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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		2011		2010
			South Africa	South Africa	South Africa
			(Rand per unit) (Rand per unit)	(Rand per unit)
Average sales price per
barrel			865,76           675,76		564,64


Average production cost	376,65		323,84		278,19
per barrel

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

2010					(Rand per unit)
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	  -	  -




			Mozambique	Gabon	Canada	Other Areas

2011					(Rand per unit)
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	    -	  -




		 	Mozambique	Gabon	Canada	Other Areas

2012					(Rand per unit)
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

			Mozam-			Other
 			bique 	Gabon	Canada	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

 			Mozam-			Other
 			bique 	Gabon	Canada	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


Number of productive wells and acreage concentrations
at 30 June 2012
     		     Mozambique	Gabon	 Canada	 Other	  Total


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 		Mozam-	Canada	Other		Mozam-	Canada	Other
		Africa  	bique		areas*	Total	bique		areas*	Total


		Millions	Millions of barrels		Billions of cubic feet
		of barrels

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	1521,4	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

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