February 19, 2014
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 December 13, 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 February 4, 2014 (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 December 13, 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 to Comment 6 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.
Form 10-K for the Fiscal Year ended December 31, 2012
Business, page 1
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 2
Business Segments and Primary Operations, page 4
West Texas Overthrust, page 6
1. We note your response to prior comment two, clarifying that you have accrued your delivery shortfall liability using the $0.25 rate and have not accrued the incremental $0.70 per Mcf end-of-contract penalty because the opportunity to avoid payment by making excess deliveries in a future period has introduced uncertainty about the extent to which this liability may be reduced before it must otherwise be paid in 2042 (i.e., the final year of the contract).
You thereby emphasize that ultimate payment is less than probable and not estimable. However, these assessments appear to arise only when contemplating future events that may alleviate your liability rather than being attributable to incomplete information about the delivery shortfalls that have already occurred. We would like to understand why you believe the financial implications of actual delivery shortfall are subject to the guidance for loss contingencies in FASB ASC 450-20, and why if you are subject to this guidance, you have not effectively offset your loss with gain that is contingent on excess deliveries in the future, contrary to the guidance in FASB ASC 450-30-25-1 and 50-1.
Please explain your basis for assuming future excess deliveries will occur and be sufficient to avoid additional payment. Given your history of recording shortfalls in 2012 and 2013, and the information set forth in your response regarding an inability to provide an estimate, there does not appear to be a basis to forecast a surplus sufficient to overcome past CO2 delivery deficiencies.
Response
The terms of the treating agreement specify that delivery deficiency volumes in a given year are not added to the subsequent year’s annual requirement, but rather are added to the annual requirement of the final year of the term of the agreement. In the event the contract is cancelled by Occidental prior to the end of its term, whether due to nonperformance by the Company or otherwise, the Company is not obligated to pay Occidental the $0.70 end-of-contract penalty on any delivery deficiency volumes incurred through the date of cancellation. ASC 450-20 defines a contingency as “An existing condition, situation, or set of circumstances involving uncertainty as to possible gain (gain contingency) or loss (loss contingency) to an entity that will ultimately be resolved when one or more future events occur or fail to occur.” As the delivery shortfalls in 2012 and 2013 create uncertainty that will not be resolved until future deliveries occur or fail to occur, the Company believes the contingencies guidance is applicable with respect to the treating agreement.
The Company has prepared several analyses based upon the assumption that drilling will resume in the West Texas Overthrust (“WTO”) once natural gas prices reach a level sufficient to produce a reasonable rate of return, all of which indicate that the Company would produce enough natural gas, and consequently enough CO2, to satisfy the total CO2 volume delivery commitment under the treating agreement. For this reason, the Company is currently not able to reasonably determine what portion of delivery deficiency volumes incurred in 2012 and 2013, if any, will ultimately be attributed to the annual requirement of the final year of the term of the agreement (2042) and believes its disclosures are compliant with guidance set forth in ASC 450-20.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 3
As mentioned in the correspondence dated December 13, 2013, the Company is in discussions with other companies that have expressed interest in developing the WTO. As part of those discussions, the Company has analyzed various scenarios for the development of the field. The attached chart presents estimated CO2 volumes that would be delivered as a result of WTO development assuming the resumption of drilling in the WTO at a price of $4.80 per Mcf of natural gas. This would result in a 20% rate of return, which the Company believes is a reasonable rate for natural gas drilling compared to other available drilling projects. Analyses of WTO development utilizing both a 10-rig drilling program and a 15-rig drilling program were prepared. The Company believes these would be nominal amounts of drilling activity given the fact that at one point in time the Company had over 40 rigs drilling in the WTO. At the time these analyses were prepared, the November NYMEX strip indicated a natural gas price of $4.80 per Mcf in 2021; Therefore, four of the analyses assumed the resumption of drilling in 2022. Additionally, in order to analyze the impact to production of an earlier natural gas price recovery, four analyses assumed that the price of natural gas would reach $4.80 per Mcf and drilling would resume in 2016. Under each scenario, CO2 volumes delivered are sufficient to satisfy the Company’s total delivery obligation under the treating agreement such that the Company would not incur any end-of-term penalties.
After the Staff’s review of the above discussion and the attached chart, the Company would welcome any questions and is available to discuss any such questions at the Staff’s convenience.
Financial Statements
Note 1—Summary of Significant Accounting Policies, page F-9
Revenue Recognition and Natural Gas Balancing, page F-13
2. We have read your response to prior comment seven and understand that you regard the Century Plant construction and CO2 delivery contracts to be separate units of accounting under FASB ASC 605-25-25-5. We would like to understand how you applied the guidance in FASB ASC 605-25-30-2 and 5, in recognizing the entire $796.3 million contract price as revenue in 2012, while zero has been allocated to your CO2 delivery commitment, which appears to represent a substantial performance obligations as evidenced by the penalty provisions in the treating and delivery agreement. Please explain why the amount allocated to the Century Plant was not limited to zero under this provision and why ultimate realization of proceeds are not viewed as contingent upon the delivery of CO2.
Response
The Company believes the construction and treating agreements entered into by the Company and Occidental are not typical to those contemplated under the guidance set forth in ASC 605-25, as (1) the Company has entered into the treating agreement in order to contract for the provision of services (processing of its natural gas production) and not as a revenue earnings
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 4
activity, and (2) both parties to the treating agreement have significant performance obligations – the Company is obligated to deliver CO2 through the delivery of natural gas for treating at the Century Plant and Occidental is obligated to provide available treating capacity and treating services for Company-delivered volumes. The guidance set forth in ASC 605-25 does not specifically address the recognition of revenue attributable to a delivered item in situations where contracts have been entered into in contemplation of one another, but the purchaser of the initial deliverable is obligated to provide significant services in conjunction with the receipt of another deliverable of the arrangement; however, application of the guidance found in ASC 605-25-30-2 to both the Century Plant construction and CO2 delivery obligation as “deliverables” under the contracts requires consideration to be allocated at inception to all deliverables on the basis of their relative selling price. Consideration received from Occidental under the construction contract of $796.3 million represents the selling price of the Century Plant under construction accounting treatment and represented the Company’s best estimate of the selling price of such a plant; as mentioned previously, CO2 is considered a “waste gas” and a byproduct of the natural gas treating process which must be disposed; therefore, a relative selling price of $0 was allocated to the CO2 to be delivered in the future.
ASC 605-25-30-5 states that the amount allocable to the delivered unit of accounting (the Century Plant) is limited to the amount that is not contingent upon delivery of additional items or meeting other specified performance conditions, with ASC 605-25-30-6 further indicating that the amount recognized attributable to the delivered item shall not exceed all amounts to which the vendor is legally entitled, including cancellation fees (in the event of customer cancellation). Under the terms of the treating agreement, Occidental is subject to significant penalties in the event that Occidental chooses to terminate the agreement. Upon termination of the contract by Occidental, whether as a result of nonperformance by the Company or otherwise, Occidental is required to transfer title of the Century Plant to the Company, reimburse the Company for contract overages (i.e., costs incurred by the Company in excess of reimbursements paid by Occidental) during the construction of the Century Plant and pay the Company a lump sum penalty calculated based upon the Company’s CO2 delivery requirements in future periods (at a rate of $0.70 per Mcf). As such, an amount greater than the $796.3 million consideration received would be required to be transferred to the Company in the event Occidental terminated the agreement; therefore the allocable proceeds are not considered contingent upon future delivery of CO2 volumes under the guidance of ASC 605-25-30-5 nor are the proceeds limited under the guidance in ASC 605-25-30-6.
3. We understand from your response to prior comment seven that you have not recognized incremental oil and gas reserves in conjunction with the construction of the Century Plant, notwithstanding your accounting for construction contract losses as oil and gas property development costs under the full cost method. Tell us how you determined that construction costs were not development costs under the full cost method while also concluding that losses on the construction contract were development costs. Please also clarify whether you attributed the losses to evaluated properties whose costs are subject to amortization or unevaluated properties whose costs are not subject to amortization and explain how these losses have been factored into your ceiling tests at each balance sheet date
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 5
Response
As an oil and gas company following the full cost method of accounting that had also been contracted to construct a processing plant for a third party, it was necessary for the Company to decide as to which of two competing accounting models—full cost method of accounting for oil and gas or construction accounting—it would follow in accounting for the construction of the Century Plant, including any differences in billings and costs incurred. The Company’s capitalization of costs incurred in excess of billings that will not be paid or reimbursed by Occidental (“losses”) as development costs within the full cost pool resulted in the same impact to the full cost pool and net income as would have been recognized had the Company capitalized all costs incurred to construct the Century Plant in its full cost pool and credited reimbursements from Occidental to the full cost pool as received; however, the Company believes that its use of the completed contract method in this instance provides financial statement users greater visibility into the costs incurred and borne by the Company in connection with the construction agreement.
The Company acknowledges that costs incurred during construction in excess of payments received for the constructed asset would typically result in a loss on the income statement under construction accounting guidance; however, the Company believes in this instance that such losses are properly classified within the Company’s full cost pool as “development costs” as defined in Rule 4-10 of Regulation S-X (costs incurred to obtain access to proved reserves for extraction, treating, gathering and storing the oil and gas) because the Company incurred those costs solely for the purpose of developing its high-CO2 reserves within the Piñon Field. Because the Century Plant was constructed on behalf of Occidental and, upon completion, is an asset the title to which is held by Occidental, the Company did not consider construction costs subject to reimbursement under the construction contract to be development costs of the Company. Only the costs of the Plant’s construction that were ultimately borne by the Company, i.e., the losses, are considered development costs incurred by the Company.
During the construction phase of the Century Plant, estimated losses were accounted for as a major development project (Regulation SX Rule 4-10(c)(3)(ii)(B)) attributed to unevaluated properties in the WTO and were, therefore, excluded from costs subject to amortization. Additionally, such estimated losses were included in the Company’s ceiling for ceiling test purposes at the then current carrying cost (i.e., the losses were included in both the ceiling and the capitalized costs compared to the ceiling as allowed under Regulation SX Rule 4-10(c)(4)(i)(B)). Upon completion of the construction phase of the Century Plant, these losses were included in costs subject to amortization and were no longer included in the Company’s ceiling for ceiling test purposes (included only in capitalized costs subject to the ceiling limitation), due to the fact that construction of the Plant had concluded. The Company believes that attribution of these costs to unevaluated properties during the construction period was reasonable given the large number of unproved future identified drilling locations in the WTO and the fact that the Company’s existing smaller CO2 processing plants had capacity adequate to process natural gas volumes from then-producing WTO wells; however, attribution of these costs exclusively to proved properties, resulting in the inclusion of the losses in total costs subject to amortization during construction of the Century Plant, rather than upon completion, would not have resulted in a material change to the Company’s depletion rate nor would the resulting exclusion of the costs from the Company’s ceiling at each balance sheet date during construction of the Century Plant have resulted in a ceiling test impairment for any quarterly period.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 6
4. We have read your response to prior comment eight regarding mobilization fees, including your assertion that the difference between recognizing such fees over the mobilization period rather than upon mobilization would be insignificant. However, our concern is that you are recognizing these fees as revenue prior to the commencement of drilling and not over the period that you are operating the drilling rigs. We do not generally find that mobilization is regarded as a separate deliverable when incurred in conjunction with a drilling contract. Please explain to us why you believe all fees and costs associated with periods of mobilization would not be attributable to the drilling contract under FASB ASC 605-35-25-16 and 32, and reflected in the percentage of completion computations that you perform in accordance with FASB ASC 605-35-25-60, 70 and 78.
If you do not believe this guidance is applicable to your drilling contracts please explain the basis for your view and identify the specific authoritative literature that you have followed instead. Otherwise, explain your approach to selecting input or output measures in computing the percentage of completion, explain how you review and confirm progress by alternate means of observation and inspection, and describe your application of the segmenting guidance in FASB ASC 605-35-25-10 through 13 if you believe that you have more than one profit center with your drilling contracts. We reissue prior comment eight.
Response
The Company’s historical accounting treatment with respect to mobilization fees reflects its belief that mobilization is a stand-alone earnings process. This is because the fees are earned each time a rig is moved, whether conducted at the start of the contract or during the contract period. The Company considers its drilling contracts to be service contracts and, therefore, not within the scope of FASB ASC 605-35. Because the majority of the Company’s rig contracts cover the drilling of multiple wells over their contract terms, the Company considers each mobilization a deliverable under the arrangement. For this reason, the Company’s policy for recognition of mobilization fees is based upon analysis of the guidance in FASB ASC 605-25 for multiple element arrangements. Under the guidance found in FASB ASC 605-25-25-5, each mobilization may be accounted for as a separate unit of accounting because (a) each mobilization and well drilled has value to the customer on a stand-alone basis (ASC 605-25-25-5(a)) because such services are provided by other vendors on a stand alone basis and (b) as a service contract, no general right of return exists (ASC 605-25-25-5(c)). The Company’s contracts to provide drilling services state that mobilization fees are due and payable at the time the rig is rigged up or positioned at the well site ready to spud. Further, once a rig is mobilized, such mobilization fees are non-refundable regardless of whether the customer proceeds with subsequent drilling of a well at that particular location. Because spud-to-completion time for wells typically drilled by the Company’s rigs is relatively short, the impact of recognizing fees over the period the Company operates the drilling rigs rather than recognizing them upon completion of mobilization would have resulted in insignificant (decreases) increases in drilling and services revenue of approximately ($69,000), $331,000 and $36,000 for the years ended December 2012, 2011 and 2010, respectively.
5. We have read your response to prior comment nine and understand that you believe you have complied with Rule 4-10(c)(6)(iv)(B) of Regulation S-X. However, Rule 4-10(c)(6)(iv)(C) of Regulation S-X precludes application of the guidance you cite when services
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 7
are provided on behalf of investors in oil and gas producing activities managed by you or an affiliate. As previously set forth, we regard an operator of oil and gas properties to be a manager that is subject to the prohibition imposed by this guidance. Therefore, we believe you will need to revise your accounting policy to conform. If you believe that errors in your accounting are not material and you prefer to limit compliance to future filings, please submit the analysis that you performed in formulating your view.
Response
Drilling and oil field service revenues earned and expense incurred in performing services for the Company’s own account (i.e., its working interest in a property) are eliminated in consolidation such that, in the consolidated presentation, only revenues earned and expenses incurred attributable to services performed for third parties remain in the Company’s consolidated statement of operations. For this reason, and because the Company’s acquisition of its ownership interest in the properties was at least one year prior to the date of the associated service contracts and such ownership came about through transactions unrelated to the service contract, the Company submits that its accounting policy, and the disclosure describing such policy, are accurate and compliant with applicable guidance found in Rule 4-10(c)(6)(iv)(B). Such rule states that income may be recognized in connection with contractual services performed in connection with properties in which the registrant or an affiliate holds an ownership or other economic interest “where the registrant acquired an interest in the properties at least one year before the date of the service contract through transactions unrelated to the service contract, and that interest is unaffected by the service contract.” The rule further states that “income from such contract may be recognized subject to the general provisions for elimination of intercompany profits under generally accepted accounting principles.”
Note 14—Derivatives, page F-37
6. We have read your responses to prior comments 10 and 11 and note that although you have changed various captions of amounts presented in your filings, you have not referenced authoritative support for your calculations or related disclosures in lieu of the GAAP metrics. We reissue prior comments 10 and 11.
Response
The Company acknowledges that ASC 815 does not contain specific provisions that require the separate disclosure of realized and unrealized gains/losses on derivative contracts that are not designated as cash flow hedges.
Historically, in accordance with ASC 815-10-35-1 and ASC 815-10-35-2, the Company has presented one net figure within the consolidated statements of operations entitled “(gain) loss on derivative contracts” that represents all changes for the period in the value of derivative instruments, either settled or which continue to be held during the applicable period(s), (i.e., both realized and unrealized gains/losses). To enhance transparency of the components of this “(gain) loss on derivative contracts” amount, the Company’s historical 2012 Form 10-K separately disclosed within the footnotes on page F-39, unrealized gains/losses on derivative contracts, which included gains/losses due to changes in the fair value of derivative contracts to be settled in
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 8
future periods as well as the effects of reclassification of previously recognized unrealized gains/losses on contracts settled or otherwise terminated during the period to classification as realized gains/losses, in order to separately present as “realized” the total change in the respective contracts’ value from the date of inception to the date of settlement/termination.
As the terms “unrealized” and “realized” are utilized within ASC 815, although not in the context of required disclosures, and are commonly used in the industry, the Company believes its historical presentation enhanced transparency around the components of its net “(gain) loss on derivative contracts” amount. The historical disclosure of unrealized and realized gains/losses on derivative contracts in the Company’s footnotes, page F-39, reconciles to the aforementioned “(gain) loss on derivative contracts” presented within the consolidated statements of operations which as noted above, is in compliance with ASC 815-10-35-2. However, while ASC 815 does not prohibit the aforementioned disclosure of unrealized and realized gains/losses on derivative contracts, neither is this separate disclosure required.
Accordingly, we will revise our disclosures beginning with our 2013 Form 10-K, to disclose only the combined presentation of “(gain) loss on derivative contracts,” which includes all changes in the value of commodity derivative instruments, which is separately reported within our consolidated statements of operations, along with separate disclosure of the cash received (paid) upon settlement of derivative contracts and non-cash settlements related to any derivative contracts that are amended, if applicable.
Further, we will revise our consolidated statements of cash flows beginning with our 2013 Form 10-K, to disclose only the combined presentation of “(gain) loss on derivative contracts,” which includes all changes in the value of commodity derivative instruments. We will separately disclose the cash received (paid) upon settlement of derivative contracts, including any cash (paid) received on settlement of any financing derivative contracts, as applicable.
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 | |
Attachment
10 Rig Drilling Program | ||||||||||||||||||||||
Start Year | CO2 Volume (1) | Banked Volumes (2) | Total Delivered CO2 Volumes | Total Due (3) | Total Excess Delivered | |||||||||||||||||
2022 | 3,553,711,908 | 57,578,733 | 3,611,290,641 | 3,192,894,333 | 418,396,308 | 10 rigs, reducing to 4 rigs in the 3rd year drilling through the end of contract | ||||||||||||||||
2022 | 4,590,071,719 | 57,578,733 | 4,647,650,452 | 3,192,894,333 | 1,454,756,119 | 10 rigs, reducing to 6 rigs in the 7th year, then 5 rigs in the 11th year and drilling through the 20th year of the contract | ||||||||||||||||
2016 | 4,517,135,869 | 57,578,733 | 4,574,714,602 | 3,192,894,333 | 1,381,820,269 | 10 rigs, reducing to 4 rigs in the 3rd year and continuing to drill through the end of the contract | ||||||||||||||||
2016 | 5,543,073,392 | 57,578,733 | 5,600,652,125 | 3,192,894,333 | 2,407,757,792 | 10 rigs, reducing to 6 rigs in the 7th year, then 5 rigs in the 11th year and drilling through the 19th year of the contract | ||||||||||||||||
15 Rig Drilling Program | ||||||||||||||||||||||
2022 | 3,804,901,286 | 57,578,733 | 3,862,480,019 | 3,192,894,333 | 669,585,686 | 15 rigs, reducing to 4 rigs in the 4th year drilling through the 25th year of the contract | ||||||||||||||||
2022 | 4,770,092,179 | 57,578,733 | 4,827,670,912 | 3,192,894,333 | 1,634,776,579 | 15 rigs, reducing to 5 rigs in the 10th year drilling through the 20th year of the contract | ||||||||||||||||
2016 | 4,776,088,594 | 57,578,733 | 4,833,667,327 | 3,192,894,333 | 1,640,772,994 | 15 rigs, reducing to 4 rigs in the 4th year drilling through the 27th year of the contract | ||||||||||||||||
2016 | 5,655,998,502 | 57,578,733 | 5,713,577,235 | 3,192,894,333 | 2,520,682,902 | 15 rigs, reducing to 6 rigs in the 4th year, then 5 rigs in the 11th year and drilling through the 19th year of the contract | ||||||||||||||||
| (1) | Total CO2 produced as part of the raw gas stream along with the methane |
| (2) | Volume of CO2 produced prior to the startup of the Century Plant and allowed to be banked and credited to the contract obligation volumes |
| (3) | Total CO2 delivery obligation under contract |