55

22. Please expand to explain the reason the Company’s 2013 budget for capital expenditures was revised in May 2013 to approximately $1.45 billion, from the previous budget of $1.75 billion. Similarly, please expand the disclosure of Capital Expenditures on page 58 to discuss the factors underlying the decrease in capital expenditures from $580 million in the first quarter of 2012, to $394 million in the first quarter of 2013.

Response

We acknowledge the Staff’s comment. Set forth below is proposed disclosure which we believe responds to the Staff’s comment. We undertake to include this disclosure (updated appropriately) in future annual reports on Form 10-K and quarterly reports on Form 10-Q. We also note for the Staff that this disclosure was included on pages 63 and 65 of the Second Quarter Form 10-Q under the heading “Liquidity and Capital Resources.”

After a comprehensive review and analysis by management and the Board of Directors of the Company’s strategy, assets and spending levels, which resulted in an increased focus on capital discipline, creating sustainable returns and lowering risk levels, the Company’s 2013 budget for capital expenditures, including expenditures related to the Company’s drilling programs for the Royalty Trusts, was revised in May 2013 to approximately $1.45 billion. The majority of the Company’s capital expenditures are discretionary and could be curtailed if the Company’s cash flows are less than expected or if the Company is unable to obtain capital on attractive terms. The Company and one of its wholly owned subsidiaries are parties to development agreements with the Permian Trust and the Mississippian Trust II that obligate the Company to drill, or cause to be drilled, a specified number of wells within specified areas of mutual interest for each Royalty Trust by March 31, 2016 and December 31, 2016, respectively. The Company fulfilled its drilling obligation to the Mississippian Trust I during the second quarter of 2013. In addition, production targets contained in certain gathering and treating arrangements require the Company to incur capital expenditures or make associated shortfall payments.

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Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 17

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the six-month periods ended June 30, 2013 and 2012 are summarized below:

	Six Months Ended June 30, — 2013	2012
	(In thousands)
Capital Expenditures
Exploration and production	$ 716,173	$ 1,010,248
Drilling and oil field services	1,515	13,752
Midstream services	30,332	41,729
Other	27,850	65,983
Capital expenditures, excluding acquisitions	775,870	1,131,712
Acquisitions	8,602	761,575
Total	$ 784,472	$ 1,893,287

Capital expenditures for the six months ended June 30, 2013 decreased by $1.1 billion from the same period in 2012 primarily as a result of the Dynamic Acquisition having occurred in 2012 and, to a lesser extent, a reduction to the Company’s 2013 capital budget resulting from management’s and the Board of Directors’ review and analysis of the Company’s strategy, assets and spending levels.

Definitive Proxy Statement on Schedule 14A Filed May 29, 2013

Disclosure Related to Summary Compensation Table and Grants of Plan-Based Awards Table, page 33

Employment Agreement of Tom L. Ward, page 33

23. Please revise to disclose the activities that Mr. Ward is prohibited from engaging in, as set forth in Section 3 of his employment agreement. Please also expand to discuss in better detail the non-competition provision set forth in Mr. Ward’s employment agreement in the event his employment is terminated.

Response

We acknowledge the Staff’s comment and note for the Staff that (i) the Company’s 2013 Annual Meeting of Stockholders was held on July 1, 2013 and (ii) Mr. Ward’s employment with the Company was terminated, effective June 28, 2013. Consequently, the Company believes the requested revision to the proxy statement would be of little value to the Company’s stockholders. The Company undertakes to provide disclosure to address the Staff’s comment in its future filings with the Commission to the extent provisions similar to those contained in Mr. Ward’s employment agreement are included in any of its other executives’ employment agreements.

Website Presentations

Non-GAAP Financial Reconciliations

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 18

24. We note that you have identified in your general discussion of non-GAAP measures, operating cash flow as a non-GAAP measure. However, as this label is a GAAP term that is synonymous with cash flows with operations, terms that you have utilized interchangeably in your annual report, you should discontinue using this label for your non-GAAP measures and instead utilize a label that is clearly distinct and representationally faithful.

Response

We note the Staff’s comment, and in response thereto, we have changed the label of this non-GAAP measure to adjusted operating cash flows beginning with the Company’s presentation related to its earnings release for the fiscal quarter ended June 30, 2013.

Non-GAAP Measures—Fourth Quarter/Year End 2012

25. Tell us whether the commodity derivative related adjustments made in computing your non-GAAP measures of Adjusted EBITDA are intended to reflect only cash settlements of your commodity derivatives. Please submit a schedule showing the extent to which these adjustments do not result in a settlement measure that correlates precisely with the cumulative gain or loss recognized in accounting for your commodity derivatives at fair value since acquired.

Response

With the exception of the commodity derivative adjustments designated as “realized on early settlements of derivative contracts,” the commodity derivative adjustments made in computing the Company’s non-GAAP measure of Adjusted EBITDA are intended to reflect only cash settlements of the Company’s commodity derivative contracts. For contracts designated as “realized on early settlements of derivative contracts,” cash settlements have occurred; however, the Company removes the effect of such cash settlements as it considers these transactions to be event-driven rather than part of the Company’s overall, ongoing commodity hedging strategy. A schedule of (gains) or losses realized on early settlements of derivative contracts during the fourth quarter and year ended December 31, 2012 is as follows:

	Quarter Ended	Year Ended
	December 31, 2012
	(in thousands)
Realized gains on early settlements of derivative contracts	$ —	$ (59,338	)

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 19

The Company hereby acknowledges that:

• the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

• staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Mr. H. Roger Schwall

U.S. Securities and Exchange Commission

Page 20

If you have any questions or require any additional information, please contact Philip T. Warman at 405-429-6136 or Justin P. Byrne at 405-429-5706.

Very truly yours,
SandRidge Energy, Inc.
By:	/s/ Eddie M. LeBlanc III
Name:	Eddie M. LeBlanc III
Title:	Executive Vice President and Chief Financial Officer