ITEM 4. INFORMATION ON THE COMPANY
4.A History and development of the company
Sasol Limited, the ultimate holding company of our group, is a public company. It was incorporated under the laws of the Republic of
South Africa in 1979 and has been listed on the JSE Limited (JSE) since October 1979. Our registered office and corporate headquarters are at 1 Sturdee Avenue, Rosebank, 2196, South Africa, and our
telephone number is +27 11 441 3111. Our agent for service of process in the United States is Puglisi & Associates, 850 Library Avenue, Suite 204,
P.O. Box 885, Newark, Delaware 19715.
For
a description of the company's principal capital expenditures and divestitures refer to "Item 5.B—Liquidity and capital resources".
4.B Business overview
Sasol is an international integrated chemicals and energy company that leverages technologies and the expertise of our 30 100 people
working in 33 countries. We develop and commercialise technologies, and build and operate world-scale facilities, to produce a range of product streams, including liquid fuels, chemicals and
low-carbon electricity.
For
detail regarding the following sections, refer as indicated.
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•
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For information regarding our Business Overview, refer "Integrated Report—Our operating model structure" as contained in
Exhibit 99.4;
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•
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For information regarding our Strategy, refer Integrated Report—"Our strategy" as contained in Exhibit 99.5; and
"Our integrated value chain" as contained in Exhibit 99.6;
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For a description of the company's operations and principle activities refer "Integrated Report—Our operating model
structure" as contained in Exhibit 99.4; "Integrated Report—Operational reviews" as contained in Exhibit 99.7; and Item 18—"Annual Financial
Statements—
Seasonality
Production and sales volumes of our products are generally not subject to seasonal fluctuations, but tend to follow broader global
industry trends and are therefore impacted by macro-economic factors. Sasol operates globally and in many diverse markets, and accordingly, no element of seasonality is likely to be material to the
results of Sasol as a whole.
Raw materials
The main feedstock components for our businesses are coal, natural gas and crude oil produced by Mining and Exploration and Production
International. Feedstock for the production of fuels and chemical products is obtained from Mining, Exploration and Production International as well as purchased from external suppliers.
In
our Performance Chemicals business, the main feedstocks used are kerosene, benzene, ethane, ethylene, oleochemical and aluminium. Feedstocks are purchased externally, with the
exception of a portion of our ethylene which is produced at our Lake Charles facility and the Fischer-Tropsch-based feedstock used for our South African alcohol, wax, ammonia, phenolics, and
co-monomer production. The pricing of most of these materials follow the crude oil and energy price.
Marketing channels and principal markets
In our Operating Business Units, we make use of direct sales models, long-term marketing gas sales agreements and short-term crude oil
sale and purchase agreements.
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Our
Regional Operating Hubs channel their products through the Strategic Business Units to external markets.
In
our Strategic Business Units, marketing channels can be divided into the following main areas:
Energy:
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Liquid fuel sales to licenced wholesalers;
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Liquid fuels direct marketing (retail and commercial markets in South Africa);
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Natural gas marketing in South Africa (wholesale and commercial markets);
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Liquid fuels overland exports into Southern Africa; and
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Electricity sales to Eskom and Electricidade de Moçambique (EDM) in Mozambique.
Base
chemicals:
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Polymer products are sold directly to customers in South Africa and internationally;
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Solvents products are sold through 13 regional sales offices and nine storage hubs in South Africa, Europe, the Asia-Pacific region,
the Middle East and the United States; and
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Fertiliser and explosives are sold mainly within Southern Africa.
Performance
chemicals:
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•
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The majority of products are sold directly to end-user customers under annual and multi-year contracts.
Factors on which the business is dependent
Intellectual property
For information regarding our patents and licences, refer to the "Integrated Report—Intellectual capital" as contained in
Exhibit 99.8.
The Sasol Slurry Phase Distillate
TM
(SPD
TM
)
process—
Based on our Technology function's extensive experience in the commercial application of
the Fischer-Tropsch (FT)
technology,
we have successfully developed the FT-based Sasol SPD
TM
process for converting natural gas into high-quality, environment-friendly GTL diesel, GTL kerosene and other liquid
hydrocarbons.
The
SPD
TM
process consists of three main steps, each of which is commercially proven. These include:
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•
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the Haldor Topsøe reforming technology, which converts natural gas and oxygen into syngas;
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our Slurry Phase Distillate FT technology, which converts syngas into hydrocarbons; and
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•
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the Chevron Isocracking
TM
technology, which converts hydrocarbons into particular products, mainly diesel, naphtha
and LPG.
Currently
we believe, based on our knowledge of the industry and publicly available information, that globally, we have the most extensive experience in the application of FT technology
on a commercial scale. Given the increasing discovery of extensive natural gas reserves, our Sasol SPD
TM
process can be applied with significant commercial advantages in various parts of
the world. As a consequence, our technology has evoked interest from countries and companies with extensive natural gas reserves as an appealing alternative for commercialising these reserves. The
Sasol SPD
TM
process converts natural gas into diesel and other liquid hydrocarbons, which are generally more environmentally friendly and of higher quality and performance compared to
the equivalent crude oil-derived products. In view of product specifications gradually becoming more stringent, especially with respect to emissions, we believe that the option of environmentally
friendly GTL fuels will become increasingly appealing. GTL diesel can be used with optimised engines for best performance, although it can also be utilised with current compression ignition engines.
GTL diesel is currently used as a cost-competitive blend stock for conventional diesels, thereby enabling conventional diesel producers to improve the quality and capacity of their product without
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investing
substantially in sophisticated new plants and infrastructure. We anticipate that the combined factors of GTL diesel's superior characteristics and the prevailing market conditions in
developed economies will enable GTL diesel to command premium prices for either niche applications or as a blend stock for upgrading lower-specification products. The construction of GTL facilities
and the production of GTL fuels require significant capital investment.
Key contracts
ORYX GTL, our 49% joint venture in Qatar, purchases natural gas feedstock from Al Khaleej Gas, a joint venture between ExxonMobil
Middle East Gas Marketing Limited and Qatar Petroleum, under a gas purchase agreement with a contracted minimum off-take volume. The agreement commenced in November 2005 and is valid for a term of
25 years. The term of the agreement may be extended by the parties on terms and conditions that are mutually agreed.
Escravos
GTL (EGTL), in which we hold a 10% indirect interest, purchases 100% of its gas requirements for the EGTL plant from Chevron Nigeria Limited (CNL) and Nigerian National
Petroleum Corporation (NNPC), the upstream joint venture partners. The agreement commenced in November 2005, and is valid for a term of 25 years. The term of the agreement may be extended by
the parties on terms and conditions that are mutually agreed.
Ethane
and propane used as feedstock for the cracker in Malaysia (12% shareholding) (PETRONAS Chemicals Olefins Sdn Bhd), is purchased from PETRONAS at a set price, which escalates
annually in line with US inflation rates.
Refer
to Item 4.D—Exploration and Production International" for detail regarding key contracts in Gabon and Mozambique.
Legal proceedings and other contingencies
From time to time, Sasol companies are involved in litigation, tax and similar proceedings in the normal course of business. A detailed
assessment
is performed on each matter, and a provision is recognised, or contingent liability disclosed, where appropriate in terms of International Financial Reporting Standards. Although the
outcome of these proceedings and claims cannot be predicted with certainty, the company does not believe that the outcome of any of these cases would have a material effect on the group's financial
results.
Following
a judgement by the South African Constitutional Court in 2011, which confirmed the right of employees in the mining industry who contracted certain occupational diseases to
claim damages from their employers, a number of legal cases were instituted in South Africa. During 2014 and 2015, similar cases have also been threatened against participants in the coal sector of
the mining industry.
As
a result of the Constitutional Court judgement referred to above, Sasol Mining is currently the defendant in three separate litigation matters involving 22 former employees. Sasol
Mining is defending the claims. It is not possible at this stage to make an estimate of the likelihood that the plaintiffs will succeed with their claim and if successful, what the quantum of damages
would be that the court will award. Therefore, no provision has been raised at 30 June 2016.
Further,
from time to time, communities and non-governmental organisations challenge our environmental licences and related applications on the basis of concerns regarding potential
health and environmental impacts associated with Sasol's activities.
For
instance, the South African Air Quality Act prescribed minimum emission standards, applicable to existing plants which had to be complied with starting on 1 April 2015. Some
of our business units were not able to comply with the new emission standards, and accordingly, applied for postponements. On 24 February 2015, the Department of Environmental Affairs issued
the postponement decisions. The Legal Resources Centre in South Africa submitted appeals to the Minister of Environmental Affairs, challenging the postponement decisions of the National Air Quality
Officer. On 13 April 2016, the Minister of Environmental Affairs
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rejected
the appeals and thus the postponement decisions granted to Sasol remain valid. It is uncertain whether the postponement decisions can be always defended successfully if legally challenged by
third parties. In case of the postponement decisions being declared invalid, the consequences for Sasol may be material as operating units may be found in non-compliance with the Air Quality Act which
may trigger substantial investment requirements or even a cease operation decision by the competent authorities.
Competition law compliance
Sasol continuously evaluates its compliance programmes and controls in general, including its competition law compliance programme and
controls. As a consequence of these compliance programmes and controls, including monitoring and review activities, Sasol has also adopted appropriate remedial and/or mitigating steps, where necessary
or advisable, lodged leniency applications and made disclosures on material findings as and when appropriate. These ongoing compliance activities have already revealed, and may still reveal,
competition law contraventions or potential contraventions in respect of which we have taken, or will take, appropriate remedial and/or mitigating steps including lodging leniency applications.
The
South African Competition Commission is conducting investigations into the South African petroleum products industry. Sasol continues to interact and co-operate with the Commission
in respect of the subject matter of current leniency applications brought by Sasol, as well as in the areas that are subject to the Commission's investigations.
Environmental Orders
Sasol is subject to loss contingencies pursuant to numerous national and local environmental laws and regulations that regulate the
discharge of materials into the environment and that may require Sasol to remediate or rehabilitate the effects of its operations on the environment. The contingencies may exist at a number of sites,
including, but not limited to, sites where action has been taken to remediate
soil
and groundwater contamination. These future costs are not fully determinable due to factors such as the unknown extent of possible contamination, uncertainty regarding the timing and extent of
remediation actions that may be required, the allocation of the environmental obligation among multiple parties, the discretion of regulators and changing legal requirements.
Sasol's
environmental obligation accrued at 30 June 2016 was R17 127 million compared to R11 022 million at 30 June 2015. Included
in this balance is an amount accrued of approximately R4 810 million in respect of the costs of remediation of soil and groundwater contamination and similar environmental costs.
These costs relate to the following activities: site assessments, soil and groundwater clean-up and remediation, and on-going monitoring. Due to uncertainties regarding future costs, the potential
loss in excess of the amount accrued cannot be reasonably determined.
Although
Sasol has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs relating to remediation and
rehabilitation may be material to results of operations in the period in which they are recognised. It is not expected that these environmental obligations will have a material effect on the financial
position of the group.
Regulation
The South African government has, over the past 20 years, introduced a legislative and policy regime with the imperative of
redressing historical social and economic inequalities, as stated in the Constitution of the Republic of South Africa, by way of the empowerment of historically disadvantaged South Africans (HDSAs) in
the areas of ownership, management and control, employment equity, skills development, procurement, enterprise development and socio-economic development.
The
majority of our operations are based in South Africa, but we also operate in numerous other countries throughout the world. In South Africa, we operate coal mines and a number of
production plants and facilities for the storage, processing and transportation of raw materials,
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products
and wastes related to coal, oil, chemicals and gas. These facilities and the respective operations are subject to various laws and regulations that may become more stringent and may, in some
cases, affect our business, operating results, cash flows and financial condition.
Our
business activities in South Africa relating to coal mining, petroleum production, distribution and marketing of fuel products, electricity and gas are subject to regulation by
various government departments and independent regulators. Refer to "Item 3.D—Risk factors" for details on particular aspects of regulation affecting our business activities.
Empowerment of historically disadvantaged South Africans
Black Economic Empowerment policies and legislation
Broad-based Black Economic Empowerment Act, 53 of 2003
Sasol is well aligned with the economic transformation and sustainable development objectives embodied in the South African legislative
and regulatory framework governing Broad-based Black Economic Empowerment (B-BBEE). The key elements of this framework are the B-BBEE Act and the Codes of Good Practice (the new Codes were gazetted on
11 October 2013, with a transition period until 30 April 2015) for B-BBEE issued by the Minister of Trade and Industry in terms of the Act (Codes), as well as the Charters
(i.e. the Mining Charter and Liquid Fuels Charter) adopted by the various sectors within which Sasol operates businesses and related scorecards.
The
scorecard contained in the 2013 Codes measures the following key pillars:
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•
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ownership;
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management control;
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•
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skills development;
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enterprise and supplier development; and
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•
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socio-economic development.
In
addition to some changes in the key pillars, including the introduction of sub-minimum requirements within certain pillars, the 2013 Codes also contain a higher points threshold in
the scorecard than their predecessor in order to achieve a similar Contributor level status. As a result, Sasol has declined from a Level 4 under the previous Codes to a Level 8 under
the new Codes. The measures discussed below do however reflect Sasol's commitment to giving meaningful effect to the letter and spirit of the B-BBEE legislative and regulatory framework. We view
B-BBEE in South Africa as a business imperative and have embarked on a project to realise the goals envisaged by the revised codes, and re-establish a Level 4 by 2020.
Management Control
In keeping with the spirit of the Charter, as well as the Employment Equity Act, specific employment equity targets have been set
across all role categories of the organisation. Actions have been implemented to ensure that HDSAs are given equal and fair opportunity in terms of appointments, development and career progression.
The actual employment equity performance is reviewed periodically to ensure that appropriate plans are in place to enable the
targets to be met. Learning programmes, including coaching and mentorship, are in place to create an inclusive work environment that is suited to the successful nurturing of HDSA staff.
Skills Development
Sasol's skills development strategy is aligned to and supports the goals of the National Development Plan (NDP) 2030, B-BBEE,
Employment Equity and Skills Development Acts. Sasol supports the broader objectives of skills development and has been a significant contributor to skills development and in turn socio-economic
development in South Africa over the years.
To
secure and develop a pipeline of future talent for Sasol, we continue to run one of the largest bursary, learnership, graduate development and internship schemes in South Africa.
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Enterprise and Supplier Development
We recognise that a growing and active small, medium and micro-enterprises (SMMEs) sector is vital for broadening economic
participation and delivering on socio-economic development priorities. Supporting the development of SMMEs does not only help us localise and diversify our supply chain, it also contributes to
economic growth and transformation in South Africa. To drive these objectives, we have a dedicated Enterprise and Supplier Development (ESD) team. Our ESD support to SMMEs includes loan funding to
majority black-owned suppliers through the Sasol Siyakha Enterprise and Supplier Development Fund and, business development and incubation support through our Sasol Business Incubator located in
Sasolburg. Further, our experience in small business development has indicated that SMMEs require market access support. As a result, we have developed favourable preferential procurement requirements
in our sourcing strategies, to enable black-owned and 30% black women-owned SMMEs into our supply chain.
Socio-economic development
Being a credible corporate partner and member of the communities in which we operate is at the core of our approach to our
socio-economic development contribution. Our social investments are informed by the issues and challenges of our communities established through extensive engagements with multiple stakeholders.
Regular direct engagements with members of our host communities have enabled us to understand their concerns and needs and them understanding ours. As a result, we have realigned our social
investments towards programmes that enable access to quality education; stimulate local economic development and job creation, bolster the pool of technical, vocational and science, technology,
engineering and mathematics-related skills; facilitate collaboration to advance the delivery of municipal services; and promote the protection of the environment.
Sasol Inzalo share transaction
In 2008, Sasol entered into the Sasol Inzalo black economic empowerment (BEE) share transaction, which resulted in the transfer of
beneficial ownership of 10% (63,1 million shares) of Sasol Limited's issued share capital before the implementation of this transaction, to its employees and a wide spread of black South
Africans (BEE participants). Refer to "Item 18—Annual Financial Statements—Note 36—Share based payment reserve".
The Mining Charter
The Mining Charter requires mining companies to meet various criteria intended to promote meaningful participation of HDSAs in the
mining sector.
A
draft revision of the Mining Charter was published on 15 April 2016 for public comment. The revised Mining Charter is intended to ensure alignment between the B-BBEE Act and the
Mining Charter. The draft Mining Charter determines that the "once-empowered-always-empowered" principle is not applicable, even though the declaratory process is still to be finalised by the court.
In 2015, the Chamber of Mines and the Department of Mineral Resources agreed to approach the Court and obtain a declaratory order to determine whether the "once-empowered-always-empowered" principle
is applicable. The period for public comment closed during May 2016 and the Department of Mineral Resources is currently considering the inputs, whereafter it is expected that an updated draft Mining
Charter will be published. It is not certain whether further comments will be invited or if additional consultations will take place before the final revised Mining Charter is implemented. Sasol
Mining will consider its level of compliance against the revised Mining Charter as soon as it is implemented.
Currently,
Sasol Mining exceeds the 26% ownership target set out in the Mining Charter.
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The Liquid Fuels Charter
In 2000, following a process of consultation, the Department of Minerals and Energy (now the Department of Energy) and a number of
companies in the liquid fuels industry, including Sasol Oil, signed the Liquid Fuels Charter (the Charter) which sets out the principles for the empowerment of HDSAs in the South African petroleum and
liquid fuels industry. The Charter requires liquid fuels companies, including Sasol Oil, to ensure that HDSAs hold at least 25% equity ownership in the South African entity holding their operating
assets by the end of a period of 10 years from the date of the signing of the Charter.
The
Charter also requires liquid fuels companies to adopt policies to further other empowerment objectives of the Charter, among other things, employment equity, preferential procurement
and skills development.
In
order to meet the equity ownership objective of the Charter, Sasol Limited concluded a BEE transaction with an HDSA-owned company, Tshwarisano LFB Investment (Pty) Ltd
(Tshwarisano), in terms of which Sasol Limited disposed of 25% of its shareholding in Sasol Oil to Tshwarisano.
With
effect from 1 July 2006, Sasol Oil met the 25% BEE ownership target, with Tshwarisano holding 25% of the shares in Sasol Oil in line with the Charter.
Tshwarisano
settled the last of its debt relating to its equity shareholding in February 2016, based on the attractive returns generated by Sasol Oil Proprietary Limited over many years.
Tshwarisano's shareholding is therefore fully unencumbered. This represents the realisation of one aspect of our work to deliver social and economic value.
The
Charter further provides for the evaluation by the Department of Energy, from time to time, of the industry's progress in achieving the objectives of the Charter. Given the fact that
the aforementioned 10-year period had run its course, the Department of Energy initiated a compliance audit in respect of the Charter in the latter part of the 2010 calendar year. Sasol Oil's
compliance with the Charter
was
audited during the first half of the 2011 calendar year and the final industry report, albeit that the written report has not yet been issued to industry, has been discussed with industry by the
Department of Energy on an aggregated basis. Together with the other members of the South African Petroleum Industry Association (SAPIA), Sasol Oil is involved in the ongoing engagements with the
Department of Energy regarding the status and possible review of the Liquid Fuels Charter in the context of the new B-BBEE legislation and the Codes of Good Practice.
The Restitution of Land Rights Act, 22 of 1994
Our privately held land could be subject to land restitution claims under the Restitution of Land Rights Act, 22 of 1994. Under this
act, any person who was dispossessed of rights to land in South Africa as a result of past racially discriminatory laws or practices is granted certain remedies, including, but not limited to the
restoration of the land claimed with or without compensation to the holder.
Mining rights
Sasol Mining is the holder of mining rights in terms of the Mineral and Petroleum Resources Development Act, 2002, in respect of its
operations in Mpumalanga and the Free State province in South Africa.
The
mining rights have been granted until 2040, and can be renewed for further periods of 30 years at a time depending on the approval of the competent authorities and the
applicable legal framework at that point in time.
Safety, health and environment
Regions in which Sasol operates and their applicable legislation
South Africa
The major part of our operations is located in South Africa. We operate a number of plants and facilities for the manufacture, storage,
processing and transportation of chemical feedstock, products and wastes. These operations are subject to numerous laws and regulations
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relating
to safety, health and the protection of the environment.
Environmental regulation
The Constitution of the Republic of South Africa (the Constitution) provides the framework for the environmental legislation in South
Africa. The South African National Environmental Management Act is a framework Act which aims to give effect to the Constitutional environmental right. It also gives effect to specific environmental
management acts, such as the National Environmental Management: Waste Act, the National Water Act and the National Environmental Management: Air Quality Act which all, in turn, regulate specific
environmental media and the associated regulation of potential impacts thereon. The National Environmental Management: Waste Act also specifically regulates the process for management of contaminated
land. These Acts also provide for enforcement mechanisms as well as provisions for the imposition of criminal sanction. These also apply to mining activities.
Apart
from its international commitments, climate change regulation in South Africa is still being developed. Sasol continues to engage with the South African government on the
development of pollution prevention plans, a draft Carbon Tax Bill as well as the imposition of carbon budgets by the Department of Environmental Affairs. Sasol's engagement focuses on the need for
alignment of these instruments in an effort to create long-term policy certainty.
For
information regarding our challenges associated with these regulatory requirements refer to "Item 3.D—Risk factors".
Health and safety
Occupational health and safety is governed by the Occupational Health and Safety Act and the Mine Health and Safety Act for
compensation of employees who suffer
occupationally related diseases or injuries. Specific requirements for chemicals and hazardous substances are currently regulated by the Hazardous Substances Act.
Germany and Italy
In Germany and Italy, we operate a number of plants and facilities for the manufacture, storage, processing and transportation of
chemical feedstock, products and waste. These operations are subject to numerous laws and ordinances relating to safety, health and the protection of the environment. The objectives and requirements
of these legal frameworks are largely consistent with that of the South African Framework, although more established and entrenched in some respects.
Hazardous substances
Provisions for the protection of humans and the environment against the harmful effects of hazardous substances and preparations are
provided in the Chemicals Acts, and related ordinances on the Prohibition of Certain Chemicals and Hazardous Incidents. All hazardous substances are subject to the requirements of the European Union
(EU) REACH Regulation, including requirements for registration and notification obligation before these substances can be brought onto the market. Hazardous substances and mixtures must be classified,
labelled and packed in accordance with the EU Classification, Labelling and Packaging Regulation. Further regulations prohibiting and limiting manufacture, marketing and use also apply.
United States
In the US, we operate a number of plants and facilities for the storage and processing of chemical feedstock, products and wastes.
Sasol's US operations and growth projects are subject to numerous laws, regulations and ordinances relating to safety, health and the protection of the environment. The objectives and requirements of
these legal frameworks are largely consistent with that of the South African Framework, although more established and entrenched in some respects.
Hazardous
substances are, in particular, regulated by a standard that incorporates the requirements of the Globally Harmonised System for classification and labelling of chemicals into
occupational health and safety
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legislations.
Chemical manufacturers and importers are required to evaluate the hazards of the chemicals they produce or import, and prepare labels and safety data sheets to convey the hazard
information to their downstream customers.
Canada
Oil and natural gas production
The British Columbia (BC) Petroleum and Natural Gas Act and Environmental Management Act are the primary sources of regulatory controls
over our natural oil and gas-producing areas in Canada. The acts and supporting legislation are administered by the BC Oil & Gas Commission to regulate the oil and gas industry and ensure
public safety, environmental protection, conservation of petroleum resources and equitable participation in production.
Mozambique
A National Environmental Policy (Resolution 5/95) is the government document outlining the priorities for environmental management and
sustainable development in Mozambique, including the required legal framework. The Environmental Law (Law 20/1997) provides a legal framework for the use and correct management of the
environment and its components and to assure sustainable development in Mozambique.
Environmental Regulations for Petroleum Operations (Decree 56/2010)
Regulations on Environmental Quality and Emission Standards (Decree 18/2004) aim to establish the standards for environmental quality
and for effluents release in order to assure the effective control and maintenance of the admissible standards of concentration of polluting substances on the environmental components. This is
supplemented by specific regulations on solid waste and water quality management.
The
Petroleum Act (Law 21/2014) requires holders of exploration and production rights to conduct petroleum operations in compliance
with
environmental and other applicable legislation. The law makes provision for compensation to be paid under general legislation by the holder of a right to conduct petroleum operations to persons
whose assets are damaged. The law establishes strict liability for the holder of the right who causes environmental damage or pollution.
Gabon
Natural oil and gas activities
The primary legislation in Gabon governing oil and gas activities is the new Hydrocarbon Law (law No. 011/2014) enacted by the
government of Gabon on 15 September 2014, with the aim to establish a new regime governing hydrocarbons exploration, exploitation and transportation activities. Existing production sharing
contracts remain in force until their expiry and will remain governed by Law No. 14/82 dated 24 January 1983, with the exception of a limited number of additional obligations under the
new regime such as a natural gas flaring prohibition.
Other countries
In a number of other countries, we are engaged in various activities that are regulated by local and international laws, regulations
and treaties. In Malaysia, China and other countries, we operate plants and facilities for the storage, processing and transportation of chemical substances, including feedstock, products and waste.
In the United Arab Emirates, Nigeria and other countries, we are involved, or are in the process of becoming involved, in exploration, extraction, processing or storage and transportation activities
in connection with feedstock, products and waste relating to natural oil and gas, petroleum and chemical substances.
In
Qatar, we participate in a joint venture owning and operating a GTL facility involving the production, storage and transportation of GTL diesel, GTL naphtha and LPG. These
operations are subject to numerous laws and ordinances relating to safety, health and the protection of the environment.
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Our operations in the respective jurisdictions are subject to numerous laws and regulations relating to exploration and mining rights and the protection of
safety, health and the environment.
4.C Organisational Structure
Sasol Limited (Sasol) is the ultimate parent of the Sasol group of companies.
Sasol
South Africa (Pty) Ltd, a wholly owned subsidiary in the Sasol group and a company incorporated in the Republic of South Africa, primarily holds our operations located in
South Africa. A number of other subsidiaries incorporated in the Republic of South Africa, including Sasol Oil (Pty) Ltd, Sasol Mining Holdings (Pty) Ltd, Sasol Middle East and India
(Pty) Ltd and Sasol Africa (Pty) Ltd, hold our interests in operations in South Africa, Africa and the Middle East. Sasol Financing (Pty) Ltd, responsible for the management of
cash
resources
and investments, and Sasol Technology (Pty) Ltd, responsible for engineering services, research, development and technology transfer, are also wholly owned and incorporated in the
Republic of South Africa.
Our
wholly owned subsidiary, Sasol Investment Company (Pty) Ltd, a company incorporated in the Republic of South Africa, primarily holds our interests in companies incorporated
outside South Africa, including Sasol European Holdings Limited (United Kingdom), Sasol Wax International AG (Germany), Sasol (USA) Corporation (United States), Sasol Holdings (Asia Pacific)
(Pty) Ltd (South Africa), Sasol Chemical Holdings International (Pty) Ltd (South Africa), Sasol Canada Holdings Limited (Canada) and their subsidiaries.
See
Exhibit 8.1 for a list of our significant subsidiaries and significantly jointly controlled entities.
4.D Property, plants and equipment
Refer to "Item 18—Annual Financial Statements—Note 17—Property, plant and equipment"
for further information regarding our property, plant and equipment.
Mining
Coal mining facilities
Our main coal mining facilities are located at the Secunda Mining Complex, which consists of underground collieries (Bosjesspruit,
Brandspruit, Impumelelo, Middelbult, Syferfontein, and Twistdraai, Thubelisha shaft) and the Sigma complex consisting of the Mooikraal colliery near Sasolburg.
For
detail regarding the cost of the assets in our coal mining facilities, refer to the segmental information contained in "Item 18—Annual Financial
Statements—Note 17—Property, plant and equipment".
A
map showing the location of our coal properties and major manufacturing plants in South Africa is shown on page M-1.
Mining
operates seven mines for the supply of coal to the Secunda Synfuels Operations, Sasolburg Operations (utility coal only) and the external market. The annual production of each
mine, the
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primary
market to which it supplies coal and the location of each mine are indicated in the table below:
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Production
(Mt)(3)
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Nominated
capacity
per year (Mt)(2)
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Colliery
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Location
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2016
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2015
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2014
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Bosjesspruit
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Secunda
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Secunda Synfuels Operations
|
|
|
7,2
|
|
|
6,6
|
|
|
7,3
|
|
|
7,9
|
|
|
Brandspruit
|
|
Secunda
|
|
Secunda Synfuels Operations
|
|
|
4,9
|
|
|
5,3
|
|
|
7,0
|
|
|
7,7
|
|
|
Impumelelo
|
|
Secunda
|
|
Secunda Synfuels Operations
|
|
|
2,1
|
|
|
1,7
|
|
|
—
|
|
|
—
|
|
|
Middelbult
|
|
Secunda
|
|
Secunda Synfuels Operations
|
|
|
7,8
|
|
|
7,6
|
|
|
6,9
|
|
|
7,6
|
|
|
Syferfontein
|
|
Secunda
|
|
Secunda Synfuels Operations
|
|
|
10,8
|
|
|
11,1
|
|
|
10,6
|
|
|
9,7
|
|
|
Twistdraai, Thubelisha shaft
|
|
Secunda
|
|
Export/Secunda Synfuels Operations(1)
|
|
|
8,3
|
|
|
8,2
|
|
|
7,5
|
|
|
6,9
|
|
|
Sigma : Mooikraal
|
|
Sasolburg
|
|
Sasolburg Operations
|
|
|
1,9
|
|
|
1,8
|
|
|
1,9
|
|
|
1,7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,3
|
|
|
41,2
|
|
|
41,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production tons per continuous miner (mining production machine) per shift (t/cm/shift)
|
|
|
|
|
|
|
|
|
|
1 322
|
|
|
1 367
|
|
|
1 338
|
|
-
(1)
-
The
secondary product from the export beneficiation plant is supplied to Secunda Synfuels Operations.
-
(2)
-
The
nominated capacity of the mines is the expected maximum production of that mine during normal operating hours, and does not represent the total maximum
capacity of the mine.
-
(3)
-
Production
includes externally purchased coal.
Processing operations
Coal export business—Secunda operations.
We started the coal export business in August 1996. Run of mine coal is sourced from the
existing East shaft of Twistdraai Colliery (formerly East, West and Central shafts) and the Thubelisha shaft. The export beneficiation plant has a design throughput capacity of 10,5 Million
tons (Mt) per annum. In 2016, we produced 8,2Mt from Twistdraai, Thubelisha shaft; of which we beneficiated 8,1Mt.
The
run of mine (ROM) coal is transported via overland conveyor belts to the export beneficiation plant from the Twistdraai shafts. The export product is loaded onto trains by means of a
rapid load-out system, and then transported to the Richards Bay Coal Terminal (RBCT) in KwaZulu-Natal.
The
capacity at the RBCT was increased from 76Mt to 91Mt per year, following the commissioning of the Phase V expansion in May 2010. Mining has a 4,23% share in the capacity of
this terminal, which corresponds to the existing entitlement of 3,6Mt per year. For the foreseeable future, we anticipate exports of approximately 3,25Mt per year, equal to the exports in 2016.
Sasol Coal Supply—Secunda operations.
Sasol Coal Supply operates the coal handling facility between Mining and Secunda Synfuels
Operations by stacking and blending coal on six live stockpiles. The overland conveyors from the mining operations to the coal handling facility are, in total, 100 kilometres (km) long and also form
part of the Sasol Coal Supply operation.
The
operation has a live stockpile capacity of 660 000 tons, which is turned over around 1,2 times per week. In addition, there is a strategic stockpile capacity of
more than 2,0Mt. The objectives of this facility are:
-
•
-
to homogenise the coal quality supplied to Secunda Synfuels Operations;
-
•
-
to keep mine bunkers empty;
-
•
-
to keep the Secunda Synfuels Operations bunkers full with a product that conforms to customer requirements;
-
•
-
to maintain a buffer stockpile to ensure even supply; and
-
•
-
to prevent fine coal generation.
The
daily coal supply to Secunda Synfuels Operations is approximately 112 000 tons.
34
Table of Contents
Coal exploration techniques
Mining's geology department employs several exploration techniques in assessing the geological risks associated with the exploitation
of the coal deposits. These techniques are applied in a mutually supportive way to achieve an optimal geological model of the relevant coal seams, targeted for production purposes. The Highveld Basin
is considered to be structurally complex when compared to the other coalfields in South Africa where mining activities take place. As a result, Mining bases its geological modelling on sufficient and
varied geological information. This approach is utilised in order to achieve a high level of confidence and support to the production environment.
Core recovery exploration drilling.
This is the primary exploration technique that is applied in all exploration areas, especially
during
reconnaissance phases. In and around operational mines, the average vertical borehole density varies from 1:10 to 1:15 (boreholes per hectare), while in medium-term mining areas, the average borehole
density is in the order of 1:25. Depths of the boreholes drilled vary, depending on the depth to the Pre-Karoo basement, from 160 metres (m) to 380m. The major application of this technique is
to locate the coal horizons, to determine coal quality and to gather structural information about dolerite dykes and sills, and the associated de-volatilisation and displacement of coal reserves. This
information is used to compile geological models and forms the basis of geological interpretation.
Directional drilling.
Directional drilling from surface to in-seam has been successfully applied for several
years. A circular area with a radius of approximately 1,4km of coal deposit can be covered by this method from one drill site. The main objective of this approach is to locate dolerite dykes and
transgressive dolerite sills, as well as faults with displacements larger than the coal seam thickness.
Horizontal drilling.
This technique is applied to all operational underground mines and supplies short-term (minimum three months)
exploration
coverage per mining section.
No
core is usually recovered, although core recovery is possible, if required. The main objective is to locate dolerite dykes and transgressive sills intersecting the coal mining horizon, by drilling
horizontal holes in the coal seam from a mined out area. A drilling reach of up to 1km is possible, although the average length is usually 800m in undisturbed coal.
Aeromagnetic surveys.
Many explorations are usually aero-magnetically surveyed before the focused exploration is initiated. The main
objective is to
locate magnetic dolerite sills and dykes, as well as large-scale fault zones.
Geophysical wireline surveys of directional boreholes.
Geophysical surveys are routinely conducted in the completed directional drilled
boreholes.
This results in the availability of detailed information leading to increased confidence of the surface directional drilling results.
Secunda operations
The coal supplied to Secunda Synfuels Operations is the raw coal mined from the five mines supplying Secunda Synfuels Operations
exclusively and the secondary product from the export beneficiation plant.
We
have carried out extensive geological exploration in the coal resource areas, and undertake additional exploration to update and refine the geological models. This allows for accurate
forecasting of geological conditions and coal qualities, and also effective planning and utilisation of coal reserves.
Computation and storage of geological information
We store geological information in the acQuire database. We conduct regular data validation and quality checking through several
in-house methods. Data modelling is conducted by manual interpretation and computer-derived geological models, using the Minex 6 edition of the GEOVIA/ MINEX software. Reserves and composite qualities
are computed using established and recognised geo-statistical techniques.
35
Table of Contents
General stratigraphy
The principal coal horizon, the Number 4 Lower Coal Seam, provides some 89,41% (2015—89,66%) of the total proved and
probable reserves. The Number 4 Lower Coal Seam is one of six coal horizons occurring in the Vryheid Formation of the Karoo Supergroup, a permo-carboniferous aged, primarily sedimentary
sequence. The coal seams are numbered from the oldest to the youngest.
The
Number 4 Lower Coal Seam is a bituminous hard coal, characterised by the following borehole statistics:
-
•
-
The depth to the base of the seam ranges from 40m to 241m with an average depth of 135m below the surface topography. All the current
mining done on this seam is underground;
-
•
-
The floor of the seam dips gently from north to south at approximately 0,5 degrees;
-
•
-
The thickness of the seam varies in a range up to 10m with a weighted average thickness of 3,3m. In general, thinner coal is found to
the south and thicker coal to the west adjacent to the Pre-Karoo basement highs;
-
•
-
The inherent ash content (air dried basis) is an average 28,6%, which is in line with the coal qualities supplied during the past
30 years to Secunda Synfuels Operations;
-
•
-
The volatile matter content is tightly clustered around a mean of 19,5% (air dried); and
-
•
-
The total sulphur content (air dried), which primarily consists of mineral sulphur in the form of pyrite and minor amounts of organic
sulphur, averages 0,92% of the total mass of the coal.
The
other potential coal seam is:
-
•
-
The Number 2 Coal Seam at Middelbult colliery and Impumelelo colliery, which has been included in our reserve base.
Reserve estimation (remaining reserves at 31 March 2016)
We have approximately 3,7 billion tons (Bt) (2015—3,7 Bt) of gross in situ proved and probable coal reserves in the
Secunda Deposit and approximately 1,2 Bt (2015—1,2 Bt) of recoverable reserves. The coal reserve estimations are set out in table 1 below. Reported reserves will be converted into
synthetic oil reserves, except for reserves which will be used for utilities in Secunda Synfuels Operations and the majority of the Twistdraai, Thubelisha shaft reserves which will be exported. The
reserve disclosure in this section includes Mining's total coal resources and reserves available for mining operations in Secunda. These reserves have not been adjusted for the synthetic oil reserves
reported in the supplemental oil and gas information. The different reserve areas are depicted on the map on page M-1, as well as whether a specific reserve area has been assigned to a specific
mine.
36
Table of Contents
Table 1.
Coal reserve estimations(1) as at 31 March 2016, in the Secunda area where we have converted
mining rights (signed on 29 March 2010) in terms of the Mineral and Petroleum Resources Development Act, Act 28 of 2002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve area
|
|
Gross in
situ coal
resource(2)
(Mt)(5)
|
|
Geological
discount
(Mt)(5)
|
|
Mine
layout
losses
(Mt)(5)
|
|
Extraction
rate
(%)
|
|
Recoverable
reserves(3)
(Mt)(5)
|
|
Beneficiated
yield(4)
(%)
|
|
Proved/
probable
|
|
Middelbult mine, number 4 seam
|
|
|
731
|
|
|
97
|
|
|
162
|
|
|
42
|
|
|
214
|
|
|
100
|
|
Proved
|
|
Middelbult mine, number 2 seam
|
|
|
61
|
|
|
13
|
|
|
8
|
|
|
39
|
|
|
19
|
|
|
100
|
|
Probable
|
|
Bosjesspruit mine
|
|
|
304
|
|
|
27
|
|
|
97
|
|
|
50
|
|
|
84
|
|
|
100
|
|
Proved
|
|
Bosjesspruit mine
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|
100
|
|
Probable
|
|
Twistdraai mine
|
|
|
7
|
|
|
1
|
|
|
4
|
|
|
56
|
|
|
4
|
|
|
P46,S20
|
|
Proved
|
|
Syferfontein mine
|
|
|
261
|
|
|
19
|
|
|
60
|
|
|
42
|
|
|
98
|
|
|
100
|
|
Proved
|
|
Brandspruit mine
|
|
|
45
|
|
|
24
|
|
|
46
|
|
|
45
|
|
|
6
|
|
|
100
|
|
Proved
|
|
Twistdraai Thubelisha shaft
|
|
|
578
|
|
|
100
|
|
|
123
|
|
|
68
|
|
|
230
|
|
|
P34,S39
|
|
Proved
|
|
Impumelelo, Block 2, number 4 seam
|
|
|
710
|
|
|
49
|
|
|
147
|
|
|
47
|
|
|
233
|
|
|
100
|
|
Proved
|
|
Impumelelo, Block 2, number 2 seam
|
|
|
384
|
|
|
27
|
|
|
118
|
|
|
36
|
|
|
63
|
|
|
100
|
|
Probable
|
|
Block 2 South, number 4 seam
|
|
|
363
|
|
|
98
|
|
|
48
|
|
|
54
|
|
|
122
|
|
|
100
|
|
Probable
|
|
Block 2 South, number 2 seam
|
|
|
133
|
|
|
36
|
|
|
18
|
|
|
54
|
|
|
45
|
|
|
100
|
|
Probable
|
|
Block 3 South
|
|
|
141
|
|
|
38
|
|
|
19
|
|
|
58
|
|
|
52
|
|
|
100
|
|
Probable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Secunda area
|
|
|
3 718
|
|
|
|
|
|
|
|
|
|
|
|
1 203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
The
coal reserve estimations in this table were compiled under supervision of Mr Viren Deonarain and Mr Jakes Lock who are considered
competent people. The "South African Code for Reporting of Minerals Resources and Minerals Reserves (The SAMREC Code 2007 edition)" dealing with competence and responsibility, paragraph 7,
state Documentation detailing Exploration Results, Mineral Resources and Mineral reserves from which a Public Report is prepared, must be prepared by, or under the direction of, and signed by a
Competent Person. Paragraph 9 states: A 'Competent Person' is a person who is registered with SACNASP, ECSA or PLATO, or is a Member or Fellow of the SAIMM, the GSS or a Recognised Overseas
Professional organisation (ROPO). The Competent Person must comply with the provisions of the relevant promulgated Acts. Mr J Erasmus (Pr.Nat.Sc), on behalf of Sumsare Consulting performed a
comprehensive and independent audit of the coal resource/reserve estimations in July 2015 and the estimates were certified as correct. The estimation of the reserves is compliant with the definition
and guidelines as stated in the SAMREC and Joint Ore Reserve Committee (JORC) codes, as well as SEC Industry Guideline 7.
-
(2)
-
The
gross in situ coal resource is an estimate of the coal tonnage, contained in the full coal seam above the minimum thickness cut off and relevant coal
quality cut off parameters. No loss factors are applied and seam height does not include external dilution or contamination material.
-
(3)
-
The
recoverable coal reserve is an estimate of the expected recovery of the mines in these areas and is determined by the subtraction of losses due to
geological and mining factors and the addition of dilatants such as moisture and contamination.
-
(4)
-
The
P% of P46 and P34 refers to the export product yield from the recoverable coal reserve and the S% of S20 and S39 refers to secondary product yield,
which will be supplied to the Sasol Synfuels Operations. The balance of this is discard material.
-
(5)
-
Mt
refers to 1 million tons. Reference is made of tons, each of which equals 1 000 kilograms, approximately 2 205 pounds or
1 102 short tons.
37
Table of Contents
Table 2.
Coal qualities, on an air dry basis, in respective coal reserve areas, where Mining has converted
mining rights in respect of the Secunda mining complex in terms of the Mineral and Petroleum Resources Development Act, Act 28 of 2002.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve area
|
|
Wet/dry
tons
|
|
Average
Inherent
Moisture
Content
(%)
|
|
Average
Superficial
Moisture
Content
(%)
|
|
Assigned/
unassigned
|
|
Steam/
metallurgical
coal
|
|
Heat
Value
(air dry)
basis
MJ/kg
|
|
Sulphur
(air dry
basis)
|
|
|
Middelbult mine
|
|
Wet
|
|
|
4,2
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
21,3
|
|
|
0,9
|
|
|
Bosjesspruit mine
|
|
Wet
|
|
|
4,0
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
19,7
|
|
|
0,9
|
|
|
Twistdraai mine
|
|
Wet
|
|
|
3,8
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
20,8
|
|
|
1,1
|
|
|
Syferfontein mine
|
|
Wet
|
|
|
5,5
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
21,4
|
|
|
0,8
|
|
|
Brandspruit mine
|
|
Wet
|
|
|
3,9
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
17,8
|
|
|
1,3
|
|
|
Twistdraai, Thubelisha shaft
|
|
Wet
|
|
|
4,3
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
21,4
|
|
|
1,1
|
|
|
Impumelelo, Block 2, number 4 seam.
|
|
Wet
|
|
|
4,1
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
18,1
|
|
|
1,2
|
|
|
Impumelelo, Block 2, number 2 seam
|
|
Wet
|
|
|
3,7
|
|
n/a
|
|
Assigned
|
|
Steam
|
|
|
17,5
|
|
|
0,8
|
|
|
Block 2 South, number 4 seam
|
|
Wet
|
|
|
4,1
|
|
n/a
|
|
Unassigned
|
|
Steam
|
|
|
18,2
|
|
|
1,2
|
|
|
Block 2 South, number 2 seam
|
|
Wet
|
|
|
3,6
|
|
n/a
|
|
Unassigned
|
|
Steam
|
|
|
17,4
|
|
|
0,7
|
|
|
Block 3 South
|
|
Wet
|
|
|
3,6
|
|
n/a
|
|
Unassigned
|
|
Steam
|
|
|
21,9
|
|
|
0,7
|
|
Table 3.
Coal qualities, on an as received basis, in respective coal reserve areas, where Mining has
converted mining rights in the Secunda mining complex in terms of the Mineral and Petroleum Resources Development Act, Act 28 of 2002.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve area
|
|
Wet/dry
tons
|
|
Average
Inherent
Moisture
Content
(%)
|
|
Average
Superficial
Moisture
Content
(%)
|
|
Assigned/
unassigned
|
|
Steam/
metallurgical
coal
|
|
Heat
Value
(as received)
basis
MJ/kg
|
|
Sulphur
(as received
basis)
|
|
|
Middelbult mine
|
|
Wet
|
|
|
4,2
|
|
|
4,5
|
|
Assigned
|
|
Steam
|
|
|
20,3
|
|
|
0,9
|
|
|
Bosjesspruit mine
|
|
Wet
|
|
|
4,0
|
|
|
4,0
|
|
Assigned
|
|
Steam
|
|
|
18,9
|
|
|
0,9
|
|
|
Twistdraai mine
|
|
Wet
|
|
|
3,8
|
|
|
3,6
|
|
Assigned
|
|
Steam
|
|
|
20,0
|
|
|
1,1
|
|
|
Syferfontein mine
|
|
Wet
|
|
|
5,6
|
|
|
4,7
|
|
Assigned
|
|
Steam
|
|
|
20,5
|
|
|
0,8
|
|
|
Brandspruit mine
|
|
Wet
|
|
|
3,9
|
|
|
3,7
|
|
Assigned
|
|
Steam
|
|
|
17,1
|
|
|
1,2
|
|
|
Twistdraai, Thubelisha shaft
|
|
Wet
|
|
|
4,3
|
|
|
4,3
|
|
Assigned
|
|
Steam
|
|
|
20,4
|
|
|
1,0
|
|
|
Impumelelo, Block 2, number 4 seam
|
|
Wet
|
|
|
4,1
|
|
|
3,7
|
|
Assigned
|
|
Steam
|
|
|
18,0
|
|
|
1,1
|
|
|
Impumelelo, Block 2, number 2 seam
|
|
Wet
|
|
|
3,7
|
|
|
3,7
|
|
Assigned
|
|
Steam
|
|
|
17,5
|
|
|
0,8
|
|
|
Block 2 South, number 4 seam
|
|
Wet
|
|
|
4,1
|
|
|
3,1
|
|
Unassigned
|
|
Steam
|
|
|
18,0
|
|
|
1,1
|
|
|
Block 2 South, number 2 seam
|
|
Wet
|
|
|
3,6
|
|
|
2,7
|
|
Unassigned
|
|
Steam
|
|
|
17,2
|
|
|
0,7
|
|
|
Block 3 South
|
|
Wet
|
|
|
3,4
|
|
|
3,6
|
|
Unassigned
|
|
Steam
|
|
|
21,8
|
|
|
0,7
|
|
38
Table of Contents
Criteria for proved and probable
Over and above the definitions for coal reserves, probable coal reserves and proved coal reserves, set forth in Industry Guide 7,
promulgated by the US Securities and Exchange Commission, we consider the following criteria to be pertinent to the classification of the reserves:
Probable
reserves are those reserve areas where the drill hole spacing is sufficiently close in the context of the deposit under consideration, where conceptual mine design can be
applied, and for which all the legal and environmental aspects have been considered. Probable reserves can be estimated with a lower level of confidence than proved coal reserves. Currently this
classification results in variable drill spacing depending on the complexity of the area being considered and is generally less than 500m, although in some areas it may extend to 880m. The influence
of increased drilling in these areas should not materially change the underlying geostatistics of the area on the critical parameters such as seam floor, seam thickness, ash and volatile content.
Proved
reserves are those reserves for which the drill hole spacing is generally less than 350m, for which a complete mine design has been applied which includes layouts and schedules
resulting in a full financial estimation of the reserve. This classification has been applied to areas in the production stage or for which a detailed feasibility study has been completed.
Legal rights on coalfields
Our subsidiary, Sasol Mining (Pty) Ltd, is the holder of various prospecting and mining rights in respect of the areas where we
operate, granted in terms of the provisions of the Mineral and Petroleum Resources Development Act, 28 of 2002 (MPRDA). In respect of the Secunda Complex, the mining right, in extent of approximately
168 439ha, became effective on 29 March 2010. It has been amended and is valid for a period of 30 years and comprises the total reserve area shown in table 1 and on
page M-1. The amendment to the Secunda Complex mining right has still to be registered in
the
Mineral and Petroleum Titles Registration Office. In respect of the Sigma: Mooikraal Operation in the Free State, the two mining rights which became effective on 29 March 2010 were
consolidated into a single mining right. The mining right, approximately 6 647 ha in extent, has been granted for a period of 30 years. The consolidation of Sigma: Mooikraal mining
rights is still to be registered in the Mineral and Petroleum Titles Registration Office. The validity period of our mining rights may, on application, be renewed for further periods not exceeding
30 years each.
Exploration and Production International (E&PI)
Natural Oil and Gas
Our natural oil and gas assets are managed by our Exploration and Production International (E&PI) business unit. E&PI's principal
activities are the exploration, appraisal, development and production of hydrocarbon resources. Currently we hold equity in three assets with proved reserves in Mozambique, Canada and Gabon. We also
have equity in a non-producing asset in Mozambique and in exploration licences in Mozambique, Australia, Nigeria and South Africa. The maps on page M-2 show E&PI's global footprint and the
location of our assets.
In
the following narrative sections, unless stated otherwise, all quantitative statements are to gross figures.
Mozambique
Licence Terms
See "Item 4.D—Developed and Undeveloped Acreage" for the total gross and net developed and undeveloped acreage of
our natural oil and gas assets by geographic area, in tabular format, at 30 June 2016.
In Mozambique, we have interests in two onshore assets, one of which is producing, with proved reserves. The other consists of two
areas under development and other reservoirs that are being assessed for commerciality.
39
Table of Contents
The
producing asset is the Pande-Temane Petroleum Production Agreement (PPA) licence (302,2 thousand developed net acres). Our subsidiary, Sasol Petroleum Temane Limitada (SPT),
the operator, holds a 70% working interest in the PPA. The PPA expires in 2034, and carries two possible five-year extensions. There is no requirement to relinquish any acreage until the expiry of the
PPA.
The
other asset is the Pande-Temane Production Sharing Agreement (PSA) licence. Our subsidiary, Sasol Petroleum Mozambique Limitada (SPM), the operator, holds a 100% interest in the
asset with Empresa National de Hidrocarbonetos de Moçambique (ENH), the national oil company of Mozambique, entitled under the terms of the PSA to a calculated share in production. The
asset includes two areas which are under development in accordance with a field development plan approved by the Mozambican authorities in January 2016. These areas are covered by development and
production periods until 2041 for the oil development (125,9 thousand undeveloped net acres) and 2046 for the gas development (157,3 thousand undeveloped net acres). The remaining PSA
area (159,6 thousand undeveloped net acres) is covered by a five-year commercial assessment period (CAP) ending in February 2018. The retention of the reservoirs in this area is contingent on a
declaration of commerciality and government approval of an additional field development plan.
We also have interests in two exploration licences, one offshore and the other onshore, and two licences which are in the process of
being negotiated.
The
offshore exploration licence comprises the shallow water parts of the Exploration and Production Concession Blocks 16 & 19. Our subsidiary, Sasol Petroleum Mozambique
Exploration Limitada (SPMEL), the operator, will hold an 85% working interest (622,7 thousand undeveloped net acres) when the assignment of our partner's interest is approved by the
authorities. ENH has a 15% interest that is carried until field development.
Petroleum
operations in the licence were suspended in 2008 and will remain so until the Strategic Environmental Assessment (SEA), which was commissioned by the Mozambique government, is made public.
We have retained our interest in the licence with a view to defining a future work programme when the outcome of the SEA is known.
The
onshore exploration licence is the Exploration and Production Concession Area A. Following the completion of a farm-down of 40% working interest to Petrogas E&P
Moçambique BV in March 2016, our subsidiary SPMEL, the operator, now holds a 50% working interest (827,8 thousand undeveloped net acres). ENH has a 10% interest that is
carried until field development. The Area A licence is in the second exploration period, which has been extended for one year until May 2017, and includes one commitment well.
In
October 2015, the authorities announced the results of the Fifth Mozambique Licencing Round in which our subsidiary, SPMEL, and our partners, were successful and were invited to
commence negotiations for Exploration Production Concession Contracts for one onshore and one offshore licence. On completion of the negotiations, SPMEL will hold a 70% working interest in the onshore
Area PT5-C as operator, and a 30% working interest in the offshore Area A5-A which will be operated by Eni Mozambico S.p.A
Activities
See "Item 4.D—Drilling activities" for the number of net natural oil and gas wells completed in each of the last
three years and the number of wells being drilled or temporarily suspended at 30 June 2016.
In
the Pande-Temane PPA asset, the first phase of the project contained in the approved PPA field development plan to lower the inlet pressure at the Central Processing Facilities (CPF)
was completed in December 2015. This, as well as the second and third phases of the project and infill drilling, is necessary to maintain production as the field depletes.
40
Table of Contents
Following
approval of the field development plan, the first well in the PSA Phase 1 Tranche 1 development was spudded in May 2016. The current drilling programme, which
comprises 12 development wells, and one service well, representing the initial development of four oil and gas reservoirs, is expected to last for two years. The PSA field development plan also
requires the capacity of the PPA CPF to be increased to 633 MMscf/day of gas and a Liquids Processing Facility (LPF) with a capacity of 15 000 bpd of oil and 20 000 tons per
annum liquefied petroleum gas to be constructed adjacent to the CPF. The cost of the development plan is US$1,4 billion covering expansion of the CPF, construction of the LPF and
flowlines; and the initial drilling programme. US$80 million has been spent to end 2016 comprising drilling costs, civil engineering works and detailed engineering.
Evaluation
and well planning activities have also been undertaken in the PSA CAP area.
In
the Area A, exploration licence well planning activities have been undertaken in order to drill the commitment exploration well before the end of the second exploration period.
Capitalised Exploratory Well Costs
See "Item 4.D—Capitalised exploratory well costs" for information, in tabular format, about the continued
capitalisation of exploratory well costs, at 30 June 2016.
At
30 June 2016, there were no exploratory wells costs capitalised in the Pande-Temane PPA asset.
In
the Pande-Temane PSA asset, CAP area, exploratory well costs continue to be capitalised for a period greater than one year after the completion of drilling. These relate to the
exploration drilling conducted and completed in 2008, and follow-up activities which continued to 2016. Capitalised exploratory well costs amounted to R41,6 million in 2016.
During
2016, planning activities began for an exploratory well to be drilled in Area A in 2017. At 30 June 2016, there were no exploratory wells costs capitalised in Area A. Any
such costs capitalised at the beginning of
the
year have been met by the proceeds of the farm-down to Petrogas.
Facilities and Productive Wells
See "Item 4.D "Oil and Gas production facilities and productive wells" for details, in tabular format, about the production
capacity of our natural oil and gas production facilities and the number of productive natural oil and gas wells at 30 June 2016.
Natural
gas and condensate is produced from the Pande-Temane PPA asset, at the CPF on a site of approximately 400 000 square metres (m
2
), that is
located some 700 kilometres (km) north of Maputo, the capital of Mozambique. Production from the Temane and Pande fields, which are managed as a single operational field is routed from
production wells via in-field flowlines and pipelines to the CPF.
The
current design capacity of the CPF is 450MMscf/day sales gas together with small amounts of associated condensate. A minor de-bottlenecking project is underway to increase the
capacity of the CPF to 491MMscf/day.
At
30 June 2016, there were 24 PPA asset productive wells.
Delivery Commitments
Gas produced from the Pande-Temane PPA asset, other than royalty gas that is provided to the Mozambican government, is supplied in
accordance with long-term Gas Sales Agreements (GSAs). The gas produced in accordance with GSA1, signed on 27 December 2002 (25 years contract term), and GSA2, signed on
10 December 2008 (20 years contract term), is sold internally for use as part of the feedstock for our chemical and synthetic fuel operations in South Africa, with a base-case supply of
120 PJ/a (108,86 bscf/a) and 27 PJ/a (24,49 bscf/a) respectively. There are four GSA3 20-year contracts, that supply gas to the Mozambique market. These satisfy a licence condition that a portion of
gas produced is utilised in-country. The contracts are with Matola Gas Company S.A from 1 July 2014 for 8 PJ/a (7,26 bscf/a), ENH-Kogas from 1 March 2013 for
41
Table of Contents
6
PJ/a (5,44 bscf/a), Central Termica de Ressano Garcia S.A. from end-February 2015 for 11 PJ/a (9,98 bscf/a) and ENH-Kogas effective from 1 June 2015 for 2PJ/a (1,81 bscf/a).
Following
completion of the first phase of the project to reduce inlet pressure at the CPF, proved developed reserves from the PPA are sufficient to meet commitments for the near future.
Steps are under way to ensure commitments can be met to the end of the contracts.
PPA
condensate is sold to Petróleos de Moçambique, S.A. (Petromoc), who then transports the condensate by truck, for export via the port of Beira.
Proved Reserves
See supplementary Natural Oil and Gas information Table 4 "Proved Reserve quantity information" on page G-2 for details
of proved developed and proved undeveloped reserves of natural oil and gas, in tabular format, for the last three years..
Our
Mozambique proved reserves are contained in the Pande-Temane PPA licence. These represent the net economic interest volumes that are attributable to Sasol after the deduction of
production tax. The primary sales product for the PPA is natural gas, with minor amounts of associated liquid hydrocarbon.
There was a reduction in proved gas reserves due to production of 114,4 billion cubic feet.
Changes to proved developed reserves
Proved developed gas reserves increased by 351,3 billion cubic feet. This was due to conversion of undeveloped reserves to
developed partially offset by production and a minor revision.
Proved undeveloped reserves converted to proved developed reserves
The first phase of a project to lower the inlet pressure at the CPF was completed in
December
2015. This has resulted in the conversion of 516,7 billion cubic feet undeveloped gas reserves to developed reserves during 2016. The total cost of this project was
US$98 million net to Sasol.
Changes to proved undeveloped reserves
Proved undeveloped gas reserves decreased by 511,9 billion cubic feet. The reduction is largely due to the conversion of
undeveloped reserves to developed.
Proved undeveloped reserves remaining undeveloped
A significant volume of proved undeveloped gas reserves (presently estimated to be 472,4 billion cubic feet) has remained
undeveloped in the Pande-Temane PPA asset for the last ten years. The total proved volume (developed plus undeveloped) represents gas that will be recovered as part of the approved field development
plan and which is required to satisfy existing gas sales agreements. In order to optimise timing of capital expenditure required to convert undeveloped reserves to developed reserves, E&PI regularly
studies production performance from the two fields and reviews its plan for installation of additional compression and wells. The initial infill wells are planned for 2018 and additional compression
is planned within the next five years.
Production, Sales Prices and Production Costs
See Natural Oil and Gas supplementary information Table 4 "Proved reserve quantity information" on page G-4 for details
of natural oil and gas production, in tabular format, for the last three years.
See
"Item 4.D—Sales Prices and Production Costs" for details of average sales prices and production costs, provided in tabular format, of natural oil and gas.
Canada
Licence Terms
See "Item 4.D—Developed and Undeveloped Acreage" for the total gross and net developed and undeveloped
42
Table of Contents
acreage
of our natural oil and gas assets by geographic area, in tabular format, at 30 June 2016.
In
Canada, our subsidiary Sasol Canada Exploration and Production Limited (SCEPL), holds a 50% working interest in the Farrell Creek and Cypress A asset located in British Columbia which
is operated by Progress Energy Canada Ltd (PECL).
As
at 30 June 2016, following expiry of deep rights in three contract areas, Farrell Creek comprised 29 licences and leases and Cypress A comprised 25 licences and leases.
The
Farrell Creek and Cypress A asset covers an area of 17,3 thousand developed net acres and 39,0 thousand undeveloped net acres. Acreage retention and the conversion of
licences (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
licence extension applications.
The
decision to retain acreage and convert licences to leases is dependent on the drilling results and ongoing study work. Production, drilling and other retention activities are
included in the applicable work programmes so that licences and leases for the asset, due to expire before 30 December 2017 are retained (13,9 thousand net acres affected).
Activities
See "Item 4.D—Drilling Activities" for the number of net natural oil and gas wells completed in each of the last
three years and the number of wells being drilled or temporarily suspended at 30 June 2016.
Development
activities in the Farrell Creek and Cypress A asset continued and, in 2016;
in
Farrell Creek:
-
•
-
four wells were drilled but not completed;
-
•
-
four wells were drilled and completed; and
-
•
-
four previously-drilled wells were completed.
in
Cypress A:
-
•
-
eight wells were drilled but not completed;
-
•
-
seven wells were drilled and completed; and
-
•
-
three previously-drilled wells were completed.
Additionally
three wells were reinstated to production in Farrell Creek. At 30 June 2016, ten wells were awaiting completion according to the approved work programme (three in
Farrell Creek and seven in Cypress A).
In
2016, a project to connect the southern Cypress A wells to the Farrell Creek facilities by means of an inter-field gas pipeline and two water pipelines was completed. The pipelines
became operational in October 2015 improving the Farrell Creek Gas Plant utilisation, lowering operating costs and transportation fees, and reducing dependency on third party transportation and the
associated processing fees.
At
the end of 2016, SCEPL and PECL reached agreement and the funding commitments of the Progress and Sasol Montney Partnership (PSMP) were settled. In order to responsibly steward the
Farrell Creek and Cypress A asset through the low gas price environment, the PSMP agreed to slow down the pace of appraisal and development and significantly reduce activities. An 18 month work
programme and budget to December 2017 was approved in June 2016. With effect from 1 July 2016, SCEPL and PECL will contribute equally in the development and operation of the PSMP in accordance
with their respective 50% partnership interests.
Capitalised Exploratory Well Costs
At 30 June 2016, there are no exploratory well costs capitalised in the Farrell Creek and Cypress A asset.
Facilities and Productive Wells
See "Item 4.D—Oil and Gas production facilities and productive wells" for details, in tabular format, about the
production
43
Table of Contents
capacity
of our natural oil and gas production facilities and the number of productive natural oil and gas wells at 30 June 2016.
Natural
gas and liquids are produced from the Farrell Creek and Cypress A asset by means of production wells, flowlines, gathering lines and processing facilities. Gas from Farrell Creek
and Cypress A southern wells is processed through facilities owned by SCEPL and PECL, covering a site of approximately 160 000 m
2
. Gas from Cypress A northern wells is
currently processed and sold through third party production facilities.
At
30 June 2016, there were 169 productive wells with a further 10 planned to be completed in the first six months of 2017.
Delivery Commitments
Our gas from the Farrell Creek and Cypress A asset is sold into the Western Canada market, under a long-term agreement with PECL,
effective until 2024. Pricing is based on the daily realised spot market prices less transportation and marketing fees. The small amount of petroleum liquids are sold under the same agreement.
Production
from Farrell Creek and Cypress A is currently not sufficient to fully utilise contracted gas transportation capacity. Low production in 2016 resulted in continued non-utilised
transport charges in the Spectra and TransCanada/NOVA pipelines. PECL, as operator, partially mitigates exposure through placing of non-utilised gas transmission capacity in the gas transmission
market.
Proved Reserves
See Natural Oil and Gas supplementary information Table 4 "Proved Reserve quantity information" on page G-4 for details
of proved developed and proved undeveloped reserves of natural oil and gas, in tabular format, for the last three years.
Our
Canada proved reserves are contained in the Farrell Creek and Cypress A fields, which are managed as a single operational field. These represent the net economic interest volumes
that
are
attributable to Sasol after the deduction of royalty. The primary sales product is natural gas, with minor amounts of associated liquid hydrocarbons.
Full
development of the fields will require around 2 900 wells, of which only some 6% have been drilled and completed to date. Reserves are limited to those volumes of gas
and associated liquid hydrocarbons attributable to Sasol that are forecast to be produced from existing wells together with wells to be drilled and/or completed in the approved work programme.
Changes to proved reserves
There was a reduction in proved gas reserves due to production of 20,7 billion cubic feet.
Changes to proved developed reserves
Proved developed reserves increased by 4,2 billion cubic feet. The installation of the Cypress A to Farrell Creek pipelines
(CAD32 million net to Sasol) and continued development drilling and completion resulted in proved developed reserves increasing by 12,4 billion cubic feet. Additional volumes were
converted from undeveloped and there was a small positive revision. These increases were partly offset by production.
Proved undeveloped reserves converted to proved developed reserves
Completion of seven wells during 2016 resulted in conversion of 8,2 billion cubic feet undeveloped gas reserves to developed
reserves. The total cost of this conversion was CAD56 million net to Sasol.
Changes to proved undeveloped reserves
As at 30 June 2016, undeveloped reserves (14,8 billion cubic feet) are associated with the completion of ten wells which
have already been drilled. Although these completions are assessed to have a negative present value they generate a positive cash flow and are included in the approved work programme for completion in
2017.
44
Table of Contents
There were no undeveloped reserves remaining from 30 June 2015.
Production, Sales Prices and Production Costs
See Natural Gas and Oil supplementary information Table 4 "Proved Reserve quantity information" on page G-4 for details
of natural oil and gas production, in tabular format, for the last three years.
See
"Item 4.D—Sales prices and production costs" for details of average sales prices and production costs, provided in tabular format, of natural oil and gas.
Gabon
Licence Terms
See "Item 4.D—Developed and undeveloped acreage" for the total gross and net developed and undeveloped acreage of
our natural oil and gas assets by geographic area, in tabular format, at 30 June 2016.
In
Gabon, we hold a 27,75% working interest in the Etame Marin Permit (EMP) areas covered by Exclusive Exploitation Authorisations (EEAs) under the terms of the EMP Exploration and
Production Sharing Contract. The licence is operated by VAALCO Gabon (Etame) Inc.
The
exploitation areas of the Etame Marine asset are covered by three 10-year EEAs, each with two five-year renewal periods available on request and subject to government decree. The
Etame EEA was in the first five-year renewal period, which expired in July 2016. An application for the second five-year renewal period was submitted in April 2016. The Avouma EEA is currently in the
first five-year renewal period to March 2020. The initial ten-year period of the Ebouri EEA expired in June 2016 and an application for the first five-year renewal period was submitted in March 2016.
The current production plan assumes the renewals will be granted as required on a similar basis as in the past.
-
•
-
Etame EEA: 3 387 developed net acres, 2001-2016 + one five-year extension (to July 2021)
-
•
-
Avouma EEA: 3 566 developed net acres, 2005-2020 + one five-year extension (to March 2025)
-
•
-
Ebouri EEA: 1 022 developed net acres, 2006-2016 + two five-year extensions (to June 2026)
Activities
See Item 4.D "Drilling Activities" for the number of net natural oil and gas wells completed in each of the last three years and
the number of wells being drilled or temporarily suspended at 30 June 2016.
The
Etame Expansion Project (EEP) and South East Etame & North Tchibala (SEENT) project was completed in 2016 with the drilling, completion and start-up of the final three SEENT
wells.
Conceptual
studies are being undertaken looking at future development opportunities, including options for crude-sweetening.
The
operator's response to the findings of the industry-wide audit performed on behalf of the Gabon government and issued in October 2014 is still being discussed with the government.
Final notification from the government on the audit settlement is therefore pending.
Capitalised Exploratory Well Costs
At 30 June 2016, there were no exploratory well costs capitalised in the EMP asset.
Facilities and Productive Wells
See "Item 4.D—Oil and Gas production facilities and productive wells" for details, in tabular format, about the
production capacity of our natural oil and gas production facilities and the number of productive natural oil and gas wells at 30 June 2016.
Oil
is produced from the EMP asset facilities, located some 35 km offshore southern Gabon which consist of four wellhead platforms, subsea flowlines and a floating production,
45
Table of Contents
storage and off-loading vessel (FPSO). Oil, from Etame, Avouma and Ebouri, which are managed as a single operational field, is produced by means of a
combination of subsea and platform wells, which are routed by pipelines to the FPSO contracted from, and operated by Tinworth Pte. Limited. The processed oil is stored in tanks on the FPSO prior to
export by shipping tanker.
At
30 June 2016, there were 10 productive wells across the three fields.
Delivery Commitments
Oil produced from the EMP asset is marketed internationally on the open market. The oil is sold under a short-term Crude Oil Sale and
Purchase Agreement (COSPA) which is renewed periodically. The current COSPA, with Glencore as buyer, expires on 31 January 2017. The COSPA is expected to be further renewed or re-contracted as
required on terms not dissimilar to the current contract.
Proved Reserves
See Natural Oil and Gas supplementary information Table 4 "Proved Reserve quantity information" on page G-4 for details
of proved developed and proved undeveloped reserves of natural oil and gas, in tabular format, for the last three years.
Our
Gabon proved reserves are contained in the EMP licence. These represent the net economic interest volumes attributable to Sasol after application of the licence terms. The primary
sales product is natural crude oil, all gas produced is consumed in operations or flared.
Changes to proved reserves
There was a reduction in proved oil reserves due to production of 1,5 million barrels.
Changes to proved developed reserves
Proved developed reserves decreased by 0,3 million barrels. Drilling and completion of three SEENT wells during 2016 resulted in
proved developed reserves increasing by 1,1 million barrels (at a cost of US$ 86,8 million net to Sasol), which was partly offset by production and a minor revision.
Proved undeveloped reserves converted to proved developed reserves
No reserves were converted from undeveloped to developed during 2016.
Changes to proved undeveloped reserves
There were no proved, undeveloped reserves at the beginning or end of 2016.
Proved undeveloped reserves remaining undeveloped
There were no reserves remaining undeveloped as at 30 June 2016.
Production, Sales Prices and Production Costs
See Natural Oil and Gas supplementary information Table 4 "Proved Reserve quantity information" on page G-4 for details
of natural oil and gas production, in tabular format, for the last three years.
See
"Item 4.D—Sales Prices and Production Costs" for details of average sales prices and production costs, provided in tabular format, of natural oil and gas.
Other Areas
Licence terms
See "Item 4.D—Developed and undeveloped acreage" for the total gross and net developed and undeveloped acreage of
our natural oil and gas assets by geographic area, in tabular format, at 30 June 2016.
Australia
In Australia, we have interests in one offshore exploration licence and three onshore exploration licences.
Offshore
in the Northwest Shelf of Australia, our subsidiary Sasol Petroleum Australia Limited (SPAL) holds a 30% working interest in the AC/P 52 licence (160,9 thousand
undeveloped net acres). The licence permit Year 6 has been suspended for a period of 24 months, until May 2017. The AC/P 52 licence holders will
46
Table of Contents
not
drill the commitment well during the suspension period.
Onshore
in the Beetaloo Basin of Australia's Northern Territory, our subsidiary SPAL holds a 35% working interest in the EP76, EP98 and EP117 licences
(1 583,6 thousand undeveloped net acres). The licences are operated by Origin Energy Resources Limited. Our farm-in to these licences was concluded in August 2014 and in return we
pay 50% of the stage one work programme costs, carrying Falcon Oil & Gas Limited. The remaining commitments in the stage one work programme include two vertical wells.
Nigeria
Our subsidiary, Sasol Exploration and Production Nigeria Limited (SEPNL), gave notice of our intention to withdraw from the OML 145
licence in Nigeria in May 2015. Once government approval is obtained, the relinquishment of our 5% working interest (16,9 thousand undeveloped net acres) will be completed.
South Africa
In South Africa, we have interests in one exploration licence and one licence which is in the process of being negotiated.
Our
subsidiary Sasol Africa (Pty) Ltd holds a 60% working interest in the ER236 licence (12 174,9 thousand undeveloped net acres), offshore in the Durban
Basin. The licence is operated by Eni South Africa BV. The initial three-year exploration period runs to November 2016 and the commitment work programme, which included the acquisition of 5
950km of 2D reconnaissance seismic data has been fulfilled. It is envisaged that we will enter the first licence extension period which runs from November 2016 to November 2018. Relinquishment of 20%
of the licence area will be required.
In
July 2015, our subsidiary Sasol Africa (Pty) Ltd and PetroSA were invited to commence negotiations for an Exploration Right over the 3A/4A area located offshore in the
Orange
Basin which was previously covered by a technical co-operation permit. On completion of the negotiations, Sasol Africa (Pty) Ltd and PetroSA, the operator, will each hold a 50% working
interest (2 645,1 thousand undeveloped net acres).
Activities
See "Item 4.D—Drilling Activities" for the number of net natural oil and gas wells completed in each of the last
three years and the number of wells being drilled or temporarily suspended at 30 June 2016.
Australia
In 2016, in the Beetaloo Basin, two vertical wells (Kalala S-1 and Amungee NW-1) and one horizontal well (Amungee NW-1H) were drilled
in the EP98 licence as part of the stage one work programme. Operations to re-enter and re-set casing in Amungee NW-1H well commenced in June 2016, and a multi-stage fracture stimulation programme
will be performed in August 2016 followed by a 90-day production test. The campaign to drill the remaining two vertical wells in the stage one work programme, in the EP117 licence, started in July
2016.
South Africa
The acquisition of a 3D seismic survey over the ER236 licence commenced in February 2016 and is expected to be completed in 2016.
Capitalised Exploratory Wells Costs
See Item 4D "Capitalised Exploratory Well Costs" for information, in tabular format, about the continued capitalisation of
exploratory well costs, at 30 June 2016.
Australia
At 30 June 2016, there are no exploratory well costs capitalised in the Beetaloo Basin licences. As such, costs capitalised at
the beginning of the year have been expensed.
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Nigeria
At 30 June 2016, there are no exploratory wells costs capitalised in the OML 145 licence.
South Africa
At 30 June 2016, there were no exploratory wells costs capitalised in the ER236 licence.
Tabular Natural Oil and Gas Information
Developed and Undeveloped Acreage
The table below provides total gross and net developed and undeveloped acreage for our natural oil and gas assets by geographic area at
30 June 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural oil and
gas acreage
concentrations at
30 June 2016
|
|
Mozambique(1)
|
|
South
Africa
|
|
Rest of
Africa(2)
|
|
North
America(1)(2)
|
|
Australasia(2)
|
|
Total
|
|
|
|
thousand acres
|
|
|
Developed acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
431,7
|
|
|
—
|
|
|
28,7
|
|
|
34,7
|
|
|
—
|
|
|
495,1
|
|
|
Net
|
|
|
302,2
|
|
|
—
|
|
|
8,0
|
|
|
17,3
|
|
|
—
|
|
|
327,5
|
|
|
Undeveloped acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
2 831,0
|
|
|
25 581,8
|
|
|
338
|
|
|
78,0
|
|
|
5 060,7
|
|
|
33 889,5
|
|
|
Net
|
|
|
1 893,3
|
|
|
14 820,1
|
|
|
16,9
|
|
|
39,0
|
|
|
1 744,4
|
|
|
18 513,7
|
|
-
(1)
-
Certain
licences in Mozambique and North America overlap as they relate to specific stratigraphic horizons.
-
(2)
-
Rest
of Africa consists of Gabon and Nigeria, North America consists of Canada, Australasia consists of Australia.
Drilling Activities
The table below provides the number of net wells completed in each of the last three years and the number of wells being drilled or
temporarily suspended at 30 June 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of wells(2) drilled for the
year ended 30 June
|
|
Mozambique(1)
|
|
Rest of
Africa(1)
|
|
North
America(1)
|
|
Australasia(1)
|
|
Total
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development well—productive(2)
|
|
|
—
|
|
|
0,3
|
|
|
12,5
|
|
|
—
|
|
|
12,8
|
|
|
Stratigraphic test well—exploratory type(3)
|
|
|
—
|
|
|
0,3
|
|
|
2,0
|
|
|
—
|
|
|
2,3
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development well—productive(2)
|
|
|
—
|
|
|
0,8
|
|
|
7,5
|
|
|
—
|
|
|
8,3
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development well—productive(2)
|
|
|
—
|
|
|
0,8
|
|
|
9,0
|
|
|
—
|
|
|
9,8
|
|
|
Stratigraphic test well—exploratory type(3)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,0
|
|
|
1,0
|
|
|
As at 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells being drilled(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
1,0
|
|
|
—
|
|
|
11,0
|
|
|
—
|
|
|
12,0
|
|
|
Net
|
|
|
1,0
|
|
|
—
|
|
|
5,5
|
|
|
—
|
|
|
6,5
|
|
|
Temporarily Suspended wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
—
|
|
|
—
|
|
|
8,0
|
|
|
—
|
|
|
8,0
|
|
|
Net
|
|
|
—
|
|
|
—
|
|
|
4,0
|
|
|
—
|
|
|
4,0
|
|
-
(1)
-
Rest
of Africa comprises Gabon and Nigeria, North America comprises Canada, Australasia comprises Australia.
-
(2)
-
A
productive well is an exploratory or development well that is not a dry well. 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.
-
(3)
-
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.
-
(4)
-
The
number of wells being drilled includes wells that have been drilled, but have not yet been mechanically completed.
Capitalised Exploratory Well Costs
The table below provides details of the capitalised exploratory natural oil and gas well costs, in Mozambique (and Australia in 2015
and 2014), at the end of the last three years, showing additions, costs charged to expense and cost reclassified. This table is presented in accordance with the International Financial Reporting
Standards in order to ensure consistency between this document and the Annual Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
(Rand in millions)
|
|
|
Capitalised Exploratory Well Costs
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year
|
|
|
1 670,2
|
|
|
1 351,9
|
|
|
1 560,7
|
|
|
Additions for the year
|
|
|
1 588,7
|
|
|
511,8
|
|
|
203,5
|
|
|
Costs incurred
|
|
|
897,8
|
|
|
583,7
|
|
|
248,8
|
|
|
Asset retirement obligation adjustments
|
|
|
690,9
|
|
|
(71,9
|
)
|
|
(45,3
|
)
|
|
Charged to expense for the year
|
|
|
(320,0
|
)
|
|
—
|
|
|
(135,9
|
)
|
|
Farm down proceeds
|
|
|
(112,0
|
)
|
|
—
|
|
|
—
|
|
|
Exiting of licences
|
|
|
—
|
|
|
(200,7
|
)
|
|
—
|
|
|
Reclassified exploratory well costs
|
|
|
(2 620,3
|
)
|
|
—
|
|
|
(292,3
|
)
|
|
Translation of foreign entities
|
|
|
73,2
|
|
|
7,2
|
|
|
15,9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
|
279,8
|
|
|
1 670,2
|
|
|
1 351,9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 Capitalised exploratory well cost
ageing
|
|
Mozambique
(Rand in millions)
|
|
|
1 to 5 years
|
|
|
—
|
|
|
over 5 years
|
|
|
58,2
|
|
|
Number of projects
|
|
|
1
|
|
Oil and Gas Production Facilities and Productive Wells
We operate production facilities in Mozambique and have non-operating interests in producing assets in Canada and Gabon.
The
table below provides the production capacity at 30 June 2016.
|
|
|
|
|
|
|
Plant Description
|
|
Location
|
|
Design Capacity
|
|
Central Processing Facility
|
|
Pande-Temane PPA, Mozambique
|
|
450 MMscf/day gas
|
|
Floating, Production, Storage and Offloading facility
|
|
Etame Marin Permit, Gabon
|
|
25 000 bpd oil
|
|
Processing Facilities
|
|
Farrell Creek, Canada
|
|
320 MMscf/day gas
|
The
table below provides the number of productive oil and gas wells at 30 June 2016. A
48
Table of Contents
productive
well is a producing well or a well that is mechanically capable of production.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of productive
wells 30 June 2016
|
|
Mozambique
|
|
North
America(1)
|
|
Rest of
Africa(1)
|
|
Total
|
|
|
Productive oil wells (number)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
|
Net
|
|
|
|
|
|
|
|
|
2,8
|
|
|
2,8
|
|
|
Productive gas wells (number)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
24
|
|
|
169
|
|
|
—
|
|
|
193
|
|
|
Net
|
|
|
16,8
|
|
|
84,5
|
|
|
—
|
|
|
101,3
|
|
-
(1)
-
Rest
of Africa comprises Gabon and Nigeria, North America comprises Canada.
Proved Reserves and Production
The proved developed and proved undeveloped reserves of natural oil and gas as at 30 June 2016 and the two previous years along
with volumes produced during the year are contained in the Natural Gas and Oil supplemental information, in Table 4, on page G-4.
Sales Prices and Production Costs
The table below summarises the average sales prices for natural gas and petroleum liquids 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 sale prices and
production costs (Rand per
unit) for the year ended
30 June
|
|
Mozambique
|
|
North
America(2)
|
|
Rest of
Africa(2)
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, per thousand standard cubic feet
|
|
|
23,9
|
|
|
38,4
|
|
|
—
|
|
|
Natural liquids, per barrel
|
|
|
863,1
|
|
|
627,8
|
|
|
989,4
|
|
|
Average production cost(1)
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, per thousand standard cubic feet
|
|
|
4,9
|
|
|
21,4
|
|
|
—
|
|
|
Natural liquids, per barrel
|
|
|
—
|
|
|
—
|
|
|
301,5
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, per thousand standard cubic feet
|
|
|
30,9
|
|
|
28,3
|
|
|
—
|
|
|
Natural liquids, per barrel
|
|
|
489,5
|
|
|
385,7
|
|
|
614,2
|
|
|
Average production cost(1)
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, per thousand standard cubic feet
|
|
|
10,0
|
|
|
7,4
|
|
|
—
|
|
|
Natural liquids, per barrel
|
|
|
—
|
|
|
—
|
|
|
308,9
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, per thousand standard cubic feet
|
|
|
25,1
|
|
|
20,0
|
|
|
|
|
|
Natural liquids, per barrel
|
|
|
106,4
|
|
|
361,6
|
|
|
574,3
|
|
|
Average production cost(1)
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, per thousand standard cubic feet
|
|
|
3,9
|
|
|
9,1
|
|
|
—
|
|
|
Natural liquids, per barrel
|
|
|
—
|
|
|
—
|
|
|
489,4
|
|
-
(1)
-
Average
production costs per unit of production are calculated according to the primary sales product.
-
(2)
-
North
America comprises Canada, Rest of Africa comprises Gabon
Supplemental oil and gas information
Supplemental oil and gas information: See "Item 18—Financial Statements—Supplemental Oil and Gas
Information" for supplemental information relating to natural oil and gas producing activities.
Energy—Plants and Facilities
Our Secunda facilities
Our main manufacturing facilities are located at Secunda, the base for our Secunda Synfuels Operations and a range of our chemical
industries operations. The size of this total property is approximately 82,5 square kilometres (km
2
) with operating plants accounting for 8,35 km
2
.
Our Sasolburg facilities
The size of the Natref refinery, based in Sasolburg, is approximately 2,0 km
2
.
49
Table of Contents
Our interests in facilities in Qatar
ORYX GTL is a gas-to-liquids plant, located at Ras Laffan Industrial City, situated along the northeast coast of Qatar.
Production capacity
The table below provides details of the production capacity and location of main gas plants of the Energy business.
|
|
|
|
|
|
|
Plant description
|
|
Location
|
|
Design
capacity(1)
|
|
Gauteng transmission network
|
|
Gauteng
|
|
128 bscf/a
|
|
Rompco Pipeline
|
|
From Central Processing Facility (Mozambique) to Pressure Protection Station (Secunda) (865km)
|
|
169 bscf/a
|
|
Secunda, Witbank and Middelburg pipeline
|
|
South Africa
|
|
11 bscf/a
|
|
Transnet Pipeline transmission pipeline
|
|
South Africa
|
|
23 bscf/a
|
-
(1)
-
Nameplate
capacity represents the total saleable production capacity. Due to the integrated nature of these facilities, the requirement for regular
statutory maintenance shutdowns and market conditions, actual saleable volumes will be less than the nameplate
The
following table provides details of the production capacity and location of the main joint arrangement plants where the Energy business has an interest.
|
|
|
|
|
|
|
Plant description
|
|
Location
|
|
Design capacity(1)
|
|
ORYX GTL
|
|
Ras Laffan Industrial City in Qatar
|
|
32 400 bpd (nominal)
|
|
EGTL
|
|
Escravos, Nigeria
|
|
33 200 bpd (nominal)
|
|
Natref
|
|
Sasolburg, South Africa
|
|
108 000 bpd (nominal)
|
|
CTRG
|
|
Ressano Garcia, Mozambique
|
|
175MW
|
-
(1)
-
Nameplate
capacity represents the total saleable production capacity. Due to the integrated nature of these facilities, the requirement for regular
statutory maintenance shutdowns and market conditions, actual saleable volumes will be less than the nameplate.
Secunda Synfuels operations
Synthetic oil
Refer to "Item 4. D Property, plants and equipment—Mining" for details on our mining properties and coal exploration
techniques used during the estimation of synthetic oil reserves.
The
following table sets forth a summary of the synthetic oil equivalent average sales price and related production costs for the year shown:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
Average sales price per barrel (Rand per unit)
|
|
|
635,85
|
|
|
869,72
|
|
|
1 126,88
|
|
|
Average production cost per barrel (Rand per unit)
|
|
|
359,75
|
|
|
280,88
|
|
|
372,20
|
|
|
Production (millions of barrels)
|
|
|
51,6
|
|
|
51,8
|
|
|
51,7
|
|
Supplemental oil and gas information
Supplemental oil and gas information: See "Item 18—Financial Statements—Supplemental Oil and Gas
Information" for supplemental information relating to synthetic oil producing activities.
Base Chemicals
Our Secunda facilities
Our main manufacturing facilities are located at Secunda, the base for our Secunda Chemicals Operations and the Secunda Synfuels
Operations. The size of this total property is approximately 82,5 square kilometres (km
2
) with operating plants accounting for 8,35 km
2
.
Our Sasolburg facilities
Our facilities at Sasolburg are the base for a number of our chemical industries operations. The size of these properties is
approximately 51,4 km
2
.
The
following table summarises the main production capacities of the Regional Operating Hubs that produce polymer and monomer products marketed by Base Chemicals.
50
Table of Contents
Production capacity at 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Product
|
|
South
Africa(2)
|
|
Malaysia(1)(2)
|
|
Total
|
|
|
|
(ktpa)
|
|
|
Ethylene
|
|
|
615
|
|
|
72
|
|
|
687
|
|
|
Propylene
|
|
|
950
|
|
|
11
|
|
|
961
|
|
|
LDPE
|
|
|
220
|
|
|
102
|
|
|
322
|
|
|
LLDPE
|
|
|
150
|
|
|
—
|
|
|
150
|
|
|
Polypropylene-1
|
|
|
250
|
|
|
—
|
|
|
250
|
|
|
Polypropylene-2
|
|
|
375
|
|
|
—
|
|
|
375
|
|
|
Ethylene dichloride
|
|
|
160
|
|
|
—
|
|
|
160
|
|
|
Vinyl chloride
|
|
|
205
|
|
|
—
|
|
|
205
|
|
|
PVC
|
|
|
190
|
|
|
—
|
|
|
190
|
|
|
Chlorine
|
|
|
145
|
|
|
—
|
|
|
145
|
|
|
Caustic soda
|
|
|
167
|
|
|
—
|
|
|
167
|
|
|
Cyanide
|
|
|
40
|
|
|
—
|
|
|
40
|
|
|
Hydrochloric acid
|
|
|
90
|
|
|
—
|
|
|
90
|
|
|
Calcium chloride
|
|
|
10
|
|
|
—
|
|
|
10
|
|
-
(1)
-
Includes
our attributable share of the production capacity of joint operations.
-
(2)
-
Nameplate
capacity represents the total saleable production capacity. Due to the integrated nature of these facilities, the requirement for regular
statutory maintenance shutdowns and market conditions, actual saleable volumes will be less than the nameplate capacity.
The
following table summarises the main production capacities of the Regional Operating Hubs that produce solvent products marketed by Base Chemicals:
Production capacity as at 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Product
|
|
South
Africa
|
|
Germany
|
|
Total(1)
|
|
|
|
(ktpa)
|
|
|
Ethylene
|
|
|
293
|
|
|
—
|
|
|
293
|
|
|
•
Acetone
|
|
|
175
|
|
|
—
|
|
|
175
|
|
|
•
MEK
|
|
|
60
|
|
|
—
|
|
|
60
|
|
|
•
MiBK
|
|
|
58
|
|
|
—
|
|
|
58
|
|
|
Glycol ethers
|
|
|
—
|
|
|
80
|
|
|
80
|
|
|
•
Butyl glycol
ether
|
|
|
—
|
|
|
80
|
|
|
80
|
|
|
Acetates
|
|
|
54
|
|
|
—
|
|
|
54
|
|
|
•
Ethyl
acetate
|
|
|
54
|
|
|
—
|
|
|
54
|
|
|
Mixed alcohols
|
|
|
215
|
|
|
—
|
|
|
215
|
|
|
Pure alcohols
|
|
|
473
|
|
|
—
|
|
|
473
|
|
|
•
Methanol (C
1
)
|
|
|
140
|
|
|
—
|
|
|
140
|
|
|
•
Ethanol (C
2
)
|
|
|
114
|
|
|
—
|
|
|
114
|
|
|
•
n-Propanol
(C
3
)
|
|
|
54
|
|
|
—
|
|
|
54
|
|
|
•
Isopropanol
(C
3
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
•
n-Butanol
(C
4
)
|
|
|
150
|
|
|
—
|
|
|
150
|
|
|
•
iso-Butanol
(C
4
)
|
|
|
15
|
|
|
—
|
|
|
15
|
|
|
Acrylates
|
|
|
125
|
|
|
—
|
|
|
125
|
|
|
•
Ethyl
acrylate
|
|
|
35
|
|
|
—
|
|
|
35
|
|
|
•
Butyl
acrylate
|
|
|
80
|
|
|
—
|
|
|
80
|
|
|
•
Glacial acrylic acid
|
|
|
10
|
|
|
—
|
|
|
10
|
|
|
Maleic anhydride
|
|
|
—
|
|
|
53
|
|
|
53
|
|
|
Other
|
|
|
19
|
|
|
—
|
|
|
19
|
|
-
(1)
-
Consolidated
nameplate capacities excluding internal consumption and including our attributable share of the production capacity of our Sasol Huntsman joint
venture.
Nameplate
capacity represents the total saleable production capacity. Due to the integrated nature of these facilities, the requirement for regular statutory maintenance shutdowns and market
conditions, actual saleable volumes will be less than the nameplate capacity.
Approximately
90% of our production capacity is located at sites in South Africa and 10% in Germany.
Our facilities in the United States
Construction of our 50% joint venture high-density polyethylene plant with Ineos Olefins and Polymers USA continues to make good
progress, and is on track for completion in the second half of the 2016 calendar year. Upon completion, the plant will be the largest bimodal HDPE manufacturing facility in the US with a nameplate
capacity of 470 kilotons annually.
51
Table of Contents
Base Chemicals' share of the LCCP, currently being constructed, is located at Lake Charles, Louisiana (site size approximately 3 million m
2
;
plant size 540 000m
2
).
Refer
to "Item 3.D—Risk factors" and "Item 5.B—Capital Commitments" for further detail on the construction of the LCCP.
Performance Chemicals
Our facilities at Secunda and Sasolburg are the base for a number of our chemical industries operations. The size of these properties
are approximately 82,5km
2
and 51,4 km
2
, respectively.
Performance Chemicals operations are based at three locations in Germany, namely Brunsbüttel (site size approximately
2,0 million m
2
; plant size 500 000 m
2
), Marl (site size approximately 160 000 m
2
; plant size
75 000 m
2
) and the Wax facility based in Hamburg (site size approximately 160 000 m
2
; plant size
100 000 m
2
).
The operations of Performance Chemicals are based at three locations in Italy. The primary facilities are at Augusta (site size
approximately 1,36 million m
2
; plant size 510 000 m
2
) and Terranova (site size approximately 330 000 m
2
; plant size
160 000 m
2
).
Various Performance Chemicals operations are based at a number of locations in the US. The most significant of these facilities is
located at Lake Charles, Louisiana (site size approximately 3 million m
2
; plant size 540 000 m
2
).
Performance
Chemicals also has phenolics operations based at Oil City, Pennsylvania; Houston and Winnie, Texas; and Tucson, Arizona.
Production capacity at 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
Product
|
|
Facilities location
|
|
Total(1)
|
|
|
|
|
|
(ktpa)
|
|
|
Surfactants
|
|
United States, Europe, Far East
|
|
|
1 000
|
|
|
|
C
6+
alcohol
|
|
United States, Europe, South Africa, Far East
|
|
|
630
|
|
|
|
Ethylene
|
|
United States
|
|
|
455
|
|
|
|
Inorganics
|
|
United States, Europe
|
|
|
70
|
|
|
|
Paraffins and olefins
|
|
United States, Europe
|
|
|
750
|
|
|
|
LAB
|
|
United States, Europe
|
|
|
435
|
|
|
|
C
5
-C
8
alpha olefins
|
|
United States, South Africa
|
|
|
456
|
|
|
|
Paraffin wax and wax emulsions
|
|
Europe
|
|
|
430
|
|
|
|
FT-based wax and related products
|
|
South Africa
|
|
|
280
|
|
|
|
Paraffin wax
|
|
South Africa
|
|
|
30
|
|
|
-
(1)
-
Nameplate
capacity represents the total saleable production capacity. Due to the integrated nature of these facilities, the requirement for regular
statutory maintenance shutdowns and market conditions, actual saleable volumes will be less than the nameplate capacity.
Performance
Chemicals' share of the LCCP, currently being constructed, is located at Lake Charles, Louisiana (site size approximately 3 million m
2
; plant size 540
000m
2
.
Refer
to "Item 3.D—Risk factors" and "Item 5.B—Capital Commitments" for further detail on the construction of the LCCP.
ITEM 4A. UNRESOLVED STAFF COMMENTS
There are no unresolved written comments from the SEC staff regarding our periodic reports under the Securities Exchange Act of 1934
received not less than 180 days before 30 June 2016, that are considered material.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
This section should be read in conjunction with our consolidated financial statements included in "Item 18—Annual
Financial Statements" as at 30 June 2016 and 2015, and for the years ended 30 June 2016, 2015 and 2014, including the accompanying notes, that are included in this annual report on
Form 20-F. The following discussion of operating results and the financial review and prospects as well as our consolidated financial statements have been prepared in accordance with IFRS as
issued by the IASB.
For
information regarding our financial overview and external factors impacting on our business, refer to the "CFO Report—Key financial risks and uncertainties affecting
performance" as contained in Exhibit 99.3. This
52
Table of Contents
includes
an analysis of the impact of macroeconomic factors on Sasol's performance and an overview of the current economic environment, crude oil prices, exchange rates, gas prices and chemical
prices. Movements in our cost base are also analysed, including the impact of cost reduction measures and inflation.
Certain
information contained in the discussion and analysis set forth below and elsewhere in this annual report includes forward-looking statements that involve risks and uncertainties.
See "Forward-Looking Statements". See "Item 3.D—Key information—Risk factors" for a discussion of significant factors that could cause actual results to differ
materially from the results described in or implied by the forward-looking statements contained in this annual report.
5.A Operating results
Results of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/2015
|
|
2014
|
|
Change
2015/2014
|
|
|
|
(Rand
in millions)
|
|
(%)
|
|
(Rand
in millions)
|
|
(%)
|
|
|
Turnover
|
|
172 942
|
|
185 266
|
|
|
(7
|
)
|
|
|
202 683
|
|
|
|
(9
|
)
|
|
|
Operating costs and expenses
|
|
(136 320
|
)
|
(139 967
|
)
|
|
(3
|
)
|
|
|
(153 380
|
)
|
|
|
(9
|
)
|
|
|
Remeasurement items
|
|
(12 892
|
)
|
(807
|
)
|
|
1 498
|
|
|
|
(7 629
|
)
|
|
|
(89
|
)
|
|
|
Share of profit of equity accounted investments, net of tax
|
|
509
|
|
2 057
|
|
|
(75
|
)
|
|
|
4 144
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
24 239
|
|
46 549
|
|
|
(48
|
)
|
|
|
45 818
|
|
|
|
2
|
|
|
|
Net finance costs
|
|
(521
|
)
|
(956
|
)
|
|
(46
|
)
|
|
|
(705
|
)
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit before tax
|
|
23 718
|
|
45 593
|
|
|
(48
|
)
|
|
|
45 113
|
|
|
|
1
|
|
|
|
Taxation
|
|
(8 691
|
)
|
(14 431
|
)
|
|
(40
|
)
|
|
|
(14 696
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit
|
|
15 027
|
|
31 162
|
|
|
(52
|
)
|
|
|
30 417
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial review 2016
-
•
-
For information regarding our financial condition, and an overview of our results refer "CFO Report—Financial performance"
as contained in Exhibit 99.3.
-
•
-
For information on changes in our financial condition, and overall financial performance refer "CFO Report—Financial
performance—Key drivers impacting operating profit" as contained in Exhibit 99.3.
Turnover
Turnover consists of the following categories:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/2015
|
|
2014
|
|
Change
2015/2014
|
|
|
|
(Rand
in millions)
|
|
(%)
|
|
(Rand
in millions)
|
|
(%)
|
|
|
Sale of products
|
|
170 830
|
|
183 935
|
|
|
(7
|
)
|
|
|
200 960
|
|
|
|
(8
|
)
|
|
|
Services rendered
|
|
1 695
|
|
998
|
|
|
70
|
|
|
|
1 082
|
|
|
|
(8
|
)
|
|
|
Other trading income
|
|
417
|
|
333
|
|
|
25
|
|
|
|
641
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Turnover
|
|
172 942
|
|
185 266
|
|
|
(7
|
)
|
|
|
202 683
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
primary factors contributing to the decreases in turnover were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
2016/2015
|
|
Change
2015/2014
|
|
|
|
(Rand in
millions)
|
|
(%)
|
|
(Rand in
millions)
|
|
(%)
|
|
|
Turnover, 2015 and 2014
|
|
|
185 266
|
|
|
|
|
|
|
|
202 683
|
|
|
|
|
|
|
|
Exchange rate effects
|
|
|
23 565
|
|
|
|
13
|
|
|
|
6 161
|
|
|
|
3
|
|
|
|
Product prices
|
|
|
(32 442
|
)
|
|
|
(18
|
)
|
|
|
(27 439
|
)
|
|
|
(14
|
)
|
|
|
—crude oil
|
|
|
(26 120
|
)
|
|
|
(14
|
)
|
|
|
(21 493
|
)
|
|
|
(11
|
)
|
|
|
—other products
|
|
|
(6 322
|
)
|
|
|
(4
|
)
|
|
|
(5 946
|
)
|
|
|
(3
|
)
|
|
|
Net volume changes
|
|
|
(3 413
|
)
|
|
|
(2
|
)
|
|
|
3 390
|
|
|
|
2
|
|
|
|
Other effects
|
|
|
(34
|
)
|
|
|
—
|
|
|
|
471
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Turnover
|
|
|
172 942
|
|
|
|
(7
|
)
|
|
|
185 266
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
Operating costs and expense consists of the following categories:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/2015
|
|
2014
|
|
Change
2015/2014
|
|
|
|
(Rand
in millions)
|
|
(%)
|
|
(Rand
in millions)
|
|
(%)
|
|
|
Materials, energy and consumable used
|
|
(71 320
|
)
|
(80 169
|
)
|
|
(11
|
)
|
|
|
(89 244
|
)
|
|
|
(10
|
)
|
|
|
Selling and distribution costs
|
|
(6 914
|
)
|
(6 041
|
)
|
|
15
|
|
|
|
(5 762
|
)
|
|
|
5
|
|
|
|
Maintenance expenditure
|
|
(8 453
|
)
|
(7 628
|
)
|
|
11
|
|
|
|
(8 290
|
)
|
|
|
(8
|
)
|
|
|
Employee-related expenditure
|
|
(23 911
|
)
|
(22 096
|
)
|
|
8
|
|
|
|
(28 569
|
)
|
|
|
(23
|
)
|
|
|
Exploration expenditure and feasibility costs
|
|
(282
|
)
|
(554
|
)
|
|
(49
|
)
|
|
|
(604
|
)
|
|
|
(8
|
)
|
|
|
Depreciation and amortisation
|
|
(16 367
|
)
|
(13 567
|
)
|
|
21
|
|
|
|
(13 516
|
)
|
|
|
—
|
|
|
|
Translation gains/ (losses)
|
|
1 070
|
|
(1 115
|
)
|
|
196
|
|
|
|
798
|
|
|
|
(240
|
)
|
|
|
Other operating expenses
|
|
(11 635
|
)
|
(10 164
|
)
|
|
15
|
|
|
|
(12 522
|
)
|
|
|
(19
|
)
|
|
|
Other operating income
|
|
1 492
|
|
1 367
|
|
|
9
|
|
|
|
4 309
|
|
|
|
(68
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
(136 320
|
)
|
(139 967
|
)
|
|
(3
|
)
|
|
|
(153 380
|
)
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Materials, energy and consumables used.
Materials, energy and consumables used in 2016 amounted to R71 320 million, a
decrease of
R8 849 million, or 11%, compared with R80 169 million in 2015, which decreased by 10% from R89 224 million in 2014. The decrease in 2016 and
2015, as compared to 2014, was due to the continued decline in crude oil prices,
53
Table of Contents
partially
offset by higher production volumes at Secunda Synfuels Operations and Natref operations.
Selling and distribution costs.
These costs comprise of marketing and distribution of products, freight and customs and excise duty
after the point
of sale. Selling and distribution costs in 2016 amounted to R6 914 million, which represents an increase of R873 million, or 15%, compared with
R6 041 million in 2015, which increased by R279, or 5%, million compared with R5 762 million in 2014. The variation in these costs was mainly
attributable to the weaker rand against major currencies, which impacted our foreign operations during 2016. Selling and distribution costs represented 4% of sales in 2016, and 3% of sales in 2015 and
2014.
Maintenance expenditure.
Maintenance expenditure in 2016 amounted to R8 453 million, which represents an increase of
R825 million, or 11%, compared with R7 628 million in 2015, which decreased by R662 million, or 8%, compared with R8 290 million in 2014. The
increase in maintenance expenditure in 2016 compared to 2015 is largely due to the weakening of the exchange rate against major currencies, planned extended shutdowns in Sasolburg and the US, as well
as well workovers amounting to R133 million in Gabon. The reduction in maintenance expenditure in 2015 was mainly due to the implementation of our BPEP and Response Plan initiatives to reduce
cash costs, without compromising on the safety, reliability and the sustainability of our operations.
Employee related expenditure.
Employee related expenditure amounted to R23 911 million, which represents an increase of
R1 815 million, or 8%, compared with R22 096 million in 2015, which decreased by R6 473 million, or 23%, from 2014.
This
amount includes labour costs of R23 540 million (2015—R23 478 million and 2014—R23 814 million)
and a cash settled share-based payment charge to the income statement of R371 million, (2015—R1 161 million (credit) and
2014—R5 652 million (expense)). In 2015,
the
credit was largely due to a 29% decrease in the share price.
Excluding
the effect of the share-based payment expenses, our employee costs increased by only R61 million in 2016. This was primarily due to our BPEP and RP, whereby at
30 June 2016, a total of approximately 2 500 voluntary separations and early retirement applications were approved by the company. Overall headcount reduced from
35 400 in 2013 to 30 100 employees at the end of the 2016 year, a net reduction of 15%.
Exploration expenditure and feasibility costs.
Exploration expenditure and feasibility costs in 2016
amounted to R282 million, which represents a decrease of R272 million, or 49%, compared with R554 million in 2015, which decreased by R50 million compared with
R604 million in 2014. The decrease in 2016 and 2015, as compared to 2014 was due to the implementation of our BPEP and RP initiatives, where we focused on reducing our exploration spend.
Depreciation and amortisation.
Depreciation and amortisation in 2016 amounted to R16 367 million, which represents an
increase of
R2 800 million, compared with R13 567 million in 2015, which increased by R51 million compared with R13 516 million in 2014. The
increase in depreciation and amortisation in 2016 compared to 2015 is mainly due to the increase in assets that reached beneficial operations in 2016 at Secunda Synfuels operations, Mining and Base
Chemicals, as well as the impact of the weaker rand/US dollar exchange rate. In addition, our Gabon assets recorded higher depreciation (R779 million), due to lower reserves being declared, on
the back of a lower oil price.
In
2015, the extension of the useful life of our operating assets in South Africa resulted in a decrease in depreciation of R1,4 billion, which was offset by the increase in
depreciation of assets that reached beneficial operations during the year in Secunda Synfuels Operations, Mining and Performance Chemicals.
Translation gains/(losses).
Translation gains arising primarily from the translation of
54
Table of Contents
monetary
assets and liabilities amounted to R1 070 million in 2016, as compared to a R1 115 million loss in 2015 and a R798 million gain in 2014. The
gain recognised in 2016 includes gains on the valuation of the open Canadian forward exchange contracts amounting to R48 million which were entered into to protect our capital investments
against foreign currency risk.
The
closing rate is used to translate, to rand, all our monetary assets and liabilities denominated in a currency other than the rand at the reporting date and, as a result, a net gain
was recognised on these translations in 2016 and 2014. The strengthening of the rand has a positive impact on the translation of our monetary liabilities, while the weakening of the rand has a
positive impact on the translation of our monetary assets
Other operating expenses.
Other operating expenses in 2016 amounted to R11 635 million, an increase of
R1 471 million, compared to R10 164 million in 2015, which decreased by R2 358 million from R12 522 million in 2014.
This
amount includes:
-
•
-
rental expenses of R1 243 million (2015—R1 114 million and
2014—R1 141 million);
-
•
-
insurance costs of R457 million (2015—R542 million and 2014—R649 million);
-
•
-
computer costs of R1 832 million (2015—R1 614 million and
2014—R1 568 million);
-
•
-
hired labour of R893 million (2015—R804 million and 2014—R771 million);
-
•
-
restructuring costs associated mainly with our BPEP and RP initiatives of R235 million
(2015—R1 525 million and 2014—R714 million);
-
•
-
professional fees of R1 202 million (2015—R 1 227 million and
2014—R1 415 million);
-
•
-
commodity gains of (R330 million) (2015—(R473 million) and 2014—losses of R253 million;
-
•
-
movements in rehabilitation provisions of R1 946 million (2015—(R1 722 million)
and 2014—R86 million);and
-
•
-
other expenses of R6 368 million (2015—R5 980 million and
2014—R5 305 million).
In
2016, the reversal of a provision of R2,3 billion (US$166 million) based on a favourable ruling received from the Tax Appeal Tribunal in Nigeria relating to the Escravos
Gas-to-Liquids (EGTL) project was included against other operating expenses.
In
2015, the reversal of the administrative penalty of R534 million, which was imposed by the Competition Tribunal in June 2014 was included against other operating expenses.
Other operating income.
Other operating income in 2016 amounted to R1 492 million, which represents an increase of
R125 million, or 9%, compared with R1 367 million in 2015. In 2014, other operating income amounted to R4 309 million, mainly due to the European Union Cartel
fine reduction in that year.
Share of profits from equity accounted investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/2015
|
|
2014
|
|
Change
2015/2014
|
|
|
|
|
|
(%)
|
|
|
|
(Rand
in millions)
|
|
(%)
|
|
|
Profit before tax
|
|
|
378
|
|
|
2 333
|
|
|
(84
|
)
|
|
|
4 312
|
|
|
|
(46
|
)
|
|
|
Tax
|
|
|
131
|
|
|
(276
|
)
|
|
147
|
|
|
|
(168
|
)
|
|
|
(64
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share of equity accounted profit, net of tax
|
|
|
509
|
|
|
2 057
|
|
|
(75
|
)
|
|
|
4 144
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remeasurement items, net of tax
|
|
|
13
|
|
|
1
|
|
|
1 200
|
|
|
|
(13
|
)
|
|
|
108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
share of profits of equity accounted investments (net of tax) amounted to R509 million in 2016 as compared to R2 057 million in 2015 and
R4 144 million in 2014. The decrease in share of profit of equity accounted investments in 2016 and 2015 is mainly due to lower oil prices and a planned shutdown at our ORYX GTL
facility, which resulted in a 75% decrease in earnings from R1 858 million in 2015 to R463 million in 2016. The ORYX GTL plant achieved an average utilisation rate of 81%
during the 2016 year. The Escravos gas-to-liquids (EGTL) plant in Nigeria,
55
Table of Contents
which
achieved beneficial operations (BO) in the 2015 financial year, continues to ramp up towards design capacity. Losses of R571 million were incurred relating to EGTL in 2016.
Remeasurement items
For information regarding the remeasurement items recognised, refer to "Item 18—Annual Financial
Statements—Note 8".
Finance costs and finance income
For information regarding finance costs incurred and finance income earned, refer to "Item 18—Annual Financial
Statements—Note 6".
The
increase in finance costs is due to the increase in the debt raised for the construction of the LCCP.
Tax
For information regarding the tax charge, refer to "Item 18—Annual Financial Statements—Note 12",
as well as the "CFO Report—Financial performance" as contained in Exhibit 99.3.
Non-controlling interests
For information regarding our non-controlling interests, and their share of profit, refer "Item 18—Annual Financial
Statements—Note 23".
Profit
attributable to non-controlling interests in subsidiaries of R1 802 million increased by R356 million, or 25%, from R1 446 million
in 2015; which was an increase of R609 million or 70% from R837 million in 2014.
The
increase in profit attributable to non-controlling interests in 2016, 2015 and 2014 is due to the higher profits earned in Mining, Sasol Oil and the Republic of Mozambique Pipeline
Investment Company (ROMPCO).
Financial review 2015
Group results
Operating profit of R46,5 billion increased by 2% compared to the prior year. This achievement was due to a strong overall
operational performance with increased sales volumes, resilient margins and cost increases contained to below inflation. Conversely, the group's profitability was adversely impacted by a 33% decline
in average Brent crude oil prices (average dated Brent was US$73,46/bbl for the year ended 30 June 2015 compared with US$109,40/bbl in the prior year). This decrease was partly off-set by a 10%
weaker average rand/US dollar exchange rate (R11,45/US$ for the year ended 30 June 2015 compared with R10,39/US$ in the prior year).
Items which materially impacted operating profit
During 2015, profitability was positively impacted by the following significant
items:
-
•
-
a cash-settled share-based payment credit to the income statement of R1,4 billion compared to an expense of R5,4 billion
in the prior year, largely due to a 29% lower share price (closing share price of R450,00 compared to R632,36 in the prior year), partially negated by the increase in the number of share options
exercised during the year;
-
•
-
the extension of the useful life of our operating assets in South Africa resulting in a decrease in depreciation of
R1,4 billion and environmental rehabilitation provisions of R1,8 billion; and
-
•
-
net remeasurement items expense of R0,8 billion in 2015, as compared to a R7,6 billion expense in the prior year. These
items relate mainly to the full reversal of the previous R2,0 billion impairment of the FT Wax Expansion Project, the partial impairment of our Canadian shale gas assets of R1,3 billion
and the partial impairment of our Etame assets in Gabon of R1,3 billion.
56
Table of Contents
Excluding
the impact of remeasurement items, net once-off charges and movements in our share-based payment expense, earnings attributable to shareholders decreased by 30%.
Financial review 2014
Group results
In 2014, operating profit was boosted by a 17% weaker average rand/US dollar exchange rate (R10,39/US$ for the year ended
30 June 2014 compared with R8,85/US$ in the prior year), and a progressive improvement in chemical prices, while the average Brent crude oil price remained relatively flat (average dated Brent
was US$109,40/bbl for the year ended 30 June 2014 compared with US$108,66/bbl in the prior year). Operating profit was negatively impacted by remeasurement items totaling R7,6 billion,
primarily consisting of the R5,3 billion (CAD540 million) partial impairment of our Canadian shale gas asset, and the R466 million (EUR32 million) partial impairment and
final loss on disposal of R966 million (EUR 67 million) of our Solvents Germany assets.
Segment review—results of operations
Segmental financial performance is measured on a management basis. This approach is based on the way in which the Joint Presidents and
Chief Executive Officers organise segments within our group for making operating decisions and assessing performance. The segment overview included below is based on our segment results. Inter-segment
turnover was entered into under terms and conditions substantially similar to terms and conditions which would have been negotiated with an independent third party. Refer to Business segment
information of "Item 18—Annual Financial statements" for further detail regarding turnover and Operating profit per segment.
Refer
also to "Integrated Report—Our Operating Model structure" as contained in Exhibit 99.4.
Operating Business Units
Mining
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/2015
|
|
2014
|
|
Change
2015/2014
|
|
|
|
(Rand
in millions)
|
|
(%)
|
|
(Rand
in millions)
|
|
(%)
|
|
|
External turnover
|
|
2 360
|
|
2 215
|
|
|
7
|
|
|
|
2 154
|
|
|
|
3
|
|
|
|
Inter-segment turnover
|
|
14 615
|
|
13 472
|
|
|
9
|
|
|
|
11 980
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total turnover
|
|
16 975
|
|
15 687
|
|
|
8
|
|
|
|
14 134
|
|
|
|
11
|
|
|
|
Operating costs and expenses(1)
|
|
(12 236
|
)
|
(11 344
|
)
|
|
8
|
|
|
|
(11 681
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
4 739
|
|
4 343
|
|
|
9
|
|
|
|
2 453
|
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin %
|
|
28
|
|
28
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
-
(1)
-
Operating
costs and expenses net of other income.
Results of operations 2016 compared to 2015
Total turnover increased by 8% from R15 687 million to R16 975 million. Operating profit of
R4 739 million represents an increase of 9% as compared to the prior year. Production volumes increased to 42,3 Mt for 2016 compared with 41,2 Mt in 2015. Normalised unit costs of
production were contained to 5% below inflation in 2016, following on from a 2% decrease in 2015 as compared to 2014.
Our
export volumes, primarily to Pakistan, India and Africa decreased by 6% to 3,2 million tons (Mt) (2015—3,4 Mt). Export sales represented approximately 14% of the
total turnover generated by Mining during 2016 (2015—14%).
For
further analysis of our results refer "Integrated Report—Operational reviews" as contained in Exhibit 99.7.
Results of operations 2015 compared to 2014
Total turnover increased by 11% from R14 134 million to R15 687 million. Operating profit
increased by 77% to R4 343 million compared to the prior year. This was mainly as a result of a 2% increase in productivity, the optimisation of production opportunities, benefits
of the BPEP of R569 million and higher export coal volumes, which was partially negated by lower export coal prices.
Production
volumes remained at 41,2 Mt for 2015 compared with 41,5 Mt in 2014.
Operating
costs and expenses decreased by 3%, mainly due to the BPEP initiative which focused on cost reduction. Normalised mining unit costs of production decreased by 2% compared to
the prior year.
57
Table of Contents
Exploration and Production International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/
2015
|
|
2014
|
|
Change
2015/
2014
|
|
|
|
(Rand in
millions)
|
|
(%)
|
|
(Rand in
millions)
|
|
(%)
|
|
|
External turnover
|
|
|
1 706
|
|
|
2 043
|
|
|
(17
|
)
|
|
2 990
|
|
|
(32
|
)
|
|
Inter-segment turnover
|
|
|
2 505
|
|
|
3 129
|
|
|
(20
|
)
|
|
2 218
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total turnover
|
|
|
4 211
|
|
|
5 172
|
|
|
(19
|
)
|
|
5 208
|
|
|
(1
|
)
|
|
Operating costs and expenses(1)
|
|
|
(15 925
|
)
|
|
(8 342
|
)
|
|
91
|
|
|
(11 188
|
)
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(11 714
|
)
|
|
(3 170
|
)
|
|
270
|
|
|
(5 980
|
)
|
|
(47
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin %
|
|
|
(278
|
)
|
|
(61
|
)
|
|
|
|
|
(115
|
)
|
|
|
|
-
(1)
-
Operating
costs and expenses net of other income including exploration costs and depreciation
Results of operations 2016 compared to 2015
Total turnover decreased by 19% from R5 172 million in 2015 to R4 211 million in 2016. The
business recorded an operating loss of R11 714 million compared to an operating loss of R3 170 million in the prior year.
Excluding
the partial impairment of our Canadian shale gas operations of R9 882 million (CAD880 million), which was recognised due to the continued decline in
gas prices, the business recorded a loss of R1 832 million.
In
Mozambique, production volumes increased by 5% as a result of our efforts to debottleneck the production facility, coupled with the increase in gas transportation capacity to
169 billion standard cubic feet (bscf), and a full volume offtake by our joint electricity operations in Mozambique.
The
lower oil price had a significant impact on our Gabon assets resulting in a loss of R994 million which includes the impact of higher depreciation (R779 million) due to
lower reserves being declared, on the back of a lower oil price. This is compared to a R1 124 million loss in the prior year, which included the partial impairment of the asset of
R1 331 million.
The
new development wells which were brought on line during the financial year resulted in a 16% higher average of 18 824 barrels of oil production per day (on a
gross basis) when compared to 16 284 barrels in the prior year.
Our
Canadian gas production volumes were 5% lower compared to the prior year due to reduced development activities, driven by lower oil and gas prices. Our Canadian operations produced
and sold 20,7 bscf of natural gas during 2016 compared to 21,8 bscf in 2015.
In
order to manage the shale gas asset through the low gas price environment, we concluded an agreement with our partner, Progress Energy, to settle the outstanding funding commitment of
R4 160 million (CAD380 million) and reduce the pace of appraisal, development and drilling activities. An 18-month reduced work programme was approved in June 2016. CAD305
million was paid in June 2016. The remaining CAD75 million will be paid on 1 July 2018. The carrying value of property, plant and equipment, and assets under construction relating to the shale
gas assets (after settlement of the carry obligation) is CAD800 million.
For
further analysis of our results refer "Integrated Report—Operational reviews" as contained in Exhibit 99.7.
Results of operations 2015 compared to 2014
Total turnover decreased by 1% from R5 208 million in 2014 to R5 172 million in 2015.
Our
Canadian operations produced and sold 21,8 billion standard cubic feet (bscf) of natural gas during 2015 compared to 21,3 bscf in 2014. Total condensate sales increased from
0,3 million bbl in 2014 to 0,5 million bbl in 2015. Oil production in Gabon was slightly lower and averaged 16 284 barrels of oil per day (on a gross basis).
The
business recorded a loss from operations of R3 170 million compared to a loss from operations of R5 980 million in the prior year. Excluding
the partial impairment of our Canadian shale gas operations of R1 296 million, the partial impairment reported during the first half of the financial year of
R1 331 million of our Etame assets in Gabon, and a loss of R569 million on exiting the Nigerian upstream licences, the business generated a profit of R26 million in
2015.
Our
Mozambican producing operations recorded a profit of R1 847 million (2014—R1 586 million), principally due to favourable gas
prices and a 13% increase in gas volumes, coupled with increased cost containment initiatives. Our Gabon assets recorded a loss of R1 124 million compared to a profit of
58
Table of Contents
R827 million
in the prior year due to lower oil prices.
Our
Canadian shale gas assets in Montney generated a loss from operations of R2 449 million compared to a loss of R7 003 million in 2014, which
included the partial impairment of the assets of R5 308 million (CAD540 million) in the prior year. Due to a further decline in gas prices in North America, we
recognised an additional partial impairment of R1 296 million (CAD133 million) on our Canadian shale gas operations during this year. Excluding the effect of the impairment,
the loss decreased to R1 153 million compared to R1 695 million in the prior year, mainly due to a lower depreciation rate and operational costs.
Despite
the impact of lower gas prices and weaker oil prices affecting the profitability of the business, E&PI was able to contribute more than R3 billion to Sasol's cash
conservation initiatives during the year through reduced capital cash flow and exploration spend and cash fixed cost savings.
Strategic Business Units
Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/
2015
|
|
2014
|
|
Change
2015/
2014
|
|
|
|
(Rand in
millions)
|
|
(%)
|
|
(Rand in
millions)
|
|
(%)
|
|
|
External turnover
|
|
|
63 818
|
|
|
75 264
|
|
|
(15
|
)
|
|
84 632
|
|
|
(11
|
)
|
|
Inter-segment turnover
|
|
|
523
|
|
|
536
|
|
|
(2
|
)
|
|
1 420
|
|
|
(62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total turnover
|
|
|
64 341
|
|
|
75 800
|
|
|
(15
|
)
|
|
86 052
|
|
|
(12
|
)
|
|
Operating costs and expenses(1)
|
|
|
(50 272
|
)
|
|
(53 274
|
)
|
|
(6
|
)
|
|
(54 629
|
)
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
|
14 069
|
|
|
22 526
|
|
|
(38
|
)
|
|
31 423
|
|
|
(28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin %
|
|
|
22
|
|
|
30
|
|
|
|
|
|
37
|
|
|
|
|
-
(1)
-
Operating
costs and expenses net of other income.
Results of operations 2016 compared to 2015
Total turnover decreased by 15% from R75 800 million in 2015 to R64 341 million in 2016, due to
the sharp decline in oil prices.
Operating
profit of R14 069 million decreased by R8 457 million or 38% compared to the prior year despite a 41% reduction in crude oil prices.
Operating margins held firm
at
22%, mainly as a result of record production volumes, higher liquid fuels sales through higher yielding marketing channels, the weaker rand/US dollar exchange rate and contributions from the BPEP
and RP initiatives.
Secunda
Synfuels Operations increased production volumes of refined product by 1%; to a record 7,8Mt. Natref Operations increased production volumes by 1% compared to the prior year.
Sales volumes, however, remained flat on the back of challenging market and trading conditions experienced during the first half of the financial year, driven by lower demand for liquid fuels in
Southern Africa, specifically in the agricultural, mining and manufacturing sectors.
Gas
sales volumes were 1% higher compared to the prior year, mainly due to higher methane-rich gas sales to commercial customers. Our share of the Central Termica de Ressano Garcia
(CTRG) joint operation in Mozambique delivered 653 089 megawatt-hours of electricity.
For
further analysis of our results refer "Integrated Report—Operational reviews" as contained in Exhibit 99.7.
Results of operations 2015 compared to 2014
Total turnover decreased by 12% from R86 052 million in 2014 to R75 800 million in 2015 due to
the sharp decline in oil prices. Operating profit of R22 526 million decreased by R8 897 million or 28% compared to the prior year. Production volumes of
refined products at Secunda Synfuels Operations and Natref operations increased by 2% and 6%, respectively, in comparison with the prior year. Secunda Synfuels Operations produced its highest
throughput levels since 2004 and Natref improved production on the back of improved operations stability compared to the previous financial year.
In
South Africa, Energy's profitability was enhanced by a 5% increase in liquid fuels sales volumes, compared to the prior year, and higher refining margins on the back of strong product
differentials. Despite the 33% decrease in oil prices, our gross margins in this business decreased by only 19% for the year. Through our BPEP, the business managed to contain our
59
Table of Contents
normalised
cash cost increase per unit for the full year to below SA PPI. Gas sales were 1% higher compared to the prior year and our Central Termica de Ressano Garcia joint operation in
Mozambique delivered 206 452 megawatt-hours of electricity. Operating costs and expenses decreased by 2% mainly due to the BPEP initiative which was aimed at reducing costs.
The
share of profit from equity accounted joint ventures of R1 941 million decreased from R3 710 million in the prior year. This was primarily due
to lower oil prices and an earlier than planned shutdown at our ORYX GTL facility. The plant achieved an average utilisation rate of 90%.
Base Chemicals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/
2015
|
|
2014
|
|
Change
2015/
2014
|
|
|
|
(Rand in
millions)
|
|
(%)
|
|
(Rand in
millions)
|
|
(%)
|
|
|
External turnover
|
|
|
33 696
|
|
|
36 838
|
|
|
(9
|
)
|
|
42 262
|
|
|
(13
|
)
|
|
Inter-segment turnover
|
|
|
1 371
|
|
|
2 890
|
|
|
(53
|
)
|
|
2 778
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total turnover
|
|
|
35 067
|
|
|
39 728
|
|
|
(12
|
)
|
|
45 040
|
|
|
(12
|
)
|
|
Operating costs and expenses(1)
|
|
|
(30 581
|
)
|
|
(29 520
|
)
|
|
4
|
|
|
(38 298
|
)
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
|
4 486
|
|
|
10 208
|
|
|
(56
|
)
|
|
6 742
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin %
|
|
|
13
|
|
|
26
|
|
|
|
|
|
15
|
|
|
|
|
-
(1)
-
Operating
costs and expenses net of other income.
Results of operations 2016 compared to 2015
Total turnover decreased by 12% from R39 728 million in 2015 to R35 067 million in 2016.
Excluding
the partial impairment of our low density polyethylene (LDPE) cash generating unit in the US of R956 million (US$65 million) and the R537 million
impairment of our methyl isobutyl ketone (MIBK) business in Sasolburg; Base Chemicals recorded an operating profit of R5 979 million.
The
operating margin decreased from 26% in the prior year to 13%. Sales volumes were down by 8% as a result of a planned extended shutdown to enable commissioning activities associated
with the C3 Expansion Project, subdued demand for explosives and fertilisers
and
a planned stock build. A 22% decrease in our basket of commodity chemical prices was partly negated by the weaker rand/US dollar exchange rate. In nominal terms, we reduced our cash fixed costs by
1,5% compared to the prior year.
For
further analysis of our results refer "Integrated Report—Operational reviews" as contained in Exhibit 99.7.
Results of operations 2015 compared to 2014
Total turnover decreased by 12% from R45 040 million in 2014 to R39 728 million in 2015. This
was primarily due to the sale of our Solvents Germany and Sasol Polymer Middle East operations in 2014. On a normalised basis, sales volume increased by 2%.
Base
Chemicals delivered a strong performance, increasing Operating profit by 51% to R10 208 million compared to the prior year. Normalised cash fixed costs were
contained to below inflation. The negative impact on margins, as a result of a 13% decline in dollar-based sales prices, was partly negated by the weaker rand/US dollar exchange rate. Chemical sales
prices displayed some resilience when compared to the crude oil prices over the same period.
Operating
profit further benefited from the reversal of the administrative penalty of R534 million, which was imposed by the South African Competition Tribunal in June 2014, and
the lower depreciation charge amounting to R684 million, which arose from the extension in the useful life of our operating assets in South Africa.
Performance Chemicals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
2016/
2015
|
|
2014
|
|
Change
2015/
2014
|
|
|
|
(Rand in
millions)
|
|
(%)
|
|
(Rand in
millions)
|
|
(%)
|
|
|
External turnover
|
|
|
71 254
|
|
|
68 874
|
|
|
3
|
|
|
70 592
|
|
|
(2
|
)
|
|
Inter-segment turnover
|
|
|
2 380
|
|
|
2 910
|
|
|
(18
|
)
|
|
2 982
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total turnover
|
|
|
73 634
|
|
|
71 784
|
|
|
3
|
|
|
73 574
|
|
|
(2
|
)
|
|
Operating costs and expenses(1)
|
|
|
(62 358
|
)
|
|
(59 070
|
)
|
|
6
|
|
|
(61 726
|
)
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
|
11 276
|
|
|
12 714
|
|
|
(11
|
)
|
|
11 848
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin %
|
|
|
15
|
|
|
18
|
|
|
|
|
|
16
|
|
|
|
|
-
(1)
-
Operating
costs and expenses net of other income.
60
Table of Contents
Results of operations 2016 compared to 2015
Turnover increased by 3% from R71 874 million to R73 634 million. Operating profit of
R11 276 million decreased by 11% compared to the prior year mainly as a result of the R2 021 million FT Wax Expansion Project (FTWEP) impairment reversal in the
prior year.
Our
operating margin reflects the full annual depreciation charge being recognised on FTWEP, while the project is still ramping up to full production. Excluding the impact of the
impairment reversal in the prior year, operating profit increased by 5%. This increase is largely as a result of the weakening of the rand, coupled with resilience of the margins achieved by our
European surfactants and alcohols businesses, negated by lower ethylene prices which negatively impacted the margins achieved by our assets in the US. Production volumes in our Eurasian Operations
increased by 4%, while production volumes at our US Operations remained flat compared to the prior year.
Total
sales volumes decreased marginally by 1% compared to the prior year, as a result of planned shutdowns at our ethylene plant in North America and our production facilities in
Sasolburg and reduced demand for oilfield chemicals. The decrease in wax and ammonia sales volumes were compensated by an increase of 4% in organic sales volumes. Normalised sales volumes were up by
1,8%.
For
further analysis of our results refer "Integrated Report—Operational reviews" as contained in Exhibit 99.7.
Results of operations 2015 compared to 2014
Turnover decreased by 2% from R73 574 million to R71 874 million, despite the 33% decline in
oil prices. The positive performance is largely as a result of a 2% increase in sales volumes mainly due to improved production output, higher demand, and resilient gross margins, supported by a
weaker rand/US dollar exchange rate.
Operating
profit increased by 7% to R12 714 million compared to R11 848 million for the prior year. The financial performance was positively
impacted by the R2 021 million impairment reversal of the FTWEP in Sasolburg
and
the weaker rand/US dollar exchange rate. Normalising for the impairment reversal and the R2 449 million payment received from the European Commission in the prior year,
Operating profit increased by 14% compared to the previous financial year.
In
base currency terms, cash fixed costs were maintained within inflation. Our business in the US realised favourable margins, despite a 33% decrease in oil prices, which negatively
impacted the results of our ethylene value chain. Our Eurasian Operations reported a 3% increase in production volumes.
Significant accounting policies and estimates
The preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported
results of its operations. Some of our accounting policies require the application of significant judgements and estimates by management in selecting the appropriate assumptions for calculating
financial estimates. By their nature, these judgements are subject to an inherent degree of uncertainty and are based on our historical experience, terms of existing contracts, management's view on
trends in the industries in which we operate and information from outside sources and experts. Actual results may differ from those estimates. Management believes that the more significant judgement
and estimates relating to the accounting policies used in the preparation of Sasol's consolidated financial statements could potentially impact the reporting of our financial results and future
financial performance.
We
evaluate our estimates, including those relating to environmental rehabilitation and decommissioning obligations, long-lived assets, trade receivables, inventories, investments,
intangible assets, income taxes, share-based payment expenses, pension and other post-retirement benefits and contingencies and litigation on an ongoing basis. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making our judgements about carrying values of assets and
61
Table of Contents
liabilities
that are not readily available from other sources.
In
addition to the items below, "Item 18—Annual Financial statements" are incorporated by reference.
For
accounting policies and areas of judgements relating to:
-
•
-
Valuation of share-based payments , refer "Item 18—Annual Financial statements"—Note 35 Cash
settled share appreciation rights and Note 36—Share-based payment reserve;
-
•
-
Impairments—refer "Item 18—Annual Financial statements—Note 8 Remeasurement items";
-
•
-
Long-term provisions—refer "Item 18—Annual Financial statements—Note 32 Long-term
provisions";
-
•
-
Post-retirement benefit obligations—refer "Item 18—Annual Financial
statements—Note 34 Post-retirement benefit obligations";
-
•
-
Useful economic lives of assets and depreciation of coal mining assets—"Item 18—Annual Financial
statements—Note 17 Property, plant and equipment, Note 18 Assets under construction and Note 19 Goodwill and other intangible assets";
-
•
-
Estimation of coal reserves—refer "Item 18—Annual Financial statements—Note 18
Assets under construction";
-
•
-
Recognition of deferred tax assets and utilisation of tax losses—refer "Item 18—Annual Financial
statements—Note 13 Deferred tax and Note 14 Tax paid";
Estimation of natural oil and gas reserves
In accordance with the United States Securities and Exchange Commission (SEC) regulations, proved oil and gas reserves are 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. Existing economic conditions define prices and costs at which economic producibility is to be determined. The price is the average sales price during the
12-month period prior to the reporting date (30 June), determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are
defined by contractual arrangements. Future price changes are limited to those provided by contractual arrangements in existence at year-end.
Our
reported natural oil and gas reserves are estimated quantities based on SEC reporting regulations. Additionally, we require that the estimated quantities of oil and gas and related
substances to be produced by a project be sanctioned by all internal and external parties to the extent necessary for the project to enter the execution phase and sufficient to allow the resultant
products to be brought to market. See "Item 4.D Information on the company—Property, plants and equipment".
There
are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production, including factors which are beyond our control. The accuracy
of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgement. Estimates of oil and gas reserves therefore are subject to future
revision, upward or downward, resulting from new data and current interpretation, as well as a result of improved recovery, extensions and discoveries, the purchase or sale of assets, and production.
Accordingly, financial and accounting measures (such as the standardised measure of future discounted cash flows, depreciation and amortisation charges and environmental and decommissioning
obligations) that are based on proved reserves are also subject to revision and change.
62
Table of Contents
Refer to "Standardised measure of discounted future net cash flows", on page G-6 for our standardised discounted future net cash flow information in
respect of proved reserves for the year ended 30 June 2016 and to "Changes in the standardised measure of discounted future net cash flows", on page G-7.
Depreciation of natural oil and gas assets
Depreciation of mineral assets on producing oil and gas properties and property acquisition costs is based on the units-of-production
method, calculated using estimated proved developed reserves.
Fair value estimations of financial instruments
We base fair values of financial instruments on quoted market prices of identical instruments, where available. If quoted market prices
are not available, fair value is determined based on other relevant factors, including dealers' price quotations and price quotations for similar instruments traded in different markets. Fair value
for certain derivatives is based on pricing models that consider current market and contractual prices for the underlying financial instruments or commodities, as well as the time value and yield
curve or fluctuation factors underlying the positions. Pricing models and their underlying assumptions impact the amount and timing of unrealised gains and losses recognised, and the use of different
pricing models or assumptions could produce different financial results. Refer to "Item 11—Quantitative and qualitative disclosures about market risk".
5.B Liquidity and capital resources
Liquidity, cash flows and borrowings
Management believes that cash on hand and funds from operations, together with our existing borrowing facilities, will be sufficient to
cover our working capital and debt service requirements in the year ahead. We finance our capital expenditure from funds generated out
of our business operations, existing borrowing facilities and, in some cases, additional borrowings to fund specific projects.
For
information regarding our funding cash flows and liquidity, refer "Item 18—Annual Financial Statements—Note 16—Long-term debt" which
includes an overview of our banking facilities and debt arrangements.
For
information regarding the company's cash flow requirements refer to the "CFO Report—Our cash flow generation and utilisation" and "Managing our funding strategy" as
contained in Exhibit 99.3.
The
following table provides a summary of our cash flows for each of the three years ended 30 June 2016, 2015 and 2014.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
(Rand in millions)
|
|
|
Net cash retained from operating activities
|
|
|
33 935
|
|
|
40 936
|
|
|
43 975
|
|
|
Net cash used in investing activities
|
|
|
(71 034
|
)
|
|
(42 085
|
)
|
|
(37 813
|
)
|
|
Net cash generated by financing activities
|
|
|
29 178
|
|
|
13 065
|
|
|
909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows retained from operating activities include the following significant items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
(Rand in millions)
|
|
|
Cash generated by operating activities
|
|
|
54 673
|
|
|
61 783
|
|
|
65 449
|
|
|
Income tax paid
|
|
|
(9 329
|
)
|
|
(10 057
|
)
|
|
(13 647
|
)
|
|
Dividends paid
|
|
|
(10 680
|
)
|
|
(12 739
|
)
|
|
(13 248
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
The
cash generated by our operating activities is applied first to fund our operations, pay our debt and tax commitments and then to provide a return in the form of a dividend to our
shareholders. The net cash retained is applied primarily to invest in our capital investment programme.
Cash generated by operating activities decreased by 12% to R54 673 million mainly as a result of a decrease in
turnover due to lower oil prices (average dated Brent was 41% lower at $43/bbl for the year ended 30 June 2016 compared with US$73/bbl in the prior year). The impact of low crude oil prices was
partially offset
63
Table of Contents
by
the weakening of the average rand/US dollar exchange rate, lower dividends and a reduction in cash costs, in line with our Response Plan.
In
2015, cash generated by operating activities decreased by 6% to R61 783 million from R65 449 million in 2014. This movement was also due to a
33% lower oil price in 2015 which impacted on turnover.
For
further information regarding our cash flow generation, refer "CFO Report—Our cash flow generation and utilisations" as contained in Exhibit 99.3.
Net cash utilised in investing activities has increased to R71 034 million in 2016, from
R42 085 million in 2015 and R37 813 million in 2014.
Included
in investing activities is the settlement of our funding commitment on the Canadian shale gas asset of R4,4 billion (CAD380 million). Included in additions to
non-current assets is R42,4 billion (US$2,9 billion) relating to the construction of the LCCP.
Cash
flows utilised in investing activities include the following significant items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
(Rand in millions)
|
|
|
Additions to non-current assets(1)
|
|
|
(67 158
|
)
|
|
(42 645
|
)
|
|
(38 779
|
)
|
|
Proceeds on disposals
|
|
|
569
|
|
|
1 210
|
|
|
1 538
|
|
-
(1)
-
Includes
additions to property, plant and equipment; assets under construction and other intangible assets.
For
information regarding cash flows from investing activities refer "CFO Report—"Managing our fund strategy" as contained in Exhibit 99.3.
For
information regarding cash flows from additions and disposals, refer "Item 18—Annual Financial Statements—Note 9 and Note 10".
For
details of our additions to non-current assets, and the projects to which these relate, refer to "Note 18—Assets under construction".
For
details of our capital commitments refer to "Note 17—Property, plant and equipment".
The group's operations are financed primarily by means of its operating cash flows. Cash shortfalls are usually short-term in nature
and are met primarily from short-term banking facilities. Our long-term capital expansion projects are financed by a combination of floating and fixed rate long-term debt, as well as internally
generated funds. This debt is normally financed in the same currency as the underlying project and the repayment terms are designed to match the cash flows expected from that project.
For
information regarding our debt and funding structure, refer "CFO Report—Managing our funding strategy" and "Managing our debt profile" as contained in
Exhibit 99.3.
Capital resources
Sasol Financing (Pty) Ltd and Sasol Financing International Limited act as our group's financing vehicles. All our group
treasury, cash management and borrowing activities are facilitated through Sasol Financing (Pty) Ltd and Sasol Financing International Limited. The group executive committee (GEC) and senior
management meet regularly, to review and, if appropriate, approve the implementation of optimal strategies for the effective management of the group's financial risk.
Our
cash requirements for working capital, share repurchases, capital expenditures, debt service and acquisitions over the past three years have been primarily financed through a
combination of funds generated from operations and borrowings. In our opinion, our working capital is sufficient for present requirements.
64
Table of Contents
Our
debt as at 30 June comprises the following:
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
|
|
(Rand in millions)
|
|
|
Long-term debt, including current portion
|
|
|
79 877
|
|
|
42 066
|
|
|
Short-term debt
|
|
|
138
|
|
|
534
|
|
|
Bank overdraft
|
|
|
136
|
|
|
319
|
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
80 151
|
|
|
42 919
|
|
|
Less cash (excluding cash restricted for use)
|
|
|
(49 985
|
)
|
|
(48 329
|
)
|
|
|
|
|
|
|
|
|
|
|
Net debt/(cash)
|
|
|
30 166
|
|
|
(5 410
|
)
|
|
|
|
|
|
|
|
|
|
As
at 30 June 2016, we had R2 331 million (2015—R5 022 million) in cash restricted for use. Refer to
"Item 18—Financial Statements—Note 28" for a breakdown of amounts included in cash restricted for use.
The
group has borrowing facilities with major financial institutions of R132 448 million (2015—R113 732 million). Of these facilities,
R 80 151 million (2015—R42 919 million) has been utilised at year end. Refer to "Item 18—Annual Financial
Statements—Note 16 Long-term debt", for a breakdown of our banking facilities and the utilisation thereof.
There
were no events of default for the years ended 30 June 2016 and 30 June 2015.
Included
in the abovementioned borrowing facilities is our commercial paper programme of R8 billion, normally at fixed interest rates. There were no amounts outstanding under the
commercial paper programme at 30 June 2016. Further, a revolving credit facility of US$1,5 billion is available to the group for further funding requirements.
Financial instruments and risk
Refer to "Item 11—Quantitative and qualitative disclosures about market risk" for a breakdown of our liabilities
summarised by fixed and floating interest rates.
Debt profile & covenants
The information set forth under "Item 18—"Annual Financial
Statements—Note 16—Long-term debt" is incorporated by reference.
Capital commitments
Refer "Item 18—"Annual Financial Statements—Note 17—Property, plant and equipment".
Our
growth aspirations have been prioritised as we steadily advance our growth strategy, particularly in Southern Africa and North America. Capital investments in these regions will
constitute a significant portion of our total capital expenditure over the next 10 years. Our gearing remains low, and we have sufficient headroom in our balance sheet to fund selective growth
opportunities, pay dividends and provide a buffer against volatilities. Given that a large portion of our funding for our capital intensive growth plan will come from the offshore debt markets, we are
acutely aware that we need to manage our gearing within our long-term targeted range. We expect that our gearing is likely to reach our targeted gearing range of 20% - 44% in the near
term.
In
the US, we are constructing the US$11 billion LCCP, which consists of a world-scale 1,5 million ton per year ethane cracker, and six downstream chemical projects.
At
30 June 2016, the capital expenditure to date is $4,8 billion, and the overall project completion is around 50%. We have project specific finance facilities in place to
fund the LCCP. For further detail on the funding of the LCCP, refer "Item 18—Annual Financial Statements—Note 16—Long-term debt".
65
Table of Contents
A
detailed review on the LCCP confirmed that the total capital cost for the project is expected to be US$11 billion, which includes site infrastructure and utility improvements.
This is an increase of $2,1 billion from the original estimate at the time of final investment decision (FID) in October 2014. This estimate includes a contingency, which measured against
industry norms for this stage of project completion, is considered sufficient to effectively take the project to beneficial operation within the revised cost estimate.
The
schedule for LCCP has not been impacted by the increase in cost estimate. The first unit, the linear low-density polyethylene unit, is expected to achieve beneficial operation in the
second half of calendar year 2018, which will be followed by the ethane cracker and ethylene oxide and mono ethylene glycol units later that year, with the low-density polyethylene unit shortly
thereafter. This will result in over 80% of the total output from LCCP reaching beneficial operation by early 2019. The remaining derivative units will reach beneficial operation by the second half of
2019.
The
detailed review process has confirmed that the $2,1 billion capital cost increase is mostly attributable to the following factors, in an approximately equal
proportion:
-
•
-
a significant increase in site and civil costs due to poorer than anticipated subsurface conditions, 50% more weather day delays over
the site construction period compared to the average norm, and much lower field productivity resulting from a conscious decision to proceed with out-of-sequence site preparation activities while
waiting for a variation of permit conditions to be granted;
-
•
-
an increase in the home office and construction costs of the Engineering, Procurement, Construction and Management Contractor (EPCm)
mainly as a result of an increase in contractor wage rates compared to what were assumed at FID, lower engineering productivity, and an increase in contractor engineering hours as a result of the
increased material quantities; and
-
•
-
an increase in labour costs as a result of higher quantities of material for installation, the decision to change to a higher-skilled
and thus higher cost crew mix to enable planned labour productivity improvements for the remainder of the project, and lump-sum contracts placed at higher rates than estimated.
Notwithstanding
these challenges, various other savings opportunities have been identified and are being implemented to mitigate the increase in the overall capital cost estimate.
As
a result of the detailed review process, Sasol is confident that a high degree of certainty exists over the updated capital cost estimate of $11 billion. With the project now
over 50% complete, several changes have been, or are in the process of being, implemented which are intended to ensure that the project has a good probability of being completed within the updated
cost and schedule guidance.
Although
unplanned event-driven risks may still impact the execution and cost of the project, we are confident that the remaining construction, procurement, execution and business
readiness risks can be managed within the estimate as a result of these changes.
The
expected returns from the LCCP have also been updated, taking into account our updated oil and petrochemical price forecasts as well as the revised cost and schedule resulting from
the review process. On an unlevered basis, the returns from LCCP are expected to be slightly above the company's US dollar weighted average cost of capital of 8%, although below the returns expected
at the time of FID in October 2014. However on the low density polyethylene individual cash generating unit, due to lower margins and the increased cost estimate, we recognised an impairment of
R956 million (US$65 million) during the 2016 financial year.
Even
though the expected capital expenditure for LCCP has increased, we do not expect this to result in the company exceeding its self-imposed gearing targets. Our funding strategy has
not changed as a result of the higher estimated capital expenditure and the
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Table of Contents
project
will continue to be funded from existing facilities and ongoing group cash flow. Despite the lower expected returns, we still consider the LCCP to be a sound investment that will return value
to our shareholders for many years into the future.
In
Mozambique, the field development plan (FDP) for the Production Sharing Agreement (PSA) licence was approved by regulatory authorities. The PSA FDP proposes an integrated oil,
Liquefied Petroleum Gas (LPG) and gas to power project adjacent to the Petroleum Production Agreement (PPA) area. The development of these projects is a capital-intensive process carried out over long
durations and requires us to commit significant capital expenditure. The total project cost for tranche one of the first phase of the PSA licence area and the fifth train is estimated at
US$1,4 billion. The project is in its early stages of execution with the drill rig proceeding with the 13 well drilling programme.
For
information on amounts capitalised in respect of these projects refer, "Item 18—Annual Financial Statements—Note 17—Property, plant
and equipment" and "Note 18—Assets under construction".
For
information on future amounts expected to be spent to complete the projects, refer "Item 18—Annual Financial
Statements—Note 18—Assets under construction".
5.C Research and development, patents and licences
Refer to the "Integrated Report—Intellectual Capital" as contained in Exhibit 99.8.
During
2016, R1 105 million was spent on research and development activities (2015—R1 645 million;
2014—R1 550 million).
5.D Trend information
Refer to the "CFO Report—Key financial risks and uncertainties affecting our performance" as contained in
Exhibit 99.3.
5.E Off-balance sheet arrangements
We do not engage in off-balance sheet financing activities and do not have any off-balance sheet debt obligations, off-balance sheet
structured entities or unconsolidated affiliates.
Guarantees
As at 30 June 2016, the group has recognised amounts in respect of certain guarantees. Refer to
"Item 18—Annual Financial Statements, "Note 16 Long-term debt", "Note 18 Assets under construction", and "Note 21 Equity accounted investments" for further
information on guarantees.
Product warranties
The group provides product warranties with respect to certain products sold to customers in the ordinary course of business. These
warranties typically provide that products sold will conform to specifications. The group accrues a warranty liability on a transaction-specific basis depending on the individual facts and
circumstances related to each sale. Both the liability and expense related to product warranties are immaterial to the consolidated financial statements.
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Table of Contents
5.F Tabular disclosure of contractual obligations
Contractual obligations/commitments.
The following significant undiscounted contractual obligations existed at 30 June 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual
obligations
|
|
Total
amount
|
|
Within
1 year
|
|
1 to 5
years
|
|
More than
5 years
|
|
|
|
(Rand in millions)
|
|
|
Bank overdraft
|
|
|
136
|
|
|
136
|
|
|
—
|
|
|
—
|
|
|
Capital commitments
|
|
|
137 286
|
|
|
75 134
|
|
|
62 152
|
|
|
—
|
|
|
Environmental and other obligations
|
|
|
119 366
|
|
|
8 275
|
|
|
19 726
|
|
|
91 365
|
|
|
External long-term debt
|
|
|
97 443
|
|
|
4 656
|
|
|
36 322
|
|
|
56 465
|
|
|
External short-term debt
|
|
|
138
|
|
|
138
|
|
|
—
|
|
|
—
|
|
|
Finance leases
|
|
|
3 065
|
|
|
276
|
|
|
920
|
|
|
1 869
|
|
|
Operating leases
|
|
|
20 521
|
|
|
1 559
|
|
|
4 532
|
|
|
14 430
|
|
|
Post-retirement healthcare obligations(1)
|
|
|
3 994
|
|
|
166
|
|
|
832
|
|
|
2 996
|
|
|
Post-retirement pension obligations(1)
|
|
|
9 067
|
|
|
192
|
|
|
2 219
|
|
|
6 656
|
|
|
Purchase commitments
|
|
|
45 493
|
|
|
17 284
|
|
|
27 080
|
|
|
1 129
|
|
|
Share-based payments
|
|
|
2 515
|
|
|
1 721
|
|
|
794
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
439 024
|
|
|
109 537
|
|
|
154 577
|
|
|
174 910
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Represents
discounted values
Refer
Note 17 of "Item 18—Annual Financial statements" for significant capital commitments.
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
6.A Directors and senior management
The board of directors and senior management
-
•
-
For information regarding our directors, refer to "Integrated Report—Our board of directors" as contained in
Exhibit 99.9
Senior management—experience
We have identified our senior management as the members of our group executive committee (GEC). See "Our board of directors" above for
experience of our executive directors who are members of the GEC.
Fleetwood Grobler
has been a member of our GEC since 1 December 2013. He is our Executive Vice President, Chemicals Business,
and
is responsible for our global chemicals business. Prior to his appointment to the GEC, he was the Managing Director of Sasol Olefins & Surfactants. Mr Grobler joined Sasol in 1984
and has served in most of our South African operating facilities and has extensive experience in our international businesses. He obtained a Bachelor of Mechanical Engineering degree from the
University of Pretoria, South Africa in 1984 and completed the Advanced Executive Program at the University of South Africa in 1994.
Vuyo Kahla
has been a member of our GEC since 1 January 2011 and has been our Company Secretary since 14 March 2011. He is
the Executive Vice President, Advisory and Assurance and Company Secretary, and is responsible for the governance, compliance and ethics; legal, intellectual property and regulatory services;
assurance services (incorporating the internal audit and forensic services functions); and supply chain functions. From June 2004 to November 2010, he held executive positions in Transnet SOC Limited,
with responsibility for legal services, risk management, compliance, company secretarial services, strategy and business modelling, corporate and public affairs and public policy and regulation. The
World Economic Forum recognised him as a Young Global Leader and he is an alumnus of the Prince of Wales University of Cambridge Programme on Sustainability Leadership. He is the Chairman of the
Council of Rhodes University. He obtained a Bachelor of Arts (Law) degree and a postgraduate Bachelor of Law degree from Rhodes University, South Africa in 1994 and 1996, respectively.
Bernard Klingenberg
became a member of the GEC on 1 April 2009. He has been our Executive Vice President, Southern African
Operations since 1 July 2014 and with effect from 1 July 2016, is responsible for our operations globally. He was responsible for group human resources for a period of two years from
1 April 2009. Since joining the Sasol group in 1986, he has held various positions in maintenance, technical and general management fields in some of the South African Energy and the global
Chemicals businesses of the group. He was the Managing Director of Sasol Polymers
68
Table of Contents
from
April 2007 to March 2009 and before that the Managing Director of Sasol Nitro. He obtained a Master of Science (Mechanical Engineering) from the University of Cape Town, South Africa in 1986.
Maurice Radebe
has been a member of our GEC since 1 November 2010. He has been our Executive Vice President responsible for our
Energy Business since 1 July 2014. Prior to that, he was our Group Executive responsible for global corporate affairs, government relations and enterprise development. Mr Radebe joined
Sasol Oil in January 2004, when Sasol Oil purchased Exel Petroleum, where he was the Managing Director. He served as the Managing Director of Sasol Oil from December 2006 until October 2010. He is
chairman of the South African Petroleum Industry Association for the 2015 and 2016 calendar years. He obtained a Bachelor of Science (Applied Mathematics and Physics) from the University of the North
(now known as the University of Limpopo), Polokwane, South Africa in 1983 and a Higher Diploma for Educators of Adults from the University of Witwatersrand, Johannesburg, South Africa in 1988. He
attended the Management Advancement Programme at the Wits Business School in Johannesburg, South Africa in 1991 and obtained a Masters in Business Administration from Wits Business School in 1997. He
attended the General Management Program at Harvard Business School in the US in 2007.
Riaan Rademan
has been a member of our GEC since 1 May 2009. He is our Executive Vice President, Upstream and Business Enablement,
responsible for mining, exploration and production and business enablement. Prior to that, he had been responsible for mining, safety, health and environment, supply chain and information management,
shared services, group information management and procurement and supply chain. He previously served as Managing Director of Sasol Nitro and Sasol Mining. Mr Rademan obtained a Bachelor of
Mechanical Engineering degree from the University of Pretoria, South Africa in 1980 and a Master of Business Leadership from the University of South Africa in 1987. He attended the Advanced
Management
Program at the University of Pennsylvania, Wharton School in the US in 1995.
Stephan Schoeman
has been a member of our GEC since 1 May 2014. He is our Executive Vice President, Technology responsible for
technology and our mega-projects in Lake Charles, Louisiana in the US. He was the Managing Director of Sasol Synfuels from May 2011 to March 2014. Prior to that, he was the Managing Director of Sasol
Infrachem. Mr Schoeman has worked at most of Sasol's South African operating facilities and has extensive international experience. He obtained a Bachelor of Chemical Engineering degree from
the University of Pretoria, South Africa in 1986.
Family relationship
There are no family relationships between any of our non-executive directors, executive directors or members of our group executive
committee.
Other arrangements
None of our non-executive directors, executive directors or group executive committee members or other key management personnel are
elected or appointed under any arrangement or understanding with any major shareholder, customer, supplier or otherwise.
6.B Compensation
Refer to our Remuneration Report filed as Exhibit 99.2 for details of our directors and senior management compensation.
Long-term incentive schemes applicable to executive directors and senior management
For details regarding our long-term incentive schemes applicable to executive directors and senior management named in Item 6.A.
Refer to our Remuneration Report filed as Exhibit 99.2.
6.C Board practices
For more information regarding our board practices refer "Integrated Report—Our board of directors" files as
Exhibit 99.9.
69
Table of Contents
Refer
to our Remuneration Report filed as Exhibit 99.2 for details of our directors' and senior management service contracts and benefits upon termination of employment.
Refer
to "Integrated report—Our governance framework" as contained in Exhibit 99.10, for details of our board practices, including details relating to our audit
committee and remuneration
committee, as well as the names of committee members and summaries of the terms of reference under which the committees operate.
6.D Employees
The information set forth under "Item 18—Annual Financial
Statements—Note 3—Employee-related expenditure" is incorporated by reference.
Remuneration
of directors and key personnel is contained in the Remuneration Report, contained in Exhibit 99.2.
For
information regarding the employees per segment, refer to "Item 18—Annual Financial Statements—Note 3—Employee-related expenditure".
Our workforce geographic location composition at 30 June is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Region
|
|
2016
|
|
2015
|
|
2014
|
|
|
South Africa
|
|
|
25 394
|
|
|
26 138
|
|
|
28 637
|
|
|
Europe
|
|
|
2721
|
|
|
2 780
|
|
|
2 836
|
|
|
North America
|
|
|
1 289
|
|
|
1 209
|
|
|
1 109
|
|
|
Other
|
|
|
696
|
|
|
792
|
|
|
818
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
30 100
|
|
|
30 919
|
|
|
33 400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.E. Share ownership
Refer to our Remuneration Report filed as Exhibit 99.2 for details of share ownership applicable to executive directors and
senior management.
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
7.A Major shareholders
Refer to "Item 18—Annual Financial Statements—Note 15—Equity" for the
authorised
and issued share capital of Sasol Limited.
To
the best of our knowledge, Sasol Limited is not directly or indirectly owned or controlled by another corporation or the government of South Africa or any other government. We believe
that no single person or entity holds a controlling interest in our securities.
In
accordance with the requirements of the Companies Act of South Africa (Companies Act), the following beneficial shareholdings equal to or exceeding 5% of the total issued securities
during the last three years were disclosed or established from inquiries as of 30 June 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
Number of
shares
|
|
% of
shares
|
|
Number of
shares
|
|
% of
shares
|
|
Number of
shares
|
|
% of
shares
|
|
|
GEPF(1)(2)
|
|
|
84 121 005
|
|
|
12,9
|
|
|
92 425 614
|
|
|
13,6
|
|
|
93 978 508
|
|
|
13,8
|
|
|
IDC(3)
|
|
|
53 266 887
|
|
|
8,2
|
|
|
53 266 887
|
|
|
7,8
|
|
|
53 266 887
|
|
|
7,9
|
|
-
(1)
-
Government
Employees Pension Fund (GEPF)
-
(2)
-
PIC
Equities manages 78,7 million of the shares owned by GEPF.
-
(3)
-
Industrial
Development Corporation of South Africa (IDC)
The
voting rights of major shareholders do not differ from the voting rights of other shareholders.
As
of 31 August 2016, 40,70 million Sasol ordinary shares, or approximately 6,0% of our total issued securities, were held in the form of American Depositary Receipts
(ADRs). As of 31 August 2016, 413 record holders in the United States held approximately 20,2% of our total issued securities in the form of either Sasol ordinary shares or ADRs.
7.B Related party transactions
There have been no material transactions during the most recent three years, other than as described below, nor are there proposed to
be any material transactions at present to which we or any of our subsidiaries are or were a party and in which any senior executive or director, or 10% shareholder, or any relative or spouse thereof
or any relative of such spouse, who shared a home with this person, or who is a director or executive officer of any parent or subsidiary of ours, had or is to have a direct or indirect material
interest. Furthermore, during
70
Table of Contents
our
three most recent years, there has been no, and at 30 June 2016 there was no, outstanding indebtedness to us or any of our subsidiaries owed by any of our executive or independent directors
or any associate thereof.
During
the year, group companies, in the ordinary course of business, entered into various purchases and sale transactions with associates, joint ventures and certain other related
parties. The effect of these transactions is included in the financial performance and results of the group. Terms and conditions are determined on an arm's length basis.
Amounts
due to and from related parties are disclosed in the respective notes to the financial statements for the respective statement of financial position line items. Refer to
"Item 18—Annual Financial Statements—Note 39—Related party transactions" for further details.
7.C Interests of experts and counsel
Not applicable.
ITEM 8. FINANCIAL INFORMATION
8.A Consolidated statements and other financial information
Refer "Item—18. Annual Financial Statements" for our financial statements, related notes and other financial information.
Dividend policy
Our previous dividend distribution policy was a progressive dividend policy. In February 2015 the Sasol Limited Board approved a change
in the company's dividend policy, which is based on a dividend cover range. The Company´s dividend policy takes into consideration various factors, including overall market and
economic conditions, the Group's financial position, capital investment plans as well as earnings growth.
Headline
earnings per share will serve as the basis for deciding on the dividend amount.
The
prevailing circumstances of the company, future investment plans, financial performance and the trading and macroeconomic environments will be considered when we make decisions on dividends. The
average rate of earnings to dividend distributions in the past five years was approximately 2,3 times. Our dividend cover for 2016 was 2,8 times. We distribute dividends twice a year.
Refer
to "Item 10.B—Memorandum and articles of association—Rights and privileges of holders of our securities".
Legal proceedings
For information regarding our legal proceedings refer to "Item 4.B—Business overview—Legal proceedings
and other contingencies".
8.B Significant changes
Refer to "Item 18—Annual Financial statements—Note 40 Subsequent events".
In
August 2016, Sasol completed its detailed review of the Lake Charles Chemical Project, and has confirmed that a high degree of certainty exists over the capital cost estimated at
US$11 billion. The LCCP is 50% complete, and after the implementation of improved change management practices and key project leadership personnel changes, management remains confident that the
project is a sound strategic investment that will return value to our shareholders.
ITEM 9. THE OFFER AND LISTING
9.A Offer and listing details
The following table sets forth, for the years indicated, the reported high and low quoted prices for the ordinary shares on the
Johannesburg Stock Exchange (JSE) and for our
71
Table of Contents
American
Depositary Receipts (ADRs) on the New York Stock Exchange.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
(Price per
share in rand)
|
|
ADRs
(Price per
ADR in US$)
|
|
|
Period
|
|
High
|
|
Low
|
|
High
|
|
Low
|
|
|
2012
|
|
|
409,99
|
|
|
303,45
|
|
|
48,96
|
|
|
40,01
|
|
|
2013
|
|
|
452,96
|
|
|
336,00
|
|
|
47,92
|
|
|
39,94
|
|
|
2014
|
|
|
645,10
|
|
|
420,00
|
|
|
60,21
|
|
|
41,65
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
|
642,72
|
|
|
597,65
|
|
|
60,80
|
|
|
54,25
|
|
|
Second quarter
|
|
|
609,28
|
|
|
392,78
|
|
|
54,11
|
|
|
33,18
|
|
|
Third quarter
|
|
|
477,56
|
|
|
365,10
|
|
|
42,20
|
|
|
31,66
|
|
|
Fourth quarter
|
|
|
490,06
|
|
|
395,80
|
|
|
41,64
|
|
|
33,76
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
|
447,89
|
|
|
375,25
|
|
|
36,57
|
|
|
26,97
|
|
|
Second quarter
|
|
|
465,69
|
|
|
358,79
|
|
|
34,31
|
|
|
24,55
|
|
|
Third quarter
|
|
|
492,50
|
|
|
360,70
|
|
|
31,62
|
|
|
21,88
|
|
|
Fourth quarter
|
|
|
487,00
|
|
|
390,10
|
|
|
32,96
|
|
|
25,29
|
|
|
April
|
|
|
471,35
|
|
|
408,18
|
|
|
32,96
|
|
|
27,27
|
|
|
May
|
|
|
487,00
|
|
|
436,25
|
|
|
32,13
|
|
|
28,65
|
|
|
June
|
|
|
485,00
|
|
|
390,10
|
|
|
32,13
|
|
|
25,29
|
|
|
July
|
|
|
402,44
|
|
|
368,74
|
|
|
28,08
|
|
|
25,90
|
|
|
August
|
|
|
384,00
|
|
|
363,38
|
|
|
28,48
|
|
|
25,26
|
|
|
September (up to 19 September 2016)
|
|
|
386,50
|
|
|
362,91
|
|
|
26,73
|
|
|
25,15
|
|
9.B Plan of distribution
Not applicable.
9.C Markets
The principal trading market for our shares is currently the JSE. Our American Depositary Shares (ADS) have been listed on the New York
Stock Exchange since 9 April 2003, each representing one common ordinary share of no par value, under the symbol "SSL". The Bank of New York Mellon is acting as the Depositary
for our ADSs and issues our ADRs in respect of our ADSs.
9.D Selling shareholders
Not applicable.
9.E Dilution
Not applicable.
9.F Expenses of the issue
Not applicable.
ITEM 10. ADDITIONAL INFORMATION
10.A Share capital
Not applicable.
10.B Memorandum and articles of association
1. Registration number, and object and purpose
Refer to "Item 10.B" of our registration statement pursuant to section 12(b) or 12(g) of the Securities Exchange Act of
1934, filed with the Securities and Exchange Commission on 6 March 2003 (the Registration Statement) for the registration number and object and purpose of the Company.
2. Our board of directors
The directors shall, within the minimum and maximum limits stipulated in the Memorandum of Incorporation (MOI), determine the number of
directors from time to time. If so approved by the board, directors may also appoint alternate directors in their stead.
The
directors who retire every year shall be the longest serving since their last election, but will be eligible for re-election. As between directors of equal seniority, the directors
to retire, in the absence of agreement, will be selected from among them in alphabetical order.
If
at the date of the annual general meeting a director has held office for a period of five years since his last election or appointment, he shall retire at such meeting, if not
included as one of the directors to retire by rotation.
Power to vote in respect of matters in which a director has a material interest.
In terms of our MOI and the Companies Act, a director
who has a
personal financial interest in respect of a matter to be considered at a meeting, or knows that a related person has a personal financial interest in the matter, may not vote on the matter. In terms
of our board charter, directors are appointed on the express understanding and agreement that they may be removed by the board if and when they develop an actual or prospective material, enduring
conflict of interest with Sasol or a group company.
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Power to vote on remuneration.
A distinction must be drawn between remuneration of directors as employees (executive directors) of the
company and
remuneration of directors for their services as directors. With regard to remuneration of directors for their services as directors and in accordance with Companies Act, our MOI requires shareholder
approval by way of a special resolution obtained in the previous two years for the payment of remuneration to directors for their service as directors, and the basis of payment thereof.
The
remuneration of executive directors is determined by a disinterested quorum of directors on recommendation of the remuneration committee determined in accordance with the group's
remuneration policy put to shareholders for a non-binding advisory vote at the annual general meeting as required by the King Code of Governance Principles for South Africa 2009 (King III Code). No
powers are conferred by our MOI, or by any other means, on the directors who are employees of the company, to vote on their own remuneration in the absence of a disinterested quorum of directors.
Borrowing powers exercisable by directors.
Clause 26.2 of our MOI provides that the directors, acting on behalf of subsidiaries,
may borrow
money and secure the payment or repayment thereof upon terms and conditions which they may deem fit in all respects and, in particular, through the issue of debentures which bind as security all or
any part of the property of the Company, both current and future.
For
more information regarding the retirement, appointment and re-election of directors, as well as qualification shares to be held by directors, see information provided in our
Registration Statement.
3. Rights and privileges of holders of our securities
Classes of shares.
We have three classes of shares in issue, namely:
-
•
-
Ordinary Shares;
-
•
-
Preferred Ordinary Shares; and
-
•
-
Sasol BEE Ordinary Shares,
which
have the rights and privileges more fully set out in our MOI and which are briefly described herein.
Any
payments made to holders of Sasol preferred ordinary shares must be made without deduction, set-off or withholding.
In
terms of our MOI, no dividend may be paid unless it reasonably appears that the company will satisfy the solvency and liquidity test as defined in the Companies Act immediately after
completing the proposed
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distribution;
and the board, by resolution, has acknowledged that it has applied the solvency and liquidity test and has reasonably concluded that the company's assets equal or exceed the liabilities
of the company and that the company will be able to pay its debts as they become due in the ordinary course of business for a period of 12 months following the payment of the dividend.
For
further information on our dividend policy, see "Item 8.A—Consolidated statements and other financial information and our Registration Statement".
Voting rights.
The Sasol BEE Ordinary Shares and the Preferred Ordinary Shares rank
pari passu
with
Ordinary Shares in relation to the right to vote at shareholders' meetings of the company.
In
terms of our MOI, every shareholder, or representative of a shareholder, who is present at a shareholders' meeting has one vote on a show of hands, regardless of the number of shares
he holds or represents. On a poll, a shareholder has one vote for every share held by him. If the rights of any class of shareholders will be affected, then provision is made in the Companies Act for
a separate class meeting.
Right to share in profits.
This is not relevant under South African law. In terms of South African law, dividends are declared subject
to the
directors being satisfied as to the solvency and liquidity of a company.
Rights to surplus in the event of liquidation.
Preferred Ordinary Shares:
On the winding up of the company all dividends that should have been declared and paid to the holders of
Preferred
Ordinary Shares at that point in time will automatically be declared and paid in priority to shareholders of any other class of shares other than preference shares. Thereafter, each Preferred Ordinary
Share shall participate
pari passu
with each Ordinary Share in the remaining assets of the company and the assets remaining after payment of the debts
and liabilities of the company, the costs of liquidation and the payment of all dividends that should have been declared and paid to the
holders
of Preferred Ordinary Shares, as set out above, shall be distributed among the shareholders in proportion to the number of shares respectively held by each of them.
Redemption provision:.
There are no redemption provisions relating to the Ordinary Shares and the Sasol BEE Ordinary Shares.
Preferred Ordinary Shares:
The restrictions on and entitlements in relation to the Preferred Ordinary Shares will lapse on the earlier
of the tenth
anniversary of the date of issue of the first Preferred Ordinary Shares or on the date of receipt by the company of a notice that a redemption event has occurred, in accordance with the terms of
various agreements entered into by
inter alia
Sasol and the company Sasol Inzalo Groups Funding (Pty) Ltd (RF), and the company Sasol Inzalo
Public Funding (Pty) Ltd (RF), (the redesignation date). On the redesignation date, the Preferred Ordinary Shares will be redesignated as Sasol ordinary shares and will rank
pari passu
in all
respects with the Ordinary Shares.
Sinking funds.
There are no sinking funds.
Liability for further capital calls.
Under the previous Companies Act of South Africa, shares could only be issued if they were fully
paid.
Accordingly, no shares were issued which were subject to any capital calls. Under the latest Companies Act of South Africa however, partly paid shares may be issued under certain circumstances. The
company has not yet made use of these provisions.
Discriminatory provisions against majority shareholders.
There are no discriminatory provisions in our MOI against any holder of
securities as a
result of such holder owning a substantial number of shares in the company.
4. Changing rights of holders of securities
In terms of our MOI, we may only by way of special resolution amend the rights attached to any shares or convert any of our shares
(whether issued or not) into shares of another class. A special resolution is also required for the company to convert shares into stock and to reconvert stock into shares. If the rights of any
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class
of shareholders will be affected, then provision is made in the Companies Act for a separate class meeting of the holders of such shares. In addition to the above, shareholders have appraisal
rights under the Companies Act, and accordingly, if we amend our MOI by altering the preferences, rights, limitations or other terms of any class of our shares in a manner that is materially adverse
to the rights or interests of holders of that class of shares, every holder of that class of shares that was present at the meeting at which the resolution to amend our MOI was passed and voted
against such resolution, will be entitled, on notice to the company to seek court relief upon establishing that they have been unfairly prejudiced by the company. For a special resolution to be
approved by shareholders, it must be supported by at least 75% of the voting rights exercised on the resolution.
5. General meeting of shareholders
In terms of the Companies Act, the board or any other person specified in the company's MOI may call a shareholders' meeting at any
time. In terms of our MOI, the board (or any other person who may be specified in the MOI) must call a shareholders' meeting:
-
•
-
at any time that the board is required in terms of the Companies Act, or our MOI to refer a matter to shareholders for decision;
-
•
-
whenever required in terms of the Companies Act to fill a vacancy on the board;
-
•
-
whenever required in terms of our MOI to call a meeting; and
-
•
-
if one or more demands for a meeting with substantially the same purpose are delivered to the company by persons holding in aggregate
at least 10% of the voting rights entitled to be exercised in relation to the matter proposed.
One
or more shareholders holding not less than 10% of the voting rights may convene a shareholders' meeting.
If
a company is unable to convene a meeting because it has no directors, then in terms of our MOI, any single shareholder entitled to vote may convene a meeting.
If
the company fails to convene a meeting in accordance with its MOI, or as required by the shareholders holding in the aggregate at least 10% of the voting rights as set out above, or
within the time periods as required, any shareholder may apply to court for an order to convene a shareholders' meeting on a date and subject to such terms as a court considers appropriate.
Notices.
In terms of our MOI we are required to deliver written notice of shareholders' meetings to each shareholder and each
beneficial shareholder
at least 15 business days before a meeting. The Companies Act also stipulates that delivery of a notice will be deemed to have taken place on the seventh calendar day following the day on which the
notice was posted by way of registered post.
Attendance at meetings.
Before a person will be allowed to attend or participate at shareholder meetings, that person must present
reasonably
satisfactory identification and the person presiding at the meeting must reasonably satisfy himself that the right of the person to attend as shareholder or proxy has been reasonably verified.
Meetings of shareholders may be attended by any person who holds shares in the company and whose name has been entered into our securities register and includes any person who is entitled to exercise
any voting rights in relation to the company. Any person entitled to attend and to vote at any meeting may appoint a proxy/ies in writing to attend and to vote at such meeting on his/her/its behalf.
In respect of shares which are not subject to the rules of a central securities depository, and in respect of which a person holds a beneficial interest which includes the right to vote on a matter,
that beneficial holder may attend and vote on a matter at a meeting of shareholders, but only if that person's name has been entered in our register of disclosures as the holder of that beneficial
interest. Beneficial shareholders whose shares are not registered in their own name or (in the case of certificated shares in the
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company's
register of disclosure), or beneficial owners who have dematerialised their shares, are required to contact the registered shareholder or their Central Securities Depository Participant, as
the case may be, for assistance to attend and vote at meetings.
Quorum.
In terms of our MOI, the quorum necessary for the commencement of a shareholders meeting shall be sufficient persons present at
the meeting
to exercise, in aggregate, at least 25% of all the voting rights that are entitled to be exercised in respect of at least one matter to be decided at the shareholders meeting but the shareholders'
meeting may not begin unless at least three persons entitled to vote are present. In terms of our MOI, if the required quorum of shareholders is not present within 30 minutes from the time appointed
for the meeting to begin, the meeting will be postponed to the next business day and if at such adjourned shareholders' meeting a quorum is not present within 15 minutes from the time appointed for
the shareholders' meeting, then the persons entitled to vote present shall be deemed to be the requisite quorum. In terms of the Companies Act, no further notice is required of a postponed or
adjourned meeting unless the location is different from that of the postponed or adjourned meeting, or is different from a location announced at the time of an adjourned meeting.
See
our Registration Statement for more information with respect to the holding of an annual general meeting and the proceedings at the annual general meeting.
6. Rights of non-South African shareholders
The Sasol BEE ordinary shares may only be owned by persons who meet certain broad-based black economic empowerment credentials. In
order to meet such credentials such person must,
inter alia
, be a South African citizen.
There
are no limitations imposed by South African law or the MOI on the rights of non-South African shareholders to hold or vote shares in the company (other than the Sasol BEE ordinary
shares). Acquisitions of shares in South African companies are not generally subject to review by the SARB. However, its
approval
may be required in certain cases where such share acquisition is financed by South African lenders.
7. Provisions that would have the effect of delaying a change of control or merger
The Companies Act and the regulations to the Companies Act deal extensively with the requirements that must be met by a company with
respect to a merger, an acquisition or a corporate restructure.
8. Disclosure of ownership threshold
Pursuant to section 122(1)(a) and (b) of the Companies Act, a person must notify the company within three business days
after acquiring or disposing of a beneficial interest in sufficient securities of a class issued by that company such that, as a result of the acquisition or disposal, the person holds or no longer
holds as the case may be, a beneficial interest in securities amounting to any multiple of 5% of the issued securities of that class. The Takeover Regulation Panel has interpreted this to mean an
acquisition or disposal of shares in any 5% increment.
The
JSE Listings Requirements require a listed company to disclose in its annual financial statements the interest of any shareholder, other than a director, who, insofar as it is known
to the company, is directly or indirectly beneficially interested in 5% or more of any class of the company's capital.
9. Effect of the law
With respect to items 2 through 8 above, the effect of the law applicable to our company and where required, is explained.
10. Changes in share capital
In terms of the Companies Act, the board may (save to the extent that a company's MOI provides otherwise), increase or decrease the
number of authorised shares in any class of shares. In addition, the board may (save to the extent that the company's MOI provides otherwise), classify any unclassified shares, or determine any
preference rights, limitations or
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other
terms in respect of a class of shares which have been provided for in a company's MOI and for which the board is required to determine the associated preference rights, limitations or other
terms of shares.
In
terms of our MOI and the JSE Listings Requirements, we are required to obtain the consent of shareholders, by special resolution, to increase the number of authorised shares in the
share capital of the company, or to consolidate or to subdivide all or any shares or to amend the rights and privileges of any class of shares.
Issued shares placed under the control of directors.
See section 4 above.
Unissued shares placed under the control of directors.
The Companies Act generally allows the board to issue authorised shares without
shareholder
approval. However, in terms of our MOI, and subject to the JSE Listings Requirements, the company may, in a shareholders' meeting, place the balance of the ordinary shares not allotted under the
control of the directors with general authorisation to allot, and issue such shares at such prices and upon such terms and conditions and with the rights and privileges attached thereto, as may be
determined in shareholders' meeting. A special resolution is required to place the preference shares under the control of the directors. Further, in terms of our MOI, a special resolution is required
to amend the rights attached to any unissued shares or convert any of our unissued shares into shares of another class. A special resolution is also required for the company to cancel, vary or amend
shares or any rights attached to shares which, at the time of the passing of the relevant resolution, have not been taken up by any person or which no person has agreed to take up, and we may reduce
our share capital by the amount of the shares so cancelled.
In
terms of the Companies Act, a special resolution is required to approve an issue of shares or securities convertible into shares, or the issue of options for the allotment or
subscription of authorised shares or other securities of the company, or a grant of any other rights exercisable for securities, if the shares, securities, options or rights are issued to
a
director, future director, prescribed officer, or future prescribed officer of the company, or their related parties or nominees. In addition, a special resolution is required to approve an issue of
shares or securities which will, as a result of a transaction or a series of transactions, result in the voting power of the class of shares being issued being equal to or exceeding 30% of the voting
powers of all the shares of that class immediately before the transaction or series of transactions.
10.C Material contracts
We do not have any material contracts, other than contracts entered into in the ordinary course of business.
10.D Exchange controls
South African exchange control regulations are administered by the Financial Surveillance Department (FSD) of the South African Reserve
Bank and are applied throughout the Common Monetary Area (CMA) (South Africa, the Kingdoms of Lesotho and Swaziland and the Republic of Namibia) and regulate transactions involving South African
residents, as defined in the Exchange Control Rulings, including natural persons and legal entities.
Day
to day interaction with the FSD on exchange control matters is facilitated through Authorised Dealers who are persons authorised by National Treasury to deal in foreign exchange, in
so far as transactions in respect of foreign exchange are concerned.
The
South African government has from time to time stated its intention to relax South Africa's exchange control regulations when economic conditions permit such action. In recent years,
the government has incrementally relaxed aspects of exchange control.
The
following is a general outline of South African exchange controls. The comments below relate to exchange controls in force at the date of this annual report. These controls are
subject to change at any time without notice. Investors should consult a professional advisor as to the exchange control implications of their particular investments.
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Foreign financing and investments
Foreign debt.
We, and our South African subsidiaries, require approval by the FSD to obtain foreign loans.
Funds
raised outside the CMA by our non-resident subsidiaries, i.e. a non-resident for exchange control purposes, are not restricted under South African exchange control
regulations and may be used for any purpose including foreign investment, as long as such use is without recourse to South Africa. We, and our South African subsidiaries, would, however, require
approval by the FSD in order to provide guarantees for the obligations of any of our subsidiaries with regard to funds obtained from non-residents of the CMA.
Debt
raised outside the CMA by our non-resident subsidiaries must be repaid or serviced by those foreign subsidiaries. Without approval by the FSD, we can neither use cash we earn in
South Africa to repay or service such foreign debts nor can we provide security on behalf of our non-resident subsidiaries.
We
may retain dividends declared by our foreign subsidiaries offshore which we may use for any purpose, without any recourse to South Africa. These funds may, subject to certain
conditions, also be invested back into the CMA in the form of equity investments or loans.
Raising capital overseas.
A listing by a South African company on any stock exchange requires prior approval by the FSD.
Under
South African exchange control regulations, we must obtain approval from the FSD regarding any capital raising activity involving a currency other than the rand. In granting its
approval, the FSD may impose conditions on our use of the proceeds of the capital raising activity outside South Africa, including limits on our ability to retain the proceeds of this capital raising
activity outside South Africa or a requirement that we seek further approval by the FSD prior to applying any of these funds to any specific use. Any limitations imposed by the FSD on our use of the
proceeds of a capital raising activity could adversely affect our flexibility in financing our investments.
Foreign investments.
Under current exchange control regulations we, and our South African subsidiaries, require approval, either by
Authorised
Dealers of the FSD to invest offshore.
Although
there is no limitation placed on us with regard to the amount of funds that we can transfer from South Africa for an approved foreign investment, the FSD may, however, request
us to stagger the capital outflows relating to large foreign investments in order to limit the impact of such outflows on the South African economy and the foreign exchange market.
The
FSD also requires us to provide it with an annual report, which will include the results, of all our foreign subsidiaries.
Investment in South African companies
Inward investment.
As a general rule, a foreign investor may invest freely in shares in a South African company. Foreign investors may
also sell
shares in a South African company and transfer the proceeds out of South Africa without restriction. Acquisitions of shares or assets of South African companies by non-South African purchasers are not
generally subject to review by the FSD when the consideration is in cash, but may require review by the FSD in certain circumstances, including when the consideration is equity in a non-South African
company or when the acquisition is financed by a loan from a South African lender.
Dividends.
There are no exchange control restrictions on the remittance of dividends declared out of trading profits to non-residents
of the CMA.
However, residents of the CMA may under no circumstances have dividends paid outside the CMA without specific approval from the FSD.
Transfer of shares and ADSs.
Under South African exchange control regulations, our shares and ADSs are freely transferable outside South
Africa among
persons who are not residents of the CMA. Additionally, where shares are sold on the JSE on behalf of our shareholders who are not residents of the CMA, the proceeds of such sales will be freely
exchangeable into foreign currency and remittable to them. The FSD may
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also
require a review to establish that the shares have been sold at market value and at arm's length. While share certificates held by non-resident shareholders will be endorsed with the words
"non-resident", such endorsement will, however, not be applicable to ADSs held by non-resident shareholders.
10.E Taxation
South African taxation
The following discussion summarises the South African tax consequences of the ownership and disposition of shares or ADSs by a US
holder (as defined below). This summary is based upon current South African tax law and the convention that has been concluded between the governments of the United States and the Republic of South
Africa for the avoidance of double taxation and the prevention of fiscal evasion with respect to taxes on income and capital gains, signed on 17 February 1997 (the Treaty). In addition, this
summary is based in part upon representations of the Depositary (The Bank of New York Mellon, as Depositary for our ADSs), and assumes that each obligation provided for in, or otherwise contemplated
by the Deposit Agreement and any related agreement, will be performed in accordance with its respective terms.
The
summary of the South African tax considerations does not address the tax consequences to a US holder that is resident in South Africa for South African tax purposes or whose holding
of shares or ADSs is effectively connected with a permanent establishment in South Africa through which such US holder carries on business activities. It equally does not address the scenario where
the US holder is not the beneficial recipient of the dividends or returns or, where the source of the transaction is deemed to be in South Africa, the recipient is not entitled to the full benefits
under the Treaty or, in the case of an individual who performs independent person services, who has a fixed base situated in South Africa.
The
statements of law set forth below are subject to any changes (which may be applied retroactively) in South African law or in the interpretation thereof by the South African tax
authorities,
or in the Treaty, occurring after the date hereof. Holders are strongly urged to consult their own tax advisors as to the consequences under South African, US federal, state and local,
and other applicable laws, of the ownership and disposition of shares or ADSs.
Taxation of dividends
A dividends tax was introduced in South Africa with effect from 1 April 2012. In terms of these provisions, a dividends tax at
the rate of 15% is levied on any dividend declared by a company to a shareholder. The liability to pay such dividends tax is on the shareholder, even though the company generally acts as a withholding
agent. In the case of listed shares the regulated intermediary (being the Central Securities Depository Participant referred to below) is liable to withhold the dividends tax.
In
the absence of any renegotiation of the Treaty, the tax on the dividends paid to a US holder with respect to shares or ADSs, is limited to 5% of the gross amount of the dividends
where a US corporate holder holds directly at least 10% of the voting stock of Sasol. The maximum dividends tax rate is equal to 15% of the gross amount of the dividends in all other cases.
The
definition of a dividend currently means any amount transferred or applied by a company that is a resident (including Sasol) for the benefit or on behalf of any person in respect of
any share in that company, whether that amount is transferred or applied by way of a distribution made by the company, or as consideration for the acquisition of any share in that company. It
specifically excludes any amount transferred or applied by the company that results in a reduction of so-called contributed tax capital (CTC) or constitutes shares in the company or constitutes an
acquisition by the company of its own securities by way of a general repurchase of securities in terms of the JSE Listings Requirements. A distinction is thus made between a general repurchase of
securities and a specific repurchase of securities. If the company embarks upon a general repurchase of securities, the proceeds are not deemed to be a dividend whereas, in the case of a specific
repurchase of
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securities
where the purchase price is not funded out of CTC, the proceeds are likely to constitute a dividend.
The
concept of CTC effectively means the sum of the stated capital or share capital and share premium of a company that existed on 1 January 2011, excluding any transfers from
reserves to the share premium account or stated capital account, plus proceeds from any new issue of shares by a company. Any application of CTC is limited to the holders of a class of shares and
specifically that a distribution of CTC attributable to a specific class of shares must be made proportionately to the number of shares held by a shareholder in a specific class of shares. In other
words, CTC can only be used proportionately by a company and cannot be applied by a company for the benefit of only one specific shareholder. The CTC of the company cannot therefore also be used in
respect of different classes of shares and the CTC of a specific class is ring-fenced.
Taxation of gains on sale or other disposition
With effect from 1 October 2001, South Africa introduced a tax on capital gains, which only applies to South African residents
and to non-residents if the sale is attributable to a permanent establishment of the non-resident or if it relates to an interest in immovable property in South Africa. With effect from
1 October 2007, gains realised on the sale of ordinary shares are automatically deemed to be on capital account, and therefore, subject to capital gains tax, if the ordinary shares have been
held for a continuous period of at least three years by the holder thereof. This deeming provision is limited to ordinary shares and does not extend to preference shares or ADSs. The meaning of the
word "resident" is different for individuals and corporations and is governed by the South African Income Tax Act of 1962 (the Act) and by the Treaty. In the event of conflict, the Treaty, which
contains a tie breaker clause or mechanism to determine residency if a holder is resident in both countries, will prevail. In terms of the Act and the Treaty, a US resident holder
of
shares or ADSs will not be subject to capital gains tax on the disposal of securities held as capital assets unless the securities are linked to a permanent establishment conducted in South Africa.
In contrast, gains on the disposal of securities which are not capital in nature are usually subject to income tax. However, even in the latter case, a US resident holder will not be subject to income
tax unless the US resident holder carries on business in South Africa through a permanent establishment situated therein. In such a case, this gain may be subject to tax in South Africa, but only so
much as is attributable generally to that permanent establishment.
Securities transfer tax
With effect from 1 July 2008, a single security transfer tax of 0,25% was introduced and is applicable to all secondary
transfers of shares. No securities transfer tax (STT) is payable on the issue of securities, even though it is payable on the redemption of securities. STT is payable in South Africa regardless of
whether the transfer is executed within or outside South Africa. A transfer of a dematerialised share can only occur in South Africa.
A
security is also defined as a depository receipt in a company. Accordingly, STT is payable on the transfer of a depository receipt issued by a company. Generally, the central
securities depository that has been accepted as a participant in terms of the Financial Markets Act, No. 19 of 2012 (that commenced on 3 June 2013) is liable for the payment of the STT,
on the basis that the STT is recoverable from the person to whom the security is transferred.
Withholding taxes
A withholding tax of interest at the rate of 15% has been introduced with effect from 1 March 2015. This withholding tax is
reduced to zero percent in terms of the Treaty to the extent that the interest is derived and beneficially owned by a resident of the other Contracting State.
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United States federal income taxation
The following is a general summary of the material US federal income tax consequences of the ownership and disposition of shares or
ADSs to a US holder (as defined below) that holds its shares or ADSs as capital assets. This summary is based on US tax laws, including the Internal Revenue Code of 1986, as amended (the Code),
Treasury regulations, rulings, judicial decisions, administrative pronouncements, all as of the date of this annual report, and all of which are subject to change or changes in interpretation,
possibly with retroactive effect. In addition, this summary is based in part upon the representations of the Depositary and the assumption that each obligation in the Deposit Agreement relating to the
ADSs and any related agreement will be performed in accordance with its terms.
This
summary does not address all aspects of US federal income taxation that may apply to holders that are subject to special tax rules, including US expatriates, insurance companies,
tax-exempt organisations, banks, financial institutions, regulated investment companies, persons subject to the alternative minimum tax or the Medicare tax on net investment income, securities
broker-dealers, traders in securities who elect to apply a mark-to-market method of accounting, persons holding their shares or ADSs as part of a straddle, hedging transaction or conversion
transaction, persons who acquired their shares or ADSs pursuant to the exercise of employee stock options or similar derivative securities or otherwise as compensation, persons who directly or
indirectly hold more than 10% of the total combined voting power of Sasol's shares or persons whose functional currency is not the US dollar. Such holders may be subject to US federal income tax
consequences different from those set forth below.
As
used herein, the term "US holder" means a beneficial owner of shares or ADSs that is:
-
(a)
-
a
citizen or individual resident of the US for US federal income tax purposes;
-
(b)
-
a
corporation (or other entity taxable as a corporation for US federal income tax purposes) created or organised in or under the laws of the US, any state
thereof or the District of Columbia;
-
(c)
-
an
estate whose income is subject to US federal income taxation regardless of its source; or
-
(d)
-
a
trust if a court within the US can exercise primary supervision over the administration of the trust and one or more US persons are authorised to control
all substantial decisions of the trust.
If
a partnership (or other entity or arrangement treated as a partnership for US federal income tax purposes) holds shares or ADSs, the tax treatment of a partner generally will depend
upon the status of the partner and the activities of the partnership. A partner in a partnership that holds shares or ADSs is urged to consult its own tax advisor regarding the specific tax
consequences of the ownership and disposition of the shares or ADSs.
US
holders should consult their own tax advisors regarding the specific South African and US federal, state and local tax consequences of owning and disposing of shares or ADSs in light
of their particular circumstances as well as any consequences arising under the laws of any other taxing jurisdiction. In
particular, US holders are urged to consult their own tax advisors regarding whether they are eligible for benefits under the Treaty.
For
US federal income tax purposes, a US holder of ADSs should be treated as owning the underlying shares represented by those ADSs. The following discussion (except where otherwise
expressly noted) applies equally to US holders of shares and US holders of ADSs. Furthermore, deposits or withdrawals of shares by a US holder for ADSs or ADSs for shares will not be subject to US
federal income tax.
Taxation of distributions
Distributions (without reduction of South African withholding taxes, if any) made with respect to shares or ADSs (other than certain
pro rata distributions of Sasol's capital stock or rights to subscribe for shares of Sasol's capital stock) are includible in the gross income of a US holder as foreign source dividend income on the
date such distributions are received by the US holder, in the case of shares, or by the
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Depositary,
in the case of ADSs, to the extent paid out of Sasol's current or accumulated earnings and profits, if any, as determined for US federal income tax purposes ("earnings and profits"). Any
distribution that exceeds Sasol's earnings and profits will be treated first as a nontaxable return of
capital to the extent of the US holder's tax basis in the shares or ADSs (thereby reducing a US holder's tax basis in such shares or ADSs) and thereafter as either long-term or short-term capital gain
(depending on whether the US holder has held shares or ADSs, as applicable, for more than one year as of the time such distribution is actually or constructively received).
The
amount of any distribution paid in foreign currency, including the amount of any South African withholding tax thereon, will be included in the gross income of a US holder in an
amount equal to the US dollar value of the foreign currency calculated by reference to the spot rate in effect on the date the dividend is actually or constructively received by the US holder, in the
case of shares, or by the Depositary, in the case of ADSs, regardless of whether the foreign currency is converted into US dollars at such time. If the foreign currency is converted into US dollars on
the date of receipt, a US holder of shares generally should not be required to recognise foreign currency gain or loss in respect of the dividend. If the foreign currency received in the distribution
is not converted into US dollars on the date of receipt, a US holder of shares will have a basis in the foreign currency equal to its US dollar value on the date of receipt.
Any
gain or loss recognised upon a subsequent conversion or other disposition of the foreign currency will be treated as US source ordinary income or loss. In the case of a US holder of
ADSs, the amount of any distribution paid in a foreign currency ordinarily will be converted into US dollars by the Depositary upon its receipt. Accordingly, a US holder of ADSs generally will not be
required to recognise foreign currency gain or loss in respect of the distribution. Special rules govern and specific elections are available to accrual method taxpayers to determine the US dollar
amount includable in income in the case of taxes
withheld
in a foreign currency. Accrual basis taxpayers therefore are urged to consult their own tax advisors regarding the requirements and elections applicable in this regard.
Subject
to certain limitations (including a minimum holding period requirement), South African dividend withholding taxes (as discussed above under "Taxation—South African
taxation—Taxation of dividends") will be treated as foreign taxes eligible for credit against a US holder's US federal income tax liability. For this purpose, dividends distributed by
Sasol with respect to shares or ADSs generally will constitute foreign source "passive category income" for most US holders. The use of foreign tax credits is subject to complex conditions and
limitations. In lieu of a credit, a US holder may instead elect to deduct any such foreign income taxes paid or accrued in the taxable year, provided that the US holder elects to deduct (rather than
credit) all foreign income taxes paid or accrued for the taxable year. A deduction for foreign taxes is not subject to the same
limitations applicable to foreign tax credits. US holders are urged to consult their own tax advisors regarding the availability of foreign tax credits.
Dividends
paid by Sasol will not be eligible for the dividends-received deduction generally allowed to US corporations in respect of dividends received from other US corporations.
Certain non-corporate US holders are eligible for preferential rates of US federal income tax in respect of "qualified dividend income". For this purpose, qualified dividend income generally includes
dividends paid by a non-US corporation if, among other things, the US holders meet certain minimum holding periods and the non-US corporation satisfies certain requirements, including that
either:
-
(i)
-
the
shares or the ADSs with respect to which the dividend has been paid are readily tradable on an established securities market in the United States; or
-
(ii)
-
the
non-US corporation is eligible for the benefits of a comprehensive US income tax treaty (such as the Treaty) which provides for the exchange of
information.
82
Table of Contents
Sasol currently believes that dividends paid with respect to its shares and ADSs should constitute qualified dividend income for US federal income tax purposes
(and Sasol anticipates that such dividends will be reported as qualified dividends on Form 1099-DIV delivered to US holders) if Sasol was not, in the year prior to the year in which the
dividend was paid, and is not, in the year in which the dividend is paid, a Passive Foreign Investment Company (PFIC) for US federal income tax purposes. In computing foreign tax credit limitations,
non-corporate US holders may take into account only a portion of a qualified dividend to reflect the reduced US tax rate applicable to such dividend. Each individual US holder of shares or ADSs is
urged to consult his own tax advisor regarding the availability to him of the preferential dividend tax rate in light of his own particular situation and regarding the computations of his foreign tax
credit limitations with respect to any qualified dividend income paid by Sasol to him, as applicable.
Sale, exchange or other taxable disposition of shares or ADSs
Upon a sale, exchange or other taxable disposition of shares or ADSs, a US holder generally will recognise capital gain or loss for US
federal income tax purposes in an amount equal to the difference between the US dollar value of the amount realised on the disposition and the US holder's adjusted tax basis, determined in US dollars,
in the shares or ADSs. Such gain or loss generally will be US source gain or loss, and generally will be treated as a long-term capital gain or loss if the holder's holding period in the shares or
ADSs exceeds one year at the time of disposition if Sasol was not, at any time during the holder's holding period, a PFIC for US federal income tax purposes. The deductibility of capital losses is
subject to significant limitations. If the US holder is an individual, long-term capital gain generally is subject to US federal income tax at preferential rates.
The
tax basis of shares purchased with foreign currency will be the US dollar value of the purchase price on the date of purchase, or the settlement date for the purchase, in the case of
shares traded on an established securities market that are purchased by a cash basis US
holder
(or an accrual basis US holder that so elects). The amount realised on a sale or other disposition of shares for an amount in foreign currency will be the US dollar value of this amount on the
date of sale or disposition (in the case of an accrual basis US holder or the date payment is received (in the case of a cash basis US holder). On the settlement date, the US holder will recognise the
US source foreign currency gain or loss (taxable as ordinary income or loss) equal to the difference (if any) between the US dollar value of the amount received based in the exchange rates in effect
on the date of sale or other disposition and the settlement date. However, in the case of shares traded on an established securities market that are sold by a cash basis US holder (or an accrual basis
US holder that so elects), the amount realised will be based on the exchange rate in effect on the settlement date for the sale, and no exchange gain or loss will be recognised at that time. If an
accrual basis US holder makes an election described above, it must be applied consistently from year to year and cannot be revoked without the consent of the Internal Revenue Service (IRS). If any
South African income tax is withheld on the sale, exchange or other taxable disposition of shares or ADSs, the amount realised by a US holder will include the gross amount of the proceeds of that
sale, exchange or other taxable disposition before deduction of the South African income tax withheld. Any gain and loss recognised by a US holder in respect of the sale, exchange or other taxable
disposition of shares or ADSs generally will be treated as derived from US sources for foreign tax credit purposes. Consequently, in the case of
a gain from the disposition of shares or ADSs that is subject to South African income tax (see "Taxation—South African taxation—Taxation of gains on sale or other disposition"
above), the US holder may not be able to benefit from the foreign tax credit for that South African income tax (i.e., because the gain from the disposition would be US source), unless the US
holder can apply the credit against US federal income tax payable on other income from foreign sources. Alternatively, the US holder may take a deduction for the South African income tax, provided
that the US holder elects to deduct all foreign income taxes paid or accrued for the taxable year.
83
Table of Contents
Passive foreign investment company considerations
Sasol believes that it should not be classified as a PFIC for US federal income tax purposes for the taxable year ended 30 June
2016. US holders are advised, however, that this conclusion is a factual determination that must be made annually and thus may be subject to change. If Sasol were to be classified as a PFIC, the tax
on distributions on its shares or ADSs and on any gains realised upon the disposition of its shares or ADSs may be less favourable than as described herein. Furthermore, dividends paid by a PFIC are
not "qualified dividend income" and are not eligible for the reduced rates of taxation for certain dividends. In addition, each US person that is a shareholder of a PFIC, may be required to file an
annual report disclosing its ownership of shares in a PFIC and certain other information. US holders should consult their own tax advisors regarding the application of the PFIC rules (including
applicable reporting requirements) to their ownership of the shares or ADSs.
US information reporting and backup withholding
Dividend payments made to a holder and proceeds paid from the sale, exchange, or other disposition of shares or ADSs may be subject to
information reporting to the IRS. US federal backup withholding generally is imposed on specified payments to persons who fail to furnish required information. Backup withholding will not apply to a
holder who furnishes a correct taxpayer identification number or certificate of foreign status and makes any other required certification, or who is otherwise exempt from backup withholding. US
persons who are required to establish their exempt status generally must provide IRS Form W-9 (Request for Taxpayer Identification Number and Certification) or applicable substitute form.
Non-US holders generally will not be subject to US information reporting or backup withholding. However, these holders may be required to provide certification of non-US status (generally on IRS
Form W-8BEN, W-8BEN-E or applicable substitute form) in connection with payments received in the United States or through certain US-related financial intermediaries.
Backup
withholding is not an additional tax. Amounts withheld as backup withholding may be credited against a holder's US federal income tax liability. A holder may obtain a refund of
any excess amounts withheld under the backup withholding rules by timely filing the appropriate claim for refund with the IRS and furnishing any required information.
Additional reporting requirements
Under recently enacted legislation and Treasury regulations, US holders who are individuals may be required to report to the IRS on
Form 8938 information relating to their ownership of shares or ADSs, subject to certain exceptions (including an exception for shares or ADSs held in accounts maintained by certain financial
institutions). US holders should consult their tax advisors regarding the effect, if any, of this legislation and these regulations on their obligations to file information reports with respect to the
shares or ADSs.
10.F Dividends and paying agents
Not applicable.
10.G Statement by experts
Not applicable.
10.H Documents on display
All reports and other information that we file with the Securities and Exchange Commission (SEC) may be obtained, upon written request,
from the Bank of New York Mellon, as Depositary for our ADSs at its Corporate Trust office, located at 101 Barclay Street, New York, New York 10286. These reports and other information can also be
inspected without charge and copied at prescribed rates at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. These reports may also be
accessed via the SEC's website (
www.sec.gov
). Also, certain reports and other information concerning us will be available for inspection at the offices
of the NYSE. In addition, all the statutory records of the company and its subsidiaries may be viewed at the registered address of the company in South Africa.
84
Table of Contents
10.I Subsidiary information
Not applicable. For a list of our subsidiaries see Exhibit 8.1 to this annual report on Form 20-F.
85
Table of Contents
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As a group, we are exposed to various market risks associated with our underlying assets, liabilities and anticipated transactions. We
continuously monitor these exposures and enter into derivative financial instruments to reduce these risks. We do not enter into derivative transactions on a speculative basis. All fair values have
been determined using current market pricing models.
The
principal market risks (i.e. the risk of losses arising from adverse movements in market rates and prices) to which we are exposed
are:
-
•
-
foreign exchange rates applicable on conversion of foreign currency transactions as well as on conversion of assets and liabilities to
rand;
-
•
-
commodity prices, mainly crude oil prices; and
-
•
-
interest rates on debt and cash deposits.
Refer
to "Item 18—Annual Financial statements—Note 41 Financial risk management" for a qualitative and quantitative discussion of the group's exposure to these
market
risks. Specific recognition and measurement principles of the interest rate swap are contained within the same reference.The following is a breakdown of our debt arrangements and a summary of fixed
versus floating interest rate exposures for operations. Liabilities reflect principal payments in each year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities—notional
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
|
Fair
value
|
|
|
|
(Rand in millions)
|
|
|
Fixed rate (Rand)
|
|
|
470
|
|
|
1 122
|
|
|
1 653
|
|
|
28
|
|
|
28
|
|
|
1 374
|
|
|
4 675
|
|
|
3 753
|
|
|
Average interest rate
|
|
|
11,64
|
%
|
|
11,15
|
%
|
|
7,93
|
%
|
|
7,92
|
%
|
|
7,
|
%
|
|
8,03
|
%
|
|
|
|
|
|
|
|
Variable rate (Rand)
|
|
|
1 350
|
|
|
5 224
|
|
|
6 777
|
|
|
644
|
|
|
691
|
|
|
780
|
|
|
15 466
|
|
|
16 112
|
|
|
Average interest rate
|
|
|
7,94
|
%
|
|
8,03
|
%
|
|
9,33
|
%
|
|
9,29
|
%
|
|
9,19
|
%
|
|
9,19
|
%
|
|
|
|
|
|
|
|
Fixed Rate (US$)
|
|
|
111
|
|
|
8
|
|
|
8
|
|
|
9
|
|
|
9
|
|
|
14 759
|
|
|
14 904
|
|
|
15 026
|
|
|
Average interest rate
|
|
|
4,52
|
%
|
|
4,52
|
%
|
|
4,52
|
%
|
|
4,52
|
%
|
|
4,52
|
%
|
|
7,00
|
%
|
|
|
|
|
|
|
|
Variable rate (US$)
|
|
|
37
|
|
|
276
|
|
|
1 434
|
|
|
1 515
|
|
|
4 221
|
|
|
36 298
|
|
|
43 781
|
|
|
44 768
|
|
|
Average interest rate
|
|
|
3,04
|
%
|
|
3,03
|
%
|
|
3,02
|
%
|
|
3,00
|
%
|
|
2,91
|
%
|
|
2,91
|
%
|
|
|
|
|
|
|
|
Fixed rate (Euro)
|
|
|
168
|
|
|
75
|
|
|
32
|
|
|
33
|
|
|
29
|
|
|
135
|
|
|
472
|
|
|
515
|
|
|
Average interest rate
|
|
|
1,68
|
%
|
|
1,26
|
%
|
|
1,21
|
%
|
|
1,14
|
%
|
|
1,11
|
%
|
|
1,11
|
%
|
|
|
|
|
|
|
|
Fixed rate (Other currencies)
|
|
|
—
|
|
|
—
|
|
|
853
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
853
|
|
|
853
|
|
|
Average interest rate
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2 995
|
|
|
6 749
|
|
|
9 991
|
|
|
2 316
|
|
|
5 068
|
|
|
53 032
|
|
|
80 151
|
|
|
81 027
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Rand in millions)
|
|
|
Interest rate swap
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average notional amount
|
|
|
29 373
|
|
|
29 373
|
|
|
28 323
|
|
|
26 893
|
|
|
25 361
|
|
|
21 303
|
|
|
|
|
|
3 208
|
|
|
Average receive rate
|
|
|
0,78
|
%
|
|
0,95
|
%
|
|
1,13
|
%
|
|
1,32
|
%
|
|
1,52
|
%
|
|
1,85
|
%
|
|
|
|
|
|
|
|
Average pay rate
|
|
|
2,7
|
%
|
|
2,7
|
%
|
|
2,7
|
%
|
|
2,7
|
%
|
|
2,7
|
%
|
|
2,7
|
%
|
|
|
|
|
|
|
|
Notional at 30 June
|
|
|
29 373
|
|
|
29 373
|
|
|
28 668
|
|
|
27 261
|
|
|
25 754
|
|
|
21 303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable exposure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Swap notional
|
|
|
(9 182
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate debt total
|
|
|
59 247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net variable rate debt
|
|
|
50 065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
Table of Contents
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
12.A Debt securities
Not applicable.
12.B Warrants and rights
Not applicable.
12.C Other securities
Not applicable.
12.D American depositary shares
12.D.1 Depositary name and address
Not applicable.
12.D.2 Description of American depositary shares
Not applicable.
12.D.3 Depositary fees and charges
The Bank of New York Mellon serves as the depositary for Sasol's American Depositary Shares (ADSs). Sasol's ADSs, each representing one
Sasol ordinary share, are traded on the New York Stock Exchange under the symbol "SSL". The ADSs are evidenced by American Depositary Receipts, or ADRs, issued by The Bank of New York
Mellon, as Depositary, under the Deposit Agreement (dated as of 14 July 1994, as amended and restated as of 6 March 2003), among The Bank of New York Mellon, Sasol Limited and its
registered ADR holders. ADR holders are required to pay the following service fees to the Depositary:
|
|
|
|
|
Service
|
|
Fees (USD)
|
|
Depositing or substituting the underlying shares
|
|
Up to US$5,00
per 100 ADS
|
|
Receiving or distributing dividends
|
|
Up to US$0,02
per ADS
|
|
Selling or exercising rights
|
|
Up to US$5,00
per 100 ADS
|
|
Withdrawing an underlying security
|
|
Up to US$5,00
per 100 ADS
|
In
addition, all non-standard out-of-pocket administration and maintenance expenses, including but not limited to, any and all reasonable legal fees and disbursements incurred by the
Depositary (including legal opinions, and any fees and expenses incurred by or waived to third-parties) will be paid by the company. Fees and out-of-pocket expenses for the servicing of non-registered
ADR holders and for any special service(s) performed by the Depositary will be paid for by the company.
12.D.4 Depositary payments for 2016
In terms of the Amended and Restated Deposit Letter Agreement dated as of 21 September 2015 (the Letter Agreement), the
Depositary will pay the company 70% of all dividend fees it collects. These payments will be made to the company within 60 days from the date such fees are collected. During the 2016 financial
year, two payments of $612,839.00 and $588 377.44 were received from the Bank of New York Mellon in respect of the 2015 year end final dividend and the 2016 interim dividend
respectively.
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
Not applicable.
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
Not applicable.
ITEM 15. CONTROLS AND PROCEDURES
(a) Disclosure controls and procedures
The
company's Joint Presidents and Chief Executive Officers and Chief Financial Officer, based on their evaluation of the effectiveness of the group's
disclosure controls and procedures (required by paragraph (b) of 17 CFR 240.13a-15) as of the end of the period covered by this annual report on Form 20-F, have concluded that, as of
such date, the company's
87
Table of Contents
disclosure
controls and procedures were effective.
-
(b)
-
Management's
annual report on internal control over financial reporting
Management
of Sasol is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange
Act of 1934, as amended. Under Section 404 of the Sarbanes-Oxley Act of 2002, management is required to assess the effectiveness of Sasol's internal control over financial reporting as of the
end of each financial year and report, based on that assessment, whether the Company's internal control over financial reporting is effective.
Sasol's
internal control over financial reporting is a process designed under the supervision of the Joint Presidents and Chief Executive Officers and Chief Financial Officer to provide
reasonable assurance as to the reliability of Sasol's financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal
control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly
reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorisations of our management and directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorised acquisition, use or disposition of assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement preparation and presentation.
Management
assessed the effectiveness of Sasol's internal control over financial reporting
as
of 30 June 2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organisations of the Treadway Commission (COSO) in "Internal
Control—Integrated Framework (2013)". Based on this assessment, our management has determined that, as of 30 June 2016, Sasol's internal control over financial reporting was
effective.
-
(c)
-
The
effectiveness of internal control over financial reporting as of 30 June 2016 was audited by PricewaterhouseCoopers Inc., independent
registered public accounting firm, as stated in their report on page F-1 of this Form 20-F.
-
(d)
-
Changes
in internal control over financial reporting
There
were no changes in our internal control over financial reporting that occurred during the year ended 30 June 2016 that have materially affected, or are likely to materially
affect, our internal control over financial reporting as at 30 June 2016.
Item 16.A AUDIT COMMITTEE FINANCIAL EXPERT
Mr. Colin Beggs, an independent member of the audit committee and its chairman since 1 January 2011, was determined by
our board to be the audit committee's financial expert within the meaning of the Sarbanes-Oxley Act, in accordance with the Rules of the NYSE and the SEC.
Item 16.B CODE OF ETHICS
Sasol has a code of ethics that applies to all of our directors, officers and employees, including the Joint Presidents and Chief
Executive Officers, Chief Financial Officer and the Senior Vice President: Financial Control Services. We undertook a comprehensive review of our code in 2014, and adopted the current code with effect
from 1 July 2014. The revised code has been translated into the common languages of all major countries in which we operate, and we conducted an extensive awareness campaign for our employees,
service
88
Table of Contents
providers
and customers. In July 2015, we also adopted a code of ethics for suppliers.
Any
amendment or waiver of the code as it relates to our Joint Presidents and Chief Executive Officers or Chief Financial Officer will be posted on our website within five business days
following such amendment or waiver. No such amendments or waivers are anticipated.
The
code is available on our internet and intranet websites. The website address is http://www.sasol.com/sustainability/ethics.
This
website is not incorporated by reference in this annual report.
We
have been operating an independent ethics reporting telephone line through external advisors since 2002. This confidential and anonymous ethics hotline provides an impartial facility
for all stakeholders to report deviations from ethical behaviour, including fraud and unsafe behaviour or environmental misconduct. Our code of ethics guides our interactions with all government
representatives. Our policy prohibits contributions to political parties or government officials since these may be interpreted as an inducement for future beneficial treatment, and as interference in
the democratic process.
Item 16.C PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table sets forth the aggregate audit and audit-related fees, tax fees and all other fees billed by our principal
accountants (PricewaterhouseCoopers Inc.) for each of the 2016 and 2015 years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audit
fees
|
|
Audit-
related
fees
|
|
Tax
fees
|
|
All
other
fees
|
|
Total
|
|
|
|
(Rand in millions)
|
|
|
2016(1)
|
|
|
85
|
|
|
4
|
|
|
1
|
|
|
—
|
|
|
90
|
|
|
2015(1)
|
|
|
85
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
86
|
|
-
(1)
-
In
respect of our audit committee approval process, all non-audit and audit fees paid to PricewaterhouseCoopers Inc. have been pre-approved by the
audit committee.
Audit
fees consist of fees billed for the annual audit of the company's consolidated
financial
statements, review of the group's internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act and the audit of statutory financial statements
of the company's subsidiaries, including fees billed for assurance and related services that are reasonably related to the performance of the audit or reviews of the company's financial statements
that are services that only an external auditor can reasonably provide.
Audit-related
fees consist of the review of documents filed with regulatory authorities, consultations concerning financial accounting and reporting standards, review of security
controls and operational effectiveness of systems, due diligence related to acquisitions and employee benefit plan audits.
Tax
fees include fees billed for tax compliance services, including assistance in the preparation of original and amended tax returns; tax consultations, such as assistance in connection
with tax audits and appeals; tax advice relating to acquisitions, transfer pricing, and requests for rulings or technical advice from tax authorities; and tax planning services and expatriate tax
compliance, consultation and planning services.
All
other fees consist of fees billed which are not included under audit fees, audit related fees or tax fees.
Audit committee approval policy
In accordance with our audit committee pre-approval policy, all audit and non-audit services performed for us by our independent
accountants were approved by the audit committee of our board of directors, which concluded that the provision of such services by the independent accountants was compatible with the maintenance of
that firm's independence in the conduct of its auditing functions.
In
terms of our policy, non-audit services not exceeding R500 000 that fall into the categories set out in the pre-approval policy, do not require pre-approval by the audit
committee, but are pre-approved by the Senior Vice
89
Table of Contents
President:
Financial Control Services. The audit committee is notified of each such service at its first meeting following the rendering of such service. All non-audit services exceeding
R500 000 but not exceeding R2 million are pre-approved by the Chief Financial Officer, Chairman, and the audit committee is notified on a monthly basis of services approved within
this threshold. Fees in respect of non-audit services exceeding R2 million require pre-approval by the audit committee, prior to engagement.
The
total aggregate amount of non-audit fees in any one financial year must be less than 20% of the total audit fees for Sasol's annual audit engagement, unless otherwise directed by the
audit committee. In addition, services to be provided by the independent accountants that are not within the category of approved services must be approved by the audit committee prior to engagement,
regardless of the service being requested and the amount, but subject to the restriction above.
Requests
or applications for services that require specific separate approval by the audit committee are required to be submitted to the audit committee by both management and the
independent accountants, and must include a detailed description of the services to be provided and a joint statement confirming that the provision of the proposed services does not impair the
independence of the independent accountants.
No
work was performed by persons other than the principal accountant's employees on the principal accountant's engagement to audit Sasol Limited's financial statements for 2016.
Item 16.D EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
Not applicable.
Item 16.E PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Total
number of
shares
repurchased
|
|
Average
price
paid
per
share
|
|
Shares
cancelled
under the
share
repurchase
programme
|
|
Total
number of
shares
purchased
as part of
publicly
announced
programmes
|
|
Maximum
number of
shares
that may
yet be
purchased
under the
programmes(1)
|
|
|
For the year ended 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at 30 June 2015
|
|
|
40 309 886
|
|
|
—
|
|
|
(31 500 000
|
)
|
|
8 809 886
|
|
|
56 268 816
|
|
|
2015-07-01 to 2015-07-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 591 912
|
|
|
2015-08-01 to 2015-08-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 593 482
|
|
|
2015-09-01 to 2015-09-30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 605 882
|
|
|
2015-10-01 to 2015-10-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 607 392
|
|
|
2015-11-01 to 2015-11-30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 608 562
|
|
|
2015-12-01 to 2015-12-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-01-01 to 2015-01-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-02-01 to 2016-02-29
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-03-01 to 2016-03-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-04-01 to 2016-04-30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-05-01 to 2016-05-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-06-01 to 2016-06-30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-07-01 to 2016-07-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-08-01 to 2016-08-31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
2016-09-01 to 2016-09-27
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56 612 922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40 309 886
|
|
|
|
|
|
(31 500 000
|
)
|
|
8 809 886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Approval
is obtained annually at the annual general meeting for a new maximum number of shares to be repurchased.
-
a.
-
At
our annual general meeting held on 4 December 2015, shareholders granted the authority to the directors to approve the repurchase by the company
of its issued securities up to 10% of each of Sasol's ordinary shares and Sasol BEE ordinary shares. The company's issued ordinary shares as at 4 December 2015, was
651 389 516 (21 November 2014—650 787 016) and its issued Sasol BEE ordinary shares as at 4 December 2015, was
2 838 565 (21 November 2014—2 838 565). No shares were repurchased in terms of this authority.
-
b.
-
The
repurchase is limited to a maximum of 10% of the company's securities in the applicable class at the time the authority was granted and no acquisition
may be made at a price more than 10% above the weighted average of the market value of the securities for the five business days immediately preceding the date of such acquisition.
-
c.
-
In
terms of the JSE Limited Listings Requirements and the terms of the resolution, the general authority granted to the directors by shareholders on
4 December 2015 to acquire the company's issued securities will not exceed 15 months from the date of the resolution and will be valid only until the company's next annual general
meeting, which is scheduled for 25 November 2016.
-
d.
-
The
authority granted by shareholders on 21 November 2014, was replaced by a new authority from shareholders on 4 December 2015 to repurchase
Sasol ordinary shares and Sasol BEE ordinary shares. The maximum number of Sasol ordinary shares that could be repurchased between 21 November 2014 and 4 December 2015 amounts to
65 138 951 and the maximum number of Sasol BEE ordinary shares 283 856.
-
e.
-
No
programme was terminated prior to the expiration date. All programme previously approved by shareholders expire at the annual general meeting following
the meeting at which such approval was granted.
90
Table of Contents
Item 16.F CHANGE IN
REGISTRANT'S CERTIFYING ACCOUNTANT
Not applicable.
Item 16.G CORPORATE GOVERNANCE
Sasol maintains a primary listing of its ordinary shares and Sasol BEE ordinary shares on the Johannesburg Stock Exchange operated by
the JSE Limited (JSE) and a listing of American Depositary Shares on the New York Stock Exchange (NYSE). Accordingly, the company is subject to the disclosure, corporate governance and other
requirements imposed by applicable South African and United States legislation, the JSE, the United States Securities and Exchange Commission (SEC) and the NYSE. We have implemented controls to
provide reasonable assurance of our compliance with all relevant requirements in respect of our listings.
We
have compared our corporate governance practices to those for domestic US companies listed on the NYSE and confirm that we comply substantially with such NYSE corporate governance
standards and there were no significant differences at 30 June 2016.
Refer
to "Integrated Report—Our governance framework" as contained in Exhibit 99.10 for further details of our corporate governance practices.
Item 16.H Mine Safety Disclosure
Not applicable.
Item 17. FINANCIAL STATEMENTS
Sasol is furnishing financial statements pursuant to the instructions of Item 18 of Form 20-F.
Item 18. FINANCIAL STATEMENTS
The following consolidated financial statements, together with the auditors' report of PricewaterhouseCoopers Inc. (PwC) are
filed as part of this annual report on Form 20-F:
Index to Consolidated Financial Statements for the years ended 30 June 2016, 2015 and
2014
-
*
-
Refer
to Item 18—"Annual financial statements" which have been incorporated by reference.
91
Table of Contents
Report of Independent Registered Public Accounting Firm
To
the Board of Directors and Shareholders of Sasol Limited
In
our opinion, the accompanying consolidated statements of financial position and the related consolidated statements of income, comprehensive income, changes in equity and cash flows
present fairly, in all material respects, the financial position of Sasol Limited and its subsidiaries at 30 June 2016 and 30 June 2015, and the results of their operations and their
cash flows for each of the three years in
the period ended 30 June 2016 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial reporting as of 30 June 2016, based on criteria established in Internal Control—Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control
Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and International Standards on Auditing. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a
reasonable basis for our opinions.
A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/
PricewaterhouseCoopers Inc.
Johannesburg,
Republic of South Africa
27 September 2016
F-1
Table of Contents
SUPPLEMENTAL OIL AND GAS INFORMATION (unaudited)
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Section 932, "Extractive
Industries—Oil and Gas", and regulations of the US Securities and Exchange Commission (SEC), this section provides supplemental information about natural oil and gas exploration and
production operations that are managed by Exploration and Production International (E&PI). Supplemental information is also provided about our coal mining operations and the conversion of coal
reserves to synthetic oil, as managed by Mining and Sasol Secunda Operations, respectively.
Tables 1
through to 3 provide historical information pertaining to costs incurred for property acquisitions, exploration and development; capitalised costs and results of
operations. Tables 5and 6 present information on standardised measure of estimated discounted future net cash flows related to proved reserves and changes therein.
NATURAL OIL AND GAS
TABLE 1—COSTS INCURRED FOR PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT
ACTIVITIES
The table below provides the costs incurred during the year in natural oil and gas property acquisition, exploration and development
activities, whether capitalised or charged to income currently.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural oil and gas
|
|
|
|
Mozambique
|
|
North America(1)(2)
|
|
Other areas(1)
|
|
|
Year ended 30 June 2014
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
|
|
|
304,9
|
|
|
560,0
|
|
|
297,0
|
|
|
Development
|
|
|
460,5
|
|
|
2 595,1
|
|
|
512,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
|
765,4
|
|
|
3 155,1
|
|
|
809,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2015
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of proved properties
|
|
|
—
|
|
|
—
|
|
|
120,7
|
|
|
Exploration
|
|
|
550,8
|
|
|
—
|
|
|
248,9
|
|
|
Development
|
|
|
636,5
|
|
|
2 923,9
|
|
|
857,7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
|
1 187,3
|
|
|
2 923,9
|
|
|
1 227,3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of proved properties
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Exploration
|
|
|
736,1
|
|
|
—
|
|
|
238,7
|
|
|
Development
|
|
|
745,6
|
|
|
7 447,7
|
|
|
391,7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
|
1 481,7
|
|
|
7 447,7
|
|
|
630,4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
North
America comprises Canada. In 2016, other areas comprises: Gabon, Australia, and South Africa. In 2015 and 2014 other areas also included licences in
which we no longer have any interests.
-
(2)
-
Development
cost in 2016 includes CAD380 million (R4,2 billion), agreed with our partner, Progress Energy, as a settlement of the remaining
funding commitment.
G-1
Table of Contents
TABLE 2—CAPITALISED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
The table below summarises the aggregate amount of property, plant and equipment and intangible assets relating to oil and gas
exploration and production activities, and the aggregate amount of the related depreciation and amortisation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Oil and Gas
|
|
|
|
|
Mozambique
|
|
North America(1)
|
|
Other areas(1)
|
|
|
|
Year ended 30 June 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
|
|
6 717,3
|
|
|
16 447,2
|
|
|
3 221,6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing wells and equipment
|
|
|
|
|
6 013,8
|
|
|
15 660,8
|
|
|
2 395,6
|
|
|
|
Non-producing wells and equipment
|
|
|
|
|
703,5
|
|
|
786,4
|
|
|
826,0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
|
|
|
1 360,6
|
|
|
3 726,6
|
|
|
501,4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalised costs
|
|
|
|
|
8 077,9
|
|
|
20 173,8
|
|
|
3 723,0
|
|
|
|
Accumulated depreciation
|
|
|
|
|
(2 081,6
|
)
|
|
(9 486,3
|
)
|
|
(2 055,7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net book value
|
|
|
|
|
5 996,3
|
|
|
10 687,5
|
|
|
1 667,3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
|
|
8 135,5
|
|
|
20 171,9
|
|
|
3 836,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing wells and equipment
|
|
|
|
|
6 672,5
|
|
|
19 086,0
|
|
|
3 325,0
|
|
|
|
Non-producing wells and equipment
|
|
|
|
|
1 463,0
|
|
|
1 085,9
|
|
|
511,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
|
|
|
1 882,6
|
|
|
1 278,8
|
|
|
216,3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalised costs
|
|
|
|
|
10 018,1
|
|
|
21 450,7
|
|
|
4 052,8
|
|
|
|
Accumulated depreciation
|
|
|
|
|
(2 648,1
|
)
|
|
(10 870,8
|
)
|
|
(2 875,7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net book value
|
|
|
|
|
7 370,0
|
|
|
10 579,9
|
|
|
1 177,1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
|
|
8 992,2
|
|
|
31 030,0
|
|
|
5 099,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing wells and equipment
|
|
|
|
|
8 808,2
|
|
|
30 584,2
|
|
|
5 099,2
|
|
|
|
Non-producing wells and equipment
|
|
|
|
|
184
|
|
|
445,8
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
|
|
|
4 466,0
|
|
|
—
|
|
|
55,9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalised costs
|
|
|
|
|
13 458,2
|
|
|
31 030,0
|
|
|
5 155,1
|
|
|
|
Accumulated depreciation
|
|
|
|
|
(3 274,3
|
)
|
|
(21 927,3
|
)
|
|
(4 545,6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net book value
|
|
|
|
|
10 183,9
|
|
|
9 102,7
|
|
|
609,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
North
America comprises Canada. In 2016, other areas comprises: Gabon, Australia and South Africa. In 2015 and 2014 other areas also included licences in
which we no longer have any interests.
G-2
Table of Contents
TABLE 3—RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
The results of operations for oil and gas producing activities are summarised in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural oil and gas
|
|
|
|
Mozambique
|
|
North America(1)
|
|
Other areas(1)
|
|
|
Year ended 30 June 2014
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated parties
|
|
|
461,6
|
|
|
860,4
|
|
|
1 667,7
|
|
|
Transfers to affiliated parties
|
|
|
2 218,5
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
2 680,1
|
|
|
860,4
|
|
|
1 667,7
|
|
|
Production costs
|
|
|
(533,9
|
)
|
|
(454,4
|
)
|
|
(478,7
|
)
|
|
Foreign currency translation (losses)/gains
|
|
|
(126,0
|
)
|
|
0,1
|
|
|
(11,0
|
)
|
|
Exploration expenses
|
|
|
(115,1
|
)
|
|
—
|
|
|
(259,4
|
)
|
|
Valuation provision
|
|
|
(36,0
|
)
|
|
(5 308,6
|
)
|
|
(95,2
|
)
|
|
Depreciation
|
|
|
(411,4
|
)
|
|
(1 946,6
|
)
|
|
(286,5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit / (loss)
|
|
|
1 457,7
|
|
|
(6 849,1
|
)
|
|
536,9
|
|
|
Tax
|
|
|
(542,7
|
)
|
|
—
|
|
|
(321,3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
|
915,0
|
|
|
(6 849,1
|
)
|
|
215,6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2015
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated parties
|
|
|
392,4
|
|
|
695,5
|
|
|
954,9
|
|
|
Transfers to affiliated parties
|
|
|
3 129,2
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
3 521,6
|
|
|
695,5
|
|
|
954,9
|
|
|
Production costs
|
|
|
(1 102,1
|
)
|
|
(161,8
|
)
|
|
(493,5
|
)
|
|
Foreign currency translation (losses)/gains
|
|
|
(402,0
|
)
|
|
—
|
|
|
(9,4
|
)
|
|
Exploration expenses
|
|
|
(21,7
|
)
|
|
—
|
|
|
(189,7
|
)
|
|
Valuation provision
|
|
|
—
|
|
|
(1 295,6
|
)
|
|
(1 330,7
|
)
|
|
Farm-down losses
|
|
|
—
|
|
|
—
|
|
|
(502,9
|
)
|
|
Depreciation
|
|
|
(569,3
|
)
|
|
(1 604,2
|
)
|
|
(259,7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit/(loss)
|
|
|
1 426,5
|
|
|
(2 366,1
|
)
|
|
(1 831,0
|
)
|
|
Tax
|
|
|
(746,4
|
)
|
|
—
|
|
|
356,8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
|
680,1
|
|
|
(2 366,1
|
)
|
|
(1 474,2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated parties
|
|
|
228,4
|
|
|
466,4
|
|
|
861,4
|
|
|
Transfers to affiliated parties
|
|
|
2 655,2
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
2 883,6
|
|
|
466,4
|
|
|
861,4
|
|
|
Production costs
|
|
|
(440,8
|
)
|
|
(185,8
|
)
|
|
(783,1
|
)
|
|
Foreign currency translation (losses)/gains
|
|
|
(1 053,2
|
)
|
|
—
|
|
|
(2,8
|
)
|
|
Exploration expenses
|
|
|
(108,8
|
)
|
|
—
|
|
|
(71,1
|
)
|
|
Valuation provision
|
|
|
—
|
|
|
(9 882,1
|
)
|
|
(416,8
|
)
|
|
Farm-down losses
|
|
|
347,5
|
|
|
—
|
|
|
(13,7
|
)
|
|
Depreciation
|
|
|
(630,1
|
)
|
|
(1 310,3
|
)
|
|
(1 061,5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit/(loss)
|
|
|
998,2
|
|
|
(10 911,8
|
)
|
|
(1 487,6
|
)
|
|
Tax
|
|
|
589,3
|
|
|
—
|
|
|
389,1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
|
1 587,5
|
|
|
(10 911,8
|
)
|
|
(1 098,5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
North
America comprises Canada. In 2016, other areas comprises: Gabon, Australia, Nigeria and South Africa. In 2015 and 2014, other areas included licences
in which we no longer have any interests.
G-3
Table of Contents
TABLE 4—PROVED RESERVE QUANTITY INFORMATION
The table below summarises the proved developed and proved undeveloped reserves of natural oil and gas, as at 30 June 2016 and
the two previous years, along with volumes produced during the year.
Proved
reserves of synthetic oil is shown separately on page G-6. As at 30 June 2016, the total proved reserve estimate for natural oil and gas is 227,5 million
barrels in oil equivalent terms (6 000 standard cubic feet of natural gas is equivalent to 1 barrel of oil).
The
table below also presents the changes in proved reserves of natural oil and gas over the last three years and identifies the reasons for the changes in the estimates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and condensate
|
|
Natural gas
|
|
Oil equivalent(1)
|
|
|
|
Mozambique(2)
|
|
North
America(3)
|
|
Rest of
Africa(3)
|
|
Total
|
|
Mozambique(2)
|
|
North
America(3)
|
|
Total
|
|
Mozambique
|
|
North
America(3)
|
|
Rest of
Africa(3)
|
|
Total
|
|
|
|
Millions of barrels
|
|
Billions of cubic feet
|
|
Equivalent, Millions of barrels
|
|
|
Balance at 30 June 2013
|
|
|
4,5
|
|
|
0,2
|
|
|
4,3
|
|
|
9,0
|
|
|
1 519,2
|
|
|
47,9
|
|
|
1 567,1
|
|
|
257,6
|
|
|
8,2
|
|
|
4,3
|
|
|
270,1
|
|
|
Revisions
|
|
|
(0,2
|
)
|
|
—
|
|
|
1,2
|
|
|
1,0
|
|
|
(25,7
|
)
|
|
21,8
|
|
|
(3,9
|
)
|
|
(4,4
|
)
|
|
3,6
|
|
|
1,2
|
|
|
0,4
|
|
|
Improved recovery
|
|
|
—
|
|
|
0,1
|
|
|
0,1
|
|
|
0,2
|
|
|
—
|
|
|
24,1
|
|
|
24,1
|
|
|
—
|
|
|
4,1
|
|
|
0,1
|
|
|
4,2
|
|
|
Production
|
|
|
(0,2
|
)
|
|
(0,1
|
)
|
|
(1,4
|
)
|
|
(1,7
|
)
|
|
(105,1
|
)
|
|
(21,3
|
)
|
|
(126,4
|
)
|
|
(17,7
|
)
|
|
(3,6
|
)
|
|
(1,4
|
)
|
|
(22,7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at 30 June 2014
|
|
|
4,1
|
|
|
0,2
|
|
|
4,2
|
|
|
8,5
|
|
|
1 388,4
|
|
|
72,5
|
|
|
1 460,9
|
|
|
235,5
|
|
|
12,3
|
|
|
4,2
|
|
|
252,0
|
|
|
Revisions
|
|
|
0,0
|
|
|
0,1
|
|
|
(1,3
|
)
|
|
(1,2
|
)
|
|
(82,8
|
)
|
|
33,3
|
|
|
(49,5
|
)
|
|
(13,8
|
)
|
|
5,6
|
|
|
(1,3
|
)
|
|
(9,5
|
)
|
|
Improved recovery
|
|
|
0,6
|
|
|
0,2
|
|
|
(0,5
|
)
|
|
0,3
|
|
|
174,7
|
|
|
32,8
|
|
|
207,5
|
|
|
29,7
|
|
|
5,7
|
|
|
(0,5
|
)
|
|
34,9
|
|
|
Production
|
|
|
(0,3
|
)
|
|
(0,2
|
)
|
|
(1,3
|
)
|
|
(1,8
|
)
|
|
(109,2
|
)
|
|
(21,8
|
)
|
|
(131,0
|
)
|
|
(18,5
|
)
|
|
(3,8
|
)
|
|
(1,3
|
)
|
|
(23,6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at 30 June 2015
|
|
|
4,4
|
|
|
0,3
|
|
|
1,1
|
|
|
5,8
|
|
|
1 371,1
|
|
|
116,8
|
|
|
1 487,9
|
|
|
232,9
|
|
|
19,8
|
|
|
1,1
|
|
|
253,8
|
|
|
Revisions
|
|
|
(0,3
|
)
|
|
0,1
|
|
|
0,8
|
|
|
0,6
|
|
|
(42,4
|
)
|
|
0,6
|
|
|
(43,0
|
)
|
|
(7,4
|
)
|
|
0,0
|
|
|
0,8
|
|
|
(6,6
|
)
|
|
Improved recovery
|
|
|
(0,0
|
)
|
|
0,0
|
|
|
0,4
|
|
|
0,4
|
|
|
(3,8
|
)
|
|
27,2
|
|
|
23,4
|
|
|
(0,6
|
)
|
|
4,5
|
|
|
0,4
|
|
|
4,3
|
|
|
Production
|
|
|
(0,3
|
)
|
|
(0,2
|
)
|
|
(1,5
|
)
|
|
(2,0
|
)
|
|
(114,4
|
)
|
|
(20,7
|
)
|
|
(135,1
|
)
|
|
(19,4
|
)
|
|
(3,6
|
)
|
|
(1,5
|
)
|
|
(24,5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at 30 June 2016
|
|
|
3,8
|
|
|
0,2
|
|
|
0,8
|
|
|
4,8
|
|
|
1 210,5
|
|
|
122,7
|
|
|
1 333,2
|
|
|
205,5
|
|
|
20,7
|
|
|
0,8
|
|
|
227,0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2014
|
|
|
1,4
|
|
|
0,2
|
|
|
1,9
|
|
|
3,5
|
|
|
591,7
|
|
|
72,5
|
|
|
664,2
|
|
|
100,0
|
|
|
12,3
|
|
|
1,9
|
|
|
114,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2015
|
|
|
1,1
|
|
|
0,3
|
|
|
1,1
|
|
|
2,5
|
|
|
386,8
|
|
|
103,7
|
|
|
490,5
|
|
|
65,5
|
|
|
17,6
|
|
|
1,1
|
|
|
84,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2016
|
|
|
2,2
|
|
|
0,2
|
|
|
0,8
|
|
|
3,2
|
|
|
738,1
|
|
|
107,9
|
|
|
846,0
|
|
|
125,2
|
|
|
18,2
|
|
|
0,8
|
|
|
144,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2014
|
|
|
2,7
|
|
|
—
|
|
|
2,3
|
|
|
5,0
|
|
|
796,7
|
|
|
—
|
|
|
796,7
|
|
|
135,5
|
|
|
—
|
|
|
2,3
|
|
|
137,8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2015
|
|
|
3,3
|
|
|
0,0
|
|
|
—
|
|
|
3,3
|
|
|
984,3
|
|
|
13,1
|
|
|
997,4
|
|
|
167,4
|
|
|
2,2
|
|
|
—
|
|
|
169,6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2016
|
|
|
1,6
|
|
|
0,0
|
|
|
—
|
|
|
1,6
|
|
|
472,4
|
|
|
14,8
|
|
|
487,2
|
|
|
80,3
|
|
|
2,5
|
|
|
—
|
|
|
82,8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
6 000
standard cubic feet of natural gas is equivalent to 1 barrel of oil.
-
(2)
-
Natural
oil and gas production in Mozambique in 2014, 2015 and 2016 originated from the single operational Pande-Temane PPA field, which comprises more than
15% of our total proved reserves.
-
(3)
-
North
America comprises Canada, Rest of Africa comprises Gabon.
G-4
Table of Contents
Preparation of Reserve Estimates
To ensure natural oil and gas reserves are appropriately estimated, are accurately disclosed and are compliant with current Securities
and Exchange Commission (SEC) regulations and Financial Accounting Standards Board (FASB) requirements, E&PI has established and maintains estimation guidelines, procedures and standards, which are
subject to review by suitably experienced independent external consultants, and a set of internal controls, which are in accordance
with the requirements of the Sarbanes Oxley Act of 2002. The internal controls cover, amongst other matters, the segregation of duties between the asset teams which provide the necessary data, the
corporate reserves team which prepares the reserves estimates, and the corporate authority which is the E&PI executive committee. The controls also include confirmation that the members of the
corporate reserves team are appropriately qualified and experienced and that their compensation arrangements are not materially affected by the reserves.
The
process includes a review of all estimated future production rates and future capital and operating costs to ensure that the assumptions, data, methods and procedures are
appropriate; a review of the technologies used in the estimation process to determine reliability; and arrangements to validate the economic assumptions and to ensure that only accurate, complete and
consistent data are used in the estimation of reserves.
The
technical person within E&PI who is primarily responsible for overseeing the preparation of natural oil and gas reserves is the E&PI Manager: Corporate Reserves and Resources. The
qualifications of the incumbent include a MA and MSc in Mathematics with 38 years' experience in oil and gas exploration and production activities and 29 years' experience in reserves
estimation.
The
definitions of categories of natural oil and gas reserves used in this disclosure are consistent with those set forth in the regulations of the SEC:
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 sales price during the 12-month period prior to the
ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by
contractual arrangements. 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 Sasol's 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.
G-5
Table of Contents
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 before production can commence.
Definitions of Changes to Proved Reserves
The definitions of the changes to Proved Reserves estimates used in this disclosure are consistent with FASB ASC 932-235-50-5.
TABLE 5—STANDARDISED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED RESERVES
The standardised measures of discounted future net cash flows, relating to natural oil and gas proved reserves for the last three
years, are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural oil and gas
|
|
|
|
Mozambique(1)
|
|
North
America(2)
|
|
Rest of
Africa(2)
|
|
|
Year ended 30 June 2014
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
|
50 748,4
|
|
|
3 172,9
|
|
|
5 188,9
|
|
|
Future production costs
|
|
|
(6 446,9
|
)
|
|
(3 220,5
|
)
|
|
(2 498,5
|
)
|
|
Future development costs
|
|
|
(6 705,0
|
)
|
|
(1 384,5
|
)
|
|
(1 507,8
|
)
|
|
Future income taxes
|
|
|
(12 498,0
|
)
|
|
—
|
|
|
(690,9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
25 098,6
|
|
|
(1 432,1
|
)
|
|
491,7
|
|
|
10% annual discount for timing of estimated cash flows
|
|
|
(11 597,5
|
)
|
|
1 031,6
|
|
|
(31,3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardised measure of discounted future net cash flows
|
|
|
13 501,1
|
|
|
(400,5
|
)
|
|
460,4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2015
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
|
48 356,0
|
|
|
3 908,1
|
|
|
1 006,0
|
|
|
Future production costs
|
|
|
(7 879,1
|
)
|
|
(3 122,6
|
)
|
|
(1 139,5
|
)
|
|
Future development costs
|
|
|
(6 825,3
|
)
|
|
(1 830,4
|
)
|
|
(927,9
|
)
|
|
Future income taxes
|
|
|
(11 060,1
|
)
|
|
—
|
|
|
(100,4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
22 591,5
|
|
|
(1 044,9
|
)
|
|
(1 161,8
|
)
|
|
10% annual discount for timing of estimated cash flows
|
|
|
(9 941,5
|
)
|
|
882,9
|
|
|
229,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardised measure of discounted future net cash flows
|
|
|
12 650,0
|
|
|
(162,0
|
)
|
|
(932,6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended 30 June 2016
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
|
31 758,7
|
|
|
3 306,5
|
|
|
507, 5
|
|
|
Future production costs
|
|
|
(6 445,2
|
)
|
|
(3 140,9
|
)
|
|
(967,2
|
)
|
|
Future development costs
|
|
|
(7 394,8
|
)
|
|
(2 436,4
|
)
|
|
(889,7
|
)
|
|
Future income taxes
|
|
|
(6 677,0
|
)
|
|
0,0
|
|
|
(50,6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
11 241,7
|
|
|
(2 270,8
|
)
|
|
(1 400,0
|
)
|
|
10% annual discount for timing of estimated cash flows
|
|
|
(3 797,0
|
)
|
|
1 118,1
|
|
|
224,8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardised measure of discounted future net cash flows
|
|
|
7 444,7
|
|
|
(1 152,7
|
)
|
|
(1 175,2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Mozambique
values for 2014 were recalculated in 2015.
-
(2)
-
North
America comprises Canada, Rest of Africa comprises Gabon.
The
undiscounted future net cash flows for Canada in 2014, 2015 and 2016 and for Gabon in 2015 and 2016 are negative as a result of future production and development costs, primarily
contractually committed costs and asset retirement costs, which are not directly related to future production or dependent upon the continuation of production and will be incurred even in the event of
no future production. For both assets these costs are fully responsible for the negative future cash flow.
In
Canada, the cost of unused gas transportation capacity is included in production cost. We market the unused capacity on an ad hoc basis and though such marketing has been successful
in the past, no future revenue from this marketing is included in the calculation of the standardised measure of discounted future net cash flows.
Standardised Measure of Discounted Future Net Cash Flows
The standardised measure of discounted future net cash flows, relating to the proved reserves in the table above, are calculated in
accordance with 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. 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 allowances 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.
G-6
Table of Contents
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 companies' future cash flows or value of natural oil and gas reserves.
TABLE 6—CHANGES IN THE STANDARDISED MEASURE OF DISCOUNTED NET CASH FLOWS
The changes in standardised measure of discounted future net cash flows, relating to the Proved Reserves are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural oil and gas
|
|
|
|
|
|
|
Mozambique(1)
|
|
North
America(2)
|
|
Rest of
Africa(2)
|
|
|
|
Present value at 30 June 2013
|
|
|
|
|
13 166,0
|
|
|
|
(1 063,6
|
)
|
|
|
184,6
|
|
|
|
|
Net changes for the year
|
|
|
|
|
335,1
|
|
|
|
663,1
|
|
|
|
275,8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced net of production costs
|
|
|
|
|
(2 377,0
|
)
|
|
|
(158,1
|
)
|
|
|
(1 285,3
|
)
|
|
|
|
Development costs incurred
|
|
|
|
|
569,8
|
|
|
|
3 155,2
|
|
|
|
661,1
|
|
|
|
|
Net change due to current reserves estimates from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Improved recovery
|
|
|
|
|
—
|
|
|
|
272,0
|
|
|
|
53,5
|
|
|
|
|
Revisions
|
|
|
|
|
567,3
|
|
|
|
889,0
|
|
|
|
1 038,1
|
|
|
|
|
Net changes in prices and costs related to future production
|
|
|
|
|
(734,9
|
)
|
|
|
(328,5
|
)
|
|
|
(121,0
|
)
|
|
|
|
Changes in estimated future development costs
|
|
|
|
|
(1 138,8
|
)
|
|
|
(3 047,7
|
)
|
|
|
(35,7
|
)
|
|
|
|
Accretion of discount
|
|
|
|
|
1 920,7
|
|
|
|
(106,4
|
)
|
|
|
58,1
|
|
|
|
|
Net change in income tax
|
|
|
|
|
(333,0
|
)
|
|
|
—
|
|
|
|
(149,5
|
)
|
|
|
|
Net change due to exchange rate
|
|
|
|
|
1 861,0
|
|
|
|
(12,4
|
)
|
|
|
56,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value at 30 June 2014
|
|
|
|
|
13 501,1
|
|
|
|
(400,5
|
)
|
|
|
460,4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net changes for the year
|
|
|
|
|
(851,1
|
)
|
|
|
238,5
|
|
|
|
(1 393,0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced net of production costs
|
|
|
|
|
(3 317,7
|
)
|
|
|
(506,8
|
)
|
|
|
(662,0
|
)
|
|
|
|
Development costs incurred
|
|
|
|
|
853,8
|
|
|
|
2 930,0
|
|
|
|
855,0
|
|
|
|
|
Net change due to current reserves estimates from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Improved recovery
|
|
|
|
|
2 208,6
|
|
|
|
291,4
|
|
|
|
(381,5
|
)
|
|
|
|
Revisions
|
|
|
|
|
(1 349,3
|
)
|
|
|
1 118,6
|
|
|
|
(771,0
|
)
|
|
|
|
Net changes in prices and costs related to future production
|
|
|
|
|
(5 216,4
|
)
|
|
|
(440,7
|
)
|
|
|
(1 052,6
|
)
|
|
|
|
Changes in estimated future development costs
|
|
|
|
|
(14,9
|
)
|
|
|
(3 114,3
|
)
|
|
|
(102,2
|
)
|
|
|
|
Accretion of discount
|
|
|
|
|
1 987,5
|
|
|
|
(40,1
|
)
|
|
|
100,7
|
|
|
|
|
Net change in income tax
|
|
|
|
|
769,6
|
|
|
|
0,0
|
|
|
|
457,2
|
|
|
|
|
Net change due to exchange rate
|
|
|
|
|
3 227,7
|
|
|
|
0,4
|
|
|
|
163,4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value at 30 June 2015
|
|
|
|
|
12 650,0
|
|
|
|
(162,0
|
)
|
|
|
(932,6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net changes for the year
|
|
|
|
|
(5 205,3
|
)
|
|
|
(990,7
|
)
|
|
|
(242,6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced net of production costs
|
|
|
|
|
(2 394,0
|
)
|
|
|
(521,5
|
)
|
|
|
(209,1
|
)
|
|
|
|
Development costs incurred
|
|
|
|
|
637,7
|
|
|
|
2 205,9
|
|
|
|
570,6
|
|
|
|
|
Net change due to current reserves estimates from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Reduced)/improved recovery
|
|
|
|
|
(88,3
|
)
|
|
|
182,0
|
|
|
|
213,5
|
|
|
|
|
Revisions
|
|
|
|
|
697,7
|
|
|
|
333,9
|
|
|
|
501,8
|
|
|
|
|
Net changes in prices and costs related to future production
|
|
|
|
|
(11 445,5
|
)
|
|
|
(580,1
|
)
|
|
|
(739,3
|
)
|
|
|
|
Changes in estimated future development costs
|
|
|
|
|
(213,1
|
)
|
|
|
(2 565,8
|
)
|
|
|
(354,1
|
)
|
|
|
|
Accretion of discount
|
|
|
|
|
1 825,4
|
|
|
|
(16,2
|
)
|
|
|
(84,3
|
)
|
|
|
|
Net change in income tax
|
|
|
|
|
1 775,2
|
|
|
|
0,0
|
|
|
|
43,1
|
|
|
|
|
Net change due to exchange rate
|
|
|
|
|
3 999,6
|
|
|
|
(28,9
|
)
|
|
|
(184,8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value at 30 June 2016
|
|
|
|
|
7 444,7
|
|
|
|
(1 152,7
|
)
|
|
|
(1 175,2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Mozambique
values for 2014 have been recalculated in 2015.
-
(2)
-
North
America comprises of Canada, Rest of Africa comprises of Gabon.
G-7
Table of Contents
SYNTHETIC OIL
TABLE 1—COSTS INCURRED FOR PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT
ACTIVITIES
The table below provides the costs incurred during the year in synthetic oil property acquisition, exploration and development
activities, whether capitalised or charged to income currently.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic oil—South Africa
|
|
|
Year ended 30 June
|
|
2016
|
|
2015
|
|
2014
|
|
|
Acquisition of proved properties
|
|
|
11,8
|
|
|
174,4
|
|
|
561,0
|
|
|
Exploration
|
|
|
154,3
|
|
|
148,0
|
|
|
85,5
|
|
|
Development
|
|
|
3 014,4
|
|
|
4 729,7
|
|
|
6 265,5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
|
3 180,5
|
|
|
5 052,1
|
|
|
6 912,0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE 2—CAPITALISED COSTS RELATING TO SYNTHETIC OIL ACTIVITIES
The table below summarises the aggregate amount of property, plant and equipment and intangible assets relating to synthetic oil and
production activities, and the aggregate amount of the related depreciation and amortisation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic oil—South Africa
|
|
|
|
Year ended 30 June
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
Proved properties
|
|
|
|
|
85 985,0
|
|
|
78 711,2
|
|
|
68 636,9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing wells and equipment
|
|
|
|
|
85 985,0
|
|
|
71 191,5
|
|
|
63 279,9
|
|
|
|
Non-producing wells and equipment
|
|
|
|
|
—
|
|
|
7 519,7
|
|
|
5 357,0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalised costs
|
|
|
|
|
85 985,0
|
|
|
78 711,2
|
|
|
68 636,9
|
|
|
|
Accumulated depreciation
|
|
|
|
|
(26 027,6
|
)
|
|
(22 853,3
|
)
|
|
(19 699,6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net book value
|
|
|
|
|
59 957,4
|
|
|
55 857,9
|
|
|
48 937,3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE 3—RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
The results of operations for synthetic oil activities are summarised in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic oil—South Africa
|
|
|
Year ended 30 June
|
|
2016
|
|
2015
|
|
2014
|
|
|
Sales to unaffiliated parties
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Transfers to affiliated parties
|
|
|
33 428,4
|
|
|
45 709,4
|
|
|
59 912,7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
33 428,4
|
|
|
45 709,4
|
|
|
59 912,7
|
|
|
Production costs
|
|
|
(18 557,3
|
)
|
|
(14 543,2
|
)
|
|
(19 250,0
|
)
|
|
Foreign currency translation gains / (losses)
|
|
|
8,6
|
|
|
(11,1
|
)
|
|
1,5
|
|
|
Exploration expenses
|
|
|
(47,0
|
)
|
|
(45,0
|
)
|
|
(47,5
|
)
|
|
Depreciation
|
|
|
(5 395,0
|
)
|
|
(4 511,8
|
)
|
|
(4 253,2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit/(loss)
|
|
|
9 437,7
|
|
|
26 598,3
|
|
|
36 363,5
|
|
|
Tax
|
|
|
(2 600,2
|
)
|
|
(6 954,4
|
)
|
|
(10 879,2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
|
6 837,5
|
|
|
19 643,9
|
|
|
25 484,3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE 4—PROVED RESERVE QUANTITY INFORMATION
The table below summarises proved developed and proved undeveloped reserves of synthetic oil as at 30 June 2016, for the last
three years. As at 30 June 2016, the total proved reserve estimate for synthetic oil is 990,9 million barrels in oil equivalent terms.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic oil—South
Africa
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
Opening balance
|
|
|
1 042,5
|
|
|
680,7
|
|
|
713,3
|
|
|
Revisions
|
|
|
—
|
|
|
413,6
|
|
|
19,1
|
|
|
Recovery/ (loss)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Production
|
|
|
(51,6
|
)
|
|
(51,8
|
)
|
|
(51,7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at 30 June
|
|
|
990,9
|
|
|
1 042,5
|
|
|
680,7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
990,9
|
|
|
1 042,5
|
|
|
680,7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE 5—STANDARDISED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic oil—South Africa
|
|
|
Year ended 30 June
|
|
2016
|
|
2015(1)
|
|
2014
|
|
|
Future cash inflows
|
|
|
630 028,9
|
|
|
906 161,1
|
|
|
767 028,1
|
|
|
Future production costs
|
|
|
(341 767,1
|
)
|
|
(346 619,9
|
)
|
|
(245 502,2
|
)
|
|
Future development costs
|
|
|
(183 888,3
|
)
|
|
(181 021,4
|
)
|
|
(98 658,3
|
)
|
|
Future income taxes
|
|
|
(36 878,3
|
)
|
|
(114 069,6
|
)
|
|
(124 676,7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
67 495,2
|
|
|
264 450,3
|
|
|
298 190,9
|
|
|
10% annual discount for timing of estimated cash flows
|
|
|
(43 046,6
|
)
|
|
(160 169,1
|
)
|
|
(135 347,7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardised measure of discounted future net cash flows
|
|
|
24 448,6
|
|
|
104 281,2
|
|
|
162 843,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Standardised
measure of discounted future net cash flows at 30 June 2015 has been restated to correct the allocation of future development costs. In
2015, the useful life of Secunda Synfuels Operations was extended to 2050, which exceeded the quantities of the proved coal reserves. The future development costs are now allocated in line with proved
coal reserves and not on total synthetic oil production as used previously.
The
standardised measure of discounted future net cash flows, relating to the proved reserves in the table above, are calculated in accordance with the requirements of FASB ASC
Section 932-235.
TABLE 6—CHANGES IN THE STANDARDISED MEASURE OF DISCOUNTED NET CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic oil—South Africa
|
|
|
|
|
|
|
2016
|
|
2015(1)
|
|
2014
|
|
|
|
Present value—opening balance
|
|
|
|
|
104 281,2
|
|
|
162 843,1
|
|
|
120 917,2
|
|
|
|
Net changes for the year
|
|
|
|
|
(79 832,5
|
)
|
|
(58 562,1
|
)
|
|
41 925,9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced net of production costs
|
|
|
|
|
(14 871,2
|
)
|
|
(31 166,1
|
)
|
|
(40 662,7
|
)
|
|
|
Development costs incurred
|
|
|
|
|
9 367,1
|
|
|
11 369,9
|
|
|
12 299,3
|
|
|
|
Net change due to current reserves estimates from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Improved recovery
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Commercial arrangements
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Revisions
|
|
|
|
|
3 527,6
|
|
|
30 491,1
|
|
|
11 418,2
|
|
|
|
Net changes in prices and costs related to future production
|
|
|
|
|
(173 986,8
|
)
|
|
(123 966,6
|
)
|
|
(5 241,1
|
)
|
|
|
Changes in estimated future development costs
|
|
|
|
|
(8 348,0
|
)
|
|
(20 968,8
|
)
|
|
(9 021,3
|
)
|
|
|
Accretion of discount
|
|
|
|
|
9 441,1
|
|
|
14 599,3
|
|
|
10 958,5
|
|
|
|
Net change in income tax
|
|
|
|
|
35 442,4
|
|
|
28 759,1
|
|
|
(9 366,6
|
)
|
|
|
Net change due to exchange rate
|
|
|
|
|
59 595,3
|
|
|
32 320,0
|
|
|
71 541,6
|
|
|
|
|
|
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|
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|
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Present value at 30 June
|
|
|
|
|
24 448,7
|
|
|
104 281,0
|
|
|
162 843,1
|
|
|
|
|
|
|
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|
|
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|
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|
-
(1)
-
Standardised
measure of discounted future net cash flows at 30 June 2015 has been restated to correct the allocation of future development costs. In
2015, the useful life of Secunda Synfuels Operations was extended to 2050, which exceeded the quantities of the proved coal reserves. The future development costs are now allocated in line with proved
coal reserves and not on total synthetic oil production as used previously.
Standardised Measure of Discounted Future Net Cash Flows
The standardised measure of discounted future net cash flows, relating to the proved reserves in the table above, are calculated in
accordance with 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. 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
G-9
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