SASOL LTD — Annual Report 2013

Jul 30, 2013

29 July 2013 Mr. Brad Skinner Senior Assistant Chief Accountant Securities and Exchange Commission 100 F Street, N.E. Washington, D.C 20549 Dear Mr. Skinner Sasol Limited Annual Report on Form 20-F for the Year Ended June 30, 2012 Filed October 12, 2012 File No. 001-31615 We refer to the Staff's comment letter dated 28 June 2013, relating to the Form 20-F of Sasol Limited (the Company for the year ended 30 June 2012. Set forth below in detail are the responses to the Staff's comments, which have been provided in each case following the text of the comment in the Staff's letter. In response to the Staff's comments, the Company intends to revise the disclosures in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013 (which the Company intends to file during October 2013), as discussed in our responses. 1. Since you disclose synthetic oil as reserves elsewhere in your filing under supplemental oil and gas information, please expand your disclosure to include the production, average sales price and average production cost for each of the last three years in accordance with the requirements set forth in Item 1204 of Regulation S-K. Response The Company has referred to Regulation S-K, Item 1204 and the intends to revise the disclosure under the subheading Synthetic Oil Equivalent Production, Production Prices and Production Costs in future filings to present the production, average sales price and average production cost for each of the last three years. For illustration purposes, we set out below the disclosures as it would have appeared in our Form 20-F for the year ended 30 June 2012: 2012 South Africa (Rand per unit) 2011 South Africa (Rand per unit) 2010 South Africa (Rand per unit) Average sales price per barrel 865,76 675,76 564,64 Average production cost per barrel 376,65 323,84 278,19 Production (millions of barrels) 42,4 44,1 47,0 2. You disclose under this section that the June 30, 2012 net quantities of proved condensate reserves were .22 Mbbl. However, elsewhere in this section you disclose quantities in terms of MMbbl. Review your disclosure under this section and revise as may be necessary to use consistent volume measurements. Response The Company acknowledges the Staff's comment, and in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, the Company will revise the disclosure to ensure the consistent use of volume measurements. For illustration purposes, the Company has set forth below a draft of the modified disclosures regarding the net quantities of proved condensate reserves relating to the Canada producing assets that the Company believes are responsive to the Staff's comment. Illustrative disclosure based on the annual report on Form 20-F for the year ended 30 June 2012 Canada producing assets In 2012, production from the Farrell Creek and Cypress A asset amounted to 17,0 Bscf gas and 0,01 MMbbl condensate; and the net economic interest proved reserves at 30 June 2012 are estimated to be 55,21 Bscf gas and 0,22 MMbbl condensate. 3. We note your presentation of the average production cost as a single value per thousand cubic feet/barrel. Please revise the disclosure to separately present the cost per unit of gas and the cost per unit of oil produced or to clarify that the presentation represents a single aggregated unit cost disclosed on a gas or oil equivalent basis. Refer to the requirements set forth in Item 1204(b)(2). Response The Company acknowledges the Staff's comment, and in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, the Company intends to revise the disclosure under the subheading Oil and gas production prices and costs to present the average production cost per unit of gas and per unit of liquids as separate table entries. The average production cost per unit of production is calculated according to the primary sales product. Where a co-product is sold (e.g. small liquid volumes associated with primary gas production) the co-product is not included in the production cost calculation. The Company confirms capital amortisation is performed on the same basis. For illustration purposes, we set out below the disclosures as it would have appeared in our Form 20-F for the year ended 30 June 2012: Illustrative disclosure based on the annual report on Form 20-F for the year ended 30 June 2012 Oil and gas sales prices and production costs: The table below summarises the average sales prices for natural gas or oil produced and the average production cost, not including ad valorem and severance taxes, per unit of production for each of the last three years. Average sales prices and production costs for the year ended 30 June Mozambique Gabon Canada Other areas (Rand per unit) 2010 Average sales prices Natural gas, per thousand standard cubic feet 11,2 - - - Liquids, per barrel 324,2 455,4 - - Average production cost Natural gas, per thousand standard cubic feet 2,6 - - - Liquids, per barrel - 116,2 - - 2011 Average sales prices Natural gas, per thousand standard cubic feet 11,9 - 23,9 - Liquids, per barrel 451,0 558,4 551,8 - Average production cost Natural gas, per thousand standard cubic feet 2,3 - 7,9 - Liquids, per barrel - 80,8 - - 2012 Average sales prices Natural gas, per thousand standard cubic feet 15,8 - 18,7 - Liquids, per barrel 636,6 741,7 650,2 - Average production cost Natural gas, per thousand standard cubic feet 3,4 - 9,2 - Liquids, per barrel - 124,3 - - * Average production costs per unit of production are calculated according to the primary sales product. 4. Please refer to Item 1205 of Regulation S-K and revise your disclosure to present the number of net wells drilled Response The Company acknowledges the Staff's comment, and in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, the Company will revise the disclosure under the subheading Exploratory and development wells to present the net number of wells drilled as defined. Additionally the Company will include further disclosure under the subheading Other exploratory and development drilling activities to disclose the net number of other well types as defined in Regulation S-X Part 210.4-10 (a). For illustration purposes, we set out below the disclosures as it would have appeared in our Form 20-F for the year ended 30 June 2012 Illustrative disclosure based on the annual report on Form 20-F for the year ended 30 June 2012 Exploratory and development wells: The table below provides the number of net exploratory wells and development wells completed regardless of when drilling was initiated, in each of the last three years. Number of wells drilled for the year ended 30 June Mozambique Gabon Canada Other areas Total (net number of wells drilled) 2010 Exploratory well-productive - - - - - Exploratory well-dry - - - - - Development well-productive - 0,3 - - 0,3 Development well-dry - - - - - 2011 Exploratory well-productive 1,0 - - - 1,0 Exploratory well-dry - - - - - Development well-productive 2,1 0,6 - - 2,7 Development well-dry - - - - - 2012 Exploratory well-productive - - - - - Exploratory well-dry - - - - - Development well-productive - - 26,0 - 26,0 Development well-dry - - - - - - A dry well is an exploratory or development well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion. - A productive well is an exploratory or development well that is not a dry well. Other exploratory and development drilling activities: The table below provides the number of net wells, that are not exploratory wells or development wells, drilled in each of the last three years. Number of wells drilled for the year ended 30 June Mozambique Gabon Canada Other areas Total (net number of wells drilled) 2010 Stratigraphic test well exploratory type - 0,9 - - 0,9 Stratigraphic test well development type - - - - - Service well - - - - - 2011 Stratigraphic test well exploratory type 2,0 0,3 - 0,6 2,9 Stratigraphic test well development type - - - - - Service well - - - - - 2012 Stratigraphic test well exploratory type - - - 0,4 0,4 Stratigraphic test well development type - - - - - Service well - - 0,5 - 0,5 - A stratigraphic test well is drilled to obtain information pertaining to a specific geological condition and is customarily drilled without the intent of being completed. Stratigraphic test wells are exploratory type if not drilled in a known area or development type if drilled in known area. - A service wells is an injection well, water supply / disposal well or an observation well. 5. Please refer to the definitions contained in Item 1208(c) and revise your disclosure to provide the area in terms of acres. Alternatively, disclose the factor to convert the area from km2 to acres as a footnote to the table. Response The Company acknowledges the Staff's comment, and in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, the Company will revise the disclosure under the subheading Productive wells and area to provide the developed and undeveloped amounts in acres. For illustration purposes, we set out below the disclosures as it would have appeared in our Form 20-F for the year ended 30 June 2012: Illustrative disclosure based on the annual report on Form 20-F for the year ended 30 June 2012 Productive wells and acreage: The table below provides details of the productive wells and the amount of developed and undeveloped acreage at 30 June 2012. Number of productive wells and acreage concentrations at 30 June 2012 Mozambique Gabon Canada Other Total Productive oil wells (number) Gross 1 10 - - 11 Net 1,0 2,8 - - 3,8 Productive gas wells (number) Gross 22 - 88 - 110 Net 15,4 - 44,0 - 59,4 Developed acreage (thousand acres) Gross 431,7 28,7 27,2 - 487,6 Net 302,2 8,0 13,6 - 323,8 Undeveloped acreage (thousand acres) Gross 7 708,5 730,9 84,3 17 916,9 26 440,5 Net 5 591,8 219,3 42,2 5 951,6 11 804,8 - A productive well is a producing well or a well that is mechanically capable of production. - Certain licenses in Mozambique overlap as they relate to specific stratigraphic horizons. 6. Item 1208(b) of Regulation S-K requires the disclosure of material amounts of expiring acreage by geographic area. Please expand your discussion of the individual concessions and licenses on pages 129 through 130 to include such disclosure. Response The Company acknowledges the Staff's comment, and in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, the Company will expand its disclosure on licence terms to more clearly identify amounts of expiring acreage. For illustration purposes, we set out below the disclosures as it would have appeared in our Form 20-F for the year ended 30 June 2012: Illustrative disclosure based on the annual report on Form 20-F for the year ended 30 June 2012 Licence terms Mozambique: The Petroleum Production Agreement for the Pande-Temane PPA asset expires in 2034 and carries two possible five year extensions. There are no remaining licence obligations and there is no requirement to relinquish any acreage until the expiry of the Petroleum Production Agreement. The Pande-Temane PSA licence is in the third and last exploration period. Two discovery areas (Pande/Corvo/Tafula and Temane/Temane East /Inhassoro) are currently being appraised. The appraisal phase is scheduled to end in December 2012. The decision to develop the fields and retain the associated acreage is dependent on the appraisal results (442,8 thousand undeveloped net acres affected). The Exploration and Production Concession for Blocks 16&19 is in the third and last exploration period which expires in June 2013. There are no remaining commitments. The acreage will be relinquished at the end of the exploration period unless the Njika discovery is declared commercial (1 157,6 thousand undeveloped net acres affected). The Exploration and Production Concession M-10 is in the second exploration period which carries a one well commitment and is due to expire in January 2013. Approval to drill the commitment well (Mupeji) has been obtained and preparation is under way to drill the well. The decision to enter the third exploration period and associated acreage relinquishment is dependent on the drilling results and ongoing study work (320,0 thousand undeveloped net acres affected). The Exploration and Production Concession Sofala is in the second exploration period which expires in January 2013. The gravity survey and seismic acquisition commitments have been completed. The decision to enter the third exploration period and associated acreage relinquishment is dependent on the seismic interpretation results and ongoing study work (1 809,3 thousand undeveloped net acres affected). The Exploration and Production Concession Area A licence is in the first exploration period which expires in May 2014. The gravity survey commitment has been completed and the seismic acquisition commitment has commenced. The decision to enter the second exploration period and associated acreage relinquishment is dependent on the seismic interpretation results and ongoing study work (1 862,1 thousand undeveloped net acres affected). Licence terms Gabon: The exploration area of the Etame Marin Permit expires in July 2014. There is 1 well commitment outstanding. The decision to apply for permission to exploit the area and retain acreage is dependent on the drilling results and ongoing study work. The full exploration area will be relinquished if it is decided not to submit a development plan (219,3 thousand undeveloped net acres affected). The exploitation area of the Etame Marin Permit is covered by three 10 year Exclusive Exploitation Authorisations each with two five year extensions available on request and subject to government decree. The Etame Exclusive Exploitation Authorisation is in the first extension period to July 2016. The Exclusive Exploitation Authorisations for Avouma and Ebouri expire in March 2015 and June 2016, respectively. The current plan of development is based on granting of the various extensions to July 2021. Licence terms Canada: As at 30 June 2012, Farrell Creek comprised of 26 licenses and leases and Cypress A comprised of 27 licenses and leases. Acreage retention and the conversion of licenses (which carry no production rights) to leases (with production rights) is enabled by drilling commitments, the provincial government's prescribed lease selection and validation process and license extension applications. The decision to retain acreage and convert licences to leases is dependent on the drilling results and ongoing study work. Drilling and retention activities have been and will be included in the applicable work programmes in order that licences and leases that are due to expire before 30 December 2013 are retained (10 licences and leases, 4,4 thousand undeveloped and 9,5 thousand developed net acres). Licence terms other areas: The Botswana licences PL134/2010, PL135/2010 and PL136/2010 are in the first exploration period which expires in September 2013. The plan is to obtain government approval by June 2013 to continue the current work programme into the second exploration period in order to complete the minimum commitments (367,0 thousand undeveloped net acres affected). In the Papua New Guinea PPL285, 286, and 288 licences the plan is to retain a prospective area in the north of PPL285 and PPL288 (685,9 thousand undeveloped net acres) under a combined new licence. The remaining areas of PPL285 and PPL288 and all of PPL286 (2 922,9 thousand undeveloped net acres) will be relinquished or assigned. The PPL287 licence is in its third exploration period and it is anticipated that the full licence area will be relinquished (941,8 thousand undeveloped net acres) at the end of the period in August 2013. In Australia the WA-388 licence expires in August 2012 when Sasol will exit the licence (190,8 thousand undeveloped net acres). The ACP-52 licence current Year 4 term ends in May 2013 (241,3 thousand undeveloped net acres affected) and the WA-433 licence current Year 4 term ends in May 2013 (76,1 thousand undeveloped net acres affected). In both cases the decision to enter the Year 5 term and associated acreage relinquishment is dependent on ongoing study work. The Nigeria OPL-214 exploration licence expired in June 2012 (33,8 thousand undeveloped net acres). The operator applied to the government in April 2012 to convert the licence into a development and production licence (an OML) and confirmation of the conversion is awaited. The Nigeria OPL-247 exploration licence is in the process of being re-assigned (7,0 thousand undeveloped net acres). The Nigeria OML-140 licence for development and production expires in 2029.In South Africa the venture partners have agreed to abandon the Block 3A/4A exploration rights and withdraw from the licence (471,1 thousand undeveloped net acres). 7. We note your disclosure of synthetic oil as reserves. Please refer to the definition of reserves contained in Rule 4-10(a)(26) and tell us if all such reserves are the result of the extraction of saleable hydrocarbons from coal reserves in which you have an underlying direct ownership and exclusive of any coal which you have otherwise purchased. Response The Company confirms that all reserves are the result of the extraction of saleable hydrocarbons from coal reserves in which the company has a direct ownership. External coal purchased from Anglo American Thermal Coal, export coal and coal used for utilities are excluded. 8. Please revise Table 4 as follows: * Specify, if true, that the right-most three columns relate to natural gas as the product type and to indicate the measurement units for the reserve quantities disclosed per the requirements in FASB ASC paragraph 932-235-50-4; Response The Company confirms that the column headings in Table 4-Proved Reserve Quantity Information were not correctly reproduced in the filing. Please refer to the illustrative disclosures of Table 4 presented below where the product types and measurement units are specified. The Company will in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, clarify the column headings provided in Table 4-Proved reserve Quantity Information. * Clarify, if true, that the geographic area/country associated with "Other Areas" is Gabon per the requirements in FASB ASC paragraph 932-235-6A; Response The Company acknowledges the Staff's comment, and in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, the Company will clarify the disclosure in Table 4-Proved Reserve Quantity Information to identify, as a footnote, which geographical areas/countries are included in the 'Other Areas' grouping. It should be noted that Gabon is included but is not separately presented as the 15% materiality threshold which is specified in FASB ASC 932-235-6B has not been met. Refer to illustrative disclosures of Table 4 presented below where Gabon is identified in the footnote. Note: 'Other Areas' in Supplemental Oil and Gas Information Tables 1, 2 and 3 relate to Gabon, Nigeria, Papua New Guinea, Australia and South Africa, whereas 'Other Areas' in Supplemental Oil and Gas Information Tables 4, 5 and 6 relate only to Gabon. * Revise the caption "Commercial arrangements" to use terminology consistent with the change categories specified in FASB ASC paragraph 932-235-50-5, and; Response The Company believes that the change category terminology used is consistent with FASB ASC 932-235-50-5. To aid investor understanding, additional change categories have been added to account for changes in reserves that do not result from (a) revision of previous estimates, (b) improved recovery, (c) purchase of minerals in place, (d) extensions and discoveries, (e) production or (f) sales of minerals in place. The Company will in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013 expand the disclosure to include the definitions for the change categories 'Commercial Arrangements' and 'Operational Factors'. Refer to illustrative disclosures of Table 4 Notes and Definitions below for definitions relating to 'Commercial Arrangements' and 'Operational Factors'. * Disclose volumes of proved undeveloped reserves as required by FASB ASC paragraph 932-235-50-4. Response The Company acknowledges the Staff's comment, and in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013, the Company will expand its disclosure on proved undeveloped reserves to include volumes. The Company has set forth below a draft of the modified disclosures relating to Table 4, Proved Reserve Quantity Information, that the Company believes are responsive to the Staff's comment. For illustration purposes, we set out below the disclosures as it would have appeared in our Form 20-F for the year ended 30 June 2012: Illustrative disclosure based on the annual report on Form 20-F for the year ended 30 June 2012 TABLE 4-PROVED RESERVE QUANTITY INFORMATION Synthetic oil Crude oil and condensate Natural gas South Africa Mozambique Canada Other areas Total Mozambique Canada Other areas* Total Millions of barrels Millions of barrels Billions of cubic feet Proved Reserves Balance at 30 June 2009 - 5,6 - 7,2 12,8 1 643,8 - - 1 643,8 Revisions 685,0 (0,7) - (0,9) (1,6) 21,6 - - 21,6 Improved recovery - - - 0,2 0,2 - - - - Extensions/discoveries 203,0 - - - - - - - - Production (47,0) (0,2) - (1,9) (2,1) (68,0) - - (68,0) Balance at 30 June 2010 841,0 4,7 - 4,6 9,3 1 597,4 - - 1 597,4 Revisions 10,5 0,1 - 0,9 1,0 3,7 - - 3,7 Improved recovery - - - 0,2 0,2 - - - - Extensions/discoveries - - - - - - - - - Purchases/sales - - - - - - 57,8 - 57,8 Commercial arrangements - - - (0,1) (0,1) - - - - Production (44,1) (0,3) - (1,9) (2,2) (79,7) (2,9) - (82,6) Balance at 30 June 2011 807,8 4,5 - 3,7 8,2 1 521,4 54,9 - 1 576,3 Revisions 10,9 (0,6) - 1,1 0,5 10,8 18,1 - 28,9 Improved recovery - - 0,2 0,6 0,8 - (0,8) - (0,8) Commercial arrangements - - - 0,1 0,1 - - - - Production (42,4) (0,3) - (1,5) (1,8) (81,1) (17,0) - (98,1) Balance at 30 June 2012 776,3 3,6 0,2 4,0 7,8 1 451,1 55,2 - 1 506,3 Proved Developed Reserves At 30 June 2010 638,0 2,0 - 2,7 4,7 805,5 - - 805,5 At 30 June 2011 729,5 1,7 - 3,7 5,4 729,6 7,2 - 736,8 At 30 June 2012 640,1 1,7 0,2 3,5 5,4 796,1 55,2 - 851,3 Proved Undeveloped Reserves At 30 June 2010 203,0 2,7 - 1,9 4,6 791,9 - - 791,9 At 30 June 2011 78,3 2,8 - 0,0 2,8 791,8 47,7 - 839,5 At 30 June 2012 136,2 1,9 0,0 0,5 2,4 655,0 0,0 - 655,0 * Other areas comprises: Gabon. NOTES AND DEFINITIONS The definitions of reserves used in this disclosure are consistent with those set forth in the regulations of the Securities and Exchange Commission. Proved Reserves of oil and gas-Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must be approved and must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Additionally Sasol requires that natural oil and gas Reserves will be produced by a "project sanctioned by all internal and "external parties". Existing economic conditions define prices and costs at which economic producibility is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are limited to those provided by contractual arrangements in existence at year-end. At the reporting date, product sales prices were determined by existing contracts for the majority of natural oil and gas reserves. Costs comprise development and production expenditure, assessed in real terms, applicable to the Reserves class being estimated. Depending upon the status of development, Proved Reserves of oil and gas are subdivided into "Proved Developed Reserves" and Proved Undeveloped Reserves. Proved Developed Reserves-Those Proved Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods (or in which the cost of the required equipment is relatively minor compared to the cost of a new well) and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved Undeveloped Reserves-Those Proved Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for before production can commence. The definitions of the change to Reserves estimates used in this disclosure are consistent with FASB ASC 932-235-50-5 and also include, where material, changes resulting from Commercial Arrangements or Operational Factors as defined below. Commercial Arrangements-The Reserves change category used to describe changes in Reserves estimates resulting from new or amendments to existing petroleum licensing agreements (granting instrument); venture operating agreements, unit and pre-unit agreements; transportation, processing and operating services agreements; product sale or supply agreements; lifting and off-take agreements. Operational Factors-The Reserves change category used to describe changes in Reserves estimates resulting from a change in production operations or maintenance philosophies and practices that change the cost of operations. 9. You state on page G-8 that your estimated future cash inflows from production were computed by applying the average price for oil and gas for the 12-month period prior to the end of the reporting period. Please tell us how you have considered the SEC requirements for prices as defined in part (v) of the definition of proved oil and gas reserves contained in Rule 4-10(a)(22) of Regulation S-X Response The Company has referred to FASB ASC 932-235-50-31a and to Regulation S-X Part 210.4-10 (a) (22) and confirms that the estimated future cash flows from production were computed in accordance with the SEC's requirement for prices. The Company will in all future filings, beginning with the annual report on Form 20-F for the year ended 30 June 2013 expand its disclosure on the estimated future cash flows from production to clarify the pricing used. The Company has set forth below a draft of the modified disclosures relating to the notes and definitions that the Company believes are responsive to the Staff's comment. For illustration purposes, we set out below the disclosures as it would have appeared in our Form 20-F for the year ended 30 June 2012: Illustrative disclosure based on the annual report on Form 20-F for the year ended 30 June 2012 TABLE 5-STANDARDISED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS NOTES AND DEFINITIONS The standardised measure of discounted future net cash flows, relating to the Proved Reserves in Table 4, is calculated in accordance with the regulations of the Securities and Exchange Commission and the requirements of FASB ASC Section 932-235. Future cash inflows are computed by applying the prices used in estimating Proved Reserves to the year-end quantities of those Reserves. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are limited to those provided by contractual arrangements in existence at year-end. At the reporting date, product sales prices were determined by existing contracts for the majority of natural oil and gas reserves. Costs comprise development and production expenditure, assessed in real terms, applicable to the Reserves class being estimated. Future price changes are limited to those provided by contractual arrangements in existence at year-end. Future development and production costs are computed by applying the costs used in estimating Proved Reserves. Future income taxes are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the reserves, less the tax basis of the properties involved. The future income tax expenses therefore give effect to the tax deductions, tax credits and allowance relating to the Reserves. Discounted future net cash flows are the result of subtracting future development and production costs and future income taxes from the cash inflows. A discount rate of 10 percent a year is applied to reflect the timing of the future net cash flows relating to the Reserves. The information provided here does not represent management's estimate of the expected future cash flows or value of the properties. Estimates of Reserves are imprecise and will change over time as new information becomes available. Moreover, probable and possible Reserves along with other classes of resources, which may become proved reserves in the future, are excluded from the calculations. The valuation prescribed under FASB ASC Section 932 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of 30 June each year and should not be relied upon as an indication of the company's' future cash flows or value of synthetic oil and natural oil and gas Reserves. 10. Please tell us how you have considered the inclusion of abandonment costs as development costs in the preparation of the standardized measure relating to your proved oil and gas reserve quantities. Refer to the guidance provided by the Division of Corporation Finance at http://www.sec.gov/divisions/corpfin/guidance/oilgasletter.htm Response The Company includes the cash outflows associated with the settlement of asset retirement obligations as part of 'future development costs' when preparing the standardised measure relating to Proved Reserves. Asset retirement obligations and the estimated settlement costs are determined in accordance with standard estimating practices and Sasol Petroleum International guidelines and internal controls which are established and maintained in compliance with the requirements of the Sarbanes-Oxley Act of 2002. The internal controls cover, amongst other matters, the segregation of duties between those who prepare, review and approve the estimates and confirmation that those involved in the preparation, review and approval process are appropriately qualified and experienced. The estimated settlement costs appropriate to the Reserves class are included in the asset cash outflows with a timing appropriate to end of asset life or economic cut-off, whichever is sooner. The estimated settlement costs are consistent with provisions disclosed in the Notes to the Financial Statements - Item 19 Long-term provisions (pages F-87 to F-90). We acknowledge 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 defence in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. We appreciate the Staff's review of the Form 20-F for the year ended 30 June 2012. Should the Staff have any questions or require any additional information, please telephone the undersigned at +27-11-441-3435. My email address is christine.ramon@sasol.com. Yours faithfully /s/ Kandimathie Christine Ramon Christine Ramon Chief Financial Officer 2