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 | ||||||||||
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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 | ||||||||||
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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 | ||||||||||
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Total proved (MMBoe)(3) | 565.9 | 470.6 | ||||||||||
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PV-10 (in millions)(4) | $ | $ | 7,488.4 | $ | 6,875.9 | |||||||
Standardized Measure of Discounted Net Cash Flows | $ | $ | 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 | ||||||||||
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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 | ||||||||||
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PV-10 | $ | $ | 7,488.4 | $ | 6,875.9 | |||||||
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| (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 | |||||||
| (1) | Prices represent actual average prices for the periods presented and do not include effects of derivative transactions. |
Risk Factors, page 32
“The Company’s development and exploration operations require substantial capital…,” page 37
5. We note your response to prior comment eight and we reissue that comment in part. We note that your capital expenditures for 2012 related to your exploration and production segment were $2.0 billion, while your cash flows from operations were $783 million. Please provide context for this risk factor by quantifying the amount of cash flows from operations available in the recent past to fund your capital expenditures.
Response
The Company will update its disclosures in future filings, beginning with its 2013 Form 10-K, by quantifying the amount of cash flows from operations available to fund the Company’s capital expenditures in recent prior periods.
Management’s Discussion and Analysis, page 61
Liquidity and Capital Resources, page 73
6. We note your response to prior comment 11 and we reissue that comment. Notwithstanding your presentation at Note 3 of drilling carry amounts received, utilized, and remaining, we believe that you should provide here a more robust discussion of your dependence on such arrangements. Our MD&A requirements call for companies to provide investors and other users with material information that is necessary to an understanding of the company’s financial condition and operating performance, as well as its prospects for the future. In determining required or appropriate disclosure, you should evaluate separately your ability to meet upcoming cash requirements over both the short and long term. Absent further analysis, merely reciting the sources that you “depend on” for cash flows is not sufficient. Nor is stating that you have adequate resources to meet your short-term cash requirements, unless no additional more detailed or nuanced information is material.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 8
Given your history of not generating sufficient cash flows from operations to fund your exploration and production capital expenditures, we believe you should further discuss and analyze your various sources of financing. For further guidance on the overall approach to MD&A, including the presentation, content, and focus of the disclosure, please refer to Sections III and IV of the SEC Interpretive Release No. 33-8350 and Sections 501.12 and 501.13 of the Financial Reporting Codification.
With respect to your response that you expect drilling carries in 2013 to be consistent with amounts received in respect of 2012, please tell us whether you are aware of or expect these amounts to be consistent beyond 2013.
Response
The Company will include within theCapital and Liquiditysection in the 2013 Form 10-K amounts by which the Company’s capital expenditures have been offset through drilling carry funding received during each period presented. The Company expects any unused drilling carry amounts remaining at December 31, 2013 to be fully used during 2014 such that no carry amounts will remain unused at December 31, 2014. The Company will disclose this fact within theCapital and Liquidity section of the 2013 Form 10-K.
Additionally, set forth below is proposed disclosure which we believe responds to the Staff’s comments regarding the analysis of the Company’s various sources of financing. We undertake to include this disclosure (updated appropriately) in future annual reports on Form 10-K and quarterly reports on Form 10-Q.
The Company’s 2014 budget for capital expenditures, including expenditures related to the Company’s drilling programs for SandRidge Permian Trust and SandRidge Mississippian Trust II and net of approximately $X million in drilling carries estimated to be received, is approximately $X.X billion. The Company expects to fund its near term capital and debt service requirements and working capital needs with cash on hand ($XXX million at December 31, 2013), cash flow from operations and available borrowing capacity under its $750 million senior credit facility, which is fully undrawn, other than $XX million in letters of credit secured by the facility that reduce availability on a dollar for dollar basis, at December 31, 2013. The Company has no maturities of long-term debt prior to 2020, and may choose to issue new long-term debt, subject to market availability, as an alternative to borrowing under its senior credit facility. Alternatively, the Company may issue equity or other non-debt securities in the capital markets, depending on market conditions, to address its funding requirements. In the longer term, the Company expects an increasing portion of its funding needs to be covered by increased cash flows from operations, resulting from its drilling program combined with recently implemented cost cutting initiatives, and may issue long-term debt or equity or sell non-core assets to cover any difference between cash flow from operations and capital needs. Further, the majority of the Company’s capital expenditures is discretionary and could be curtailed if the Company’s cash flows decline from expected levels.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 9
Financial Statements
Note 1—Summary of Significant Accounting Policies, page F-9
Revenue Recognition and Natural Gas Balancing, page F-13
7. We have read your response to prior comment 13 and have the following additional questions regarding your accounting for the contracts with Occidental Petroleum Corporation to build the Century Plant and to deliver CO2:
| a. | Given that you disclosed that you were following the completed contract method of accounting, and entered into both contracts in conjunction with one another, explain how you considered the CO2 delivery obligation to be outside of the contract accounting model and not subject to the project segmenting criteria in FASB ASC 605-35-25-11, 12 and 13. |
Response
As a preliminary matter, the Company directs the Staff’s attention to theTimeline – Century Plant Transaction, Natural Gas Prices and WTO Development(the “Timeline”) attached hereto as Annex A, which the Company believes will be useful in the Staff’s consideration of this response and certain other responses below.
Because the Century Plant construction and natural gas treating agreements were entered into at or near the same time between the same entities, the two contracts were evaluated pursuant to ASC 605-25 for revenue recognition for multiple-element arrangements, since the treating agreement is a service contract (for processing services to be performed by Occidental as owner of the Century Plant) that is not within the scope of ASC 605-35 (ASC 605-35-15-6j).
Pursuant to ASC 605-25-15-3A(c), the provisions of ASC 605-25 should be applied in order to determine whether to separate the deliverables. The Company’s deliverables under the construction agreement and natural gas treating service agreement are the Century Plant and specified volumes of CO2, respectively. Although ASC 605-25-25-3 through 605-25-25-6 state that separate contracts with the same entity or related parties that are entered into at or near the same time are presumed to have been negotiated as a package and shall, therefore, be evaluated as a single arrangement in considering whether there are one or more units of accounting, this presumption may be overcome if there is sufficient evidence to the contrary. A vendor shall evaluate all deliverables in an arrangement to determine whether they represent separate units of accounting.
In analyzing an arrangement with multiple deliverables, the delivered item or items shall be considered a separate unit of accounting if all the following criteria of ASC 605-25-25-5 are met:
| a. | The delivered item or items have value to the customer on a standalone basis. The item or items have value on a standalone basis if they are sold separately by any vendor or the customer could resell the delivered item(s) on a standalone basis. In the context of a customer’s ability to resell the delivered item(s), this criterion does not require the existence of an observable market for the deliverable(s). |
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 10
| b. | Subparagraph superseded by Accounting Standards Update No. 2009-13 |
| c. | If the arrangement includes a general right of return relative to the delivered item, delivery or performance of the undelivered item or items is considered probable and substantially in the control of the vendor. |
With respect to the two Occidental agreements, the first criterion is met because the delivered item, the Century Plant, has value on a standalone basis, as natural gas processing plants are sold separately by others in the industry and Occidental may resell the Century Plant.
Analysis of the second criterion requires analysis of the delivered item, the Century Plant, and additional analysis of the undelivered item, CO2, only if there is a general right of return for the Century Plant. With respect to the Century Plant, there is no general right of return; therefore, the criteria of ASC 605-25-25-5 are met, and the Company considers the Century Plant and the CO2 delivery separate units of accounting.
| b. | Tell us how you determined that the 30-year treating agreement was both “separate” and “at market,” as indicated in your response. Please analyze and discuss how “the price you pay” under the agreement to treat your natural gas, and the annual and end-of-agreement shortfall payments over the 30 year duration of the agreement have been taken into account. |
The Company directs the Staff’s attention to its response to Comment 7.a. for an analysis of the construction and 30-year treating agreements as “separate.”
The Company considers the 30-year treating agreement to be “at market” because the terms of the agreement are terms consistent with long-term treating contracts to which the Company is or was a party and contains features common in the oil and gas industry. The Company directs the Staff’s attention to the Timeline (June 2008 section) for further discussion of the terms of the treating agreement, which support the Company’s determination that the agreement is “at market”.
| c. | Please explain how you would view these contracts as pertaining to separate earnings processes and discrete earnings events in defining your units of account, with reference as applicable to the guidance in FASB ASC 605-25, regarding multiple element arrangements, also considering the guidance in SAB Topic 13:A.3.f., IRQ1, as the economics of plant construction from the standpoint of the counterparty would seem to depend on your CO2 delivery obligation. |
The Company directs the Staff’s attention to its response to Comment 7.a. for an analysis of the agreements as separate units of accounting.
| d. | You state that construction of the plant was necessary to develop your natural gas reserves in the Piñon Field, and for this reason you accounted for loss on the construction contract as a development cost under the full cost methodology rather than as prescribed in FASB ASC 605-35-25-46. Tell us the quantities of reserves in this field that were reclassified from proved undeveloped to proved developed in conjunction with completing construction of the plant in the fourth quarter of 2012, and explain how the related CO2 content compares to the amounts you are required to deliver. |
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 11
As discussed in the Timeline, the Company’s ability to economically develop the Piñon Field and greater WTO and, therefore, recognize quantities of proved reserves (both developed and undeveloped) depend upon both (1) the availability of processing capacity for the high CO2 gas found there and (2) the price the Company is able to realize upon sale of the processed natural gas. As discussed in greater detail in the Timeline, market prices for natural gas from mid-2008 through the end of 2012 were volatile, decreasing from the effective date of the contract with Occidental to the delivery of the plant to Occidental by approximately 74%. This sharp decline in natural gas prices resulted in many previously identified WTO drilling locations being no longer economically viable and also caused the productive lives of some already producing wells to be truncated, regardless of available processing capacity. No significant drilling took place in the WTO during 2010, 2011 or 2012 and at December 31, 2012, no proved undeveloped WTO locations remained in the Company’s reserves. Accordingly, no reserves in the Piñon Field were converted from proved undeveloped to proved developed in conjunction with completing construction of the Century Plant.
| e. | Please explain the reasons for any discrepancy between the incremental developed reserves obtained upon completing construction and the quantities necessary to satisfy your delivery obligations so that we may better understand your view of the losses as development costs. |
As explained in the response to Comment 7.d above, no reserves in the Piñon Field were converted from proved undeveloped to proved developed in conjunction with completing construction of the Century Plant.
| f. | Submit a schedule showing a rollforward of your contract costs, billings, collections, and contract losses booked to the full cost pool each period since the commencement of the construction contract. Tell us the manner by which the losses were calculated and the extent to which the amounts reflected a change in your estimates of future costs. |
Through 2009, costs for the Century Plant construction project were estimated to be within the contract amount of $800 million. Beginning in the fourth quarter of 2009, the Company engineer in charge of the Century Plant construction project began preparing quarterly a cost summary and forecast for the project. This cost summary reflected the then current estimate to complete the entire project, the amount spent to date and the estimated remaining balance to be spent using current information available to estimate costs for completion. A factor was applied to the estimated costs for potential fluctuations in prices of the materials remaining to be purchased and the contingencies for the project. A low and high estimate was determined in this process and the low estimate was then compared to the contract price to determine either a gain or loss.
Please see the attached schedule for the low and high estimates to complete the project, along with the cumulative loss taken to the full cost pool as development costs. As requested by the Staff, the attached schedule also contains a rollforward of the costs, billings, receipts and losses booked to the full cost pool and the balance of costs in excess of billings and loss or billings and loss in excess of costs reflected in the Company’s balance sheet.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 12
| g. | Tell us the extent to which the shortfall obligation you have recognized is attributable to insufficient CO2 content in deliveries that were made and expected to satisfy your delivery obligation for the period, or curtailed or limited production from the Piñon Field. |
As discussed above, the steep decline in natural gas prices between 2008 and 2012 resulted in many previously identified Piñon Field drilling locations being no longer economically viable and caused the productive lives of some already producing wells to be truncated. Accordingly, fewer wells have been drilled than were projected at the time the treating agreement was executed. The shortfall obligation the Company has recognized is attributable to this decreased drilling and the resulting decline in production from the Piñon Field and WTO; it is not the result of the delivered gas having a lower CO2 content than anticipated.
| h. | Please explain how the circumstances leading to the CO2 delivery shortfall have been considered in forming an expectation about meeting your delivery obligations in future periods. |
As stated in the Company’s response to Comment 7.g, the cause of the Company’s current CO2 delivery shortfall is the decline in production from the Piñon Field and WTO resulting from decreased drilling due to depressed natural gas prices. Because economic development of the WTO depends heavily on prices that may be realized from the sale of processed natural gas, which are volatile, the Company is not able to form any reliable expectation as to whether the circumstance leading to the currently recorded shortfall obligation will continue in future periods, because it is not able to predict with any certainty the prevailing levels of natural gas prices in future periods.
As noted in the Company’s response to Comments 2 and 12, however, the Company included revised disclosure in 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 necessary for the reader to estimate a minimum to maximum liability range or an estimated liability according to the reader’s discretion.
8. We have read your response to prior comment 14 and note that you describe an accounting policy for mobilization fees that does not appear to be the same as the policy disclosed in your financial statements. Further, it is not clear how your practice of recognizing such fees as revenues upon completing mobilization complies with either the guidance on segmenting contracts in FASB ASC 605-35-25-12 and 13, or SAB Topic 13 (A)(3)(f), IRQ 1. Please explain to us the reason for the apparent disparity between your explanation in the response letter and your policy disclosure on page F-13. Please also provide reference to the authoritative literature that you have followed in formulating your accounting policy for mobilization fees.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 13
Response
The Company’s accounting policy for rig mobilization fees is to recognize mobilization fees each time a rig is moved, whether the mobilization is conducted at the start of the contract or within the contract period. The Company’s response to the Staff’s prior Comment 14 attempted to clarify the description of the Company’s policy in its 2012 Form 10-K by explaining more clearly how the Company accounts for such fees. As noted in the Company’s response to the Staff’s prior Comment 14, terms of the Company’s rig contracts range from one month to two years. Given that drilling a well in areas where the Company’s rigs operate typically takes from five to 30 days, it is common for a rig to move and be mobilized at a new location multiple times throughout the term of a contract. These contracts are for onshore drilling, with mobilization fees consisting primarily of actual trucking and crane service costs incurred to mobilize the rig and/or a percentage (typically 75% to 90%) of the day rate for each mobilization. Because mobilizations are typically completed within a few days, the impact, if any, of recognizing fees over the mobilization period rather than recognizing them upon completion of mobilization would be insignificant. Mobilization fees recognized by the Company were $12 million for 2012, which averaged $40,000 per well drilled, $13 million for 2011, which averaged $70,000 per well drilled and $4 million for 2010, which averaged $53,000 per well drilled.
9. We have read your response to prior comment 15, regarding income recognized for services performed on behalf of third-parties having interests in wells that you operate. We understand that you have not considered the prohibition on income recognition in Rule 4-10(c)(6)(iv)(C) of Regulation S-X to be applicable because you are not the sponsor of the properties nor an owner also managing other investments of the investors, and you consider your role to be that of an operator, which you view differently than a manager of oil and gas producing activities. However, the guidance referenced above does not accommodate the interpretation you have described. We regard an operator of oil and gas properties to be a manager that is subject to the prohibition imposed by this guidance.
Under the full cost method, fees received for contractual services performed in connection with properties in which you or an affiliate hold an ownership or other economic interest and for which either you or an affiliate serve as the operator, should be recorded as an adjustment to the full cost pool rather than as income. Please submit the revisions that you propose to conform with the aforementioned guidance, including the changes to your accounting, narratives in MD&A, and the related policy disclosures. If you believe the revisions would not be material please submit your analysis for each quarterly and annual period.
Response
To further clarify the Company’s previous 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. Such revenues earned less expenses incurred, after applicable eliminations, totaled $4.9 million, $2.3 million and ($1.6) million for the years ended December 31, 2012, 2011 and 2010, respectively. 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
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 14
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
10. We have read your responses to prior comment 17 including your observation that the termsrealized andunrealized gain andloss are used in ASC 815. Please identify the specific provisions of ASC 815 that support the separate disclosure of realized and unrealized gains / losses on derivative contracts not designated as cash flow hedges. As part of your response, explain to us why the measure of unrealized gains / losses that you have presented is an amount calculated in accordance with U.S. GAAP. In addition, please tell us whether unrealized gains / losses on derivative contracts not designated as cash flow hedges represents both unrealized gains / losses on instruments held at period end and the reversal of previously recognized gains / losses on instruments settled during the period.
Response
Where gains/losses on derivative contracts have been presented separately in the Company’s filings, use of the term “realized” indicates gain/loss associated with contracts that have been settled or otherwise terminated. Use of the term “unrealized” indicates gain/loss due to changes in the fair value of derivative contracts to be settled in 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 present as “realized” the total change in the respective contracts’ value from the date of inception to the date of settlement/termination. Set forth below in response to Staff’s Comment 11 is proposed disclosure which we believe responds to the Staff’s comment and also provides clarified disclosure to investors.
11. Separately, in view of our question regarding the support under U.S. GAAP for your separate presentation of realized and unrealized gains and losses, please explain your basis for concluding the following presentations are appropriate:
Response
| • | Separate disclosure of unrealized gains and losses on the face of your consolidated statements of operations; |
The Company has not presented unrealized gains and losses separately on the face of its statement of operations.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 15
| • | The line items for “Unrealized hedge loss (gain)” and “Realized (gain) loss on derivative contracts” in your consolidated statements of cash flows; |
The Company has presented separately “unrealized gain/loss on derivative contracts,” “realized gain/loss on amended derivative contracts” and “realized gain/loss on financing derivative contracts” in its consolidated statements of cash flows in order to clarify for the reader that, while each of these items is a non-cash adjustment to net income in order to arrive at net cash provided by operating activities, the latter two line items, “realized gain/loss on amended derivative contracts” and “realized gain/loss on financing derivative contracts,” are non-cash adjustments associated with contracts that have settled or otherwise terminated, while the former line item is a non-cash adjustment due to changes in market value of open contracts. Additionally, the latter two referenced items have been presented separately from each other in order to clarify for the reader that the contracts were settled under different circumstances (amendment versus contractual maturity).
In the Company’s Third Quarter Form 10-Q, the following changes that we believe respond to the Staff’s Comments (#10 and #11) were made to the line item descriptions referenced above. We undertake to include this disclosure in future annual reports on Form 10-K and future quarterly reports on Form 10-Q.
Description as Presented in: | ||
2012 Form 10-K | Third Quarter 2013 Form 10-Q | |
| Unrealized gain/loss on derivative contracts | Gain/loss due to change in fair value of derivative contracts | |
| Realized gain/loss on amended derivative contracts | Gain/loss due to amendment of derivative contracts | |
| Realized gain/loss on financing derivative contracts | Gain/loss due to contractual maturity of financing derivative contracts | |
| • | Disaggregated presentation of realized and unrealized gains / losses in the notes to your consolidated financial statements; |
In the Company’s Third Quarter Form 10-Q, the following changes that we believe respond to the Staff’s Comments (#10 and #11) were made to the line item descriptions referenced above. We undertake to include this disclosure in future annual reports on Form 10-K and future quarterly reports on Form 10-Q.
Description as Presented in: | ||
2012 Form 10-K | Third Quarter 2013 Form 10-Q | |
| Realized gain/loss on derivative contracts | Gain/loss on settlement of derivative cotracts | |
| Unrealized gain/loss on derivative contracts | Gain/loss due to change in fair value of derivative contracts | |
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 16
| • | Separate presentation and discussion of realized and unrealized gains /losses in both tables and text provided in your MD&A; and |
The Company directs the Staff’s attention to its response to the previous portion of this Comment.
| • | Separate presentation and discussion of realized and unrealized gains /losses under your Quantitative and Qualitative Disclosures About Market Risk. |
The Company directs the Staff’s attention to its response to the previous portion of this Comment.
As part of your response to these points, explain to us why you believe presentations based solely on total net GAAP gain or loss and/or total net proceeds, as may be relevant to the circumstances of a particular presentation, would not be preferable.
The Company directs the Staff’s attention to its response to the previous portion of this Comment.
Note 16—Commitments and Contingencies, page F-41
12. We have read your response to prior comments 11 and 12 regarding payments that may be required under your development agreements with Royalty Trusts and your CO2 delivery obligations under your Treating Agreement Commitment. Please expand your disclosure under this heading to quantify payments that are reasonably possible under these arrangements. Given the uncertainty and potential significance of your minimum CO2 delivery obligations, this disclosure should include the maximum cumulative payments that may be required over the term of the agreement, on the basis of being unable to deliver quantities of CO2 beyond those future deliveries that you assess as probable of occurring, for which the incurrence of payments under the minimum delivery provision is considered to be remote, and therefore not within the range of reasonably possible loss.
Response
The Company will expand its disclosure within its Commitments and Contingencies footnote to the financial statements in future filings on Form 10-K and Form 10-Q to include amounts the Company considers reasonably possible to be paid in conjunction with its development agreements with Royalty Trusts consistent with the information disclosed on page 78 of the Company’s 2012 Form 10-K. Set forth below is such proposed disclosure. We undertake to include this disclosure (updated appropriately) in future annual reports on Form 10-K and quarterly reports on Form 10-Q.
Development Agreements with Royalty Trusts. The Company’s development agreements with the Permian Trust and Mississippian Trust II obligate the Company to drill, or cause to be drilled, a specified number of wells within an area of mutual interest for each trust by March 31, 2016 and December 31, 2016, respectively. The estimated cost to fulfill the drilling obligations remaining at December 31, 2013 totaled approximately $XXX.X million. The Company fulfilled its drilling obligation to SandRidge Mississippian Trust I during 2013.
Mr. H. Roger Schwall
U.S. Securities and Exchange Commission
Page 17
With respect to the Company’s CO2 delivery obligation under the 30-year treating agreement, the Company directs the Staff’s attention to its response to Comment 2.
Note 25 Supplemental Information on Oil and Natural Gas Producing Activities, page F-62
Oil and Natural Gas Reserve Quantities (Unaudited), page F-63
13. We acknowledge your response to prior comment 19 with respect to expanding the disclosure on page F-64 relating to the 2010, 2011 and 2012 revisions of previous estimates. Based on the information presented on pages F-64 and F-65, it appears the Trust recognized a reduction of 538.2 Bcf or approximately 40% in the December 31, 2011 proved natural gas reserves “primarily due to lower natural gas prices, and, to a lesser extent, due to well performance in the Mid-Continent and Permian Basin.”
In light of the requirement for your estimates of proved natural gas reserves to be reasonably certain, we re-issue prior comment 19 in part and ask that you please explain to us the proportion of the total change in your 2012 natural gas reserves attributable to well performance and the nature of the well performance issues.
Response
Approximately 89% of the net reduction in the Company’s December 31, 2011 natural gas reserves was the result of changes in pricing, as natural gas index pricing decreased by 33% from December 31, 2011 to December 31, 2012. The remaining net reductions (11% of the total reduction) were performance revisions primarily in the Company’s Mississippian operations, which revealed a higher degree of variability for both oil and gas due to geographic and stratigraphic reservoir heterogeneities and the use of various artificial lift strategies.
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 | |
ANNEX A
Timeline—Century Plant Transaction, Natural Gas Prices and WTO Development
December 31, 2007: The Company’s proved reserves in the West Texas Overthrust (“WTO”), where the Piñon Field is located, total 922.2 Bcfe, net of associated CO2 (on 471 producing wells and approximately 400 undeveloped locations), and constitute approximately 61% of the Company’s total proved reserves. PV-10 of the WTO reserves is $1,785.5 million. As of this date, the Company has also identified approximately 2,200 additional future drilling locations within the WTO, with no currently associated proved reserves. The Henry Hub monthly average and December 31, 2007 spot (required by the SEC at that time to be used by registrants to calculate year end proved reserves) prices for natural gas are $7.11 and $6.80 per Mcf, respectively, and the Company is operating 30 rigs drilling wells in the WTO. High quantities of CO2associated with the natural gas reserves constrain the Company’s development of its WTO reserves because pipeline specifications require CO2 to be reduced to acceptable levels prior to marketing. Limited options exist for the disposal of CO2, which is considered a “waste gas” and a byproduct of the natural gas treating process, due to restrictions on CO2 emissions into the environment and sub-surface injection. Treatment of natural gas to remove CO2, recorded as lease operating expense, is costly. Therefore, economic development of the WTO is highly dependent upon prices received for processed natural gas.
June 2008: The Company and Occidental enter into (i) the construction agreement to build the Century Plant and (ii) the 30-year treating agreement. The Henry Hub monthly average price of natural gas is $12.69 per Mcf. The Company is operating 33 rigs drilling wells in the WTO and believes construction of the large-scale processing facility will allow economic development of the WTO by providing adequate treating capacity for the high-CO2 production stream as the area is developed. Additionally, the 30-year treating agreement provides a means for disposal of CO2 after separation from WTO production as, under the agreement, Occidental is to take the CO2 separated from Company-delivered volumes for use in its tertiary recovery operations. Given that natural gas constitutes roughly one-third of the production stream from the WTO, with CO2 comprising the remaining two-thirds, the Company believes that production from current proved reserves and additional reserves to be established as identified unproved WTO drilling locations are developed will provide sufficient quantities of CO2 to meet the delivery requirements contained in the treating agreement.
The 30-year treating agreement contains terms consistent with other processing agreements to which the Company is party and common to long-term natural gas processing contracts standard in the oil and gas industry:
| • | The Company is to pay a portion of the monthly costs to operate the plant (calculated based upon the volumes delivered by the Company for processing and the quality of the natural gas production stream delivered/percentage of CO2 contained in the delivered volumes). |
| • | The owner/operator of the plant (Occidental) agrees to take payment for processing services provided “in-kind” by retaining products extracted from the delivered production stream (in this case, CO2). |
| • | The Company will retain all processed natural gas for sale to third-parties. |
| • | The Company will pay the owners/operator an agreed upon fee(s) if it does not deliver minimum amounts of CO2 annually and cumulatively for the 30-year term of the agreement. A minimum throughput requirement is a mechanism commonly used in such agreements to (i) provide a guaranteed cash flow to natural gas processing plant owners and (ii) provide natural gas producers guaranteed treating capacity for production (in this case, the Company’s production from the WTO). |
Contracts for processing services are negotiated with each plant owner/operator separately and, therefore, each contains different terms; however most have these or other similar components. For example, at the time the treating agreement was signed, a portion of the Company’s high-CO2 production stream from the WTO was being processed at the third-party owned Mitchell Plant under a long-term fixed fee arrangement. Under this arrangement, the Company paid a portion of the plant utilities and $0.28 per Mcf processed through the plant and retained the separated CO2volumes at the tailgate of the plant. Additionally, the Company is currently party to a natural gas processing contract for production from its Mid-Continent properties pursuant to which the plant owner retains a percentage of natural gas liquids after processing as “in kind” payment for processing services rendered.
December 31, 2008:The Henry Hub monthly average and December 31, 2008 spot prices for natural gas have declined to $5.63 and $5.71 per Mcf, respectively. The Company is operating 9 rigs in the WTO. The quantity of WTO proved reserves has increased to 1,342.6 Bcfe; however, the associated PV-10 has declined to $1,223.2 million due to declines in pricing. The Company records a full cost ceiling impairment of approximately $1,855 million.
March 2009: Ground breaking for construction of the Century Plant occurs. The Henry Hub monthly price for natural gas has declined to $3.96 per Mcf and the Company is operating 5 rigs in the WTO. The Company records a full cost ceiling impairment of approximately $1,304 million at March 31, 2009.
December 31, 2009:The Henry Hub monthly and trailing 12-month average (“SEC case” for quarterly periods beginning with December 31, 2009) prices for natural gas are $5.35 and $3.87 per Mcf, respectively, and the Company is operating 8 rigs in the WTO. The quantity of WTO proved reserves is 340.0 Bcfe with an associated PV-10 of $224.3 million. The Company records an additional full cost ceiling impairment of approximately $389 million.
October 2010:Century Plant construction is ongoing. Train 1 startup occurs and WTO production stream begins to divert from the Company’s legacy processing plants to the Century Plant as testing progresses.
December 31, 2010: The Henry Hub monthly average and SEC case prices for natural gas are $4.25 and $4.38 per Mcf, respectively. The Company is operating 1 rig in the WTO as its development efforts are now focused on higher-return oil drilling in the Permian Basin and Mid-Continent. Proved reserve quantities in the WTO total 814.2 Bcfe with an associated PV-10 of $157.5 million, as the net revenue stream from the properties is now burdened by fees associated with a gathering arrangement entered into by the Company.
January 2011: Century Plant construction is ongoing. Construction of Train 2 begins.
December 31, 2011: The Henry Hub monthly and SEC case prices for natural gas are $3.17 and $4.12 per Mcf, respectively. The Company does not have any rigs drilling in the WTO. Proved reserve quantities in the WTO total 615.0 Bcfe with an associated PV-10 of $131.9 million. Based on the SEC case price of natural gas, approximately 20% of the proved undeveloped WTO reserves (those with the highest CO2 content) existing at December 31, 2010 are written off as uneconomic.
December 31, 2012: Century Plant (both Train 1 and 2) is substantially complete and transferred to Occidental. The Henry Hub and SEC case prices for natural gas are $3.34 and $2.76 per Mcf, respectively. Additionally, due to depressed natural gas pricing, no proved undeveloped reserves within the WTO remain on the Company’s books. The Company does not have any rigs drilling in the WTO and due to decreased drilling activity in the area from 2008 through 2012, production deliverable to the Century Plant has declined to the extent that the Company records a liability for delivery shortfalls at December 31, 2012 of $8.5 million.
December 2013:Due to recent increases in natural gas prices, the Company is evaluating the economics of resuming development of the WTO. The Company is also in discussions with other companies that have expressed interest in developing the field. No drilling has taken place during 2013 in the WTO and production continues to decline such that the Company expects to record a liability for delivery shortfalls at December 31, 2013 between $29.5 million and $36.0 million.
SCHEDULE 7.f
| Plant Cost Estimates | ||||||||||||||||||||||||||||||||||||||||||||
Century Plant Construction Contract Rollforward | Estimate | |||||||||||||||||||||||||||||||||||||||||||
Period End | Costs | Billings | Receipts | Contract Losses booked to FCP | Balance | Period end | Cumulative Development Costs | Loss Recored to the FCP | Low | High | Final Estimate to Complete | Comments: | ||||||||||||||||||||||||||||||||
Q2 2008 | $ | 39,808,938 | $ | — | $ | — | $ | — | $ | 39,808,938 | ||||||||||||||||||||||||||||||||||
Q3 2008 | 16,385,906 | 68,080,000 | (68,080,000 | ) | — | (11,885,156 | ) | |||||||||||||||||||||||||||||||||||||
Q4 2008 | 41,661,084 | 54,825,620 | (54,825,620 | ) | — | (25,049,692 | ) | |||||||||||||||||||||||||||||||||||||
Q1 2009 | 66,083,502 | 67,040,000 | (24,800,000 | ) | — | 16,233,810 | ||||||||||||||||||||||||||||||||||||||
Q2 2009 | 65,094,742 | 50,560,000 | (64,880,000 | ) | — | 16,448,552 | ||||||||||||||||||||||||||||||||||||||
Q3 2009 | 79,370,334 | 109,760,000 | (100,960,000 | ) | — | (5,141,114 | ) | Q2 2008-Q3 2009 | * Unable to accurately make an estimate with any certainty | |||||||||||||||||||||||||||||||||||
Q4 2009 | 106,527,198 | 75,200,000 | (89,040,000 | ) | — | 12,346,084 | Q4 2009 | $ | — | $ | — | $ | 790,000,000 | $ | 990,000,000 | |||||||||||||||||||||||||||||
Q1 2010 | 91,138,003 | 75,120,000 | (71,520,000 | ) | — | 31,964,087 | Q1 2010 | — | — | 840,000,000 | 1,018,000,000 | * 5% variance, decided not to book a loss at this time. Not probable at this time | ||||||||||||||||||||||||||||||||
Q2 2010 | 80,010,234 | 47,920,000 | (65,520,000 | ) | — | 46,454,320 | Q2 2010 | — | — | 880,000,000 | 1,044,000,000 | * 10% variance, decided not to book a loss at this time. Not probable at this time | ||||||||||||||||||||||||||||||||
Q3 2010 | 55,940,098 | 25,760,000 | (26,560,000 | ) | — | 75,834,419 | Q3 2010 | — | 98,000,000 | 898,000,000 | 1,010,000,000 | * Phase I was mechanically complete this quarter, the loss is now probable | ||||||||||||||||||||||||||||||||
Q4 2010 | 31,131,658 | 34,960,000 | (33,440,000 | ) | 105,000,000 | (31,473,924 | ) | Q4 2010 | 105,000,000 | 7,000,000 | 905,000,000 | 998,000,000 | ||||||||||||||||||||||||||||||||
Q1 2011 | 57,991,051 | 50,800,000 | (39,760,000 | ) | 19,000,000 | (32,242,873 | ) | Q1 2011 | 124,000,000 | 19,000,000 | 924,000,000 | 1,007,000,000 | ||||||||||||||||||||||||||||||||
Q2 2011 | 47,731,016 | 53,040,000 | (56,720,000 | ) | — | (41,231,856 | ) | Q2 2011 | 124,000,000 | — | 927,000,000 | 1,002,000,000 | * Deemed an immaterial change to the estimate | |||||||||||||||||||||||||||||||
Q3 2011 | 48,323,016 | 44,240,000 | (49,360,000 | ) | — | (42,268,840 | ) | Q3 2011 | 124,000,000 | — | 909,000,000 | 966,000,000 | * Even though the estimate decreased we remained with the previous estimate | |||||||||||||||||||||||||||||||
Q4 2011 | 35,908,872 | 23,600,000 | (30,960,000 | ) | 6,000,000 | (43,319,969 | ) | Q4 2011 | 130,000,000 | 6,000,000 | 930,000,000 | 976,000,000 | ||||||||||||||||||||||||||||||||
Q1 2012 | 28,610,447 | 9,760,000 | (9,600,000 | ) | 10,000,000 | (34,309,522 | ) | Q1 2012 | 140,000,000 | 10,000,000 | 940,000,000 | 976,000,000 | ||||||||||||||||||||||||||||||||
Q2 2012 | 27,988,216 | 4,899,036 | — | — | (6,321,306 | ) | Q2 2012 | 140,000,000 | — | 939,000,000 | 977,000,000 | * Deemed an immaterial change to the estimate | ||||||||||||||||||||||||||||||||
Q3 2012 | 20,317,332 | 3,153,723 | — | — | 13,996,026 | Q3 2012 | 140,000,000 | — | 941,000,000 | 966,000,000 | * Deemed an immaterial change to the estimate | |||||||||||||||||||||||||||||||||
Q4 2012 | 13,457,800 | (1,968,451 | ) | (3,000,000 | ) | 40,000,000 | (15,546,174 | ) | Q4 2012 | 180,000,000 | 40,000,000 | — | — | 976,000,000 | * New adjusted contract price is $796 million and cost to complete is finalized at $976 million | |||||||||||||||||||||||||||||
Q1 2013 | 9,748,016 | — | — | — | (5,798,158 | ) | Q1 2013 | 180,000,000 | — | — | — | 976,000,000 | ||||||||||||||||||||||||||||||||
Q2 2013 | 8,570,219 | — | — | — | 2,772,061 | Q2 2013 | 180,000,000 | — | — | — | 976,000,000 | |||||||||||||||||||||||||||||||||
Q3 2013 | 1,178,564 | — | — | — | 3,950,625 | Q3 2013 | 180,000,000 | — | — | — | 976,000,000 | |||||||||||||||||||||||||||||||||
Grand Total | $ | 972,976,246 | $ | 796,749,928 | $ | (789,025,620 | ) | $ | 180,000,000 | |||||||||||||||||||||||||||||||||||