Eskom Holdings Soc Ltd

ESKOM HOLDINGS SOC LTD

(Registration Number 2002/015527/30) (incorporated with limited liability in the Republic of South Africa) U.S.$4,000,000,000 Global Medium Term Note Programme

Under this Global Medium Term Note Programme (the “Programme”), Eskom Holdings SOC Ltd (the “Issuer”, the “Company” or “Eskom” and, together with its consolidated subsidiaries, the “Group”), subject to compliance with all relevant laws, regulations and directives, may from time to time issue notes (the “Notes”) denominated in any currency agreed between the Issuer and the relevant Dealer (as defined below). Notes may be issued in bearer or registered form (respectively “Bearer Notes” and “Registered Notes”). The maximum aggregate nominal amount of all Notes from time to time outstanding under the Programme will not exceed U.S.$4,000,000,000 (or its equivalent in other currencies calculated as provided for in the Dealer Agreement described herein), subject to increase as described herein. The Notes may be issued on a continuing basis to one or more of the Dealers specified under “Overview of the Issuer and the Programme” and any additional Dealer appointed under the Programme from time to time by the Issuer (each a “Dealer” and, together, the “Dealers”), which appointment may be for a specific issue or on an ongoing basis. References in this Base Prospectus to the “relevant Dealer” shall, in the case of an issue of Notes being (or intended to be) subscribed for by more than one Dealer, be to all Dealers agreeing to subscribe for such Notes. An investment in Notes issued under the Programme involves certain risks. For a discussion of these risks see “Risk Factors”. Application has been made to the Commission de Surveillance du Secteur Financier (the “CSSF”) in its capacity as competent authority under the Luxembourg law of 10 July 2005 on prospectuses for securities (the “Law on Prospectuses for Securities”) to approve this document as a base prospectus for the purposes of Directive 2003/71/EC (the “Prospectus Directive”) as amended (which includes amendments made by Directive 2010/73/EU (the “2010 PD Amending Directive”) to the extent that such amendments have been implemented in any Member State of the European Economic Area (the “EEA”) which has implemented the Prospectus Directive (“Relevant Member State”)). Application has also been made to the Luxembourg Stock Exchange for Notes issued under this Base Prospectus to be admitted to trading on the Bourse de Luxembourg, which is the regulated market in Luxembourg (the “Market”) and to be listed on the Official List of the Luxembourg Stock Exchange (the “Official List”). The Market is a regulated market for the purposes of the Markets in Financial Instruments Directive 2004/39/EC (“MiFID”). However, Notes may be issued under the Programme which will not be listed on the Official List or on any other stock exchange, and the Final Terms (as defined below) applicable to the Notes in a series will specify whether or not Notes in such series will be listed on the Official List or on any other stock exchange. Notice of the aggregate nominal amount of Notes, interest (if any) payable in respect of Notes, the issue price of Notes and any other terms and conditions not contained herein which are applicable to each Tranche (as defined under “Terms and Conditions of the Notes”) of Notes will be set out in a final terms document (the “Final Terms”) or in a drawdown prospectus (“Drawdown Prospectus”) which, with respect to Notes to be listed on the Luxembourg Stock Exchange, will be delivered to the CSSF and the Luxembourg Stock Exchange. The CSSF assumes no responsibility for the economic and financial soundness of the transactions contemplated by this Base Prospectus or the quality or solvency of the Issuer in accordance with Article 7(7) of the Prospectus Act 2005. The Programme is rated Ba1 by Moody’s Investors Service Ltd. (“Moody’s”) and BBB- by Standard & Poor’s Credit Market Services Europe Limited (“S&P”). Each of Moody’s and S&P is established in the European Union (“EU”) and is included in the list of credit rating agencies registered in accordance with Regulation (EC) No. 1060/2009 on Credit Rating Agencies as amended by Regulation (EU) No 513/2011 (the “CRA Regulation”). Where a Series (as defined under “Terms and Conditions of the Notes”) of Notes issued under the Programme is to be rated, such rating will be specified in the applicable Final Terms or relevant Drawdown Prospectus. A rating is not a recommendation to buy, sell or hold securities and may be subject to suspension, reduction or withdrawal at any time by the assigning rating agency. This Base Prospectus should be read and construed together with any supplement hereto. Further, in relation to any series of Notes, this Base Prospectus should be read and construed together with the relevant Final Terms or relevant Drawdown Prospectus. As described further in this Base Prospectus, the prior written approval of the Financial Surveillance Department (“ExCon”) of the South African Reserve Bank (the “SARB”) will be required for each Tranche of Notes issued under the Programme. Arrangers and Permanent Dealers

AFRICA RISING CAPITAL BASIS POINTS CAPITAL DEUTSCHE BANK

PAMOJA CAPITAL RAND MERCHANT BANK STANDARD BANK

The date of this Base Prospectus is 23 January 2015

This Base Prospectus constitutes a base prospectus for the purpose of Article 5.4 of the Prospectus Directive and the Law on Prospectuses for Securities implementing the Prospectus Directive in Luxembourg, and for the purpose of giving information with regard to the Issuer, the Group and the Notes, which is necessary to enable investors to make an informed assessment of the assets and liabilities, financial position, profit and loss and prospects of the Issuer and of the rights attaching to the Notes. The Issuer accepts responsibility for the information contained in this Base Prospectus and the Final Terms for each Tranche of Notes issued under the Programme. To the best of the knowledge and belief of the Issuer (which has taken all reasonable care to ensure that such is the case), the information contained in this Base Prospectus is in accordance with the facts and does not omit anything likely to affect the import of such information. This Base Prospectus is to be read in conjunction with all documents which are deemed to be incorporated herein by reference (see “Documents Incorporated by Reference”). This Base Prospectus shall be read and construed on the basis that such documents are incorporated in, and form part of, this Base Prospectus. Copies of the Final Terms or Drawdown Prospectus will be available from the registered office of the Issuer and the specified office set out below of each of the Paying Agents (as defined below). Certain information under the heading “Book Entry, Settlement and Clearance” has been extracted from information provided by the clearing systems referred to therein. The Issuer confirms that such information has been accurately reproduced and that, so far as it is aware, and is able to ascertain from information published by the relevant clearing systems, no facts have been omitted which would render the reproduced information inaccurate or misleading. No representation, warranty or undertaking, express or implied, is made and no responsibility or liability is accepted by the Arrangers or the Dealers (each as defined in “Overview of the Issuer and the Programme”) as to the accuracy or completeness of the information contained or incorporated by reference in this Base Prospectus or any other information provided in relation to the Programme. In making an investment decision, prospective investors must rely on their own examination of the Issuer and the Group and the terms of the relevant Tranche of Notes, including the merits and risks involved. Prospective investors should not construe anything in this Base Prospectus as legal, business or tax advice. Each prospective investor contemplating purchasing any Notes should consult its own advisers as needed to make its investment decision and to determine whether it is legally permitted to purchase the securities under applicable legal investment or similar laws or regulations. None of the Arrangers, Dealers or Citicorp Trustee Company Limited as trustee (the “Trustee” which expression shall include any successor trustee) undertakes to review the financial condition or affairs of the Issuer or the Group during the life of the arrangements contemplated by the Base Prospectus or to advise any investor or potential investors in Notes of any information coming to their attention. No Arranger, Dealer or the Trustee accepts any liability in relation to the information contained or incorporated by reference in this Base Prospectus or any other information provided by the Issuer in connection with the Programme. Investors acknowledge that they have not relied, and will not rely, on the Arrangers or Dealers in connection with their investigation of the accuracy of any information or their decision whether to invest in the Notes. No person is or has been authorised to give any information or to make any representation other than those contained in this Base Prospectus in connection with the issue or sale of the Notes and, if given or made, such information or representation must not be relied upon as having been authorised by the Issuer or any Arranger or Dealer. Neither the delivery of this Base Prospectus nor the offering, sale or delivery of any Notes shall in any circumstances imply that the information contained herein concerning the Issuer is correct at any time subsequent to the date hereof or that any other information supplied in connection with the Programme is correct as of any time subsequent to the date indicated in the document containing the same. The Arrangers, the Dealers and the Trustee expressly do not undertake to review the financial condition or affairs of the Issuer throughout the life of the Programme or to advise any investor in the Notes of any information coming to their attention. Notes in bearer form are subject to U.S. tax law requirements and may not be offered, sold or delivered within the United States or its possessions or to United States persons, except in certain transactions permitted by

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U.S. Treasury regulations. Terms used in this paragraph have the meanings given to them by the U.S. Internal Revenue Code of 1986 and the U.S. Treasury regulations promulgated thereunder. This Base Prospectus does not constitute an offer to sell or the solicitation of an offer to buy any Notes in any jurisdiction to any person to whom it is unlawful to make the offer or solicitation in such jurisdiction. The distribution of this Base Prospectus and the offer or sale of Notes may be restricted by law in certain jurisdictions. The Issuer, the Arrangers, the Dealers and the Trustee do not represent that this Base Prospectus may be lawfully distributed, or that any Notes may be lawfully offered, in compliance with any applicable registration or other requirements in any such jurisdiction, or pursuant to an exemption available thereunder, or assume any responsibility for facilitating any such distribution or offering. In particular, no action has been taken by the Issuer, the Arrangers, the Dealers or the Trustee which is intended to permit a public offering of any Notes or distribution of this Base Prospectus in any jurisdiction where action for that purpose is required. Accordingly, no Notes may be offered or sold, directly or indirectly, and neither this Base Prospectus nor any advertisement or other offering material may be distributed or published in any jurisdiction, except under circumstances that will result in compliance with any applicable laws and regulations. Persons into whose possession this Base Prospectus or any Notes may come must inform themselves about, and observe, any such restrictions on the distribution of this Base Prospectus and the offering and sale of Notes. In particular, there are restrictions on the distribution of this Base Prospectus and the offer or sale of Notes in the United States, the United Kingdom and the Republic of South Africa (“South Africa”). See “Subscription and Sale and Transfer and Selling Restrictions”. None of the Arrangers, the Dealers, the Issuer or the Trustee makes any representation to any investor regarding the legality of its investment under any applicable laws. Any investor should be able to bear the economic risk of an investment in the Notes for an indefinite period of time. In making an investment decision, an investor must rely on its own independent examination of the Issuer and the Group and the terms of the Notes being offered, including the merits of the risks involved. The Notes have not been approved or disapproved by the United States Securities Exchange Commission (the “SEC”) or any other securities commission or other regulatory authority in the United States, nor have the foregoing authorities approved this Base Prospectus or confirmed the accuracy or determined the adequacy of the information contained in this Base Prospectus. Any representation to the contrary is unlawful. Registered Notes may be offered or sold within the United States only to “qualified institutional buyers” within the meaning of Rule 144A of the U.S. Securities Act of 1933, as amended (the “Securities Act”) (“QIBs”). Each U.S. purchaser of Registered Notes is hereby notified that the offer and sale of any Registered Notes to it may be being made in reliance upon the exemption from the registration requirements of the Securities Act provided by Rule 144A under the Securities Act (“Rule 144A”). U.S. INFORMATION

Each purchaser or holder of Notes represented by a Rule 144A Global Note (as defined in “Form of the Notes—Registered Notes”) or any Notes issued in registered form in exchange or substitution therefor (together “Legended Notes”) will be deemed, by its acceptance or purchase of any such Legended Notes, to have made certain representations and agreements intended to restrict the resale or other transfer of such Notes as set out in “Subscription and Sale and Transfer and Selling Restrictions”. Unless otherwise stated, terms used in this paragraph have the meanings given to them in “Form of the Notes”. NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENCE HAS BEEN FILED UNDER RSA 421-B OF THE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENCED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE OF NEW HAMPSHIRE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE,

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TO ANY PROSPECTIVE PURCHASER, CUSTOMER OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH. NOTICE TO SOUTH AFRICAN INVESTORS

The Notes may not be, and accordingly are not being, offered or sold to the public in South Africa. Accordingly, any offer of Notes will not be an “offer to the public” as defined in section 95(1)(h) of the South African Companies Act, 2008 (the “SA Companies Act”). This Base Prospectus does not, nor is it intended to, constitute a “registered prospectus” (as that term is defined in section 95(1)(k) of the SA Companies Act) prepared and registered under the SA Companies Act. No Notes will be offered or sold to prospective investors in South Africa other than on a reverse-solicitation basis and pursuant to section 96(1) of the SA Companies Act. NOTICE TO EEA INVESTORS

This Base Prospectus has been prepared on the basis that any offer of Notes in any Member State of the EEA which has implemented the Prospectus Directive (each, a “Relevant Member State”) will be made pursuant to an exemption under the Prospectus Directive, as implemented in that Relevant Member State, from the requirement to publish a prospectus for offers of Notes. Accordingly, any person making or intending to make an offer in that Relevant Member State of Notes which are the subject of an offering contemplated in this Base Prospectus as completed by the Final Terms or Drawdown Prospectus in relation to the offer of those Notes may only do so in circumstances in which no obligation arises for the Issuer or any Dealer to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive, in each case, in relation to such offer. Neither the Issuer nor any Dealer has authorised, nor do they authorise, the making of any offer of the Notes in circumstances in which an obligation arises for the Issuer or any Dealer to publish or supplement a prospectus for such offer. STABILISATION

In connection with the issue of any Tranche of Notes, the Dealer or Dealers (if any) named as the Stabilising Manager(s) (or persons acting on behalf of any Stabilising Manager(s)) in the applicable Final Terms or relevant Drawdown Prospectus may over allot Notes or effect transactions with a view to supporting the market price of the Notes at a level higher than that which might otherwise prevail. However, there is no assurance that the Stabilising Manager(s) (or persons acting on behalf of a Stabilising Manager) will undertake stabilisation action. Any stabilisation action may begin on or after the date on which adequate public disclosure of the terms of the offer of the relevant Tranche of Notes is made and, if begun, may be ended at any time, but it must end no later than the earlier of 30 days after the issue date of the relevant Tranche of Notes and 60 days after the date of the allotment of the relevant Tranche of Notes. Any stabilisation action or over allotment must be conducted by the relevant Stabilising Manager(s) (or persons acting on behalf of any Stabilising Manager(s)) in accordance with all applicable laws and rules. AVAILABLE INFORMATION

The Issuer has agreed that, for so long as any Notes are “restricted securities” within the meaning of Rule 144(a)(3) under the Securities Act, the Issuer will, during any period in which the Issuer is neither subject to section 13 or 15(d) of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”), or exempt from reporting pursuant to Rule 12g3-2(b) thereunder, provide to any holder or beneficial owner of such restricted securities or to any prospective purchaser of such restricted securities designated by such holder or beneficial owner upon the request of such holder, beneficial owner or prospective purchaser, the information required to be provided by Rule 144(d)(4) under the Securities Act.

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TABLE OF CONTENTS

RISK FACTORS ...... 1 PRESENTATION OF FINANCIAL AND OTHER INFORMATION ...... 30 CURRENCIES AND EXCHANGE RATES ...... 32 FORWARD LOOKING STATEMENTS ...... 33 DOCUMENTS INCORPORATED BY REFERENCE ...... 34 SUPPLEMENTS ...... 35 FINAL TERMS AND DRAWDOWN PROSPECTUSES ...... 36 SERVICE OF PROCESS AND ENFORCEMENT OF JUDGMENTS ...... 37 OVERVIEW OF THE ISSUER AND THE PROGRAMME ...... 40 USE OF PROCEEDS ...... 50 CAPITALISATION AND INDEBTEDNESS ...... 51 RATIO OF EARNINGS TO FIXED CHARGES ...... 52 SELECTED FINANCIAL INFORMATION AND OPERATING DATA ...... 53 MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ...... 56 BUSINESS ...... 88 MANAGEMENT ...... 124 OVERVIEW OF SOUTH AFRICA AND THE SOUTH AFRICAN ELECTRICITY INDUSTRY ...... 133 EXCHANGE CONTROLS ...... 154 TERMS AND CONDITIONS OF THE NOTES ...... 155 APPLICABLE FINAL TERMS ...... 190 FORM OF THE NOTES ...... 200 BOOK ENTRY, SETTLEMENT AND CLEARANCE ...... 203 TAXATION ...... 207 SUBSCRIPTION AND SALE AND TRANSFER AND SELLING RESTRICTIONS ...... 217 LEGAL MATTERS ...... 222 INDEPENDENT AUDITORS ...... 223 GENERAL INFORMATION...... 224

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RISK FACTORS The Issuer believes that the following factors may affect its ability to fulfil its obligations under Notes issued under the Programme. Most of these factors are contingencies which may or may not occur and the Group is not in a position to express a view on the likelihood of any such contingency occurring. In addition, factors which are material for the purpose of assessing the market risks associated with Notes issued under the Programme are also described below. If the risks described below materialise, the Group’s business, results of operations, financial condition or prospects could be materially adversely affected, which could cause the trading price of the Notes to decline and investors to lose all or part of their investment. Furthermore, Notes issued under the Programme will have no established trading market when issued, and such market may never develop. If a market does develop, it may not be liquid. Therefore, investors may not be able to sell their Notes easily, or at all, or at prices that will provide them with a yield comparable to similar investments that have a developed secondary market. The Issuer believes that the factors described below represent the principal risks inherent in investing in Notes issued under the Programme, but the inability of the Issuer to pay interest, principal or other amounts on or in connection with any Notes may occur for other reasons which may not be considered significant risks by the Group based on information currently available to it or which it may not currently be able to anticipate. Prospective investors should also read the detailed information set out elsewhere in this Base Prospectus and reach their own views prior to making any investment decision. Risks relating to the Group The Group’s tariffs, which are determined by the regulator and which are subject to considerable uncertainty in light of political and economic sensitivities, have historically been, and remain, below the Group’s cost of delivering service. Most of the Group’s operating activities as well as tariffs and resulting revenues are subject to regulation by the National Energy Regulator of South Africa (“NERSA”). While the Electricity Regulation Act, 2006 (the “Electricity Regulation Act”) provides that the Group must recover the full cost of its licensing activities, including a reasonable margin or return, the electricity tariffs that the Group charges its customers in South Africa, which are determined by NERSA, are inevitably sensitive to political and economic considerations and have historically not been cost-reflective. As a result, the Group’s ability to bridge resultant revenue gaps, create adequate borrowing capacity and build sufficient cash reserves to fully support the significant capacity expansion programme it has put in place to address its ageing infrastructure and growing demand has been, and continues to be, extremely limited. As a result, the Group’s debt and interest cover ratios and free funds from operations (“FFO”) as a percentage of total debt remain relatively low. Since 2006, NERSA has established annual tariff increases for future fixed periods on the basis of multi-year pricing determination (“MYPD”) applications filed by the Group, in which the Group identifies the average annual tariff increases that it has determined it requires over the relevant period to meet its expected operational and business needs. The setting and revision of tariffs is politically and economically sensitive, and the Group has, historically, not always received the tariff increases it has requested. While the Group has the ability, through NERSA’s regulatory clearing account (“RCA”) application process, to request subsequent upward revisions to NERSA’s MYPD tariff determinations for future periods, the Group can never be certain that such applications will be successful. Despite having increased rapidly in recent years, electricity tariffs in South Africa, as determined by NERSA, have historically been, and continue to be, low compared to tariffs charged in other countries. Since the first MYPD, which covered the period between 1 April 2006 and 31 March 2009 (“MYPD 1”), the Group has been unable to obtain cost-reflective tariffs and a return on assets. With respect to the current MYPD, which is the third MYPD to date and runs for the period from 1 April 2013 to 31 March 2018 (“MYPD 3”), NERSA granted the Group an average annual tariff increase of only 8% during the five-year period, which was considerably lower than the 16% average annual tariff increase that the Group had requested in its MYPD application and the 31.3%, 24.8% and 25.8% tariff increases that had been granted for the 2009/10, 2010/11 and 2011/12 financial years, respectively. While NERSA and the South African Government (the “Government”) acknowledge that tariff increases are necessary to recover costs and earn a fair return on

assets and that the current economic regulatory framework provides overall guidance to achieve full cost recovery, the tariff increases provided for MYPD 3 are insufficient to permit full cost recovery. See “Overview of South Africa and the South African Electricity Industry—Electricity Tariffs—Multi-Year Price Determination Methodology” for a discussion on the historical and current pricing and tariff methodology applied to the Group’s tariffs. Upon NERSA’s 2013 announcement of its MYPD 3 tariff determination, the Group originally estimated that the lower-than-expected tariff regime would result in a revenue shortfall of approximately R225 billion over the five-year MYPD 3 period. While the Group initially implemented a number of measures to close the identified revenue gap, including, among other steps, applying for, and obtaining, a nearly 13% tariff increase for the 2015/16 financial year by way of NERSA’s RCA application process and implementing a cost-cutting business productivity programme (“BPP”), the Group has since been forced to revise upwards its estimated revenue shortfall for the MYPD 3 period, which amount is still being quantified. This upward revision is based on the latest projections, which anticipate a decline in electricity sales volumes stemming primarily from lower growth in demand, which has been hindered by low gross domestic product (“GDP”) growth and high tariffs. In the financial year that ended 31 March 2014, the Group’s electricity sales volumes increased by only 0.6% compared to the previous financial year, while during the six months ended 30 September 2014, electricity sales volumes decreased by 1.3% compared to the same period in 2013. Given the uncertainty surrounding the Group’s estimated future revenues, S&P placed the Issuer on Creditwatch with negative implications in June 2014. In October 2014, to address concerns over the Group’s credit profile, the Government announced its Government Finance Support Package (as defined below), which includes, among other things, Government support for future upward adjustments to electricity tariffs by way of NERSA’s RCA application process. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Sources of Liquidity—Regulatory Clearing Account” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Sources of Liquidity—Government support”. There can be no assurance, however, that the Issuer will succeed in obtaining from NERSA the cost-reflective tariffs it requires through future RCA and MYPD applications going forward. Despite the measures currently being implemented by the Group, tariff determinations that are lower than those requested by the Group will require significant cost-cutting and reprioritisation until at least 2018. Additionally, suppressed electricity demand may continue to adversely affect Group revenues, increasing further the Group’s revenue gap, and the Group’s cost-saving initiatives may prove unsuccessful if faced with unforeseen trends or circumstances. Any such events could undermine the Group’s efforts to obtain cost-reflective tariffs and solve its revenue gap, which, in turn, could have a material adverse effect on the Group’s business, results of operations or financial condition. The Group’s electricity generation capacity is affected by a low operating reserve margin, which strains its ageing infrastructure, increases costs and jeopardises its ability to consistently meet the electricity supply requirements of its customers. The Group’s operations are affected by a low generation capacity operating reserve margin, which hinders the Group’s ability to cope with unexpected increases in demand for electricity and plant outages, strains its ageing infrastructure, increases its primary energy costs and, ultimately, jeopardises the Group’s ability to provide uninterrupted electricity to customers. The Group calculates its reserve margin as the difference between installed system capability and the system’s maximum load requirements (peak load or peak demand), while its operating reserve margin represents the Group’s generating capacity available to meet demand (excluding energy supplied by independent power producers (each an “IPP”), which reduces the residual demand that the Group is required to meet through generation) during the “peak hour”. The “peak hour” represents the hour in a specified period during which electricity demand is at its highest (and exceeds the available capacity) and only considers the available capacity (i.e. after discounting any plants which are out of service for either planned or unplanned maintenance, outages, failures or other problems). While the Group’s reserve margin was approximately 22.2% and 20.0% in 2013/14 and 2012/13, respectively, as compared to the international norm of 15%, its operating reserve margin, which the Group views as a more indicative “real time” measure of its generation capacity cushion at any particular time, was only approximately 1.3% and 4.8% in 2013/14 and 2012/13, respectively. Without factoring in generation capacity from its gas turbines, the Group’s operating reserve margin was -5.3% and -1.7% in 2013/14 and 2012/13, respectively. With the Group’s average targeted generation plant availability, or energy availability factor (“EAF”), for the financial year ended 31 March 2015 being only 80% and EAF for the six months ended 30 September 2014 being only 76.8%, significant pressure is placed on the availability of operating reserves over

peak periods. The Group’s operating reserve margin has steadily declined since 2008 in light of increased generation plant maintenance requirements and unplanned outages brought on by Group’s ageing electricity generation and transmission infrastructure. The Group expects its operating reserve margin to remain low at least until completion of the commissioning of its current planned capacity expansion, which is scheduled to take place during the 2020/21 financial year. See “Business—Corporate Divisions—Capacity Expansion Programme” and “Operating and Financial Review—Capital Expenditure”. Given the Group’s very limited generational capacity cushion, the Group has little room for manoeuvre in the event of abnormal or unplanned events, such as plant failures, unplanned maintenance requirements or sustained increases in electricity demand above Group forecasts, when generation is unable to keep up with demand, jeopardising the Group’s ability to continue to supply electricity to customers and avoid large-scale blackouts. In such instances, when the Group’s demand and supply-side management efforts prove insufficient, the Group has historically, as a last resort, implemented pre-planned supply interruptions, conducted on a rotating schedule and managed by disconnecting parts of the grid in an attempt to prevent failure of the entire system due to overloading (“load-shedding”). Although the Group actively sought to avoid load-shedding between 2008 and 2014 as part of its “keep the lights on” policy, the Group has been compelled to resort to load-shedding on numerous occasions in 2014, including in several instances in late 2014 and January 2015, as increased unplanned outages combined with the Group’s low operating reserve margin have made the avoidance of load-shedding increasingly untenable. For example, separate incidents at two of the Group’s power plants in November 2014, including a coal silo collapse at Majuba and a temporary shut-down of two of Lethabo’s units due to an excess of ash build-up, resulted in multiple instances of load- shedding in late 2014, which has led to a substantial amount of adverse publicity and political pressure. The Group believes that, going forward, further instances of load-shedding will be likely given the current condition of its generation fleet, the Group’s increased focus on prioritising the necessary maintenance of its ageing power plants and reducing its maintenance backlog and the prospect of electricity supply shortfalls at least until completion of the Group’s planned capacity expansion. The regular implementation of load- shedding could have a material adverse effect on the Group’s reputation, operations and financial condition. Furthermore, the Group’s low operating reserve margin places limitations on its ability to take its ageing infrastructure offline for much-needed maintenance, which increases the risks of plant outages and load- shedding. Postponing required maintenance and the consequent backlogs, as evidenced in the wake of the 2008-2014 period, when the Group, in pursuing its “keep the lights on” strategy, delayed several planned maintenance outages, has resulted in a significant adverse effect on the health and performance of the Group’s plants and the general integrity of the Group’s generation infrastructure. See “—Urgent maintenance is needed on the Group’s generation fleet and any further deferral of maintenance work or failure to properly implement its sustainability strategy may materially adversely affect its business operations.” Additionally, as an indirect result of the Group’s declining operating reserve margin, the Group has incurred, and continues to incur, higher primary energy costs in light of its increasing reliance on open-cycle gas turbines (each an “OCGT”), which run on costly diesel fuel, to supplement load reductions during peak periods and planned or unplanned plant outages. Any sustained increases in demand for electricity above the Group’s forecasts and/or unplanned outages or maintenance requirements that result in the Group’s generation capacity being taken offline, could lead to renewed load-shedding, further increases in the maintenance backlog of its fleet, higher primary energy costs and, generally, an inability of the Group to meet demand due to a lack of electricity generation capacity. Any such event could have a material adverse effect on the Group’s reputation, operations and financial condition. While the Group has committed to improve its operating reserve margin through an extensive capacity expansion programme initiated in 2005 designed to increase the Group’s generation capacity by 17.4 GW (200 MW of which will be from renewable energy sources) by the 2020/21 financial year, there can be no assurance that any additional capacity that the Group may add, or its demand response initiatives and energy conservation programmes, will prevent load-shedding or allow the Group to carry out sufficient maintenance on its ageing power plants. Any delays in completing the Group’s committed capacity expansion programme will likely have a negative impact on the Group’s already low operating reserve margin. See “–Due to the size and complexity of the committed capacity expansion programme, the Group may fail to implement the programme on a timely and successful basis”. Moreover, although the anticipated addition of further IPPs to the grid in the future is intended to alleviate capacity constraints, it may (due to the unreliability of renewable energy) result in increased strain on the power supply system. Renewable energy is not always regarded as a reliable source of energy (as it is contingent upon a number of factors, including, natural elements such as

wind, in the case of wind turbines and sun, in the case of solar power, specialised infrastructure and expertise) and the Group expects that it will need to continue to have costly back-up generating capacity available in the event that IPPs fail to supply electricity due to unforeseen circumstances. Urgent maintenance is needed on the Group’s generation fleet and any further deferral of maintenance work or failure to properly implement its sustainability strategy may materially adversely affect its business operations. Nearly two-thirds of the Group’s power stations are beyond the mid-point of their expected lifespans and there has been limited investment in the Group’s generation capacity since the mid-1990s. Given the tight supply-and-demand balance in the last five to six years and the Group’s “keep the lights on” strategy, the Group was frequently required, or chose, to defer planned maintenance to ensure uninterrupted and sufficient power supply to South Africa. Although this maintenance deferral strategy was generally successful in avoiding load-shedding from 2008 until 2014, whereupon the Group resumed load-shedding in light of increased unplanned outages, declining operating reserve margins and a shifted focus toward generation sustainability, it significantly compromised the health of the Group’s generation and transmission fleet, the performance of which has become increasingly volatile. For example, in early 2013 a decision was taken to increase the scope and timing for scheduled maintenance in relation to one of the Koeberg nuclear reactors, resulting in a maintenance backlog at several of the Group’s coal-fired stations given the additional pressure that the Koeberg unit shutdown placed on an already tight system. In March 2014, Unit 3 of the Duvha power station (575 MW) was taken out of service due to an over-pressurisation incident and, during the six months ended 30 September 2014, the Group had to postpone planned outages or rely on expensive OCGTs to address supply shortages from Cahora Bassa, Mozambique, from which the Group imports hydroelectric power, which resulted from certain equipment faults on the high-voltage direct current (“HVDC”) transmission lines. The Group’s unplanned capability loss factor (“UCLF”), an indicator of plant performance, was 13.3% as at 30 September 2014 and, although the Group expects to meet the 13% target for the year ending 31 March 2015, this represents a further deterioration from 12.6% as at 31 March 2014 and 12.1% as at 31 March 2013. A higher UCLF rating means that power station units have tripped or have had to be taken offline due to operational problems or failures, or that a power station is producing less energy than it is contracted to as a result of unplanned setbacks. The deterioration in UCLF and higher planned maintenance in recent years has resulted in a lower EAF, a measure of plant availability. The EAF was 76.8% for the six months ended 30 September 2014 and 75.1% and 77.7% for the financial years ended 31 March 2014 and 31 March 2013, respectively. The Group’s poor UCLF performance is an indication that fleet maintenance has become a priority. Any breakdown or failure of the Group’s operating facilities may cause outages or interruptions that affect the public or its other customers, prevent it from performing under applicable power sales agreements or result in increased costs to repair and replace damaged plant components. As a further consequence of the existing maintenance backlog, a number of the Group’s power stations and other plant components (including plant technology) have become “outdated” and fail to meet the required standards or to perform in accordance with the compliance requirements set by current environmental regulation, resulting not only in poor plant performance generally, but also in environmental legal contraventions which, in turn, could result in fines, penalties or other sanctions being imposed on the Group. For example, in the financial year ended 31 March 2014, the Group received two administrative fines totalling R2.6 million as a result of water-related contraventions and the construction of certain power lines on an incorrect servitude option, which was declared in the financial year ended 31 March 2013. For the period ended 30 September 2014, the Group received no such administrative fines. In order for the Group to meet the relevant standards and requirements set by applicable regulation, it will require substantial refurbishment, and in some instances, retro-fitting of existing power plants and components. This will result in significant expenditure for the Group, including further strain on its already tight operating reserve margin. In 2013, the Board approved a five-year plan for generation sustainability. The policy follows an 80:10:10 principle (the “80:10:10 Principle”) to ensure that the Group’s fleet remains sustainable in the long-term. Under this principle it is envisaged that the generating fleet should, on average, have an EAF of 80%, leaving 10% for planned maintenance outages and 10% for unplanned outages. See “—Business—Strategy—Leading and partnering to keep the lights on while ensuring the integrity of the Group’s generation and transmission infrastructure”. As a result of the implementation of the 80:10:10 Principle, the Group was able to do more planned maintenance in the 2013/14 financial year than in prior years. However, given the current state of its

ageing infrastructure, the Group has recently experienced a number of incidents which indicated that urgent maintenance is now required, including the collapse of the main coal silo at the Majuba power station and, in November 2014 an excess build-up of ash at the Lethabo power station, which necessitated the temporary shut-down of two of its units. The incident at the Lethabo power station, which resulted in several instances of load-shedding in the following weeks, prompted the Group to undertake urgent repairs and develop an improved maintenance programme to address the problem and reduce the likelihood of renewed outages. Furthermore, although the Group considers the 80:10:10 Principle to be a key priority, there can be no assurance that the Group’s sustainability strategy will be successful as the Group’s power system remains significantly constrained and prone to unforeseeable incidents which could require the implementation of additional load-shedding. As a result, unplanned losses may occur that could have a material adverse effect on the Group’s reputation, business and results of operations. Due to the size and complexity of the committed capacity expansion programme, the Group may fail to implement such programme on a timely and successful basis. The Group has committed to continue a capacity expansion programme on which it spent approximately R251 billion (excluding capitalised borrowing costs), between its inception in 2005 and 30 September 2014. The Group estimates that the total cost of the programme from 2005 until its completion, expected in the 2020/21 financial year, will be approximately R348 billion (excluding capitalised borrowing costs). This is the largest investment programme in the Group’s history. Due to the size and complexity of the Group’s committed capacity expansion programme, it may be unable to manage the cost or implementation, including the funding, of the programme successfully. Any inability on the Group’s part to manage and execute its committed capacity expansion programme successfully might result in load-shedding and power shutdowns, cost overruns, difficulties with regulators or completion delays, which would, in turn, have a material adverse effect on the Group’s results of operations, financial condition and prospects and could result in adverse regulatory consequences. Capital investment and construction projects, including those currently included in the Group’s committed capacity expansion programme, typically require substantial capital expenditure throughout the development phase, and may take months or years before they become operational, during which time the Group will be subject to a number of construction, financing, operating and other risks, many of which are beyond its control. These risks include, but are not limited to:

• safety;

• a shortage of project staff (such as project managers, planners, contract managers), suppliers and contractors;

• upward pressure on capital costs on the back of high global demand for equipment;

• timely completion of environmental impact assessments and obtaining environmental authorisations, permits, rights and land servitudes;

• inadequate and non-standardised processes and tools to manage and monitor progress;

• managing the sourcing of commodities and high exposure items;

• labour unrest; and

• the effect of demobilisation of construction projects on local communities, an initiative to mitigate the economic impact of demobilisation in the areas once new build projects start coming online. Additionally, the Group experienced a number of capacity expansion challenges during the financial year ended 31 March 2014, which continue as of the date hereof, including delays in the completion schedule and cost overruns. Delays were generally caused by poor contractor performance from certain key contractors on which the Group is dependent for the implementation of its committed capacity expansion programme on schedule and within budget, certain technical and quality difficulties, industrial action and accidents. The first units of each of the Medupi and Kusile power stations are expected to be synchronised in the first quarter of 2015 and 2017, respectively. Limited progress has been made on the Ingula pumped-storage power station in

the past 12 months due to work stoppage following an accident at the station in October 2013. The work stoppage was lifted in September 2014 to allow the main underground works to resume. As a result of the delay, the expected date of the first synchronisation of Unit 3 has been pushed back from November 2015 to the second quarter of 2016. See “Business—Finance and Group Capital—Capacity Expansion Programme” for more detail on the committed capacity expansion programme generally. Although the Group uses an integrated approach to manage its capacity expansion schedules, budgets and the risks associated with the execution of the capacity expansion programme, to the extent that it is unable to sufficiently manage such risks and if one or more of these risks materialises, it could negatively affect the Group’s ability to complete its current or future projects on schedule, if at all, or within the estimated budget, damage the Issuer’s reputation both locally and internationally and may prevent the Group from achieving the projected revenues, internal rates of return or capacity expected from such projects. Failure to complete the capital projects according to current estimated timetables and budgets and/or damage to the Issuer’s reputation, could have a material adverse effect on the Group’s business, results of operations and financial condition. The Group’s ability to implement its committed capacity expansion programme and expand and improve its business operations could be materially adversely affected if it is unable to raise sufficient capital on favourable terms, or at all, or if Government support of such capital raising is withdrawn. Since 2005, the Group has undertaken a significant programme to expand and maintain its ageing infrastructure, which has required, and will continue to require, significant capital investments by the Group. See “—Due to the size and complexity of the committed capacity expansion programme, the Group may fail to implement the programme on a timely and successful basis” and “Business—Finance and Group Capital— Capacity Expansion Programme” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Capital Expenditure”. Capital expenditure in connection with the Group’s committed capacity expansion programme, from its inception in 2005 until its expected completion in the 2020/21 financial year is estimated to be approximately R348 billion (excluding capitalised borrowing costs). As at 30 September 2014, the Group had secured R65.5 billion in funding as part of its R200 billion funding requirement for the MYPD 3 period (including the maximum borrowing limits of certain established programmes). See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Capital Expenditure—Sources of Liquidity”. The Group expects its total capital expenditure to be funded from operating cash flows and debt financing (raised locally and internationally). A key component of the Group’s ability to raise funds through debt financing is support from the Government, which has currently pledged to guarantee up to R350 billion of financing for the Group (which will, however, not include the Notes), of which R154 billion has already been utilised (calculated at the exchange rates applicable as of the date of signing of the currency-related facilities). The availability of Government guarantees allows the Group to secure funding from lenders that require guarantees, which funding the Group would be unable to access without such Government support. The lower-than-expected tariff increase established by NERSA for the MYPD 3 period (which the Group originally estimated to result in a R225 billion revenue shortfall for the Group over the course of the MYPD 3 period) and the impact of lower sales revenues stemming primarily from depressed electricity demand, will likely extend the Group’s reliance on Government support for a number of years. Recently, on 22 October 2014, the Government announced a financial support package (“Government Finance Support Package”) for the Group which includes, among other things, a R20 billion Government equity injection, the potential conversion of R60 billion in subordinated debt to equity, approval to issue additional debt of R50 billion and the Government’s support for future upward adjustments to electricity tariffs by way of NERSA’s RCA application process. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Capital Expenditure—Government support”. Any change in Government policy or withdrawal of such support could make it difficult or impossible to secure the funding necessary to complete the committed capacity expansion programme on time. In addition, while the Electricity Pricing Policy (the “EPP”) approved by the Government in 2008 calls for revenues to reach cost-reflective levels, the necessary increases to achieve cost-reflectivity have not yet been approved by NERSA (as was evident from the MYPD 3 determination). There can be no assurance that the underlying regulation or NERSA’s implementation of the EPP will not change before such revenues are achieved. As a result of the capacity expansion programme, Eskom has held a moratorium on dividend payments since 2008.

Apart from continued Government support, the Group’s ability to fund the committed capacity expansion programme and other capital improvements is dependent on numerous additional factors, some of which are beyond the Group’s control, including:

• general economic and capital market conditions;

• the availability of funding in capital markets generally;

• investor confidence and sentiment toward the South African economy in particular;

• the financial condition, performance and prospects of the Group in general; and

• changes in tax and securities laws. Revenue from tariffs or sources of financing and capital resources may not be available to the Group at all or in the amount required, resulting in an inability to implement its committed capacity expansion programme fully or in a timely manner. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Capital Expenditure” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Capital Expenditure—Sources of Liquidity”. In addition, as the Group relies on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows and will need to do so in the future to finance its capital requirements, any downgrade in the Issuer’s credit ratings could jeopardise the Group’s ability to raise capital on favourable terms and borrowing costs could increase. In particular, any downgrade in the credit ratings of South Africa, on which the Group’s credit ratings are dependent, are expected to have a direct impact on, and result in a downgrade of, the Issuer’s credit rating, which could, in turn, restrict the Group’s ability to raise capital under a guaranteed debt arrangement. For example, in November 2014, Moody’s downgraded Eskom’s credit rating from Baa3 to Ba1, resulting directly from a one-notch downgrade in the sovereign’s credit rating. The Issuer’s credit ratings are dependent on, among other things, the regulatory environment and the Government’s support through guarantees, potential equity injections and other means. Whilst the Group continues to enjoy support from its shareholder in the form of up to R350 billion in Government guarantees (of which R154 billion has been utilised to date, calculated at the exchange rates applicable as of the date of signing of the currency related facilities) and, most recently, the Government Finance Support Package, any further downgrade of the Issuer’s current credit rating, combined with the lower level of tariffs allowed under the MYPD 3 allocation until 2018, may impact on both the availability and cost of funding for the Group’s committed capacity expansion programme and the refinancing of its existing obligations. Accordingly, with respect to both new and existing commitments, the Group may be required to provide some form of assurance to backstop or replace any additional credit support by the Government as a consequence of the Issuer’s credit rating having been downgraded to below investment grade. For example, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Sources of Liquidity—Impact of Moody’s November 2014 Issuer credit rating downgrade”. In addition, to the extent that the Group is required and able to provide assurance or collateral to such counterparties, this will limit the amount of credit available to the Group to meet its other liquidity needs. As a result, the Group can give no assurance that it will be able to finance the maintenance or expansion of its current operations, which could have a material adverse effect on the Group’s business, results of operations and financial condition. The Group’s activities are subject to government policy and there is uncertainty as to how the Government may elect to implement such regulations and fund resulting initiatives in the future and their impact on the Group. Much of the Group’s strategy and many of its future prospects are subject, and will have to be aligned, to the Department of Energy’s Integrated Resource Plan for Electricity (the “IRP”), which sets out a long-term electricity plan for South Africa, and the Department of Energy’s Integrated Energy Plan (“IEP”), which is broadly designed to guide future South African energy infrastructure investment and policy for the 2010 to 2050 period. The IEP was published in June 2013 for public consultation, and a final report is expected to be published in March 2015. The IRP, which was promulgated in 2011 and covered the 2010 to 2030 period, is currently in the process of being revised to reflect the continuing evolution of the Government’s long-term electricity strategy. It remains unclear when the updated IRP will be finalised and approved by the South African Cabinet of Ministers (the “Cabinet”). While a draft updated version of the IRP was published in

November 2013 for public comment, it is expected that the final revised IRP will only be formally approved after the Government has approved the over-arching IEP, which is expected to inform the contents of the revised IRP. The IRP, which seeks to develop a sustainable electricity investment strategy for South Africa through 2030 sets out the country’s future generating needs, the mix of energy technologies that should be employed to achieve this and the timing and costs associated with meeting such needs. In light of Eskom’s role as the dominant electricity provider in South Africa, the strategies and measures contemplated in the IRP which, among other things, include an emphasis on nuclear power expansion, are expected to have a significant impact on the Group’s business and operations going forward. However, there is still a significant degree of uncertainty regarding the nature and extent of such impact. For example, the Cabinet has previously indicated that the Issuer will be responsible for owning and operating the new nuclear capacity envisaged under the IRP, which could add 9,600 megawatts of nuclear-generated electricity to the national electricity grid through a vast new build programme. Meanwhile, the Government recently announced entry into intergovernmental framework agreements on nuclear co-operation with China, the Russian Federation and France, which initiates the preparatory phase for a possible large-scale nuclear construction programme with one or more such countries. However, it is still unclear to what extent and in what form the Group will be involved in any nuclear new build programme, how such additional generating and transmission capacity will be funded and what impact it may have generally on the Group going forward. Moreover, a new power station can take more than a decade to plan, build and commission, which makes it difficult to plan large-scale generating and transmission projects. The IRP also assumes a migration from coal-fired power stations, on which the Group is highly dependent, to “renewable energy” sources. The Group may be required to diversify its generation methods to meet the Government’s policy to reduce the impact of the industry on the environment, in line with the IRP (and any revised version thereof). Additionally, the IRP contemplates a sizeable role in future electricity generation for IPPs, although it is unclear what impact this would have on the Group. The Department of Energy has previously indicated that 3,725 MW of additional capacity must be procured from IPPs. The Government may decide that IPPs should supplement, replace or assume a significant proportion of the Group’s contribution to generation capacity, which could adversely affect the Group’s operations. Finally, while the draft IRP update published in 2013 addresses the effect of slowing economic growth on projected electricity demand, until such date as the revised IRP has been finalised and approved, which is expected to occur only after the IEP’s anticipated approval in March 2015, the Group cannot be certain of the form and contents of South Africa’s long-term electricity investment strategy and, accordingly, its potential implications on the Group’s future operations, funding requirements and sources and general development. Moreover, given the final IEP will likely inform the contents of the final revised IRP, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. The uncertainties involving the scope, further development and implementation of the IRP (and the implications thereof), including the Issuer’s role and the availability of funding for the building of any required new generation capacity, is currently preventing the Group from planning ahead effectively. These factors, including any need for the Group to diversify its generation methods, the allocation of a significant portion of future electricity generation to IPPs or any failure by the Group to effectively adjust its business plan to address such factors, could have a material adverse effect on the Group’s business, results of operations or financial condition. The Group may not be able to meet the demand for electricity in South Africa in the longer term and there is no guarantee that the Group will be the chosen provider of generation capacity in the future. The Government has indicated that South Africa will need approximately 50,000 MW of additional capacity (including 10,000 MW of replacement capacity) to come on stream by 2028 to ensure an adequate reserve margin. While these figures are subject to revision upon the approval and publication of the updated IRP, which is expected to occur only after the IEP’s anticipated approval in March 2015, such requirement will require a faster build rate than has previously been achieved. Pending the finalisation and publication of the updated IRP, the Group has not approved or committed to any new build projects beyond Kusile under its committed capacity expansion programme, and its MYPD 3 application did not include any funding for any such new capacity build. See “Business—Finance and Group Capital—Capacity Expansion Programme” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Capital Expenditure”. Therefore, although the Government has previously indicated that the Issuer will be responsible for owning and operating any new nuclear capacity, and the IRP provides that 3,725 MW of additional generation capacity will be procured from IPPs, there is no commitment for the Group to provide additional capacity after 2018 and there is no assurance that IPPs will successfully supplement or replace the

Group’s contribution to investment and capacity expansion. Without the additional capacity, the electricity supply is unlikely to meet South Africa’s electricity demand, and the Group’s business and financial results could be adversely affected by resulting disruptions. In addition, under the IRP, the Department of Energy makes assumptions regarding future economic growth and demand for electricity and makes projections regarding generation requirements and provision of generation capacity to 2030. Although the Group currently supplies approximately 95% of South Africa’s electricity, it is not certain what its future role and the extent thereof would be. See “—The Group’s activities are subject to government policy and there is uncertainty with respect to how the Government may elect to implement such regulation and policies in the future and the impact they will have on the Group”. A decline in market share or the impact of the requirement for the Group to purchase IPP-generated electricity could have a material adverse effect on the Group’s business, results of operations and financial condition. The Group has a significant amount of debt, some of which is secured, which could adversely affect the Group’s business and the ability to service such debt or raise new debt. The Group has engaged in a number of transactions to raise debt in order to fulfil its funding requirements for working capital as well as its committed capacity expansion programme. The fair value of outstanding borrowings and debt securities issued amounted to R240.6 billion as at 31 March 2014, of which R18.1 billion is secured with a first charge against all of the Group’s assets and revenues by virtue of section 7 of the Conversion Act. The actual secured debt issued as at 31 March 2014 amounts to R16.9 billion at carrying value (R28.9 billion at nominal value). The actual secured debt issued as at 30 September 2014 amounts to R17.0 billion at carrying value (R29.0 billion at nominal value). This reduces the amount of collateral that is available for future secured debt or credit support and reduces the Group’s flexibility in managing these secured assets. Under the Registered Stock Loan No.170 (the “Stock Loan”) of the Issuer, an additional R8.65 billion of debt may be borrowed against an existing security arrangement and which will constitute “Permitted Securities”. See “Terms and Conditions of the Notes——Condition 4 (Negative Pledge)”. Furthermore, the Group plans to finance a proportion of its committed capacity expansion programme through debt offerings. As a result, a substantial portion of cash flow from operations may be used to make payments on current and future debt. In addition, any new debt issued may be subordinated in preference of payment or security to such existing debt. To the extent the Group becomes more leveraged, these risks would increase. Furthermore, the Group’s actual cash requirements in the future may be greater than expected. Accordingly, the Group’s cash flow from operations may not be sufficient to repay all of the outstanding debt as it becomes due and the Group may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance its debt as it becomes due. Although the Group has up to R350 billion available to it in Government guarantees, and the Group has utilised R154 billion thereof to date (calculated at the exchange rates applicable as of the date of signing of the currency-related facilities) and may in future use such guarantee capacity to guarantee certain of its borrowings, the Notes, in line with the Issuer’s previous international bond offerings, will not benefit from these guarantees. The Government controls the Group and may adopt policies or take steps that significantly affect the Group’s business profile and corporate structure including the potential restructuring of the Group’s business. At present, the Government is the sole shareholder of the Group and, so long as it is the sole shareholder, or so long as the Group is controlled by the Government, the Group may continue to be particularly affected by changes in Government policies and other political, economic and social developments in or affecting South Africa. The Government, through the Department of Public Enterprises, appoints the Issuer’s executive directors (the chief executive and the finance director) and non-executive directors. Accordingly, the Group is subject to the direction of the Government on shareholder and policy matters. For example, in December 2014, upon the conclusion of a five month review period following the Issuer’s 2014 annual general meeting (“AGM”), the Minister of Public Enterprises replaced nine of the Issuer’s 13 directors, reappointing the chairman and one other non-executive director and leaving in place the Issuer’s two executive directors. The new composition of the Board became effective on 11 December 2014, and the formal induction of the new directors is scheduled for January 2015. See “Management”. It may understandably take time for the new Board to fully familiarise itself with the various and complex issues facing the Issuer, given, in particular, that a majority of the new Board members comprise individuals who are new to Eskom and/or the electricity industry. Accordingly, it will be important that the new Board quickly develop a constructive working

relationship with the Group’s Executive Management Committee (“EXCO”) so as to ensure as seamless a transition as possible. In addition, the shareholder determines certain key performance indicators in its shareholder’s compact (the “Shareholder’s Compact”) against which the Group’s performance is measured. See “—Business—Relationship with the Government”. In May 2011, the Government published the Independent System and Market Operator (“ISMO”) Bill, introduced in the National Assembly as a Section 75 Bill (the “ISMO Bill”), which sought to establish the ISMO, a separate state-owned entity, independent from the Group, to which certain existing functions of the Group, including, potentially, its transmission assets, would be transferred over time. The establishment of the ISMO was originally suggested, among other things, to prevent a possible conflict of interest between the Group and IPPs with regard to the dispatch of power. However, the ISMO Bill has since been withdrawn from consideration by the Department of Energy. While the Department of Energy has announced publically that it intends to re-table the ISMO Bill, there is little clarity as to if and when this will take place and how the re-introduced ISMO Bill would compare to the originally tabled bill. The Group has undertaken no internal restructuring to accommodate the original bill nor anticipates undertaking such restructuring until there is clarity regarding the new bill. Any restructuring and transfer of the Group’s transmission assets to an entity outside the Group would have a significant impact on its balance sheet and may have a material adverse effect on the Group’s business, results of operations and financial condition. See “—Overview of South Africa and the South African Electricity Industry—Restructuring—Independent System and Market Operator”. Separately, because of the Government’s influence over the Group and the importance of the Group in meeting the social and economic development goals of South Africa, the Group may be requested to undertake certain activities and devote certain resources to projects that may not bear a commercial rate of return. Involvement in such projects, such as the Integrated National Electrification Programme (“Electrification Programme”), a programme whereby electricity access is made available directly to end users, may have an impact on the Group’s results of operations if not reflected in its approved tariffs. For example, under NERSA’s MYPD 3 determination, the Group was not allowed sufficient revenues to recover its costs of implementing the targets agreed by Government under the Electrification Programme. See “Overview of South Africa and the South African Electricity Industry—Electrification”. The majority of the Group’s power stations depend on a steady and adequate supply of coal and water of a certain quality, including liquid-fuel, for their operations, and any failure to secure such amounts or quality could result in cost increases or supply shortages. A significant proportion of the Group’s power generation facilities rely on a continuous supply of coal of a certain quality for fuel. Currently, the Group has several long-standing contracts with coal producers to supply coal for the Group’s coal-fired power stations and, in addition, secured a number of medium-term contracts in the six months ended 30 September 2014 to close any shortfalls in supply. With respect to new generation facilities, the Group has secured a long-term contract for the supply of coal to the Medupi power station currently under construction. Medupi will be supplied by coal from Exxaro’s Grootgeluk coal mine located to the north of the site. As at the date of this Base Prospectus, four medium-term contracts have been signed for coal supply to the Kusile power station during the commissioning phase. The conclusion of long-term coal and limestone supply agreements for Kusile is yet to be finalised. Coal of a sub-standard quality can negatively impact boiler performance and impact efforts to optimise energy output. One of the Group’s ongoing challenges is poor performance of contractor supply agreements. Additionally, the Group continues to experience problems ensuring the consistent supply of coal of an acceptable quality to some of its power stations. Should the Group’s coal suppliers continue to fail to perform adequately or at all under current agreements, or supply coal that is of sub-standard quality, the Group would either have to find other suppliers to make up for the shortfall (possibly from the short-to-medium term market at more expensive prices) or be forced to reduce its coal-fired power generation operations. Moreover, coal of sub-standard quality can have an adverse impact on the operational integrity and performance of the Group’s power plants, resulting in plant damage, outages and higher repair and maintenance costs and requirements. Certain of the Group’s power plants, including the Tutuka, Arnot and Matla power stations, are currently particularly affected by poor quality coal. Although the Group’s average coal stock levels remained high at 46 days as at 30 September 2014 (exceeding the 2015/16 annual target of 42 days), compared to 44 days as at 31 March 2014 and 46 days as at 31 March 2013, the amount of coal procured from the Group’s tied collieries has, however, recently been below committed levels. Some mines have, however, already started

implementing optimisation initiatives and several short, medium and long-term initiatives are under way to ensure that the coal delivered to power plants is of the quality required to generate electricity with minimal coal-related load losses. Additionally, the Group relies on the continued availability of sufficient freight capacity, rail capacity and infrastructure in South Africa to transport coal in a timely and efficient manner. Any significant disruption in the Group’s coal supply or significant drop in the quality of the coal that is supplied could force the Group to purchase additional quantities under unfavourable commercial circumstances, which could significantly increase its expenditure for coal and coal transportation, or to rely on more expensive methods of generation. In addition, disruption of the coal supply could result in reduced generation, which could cause outages affecting the public and could have a material adverse effect on the Group’s results of operations. The Group aims to reduce the volume of coal transported by road. To achieve this, a road transport changeover strategy has been implemented in parallel with the road-to-rail migration plan. The expectation is that this will improve the cost and safety of coal logistics and, ultimately, will contribute to a reliable supply of coal. Although much of the coal that the Group uses to supply its power plants is not exportable in light of its low quality, the Issuer nevertheless also has to compete with international buyers of coal, which has a direct impact on the coal price. South Africa’s coal supply for power generation is under threat due to an increasing demand from China and India in the international market for “Eskom” grade coal. Domestic coal producers are currently restricted as to the amount of coal they can export abroad in light of South Africa’s currently limited coal export terminal capacity. Moreover, domestic coal producers currently have little incentive to choose to sell their coal abroad given international coal prices remain at historically low levels. However, should South Africa’s coal export terminal capacity be increased and/or international coal prices rise significantly, the Group may face greater competition for low-grade coal resulting in potential supply constraints and increased operating costs if compelled to pay higher prices for the coal on which it relies. Despite claims that the country has ample coal both for export and to supply Eskom, the Group believes that given the importance of the resource to the country, state intervention is required to ensure that South Africa has enough coal to meet its growing energy needs. While there is currently no national legislation in force which dedicates coal for security of electricity supply, the Group has been in discussion with several Government departments, including the Department of Mineral Resources, Department of Public Enterprises, Department of Energy and the National Planning Commission of South Africa (“NPC”), regarding coal supply security, and in March 2014 the National Assembly and the National Council of Provinces approved the Mineral and Petroleum Resources Development Amendment Bill, 2013, which aims to promote national energy security, including the possibility of declaring coal a strategic resource. However, on 16 January 2015, the President referred the Mineral and Petroleum Resources Development Amendment Bill, 2013 back to the National Assembly for further consideration based, according to a statement released by the Office of Presidency, on the President’s view “that the bill as it stand[s] would not pass constitutional muster”. As at the date of this Base Prospectus, the National Assembly has not convened to reconsider the bill, and there is accordingly no indication as to how parliament will take the matter forward (including as to the content of any amendments that may be made to the existing draft of the bill). Therefore, there can be no assurances that the objectives contemplated by the bill will be achieved.

Furthermore, electricity is an important input for the mining industry, being used for the transport of personnel and materials, as well as for production machines and industrial processes. A disruption of the supply of electricity to coal mines could result in a disruption in the supply of coal which, in turn, could have a further material adverse effect on the Group’s generating capabilities and financial condition. Separately, labour strikes and unrest at some of South Africa’s mines have in the past led to logistical problems in coal supply, and while this has had no effect on the Group’s coal stock supply as such, it impacted, for example, the Group’s ability to physically move coal from the stock yard to its power stations. In addition, the Group’s coal-fired and hydro-power stations, as well as the pumped-storage facility, rely on a certain quantity and quality of water for their operations. Water is used as a coolant (and to create steam in the boilers) in the Group’s coal-fired power stations. The Group relies on the infrastructure in South Africa to transfer water between water catchments and transport water in a timely and efficient manner. Any shortage of water or a significant drop in quality of the water that is supplied could result in reduced generation capability, which could cause outages affecting the public and have a material adverse effect on the Group’s results of operations.

Given the Group’s increased reliance on liquid fuels, not only for the purposes of power generation, but also to ensure the proper and reliable functioning of its other plant components (for example, to start up its gas-fired plants), it is increasingly dependent on a steady and reliable supply of such fuels in order to operate its plant properly and at full capacity. In the 2012/13 and 2013/14 financial years, the Group experienced shortages in the supply of diesel and fuel oil supply from its existing suppliers, which are limited in number, as a result of unexpected circumstances. In order to secure sufficient supplies of liquid fuel in the future, the Group will need to diversify and expand its supplier base. If not, the Group may continue to experience shortages in supplies, which can result in an inability to operate its plant properly or to generate electricity through some of its power stations, all of which can have a material adverse effect on its results of operations and financial condition. Additionally, in light of the Group’s increasing reliance in recent years on OCGTs, which run on costly diesel fuel, to supplement load reductions during peak periods and planned or unplanned plant outages, the Group has incurred, and continues to incur, higher primary energy costs than in the past, which can have a material adverse effect on its results of operations and financial condition. The Group’s operations are subject to significant regulation beyond pricing and allowed tariffs. The Group’s operating activities related to the generation, transmission and distribution of electricity are highly regulated. The Group is regulated under licences granted by NERSA under the Electricity Regulation Act, as well as by the National Nuclear Regulator (the “NNR”) under the National Nuclear Regulator Act, 1999 (the “National Nuclear Regulator Act”). The Group is required to obtain numerous permits and governmental approvals for the operations of its power stations, which can be a lengthy process. If the Group fails to obtain, renew, or maintain the permits and governmental approvals required to operate its generation and transmission systems or to comply with, or to satisfy new conditions of such standards, laws, regulations, permits and governmental approvals, or is unsuccessful in any pending or future application, it could incur material costs or liabilities, fines, penalties or other sanctions, including the limitation, suspension or termination of some of its operations. In April 2014, certain air emissions regulations were promulgated, requiring the Group’s existing power plants (in particular, its older coal-fired stations) to meet certain specified minimum emissions standards (“MES”) by April 2015 and even more rigorous standards by April 2020. Full compliance with the MES can only be achieved by retrofitting fabric filter plants, low NOx burners and Flu Gas Desulphurisation on all units of all of the Group’s coal-fired power stations by April 2020. While the Group has started to plan an extensive retrofit programme, full compliance with the MES is not attainable in the specified time periods, or in some cases, at all. As a result, the Group is engaging with local authorities to align the new atmospheric emission licences (“AEL”) with the capabilities of its installed technologies and considering its current operating conditions. All of the Group’s power stations operate under emissions licenses. While some of Group’s power stations still operate under the old APPA Registration Certificates, the Group has obtained new AELs for most of its power stations. Some of the units at the eight power stations that have been issued the new AELs are, however, unable to comply (or periodically fail to comply) with the emissions limits set by the AELs, mainly due to the older technology and systems employed at such stations. While a process is under way to appeal, review or amend the newly issued AELs, it may take up to a year to obtain a final response. The Group has also applied for a five-year postponement of the compliance timeframe for some of its generating plants (in cases where more time is needed to complete the required retrofitting, and for exemptions in those cases where it is not feasible to comply with the MES requirements before commission of the relevant power station). Any failure by the Group to obtain permission to extend the compliance timeframe or obtain the requisite exemptions may have a material adverse effect on its business. For example, in the case of Eskom’s Kriel power station, Eskom’s request to increase the particulate-emissions limit and to allow a grace period for compliance with emissions limitations has been denied, which will require load losses as the station will be unable to continuously operate at full capacity. Apart from non-compliance with the AEL limits, there is also occasional non-compliance by the Group with the emissions limits set under the APPA Registration Certificates. The Group’s inability to comply with emissions limits is further exacerbated by the significant maintenance backlog of its fleet as well as other factors, including the deterioration of coal quality in the last few years, which negatively affects emissions performance. Relative particulate emissions (defined as kg ash emitted per MWh of electricity power sent out) for the six months ended 30 September 2014 was 0.33 kg/MWh sent out (which is projected to meet the target of 0.35kg/MWH sent out for the 2014/15 financial year), compared to 0.35kg/MWh sent out for each of

the financial years ended 31 March 2014 and 31 March 2013. See “Overview of South Africa—Environmental Regulation—Air Quality”. Changes to existing regulations or the introduction of new regulations or licensing requirements impacting the operations of the Group could have a material adverse effect on the Group’s business. There are many operational risks that are inherent to power generation and transmission that could adversely affect the Group’s operations and financial results. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating heavy equipment and delivering electricity to transmission and distribution systems. In addition, hazards such as fire, explosion and machinery failure are risks inherent in the Group’s operations, which may occur as a result of inadequate internal processes, technological flaws, human error or certain external events. The occurrence of any of these hazards in higher levels than normal could have a material adverse effect on the Group’s operational capacity and financial results. Furthermore, the hazards described above could cause significant personal injury or loss of life, damage to or destruction of property, plant and equipment, contamination of or damage to the environment, and suspension of operations. Consequently, the Group’s operations pose significant safety and occupational risks to some of its employees, contractors and third parties and despite the Group’s efforts in safety and risk management, each year a number of employees, contractors or third parties are injured or killed. Similarly, the Group’s operations pose significant risk to the environment. If such activities are not effectively controlled, they could lead to irreversible long-term environmental damage, as well as the removal of licences to operate, and prosecution. This could adversely affect the Group’s ability to carry on its operations, affect the Group’s financial results or damage the Group’s reputation. The occurrence of any of these events in the future, if the Group is judged to be at fault, may result in liability for the Group in respect of damages or penalties. Depreciation of the Rand or changes to exchange control policy could affect the Group’s ability to make payments in relation to U.S. dollar-denominated Notes and other indebtedness. The Group’s revenues are generated primarily in Rand. Since the late 1990s, there have been periods when the Rand has depreciated significantly against the U.S. dollar, including during 2014. The Group has employed a comprehensive hedging strategy to reduce its exposure to fluctuations in the value of the Rand. In accordance with the Group’s current hedging policy, the Group expects its obligations in U.S. dollars (including any U.S. dollar-denominated Notes issued under the Programme) will be fully hedged on a spot basis into Rand. The Group may continue to be exposed to relative interest rate differentials until the hedged cash flows are realised. In addition, as the Group rolls its hedge book, it may require additional liquidity depending on the market value of the Rand against hedged currencies. These hedging arrangements will subject the Issuer to the creditworthiness of the counter-parties and there can be no assurance that such hedging policies will fully cover any fluctuation in the value of the Rand against the U.S. dollar. The Government does not restrict and has not restricted the ability of South African persons or entities to convert U.S. dollars into Rand in respect of any transaction where initial SARB approval has been obtained. The Issuer expects to obtain SARB approval for the issuance and repayment of Notes issued under the Programme. However, no assurance can be given that the Government will not institute a more restrictive exchange control policy in the future. Any significant depreciation in the Rand against the U.S. dollar or any restriction on exchange controls in the future may affect the Group’s ability to meet any U.S. dollar or other foreign currency obligations, including payments in relation to any Notes issued under the Programme. The risks inherent in nuclear power generation expose the Group to significant potential liabilities and risks. Operating a nuclear power station has inherent risks, including damage arising from a nuclear accident or incident, the consequences of which could include the dispersion of radioactive material into the environment resulting in exposure of employees, contractors and third parties to radiation, which could result in radioactive contamination. An accident could also result in the direct exposure of employees at the power station to higher, and possibly fatal, levels of radiation. The unintended dispersion of radioactive contamination or unintended exposure to radiation could be as a result of human error, equipment malfunction, mishandling of radioactive materials and waste, ill-intentioned acts or terrorism, natural disasters (such as floods or

earthquakes) affecting the nuclear power station facilities, or during the transportation, treatment or conditioning of radioactive materials and waste. Such accidents and incidents (including, any public liability claims against which the Group is not insured) could result in the Group facing considerable liability for nuclear damage, as well as having a material adverse effect on the Group’s activities, operations and financial condition and reputation. See “Risk Factors—Risks relating to the Group—The Group may not have adequate insurance coverage to cover all potential risks”. Following the 2011 nuclear accident at Fukushima, Japan, which was triggered by an earthquake and tsunami, the Issuer undertook an assessment of the impact of external events, including earthquakes and tsunamis, on the safety of Koeberg. The assessment was approved by the NNR, which concluded that Koeberg is adequately designed, maintained and operated to withstand all external events considered in the original design and that there are no findings that would need operations to be altered or which question the design margins. However, a number of areas for potential improvement were identified to further reduce the risk beyond the design requirements. The focus of these improvements is on the site’s ability to be self-sufficient for an extended period. These measures are currently being discussed with the NNR and are in the process of being implemented or will be installed during future outages. The Group is currently evaluating three potential sites to accommodate any future additional nuclear facilities. Future areas of focus for the Group include finalising preparation for the site characterisation, design and execution of the three potential sites. Under the IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015), nuclear power has been identified as a preferred base load generating option and the Group was previously identified to be the owner and operator of any such future nuclear requirement. However, there is still a significant degree of uncertainty regarding the nature and extent of the Issuer’s role. Any such expansion of the Group’s nuclear operations may result in greater potential liability in the future. See “—The Group’s activities are subject to government policy and there is uncertainty with respect to how the Government may elect to implement such regulations and fund resulting initiatives in the future and the impact they will have on the Group. The disposal of spent nuclear fuel and ultimate decommissioning of its nuclear power plant will result in considerable costs for the Group which, although provisioned in the Group’s balance sheet, will have to be funded in the future. The Group’s Koeberg nuclear power plant produces used (spent) nuclear fuel, which has to be stored and eventually disposed of safely in a licensed disposal facility. The power station itself will, at the end of its economically viable life (currently set for 2045), have to be decommissioned. The final disposal of spent nuclear fuel and the decommissioning of the power station will both incur considerable costs which, although provisioned in the Group’s statement of financial position, will have to be funded at the time. There is long-term financial provision to reflect the costs of storing Koeberg’s spent fuel and the eventual decommissioning of the plant accounted for in the Group’s Consolidated Financial Statements. The spent fuel provision was R5.7 billion as at 30 September 2014 and is based on a management strategy and associated costs that are benchmarked against international practices. The decommissioning provision for Koeberg is based on a specific Koeberg decommissioning study performed by independent consultants and was R4.9 billion as at 30 September 2014. It is not certain whether, at the time of disposal of the spent fuel or the decommissioning of the plant, scheduled for 2045, the Group will have or be able to obtain sufficient funding to pay for such costs. In addition, long-term spent fuel and decommissioning costs are subject to changes in national and international legislation, changes in safety policies and changes in project costs. Any such changes could result in significant additional costs for the Group, while failure by the Group to comply with relevant obligations could lead to significant liability and penalties, any of which could have a material adverse effect on the Group’s results of operations and financial condition. The Group depends on key customers, which include a limited number of large companies in specific sectors of the economy and municipalities. For the six months ended 30 September 2014, the Group sold 38% (39% as at 31 March 2014) of its electricity to its ten largest mining and industrial customers, or 81% (81% as at 31 March 2014) if municipalities are included in the top ten customers. These customers are important to the Group’s business and play a critical role in the South African economy. Certain of the Group’s customers’ operations are particularly subject to changes in economic conditions within South Africa, and also regional and global market and economic conditions. The revenue loss from the failure of any of these customers to fulfil their

obligations under electricity purchase contracts with the Group could have a material adverse effect on the Group’s financial condition. The Group is exposed to fluctuations in commodity prices and certain indices through certain of its electricity supply agreements. For the six months ended 30 September 2014, the Group sold 4.9% (5.3% as at 31 March 2014) of its energy to customers under negotiated pricing agreements that link contract revenue to variables such as commodity prices, foreign currency exchange rates and local and foreign production price indices, exposing the Group to fluctuations in these prices and indices. These prices and indices are subject to wide fluctuations and are affected by numerous factors beyond the Group’s control, such as international economic and political conditions, commodity markets and actions of market participants. Under IFRS, the Group is required to account for the variability within the remaining negotiated pricing agreement as embedded derivatives. Embedded derivatives are recorded in the Group’s balance sheet at fair value with changes in fair value recorded in the income statement. During the six months ended 30 September 2014, embedded derivatives in these contracts resulted in a gain in the Group’s income statement of R1.6 billion for the period (compared to a R1.9 billion for the same period in 2013) and R2.1 billion for the 2013/14 financial year, compared to a loss of R5.9 billion in the 2012/13 financial year. Embedded derivative liabilities amounted to R7.7 billion as at 30 September 2014 (compared to R9.3 billion as at 31 March 2014, R11.5 billion as at 31 March 2013 and R5.5 billion as at 31 March 2012), primarily as a result of the costs of rolling over forward exchange contracts, which vary from period-to-period due to the timing of the placement of related procurement contracts and exchange rate fluctuations, which results primarily from the lower aluminium price curve, the strengthening of the Rand, the decrease in South African interest rates and changes in the U.S. Producer Price Index and the South African Consumer Price Index. Fluctuations in these prices and indices may have negative impacts in future. These contracts add significant volatility to the Group’s results of operations and financial condition. One of these pricing agreements was renegotiated in 2010 to reduce the impact of these derivatives. Currently, two special pricing contracts that give rise to embedded derivatives, both of which relate to aluminium smelters owned by one of the Group’s customers in KwaZulu-Natal, remain in place. In October 2012, the Group submitted an application to NERSA to review the final outstanding contracts to make them cost-reflective and to remove the commodity-linked pricing element, which will in turn remove the embedded derivatives. However, it is not certain when NERSA will make any determination in this regard and whether such determination will be in favour of the Group. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Factors Affecting Results of Operations—Embedded Derivatives”. Catastrophic events could adversely affect the power stations or the transmission and distribution system. The occurrence of a fire, earthquake, explosion, flood, severe storm, terrorist attack or other similar event, could damage, destroy or otherwise affect the power stations, the transmission systems, the transport infrastructure or any of the power stations’ principal suppliers of coal and other inputs. The occurrence of such events could have a material adverse effect on the results of operations and financial condition of the Group, especially if such an event were to disrupt the operations of the power stations significantly. Furthermore, the Group’s main offices and systems operations contain key staff, critical computer systems, and sophisticated hardware and communications systems that are necessary for the efficient operation of the business. If these facilities and the teams of people working in them were affected by such a catastrophic event, the Group could experience difficulties in maintaining business continuity, which could have a material adverse effect on the Group’s reputation, operations and financial condition. The Group’s operations are reliant on payments from, and subject to non-payment by, its customers as well as theft and other losses. The Group continues to experience problems with slow-paying or defaulting customers, including, in particular, overdue electricity accounts from municipalities. Forty-three percent of the Group’s revenues in the six months ending 30 September 2014 were generated from municipalities and they remain the principal service provider for electricity in large urban centres in South Africa. Although the Group has implemented a credit management policy that provides for the disconnection of the electricity supply to such customers (in line with the Promotion of Administrative Justice Act, 2000), there are instances when the recovery of sums owed is not possible. The Group’s large customer profile has a direct influence on the number of defaulting customers. The bigger the Group’s customer profile, the more payment and credit risks the Group has to

manage. There are also social pressures on the Group not to disconnect some retail customers (and the municipalities in which they live), despite persistent late payment. The value of the Group’s small power user debtors more than doubled in financial terms over the past four to five years. The recent tariff increases have also contributed to this growing number of debtors. Of particular concern is the outstanding debt of the Soweto township. As at 30 September 2014, the Issuer supplied electricity to approximately 180,000 households in this area from which, on average, payments received comprised approximately 15% of the revenue billed to such households. Electricity debtors (gross) increased from R16.7 billion as at 31 March 2013 to R20.2 billion as at 31 March 2014 and to R23.6 billion as at 30 September 2014. Some of the Group’s larger customers also fail to make timely payments, particularly certain municipalities that are redistributors. Municipal “arrear debt” (i.e. municipal debtor accounts which owe R20 million or more, or have had overdue balances for longer than 90 days; with specific focus on the top 20-25 debtors’ accounts which owe greater than R10 million) continues to rise. The key factors contributing to such increase include the high turnover of key municipal staff, revenue losses, poor revenue collection, insufficient grant funding, budgeting processes and reliance on government grant funding. Group annual arrear bad debt (i.e. annual accumulation of the provision raised for municipal debtors’ accounts, as explained above) was 0.9% of the external revenue for the six months ended 30 September 2014 (compared to 1.1% for the financial year ended 31 March 2014 and 0.8% for the financial year ended 31 March 2013). The allowance for impairment for trade and other receivables increased from R4.3 billion as at 31 March 2013 to R6.5 billion as at 30 September 2014. In addition, the Group suffers from theft of electricity through illegal connections to the grid and meter tampering, as well as from the theft of copper cables and other hardware. Eskom loses on average over R2 billion per year due to electricity theft. The Group’s hardware and infrastructure have been subject to theft and vandalism, sometimes involving harm to the Group’s employees. During the six months ended 30 September 2014, losses due to conductor theft (including theft of copper, cable, transformers and tower related structures) totalled R46.7 million (compared to R27.5 million in the financial year ended 31 March 2014) and involved 2,743 incidents (compared to 1,738 in the financial year ended 31 March 2014). The loss of key equipment, in and around the stations, that is required for transmission and plant protection, can cause a suspension of operations and result in financial losses for the Group. Non-payment of bills, theft of hardware and energy losses, each have had in the past and could have in the future a material adverse effect on the Group’s results of operations. Violation of, or an inability to comply with, the environmental and safety standards and regulations that apply to the Group could have a material adverse effect on its results of operations and financial condition. The Group’s facilities and operations are subject to environmental legislation and regulations which serve to protect the public interest and ensure effective environmental control. The Constitution of South Africa grants every person the right to an environment that is not harmful to their health or well-being and to have the environment protected through reasonable legislative and other measures. Where harm cannot be altogether prevented, it must be minimised and remedied appropriately. This is achieved through the issuing of authorisations for construction and permits and licences for atmospheric emissions, waste activities and water usage. Air quality management in South Africa falls under the National Environment Management: Air Quality Act, 2004 (“NEMAQA”). MES and National Ambient Air Quality Standards have been published in accordance with NEMAQA. All of the Group’s coal-fired power stations fall in National Air Quality Priority Areas, where special measures are being implemented to improve air quality. In terms of the South African MES enacted on 1 April 2010, the Group’s existing power plants need to meet certain specified MES by 2015, and more rigorous standards by 2020. The MES are applicable to new plants immediately, although a five year postponement of the compliance timeframe may be requested for existing plants (in those cases where more time is needed to complete the required work) and certain exemptions may be sought where it is not at all possible to comply with the relevant MES standards. Any failure by the Group to obtain permission to extend the compliance timeframe or obtain the requisite exemptions may have a material adverse effect on its business, results of operation and financial condition. For example, the Group’s requested, in the case of its Kriel power station, to increase the particulate emissions limit and allow for a grace period for exceeding the emissions limit of the new licence. This application was denied and whilst every effort will be made by the Group to comply with the conditions of the licence, the new limit does not allow the station to continuously

operate at its full rated power, and will therefore require load losses during off peak time. In turn, this will increase the Group’s operating costs if other alternatives, such as OCGTs, have to be used to supplement this reduction in load. The Group maintains performance targets to reduce particulate emissions, reduce water usage, improve regulatory compliance and improve customer perception. The Group does not always meet these targets and, in the most recent financial year, particulate emissions performance, water consumption performance and legal contraventions performance declined. Factors contributing to this deteriorating performance include a decline in coal quality at some power stations, fewer opportunities to perform maintenance due to less downtime, higher load factors, scope and execution of maintenance work, ageing property, plant and equipment, and loss of skilled personnel. The Group spent R3.9 billion on projects (primarily focused on improving emissions and water performance and improving coal mines) to improve its environmental performance, the Group reduced the number of environmental legal contraventions, from 48 in the financial year ended 31 March 2013 to 32 in the financial year ended 31 March 2014 and both relative particulate emissions and water consumption increased during the reporting period. The weak performance of the Group in the financial year ended 31 March 2014 and for the six months ended 30 September 2014 reflects the reality that it is operating ageing plants with little opportunity for maintenance or upgrades to reduce its environmental impact. The Group will only be able to significantly improve its environmental performance once it has created the maintenance downtime needed to fit existing plants with emissions-limiting technologies. See “—Urgent maintenance is needed on the Group’s generation fleet and any further deferral of maintenance work or failure to properly implement its sustainability strategy may materially adversely affect its business operations”. Separately, some projects which are critical to the Group’s committed capacity expansion programme, including its ability to transfer electricity through high-voltage transmission lines, are hindered by an inability to obtain the necessary environmental approvals and to acquire the necessary servitudes. Any continuation in these factors and/or inability to obtain the necessary approvals or servitudes could have a material adverse effect on the Group’s operations and financial results. Furthermore, should the Group fail to comply with applicable environmental standards and regulation, such failure may constitute a civil or criminal offence and the Group may be liable to penalties. In addition, the Government may begin to enforce existing environmental laws and regulations more strictly than they have in past, impose stricter environmental standards, or increase levels of fines and penalties for violations. Accordingly, the Group is unable to estimate the future financial impact of compliance with or the cost of a violation of its environmental obligations. Failure or any inability to comply with such obligations could have a material adverse effect on the Group’s current or future business, results of operations and financial condition. The Group is subject to environmental taxation and any increase in such environmental taxes or inability to pass such costs on to consumers could reduce its profitability. In 2006, South Africa’s National Treasury released a draft policy paper for comment entitled “A framework for considering market-based instruments to support environmental fiscal reform in South Africa”. Subsequent to this, an environmental tax was implemented in South Africa on 1 July 2009 with the introduction of a 2c/kWh environmental levy on electricity supply which was effective until 31 March 2011. On 1 April 2011 the levy was raised to 2.5c/kWh followed by another increase to 3.5c/kWh on 1 July 2012 at which rate it currently remains. The levy is payable for electricity produced from non-renewable sources (coal, nuclear and petroleum) and is raised on the total electricity produced. The environmental levy, which is paid by the Group to the South African Revenue Service (“SARS”) on a pass-through basis, is included in the cost of electricity charged to customers and, as such, recovered from consumers. In addition, on 2 May 2013, the Government published the Draft Carbon Tax Paper, introducing a carbon tax based on the emissions derived from emission factors linked to the relevant fuel inputs used. It is anticipated that the carbon tax (which is expected to replace the environmental levy) will be an inherent variable cost to the production of electricity from non-renewable sources, similar to fuel costs. It is currently anticipated that the carbon tax will be effective from January 2016. While the Group is currently able to pass environmental taxes on to the end consumer, there is no guarantee that it will be able to continue to do so in the future or that it will be able to pass on to consumers the carbon tax the Government is proposing to introduce in the next couple of years. Any inability of the Group to do so

could result in significantly increased operational costs for the Group, which will reduce its profitability and, ultimately, have a materially adverse effect on its results of operations and financial condition. The Group is exposed to risks and costs related to the health and safety of its employees, contractors and the public. The Group’s operations are subject to health and safety laws and regulations designed to improve and to protect the safety and health of employees, contractors and members of the public. The Issuer’s workplace safety performance, however, requires improvement. During the period ended 30 September 2014, the Group experienced one employee, six contractor and 11 public fatalities, compared to two employee, eight contractor and 23 public fatalities during the period ended 30 September 2013. During the financial year ended 31 March 2014, the Group experienced five employee, 18 contractor and 33 public fatalities, compared to three employee, 16 contractor and 29 public fatalities in the financial year ended 31 March 2013. Improving the Group’s safety record is one of its key objectives and the following safety-improvement initiatives are being implemented to reduce the number of fatalities and injuries to zero:

• the introduction of key performance indicators to monitor compliance with safety behaviours;

• a health and safety agreement between the Group and its trade unions;

• the approval of a contractor safety management plan (aimed at establishing a safety, hygiene, environment and security inspectorate unit to ensure adherence to legislative requirements in these fields); and

• the implementation of a zero-harm initiative to monitor the progress of key strategic safety initiatives across the Group. Safety incidents may lead to business interruptions, loss of assets, harm to employees, contractors and the public, damage to the environment and adverse publicity, damaging the Group’s reputation. The costs of complying with health and safety laws and regulations, and the imposition of civil or criminal liability for violations and liability for damages arising under personal injury or other legal actions could have a material adverse effect on the Group’s business, results of operations, financial condition and prospects. In addition, if these laws and regulations were to change and if material expenditure were then required in order to comply with such new laws and regulations, this could adversely affect the Group’s business, results of operations, financial condition and prospects. An increase in domestic interest rates may increase the Group’s borrowing costs. The SARB uses the repurchase rate as the primary instrument to ensure it achieves its stated inflation target range. The repurchase rate in turn determines the prime lending rate (the benchmark rate used by South African banks in determining lending rates for their customers). There is a risk that the SARB could respond to any inflationary pressures by raising the repurchase rate, leading to an increase in South African interest rates, increasing the cost of the Group’s borrowings and cost of capital, which could affect the Group’s ability to obtain new funds, maintain payments on existing debts or satisfy its funding requirement for the committed capacity expansion programme. The Group relies on information technology systems and any failure or delay to implement its planned information technology strategy and business plan, may adversely affect its operations and business. The Group’s business is dependent on the successful and uninterrupted functioning of its information technology (“IT”) systems. The Group relies on these systems for complex logistical and monitoring tasks, critical for its operational needs and central to its electricity business. In the financial year ended 31 March 2013, the Group approved an IT sourcing strategy and business plan, aimed at upgrading, centralising and standardising the IT systems across the Group. The strategy is also aimed at ensuring compliance with the Protection of Personal Information Act, 2013, which was passed into law on 19 November 2013. There can, however, be no assurance that this strategy will be implemented successfully, on time or on budget and any such failure or delay in upgrading the current systems successfully may compromise the Group’s ability to carry out its business. Separately, following a number of incidents including a power feeder meltdown and leakage from flooding, in the 2012/2013 financial year, one of the key priorities identified by the Group for

the immediate and short term is to rebuild and relocate its existing data centre, which is currently located below its head office. The budget allocated to this project was originally expected to be approximately R14 billion, however, as a result of the increase in the Group’s revenue shortfall identified for the MYPD 3 period, this number has since been revised downwards. Any failure by the Group to secure its data centre and consequently its IT systems and technology and business data, will expose the Group to significant risks. Any inability of the Group to operate its business due to data loss, could have a material adverse effect on its business and results of operations. The energy business is affected by seasonality and weather conditions generally, which impact the Group’s financial results. The sale of the Group’s electricity and its operation and maintenance activities are subject to seasonal variations and variations in general weather conditions and unusually severe weather. While the Group considers and plans for possible variations in normal weather patterns and potential impacts on its facilities, there can be no assurance that such planning can prevent these impacts, which can adversely affect the business. Generally, demand for electricity is higher in the first and second quarters of the financial year (April through September), when cooler temperatures cause an increase in electricity consumption. The difference between peak times in winter compared to summer can be as high as 10,000 MW. This seasonality of demand impacts the Group’s results of operations. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Factors Affecting Results of Operations—Seasonality”. Furthermore, the Group cannot give any assurance that its generation and transmission systems can satisfy the increased capacity requirements during this period, particularly with its current inadequate reserve margin for generation capacity. Significant variations from normal weather patterns could lead to under-capacity and, potentially, load-shedding, which would have a material adverse effect on the Group’s reputation, results of operations and financial condition. If the Group is unable to continue to retain and attract suitably qualified and skilled employees, this could have a material adverse effect on its business and results of operations. The success of the Group’s operations depends largely on its ability to attract and retain senior management and other employees who are suitably qualified, skilled or knowledgeable. Moreover, the operation of the power generation facilities depends on a large number of employees and contractors, some of whom perform specialised services. These include individuals with the industrial and professional skills to operate and maintain the Group’s power generation facilities, transmission lines and other items related to the Group’s business. It should be noted that for some of these roles there is a limited pool of candidates with the necessary credentials. The Group may not always be successful in hiring or retaining the best candidate or may have difficulty retaining skilled people. Consequently, if the Group is unable to engage or retain an adequate number of suitably experienced employees and contractors or such employees and contractors were to seek wage increases or to charge prices that were not competitive, this could have a material adverse effect on the Group’s business and results of operations. A large number of employees are members of the Group’s three recognised labour unions and have in the past and could, in the future, strike or participate in industrial action. A significant proportion of employees and contractors at the Group are members of trade unions. While the ability of employees, contractors or trade unions to strike is limited by regulation and agreements, the Group can give no assurance that there will not be labour-related actions in the future, including strikes, threats of strikes or other types of conflict. See “Business—Other Business Imperatives—Employees”. The threat of strikes or work stoppages can result and have resulted in disruptions and increased costs. Such disputes and resulting disruption and costs could have a material adverse effect on the Group’s business and results of operations. In the financial year ended 31 March 2013, the Issuer’s construction programme was affected by violent strikes in the farming and mining industries. Labour unrest among the Issuer’s contractors remains an ongoing challenge and may continue to cause delays on major construction projects, including compromising the safety of the Group’s employees and infrastructure. For example, in July 2014, the construction progress for Medupi was hindered due to industrial action by contractors. Additional resources were mobilised by the contractors to mitigate resource-driven delays and additional shifts were introduced to accelerate progress. In addition, the Group cannot rule out the possibility of any such labour unrest or strike activities spreading to its own work force at some point in the future. The Group is also subject to South African labour laws that provide for mandatory compensation to employees in the event of termination of employment for operational

reasons, and administrative and reporting requirements in respect of employment equity compliance. Non-compliance with labour law could result in large monetary penalties. Changes to existing regulations or the introduction of new regulations or licensing requirements could have a material adverse effect on the Group’s business. The Group may not have adequate insurance coverage to cover all potential risks. As a result of the potential hazards associated with the power generation and distribution industries, the Group may from time to time become exposed to significant liabilities for which it may not have adequate insurance coverage. In addition, there may be uninsurable risks for which the Group may not be able to obtain any insurance coverage, at all. For example, the Group only insures its nuclear plant (as per industry standard), however, no cover for public liability claims in relation to any nuclear incidents exists. The Group maintains an amount of insurance protection that it believes is adequate, but there can be no assurance that the Group’s insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. Furthermore, there can be no assurance that such coverage will continue to be available on commercially reasonable terms. A successful claim for which the Group is not fully insured or any interruption in its business operations for which the Group is not fully insured could materially and adversely affect its financial results and materially harm its financial condition. Additionally, to the extent that critical maintenance is deferred and this results in damage or a breakdown of generating plant or components, it is uncertain whether and to what extent the Group will be successful in recovering costs associated with the replacement and/or repair of such plant through its insurance policies. Any loss not covered by insurance could have a material adverse effect on the Group’s cash flows and financial condition. Risks relating to South Africa The ongoing uncertain global economic outlook could adversely affect the South African economy’s growth prospects and its financial markets. The disruptions experienced in recent years due to the impact of the global financial crisis in the international and domestic capital markets have led to reduced liquidity and increased credit risk premiums for certain market participants and have resulted in a reduction of available financing. Companies located in countries in emerging markets such as South Africa may be particularly susceptible to these disruptions and reductions in the availability of credit or increases in financing costs, which could result in them experiencing financial difficulty. Furthermore, it is not possible to predict what structural or regulatory changes may result from the current market conditions or whether such changes may be materially adverse to the South African economy and financial system. Following the negative growth rate recorded in the first quarter of 2014, the South African economy escaped a further contraction in the second quarter as real domestic production rose at an annualised rate of 0.6%. Growth was hampered during this period primarily as a result of the drawn-out industrial action in the platinum-mining subsector which started on 23 January 2014 and only came to an end five months later. The strike activity, which resulted in a sharp contraction in mining output in the first quarter of the year, led to a further but less drastic decline in real mining production in the second quarter of 2014 as the real output of platinum group metals registered a pronounced decline. Given the backward and forward linkages of the mining sector, real value added by and utilisation of capacity in the manufacturing sector also declined in the second quarter of the year. The subdued conditions extended to the electricity sector, where weakness in demand was amplified by a relatively mild winter and a higher real price of electricity. Global economic growth accelerated marginally from an annualised rate of 3.3% in the second quarter of 2014 to 3.6% in the third quarter of 2014, largely due to the improved growth momentum in some advanced economies. However, growth outcomes and prospects remained uneven, resulting in different monetary policy stances being adopted. Facing headwinds, policymakers in the euro area and Japan added further monetary stimulus, whereas in the U.S. the sustained improvement in economic activity enabled the Federal Reserve to bring its stimulatory programme of asset purchases to an end. Among emerging market economies growth outcomes and inflation pressures were mixed, leading to divergent central bank policy decisions. The sustained slack in the world economy continued to weigh on international commodity prices, reinforced by indications of excess capacity in the Chinese manufacturing sector. With global oil demand lacking vigour and oil supply remaining robust, augmented by shale gas, the price of Brent crude oil receded to nearly 6-year

lows of approximately U.S.$50 per barrel in January 2015. This has contributed to a reduction in actual and projected inflation in most parts of the world, while also impacting negatively on the external and fiscal balances of, and growth prospects for, oil-producing countries. In sub-Saharan Africa, which includes several oil producers such as Nigeria, Ghana and Angola, the near-term growth outlook was scaled down accordingly. In South Africa, the annualised real economic growth rate picked up to 1.4% in the third quarter of 2014 as the frictions related to the five-month-long platinum strike in the first half of the year started to dissipate, but were replaced by industrial action in the steel and engineering subsector of manufacturing. This lasted one month, involved 220,000 employees and contributed to the manufacturing sector registering a third successive quarter of negative real growth. It also spilled over to the real output of the electricity-producing sector, which contracted for a second successive quarter. Taking account of the direct and indirect effects, it is estimated that in the absence of the industrial action in the manufacturing sector, the growth rate of the overall economy in the third quarter would have been 3.1%. On a year-on-year basis, GDP grew by 1.4%, compared to a revised 1.3% in the previous year. In addition, the revisions reflected that the South African economy is 4.4% larger than previous estimates. The Group’s business and operations are closely related to the South African economy and are materially affected by conditions in the South African economy that are outside its control, such as interest rates, inflation rates, sovereign credit ratings, economic uncertainty, changes in laws (including laws relating to taxation) and national and international political circumstances. Any event adversely affecting South Africa generally or the South African manufacturing and service sectors, including reduced volumes of coal, iron ore and other mineral exports from South Africa, an increase in energy prices, fluctuations in the prices of commodities or raw materials, adverse shifts in interest rates or foreign exchange rates and changes in Government policies (including environmental regulation) or infrastructure spending, could materially adversely affect the Group’s business, results of operations, financial condition and prospects and may cause the Group to re-evaluate, and possibly reduce, its anticipated spending in relation to the committed capacity expansion programme. Furthermore, the Issuer’s credit rating is closely linked to that of the sovereign and any downgrade of South Africa’s credit rating is expected to have a direct impact on the Issuer’s credit rating which could, in turn, affect the Issuer’s ability to raise finance on favourable terms, or at all. For further details of the Issuer’s credit rating and the impact thereof on its operations and financial condition, see “—Risk Factors—The Group’s ability to implement its committed capacity expansion programme and expand and improve its business operations could be materially adversely affected if it is unable to raise sufficient capital on favourable terms, or at all, or if Government support of such capital raising is withdrawn” and “Business—Overview”. South Africa is an emerging market country and investors there are exposed to risks that are not common in more developed countries. Investing in an emerging market country such as South Africa carries risks which are different from those which apply to investment in a more developed country. These risks include economic and/or political instability, which may be exacerbated by global economic instability. Such instability in South Africa in the past has been caused by many different factors, including the following:

• general social, economic and business conditions;

• high interest rates;

• changes in exchange rates;

• high levels of inflation;

• exchange controls;

• wage and price controls;

• foreign currency reserves;

• changes in economic or tax policies;

• the imposition of trade barriers;

• changes in investor confidence;

• poverty, labour tensions, unemployment and crime and social inequality;

• perceived or actual security issues and political changes; and

• negative economic or financial developments in other emerging market countries. Any of these factors, as well as volatility in the markets for securities similar to the Notes, may adversely affect the value or liquidity of the Notes. Accordingly, investors should exercise particular care in evaluating the risks involved and must decide for themselves whether, in light of those risks, their investment is appropriate. Generally, investment in emerging markets is only suitable for sophisticated investors who fully appreciate the significance of the risks involved, and prospective investors are urged to consult with their own legal and financial advisors before making an investment in the Notes. Investors should also note that developing markets such as South Africa are subject to rapid change and that the information set out in this Base Prospectus may become outdated relatively quickly. Capital flows to and from South Africa are limited by exchange controls. South African law provides for Exchange Control Regulations (as defined below) that restrict the export of capital from South Africa without approval from the SARB. These regulations limit the extent to which the Group can borrow funds from non-South African sources for use in South Africa. While the Group determines and proposes its own borrowing needs, it is the SARB that ultimately approves the total amount that the Group may borrow from non-South African sources. See “Exchange Controls”. In 1995, the Government began relaxing certain Exchange Control Regulations (as defined below) and has recently stated that it intends to continue this gradual relaxation, as evidenced by proposed reforms contained in its 22 October 2014 Medium Term Budget Policy Statement (“MTBPS”), which are intended to lower the costs of doing business in South Africa, as well as certain further relaxations of controls announced by the Minister of Finance during his budget speech on 17 February 2010. The extent to which the Government may further relax such exchange controls cannot be predicted with certainty. Further relaxation or immediate elimination of current exchange controls may precipitate a change in the capital flows to and from South Africa. If the net result of this were to cause large Rand-denominated capital outflows, this could adversely affect South Africa’s economy through possible depreciation of the Rand or an increase in interest rates, because South Africa has a fully floating exchange rate and flexible interest rate policy. It could also impact the Group’s ability to finance itself in its domestic capital market. The high rate of HIV infection in South Africa may cause the Group to lose skilled employees, increase employee-related costs and may adversely affect economic conditions generally. South Africa has one of the highest reported Human Immunodeficiency Virus (“HIV”) infection rates in the world. According to Statistics South Africa, the total number of people living with HIV in South Africa is estimated at approximately 5.51 million in 2014. For adults aged 15–49 years, an estimated 16.8% of the population is HIV positive. The socio-economic impact of this pandemic on South Africa is, and will continue to be, significant. However, the exact effect of increased mortality rates due to Acquired Immune Deficiency Syndrome (“AIDS”) related deaths on the cost of doing business in South Africa and the potential growth in the economy is unclear at this time. The incidence of HIV/AIDS in South Africa, and amongst the Group’s workforce specifically, will likely lead to increasing absenteeism, increasing deaths from AIDS related illnesses, increasing medical and other costs and decreasing productivity and quality of life. It may also contribute to other human resources challenges, such as difficulty in recruiting and retaining employees. In addition, employee-related costs in South Africa may increase as a result of higher HIV infection rates. The Group may incur costs relating to medical treatment and loss of infected personnel, as well as loss of productivity. The Group may also incur costs relating to the recruitment and training of new personnel. The effects of HIV infection on both the Group’s employees and on the South African markets are difficult to quantify and may have a material adverse effect on the Group’s business, results of operations and financial condition.

South Africa’s balance of payments is vulnerable to fluctuations in the price of oil imports and key commodities exports. A significant variation in these prices could have a material impact on South Africa’s external financing needs, capital inflows and ultimately the Rand’s exchange rate. Real net exports declined somewhat in the third quarter of 2014, subtracting from the overall expenditure on gross domestic product. Export volumes rose by less than import volumes over the period, with exports of gold and iron ore registering contractions as short-term frictions inhibited delivery to external markets and global demand for commodities softened. However, with the price of crude oil declining more steeply than the prices of South African export commodities, the terms of trade improved. In value terms, the deficit on the trade account narrowed somewhat in the third quarter of 2014. This was partly offset by the widening in the deficit on the services, income and current transfer account, reflecting higher net interest payments to non- residents and higher net payments for transport-related services. The smaller trade deficit but larger services and income shortfall culminated in a slightly narrower deficit on the current account; it edged lower from 6.3% of gross domestic product in the second quarter to 6.0% in the third quarter. The third quarter deficit was fully financed by net portfolio and net other investment flows. Non-resident investors acquired domestic equity and debt securities in roughly equal proportions during the third quarter, and supported the South African government when it issued three international bonds. In the other investment category, loans extended to the South African banking sector rose significantly. By contrast, net direct investment recorded a sizeable outflow of capital over the same period, with a substantial part involving a food and beverage retail investment by a South African entity. South Africa finances its current account deficit largely through portfolio investments into its capital markets. South Africa’s highly liquid equity and debt markets (by emerging market standards) have attracted investors, as global markets have stabilised since the financial crisis, but render the country vulnerable to investor sentiment towards the sovereign and emerging markets in general. The impact of balance-of-payments adjustments is dampened by the Rand’s free-floating exchange rate. However, depreciation may not always re-price South African assets to a sufficiently attractive level to fully restore the financial account surplus. Furthermore, sustained depreciations and appreciations as a result of the current account position can complicate monetary policy, adversely affect the Rand’s exchange rate and act as an investment disincentive. Socio-economic challenges (in particular poor public services including health and education, high levels of unemployment and income inequality) are more acute than similarly rated emerging markets. Failure to address these could lead to social instability in the longer term. Serious health issues and a poor public education system are reflected in South Africa’s low United Nations Human Development ranking at 121 out of 187 countries. South Africa’s Gini coefficient index (63.1, published in 2010) representing income inequality is the second worst of the peer group, according to 2013 World Development Indicators. In the third quarter of 2014, quarterly changes reflected an increase in the number of people employed (22,000) and a decrease in unemployment (3,000). This resulted in a slight decrease in the unemployment rate from 25.5% in the second quarter of 2014 to 25.4% in the third quarter of 2014. These persistent socio-economic challenges adversely impact South Africa’s creditworthiness and give rise to long-term expenditure needs, heightened social pressures and constrain growth. As a result, the risk of long-term social frictions is more acute than its peers. Risks related to the structure of a particular issue of Notes A range of Notes may be issued under the Programme. A number of these Notes may have features which contain particular risks for potential investors. Set out below is a description of the most common of such features: Notes subject to optional redemption by the Issuer. An optional redemption feature is likely to limit the Notes’ market value. During any period when the Issuer may elect to redeem Notes, the market value of those Notes generally will not rise substantially above the price at which they can be redeemed. This also may be true prior to any redemption period. The Issuer may be expected to redeem Notes when its cost of borrowing is lower than the interest rate on the Notes. At those times, an investor generally would not be able to reinvest the redemption proceeds at an effective interest rate as high as the interest rate on the Notes being redeemed and may only be able to do so at

a significantly lower rate. Potential investors should consider reinvestment risk in light of other investments available at that time. Variable Rate Notes with a multiplier or other leverage factor. Notes with variable interest rates can be volatile investments. If they are structured to include multipliers or other leverage factors, or caps or floors, or any combination of those features or other similar related features, their market values may be even more volatile than those for securities that do not include those features. Fixed/Floating Rate Notes. Fixed/Floating Rate Notes may bear interest at a rate that converts from a fixed rate to a floating rate, or from a floating rate to a fixed rate. Where the Issuer has the right to effect such a conversion, this will affect the secondary market and the market value of the Notes since the Issuer may be expected to convert the rate when it is likely to produce a lower overall cost of borrowing. If the Issuer converts from a fixed rate to a floating rate in such circumstances, the spread on the Fixed/Floating Rate Notes may be less favourable than prevailing spreads on comparable Floating Rate Notes tied to the same reference rate. In addition, the new floating rate at any time may be lower than the rates on other Notes. If the Issuer converts from a floating rate to a fixed rate in such circumstances, the fixed rate may be lower than then-prevailing rates on its Notes. Notes issued at a substantial discount or premium. The market values of securities issued at a substantial discount or premium from their principal amount tend to fluctuate more in relation to general changes in interest rates than do prices for conventional interest bearing securities. Generally, the longer the remaining term of the securities, the greater the price volatility as compared to conventional interest bearing securities with comparable maturities. Risks related to the Notes generally Set out below is a description of material risks relating to the Notes generally: The Notes may not be a suitable investment for all investors. Investors must determine the suitability of an investment in the Notes in light of their own circumstances. In particular, each potential investor should:

• have sufficient knowledge and experience to make a meaningful evaluation of the Notes, the merits and risks of investing in the Notes and the information contained in this Base Prospectus or any applicable supplement;

• have access to, and knowledge of, appropriate analytical tools to evaluate, in the context of its particular financial situation, an investment in the Notes and the impact the Notes will have on its overall investment portfolio;

• have sufficient financial resources and liquidity to bear all of the risks of an investment in the Notes, including Notes with principal or interest payable in one or more currencies, or where the currency for principal or interest payments is different from the potential investor’s home currency;

• understand thoroughly the terms of the Notes and be familiar with the behaviour of any relevant indices and financial markets; and

• be able to evaluate (either alone or with the help of a financial adviser) possible scenarios for economic, interest rate and other factors that may affect its investment and its ability to bear the applicable risks. Some Notes may be complex financial instruments. Sophisticated institutional investors generally do not purchase complex financial instruments as standalone investments. They purchase complex financial instruments as a way to reduce risk or enhance yield with an understood, measured, appropriate addition of risk to their overall portfolios. A potential investor should not invest in Notes which are complex financial instruments unless it has the expertise (either alone or with a financial adviser) to evaluate how the Notes will

perform under changing conditions, the resulting effects on the value of the Notes and the impact this investment will have on the potential investor’s overall investment portfolio. The Notes are unsecured obligations of the Issuer and are subordinated to secured obligations on insolvency. Holders of secured obligations of the Issuer will have claims that are prior to the claims of holders of the Notes to the extent of the value of the Issuer’s assets securing those other obligations. The Notes are unsecured obligations and are effectively subordinated to secured indebtedness to the extent of the value of the assets securing those other obligations. As at 30 September 2014, the liabilities of the Issuer that were secured by its assets had a carrying value of R17.0 billion (R29.0 billion at nominal value), which amount may increase or decrease over time. The terms of the Notes permit additional secured indebtedness in certain circumstances. See “Terms and Conditions of the Notes—Condition 4 (Negative Pledge)” and “Risks relating to the Group—The Group has a significant amount of debt, some of which is secured, which could adversely affect the Group’s business and the ability to service such debt or raise new debt”. In the event of any distribution of assets or payment in any foreclosure, dissolution, winding up, liquidation, reorganisation, or other bankruptcy proceeding, the assets securing the claims of secured creditors will be available to satisfy the claims of those creditors, if any, before they are available to unsecured creditors, including the holders of the Notes. In any of the foregoing events, there is no assurance to holders of Notes that there will be sufficient assets to pay amounts due on any Notes. Modification, waivers and substitution. The conditions of the Notes contain provisions for calling meetings of Noteholders to consider matters affecting their interests generally. These provisions permit defined majorities to bind all Noteholders, including Noteholders who did not attend and vote at the relevant meeting and Noteholders who voted in a manner contrary to the majority. The conditions of the Notes also provide that the Trustee may, without the consent of Noteholders, agree to any modification of, or to the waiver or authorisation of any breach or proposed breach of, any of the provisions of the Notes, or determine without the consent of the Noteholders that any Event of Default (as defined in the Terms and Conditions of the Notes) or potential Event of Default shall not be treated as such or agree to the substitution of another company as principal debtor under any Notes in place of the Group, in the circumstances described in the Terms and Conditions of the Notes. See “Terms and Conditions of the Notes— Condition 15 (Meetings of Noteholders, Modification, Waiver and Substitution)”. The modification, waiver or substitution of the provisions of the Notes may affect Noteholders’ rights and will be binding on them. EU Savings Directive.

Under Council Directive 2003/48/EC on the taxation of savings income (“EU Savings Directive”), Member States are required to provide to the tax authorities of other Member States details of certain payments of interest or similar income paid or secured by a person established in a Member State to or for the benefit of an individual resident in another Member State or certain limited types of entities established in another Member State.

On 24 March 2014, the Council of the European Union adopted a Council Directive amending and broadening the scope of the requirements described above. Member States are required to apply these new requirements from 1 January 2017. The changes will expand the range of payments covered by the Directive, in particular to include additional types of income payable on securities. The Directive will also expand the circumstances in which payments that indirectly benefit an individual resident in a Member State must be reported. This approach will apply to payments made to, or secured for, persons, entities or legal arrangements (including trusts) where certain conditions are satisfied, and may in some cases apply where the person, entity or arrangement is established or effectively managed outside of the European Union.

For a transitional period, Luxembourg and Austria are required (unless during that period they elect otherwise) to operate a withholding system in relation to such payments. The changes referred to above will broaden the types of payments subject to withholding in those Member States which still operate a withholding system when they are implemented. In April 2013, the Luxembourg Government announced its intention to abolish

the withholding system with effect from 1 January 2015, in favour of automatic information exchange under the Directive.

The end of the transitional period is dependent upon the conclusion of certain other agreements relating to information exchange with certain other countries. A number of non-EU countries and territories including Switzerland have adopted similar measures (i.e. a withholding system in the case of Switzerland).

If a payment were to be made or collected through a Member State which has opted for a withholding system and an amount of, or in respect of, tax were to be withheld from that payment, neither the Issuer nor any Paying Agent nor any other person would be obliged to pay additional amounts with respect to any Note as a result of the imposition of such withholding tax. If a withholding tax is imposed on payment made by a Paying Agent, the Issuer will be required to maintain a Paying Agent in a Member State that will not be obliged to withhold or deduct tax pursuant to the EU Savings Directive.

Change of law The conditions of the Notes are based on English law in effect as of the date of this Base Prospectus. No assurance can be given as to the impact of any possible judicial decision or change to English law or administrative practice after the date of this Base Prospectus. The Notes may be redeemed prior to maturity following a change in tax laws in South Africa. In the event that the Issuer is obliged to pay additional amounts on account of any South African taxes in respect of payments under any Notes as a result of any change in or amendment to the laws or regulations of South Africa, coming into effect after the date of the relevant Notes issue, the Issuer may redeem all outstanding Notes of the relevant series in accordance with the Terms and Conditions of the Notes. See “Terms and Conditions of the Notes—Condition 5 (Interest)” and “Terms and Conditions of the Notes— Condition 8 (Taxation)”. Bearer Notes where denominations involve integral multiples: definitive Bearer Notes. In relation to any issue of Bearer Notes which have denominations consisting of a minimum Specified Denomination plus one or more higher integral multiples of another smaller amount, it is possible that such Notes may be traded in amounts in excess of the minimum Specified Denomination that are not integral multiples of such minimum Specified Denomination. In such a case, a holder who, as a result of trading such amounts, holds an amount which is less than the minimum Specified Denomination in its account with the relevant clearing system would not be able to sell the remainder of such holding without first purchasing a principal amount of Notes at or in excess of the minimum Specified Denomination such that its holding amounts to a Specified Denomination. Further, a holder who, as a result of trading such amounts, holds an amount which is less than the minimum Specified Denomination in its account with the relevant clearing system at the relevant time may not receive a definitive Bearer Note in respect of such holding (should definitive Bearer Notes be printed) and would need to purchase a principal amount of Notes at or in excess of the minimum Specified Denomination such that its holding amounts to a Specified Denomination. If definitive Notes are issued, holders should be aware that definitive Notes which have a denomination that is not an integral multiple of the minimum Specified Denomination may be illiquid and difficult to trade. The Issuer may not be able to finance a redemption at the option of the Noteholders upon occurrence of a Put Event. If a Put Event (as defined in the “Terms and Conditions of the Notes—Condition 7.5 (Redemption and Purchase—Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put))”) occurs, each Noteholder will have the right to require the Issuer to redeem each Note held by such Noteholder at its principal amount, plus accrued and unpaid interest. See “Terms and Conditions of the Notes— Condition 7 (Redemption and Purchase)”. Certain other debt of the Issuer may also be subject to early repayment upon occurrence of a Put Event. There can be no assurance that the Issuer will be in a position to finance a redemption of all Notes which the Noteholders may require the Issuer to redeem upon occurrence of a Put Event and to repay any other debt that becomes due upon occurrence of a Put Event.

Clearing Systems – reliance on DTC, Euroclear and Clearstream, Luxembourg procedures. Unless issued in definitive form, Notes issued under the Programme will be represented on issue by one or more Global Notes that may be deposited with or registered in the name of a nominee for a common depositary for Euroclear and Clearstream, Luxembourg or may be deposited with or registered in the name of a nominee for DTC (each as defined under “Form of the Notes”). Except in the circumstances described in each Global Note, investors will not be entitled to receive Notes in definitive form. Each of DTC, Euroclear and Clearstream, Luxembourg and their respective direct and indirect participants will maintain records of the beneficial interests in each Global Note held through it. While the Notes are represented by a Global Note, investors will be able to trade their beneficial interests only through the relevant clearing systems and their respective participants. For so long as the Notes are represented by Global Notes, the Issuer will discharge its payment obligation under the Notes by making payments through the relevant clearing systems. A holder of a beneficial interest in a Global Note must rely on the procedures of the relevant clearing system and its participants to receive payments under the Notes. The Issuer has no responsibility or liability for the records relating to, or payments made in respect of, beneficial interests in any Global Note. Holders of beneficial interests in a Global Note will not have a direct right to vote in respect of the Notes so represented. Instead, such holders will be permitted to act only to the extent that they are enabled by the relevant clearing system and its participants to appoint appropriate proxies. Investors may be unable to recover from the Issuer in civil proceedings for violations of U.S. securities laws. The Issuer is a limited company incorporated under the laws of South Africa. The Issuer’s assets are located outside the United States. In addition, all of the members of the Board and officers of the Issuer are residents of countries other than the United States. As a result, it may be impossible for investors to effect service of process within the United States upon the Issuer or its Board or officers, or to enforce against them any judgments obtained in U.S. courts predicated upon the civil liability provisions of the U.S. securities laws. There can be no assurance that civil liabilities predicated upon the federal securities laws of the United States will be enforceable in South Africa. Investors are relying solely on the creditworthiness of the Issuer. Notes issued under the Programme will constitute direct, unconditional, unsubordinated and, subject to the provisions of Condition 4.1 (Negative Pledge), unsecured obligations of the Issuer and will rank pari passu among themselves (save for certain obligations required to be preferred by law) and equally with all other unsecured obligations of the Issuer (other than subordinated obligations or obligations preferred by mandatory provisions of law, if any). If a prospective investor purchases Notes, it is relying on the creditworthiness of the Issuer and no other person. In addition, an investment in the Notes involves the risk that subsequent changes in the actual or perceived creditworthiness of the Issuer may adversely affect the market value of the Notes. Return on an investment in Notes will be affected by charges incurred by investors. An investor’s total return on an investment in any Notes will be affected by the level of fees charged by an Agent, nominee service provider and/or clearing system used by the investor. Such a person or institution may charge fees for the opening and operation of an investment account, transfers of Notes, custody services and on payments of interest and principal. Potential investors are, therefore, advised to investigate the basis on which any such fees will be charged on the relevant Notes. Tax consequences of holding the Notes. Potential investors should consider the tax consequences of investing in the Notes and consult their tax advisors about their own tax situation. U.S. Foreign Account Tax Compliance Act Withholding. The U.S. Foreign Account Tax Compliance Act imposes a new reporting regime and, potentially, a 30% withholding tax with respect to: (a) certain payments from sources within the United States, (b) “foreign

passthru payments” made to certain non-U.S. financial institutions that do not comply with this new reporting regime, and (c) payments to certain investors that do not provide identification information with respect to interests issued by a participating non-U.S. financial institution. Such withholding could apply if the Issuer, the paying agent or any intermediary through which payments in respect of the notes are made were to be classified as a financial institution, as such term is defined for purposes of FATCA. If an amount in respect of such withholding tax were to be deducted or withheld from interest, principal or other payments made in respect of the Notes, then neither the Issuer nor any paying agent nor any other person would, pursuant to the Conditions of the Notes, be required to pay additional amounts as a result of the deduction or withholding. As a result, investors may receive less interest or principal than expected. Prospective investors should refer to the section “Taxation—FATCA”. Legal investment considerations may restrict certain investments. The investment activities of certain investors are subject to legal investment laws and regulations, or review or regulation by certain authorities. Each potential investor should consult its legal advisers to determine whether and to what extent (1) Notes are legal investments for it, (2) Notes can be used as collateral for various types of borrowing and (3) other restrictions apply to its purchase or pledge of any Notes. Financial institutions should consult their legal advisors or the appropriate regulators to determine the appropriate treatment of Notes under any applicable risk based capital or similar rules. Risks related to the market generally Set out below is a description of material market risks, including liquidity risk, exchange rate risk, interest rate risk and credit risk: The secondary market generally. Notes issued under the Programme may have no established trading market when issued, and one may never develop. If a market does develop, it may not be very liquid. Therefore, investors may not be able to sell their Notes easily or at prices that will provide them with a yield comparable to similar investments that have a developed secondary market. This is particularly the case for Notes that are especially sensitive to interest rate, currency or market risks, are designed for specific investment objectives or strategies or have been structured to meet the investment requirements of limited categories of investors. These types of Notes generally would have a more limited secondary market and more price volatility than conventional debt securities. Illiquidity may have a severely adverse effect on the market value of Notes. Exchange rate risks and exchange controls. The Issuer will pay principal and interest on the Notes in the Specified Currency. This presents certain risks relating to currency conversions if an investor’s financial activities are denominated principally in a currency or currency unit (the “Investor’s Currency”) other than the Specified Currency. These include the risk that exchange rates may significantly change (including changes due to depreciation or devaluation of the Specified Currency or, conversely, appreciation or revaluation of the Investor’s Currency) and the risk that authorities with jurisdiction over the Investor’s Currency may impose or modify exchange controls. In addition, such risks generally depend on economic and political events over which the Issuer has no control. An appreciation in the value of the Investor’s Currency relative to the Specified Currency would decrease (1) the Investor’s Currency equivalent yield on the Notes, (2) the Investor’s Currency equivalent value of the principal payable on the Notes and (3) the Investor’s Currency equivalent market value of the Notes. Government and monetary authorities may impose (as some have done in the past) exchange controls that could adversely affect an applicable exchange rate as well as the availability of a specified foreign currency at the time of any payment of principal or interest on a Note. As a result, investors may receive less interest or principal than expected, or no interest or principal. Even if there are no actual exchange controls, it is possible that the Specified Currency for any particular Note not denominated in U.S. dollars would not be available at such Note’s maturity. Interest rate risks. Investment in Fixed Rate Notes involves the risk that subsequent changes in market interest rates may adversely affect the value of the Fixed Rate Notes.

Credit ratings may not reflect all risks. The Issuer’s credit ratings are an assessment by the relevant rating agencies of its ability to pay its debts when due. Consequently, real or anticipated changes in its credit ratings will generally affect the market value of the Notes. One or more independent credit rating agencies may assign credit ratings to the Notes. The ratings may not reflect the potential impact of all risks related to structure, market, additional factors discussed in this Base Prospectus, and other factors that may affect the value of the Notes. A credit rating is not a recommendation to buy, sell or hold securities and may be revised or withdrawn by the rating agency at any time. The market price of the Notes may be volatile. The market price of the Notes could be subject to significant fluctuations in response to actual or anticipated variations in the Issuer’s operating results and those of its competitors, adverse business developments, changes to the regulatory environment in which the Issuer operates, changes in financial estimates by securities analysts and the actual or expected sale of a large number of Notes, as well as other factors, including the trading market for notes issued by or on behalf of South Africa as a sovereign borrower. In addition, in recent years the global financial markets have experienced significant price and volume fluctuations, which, if repeated in the future, could adversely affect the market price of the Notes without regard to the Issuer’s results of operations, financial condition or prospects. Factors including increased competition, fluctuations in the Group’s operating results, the regulatory environment, availability of reserves, general market conditions, natural disasters and war may have an adverse effect on the market price of the Notes. Financial turmoil in emerging markets may lead to unstable pricing of the Notes. The market price of the Notes is influenced by economic and market conditions in South Africa and, to a varying degree, economic and market conditions in other African and emerging markets generally. Financial turmoil in other emerging markets in the past has adversely affected market prices in the world’s securities markets for companies that operate in those developing economies. Even if the South African economy remains relatively stable, financial turmoil in other emerging markets could materially adversely affect the market price of the Notes.

PRESENTATION OF FINANCIAL AND OTHER INFORMATION In this Base Prospectus, references to the “Group” refer to the Issuer together with its consolidated subsidiaries. All the Group’s business activities are conducted through the Issuer and its subsidiaries. In this Base Prospectus, all references to “South Africa” are to the Republic of South Africa and references to the “United States” and “U.S.” means the United States of America, its territories and possessions and any state of the United States and the District of Colombia. The discussion of operating and financial results contained herein, unless otherwise specified, relates to the Issuer and should be considered alongside a careful review of the Consolidated Financial Statements (as defined below), which have been incorporated by reference herein (see “Documents Incorporated by Reference”) . Unless otherwise stated, the description of management, business activities, management’s discussion and analysis of results of operations and financial condition, capitalisation, related party transactions and certain other matters contained in this Base Prospectus relate only to the Group. Presentation of Financial Information The Issuer maintains its books of account in South African Rand in accordance with South African accounting and tax regulations. The financial information of the Issuer set forth herein has, unless otherwise indicated, been derived from its audited statements of financial position (i.e. balance sheets), income statements, statements of cash flows and changes in equity and the notes thereto as at and for each of the financial years ended 31 March 2014, 31 March 2013 and 31 March 2012 (the “Audited Annual Financial Statements”) and its reviewed interim statements of financial position (i.e. balance sheets), income statements, statements of cash flows and changes in equity and the notes thereto as at and for the six months ended 30 September 2014 and 2013 (the “Reviewed Interim Financial Statements” and together with the Audited Annual Financial Statements, the “Consolidated Financial Statements”). The Consolidated Financial Statements were prepared in accordance with International Financial Reporting Standards (“IFRS”). The Consolidated Financial Statements, including the audit reports of SizweNtsalubaGobodo Inc. (“SNG” or the “Auditors”) and KPMG Inc., in respect of the Audited Annual Financial Statements for each of the financial years ended 31 March 2014, 31 March 2013, and 31 March 2012 and the review report of SNG in respect of the Reviewed Interim Financial Statements for the six months ended 30 September 2014, have been incorporated by reference herein (see “Documents Incorporated by Reference”). The financial information in the Base Prospectus for the six months ended 30 September 2014 and 2013, respectively, has been extracted from the Reviewed Interim Financial Statements of the Group for the six months ended 30 September 2014. The Group’s income statement and statements of cash flows for the six months ended 30 September 2013, as set out in the Group’s Reviewed Interim Financial Statements for the six months ended 30 September 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of the assets and liabilities of Eskom Energie Manantali s.a. (“EEM”) as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 21 of the Reviewed Interim Financial Statements (with respect to the six months ended 30 September 2013). The financial information in the Base Prospectus for the financial years ended 31 March 2014 and 2013, respectively, has been extracted from the Audited Annual Financial Statements of the Group for the year ended 31 March 2014. The Group’s income statement and statements of cash flows for the financial year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the financial year ended 31 March 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of the assets and liabilities of EEM as a discontinued operation held-for- sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Audited Annual Financial Statements (with respect to the financial year ended 31 March 2013). The financial information in the Base Prospectus for the financial year ended 31 March 2012 has been extracted from the Consolidated Financial Statements of the Group for the financial year ended 31 March 2012. In addition, the Group’s income statement and statements of cash flows for the financial year ended 31

March 2012 as set out in the Group’s Consolidated Financial Statements for the year ended 31 March 2012 and extracted herein, included a “continuing operation” (the investment in EEM). In presenting the Group’s financial and operating data, the Issuer has included and discussed certain non-IFRS financial measures in this Base Prospectus. Management believes that these non-IFRS measures, such as EBITDA and capital expenditure, which may be defined differently by other companies, explain the Group’s results of operations in a manner that allows for a better understanding of the underlying trends in the Issuer’s business. However, these measures should not be viewed as a substitute for those prepared in accordance with IFRS, even where they have been included in the Consolidated Financial Statements. Presentation of Other Information Certain information regarding South Africa has been taken from the Form 18-K of South Africa filed with the SEC on 28 November 2014 and the SARB’s Quarterly Bulletin (no. 274, December 2014) and is based on publicly available information. The Issuer accepts responsibility for accurately reproducing such information, but has not independently verified the accuracy of such information. Such information may be approximations or use rounded numbers. Certain figures in this Base Prospectus relate to measurements of electricity or length. The principal measurements used are as follows: “c/kWh” refers to cents per kilowatt hour; “GW” refers to gigawatts; “GWh” refers to gigawatt hours; “kg” refers to kilograms; “km” refers to kilometres; “kWh” refers to kilowatt hours; “kV” refers to kilo volts; “MW” refers to megawatts; “MWh” refers to megawatt hours; and “MVA” refers to mega volt ampere. MW refers to the capacity of a power plant, whereas MWh refers to the actual energy produced over time. Rounding Certain figures included in, or incorporated by reference into, this Base Prospectus have been subject to rounding adjustments. Accordingly, figures shown for the same category presented in different tables may vary slightly and figures shown as totals in certain tables may not be an arithmetic aggregation of the figures which precede them.

CURRENCIES AND EXCHANGE RATES In this Base Prospectus, reference to “South African Rand” “RAND”, “ZAR”, “R”, “cents” or “c” are to the lawful currency of South Africa. References to “U.S. dollar” or “U.S.$” are to the lawful currency of the United States. References to “EUR”, “euro” or “€” are to the currency introduced at the start of the third stage of the European Economic and Monetary Union pursuant to the Treaty establishing the European Community, as amended. References to “Sterling” or “GBP” are to the lawful currency of the United Kingdom. References to “JPY” or “¥” are to the lawful currency of Japan. References to “SEK” are to the lawful currency of Sweden. References to “AUD” are to the lawful currency of Australia. References to “CHF” are to the lawful currency of Switzerland. References to “AUD” are to the lawful currency of Australia. References to “CAD” are to the lawful currency of Canada. References to “NOK” are to the lawful currency of Norway. The following table sets out, for the periods indicated, the high, low, average and period end Bloomberg composite rate expressed as South African Rand per U.S. dollar. The Bloomberg composite rate is a “best market” calculation, in which, at any point in time, the bid rate is equal to the highest bid rate of all contributing bank indications and the ask rate is set to the lowest ask rate offered by these banks. The Bloomberg composite rate is a mid-value rate between the applied highest bid rate and the lowest ask rate. The rates may differ from the actual rates used in the preparation of the consolidated financial statements and other financial information appearing in this Base Prospectus. The average rate for a year means the average of the Bloomberg composite rates on the last day of each month during a year. The average rate for a month, or for any shorter period, means the average of the daily Bloomberg composite rates during that month, or shorter period, as the case may be.

Period High Low End Average Rand per U.S.$1.00 Year ended 31 December 2010 ...... 8.0154 6.5869 6.5869 7.3152 2011 ...... 8.5412 6.5791 8.0751 7.2635 2012 ...... 8.9608 7.4531 8.4778 8.2104 2013 ...... 10.5404 8.4575 10.5206 9.6504 2014 ...... 11.7600 10.3008 11.5510 10.8493 The last day of the month July 2014 ...... 10.7669 10.4955 10.7029 10.6603 August 2014 ...... 10.7594 10.5479 10.6493 10.6649 September 2014 ...... 11.2970 10.6730 11.2970 10.9811 October 2014 ...... 11.3465 10.8507 11.0319 11.0610 November 2014 ...... 11.2705 10.9472 11.0751 11.0980 December 2014 ...... 11.7600 10.9764 11.5510 11.5112 January 2015 (through 21 January)...... 11.7190 11.4359 11.5432 11.5824

On 21 January 2015, the exchange rate translated to R11.5432 = U.S.$1.00. The Issuer makes no representation that the amounts referred to above could have been or could be converted into the foregoing currencies at any particular rate or at all. This Base Prospectus contains translations of certain U.S. dollar amounts into South African Rand. Unless otherwise stated, U.S. dollar amounts are translated into South African Rand at prevailing exchange rates applicable at the time. These translations should not be construed as representations that the South African Rand amounts actually represent such U.S. dollar amounts or could be converted into U.S. dollars at the rate indicated.

FORWARD LOOKING STATEMENTS This Base Prospectus includes “forward-looking information” within the meaning of section 27A of the Securities Act and section 21E of the Exchange Act. Statements included in this Base Prospectus, which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto), are forward-looking statements. Forward-looking statements can be identified by words such as “believes”, “estimates”, “anticipates”, “expects”, “intends”, “may”, “will”, “plans”, “outlook” and other words of similar meaning in connection with a discussion of future operating or financial performance. Such forward-looking statements are necessarily dependent on assumptions, data or methods that may be incorrect or imprecise and that may be incapable of being realised. Such forward-looking statements relate to, and are subject to, among other things:

• the Group’s level of capital expenditures over the next several years, regulatory increase approvals to reflect costs related thereto and sources of liquidity to meet the committed capacity expansion programme;

• future changes in electricity tariffs;

• the Group’s ability to tackle low reserve and operating reserve margins to ensure that it meets the electricity supply requirements of its customers;

• the development of South Africa’s electricity industry under the Government’s IRP or similar plans, laws or guidelines;

• the Group’s ability to reduce reliance on coal as a fuel source and diversify its energy generation assets;

• fluctuations in interest rates and other market conditions, including foreign currency exchange rates; and

• diverse political, economic, legal, tax and other conditions affecting generally the markets in which the Group operates. Other factors that might affect such forward-looking statements include, among other things, the various events, uncertainties, trends and factors set forth under “Risk Factors” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Factors Affecting Results of Operations”. The Issuer is not obliged to, and does not intend to, update or revise any forward-looking statements made in this Base Prospectus whether as a result of new information, future events or otherwise. All subsequent written or oral forward-looking statements attributable to the Issuer, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements contained throughout this Base Prospectus. As a result of these risks, uncertainties and assumptions, a prospective purchaser of the Notes should not place undue reliance on these forward-looking statements.

DOCUMENTS INCORPORATED BY REFERENCE The following documents, which are published simultaneously with this Base Prospectus on the website of the Luxembourg Stock Exchange, shall be deemed to be incorporated in, and to form part of, this Base Prospectus: (a) the Terms and Conditions of the Notes contained on pages 124 to 153 of the Base Prospectus dated 22 July 2013 (for the avoidance of doubt, no other sections of the Base Prospectus dated 22 July 2013 shall be deemed to be incorporated in, or form part of, this Base Prospectus); (b) the consolidated reviewed interim financial statements of the Issuer as at and for the six months ended 30 September 2014, including comparative figures as at and for the six months ended 30 September 2013; (c) the consolidated audited annual financial statements of the Issuer as at and for the financial year ended 31 March 2014, including restated comparative figures as at and for the financial year ended 31 March 2013; (d) the consolidated audited annual financial statements of the Issuer as at and for the financial year ended 31 March 2013, including restated comparative figures as at and for the financial year ended 31 March 2012; and (e) the consolidated audited annual financial statements of the Issuer as at and for the financial year ended 31 March 2012, including restated comparative figures as at and for the financial year ended 31 March 2011. Cross Reference List The following table sets out a cross reference list for the specific items of Commission Regulation (EC) No 809/2004 which have been incorporated by reference.

Consolidated reviewed Consolidated audited Consolidated audited Consolidated audited interim financial annual financial annual financial annual financial statements as at and for statements as at and statements as at and for statements as at and for the six months ended 30 for the financial year the financial year ended the financial year ended September 2014 ended 31 March 2014 31 March 2013 31 March 2012 Independent auditors’ Page 3 Pages 12 to 13 Pages 10 to 11 Pages 4 to 5 report to Parliament and the shareholder ...... Statements of financial Page 4 Page 14 Page 12 Page 12 position ...... Income Statements ...... Page 5 Page 15 Page 13 Page 13 Statements of equity ...... Page 6 Page 16 Pages 14 to 15 Pages 14 to15 Statements of cash flows ... Page 7 Page 17 Pages 16 to 17 Pages 16 to 17 Explanatory notes ...... Pages 8 to 21 Pages 18 to 98 Pages 18 to 111 Pages 18 to 111

The information incorporated by reference that is not included in the cross reference list, is considered as additional information and is not required by the relevant schedules of Commission Regulation (EC) No 809/2004. All information contained in the Base Prospectus dated 22 July 2013 (other than the Terms and Conditions of the Notes on pages 124 to 153 which are incorporated by reference into this Base Prospectus) is either covered elsewhere in this Base Prospectus or is not relevant for investors. Each document incorporated by reference and any supplements or amendments to this Base Prospectus circulated by the Issuer from time-to-time will be published on the Luxembourg Stock Exchange’s website (www.bourse.lu). Any documents themselves incorporated by reference in the documents incorporated by reference into this Base Prospectus shall not form part of this Base Prospectus.

SUPPLEMENTS If at any time the Issuer shall be required to prepare a supplement in accordance with Article 13 of the Law on Prospectuses for Securities, the Issuer will prepare and make available an appropriate supplement to this Base Prospectus which, in respect of any subsequent issue of Notes to be listed and admitted to trading on the Market, shall constitute a prospectus supplement in accordance with Article 13 of the Law on Prospectuses for Securities. The Issuer has given an undertaking to the Dealers that, if at any time during the duration of the Programme, there is a significant new factor, material mistake or inaccuracy relating to information included in this Base Prospectus which is capable of affecting the assessment of any Notes and whose inclusion in or removal from this Base Prospectus is necessary for the purpose of allowing an investor to make an informed assessment of the assets and liabilities, financial position, profits and losses and prospects of the Issuer, and the rights attaching to the Notes, the Issuer shall prepare a supplement to this Base Prospectus or publish a new base prospectus for use in connection with any subsequent offering of the Notes and shall supply to each Dealer such number of copies of such supplement hereto as such Dealer may reasonably request.

FINAL TERMS AND DRAWDOWN PROSPECTUSES In this section the expression “necessary information” means, in relation to any Tranche of Notes, the information necessary to enable investors to make an informed assessment of the assets and liabilities, financial position, profits and losses and prospects of the Issuer and of the rights attaching to the Notes. In relation to the different types of Notes which may be issued under the Programme, the Issuer has endeavoured to include in this Base Prospectus all of the necessary information except for information relating to the Notes which is not known at the date of this Base Prospectus and which can only be determined at the time of an individual issue of a Tranche of Notes. Any information relating to the Notes which is not included in this Base Prospectus or any supplement hereto and which is required in order to complete the necessary information in relation to a Tranche of Notes will be contained either in the relevant Final Terms or in a Drawdown Prospectus. Such information will be contained in the relevant Final Terms unless any of such information constitutes a significant new factor relating to the information contained in this Base Prospectus, in which case such information, together with all of the other necessary information in relation to the relevant series of Notes, will be contained in a Drawdown Prospectus. For a Tranche of Notes which is the subject of Final Terms, those Final Terms will, for the purposes of that Tranche only, complete the Terms and Conditions of the Notes (the “Conditions”) contained in this Base Prospectus and must be read in conjunction with this Base Prospectus. The terms and conditions applicable to any particular Tranche of Notes which is the subject of Final Terms are the Conditions as completed by the relevant Final Terms. The terms and conditions applicable to any particular Tranche of Notes which is the subject of a Drawdown Prospectus will be the Conditions as supplemented, amended and/or replaced to the extent described in the relevant Drawdown Prospectus. In the case of a Tranche of Notes which is the subject of a Drawdown Prospectus, each reference in this Base Prospectus to information being specified or identified in the relevant Final Terms shall be read and construed as a reference to such information being specified or identified in the relevant Drawdown Prospectus unless the context requires otherwise. Each Drawdown Prospectus will be constituted either (1) by a single document containing the necessary information relating to the Issuer and the relevant Notes or (2) by a registration document (the “Registration Document”) containing the necessary information relating to the Issuer, a securities note (the “Securities Note”) containing the necessary information relating to the relevant Notes and, if necessary, a summary note. In addition, if the Drawdown Prospectus is constituted by a Registration Document and a Securities Note, any significant new factor, material mistake or inaccuracy relating to the information included in the Registration Document which arises or is noted between the date of the Registration Document and the date of the Securities Note which is capable of affecting the assessment of the relevant Notes will be included in the Securities Note.

SERVICE OF PROCESS AND ENFORCEMENT OF JUDGMENTS United States The Issuer is a company with limited liability incorporated under the laws of South Africa. The assets of the Issuer are located outside the United States. In addition, all of the Board of directors of the Issuer and officers of the Issuer are residents of countries other than the United States and all of their assets are located outside of the United States. As a result, it may be impossible for investors to effect service of process within the United States upon the Issuer or their Board or officers, or to enforce against them any judgments obtained in U.S. courts predicated upon the civil liability provisions of the U.S. securities laws. There can be no assurance that civil liabilities predicated upon the federal securities laws of the United States will be enforceable in South Africa. South Africa Choice of law In any proceedings for the enforcement of the obligations of the Issuer under the Notes, the South African courts will generally give effect to the choice of foreign law as contemplated in the Notes as the governing law thereof. Jurisdiction Subject to the paragraph below, the Issuer’s (i) irrevocable submission under the Notes to the jurisdiction of a foreign court, and (ii) agreement not to claim any immunity to which it or its assets may be entitled (including in relation to the making, enforcement or execution against any assets) to the extent permitted under South African law, is generally legal, valid, binding and enforceable under the laws of South Africa. The appointment by the Issuer of an agent within the jurisdiction of a foreign court to accept service of process in respect of the jurisdiction of the foreign courts is generally valid and binding on the Issuer. Under South African law, a court will not accept a complete ouster of jurisdiction, although generally it recognises party autonomy and gives effect to choice of law and submission to jurisdiction provisions. However, jurisdiction remains within the purview of the court and a court may in certain circumstances generally assume jurisdiction provided that (in terms of the “doctrine of effectiveness”) there are sufficient jurisdictional connecting factors in respect of the matter brought against the defendant. South African courts may, in rare instances, choose not to give effect to a choice of jurisdiction clause if, for example, such choice is contrary to public policy. Proceedings before a court of South Africa may be stayed if the subject matter of the proceedings is concurrently before any other court. Recognition and enforcement of foreign judgments Subject to the paragraph below, an authenticated judgment rendered by any foreign court of competent jurisdiction against the Issuer in respect of any of its obligations under the Notes will generally be recognised by the courts of South Africa and will generally be enforced in South Africa against the Issuer without the re-examination or re-litigation of any of the matters which are the subject of that judgment. Subject to the above qualifications, a judgment obtained outside South Africa will be recognised and enforced in accordance with the procedures ordinarily applicable under South African law for the recognition and enforcement of foreign judgments, namely by way of a provisional sentence summons or application or action claiming enforcement of the foreign judgement, provided (i) the foreign judgment was final and conclusive and is not superannuated, (ii) the recognition and enforcement of the foreign judgment by the South African courts is not contrary to South African public policy, (iii) the foreign court in question had jurisdiction and international competence according to the applicable rules recognised by the laws of South Africa in relation to conflict of laws and (iv) section 1(1) of the Protection of Business Act, 1978 has been complied with, where necessary (i.e. the Minister of Economic Affairs has given his/her permission to the enforcement of judgement). The principal requirements in regard to South African public policy are that the foreign judgment must not have been obtained by fraudulent or improper means or have been given contrary to natural justice, and must not involve the enforcement of foreign revenue or penal law. South African courts have, as a matter of public policy, generally not enforced awards for multiple or punitive damages. It is generally accepted that

it would be contrary to public policy for a court in South Africa to apply the law of a foreign jurisdiction when dealing with the insolvency of a South African party. Where obligations are to be performed in a jurisdiction outside South Africa, they may not be enforceable under the laws of South Africa to the extent that such performance would be illegal or contrary to public policy under the laws of South Africa, or the foreign jurisdiction or to the extent that the law precludes South African courts from granting extraterritorial orders. As an alternative to the common law enforcement proceedings, the Enforcement of Foreign Civil Judgments Act, 1988 makes provision, subject to the fulfilment of the applicable requirements, for the enforcement of final judgments sounding in money, and given in designated countries, on registration of such judgments by the appropriate Magistrates’ Court in South Africa. As soon as the judgment has been duly registered, it has the effect of a civil judgment of the registering court. The judgment cannot be enforced before the expiry of 21 days after service of the notice on the judgment debtor or until proceedings for setting it aside have been disposed of. Under section 2 of the Recognition and Enforcement of Foreign Arbitral Awards Act, 1977 (the “Enforcement Act”) any foreign arbitral award may, subject to section 3 and section 4 of the Enforcement Act, be made an order of court by a South African court. Any such award which has been made an order of court pursuant to the provisions of the Enforcement Act may be enforced in the same manner as any judgment or order to the same effect (subject to the provisions of the Protection of Businesses Act, 1978, which apply mutatis mutandis to foreign arbitral awards). Winding-up and Insolvency Under South African law, the winding up and judicial management of companies is regulated by both the SA Companies Act (of which in terms of the transitional provisions, the South African Companies Act, 1973 provisions relating to winding up and liquidation continue to apply) and the Insolvency Act, 1936 (the “Insolvency Act”). The effect of the SA Companies Act and the Insolvency Act (together with any other laws regulating the enforcement of creditors’ rights generally) is such that it may not be possible to enforce the rights conferred on the parties to the programme documents to the full extent contemplated therein. In particular, certain categories of creditors of the Issuer will, upon the liquidation of the Issuer, have statutory preferences over all or part of the claims of concurrent creditors of the Issuer. Any provision in any programme document which confers or purports to confer a right of set-off (or similar rights) may be ineffective against a liquidator or creditor of the Issuer. Effect of liquidation and civil proceedings In general and subject to certain exceptions, civil proceedings (including arbitration proceedings) instituted by or against an insolvent entity are automatically stayed on the liquidation of the insolvent entity’s estate until the appointment of a liquidator. A plaintiff/creditor wishing to continue with proceedings against an insolvent entity must give notice of its intention to continue legal proceedings within four weeks after the appointment of a liquidator, in accordance with the provisions of the South African Companies Act, 1973 failing which the proceedings shall be considered to be abandoned unless the Court directs otherwise. Execution against the insolvent entity’s assets are similarly stayed. Business Rescue Chapter 6 of the SA Companies Act makes provision for business rescue proceedings. Once the business rescue proceedings have commenced, there is a general moratorium on legal proceedings against the company. This means no legal proceedings, including enforcement action, may be commenced against the company save for a few exceptions provided for under the SA Companies Act. The business rescue practitioner has the power, despite any provision of an agreement to the contrary, to entirely, partially or conditionally suspend any obligation of the company that arises under an agreement to which the company is a party for the duration of the business rescue proceedings. The business rescue practitioner can also apply to a court to entirely, partially or conditionally cancel, on any terms that are just and reasonable in the circumstances, any agreement to which the company is a party. The only agreements that may not be cancelled or suspended are employment contracts and agreements to which section 35A and 35B of the Insolvency Act would have applied had the company been liquidated. Section 35A and 35B of the

Insolvency Act cover transactions on an exchange as provided for in the Financial Markets Act, 2012 and certain master agreements which provide for termination and netting, respectively.

OVERVIEW OF THE ISSUER AND THE PROGRAMME This overview does not contain all the information that may be important to prospective purchasers of the Notes and, therefore, should be read in conjunction with this entire Base Prospectus, including the more detailed information regarding the Group’s business and the Consolidated Financial Statements and related notes thereto which are incorporated by reference in this Base Prospectus. This Base Prospectus should be read carefully, and prospective purchasers of the Notes should also carefully consider the information set forth under the heading “Risk Factors”. Certain statements in this Base Prospectus include forward-looking statements that also involve risks and uncertainties as described under “Forward-Looking Statements”. Terms defined elsewhere in this Base Prospectus shall have the same meanings in this overview. Overview of the Issuer The Issuer is South Africa’s national electricity utility, engaged in the generation, transmission, distribution and retailing of electricity to industrial, mining, commercial, agricultural and residential customers, as well as to municipalities and other redistributors. The Government, through the Department of Public Enterprises, is the Issuer’s sole shareholder. As a vertically-integrated company, with responsibilities that extend from procuring coal to distributing electricity generated from that coal, the Group has the ability to be innovative and efficient across the value chain, following an integrated approach to the generation, transmission and distribution of electricity. The Group supplies approximately 95% of South Africa’s electricity (with the remainder being produced by local authorities and certain large customers for their own consumption) and approximately 40% of the total electricity consumed on the African continent. The Group directly provides electricity to approximately 45% of all end-users in South Africa and to redistributors (including municipalities) who, in turn, resell and supply the other 55%. The Group currently sells directly to approximately 3,000 industrial, 1,000 mining, 50,000 commercial, 83,000 agricultural and more than five million residential customers, 40% of whom are in rural areas. The figure for residential customers includes prepaid customers. The Issuer was established in South Africa in 1923 as the Electricity Supply Commission and was subsequently converted into a public limited liability company, wholly-owned by the Government, in July 2002. With over 90 years of operational experience in Southern Africa, the Group believes its resilience to the broad economic and fiscal adversity of recent years is a strength that will help it progress in the future. As at 30 September 2014 and 31 March 2014, the Group had a total nominal capacity of 41,995 MW, while as at 31 March 2013 the Group had a total nominal capacity of 41,919 MW. As at 30 September 2014, the Group’s transmission network consisted of approximately 30,068 km of transmission lines of voltages ranging between 132 to 765 kV (compared to 29,924 km as at 31 March 2014) and a network of 159 substations (compared to 157 as at 31 March 2014). Electricity distribution is carried out by the Group and approximately 800 redistributors that purchase the electricity from the Group and, in a few cases, supplement it from their own power stations. For the six months ended 30 September 2014, the Group had total electricity sales of 109,168 GWh, representing a decrease of 1.3% compared to 110,659 GWh for the six months ended 30 September 2013. For the financial year ended 31 March 2014, the Group had total electricity sales of 217,903 GWh, representing an increase of 0.6% compared to 216,561 GWh for the financial year ended 31 March 2013. For the six months ended 30 September 2014, the Group had revenues and profit before tax of R81,898 million and R12,996 million, respectively, and as at 30 September 2014, the Group had total assets of R534,334 million. For the financial year ended 31 March 2014, the Group had revenues and profit before tax of R139,506 million and R9,163 million, respectively, and as at 31 March 2014, the Group had total assets of R504,993 million. Most of the Group’s operating activities, as well as related revenues and resulting tariffs, are subject to regulation by NERSA. In addition, much of the Group’s strategy and many of its future prospects will ultimately have to be aligned with the Department of Energy’s IRP, which sets out a long-term electricity plan for South Africa, and the Department of Energy’s IEP, which is broadly designed to guide future South African energy infrastructure investment and policy for the 2010 to 2050 period. The IEP was published in June 2013 for public consultation, and a final report is expected to be published in March 2015. The IRP, which was promulgated in 2011 and covered the 2010 to 2030 period, is currently in the process of being revised to reflect the continuing evolution of the Government’s long-term electricity strategy. It remains

unclear when the updated IRP will be finalised and approved by the Cabinet. While a draft updated version of the IRP was published in November 2013 for public comment, it is expected that the final revised IRP will only be formally approved after the Government has approved the over-arching IEP, which is expected to inform the contents of the revised IRP. The draft IRP update is not an official update to the promulgated IRP, but the update has, however, revised scenarios based on changes to South Africa’s economic outlook, including addressing the effect of slowing economic growth on projected electricity demand (anticipating that less capacity will be required by 2030). However, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. Regardless, the IRP is expected to have a significant impact on the Group’s operations. The Group holds separate licences for its generation, transmission and electricity distribution activities, with revenues being regulated for each of these licensed activities. The Group allocates its revenues internally across these segments, using a cost-of-service-based methodology with incentives for cost savings and efficient and prudent procurement by the Issuer. This methodology also provides for Services Quality Incentives (“SQIs”) which are used as a measure to encourage the Group to improve its reliability of supply. The objective of SQIs is to ensure that the provision of good quality supply is rewarded and poor quality of supply is penalised. Each segment’s revenue is calculated separately with the overall price and revenue determined at the distribution level and communicated as such to customers. See “Overview of South Africa and the South African Electricity Industry—Regulation of the South African Electricity Industry” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Factors Affecting Results of Operations—Pricing”. In June 2014, following the local and foreign currency downgrade of South Africa, the Issuer’s credit ratings were revised by two credit rating agencies. Fitch, Inc. (“Fitch”) revised Eskom’s ratings outlook from Stable to Negative while S&P downgraded the Issuer to BBB with a Negative CreditWatch. In October 2014, Fitch affirmed the Issuer’s long-term local currency credit rating with a Negative outlook. However, on 7 November 2014, Moody’s downgraded the Issuer’s senior unsecured rating from Baa3 (Negative outlook) to Ba1 (Stable outlook). Following this announcement, on 11 November 2014, S&P affirmed its BBB- credit rating of Eskom and removed it from CreditWatch. The Issuer’s current local and foreign currency ratings are as follows:

Ratings and Outlook S&P Foreign currency ...... BBB- Negative(1) Local currency ...... BBB- Negative(1) Moody’s Foreign currency ...... Ba1 Stable(2) Local currency ...... Ba1 Stable(2) Fitch Local currency ...... BBB+ Negative (3) ______(1) Last changed on 11 November 2014. (2) Last changed on 7 November 2014. (3) Last changed on 28 October 2014.

Strategy The Group’s overall strategy is to concentrate its resources on building South Africa’s power infrastructure to promote sustainable growth and development in its core businesses of electricity generation, transmission, trading and retail. The Group has developed the following eight broad strategic objectives:

• becoming a high performing organisation;

• leading and partnering to keep the lights on while ensuring the integrity of the Group’s generation and transmission infrastructure;

• reducing the Group’s environmental footprint and pursuing low carbon growth opportunities;

• securing the Group’s future resource requirements;

• ensuring the financial sustainability of the Group;

• implementing coal haulage and the road-to-rail migration plan;

• pursuing private sector participation through IPPs; and

• transformation (including the BPP). Given the outcome of the MYPD 3 determination and the Group’s latest sales projections, the Group will have to continue to revisit its strategies and adapt its business plan to align them with the challenges posed by reduced income (and the estimated revenue shortfall as a result of lower tariffs and revised sales projections for the remainder of the MYPD 3 period) as well as the uncertainties created by the IRP, including, among other things, with respect to future generation capacity, “the energy mix” and funding. A revised version of the IRP is expected to be approved following the IEP’s anticipated approval in March 2015. Based on the Group’s available budget over the five-year MYPD 3 period, capital investment will prioritise capacity expansion projects, generation sustainability, environmental compliance, transmission strengthening and compliance, customer connections, asset maintenance, asset replacement and refurbishment and the connection of IPPs. Additionally, the Group will focus on alternative funding options (including Government support), RCA adjustments and a continuing focus on skills building, transformation and environmental sustainability. Certain Financial Information and Operating Data

For the six months ended For the year ended 30 September 31 March 2014 2013(1) 2014 2013(2) 2012 (millions of Rand) INCOME STATEMENT Revenue ...... 81,898 77,722 139,506 128,775 114,760 Primary energy ...... (38,065) (31,266) (69,812) (60,748) (46,314) Net employee benefit expense...... (13,176) (12,951) (25,622) (23,564) (20,132) Depreciation and amortisation expense ...... (6,672) (5,912) (11,937) (9,960) (8,801) Net impairment loss...... (855) (682) (1,557) (1,039) (620) Other operating expenses ...... (7,841) (9,077) (19,177) (23,039) (15,209) Other income 452 183 962 1,126 699 Net fair value loss on financial instruments, excluding embedded derivatives ...... (860) (998) (620) (1,655) (2,388) Net fair value gain/(loss) on embedded derivatives ...... 1,621 1,868 2,149 (5,942) 334 Operating profit before net finance cost ...... 16,502 18,887 13,892 3,954 22,329 Net finance (cost)/income ...... (3,539) (1,853) (4,772) 3,003 (3,963) Share of profit of equity-accounted investees after tax ...... 33 26 43 35 41 Profit before tax ...... 12,996 17,060 9,163 6,992 18,407 Income tax ...... (3,675) (4,846) (2,137) (1,856) (5,156) Profit from continuing operations ...... 9,321 12,214 7,026 5,136 13,251 DISCONTINUED OPERATIONS (Losses)/profit from discontinued operations ...... (34) 27 63 47 (3) Profit for the period ...... 9,287 12,241 7,089 5,183 13,248 Attributable to: Owner of the company ...... 9,287 12,241 7,089 5,183 13,248 Non-controlling interest(3) ...... — — — — — 9,287 12,241 7,089 5,183 13,248 ______(1) The Group’s income statement and statements of cash flows for the six months ended 30 September 2013 as set out in the Group’s Reviewed Interim Financial Statements for the six months ended 30 September 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 21 of the Reviewed Interim Financial Statements (with respect to the six months ended 30 September 2013). (2) The Group’s income statement and statement of cash flows for the year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the year ended 31 March 2014, and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Group’s Audited Annual Financial Statements (with respect to the year ended 31 March 2014). (3) Nominal amount.

For the six months ended For the year ended 30 September 31 March 2014 2013(1) 2014 2013(2) 2012 (millions of Rand) Statement of Cash Flow Net cash generated from operating activities ...... 18,106 19,625 33,616 27,669 38,529 Net cash utilised in investing activities ...... (25,284) (24,505) (57,207) (58,359) (60,013) Net cash generated from financing activities ...... 438 24,468 32,795 21,784 28,720 Statement of Financial Position Cash and cash equivalents ...... 12,953 30,193 19,676 10,620 19,450 Current assets ...... 65,150 79,241 64,977 53,241 63,050 Property, plant and equipment and intangible assets ...... 432,375 366,366 404,389 344,271 292,209 Non-current assets held for sale ...... 12 8 147 8 438 Total assets ...... 534,334 481,665 504,993 432,024 382,365 Current liabilities ...... 83,687 63,269 74,181 58,439 56,115 Non-current liabilities ...... 322,235 294,950 310,915 264,446 222,672 Non-current liabilities held-for-sale ...... — — 113 — 475 Total liabilities ...... 405,922 358,219 385,209 322,885 279,262 Minority interests(3) ...... — — — — — Capital and reserves attributable to owner of the company ...... 128,412 123,446 119,784 109,139 103,103 Total equity and liabilities ...... 534,334 481,665 504,993 432,024 382,365 ______(1) The Group’s income statement and statements of cash flows for the six months ended 30 September 2013 as set out in the Group’s Reviewed Interim Financial Statements for the six months ended 30 September 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 21 of the Reviewed Interim Financial Statements (with respect to the six months ended 30 September 2013). (2) The Group’s income statement and statement of cash flows for the year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the year ended 31 March 2014, and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Group’s Audited Annual Financial Statements (with respect to the year ended 31 March 2014). (3) Nominal amount.

For the six months ended For the financial year ended 30 September 31 March 2014 2013 2014 2013 2012 Other Financial and Operating Data Capital expenditure (including capitalised borrowing costs) (millions of Rand) ...... 34,808 29,419 72,716 61,046 63,354 Depreciation (millions of Rand) ...... 6,672 5,912 11,937 9,960 8,801 EBITDA (millions of Rand)(1) ...... 23,174 24,799 25,829 13,914 31,130 Ratio of earnings to fixed charges (interest cover)(2) ...... 1.29x 2.27x 0.77x 0.22x 3.35x Gross debt(3) (millions of Rand) ...... 297,922 263,379 282,982 225,364 201,179 Total capitalisation (gross debt(3) plus shareholder equity) (millions of Rand) ...... 426,334 386,825 402,766 334,503 124,146 Debt/Equity (including long-term provisions) ...... 2.08x 1.72x 2.06x 1.84x 1.64x Net debt (millions of Rand) ...... 222,230 174,557 205,088 161,044 137,815 Gross debt/EBITDA(1)(10)(11) ...... 12.86x 10.62x 10.96x 16.20x 6.46x Net debt/EBITDA(1)(8)(12) ...... 9.59x 7.04x 7.94x 11.57x x 4.43x Working capital ratio(4) ...... 0.82x 0.89x 0.71x 0.68x 0.76x Group annual arrear debt as a percentage of revenue (%)(13) ...... 0.91 0.9 1.10 0.82 0.53 Debtors days(5) of which: Customer service—top customers excluding disputes ...... 15.2 15.2 14.5 12.3 14.4 Customer service—large power users, municipalities ...... 33 26.4 32.7 22.4 n.a.(14) Customer service—large power users, (<100GWh a year) ...... 17 16.5 16.9 18.3 n.a.(14) Customer service—small customers excluding Soweto ...... 46.1 44.3 50.2 48.2 42.9 Average days coal stock(9) ...... 46 53 44 46 39 Free funds from operations (millions of Rand)(6) ...... 16,899 23,312 27,542 18,108 30,483 Electricity revenue per kWh (cents per kWh) ...... 74.00 68.95 62.82 58.49 50.27 Electricity operating costs per kWh(7) (cents per kWh)...... 62.14 55.29 59.67 54.14 41.28 ______(1) EBITDA means operating profit before net finance (cost)/income plus depreciation and amortisation. See “Presentation of Financial and Other Information—Presentation of Financial Information”. (2) Operating profit before net finance cost/net finance cost before change in discount rate, unwinding of interest and borrowing cost capitalised. (3) Gross debt consists of debt as set out in the Group’s Consolidated Financial Statements plus power station-related environmental restoration costs, mine- related closure provisions and non-current employee benefit obligations (all net of tax). (4) Working capital ratio: adjusted current assets/adjusted current liabilities. (5) Average outstanding debtors’ days. (6) Free funds from operations means cash generated from operations adjusted for working capital (excluding provisions) and net interest paid/received and non-current assets held for risk management. (7) Including depreciation and amortisation. (8) Net debt consists of (Financial liabilities–financial assets but excluding trade and other payables and receivables and finance lease payables and receivables) + (long-term provisions). (9) Average days’ coal stock is calculated by dividing total tonnages on hand by the standard daily burn. (10) Debt securities issued, Borrowings, Finance lease liabilities, Financial trading liabilities, and Unadjusted Debt of Power Station related environmental restoration, Mine related Closure provision, Non-Current Employee benefit obligations, after tax. (11) The increase in the gross debt/EBITDA ratio for the financial year ended 31 March 2013 was due largely to an increase in debt and a decrease in EBITDA as a result of increases in primary energy and operational costs. (12) The increase in the net debt/EBITDA ratio for the financial year ended 31 March 2013 was due largely to an increase in debt and a decrease in EBITDA as a result of increases in primary energy and operational costs. (13) Group annual arrear debt means impairment for trade and other receivables. (14) These performance indicators came into effect 31 March 2013. Data is not available for the financial year ended 31 March 2012.

Overview of the Programme The following overview does not purport to be complete and is taken from, and is qualified in its entirety by, the remainder of this Base Prospectus and, in relation to the terms and conditions of any particular Tranche of Notes, the applicable Final Terms or relevant Drawdown Prospectus. This overview constitutes a general description of the Programme for the purposes of Article 22.5(3) of Commission Regulation (EC) No. 809/2004. Words and expressions defined in the “Form of Notes” and “Terms and Conditions of the Notes” shall have the same meanings in this overview. Issuer ...... Eskom Holdings SOC Ltd. Risk Factors ...... There are certain factors that may affect the Issuer’s ability to fulfil its obligations under Notes issued under the Programme. These factors are set out under “Risk Factors”. In addition, there are certain factors which are material for the purpose of assessing the market risks associated with Notes issued under the Programme. These are also set out under “Risk Factors” and include the fact that the Notes may not be a suitable investment for all investors, certain risks relating to the structure of particular series of Notes and certain market risks. Description ...... Global Medium Term Note Programme. Arrangers ...... Africa Rising Capital Proprietary Limited, Basis Points Capital Proprietary Limited, Deutsche Bank AG, London Branch, Pamoja Capital Proprietary Limited, Rand Merchant Bank, a division of FirstRand Bank Limited (London Branch) and The Standard Bank of South Africa Limited. Dealers ...... Africa Rising Capital Proprietary Limited, Basis Points Capital Proprietary Limited, Deutsche Bank AG, London Branch, Pamoja Capital Proprietary Limited, Rand Merchant Bank, a division of FirstRand Bank Limited (London Branch) and The Standard Bank of South Africa Limited and any other Dealer appointed from time to time by the Issuer either generally in respect of the Programme or in relation to a particular Tranche of Notes. Trustee ...... Citicorp Trustee Company Limited. Principal Paying and Transfer Agent, Citibank N.A., London Branch. Custodian and Calculation Agent ...... Registrar ...... Citigroup Global Markets Deutschland AG. Programme Size ...... Up to U.S.$4,000,000,000 (or its equivalent in other currencies calculated as described in the Dealer Agreement) outstanding at any time. The Issuer may increase the amount of the Programme in accordance with the terms of the Dealer Agreement. Certain Restrictions ...... Each issue of Notes denominated in a currency in respect of which particular laws, guidelines, regulations, restrictions or reporting requirements apply will only be issued in circumstances which comply with such laws, guidelines, regulations, restrictions or reporting requirements from time to time (see “Subscription and Sale and Transfer and Selling Restrictions”) including the following restrictions applicable at the date of this Base Prospectus:

Notes having a maturity of less than one year. Notes having a maturity of less than one year will, if the proceeds of the issue are accepted in the United Kingdom, constitute deposits for the purposes of the prohibition on accepting deposits contained in section 19 of the Financial Services and Markets Act 2000 unless they are issued to a limited class of professional investors and have a denomination of at least £100,000 or its equivalent. See “Subscription and Sale and Transfer and Selling Restrictions”. Bearer Notes. Notes may only be issued in bearer form in accordance with the requirements of South African law which includes the prior approval of the South African Minister of Finance. The Notes in bearer form are subject to certain restrictions on transfer. See “Subscription and Sale and Transfer and Selling Restrictions”. Final Terms or Drawdown Prospectus Notes issued under the Programme may be issued either (1) pursuant to this Base Prospectus and associated Final Terms or (2) pursuant to a Drawdown Prospectus. The terms and conditions applicable to any particular Tranche of Notes will be the Conditions as completed by the relevant Final Terms or as supplemented, amended and/or replaced to the extent described in the relevant Drawdown Prospectus, as the case may be. Distribution ...... Notes may be distributed by way of private or public placement and in each case on a syndicated or non-syndicated basis. Issuance in series ...... Notes will be issued in series. Each series may comprise one or more Tranches issued on different issue dates. The Notes of each series will all be subject to identical terms, except that the issue date and the amount of the first payment of interest may be different in respect of different Tranches. The Notes of each Tranche will all be subject to identical terms in all respects save that a Tranche may comprise Notes of different denominations. Prior written approval of ExCon is required for the issuance of each Tranche of Notes under the Programme. Currencies ...... Notes may be denominated and payments in respect of the Notes may be made in euro, Sterling, U.S. dollar, South African Rand or, subject to any applicable legal or regulatory restrictions, any other currency agreed between the Issuer and the relevant Dealer, and as set out in the conditions and specified in the applicable Final Terms or relevant Drawdown Prospectus. Maturities ...... The Notes will have such maturities as may be agreed between the Issuer and the relevant Dealer, subject to a maximum of 30 years and such other minimum or maximum maturities as may be allowed or required from time to time by the relevant central bank (or equivalent body) or any laws or regulations applicable to the Issuer or the relevant Specified Currency (as set out in the applicable Final Terms or relevant Drawdown Prospectus). Issue Price...... Notes may be issued on a fully paid basis and at an issue price

which is at par or at a discount to, or premium over, par. Form of Notes ...... The Notes will be issued in bearer or registered form as described in “Form of the Notes”. Registered Notes will not be exchangeable for Bearer Notes and vice versa. Clearing Systems ...... Euroclear and Clearstream, Luxembourg for Bearer Notes. Euroclear, Clearstream, Luxembourg and DTC for Registered Notes or as may be specified in the relevant Final Terms or relevant Drawdown Prospectus. Fixed Rate Notes ...... Fixed interest will be payable on such date or dates as may be agreed between the Issuer and the relevant Dealer and on redemption and will be calculated on the basis of such Day Count Fraction as may be agreed between the Issuer and the relevant Dealer. Interest on Fixed Rate Notes in bearer form will only be payable outside the United States and its possessions, subject to Condition 6.5 (General Provisions Applicable to Payments). Floating Rate Notes ...... Floating Rate Notes will bear interest at a rate determined: (a) on the same basis as the floating rate under a notional interest rate swap transaction in the relevant Specified Currency governed by an agreement incorporating the 2006 ISDA Definitions (as published by the International Swaps and Derivatives Association, Inc., and as amended and updated as of the Issue Date of the first Tranche of the Notes of the relevant series); (b) on the basis of a reference rate appearing on the agreed screen page of a commercial quotation service; or (c) on such other basis as may be agreed between the Issuer and the relevant Dealer. The margin (if any) relating to such floating rate will be agreed between the Issuer and the relevant Dealer for each series of Floating Rate Notes. Interest on Floating Rate Notes in bearer form will only be payable outside the United States and its possessions, subject to Condition 6.5 (General Provisions Applicable to Payments). Zero Coupon Notes ...... Zero Coupon Notes will be offered and sold at a discount to their nominal amount and will not bear interest. Redemption ...... The applicable Final Terms or relevant Drawdown Prospectus will indicate either that the relevant Notes cannot be redeemed prior to their stated maturity (other than for taxation reasons or following an Event of Default or upon an Investor Put Option or upon a Put Event (which occurs if the Government of South Africa ceases to have control or a Restructuring Event occurs within the Restructuring Period – see Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)) or that such Notes will be redeemable at the option of the Issuer and/or the Noteholders upon giving notice to the Noteholders or the Issuer, as the case may be, on a date or dates specified prior to such stated maturity at the Make-Whole Amount (as defined in the Conditions) or Optional Redemption Amount (as specified in the applicable Final Terms) together with accrued interest. The terms of any such redemption, including notice

periods, any relevant conditions to be satisfied and the relevant redemption dates and prices will be indicated in the applicable Final Terms or relevant Drawdown Prospectus. Notes having a maturity of less than one year may be subject to restrictions on their denomination and distribution. See “Certain Restrictions: Notes having a maturity of less than one year” above. Denomination of Notes ...... The Notes will be issued in such denominations as may be specified in the relevant Final Terms or relevant Drawdown Prospectus, subject to compliance with all applicable legal and/or regulatory and/or central bank requirements applicable to the currency of the relevant Tranche of Notes. Notes which are to be admitted to trading on a regulated market within the EEA or offered to the public in a Member State of the EEA in circumstances which require the publication of a prospectus under the Prospectus Directive shall have a minimum specified denomination of €100,000, or not less than the equivalent of €100,000 in any other currency as at the date of issue of the relevant Notes. Notes (including Notes denominated in Sterling) which have a maturity of less than one year and in respect of which the issue proceeds are to be accepted by the Issuer in the United Kingdom or whose issue otherwise constitutes a contravention of section 19 of the FSMA will have a minimum denomination of £100,000 (or its equivalent in another currency). Taxation ...... All payments in respect of the Notes will be made without deduction for or on account of withholding taxes imposed by any Relevant Jurisdiction as provided in Condition 8 (Taxation), unless such deduction is required by law in the Relevant Jurisdiction. In the event that any such deduction is made the Issuer will, save in certain limited circumstances provided in Condition 8 (Taxation), be required to pay additional amounts to cover the amounts so deducted. Negative Pledge ...... So long as the Notes remain outstanding, the Issuer shall not, and shall procure that none of its Material Subsidiaries will, create or have outstanding any Security Interest upon, or with respect to, any of its present or future business, undertaking, assets or revenues (including any uncalled capital) or any parts of any Relevant Indebtedness, save as provided in Condition 4.1 (Negative Pledge) and as more fully described therein. Cross Default ...... An Event of Default will occur in respect of accelerated or unpaid Borrowed Moneys Indebtedness of U.S.$100,000,000 or more as provided in Condition 10.1 (Events of Default). Status of the Notes ...... The Notes will constitute direct, unsubordinated and, subject to Condition 4.1(a) (Negative Pledge), unsecured obligations of the Issuer. The Notes rank and will rank pari passu in right of payment with the Issuer’s other unsubordinated obligations, present and future, but, in the event of insolvency, only to the extent permitted by applicable laws relating to creditors’ rights and pari passu without any preference among themselves. The Notes will not be secured by section 7 of the Eskom Conversion Act, 2001, as amended. See Condition 3 (Status of the Notes).

Rating ...... The Programme is rated Ba1 by Moody’s and BBB- by S&P. Where a Series of Notes issued under the Programme is to be rated, such rating will be specified in the applicable Final Terms or relevant Drawdown Prospectus. Listing and admission to trading ...... Application has been made to the CSSF for Notes issued under the Programme to be admitted to the Official List and to the Market. Notes may be listed or admitted to trading, as the case may be, on other or further stock exchanges or markets agreed between the Issuer and the relevant Dealer in relation to the series. Notes which are neither listed nor admitted to trading on any market may also be issued. The applicable Final Terms or relevant Drawdown Prospectus will state whether or not the relevant Notes are to be listed and/or admitted to trading and, if so, on which stock exchanges and/or markets. Governing Law ...... The Programme and any Notes will be governed by, and construed in accordance with, English law. Selling Restrictions ...... There are restrictions on the offer, sale and transfer of the Notes in the United States, the United Kingdom and South Africa and such other restrictions as may be required in connection with the offering and sale of a particular Tranche of Notes. See “Subscription and Sale and Transfer and Selling Restrictions”. United States Selling Restrictions ...... Regulation S (as defined in “Form of the Notes”), Category 2. Rule 144A and TEFRA C, TEFRA D or TEFRA not applicable and as specified in the applicable Final Terms or relevant Drawdown Prospectus. The Notes in bearer form are subject to certain restrictions on transfer. See “Subscription and Sale and Transfer and Selling Restrictions”.

USE OF PROCEEDS The net proceeds from each issue of Notes will be added to the Issuer’s general funding pool, to be applied in the committed capacity expansion programme of generation and transmission assets and general working capital. If, in respect of any particular issue of Notes, there is a particular identified use of proceeds, this will be stated in the relevant Drawdown Prospectus.

CAPITALISATION AND INDEBTEDNESS The following table sets out the Issuer’s consolidated capitalisation as at 30 September 2014 and 31 March 2014. Investors should read this table in conjunction with the Group’s Consolidated Financial Statements and related notes which are incorporated by reference in this Base Prospectus.

As at 30 September As at 31 March 2014 2014 (millions of Rand unless otherwise indicated) Cash and cash equivalents ...... 12,953 19,676 Debt securities and borrowings (current) ...... 27,942 20,258 Debt securities and borrowings (non-current) ...... 236,973 234,562 Equity ...... 128,412 119,784 Total capitalisation(1) (debt(2) and equity) ...... 393,327 374,604 Ratio of debt(2) to total capitalisation ...... 67.4% 68.0% ______(1) Total capitalisation includes current and non-current debt securities and borrowings and equity as disclosed above. (2) Debt includes current and non-current debt securities and borrowings as disclosed above.

There have been no material changes in the total capitalisation and long-term liabilities of the Issuer since 30 September 2014.

RATIO OF EARNINGS TO FIXED CHARGES The following table sets out the Group’s ratio of earnings to fixed charges for the periods indicated:

For the six months ended For the financial year ended 31 30 September March 2014 2014 2013 Ratio of earnings to fixed charges (interest cover)(1) ...... 1.29x 0.77x 0.22x ______(1) Operating profit before net finance cost/net finance cost before unwinding of discount on provisions, change in discount rate and borrowing cost capitalised.

SELECTED FINANCIAL INFORMATION AND OPERATING DATA The selected income statement and cash flow information of the Group as at and for the six months ended 30 September 2014 and 30 September 2013 and the financial years ended 31 March 2014, 31 March 2013 and 31 March 2012 has been derived from the Group’s Consolidated Financial Statements which are incorporated by reference in this Base Prospectus. The selected consolidated financial information has been derived from, and should be read in conjunction with, the Consolidated Financial Statements and the related notes thereto which are incorporated by reference in this Base Prospectus, as well as the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition”.

For the six months ended For the financial year ended 30 September 31 March 2014 2013(1) 2014 2013(2) 2012 (millions of Rand) INCOME STATEMENT Revenue ...... 81,898 77,722 139,506 128,775 114,760 Primary energy ...... (38,065) (31,266) (69,812) (60,748) (46,314) Net employee benefit expense...... (13,176) (12,951) (25,622) (23,564) (20,132) Depreciation and amortisation expense ...... (6,672) (5,912) (11,937) (9,960) (8,801) Net impairment loss...... (855) (682) (1,557) (1,039) (620) Other operating expenses ...... (7,841) (9,077) (19,177) (23,039) (15,209) Other income 452 183 962 1,126 699 Net fair value loss on financial instruments, excluding embedded derivatives ...... (860) (998) (620) (1,655) (2,388) Net fair value gain/(loss) on embedded derivatives ...... 1,621 1,868 2,149 (5,942) 334 Operating profit before net finance cost ...... 16,502 18,887 13,892 3,954 22,329 Net finance (cost)/income ...... (3,539) (1,853) (4,772) 3,003 (3,963) Share of profit of equity-accounted investees after tax ...... 33 26 43 35 41 Profit before tax ...... 12,996 17,060 9,163 6,992 18,407 Income tax ...... (3,675) (4,846) (2,137) (1,856) (5,156) Profit from continuing operations ...... 9,321 12,214 7,026 5,136 13,251 DISCONTINUED OPERATIONS (Losses)/profit from discontinued operations ...... (34) 27 63 47 (3) Profit for the period ...... 9,287 12,241 7,089 5,183 13,248 Attributable to: Owner of the company ...... 9,287 12,241 7,089 5,183 13,248 Non-controlling interest(3) ...... — — — — — 9,287 12,241 7,089 5,183 13,248 ______(1) The Group’s income statement and statements of cash flows for the six months ended 30 September 2013 as set out in the Group’s Reviewed Interim Financial Statements for the six months ended 30 September 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 21 of the Reviewed Interim Financial Statements (with respect to the six months ended 30 September 2013). (2) The Group’s income statement and statement of cash flows for the year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the year ended 31 March 2014, and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Group’s Audited Annual Financial Statements (with respect to the year ended 31 March 2014). (3) Nominal amount.

For the six months ended For the financial year ended 30 September 31 March 2014 2013(1) 2014 2013(2) 2012 (millions of Rand) Statement of Cash Flow Net cash generated from operating activities ...... 18,106 19,625 33,616 27,669 38,529 Net cash utilised in investing activities ...... (25,284) (24,505) (57,207) (58,359) (60,013) Net cash generated from financing activities ...... 438 24,468 32,795 21,784 28,720 Statement of Financial Position Cash and cash equivalents ...... 12,953 30,193 19,676 10,620 19,450 Current assets ...... 65,150 79,241 64,977 53,241 63,050 Property, plant and equipment and intangible assets ...... 432,375 366,366 404,389 344,271 292,209 Non-current assets held for sale ...... 12 8 147 8 438 Total assets ...... 534,334 481,665 504,993 432,024 382,365 Current liabilities ...... 83,687 63,269 74,181 58,439 56,115 Non-current liabilities ...... 322,235 294,950 310,915 264,446 222,672 Non-current liabilities held-for-sale ...... — — 113 — 475 Total liabilities ...... 405,922 358,219 385,209 322,885 279,262 Minority interests(3) ...... — — — — — Capital and reserves attributable to owner of the company ...... 128,412 123,446 119,784 109,139 103,103 Total equity and liabilities ...... 534,334 481,665 504,993 432,024 382,365 ______(1) The Group’s income statement and statements of cash flows for the six months ended 30 September 2013 as set out in the Group’s Reviewed Interim Financial Statements for the six months ended 30 September 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 21 of the Reviewed Interim Financial Statements (with respect to the six months ended 30 September 2013). (2) The Group’s income statement and statement of cash flows for the year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the year ended 31 March 2014, and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Group’s Audited Annual Financial Statements (with respect to the year ended 31 March 2014). (3) Nominal amount.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The following discussion and analysis should be read together with the Consolidated Financial Statements and the related notes thereto which are incorporated by reference in this Base Prospectus. The Consolidated Financial Statements have been prepared in accordance with IFRS and in the manner required by the Public Finance Management Act, 1999 (“PFMA”) and the SA Companies Act. Certain information contained in the following discussion and analysis and elsewhere in this Base Prospectus includes forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” and “Risk Factors” for a discussion of the important factors that could cause actual results to differ materially from the results described or implied by the forward-looking statements contained in this Base Prospectus. Overview The Issuer is South Africa’s national electricity utility, engaged in the generation, transmission, distribution and retailing of electricity to industrial, mining, commercial, agricultural and residential customers, as well as to municipalities and other redistributors. The Government, through the Department of Public Enterprises, is the Issuer’s sole shareholder. As a vertically-integrated company, with responsibilities that extend from procuring coal to distributing electricity generated from that coal, the Group has the ability to be innovative and efficient across the value chain, following an integrated approach to the generation, transmission and distribution of electricity. The Group supplies approximately 95% of South Africa’s electricity (with the remainder being produced by local authorities and certain large customers for their own consumption) and approximately 40% of the total electricity consumed on the African continent. The Group directly provides electricity to approximately 45% of all end-users in South Africa and to redistributors (including municipalities) who, in turn, resell and supply the other 55%. The Group currently sells directly to approximately 3,000 industrial, 1,000 mining, 50,000 commercial, 83,000 agricultural and more than five million residential customers, 40% of whom are in rural areas. The figure for residential customers includes prepaid customers. The Issuer was established in South Africa in 1923 as the Electricity Supply Commission and was subsequently converted into a public limited liability company, wholly-owned by the Government, in July 2002. With over 90 years of operational experience in Southern Africa, the Group believes its resilience to the broad economic and fiscal adversity of recent years is a strength that will help it progress in the future. As at 30 September 2014 and 31 March 2014, the Group had a total nominal capacity of 41,995 MW, while as at 31 March 2013 the Group had a total nominal capacity of 41,919 MW. As at 30 September 2014, the Group’s transmission network consisted of approximately 30,068 km of transmission lines of voltages ranging between 132 to 765 kV (compared to 29,924 km as at 31 March 2014) and a network of 159 substations (compared to 157 as at 31 March 2014). Electricity distribution is carried out by the Group and approximately 800 redistributors that purchase the electricity from the Group and, in a few cases, supplement it from their own power stations. For the six months ended 30 September 2014, the Group had total electricity sales of 109,168 GWh, representing a decrease of 1.3% compared to 110,659 GWh for the six months ended 30 September 2013. For the financial year ended 31 March 2014, the Group had total electricity sales of 217,903 GWh, representing an increase of 0.6% compared to 216,561 GWh for the financial year ended 31 March 2013. For the six months ended 30 September 2014, the Group had revenues and profit before tax of R81,898 million and R12,996 million, respectively, and as at 30 September 2014, the Group had total assets of R534,334 million. For the financial year ended 31 March 2014, the Group had revenues and profit before tax of R139,506 million and R9,163 million, respectively, and as at 31 March 2014, the Group had total assets of R504,993 million. Most of the Group’s operating activities, as well as related revenues and resulting tariffs, are subject to regulation by NERSA. In addition, much of the Group’s strategy and many of its future prospects will ultimately have to be aligned with the Department of Energy’s IRP, which sets out a long-term electricity plan for South Africa, and the Department of Energy’s IEP, which is broadly designed to guide future South African energy infrastructure investment and policy for the 2010 to 2050 period. The IEP was published in June 2013 for public consultation, and a final report is expected to be published in March 2015. The IRP, which was promulgated in 2011 and covered the 2010 to 2030 period, is currently in the process of being

revised to reflect the continuing evolution of the Government’s long-term electricity strategy. It remains unclear when the updated IRP will be finalised and approved by the Cabinet. While a draft updated version of the IRP was published in November 2013 for public comment, it is expected that the final revised IRP will only be formally approved after the Government has approved the over-arching IEP, which is expected to inform the contents of the revised IRP. The draft IRP update is not an official update to the promulgated IRP, but the update has, however, revised scenarios based on changes to South Africa’s economic outlook, including addressing the effect of slowing economic growth on projected electricity demand (anticipating that less capacity will be required by 2030). However, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. Regardless, the IRP is expected to have a significant impact on the Group’s operations. The Group holds separate licences for its generation, transmission and electricity distribution activities, with revenues being regulated for each of these licensed activities. The Group allocates its revenues internally across these segments, using a cost-of-service-based methodology with incentives for cost savings and efficient and prudent procurement by the Issuer. This methodology also provides for SQIs which are used as a measure to encourage the Group to improve its reliability of supply. The objective of SQIs is to ensure that the provision of good quality supply is rewarded and poor quality of supply is penalised. Each segment’s revenue is calculated separately with the overall price and revenue determined at the distribution level and communicated as such to customers. See “Overview of South Africa and the South African Electricity Industry—Regulation of the South African Electricity Industry” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Factors Affecting Results of Operations—Pricing”. Reportable Segment Information Management has determined the reportable segments in accordance with IFRS 8 in its Consolidated Financial Statements, as described below, based on the reports regularly provided, reviewed and used by EXCO to make strategic decisions and assess performance of the segments. EXCO assesses the performance of the operating segments based on a measure of profit or loss consistent with that of the financial statements. The amounts provided by EXCO with respect to total assets and liabilities are measures in terms of IFRS. These assets and liabilities are allocated based on the operation of the segment and the physical location of the assets. Further information on the Group’s segment reporting is set out in Note 5 and Note 10 of the Audited Annual Financial Statements and the Reviewed Interim Financial Statements, respectively. The following summary describes the operations in each of the Group’s reportable segments: Generation Consists of the generation and primary energy functions. These functions procure primary energy and generate electricity for sale. Transmission Consists of the transmission grids, systems operations and the South African Energy (international buyer). These functions operate and maintain the transmission network for transmitting electricity and also sell bulk electricity to international customers. Distribution This segment provides, operates and maintains the distribution network for distributing. Consists of nine provincial operating units. Group Customer Services Consists of the customer service and integrated demand-management functions and sells electricity to local large key redistributors, large and small customers. Group Capital Responsible for the planning, development and monitoring of all capital projects and the execution of capacity expansion projects. All other segments Relates to operating segments which are below the quantitative thresholds for determining a reportable segment in terms of IFRS 8 and include the Group’s subsidiaries. Corporate and other Relates to all service and strategic functions which do not qualify as a reportable segment in terms of IFRS 8.

Factors Affecting Results of Operations The following are key factors affecting the Group’s results of operations and statements of financial position for recent periods. Pricing NERSA determines the pricing of electricity in South Africa. The Group periodically applies to NERSA for the revenue it requires to sustainably operate its business. The application for revenue is in the form of an MYPD. Currently, the third pricing application, MYPD 3, is in effect for a five-year period until the end of 31 March 2018. NERSA follows a “cost-of-service” approach to pricing, with annual revenues and tariff levels based on the Group’s four main cost elements: fuel cost (primary energy); non-fuel operating and maintenance cost; depreciation; and return on assets (cost of capital). In 2005, NERSA introduced the MYPD, which is a multi-year incentive-based, cost-of-service, revenue determination methodology, where prices are set and cover a pre-determined year period, allowing both the Group and its customers to plan costs and revenues. Through the MYPD, NERSA predetermines revenue limits based on its assumptions regarding a fair rate-of- return and prudent operating cost (with reference to the Group’s four main cost elements). The first MYPD period, MYPD 1, applied from 1 April 2006 to 31 March 2009. In 2008, the Government approved the EPP which, among other things, changed the method for determining the depreciation of and return on assets from an historic costs-basis to a replacement value-basis (focusing on the replacement values of existing assets). In a high inflation environment such as South Africa, the replacement value approach provides for more stable and flatter tariff profiles over the life cycle of an asset compared to the historic cost approach, which results in very high initial tariffs that steeply decline over the life of an asset, and is then followed by a sharp adjustment upon replacement of the asset. In addition, the EPP sets out a plan to ensure that electricity tariffs reach “cost-reflective” levels within five years, commencing in 2009. “Cost-reflectivity” under the EPP envisages the passing through of all costs of providing electricity on the replacement value-basis and, unlike MYPD 1, includes the costs of capital expenditure as set out in the Group’s committed capacity expansion programme. This target, however, has not been achieved. If fully implemented, the revenue methodology as defined by the EPP is expected to result in adequate, yet stable and predictable future tariffs with gradual movements. While the current economic-regulatory framework provides for the full recovery of costs, including a reasonable margin or return on assets, the determination and revision of tariffs is politically sensitive and the Group has since 2006 been unable to achieve the tariff increases it requested. For the financial year ended 31 March 2010 (following the conclusion of MYPD 1), the Group was awarded a one-year 31.3% price increase, instead of the 34% increase it had applied for. For the three year period thereafter (from 1 April 2010 until 31 March 2013), under the second MYPD (“MYPD 2”), the Group was awarded average annual increases of 24.8%, 25.8% and 25.9%, respectively, instead of the average 35% annual increase it had applied for over this three-year period. In setting the levels of yearly tariff increases under MYPD 2 at lower levels than applied for by the Group, NERSA determined that achieving cost-reflectivity by 2012-2013 would result in tariff increases that were too large for users in South Africa, and indicated at the time that its intention was to achieve cost-reflectivity for electricity tariffs in five years (by 2014-2015). However, following the Group’s MYPD 3 application for a 16% average annual increase over the five-year period from 1 April 2013 until 31 March 2018, NERSA granted an annual average increase of only 8% for the MYPD 3 period, which was initially estimated to result in a revenue shortfall for the Group of R225 billion over the five-year MYPD 3 period. However, the Group has since revised upwards its estimated revenue shortfall for the MYPD 3 period in light of the latest projections, which anticipate a decline in electricity sales volumes stemming primarily from lower growth in demand, which has been hindered by low GDP growth and high tariffs. In response to the Group’s RCA application regarding under-recoveries for the MYPD 2 period, NERSA announced in October 2014 its decision to revise the average annual tariff increase for the 2015/16 financial year upward from 8% to 12.7%, allowing the Group to recoup R7.8 billion in under-recoveries. The tariff will revert to 8% for the remaining years of the MYPD 3 period unless NERSA agrees to additional tariff adjustments pursuant to further Group RCA applications. Accordingly, the Group expects that revenues will continue to remain below its cost of delivery. See “Overview of South Africa and the South African Electricity Industry—Electricity Tariffs—Multi-Year Price Determination Methodology” for a discussion of the historical and current pricing and tariff methodology applied to the Group’s tariffs.

Capacity Expansion Programme The Group is committed to incurring significant expenditure related to its capacity expansion programme, on which the Group spent approximately R251 billion (excluding capitalised borrowing costs) between its inception in 2005 and 30 September 2014. The Group estimates that the total cost of the programme from 2005 until its completion, expected in the 2020/21 financial year, will be approximately R348 billion (excluding capitalised borrowing costs). See “—Capital Expenditure” and “Business—Finance—Capacity Expansion Programme”. The committed capacity expansion programme is intended to address historical underinvestment in generation, transmission and distribution capacity that led, among other things, to load- shedding in 2008 and again beginning in 2014 and to support the growth of the South African economy. In 2005, the Group started the capacity expansion programme to increase its generation, transmission and distribution capacity. Eskom’s nominal capacity was only 36.2 GW in 2005. The Group has committed to the current capacity expansion programme to invest in the South African electricity sector, expecting to increase nominal generating capacity by 17.4 GW (200 MW of which will be from renewable energy sources), by the 2020/21 financial year. Additionally, a total of 9,756 km of transmission lines, delivering an additional 42,470 MVA of transmission capacity are expected to be laid by the 2020/21 financial year. Between the inception of the capacity expansion programme in 2005 and 30 September 2014 the Group commissioned an additional 6,137 MW of new capacity. This consisted of two new (Greenfield) gas turbine plants (Ankerlig and Gourikwa), and the recommissioning of three mothballed plants (Camden, Grootvlei and Komati, all of which have been completed to date) and the upgrade of existing coal-fired plants. In addition, 5,659 km of transmission lines, representing 27,655 MVA of transmission capacity, has been commissioned. The Board periodically reviews the Group’s corporate plan. Following the outcome of the MYPD 3 determination, which allowed an annual tariff increase of only 8% over the five year period up to 31 March 2018, significant capital reprioritisation was performed to address the Group’s critical business needs and the R225 billion revenue shortfall identified as a result of the lower-than-expected tariff increases for the MYPD 3 period (which shortfall has since been revised upwards to primarily reflect a projected decline in electricity sales volumes stemming from lower growth in demand). In order to support the financial sustainability of the Group, the Government announced in October 2014, the Government Finance Support Package which, among other things, approved a R20 billion Government equity injection, expected to be made during the 2015/16 financial year and financed through the Government’s liquidation of certain non-strategic assets. However, the Group’s capacity expansion programme nevertheless remains under discussion to assess the impact of the anticipated revenue shortfall for the MYPD 3 period and to determine and discuss alternative capacity and generation options with its shareholder. The biggest revenue constraints are expected in relation to the last three years of MYPD 3. The Group expects the Minister of Energy’s determination on these issues to take into consideration the objectives of the IEP (expected to be approved in March 2015) as well as the IRP (a revised version of which is expected to be approved following the IEP’s approval). The draft of the revised IRP, which was published in 2013, addresses the effect of slowing economic growth on projected electricity demand (anticipating that less capacity will be required by 2030). However, given the final IEP will likely inform the contents of the final revised IRP, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. The version of the IRP, which sets out an electricity plan for South Africa for the 2010 to 2030 period, emphasises, for example, the diversification of South Africa’s (and by extension, the Group’s) methods of electricity generation to meet the Government’s policy to reduce the impact of the industry on the environment. This assumes a migration from coal-fired power stations, on which the Group is highly dependent, to “renewable energy sources”. See “Risk Factors—Risks relating to the Group—The Group’s activities are subject to government policy and there is uncertainty with respect to how the Government may elect to implement such regulations and fund resulting initiatives in the future and the impact they will have on the Group”.

Based on the MYPD 3 determination, the Group’s generation capacity plan from the financial year ended 31 March 2014 to the financial year ending 31 March 2021, with respect to capacity installed and “first power to the grid”, is set out in the table below.

Cumulative Project (MW) 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 total Medupi (coal-fired) ...... — 794 — 1,588 1,588 794 — 4,764 Kusile (coal-fired) ...... — — 800 800 800 1,600 800 4,800 Ingula (pumped-storage) ...... — 666 666 — — — — 1,332 Sere wind farm (renewable) ...... 100 — — — — — — 100 Concentrating solar plant (renewable) ...... — — — — 100 — — 100 Total (MW) ...... 100 1,460 1,466 2,388 2,488 2,394 800 11,096

Eskom has commenced the development of a 100 MW concentrating solar power plant in Upington, which is expected to be commissioned in 2019. This solar plant will save an estimated 480 tonnes of carbon dioxide emissions on an annual basis and the potential to electrify in excess of 200,000 homes. The key generation expansion projects are the 4,764 MW Medupi and 4,800 MW Kusile coal-fired stations, and the Ingula pumped-storage scheme in the Drakensberg, which (once fully commissioned) is expected to deliver 1,332 MW of hydroelectricity during peak demand periods. Additionally, transmission line length and substation capacity will also increase substantially. The implementation of the committed capacity expansion programme continues to require Government support. The support that the Group has received from the Government to date and that it expects to receive in the future is described under the heading “—Capital Expenditure—Sources of Liquidity—Government Support”. The total amount of Government support that the Group expects to receive through guarantees, proposed equity and loans is R350 billion (inclusive of guarantees already utilised). As at 30 September 2014, a total amount of R154 billion of guarantees have already been utilised. See also “Risk Factors—Risks relating to the Group—The Group’s ability to implement its committed capacity expansion programme and expand and improve its business operations could be materially adversely affected if it is unable to raise sufficient capital on favourable terms, or at all, or if Government support of such capital raising is withdrawn”. Embedded Derivatives In the early 1990s, when the Group still benefited from excess generation capacity, it entered into a number of customised pricing agreements with its major industrial customers, mainly to supply low-priced electricity to energy-intensive industries and to further the Government’s growth and job creation objectives for the South African Development Community (“SADC”) region. The price of electricity under these contracts was determined by reference to the underlying international market price of the commodity being produced by the customer (primarily aluminium) and was also dependent on foreign currency exchange rates to the Rand (mainly U.S. dollars) and foreign commodity production price indices. The expectation was that, over the duration of these contracts, the price cycles of the underlying commodities would balance out and, on average, would provide electricity tariffs approximately equal to the standard tariffs prevailing over that period. Though approved by the Group and the Government at the time, the pricing agreements represented and continue to represent poor value for the Group due to the increasing cost of generation. Due to the underlying commodity-linked and foreign exchange rate pricing elements and the application of IFRS principles relating to the fair valuation of financial instruments, the contracts are deemed to contain embedded derivatives. The change in net fair value of embedded derivatives for the Group from period-to- period fluctuates due to changes in assumptions regarding future commodity prices, interest rates, exchange rates of the Rand to U.S. dollars, the rate of inflation in South Africa, the U.S. Producer Price Index and in assumptions regarding the future levels of standard tariffs. The standard tariffs that were used to value the embedded derivatives as at 30 September 2014 were the forward curves based on a price increase of 8% as per

MYPD 3. The Group determines the fair value of commodity-linked, embedded derivative contracts under IFRS, taking into account aluminium prices, exchange rates, interest rates, production price indices and electricity tariffs. Additional risk adjustments (due to the uncertainty inherent in future cash flow from embedded derivatives), such as liquidity, model risk and other economic factors, are also factored into the determination of the fair value. Currently, two special pricing contracts that give rise to embedded derivatives, both of which relate to aluminium smelters owned by one of the Group’s customers in KwaZulu-Natal, remain in place. In October 2012, the Group submitted an application to NERSA to review the final outstanding contracts to make them cost-reflective and to remove the commodity-linked pricing element, which will in turn remove the embedded derivatives. However, it is not certain when NERSA will make any determination in this regard and whether such determination will be in favour of the Group. As at 30 September 2014, total embedded derivative liabilities amounted to R7,711 million compared to R9,332 million as at 31 March 2014. The net impact on the income statement of changes in the fair value of the embedded derivatives for the six months ended 30 September 2014 is a fair value gain of R1,621 million compared to a R1,868 million for the six months ended 30 September 2013. Although the impact of these embedded derivatives on the Group’s balance sheet is significant, it is mainly an IFRS accounting requirement and does not affect cash flows. For the purposes of determining cash flows, the revenue expected to be received under these contracts are taken into account and not the derivative value thereof. The cash flows for the Group for the six months ended 30 September 2014 and 2013 and the financial years ended 31 March 2012, 2013 and 2014 were therefore not affected by the outstanding contracts. A sensitivity analysis (in respect of the embedded derivatives) appears in Note 4.2 and Note 20.2 of the Audited Annual Financial Statements and the Reviewed Interim Financial Statements, respectively, which are incorporated by reference in this Base Prospectus. The Group has put risk management processes and controls in place to mitigate losses on embedded derivatives. Since obtaining approval from the SARB in 1998, the Group has undertaken hedging activity to mitigate potential losses on the contracts. See “—Market-Related Risks—Hedging Policy”, “Risk Factors— Risks relating to the Group—The Group is exposed to fluctuations in commodity prices and certain indices through certain of its electricity supply agreements” and “Risk Factors—Risks relating to the Group— Depreciation of the Rand or changes to exchange control policy could affect the Group’s ability to make payments in relation to U.S. dollar-denominated Notes and other indebtedness” and see Note 4.2 and Note 20.2 of the Audited Annual Financial Statements and the Reviewed Interim Financial Statements, respectively, which are incorporated by reference in this Base Prospectus. Seasonality The sale of the Group’s electricity and its operation and maintenance activities are subject to seasonal variations. Demand for electricity is usually higher in the first and second quarters of the financial year (April through September), when cooler temperatures cause an increase in electricity consumption and, in addition, large power users pay a winter tariff, which can be up to 50% higher than the tariff paid for the remainder of the year, resulting in higher revenue during the winter months. Demand from large industrial users, on which a substantial amount of the Group’s revenues are dependent, is affected by plant shutdowns during the summer holiday periods. Maintenance costs are also lower in winter as most major maintenance for the Group’s power stations is scheduled for the summer months when demand is lower, resulting in increased operating expenses and lower revenues during summer. In the future, the Group intends to schedule more maintenance during the winter than what it has done previously, in order to reduce backlogs. Description of Principal Income Statement Items and Other Financial Measures Revenue The Group’s revenue is derived principally from the generation, transmission, distribution and sale of electricity. Since 2009, the Government has imposed an environmental levy, payable by the Group to the SARS, on the gross production of electricity produced from non-renewable sources (coal, nuclear and petroleum) and raised on the total electricity produced. The environmental levy, which is paid by the Group

on a pass-through basis, is included in the cost of electricity charged to customers and, as such, recovered from consumers in full. The Group accounts for amounts attributable to the environmental levy charged to customers as revenue of the Transmission and Distribution segments and for the amount of the environmental levy paid to the SARS as a primary energy operating cost (see “—Operating Expenses”). From an internal accounting perspective, beginning in the 2013/14 financial year, the Group’s consumer tariff structure no longer distinguishes between revenue attributable to the environmental levy and other revenue and instead includes the environmental levy charge within the underlying base tariff structure. On 1 July 2012, the environmental levy was raised from 2.5c/kWh to 3.5c/kWh, at which rate it currently remains. The environmental levy paid to the SARS for the financial year ended 31 March 2014 was R8.5 billion, compared to R8.0 billion for the financial year ender 31 March 2013. Nearly all of the Group’s revenue (e.g., 98% during the financial year ended 31 March 2014) is generated from the sale of electricity, while the balance relates to connection fees and customer contributions to capital projects (referred to as “non-electricity” revenue). External electricity revenues that derive from the Group’s domestic sales are initially attributed to the Group Customer Services segment before being allocated to the other segments for the purposes of IFRS segment reporting and in order to comply with regulatory segment reporting requirements. External electricity revenues that derive from the Group’s international customers are attributed, in the first instance, to the Transmission segment, while non-electricity revenues related to connection fees are attributed, in the first instance, to the Distribution and Transmission segments. The Issuer records non-electricity revenues generated by its subsidiaries under “other segment revenues”. Inter-segment purchases of electricity and inter-segment revenue from inter-segment electricity sales are allocated between the Generation, Transmission, Distribution and Group Customer Services segments based on cost recovery principles. A final inter-segment entry is processed at interim and year-end timeframes to adjust segment revenues in order to reflect a uniform return on assets. Operating Expenses The Group’s operating expenses consist principally of:

• Primary energy expense. Primary energy expense relates to the acquisition of coal, nuclear fuel (uranium), water and liquid fuels (gas and diesel) that are used in the generation of electricity and also includes the environmental levy (as well as purchases from IPPs and imported power). The environmental levy, which is passed on fully to consumers as part of the tariffs charged by the Group, is accounted for as an operating cost of the Generation segment within primary energy.

• Net employee benefit expense. Net employee benefit expense consists of salaries and other staff costs, incentives, pension benefits, post-retirement medical aid benefits, gratuities and direct training and development.

• Depreciation and amortisation expense. Depreciation and amortisation expense consists of depreciation of property, plant and equipment and amortisation of intangible assets and deferred income recognised (such as Government grants for electrification).

• Net impairment reversal/(loss). Net impairment reversal/(loss) consists primarily of reversals of, or losses recognised due to, impairment of property, plant and equipment, investment in associates, write-down of inventory and trade and other receivables.

• Other operating expenses. Other operating expenses consist of managerial, technical and other fees, research and development, operating lease expense, auditors’ remuneration, repairs and maintenance, transport and other expenses. Net finance income/(cost) Net finance income/(cost) consists of finance income and finance cost. Finance income comprises interest receivable on loans, advances, trade receivables and income from financial market investments. Interest is only recognised where it is probable that the economic benefits associated with the transaction will flow to the Group. Finance income is recognised on a time-proportionate basis that takes into account the effective yield on assets. Finance income on impaired loans is recognised using the original effective interest rate.

Finance cost comprises interest payable on borrowings calculated using the effective interest method as well as interest resulting from the unwinding of discounts on provisions before the impact of the re-measurement of the R60 billion subordinated Government loan at fair value (resulting in income of R17.3 billion during the financial year ended 31 March 2013). Such re-measurement of the Government loan is based on the new MYPD 3 determination allowing an 8% tariff increase. Borrowing costs attributable to the construction of qualifying assets are capitalised over the period of the construction to the extent that the assets are financed by borrowings. Net fair value loss/gain on derivatives Net fair value gain/(loss) on derivatives represents the movements in the fair value of derivatives from one reporting date to another, where the fair value is the valuation of the derivative in accordance with standard methodology, that is reasonable to all parties in a transaction in light of the pre-existing conditions and circumstances. Interim comparison of the six months ended 30 September 2014 and 30 September 2013

For the six months ended 30 September (1) 2014 2013 (millions of Rand) INCOME STATEMENT` Revenue ...... 81,898 77,722 Primary energy ...... (38,065) (31,266) Net employee benefit expense...... (13,176) (12,951) Depreciation and amortisation expense ...... (6,672) (5,912) Net impairment loss...... (855) (682) Other operating expenses ...... (7,841) (9,077) Other income ...... 452 183 Net fair value loss on financial instruments, excluding embedded derivatives ...... (860) (998) Net fair value gain on embedded derivatives ...... 1,621 1,868 Operating profit before net finance cost ...... 16,502 18,887 Net finance cost ...... (3,539) (1,853) Share of profit of equity-accounted investees, net of tax ...... 33 26 Profit before tax ...... 12,996 17,060 Income tax ...... (3,675) (4,846) Profit from continuing operations ...... 9,321 12,214 DISCONTINUED OPERATIONS Profit/(loss) from discontinued operations ...... (34) 27 Profit for the period ...... 9,287 12,241 Attributable to:...... Owner of the company ...... 9,287 12,241 Non-controlling interest(2) ...... — — 9,287 12,241 ______(1) The Group’s income statement and statements of cash flows for the six months ended 30 September 2013 as set out in the Group’s Reviewed Interim Financial Statements for the six months ended 30 September 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 21 of the Reviewed Interim Financial Statements (with respect to the six months ended 30 September 2013). (2) Nominal amount.

Revenue Revenue for the Group for the six months ended 30 September 2014 and 2013 was R81,898 million and R77,722 million, respectively. The increase of R4,176 million, or 5.4%, was principally due to the 8% tariff increase under MYPD 3 in the six months ended 30 September 2013 and 2014 (which resulted in a 7.3% average increase in electricity revenue per kilowatt-hour), which was offset by a slight decrease in sales volumes. The volume of electricity sales for the six months ended 30 September 2014 totalled 109,168 GWh, representing a decrease of 1.3% compared to 110,659 GWh for the six months ended 30 September 2013. The overall revenue increase was lower than budgeted for due to lower electricity sales volumes. The lower volumes were mainly due to lower electricity demand from the Group’s gold and platinum-producing customers, who decreased production as a result of labour unrest and lower commodity prices. Revenue recorded for the six months ended 30 September 2014 and 2013 includes amounts recovered from customers corresponding to the environmental levy paid by the Group to the SARS and accounted for as a primary operating cost. From an internal accounting perspective, beginning in the 2013/14 financial year, the Group’s

consumer tariff structure no longer distinguishes between revenue attributable to the environmental levy and other revenue and instead includes the environmental levy charge within the underlying base tariff structure. See “—Operating expenses”. Revenue for the Generation segment for the six months ended 30 September 2014 and 2013 was R55,372 million and R51,296 million, respectively; revenue for the Transmission segment for the six months ended 30 September 2014 and 2013 was R9,657 million and R8,205 million, respectively, and revenue for the Distribution segment for the six months ended 30 September 2014 and 2013 was R13,108 million and R13,491 million, respectively. Revenue for the Group Customer Services segment for the six months ended 30 September 2014 and 2013 was R3,181 million and R4,078 million, respectively, while revenue for all other segments for the six months ended 30 September 2014 and 2013 was R5,318 million and R4,931 million, respectively. Variability in segment reported revenues between the periods is due to changes in the profit equalisation entry processed at the end of each period, which adjusts segment revenue in order to reflect a uniform return on assets. Net fair value gain on embedded derivatives The net fair value gain on embedded derivatives for the six months ended 30 September 2014 decreased to R1,621 million from a net fair value gain of R1,868 million for the six months ended 30 September 2013. This decrease of R247 million was principally due to the termination of the Bayside aluminium smelter contract with BHP Billiton. Net fair value losses on other derivatives for the six months ended 30 September 2014 decreased to R860 million from R998 million for the six months ended 30 September 2013. The decrease was due primarily to exchange and interest rate movements as well as credit and debit value adjustments. Operating expenses Operating expenses for the Group for the six months ended 30 September 2014 and 2013 were R66,609 million and R59,888 million, respectively. This increase of R6,721 million, or 11.2%, resulted from the following components. Primary energy costs for the six months ended 30 September 2014 increased to R38,065 million from R31,266 million for the six months ended 30 September 2013. This R6,799 million, or 21.7%, increase was primarily due to an increase in coal, water and liquid fuel spent, the R2.5 million Medupi coal contract penalty and an increased use of costly diesel-fuelled OCGTs due to the Group’s low operating reserve margin. Additional power was purchased from IPPs, further increasing primary energy costs. For the six months ended 30 September 2014 and 2013, the environmental levy, which is accounted for as a primary energy cost and passed on fully to consumers as part of the tariffs charged by the Group, was R4.3 billion and R4.4 billion, respectively. The cost of primary energy as a percentage of revenue for the six-month periods ended 30 September 2014 and 2013 was 46.5% and 40.2%, respectively. Net employee benefit expense for the six months ended 30 September 2014 increased to R13,176 million from R12,951 million for the six months ended 30 September 2013. This increase of R225 million, or 1.7%, was due to the annual increase in employee salary packages and an increase in overtime in the Generation segment driven by maintenance undertaken during weekends, as well as a general increase in the focus on maintenance. Depreciation and amortisation expense for the six months ended 30 September 2014 and 2013 was R6,672 million and R5,912 million, respectively. This increase of R760 million, or 12.9%, was principally due to normal business operations with capital projects reaching the end of the execution phase and being transferred to commercial operation across all segments. Acquisition and replacement of fleet, IT and other production equipment assets through procurement transactions also gave rise to additional depreciation. Net impairment loss for the six months ended 30 September 2014 and 2013 was R855 million and R682 million, respectively. This increased loss of R173 million, or 25.4%, was principally due to an increase in municipality debt levels between periods due to persistent arrears in several regions. Other operating expenses for the Group for the six months ended 30 September 2014 decreased to R7,841 million from R9,077 million for the six months ended 30 September 2013. These expenses primarily consist

of repairs and maintenance costs, which were R3,340 million and R2,505 million for the six months ended 30 September 2014 and 2013, respectively, offset by adjustments relating to intra Group transactions. Net finance cost Net finance cost after capitalisation of borrowing costs (and including the unwinding of interest provisions) for the six months ended 30 September 2014 increased to R3,539 million from R1,853 million for the six months ended 30 September 2013. Finance income increased to R1,157 million for the six months ended 30 September 2014 from R1,124 million for the six months ended 30 September 2013. This increase of R33 million, or 2.9%, was principally due to income received from investments in government securities. Finance cost increased to R4,696 million for the six months ended 30 September 2014 from R2,977 million for the six months ended 30 September 2013. This increase of R1,719 million, or 57.7%, was mainly due to higher interest costs attributable to the increase in the Group’s borrowings over the period. Share of profit of equity – accounted investees Share of profit of equity – accounted investees for the six months ended 30 September 2014 and 2013 was R33 million and R26 million, respectively. This relates primarily to the Group’s share of its associates’ and joint ventures’ post-acquisition profits or losses. The slight increase of R7 million, or 26.9%, represents profits from Mozambique Transmission Company SARL (“Motraco”). Income tax Income tax expense for the six months ended 30 September 2014 was R3,675 million compared to R4,846 million for the six months ended 30 September 2013. This decrease of R1,171 million, or 24.2%, was principally due to a decrease in profit before tax. The effective tax rate for the six months ended 30 September 2014 and 2013 was 28.3% and 28.4%, respectively. Profit from continuing operations Profit from continuing operations for the six months ended 30 September 2014 was R9,321 million, compared to R12,214 million for the six months ended 30 September 2013. This decrease of R2,893 million, or 23.7%, was principally due to the increase in primary energy and finance costs during the period, which more than offset the increased revenue for the period. Profit/(loss) from discontinued operations The loss from discontinued operations for the six months ended 30 September 2014 was R34 million, compared to profit from discontinued operations of R27 million for the six months ended 30 September 2013. This variation was principally due to the winding up of Energie Manantali, a subsidiary of Eskom Enterprises SOC Ltd (Eskom Enterprises”). Profit for the period Profit for the six months ended 30 September 2014 was R9,287 million, compared to R12,241 million for the six months ended 30 September 2013. This decrease of R2,954 million, or 24.1%, was principally due to the increase in operating costs (primary energy and finance costs in particular) which outweighed the increase in revenue for the period. Comparison of the financial years ended 31 March 2014 and 31 March 2013 The table below sets out the Group’s results of operations for the periods indicated.

For the financial year ended 31 March 2014 2013(1) (millions of Rand) INCOME STATEMENT Revenue ...... 139,506 128,775 Primary energy ...... (69,812) (60,748) Net employee benefit expense...... (25,622) (23,564) Depreciation and amortisation expense ...... (11,937) (9,960) Net impairment loss...... (1,557) (1,039) Other operating expenses ...... (19,177) (23,039) Other income ...... 962 1,126 Net fair value loss on financial instruments, excluding embedded derivatives ...... (620) (1,655) Net fair value (loss)/gain on embedded derivatives ...... 2,149 (5,942) Operating profit before net finance income/(cost) ...... 13,892 3,954 Net finance (cost)/income ...... (4,772) 3,003 Share of profit of equity-accounted investees, net of tax ...... 43 35 Profit before tax ...... 9,163 6,992 Income tax ...... (2,137) (1,856) Profit from continuing operations ...... 7,026 5,136 DISCONTINUED OPERATIONS Profit from discontinued operations ...... 63 47 Profit for the period ...... 7,089 5,183 Attributable to:...... Owner of the company ...... 7,089 5,183 Non-controlling interest(2) ...... — — 7,089 5,183 ______(1) The Group’s income statement and statement of cash flows for the financial year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the financial year ended 31 March 2014, and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Group’s Audited Annual Financial Statements (with respect to the financial year ended 31 March 2014). (2) Nominal amount.

Revenue Revenue for the Group for the financial years ended 31 March 2014 and 2013 was R139,506 million and R128,775 million, respectively. The increase of R10,731 million, or 8.3%, was principally due to the 8% tariff increase under MYPD 3 in the financial year ended 31 March 2014 (which resulted in a 7.4% average increase in electricity revenue per kWh) combined with a slight increase in electricity sales volumes. The volume of electricity sales for the financial year ended 31 March 2014 totalled 217,903 GWh, representing an increase of 0.6% compared to 216,561 GWh for the financial year ended 31 March 2013. The overall revenue increase was higher than budgeted for due to higher sales volumes. The higher volumes were mainly due to a 5.6% increase in local sales to industrial customers during the financial year ended 31 March 2014, which was the result of increased operations by certain key customers as well as less power buybacks during financial year ended 31 March 2014 compared to the financial year ended 31 March 2013. This increase was offset by a decline of 3.0% in the mining sector and a 9.6% decrease in international sales. Revenue recorded for the financial years ended 31 March 2014 and 2013 includes amounts recovered from customers corresponding to the environmental levy paid by the Group to the SARS and accounted for as a primary operating cost. From an internal accounting perspective, beginning in the 2013/14 financial year, the Group’s consumer tariff structure no longer distinguishes between revenue attributable to the environmental levy and other revenue and instead includes the environmental levy charge within the underlying base tariff structure. See “— Operating expenses”. Revenue for the Generation segment for the financial years ended 31 March 2014 and 2013 was R97,303 million and R86,395 million, respectively, revenue for the Transmission segment for the financial years ended 31 March 2014 and 2013 was R13,378 million and R10,738 million, respectively, and revenue for the Distribution segment for the financial years ended 31 March 2014 and 2013 was R21,440 million and R19,273 million, respectively. Revenue for the Group Customer Services segment for the financial years ended 31 March 2014 and 2013 was R6,191 million and R10,918 million, respectively, and revenue for all other segments for the financial years ended 31 March 2014 was R10,420 million and R9,522 million, respectively. Changes in segment reported revenues between the periods resulted from the adjustments made to the transfer pricing rate used to internally recover the cost of generating electricity between the periods.

Net fair value gain (loss) on embedded derivatives The net fair value gain (loss) on embedded derivatives for the financial year ended 31 March 2014 increased to a net fair value gain of R2,149 million from a net fair value loss of R5,942 million for the financial year ended 31 March 2013. This variation was principally due to the decrease in the aluminium price curve, the weakening of the U.S. dollar/ZAR exchange rate and the increase in U.S. dollar and ZAR interest rates. Net fair value losses on other derivatives for the financial year ended 31 March 2014 decreased to R620 million from R1,655 million for the financial year ended 31 March 2013. The decrease was due primarily to the depreciation of the Rand offset by the costs attributable to the rolling over of forward cover exchange contracts, which vary from period-to-period due to the timing of the placement of the related procurement contracts. The Group’s policy is to hedge all foreign exchange exposures above R150,000. Operating expenses Operating expenses for the Group for the financial year ended 31 March 2014 and 2013 were R128,105 million and R118,350 million, respectively. This increase of R9,755 million, or 8.2%, resulted from the following components. Primary energy costs for the financial year ended 31 March 2014 increased to R69,812 million from R60,748 million for the financial year ended 31 March 2013. This R9,064 million, or 14.9%, increase was primarily due to an increase in coal usage costs and an increase in the cost of using the OCGTs, which were partially offset by a decrease in demand-market participation, power buybacks and co-generation costs. Other expenditure that contributed to the cost increase included increased costs associated with coal handling (which encompasses the storage of coal across the various stages of the preparation process), fuel for gas-fired start- ups, water usage, environmental levies and international purchases. For the financial years ended 31 March 2014 and 2013, the environmental levy, which is accounted for as a primary energy cost and passed on fully to consumers as part of the tariffs charged by the Group, was R8.5 billion and R8.0 billion, respectively. The cost of primary energy as a percentage of revenue for the financial year ended 31 March 2014 and 2013 was 50.0% and 47.2%, respectively. Net employee benefit expense for the financial year ended 31 March 2014 increased to R25,622 million from R23,564 million for the financial year ended 31 March 2013. This increase of R2,058 million, or 8.7%, was principally due to an increase in contract labour cost relating to the capacity expansion programme and incremental salary increases, the effects of which were partially offset by a reduction in employees to 46,919 as at 31 March 2014 from 47,295 as at 31 March 2013. The gross employee costs (before capitalisation of expenses) for the Group for the financial years ended 31 March 2014 and 2013 were R31,324 million and R28,626 million, respectively. Depreciation and amortisation expense for the financial year ended 31 March 2014 and 2013 was R11,937 million and R9,960 million, respectively. This increase of R1,977 million, or 19.8%, was principally due to the increase in property, plant and equipment and intangible assets of R60,118 million. Net impairment loss for the financial year ended 31 March 2014 and 2013 was R1,557 million and R1,039 million, respectively. This increased loss of R518 million, or 49.9%, was principally due to an increase in municipal debt. Other operating expenses for the Group for the financial year ended 31 March 2014 decreased to R19,177 million from R23,039 million for the financial year ended 31 March 2013, a 16.8% reduction year- on-year. These expenses primarily consist of repairs and maintenance costs which were R8,196 million and R14,152 million for the financial year ended 31 March 2014 and 2013 respectively, offset by adjustments relating to intra–Group transactions. Besides normal inflationary pressures, the increase in maintenance is predominantly in the Generation segment as a result of additional planned maintenance (as part of the generation sustainability project) and unplanned maintenance in the ageing fleet as well as the implementation of maintenance strategies in the Distribution segment to comply with legal and regulatory requirements. The higher maintenance costs were subsidised from other areas of the business to minimize the financial impact.

Net finance income/(cost) Net finance income after capitalisation of borrowing costs (and including the unwinding of interest provisions) for the financial year ended 31 March 2014 decreased to a net finance cost of R4,772 million from a net finance income of R3,003 million for the financial year ended 31 March 2013. Finance income decreased to R2,475 million for the financial year ended 31 March 2014 from R2,796 million for the financial year ended 31 March 2013. This decrease of R321 million, or 11.5%, was principally due to lower investments in fixed deposits and government and short-term securities, which was compounded by lower short-term interest rates and fixed deposits made in the United States which experienced extended periods of lower interest rate returns. Finance costs after capitalisation of borrowing costs resulted in a cost of R7,247 million for the financial year ended 31 March 2014 compared to an income of R207 million for the financial year ended 31 March 2013. This variation was mainly due to the re-measurement of the R60 billion subordinated Government loan at fair value (following the 8% tariff increase under the recent MYPD 3 determination), which resulted in a gain of R17,295 million for the financial year ended 31 March 2013. There was no re-measurement of the subordinated loan from the shareholder in 2014 as there was no change in estimated future cash flows. Share of profit of equity–accounted investees Share of profit of equity–accounted investees for the financial years ended 31 March 2014 and 2013 was R43 million and R35 million, respectively. This relates primarily to the Group’s share of its associates’ and joint ventures’ post acquisition profits or losses. The increase of R8 million, or 22.9%, was principally due to profits from Motraco. Income tax Income tax expense for the financial year ended 31 March 2014 was R2,137 million compared to R1,856 million for the financial year ended 31 March 2013. This increase of R281 million, or 15.1% was principally due to an increase in net profit before tax. The effective tax rate for the financial years ended 31 March 2014 and 2013 was 23.3% and 26.5%, respectively. The decrease in the effective tax rate was principally due to additional non-taxable income arising from the research and development projects undertaken during the year. Profit from continuing operations Profit from continuing operations for the financial year ended 31 March 2014 was R7,026 million, compared to R5,136 million for the financial year ended 31 March 2013. This increase of R1,890 million, or 36.8%, was principally due to an increase in revenue and lower operating costs. Profit from discontinued operations Profit from discontinued operations for the financial year ended 31 March 2014 was R63 million, compared to R47 million for the financial year ended 31 March 2013. This increase of R16 million, or 34.0%, was principally due to EEM, a subsidiary of Eskom Enterprises, being reclassified as a discontinued operation. Profit for the year Profit for the financial year ended 31 March 2014 was R7,089 million, compared to R5,183 million for the financial year ended 31 March 2013. This increase of R1,906 million, or 36.8%, was principally due to an increase in revenue and lower operating costs.

Comparison of the financial years ended 31 March 2013 and 31 March 2012 The table below sets out the Group’s results of operations for the periods indicated.

For the financial year ended 31 March 2013(1) 2012 (millions of Rand) INCOME STATEMENT Revenue ...... 128,775 114,760 Primary energy ...... (60,748) (46,314) Net employee benefit expense...... (23,564) (20,132) Depreciation and amortisation expense ...... (9,960) (8,801) Net impairment loss...... (1,039) (620) Other operating expenses ...... (23,039) (15,209) Other income ...... 1,126 699 Net fair value loss on financial instruments, excluding embedded derivatives ...... (1,655) (2,388) Net fair value (loss)/gain on embedded derivatives ...... (5,942) 334 Operating profit before net finance income/(cost) ...... 3,954 22,329 Net finance income/(cost) ...... 3,003 (3,963) Share of profit of equity-accounted investees, net of tax ...... 35 41 Profit before tax ...... 6,992 18,407 Income tax ...... (1,856) (5,156) Profit from continuing operations ...... 5,136 13,251 DISCONTINUED OPERATIONS Profit/(loss) from discontinued operations ...... 47 (3) Profit for the period ...... 5,183 13,248 Attributable to:...... Owner of the company ...... 5,183 13,248 Non-controlling interest(2) ...... — — 5,183 13,248 ______(1) The Group’s income statement and statement of cash flows for the financial year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the financial year ended 31 March 2014, and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Group’s Audited Annual Financial Statements (with respect to the financial year ended 31 March 2014). (2) Nominal amount.

Revenue Revenue for the Group for the financial years ended 31 March 2013 and 2012 was R128,775 million and R114,760 million, respectively. The increase of R14,015 million, or 12.2%, was principally due to the 16% tariff increase under MYPD 2 in the financial year ended 31 March 2013 (which resulted in a 16.4% average increase in electricity revenue per kilowatt-hour). The volume of electricity sales for the financial year ended 31 March 2013 totalled 216,561 GWh, representing a decrease of 3.7% compared to 224,785 GWh for the financial year ended 31 March 2012. The overall revenue increase was lower than budgeted for due to lower electricity sales volumes. The lower volumes were mainly due to lower electricity demand and demand- response initiatives, including power buy-backs as well as industrial action and operational issues at large mining customers (which, in turn, were slightly offset by increased and opportunistic international sales to international customers, to take advantage of favourable pricing at the time). Revenue for the financial year ended 31 March 2013 includes an environmental levy charged to customers of R6.5 billion, compared to R4.3 billion for the financial year ended 31 March 2012. For each period, the environmental levy was paid directly to the Government. Revenue for the Generation segment for the financial years ended 31 March 2013 and 2012 was R86,395 million and R72,705 million, respectively, revenue for the Transmission segment for the financial years ended 31 March 2013 and 2012 was R10,738 million and R11,934 million, respectively, and revenue for the Distribution segment for the financial years ended 31 March 2013 and 2012 was R19,273 million and R22,212 million, respectively. Revenue for the Group Customer Services segment for the financial years ended 31 March 2013 and 2012 was R10,918 million and R6,477 million, respectively, while revenue for all other segments for the financial years ended 31 March 2013 and 2012 was R9,522 million and R8,187 million, respectively. Variability in segment reported revenues between the periods is due to changes in the profit equalisation entry processed at the end of each period, which adjusts segment revenue in order to reflect a uniform return on assets.

Net fair value loss on embedded derivatives The net fair value loss on embedded derivatives for the financial year ended 31 March 2013 increased to R5,942 million from a net fair value gain of R334 million for the financial year ended 31 March 2012. This increase in losses of R6,276 million was principally due to a change in the contractual period of the contracts underlying the embedded derivatives. Net fair value losses on other derivatives for the financial year ended 31 March 2013 decreased to R1,655 million from R2,388 million for the financial year ended 31 March 2012. The decrease was due primarily to the costs attributable to the rolling over of forward cover exchange contracts, which vary from period-to- period due to the timing of the placement of the related procurement contracts and exchange rate fluctuations (depreciation). The Group’s policy is to hedge all foreign exchange exposures above R150,000. Operating expenses Operating expenses for the Group for the financial year ended 31 March 2013 and 2012 were R118,350 million and R91,076 million, respectively. This increase of R27,274 million, or 29.9 %, resulted from the following components. Primary energy costs for the financial year ended 31 March 2013 increased to R60,748 million from R46,314 million for the financial year ended 31 March 2012. This R14,434 million, or 31.2%, increase was primarily due to an increase in coal usage costs; an increase in the cost of using the OCGTs; an increase in the environmental levy and an increase in demand-market participation, power buybacks and co-generation costs. For the financial years ended 31 March 2013 and 2012, the environmental levy, which is accounted for as a primary energy cost and passed on fully to consumers as part of the tariffs charged by the Group, was R8.0 billion and R6.2 billion, respectively. This increase was attributable to the Government’s decision to raise the environmental levy from 2.5c/kWh to 3.5c/kWh on 1 July 2012. Other expenditure that contributed to the cost increase included increased costs associated with coal handling (which encompasses the storage of coal across the various stages of the preparation process), fuel for gas-fired start-ups, water usage and international purchases. The cost of primary energy as a percentage of revenue for the financial year ended 31 March 2013 and 2012 was 47.0% and 40.0%, respectively. Net employee benefit expense for the financial year ended 31 March 2013 increased to R23,564 million from R20,132 million for the financial year ended 31 March 2012. This increase of R3,432 million, or 17.0%, was principally due to an increase in the number of employees to 46,266, compared to 43,473 as at 31 March 2012, as well as incremental salary increases. The gross employee costs (before capitalisation of expenses) for the Group for the financial years ended 31 March 2013 and 2012 were R28,626 million and R24,362 million, respectively. Depreciation and amortisation expense for the financial year ended 31 March 2013 and 2012 was R9,960 million and R8,801 million, respectively. This increase of R1,159 million, or 13.2%, was principally due to the increase in property, plant and equipment and intangible assets of R52,062 million. Net impairment loss for the financial year ended 31 March 2013 and 2012 was R1,039 million and R620 million, respectively. This increased loss of R419 million, or 67.6%, was principally due to the increase in the provision for doubtful debts. Although, in line with applicable legislation, the Issuer initiated disconnection procedures for the electricity supply to four municipalities which were in arrears, no disconnections were actually made as other arrangements were agreed to settle their debts. Other operating expenses for the Group for the financial year ended 31 March 2013 increased to R23,039 million from R15,209 million for the financial year ended 31 March 2012. These expenses primarily consist of integrated demand-management costs, which were R3,000 million and R1,530 million for the financial year ended 31 March 2013 and 2012, respectively, and repairs and maintenance costs which were R14,152 million and R11,822 million for the financial year ended 31 March 2013 and 2012, respectively. Other operating expenses for the generation segment for the financial year ended 31 March 2013 and 2012 were R16,045 million and R11,162 million, respectively; representing an increase of R4,883 million, or 43.7%. Other operating expenses for the Transmission segment for the financial year ended 31 March 2013 and 2012 were R2,317 million and R2,059 million, respectively; representing an increase of R258 million, or 12.5%. Other operating expenses for the Distribution segment for the financial year ended 31 March 2013 and 2012 were

R7,480 million and R8,518 million, respectively; representing a decrease of R1,038 million, or 12.2%. The increases in other operating expenses for the Generation and Transmission segments were mainly due to an increase in gross repairs and maintenance cost. Net finance income/(cost) Net finance income after capitalisation of borrowing costs (and including the unwinding of interest provisions) for the financial year ended 31 March 2013 increased to R3,003 million from a net finance cost of R3,963 million for the financial year ended 31 March 2012. Finance income decreased to R2,796 million for the financial year ended 31 March 2013 from R3,536 million for the financial year ended 31 March 2012. This decrease of R740 million, or 20.9%, was principally due to the decrease in cash and cash equivalents and investments in securities. Finance costs after capitalisation of borrowing costs resulted in an income of R207 million for the financial year ended 31 March 2013 as compared to a cost of R7,499 million for the financial year ended 31 March 2012. This variation was mainly due to two factors: (i) the re-measurement of the R60 billion subordinated Government loan at fair value (following the 8% tariff increase under the recent MYPD 3 determination), which resulted in a gain of R17,295 million for the financial year ended 31 March 2013 compared to a gain of only R5,472 million for the financial year ended 31 March 2012; and (ii) a decrease in the borrowing cost capitalised for the financial year ended 31 March 2013, which was R3,678 million compared to R4,999 million in the financial year ended 31 March 2012. The unwinding of interest amounted to R2,404 million as at 31 March 2013 compared to R2,025 million as at 31 March 2012. Share of profit of equity–accounted investees Share of profit of equity–accounted investees for the financial years ended 31 March 2013 and 2012 was R35 million and R41 million, respectively. This relates primarily to the Group’s share of its associates’ and joint ventures’ post acquisition profits or losses. The decrease of R6 million, or 14.6%, was principally due to a decrease in the profit share of the Motraco joint venture. Income tax Income tax expense for the financial year ended 31 March 2013 was R1,856 million compared to R5,156 million for the financial year ended 31 March 2012. This decrease of R3,300 million, or 64.0% was principally due to a decrease in profit before tax. The effective tax rate for the financial years ended 31 March 2013 and 2012 was 26.5% and 28.0%, respectively. The decrease in the effective tax rate was principally due to additional non-taxable income arising from operations in the financial year ended 31 March 2013. This included R115 million, which equates to 1.64% of net profit before tax compared to nil in the previous year. The statutory rate for both periods was 28%. Profit from continuing operations Profit from continuing operations for the financial year ended 31 March 2013 was R5,136 million, compared to R13,251million for the financial year ended 31 March 2012. This decrease of R8,115 million, or 61.2%, was principally due a reduction of the tariff increase from 25% to 16% in the financial year ended 31 March 2013. Profit/(loss) from discontinued operations Profit from discontinued operations for the financial year ended 31 March 2013 was R47 million, compared to loss from discontinued operations of R3 million for the financial year ended 31 March 2012. This variation was principally due to EEM, a subsidiary of Eskom Enterprises, being classified as a discontinued operation. Profit for the year Profit for the financial year ended 31 March 2013 was R5,183 million, compared to R13,248 million for the financial year ended 31 March 2012. This decrease of R8,065 million, or 60.9%, was principally due to a reduction of the tariff increase from 25% to 16% in the financial year ended 31 March 2013.

Liquidity and Capital Resources Overview The Group’s primary sources of liquidity are cash flow from operating activities (which are highly dependent on approved tariff levels and cost management) and bank loans, debt securities, commercial paper and other forms of indebtedness. The Group’s primary needs for liquidity are to fund its working capital and its committed capacity expansion programme. The Group expects to meet these capital expenditure requirements from operating cash flows (including revenues under MYPD 3), and debt financing (raised locally and internationally). Cash flow for the six month periods ended 30 September 3014 and 30 September 2013 and for the financial years ended 31 March 2014, 31 March 2013 and 31 March 2012 As at 30 September 2014 and 2013 the Group had cash and cash equivalents of R12,953 million and R30,193 million. As at 31 March 2014, 2013 and 2012 the Group had cash and cash equivalents of R19,676 million, R10,620 million and R19,450 million, respectively. The table below sets out the Group’s net cash flows from operating, investing and financing activities for the periods indicated.

For the six months ended For the financial year ended 30 September 31 March 2014 2013(1) 2014 2013(2) 2012 (millions of Rand) Net cash generated from operating activities ...... 18,106 19,625 33,616 27,669 38,529 Net cash utilised in investing activities ...... (25,284) (24,505) (57,207) (58,359) (60,013) Net cash generated from financing activities ...... 438 24,468 32,795 21,784 28,720 ______(1) The Group’s income statement and statements of cash flows for the six months ended 30 September 2013 as set out in the Group’s Reviewed Interim Financial Statements for the six months ended 30 September 2014 and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 21 of the Reviewed Interim Financial Statements (with respect to the six months ended 30 September 2013). (2) The Group’s income statement and statement of cash flows for the financial year ended 31 March 2013 as set out in the Group’s Audited Annual Financial Statements for the financial year ended 31 March 2014, and extracted herein, have been restated for comparative purposes due to the reclassification as at 31 March 2014 of EEM as a discontinued operation held-for-sale in accordance with IFRS 5 (Non-current assets held-for-sale and discontinued operations). For a detailed description of such restatement and changes, please see Note 48 of the Group’s Audited Annual Financial Statements (with respect to the financial year ended 31 March 2014).

Cash flow from operating activities Cash inflows from operations decreased by R1,519 million in the six months ended 30 September 2014 compared to the equivalent period in 2013. This decrease was due to the decrease in profit before tax of R4,064 million. Cash flow movements consisted of the net trading assets/liabilities using of R732 million in the six months ended 30 September 2014 compared to net trading assets/liabilities providing cash flows of R1,536 million in the equivalent period in 2013. Derivatives held for risk management used cash flows of R345 million in the six months ended 30 September 2014 compared to providing cash flows of R4,469 million during the equivalent period in 2013. Cash inflows from operations increased by R5,947 million in the financial year ended 31 March 2014 compared to the previous year and decreased by R10,860 million in the financial year ended 31 March 2013 compared to the previous year. In the financial year ended 31 March 2014, the increase was due to the increase in profit before tax of R2,171 million and in the financial year ended 31 March 2013, the decrease was due to the decrease of net profit before tax of R11,415 million. The cash flow movement is the decrease in net trading assets/liabilities of R3,528 million and a net increase in the cash flow from derivatives held for risk management of R10,609 million. Cash flow utilised in investing activities

During the six months ended 30 September 2014 and 2013, the Group recorded a net cash outflow in investing activities of R25,284 million and R24,505 million, respectively. This increase of R779 million, or 3.2%, was primarily attributable to increased acquisitions of property, plant and equipment and intangible assets. During the financial years ended 31 March 2014 and 2013, the Group recorded a net cash outflow in investing activities of R57,207 million and R58,359 million, respectively. This decrease of R1,152 million, or 2.0%, was primarily attributable to a decrease in non-current trade and other payable during the financial year ended 31 March 2014 compared to an increase during the financial year ended 31 March 2013. During the financial years ended 31 March 2013 and 2012, the Group recorded a net cash outflow from investing activities of R58,359 million and R60,013 million, respectively. This decrease of R1,654 million, or 2.8%, was primarily attributable to increased acquisitions of property, plant and equipment and intangible assets. Cash flow from financing activities During the six months ended 30 September 2014, the Group recorded a net cash inflow from financing activities of R438 million, compared to a net cash inflow of R24,468 million for the six months ended 30 September 2013. This decrease of R24,030 million, or 98.2%, was primarily attributable to decreased debt securities and borrowings raised in the six months ended 30 September 2014 compared to the equivalent period in 2013. During the financial year ended 31 March 2014, the Group recorded a net cash inflow from financing activities of R32,795 million, compared to a net cash inflow of R21,784 million for the financial year ended 31 March 2013. This increase of R11,011 million, or 50.5%, was primarily attributable to increased funding activities. During the financial year ended 31 March 2013, the Group recorded a net cash inflow from financing activities of R21,784 million, compared to a net cash inflow of R28,720 million for the financial year ended 31 March 2012. This decrease of R6,936 million, or 24.2%, was primarily attributable to reduced funding activities to match the slower capacity expansion during this period. Capital Expenditure The Group makes significant capital expenditure, particularly in connection with new build generation and transmission projects under its committed capacity expansion programme. Capital expenditure consists of capital investments and capital improvements. Capital investments comprise investments in new capital assets and are currently principally composed of investments made in connection with the Group’s ongoing capacity expansion programme. Capital improvements comprise investments designed to increase the useful life or capacity of existing capital assets through replacement (rather than general maintenance or repair), assessed in accordance with IAS 16 (Property, Plant and Equipment). Costs toward the Group’s capital assets that are not classified as capital improvements in accordance with IAS 16, such as day-to-day maintenance and repairs costs, are recorded as expenses. The Group allocates capital investments relating to its committed capacity expansion programme to the Group Capital segment, which was established for the purpose of executing the capacity expansion programme, while the Group allocates its other capital investments and capital improvements, which include capital improvements relating to plant and equipment, and capital investments/improvements relating to telecom, group commercial and technology, among other things, to the Group’s various other segments. The Group’s capital expenditure (including capitalised borrowing costs) during the six months ended 30 September 2014 was R34,808 million, an increase of R 5,389 million, or 18.3%, from R29,419 million spent in the six months ended 30 September 2013. The Group’s budget for capital expenditures in the 2014/15 financial year is R58.1 billion (excluding projects funded by the Department of Energy and the Electrification Programme). For the six months ended 30 September 2014, the Group Capital segment’s capital expenditure (including capitalised borrowing costs) was R23,998 million, or 68.9% of total capital expenditures for the period. The Group’s capital expenditure (including capitalised borrowing costs) during the financial year ended 31 March 2014 was R72,716 million, an increase of R11,670 million, or 19.1%, from R61,046 million spent in the financial year ended 31 March 2013. Much of the increase during the period was attributable to a R9,612 million increase in capitalised borrowing costs during the period. Excluding capitalised borrowing costs, the Group’s capital expenditure during the financial year ended 31 March 2014 was R2,500 million less than the

budgeted amount of R62,300 million, mainly due to construction delays in the capacity expansion programme. Capital expenditure (including capitalised borrowing costs) during the financial year ended 31 March 2012 was R63,354 million. For the year ended 31 March 2014, the Group Capital segment’s capital expenditure (including capitalised borrowing costs) was R37,186 million, or 51.1% of total capital expenditures for the period. NERSA’s MYPD 3 determination, which allowed an annual tariff increase of only 8% over the five year period up to 31 March 2018, was significantly below the annual tariff increases the Group had projected that it would need over the course of the MYPD 3 period and beyond to cover its capital expenditure budget for the period, much of which relates to costs accrued in connection with its committed capacity expansion programme. Prior to NERSA’s MYPD 3 determination, the Group’s planned capital expenditure budget for the MYPD 3 period was approximately R337 billion, while the Group’s current capital expenditure budget, as approved by NERSA in its MYPD 3 determination, is only R251 billion. As a result, the Group has performed a significant capital expenditure reprioritisation, including with respect to its capacity expansion programme, to address the Group’s critical business needs based on the Group’s strategic imperatives Capacity Expansion Programme As part of its capacity expansion programme, which was initiated in 2005 and is expected to be completed during the 2020/21 financial year, the Group has approved and committed to the building of the Medupi coal- fired power station (of which over 70% of the R114.0 billion estimated total cost had been spent as at 30 September 2014), the Kusile coal-fired power station (of which approximately 60% of the R123.5 billion estimated total cost had been spent as at 30 September 2014), and the Ingula pumped-storage plant (of which nearly 90% of the R25.9 billion estimated total cost had been spent as at 30 September 2014). The capacity expansion programme also includes the expansion of transmission network assets and new infrastructure including new transmission lines (of which 52% of the R32.3 billion estimated total cost, inclusive of transmission costs for Medupi, Kusile and Ingula, had been spent as at 30 September 2014) and two renewable energy plants. Between the inception of the capacity expansion programme in 2005 and 30 September 2014, the Group had spent a total of approximately R251 billion (excluding capitalised borrowing costs). The total cost of the programme is currently estimated at approximately R348 billion (excluding capitalised borrowing costs). The IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) sets out South Africa’s long-term energy needs and the generating capacity, technologies, timing and costs associated with meeting such needs. By 2030, the Group estimates that about 16,000 MW of additional generating capacity will need to be built, over and above the Group’s current capacity expansion programme. A number of programmes, including the renewables initiative, have been undertaken by the Government in response to the plan. When the IRP was promulgated in 2011, the Group and the Department of Public Enterprises prepared a view to reflect the potential role the Group would play in the delivery of the new build capacity presented. A final decision to determine the Group’s role will be made by the Department of Energy and the Group expects the finalisation of the IEP to inform the Group’s involvement in the new build capacity, to be set forth in the final revised IRP, which is expected to be approved following the IEP’s anticipated approval in March 2015. The Group’s MYPD 3 application did not provide for any new build capacity, as the Group has not approved or committed to any capital investments in the South African electricity sector beyond Kusile under the committed capacity expansion programme pending the finalisation and publication of the updated IRP, which is expected to be approved following the IEP’s anticipated approval in March 2015. See “Business—Finance—Capacity Expansion Programme” for more detail on the committed capacity expansion programme. Sources of Liquidity Under MYPD, NERSA-approved revenues for the Group constituted R114.8 billion for the financial year ended 31 March 2012, R128.9 billion for the financial year ended 31 March 2013 and, following the MYPD 3 determination, R139.5 billion for the financial year ended 31 March 2014. Group revenues are estimated to be

R148.8 billion and R164.8 billion for the financial years ending 31 March 2015 and 31 March 2016, respectively, as stated in the Group’s corporate plan. As at 30 September 2014, R65.5 billion, or 32.8%, of the revised funding requirement of R199.5 billion funding plan (which covers the period up to 31 March 2018) has been secured (including the maximum borrowing limits of certain established programmes), as set out in the table below.

Identified funding Committed to Draw-downs to sources date(1) date(2) (billions of Rand) Potential sources of funding: Domestic bonds ...... 41.0 5.0 5.0 International bonds ...... 42.0 3.3(3) 3.3 Commercial paper(3) ...... 60.0 2.4 2.4 Existing domestic development finance institutions (“DFI”) ...... 6.0 6.0 1.5 Existing international DFIs ...... 32.3 32.3 2.2 Existing export credit agencies (“ECA”) ...... 15.4 15.4 0.9 Other and new sources ...... 2.8 1.1 - Total ...... 199.5 65.5 15.3 (4) (5) Percentages ...... — 32.8 23.4 ______(1) Funding raised or signed facilities with milestone drawdowns. (2) Secured during the period 1 April 2014 to date. (3) Commercial paper is issued for up to one year and then redeemed and re-issued for the same net amount. It is therefore by definition not fully secured for the full period, however, the Issuer’s long-term observations and past trends support a high level of confidence that the Issuer will be able to roll over the redemption each year. For this reason, the gross value of the commercial paper issued is shown as “secured”. (4) As a percentage of the R199.5 billion funding being sourced. (5) As a percentage of the currently secured total.

The Group anticipates that further borrowing of approximately R50 billion will be required over the MYPD period and has included this in the revised funding requirement. The current borrowing programme does not incorporate any allocations of capital projects from the IRP. Regulatory Clearing Account During the last quarter of 2013, the Group submitted a RCA application to NERSA for the MYPD 2 period. This application takes into consideration the difference between the assumed costs and revenues of the Group under MYPD 2, compared to the actual costs incurred and revenues received by it for the MYPD 2 period. Pursuant to current regulation, NERSA is allowed to increase (future) electricity tariffs to compensate the Group for an under-recovery of revenues or, it can reduce (future) tariffs if the Group over-recovered revenues. On 30 July 2014, NERSA announced its decision to allow the Group to recover R7.82 billion for under- recoveries incurred during the MYPD2 period. It was further announced on 3 October 2014 that the RCA balance would be liquidated via the tariff recovered from standard tariff customers, as well as some other Eskom customer categories, but would only be implemented in the 2015/16 financial year. This adjustment will result in an average increase of approximately 13% for standard customers, instead of the previously approved 8%. Additionally, the Group is working on submitting another RCA application for a revenue adjustment for the first year of the MYPD 3 period, with the aim of increasing revenues to a more sustainable level. However, despite the RCA adjustment, the lower than expected tariff increase for MYPD 3 will necessarily extend the Group’s reliance on Government support for a number of years. See “—Government support”. Should the Group fail to raise sufficient capital for its capacity expansion programme and as a result fail to keep up with demand for electricity, there would be significant implications for the economy. See “Risk Factors—Risks relating to the Group—The Group may not be able to meet the demand for electricity in South Africa in the longer term and there is no guarantee that the Group will be the chosen provider of generation capacity in the future”. Business Productivity Programme The Group implemented its BPP in response to NERSA’s MYPD 3 determination. The BPP focuses on the reduction of the cost base, increasing productivity and revising the Group’s business model and strategy. The revision in strategy is focused on the Group’s future business, a long-term cost reflective electricity path,

enhancement of the corporate planning process to ensure systematic understanding of key business operations and assessing all organisational structure issues and opportunities. The initial phase of the BPP, completed on 31 March 2014, focused on the development of savings opportunities or “value packages”. As at the date hereof, 86 savings opportunities (or value packages) with a total value of R73 billion have been identified by the Group and approved (R13 billion more than the R60 billion target), covering six functional areas, including “Primary Energy”, “Employee costs”, “Repairs and maintenance”, “External spend”, “Finance” and “Revenue management”. Of the R73 billion, R62 billion comprised cash savings. Cost-savings projects focus on:

• improving the efficiency and effectiveness of the capacity expansion programme;

• reducing external expenditure through, amongst other things, efficient procurement practices, negotiating for better prices, revising technical standards and reviewing the necessity of some activities;

• reducing revenue losses, improving debt management and finding additional revenue sources;

• optimising maintenance costs and processes;

• reducing direct and indirect employee benefit costs;

• optimising funding options and the balance sheet; and

• optimising and reducing the costs of primary energy. Prior to the implementation of the value packages, the Group performs certain risk reviews and a number of controls are implemented and maintained to manage the risk of non-realisation of the BPP targets. The majority of these measures relate to current governance processes such as business planning, budgeting and periodic financial monitoring. However, the Group’s aim is to implement more specific measures as part of the BPP programme, such as reporting on savings realisation per value package, tracking the financial bottom line savings (the ultimate indicator of the BPP’s success), tracking and reporting on the progress of individual value packages and instituting formal interaction, on a regular basis, between segment project leaders and EXCO. These measures will be designed to provide a more granular view in monitoring value packages from the start through to savings realisation, as part of a “stage gate” methodology, which is a proven, standard methodology in cost-savings exercises. Additionally, a comprehensive project management approach and methodology is in the process of being implemented. The BPP cash savings target for the 2014/15 financial year is R9.8 billion, which includes reductions in capital expenditure (R2.3 billion), operating expenditure (R5.1 billion) and working capital (R2.4 billion). As at 30 September 2014, savings of R1.9 billion have been made, although a potential loss of R5.6 billion of the initially identified value packages was reported due to projected overspending on diesel for the OCGTs and fuel oil for the coal-fired plant, as well as slow progress in recovering outstanding debt from municipalities. The Group is continuously investigating further savings opportunities, including specific initiatives to unlock cash in its business. In an effort to close the projected savings leakages, the various BPP divisions have identified potential stretch of savings in the existing value packages, as well as additional savings initiatives. Cash unlocking initiatives are being implemented to provide additional liquidity solutions. Measures to close the projected savings gap account for R4.2 billion, resulting in a net projected savings gap of R1.3 billion. The BPP team is looking to further address the gap through additional focus on other operating expenses and general expenses, as meeting the R9.8 billion target for 2014/15 will be a challenge. Key support will be required to manage the growing arrear municipal debt as well as the consequences of reduced diesel usage on security of supply. In addition to the proposed business efficiency measures addressed through BPP, measures to specifically address the short-term liquidity constraints are being investigated. A study was conducted on potential opportunities and nine “cash unlocking” opportunities are currently being investigated or implemented. While the initiatives will assist in alleviating liquidity constraints, they will not lead to financial sustainability.

Government support The Government recognises the Group’s critical role in the economy and remains committed to ensuring the Group’s financial stability. In 2008 the Government approved the EPP, which is designed to ensure adequate funding capability in the long-term. Given that full implementation of the EPP implies significant price increases, a five year period has been provided in which to achieve the cost-reflective tariffs planned by the EPP. The five year phasing-in period creates the need for short- and medium-term funding solutions. The Government’s EPP had aimed to achieve fully cost-reflective tariffs (i.e. tariffs that would reflect the full cost of supplying electricity to customers) by the end of MYPD 2. However, NERSA’s MYPD 3 tariff determination, published in February 2013, granted only an average 8% increase per year for the five years of the determination period, which is half the 16% increase applied for by the Group. The Group has implemented a few initiatives to provide for the likely effects of a longer phase-in to achieve cost-reflective tariffs and has embarked on strategic imperatives to reduce its capital and operating expenses, and raise significant additional funding, particularly towards the end of the MYPD 3 period. The BPP has been implemented to assist in funding the revenue shortfall. See “Business Productivity Programme” above for a discussion of this programme. Additionally, the following important steps are being considered to achieve financial sustainability:

• The Group’s rate of return on assets should, at a minimum, be equal to its cost of capital; therefore, the migration to cost-reflective tariffs, that will enable the recovery of efficient operating costs, remains of paramount importance.

• Maintaining an investment grade credit rating with Government support.

• The RCA application for a revenue adjustment for the first year of the MYPD 3 period, in order to increase revenues to a more sustainable level.

• A reduction in costs, in terms of savings to be realised under the BPP.

• Although it may be impractical to disconnect supply to Soweto and defaulting municipalities, the recovery of debt remains a focus.

• An Inter-Ministerial Committee, led by the Finance, Public Enterprises and Energy Ministries, was established to work with Eskom to find solutions to Eskom’s financial challenges. On 22 October 2014, during its MTBPS, the Government announced the Government Finance Support Package, a financial support package for the Group. The package comprises four main components, including (i) a Government equity or cash injection, (ii) the potential conversion of subordinated debt to equity, (iii) the approval by the Government for Eskom to issue additional debt of ZAR50 billion and (iv) support for annual tariff increases beyond the 8% originally allowed under MYPD 3. The expectation is that Government’s equity or cash injection, to be financed through the Government’s liquidation of certain non-strategic assets, will be made during the 2015/16 financial year. To further support the Group’s liquidity and credit metrics, NERSA approved a raise in tariffs by 12.7% to be implemented on 1 April 2015 with effect for the 2015/2016 financial year instead of the previously approved 8%. Although the Government Finance Support Package will ease liquidity pressures in the short term, the issue of long-term financial sustainability will have to be addressed. In order to ensure financial sustainability, it will be key for the Group to achieve an appropriate return on assets in the long-term, and therefore, cost-reflective tariffs that allow for the recovery of efficient costs. In the short term, the Group has to obtain adequate funding to ensure liquidity, thereby supporting its going concern status, and to avoid a further ratings downgrade. In addition, the Group will continue to rely on Government support for a number of years. In 2008, the Government agreed to provide a subordinated hybrid loan of R60 billion to the Group in support of its committed capacity expansion programme. The final tranche of the loan (R5 billion) was made available in March 2011 and as at 31 March 2011, the loan was fully drawn.

In 2009, the Government originally approved R176 billion of debt guarantees to be used over a five year period. In October 2010, the Government pledged further support for the Group in the form of additional debt guarantees amounting to R174 billion. Together, the total debt guarantee support from the Government amounts to R350 billion, of which R154 billion has been utilised. As at 30 September 2014, R100 billion of the total R350 billion Government guarantee has been allocated to existing local bonds issued under the Group’s domestic multi-term note programme, R94 billion of which has been utilised and R6 billion of which is still available, if required. A total of R54 billion has been utilised under foreign facilities which brings the total amount of Government guarantees utilised as at 30 September 2014 to R154 billion (calculated at the exchange rates applicable as of the date of signing of the currency related facilities). The Group has not approved or committed to any new build projects beyond Kusile under its committed capacity expansion programme pending the finalisation and publication of the updated IRP, which is expected to be approved following the IEP’s anticipated approval in March 2015, and its MYPD 3 application did not include any funding for any such new capacity build. Description of certain indebtedness The following is a brief summary of the Group’s outstanding indebtedness (and the agreements relating thereto) as at 30 September 2014: An individual loan agreement for €114 million was signed with Deutsche Bank on 30 August 2006 (with Hermes providing export credit cover) for the financing of the OCGTs at the Atlantis and Mossel Bay power plants, a further loan agreement was signed on 20 August 2010 for €108 million for the financing of the pump turbines and controller system for the Ingula pumped-storage hydropower plant. As at 30 September 2014, €189 million had been drawn down under these two facilities. On 27 December 2006, the Group entered into a committed €80 million loan facility with the European Investment Bank (“EIB”) for the construction of a new high-voltage transmission interconnection between Johannesburg and Cape Town. The agreement contains undertakings that the borrower only utilise the proceeds for the designated project. The amortised repayment profile loan maturity date is 27 December 2031. As at 30 September 2014, the facility had been drawn down in full. This facility contains a provision whereby, if any credit rating of the Issuer’s unsecured and unsubordinated foreign currency long-term debt falls to below the lower of that of the Republic of South Africa or BBB/Baa2 and, in the reasonable opinion of EIB, the Issuer has experienced a material adverse change in its financial condition, EIB may require the Issuer to provide a third party guarantee (or equivalent security) within a specified timeframe. If the Issuer fails to do so, the EIB may accelerate the loan. On 14 February 2007, the Group entered into a committed ¥30 billion loan facility with the Japan Bank for International Cooperation (“JBIC”) for the financing of capital goods to be imported from Japan. The Group is required to use the proceeds of any drawdown to finance eligible components of an approved project. In the fourth quarter of 2013, further drawdowns under the facility (beyond those that had already taken place) were cancelled due to a lack of eligible Japanese content. As at 30 September 2014, ¥4.7 billion had been drawn down under the facility. On 7 June 2007, the Group entered into an unsecured ¥17 billion loan facility with the JBIC. The Group used the proceeds of the facility to fund the construction of two power lines connecting the Majuba Power Station to the Umfolozi Substation and the Duvha Power Station to the Leseding Substation, which is now complete. The maturity date is 10 May 2020. In the fourth quarter of 2013, further drawdowns under the facility (beyond those that had already taken place) were cancelled due to completion of the funded projects. As at 30 September 2014, ¥13.4 billion had been drawn down under this facility. On 20 July 2007, the Group entered into a committed €88 million loan facility with the EIB for the construction of a new high-voltage transmission interconnection between Johannesburg and Cape Town. The agreement contains undertakings that the borrower only utilise the proceeds for the designated project. The amortised repayment profile loan maturity date is 2 July 2032. As at 30 September 2014, the facility had been drawn down in full. This facility contains a provision whereby, if any credit rating of the Issuer’s unsecured and unsubordinated foreign currency long-term debt falls to below the lower of that of the Republic of South

Africa or BBB/Baa2 and, in the reasonable opinion of EIB, the Issuer has experienced a material adverse change in its financial condition, EIB may require the Issuer to provide a third party guarantee (or equivalent security) within a specified timeframe. If the Issuer fails to do so, the EIB may accelerate the loan. On 9 July 2008, the Group entered into another unsecured ¥7.5 billion loan facility with the JBIC. As at 30 September 2014, ¥4.2 billion had been drawn down under this facility. The Group entered into two Hermes covered financing agreements for €780 million to fund part of the foreign content of the Medupi boiler contract. The first agreement, signed on 10 September 2008, is a €250 million fixed rate Commercial Interest Reference Rate (“CIRR”) loan and the second, signed on 13 May 2009, is a €530 million floating rate loan. There are six tranches to each loan which are tied to the six units of the power station. Drawdowns are based on milestone payments on the underlying supply contract. The loans provide for a five year drawdown period and a 12 year amortised repayment profile period. The loans mature on 30 March 2026. As at 30 September 2014, €581 million had been drawn down under this facility. On 10 November 2008, the Group entered into a U.S.$500 million facility with African Development Bank (“AfDB”). The loan was drawn down in the amounts of U.S.$290.7 million and R2 billion. As at 30 September 2014, the facility has been drawn down in full. This facility contains a provision whereby, if the credit rating of the Issuer’s unsecured and unsubordinated foreign currency long-term debt falls to below an S&P rating of BBB- or a Moody’s rating of Baa3, Eskom must provide a third party guarantee or pre-pay the loan within a specified time-frame. The AfDB’s board approved loan financing for the funding of a portion of the boiler and turbine contracts (project components) for the Medupi power station on 11 December 2009. The loan is dual currency and the total loan value is €930 million and R10.63 billion. The loan will be advanced to the Group during the five year grace period on capital repayments from signature date; interest is payable over this period. Semi-annual capital repayments will commence thereafter for the following 15 years. The amortised repayment profile loan maturity date is 1 August 2029. As at 30 September 2014, total drawdowns of €524 million and R10.31 billion, respectively, had been made under this facility. On 11 December 2009, the Group entered into a Hermes (German) Export Credit Agency covered financing arrangement with four European banks and three local banks to fund part of the foreign content of the Kusile boiler contract. The three agreements under this arrangement are synchronised by a coordination agreement. The first agreement is a €100 million fixed rate CIRR loan with a single European bank, the second is a €345 million floating rate loan with three European banks and the third is a €260 million equivalent ZAR denominated floating rate loan with three local banks. The loans provide for a five year drawdown period and a 12 year amortised repayment profile period. The loans mature on 1 July 2027. As at 30 September 2013, €478 million had been drawn down under this facility. On 23 December 2009, the Group entered into a COFACE ECA covered facility with five European banks to fund part of the eligible foreign content of the Medupi turbine supply contract and Kusile turbine supply contract. The Medupi loan amounts to €623 million and the Kusile loan amounts to €546 million. There are six tranches to each loan which are tied to the six units of the power station. The loans provide for a five year drawdown period and a 12 year amortised repayment profile period. The loans mature on 1 January 2027. As at 30 September 2014, €937 million had been drawn down. On 16 April 2010, the Group entered into a U.S.$3.75 billion World Bank loan, of which U.S.$3 billion is for the financing of the Medupi power plant, the first coal-fired plant in Africa to use supercritical power generation technology; the remaining U.S.$750 million is for financing renewable energy and carbon-efficient projects such as solar, thermal and wind power, progressing South Africa’s commitment to a lower carbon footprint. The loan has an amortised repayment profile with a final maturity date of 1 May 2038. As at 30 September 2014, U.S.$1.58 billion had been drawn down under this facility with the balance to be drawn down as the projects are completed. On 30 July 2010 the Group signed a €63.7 million floating rate facility with COFACE and Crédit Agricole for the Medupi control and instrumentation supply contract. As at 30 September 2014, €19 million had been drawn down.

On 4 November 2010, the Group signed a R15 billion long-term facility with the Development Bank of Southern Africa (“DBSA”) maturing in 2031 for the financing of the capacity expansion programme. As at 30 September 2014, R10.5 billion had been drawn down under this facility. This facility contains a provision whereby, if the Issuer’s domestic local currency credit rating falls to below an investment grade rating by either S&P or Fitch, DBSA may immediately cancel the undrawn portion of the facility, request a meeting to discuss the matter to allow the Issuer to provide a third party guarantee and, if the Issuer fails to do so, require the Issuer to prepay the loan within a specified timeframe. On 28 July 2011, the Group signed a long-term facility with Agence Française de Développement (“AFD”), maturing in 2030 for R980.8 million for the financing of renewables. As at 30 September 2014, only R745 million had been drawn down. This facility contains a provision whereby, if the credit rating of the Issuer’s unsecured and unsubordinated foreign currency long-term debt falls to below an S&P rating of BBB- or a Moody’s rating of Baa3, AFD shall request a meeting to discuss the matter and, if no resolution is reached, the Issuer shall be required to provide a guarantee within a specified timeframe. If the Issuer fails to do so, it is required to pre-pay the loan. During the course of 2011 and 2012, one loan with the World Bank and two loans with AfDB in the aggregate amount of U.S.$615 million were signed for financing of renewables. As at 30 September 2014, an aggregate of U.S.$26.3 million had been drawn under these facilities. On 26 September 2011, the Group increased its R65 billion domestic multi-term note programme to R100 billion. Any notes issued under the programme constitute direct, unconditional, unsubordinated and unsecured obligations. The Group has issued ZAR denominated fixed rate notes (excluding the Stock Loan) with maturities ranging between 2015 and 2042 and ZAR denominated floating rate notes with maturities ranging between 2015 and 2030. As at 30 September 2014, the total amount outstanding under these fixed rate notes (at their nominal value and excluding the Stock Loan) and the floating rate notes (at their carrying value) was ZAR 93.25 billion. In addition, as at 30 September 2014, ZAR 13.3 billion was outstanding under the Issuer’s Stock Loan. The Stock Loan was registered on 1 July 1992 in the principal amount of up to ZAR 20,000,000,000 with final redemption scheduled for August 2021. Full details of the Stock Loan are set out in a Prospectus dated 1 July 1992. On 10 February 2012, the Group and US Ex-Im Bank signed a direct loan agreement of $800 million financing the Black and Veatch Kusile Project Management services contract. As at 30 September 2014, U.S.$317 million had been drawn under this facility. The Group and Crédit Agricole, as lender, signed a COFACE covered floating rate ECA facility of €64 million on 31 July 2012 for the Kusile control and instrumentation supply contract. The Group, which, as of the date of this Base Prospectus, has not yet drawn on this facility, is currently in discussions with Crédit Agricole with a view to terminating the facility, given that it has initiated discussions with the relevant supplier aimed at negotiating the terms of a consensual termination of the underlying supply contract. Crédit Agricole has indicated that, in principle, it has no objection to the proposed termination and foresees no objection on the part of COFACE. On 10 December 2012 and 25 January 2013, the Group signed two SACE S.p.A. (“SACE”) covered facilities, totalling €300 million, for the financing of the Ingula Underground Works supply contract with the CMC- Mavundla-Impregilo Joint Venture. The SACE Facility of €165 million, signed on 10 December 2012, was concluded with a syndicate of commercial banks comprising HSBC, UniCredit, KfW IPEX-Bank and BNP Paribas. The €135 million facility, signed on 25 January 2013, was concluded with Cassa Depositi e Prestiti. BNP Paribas was appointed as the Facility Agent for both facilities. The finalisation of the remaining conditions precedent as well as submission of the reimbursement request thereafter was completed on 7 June 2013. As at 30 September 2014, €38 million had been drawn under the facility, the remaining funds under these facilities are expected to be fully drawn by 31 July 2015. On 26 August 2013, the Group signed a U.S.$100 million loan facility with KfW to finance the Group’s 100 MW Concentrating Solar Power Plant. As at the date of this Base Prospectus, there have been no drawdowns under this facility. This facility contains a provision whereby, if the credit rating of the Issuer’s unsecured and unsubordinated foreign currency long-term debt falls to below an S&P rating of BBB- or a Moody’s rating of

Baa3, KfW shall request a meeting to discuss the matter and, if no resolution is reached, the Issuer shall be required to provide a guarantee within a specified timeframe. On 22 November 2013 the Group signed a €100 million long-term unsecured facility agreement with AFD. This funding forms part of the pool to finance the Concentrating Solar Plant. As at 30 September 2014 €3 million had been drawn under this facility. This facility contains a provision whereby, if the credit rating of the Issuer’s unsecured and unsubordinated foreign currency long-term debt falls to below an S&P rating of BBB- or a Moody’s rating of Baa3, AFD shall request a meeting to discuss the matter and, if no resolution is reached, the Issuer shall be required to provide a guarantee within a specified timeframe. If the Issuer fails to do so, it is required to pre-pay the loan. On 15 May 2014, the Group signed a long-term financing facility with EIB maturing in 2029. The total facility amount is €75 million. The facility is for the financing of the Concentrating Solar Power plant to be built in Upington in the Northern Cape. As at the date of this Base Prospectus, there have been no drawdowns under this facility. This facility contains a provision whereby, if any of several specified credit ratings of the Issuer fall to an S&P rating of BB+ or below, a Fitch rating of BB+ or below or a Moody’s rating of Ba1 or below, Eskom shall be required to provide a guarantee, cash collateral or other security, including a Government guarantee, within a specified timeframe. If the Issuer fails to do so, the EIB may accelerate the loan. As at 30 September 2014, the Group had outstanding R106 million of its Eskom bonds (with maturities ranging from 2015 to 2042), R110 million of its R320 million promissory notes (with maturities ranging from 2020 until 2023), R10 billion in Rand denominated commercial paper (with maturities of a maximum 12 months) and R3.707 billion in Rand denominated Eurorand zero coupon notes (with maturities ranging from 2018 until 2032). Outstanding international bonds of the Group as at 30 September 2014 totalled U.S.$2.75 billion, maturing in 2021 and 2023. Impact of Moody’s November 2014 Issuer credit rating downgrade On 7 November 2014, Moody’s downgraded the Issuer’s senior unsecured foreign currency debt rating from Baa3 (Negative outlook) to Ba1 (Stable outlook). As described above, certain of the unguaranteed credit facilities with multilateral and development banks to which the Issuer is currently a party contain provisions that require the Issuer, in the event its senior unsecured foreign currency debt rating falls to a Moody’s rating of Ba1 or below, to, within a specified timeframe, either put in place a guarantee in respect of its obligations under the relevant loan facility or prepay such loan facility. Following the November 2014 downgrade, the Issuer notified, and initiated discussions with, each of the relevant lenders in order to determine whether such lenders will ultimately require the Issuer to secure guarantees (in the form of Government-issued guarantees pursuant to the Issuer’s current guarantee framework agreement with the Government (the “Government Guarantee Framework Agreement”)), agree to waive such requirement or otherwise agree to an alternative course of action. Except for one facility (discussed below), the relevant time periods under these facilities for securing guarantees or otherwise resolving such matters extend from 4 February 2015 to 31 March 2015. With respect to one such facility (under which there are currently no amounts outstanding), the time period for putting into place a guarantee has expired, however, the lender has indicated that it does not intend to cancel such facility. To ensure that these issues do not result in defaults or cross-defaults in the Issuer’s indebtedness, the Issuer has already secured Government approval to issue guarantees pursuant to the Government Guarantee Framework Agreement if and to the extent that, upon the conclusion of the Issuer’s discussions with the relevant lenders (which remain on-going as of the date of this Base Prospectus), one or more of the lenders requires the Issuer to secure such guarantees. The Issuer intends to take all actions it can to ensure that all such guarantees are put in place within the designated timeframes or any extensions thereto granted by, or otherwise mutually agreed to with, the lenders. The remaining step to implementing such guarantees is the execution by the South African Minister of Finance and Minister of Public Enterprises of the relevant guarantee documentation pursuant to the approval that has already been granted under the Government Guarantee Framework Agreement. Contractual Obligations The table below sets out the Group’s contractual obligations, by maturity, as at 31 March 2014. For more detailed information on the Group’s contractual obligations, see Notes 14, 19, 24, 29, 30 and 44 to the Audited Annual Financial Statements for the financial year ended 31 March 2014.

Contractual maturity in More than 1 year or less 2-5 years 5 years Total (millions of Rand) Debt securities and borrowings ...... 30,722 103,573 333,381 467,676 Subordinated loan from shareholder ...... - - 146 356 146,356 Derivatives held for risk management…………………………. 2,838 2,736 (5,107) 467 Finance lease liabilities ...... 98 396 873 1,367 Trade and other payables...... 28,225 1,268 5 29,498 Financial trading liabilities ...... 4,973 387 977 6,337 Financial guarantees...... 165 - - 165 Total ...... 67,021 108,360 476,485 651,866 Market-Related Risks In the ordinary course of its business, the Group is exposed to a variety of market risks that are typical for the industry and sectors in which the Group operates. The principal market risks that affect the Group’s financial position, results of operations and prospects relate to credit risk, currency risk, interest rate risk and commodity price risk. While management has adopted a number of mitigation strategies to limit the Group’s exposure to market-related risks, there can be no assurances that any mitigation strategies will be effective or that the Group will not be materially adversely affected by such risks in future periods. Credit risk In the normal course of the Group’s business, it holds various financial instruments that expose it to the risk of loss arising from counterparty default. The risk of counterparty default is managed by setting exposure limits for each counterparty. This process is evaluated and managed by placing reliance on independent rating agencies. A credit committee, which is chaired by the finance director, reviews and approves these limits on a quarterly basis. International Swap Derivatives Association netting agreements are in place for all the Group’s major counterparties. For investments where collateral is held, these are reflected under the appropriate category of the issuer of the paper. The Group does not post cash margin to its bank counterparties. Currency risk The Group is exposed to currency risk primarily from foreign borrowings, imported components and electricity sales in foreign currency. Management follows a conservative approach to currency risk, and therefore forward exchange contracts are used to substantially hedge all known foreign exchange exposures. To take advantage of market liquidity, many of these hedges are taken for shorter maturities than the underlying exposures. These hedging contracts are then rolled over at maturity. This exposes the Group to interest rate differential and currency fluctuations, and additionally may result in mark to market payments or receipts at the maturity of each contract. The following table sets out the Group’s exposure to foreign currency risk, based on notional amounts, as at 31 March 2014.

EUR U.S.$ GBP JPY SEK AUD CHF CAD NOK (millions) Assets Trade and other receivables...... 1 - - - 3 - - - - Liabilities Debt securities issued and borrowings ...... (2,309) (4,226) - (16,425) - - - - - Trade and other payables ...... (232) (382) (60) (92) (11) - - (1) (1) Gross statement of financial position exposure ...... (2,540) (4,608) (60) (16 517) (8) - - (1) (1) Estimated forecast purchases(1) ...... (1,359) (194) (39) (998) (37) (2) (2) (2) (5) Gross exposure ...... (3,899) (4,802) (99) (17 515) (45) (2) (2) (3) (6) Derivatives held for risk management ...... 3,832 4,801 99 17 525 48 2 2 2 3 Net exposure(2) ...... (67) (1) - 10 3 - - (1) (3) ______(1) Represents future purchases contracted for. (2) Certain foreign loans are hedged applying the present value strategy.

Interest rate risk The Group is primarily exposed to upward interest rate movements on floating debt issued or downward interest rate movements on floating investments purchased, as well as interest rate risk in re-pricing forward exchange contracts. Interest rate risk is managed by the Group’s asset and liability committee on an integrated basis via a monthly process in which strategies are recommended and approved. The sensitivity of the book to interest rates is mainly managed through the use of derivatives (predominantly interest rate swaps) in response to the shape of the yield curve together with management’s best estimate of future interest rates. The Group’s policy is to restrict the maximum effective portion of the external debt (excluding the trading portfolio which is managed within the constraints of the treasury policy and control manual) exposed to an interest rate reset within the next 12 month period to 40%. Embedded Derivatives As described herein, the Group supplies electricity to electricity-intensive industries under agreements that link contract revenue to commodity prices and foreign currency rates and foreign production price indices that give rise to embedded derivatives. The value of the embedded derivatives depends, among other things, on the expected future electricity prices. The following table shows certain information as to the sensitivity of the value of embedded derivatives if one of the following inputs is changed, calculated as at 30 September 2014.

Increase in Decrease in Variable Description of change Change unrealised profit unrealised profit (%) (millions of Rand) (millions of Rand) Aluminium Increase in price 1 — (112) Aluminium Decrease in price 1 112 — Rand/U.S.$ Weakening of Rand 1 134 — Rand/U.S.$ Appreciation of Rand 1 — (139) Rand interest rates Parallel shift up 1 747 — Rand interest rates Parallel shift down 1 — (807) U.S. dollar interest rates Parallel shift up 1 (502) — U.S. dollar interest rates Parallel shift down 1 — 520 Consumer price indices Parallel shift up 1 768 — Consumer price indices Parallel shift down 1 — 720 U.S. producer price index Parallel shift up 1 187 — U.S. producer price index Parallel shift down 1 — (189) In the six months ended 30 September 2014, embedded derivatives resulted in a fair value gain of R1,621 million to the Group, highlighting the volatility associated with the fair value of these instruments. Based on the electricity price forward curve applied for (which, in turn, is based on the MYPD 3 approved tariff increase of 8% and a further adjustment for the 2015/16 financial year from 8% to 12.69%), the total valuation of embedded derivatives as at 30 September 2014, amounted to a liability of R7,711 million. Hedging policy Although the Group does not formally hedge against increases in coal prices, the nature of some of the contracts effectively provides a hedge element in relation to those contracts because the base price of the coal under those contracts is escalated by a pre-determined index and not the market. The Group is also exposed to the direct costs of procuring coal, but only in respect of the “cost-plus” contracts. See “Business—Generation Business Divisions—Generation Division—Coal—Cost-Plus Contracts (Long-term)”. The Group does not hedge against movements in the price of diesel due to the uncertainty of timing and quantity of this fuel. The Group has used hedging since 1998 to mitigate potential losses on embedded derivatives, and is currently renegotiating certain electricity supply contracts that contain embedded derivatives. The Group also hedges all foreign currency exposure over R150,000 principally through forward exchange contracts with short maturities and rollover at maturity. See “Risk Factors—Risks relating to the Group—Depreciation of the Rand or changes to exchange control policy could affect the Group’s ability to make payments in relation to U.S. dollar-denominated Notes and other indebtedness” above. The Group is exposed to price and supply risks of coal used in generation. The Group has entered into long- term supply agreements with mines to ensure continuous supply of coal. In the fixed price contracts the price

escalation is fixed, whereas the Group pays for all the operational costs of the collieries where the contracts are on a cost-plus basis. The contracts are monitored closely and managed to ensure costs are maintained within acceptable levels. All production requirements above those of the long-term contracts are supplied via short- to-medium-term contracts which usually have a transport element included in the purchase price. The Group is also exposed to price risk on the diesel that is used for the generation of electricity and long-term primary energy water supply agreements entered into with the Department of Water and Sanitation Affairs (“DWS”). The Group hedges all its base metal exposures (aluminium, copper, zinc and nickel) during the year via commodity forwards. The Group currently does not hedge its exposure to steel as no economically viable hedging instruments exist. Off Balance Sheet Arrangements The Group issues guarantees for strategic and business purposes to facilitate other business transactions. Contractual guarantees are valued by taking into account discounted future cash flows adjusted according to the probability of the occurrence of the trigger event. The resultant guarantee is raised as a liability, with the costs being charged to the income statement. The unprovided portion is disclosed as a contingent liability. As a result of using discounted cash flows, interest rate risk may arise due to the possibility of the actual yields on assets being different from the rates assumed in the discounting process. The Group has an established corporate governance structure and process for managing the risks relating to guarantees and contingent liabilities. All significant guarantees issued by the Group are approved by the Board and are managed on an ongoing basis through the quarterly treasury committee and by the Board’s risk management committee which meets every second month. The guarantees are administratively managed by the Issuer’s treasury department. Updated guarantee schedules are compiled every month, taking into account any changed risk factors, and are submitted to each of the committees for consideration and action if necessary. Risk factors and assumptions affecting probability calculations are reassessed twice a year and presented to the above committees.

• Motraco. The Group has guaranteed the long-term debt raised by Motraco, a private joint venture company set up by the Issuer, Electricidade de Moçambique and Swaziland Electricity Board. The joint venture owns transmission lines connecting the South African, Mozambican and Swaziland national grids to establish a secure source of electrical power for the Mozal aluminium smelter in Maputo, Mozambique. As at 30 September 2014, the outstanding amount of the long-term debt was U.S.$14.3 million, or approximately R162 million, compared to U.S.$17 million, or approximately R170 million, as at 30 September 2013. The guarantee would be triggered if Motraco were unable to meet its obligations under the long-term debt. The risk of default resulting from the political risk in Mozambique is mitigated through a guarantee arranged with an established international insurance company, which specialises in facilitating investments in high-risk, low-income countries. No payments have been made in terms of these guarantees since their inception in 1999. The loan of U.S.$18 million matures on 6 September 2019.

• Eskom Pension and Provident Fund. The Group has indemnified the Eskom Pension and Provident Fund against any loss resulting from negligence, dishonesty or fraud by the fund’s officers or trustees.

• Eskom Finance Company SOC Ltd (“Eskom Finance Company”). Eskom Finance Company has granted property loans (secured by mortgage bonds on the properties) to employees of the Group. Companies in the Group have issued guarantees to Eskom Finance Company to the extent to which the loan balance of employees exceed the current value of the property. As at 30 September 2014 the guaranteed amounts were R1,193 million compared to R1,142 million as at 30 September 2013. Appropriate processes are in place in Eskom Finance Company to manage the timely collection of loan payments and this is monitored by the Group.

• Eskom Enterprises. Eskom Enterprises had no performance bonds as at 30 September 2014 and 30 September 2013.

• Guarantees to SARS for customs duty. Customs duty and import VAT are normally due upon declaration of imported goods at the port of entry (harbour or airport). SARS allows the Group up to a maximum of 37 days after the declaration date before settlement of the customs duty and import

VAT. SARS requires the Group to provide a bank guarantee to secure the debt when it becomes due. The total contingent liability amounted to R183 million as at 30 September 2014, which had remained the same since 31 March 2014.

• Legal claims. Legal claims are in process against members of the Group as result of contractual disputes with various procurement parties. The contingent liability amounted to R34 million as at 30 September 2014, and had amounted to R50 million at 31 March 2014. For more detailed information on the Group’s off-balance sheet arrangements, see Note 44 to the Audited Consolidated Financial Statements. Critical Accounting Estimates and Judgments The Group prepares its Consolidated Financial Statements in accordance with IFRS. Certain amounts included in or affecting the financial statements incorporated by reference in this Base Prospectus and related disclosure must be estimated, requiring management to make assumptions with respect to values or conditions, which cannot be known with certainty at the time the financial statements are prepared. Management believes that the accounting estimates and judgments set out below comprise the most important “critical accounting estimates and judgments” for the Group. An “accounting estimate and judgment” is one which is both important to the portrayal of a company’s financial condition and results of operations and requires management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. Management evaluates such policies on an ongoing basis, based upon historical results and experience, consultation with experts and other methods that management considers reasonable in the particular circumstances under which the judgments and estimates are made, as well as management’s forecasts as to the manner in which such circumstances may change in the future. Valuation of electricity generation, transmission and distribution assets The impact of asset values on regulated revenues is due to two cost elements being affected by this approach, namely depreciation cost and return on assets. The approval by the Government in November 2008 of the EPP, which requires that electricity revenues be based on the replacement values of existing assets, the subsequent acknowledgement by NERSA that future electricity tariffs will be based on this approach, and the commencement by NERSA of a five year period of implementation (with MYPD 2 representing the first three years thereof), created the opportunity for the Group to reconsider the asset valuation approach for purposes of financial accounting. In the past, any revaluation to replacement values might have been largely negated by a fair value adjustment referenced to revenues based on historic costs, thus effectively adjusting asset values back to depreciated historic costs. Given, however, that future revenue assumptions will now be based on a regulatory methodology that references replacement values, a revaluation for financial accounting purposes has, since 1 April 2010, been reflective of the future anticipated revenue stream and will thus not largely be negated through fair value adjustments. The main impact on the balance sheet is on asset values. The adjustment is also reflected in equity in the form of a revaluation reserve, i.e. equity increases with the amount by which the assets values increase. Due to the significant amounts involved, this will materially change the balance sheet and all related financial metrics. Even though the income statement will reflect the higher depreciation charge, by the end of the allowed five year implementation period, the achieved pre-tax return on assets will reflect the Group’s pre-tax real weighted average cost of capital (presently estimated by NERSA at 8.16%). Hence from that point onwards, the Group’s revenues will be such that, after deducting the adjusted “replacement” depreciation, the percentage return on the re-valued assets will approximate the pre-tax real weighted average cost of capital. Useful life of generating plants Property, plant and equipment is presently valued (see discussion above) at historical cost using a component approach, less depreciation or at the recoverable amount whenever impairment has taken place. Depreciation is calculated using the straight line method based on the estimated useful life, taking into account any residual value. The assets’ residual values and useful lives are based on the Group’s best estimates and adjusted, if appropriate, at each balance sheet date.

Historically, the Group’s management has assumed a useful life of 35 years in relation to its generating plants. During the 2007 financial year, the Issuer’s management reassessed the estimates in respect of the useful life of certain plants from 35 to 50 years. Given the significance of property, plant and equipment to the Group’s financial statements, any changes to the useful life or residual values may have a material impact on the annual depreciation expense and materially impact on the Group’s results of operations and financial condition. (a) Embedded derivatives The Group is party to a number of agreements to supply electricity to electricity-intensive industries under which the revenue from these contracts is linked to commodity prices and foreign currency rates (mainly U.S. dollars) or foreign production price indices that give rise to embedded derivatives. See “—Factors Affecting Results of Operations—Embedded Derivatives”. Subsidiaries of Eskom Enterprises also entered into customised pricing agreements where the revenue is based on the U.S. dollar, foreign production price indices and foreign interest rates that give rise to embedded derivatives. The value of the embedded derivatives which involve a foreign currency is first determined by calculating the future cash flows and then discounting the cash flows by using the relevant interest rate curve. Thereafter, the net present value of the cash flows is converted at the relevant Rand/foreign currency spot rate to the reporting currency. The fair value of the embedded derivative is determined on the basis of its terms and conditions. If this is not possible, the value of the embedded derivative is determined by fair valuing the whole contract and deducting from it the fair value of the host contract. Where there is no active market for the embedded derivatives, valuation techniques are used to ascertain their fair values. Financial models are developed which incorporate valuation methods, formulae and assumptions. The valuation methods include:

• Swaps–electricity tariff is swapped for a commodity-linked tariff (e.g. aluminium price) in a foreign currency;

• Foreign Exchange forwards–electricity tariff, other revenue or expenditure is based on a foreign currency (i.e. U.S. dollars); or

• Multi-period options–electricity tariff and other related revenue are based on a foreign currency denominated and production price indices (i.e. U.S. dollars and U.S. Producer Price Index). The Monte Carlo simulation is used to value the options. The input variables (most of which are obtainable from market sources) to the valuation models include:

• commodity forward price curves;

• foreign exchange rates;

• interest rates curves;

• forecasted sales volumes;

• consumer and production price indices; and

• forward electricity prices. Market information was not available for every input for the whole period of the contracts and where such information is not available, the relevant input is based on management estimates. For more information on the critical accounting estimates and judgments in relation to embedded derivatives, see Note 4 of the Consolidated Financial Statements. (b) Post-employment medical benefits The Group has created a provision for the cost of post-employment medical benefits liability based on an estimated 8.5% long-term medical aid inflation rate. The carrying amount of the provision is R11,470 million in the six months ended 30 September 2014 compared to R10,234 million as at 31 March 2014.

(c) Occasional and service leave The Group has recorded a provision for the cost of occasional leave based on an assumption that 4% of the leave is utilised, which is in line with current experience. If the rate at which leave is taken increased to 8%, then the liability would have increased by R60 million in the financial year ended 31 March 2014, and by an estimated R53 million in financial year ended 31 March 2013. (d) Decommissioning, mine closure and rehabilitation For the six months ended 30 September 2014, the Group has recorded a provision for the cost of decommissioning, mine closure and rehabilitation based on a real discount rate of 4.8% (compared to 5% for the financial year ended 31 March 2014 and 4.6% for the financial year ended 31 March 2013). Impairments and valuation of assets Assets that have an indefinite useful life, for example land, are not subject to amortisation and are tested annually for impairment. Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units). Non-financial assets other than goodwill that suffered impairments are reviewed for possible reversal of the impairment at each reporting date. Equity portion of subordinated loan from shareholder The value of the equity portion of the R60 billion subordinated loan from the Government is the difference between the amount advanced and the calculated loan value on the day the tranches are drawn down. The loan value is calculated using Eskom’s long-term financial plan to forecast the leverage ratio and the interest cover to determine in which years interest will be payable over the period of the loan. These expected interest flows and the capital redemptions are discounted at the effective rate which was calculated at the inception of each tranche received to determine the loan amounts. Once the equity portion of a tranche is recorded it does not change. New Accounting Standards Recently Adopted Accounting Pronouncements There were no, interpretations and amendments to existing standards that were effective and applicable to the group for the six months ended 30 September 2014, which had any significant impact on the Group financial statements.

BUSINESS The following section should be read together with the Consolidated Financial Statements and the related notes thereto which are incorporated by reference in this Base Prospectus. Certain information contained in this section and elsewhere in this Base Prospectus includes forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” and “Risk Factors” for a discussion of the important factors that could cause actual results to differ materially from the results described or implied by the forward-looking statements contained in this Base Prospectus. Overview The Issuer is South Africa’s national electricity utility, engaged in the generation, transmission, distribution and retailing of electricity to industrial, mining, commercial, agricultural and residential customers, as well as to municipalities and other redistributors. The Government, through the Department of Public Enterprises, is the Issuer’s sole shareholder. As a vertically-integrated company, with responsibilities that extend from procuring coal to distributing electricity generated from that coal, the Group has the ability to be innovative and efficient across the value chain, following an integrated approach to the generation, transmission and distribution of electricity. The Group supplies approximately 95% of South Africa’s electricity (with the remainder being produced by local authorities and certain large customers for their own consumption) and approximately 40% of the total electricity consumed on the African continent. The Group directly provides electricity to approximately 45% of all end-users in South Africa and to redistributors (including municipalities) who, in turn, resell and supply the other 55%. The Group currently sells directly to approximately 3,000 industrial, 1,000 mining, 50,000 commercial, 83,000 agricultural and more than five million residential customers, 40% of whom are in rural areas. The figure for residential customers includes prepaid customers. The Issuer was established in South Africa in 1923 as the Electricity Supply Commission and was subsequently converted into a public limited liability company, wholly-owned by the Government, in July 2002. With over 90 years of operational experience in Southern Africa, the Group believes its resilience to the broad economic and fiscal adversity of recent years is a strength that will help it progress in the future. As at 30 September 2014 and 31 March 2014, the Group had a total nominal capacity of 41,995 MW, while as at 31 March 2013 the Group had a total nominal capacity of 41,919 MW. As at 30 September 2014, the Group’s transmission network consisted of approximately 30,068 km of transmission lines of voltages ranging between 132 to 765 kV (compared to 29,924 km as at 31 March 2014) and a network of 159 substations (compared to 157 as at 31 March 2014). Electricity distribution is carried out by the Group and approximately 800 redistributors that purchase the electricity from the Group and, in a few cases, supplement it from their own power stations. For the six months ended 30 September 2014, the Group had total electricity sales of 109,168 GWh, representing a decrease of 1.3% compared to 110,659 GWh for the six months ended 30 September 2013. For the financial year ended 31 March 2014, the Group had total electricity sales of 217,903 GWh, representing an increase of 0.6% compared to 216,561 GWh for the financial year ended 31 March 2013. For the six months ended 30 September 2014, the Group had revenues and profit before tax of R81,898 million and R12,996 million, respectively, and as at 30 September 2014, the Group had total assets of R534,334 million. For the financial year ended 31 March 2014, the Group had revenues and profit before tax of R139,506 million and R9,163 million, respectively, and as at 31 March 2014, the Group had total assets of R504,993 million. Most of the Group’s operating activities, as well as related revenues and resulting tariffs, are subject to regulation by NERSA. In addition, much of the Group’s strategy and many of its future prospects will ultimately have to be aligned with the Department of Energy’s IRP, which sets out a long-term electricity plan for South Africa, and the Department of Energy’s IEP, which is broadly designed to guide future South African energy infrastructure investment and policy for the 2010 to 2050 period. The IEP was published in June 2013 for public consultation, and a final report is expected to be published in March 2015. The IRP, which was promulgated in 2011 and covered the 2010 to 2030 period, is currently in the process of being revised to reflect the continuing evolution of the Government’s long-term electricity strategy. It remains unclear when the updated IRP will be finalised and approved by the Cabinet. While a draft updated version of the IRP was published in November 2013 for public comment, it is expected that the final revised IRP will

only be formally approved after the Government has approved the over-arching IEP, which is expected to inform the contents of the revised IRP. The draft IRP update is not an official update to the promulgated IRP, but the update has, however, revised scenarios based on changes to South Africa’s economic outlook, including addressing the effect of slowing economic growth on projected electricity demand (anticipating that less capacity will be required by 2030). However, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. Regardless, the IRP is expected to have a significant impact on the Group’s operations. The Group holds separate licences for its generation, transmission and electricity distribution activities, with revenues being regulated for each of these licensed activities. The Group allocates its revenues internally across these segments, using a cost-of-service-based methodology with incentives for cost savings and efficient and prudent procurement by the Issuer. This methodology also provides for SQIs which are used as a measure to encourage the Group to improve its reliability of supply. The objective of SQIs is to ensure that the provision of good quality supply is rewarded and poor quality of supply is penalised. Each segment’s revenue is calculated separately with the overall price and revenue determined at the distribution level and communicated as such to customers. See “Overview of South Africa and the South African Electricity Industry—Regulation of the South African Electricity Industry” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Factors Affecting Results of Operations—Pricing”. In June 2014, following the local and foreign currency downgrade of South Africa, the Issuer’s credit ratings were revised by two credit rating agencies. Fitch revised Eskom’s ratings outlook from Stable to Negative while S&P downgraded the Issuer to BBB with a Negative CreditWatch. In October 2014, Fitch affirmed the Issuer’s long-term local currency credit rating with a Negative outlook. However, recently, on 7 November 2014, Moody’s downgraded the Issuer’s senior unsecured rating from Baa3 (Negative outlook) to Ba1 (Stable outlook). Following this announcement, on 11 November 2014, S&P affirmed its BBB- credit rating of Eskom and removed it from CreditWatch. The Issuer’s current local and foreign currency ratings are as follows:

Ratings and Outlook S&P Foreign currency ...... BBB- Negative(1) Local currency ...... BBB- Negative(1) Moody’s Foreign currency ...... Ba1 Stable(2) Local currency ...... Ba1 Stable(2) Fitch Local currency ...... BBB+ Negative (3) ______(1) Last changed on 11 November 2014 (2) Last changed on 7 November 2014 (3) Last changed on 28 October 2014

The Issuer’s senior unsecured bond rating is primarily driven by Moody’s assumption of a high level of potential Government support to the Issuer in the case of financial distress. Given Eskom’s strong linkage with the Government and its high sensitivity to changes in the sovereign credit profile, the one-notch downgrade (from investment grade to non-investment grade) reflects the downgrade of South Africa’s credit rating which was announced on 6 November 2014. S&P is, however, of the view that the Government Finance Support Package that was announced in its 22 October 2014 MTBPS, will support the liquidity and credit metrics of the Issuer in the near term, further demonstrating the extremely high likelihood of Government support to the Issuer. The Negative outlook announced by the agency reflects S&P’s views in relation to the execution risk and additional actions required in stabilising the operating performance of the Issuer. Fitch, on the other hand, affirmed the Issuer’s credit rating based on the availability of R350 billion in Government Guarantees, the planned equity injection, the Issuer’s cost cutting and efficiency measures as well as the moderately supportive new tariff determination. The Issuer is registered in South Africa and was incorporated on 1 July 2002 with registered number 2002/015527/30. Its registered office is at Megawatt Park, 2 Maxwell Drive, Sunninghill, Sandton, 2157, South Africa and its telephone number is +27 11 800 8111.

Relationship with the Government The Government is the sole shareholder of the Issuer. The shareholder representative is the Minister of Public Enterprises. The Government, through the Department of Energy, guides energy policy for the country. In line with the stated policy objectives of the Government, NERSA determines the regulatory framework for the electricity industry, including the tariffs the Group may charge to its customers. As a state-owned entity, the Group is also regulated by the PFMA. Under the National Treasury regulations issued in accordance with the PFMA, the Group must, in consultation with the Minister of Public Enterprises, annually determine appropriate levels for several key performance indicators. The key performance indicators for each financial year are annexed to the Shareholder’s Compact which is agreed annually between the Group and the Government. The Group submits performance reports to the government on a quarterly basis and it reports publicly on its performance in each of its annual reports. The Shareholder’s Compact also sets out certain agreed principles, which focus on the business, economic, social and environmental factors affecting the Group and its operations. The Shareholder’s Compact is not intended to interfere with the normal principles of company law. The Board is entirely responsible for ensuring that proper internal controls are in place and that the Group is managed effectively. The Shareholder’s Compact promotes good governance practices in the Group, setting out the respective roles and responsibilities of the Board and the shareholder and ensuring agreement on expectations for the Group. The Group attained 16 of the 25 key performance indicators set out in the Shareholder’s Compact for the financial year ended 31 March 2014. For the six months ended 30 September 2014, the Group targeted to achieve 22 of the 32 key performance indicators for the financial year ending 31 March 2015. See “—Shareholder’s Compact—Group Performance for the six months ended 30 September 2014 and for the financial year ended 31 March 2014”. Among these indicators, the most recent Shareholder’s Compact (for the six months ended 30 September 2014) includes a target for achieving a “sustainable asset base whilst ensuring security of supply”. This is as a result of a change in focus in the Group’s generation sustainability strategy. As of the date hereof, the Group’s primary focus is no longer on “keeping the lights on”, but rather on continuing to make every effort to ensure adequate supply, but not at the cost of plant or financial sustainability or by deferring required maintenance. Previously, as set out in the Shareholder’s Compact for the financial year ended 31 March 2014, the Group’s primary focus was that of “keeping the lights on” and avoiding rotational load-shedding. Rotational load-shedding is the process whereby power supply is restricted on a geographical basis, in order to prevent a total blackout during periods where demand exceeds supply. To achieve this target, the Group until recently followed a strategy of deferring planned maintenance outages to ensure sufficient capacity, and thereby “keep the lights on”. As a result, the Group was generally successful in avoiding load-shedding from 2008 until 2014. However, this strategy significantly compromised the health of the Group’s generation and transmission fleet, the performance of which has become increasingly volatile. The deterioration in plant health that resulted from the Group’s “keep the lights on” strategy is evidenced by the Group’s current UCLF and EAF percentages and the poor environmental performance demonstrated by the relative particulate emissions and water usage figures for the financial year ended 31 March 2014. For the six months ended 30 September 2014, despite a change in focus and the resumption of load-shedding in 2014, both the Group’s UCLF percentage and particulate emissions deteriorated further, although the Group believes that its annual performance (up to 31 March 2015) will meet the required targets. EAF and water usage, on the other hand, are both expected to underperform against the 31 March 2015 annual estimated targets. In addition, the Group’s target for generation new build capacity in the financial year ended 31 March 2014 was not met due to poor contractor performance, extreme weather conditions, equipment quality issues, environmental permits not being granted and challenges to secure land. Similarly, as at September 2014, generation capacity installed was zero and is expected not to meet the 2014/15 annual target of 433 MW. Demand savings is also expected to underperform given the Group’s actual performance of only 32 MW for the first six months of its 2014/15 financial year against the annual target of 246 MW. Other key performance indicators that are expected to fail to meet the projected targets for the 2014/15 financial year include, as at 30 September 2014, the Group’s interest cover-ratio, debt/equity-ratio and FFO as a percentage of total debt along with certain procurement spend and the gender equity percentage.

The Group’s performance of its key performance indicators for the six months ended 30 September 2014 and for the financial year ended 31 March 2014 is set out below. The following key applies to the key performance indicators for 30 September 2014 and 31 March 2014, respectively:

♦ Performance for the year ending 31 March 2015 is projected to meet target

◊ Performance for the year ending 31 March 2015 is projected not to meet target

● Performance for the year ending 31 March 2015 is projected not to meet target by a small margin

Key performance indicators that exceeded the 31 March 2014 target

Target Year-end Target for 31 Target will 30 for 31 March be met? September March 31 March 2015 2014 result 2014 2014 result Key performance indicator Focus on safety Employee lost-time incident rate (LTIR), index ...... 0.35 ♦ 0.32 0.36 0.31 Sustainable asset base whilst ensuring security of supply Maintenance backlog, (number)(1) ...... 1 ♦ 3 - 5 Integrated demand management savings, (MW) ...... 246.0 ◊ 32.0 379.0 409.6 Internal energy efficiency, (GWh) ...... 10.0 ♦ 0 15.0 19.4 Put Customer at the centre Eskom KeyCare, index ...... 102.0 ♦ 109.6 N/A 108.7 Enhanced MaxiCare, index ...... 96.0 ♦ 97.2 N/A 92.7 Improve Operations Normal unplanned capability loss factor (UCLF), (%)(2) ...... 13.00 ♦ 13.30 <10.00 12.61 Energy availability factor (EAF), (%) ...... 80.00 ◊ 76.77 80.00 75.13 System average interruption duration index (SAIFI), events 22.0 ♦ 20.5 N/A 20.2 System average interruption duration index (SAIDI)(3), hours ...... 43.0 ♦ 37.7 45 37.0 Total system minutes lost for events <1 minute, (minutes) ...... 3.80 ♦ 0.62 3.40 3.05 Deliver capital expansion Generation capacity installed: first synchronisation, units(3) 1 ♦ 0 N/A - Generation capacity installed and commissioned, (MW)(4) ...... 433 ◊ 0 100 120 Transmission lines installed (km)(5) ...... 315.1 ♦ 161.8 770.0 810.9 Transmission capacity installed and commissioned (MVA) ...... 2090 ♦ 90 3790 3,790 Reduce Environmental footprint in existing fleet Relative particulate emissions, (kg/MWh) ...... 0.35 ♦ 0.33 0.36 0.35 Water usage per kWh sent out(6), (L/kWh) ...... 1.39 ● 1.40 1.39 1.35 Implementing coal haulage and the road-to-rail migration plan

Migration of Coal delivery from road to rail (additional tonnage transported on rail),(Mt) ...... 11.50 ♦ 6.57 11.48 11.60 Ensure financial sustainability(7) Cost of electricity (excluding depreciation), R/MWh ...... 532.63 ◊ 560.79 453.40 541.92 Interest cover, ratio ...... 0.69 ◊ 1.29 1.18 0.65 Debt/ equity (including long-term provisions), ratio ...... 2.48 ◊ 2.25 2.17 2.21 Free funds from operations as a (%) of total debt, (%) ...... 7.63 ◊ 5.43 9.11 9.21 Maximise socio –economic contribution: Procurement equity Local content contracted (new build), (%) ...... 65.00 ◊ 56.88 52.0 54.60 Percentage of Broad-based black economic empowerment spend, (%) of ♦ TMPS ...... 75.00 89.47 75 93.90 Procurement spend with black youth-owned suppliers, (%) of TMPS(8) 2.00 ◊ 0.78 1.0 1.0 Maximise socio –economic contribution: Employment equity Disability equity in total workforce, (%) ...... 2.50 ♦ 3.06 30.0 2.99 Racial equity in senior management, % of black employees, (%) ...... 60.00 ♦ 61.06 61.0 59.50 Racial equity in professionals and middle management, (%) of black employees (%) ...... 70.00 ♦ 72.04 71 71.20 Gender equity in senior management, % of female employees, (%) ..... 31.00 ● 30.18 30.0 28.90 Gender equity in professionals and middle management, (%) female employees ...... 37.00 ◊ 35.89 36.0 35.80 Build Strong Skills Training spend as a % of gross employee benefit costs(9) (%) ...... 5.00 ♦ 6.31 5.00 7.87 Learner through or qualifying, number(10) ...... 1200 ♦ 175 N/A -

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(1) The maintenance backlog in the Shareholder’s Compact is based on the 36 outages that informed the 2011 PFMA application, which have since been reduced to 35, due to the duplication of Matla Unit 3. Of the 35 outages, five remained at 31 March 2014. As the KPI definition has changed in the current year, the comparative as at 31 March 2014 has been restated, while previous periods are marked as not applicable. The KPI reported in 2013/14 was tracking the nine outages that had been approved by the Technical Governance Committee, all nine of which were completed. (2) The Shareholder’s Compact UCLF KPI refers to underlying UCLF, which is the difference between normal and constrained UCLF, and represents the UCLF that is still within Generation’s control. Constrained UCLF results from emissions and short-term related UCLF due to system constraints to meet the “Keeping the lights on” objective. (3) Only Medupi Unit 6 is contracted for first synchronisation in the 2014/15 financial year. Eskom and the DPE will, in subsequent years, contract on first synchronisation for Unit 5 of Medupi and Units 1 and 2 of Kusile. The subsequent units of Medupi and Kusile can then be contracted on capacity installed and commissioned (4) Comprised of the commissioning of the Sere wind farm (100 MW) in late 2014 and one unit of Ingula (333 MW). (5) During the 2013/14 financial year, Eskom exceeded the year-end target of 770km, by achieving 810.9km. Due to the finite length of transmission lines, the additional kilometres (40.9km) were deducted from the 2014/15 target of 356km, to determine the revised target of 315.1km. (6) The volume of water consumed per unit of generated power from commissioned power stations. The financial ratios have been recalculated based on the OCGT costs allowed by NERSA . The revised targets have been approved as an addendum to the approved 2014/15 Shareholder’s Compact. (7) The addendum also included additional Competitive Supplier Development Programme (CSDP) KPIs, which were added to the Shareholder’s Compact at the shareholder’s request (8) This is a new measure, effective from 1 April 2013. (9) The learner throughput or qualifying target includes only engineer (298), technician (282) and artisan (529) learners. The other learners are not included in the 1,200 target. The target is based on learners in their final year of study, less those who fail and those who leave the pipeline.

In addition to the Government’s direct and indirect oversight of the Issuer (as its sole shareholder), the Group is also subject to the oversight of the Government as policy maker for South Africa, acting through the Department of Energy. The Group is also overseen, in respect of economic regulation of electricity supply, by NERSA, whose board members are appointed by the Minister of Energy. NERSA has national jurisdiction over generators, transmitters and distributors of electricity and exercises its powers through the licensing of electricity generation, transmission, distribution and trading activities. NERSA, established in terms of the National Energy Regulator Act of 2004, is mandated to regulate South Africa’s electricity, piped gas and petroleum industries. NERSA’s functions include, among other functions, issuing licenses and setting and approving tariffs, including that of the Group. The MYPD methodology has been developed by NERSA for the regulation of the Group’s required revenues. Since the promulgation of the IRP in 2011 there have been a number of developments in the South African Energy Sector which have changed the landscape for electricity demand for the period 2010 to 2030. The IRP is currently in the process of being revised to reflect the continuing evolution of the Government’s long-term electricity strategy. It remains unclear when the updated IRP will be finalised and approved by the Cabinet. While a draft updated version of the IRP was published in November 2013 for public comment, it is expected that the final revised IRP will only be formally approved after the Government has approved the over-arching IEP, which is expected to inform the contents of the revised IRP. The IRP, which remains the official Government plan for new generation capacity, however, until the updated IRP is in final approved form, is intended to provide insight into the critical changes that are being considered in the interim. A revised economic and electricity outlook has also been developed which will be taken into consideration in the updated IRP as electricity demand in 2030 is now projected to be lower by 6,600 MW. The IRP identifies the preferred generation technology (and assumed energy efficiency demand side management) required to meet expected demand growth up to 2030. The policy adjusted IRP incorporated a number of Government objectives, including affordable electricity, carbon mitigation, reduced water consumption, localisation and regional development, producing a balanced strategy towards diversified electricity generation sources and gradual decarbonisation of the electricity sector in South Africa. See “Overview of South Africa and the South African Electricity Industry”. The Government has underlined the Group’s strategic role in the South African electricity sector and its importance in delivering the Government’s social and economic policy objectives. In 2004, the Minister of Public Enterprises launched a new strategy for state-owned enterprises to implement the Government’s policy of economic growth, job creation and a stable economy through increased investment in infrastructure. The Group’s contribution is through the continuous supply of electricity, including building new electricity infrastructure. See “—Finance—Capacity Expansion Programme”. The Group is also responsible for implementing the Electrification Programme to provide electricity access in its licensed area of supply. Since the start of the Electrification Programme in 1991 and as at 31 March 2014, over 4.5 million additional households have been provided with electricity. A total of 57,534 electricity connections were installed during the six months ended 30 September 2014. The Group’s business procurement and capital investment is also designed to maximise the inclusion and growth of small, medium and micro enterprises, black-women-owned enterprises, black economic

empowerment (“BEE”), and skills development, with the goal of ultimately leading to job creation, poverty alleviation and skills development. The Group is regulated by means of environmental authorisations, licences and permits issued by the Department of Environmental Affairs (the “DEA”), the DWS and local and provincial air quality licensing authorities. These include licences and permits for commencement of the construction of power stations and major power lines and substations, waste (including ash dams and dumps), emissions and integrated water use licences. Strategy The Group’s strategy is focused on providing sustainable electricity solutions to grow the South African economy and improve the quality of life of people in South Africa and the region. To deliver this strategy, the Group originally undertook a strategic review in October 2010, and again in 2012, to consider its strategic direction up to 2017/18, which helped identify the eight strategic imperatives set out below. Given the outcome of the MYPD 3 determination and Shareholder’s Compact, the Group has turned its focus toward sustainability of its asset base and security of supply. Becoming a high performing organisation The effective management of the Group’s total system capacity as well as availability and reliability planning is critical to the quality and continuity of sustainable energy supply. The Group is seeking to transform its business performance by improving its operational standards across the board, concentrating in particular on improving plant availability and reliability, energy efficiency and primary energy availability, as well as maintenance and refurbishment, in order to ensure maximum capacity. The Group hopes to achieve these objectives through its initiatives such as the 80:10:10 Principle and BPP, which are key priorities. See “Risk Factors—Risks relating to the Group—Urgent maintenance is needed on the Group’s generation fleet and any further deferral of maintenance work or failure to properly implement its sustainability strategy may materially adversely affect its business operations” and “—Leading and partnering to keep the lights while ensuring the integrity of the Group’s generation and transmission infrastructure”. In addition, the Group continues to focus and improve its occupational health and safety standards and is committed to becoming a customer centric organisation, to ensure that its customers are fully satisfied and serviced and building strong employee skills to ensure a sustainable business. By striving for this imperative the Group aims to achieve long-term sustainability. Leading and partnering to keep the lights on while ensuring the integrity of the Group’s generation transmission infrastructure In 2005, the Group embarked on a capacity expansion programme, the largest in its history, which will increase its generation capacity by 17.4 GW to meet increasing energy demand and diversify its energy sources, and which between its inception and 30 September 2014 had cost approximately R251 billion (excluding capitalised borrowing costs). As at 30 September 2014, the Group had installed 6,137 MW of generation capacity since 2005. See “—Finance—Capacity Expansion Programme” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Factors Affecting Results of Operations—Capacity Expansion Programme”. In carrying out the committed capacity expansion programme, the Group is seeking to build new facilities, on time and on budget, to deliver capacity expansion and to continue to manage supply-and-demand constraints, decreasing its maintenance back-log and running existing plants at optimal levels. While the Group’s commitment to “to keep the lights on” was generally successful in avoiding load-shedding from 2008 until 2014, it significantly compromised the health of the Group’s generation and transmission fleet, the performance of which has become increasingly volatile. In line with its strategy, the Group deferred several planned maintenance outages to ensure that energy capacity was maximised to meet national electricity demand. However, in light of increased unplanned outages and declining reserve margins, the Group recognised that this strategy was not sustainable and that there was a need for a generation sustainability maintenance strategy. Accordingly, in April 2013, the Board approved the 80:10:10 Principle, which is a five-year plan for generation sustainability. As a consequence, the Group’s strategy to “keep the lights on” has since been aligned with the objectives of the 80:10:10 Principle. The 80:10:10 Principle has as its main objective the sustainability of the Group’s fleet in the long-term and it is envisaged that the Group’s

generating fleet should, on average, have an EAF of 80%, leaving 10% for planned maintenance outages and 10% for unplanned outages. As a result of equipment failure, system and primary energy constraints, the Group resumed load-shedding, as a last resort, on a more regular basis in 2014. In the financial year ending 31 March 2015, the Group will target a 10% planned capacity loss factor (“PCLF”) of which 8% will be used to create a maintenance schedule with limited flexibility and the remaining 2% will be utilised for short-term maintenance including weekend maintenance. Overall, the Group’s target for its UCLF and outage capability loss factor (“OCLF”) for the financial year ending 31 March 2015 is a maximum of 10%. As UCLF and OCLF improve over time and outage execution capability increases, this will create room for the PCLF level to improve. The Group believes that this will ensure a sustainable generation capacity. The South African electricity supply-and-demand balance will remain tight in the near future. While it will require substantial effort from many stakeholders to overcome South Africa’s current electricity challenges, the Group is determined to prevent load-shedding by playing a leading role and actively partnering with all key stakeholders, including all people of South Africa, in implementing a comprehensive supply-and-demand management strategy. A major focus will be on creating an enabling environment for other players to participate in the sector. However, there are still significant risks which need to be managed. See “Risk Factors—Risks relating to the Group—The Group’s electricity generation capacity is affected by a low operating reserve margin, which strains its ageing infrastructure, increases costs and jeopardises its ability to consistently meet the electricity supply requirements of its customer”. The Group’s outlook up to 2018, based upon a moderate demand scenario, suggests a high likelihood that there will be an energy supply shortfall over this period. The supply-and-demand balance continues to be tight as additional supply options are relatively limited until new build capacity starts to come on stream. While lower-than-expected electricity demand due to a weak economy and struggling commodity market contributed to the Group being able to keep the lights on in 2012/13 and for most of 2013/14, the Group forecasts a supply shortfall of 12,000 GWh of energy in 2015 and 10,000 GWh of energy in 2016. The Group implemented certain demand-and-supply initiatives (for example, the 49M Campaign which is discussed in “Business—Generation Business Divisions—Integrated Demand Management Division”) to assist in dealing with this shortfall and a “safety net” of demand response initiatives and energy conservation programmes is being developed, which will require the participation of stakeholders. “Keep the lights on” is a collective term used by the Group to refer to the complex interplay between the ability of its demand-management initiatives to reduce electricity usage while, at the same time, widening the demand-and-supply margin sufficiently in order to do critical plant maintenance and thereby ensuring sustainable generation in the future. While, as discussed above, the Group’s pursuit of this mandate at the expense of undertaking much-needed maintenance has adversely impacted the health of the Group’s fleet in recent years, this strategic imperative, coupled with a renewed recognition that the Group must all-the-while endeavour to ensure the operational integrity of its infrastructure, remains an over-arching long-term objective for the Group. Reducing the Group’s carbon footprint and pursuing low carbon growth opportunities In providing electricity to support South Africa’s social and economic development, the Group is committed to an environmental duty of care. See “—Other Business Imperatives—Climate Change”. In 2010, and again in 2012, the Group undertook a strategic review of its business and identified key initiatives to achieve its carbon footprint reduction targets (including, its transitioning to a cleaner energy mix, reducing emissions and water use and ensuring full compliance with environmental legislation) in the short, medium and long-term. However, as a result of ongoing capacity constraints, the Group has delayed critical maintenance work on its generation fleet in the last few years, including projects that would improve particulate emissions and water usage at power stations. Other possible projects to support this strategic imperative include the possible conversion of peaking plants to use natural gas, developing wind and concentrated solar plants and contracting lower carbon capacity from the region. The Group’s aim is to become the partner of choice for developing and delivering sustainable electricity solutions for South Africa and the SADC, including low carbon growth opportunities. The Group has obtained new AELs for most of its power stations. Some of the units at the eight power stations that have been issued the new AELs are, however, unable to comply (or periodically fail to comply) with the emissions limits set by the AELs, mainly due to the older technology and systems employed at such stations. While a process is under way to appeal, review or amend the newly issued AELs, it may take up to a year to obtain a final response. In the meantime, every effort will be made by the Group to comply with the

conditions of the new licences. However, since new limits do not always allow the Group’s power stations, such as Kriel, which was recently denied a request to increase its particulate emissions limit and allow for a grace period for exceeding such limit, to continuously operate at their full rated power, in certain instances load losses during off peak time will be necessary. In turn, this will increase the Group’s operating costs if other alternatives, such as OCGTs, have to be used to supplement such reduction in load. Minimum emission standards are effective as from 2015. The Group is unable to meet the emissions standards at all sites within the required timelines, and has submitted an application for a five-year postponement for some power stations in terms of section 6 of the Listed Activities and Associated Minimum Emission Standards. Securing the Group’s future resource requirements The committed capacity expansion programme imposes significant funding of approximately R348 billion (excluding capitalised borrowing costs) and resource requirements on the Group. The Group needs to secure land and primary energy sources for its assets to operate, including coal, liquid fuel, uranium and water. In particular, securing a continuous supply of good quality coal for its coal-fired stations is an increasing challenge for the Group. In the financial year ended 31 March 2014, the Group made significant progress in the execution of coal supply strategy. As at 30 September 2014, four medium-term contracts have been signed for coal supply to the Kusile power station during the commissioning phase. The conclusion of long- term coal and limestone supply agreements for Kusile is yet to be finalised. Appropriate skills and information management systems are also vital to ensure the sustainability of the Group’s business and success of the committed capacity expansion programme. Key factors affecting funding and resourcing requirements and consequently the Group’s ability to achieve the objectives of its committed capacity expansion programme include obtaining fully cost-reflective tariffs from NERSA in the future, as well as revenue management and efficiency initiatives. Ensuring the financial sustainability of the Group Sustainability shapes the way in which the Group conducts business and provides the context for its developmental initiatives. The Group will continue to strive to improve its sustainability in the short, medium and long-term and in all its areas of its business. To achieve the necessary balance requires trade-offs between various sustainability criteria; for example, financial health compared to the costs of mitigating the effects of climate change. This should, however, be interpreted against the background of economic regulation to which the Group is subject, including the Electricity Regulation Act, which requires NERSA to set revenues for electricity producers on a cost-reflective basis. Therefore, provided that expenditure and investment are demonstrated to be efficient and prudent in terms of prevailing Government policies and legislation, the Group should recover costs through regulated revenues. Obtaining cost-reflective tariffs should enable the Group to achieve a standalone investment grade rating which will allow it to obtain funding for its capacity expansion programme at a reasonable cost. The MYPD 3 determination and Moody’s November 2014 downgrade of the Group’s credit rating have, however, significantly delayed this possibility, and the Group will continue to rely on Government support for a number of years. For the short and medium term, the Group’s liquidity position remains stable (in particular, since the Government has pledged its further support through the Government Finance Support Package in the third quarter of 2014), however, the challenge will be to secure affordable funding in the longer term, an objective which will be shaped and which the Group will need to implement, among other things, against the framework set by the IRP. The Group’s drive for sustainable development is inherent in the long-term nature of its business. While the Group is responding to the demand for electricity by building new capacity, ensuring financial stability and driving energy efficiency, it understands that the long-term nature of its business has an impact on environmental sustainability in the future. Therefore the Group also continues to strive for a balance between the different elements of sustainability. As a result, the Group’s long-term planning takes into account the reduction of carbon emissions in South Africa in the future, ensuring that it upholds its goal of sustainability within the context of providing affordable energy and related services. In order to improve performance and ensure that the aspiration for sustainable development is supported, the Group integrates sustainability criteria into its decision-making process.

The Group remains focused on re-engineering its business to achieve sustainability and cost efficiency by striking a balance between reducing costs where appropriate and the three sources of funding: equity, debt and revenue. The need for a supportive credit rating that reduces the cost of funding as well as retaining access to funding markets, and therefore, the need to migrate to cost-reflective tariffs in the future, will play a key role. The Group implemented the BPP which focuses on the reduction of the cost base, increased productivity and revisions of the Eskom-business model and strategy in order to close the revenue shortfall. Cash savings of between R50 billion and R60 billion are targeted over the MYPD 3 period. The Group also submitted an RCA application to NERSA for the MYPD 2 period during the last quarter of 2013 to address the difference between costs and revenues assumed in MYPD 2 compared to the actual costs incurred and revenues received by Eskom. In terms of the regulatory rules, the regulator can increase future electricity tariffs to compensate Eskom for an under-recovery of revenue or it can reduce tariffs in the future if Eskom has over-recovered revenue. In October 2014, NERSA announced that the annual tariff increase would be revised upwards from 8% to 12.7% for the 2015/16 financial year. Implementing coal haulage and the road-to-rail migration plan The Group will continue to reduce coal trucks on the road through various initiatives, with the aim of improving the cost and safety of coal logistics and, ultimately, contributing to the security of coal supply. This includes a strategy to migrate the transportation of coal from road to rail. The Group’s road to rail migration strategy is being implemented with the cooperation of Transnet Freight Rail. Containerised coal terminals at its Camden and Tutuka power plants have already been built and the Majuba heavy-haul line, which is expected to be completed during the 2018/19 financial year, should have enough capacity to transport 14 million tonnes of coal from Ermelo to Majuba power station each year. PFMA approval to proceed with this project was granted in December 2012 and the civil construction contract was put in place during February 2013. The establishment of the site commenced during March 2013. As of late September 2014, civil construction works were 57% complete. Pursuing private sector participation through IPPs The Group acts as a catalyst for private-sector participation in South Africa’s electricity industry by enabling IPPs to enter the supply market. This objective focuses on diversifying and ensuring security of supply for South Africa. The first project under the renewable energy independent power project (“RE-IPP”) was connected to the grid on 27 September 2013 and the first IPP was commissioned on 15 November 2013. As at 30 September 2014 more than 1,000 MW of renewable generation capacity was connecting and providing power to the grid. In future, the Group will focus on securing funding, land and environmental permissions for the transmission strengthening project in preparation for more IPPs being added to the grid. Transformation The Group has developed a transformation framework and delivery plan aligned with the Government’s goals for development and workplace transformation. Overall transformation challenges are addressed through its BPP, which aims to ensure a sustainable business despite the financial constraints faced by the Group. The Group also participates in a number of initiatives that promote economic development and social equity, including The Accelerated and Shared Growth Initiative for South Africa, BEE (with the focus being on implementing strategies to increase the number of procurement contracts with businesses owned by black women, black youth and people living with disabilities) and the electrification and free basic electricity programmes. Future focus areas include, amongst others, a continuation of the corporate social investment programme aiming to improve society at large through targeted direct investment into community education, health and development projects, finding innovative ways to further advance skills development, job creation, localisation and enterprise development in collaboration with other state-owned companies, and within the ambit of applicable procurement regulations as well as the revision of the employment equity plan. Organisational Structure The following chart shows the current organisational structure of the Group, including major subsidiaries, by businesses and divisions. The Issuer is the ultimate holding company of the Group. The Government, through the Department of Public Enterprises, is the Issuer’s sole shareholder.

Eskom Holdings SOC Ltd

Businesses Major Subsidiaries

Human Eskom Eskom Finance Generation Resources Enterprises SOC Co. SOC Ltd Ltd Technology and Transmission Rotek Escap SOC Ltd Commercial Industries SOC Ltd Eskom Distribution Group Capital Development Roshcon Foundation NPC SOC Ltd Group Customer Finance Services

Strategic function

Service function

The Eskom structure comprises certain line functions which “Operate the Business”, service functions to “Service the Operations” and strategic staff functions to “Develop the Enterprise”. The line functions comprise:

• Generation division – operates and maintains the Group’s electricity generating assets. Generation comprises 27 power stations with a total nominal capacity of 41,995 MW, comprising 35,726 MW of coal-fired stations, 1,860 MW of nuclear, 2,409 MW of gas-fired and 2,000 MW hydro and pumped- storage stations.

• Transmission division – plans, operates and maintains the Group’s transmission network throughout their economic life, and provides an integrative function for the reliable development, operation and risk management of the interconnected power system. These functions require balancing supply and demand in real time, trading energy internationally, buying energy from IPPs, and operating the transmission grid, which is comprised of 159 substations and 30,068 kilometres of transmission lines.

• Distribution division – builds, operates and maintains the Issuer’s distribution assets to provide reliable electricity supply. It also actively collaborates with wider industry to resolve distribution issues and enhance stakeholder relations. The Distribution division’s network infrastructure consists of 46,093 kilometres of distribution lines, 276,027 kilometres of reticulation lines and 7,293 kilometres of underground cables.

• Group Customer Services division – places the customer at the centre of the Issuer’s business and manages customer relations. In this way, it aims to guide the company towards achieving satisfied customers. The Group relies on customer surveys to assess its overall performance and consistently achieves customer performance ratings in the top quartile. This division overseas integrated demand management (“IDM”), which is mandated to design integrated solutions to create and mobilise a culture of energy efficiency to solve complex energy demand issues for a sustainable future. IDM is a key factor in managing the demand for electricity in light of the current electricity system constraints so as to support security of supply. The Service functions comprise:

• Human Resources division – partners with and empowers Group divisions to recruit, develop, and retain skilled, committed, engaged and accountable employees. The Human Resources division is committed to building skills, not only internally to the Group but also for the communities in which

the Group operates. This is done in support of the Group’s aspiration and duty to grow the economy and improve the quality of life of people in South Africa and the region.

• Group Technology and Commercial – oversees, monitors and executes the engineering and procurement (including primary energy) activities across the Issuer’s business.

• Group Capital – creates a centre of excellence for the allocation of capital at Group level and in the planning, development, monitoring and execution of mega projects.

• Finance – provides financial strategy, policies, assurance and strategic financial services (including treasury, corporate and regulatory reporting, taxation, as well as financial evaluation and advisory services) to the Group. The Group’s financial sustainability relies on being able to balance its revenue with its costs in a manner that allows for sustainable growth. The Strategic functions comprise:

• Enterprise Development – the Enterprise Development group comprises four key strategic functions structured as divisions with specialised capabilities to guide, position, protect and enable the Group. They are:

• Strategy and Risk Management – leads an integrated approach to organisational strategy, risk management and corporate planning and to ensure sustainability and resilience.

• Regulation and Legal – ensures that the Group conducts its business within its operating licence by ensuring good governance and compliance with current policy, regulatory and legal frameworks, and to influence the policy, regulatory and legal frameworks required in terms of achieving the Group’s strategic objectives.

• Corporate Affairs – contributing to Eskom becoming a top global power company that is resilient, reputable, trusted, valued, and highly regarded by its stakeholders and peer group of companies in South Africa and elsewhere in the world.

• Group Information Technology – responsible for ensuring the effective delivery of IT systems, infrastructure and processes to support the Group’s business objectives and business processes. From the safety of its people, to the experience of its customers and to the efficiency of its power stations, Group IT plays a vital role in achieving the Group’s aspiration of becoming a high-performance organisation, and in the running of the day-to-day operations of the business.

• Sustainability – delivers effective and innovative solutions and decision-support to enable sustainable business performance and increased stakeholder confidence, which will contribute to the transformation of the Group and South Africa. In order to diversify its energy mix, and in support of its strategic imperative of pursuing a low-carbon growth path, the renewables unit drives the Group’s renewable generation capacity by developing and operating proven technologies to address the government’s environmental commitments and aspirations, as well as to reduce Eskom’s environmental footprint. The division is responsible for implementation of the Safety, Eskom Security, Renewables, Environmental Management, Climate Change Response, Research Testing and Development and Quality Management programmes. The Issuer’s main subsidiaries and their respective functions are:

• Eskom Enterprises, whose two major subsidiaries—Rotek Industries SOC Ltd (“Rotek”) and Roshcon SOC Ltd (“Roshcon”)—provide life-cycle support and plant maintenance, network protection and support for the Group’s expansion programme in South Africa. Eskom Enterprises has two cross border interest subsidiaries which have an interest in electricity operations and maintenance concessions in Africa. EEM predominantly operates in Mali, Senegal and Mauritania, while Eskom Uganda Ltd predominantly operates in Uganda. EEM is in the process of being wound up.

• Eskom Finance Company, which primarily grants its employees access to home-loan finance, while optimising home ownership costs for both the Group and its employees.

• Escap SOC Ltd (“Escap”), the Group’s wholly-owned captive insurance company, which manages and insures the Group’s business risk.

• Eskom Development Foundation NPC (non-profit company) (“Eskom Development Foundation”), a wholly-owned non-profit company that manages the Group’s corporate social investment. Generation Business Divisions Generation Division The Generation division is responsible for the operation and maintenance of the Group’s electricity generating assets for the duration of their economic life. It operates 27 power stations, including 13 coal-fired power stations, four gas liquid fuel turbine stations, six hydroelectric stations, two pumped-storage stations, one nuclear station and one wind energy station. The 27 power stations with a total nominal capacity of 41,995 MW, comprises 35,726 MW of coal-fired stations, 1,860 MW of nuclear, 2,409 MW of gas-fired and 2,000 MW hydro- and pumped-storage stations. The share of electricity production from each type of power station varies annually, depending upon such factors as the availability of the station’s primary energy supply and maintenance outages. In the financial year ended 31 March 2014, coal-fired power stations sent out approximately 91.3% of the Group’s electricity, gas turbines 1.0%, hydroelectric 0.3%, pumped-storage 1.4% and nuclear 6.1%, and wind sent out 0 GWh of the total 115,682 GWh. There has been a change in focus in the Group’s generation sustainability strategy. The primary focus is no longer to “keep the lights on”, but rather on making every effort to ensure adequate supply, but not at the cost of plant sustainability or financial sustainability or by deferring required maintenance. The Group is pursuing a more diverse energy mix. Due to concerns about greenhouse gases and other emissions, the Group plans to reduce over time the proportion of electricity generated from coal. Though the IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) contains several scenarios for the development of the electricity industry in South Africa for the next 20 years, the Group anticipates that its future capital expenditure decisions will broadly be determined in conjunction with the objectives of the IRP. Despite there being substantial coal reserves in South Africa, the IRP emphasises diversifying South Africa’s (and by extension, the Group’s) methods of electricity generation to meet the Government’s policy to reduce the impact of the industry on the environment. See “Risk Factors— Risks relating to the Group—Due to the size and complexity of the committed capacity expansion programme, the Group may fail to implement the programme on a timely and successful basis” and “Overview of South Africa and the South African Electricity Industry—Electricity Tariffs—Multi-Year Price Determination Methodology”.

The table below sets out the 27 power stations of the Group in operation as at 31 March 2014.

Total Total Number and installed installed nominal Name of station – and total capacity of generator capacity capacity Decommissioning number Location sets (MW) (MW)(1) (MW)(1) date

Coal-fired stations – 13 Middelburg, Arnot(2) ...... Mpumalanga 1 x 370;1 x 390; 2 x 400 2,352 2,232 2033 3 x 200; 1 x 196; 2 x 195; Camden(3)(9) ...... Ermelo 1 x 190; 1 x 185 1,561 1,481 2032 Duvha(2) ...... Witbank 6 x 600 3,600 3,450 2042 Grootvlei(3) ...... Balfour 4 x 200; 2 x 190 1,180 1,120 2037 5 x 200; 2 x 195; 2 x 170; Hendrina(2)(9) ...... Mpumalanga 1 x 168 1,898 1,798 2032 Kendal(2)(4) ...... Witbank 6 x 686 4,116 3,840 2051 Middelburg, Komati(3)(9) ...... Mpumalanga 4 x 100; 4 x 125; 1 x 90 990 904 2035 Kriel(2) ...... Bethal 6 x 500 3,000 2,850 2038 Lethabo(2)...... Viljoensdrift 6 x 618 3,708 3,558 2047 Majuba(2)(4) ...... Volksrust 3 x 657; 3 x 713 4,110 3,843 2059 Matimba(2)(4) ...... Lephalale 6 x 665 3,990 3,690 2049 Matla(2) ...... Bethal 6 x 600 3,600 3,450 2041 Tutuka(2) ...... Standerton 6 x 609 3,654 3,510 2047 Subtotal coal-fired stations ...... 37,759 35,726

Gas/liquid fuel turbine stations(5) – 4 Acacia ...... Cape Town 3 x 57 171 171 2036 Ankerlig ...... Atlantis 4 x 149.2; 5 x 148.3 1,338 1,327 2060 Gourikwa ...... Mossel Bay 5 x 149.2 746 740 2048 Port Rex ...... East London 3 x 57 171 171 2050 Subtotal gas/liquid fuel turbine stations ...... 2,426 2,409

Hydroelectric stations – 6 Colley Wobbles(8) ...... Mbashe River 3 x 14 42 — — First Falls(8) ...... Umtata River 2 x 3 6 — — Gariep(5)(7) ...... Norvalspont 4 x 90 360 360 2034 Ncora(8) ...... Ncora River 2 x 0.4; 1 x 1.3 2 — — Second Falls(8) ...... Umtata River 2 x 5.5 11 — — Vanderkloof(5)(7) ...... Petrusville 2 x 120 240 240 2037 Subtotal hydroelectric stations 661 600

Pumped-storage stations(5)(6) – 2 Drakensburg ...... Bergville 4 x 250 1,000 1,000 2041 Palmiet ...... Grabouw 2 x 200 400 400 2048 Subtotal pumped storage stations ...... 1,400 1,400

Wind Energy – 1 Klipheuwel(8) ...... Klipheuwel 1 x 1.75; 1 x 0.66; 1 x 0.75 3 — 2052

Nuclear power station – 1 Koeberg(2) ...... Cape Town 2 x 970 1,940 1,860 2045

Total stations in operation – 27 44,189 41,995 ______(1) The difference between installed and nominal capacity reflects auxiliary power consumption and reduced capacity caused by the age of plant and/or low coal quality. (2) Base load station. (3) Return-to-service station. (4) Dry-cooled unit specifications are based on design back-pressure and ambient air temperature. (5) Stations used for peaking or emergency supplies. (6) Pumped-storage facilities are net users of electricity. Water is pumped during off-peak periods so that electricity can be generated during peak periods. (7) Use restricted to availability of water in Gariep and Vanderkloof dams. (8) Operational but not included for capacity management purposes. (9) Due to technical constraints, some units at these stations have been de-rated. In the six months ended 30 September 2014 and in the financial years ended 31 March 2014 and 2013, the Group sent out 115,682 GWh, 231,129 GWh and 232,749 GWh of energy, respectively, maintaining an average EAF (the energy that could have been generated expressed as a percentage of nominal energy– maximum possible energy generation under optimal operating conditions) of 76.8% for the first half of 2014, 75.1% in 2013/14 and 77.7% in 2012/13. The decrease in energy sent out from 2013 to 2014 can be attributed

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to the effect of a lower demand for electricity in addition to demand-response initiatives such as power buybacks as well as industrial action and operational issues occurring at some of the Group’s largest customers in the mining sector. These were offset, however, by higher-than anticipated (and opportunistic) sales to international customers at increased prices. During the financial year ended 31 March 2014, the Group’s coal-fired stations produced 209,483 GWh of power, consuming 122.4 million tonnes of coal and the Group consumed 317,052 mega litres of water, amounting to 1.35 litres per kWh sent out. Over the same period, unplanned automatic grid separations per 7,000 operating hours were 5.24, mainly as a result of the deferral of outages which thereby increased the maintenance backlog and caused increased volatility in the performance of the generation fleet. A significant amount of outages was forced (and not planned) and included automatic grid separations. An automatic grid separation means that a generating unit loses the connection with the national grid and stops supplying electricity, while an unplanned separation means that the separation was not scheduled or part of planned maintenance. The Group’s plant health has deteriorated over the last few years and the maintenance backlog is increasing, resulting in reduced plan availability and reliability. Increased maintenance is required, but the constrained system has not allowed for sufficient planned outages in order to do such required maintenance. Coal Coal-fired power stations accounted for approximately 91.3% of the Group’s nominal capacity and approximately 91.3% of its actual power sent out in the six months ended 30 September 2014 and 85% of the Group’s nominal capacity and approximately 91% of its actual power sent out in the financial year ended 31 March 2014. The Group burnt 61.4 million tonnes of coal for the six months ended 30 September 2014 (against a target of 121.28 million tonnes for the financial year ended 31 March 2015) and 122.4 million tonnes of coal in the financial year ended 31 March 2014 compared to 123 million tonnes of coal in the financial year ended 31 March 2013. The significant use of coal in the Group’s power stations is consistent with the availability of coal as a primary energy resource in South Africa. The coal the Group uses is, typically, of relatively poor quality and is not normally considered suitable for export. See “Risk Factors— Risks relating to the Group—The majority of the Group’s power stations depend on a steady and adequate supply of coal and water of a certain quality, including liquid-fuel, for their operations and any failure to secure such amounts or quality could result in cost increases or supply shortages”. All of the Group’s operating coal-fired power stations (with the exception of Majuba and power stations that have been returned to service) are located near coal mines to reduce transportation costs and minimise supply risks. In addition, the Group has invested in large scale water transfer schemes to secure water supply to its coal-fired power stations. This all seeks to ensure that these stations have access to low cost primary energy resources to match the expected economic life of the stations. The Group has developed a long-term coal supply strategy in order to meet the requirements of the current and future power stations. The key elements of this strategy are:

• developing the Waterberg coalfields;

• continuing to diversify the Group’s sourcing portfolio to reduce the Group’s reliability on major mining houses and, instead, sourcing a sustainable proportion of its coal from emerging black-owned mines;

• implementing new technologies to improve the quality of coal delivered to the Group’s power stations;

• developing sustainable, low-cost transportation options for the delivery of coal in a safe way;

• collaborating with state-owned mining companies to secure coal resources for future power generation; and

• engaging and collaborating at a national level to move forward to declare coal as a strategic national resource and to unfold key imperatives to ensure the implementation thereof. The Group recognises the need to budget and forecast for coal expenditure accurately so as to allow the business to prepare adequately for future coal costs. The average cost of producing electricity from coal varies from one power station to another. The main reasons for this are the different mining operations with

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different mining methods, the price that was contractually agreed to, different quality specifications, and transportation costs. The age of the power station can also be a factor in terms of efficiency, on account of the technology employed rather than the state of repair. Generally, rail transportation of coal is cheaper and safer than road transportation, and therefore the Group’s strategy is to maximise rail capacity where possible. Each power station stockpiles coal and maintains other coal storage facilities; a minimum supply of coal, measured in days, is usually stored at each power station in accordance with the Group’s policy. At 30 September 2014, the Group had average coal stocks at its power stations of 46 days, compared to 44 days as at 31 March 2014 and 46 days at 31 March 2013, in each case against a target of 42 days. The Group currently sources approximately 38% of its coal under cost-plus contracts and 25% under fixed-price (or indexed) contracts, both of which are long-term. Approximately 37% of the Group’s coal is sourced under short and medium-term contracts. This mix between contract types is intended to balance portfolio risk, insofar as it relates to the different risk profiles inherent in the structure of the contract e.g. price fluctuations over the short and long-term. The different contract types are discussed below. Cost-Plus Contracts (Long-term) There are six cost-plus coal mines that are each adjacent to a power station, producing a supply of coal exclusively for the respective power station. Together they currently supply approximately 48 million tonnes of coal per year, representing 38% of the Group’s coal supply. Under the “cost-plus” pricing mechanism, the Group pays for the total working cost of the mine together with a return on the mine owner’s original investment. The total working cost includes all the labour and operating costs of the mine as well as capital expenditure. Due to the Group’s current capital constraints, in the future it will be more difficult to leverage Eskom’s low cost of capital to enter into cost-plus agreements. The total coal cost is factored into the MYPD application and passed on to customers through the tariff. Fixed-Price/Indexed Contracts (Long-term) Under contracts with a fixed price structure (also referred to as indexed contracts), the base price paid for coal is fixed and increased annually as per indices in the contract. The contracts also allow for the Group to increase the off-take at prices close to the additional marginal cost of coal. As at 30 September 2014, there were four fixed-price/indexed agreements in place. Approximately 30 million tonnes of coal per year is supplied under these contracts, representing 25% of the Group’s coal supply. The total working cost is factored into the MYPD application and passed on to customers through the tariff. A long term contract was agreed in September 2010 for the supply of coal to the Medupi power station currently under construction. The structure of this contract follows the fixed price/index model. The total coal cost is factored into the MYPD application and passed on to customers through the tariff. The duration of this long term contract is linked to the life of the power station. As at the date of this Base Prospectus, four medium term coal supply contracts have been signed for delivery to meet the planned commissioning date of the Kusile power station also under construction. The conclusion of long-term coal and limestone supply agreements for Kusile is yet to be finalised. Short/Medium-Term Contracts Contracts with a duration of up to ten years are considered short or medium-term. These contracts are generally entered into to supplement long-term contracts when generation requirements exceed production. These contracts are generally with new entrants into the market, often previously disadvantaged South African operators, and so serve to increase the Group’s participation in BEE, although the contracts are commercially driven and not entered into in order to achieve set targets on BEE. As at 30 September 2014, these contracts supplied approximately 46.0 million tonnes of coal per year, representing 37% of the Group’s coal supply. The base price for these contracts is fixed and then escalates according to a negotiated basket of various indices, including one relating to coal costs, on a contract-by-contract basis. Transport costs are also negotiated depending on the terms of the coal supply agreement. The transport costs are benchmarked to a transport model. The total coal cost is factored into the MYPD application and passed on to customers through the tariff.

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Gas turbine/Liquid fuels (diesel) The Group operates four gas/liquid fuel turbine stations (equal to 2,409 MW in nominal capacity) that are normally used during periods of peaking electricity demand. This includes two OCGT stations, Ankerlig and Gourikwa, which came into full operation in June 2007 and have a combined nominal capacity of 2,067 MW. Ankerlig and Gourikwa supply the Western Cape during periods when the Koeberg nuclear power station is not operational, when there is a general shortage of generation to meet demand, or when problems occur in the transmission lines serving the Western Cape. Due to the high cost of generation at the OCGT plants, the Group tries to limit their use to periods of peak demand. However, given recent capacity constraints, the OCGT plants have been supplying power to the grid more regularly. During the six months ended 30 September 2014, generation from OCGTs equalled 1,164 GWh (compared to 1, 206 GWh as at 30 September 2013) and for the financial year ended 31 March 2014, generation from the OCGT plants totalled 3,621 GWh (compared to 1,904 GWh for the financial year ended 31 March 2013). In an effort to reduce the load factor of the OCGTs, existing power purchase agreements have been extended to 31 March 2015. The diesel fired OCGTs run on fuel purchased from local commercial suppliers. For Ankerlig and Gourikwa power stations, a ten year fuel supply contract is in place with an anchor supplier at each station under which the Group purchases diesel at a margin below the wholesale list price. Due to Ankerlig’s potential to consume relatively large fuel volumes in a short time, three additional fuel supply contracts are in place (two of ten years and another of five years duration) with other suppliers for this power station. OCGT stations accounted for approximately 6% of the Group’s total nominal electric generation capacity as at 30 September 2014 and as at 31 March 2014. There are specific challenges for fuel procurement and fuel storage for the OCGT stations. Primarily, as the OCGT stations are normally used as back-up plant, the uncertainty around the timing and extent of fuel usage is erratic. Additionally, suppliers require long lead times for large orders of liquid fuel. Maintaining a stock of fuel is one way of overcoming these challenges and to this end the Group has secured adequate fuel storage capacity and regularly reviews stock levels. The biggest influences on fuel costs for OCGT stations are the international price of diesel–on which the Group’s purchase prices are based–and the exchange rate of Rand to U.S. dollars, which can make the price of fuel fluctuate significantly. Overall, the average Rand price for diesel for the financial year ended 31 March 2014 increased by 12.1% compared to the preceding year mainly due to the increase in the price of oil and the weakening of the Rand against the U.S. dollar. Consumption of diesel and Kerosene increased to 1,148.5 ML in the financial year ended 31 March 2014 compared to 609.7 ML for the financial year ended 31 March 2013 and 225.2 ML for the financial year ended 31 March 2012, due to the increased operation of the gas turbine plants. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Comparison of the financial years ended 31 March 2013 and 31 March 2012”. Imported Power Although the Group’s power stations have the capacity to supply South Africa’s current demand for electricity, the Group also imports hydroelectric power from Cahora Bassa in Mozambique and expects that its imports (and exports) of electricity will increase in the future. International purchases (imports by the Group) were below target for the six months ended 30 September 2014, and this trend is expected to continue until 31 March 2015. Purchases up to the financial year-end are expected to be 23% lower than budgeted as a result of line and equipment faults on HVDC transmission lines from Cahora Bassa. As a result, the Group has had to use other generators in the fleet to make up for the shortfall when there have been interruptions in the HVDC scheme supply. A power purchase agreement entered into with Aggreko in Mozambique for the purchase of 148 MW of mid- merit supply was extended from July 2014 to August 2015, with the option to extend the agreement for a further two months. Aggreko, however, has only been able to deliver 108 MW due to constraints in the Mozambique transmission network.

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In order to use imported power to help meet load requirements during peaking demand and to minimise the short-term peaks in generator usage relating to such demand, the Group is involved in a number of projects to improve and expand the transmission network within Southern Africa. For the six months ended 30 September 2014, the Group imported 4,903 GWh of power and in the financial year ended 31 March 2014, the Group imported 9,425 GWh of power. Renewables The IRP contains significant provision for new renewable electricity generation. The implementation of independent renewable energy projects is also supported by the introduction of Renewable Energy Feed-In Tariffs published by NERSA in 2009. To incentivise the generation of electricity from renewable sources, a 2 c/kWh environmental levy on electricity generated from non-renewable sources was included in NERSA’s MYPD 2 revenues, and came into effect on 1 July 2009, until 31 March 2011. On 1 April 2011, the environmental levy was increased to 2.5 c/kWh, and on 1 July 2012 it was increased again by 1 c/kWh to 3.5 c/kWh. The Group currently passes on the cost of this levy to its customers. It is anticipated that this levy may be abolished with the introduction of the proposed new carbon tax, which was expected to be implemented in 2015 but has been deferred by the National Treasury to 2016. In the financial year ended 31 March 2014, the Group generated 1.70% of its electricity from hydroelectric, pumped-storage and wind sources. The Group remains committed to increasing the share of renewable energy in its generation output. Renewable energy, energy storage and integrated distributed energy forms a part of the Group’s research portfolio. Key research activities the Group is pursuing in the area of renewables are:

• ocean pumped-storage scheme;

• high-head underground pumped-storage;

• resource assessments and modelling;

• effects of distributed energy on networks;

• biomass technologies; and

• large-scale energy storage. Hydroelectric The Group operates two hydroelectric power stations, which as at 30 September 2014 had a combined net nominal capacity of 600 MW, and two pumped-storage power stations, which had a net maximum capacity of 400 MW. The role of these power stations is mainly to provide system security by supplying peak demand power and voltage stabilisation. During severe drought, however, the Vanderkloof and Gariep hydroelectric power stations have been unable to operate at maximum capacity because of insufficient water supply. Wind power In 2013, the German conglomerate Siemens was awarded the contract to supply the wind turbines, and install the Group’s first utility scale wind farm, Sere, a 100 MW station in the Western Cape. The contract also includes a five year service agreement.. Significant progress has been made on the construction of the wind farm with all 46 wind turbines having been installed as of the date hereof. During October 2014, the transformers of seven wind turbine generators were energised and these wind turbines were synchronised to the national grid, adding 4.4 MW of power. As at the end of December 2014 all 46 of the turbines were energised and are in the final stages of testing and commissioning, this includes a reliability test run that is required for each of the wind turbines. During the testing and commissioning phase the facility, although not in full commercial operation, is contributing power to the grid. Solar energy The Group believes that South Africa has considerable potential for harnessing solar power, primarily in the Northern Cape and Northwest provinces. Solar energy is expected to form the major proportion of the

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Group’s renewable energy output in the long-term. The Group has identified concentrating solar power technology (as applied in Spain and the United States) as having potential for large-scale power generation and has been granted a loan from a consortium of banks including the World Bank for a pilot, 100 MW, concentrating solar power plant. The potential for local supply will be a focus of this pilot as initial assessments indicate that the technology offers opportunities for developing local industry and supporting local business. This pilot is expected to be commissioned in 2017. Additionally, development work continues on the photovoltaic roll-out at existing buildings, power stations and transmission substations, and also on solar augmentation where existing power stations are hybridised with solar thermal energy. Project Ilanga, the photovoltaic project (which includes solar augmentation, where existing power stations are hybridised with solar thermal energy), is expected to add 150 MW by 2017/18. Currently, 2 MW has been installed as part of this project. Biomass The Group is continuing to research the potential of biomass as fuel for generation and rural energy solutions. Biomass power is energy contained in products such as sugar cane waste, wood waste and residues from short rotation crops, such as straw. The Group is currently investigating the use of biomass for co-firing power stations, through the use of wood waste in existing coal-fired boilers, as a means of reducing coal usage. Should the business case prove feasible, the Group aims to co-fire biomass to replace 10% of coal usage by weight in coal-fired power stations by 2026. The Group is looking to source suitable biomass within South Africa and sub-Saharan Africa. The current estimate for the first plant to be co-firing biomass is 2015. In addition, the Group is also evaluating the use of municipal solid waste as a biomass fuelstock for power generation. New technologies In light of the difficulty of procuring coal and in an effort to reduce dependence on transported coal, the Group has developed an underground coal gasification pilot plant next to Majuba power station, following years of extensive studies and tests. The process involves injecting air into a matrix of wells and the coal is ignited underground, producing a synthetic gas which is harvested and then used as fuel. Gas from the pilot plant was successfully flared in January 2007, demonstrating that the process works, and gas may be used to supplement fuel in existing boilers, if technically and economically feasible. The project is still in the planning phase and approval is being obtained for a demonstration plant. The next phase of this project will be to evaluate the commercial potential of building a 2,100 MW combined cycle gas turbine plant running on fuel harvested this way, although there can be no assurance at this stage as to whether such a plant will be built. This evaluation is expected to be completed within the next few years, although the project is currently delayed due to environmental compliance issues. Nuclear Division Eskom is affiliated to the World Association of Nuclear Operators (“WANO”) and the U.S. Institute of Nuclear Power Operations (“INPO”). South Africa is also a member of the International Atomic Energy Agency (“IAEA”). The Group’s Nuclear Operating Unit provides nuclear energy in accordance with nuclear safety standards set by the NNR which standards are aligned with, and in some cases are stricter than, the recommended standards of the IAEA and technical performance standards which are benchmarked against the standards of Electricité de France, WANO and INPO. These standards are supported through the development of nuclear safety values and beliefs for employees, continuous effort to ensure operational excellence and adherence to the fundamentals of sound financial management. The Group has one nuclear power station, located in Koeberg, near Cape Town, which accounts for approximately 4.4% of the Group’s total nominal capacity, and sent out 14,106 GWh in the financial year ended 31 March 2014. Koeberg has two reactors with a total nominal capacity of 1,860 MW. Both reactors are pressurised water reactors constructed by Areva S.A. of France based on a Westinghouse design. The reactors were commissioned in 1984 and 1985, respectively.

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Despite a one-off incident in September 2010, Koeberg’s safety record, together with the current condition of the plant following a suite of upgrades, has led the Group to consider extending the operational life of the plant from 40 to 60 years, which would result in decommissioning in 2045. The Group has made a financial provision on its balance sheet in the amount of R9.3 billion for the decommissioning of Koeberg and for the management of the spent fuel generated there, although there are currently no funds allocated to these provisions, as current regulations do not require such allocations. See “Risk Factors—Risks relating to the Group—The disposal of spent nuclear fuel and ultimate decommissioning of its nuclear power plant will result in considerable costs for the Group which, although provisioned in the Group’s balance sheet, will have to be funded in the future”. Currently all spent fuel is stored at the Koeberg facility, in either specially designed fuel pools or used fuel storage casks in accordance with regulatory requirements. Nuclear fuel is procured and delivered to Koeberg in accordance with Government-authorised contracts. All of the Group’s nuclear fuel is currently imported. The Group requires approximately 32 tonnes of enriched uranium product per year, which corresponds to approximately 288 tonnes of natural uranium. The Group’s current uranium and enriched uranium contracts are sufficient to satisfy Koeberg’s demand until 2017, while current fuel-fabrication contracts cover supply for the period up to 2016/17. The Group has approved a nuclear fuel procurement strategy to include longer-term contracts and creating strategic stockpiles that would ensure security of nuclear fuel supply. The Group has a system of nuclear oversight, in line with international best practice. This has recently been strengthened by the establishment of a Nuclear Safety Review Board, comprising external nuclear experts, who report periodically to the sustainability committee of the Board (“BSES”) and the nuclear management committee (“NMC”). The first tier is BSES, which dedicates a number of its meetings each year to nuclear considerations. These meetings are attended by a number of experienced international nuclear experts. The second tier is the NMC, a sub-committee of the EXCO, which is presided over by the Generation Group Executive. This committee monitors, reviews and makes recommendations on issues such as nuclear policy, standards, benchmarks and rules, and the Group’s overall business requirements. The third tier is the Nuclear Operating Unit safety review committee, which brings together nuclear expertise from different parts of the Group to evaluate nuclear safety issues and make appropriate recommendations to senior management and the other tiers. The Group believes the safety of Koeberg is in line with that of comparable overseas nuclear power stations. Independent confirmation of the safety standards is obtained biennially through international peer reviews undertaken by the World Association of Nuclear Operators, the IAEA or the U.S. Institute of Nuclear Power Operations. As required under the National Nuclear Regulator Act, the Group furnishes security in the form of an insurance policy for its strict liability to third parties arising out of the operation of Koeberg. In addition to overseeing the current nuclear activities of the Group, the Nuclear Operating Unit also considers future projects and activities. The Group is currently evaluating three potential sites to accommodate any future additional nuclear facilities. Future areas of focus for the Group include finalising preparation for the site characterisation, design and execution of the three potential sites. The IRP makes provision for an increase in nuclear power generating capacity in South Africa and, in November 2012, the Cabinet indicated that the Issuer would be the owner and operator of such new nuclear capacity. However, there has since been a significant degree of uncertainty as to the specific role of the Issuer in such programme and the funding thereof. A revised version of the IRP, which is expected to be approved following the IEP’s anticipated approval in March 2015, will likely provide further clarity. In November 2014, the Department of Energy publically reaffirmed its commitment to add 9,600 megawatts of nuclear- generated electricity to the national electricity grid through a new build programme in line with the IRP. In the fourth quarter of 2014, as part of the pre-procurement phase and preparation for the roll out of its nuclear new build programme, the Government announced entry into inter-governmental framework agreements on nuclear co-operation with China, the Russian Federation and France, which initiates the preparatory phase for a possible large-scale nuclear construction programme with one or more such countries. In late 2014, the Government also undertook “nuclear vendor workshops” with prospective vendor countries to allow them to demonstrate how, if chosen, they would help South Africa meet its nuclear expansion requirements. In light of the Government’s recent announcements, there continues to be little certainty whether, to what extent and in what form the Group will be involved in the nuclear new build programme and how such additional generating and transmission capacity will be funded. Decisions will be taken regarding the involvement of

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partners and the Group’s role in the procurement, ownership and operations of any future nuclear power plants. In September 2014, the Group signed a contract with Areva NP Proprietary (“Areva”) for the replacement of Koeberg’s six steam generators, targeted for 2018. Legal proceedings challenging the tender process and its outcome have since been initiated by the unsuccessful bidder. See “Litigation and Investigations”) Transmission Division The Group owns and operates the South African national transmission system. Electricity is transferred from the Group’s power stations to consumers through a network of high-voltage transmission and distribution lines owned by the Group. Transmission distances in South Africa are relatively long as the majority of the Group’s power stations are located in the remote area of the Eastern Highveld, near the coal supplies, rather than the principal consumption centres. As at 30 September 2014, the Group’s transmission network consisted of approximately 30,068 km (compared to 29,924 km as at 31 March 2014) of transmission lines of voltages ranging between 132 to 765 kV and a network of 159 substations (compared to 157 as at 31 March 2014). In order to meet future sustainability requirements and as part of continual improvement, the Group has pursued initiatives to improve the reliability of electricity supply to customers and to reduce the number of interruptions. This has included, among other things, investments to improve plant reliability as well as system strengthening investments and expansion to connect new power generation sources. In the financial year ended 31 March 2014, the Group installed 811 km of new transmission lines. A total of 161.8 km of transmission lines was installed in the six months ended 30 September 2014. The Transmission division’s organisational structure comprises the following business units: Southern African Energy (“SAE”) SAE is a business unit which focuses on pursuing the development and execution of business opportunities in the SADC region with a view to increasing imports, strengthening transmission systems, accessing strategic resources, providing consulting services including training and skills development, pursuing strategic partnerships and growing the Group’s market share through additional revenue sources. System Operator This business unit is responsible for the short-term network operation, reliability and control of the interconnected power system. Energy Planning and Market Development The functions of this business unit include planning for adequate electricity supply and resource demand to meet expected future customer energy and capacity requirements. It also facilitates the procurement from IPPs and provides the administrative services required for a wholesale electricity market, including wholesale pricing and trade settlement. Grid Planning This business unit is responsible for the planning and development of the main transmission system including the integration of new generation in accordance with the South African grid code, which is overseen and regulated by NERSA. Transmission Grids The function of this business unit is to ensure that the Group has a reliable and sustainable transmission network through operating, maintaining and restoring the electricity grid. Asset Management Execution The function of this business unit is to manage and execute the Group’s capital asset investment plan for refurbishments, strategic spares as well as land and servitude rights management.

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Business Integration and Performance Management This business unit is responsible for the performance management and assurance of technical as well as safety, health, environmental, quality and security co-ordination for the Transmission division. Office of Group Executive: Transmission The function of this business unit is to provide a strategic, integrative, enabling, assurance and support function to the Transmission division, according to regulatory requirements. Distribution Division The Group’s distribution network provides electricity supply, network connection and service and as at 30 September 2014, the Group owned 46,285 kilometres of distribution lines (46,093 kilometres as at 31 March 2014) and 277,173 kilometres of reticulation power lines (276,027 kilometres as at 31 March 2014) in South Africa, representing the largest power line system on the continent of Africa. Historically, the Group has been a wholesaler of electricity to large commercial consumers and municipalities, which were responsible for reticulation and, in the case of municipalities, further distribution to all customers in their area, being mainly residential customers for the smaller municipalities. Direct distribution by the Group to residential customers has generally been limited to rural areas, but has increased over time as a result of the Electrification Programme and the growing practice of distributing directly to end users in many areas previously supplied by municipalities. The Group has become a direct supplier to some customers previously supplied by municipalities, due to problems such as non-payment by municipalities and service delivery issues. During the six months ended 30 September 2014, the Group connected 57,534 homes as part of the Electrification Programme and in the financial year ended 31 March 2014, 201,788 homes. To date, the Department of Energy has reimbursed the Group for the costs of the connection. See “Overview of South Africa and the South African Electricity Industry—Electrification”. Most new residential customers pay for their electricity in advance through a prepayment meter fitted in their home. As at 30 September 2014, the Group had approximately 5,224,616 prepaid residential customers all of whom were located in South Africa. See also “—Customers”. Group Customer Services Division The Group Customer Services division consists of the Group’s customer service grid access and IDM functions. Customer Services The customer service functions are responsible for managing customer relationships, the customer service interface, customer acquisition and contracts, and the sales to and revenue derived from all of Eskom’s customers (including metering, billing and prepaid vending functions). The division is also responsible for defining the Group’s products, service standards and tariffs, and for managing debt and energy losses due to theft and fraud. The Group’s customers range in size from local large key redistributors, principally municipalities and metros, large and medium sized industrial, commercial and agricultural customers, to small business and residential customers (both billed and prepaid). The largest redistributor customers, as well as key industrial customers, are serviced under Eskom’s Transmission licence, while the balance of the redistributor, large, medium and small customers is serviced under Eskom’s Distribution licence. Eskom’s Transmission and Distribution divisions manage the technical aspects of electricity provision to these customers respectively, while the Group Customer Services division manages the relationships, service interfaces and revenue for all customers across the board. The grid access function facilitates the Department of Energy’s bid process for Independent Power Producers as well as the connection of successful bidders to the network The Group treats municipalities (redistributors) as bulk customers, supplying them with electricity, which they in turn sell to all customers in their service areas. Municipalities are responsible for billing and collecting tariffs within their service areas. As at 30 September 2014, the Group Customer Services division had approximately 50,638 commercial customers, 83,190 agricultural customers, 2,795 industrial customers, compared to approximately 50,425 commercial customers, 83,489 agricultural customers and 2,781 industrial customers for the financial year ended 31 March 2014. See also “—Customers”.

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IDM South Africa’s electricity infrastructure has been under strain since 2008 due to insufficient generation capacity as demand for electricity has exceeded supply and is anticipated to continue to do so until new power stations are commissioned over the next couple of years until 2019/20. To help address the situation, the Group has accelerated its DSM programme with particular emphasis on energy efficiency initiatives. In addition to easing pressure on the national grid, energy efficiency projects allow the deferment of certain capital expenditure, alleviating the effect of revenues being lower than requested under the Group’s MYPD application. Such projects also form an integral part of the Group’s climate change strategy (“Climate Change Strategy”). Since the Climate Change Strategy’s inception in 2003, the Group has installed 60.3 million energy-saving lights in homes across the country resulting in a saving of 2,504 MW. A further 1,393 MW was saved through the implementation of energy efficiency and demand reduction projects in the industrial, mining, municipal and commercial sectors. The division’s IDM function plays a key role in assisting the Group to balance power supply and demand during periods of generation constraints and develops energy efficiency and demand reduction/demand response solutions, and implements projects to roll out the relevant solutions and technologies across the customer base. Demand-side management interventions encourage customers to use electricity more efficiently, thereby reducing the gap between supply and demand in the short-to medium term. Due to the Group’s financial constraints, IDM programmes have effectively been put on hold. As a result, the performance of verified demand and internal energy efficiency are significantly below target. During the six months ended 30 September 2014, Eskom achieved total evening peak demand savings of 32 MW, compared to 117 MW during the six month period ended 20 September 2013. During the six months ended 30 September 2014, Eskom achieved annualised energy savings of 310 GWh, compared to 306 GWh during the six months ended 30 September 2013. During the six month period ended 30 September 2014, the Group spent R0.4 billion on IDM initiatives, compared to R0.7 billion in the six month period ended 30 September 2013. The Group, in evaluating the business case for IDM on a collective and individual project level, compares the project cost per unit of energy saved with the cost of generating that unit of electricity. The cost of generation differs during the day, based on the mix of power stations used to generate a specific profile. The integrated demand management impact is thus measured in terms of the impact on the generation cost profile, or the “avoided cost of generation”. Integrated demand management cost per unit is consistently less than the avoided cost of generation, specifically during peak hours when the generation is expensive due to probable running of the OCGTs. Implementation is much quicker, the impact on the environment is minimised and the customer benefits through a reduced bill. During times of generation capacity constraint integrated demand management helps to keep the country’s lights on, with resulting social and economic benefits. Further demand-management initiatives include the Demand Response Programme and the residential mass roll-out programme:

• The Demand-Response Programme consists of a range of sub-programmes which offers commercial and industrial customers financial incentives to reduce their electricity requirements as and when needed. Before being placed on hold, the requirements for taking up demand response programme products (standard product and standard offering) were amended to allow smaller companies to participate in the programme. The Group continued the roll-out of the demand response rewards programme to sign up customers to reduce demand for compensation, should the electricity system require it. Currently, 614 MW of supplemental, 791 MW of instantaneous and 12 MW of standby generation, for a total of 1,417 MW of dispatchable load, is available to the system operator for its control and evening peak reduction requirements. A total of 760 projects were installed during the six month-period to 30 September 2014, with potential demand savings of 81 MW and potential energy savings of 258 GWh.

• The residential mass roll-out programme aims to reduce residential electricity usage by encouraging households to use energy-efficient technologies. The programme is a significant lever to reduce

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demand during periods of system constraint, but it will require funding from Government as it has not been accommodated in the MYPD3 determination. It includes the following sub-programmes:

• The residential mass roll-out programme of Compact Fluorescent Lamps (“CFLs”) continues to be the key residential initiative contributor, delivering 81 MW of verified savings in the six months ended 30 September 2014. The CFL rollout (phase 3) was completed in Gauteng in July 2014, with 180,707 bulbs being installed during the six months to 30 September 2014, and a total of 372,964 bulbs (against a target of 500,000) since inception.

• The solar water-heater programme: the Group contributes to the Government’s solar water heating initiative, which aims to install one million solar water heaters. During the six months ended 30 September, 12,478 solar water heaters were installed (47,020 as at 31 March 2014) bringing the total for the rebate programme and residential contracts to 394,993 since inception in 2009.

• Eskom’s Power Alert and “5pm to 9pm” campaigns continue to reduce power demand during the evening peak. The average impact for the red flightings in the evening peak on the worst constrained day is 306 MW (July 2014). Customers The Group generates approximately 95% of the electricity used in South Africa and serves a wide variety of customers. The Group allocates its customers between its Distribution and Group Customer Services divisions. Apart from the Group’s residential customers, who fall within the remit of the Distribution division, all other remaining Group customers fall within the remit of the Group Customer Services division. As at and for the six months ended 30 September 2014, the Group had 5,363,615 total customers and sold 109,168 GWh of electricity in total, accounting for R80,243 million, or 99%, of the Group’s revenue for the six months then ended. Nearly 100% of the Group’s customers were located in South Africa, while 95% of the electricity sold by the Group was to domestic customers, accounting for 94% of total Group revenues. As at and for the year ended 31 March 2014, the Group had 5,232,915 domestic customers and sold 217,903 GWh of electricity in total, accounting for R135,407 million, or 99%, of the Group’s revenue for the year then ended. Nearly 100% of the Group’s customers were located in South Africa, while 94% of the electricity sold by the Group was to domestic customers, accounting for 93% of total Group revenues. The following table sets for the Group’s the number of customers by category as at the dates indicated and for the periods indicated. Unless otherwise indicated, all customers fall within the remit of the Group Customer Services division.

Gross Electricity Gross Electricity Electricity Revenue for Electricity sold for the sold for the the six Revenue for six months financial months the financial Customers as at Customers as ended 30 year ended ended 30 year ended 30 September at 31 March September 31 March September 31 March 2014 2014 2014 2014 2014 2014 (Number) (GWh) (millions of Rand) Category Domestic customers Redistributors(1) ...... 805 801 47,385 91,262 34,739 55,273 Residential(2)(3) ...... 5,224,616 5,093,847 5,960 11,017 5,884 10,181 Commercial ...... 50,638 50,425 4,882 9,605 4,717 7,918 Industrial ...... 2,795 2,781 26,601 54,567 16,417 28,291 Mining ...... 1,052 1,054 14,659 30,667 11,350 19,815 Agricultural ...... 83,190 83,489 2,406 5,192 3,003 5,646 Traction ...... 508 507 1,601 3,125 1,425 2,397 Total domestic customers ...... 5,363,604 5,232,904 103,494 205,435 77,535 129,521 Total international customers ...... 11 11 5,674 12.469 2,708 5,886 Total customers ...... 5,363,615 5,232,915 109,168 217,903 80,243 135,407

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______(1) Includes municipalities. (2) Includes prepaying customers and public lighting. (3) Residential customers fall within the remit of the Distribution division.

The Group’s largest users of electricity are the 805 redistributors, which principally comprise municipalities, who accounted for 47,385 GWh of electricity sold for the six months ended 2014, representing R34,739 million or 43% of revenue for the period. For the financial year ended 31 March 2014, 801 redistributors accounted for 91,262 GWh of electricity sold, representing R55,273 million or 41% of revenue for the period. Industrial and mining customers, which are among the Group’s largest sources of revenue, accounted for 26,601 GWh and 14,659 GWh, respectively, of electricity sold in the six months ended 30 September 2014 (compared to 54,567 GWh and 30,667 GWh, respectively, for the financial year ended 31 March 2014). The Group’s top ten individual customers, other than redistributors, in terms of GWh consumed annually are predominantly aluminium producers and mining companies. The Group earned R16,417 million and R11,350 million in revenue from its industrial and mining customers, respectively, for the six months ended 30 September 2014, totalling R27,767million, or 35% of its revenue. The Group earned R282,911 million and R19,815 million in revenue from its industrial and mining customers, respectively, in the financial year ended 31 March 2014, totalling R48,106 million, or 36% of its revenue. The Group had 5,224,616 residential customers and 50,638 commercial customers as at 30 September 2014, who consumed 5,960 GWh and 4,882 GWh of electricity, respectively, in the six months ended 30 September 2014, compared to 5,093 847 residential customers and 50,425 commercial customers as at 31 March 2014, who consumed 11,017 GWh and 9,605 GWh of electricity, respectively, in the financial year ended 31 March 2014. Other customers of the Group include agricultural and traction customers, who consumed a total of 4,007 GWh for the six months ended 30 September 2014 (and a total of 8,3176 GWh for the financial year ended 31 March 2014). Finance The mandate of the Finance Division is to provide financial strategy, policies, assurance and strategic financial services (including treasury, corporate and regulatory reporting, taxation, as well as financial evaluation and advisory services) to the Group. The Group’s financial sustainability relies on being able to balance its revenue with its costs in a manner that allows for sustainable growth. Group Capital Division The Group Capital Division provides capital project planning and execution strategy, policies and assurance for the Group’s capacity expansion programme. Stated objectives are reviewed annually in line with the Group’s business planning process. This methodology is followed to ensure cohesion of the Group’s objectives. The business plan builds on current strategic direction and indicates where change is required to move the division’s business forward. The divisional plan is seen as an evolving document and is therefore reviewed and monitored continuously. The business plan covers a four year period (2014/15 to 2017/18) and outlines the key forces driving the business, strategic imperatives, risks, and resource requirements. Capacity Expansion Programme Historically, the Group has had generating capacity in excess of demand. In the late 1980s and early 1990s, due to overcapacity, the Group placed three power stations (Camden, Grootvlei and Komati) into reserve storage. Over the last decade, however, capacity planning has presented a major challenge. From 2000 to 2007, the South African economy experienced significant growth and demand for electricity grew at a rate of approximately 3.4% per year during that period. Limited capital investment was made by the Group during this period and, as a result, its generation capacity has not kept pace with consumer demand. The Group calculates its reserve margin as the difference between installed system capability and the system’s maximum load requirements (peak load or peak demand), while its operating reserve margin represents the Group’s generating capacity available to meet demand (excluding energy supplied by IPPs, which reduces the residual demand that the Group is required to meet through generation) during the “peak hour”. The “peak hour” represents the hour in a specified period during which electricity demand it at its highest (and exceeds the available capacity) and only considers the available capacity (i.e. after discounting any plants which are out of service for either planned or unplanned maintenance, outages, failures or other problems). While the Group’s reserve margin was approximately 22.2% and 20.0% in 2013/14 and 2012/13, respectively, as

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compared to the international norm of 15%, its operating reserve margin, which the Group views as a more indicative “real time” measure of its generation capacity cushion at any particular time, was only approximately 1.3% and 4.8% in 2013/14 and 2012/13, respectively. Without factoring in generation capacity from its gas turbines, the Group’s operating reserve margin was -5.3% and -1.7% in 2013/14 and 2012/13, respectively. See “Risk Factors—Risks relating to the Group—The Group’s electricity generation capacity is affected by a low operating reserve margin, which strains its ageing infrastructure, increases costs and jeopardises its ability to consistently meet the electricity supply requirements of its customer”. The Government has indicated that South Africa will need approximately 50,000 MW of additional capacity (including 10,000 MW of replacement capacity) to come on stream by 2028 to ensure an adequate reserve margin. Two programmes have been implemented by the Department of Energy to help meet energy needs: the Renewable Energy Feed-In Tariff programme, under which Eskom is the proposed off-taker under certain power purchase agreements (“PPAs”); and a peaking power programme (“IPP Programme”) under which Eskom is also the proposed off-taker of electricity generated by IPPs in peak periods under certain PPAs. In the financial year ended 31 March 2013, the Group added 1.1 GW of IPP capacity to the national grid and Eskom signed PPAs for the first round of the Department of Energy’s IPP Programme, and approved procurement of other IPP generated power (including round two of the renewable energy IPP programmes) amounting to 4,753 MW. The total energy procured through IPP programmes as at 31 March 2014 was 3,671GWh. A total capacity of 4,280 MW had been contracted with IPPs as at 30 September 2014. In 2005, the Group initiated its committed capital programme to increase its generation capacity with 17.4 GW (200 MW of which will be from renewable energy sources) by the 2020/21 financial year. The Group has not approved or committed to any capital investments beyond those projects currently included in the programme, neither has it secured or applied under the MYPD 3 determination for any funding for such new build. Overall, the current committed capacity expansion programme (up until the 2020/21 financial year) is expected to require total investment of approximately R348 billion (excluding capitalised borrowing costs). The Group plans to fund the programme with shareholder equity, external debt and its operating cash flow and revenue. While funding for the next two to three years has largely been secured, given the estimated revenue gap created by the MYPD 3 determination together which has recently been revised upwards in light of the Group’s revised budget projections, it is currently anticipated that liquidity and cashflow problems will be concentrated over the last three years of this period, and the Group will have to secure additional funding to fully execute the plan. The table below sets out the Group’s completed expansion activities for the six months ended 30 September 2014 and the financial years ended 31 March 2014 and 2013.

For the six months For the financial year ended 31 March ended 30 September 2014 2013 2014 (actual) (planned) (actual) (planned) (actual) (planned) Capacity Expansion Generation capacity installed and commissioned (MW) ...... 120 130 261 260 - - Transmission lines installed (km) ...... 810.9 770 787 900 161.8 171.6 Transmission transformer capacity installed (MVA)...... 3,790 3,790 3,580 3,545 90 90 Distribution lines installed (km) ...... 329,419 - 350,289 - 46,285 - Distribution transformer capacity installed (MVA) ...... 93,829 - 89,959 - 4,036 - The success of the committed capacity expansion programme is critical for maintaining the Group’s ability to provide a sustainable and reliable supply of electricity for South Africa. The Group has commissioned and is pursuing a variety of projects under its committed capacity expansion programme, which include the following: New OCGTs The Group commissioned the construction of Ankerlig and Gourikwa liquid fuel OCGT stations, which are located in Atlantis and Mossel Bay. Construction began in January 2006 and the stations came into operation in June 2007. The units together added an additional 2,084 MW of nominal capacity. While the Group’s intention was originally to limit the use of these two power stations to peak demand periods only, given the capacity constraints experienced in the last few years, the gas turbines have been used to add additional capacity to the grid more regularly.

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Power stations returned to service Three mothballed coal-fired power stations were decommissioned in the late 1980s and early 1990s due to excess capacity. As a result of increasingly high energy demand and decreasing reserve margins, in 2004 the Group approved the return to service of the Camden, Grootvlei, and Komati coal-fired power stations. All eight units of the Camden power station were recommissioned by 2009, adding 1,520 MW of installed capacity. At 31 March 2013, the six units at Grootvlei have been recommissioned and are fully operational, adding a further 1,200 MW of installed capacity. In addition, eight of the nine units at Komati were commissioned in 2012, with the remaining unit commissioned by 30 September 2013. The returned to service units have experienced minor capacity constraints due to technical reasons which are addressed as plant enhancements are undertaken. Camden, Grootvlei, and Komati are expected to remain serviceable until 2025 to 2030. Additionally, the Arnot coal-fired power station situated near Middelburg in Mpumalanga underwent an extensive refurbishment and upgrade of its electrical and mechanical plant, increasing capacity by 300 MW. The upgrade was completed on 5 March 2012. New coal-fired power stations The construction of two large, coal-fired plants, Medupi (4,764 MW of capacity) and Kusile (4,800 MW of capacity), is still in progress. The first unit of Kusile has been scheduled for commissioning in December 2017 and the last unit in 2021. The first unit of Medupi, Unit 6, is on track for synchronisation on in the first quarter of 2015 with full commercial operation expected to commence six months thereafter. Only Medupi’s Unit 6 is contracted for first synchronisation in the 2014/15 financial year. Subsequent units of Medupi and Kusile will thereafter be contracted on capacity installed and commissioned. The Medupi power station is a greenfield coal-fired base load power station being constructed in Lephalale in the Limpopo province. When completed, it will comprise six boilers, each powering a 794 MW turbine, producing a total of 4,764 MW. It is expected to be one of the largest dry-cooled coal-fired power stations in the world once completed. Super-critical boilers will be used to improve the efficiency of the plant. Medupi will be supplied with coal from Exxaro’s Grootegeluk coal mine, located to the north of the site. Due to, among other things, poor contractor performance, technical difficulties and ongoing labour challenges, including industrial action in July 2014, the synchronisation of the first unit of Medupi, originally scheduled for the end of 2013, is now expected to take place in the first quarter of 2015. Additional resources have been mobilised by the contractors to mitigate resource-driven delays and additional shifts have been introduced to accelerate progress. The first coal for Medupi has been delivered to the stockyard. Running of coal conveyors, delivery of coal and optimising of the complete coal-in and ash-out systems continue. “Coal stacker 1” was safety cleared and commissioning is progressing well. The coal mills are also in the process of being commissioned. Site integration tests for Unit 6 and balance of plant were successfully completed, which means that the distributed control system is ready to support first fires and synchronisation. The legal registration of the boiler was obtained on 16 October 2014. The critical path to first synchronisation of Unit 6 remains through the delivery, installation, testing and integration of the boiler protection system, together with the distributed control system. The recovery strategies that were put in place to implement solutions to the post-weld heat treatment were successful and the technical issues surrounding welding on the Unit 6 boiler at Medupi have been resolved. The weld procedure requalification exercise has also been completed, with all weld procedures verified and accepted by both Eskom and the authorised inspection authority. Since 31 March 2014, the following milestones have been achieved:

• The “boiler chemical clean”, the “draught group test run” and the site integration tests for Unit 6 and the balance of plant have been successfully completed. The distributed control system is ready to support first coal fire and synchronisation.

• The first oil fire of Unit 6 was successfully achieved on 17 October 2014.

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• The water treatment plant ran continuously for 24 hours on 15 July 2014, producing demineralised water for steam production. Although problems have since been experienced, mitigation plans have been put in place to ensure that adequate demineralised water is available.

• The first coal was delivered to the coal stockyard, “coal stacker 1” was safety cleared, and commissioning of the coal stacker and coal mills is progressing well.

• The first coal fire was successfully achieved on 27 November 2014. The remaining milestones leading up to first synchronisation include boiler blow-through and steam to set. The Medupi transmission integration implementation is also on track and ready for the synchronisation of Units 6 to 1 to the Eskom grid. The commissioning of the next unit, Unit 5, was initially forecast to occur within six months of bringing Unit 6 online. This is no longer possible due to the challenges experienced at Unit 5, as resources were redeployed from Unit 5 to Unit 6 in an attempt to recover the delayed schedule at Unit 6. The expected completion date of Unit 5 is September 2017. New pumped-storage facilities The construction of a 1,332 MW pumped-storage plant (Ingula) near Ladysmith is in progress. For the past 12 months, limited progress was made as all work on the plant was ceased following an accident, where six contractors died and seven were seriously injured at the Ingula pump storage scheme on 31 October 2013. Work re-commenced in September 2014 to allow the main underground works to continue. As a result of the delay, the expected date of the first synchronisation of Unit 3 has been pushed back from November 2015 to the second quarter of 2016, with the remaining three units following at approximately two-monthly intervals thereafter. An investigation of the incident in terms of Section 60 of the Mines Health and Safety Act (“MHSA”) was converted into a formal inquiry in terms of Section 66(1) of the MHSA. The evidence-gathering inquiry was conducted at Ingula from 21 July 2014 to 2 September 2014. The Presiding Officer requested written closing submissions to be made in relation to the evidence collected. The process was completed on 15 October 2014 and the Presiding Officer is as at the date hereof in the process of preparing a report in terms of Section 72 of the MHSA. The statutory processes which fall under the jurisdiction of external regulatory authorities are designed to determine the cause of the accident and to make recommendations to prevent similar occurrences. Most recently, Ingula’s two emergency diesel generators were hot commissioned and synchronised the 22kV distribution network to perform load testing. The diesel generators will be required to perform a black start when no offsite power is available during a wide-area outage, in the event of loss of the primary power supply to the station. The diesel generators can also be used in the event of flooding of the powerhouse, fire or when the tailrace tunnel is dewatered.

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New wind facility The Sere wind farm, a 100 MW facility, is located close to the town of Koekenaap in the Vredendal area of the Western Cape. The wind farm will contribute to the diversification of the Group’s energy mix and implement technologies that will support sustainable, clean and socially responsible electricity generation. Significant progress has been made in the construction of the wind farm, with all 46 wind turbines having been installed as at the date hereof. The 132kV line, as well as the new Skaapvlei substation, have been energised. The project achieved a milestone in October 2014 with the energising of the first string of seven wind turbine generators, a move that enabled Eskom to proceed with the final commissioning of these turbines. On 10 October 2014, as part of the final testing and commissioning, the first string of seven wind turbines were synchronised, adding 4.4 MW to the national grid. The achievement of this milestone is ahead of the initial target date of December 2014, and the project remains on track to be in full commercial operation by the end of March 2015. As at the end of December 2014 all 46 of the turbines were energised and are in the final stages of testing and commissioning, this includes a reliability test run that is required for each of the wind turbines. During the testing and commissioning phase the facility, although not in full commercial operation, is contributing power to the grid. New solar thermal pilot plant The new 100 MW Concentrating Solar Plant in the Northern Cape is under development and is expected to be completed by 2017 with the expectation that further solar projects will follow. Cost of new assets International studies suggest that the Group’s committed capacity expansion costs, which comprise a sizeable portion of its capital expenditure budget, are comparable with those of similar projects implemented worldwide. However, tariff levels in South Africa have historically always been and remain lower than in many other countries, which makes the funding of capital expenditure more difficult. NERSA’s MYPD 3 determination, which allowed an annual tariff increase of only 8% over the five year period up to 31 March 2018, was significantly below the annual tariff increases the Group had projected that it would need over the course of the MYPD 3 period and beyond to cover its capital expenditure budget for the period, much of which relates to costs accrued in connection with its committed capacity expansion programme. Prior to NERSA’s MYPD 3 determination, the Group’s planned capital expenditure budget for the MYPD 3 period was approximately R337 billion, while the Group’s current capital expenditure budget, as approved by NERSA in its MYPD 3 determination, is only R251 billion. In light of the ensuing revenue shortfall, the Group has performed a significant capital expenditure reprioritisation, including with respect to its capacity expansion programme, to address the Group’s critical business needs based on the Group’s strategic imperatives. Separately, following the announcement of certain execution delays at Medupi in July 2013, the Group confirmed that the costs of completion for the Medupi project are expected to increase to approximately R114 billion (excluding interest during construction, transmission costs and claims against contractors) from the original estimate of R91.2 billion. The Group indicated that the increase will, however, be funded from existing capital expenditure allocations and will not directly impact electricity tariffs. See “Risk Factors—Risks relating to the Group—Due to the size and complexity of the committed capacity expansion programme, the Group may fail to implement the programme on a timely and successful basis” and “Risk Factors—Risks relating to the Group—The Group’s activities are subject to government policy and there is uncertainty with respect to how the Government may elect to implement such regulations and fund resulting initiatives in the future and the impact they will have on the Group”.

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The following table sets out the planned commissioning dates for the first and last generating units of each of the power stations currently under construction as part of the Group’s committed capacity expansion programme. The first synchronisation of Medupi Unit 6 is planned for the first quarter of 2015, with full commercial operation of the unit being expected approximately six months later.

Medupi Kusile Ingula First unit ...... 2015 2017 2016 Last unit ...... 2019 2021 2017

Subsidiaries Eskom Enterprises The Issuer formed Eskom Enterprises in 1999 to carry out the non-regulated, electricity-related activities of the Group in South Africa, and all its other energy and related activities outside South Africa. By 21 February 2005, a large number of Eskom Enterprises employees (excluding those of Rotek and Roshcon) were transferred back to the Issuer. Eskom Enterprises is an asset-and-investment holding company, performing non-regulated work such as telecommunication, network protection and measurement. Among other subsidiaries, Eskom Enterprises also houses two major operating subsidiaries, Rotek and Roshcon. Through its Rotek and Roshcon operating subsidiaries, Eskom Enterprises provides lifecycle support, plant maintenance, network protection and support for Eskom’s line division for its capacity expansion programme. Eskom Enterprises has an additional subsidiary, Eskom Uganda Ltd, with an interest in an electricity operating and maintenance concession in Uganda. Another subsidiary of Eskom Enterprises, EEM, operated an operating and maintenance concession with Société de Gestion de l'Energie de Manantali (“SOGEM”). As reported in the Consolidated Financial statements of the Issuer, exit options were being pursued and as a result, EEM was reclassified as a discontinued operation. Subsequent to 31 March 2014, an agreement was reached between EEM and SOGEM for the sale of EEM’s assets and a mutual discharge from the operating and maintenance concession. The documents pertaining to the exit have been signed and EEM has received the net proceeds of the sale. All formalities required by law for the winding-up of EEM have been initiated and the process is expected to be finalised by February 2015. With effect from 1 July 2014, Eskom Enterprises has sold and transferred its operating assets to Eskom, with a small balance remaining to be transferred during the 2014/15 financial year. As a result, it will become an investment holding company of the Group. Rotek

• Engineering, construction and equipment provision company with sub-sections focused on particular lines of business.

• Power Generation Services, which repairs and maintains turbo machinery.

• Power Distribution Services, which repairs and maintains transformers and switchgear equipment.

• Bulk Water Services, which operates, repairs and maintains water schemes.

• Rotek has a 240 hectare site at Rosherville, close to the centre of Johannesburg. Roshcon

• Electrical Infrastructure, which manage electrification contracts and electricity revenue management services.

• Civil Infrastructure, which is active in general civil construction.

• Waste, Environmental and Bulk Materials, which manages domestic, industrial and mining waste, and bulk material stockpiling and reclamation.

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Eskom Finance Company Eskom Finance Company was established in 1990 primarily to enable its Eskom employees to have access to home loan financing, while optimising home ownership costs for both Eskom and its employees. Eskom is in the process of finding an appropriate disposal solution for this subsidiary at the request of its shareholder. As it currently does not meet the requirements as stated in IFRS, it has not been classified as a discontinued operation in Eskom’s financial statements. Escap See “—Insurance—Escap (Self-insurance programme)”. Eskom Development Foundation Eskom Development Foundation (a non-profit company) is a wholly owned non-profit company that manages Eskom’s corporate social investment initiatives. Eskom Development Foundation is solely funded by Eskom and focuses on initiatives to develop small and medium enterprises, education, health, food security, communities, energy and the environment. During the financial year ended 31 March 2014, Eskom Development Foundation approved funding for initiatives to the value of R132.9 million, in order to ensure the sustainability and continuity of its current projects. Insurance Subject to specific exclusions, the Group is insured against all loss of or damage to the construction projects (including hot testing and commissioning of turbine generators and boilers). Each project is insured up to the contract value, including any escalation provisions. However, there is currently no cover for public liability claims in relation to any nuclear incidents. See “Risk Factors—Risks relating to the Group—The Group may not have adequate insurance coverage to cover all potential risks”. Subject to certain exclusions, the Group is insured against all loss, destruction or damage of its assets (including mechanical and electrical breakdown of machinery, plant, data processing media and other equipment and any boiler explosions). The assets of the Group with an historic cost value of R432,375 million (R1.178 trillion on a replacement value basis) as at 30 September 2014 were insured on a replacement value basis up to a maximum of R25 billion per any one event. The Group has insurance cover of up to R3 billion for any single incident in respect of fraud and theft of the Group’s money or property by the Group’s employees and directors. The Group is insured against losses incurred in respect of general liability, product liability, professional indemnity, environmental liability (for any sudden and unforeseen incidents). The limit of liability is R5 billion for any single incident and in the annual aggregate. The Group’s directors and officers are insured against being sued in their personal capacities for claims made against them for decisions made in discharging their fiduciary duties in the Group. The limit of liability is R3 billion for any single incident and in the annual aggregate. South Africa is not a signatory to the Vienna Convention on Civil Liability for Nuclear Damage of 21 May 1963, as amended, which was designed to establish some minimum standards for financial protection against damage resulting from peaceful uses of nuclear energy and to permit the contracting governments to set limits on the liability relating to nuclear power plants in their respective jurisdictions. However the National Nuclear Regulator Act requires the Group, as operator of Koeberg nuclear power station, to furnish security in the form of an insurance policy or bank guarantee of U.S.$450 million for its strict liability to third parties for liability in terms of the National Nuclear Regulator Act arising out of the operation of Koeberg, which security is furnished in the form of an insurance policy. The security may be increased by the Minister at any time. Should claims exceed the security, this would be referred to Parliament for consideration of an appropriation from the Government to fund such excess amount. The policy is reinsured by the South African and international nuclear pools together with the European Mutual Association of Nuclear Insurers (“EMANI”) to a limit of U.S.$450 million, which is the equivalent of the amount required by the NNR.

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Escap, a wholly-owned subsidiary of the Issuer, underwrites the first U.S.$25 million of any nuclear and non-nuclear losses in respect of property damage. Thereafter, the Group is covered by the South African nuclear pool, the international nuclear pools and EMANI. The indemnity limit is U.S.$2.4 billion. Escap (Self-insurance programme) The Group’s captive insurance subsidiary, Escap, provides a full range of customised short-term insurance products to the Group. Escap, a wholly-owned subsidiary of the Issuer, acts as the insurer for the Group. It insures the accident and health, engineering, liability, motor, property, transportation and miscellaneous classes of the short-term insurance business. It also insures motor vehicles in terms of the Group’s employee vehicle allowance scheme. Escap was established in 1993 to reduce the Group’s overall cost of insurance. It forms part of the Group’s insurance and risk financing strategy to formalise the insurance function and acts as a vehicle for building reserves and additional insurance capacity. Escap insures the Group up to agreed limits per risk above which the risks are covered by the reinsurance market. Escap’s underwriting profit for the six months ended 30 September 2014 was R146.5 million, compared to an underwriting profit of R33.2 million for the six months ended 30 September 2013. Escap’s underwriting loss for the financial year ended 31 March 2014 was R1,460.6 million, compared to an underwriting loss of R53.8 million for the financial year ended 31 March 2013. The loss in 2013/14 was largely as a result of high claim loss ratios on Generation, Transmission and Distribution assets, while the loss in 2012/13 was largely as a result of high claim loss ratios on Generation and Transmission assets. Escap recorded a net profit after tax of R248.3 million for the six months ended 30 September 2014, compared to a net profit after tax of R140.3 million for the six months ended 30 September 2013. Escap recorded a net loss after tax of R781 million for the year ended 31 March 2014, compared to a net profit after tax of R120.2 million for the year ended 31 March 2013. Reinsurers The creditworthiness of reinsurers is regularly assessed by the Escap risk management committee, especially prior to finalisation of any contract. Minimum credit ratings and credit limits per counterparty are set to monitor risk. The major reinsurers used during the financial year had market security ratings of A- or higher (based on S&P’s ratings). There has not been any write-off of receivables from reinsurers in the last three years. Independent Power Producers To address increased capacity requirements, the Government has decided to allow IPPs to generate electricity in South Africa. As at 30 September 2014, the Group had signed PPAs accounting for a total of 4,280 MW of generating capacity. The IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) contemplates that IPPs could account for up to 30% of the additional new electricity generation capacity by 2030. The Department of Energy has put out to tender a project for IPPs to build approximately 1,000 MW of new generation capacity in the form of two oil-fired OCGTs, operating as peaking plants in the Eastern Cape and KwaZulu-Natal. Eskom also signed PPAs for the first round of the Department of Energy’s IPP Programme and approved procurement of other IPP-generated power (including round two of the renewable energy IPP programme) amounting to more than 1,000 MW. In addition, the Group is also in the process of implementing a contract management strategy for IPPs. However, the deadlines for connecting IPPs to the grid are exceptionally tight and the Group has encountered delays stemming from difficulties expropriating affected lands. Moreover, the MYPD 3 determination did not include sufficient funding to pay for all the IPP purchases contracted for the financial year ending 31 March 2015 which, among other things, may hinder the Group’s efforts to ensure grid code N-1 redundancy compliance by 2016, when it has committed to NERSA it will be fully N-1 complaint.

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Other Business Imperatives Ethical business practices The Group is committed to the highest ethical standards and principles in all of its business. The ethics office assists the chief executive in setting the framework, rules, standards and boundaries for ethical behaviour, and provides guidance to the Group on ethical conduct. Furthermore, the Group’s ethical standards are reflected in the Group’s Code of Ethics, which establishes the foundation for the interaction of the Board and its employees with colleagues, customers, suppliers, shareholders, the environment and other stakeholders and provides a common language and understanding of what ethical behaviour means in the Group. The Code of Ethics was a product of an independent ethics climate survey performed in 2006. The Code of Ethics not only describes the acceptable behaviour and attitudes that are essential in living the Group’s values but also assists the Group in being a role model amongst its peers. Employees As at 30 September 2014, the Group had 46,370 employees (permanent staff and fixed-term contractors). The majority of the Group’s employees are represented by three recognised trade unions, which represent approximately 28,519 employees. Since 1941, forums have been implemented in order to obtain input from representatives of the trade unions on matters that may affect the Group’s employees. Trade union representatives and management participate in these joint forums permitting trade union representatives the opportunity to communicate their concerns about the Group’s long-term planning objectives and an opportunity to resolve more immediate matters such as wage negotiations. The Group’s management believes that regular forums have been an effective means of working with the trade unions that represent the Group’s employees. The Group has experienced occasional strains in labour relations, which have not materially affected its operations. Strikes are rare since under relevant legislation employees who provide essential services in South Africa, which includes electricity, are limited in their right to strike. The Group has an incentive scheme for its employees, under which employees are awarded performance-based incentives in certain circumstances. Awards under the scheme are subject to certain corporate prerequisites and individual key performance indicators. Competition The Group does not currently have any significant competitors in South Africa with respect to the generation and transmission of electricity. In the short-to-medium term, the Government’s strategy focuses on ensuring the supply of electricity and is facilitating the introduction of IPPs. See “—Independent Power Producers”. Over the next five years, the Group expects IPPs to account for a small proportion of electricity generation in South Africa. However, the IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) contemplates that IPPs could account for up to 30% of the additional new electricity generation capacity by 2030. Safety The chief executive, as chief safety officer, is responsible for overall sustainability and safety performance. Strategies for improving safety are reviewed and approved by the Group’s executive committees. Practical strategies implemented to ensure continual focus in this area include visible leadership, improved discipline, and overall accountability for safety. The strategy includes addressing vehicle, construction, contractor and electrical safety, as well as the role of leadership.

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The following table shows the number of fatalities of employees and contractors, as well as of members of the public involved in accidents with the Group’s employees or equipment.

For the period ended For the financial year ended 30 September 31 March 2014 2013 2014 2013 Fatalities Employees ...... 1 2 5 3 Contractors ...... 6 8 18 16 Public ...... 11 23 33 29 Total ...... 18 33 56 48 For the period ended 30 September 2014, the Group experienced one employee and six contractor fatalities (compared to two employee and eight contractor fatalities for the period ended 30 September 2013). The single employee fatality resulted from an electrical contact incident, while the six contractor employee fatalities were due to two motor vehicle accidents, two assault cases, one person being struck by an object and one falling from a height. The cases of assault related to contractors who were shot while in transit between sites. These cases are currently under investigation. The increase of crime-related cases affecting security personnel especially is a concern. The Group continues its implementation of various safety improvement initiatives such as the key performance indicator to monitor compliance with safety behaviours, concluding a health and safety agreement between the Group and its trade unions and approving the Group’s contractor safety management plan. The Group is also in the process of establishing a SHE-S Inspectorate, which conducts intensive inspections to identify instances of non-compliance and improvement opportunities before notices (improvement, contravention or prohibition) are issued to the business by governmental authorities. The ultimate goal is to reduce the number of safety-related incidents for both employees and contractors to zero. Additionally, five public fatalities were caused by contact with electricity and six by motor vehicle accidents. Electrical contact due to criminal activities (illegal connections) and motor vehicle accidents remain the major causes of public fatalities. The Group has embarked on a public safety programme which is aimed at managing public incidents within the areas where the Group operates, with the intention of eliminating public incidents and reducing public liability risks by educating and training the members of the public about electricity safety. The number of employee fatalities in the 2013/14 financial year remained high at five fatalities (compared to three in the 2013/14 financial year) with an increased exposure of employees and contractors to crime related assault incidents. Additionally, there were 18 contractor fatalities (compared to 16 in the 2013/14 financial year), six of whom died in an accident in October 2013 at the Ingula pumped-storage facility. An investigation of the incident in terms of Section 60 of the MHSA was converted into a formal inquiry in terms of Section 66(1) of the MHSA. The evidence-gathering inquiry was conducted at Ingula from 21 July 2014 to 2 September 2014. The Presiding Officer requested written closing submissions to be made relative to the evidence collected. The process was completed on 15 October 2014 and the Presiding Officer is as the date hereof in the process of preparing a report in terms of Section 72 of the MHSA. The statutory processes which fall under the jurisdiction of external regulatory authorities are designed to determine the cause of the accident and to make recommendations to prevent similar occurrences Despite these incidents, the Group remains committed to reduce this number in future and to continue to improve its safety performance. Safety initiatives to mitigate the risks faced by employees, contractors and members of the public include:

• conducting monthly safety audits of principal contractors (as opposed to every six months);

• devising contractor-management plans with safety performance targets;

• improving procedures for reporting safety incidents and identifying root causes;

• detailing specifications for personal protective equipment;

• using simulators to train truck drivers in defensive and all-terrain driving;

• hosting public safety intervention to educate the members of the public about electrical safety;

• implementing vehicle safety initiatives to improve driver safety awareness;

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• ensuring compliance with the Group’s and legal requirements;

• establishing and maintaining an OHS Management system that will provide a framework and methodology according to which OHS can be managed; and

• developing an Eskom OHS dashboard as well as divisional to monitor compliance to focus areas and specific initiatives. After 26 consecutive years of safe operation at the Koeberg facility, an event occurred in September 2010 during scheduled maintenance and inspection of Koeberg Unit 1, which resulted in internal contamination of radiation workers with Cobalt-58. The levels of contamination were well below the statutory limits established by the NNR (the highest level of contamination was 4.7% of the statutory limit). The event was rated at “below scale/level 0” on the IAEA International Nuclear and Radiological Event Scale. Although radiation workers are expected to be exposed to low levels of radiation, the event was given extremely high priority by the Group and measures have been implemented to prevent a repeat occurrence. A nuclear safety review board (consisting of experienced international nuclear power experts) was established earlier in 2014 to provide an additional and independent expert review of the management and performance of the Koeberg nuclear power station. The chairperson of this board provides a six-monthly report to the board Social, Ethics and Sustainability Committee. All serious incidents are discussed at the EXCO and operations meetings. Case studies sharing the lessons learnt from investigations are made available throughout the Group to continually improve the health and safety performance. The Group’s safety improvement programme has led to enhanced leadership and operational discipline amongst employees. Climate Change The Group is subject to environmental legislation and policy and, as its operations have an impact on the environment, strives to fulfil its obligations in a responsible manner. Environmental performance is managed as an integral part of the Group’s governance structure, from the Board’s Social, Ethics and Sustainability committee, to the EXCO. Accountable senior managers with the support of environmental managers and environmental practitioners ensure the effective implementation of environmental management systems throughout our business. In terms of environmental control, the Group is regulated by means of environmental authorisations, licences and permits issued by various national, provincial and local licensing authorities. These include licences and permits for the construction of power stations, substations, power lines, waste (including ash dams and dumps), emissions and water use. In order to support the government in furthering the outcomes of the 17th Conference of the Parties to the United Nations Convention on Climate Change, and its National Climate Change Response policy, the Group has developed a Climate Change Strategy. The Group’s current Climate Change Strategy is summarised by the Group’s six-point plan on climate change. The elements of the plan are:

• diversification of the generation mix to lower carbon emitting technologies;

• energy efficiency measures to reduce demand and greenhouse gas and other emissions;

• adaptation to the negative impacts of climate change;

• innovation through research, demonstration and development;

• investment through carbon market mechanisms; and

• progress through advocacy, partnerships and collaboration. The Group signed its first Emission Credits Purchase Agreement with the European bank, BNP Paribas, in September 2010. This agreement is the outcome of an open enquiry for bids requested to develop the clean development mechanism for the Group’s CFL programme, which replaced 43 million light bulbs with

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compact fluorescent lighting. This was the first time the Group used the global carbon market to achieve its sustainability objectives. The carbon assets that will be created from this project are certified emissions reduction and voluntary emissions reduction that will be traded with BNP Paribas. Following the signing of this agreement and the implementation of the Clean Development Mechanism (“CDM”) process through the UN, the Group successfully registered two small scale CFL projects and one CFL CDM project with the United Nations Framework Convention on Climate Change. The Group therefore currently has three CDM projects on the UN registry. The carbon credits that are generated from implementing the CFL projects in the residential sector are expected to be sold to BNP Paribas to generate carbon revenue for the Group, in order to support the continuous implementation of low carbon technologies such as CFLs and Light-Emitting Diodes. Black Economic Empowerment The Group continues to support broad-based black economic empowerment (“BBBEE”) through its affirmative procurement policy. A new element of the Group’s BBBEE policy was developed and implemented in 2002, and focuses on the empowerment of businesses owned and run by black women. The Group’s objective in this regard is to promote black female entrepreneurs and facilitate their participation in the mainstream economy. The Group will target black-women-owned suppliers and assist them to partake in the procurement of goods and services, for example, by including them in the hierarchy of procurement or by setting aside a portion of the tender concerned. The Group’s BBBEE spending is made across a diverse range of goods and services that the Group procures in its day to day operations. These include coal and coal transportation, transformer, control and instrumentation systems, and plant maintenance. Each supplier (other than those who are exempt) must provide the Group with its BBBEE certificate to show its level of compliance. The certification of the suppliers is then measured to determine the BBBEE attributable spend. The Group’s internal target for BBBEE is 70% of total measured procurement spend, 10% of which is attributed to black-women-owned suppliers. Total measured procurement spend is the procurement amount after deducting those exclusions which the Group cannot measure, such as imports, salaries, rates and taxes. The total measured procurement spend is then classified as an amount which was paid for the procuring of goods and services which should determine the BBBEE spend, if the supplier has a valid certificate. Although there are no specific sanctions for failing to achieve BBBEE targets, the Group is committed to the policy and its performance in relation to it is a key indicator of internal performance. In the six-months ended 30 September 2014, 75% of the Group’s measured procurement spend of R66.9 billion went to BBBEE companies. Of the total BBBEE attributable spend, R57.8 billion, or 97%, was spent on vendors with BBBEE levels 1 to 4, and only 3% on vendors with levels 5 to 8 BBBEE status. The Group’s internal targets for black and female employees in senior management, middle management and professional positions were met for the financial year ended 31 March 2014. Managing the impact of HIV/AIDS HIV/AIDS continues to present a significant social, economic and demographic problem to countries in sub-Saharan Africa. The Group is committed to managing the impact of HIV/AIDS through integrated response strategies which aim to empower all its employees through knowledge and awareness of HIV/AIDS, which will, in turn, enhance the sustainability of the Group’s business. Special attention is given to voluntary counselling and testing access to employee assistance programmes and to other methods of prevention. The ongoing HIV/AIDS education and awareness programme continues to promote voluntary confidential counselling and testing among employees. A communication plan in the form of a comprehensive toolkit has been developed to communicate the Group’s HIV/AIDS response strategies in a structured way throughout the organisation. The Group maintains a strategic focus on HIV/AIDS related developments, and provides updated management information regarding HIV/AIDS related issues. Other response strategies include ensuring that all business practices affected by HIV/AIDS adopt a non-discriminatory approach. A communication plan in the form of a comprehensive toolkit has been developed to communicate the HIV/AIDS response strategies in a structured way throughout the organisation.

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The Group continues to be committed to forming strategic partnerships aimed at enhancing effectiveness in the handling of community issues. To this end, the Group has pledged to support the Government through its “HIV Counselling and Testing campaign”, which has the objective of testing 15 million South Africans for HIV/AIDS. This campaign was nominated as a finalist in the ‘GBC Health Business Action on Health Awards’ in May 2012. Litigation and Investigations Neither the Issuer nor any other member of the Group is involved in any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened) which may have, or have had during the 12 months preceding the date of this Base Prospectus, a significant effect on the financial position or profitability of the Issuer or the Group. On 5 September 2014, following a tender process, the Group concluded a contract with Areva for the replacement of six steam generators at the Koeberg nuclear power plant, valued at approximately R4 billion. In September 2014, Westinghouse Electricity S.A. (“Westinghouse”), the unsuccessful bidder secured a court order from the High Court of South Africa, Gauteng Local Division, Johannesburg (“Gauteng Local Division”) requiring the Group to hand over all the relevant documents leading up to and forming the basis of Eskom’s decision to award the tender to Areva. In October 2014, Westinghouse launched an application in the Gauteng Local Division challenging Eskom’s decision to award the tender to Areva and seeking to set aside Eskom’s contract with Areva and to compel Eskom to enter into an agreement with Westinghouse on the terms set forth in the latter’s final offer made during the tender process (the “Review”). While the Group believes that it cooperated fully with the September 2014 court order, in November 2014, Westinghouse filed an urgent application in the Gauteng Local Division for contempt of court and the committal of certain of Eskom’s employees, alleging that the designated employees had deliberately withheld certain documents in breach of the September 2014 court order. The contempt application was, following agreement between the parties, withdrawn from the urgent roll for determination in the ordinary course and has been postponed. A hearing in connection with the Review has been provisionally set for mid-February 2015. The Group believes that Westinghouse’s legal challenge is unfounded and will continue its vigorous defence of the matter. The Group, which, to date, has made no provisions in its financial accounts in respect of this matter, is confident that it will be successful in its defence of the legal challenge. On 21 November 2014, the Group’s external auditors reported an irregularity in terms of section 45(1) of the Auditing Profession Act to the Independent Regulatory Board for Auditors. The alleged irregularity relates to the conclusion of a sponsorship contract amounting to R43 million by a member of the accounting authority contrary to the Group’s delegation of authority applicable to that contract. This resulted in alleged irregular expenditure as contemplated in the PFMA. To date, no payment has been effected pursuant to this contract. The matter was identified by management and is being considered by the Board, which included the commissioning of an independent review by an independent external audit firm. The Board is presently considering the findings of the review. The matter is receiving the full attention of the Board, and the Group is committed to the consistent enforcement of, and adherence to, principles of the highest standards of corporate governance.

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MANAGEMENT Board of Directors Eskom has a unitary board structure with a majority of independent non-executive directors. The Board currently consists of 13 directors, comprising two executive directors (the chief executive and the finance director) and 11 non-executive directors (which includes the chairman of the Board). Directors are appointed by the Minister of Public Enterprises, are drawn from diverse backgrounds, are representative of the gender and race demographics of South Africa and bring a wide range of experience and professional skills to the Board. The Memorandum of Incorporation of the Issuer provides that the Government, as sole shareholder of the Issuer, appoints the Issuer’s executive directors (the chief executive and the finance director) and non- executive directors through the Department of Public Enterprises. On 20 August 2014, the Minister of Public Enterprises announced the appointment of Mr. Tshediso Matona as the Chief Executive of Eskom, effective as of 1 October 2014. In December 2014, upon the conclusion of a five month review period following the Issuer’s 2014 AGM, the Minister of Public Enterprises replaced nine of the Issuer’s 13 directors, reappointing the chairman of the Board and one other non-executive director and leaving in place the Issuer’s two executive directors. The new composition of the Board became effective on 11 December 2014, and the formal induction of the new directors is scheduled for January 2015. Executive directors are permanent employees in terms of the Issuer’s conditions of service. The business address of each member of the Board is the registered address of the Group. The members of the Board are set out below. Name Principal outside activities Mr. Zola Tsotsi (independent Mr. Tsotsi is a chemical engineer. Mr. Tsotsi’s experience in non-executive director and Chairman of the energy sector has grown over the years from roles in a the Board) ...... number of both International and local organisations. He joined Eskom in 1995 as the Environmental Affairs Manager, during which Eskom received the prestigious Industry Award for Environmental Reporting in 1996. Mr. Tsotsi served as Director in different companies: 1983 -1995 Afritek Consulting (Pty) Ltd; 1998 to present: Torre Technologies (Pty) Ltd; 2007 to present: Mandla Technologies (Pty) Ltd; 1997 to 1998: Eskom Pension Fund trustee; 1999 to 2001: Eskom Development Foundation; 2004 to 2007: Maisha Energy (Pty) Ltd; 1999 to 2006: Ernie Els Foundation; 1997 to present: Endangered Wildlife Trust. Mr. Tsotsi has also served as chairman in numerous companies: 1993 to 1994: Lesotho Highlands Development Authority; 1993 to 1994: Lesotho Electricity Corporation; 1993 to 1994: Water and Sewerage Authority (Lesotho); 2004 to 2011: Lesotho Electricity Authority (Regulator); 1987 to 1993: Association of Basotho Consultants. He was a corporate consultant of the Issuer from 2000 to 2004 and a corporate strategy manager between 1997 and 2000. Mr. Tsotsi also headed the board of directors of the Lesotho Highlands Development Authority and the Lesotho Electricity Corporation. He holds a Bachelor of Science degree in Mathematics and Chemistry from the Botswana University, Lesotho Campus. In 1974, he was awarded an Honours degree in Chemical Engineering from the University of Surrey in the United Kingdom. He is a director at Torre Technologies (Pty) Limited and Mandla Technologies (Pty) Limited. Mr. Tsotsi was appointed as Chairman and as an independent non-executive director to the Board in June 2011 and re-appointed on 11 December 2014. He is the Chairman of the Board Build Programme Review Committee and a member of the People and

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Name Principal outside activities Governance Committee and Social, Ethics and Sustainability Committee. Mr. Tshediso Matona (chief executive) ...... Mr. Matona is a long serving professional public sector executive, akin to Eskom CEO. He has served in a number of significant high positions within the public sector. Mr. Matona served as Director General of the Department of Public Enterprises, where he gave oversight to eight major state-owned companies, including Eskom between 2010 and 2014. He was also a Task Team Member of the Accelerated and Shared Growth Initiative for South Africa. Mr. Matona has led negotiations and agreements which allowed the South African economy to be re-integrated into the global economy. Mr Matona is a member of several professional bodies including: Member of Trade and Industrial Policy Secretariat; Member of Trade and Industrial Policy Strategies (TIPS) Advisory Board; National Export Advisory Board, chaired by the Minister of Trade and Industry; Commission on Intellectual Property right, Innovation, and Public Health (World Health Organization); and a member of Trade Law Center (Tralac) Advisory Board. He holds a Master’s degree in Development Economics from the University of East Anglia in the United Kingdom, and a Bachelor of Social Science (Honours) degree in Economics and Political Science from the University of Cape Town. He also holds a diploma in International Trade Policy & Law from GATT/WTO Geneva and a Certificate in International Trade from the University of Maastricht. Mr. Matona participated in the Senior Executive Management Programme from Harvard Kennedy School of Government in 2003. Mr. Matona was appointed as Chief Executive in October 2014. He is a member of the Social, Ethics and Sustainability Committee, the Investment and Finance Committee and the Board Build Programme Review Committee. Mr. Norman Tinyiko Baloyi (independent Mr. Baloyi is a Director of Information Technology at the non-executive director) ...... Human Science Research Council (HSRC). He holds a Bachelor of Commerce in Financial Management, Bachelor of Science in Computer Science and Mathematics, Higher Diploma in Computer Auditing, Postgraduate Diploma in Business Management, Masters of Business Administration, Masters of Science in Electrical Engineering and Masters of Science in Electronics. He was appointed non-executive director on the Eskom board effective 11 December 2014. Mr. Baloyi is the Chairman of the Audit and Risk Committee and a member of the Social, Ethics and Sustainability Committee and the Board Build Programme Review Committee. Dr. Pathmanathan Naidoo (independent Dr. Naidoo is a self-employed Specialist Consultant and non-executive director) ...... Resident Professional Engineer. Dr. Naidoo holds the following qualifications: Philosophiae Doctor (PhD) of Management of Technology and Innovation from the Da Vinci Institute for Technology Management in South Africa, Masters of Science in Electrical Engineering from the University of KwaZulu-Natal, Masters of Business Administration from Samford University in the United States, Bachelor of Engineering from the University of Durban Westville in South Africa and certificate in Modelling and Managing Competitive Electricity Markets, Utility

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Name Principal outside activities Management and Electricity Regulation. During his tenure at Eskom, Dr. Naidoo held various leadership positions with his last position being Engineer in Training to Senior General Manager including Technical Director for the Mozambique Transmission Company and Chief Executive for the Western Power Corridor Company, Botswana before he resigned from the company in 2010. He was appointed to the Eskom Board effective 11 December 2014. Dr. Naidoo is a member of the Social, Ethics and Sustainability Committee, the Investment and Finance Committee and the Board Build Programme Review Committee. Ms. Venete Jarlene Klein (independent Ms. Klein is currently the Chief Executive for Kleininc non-executive director) ...... Management Consultants. She has completed various management training programmes including a Senior Executive Programme at Harvard in the U.S. and the Executive Development Programme at the new School/University of Columbia in the U.S. Ms. Klein is also currently the Chairman of the Institute of Directors of South Africa. Ms. Klein is a non- executive director at various institutions including Old Mutual Wealth Proprietary Limited and the South Africa Bureau of Standards. Her appointment to the Eskom Board was effective 11 December 2014. She is the Chairman of the Social, Ethics and Sustainability Committee and a member of the Audit and Risk Committee and the People and Governance Committee. Ms. Nazia Carrim (independent Ms. Carrim is an attorney with a career in labour law. She non-executive director) ...... obtained her undergraduate qualification from the University of Johannesburg and completed her Masters qualification at the University of Limpopo. Ms. Carrim is also accomplished as an admitted conveyancer and a notary and in the years from 2006 to 2012, Ms. Carrim gained valuable experience at a Directorship level at Engelbrecht and Carrim attorneys as well as Peer and Carrim Attorneys. She currently serves as the head of Nazia Carrim Attorneys in Polokwane and was appointed as a member of the Eskom Board on 11 December 2014. Ms. Carrim is a member of the Audit and Risk Committee and the Tender Committee. Mr. Romeo Kumalo (independent Mr. Kumalo holds a Masters degree in Business and also has non-executive director) ...... Executive Management certificates from INSEAD in Paris and Wits Business School. He is an alumnus of the Harvard Business School. In 2012, Mr. Kumalo was appointed as the CEO of Vodacom International and prior to that had been serving on the Vodacom Executive Committee. He is also a non-executive director of Vodacom Tanzania, Lesotho, Mozambique and DR Congo. Prior to his position as a director from 2005 to 2010, Mr Kumalo has worked in various sales and marketing roles, has been a General Manager at Metro FM (1997-2000), SABC TV (2000-2004) and then as Strategic Business Development Director for Vodacom Group from 2004-2005. He was appointed member of the Eskom board on 11 December 2014. Mr. Kumalo is a member of the People and Governance Committee and the Audit and Risk Committee. Ms. Chwayita Mabude (independent Ms. Mabude is an accountant with a background in financial management. She holds a Bachelor of Accounting Science

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Name Principal outside activities non-executive director) ...... degree from the University of South Africa and was appointed to the Board in June 2011. Ms. Mabude is the Chairman of the People and Governance Committee and a member of the Tender Committee. Ms. Tsholofelo Molefe (Finance Director) . Ms. Molefe was appointed as the Finance Director for Eskom in January 2014. She is a qualified Chartered Accountant and a member of the South African Institute of Chartered Accountants. Ms. Molefe holds a Bachelor Commerce and an Honours degree in Accounting and Finance from the University of East London, United Kingdom, through the British Council Scholarship she was awarded from 1988 to 1992. She also holds a Bachelor of Accounting Honours Certificate in Theory of Accounting from the University of South Africa. Ms. Molefe is a member of the Tender Committee, the Investment and Finance Committee and the Board Build Programme Review Committee. Mr. Mark Vivian Pamensky (independent Mr. Pamensky is an accountant who completed his articles at non-executive director) ...... PriceWaterhouseCoopers. He is currently on the group’s main board of directors at Blue Label Telecoms Limited and is also employed there as the group Chief Operating Officer. He has a strong track record of helping to establish start-ups into successful businesses and effecting turn around strategies in others. After completing his articles Mr. Pamensky moved to Mercantile Bank in 1998. He started working at Nucleus Corporate Finance in 2000 and then moved to Blue Label Investments in 2001 and became COO in 2004. He was appointed member of the Eskom board on 11 December 2014. Mr. Pamensky is the Chairman of the Investment and Finance Committee. Mr. Zethembe Wilfred Khoza Mr. Khoza is currently a Managing Director responsible for (independent non-executive director) ...... Customer Services at Telkom. He is also a director of Zet Kay Investments PTY Limited. He also completed various leadership programmes including a Senior Executive Programme at Wits University and Harvard Business School. He was appointed member of the Eskom board on 11 December 2014. He was appointed member of the Eskom board on 11 December 2014. He is a member of the Tender Committee and the Investment and Finance Committee. Dr. Baldwin Sipho Ngubane (independent Dr. Ngubane holds a Bachelor of Medicine and Bachelor of non-executive director) ...... Surgery degrees (MB ChB) from the Durban Medical School. He completed a diploma in Tropical Medicine and a Diploma in Public Health at the University of the Witwatersrand. Dr. Ngubane also holds a Master of Family Medicine and Primary Health from Natal Medical School and a Postgraduate Diploma in Economic Principles from the University of London. Dr. Ngubane has held various leadership roles in and outside South Africa including Premier of KwaZulu-Natal in 1999, Minister of Arts, Culture, Science and technology in 2004 and the South African Ambassador in Japan in 2004. He was appointed member of the Eskom board on 11 December 2014. Dr. Ngubane is the Chairman of the Tender Committee and a member of the Board Build Programme Review Committee and the People and Governance Committee.

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Name Principal outside activities Ms. Devapushpum Viroshini Naidoo Ms. Naidoo. has worked in telecommunications, electronics and (independent non-executive director) ...... manufacturing industries and has extensive experience in the legal environment. Her experience has spanned across both private and public sectors. After completing her articles she opened Private Practice, a law firm which she ran for 9 years, wherein she acted for private, corporate and government. In 2001 she formed African Women Investments, which supplied diesel and oil to private and government. She was also one of the first executive members of South African Women in Mining KZN. She joined the corporate environment in 2007. She currently is head of legal at Mpact Limited. Ms. Naidoo completed her LLB in 1995 at the University of Durban Westville. She also has a certificate and diploma in Business Management as well as a Master of Business Administration from the Buckinghamshire Chilterns University in the UK. She was appointed member of the Eskom board on 11 December 2014. Ms. Naidoo is a member of the Audit and Risk Committee, the Social, Ethics and Sustainability Committee and the Board Build Programme Review Committee.

Role and function of the Board The Board is the “accounting authority” of the Issuer, as defined in the PFMA. This means that the Board is the accountable body of the Issuer under the relevant legislation. The Issuer’s systems and processes are reviewed to ensure that compliance is monitored in accordance with the PFMA. In addition, the Issuer is guided in best practice by the King Code and Report on Corporate Governance for South Africa and the Protocol on Corporate Governance in the Public Sector, as well as by international developments. The Board also ensures compliance with the SA Companies Act, which became effective in 2011. To ensure that the Issuer’s governance framework continues to be of a very high standard and is aligned with developments in statutory and governance best practice, the governance framework is reviewed on a regular basis. In keeping with good corporate governance practices, the Board has developed a Board charter, and has identified its role as follows:

• determining the goals and objectives of the Issuer;

• providing strategic direction and leadership;

• approving key policies, including investment and risk management;

• reviewing the Issuer’s goals and the strategies for achieving the Issuer’s objectives;

• approving and monitoring compliance with corporate/business plans, financial plans and budgets;

• reviewing and approving the Issuer’s financial objectives, plans and expenditure;

• considering and approving the annual financial statements, interim statements and notices to the shareholder;

• ensuring good corporate governance and ethics;

• monitoring and reviewing the performance and effectiveness of controls;

• monitoring and ensuring performance;

• ensuring that succession planning takes place;

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• guiding the restructuring and transformation process;

• ensuring effective communication with relevant stakeholders;

• liaising with and reporting to the shareholder;

• approving transactions that are above the authority level of management;

• taking responsibility for information technology risk;

• taking responsibility for the governance of risk;

• considering business rescue proceedings or other turnaround mechanism if and when necessary;

• promoting the stakeholder inclusive approach of governance;

• guiding key initiatives that ensure that the Issuer is a responsible corporate citizen; and

• ensuring that the Issuer complies with applicable laws, non-binding rules, codes and standards. The power and authority to lead, control, manage and conduct the business of the Issuer, including the power and authority to delegate, is vested with the Board to ensure that the Issuer remains a sustainable and viable business of global stature. It retains full and effective control over the operations of the Group. This responsibility is facilitated by a well-developed governance structure comprising various Board committees, executive management sub-committees and a comprehensive delegation of authority framework. This delegation framework assists in the control of the decision making process and does not dilute the duties and responsibilities of the directors. Public Finance Management Act The Board is the accounting authority in terms of the PFMA, and the Issuer is listed as a Schedule 2 major public entity. The PFMA also applies to subsidiaries and entities under the ownership and control of the Issuer, which are also classified as Schedule 2 entities. The PFMA regulates financial management and governance. The Issuer ensures that all directors and employees are aware of the provisions of the PFMA through the establishment of a dedicated PFMA Office that provides advice as well as regular training programmes. The Issuer and the Group are required to submit the following to the National Treasury and/or the Minister of Public Enterprises, its representative shareholder:

• an annual corporate/business plan, currently based on a four-year window from 1 April 2014 to 31 March 2018, that includes, amongst other items, strategic objectives, a risk management plan, a fraud prevention plan and a financial plan that also addresses asset and liability management, capital expenditure programmes and a borrowing programme. The most recent submission of the corporate/business plan was made to the Department of Energy and the National Treasury on 28 February 2014;

• quarterly business performance reports;

• audited annual financial statements; and

• quarterly reports on actual borrowings. Directors comply with their duties as set out in the PFMA. Board responsibilities under the PFMA include:

• establishing efficient, effective and transparent systems of financial and risk management and internal control;

• maintaining a system for the proper evaluation of all major capital projects prior to making a final decision on each project;

• implementing appropriate and effective measures to prevent irregular or fruitless and wasteful expenditure, expenditure in contravention of legislation or losses from criminal conduct;

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• ensuring that all revenue due to the Issuer is collected;

• ensuring economic and efficient management of available working capital; and

• defining objectives and allocating of resources in an economic, efficient, effective and transparent manner. Board Committees Several committees exist to assist the Board in discharging its responsibilities. This assistance is rendered in the form of recommendations and reports submitted to Board meetings, thus ensuring transparency and full disclosure of committee activities. Each committee operates within the ambit of its defined terms of reference, which set out the composition, role, responsibilities, delegated authority and requirements for convening meetings. All the committees comprise a majority of non-executive directors. Audit and Risk Committee The Audit and Risk Committee is appointed by the shareholder in accordance with the SA Companies Act. It fulfils the prescribed duties set out in the SA Companies Act, and the PFMA and related treasury regulations while also focusing on risk management. This committee comprises five independent, non-executive directors. Collectively, members have sufficient qualifications and experience to fulfil their duties, including an understanding of financial and sustainability reporting, internal financial controls, external audit process, internal audit process, corporate law, risk management, sustainability issues and IT governance. The committee’s roles and responsibilities include:

• to fulfill the statutory functions of the audit committee set out in the SA Companies Act and the PFMA risk management;

• IT governance; and

• serving as the audit committee for Eskom’s wholly owned subsidiaries. The assurance and forensic general manager and the external auditors have unrestricted access to the Audit and Risk Committee and the chairman of the board. Six scheduled committee meetings and three ad hoc meetings were held during the financial year ended 31 March 2014. Further meetings were held during the past six months ended 30 September 2014 and attended by various EXCO members. The meetings were also attended by the external auditors, the chief executive, the finance director, the acting chief financial officer, assurance and forensic representatives and other relevant company officials. Investment and Finance Committee The Investment and Finance Committee comprises three independent non-executive directors and two executive directors. The committee’s responsibilities include:

• reviewing the Group’s investment strategy and capital programme and making recommendations to the Board;

• evaluating and approving business cases for new ventures, projects and investments within policy frameworks approved by the Board;

• monitoring the performance of major capital projects and investments;

• approving policies relating to, and monitoring the performance of the Group’s, treasury function; and

• evaluating the company’s borrowing programme and financial budgets and making recommendations to the Board. Tender Committee The Tender Committee comprises four independent non-executive directors and one executive director. The responsibilities of the committee are:

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• approving tenders and contracts within its delegated authority; and

• ensuring that the Group’s procurement system is fair, equitable, transparent, competitive and cost effective. Social, Ethics and Sustainability Committee The Social, Ethics and Sustainability Committee comprises four independent non-executive directors, as well as the chairman of the Board and the chief executive. The committee’s responsibilities include:

• to fulfill the statutory functions of the social and ethics committee set out in the SA Companies Act;

• serving as the social and ethics committee for Eskom’s wholly owned subsidiaries;

• scrutinising safety practices at the Group’s nuclear facility. The committee makes recommendations on policies, strategies and guidelines relating to nuclear issues;

• ensuring that the strategy of the Group and the ethical implementation thereof promotes the sustainability of the Issuer; and

• recommending targets and key performance indicators on performance and components of the operations sustainability index. People and Governance Committee The People and Governance Committee comprises four independent non-executive directors, the chairman of the Board and the chief executive. The committee’s responsibilities include:

• making recommendations with respect to remuneration and other human resource-related policies;

• making recommendations on succession planning;

• making recommendations on Board and committee composition, training and evaluation; and

• providing oversight on governance matters, including the ethics management programme. Board Build Programme Review Committee The Board Build Programme Review Committee comprises five independent non-executive directors, which includes the chairman of the Board and two executive directors. It is an ad hoc committee of the Board and has been established to provide a governance, monitoring and oversight role in relation to the capacity expansion programme. The committee’s responsibilities include:

• risk management and mitigation plans relating to the capacity expansion programme;

• delivery of the capacity expansion programme on time and within budget; and

• stakeholder engagement and public communication plans regarding the capacity expansion programme. Chief Executive’s Committees Executive Management Committee (EXCO) The EXCO comprises the chief executive, Mr. Tshediso Matona, the finance director, Ms. Tsholofelo Molefe and the following group executives: Generation – Mr. Mongezi Ntsokolo, Transmission – Mr. Thava Govender, Distribution – Ms. Ayanda Noah, Customer Service – Mr. Thava Govender, Group Capital – Mr. Dan Marokane, Group Technology and Commercial –Mr. Matshela Koko, Human Resources – Role vacant but Ms. Elsie Pule is acting in the role and Sustainability – Dr. Steve Lennon (term expires on 31 March 2015). Eskom’s line divisions are Generation, Transmission, Distribution and Group Customer Services. These line diversions are responsible for operations on a day-to-day basis and creating value over the short, medium and long-term. Eskom’s service functions are Group Capital, Group Technology and Commercial

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(Primary Energy – Mr. Vusi Mboweni, Technology and Commercial), Human Resources, Group Finance (Treasury – Ms. Caroline Henry (Senior General Manager), BPP and Shared Services – Ms. Nonkululeko Veleti). These functions provide support to the line divisions. The EXCO assists the chief executive in guiding and controlling the overall direction of the business and in exercising executive control over its operations. Conflicts of Interest Conflicts of interest and declarations thereof are governed normatively by the latest revisions of the Group’s Conflict of Interest Policy (EPL32-173) and the Eskom code of Ethics (THE WAY –Standard 32-527) with respect to ethical conduct. All procurement and supply chain related activities are managed strictly in accordance with the aforementioned policies and standards, with a zero-tolerance approach to unethical practices. There are no potential conflicts of interest between any duties of the members of the administrative, management or supervisory bodies of the Issuer towards the Issuer and their private interests or other duties. Independent Auditor The Issuer is required to submit an annual report, including audited financial statements and opinions from the independent auditors, for each fiscal year to the Minister of Public Enterprises. KPMG Inc. and SizweNtsalubaGobodo Inc. (previously known as SizweNtsaluba VSP) were appointed auditor of the Issuer and the Group, for the financial years ended 31 March 2010 to 31 March 2014. KPMG Inc. and SizweNtsalubaGobodo Inc. were independent auditors to the Issuer and issued an unqualified opinion on the Annual Audited Consolidated Financial Statements of the Issuer and the Group in respect of each of the financial years ended 31 March 2014, 31 March 2013 and 31 March 2012. SizweNtsalubaGobodo Inc. was reappointed as auditors of the Issuer and the Group for the financial years ending 31 March 2015 to 31 March 2020. SizweNtsalubaGobodo Inc. issued an unqualified review report on the Reviewed Interim Financial Statements of the Issuer and the Group in respect of the six months ended 30 September 2014. The Consolidated Financial Statements of the Issuer and the Group are prepared in accordance with the applicable requirements of South African company law, IFRS and PFMA.

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OVERVIEW OF SOUTH AFRICA AND THE SOUTH AFRICAN ELECTRICITY INDUSTRY Overview of South Africa Introduction South Africa has been an established constitutional democracy since 1994, when it held its first fully democratic national elections. South Africa has the most developed economy in sub-Saharan Africa, and accounts for 22% of the aggregate GDP of sub-Saharan Africa. The South African economy is diverse and supported by a well-developed legal system and a sophisticated financial system. The major strengths of the South African economy are its services and manufacturing sectors, its strong physical and economic infrastructure and its abundant natural resources, including gold, platinum, metals and coal. According to the mid-year population estimates of 2014, South Africa’s population is estimated, by Statistics South Africa, to be approximately 54 million people, of which 27.64 million people, representing 51% of the population, are female. Approximately 80.2% are black, 8.8% are coloured, 2.5% are Indian/Asian and 8.5% are white. South Africa’s most recent phase of economic growth, which was its longest expansionary period on record, began in September 1999 and came to an end in the fourth quarter of 2007, during which time the economy grew by an annualised GDP of 4.1%. The economy grew by a slightly more modest 3.6% in 2008, contracted in 2009 by 1.5% and grew again by 2.9% in 2010. GDP growth in 2012 was slower at 2.9% against 2011 when the economy grew by 3.6%. GDP growth in 2013 was 1.9% year-on-year. GDP in the second quarter of 2014 was weak at 0.6% quarter-on-quarter and 1.0% year-on-year. Real GDP at market prices for the third quarter of 2014 increased by 1.4% quarter-on-quarter, seasonally adjusted and annualised. General government services contributed 0.3 of a percentage point based growth of 2.2%. The unadjusted GDP at market prices for the first nine months of 2014 increased by 1.5% compared to the first nine months of 2013. As in many other economies, the Government has taken steps to mitigate the impact of global events on the economy through more expansionary fiscal and monetary policies. As a result, the Government has gone from a fiscal surplus of 1.7% of GDP in the financial year ended 31 March 2008 to a deficit of 5.2% of GDP in the financial year ended 31 March 2013. This does not compare favourably to the 4.1% deficit which was projected in the Government’s 2014 MTBPS. According to the MTBPS, the wider deficit is largely the result of a revenue shortfall, as well as downward revisions to nominal GDP. However, the budget deficit is projected to narrow as economic growth improves over the medium term, reaching 2.5% by the financial year ending 31 March 2017. The Government had, prior to the global crisis, embarked on an extensive infrastructure development programme, which has mitigated the impact of the global crisis on South Africa’s economy. Following the crisis, private sector capital formation has been slow, however, public infrastructure investment has compensated for this. The public sector investment entails the creation of economic infrastructure including electricity generation plants, transmission and distribution lines, roads, ports and railways. The Government also continues to invest in an array of social infrastructure including schools and health care facilities. Gross fixed capital formation (“GFCF”) increased by 4.4% year-on-year in 2012 against a 4.2% increase in 2011. The 2014 MTBPS projects GFCF for 2014 to reach only 2.7% as a result of slower growth, however, gross capita formation is expected to steadily improve to reach 5.1% by 2017. In the wake of the economic crisis, an accommodative monetary policy stance had been adopted to strengthen domestic demand. Following a decision to cut rates by 50 basis points in July 2012, the key lending rate, the repo rate, has been kept at a 30 year low of 5.0% and the prime rate at 8.50%. The SARB increase of the repo rate by 50 basis points to 5.5% raising the prime rate to 8.5% in January 2014. Another increase of 25 basis points followed in July 2014 in order to limit inflation within the 3-6% target band. Interest rates are anticipated to remain in a cycle of tightening in the short-to-medium term given the expectation that the United States and other advanced economies will be increasing rates. Following a reading of 5.0% in 2011, 5.6% in 2012 and 5.7% in 2013, CPI is projected to average 5.9% over the next two years. There is limited upwards pressure on the inflation environment emanating from food inflation and lower cost push pressure due to depressed oil prices. However, there is a risk of higher import prices following a weaker external value of the Rand.

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Against this background, South Africa continues to address a legacy of great divisions within the population, largely along racial lines, which have taken a heavy toll on human development and the economy. These divisions are evidenced by the chronically high formal sector unemployment rate and the widely divergent nature of the economy, in which vast sections of the populace still suffer significant inadequacies in areas such as housing, sanitation, healthcare and education, while a minority enjoys the benefits associated with a highly developed society. The Government has expressed its firm intent to continue to address South Africa’s social and developmental challenges within a consistent, growth-oriented fiscal and budgetary framework. Government Under the Constitution of South Africa, the executive authority of the Government is vested in the President, who serves as both Head of State and Head of Government. The President must be elected by a majority vote of the members of the National Assembly following which the President must resign his or her seat in the National Assembly. Thabo Mbeki of the African National Congress (the “ANC”) succeeded Nelson Mandela as President after the June 1999 elections and served as President until September 2008. On 20 September 2008, after the ANC announced its decision to recall President Thabo Mbeki from office, President Mbeki resigned and Cabinet member Kgalema Motlanthe was sworn in as president on 25 September 2008. On 9 May 2009, following the ANC’s victory in the April 2009 national elections, Jacob Zuma was inaugurated as the fourth democratically elected President of South Africa, with Kgalema Motlanthe as his deputy. The most recent general elections were held on 7 May 2014 and Mr. Jacob Zuma was re-elected for a second five- year term with Mr. Cyril Ramaphosa as deputy president. South African Economy The South African economy accounts for 22% of Sub-Saharan Africa’s GDP. The South African economy varies widely, ranging from “first-world” levels of development to an informal sector typical of developing countries, and to urban shantytowns and subsistence agriculture. Inequality in the economy is a primary legacy of the apartheid era, in which Government expenditures were channelled to the white population in preference to other racial groups. For example, in 2014, unemployment among the economically active white population was 3.0%, whereas the unemployment rate among the economically active black population was 85.7%. In the period from 1995 to 2008, there was a 52.8% rise in employment of black population between the ages of 15 to 65 years, being the largest percentage increase of any racial group. There is a small but rapidly growing black middle class. Research indicates that the number of black middle class households has risen by 30% with their numbers increasing from 2 million to 2.6 million. Their collective spending power has increased from R130 billion to R180 billion. Nevertheless, the Government continues to seek measures to redress imbalances in the economy through various initiatives, including its policy of BBBEE. Regulation of the South African Electricity Industry Introduction Historically, the Group has enjoyed an effective oligopoly in the generation of electricity and a monopoly in the transmission of electricity, while responsibility for distribution to end users has been divided among a number of parties. The Group supplies approximately 95% of South Africa’s electricity (with the remainder being produced by local authorities and certain large customers for their own consumption) and approximately 40% of the total electricity consumed on the African continent. Since 1991, the Group has participated in the Electrification Programme, an initiative started by the Group that has extended electricity supply to domestic customers. See “—Electrification”. In addition, the Group has begun to supply electricity to many areas in South Africa which were previously supplied by municipalities and other entities. The Group currently sells directly to approximately 3,000 industrial, 1,000 mining, 50,000 commercial, 84,000 agricultural and more than 4.8 million residential customers. The Group had a total nominal capacity of 41,995 MW as at 30 September 2014. The IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) estimates that South Africa will need to create 41,346 MW of new capacity by 2030 (excluding capacity required to replace decommissioned plants) in order to meet the projected demand and provide adequate reserves. This is based on a GDP growth trajectory averaging 4.5% over the next 20 years. It assumes at least 3.4 GW of DSM programmes, as well as a gradual reduction in electricity intensity due to increased efficiency and a

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diversification to secondary and tertiary sectors in the economy. Of the projected total new capacity, the Group has committed (under its committed capacity expansion programme) to build 17.4 GW of additional capacity (200 MW of which will be from renewable energy sources), up to and including Kusile. As at 30 September 2014, 6,000 MW of generating capacity had been installed since 2005. However, pending the finalisation and publication of the updated IRP, which is expected to be approved following the IEP’s anticipated approval in March 2015, the Group has not approved or committed to any new build projects beyond Kusile under its committed capacity expansion programme, and its MYPD 3 application did not include any funding for any such new capacity build. See “Business—Finance—Capacity Expansion Programme” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Capital Expenditure”. While the Group expects to be a major provider of new generation capacity, the Group believes that to ensure the supply of electricity meets demand set out in the IRP, a number of important interventions need to be made in the energy sector in South Africa, such as the implementation of a demand management and energy efficiency framework, the involvement of IPPs who will join in or supplement the Group’s contribution to investment and capacity expansion, and the finalisation of certain capacity choices. A number of Government and other stakeholder-led interventions are already underway to address the capacity challenge, and to facilitate progress towards an optimal regulatory and policy environment. The priorities being addressed and which need to be finalised include:

• the IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) including the assumptions regarding growth, the capacity need for the country and the fuel choices, and in particular, renewables and nuclear, and who should build this capacity (see “—IRP and IEP”);

• mechanisms to ensure the protection of the poor;

• mitigating the impact on climate change;

• industry structure, including decisions on the ISMO, the electricity distribution industry and the designation of “buyers” in terms of the regulations;

• an effective demand-management framework (including the power conservation programme which was set up by the Government, and assisted by the Group, to address energy conservation) and demand-side management interventions; and

• securing coal, water and other resources for power generation. IRP and IEP Over the longer term, South Africa’s envisaged energy generation and transmission needs and provision are outlined in the Department of Energy’s IRP, which sets out a long-term electricity plan for South Africa and the Department of Energy’s IEP, which is broadly designed to guide future South African energy infrastructure investment and policy for the 2010 to 2050 period. The IEP was published in June 2013 for public consultation, and a final report is expected to be published in March 2015. The IRP, which was promulgated in 2011, seeks to diversify the energy mix in South Africa over the 2010 to 2030 period to include gas, imports, nuclear, biomass, and renewable energy, as well as to use the existing coal resources more efficiently and in a more environmentally friendly manner. The IRP envisages creating an additional 42.6 GW of total capacity by 2030; 17.8 GW from renewable, 9.6 GW from nuclear, 6.3 GW from coal and the remainder from other generation sources. However, the IRP is currently in the process of being revised to reflect the continuing evolution of the Government’s long-term electricity strategy. It remains unclear when the updated IRP will be finalised and approved by the Cabinet. While a draft updated version of the IRP was published in November 2013 for public comment, it is expected that the final revised IRP will only be formally approved after the Government has approved the over-arching IEP, which is expected to inform the contents of the revised IRP. The draft IRP update is not an official update to the promulgated IRP, but the update has, however, revised scenarios based on changes to South Africa’s economic outlook, including addressing the effect of slowing economic growth on projected electricity demand (anticipating that less

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capacity will be required by 2030). However, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. Regulatory Framework The absence of sufficient competition in the electricity industry in South Africa necessitates economic regulation of the industry so as to ensure that the interest of customers, licensees and other stakeholders are balanced and to ensure the sustainability of the industry. The strategic importance of the industry to national growth and development objectives also necessitates regulation. The Issuer is subject to oversight directly and indirectly by the Government as its sole shareholder, and as a policy maker. The Government, acting through the Department of Energy creates the energy policy for the country. Board members of NERSA are appointed by the Minister of Energy and the Group is principally subject to oversight by NERSA in respect of economic regulation of electricity supply. NERSA has national jurisdiction over generators, transmitters and distributors of electricity and exercises its powers through the licensing of electricity generation, transmission, distribution and trading activities. In 2004, NERSA issued three separate electricity supply licences to the Group for its generation, transmission and distribution businesses under the Electricity Act, 1987 (the “Electricity Act”). The Electricity Act was later replaced by the Electricity Regulation Act, however licences issued under the Electricity Act, are deemed to continue and remain in force. A requirement of the supply licences is that separate financial information be prepared for each licensed business. The Group had already implemented a framework for separate accounting treatment of these businesses from 1996. The Group believes it has and maintains a constructive relationship with NERSA. The Group is also subject to environmental legislation as well as policies which are put forward by the NPC, Minister of Economic Development and the Minister of Trade and Industry. As the Group’s operations impact on the environment and areas beyond the energy sector, such as infrastructure, business operations need to be aligned with national planning and economic development initiatives. The Group is also regulated by the NNR in respect of its nuclear operations. The Electricity Regulation Act The Electricity Regulation Act aims to establish a national regulatory framework for the electricity supply industry and provides for NERSA to issue rules to implement (i) the Government’s electricity policy framework, (ii) the IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) and (iii) the regulations set out in the Electricity Regulation Act. In August 2009, the Department of Energy issued, in accordance with section 35(4) of the Electricity Regulation Act, Electricity Regulations on New Generation Capacity (“August 2009 Regulations”) which contained elements to be included in the development of the IRP. The August 2009 Regulations elaborate on the powers attributed to the Minister of Energy, to designate any licensed electricity supplier, as the buyer of capacity, energy or ancillary services under PPAs, with IPPs that may be selected to provide new generation capacity, pursuant to IPP bidding programmes. The Group may be designated as the buyer of capacity, energy or ancillary services under PPAs with such IPPs. Where the Group is designated as buyer in respect of any such PPA (referred to as a “Vesting PPA”), the costs incurred by the Group under the Vesting PPA will be recoverable on the terms and conditions of NERSA’s Rules for Power Purchase Cost Recovery, which came into effect on 26 November 2009. These rules were developed to facilitate the introduction of IPPs by ensuring that the costs of IPPs could be recovered by the Group through its regulated annual revenue allowance (and also by any other approved buyer of IPP-generated electricity). Under these rules all Vesting PPA costs (and any NERSA approved costs under any other PPA concluded by the Group) must be kept separate from other costs of the business to facilitate identification by the regulator of these costs in the Group’s financial statements. In order for the Group to recover such costs through its regulated revenues, the Group will include the forecasted future periods’ PPA costs into its Revenue Application as submitted to NERSA prior to the commencement of a new regulatory cycle. If deemed a reasonable estimate, such costs will be included into the Allowed Regulated Revenue. Any actual annual variances relative to such original estimates are recorded in the RCA on an accumulating basis. In the event that the balance of the RCA exceeds 2% of the total annual revenue allowance of the

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Group, the RCA balance will be recovered by the Group through adjustment to the following financial year’s Allowed Regulated Revenue. Under the August 2009 Regulations, the Minister of Energy, in consultation with NERSA has the authority to determine the type of energy sources from which electricity must be generated, and the percentages of electricity that must be generated from such sources. The August 2009 Regulations have since been repealed by the Department of Energy with the publication of the May 2011 Regulations on New Generation Capacity (“May 2011 Regulations”). The May 2011 Regulations empower the Minister of Energy to, in relation to new generation capacity projects, designate an organ of state, as the buyer of electricity generation capacity other than the capacity of existing generation facilities. The May 2011 Regulations do not apply to “Current Programmes” which are projects listed in Schedule A in the initial Integrated Resource Plan, but does apply to the Department of Energy’s peaking power programme. In January 2010, the Minister of Energy approved an initial IRP, a generation capacity plan for the period to 31 March 2013, which defined the need for new generation and transmission capacity for the country. New generation capacity identified in the IRP to come on-stream in the period to 2013 includes the early phases of the Group’s Medupi and Kusile power stations, solicitation of bids from IPPs to supply power until 2018 under the anticipated Renewable Energy Feed-in Tariff programme, the Medium Term Power Purchase Programme (“MTPPP”) and the Department of Energy’s peaking power programme. The objective of the IRP is to develop a sustainable electricity investment strategy for generation capacity and supporting infrastructure for South Africa over the next 20 years, to 2030. The investment strategy includes capacity provided from all generators (the Group and IPPs). It aims to strike a balance between an affordable electricity price to support a globally competitive economy, a more sustainable and efficient economy and the creation of local jobs. It also aims to stimulate the development of hydroelectric and other power projects in Africa. It anticipates 41,346 MW of new capacity (excluding capacity required to replace decommissioned plants) will be required in order to meet the projected demand and to provide adequate reserves. It assumes approximately 3,420 MW of electric generation capacity coming from DSM programmes starting in 2017, a gradual reduction in electricity intensity due to increased efficiency and a diversification to secondary and tertiary sectors in the economy. The IRP is currently in the process of being revised to reflect the continuing evolution of the Government’s long-term electricity strategy. It remains unclear when the updated IRP will be finalised and approved by the Cabinet. While a draft updated version of the IRP was published in November 2013 for public comment, it is expected that the final revised IRP will only be formally approved after the Government has approved the over-arching IEP, which is expected to inform the contents of the revised IRP. The draft IRP update addresses the effect of slowing economic growth on projected electricity demand (anticipating that less capacity will be required by 2030). The draft IRP update is not an official update to the promulgated IRP, but the update has, however, revised scenarios based on changes to South Africa’s economic outlook. However, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. The National Planning Commission of South Africa The NPC is a government agency established in May 2009, chaired by the Minister for National Planning and is responsible for developing a long-term vision and strategic plan for South Africa, with the aim of significantly reducing poverty and inequality by 2030. The NPC’s mandate (as contained in the Revised Green Paper, released in February 2010) is to take a broad, cross-cutting, independent and critical view of South Africa, so as to put forward solid research, sound evidence and clear recommendations for Government policy. In the financial year ended 31 March 2013, the Group held discussions on coal security with the NPC, as well as several other government departments, such as the Department of Mineral Resources, Department of Public Enterprises and the Department of Energy. In the Group’s discussions with the NPC, the need to strike a balance between local and export coal requirements and the increasing international demand for Eskom-grade coal was acknowledged. Further to these discussions, on 27 March 2014 the National Assembly and the National Council of Provinces approved the Mineral and Petroleum Resources Development Amendment Bill, 2013, although the bill has yet to be signed into law. The Mineral and Petroleum Resources Development Amendment Bill, 2013 aims to promote national energy security, including the possibility of declaring coal a strategic resource. The Minister of Mineral Resources requested that the President delay in signing the bill into law in its current form until certain concerns raised through stakeholder engagements have

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been addressed. On 16 January 2015, the President referred the Mineral and Petroleum Resources Development Amendment Bill, 2013 back to the National Assembly for further consideration based, according to a statement released by the Office of Presidency, on the President’s view “that the bill as it stand[s] would not pass constitutional muster”. The IRP (a revised version of which is expected to be approved following the IEP’s anticipated approval in March 2015) provides a number of scenarios to inform debate on specific issues relating to future generation capacity, dealing with climate change, regional integration and the benefits of demand side initiatives, particularly regarding energy efficiency. The table below contains details of the IRP as originally published and is therefore based on information as of the date of such publication.

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2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 (MW) RTS Capacity ...... 380 679 303 101 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Medupi ...... 0 0 0 722 722 1,444 722 722 0 0 0 0 0 0 0 0 0 0 0 0 0 Kusile ...... 0 0 0 0 0 0 0 1,446 723 1,446 723 0 0 0 0 0 0 0 0 0 0 Ingula ...... 0 0 0 333 999 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 DOE OCGT IPP ..... 0 0 0 1,020 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cogeneration own build ...... 260 130 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Wind ...... 0 200 200 300 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 CSP ...... 0 0 0 0 100 100 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Landfill. Hydro ...... 0 0 100 25 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Sere ...... 0 0 100 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Decommissioning ... 0 0 0 0 0 (180) (90) 0 0 0 0 (75) (1,870) (2,280) (909) (1,520) 0 0 (2,850) (1,128) 0 Coal (PF, FBC, Imports) ...... 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 750 2,000 750 1,500 Cogeneration, own build ...... 0 103 0 124 426 600 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 GasCCGT ...... 0 0 0 0 0 0 0 0 0 474 711 711 0 0 0 0 0 0 0 0 0 OCGT ...... 0 0 0 0 0 0 0 0 0 0 0 0 805 805 575 805 0 805 805 805 345 Import Hydro ...... 0 0 0 0 0 0 0 0 0 0 360 750 1,110 1,129 0 0 0 0 0 0 0 Wind ...... 0 0 0 0 200 400 800 800 800 800 0 0 0 0 0 0 0 0 0 0 0 Solar PV, CSP...... 0 0 0 0 0 0 100 100 100 100 0 0 0 0 0 0 0 0 0 0 0 Renewables (Wind, Solar, CSP, Solar PV, Landfill, Biomass, etc.) .... 0 0 0 0 0 0 0 0 0 0 800 800 800 800 800 1,400 600 1,200 0 0 0 Total New Build .... 0 0 0 0 0 0 0 0 0 0 0 0 0 1,600 1,600 1,600 1,600 0 1,600 1,600 0 Nuclear Fleet ...... 640 1,112 703 2,625 2,447 2,364 1,532 3,068 1,623 2,820 2,594 2,186 845 2,054 2,066 2,285 2,200 2,755 1,555 2,027 1,845 Total System Capacity ...... 44,535 45,647 46,350 48,975 51,422 53,786 55,318 58,386 60,009 62,829 65,423 67,609 68,454 70,508 72,574 74,859 77,059 79,814 81,369 83,396 85,214 Peak demand (net sent out forecast) ...... 38,885 39,956 40,995 42,416 43,436 44,865 45,786 47,870 49,516 51,233 52,719 54,326 55,734 57,097 58,340 60,150 61,770 63,404 64,867 66,460 67,809 Demand Side Management ...... 252 484 809 1,310 1,966 2,594 3,007 3,420 3,420 3,420 3,420 3,420 3,420 3,420 3,420 3,420 3,420 3,420 3,420 3,420 3,420 (%) Reserve Margin ...... 15.28 15.67 15.34 19.14 24.00 27.24 29.31 31.35 30.18 31.41 32.71 32.81 30.85 31.36 32.14 31.96 32.06 33.06 32.42 32.29 32.39 Reliable capacity Reserve Margin ...... 15.18 14.74 13.47 15.86 21.85 20.59 20.75 19.61 19.17 18.08 18.68 18.19 15.67 15.56 15.73 14.44 14.35 14.48 14.29 14.61 15.07

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The Group will require clarity on the funding of any additional capacity that it may be expected to build. A revised version of the IRP is expected to be approved following the IEP’s anticipated approval in March 2015. Nuclear power is likely to be considered a favourable base load generating option and was included as such in the draft updated IRP published for public comment in November 2013. However, given the final IEP will likely inform the contents of the final revised IRP, it remains unclear how and to what extent the final IRP will differ from the IRP promulgated in 2011. Independent System and Market Operator In May 2011, the Government published the ISMO Bill, which sought to establish an ISMO in response to concerns raised by stakeholders regarding the slow pace of introduction of IPPs in the electricity supply industry. The concerns raised related specifically to: (i) the absence of an enabling framework for the introduction of IPPs; and (ii) the role of the Group, and in particular, the possible conflict of interest by the Group with regard to the dispatch of power in this regard. The creation of an ISMO was therefore seen as a mechanism to support the introduction of IPPs and to ensure that power transmission was allocated equally and fairly between suppliers. The ISMO Bill provided for a separate state-owned entity into which certain functions, including, potentially, the Group’s transmission assets, would be separated from the Group over time. However, the ISMO Bill has since been withdrawn from consideration by the Department of Energy. While the Department of Energy has announced publically that it intends to re-table the ISMO Bill, there is little clarity as to if and when this will take place and how the re-introduced ISMO Bill would compare to the originally tabled bill. The Group has undertaken no internal restructuring to accommodate the original bill nor anticipates undertaking such restructuring until there is clarity regarding the new bill. At the time that parliamentary discussions that took place in respect of the ISMO Bill, the Group underscored the importance of refraining from embarking on any restructuring while the power system was constrained and recommended a phased approach toward the creation of an ISMO. See “Risk Factors—Risk Factors relating to the Group— The Government controls the Group and may adopt policies or take steps that significantly affect the Group’s business profile and corporate structure including the potential restructuring of the Group’s business”. Electricity Tariffs No licensed electricity supplier may levy any tariffs for electricity supply other than at the rates pre-approved by NERSA. Under the Electricity Regulation Act, NERSA is obliged to ensure that the licence conditions relating to the setting or approval of regulated tariffs and revenues allow the licence holder to recover the full efficient cost of its licensed activities including a reasonable margin or return. The Group’s electricity supply tariffs are proposed by the Group and approved by NERSA in consultation with the Group and various stakeholders. Requirements under the Electricity Regulation Act Section 15 of the Electricity Regulation Act requires that the regulation of revenues must allow for an efficient licensee to recover the full cost of its licensed activities, including a reasonable margin or return, and it must provide for or prescribe incentives for continued improvement of technical and economic efficiency with which services are to be delivered. Furthermore, the section requires that charges and tariffs must give end users proper information regarding the costs that their consumption imposes on the licensees business, must avoid undue discrimination between customer categories and may permit the cross-subsidy of tariffs to certain classes of customers as approved by NERSA. Independent Power Producers (IPPs) The Group remains committed to facilitating the entry of IPPs into the South African electricity market. By 30 September 2014, the Group had entered into power purchase agreements for a total capacity of 4,280 MW with IPPs including 4,196 MW with local IPPs. The Board has also approved an additional 1,457 MW, bringing the total approved capacity for local IPPs up to 5,652 MW. These figures include the Department of Energy’s renewable energy IPP procurement programme. However, the amount paid for IPP and municipal purchases for the six months ended 30 September 2014 increased to R3.5 billion from R1.6 billion for the six months ended 30 September 2013. The annual cost increased to R3.3 billion for the financial year ended 31 March 2014 from R3.0 billion for the financial year ended 31 March 2013. The cost was R3.3 billion for the financial year ended 31 March 2012. The increase in half-year costs reflects growth from the renewable

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energy IPP procurement programme. The Group remains committed to facilitating the entry of IPPs into the South African electricity market. Eskom has successfully connected 21 RE-IPPs (representing a total capacity of 1,076 MW) to the grid. Of these projects a total of 467.3 MW is currently available to the system. Total energy procured from IPPs for the year amounted to 3,671GWh at a cost of R3,266 million (averaging 88c/kWh), which is R721 million higher than the NERSA decision for 2013/14. A total of 760 projects were installed during the six months to 30 September 2014, with potential demand savings of 81 MW and potential energy savings of 258 GWh. The CFL rollout phase 3 was completed in Gauteng, with 179,447 bulbs being installed in the six months to 30 September 2014. A total of 123 new projects, with potential demand savings of 358 MW, were registered during the period under review. The demand response programme has added 56 MW of certified dispatchable load during the six months to 30 September 2014. Dispatchable load of 1,417 MW, which can be reduced or completely switched off on a scheduled day, is available to the system operator. A total capacity of 4,280 MW had been contracted with IPPs as at 30 September 2014. The table below shows the actual energy procured through IPP programmes in the 2013/2014 financial year.

Actual energy Actual cost purchased (in (Rand in Actual cost (in GWh) millions) c/kWh) IPP purchases MTPPP(1) ...... 1,478 1,217.5 82 STPPP(2) ...... 931 815.6 88 WEPS(3) ...... 139 72.3 52 Municipal base load contracts(4) ...... 873 771.9 88 RE-IPP ...... 250 350.5 140 Adjustment(5)...... — 38.3 — Totals/Averages ...... 3,671 3,266.1 89 ______(1) The medium-term power purchase programme (“MTPPP”), initiated in 2008 involves the Group purchasing base load capacity from private generators. (2) The short-term power purchase programme (“STPPP”), involves Eskom contracting private generating capacity on a short-term basis. (3) The wholesale electricity pricing system programme (“WEPS”) involves Eskom entering into annual contracts to purchase electricity at wholesale prices from co-generators outside of the ambit of the MTPPP and short-term contracts. (4) Municipal base load contracts with City Power and the City of Tshwane. Eskom contracted 585MW of generating capacity from Kelvin, Rooiwal and Pretoria West power stations. Electricity was purchased at rates comparable to the MTPPP. NERSA did not approve any further costs for purchases from municipal generators during MYPD 3, so these contracts were not extended after they expired at the end of December 2013. (5) VAT adjustment.

Short-to-medium-term IPP programmes

• Short-term power purchases The Group approved 709 MW of short term power purchase agreements (including generation from municipal generators), of which all 709 MW were operational at the end of September 2014. These contracts will expire at the end of March 2015. The number and capacity of renewable energy IPPs to be contracted through the third round of the IPP programme might be extended. The process to procure 800 MW of co-generation power and 2,500 MW of coal generation power from IPPs is underway.

• Medium-term power purchase programme The Group initiated the MTPPP in 2008 to procure base load capacity from private generators for the medium term until new generation capacity, such as the Medupi power station, comes online. A price cap was submitted to the market and all bidders capable of meeting this within the required timeline were accepted. A capacity of 288 MW has been signed as of the date of this Base Prospectus. Most of these contracts have now expired, with only 13 MW currently operational under this programme

• Long-term IPP programmes

• Department of Energy’s OCGT (“Peakers”) programme Power Purchase Agreements for a total capacity of 1,005 MW for both the Avon and Dedisa plants were entered into on 3 June 2013 and became effective on 29 August 2013. Commissioning of Dedisa is expected in the second half of 2015, while Avon is expected during the first half of 2016.

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• Renewable energy IPP programme The Department of Energy formally launched the renewable energy IPP procurement programme on 3 August 2011. A request for proposals was published following the first determination that 3,725 MW would be generated from renewable energy technologies in commercial operation between mid-2014 and the end of 2016. Developers were invited to submit proposals for the financing, construction, operation and maintenance of any onshore wind, solar thermal, solar photovoltaic, biomass, biogas, landfill gas, or small hydro technologies. As at 30 September 2014, the Group had signed contracts for a total of 2,467 MW under the RE-IPP procurement programme. The renewable projects with signed PPAs are at various stages in the construction phase. The first project under the RE-IPP programme was connected to the grid on 27 September 2013 and the first IPP was commissioned on 15 November 2013. A total of 1,175 MW was operational by 30 September 2014 from these IPPs. The Department of Energy approved an additional 1,457MW pursuant to the third bid submission, 15 of these 17 contracts were signed in December 2014 (bringing the total signed under the RE-IPP programme to 3,887 MW).

• Small renewable energy IPP programme This programme, which falls under the Department of Energy’s renewable energy IPP programme, calls for 100 MW to be generated from small renewable energy technologies. The Department of Energy released the Request for Qualification and Proposals for New Generation Capacity under the Small Projects IPP Procurement Programme dated 21 August 2013. Two Stage One Submissions Phases have been held under that RFP to date and the First Stage Two Submission Date closed on 1 November 2014. The Second Stage Two Submission Date is on 6 April 2015. Background – Prior to the MYPD From 2001 to 2005, the Group’s revenues were set according to a Rate-of-Return (“RoR”) methodology. The RoR methodology was applied on an annual basis but did not provide incentives. The Group applied annually to NERSA for approval of the following year’s regulated revenue from which was derived the average tariffs and thus average increase in the price of electricity. Revenue increases took into account various factors including projected costs after productivity improvements, projected sales growth, projected capital expenditure, appropriate return on assets and economic parameters. Multi-Year Price Determination Methodology In 2005, NERSA introduced the MYPD, which is a multi-year incentive-based, cost-of-service, revenue determination methodology, to replace the annual determination based on RoR methodology. The first MYPD cycle, MYPD 1, covered the period between 1 April 2006 and 31 March 2009. Under the MYPD, annual revenues are set for a pre-determined period and prices are only reviewed (within the determination period) if and to the extent there are any deviations between pricing assumptions and actual turnout with respect to certain specified items, including sales volumes, power purchase contracts with IPPs, inflation and property rates. If the difference between actual and allowed (assumed) revenue is more than 10%, then NERSA will initiate a public consultation regarding the timing of the recovery of the difference and may also seek to reopen the pricing determination. The MYPD is tested against a set of regulatory objectives (“Regulatory Rules”). The Regulatory Rules guide the development of the regulatory methodology underlying the MYPD. In other words, it is a set of objectives, methods, principles and rules for regulating the allowable revenue and the price at which electricity is sold. Revenues for MYPD 1 were determined on the basis that electricity prices were expected to rise by the Consumer Price Index plus 1% on an annual basis (including an electricity distribution industry restructuring levy which contributed around 0.5% of the annual increases). During the first year of MYPD 1, it became apparent that fuel costs would be significantly higher than originally anticipated, and in 2008 the Group experienced much higher increases in their primary energy costs compared to the forecast in the MYPD 1 application. As these increases were not covered under the adjustment mechanism contained in the

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MYPD, the Group submitted an official request in April 2007 for a change in the Regulatory Rules applicable to MYPD 2 to allow fuel cost variances to be recovered. In addition, changes were requested with respect to capital expenditure variances and the trigger for re-opening the revenue determination. While the Group’s request for amendments to the Regulatory Rules was ultimately denied by NERSA in December 2007, NERSA recognised the need for amendments to the Regulatory Rules and agreed to address this prior to the next regulatory cycle (MYPD 2). NERSA also recognised the Group’s capital financing needs and allowed revenues for the financial year ended 31 March 2009 to increase by 14.2% in response to changes in fuel costs and capital expenditure. Further cost increases, however, forced the Group to approach the regulator for a second time, requesting an upward revision of the 14.2% increase to 60%. In June 2008, NERSA approved a further price increase of 13.3%, resulting in an overall increase of 27.5% for the financial year ended 31 March 2009. The EPP, approved in November 2008, provides clarity with respect to specific key issues related to the determination of regulated revenues. It confirms existing practices, removes uncertainties and introduces new requirements. A key requirement introduced by the EPP is the requirement for NERSA to adopt an asset valuation methodology that accurately reflects the replacement values of the assets used in the production, transmission and distribution of electricity thus correcting the issue arising under historical cost-based asset valuation, which substantially contributed to the understated tariffs and significant price adjustments from the third year of MYPD 1 onwards. This change was intended to ensure long-term sustainability of the industry with the ability to fund future investment in the expansion of infrastructure capacity without price shocks. The EPP aimed to achieve “cost-reflectivity” in tariffs within five years. The requirement for “cost-reflectivity” is legislated by the Electricity Regulation Act, which states that “… revenues…must enable an efficient licensee to recover the full cost of its licensed activities, including a reasonable margin or return”. The EPP also required that “the revenue requirement for a regulated licensee must be set at a level which covers the full cost of production, including a reasonable risk adjusted margin or return on appropriate asset values”, with asset values clarified as “an accurate reflection of the replacement value of those assets”, thus prescribing the basis for the return of assets (depreciation charge) as well as the return on assets (cost of capital). Given the need for rapid capacity expansion in South Africa and the resultant significant price adjustment that this approach implied (given that prevailing tariffs were well below cost-reflective levels, especially if calculated on the replacement value basis), the EPP determined a five-year period to reach cost-reflective tariffs. This, however, has not been achieved. If fully implemented, the revenue methodology as defined by the EPP is expected to result in adequate, yet stable and predictable future tariffs with gradual movements. In 2008 the Group did not submit the second MYPD application as originally expected, covering the period from 1 April 2009 to 31 March 2012, as it was finalising with the Government the funding model for the Group’s committed capacity expansion programme. Instead, on 5 May 2009, the Group applied for a price increase of 34% for the financial year ended 31 March 2010 as an interim measure whilst finalising its funding model and preparing for the MYPD 2 submission. NERSA approved an average 31.3% price increase for the financial year ended 31 March 2010 to be implemented from 1 July 2009. This included the Government’s environmental levy of 2 c/kWh. In order to reduce the impact on low income households, a limited price increase of 15% was approved for low income customers of both the Group and municipalities, with high volume customers being charged a premium to cover the amount that would have otherwise been paid by such low-income customers. On 30 September 2009 the Group submitted its MYPD 2 application to NERSA for the period commencing 1 April 2010 to 31 March 2013. Initially, the Group applied for tariff increases of 45% per annum, which it believed would allow it to reach cost-reflectivity by the last year of tariffs covered by MYPD 2 (2012-2013) assuming a pre-tax “real” weighted average cost of capital (“WACC”) of between 8% and 10%. After initial engagements with stakeholders, the Group submitted a revised application on 30 November 2009 for revenues translating to increases of 35% per annum over the three years which the Group believes would have achieved cost-reflectivity by 2014 assuming a pre-tax rate “real” WACC of approximately 8%. Following public hearings on the application in all nine provinces in January and February 2010, NERSA made a revenue determination for the three years ending 31 March 2013, approving revenue for the Group of R91 billion for the financial year ended 31 March 2011, R116 billion for the financial year ended 31 March 2012 and R148 billion for the financial year ended 31 March 2013. This resulted in a standard average price of 41.57 c/kWh, 52.30 c/kWh and 65.85 c/kWh for the financial year ended 31 March 2011, 2012 and 2013, respectively. This equates to an estimated percentage price increase of 24.8% on the total average tariff from

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1 April 2010, an average increase of 25.8% from 1 April 2011 and a further increase of 25.9% from 1 April 2012. These average increases include the effects of required cross subsidies (i.e. inclining block tariff rates) for low income residential customers. However, the Group’s annual tariff application for the financial year ended 31 March 2013 fell during a time when South Africa was experiencing a slowdown in capital expansion and the economy, generally. Accordingly, on 2 March 2012, the Group requested that the approved price increase of 25.9% for the financial year ended 31 March 2013, be revised downwards to 16.0%. On 9 March 2012, NERSA approved the price adjustment from 25.9% to 16.0%, although this was done on the basis that the reduction in revenue would flow into the RCA to be recovered by the Group at a later date, given that NERSA did not revise its initial MYPD 2 revenue determination (i.e. the Group was still entitled to the revenues that would have been realised in terms of the original 25.9% determination). The 16% increase translated into a standard average price of 60.66 c/kWh for that period. In addition to the recovery of the revenue shortfall, the Regulatory Rules applicable to MYPD 2 also introduced a number of mechanisms which allow the company to “pass-through” variances between predicted and actual costs for certain specified cost items, including some of the fuel cost items and thereby to recover such cost variances by virtue of increases in future tariffs beyond the level that it would otherwise have been. In setting the levels of yearly tariff increases under MYPD 2 at lower levels than applied for by the Group, NERSA determined that achieving cost-reflectivity by 2012-2013 would result in tariff increases that were too large for users in South Africa, and indicated at the time that its intention was to achieve cost-reflectivity for electricity tariffs in five years (by 2014-2015). It remained important for the Group, including in order to provide funding for the committed capacity expansion programme, that the MYPD 3 period allowed prices to increase to cost-reflective levels. On 18 October 2012, NERSA received the Group’s Revenue Application for MYPD 3 and the Group’s Retail Tariff Structural Adjustments. The application covered a five year period from 1 April 2013 to 31 March 2018. The Group applied for annual price increases of 13% per annum over the MYPD 3 control period to cover its operating input and debt-servicing costs plus 3% per year for IPPs. The application assumed the following:

• Eskom’s goal would be to provide a secure and reliable supply of electricity;

• primary energy would increase at a rate of 8.6% per year, with coal increasing at 10% per year;

• operating costs would increase at 8% per year;

• Eskom’s application had to comply with the EPP;

• Eskom would be allowed to achieve by 2018 real pre-tax returns on assets of at least 8.16%, the target stated in NERSA’s MYPD 2 determination. Due to the Group’s approach of phasing-in to the full rate of return cost-reflectivity by 2018, it asked for an average of less than 4% over the period, resulting in a pre-tax return of 7.8% by the financial year ending 31 March 2018;

• the Government would continue to guarantee Eskom’s debt to the value of up to R350 billion and Eskom would not commit itself beyond that;

• Eskom would secure financing up to the completion of its current capacity expansion programme, including the cost of replacing and refurbishing older stations;

• Eskom would reach standalone investment grade status by the end of the MYPD 3 period;

• provision was to be made for the 3,725 MW renewable energy IPP programme and the Department of Energy’s 1,020 MW “peaker” gas plant; and

• a mandatory energy conservation scheme to prompt South Africa’s largest energy users to curb their usage during the period of supply constraints would be put in place, but only implemented if necessary. On 28 February 2013, however, NERSA approved an average annual increase of only 8% per annum including the IPPs. The total revenue awarded equates to R863 billion, or approximately half of what had been requested in the Group’s application. However, in response to the Group’s RCA application regarding under-recoveries for the MYPD 2 period, NERSA announced in October 2014 its decision to revise the

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average annual tariff increase for the 2015/16 financial year upward from 8% to 12.7%, allowing the Group to recoup R7.8 billion in under-recoveries. The tariff will revert to 8% for the remaining years of the MYPD 3 period unless NERSA agrees to additional tariff adjustments pursuant to further Group RCA applications. See “—Implications of the approved 8% tariff increase”. Implications of the approved 8% tariff increase The 8% average annual tariff increase that NERSA established for the MYPD 3 period represented only half the 16% average annual increase requested by the Group in its MYPD 3 application, which Eskom had considered necessary to achieve cost-reflective pricing and to meet the demands facing the Group. As a result of NERSA’s price determination, the Group originally estimated that the lower-than-expected tariff regime would result in a revenue shortfall of approximately R225 billion over the five-year MYPD 3 period. In order to address this shortfall, the Group implemented a number of initiatives and reforms as part of its revised business plan to reshape its business, reprioritise capital and operational expenditure and increase efficiencies. These included, among other things, applying for, and obtaining, a 12.7% tariff increase for the 2015/16 financial year by way of NERSA’s RCA application process and implementing its BPP cost-cutting programme. However, the Group has since been forced to revise upwards its estimated revenue shortfall for the MYPD 3 period, which amount is still being quantified. This upward revision is based on the Group’s latest projections, which anticipate a decline in electricity sales volumes stemming primarily from lower growth in demand, which has been hindered by low GDP growth and high tariffs. Given the uncertainty surrounding the Group’s estimated future revenues, S&P placed the Issuer on Creditwatch with negative implications in June 2014. To address concerns over the Group’s credit profile, the Government announced in September 2014 its Government Finance Support Package which includes, among other things, a R20 billion Government equity injection expected to be made in the 2015/16 financial year, the conversion of subordinated debt to equity, approval to issue additional debt of R50 billion and its support for future upward adjustments to electricity tariffs by way of NERSA’s RCA application process. However, despite Government support which will help to alleviate the funding gap to some extent, the Group will have to continue to revise its business plan and strategies (and continue to implement cost saving initiatives such as the BPP) to deal with the revenue shortfall. See “Risk Factors—Risks relating to the Group—The Group’s tariffs, which are determined by the regulator and are subject to considerable uncertainty in light of political and economic sensitivities, have historically been, and remain, below the Group’s cost of delivering service”. The Group’s tariffs support both energy and capacity efficiency through time and seasonally differentiated energy rates. In addition, the Group’s cost-reflective network charges for large customers and fixed network charges (albeit not fully cost-reflective for small customers) are intended to optimise the utilisation of networks. These principles will also support the Group’s DSM initiatives. Where technology is available, and also through media awareness initiatives and pricing signals, customers are encouraged to promote energy efficiency by the following DSM initiatives:

• consuming electricity during off-peak periods;

• making efficient use of the Group’s tariff signals that reward load shifting;

• accessing financial incentives available for upgrading of facilities for improved energy efficiency;

• choosing optimal supply capacity; and

• managing their operations effectively. Wind and Concentrating Solar Power In May 2013, NERSA granted the Group a license for construction of Sere, a planned 100 MW wind power facility near Koekenaap (Vredendal area) in the Western Cape, with funding approved by the World Bank, the African Development Bank, the Clean Technology Fund and other development banks. The R2.4 billion project is expected to be in full commercial operation by the end of 2014. The plant, with an expected operation life of 20 years, will consist of 46 Siemens wind turbine generators, a new substation and a 132 KV distribution line.

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In addition, the renewable energy research programme has identified concentrating solar power (“CSP”) as a high-potential future electricity generation option, given Southern Africa’s significant solar energy resource. The Group is developing a 100 MW CSP pilot plant that uses the central receiver technology with molten salt storage, near Upington in the Northern Cape, also co-financed by the World Bank, the African Development Bank, The Clean Technology Fund and other development banks. Electricity Transfer Pricing Within the Group The vertically-integrated nature of the Group’s business presents a transfer pricing issue. The ISMO (“Eskom Wholesaler”) buys electricity from generators and on-sells the electricity to distributors in order to supply customers. The transfer pricing issue arises with regard to the on-sale electricity price difference charged between the respective divisions; Generation, Distribution and Transmission, for transmitting electricity. Pursuant to the Electricity Regulation Act and NERSA’s regulatory methodology, NERSA historically determined regulated revenues for each of the Group’s licensed activities, namely generation, transmission and distribution. However, since the start of the MYPD 2 period in April 2010 and for the duration of the MYPD 3 period up until 31 March 2018, NERSA no longer allocates revenue per division. The allocation is therefore done internally, using the return-on-asset methodology consistent with that applied by NERSA to calculate the overall revenues. The Group’s revenue applications as well as regulatory reporting are therefore required to be structured as three distinct ring-fenced entities. As a result, the overall divisional revenues and, by extension, the prices they charge and pay to each other are also determined by NERSA. Details of transfer pricing mechanisms are, however, mostly left to the Group. The Generation division sells electricity to the Eskom Wholesaler. The price is based on the allowed revenue (determined by NERSA) for the Generation division (including the cost of energy purchased from IPPs) less revenue received by the Generation division for ancillary services sold to the Transmission division. The Transmission division incurs ancillary services costs in the course of maintaining a consistent and reliable grid. These ancillary services are provided by the Generation division and Group Customer Services. The Transmission division provides network services to transport energy from the generators to the Distribution division, Group Customer Services and the SAE business unit. As a result, the Transmission division receives network charge revenue from both generators and distributors, as well as reliability services revenue (which is used to pay for the ancillary services costs incurred by the Transmission division). In exchange for the use of the distribution network in order to supply its key customers, Group Customer Services pays a charge to the Distribution division for final delivery. The Eskom Wholesaler sells the energy received from the Generation division to Group Customer Services and the SAE business unit. NERSA treats the Distribution division and Group Customer Services as one regulated division and determines combined revenue for these entities. However, the Group treats them as two separate divisions and internally allocates each division a share of the combined revenue. Electrification The Government, through the Department of Energy, continues to fund the electrification of previously disadvantaged and farm worker households in areas where it has a license to supply. The ongoing operating costs for these connections are carried by Eskom and Eskom receives the revenue for the electricity sold while the Department of Energy funds the connections and the infrastructure development. The latest National Census which was conducted in 2011/12 reported that 3.4 million South African citizens are still without electricity. The main provinces affected by this situation include Limpopo, Eastern Cape and KwaZulu-Natal. The United Nations’ millennium development goal is to achieve universal electricity access by 2030 and the Department of Energy has thus accelerated the electrification process in a bid to reach this goal for South Africa by 2025. Construction efficiency opportunities are currently being pursued by Eskom in order to unlock savings and fund an additional 50,000 connections per year. The programme is also currently being implemented in more remote areas where the cost of infrastructure and connections are much higher due to location (i.e. the distance from more urban areas) as well as the undeveloped terrain in which the work is being carried out. The

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Department of Energy’s integrated national electrification programme has increased its funding by 17% to assist in meeting these costs. In the 2013/14 year, Eskom had managed to connect 200,000 households, excluding farm dwellers and those funded and connected by municipalities. When including the Department of Energy funded connections, Eskom achieved a total of 201,788 connections, the highest since 2002. Free Basic Electricity The Government aims to bring relief to low-income households through the national electricity basic services support tariff (“EBSST”), which was introduced by the Government in July 2003, with the goal of ensuring optimal socioeconomic benefits from the Electrification Programme. The programme established by the Government under the EBSST is known as the Free Basic Electricity (“FBE”) programme. Qualifying customers are eligible to receive 50 kWh of free electricity every month, the amount of electricity deemed sufficient to provide basic electricity services to a poor household. The Group participates in FBE by providing a service in its area of supply on behalf of municipalities. Municipalities, which are responsible for funding the provision of free basic services, receive government grants, including those covering FBE. Once received, these are paid to the Group to cover the cost of providing FBE to qualifying households. Households pay for any consumption over the set free basic service level. Any implementation costs incurred or any other costs are recoverable by the Group from the Government. Therefore, the Group has no cost associated with participating in the FBE programme. The following table sets out the results of the FBE programme for the periods indicated.

For the six months ended 30 September For the financial year ended 31 March 2014 2014 2013 2012 Municipals contracted to provide FBE ...... 243 243 243 243 Municipal contracts rolled out (%) ...... 100 100 99 99 Customers approved by municipalities for FBE ...... 1,034,614 978,246 1,142,077 1,196,117 Customer meters reconfigured to receive FBE ...... 1,179,916 1,165,906 1,139,696 1,139,120 Furthermore, in order to provide for cross-subsidies for low income domestic customers, as required by the EPP, the Issuer is in the process of implementing residential, inclining, block-rate tariffs concurrently with the price increases granted by NERSA for the MYPD 3 period (2013-2018). Environmental Regulation The Group’s generation, transmission, distribution and construction activities have an impact on the environment. Accordingly, the Group is subject to a number of South African laws, regulations and licencing requirements relating to the environment. With respect to environmental approvals, the Group is regulated by a number of authorities, including the DEA, the DWS, the Department of Agriculture, Forestry and Fisheries and provincial and local licensing authorities. These government authorities serve to protect the public interest and the environment through the regulation of the Group’s activities to ensure effective environmental protection. This is achieved through the issuing of environmental authorisations for the commencement of construction activities, licences for air quality (AELs), water usage, licencing requirements and waste licences regulating waste related activities including waste storage facilities. Such authorisations are only granted upon successful completion of relevant studies such as Environmental Impact Assessments (each an “EIA”) undertaken by independent Environmental Assessment Practitioners. Since July 2009, an environmental levy has been imposed on the Group on the electricity it generates from non-renewable resources. On 1 April 2011, the environmental levy was increased to 2.5 c/kWh, and on 1 July 2012 it was increased again by 1c/kWh to 3.5c/kWh. The Group passes on the cost of this levy to its customers. It is anticipated that this levy may be abolished with the introduction of the proposed new carbon tax, which was expected to be implemented in 2015 but has been deferred by the National Treasury to 2016. The Group revised the ISO 14001 implementation plan in 2013. The plan reduced the number of business units which obtain ISO certification to those areas with a high environmental impact. The areas with a low

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environmental impact will put appropriate controls in place to manage their environmental impacts. The following “high environmental impact” business divisions obtained ISO 14001 certification by December 2014: Generation, Transmission, Group Capital, Eskom Enterprises (Rotek and Roshcon, aviation and telecommunications departments), Primary Energy and Sustainability Systems. Distribution made significant progress towards certification with three of the nine operating units achieving certification. The remaining operating units will achieve certification by March 2016. The Group has also undertaken to develop and implement management systems that are ISO 9001:2008 compliant, in order to achieve sustainable performance improvement without deviating from applicable system requirements. The first phase in implementing such performance improvements involved establishing the ISO 9001 Quality Management Systems, to act as the foundation for good business management. This enabled the second phase to follow, which is ultimately aimed at promoting the Group as a high-performance organisation and a strong global utility. The assessment and measurement of the Group’s environmental performance are reported against set targets in the Group’s business plan report. In addition to the annual environmental audits, regular internal environmental audits, reviews and assessments are undertaken on operational divisions and reported to the relevant executive structures. These include independent audits which have to be completed by the Group as part of and as a condition to a number of environmental approval processes. The Group recorded a total of 32 environmental legal contraventions in the financial year ended 31 March 2014 compared to 48 as at 31 March 2013. Of these, 13 were water related (water leaks and spills, sewerage spills and ash line leaks) and 15 were for exceeding particulate emission limits at power stations. The remaining contraventions were related to vegetation management and clearing with a licence, environmental EIA non-compliance and oil spills. Training and awareness was initiated by Eskom as part of an initiative to ensure that both employees and contractors are aware of environmental risks In recent years, there have been a few instances of suspected non-compliance with the National Environmental Management Act 1998 within the Group which have been identified through inspections conducted by the Department of Environmental Affairs. In such instances, the Department of Environmental Affairs issues compliance notices, commonly in the form of an “intent to issue a compliance notice” or a “pre-compliance notice”. Failure to adequately address issues raised in a pre-compliance notice can result in the issuance of a compliance notice and/or criminal prosecution. The compliance issues relate to the Camden, Matimba and Lethabo power stations. A compliance notice was delivered in respect of the Camden power station during the first six months of 2012 to which the Group responded in October 2012. In April 2013, the Department of Environmental Affairs issued a request for further information. The Group submitted a response in May 2013 and follow up activities with the authorities took place during the year. There has, however, been no resolution in respect of this matter to date. In 2014, the Department of Environmental Affairs conducted a site visit at Matimba to monitor compliance with waste rock dump and temporary hazardous waste storage facility licenses. An inspection of sewerage works took place in January 2014 and a request for additional information was received in April 2014. The Group submitted a response in June 2014. In February 2014, the Department of Environment Affairs issued a notice indicating that it considered that the issues that it had raised in its July 2012 pre-compliance notice in respect of the Lethabo power station were now closed. Eskom will continue to implement its compliance programme in order to achieve full compliance in relation to environmental requirements, specifically: AELs, waste management permits, water use licences, environmental authorisations and biodiversity related permits. The minimum emission standards will become effective as April 2015 and April 2020. Eskom is unable to meet emissions standards at all sites within the required timelines, and has submitted an application for a five-year postponement for some power stations in terms of section 6 of the Listed Activities and Associated Minimum Emission Standards. Air quality The release of particulates and various pollutants into the atmosphere by the Group’s coal-fired power stations is currently regulated under the NEMAQA, which repealed the old Atmospheric Pollution Prevention Act, 1965. The MES and National Ambient Air Quality Standards have been published in accordance with NEMAQA. The commencement of NEMAQA brings South African air quality legislation in line with international best practice and includes provisions dealing with the listing of activities which result in atmospheric emissions and the requirement for an atmospheric emission licence. All of the Group’s coal-fired

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power stations fall in National Air Quality Priority Areas, where special measures are being implemented to improve air quality. The Group’s coal and liquid fuel power stations are granted emissions licences by the provincial and local (district municipality) emission licensing authorities. The Group aims to reduce particulate and gaseous emissions as well as to minimise resulting impacts on human health and the environment. It further aims to comply with regulated emission standards. Eskom’s Air Quality Strategy supports the implementation of retrofits of emission reducing abatement technologies required for emission reductions. The strategy was approved by the Board in November 2010. Planning for the “highest priority” projects is at an advanced stage. All power stations are equipped with emission abatement technologies to reduce particulate emissions from the stations’ flue gases (either, or both electrostatic precipitators or fabric filter plants). Particulate emissions are monitored and reported on a regular basis. The quantities of oxides of nitrogen, sulphur dioxide and particulate emissions emitted from the Group’s power stations are calculated on a monthly basis, based on the coal characteristics and the power station design parameters, and are published in the Group’s Annual Report. The Group has initiated a programme to implement the continuous monitoring of gaseous emissions at power stations. Currently, gaseous emissions from one unit or stack are monitored at each coal fired power station. All units or stacks are legislated to have installed functional continuous emission monitoring systems by 1 April 2015, in accordance with the MES contained in GNR 893 on 22 November 2013 which was promulgated in terms of Section 21 of the NEMAQA. The Group has undertaken regional air quality monitoring since the late 1970s as part of its air quality management programme. This provides key information for future planning, compliance and research purposes. Ambient air quality monitoring is currently undertaken at 15 ambient air-quality monitoring sites that measure a range of pollutants including sulphur dioxide, nitrogen dioxide, fine particulate matter and ozone. Meteorological parameters such as wind direction, wind velocity and temperature are also monitored. Although these sites measure pollutants from many sources, they are strategically located close to power stations and at ground level in order to detect the type of pollutants most likely to come from these power stations. Some monitors are located in residential areas and some in remote areas (to measure regional air quality). Monitoring equipment is calibrated according to National Meteorological Laboratory standards in a laboratory accredited by the South African National Accreditation System. Ambient air quality is impacted by emissions from a number of sources, including from the Group, and the combined results from all of these sources are reflected in the concentrations measured by the network. Generally, there is compliance with ambient air quality standards at the monitoring stations. In the financial year ended 31 March 2013, the annual ambient PM10 limit of 50 μg/m3 was exceeded at the Kendal, Komati and Marapong stations, and there was non-compliance with the daily PM10 standard at four sites. This could be attributed to many sources in relation to each station, including increased construction activity, proximity to a power station, mining activity and low-level sources like domestic combustion. It should be noted that power stations make only a very minor contribution to ambient PM10 levels because of the abatement equipment installed at the power stations. Climate Change and Renewable Energy South Africa is a signatory to the United Nations Framework Convention on Climate Change and the Kyoto Protocol. As a developing country, South Africa has no obligations to reduce greenhouse gas emissions. However, there is local commitment to sustainable development that benefits the South African economy, environment and society. South Africa is also particularly vulnerable to the adverse impacts of climate change, both due to impacts on the weather patterns in Southern Africa and impacts on the economy as a result of the response measures taken by developed countries. The National Treasury, on 2 May 2013, published the Carbon Tax Policy Paper, “Reducing greenhouse gas emissions and facilitating the transition to a green economy”, for public comment. In order to allow for further consultation, the erstwhile Minister of Finance in his 2014 budget speech postponed the implementation of the carbon tax to 2016. South Africa’s response to climate change is guided by the National Climate Change Response policy, which was approved by the Cabinet in November 2011. The policy is founded on the principles of sustainable growth and development of the country. Policy process will also guide South Africa’s input to the

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international negotiations in terms of what the country can and cannot do with regards to mitigation. This policy process has been driven by an intergovernmental committee led by the DEA in partnership with all stakeholders, including the Group. The implementation of a carbon tax, and the resultant possible increase in tariffs remains a challenge in terms of the economic impact thereof. National Treasury’s announcement on the deferment of the implementation to January 2016 provides further opportunities for Eskom to engage with National Treasury regarding this matter. Eskom is committed to reducing emissions to minimise the environmental effects of its operations in terms of the environment and health and Eskom also needs to comply with the regulated emissions standards. Overall environmental performance is assessed in terms of relative particulate emissions. The Group’s particulate emissions performance was better, marginally, than what was initially targeted and remained consistent with that in 2012/13. Eskom’s particulate emissions performance for 2013/14 was 0.35 kg/MWh sent out, which was better than the target of 0.36 kg/MWhSO. This shows that the maintenance measures in place and the technological advances are beginning to yield benefits. The Group has been focusing on reviewing its Climate Change Strategy in line with the Government’s policy implementation process and international discussions. The Group aspires to a more diverse energy mix, with the objective of reducing relative emissions until 2025 and subsequently reducing absolute emissions. It is a priority for the Group to adapt to impact of climate change, as this has major implications for the security of supply. The Group continually models electricity options that will balance the conflicting goals of affordability, economic growth, social inclusion and environmental protection in an optimal manner. There is currently no single technology option that will solve all of these challenges simultaneously. As a result, the Group is assessing all options, including the trade-offs and the impacts thereof. In addition, renewable energy plays an important role in meeting the Group’s diversification goals. Its renewable energy unit focuses on large power-generation technologies, including wind, photovoltaic and concentrating solar power. This will play an extremely important role in improving relative (emissions intensity) and reducing absolute emissions reduction. The Sere wind farm is located in a good wind resource area at Skaapvlei Farm within the Matzikama Municipality, in the Western Cape. The Sere wind farm will generate up to 100 MW of power for the national grid and it will avoid nearly 4.7 million tons of carbon emissions over a period of 20 years. The concentrated solar thermal power station is located near Upington and will save up to 450,000 tons of carbon dioxide emissions when it is commissioned. This plant will also yield up to 100 MW of power. In a bid to be environmentally friendly, the company has installed Photovoltaic solar panel arrays in Eskom buildings and power stations. This project is called Project Illanga and is expected to add 150 MW by 2017/18. The aim of this project is to offset electricity usage. The Group has partnerships with a diverse mix of funding institutions that are contributing to its two flagship renewable energy projects. These projects form part of South Africa’s Renewable Energy Country plan, which was developed in conjunction with the Department of Public Enterprises, the DEA, the Department of Energy and the National Treasury. Water use The Group is subject to regulation by the DWS under the National Water Act, 1998, which enforces regulations governing the supply and use of water. Since the 1970s the limitations of the water resources of South Africa have motivated the Group’s engineers to find ways to conserve water. The most effective of the solutions devised is dry cooling of coal-fired power stations, resulting in two of the biggest dry cooled power stations in the world. This has resulted in the saving of over two hundred million litres of water per day that would normally be lost through evaporation. Matimba Power Station near Lephalale in the Limpopo Province is the largest direct dry-cooled station in the world, with a generating capacity of 3,990 MW. It makes use of closed-circuit forced-draught cooling

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technology similar to the radiator and fan system used in motor vehicles. Water consumption is in the order of 0.11 litres per kWh of electricity sent out, compared with around 2.1 litres per kWh on average for the wet-cooled stations. The choice of dry-cooled technology for Matimba was largely influenced by the scarcity of water in the area. Kendal Power Station near Witbank in the Mpumalanga Province is the largest indirect dry-cooled power station in the world, with water consumption in the order of 0.14 litres per kWh of electricity sent out as at the current financial period. Indirect dry-cooling entails the cooling of the water through indirect contact with air in a natural draught cooling tower, a process during which virtually no water is lost in the transfer of the waste heat. At the Group’s water-cooled power stations improved water management has resulted in extensive re-use of water. The so-called zero liquid effluent discharge policy means in essence that water is used and re-used at the facility and no water is released from the site. The Group had a specific maximum water usage target of 1.39 litres per kWh sent out for the 2013/14 financial year. In the financial year ended 31 March 2014, the Group’s specific water usage was 1.35 litres per kWh and in the financial year ended 31 March 2013, the Group’s specific water usage was 1.42 litres per kWh. The water use target had been set at 1.39 litres per kWh for the 2014/15 financial year and, as at 30 September 2014, the Group had exceeded that target, having reached 1.40 litres per kWh. Increases in water consumption are influenced by many factors, including low rainfall at critical times, the high number of start-ups, additional activities such as air heater washing and the inability to obtain half station shut-downs to stop significant leaks at some power stations. At times of low rainfall, the station dams are not being filled from natural rainwater run-off, requiring the Group to procure water from external (metered) water sources. The Group established water management task teams at the power stations to address the reduction of water usage and legal contraventions. The objectives of the water management task team include the establishment of comprehensive plans to address all aspects of water-management and water-use performance. Therefore improvements in water use performance can be attributed mainly to an increase in the proportion of energy generated by the dry-cooled stations, increased opportunities for maintenance, implementation of initiatives identified by the water management task teams, good rains and the increased recovery of water. Eskom continues to engage with the DWS to clear the remaining backlog of water use licences. The current relative water use performance at power stations reflects the reality that the Group is operating ageing plants, with little opportunity for maintenance or upgrades to reduce their environmental impact. The Group will only be able to significantly improve environmental performance once sufficient opportunity is created for the maintenance downtime needed to undertake certain water management improvements. A programme to achieve Blue Drop (water treatment) and Green Drop (sewage works) certification by March 2016 is underway. In addition, the Group aims to reduce fresh-water usage and eliminate liquid effluent discharge through effective water-management processes, water conservation and water demand practices. The Group’s water management policy focuses on four key areas, namely: stakeholder management; corporate water stewardship; assurance and compliance; and training and development. The Group has established water-management task teams to work with power stations to address the reduction of water usage and ensure compliance to conditions of water use licences. The United Nations Global Compact’s CEO Water Mandate is a unique public-private initiative designed to help companies develop, implement and disclose water-sustainability policies and practices. As a signatory to the compact, the Group is committed to the CEO Water Mandate principles and reports annually on its progress. Waste management In accordance with part 7 of the National Environmental Management: Waste Act, 2008, the Group has commenced with the voluntary implementation of Industrial Waste Management Plans which focus on the efficient recycling, reuse and recovery of all Eskom waste streams.

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Eskom will continue to implement its compliance programme to achieve full compliance with environmental requirements, specifically: AELs, waste management permits, water use licences, environmental authorisations and biodiversity related permits. The minimum emission standards are effective from 2015. Eskom is unable to meet the emissions standards at all sites within the required timelines, and has submitted an application for a five-year postponement for some power stations in terms of section 6 of the Listed Activities and Associated Minimum Emission Standards to continue to work towards Blue drop (water treatment) and Green drop (sewerage works) certification by March 2016 and completion and commissioning of Sere wind farm project in the 2014/15 financial year. Polychlorinated biphenyls Polychlorinated biphenyls (“PCB”) are regulated by the “Regulations to Phase-Out the use of Polychlorinated Biphenyls (PCBs) Materials and Polychlorinated Biphenyl (PCBs) Contaminated Materials” under the National Environmental Management Act, 1998. The purpose) of these regulations is to: (a) prescribe requirements for the phase-out of the use of PCB materials and PCB-contaminated materials to ensure that impacts or potential impacts on health, wellbeing, safety and the environment are prevented or minimised; and (b) set timeframes during which PCB holders must have completely phased out the use of PCB materials and PCB contaminated materials and disposed of all PCB waste in their possession. The Group has been phasing out the use of PCB containing transformers by replacing them PCB with new compliant transformers. The Group’s divisions that utilise transformers have been requested to provide their divisional PCB phase-out plans by March 2015, upon which an organisation-wide plan will be compiled. So far, all divisions have PCB inventory lists in place which have recently been updated. Divisions will be measured on the implementation progress of the plan. In the financial year ended 31 March 2014, the Group destroyed 11,550 litres of PCBs. No PCBs were destroyed in the financial year ended 31 March 2013. PCBs are thermally destroyed at a licensed facility in Gauteng. Ash Of the approximately 35.0 million tonnes of coal ash produced at the Group’s coal-fired power stations in the financial year ended 31 March 2014, 7% was recycled compared to 6.8% in the financial year ended 31 March 2013. It is anticipated that the demand for ash may continue to increase as the Group continues to receive requests to supply ash to industry as a raw material for manufacturing purposes. In the financial year ended 31 March 2014, 2.4 million tonnes was sold. All remaining ash is disposed of in ash storage facilities at power stations and rehabilitated using soil and local vegetation to minimise the impact on the environment is undertaken. Eskom continues to work with the industry to pursue additional commercial opportunities associated with the utilisation of ash. Several power stations are reaching the capacity limits of their current ash storage facilities. Delays in obtaining funding for the expansion of ashing facilities and compliance with newly drafted environmental legislation may result in power stations having to significantly reduce production or even shut down. There are new legislative requirements for the construction and operation of ash storage facilities, which include the requirement for lining. The planning processes for several of these are advanced, but have been delayed due to a lack of funds for these projects. This, together with other delays, could result in power stations running out of ashing capacity as early as 2016, which may necessitate these power stations reducing their production significantly or even shutting down. Power stations are at risk if transitional arrangements are not agreed to by the DEA and the DWS. The number of legal environmental contraventions decreased from the previous year (32 contraventions against 481 in 2012/2013). A total of 13 were linked to water usage (leaks and spills, sewage spills and ash- line leaks) and 10 to power stations exceeding particulate emissions limits. The remaining contraventions related to clearing vegetation without a licence, installing distribution lines without environmental authorisation and oil spills. Eskom has initiated training and awareness initiatives to ensure that employees and contractors are made aware of environmental risks.

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Reliably procuring sufficient coal of the appropriate quality remains a challenge. Even though Eskom’s power stations are designed to use poor quality coal, in recent years some mines delivered fuel that did not meet Eskom’s coal quality standards, resulting in increased emissions, coal ash and wear on the plant. The Group continues to work with the industry and the South African Coal Ash Association to pursue commercial opportunities associated with the utilisation of ash. Such opportunities involve increasing the quantities of ash which are diverted from landfill, which not only reduces the environmental impact but also provides opportunities for business development. Nuclear The Group’s nuclear power station at Koeberg is regulated by the NNR established under the National Nuclear Regulator Act whose role it is to protect people, property and the environment against nuclear damage. The National Nuclear Regulator Act defines nuclear damage to mean (i) any injury to or the death or any sickness or disease of a person or (ii) other damage, including any damage to or any loss of use of property or damage to the environment, which arises out of, or results from, or is attributable to, the ionizing radiation associated with a nuclear installation. The NNR executes its mandate by: establishing safety standards and regulatory practices; by performing safety assessments and evaluations; issuing nuclear licences; monitoring compliance with the licence conditions and safety practices; and exercising regulatory control over the nuclear sector. Through the safety standards and regulatory practices, the NNR specifies the processes and practices that must be followed to ensure that the risk of incurring nuclear damage is maintained at acceptably low levels. Even though the risk is low, through the National Nuclear Regulator Act, the NNR also regulates the amount of financial security that the Group must provide for third party nuclear liability as insurance against compensation claims for nuclear damage. Nuclear plant safety inspections and regulations in South Africa are the responsibility of the NNR, which succeeded the Council for Nuclear Safety. The NNR has the authority to fine the Group and to suspend its nuclear operations, as appropriate, for any significant deviations from normal plant operating parameters. The Group continues to actively participate in the international nuclear domain through its affiliation to the World Association of Nuclear Operators, the IAEA and the Institute of Nuclear Power Operators. This facilitates benchmarking of performance, periodic safety reviews, definition of standards, dissemination of best practices and training of industry personnel. Koeberg’s safety standards and performance record comply with international safety standards, based on the reports of the responsible Operational Safety Review Team appointed by the IAEA, which evaluates Koeberg every two years. The year-on-year change in the quantities of radioactive waste is dependent on the total electricity production and the number of refuelling outages during the period. In the financial year ended 31 March 2013, the Group produced 188.2 m3 of low level radioactive waste (net) and 35.7 m3 of intermediate level waste (net). In the financial year ended 31 March 2014, the Group produced 180.8 m3 of low-level radioactive waste (net) and 28.7 m3 of intermediate level waste (net), and disposed of 324.0 m3 of low-level radioactive waste and 178.0 m3 of intermediate waste. Low and intermediate level radioactive waste from Koeberg power station is sealed in steel drums and concrete containers, respectively, and is disposed of at the Vaalputs National Radioactive Waste Repository, a near- surface disposal site for radioactive waste, licensed by the NNR and operated by the South African Nuclear Energy Corporation. All spent fuel (high-level waste) is stored within the power station. As of 30 September 2014, a cumulative total of 2,013 m3 spent nuclear fuel was in storage. Public exposure to radiation arising from Koeberg operations remains well within the limits set by the NNR. Exposure to radiation is measured in units of milliSievert (“mSv”). The limit recommended by the International Atomic Energy Agency for public exposure to radiation is 1mSv per year. However, the NNR has set a stricter limit of <0.25mSv per year for South Africa. The average public exposure to radiation arising from Koeberg’s operations has been below 0.005mSv in recent years, less than 2% of the limit imposed by the NNR. In the 2013/14 financial year, the public individual radiation exposure due to effluents from Koeberg was 0.0012 mSv.

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EXCHANGE CONTROLS The information below is not intended as legal advice and it does not purport to describe all the considerations that may be relevant to a prospective investor in the Notes. Prospective investors in the Notes who are non-South African residents or emigrants from the Common Monetary Area (as defined below) are urged to seek further professional advice with regard to a purchase of Notes. Exchange controls restrict the export of capital from South Africa, Namibia and the Kingdoms of Swaziland and Lesotho (collectively the “Common Monetary Area”). These exchange controls are administered by the ExCon of the SARB and regulate transactions involving South African residents. The purpose of exchange controls is to mitigate the decline of foreign capital reserves in South Africa. The Issuer expects that South African exchange controls will continue to operate for the foreseeable future. The Government has, however, committed itself to relaxing exchange controls gradually and significant relaxation has occurred in recent years. It is the stated objective of the South African authorities to achieve equality of treatment between South African residents and non-South African residents in relation to inflows and outflows of capital. This gradual approach towards the abolition of exchange controls adopted by the Government is designed to allow the economy to adjust more smoothly to the removal of controls that have been in place for a considerable period of time. Furthermore, exchange control requirements are in place under the Exchange Control Regulations, 1961 (the “Exchange Control Regulations”). The Group has obtained the written approval from the SARB, in terms of the Exchange Control Regulations, for the offering of securities under the Programme for a total amount up to U.S.$2 billion. The approval in this regard is granted conditional upon, inter alia, the Issuer furnishing ExCon with a copy of the indicative term sheet with the salient details of the offering. ExCon may impose certain conditions on the issue of each tranche of Notes, for example, with regard to maturity, issue size and listing. In addition, non-South African residents and their offshore subsidiaries may, without the prior written approval of ExCon, subscribe for or purchase any Note or beneficially hold or own any Note. South African residents and/or foreign subsidiaries of South African companies may not subscribe for or purchase Notes without the prior approval of ExCon, with the exception of those South African institutional investors who are afforded a foreign portfolio investment allowance by ExCon pursuant to the Exchange Control Regulations and subject to the relevant South African selling restrictions in the section headed “Subscription and Sale and Transfer and Selling Restrictions” below. Notes may only be issued in bearer form in accordance with the requirements of South African law which includes the prior approval of the South African Minister of Finance.

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TERMS AND CONDITIONS OF THE NOTES The following are the Terms and Conditions of the Notes which will be incorporated by reference into each Global Note (as defined below) and each Definitive Note, in the latter case only if permitted by the relevant stock exchange or other relevant authority (if any) and agreed by the Issuer and the relevant Dealer at the time of issue but, if not so permitted and agreed, such Definitive Note will have endorsed thereon or attached thereto such Terms and Conditions. The applicable Final Terms or relevant Drawdown Prospectus (as defined below) (or the relevant provisions thereof) will be endorsed upon, or attached to, each Global Note and Definitive Note. Reference should be made to “Form of the Notes” for a description of the content of the Final Terms or the Drawdown Prospectus which will specify which of such terms are to apply in relation to the relevant Notes. This Note is one of a Series (as defined below) of Notes issued by Eskom Holdings SOC Ltd (the “Issuer”) constituted by a trust deed (as modified and/or supplemented and/or restated from time to time, the “Trust Deed”) dated 22 July 2013 made between the Issuer and Citicorp Trustee Company Limited as trustee (the “Trustee”, which expression shall include any successor trustee). References herein to the “Notes” shall be references to the Notes of this Series and shall mean: (a) in relation to any Notes represented by a global Note (a “Global Note”), units of each Specified Denomination in the Specified Currency; (b) any Global Note; (c) any Definitive Notes in bearer form (“Bearer Notes”) issued in exchange for a Bearer Global Note; and (d) any Definitive Notes in registered form (“Registered Notes”) (whether or not issued in exchange for a Registered Global Note). The Notes and the Coupons (as defined below) have the benefit of an agency agreement (as amended and/or supplemented and/or restated from time to time, the “Agency Agreement”) dated 22 July 2013 and made between the Issuer, the Trustee, Citibank N.A., London branch as the principal paying agent and the transfer agent (the “Principal Paying Agent” and the “Transfer Agent”, respectively, which expression shall, in each case, include any successor principal paying agent or transfer agent, as the case may be) and Citigroup Global Markets Deutschland AG as the registrar (the “Registrar”, which expression shall include any successor registrar). Interest bearing Definitive Bearer Notes have interest coupons (“Coupons”) and, in the case of Bearer Notes which, when issued in definitive form, have more than 27 interest payments remaining, talons for further Coupons (“Talons”) attached on issue. Any reference herein to Coupons or coupons shall, unless the context otherwise requires, be deemed to include a reference to Talons or talons. Registered Notes and Global Notes do not have Coupons or Talons attached on issue. The terms and conditions applicable to the Notes are these terms and conditions (“Conditions”) as may be completed by a set of final terms in relation to each Series (as defined below) (“Final Terms”). The Final Terms for this Note (or the relevant provisions thereof) are set out in Part A of the Final Terms attached to or endorsed on this Note which supplement the Conditions. References to the “applicable Final Terms” are to Part A of the Final Terms (or the relevant provisions thereof) attached to or endorsed on this Note. The Notes may also be issued in a form not contemplated by the Conditions of the Notes herein, in which event a standalone prospectus may amend, supplement or vary the terms and conditions of any particular Tranche of Notes (a “Drawdown Prospectus”). References to the “relevant Drawdown Prospectus” are to any such prospectus which amends, supplements or varies any Tranche of Notes, as may be published from time to time. The Trustee acts for the benefit of the Noteholders (which expression shall mean (in the case of Bearer Notes) the holders of the Notes and (in the case of Registered Notes) the several persons whose names are entered in the register of holders of the Registered Notes as the holders thereof and shall, in relation to any Notes represented by a Global Note, be construed as provided in Condition 1 (Form, Denomination and Title)) and

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the holders of the Coupons (the “Couponholders”, which expression shall, unless the context otherwise requires, include the holders of the Talons), in accordance with the provisions of the Trust Deed. As used herein, “Tranche” means Notes which are identical in all respects (including as to listing and admission to trading) and “Series” means a Tranche of Notes together with any further Tranche or Tranches of Notes which are (a) expressed to be consolidated and form a single series and (b) identical in all respects (including as to listing and admission to trading) except for their respective Issue Dates, Interest Commencement Dates and/or Issue Prices. Copies of the Trust Deed and the Agency Agreement are available for inspection during normal business hours at the specified office of each of the Principal Paying Agent, the Registrar, the other paying agents (the “Paying Agents”, which expression shall include any additional successor paying agents) and transfer agents (the “Transfer Agents”, which expression shall include any additional successor transfer agents) (such agents and the Registrar being together referred to as the “Agents”). Copies of the applicable Final Terms or the relevant Drawdown Prospectus are available for viewing at the registered office of the Issuer and of the Principal Paying Agent and copies may be obtained from those offices save that, if this Note is neither admitted to trading on a regulated market in the European Economic Area nor offered to the public in the European Economic Area in circumstances which otherwise require the publication of a prospectus under Directive 2003/71/EC (and amendments thereto, including Directive 2010/73/EU, to the extent implemented in the Relevant Member State) (the “Prospectus Directive”), the applicable Final Terms or the relevant Drawdown Prospectus will only be obtainable by a Noteholder holding one or more Notes and such Noteholder must produce evidence satisfactory to the Issuer, the Trustee and the relevant Agent as to its holding of such Notes and identity. The Noteholders and the Couponholders are deemed to have notice of, and are entitled to the benefit of, all the provisions of the Trust Deed, the Agency Agreement and the applicable Final Terms or the relevant Drawdown Prospectus which are applicable to them. The statements in these Conditions include summaries of, and are subject to, the detailed provisions of the Trust Deed and the Agency Agreement. Words and expressions defined in the Trust Deed, the Agency Agreement or used in the applicable Final Terms or relevant Drawdown Prospectus shall have the same meanings where used in these Conditions unless the context otherwise requires or unless otherwise stated and provided that, in the event of inconsistency between the Trust Deed and the Agency Agreement, the Trust Deed will prevail and, in the event of inconsistency between the Trust Deed or the Agency Agreement and the applicable Final Terms or the relevant Drawdown Prospectus, the applicable Final Terms or the relevant Drawdown Prospectus will prevail. 1. FORM, DENOMINATION AND TITLE The Notes are in bearer form or in registered form as specified in the applicable Final Terms or the relevant Drawdown Prospectus, and in the case of Definitive Notes, serially numbered, in the Specified Currency. Notes of one Specified Denomination may not be exchanged for Notes of another Specified Denomination and Bearer Notes may not be exchanged for Registered Notes and vice versa. The Notes are issued in the Specified Denomination, provided that for Notes which are to be admitted to trading on a regulated market within the European Economic Area or offered to the public in a Member State of the European Economic Area in circumstances which otherwise require the publication of a prospectus under the Prospectus Directive, the minimum Specified Denomination shall be €100,000 (or its equivalent in any other currency as at the date of issue of the relevant Notes). Notes (including Notes denominated in Sterling) which have a maturity of less than one year and in respect of which the issue proceeds are to be accepted by the Issuer in the United Kingdom or whose issue otherwise constitutes a contravention of section 19 of the Financial Services and Markets Act, 2000 (as amended) will have a minimum denomination of £100,000 (or its equivalent in another currency). This Note may be a Fixed Rate Note, a Floating Rate Note, a Zero Coupon Note or a combination of any of the foregoing, depending upon the Interest Basis shown in the applicable Final Terms or relevant Drawdown Prospectus. Definitive Bearer Notes are issued with Coupons attached, unless they are Zero Coupon Notes in which case references to Coupons and Couponholders in these Conditions are not applicable.

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Registered Notes are represented by registered certificates (“Certificates”) and, save as provided in Condition 2 (Transfers of Registered Notes), each Certificate shall represent the entire holding of Registered Notes by the same holder. Each Certificate will be numbered serially with an identifying number which will be recorded in the register which the Issuer shall procure to be kept by the Registrar in accordance with the provisions of the Agency Agreement (the “Register”). Subject as set out below, title to the Bearer Notes and Coupons will pass by delivery and title to the Registered Notes will pass upon registration of transfers in accordance with the provisions of the Agency Agreement. The Issuer, the Trustee and any Agent will (except as otherwise required by law and the Trust Deed) deem and treat the bearer of any Bearer Note or Coupon and the registered holder of any Registered Note as the absolute owner thereof (whether or not overdue and notwithstanding any notice of ownership or writing thereon or notice of any previous loss or theft thereof) for all purposes but, in the case of any Global Note, without prejudice to the provisions set out in the immediately succeeding paragraph. For so long as any of the Notes is represented by a Global Note deposited with and, in the case of a Registered Global Note (as defined below in Condition 2.8 (Transfers of Registered Notes— Interpretation)), registered in the name of a nominee for a common depositary for Euroclear Bank SA/NV (“Euroclear”) and/or Clearstream Banking, société anonyme (“Clearstream, Luxembourg”), each person (other than Euroclear or Clearstream, Luxembourg) who is for the time being shown in the records of Euroclear or of Clearstream, Luxembourg as the holder of a particular nominal amount of such Notes (in which regard any certificate or other document issued by Euroclear or Clearstream, Luxembourg as to the nominal amount of such Notes standing to the account of any person shall be conclusive and binding for all purposes save in the case of manifest error) shall upon their receipt of such certificate or other document be treated by the Issuer, the Trustee and the Agents as the holder of such nominal amount of such Notes and the bearer or registered holder of such Global Note shall be deemed not to be the holder for all purposes other than with respect to the payment of principal or interest on such nominal amount of such Notes, for which purpose the bearer of the relevant Bearer Global Note or the registered holder of the relevant Registered Global Note shall be treated by the Issuer, the Trustee and any Agent as the holder of such nominal amount of such Notes in accordance with and subject to the terms of the relevant Global Note and the expressions “Noteholder” and “holder of Notes” and related expressions shall be construed accordingly. For so long as the Depository Trust Company (“DTC”) or its nominee is the registered owner or holder of a Registered Global Note, DTC or such nominee, as the case may be, will be considered the sole owner or holder of the Notes represented by such Registered Global Note for all purposes under the Trust Deed, the Agency Agreement and the Notes except to the extent that in accordance with DTC’s published rules and procedures any ownership rights may be exercised by its participants or beneficial owners through participants. In determining whether a particular person is entitled to a particular nominal amount of Notes as aforesaid, the Trustee may rely on such evidence and/or information and/or certification as it shall, in its absolute discretion, deem fit and, if it does so rely, such evidence and/or information and/or certification shall, in the absence of manifest error, be conclusive and binding on all concerned. Notes which are represented by a Global Note will be transferable only in accordance with the rules and procedures for the time being of DTC, Euroclear and Clearstream, Luxembourg, as the case may be. References to DTC, Euroclear and/or Clearstream, Luxembourg shall, whenever the context so permits, be deemed to include a reference to any additional or alternative clearing system specified in the applicable Final Terms, the relevant Drawdown Prospectus or as may otherwise be approved by the Issuer, the Principal Paying Agent and the Trustee. 2. TRANSFERS OF REGISTERED NOTES 2.1 Transfers of Interests in Registered Global Notes Transfers of beneficial interests in Registered Global Notes will be effected by DTC, Euroclear or Clearstream, Luxembourg, as the case may be, and, in turn, by other participants and, if appropriate, indirect participants in such clearing systems acting on behalf of beneficial transferors and transferees

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of such interests. A beneficial interest in a Registered Global Note will, subject to compliance with all applicable legal and regulatory restrictions, be transferable for Definitive Registered Notes or for a beneficial interest in another Registered Global Note only in the Specified Denomination(s) set out in the applicable Final Terms or relevant Drawdown Prospectus and only in accordance with the rules and operating procedures for the time being of DTC, Euroclear or Clearstream, Luxembourg, as the case may be, and in accordance with the terms and conditions specified in the Trust Deed and the Agency Agreement. Transfers of a Registered Global Note registered in the name of a nominee for DTC shall be limited to transfers of such Registered Global Note, in whole but not in part, to another nominee of DTC or to a successor of DTC or such successor’s nominee. 2.2 Transfers of Definitive Registered Notes Subject as provided in Conditions 2.5 (Transfers of Interests in Regulation S Global Note), 2.6 (Transfers of Interests in Legended Notes) and 2.7 (Exchanges and Transfers of Registered Notes Generally) below, upon the terms and subject to the conditions set forth in the Trust Deed and the Agency Agreement, a Definitive Registered Note may be transferred in whole or in part (in the Specified Denomination(s) set out in the applicable Final Terms or relevant Drawdown Prospectus). In order to effect any such transfer (i) the holder or holders must (A) surrender the Registered Note for registration of the transfer of the Registered Note (or the relevant part of the Registered Note) at the specified office of any Transfer Agent, with the form of transfer thereon duly executed by the holder or holders thereof or its or their attorney or attorneys duly authorised in writing, and (B) complete and deposit such other certifications as may be required by the relevant Transfer Agent; and (ii) the relevant Transfer Agent must, after due and careful enquiry, be satisfied with the documents of title and the identity of the person making the request. Any such transfer will be subject to such reasonable regulations as the Issuer, the Trustee and the Registrar may from time to time prescribe (the initial such regulations being set out in Schedule 5 to the Agency Agreement). Subject as provided above, the relevant Transfer Agent will, within three business days (being for this purpose a day on which banks are open for business in the city where the specified office of the relevant Transfer Agent is located) of the request (or such longer period as may be required to comply with any applicable fiscal or other laws or regulations), authenticate and deliver, or procure the authentication and delivery of, at its specified office to the transferee or (at the risk of the transferee) send by uninsured mail, to such address as the transferee may request, a new Definitive Registered Note of a like aggregate nominal amount to the Registered Note (or the relevant part of the Registered Note) transferred. In the case of the transfer of part only of a Definitive Registered Note, a new Definitive Registered Note in respect of the balance of the Registered Note not transferred will be so authenticated and delivered or (at the risk of the transferor) sent to the transferor. No transfer of a Registered Note will be valid unless and until entered in the Register. 2.3 Registration of Transfer upon Partial Redemption In the event of a partial redemption of Notes under Condition 7 (Redemption and Purchase), the Issuer shall not be required to register the transfer of any Registered Note, or part of a Registered Note, called for partial redemption. 2.4 Costs of Registration Noteholders will not be required to bear the costs and expenses of effecting any registration of transfer as provided above, except for any costs or expenses of delivery other than by regular uninsured mail and except that the Issuer and/or any Agent may require the payment of a sum sufficient to cover any stamp duty, tax or other governmental charge that may be imposed in relation to the registration and/or transfer.

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2.5 Transfers of Interests in Regulation S Global Note Prior to expiry of the applicable Distribution Compliance Period, transfers by the holder of, or of a beneficial interest in, a Regulation S Global Note to a transferee in the United States or who is a U.S. person will only be made: (a) upon receipt by the Registrar of a written certification substantially in the form set out in the Agency Agreement, amended as appropriate (a “Transfer Certificate”), copies of which are available from the specified office of any Transfer Agent, from the transferor of the Note or beneficial interest therein to the effect that such transfer is being made to a person whom the transferor reasonably believes is a QIB in a transaction meeting the requirements of Rule 144A; or (b) otherwise pursuant to the Securities Act or an exemption therefrom, subject to receipt by the Issuer of such satisfactory evidence as the Issuer may reasonably require, which may include an opinion of U.S. counsel, that such transfer is in compliance with any applicable securities laws of any State of the United States, and, in each case, in accordance with any applicable securities laws of any State of the United States or any other applicable jurisdiction. In the case of (a) above, such transferee may take delivery through a Legended Note in global or definitive form. After expiry of the applicable Distribution Compliance Period (i) beneficial interests in the relevant Regulation S Global Note registered in the name of a nominee for DTC may be held through DTC directly, by a participant in DTC, or indirectly through a participant in DTC and (ii) such certification requirements will no longer apply to such transfers. 2.6 Transfers of Interests in Legended Notes Transfers of Legended Notes or beneficial interests therein may be made: (a) to a transferee who takes delivery of such interest through a Regulation S Global Note, upon receipt by the Registrar of a duly completed Transfer Certificate from the transferor to the effect that such transfer is being made in accordance with Regulation S and that in the case of a Regulation S Global Note registered in the name of a nominee for DTC, if such transfer is being made prior to expiry of the applicable Distribution Compliance Period, the interests in the Notes being transferred will be held immediately thereafter through Euroclear and/or Clearstream, Luxembourg; or (b) to a transferee who takes delivery of such interest through a Legended Note where the transferee is a person whom the transferor reasonably believes is a QIB in a transaction meeting the requirements of Rule 144A, without certification; or (c) otherwise pursuant to the Securities Act or an exemption therefrom, subject to receipt by the Issuer of such satisfactory evidence as the Issuer may reasonably require, which may include an opinion of U.S. counsel, that such transfer is in compliance with any applicable securities laws of any State of the United States, and, in each case, in accordance with any applicable securities laws of any State of the United States or any other applicable jurisdiction. Upon the transfer, exchange or replacement of Legended Notes, or upon specific request for removal of the Legend, the Registrar shall deliver only Legended Notes if, or refuse to remove the Legend (as the case may be) unless there is delivered to the Issuer such satisfactory evidence as may reasonably be required by the Issuer, which may include an opinion of U.S. counsel, that neither the Legend nor the restrictions on transfer set forth therein are required to ensure compliance with the provisions of the Securities Act.

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2.7 Exchanges and Transfers of Registered Notes Generally Holders of Definitive Registered Notes may exchange such Notes for interests in a Registered Global Note of the same type at any time. 2.8 Interpretation For the purposes of these Conditions: “Distribution Compliance Period” means the period that ends 40 days after the completion of the distribution of each Tranche of Notes, as certified by the relevant Dealer (in the case of a non- syndicated issue) or the relevant Lead Manager(s) (in the case of a syndicated issue); “Legended Note” means Registered Notes (whether in definitive form or represented by a Registered Global Note) that include a legend restricting sales within the United States to QIBs in accordance with the requirements of Rule 144A; “QIB” means a qualified institutional buyer within the meaning of Rule 144A; “Registered Global Note” means a Global Note in registered form (whether in the form of a Regulation S Global Note or a Rule 144A Global Note); “Regulation S ” means Regulation S under the Securities Act; “Regulation S Global Note” means a Registered Global Note representing Notes sold outside the United States in reliance on Regulation S; “Rule 144A” means Rule 144A under the Securities Act; “Rule 144A Global Note” means a Registered Global Note representing Notes sold in the United States or to QIBs pursuant to Rule 144A; and “Securities Act” means the U.S. Securities Act of 1933, as amended. 3. STATUS OF THE NOTES The Notes and any relevant Coupons are direct, unconditional, unsubordinated and (subject to the provisions of Condition 4 (Negative Pledge)) unsecured obligations of the Issuer and (subject as provided above) rank and will rank pari passu without any preference among themselves and pari passu in right of payment with all other outstanding unsecured and unsubordinated obligations of the Issuer, present and future, but, in the event of insolvency, only to the extent permitted by applicable laws relating to creditors’ rights. The Notes will not benefit from any security arrangements provided for under section 7 of the Eskom Conversion Act, 2001, as amended (the “Conversion Act”). Section 7 of the Conversion Act provides that all borrowings effected by the Issuer and any interest or other costs due or to become due in respect thereof must, unless otherwise agreed between the Issuer and the lender, be a first charge against all revenues and assets of the Issuer and on all monies recovered or to be recovered by it. Pursuant to these Conditions it is agreed that the Notes will not benefit from the provisions of section 7 of the Conversion Act and accordingly will not benefit from a first charge against revenues and assets of the Issuer or any monies recovered or to be recovered by the Issuer. 4. NEGATIVE PLEDGE 4.1 Negative Pledge So long as any of the Notes remains outstanding (as defined in the Trust Deed), the Issuer shall not, and shall procure that none of its Material Subsidiaries (as defined in Condition 10.2 (Events of Default and Enforcement—Interpretation)) will, create or have outstanding any mortgage, charge, lien, pledge or other security interest (each a “Security Interest”) upon, or with respect to, any of its

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present or future business, undertaking, assets or revenues (including any uncalled capital) or any part thereof to secure any Relevant Indebtedness or any guarantee of any Relevant Indebtedness of any third parties, without at the same time promptly taking any and all action necessary to ensure that: (a) all amounts payable by it under the Notes and the Trust Deed are secured equally and rateably with such Relevant Indebtedness or guarantee, as the case may be, by the Security Interest to the satisfaction of the Trustee; or (b) such other Security Interest or other arrangement (whether or not it includes the giving of a Security Interest) is provided either (i) as the Trustee shall in its absolute discretion deem not materially less beneficial to the interests of the Noteholders or (ii) as shall be approved by an Extraordinary Resolution (which is defined in the Trust Deed as a resolution duly passed by a majority of not less than three-quarters of the votes cast) of the Noteholders, save that the Issuer or any Material Subsidiary may have outstanding a Security Interest in respect of Relevant Indebtedness and/or guarantees given by the Issuer or any Material Subsidiary in respect of Relevant Indebtedness of any other person (without the obligation to provide a Security Interest or guarantee or other arrangement in respect of the Notes and the Trust Deed as aforesaid) where such Security Interest (i) is over any of the business, undertaking, assets or revenues of a company becoming a Material Subsidiary after 22 July 2013 and where such Security Interest exists at the time that company becomes a Material Subsidiary (provided that such Security Interest is not created in contemplation of such acquisition and the principal amount secured at the time of such acquisition is not subsequently increased), (ii) arises by operation of the statutory provisions of section 7 of the Conversion Act in respect of the Permitted Securities in an aggregate principal amount outstanding at any time not in excess of ZAR 20,000,000,000 or (iii) existed on 22 July 2013. 4.2 Interpretation For the purposes of these Conditions: “Capital and Reserves” means the aggregate of: (a) the amount paid up or credited as paid up on the share capital of the Issuer; and (b) the total of the capital, revaluation and revenue reserves of the Group, including any share premium account, capital redemption reserve and credit balance on the profit and loss account, but excluding sums set aside for taxation and amounts attributable to minority interests and deducting any debit balance on the profit and loss account, all as shown in the then latest audited consolidated balance sheet and profit and loss account of the Group prepared in accordance with International Financial Reporting Standards (“IFRS”), but adjusted as may be necessary in respect of any variation in the paid-up share capital or share premium account of the Group since the date of that balance sheet and further adjusted as may be necessary to reflect any change since the date of that balance sheet in the Subsidiaries comprising the Group. A certificate addressed to the Trustee and signed by two directors of the Issuer or two members of the Executive Management Committee of the Issuer (“EXCO”) as to the amount of the Capital and Reserves at any given time shall, in the absence of manifest error, be conclusive and binding on all parties; “Excluded Subsidiary” means any Subsidiary: (a) which is a single-purpose company whose principal assets and business are constituted by the ownership, acquisition, development or operation of an asset; (b) none of whose indebtedness for borrowed money in respect of the financing of such ownership, acquisition, development or operation of an asset is subject to any recourse whatsoever to any member of the Group (other than the Subsidiary or another Excluded Subsidiary) in respect of the repayment thereof; and (c) which has been designated as such by the Issuer by written notice to the Trustee signed by two directors of the Issuer or two members of EXCO, provided that the Issuer may give

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written notice signed by two directors of the Issuer or two members of EXCO to the Trustee at any time that any Excluded Subsidiary is no longer an Excluded Subsidiary, whereupon it shall cease to be an Excluded Subsidiary; “Group” means the Issuer and the Subsidiaries; “Permitted Securities” means the Registered Stock Loan No. 170 of the Issuer in the principal amount of up to ZAR 20,000,000,000, details of which are set out in a Prospectus dated 1 July 1992, of which as at 23 January 2015 ZAR 11,353,000,000 was issued and outstanding; “Project Finance Indebtedness” means any indebtedness for borrowed money to finance the ownership, acquisition, development or operation of an asset: (a) which is incurred by an Excluded Subsidiary; or (b) in respect of which the person or persons to whom any such indebtedness for borrowed money is or may be owed by the relevant borrower (whether or not a member of the Group) has or have no recourse whatsoever to any member of the Group (other than an Excluded Subsidiary) for the repayment thereof other than: (i) recourse to such borrower for amounts limited to the cash flow or net cash flow (other than historic cash flow or historic net cash flow) from such asset; or (ii) recourse to such borrower for the purpose only of enabling amounts to be claimed in respect of such indebtedness for borrowed money in an enforcement of any encumbrance given by such borrower over such asset or the income, cash flow or other proceeds deriving therefrom (or given by any shareholder or the like in the borrower over its shares or the like in the capital of the borrower) to secure such indebtedness for borrowed money, provided that (A) the extent of such recourse to such borrower is limited solely to the amount of any recoveries made on any such enforcement, and (B) such person or persons are not entitled, by virtue of any right or claim arising out of or in connection with such indebtedness for borrowed money, to commence proceedings for the winding up or dissolution of the borrower or to appoint or procure the appointment of any receiver, trustee or similar person or officer in respect of the borrower or any of its assets (save for the assets the subject of such encumbrance); or (iii) recourse to such borrower generally, or directly or indirectly to a member of the Group, under any form of assurance, undertaking or support, which recourse is limited to a claim for damages (other than liquidated damages and damages required to be calculated in a specified way) for breach of an obligation (not being a payment obligation or an obligation to procure payment by another or an indemnity in respect thereof or an obligation to comply or to procure compliance by another with any financial ratios or other tests of financial condition) by the person against whom such recourse is available; and “Relevant Indebtedness” means (a) any present or future indebtedness (whether being principal, premium, interest or other amounts) in the form of or represented by notes, bonds, debentures, debenture stock, loan stock or other securities, whether issued for cash or in whole or in part for a consideration other than cash, and which are, or are capable of being, quoted, listed or ordinarily dealt in on any stock exchange or recognised over-the-counter or other securities market and (b) any guarantee or indemnity in respect of any such indebtedness, but shall in any event not include Project Finance Indebtedness.

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5. INTEREST 5.1 Interest on Fixed Rate Notes Each Fixed Rate Note bears interest from (and including) the Interest Commencement Date at the rate(s) per annum equal to the Rate(s) of Interest. Interest will be payable in arrear on the Interest Payment Date(s) in each year up to (and including) the Maturity Date. If the Notes are in definitive form, except as provided in the applicable Final Terms or relevant Drawdown Prospectus, the amount of interest payable on each Interest Payment Date in respect of the Fixed Interest Period ending on (but excluding) such date will amount to the Fixed Coupon Amount. Payments of interest on any Interest Payment Date will, if so specified in the applicable Final Terms or relevant Drawdown Prospectus, amount to the Broken Amount so specified. Except in the case of Definitive Notes where a Fixed Coupon Amount or Broken Amount is specified in the applicable Final Terms or relevant Drawdown Prospectus, interest shall be calculated in respect of any period by applying the Rate of Interest to: (a) in the case of Fixed Rate Notes which are represented by a Global Note, the aggregate outstanding nominal amount of the Fixed Rate Notes represented by such Global Note; or (b) in the case of Fixed Rate Notes in definitive form, the Calculation Amount; and, in each case, multiplying such sum by the applicable Day Count Fraction, and rounding the resultant figure to the nearest sub-unit of the relevant Specified Currency, half of any such sub-unit being rounded upwards or otherwise in accordance with applicable market convention. Where the Specified Denomination of a Fixed Rate Note in definitive form is a multiple of the Calculation Amount, the amount of interest payable in respect of such Fixed Rate Note shall be the product of the amount (determined in the manner provided above) for the Calculation Amount and the amount by which the Calculation Amount is multiplied to reach the Specified Denomination without any further rounding. 5.2 Interpretation For the purposes of these Conditions: “Day Count Fraction” means, in respect of the calculation of an amount of interest, in accordance with this Condition: (a) if “Actual/Actual (ICMA)” is specified in the applicable Final Terms or relevant Drawdown Prospectus: (i) in the case of Notes where the number of days in the relevant period from (and including) the most recent Interest Payment Date (or, if none, the Interest Commencement Date) to (but excluding) the relevant payment date (the “Accrual Period”) is equal to or shorter than the Determination Period during which the Accrual Period ends, the number of days in such Accrual Period divided by the product of (1) the number of days in such Determination Period and (2) the number of Determination Dates (as specified in the applicable Final Terms or relevant Drawdown Prospectus) that would occur in one calendar year; or (ii) in the case of Notes where the Accrual Period is longer than the Determination Period during which the Accrual Period ends, the sum of: (A) the number of days in such Accrual Period falling in the Determination Period in which the Accrual Period begins divided by the product of (x) the number of days in such Determination Period and (y) the number of Determination Dates that would occur in one calendar year; and (B) the number of days in such Accrual Period falling in the next Determination Period divided by the product of (x) the number of days in such

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Determination Period and (y) the number of Determination Dates that would occur in one calendar year; and (b) if “30/360” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the number of days in the period from (and including) the most recent Interest Payment Date (or, if none, the Interest Commencement Date) to (but excluding) the relevant payment date (such number of days being calculated on the basis of a year of 360 days with twelve 30-day months) divided by 360. “Determination Period ” means each period from (and including) a Determination Date to but excluding the next Determination Date (including, where either the Interest Commencement Date or the final Interest Payment Date is not a Determination Date, the period commencing on the first Determination Date prior to, and ending on the first Determination Date falling after, such date); “Fixed Interest Period” means the period from (and including) an Interest Payment Date (or the Interest Commencement Date) to (but excluding) the next (or first) Interest Payment Date; and “sub-unit” means, with respect to any currency other than euro, the lowest amount of such currency that is available as legal tender in the country of such currency and, with respect to euro, one cent. 5.3 Interest on Floating Rate Notes (a) Interest Payment Dates Each Floating Rate Note bears interest from (and including) the Interest Commencement Date and such interest will be payable in arrear on either: (i) the Specified Interest Payment Date(s) in each year specified in the applicable Final Terms or relevant Drawdown Prospectus; or (ii) if no Specified Interest Payment Date(s) is/are specified in the applicable Final Terms or relevant Drawdown Prospectus, each date (each such date, together with each Specified Interest Payment Date, an “Interest Payment Date”) which falls within the number of months or other period specified as the Specified Period in the applicable Final Terms or relevant Drawdown Prospectus after the preceding Interest Payment Date or, in the case of the first Interest Payment Date, after the Interest Commencement Date. Such interest will be payable in respect of each Interest Period (which expression shall, in these Conditions, mean the period from (and including) an Interest Payment Date (or the Interest Commencement Date) to (but excluding) the next (or first) Interest Payment Date). If a Business Day Convention is specified in the applicable Final Terms or relevant Drawdown Prospectus and (x) if there is no numerically corresponding day on the calendar month in which an Interest Payment Date should occur or (y) if any Interest Payment Date would otherwise fall on a day which is not a Business Day, then, if the Business Day Convention specified is: (i) in any case where Specified Periods are specified in accordance with Condition 5.3(a)(ii) (Interest on Floating Rate Notes—Interest Payment Dates) above, the Floating Rate Convention, such Interest Payment Date (i) in the case of (x) above, shall be the last day that is a Business Day in the relevant month and the provisions of (B) below shall apply mutatis mutandis or (ii) in the case of (y) above, shall be postponed to the next day which is a Business Day unless it would thereby fall into the next calendar month, in which event (A) such Interest Payment Date shall be brought forward to the immediately preceding Business Day and (B) each subsequent Interest Payment Date shall be the last Business Day in the month which falls the Specified Period after the preceding applicable Interest Payment Date occurred; or

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(ii) the Following Business Day Convention, such Interest Payment Date shall be postponed to the next day which is a Business Day; or (iii) the Modified Following Business Day Convention, such Interest Payment Date shall be postponed to the next day which is a Business Day unless it would thereby fall into the next calendar month, in which event such Interest Payment Date shall be brought forward to the immediately preceding Business Day; or (iv) the Preceding Business Day Convention, such Interest Payment Date shall be brought forward to the immediately preceding Business Day. In these Conditions, “Business Day” means a day which is both: (A) a day on which commercial banks and foreign exchange markets settle payments and are open for general business (including dealing in foreign exchange and foreign currency deposits) in any Additional Business Centre specified in the applicable Final Terms or relevant Drawdown Prospectus; and (B) either (1) in relation to any sum payable in a Specified Currency other than euro, a day on which commercial banks and foreign exchange markets settle payments and are open for general business (including dealing in foreign exchange and foreign currency deposits) in the principal financial centre of the country of the relevant Specified Currency or (2) in relation to any sum payable in euro, a day on which the Trans European Automated Real Time Gross Settlement Express Transfer (TARGET2) System (the “TARGET2 System”) which was launched on 19 November 2007 or any successor thereto is open. (b) Rate of Interest The Rate of Interest payable from time to time in respect of Floating Rate Notes will be determined in the manner specified in the applicable Final Terms or relevant Drawdown Prospectus. (i) ISDA Determination for Floating Rate Notes Where ISDA Determination is specified in the applicable Final Terms or relevant Drawdown Prospectus as the manner in which the Rate of Interest is to be determined, the Rate of Interest for each Interest Period will be the relevant ISDA Rate plus or minus (as indicated in the applicable Final Terms or relevant Drawdown Prospectus) the Margin (if any). For the purposes of this subparagraph (i), “ISDA Rate” for an Interest Period means a rate equal to the Floating Rate that would be determined by the Principal Paying Agent under an interest rate swap transaction if the Principal Paying Agent were acting as Calculation Agent for that swap transaction under the terms of an agreement incorporating the 2006 ISDA Definitions, as published by the International Swaps and Derivatives Association, Inc. and as amended and updated as of the Issue Date of the first Tranche of the Notes (the “ISDA Definitions”) and under which: (A) the Floating Rate Option is as specified in the applicable Final Terms or relevant Drawdown Prospectus; (B) the Designated Maturity is a period specified in the applicable Final Terms or relevant Drawdown Prospectus; and (C) the relevant Reset Date is either (i) if the applicable Floating Rate Option is based on the London interbank offered rate (“LIBOR”) or on the Euro zone interbank offered rate (“EURIBOR”), the first day of that Interest Period or

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(ii) in any other case, as specified in the applicable Final Terms or relevant Drawdown Prospectus. For the purposes of this subparagraph (i), “Floating Rate”, “Calculation Agent”, “Floating Rate Option”, “Designated Maturity” and “Reset Date” have the meanings given to those terms in the ISDA Definitions. Unless otherwise stated in the applicable Final Terms or relevant Drawdown Prospectus the Minimum Rate of Interest shall be deemed to be zero. (ii) Screen Rate Determination for Floating Rate Notes Where Screen Rate Determination is specified in the applicable Final Terms or relevant Drawdown Prospectus as the manner in which the Rate of Interest is to be determined, the Rate of Interest for each Interest Period will, subject as provided below, be either: (A) the offered quotation; or (B) the arithmetic mean (rounded if necessary to the fifth decimal place, with 0.000005 being rounded upwards) of the offered quotations, (expressed as a percentage rate per annum) for the Reference Rate which appears or appear, as the case may be, on the Relevant Screen Page as of 11.00 a.m. (London time, in the case of LIBOR, or Brussels time, in the case of EURIBOR) on the Interest Determination Date in question plus or minus (as indicated in the applicable Final Terms or relevant Drawdown Prospectus) the Margin (if any), all as determined by the Principal Paying Agent. If five or more of such offered quotations are available on the Relevant Screen Page, the highest (or, if there is more than one such highest quotation, one only of such quotations) and the lowest (or, if there is more than one such lowest quotation, one only of such quotations) shall be disregarded by the Principal Paying Agent for the purpose of determining the arithmetic mean (rounded as provided above) of such offered quotations. The Agency Agreement contains provisions for determining the Rate of Interest in the event that the Relevant Screen Page is not available or if, in the case of (A) above, no such offered quotation appears or, in the case of (B) above, fewer than three such offered quotations appear, in each case as of the time specified in the preceding subparagraph. If the Reference Rate from time to time in respect of Floating Rate Notes is specified in the applicable Final Terms or relevant Drawdown Prospectus as being other than LIBOR or EURIBOR, the Rate of Interest in respect of such Notes will be determined as provided in the applicable Final Terms or relevant Drawdown Prospectus. (c) Minimum Rate of Interest and/or Maximum Rate of Interest If the applicable Final Terms or relevant Drawdown Prospectus specifies a Minimum Rate of Interest for any Interest Period, then, in the event that the Rate of Interest in respect of such Interest Period determined in accordance with the provisions of subparagraph (b) above is less than such Minimum Rate of Interest, the Rate of Interest for such Interest Period shall be such Minimum Rate of Interest. If the applicable Final Terms or relevant Drawdown Prospectus specifies a Maximum Rate of Interest for any Interest Period, then, in the event that the Rate of Interest in respect of such Interest Period determined in accordance with the provisions of subparagraph (b) above is greater than such Maximum Rate of Interest, the Rate of Interest for such Interest Period shall be such Maximum Rate of Interest.

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(d) Determination of Rate of Interest and Calculation of Interest Amounts The Principal Paying Agent will at or as soon as practicable after each time at which the Rate of Interest is to be determined, determine the Rate of Interest for the relevant Interest Period. The Principal Paying Agent will calculate the amount of interest (the “Interest Amount”) payable on the Floating Rate Notes for the relevant Interest Period by applying the Rate of Interest to: (i) in the case of Floating Rate Notes which are represented by a Global Note, the aggregate outstanding nominal amount of the Notes represented by such Global Note; or (ii) in the case of Floating Rate Notes in definitive form, the Calculation Amount; and, in each case, multiplying such sum by the applicable Day Count Fraction, and rounding the resultant figure to the nearest sub-unit of the relevant Specified Currency, half of any such sub-unit being rounded upwards or otherwise in accordance with applicable market convention. Where the Specified Denomination of a Floating Rate Note in definitive form is a multiple of the Calculation Amount, the Interest Amount payable in respect of such Note shall be the product of the amount (determined in the manner provided above) for the Calculation Amount and the amount by which the Calculation Amount is multiplied to reach the Specified Denomination without any further rounding. “Day Count Fraction” means, in respect of the calculation of an amount of interest in accordance with this Condition: (i) if “Actual/Actual (ISDA)” or “Actual/Actual” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the actual number of days in the Interest Period divided by 365 (or, if any portion of that Interest Period falls in a leap year, the sum of (A) the actual number of days in that portion of the Interest Period falling in a leap year divided by 366 and (B) the actual number of days in that portion of the Interest Period falling in a non-leap year divided by 365); (ii) if “Actual/365 (Fixed)” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the actual number of days in the Interest Period divided by 365; (iii) if “Actual/365 (Sterling)” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the actual number of days in the Interest Period divided by 365 or, in the case of an Interest Payment Date falling in a leap year, 366; (iv) if “Actual/360” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the actual number of days in the Interest Period divided by 360; (v) if “30/360”, “360/360” or “Bond Basis” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the number of days in the Interest Period divided by 360, calculated on a formula basis as follows: 360 − + 30 − + − = 360 where:

“Y1” is the year, expressed as a number, in which the first day of the Interest Period falls;

“Y2” is the year, expressed as a number, in which the day immediately following the last day of the Interest Period falls;

“M1” is the calendar month, expressed as a number, in which the first day of the Interest Period falls;

“M2” is the calendar month, expressed as a number, in which the day immediately following the last day of the Interest Period falls;

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“D1” is the first calendar day, expressed as a number, of the Interest Period, unless such number is 31, in which case D1 will be 30; and

“D2” is the calendar day, expressed as a number, immediately following the last day included in the Interest Period, unless such number would be 31 and D1 is greater than 29, in which case D2 will be 30; (vi) if “30E/360” or “Eurobond Basis” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the number of days in the Interest Period divided by 360, calculated on a formula basis as follows: 360 − + 30 − + − = 360 where:

“Y1” is the year, expressed as a number, in which the first day of the Interest Period falls;

“Y2” is the year, expressed as a number, in which the day immediately following the last day of the Interest Period falls;

“M1” is the calendar month, expressed as a number, in which the first day of the Interest Period falls;

“M2” is the calendar month, expressed as a number, in which the day immediately following the last day of the Interest Period falls;

“D1” is the first calendar day, expressed as a number, of the Interest Period, unless such number would be 31, in which case D1 will be 30; and

“D2” is the calendar day, expressed as a number, immediately following the last day included in the Interest Period, unless such number would be 31, in which case D2 will be 30; (vii) if “30E/360 (ISDA)” is specified in the applicable Final Terms or relevant Drawdown Prospectus, the number of days in the Interest Period divided by 360, calculated on a formula basis as follows: 360 − + 30 − + − = 360 where:

“Y1” is the year, expressed as a number, in which the first day of the Interest Period falls;

“Y2” is the year, expressed as a number, in which the day immediately following the last day of the Interest Period falls;

“M1” is the calendar month, expressed as a number, in which the first day of the Interest Period falls;

“M2” is the calendar month, expressed as a number, in which the day immediately following the last day of the Interest Period falls;

“D1” is the first calendar day, expressed as a number, of the Interest Period, unless (i) that day is the last day of February or (ii) such number would be 31, in which case D1 will be 30; and

“D2” is the calendar day, expressed as a number, immediately following the last day included in the Interest Period, unless (i) that day is the last day of February but not the Maturity Date or (ii) such number would be 31, in which case D2 will be 30.

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(e) Notification of Rate of Interest and Interest Amounts The Principal Paying Agent will cause the Rate of Interest and each Interest Amount for each Interest Period and the relevant Interest Payment Date to be notified to the Issuer, the Trustee and any stock exchange on which the relevant Floating Rate Notes are for the time being listed and notice thereof to be published in accordance with Condition 14 (Notices) as soon as possible after their determination but in no event later than the fourth London Business Day thereafter. Each Interest Amount and Interest Payment Date so notified may subsequently be amended (or appropriate alternative arrangements made by way of adjustment) without prior notice in the event of an extension or shortening of the Interest Period. Any such amendment will be promptly notified to each stock exchange on which the relevant Floating Rate Notes are for the time being listed and to the Noteholders in accordance with Condition 14 (Notices). For the purposes of this subparagraph, the expression “London Business Day” means a day (other than a Saturday or a Sunday) on which banks and foreign exchange markets are open for general business in London. (f) Determination or Calculation by Trustee If for any reason at any relevant time the Principal Paying Agent or, as the case may be, the Calculation Agent defaults in its obligation to determine the Rate of Interest or the Principal Paying Agent defaults in its obligation to calculate any Interest Amount in accordance with subparagraph (b)(i) (ISDA Determination for Floating Rate Notes) or subparagraph (b)(ii) (Screen Rate Determination for Floating Rate Notes) above or as otherwise specified in the applicable Final Terms or relevant Drawdown Prospectus, as the case may be, and in each case in accordance with subparagraph (d) (Determination of Rate of Interest and calculation of Interest Amounts) above, the Trustee (or its agent) shall determine the Rate of Interest at such rate as, in its absolute discretion (having such regard as it shall think fit to the foregoing provisions of this Condition, but subject always to any Minimum Rate of Interest or Maximum Rate of Interest specified in the applicable Final Terms or relevant Drawdown Prospectus), it shall deem fair and reasonable in all the circumstances or, as the case may be, the Trustee (or its agent) shall calculate the Interest Amount(s) in such manner as it shall deem fair and reasonable in all the circumstances and each such determination or calculation shall be deemed to have been made by the Principal Paying Agent or the Calculation Agent, as applicable. (g) Certificates to be final All certificates, communications, opinions, determinations, calculations, quotations and decisions given, expressed, made or obtained for the purposes of the provisions of this Condition 5.3 (Interest on Floating Rate Notes), whether by the Principal Paying Agent or, if applicable, the Calculation Agent or the Trustee, shall (in the absence of wilful default, bad faith and manifest error) be binding on the Issuer, the Principal Paying Agent, the Calculation Agent (if applicable), the other Agents and all Noteholders and Couponholders and (in the absence of wilful default and bad faith) no liability to the Issuer, the Noteholders or the Couponholders shall attach to the Principal Paying Agent or, if applicable, the Calculation Agent or the Trustee in connection with the exercise or non-exercise by it of its powers, duties and discretions pursuant to such provisions. 5.4 Accrual of Interest Each Note (or in the case of the redemption of part only of a Note, that part only of such Note) will cease to bear interest (if any) from the date for its redemption unless, upon due presentation thereof, payment of principal is improperly withheld or refused. In such event, interest will continue to accrue until whichever is the earlier of: (a) the date on which all amounts due in respect of such Note have been paid; and (b) as provided in the Trust Deed.

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6. PAYMENTS 6.1 Method of Payment Subject as provided below: (a) payments in a Specified Currency other than euro will be made by credit or transfer to an account in the relevant Specified Currency maintained by the payee with, or, at the option of the payee, by a cheque in such Specified Currency drawn on, a bank in the principal financial centre of the country of such Specified Currency; and (b) payments in euro will be made by credit or transfer to a euro account (or any other account to which euro may be credited or transferred) specified by the payee or, at the option of the payee, by a euro cheque. Payments will be subject in all cases to: (a) any fiscal or other laws and regulations applicable thereto in the place of payment, but without prejudice to the provisions of Condition 8 (Taxation) and (b) any withholding or deduction required pursuant to an agreement described in Section 1471(b) of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), or otherwise imposed pursuant to Sections 1471 through 1474 of the Code and any regulations or agreements thereunder or official interpretations thereof (“FATCA”) or any law implementing an intergovernmental approach to FATCA. 6.2 Presentation of Definitive Bearer Notes and Coupons Payments of principal in respect of Definitive Bearer Notes will (subject as provided below) be made in the manner provided in Condition 6.1 (Method of Payment) above only against presentation and surrender (or, in the case of part payment of any sum due, endorsement) of Definitive Bearer Notes, and payments of interest in respect of Definitive Bearer Notes will (subject as provided below) be made as aforesaid only against presentation and surrender (or, in the case of part payment of any sum due, endorsement) of Coupons, in each case only at the specified office of any Paying Agent outside the United States (which expression, as used herein, means the United States of America (including the States and the District of Columbia, its territories, its possessions and other areas subject to its jurisdiction)). Fixed Rate Notes in definitive bearer form (other than Long Maturity Notes (as defined below)) should be presented for payment together with all unmatured Coupons appertaining thereto (which expression shall for this purpose include Coupons falling to be issued on exchange of matured Talons), failing which the amount of any missing unmatured Coupon (or, in the case of payment not being made in full, the same proportion of the amount of such missing unmatured Coupon as the sum so paid bears to the sum due) will be deducted from the sum due for payment. Each amount of principal so deducted will be paid in the manner mentioned above against surrender of the relative missing Coupon at any time before the expiry of 10 years after the Relevant Date (as defined in Condition 8 (Taxation)) in respect of such principal (whether or not such Coupon would otherwise have become void under Condition 9 (Prescription)) or, if later, five years from the date on which such Coupon would otherwise have become due, but in no event thereafter. Upon any Fixed Rate Note in definitive bearer form becoming due and repayable prior to its Maturity Date, all unmatured Talons (if any) appertaining thereto will become void and no further Coupons will be issued in respect thereof. Upon the date on which any Floating Rate Note or Long Maturity Note in definitive bearer form becomes due and repayable, unmatured Coupons and Talons (if any) relating thereto (whether or not attached) shall become void and no payment or, as the case may be, exchange for further Coupons shall be made in respect thereof. A “Long Maturity Note” is a Fixed Rate Note (other than a Fixed Rate Note which on issue had a Talon attached) whose nominal amount on issue is less than the aggregate interest payable thereon provided that such Note shall cease to be a Long Maturity Note on the Interest Payment Date on which the aggregate amount of interest remaining to be paid after that date is less than the nominal amount of such Note.

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If the due date for redemption of any Definitive Bearer Note is not an Interest Payment Date, interest (if any) accrued in respect of such Note from (and including) the preceding Interest Payment Date or, as the case may be, the Interest Commencement Date shall be payable only against surrender of the relevant Definitive Bearer Note. 6.3 Payments in Respect of Bearer Global Notes Payments of principal and interest (if any) in respect of Notes represented by any Bearer Global Note will (subject as provided below) be made in the manner specified above in relation to Definitive Bearer Notes and otherwise in the manner specified in the relevant Global Note against presentation or surrender, as the case may be, of such Global Note only at the specified office of any Paying Agent outside the United States or its possessions. A record of each payment made against presentation or surrender of any Bearer Global Note, distinguishing between any payment of principal and any payment of interest, will be made on such Global Note by the Paying Agent to which it was presented and such record shall be prima facie evidence that the payment in question has been made. 6.4 Payments in Respect of Registered Notes Payments of principal in respect of each Registered Note (whether or not in global form) will be made against presentation and surrender (or, in the case of part payment of any sum due, endorsement) of the Registered Note at the specified office of the Registrar or any of the Paying Agents. Such payments will be made by transfer to the Designated Account (as defined below) of the holder (or the first named of joint holders) of the Registered Note appearing in the Register at the close of business on the third business day (being for this purpose, a day on which banks are open for business in the city where the specified office of the Registrar is located) before the relevant due date. Notwithstanding the previous sentence, if (i) a holder does not have a Designated Account or (ii) the principal amount of the Notes held by a holder is less than U.S.$250,000 (or its approximate equivalent in any other Specified Currency), payment will instead be made by a cheque in the Specified Currency drawn on a Designated Bank (as defined below). Payments of interest in respect of each Registered Note (whether or not in global form) will be made by a cheque in the Specified Currency drawn on a Designated Bank and mailed by uninsured mail on the business day in the city where the specified office of the Registrar is located immediately preceding the relevant due date to the holder (or the first named of joint holders) of the Registered Note appearing in the Register (i) where in global form, at the close of the business day (being for this purpose, a Clearing System Business Day (as defined below)) before the relevant due date, and (ii) where in definitive form, at the close of business on the fifteenth day (whether or not such fifteenth day is a business day) before the relevant due date (the “Record Date”) at its address shown in the Register on the Record Date and at its risk. Upon application of the holder to the specified office of the Registrar not less than three business days in the city where the specified office of the Registrar is located before the due date for any payment of interest in respect of a Registered Note, the payment may be made by transfer on the due date in the manner provided in the preceding paragraph. Any such application for transfer shall be deemed to relate to all future payments of interest (other than interest due on redemption) in respect of the Registered Notes which become payable to the holder who has made the initial application until such time as the Registrar is notified in writing to the contrary by such holder. Payment of the interest due in respect of each Registered Note on redemption will be made in the same manner as payment of the principal amount of such Registered Note. For the purposes of this Condition, “Designated Account” means the account maintained by a holder with a Designated Bank and identified as such in the Register; “Designated Bank” means (in the case of payment in a Specified Currency other than euro) a bank in the principal financial centre of the country of such Specified Currency and (in the case of a payment in euro) any bank which processes payments in euro; and “Clearing System Business Day” means Monday to Friday inclusive, except 25 December and 1 January. Holders of Registered Notes will not be entitled to any interest or other payment for any delay in receiving any amount due in respect of any Registered Note as a result of a cheque posted in accordance with this Condition arriving after the due date for payment or being lost in the post. No

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commissions or expenses shall be charged to such holders by the Registrar in respect of any payments of principal or interest in respect of the Registered Notes. All amounts payable to DTC or its nominee as registered holder of a Registered Global Note in respect of Notes denominated in a Specified Currency other than U.S. dollars shall be paid by transfer by the Registrar to an account in the relevant Specified Currency of the Paying Agent on behalf of DTC or its nominee for conversion into and payment in U.S. dollars in accordance with the provisions of the Agency Agreement. None of the Issuer, the Trustee or the Agents will have any responsibility or liability for any aspect of the records relating to, or payments made on account of, beneficial ownership interests in the Registered Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. 6.5 General Provisions Applicable to Payments The holder of a Global Note shall be the only person entitled to receive payments in respect of Notes represented by such Global Note and the Issuer will be discharged by payment to, or to the order of, the holder of such Global Note in respect of each amount so paid. Each of the persons shown in the records of Euroclear, Clearstream, Luxembourg or DTC as the beneficial holder of a particular nominal amount of Notes represented by such Global Note must look solely to Euroclear, Clearstream, Luxembourg or DTC, as the case may be, for its share of each payment so made by the Issuer, or to the order of, the holder of such Global Note. Notwithstanding the foregoing provisions of this Condition, if any amount of principal and/or interest in respect of Bearer Notes is payable in U.S. dollars, such U.S. dollar payments of principal and/or interest in respect of such Notes will be made at the specified office of a Paying Agent in the United States if: (i) the Issuer has appointed Paying Agents with specified offices outside the United States with the reasonable expectation that such Paying Agents would be able to make payment in U.S. dollars at such specified offices outside the United States of the full amount of principal and interest on the Bearer Notes in the manner provided above when due; (ii) payment of the full amount of such principal and interest at all such specified offices outside the United States is illegal or effectively precluded by exchange controls or other similar restrictions on the full payment or receipt of principal and interest in U.S. dollars; and (iii) the Issuer delivers to the Trustee a legal opinion (in a form satisfactory to the Trustee) to the effect that such payment is then permitted under United States law and will not result in adverse tax consequences to the Issuer or holders of such Notes (such opinion the Trustee will be able to rely upon absolutely). 6.6 Payment Day If the date for payment of any amount in respect of any Note or Coupon is not a Payment Day, the holder thereof shall not be entitled to payment until the next following Payment Day in the relevant place and shall not be entitled to further interest or other payment in respect of such delay. For these purposes, “Payment Day” means any day which (subject to Condition 9 (Prescription)) is: (a) a day on which commercial banks and foreign exchange markets settle payments and are open for general business (including dealing in foreign exchange and foreign currency deposits) in: (i) in the case of Definitive Notes only, the relevant place of presentation; (ii) each Additional Financial Centre specified in the applicable Final Terms or relevant Drawdown Prospectus; and (b) either (i) in relation to any sum payable in a Specified Currency other than euro, a day on which commercial banks and foreign exchange markets settle payments and are open for general business (including dealing in foreign exchange and foreign currency deposits) in the

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principal financial centre of the country of the relevant Specified Currency or (ii) in relation to any sum payable in euro, a day on which the TARGET2 System is open. 6.7 Interpretation of Principal and Interest Any reference in the Conditions to principal in respect of the Notes shall be deemed to include, as applicable: (i) any additional amounts which may be payable with respect to principal under Condition 8 (Taxation) or under any undertaking or covenant given in addition thereto, or in substitution therefor, pursuant to the Trust Deed; (ii) the Final Redemption Amount of the Notes; (iii) the Early Redemption Amount of the Notes; (iv) the Optional Redemption Amount(s) (if any) of the Notes; (v) in relation to Zero Coupon Notes, the Amortised Face Amount (as defined in Condition 7.7 (Early Redemption Amount)); and (vi) any premium and any other amounts (other than interest) which may be payable by the Issuer under or in respect of the Notes. Any reference in the Conditions to interest in respect of the Notes shall be deemed to include, as applicable, any additional amounts which may be payable with respect to interest under Condition 8 (Taxation) or under any undertaking or covenant given in addition thereto, or in substitution therefor, pursuant to the Trust Deed. 7. REDEMPTION AND PURCHASE 7.1 Redemption at Maturity Unless previously redeemed or purchased and cancelled as specified below, each Note will be redeemed by the Issuer at its Final Redemption Amount specified in, or determined in the manner specified in, the applicable Final Terms or relevant Drawdown Prospectus in the relevant Specified Currency on the Maturity Date. 7.2 Redemption for Tax Reasons If the Issuer satisfies the Trustee immediately before the giving of the notice referred to below that: (a) as a result of any change in, or amendment to, the laws or regulations of the Relevant Jurisdiction (as defined in Condition 8.2 (Taxation—Interpretation)), or any change in the application or official interpretation or any official published supplementary clarification of the laws or regulations of the Relevant Jurisdiction, which change or amendment becomes effective on or after the date on which agreement is reached to issue the first Tranche of the Notes or in the case of a successor to the Issuer, such change or amendment becomes effective after such successor becomes subject to the terms of the Notes, on the next Interest Payment Date the Issuer would be required to pay additional amounts as provided or referred to in Condition 8 (Taxation); and (b) the requirement cannot be avoided by the Issuer taking reasonable measures available to it, the Issuer may at its option, having given not fewer than 30 nor more than 60 days’ notice to the Noteholders in accordance with Condition 14 (Notices) and to the Trustee (which notice shall be irrevocable), redeem all, but not some only, of the Notes at any time at their principal amount together with interest accrued to but excluding the date of redemption, provided that no notice of redemption shall be given earlier than 90 days before the earliest date on which the Issuer would be required to pay the additional amounts were a payment in respect of the Notes then due. Prior to the publication of any notice of redemption pursuant to this Condition, the Issuer shall deliver to the Trustee a certificate signed by two directors of the Issuer or two members of EXCO stating that the requirement

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referred to in paragraph (a) above will apply on the next Interest Payment Date and cannot be avoided by the Issuer taking reasonable measures available to it and the Trustee shall be entitled to accept the certificate as sufficient evidence of the satisfaction of the conditions precedent set out above, in which event it shall be conclusive and binding on the Noteholders. 7.3 Redemption at the Option of the Issuer (Issuer Call) If an Issuer Call is specified in the applicable Final Terms or the relevant Drawdown Prospectus, on giving not fewer than 30 nor more than 60 days’ notice (an “Optional Redemption Notice”) to the Noteholders in accordance with Condition 14 (Notices) and to the Trustee (which notice shall be irrevocable and shall specify the date fixed for redemption), the Issuer may redeem all, or, if redemption in part is specified as being applicable in the applicable Final Terms or the relevant Drawdown Prospectus, some only of the Notes then outstanding on the date (the “Optional Redemption Date”) specified in the applicable Final Terms or the relevant Drawdown Prospectus, as applicable, at (a) if Make-Whole Amount is specified in the applicable Final Terms or the relevant Drawdown Prospectus, as applicable, the Make-Whole Amount (as defined below), or (b) the Optional Redemption Amount specified in the applicable Final Terms or the relevant Drawdown Prospectus, as applicable, together in either case with accrued interest up to but excluding the Optional Redemption Date. If redemption in part is specified as being applicable in the applicable Final Terms or the relevant Drawdown Prospectus, as applicable, any such redemption must be of a nominal amount not less than the Minimum Redemption Amount and not more than the Maximum Redemption Amount in each case as may be specified in the applicable Final Terms or the relevant Drawdown Prospectus. In the case of a partial redemption of Notes, the Notes to be redeemed (“Redeemed Notes”) will be selected individually by lot, in the case of Redeemed Notes represented by Definitive Notes, and in accordance with the rules of Euroclear and/or Clearstream, Luxembourg and/or DTC, in the case of Redeemed Notes represented by a Global Note, not more than 30 days prior to the date fixed for redemption (such date of selection being hereinafter called the “Selection Date”). In the case of Redeemed Notes represented by Definitive Notes, a list of the serial numbers of such Redeemed Notes will be published in accordance with Condition 14 (Notices) not fewer than 15 days prior to the date fixed for redemption. No exchange of the relevant Global Note will be permitted during the period from (and including) the Selection Date to (and including) the date fixed for redemption pursuant to this Condition 7.3 (Redemption at the Option of the Issuer (Issuer Call)) and notice to that effect shall be given by the Issuer to the Noteholders in accordance with Condition 14 (Notices) at least five days prior to the Selection Date. 7.4 Redemption at the Option of the Noteholders (Investor Put) (a) If an Investor Put is specified in the applicable Final Terms or relevant Drawdown Prospectus, upon the holder of any Note giving to the Issuer, in accordance with Condition 14 (Notices), not fewer than 15 nor more than 30 days’ notice, the Issuer will, upon the expiry of such notice, redeem, subject to, and in accordance with, the terms specified in the applicable Final Terms or relevant Drawdown Prospectus, such Note on the Optional Redemption Date and at the Optional Redemption Amount together, if appropriate, with interest accrued to (but excluding) the Optional Redemption Date. Registered Notes may be redeemed under this Condition 7.4 (Redemption at the Option of the Noteholders (Investor Put)) in any Specified Denomination. It may be that before an Investor Put can be exercised, certain conditions and/or circumstances will need to be satisfied. Where relevant, the provisions will be set out in the applicable Final Terms or relevant Drawdown Prospectus. (b) To exercise the right to require redemption of a particular Note, a holder of a Note must, if the Note is in definitive form and held outside Euroclear, Clearstream, Luxembourg and DTC, deliver, at the specified office of any Principal Paying Agent (in the case of Bearer Notes) or the Registrar (in the case of Registered Notes), on any Business Day (as defined in Condition 5 (Interest)) falling within the notice period, a duly completed and signed notice of exercise in the form (for the time being current) obtainable from any specified office of any Paying Agent, or as the case may be, the Registrar (a “Put Notice”) and in which the holder must specify a bank account (or, if payment is required to be made by cheque, an address) to which payment is to be made under this Condition 7.4 (Redemption at the Option of the

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Noteholders (Investor Put)) and, in the case of a partial redemption of Registered Notes, the nominal amount thereof to be redeemed and an address to which a new Registered Note in respect of the balance of such Registered Notes is to be sent subject to and in accordance with the provisions of Condition 2.2 (Transfers of Definitive Registered Notes). If the relevant Note is in definitive bearer form, the Put Notice must be accompanied by such Notes or evidence satisfactory to the Principal Paying Agent concerned that the certificate for such Notes will, following delivery of the Put Notice, be held to its order or under its control. If this Note is represented by a Global Note or is in definitive form and held through Euroclear, Clearstream, Luxembourg or DTC, to exercise the right to require redemption of this Note, the holder of this Note must, within the notice period, give notice to the Paying Agent of such exercise in accordance with the standard procedures of Euroclear, Clearstream, Luxembourg or DTC, as applicable, (which may include notice being given on his instruction by Euroclear, Clearstream, Luxembourg, DTC or any common depositary, as the case may be, for any of them to the Paying Agent by electronic means) in a form acceptable to Euroclear, Clearstream, Luxembourg or DTC, as applicable, from time to time and, if the relevant Note is represented by a Global Note, at the same time present or procure the presentation of the relevant Global Note to the Paying Agent for notation accordingly. (c) Any Put Notice or other notice in accordance with the standard procedures of Euroclear, Clearstream, Luxembourg and DTC given by a holder of any Note pursuant to this Condition 7.4 (Redemption at the Option of the Noteholders (Investor Put)) shall be irrevocable except where, prior to the due date of redemption, an Event of Default has occurred and the Trustee has declared the Notes to be due and payable pursuant to Condition 10 (Events of Default and Enforcement), in which event such holder, at its option, may elect by notice to the Issuer to withdraw the notice given pursuant to this Condition 7.4 (Redemption at the Option of the Noteholders (Investor Put)) and instead to declare such Note forthwith due and payable pursuant to Condition 10 (Events of Default and Enforcement). 7.5 Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put) If a Change of Control/Restructuring Investor Put is specified in the applicable Final Terms or relevant Drawdown Prospectus: (a) if, at any time while any of the Notes remains outstanding: (i) the Government of the Republic of South Africa ceases to have Control (as defined below) of the Issuer; or (ii) a Restructuring Event occurs and within the Restructuring Period, either (subject as provided below including in the definition of Put Event): (A) if at the time such Restructuring Event occurs the Notes are rated by a Rating Agency, a Rating Downgrade in respect of such Restructuring Event also occurs; or (B) if at the time such Restructuring Event occurs the Notes do not have a rating from a Rating Agency, a Negative Rating Event in respect of such Restructuring Event also occurs, then, unless at any time the Issuer shall have given a notice under Condition 7.2 (Redemption for Tax Reasons) or Condition 7.3 (Redemption at the Option of the Issuer (Issuer Call)) in respect of the Notes, the holder of each Note shall, upon the giving of a Put Event Notice (as defined below), have the option (the “Put Option”) to require the Issuer to redeem or, at the option of the Issuer, purchase (or procure the purchase of) that Note on the Put Date (as defined below), at its principal amount together with (or, where purchased, together with an amount equal to) interest (if any) accrued to (but excluding) the Put Date. (b) Promptly upon, and in any event within 30 days after, the Issuer becoming aware that a Put Event has occurred, the Issuer shall, and at any time upon the Trustee becoming similarly so aware the Trustee may, and if so requested by the holders of at least one quarter in principal

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amount of the Notes then outstanding shall (subject to being indemnified and secured to its satisfaction), give notice (a “Put Event Notice”) to the Noteholders in accordance with Condition 14 (Notices) specifying the nature of the Put Event and the procedure for exercising the Put Option. (c) To exercise the Put Option, a holder of a Note must, if the Note is in definitive form and held outside Euroclear, Clearstream Luxembourg and DTC, deliver at the specified office of any Principal Paying Agent (in the case of a Bearer Note) or the Registrar (in the case of a Registered Note) on any Business Day (as defined in Condition 5 (Interest)) falling within the period commencing on the occurrence of a Put Event and ending 30 days after such occurrence or, if later, 30 days after the date on which the Put Event Notice is given to Noteholders as required by this Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)) (the “Put Period”), a Put Notice in which the holder must specify a bank account (or, if payment is required to be made by cheque, an address) to which payment is to be made under this Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)) and, in the case of a partial redemption of a Registered Note, the nominal amount thereof to be redeemed and an address to which a new Registered Note in respect of the balance of such Registered Note is to be sent subject to and in accordance with the provisions of Condition 2.2 (Transfers of Definitive Registered Notes). If the Note is in definitive bearer form, the Put Notice must be accompanied by the certificate for such Notes or evidence satisfactory to the Principal Paying Agent concerned that the certificate for such Notes will, following the delivery of the Put Notice, be held to its order or under its control. If the Note is represented by a Global Note or is in definitive form and held through DTC, Euroclear or Clearstream, Luxembourg, in order to exercise the right to require redemption of the Note the holder of the Note must, within the notice period, give notice to the Paying Agent of such exercise in accordance with the standard procedures of DTC, Euroclear or Clearstream, Luxembourg, as applicable, (which may include notice being given on his instruction by DTC, Euroclear or Clearstream, Luxembourg or any common depositary for any of them to the Paying Agent by electronic means) in a form acceptable to DTC, Euroclear or Clearstream, Luxembourg, as applicable, from time to time and, if the Note is represented by a Global Note, at the same time present or procure the presentation of the relevant Global Note to the Paying Agent for notation accordingly. (d) A Rating Downgrade or a Negative Rating Event or a non-Investment Grade rating shall be deemed not to have occurred as a result or in respect of a Restructuring Event if the Rating Agency making the relevant reduction in rating or, where applicable, declining to assign a rating of at least Investment Grade as provided in this Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)) does not announce or publicly confirm or inform the Trustee in writing at its request that the reduction or, where applicable, declining to assign a rating of at least Investment Grade was the result, in whole or in part, of any event or circumstance comprised in or arising as a result of the applicable Restructuring Event. (e) The Trust Deed provides that the Trustee is under no obligation to ascertain whether the event described in this Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)), a Restructuring Event, a Negative Rating Event or any event which could lead to the occurrence of or could constitute the event described in this Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)) or a Restructuring Event has occurred and until it shall have actual knowledge or express notice pursuant to the Trust Deed to the contrary the Trustee may assume that no such Restructuring Event, Negative Rating Event or such other event has occurred. The Trust Deed also provides that in determining whether or not the event described in this Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)) or a Restructuring Event has occurred, the Trustee may rely solely on an opinion given in a certificate signed by two directors of the Issuer or two members of EXCO.

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7.6 Interpretation For the purposes of these Conditions: “Comparable Treasury Issue” means the benchmark sovereign or sovereign-equivalent security relevant to the Specified Currency selected by the Independent Investment Bank that would be utilised, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Notes from the Optional Redemption Date to the Maturity Date of the Notes; “Comparable Treasury Price” means, (i) the average of the Reference Treasury Dealer Quotations, after excluding the highest and lowest such Reference Treasury Dealer Quotations, or (ii) if the Issuer obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations; “Control” means, in relation to any entity, that a Person holds more than 50 per cent. of the share capital and the voting capital of such entity; “Distribution Licence” means the distribution licence held or deemed to be held by the Issuer under the Electricity Legislation, including any such licence issued in substitution thereof; “Electricity Legislation” means the Electricity Regulation Act, No. 4 of 2006, as amended, modified, supplemented or substituted from time to time, including any regulations prescribed and promulgated pursuant thereto; “Generation Licence” means the electricity generation licence held or deemed to be held by the Issuer under the Electricity Legislation, including any such licence issued in substitution thereof; “Independent Investment Bank” means one of the Reference Treasury Dealers appointed by the Issuer to act as an independent investment bank for the purposes of determining the Make-Whole Amount; “Investment Grade” in relation to a rating means that the relevant Rating Agency has designated the rating as BBB-, Baa3 or their respective equivalents or better; “Make-Whole Amount” means the greater of (i) 100 per cent. of the principal amount of the Notes and (ii) as determined by the Independent Investment Bank, the sum of the present values of the applicable Remaining Scheduled Payments discounted to the Optional Redemption Date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months or in the case of an incomplete month, the number of days elapsed) at the Treasury Rate plus the Margin specified in the relevant Final Terms or relevant Drawdown Prospectus; “Maturity Date” means the date specified as such in the applicable Final Terms or relevant Drawdown Prospectus; a “Negative Rating Event” shall be deemed to have occurred if following a Restructuring Event (a) the Issuer does not, during the Restructuring Period, seek, and thereupon use all reasonable endeavours to obtain, a rating of the Notes from a Rating Agency or (b) it does so seek and use such endeavours but, it has not, as a result of such Restructuring Event, obtained in respect of the Notes a rating of at least Investment Grade from at least one Rating Agency by no later than the end of the Restructuring Period; “Optional Redemption Date” has the meaning provided in Condition 7.3 (Redemption at the Option of the Issuer (Issuer Call)); “Optional Redemption Notice” has the meaning provided in Condition 7.3 (Redemption at the Option of the Issuer (Issuer Call)); “Person” means any individual, company, corporation, firm, partnership, joint venture, association, unincorporated organisation, trust or other judicial entity, including, without limitation, any state or agency of a state or other entity, whether or not having separate legal personality;

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“Put Date” means the fifteenth day after the expiry of the Put Period; a “Put Event” occurs: (a) if the Government of the Republic of South Africa ceases to have Control (as defined above) of the Issuer; or (b) in the case of the occurrence of a Restructuring Event, where there shall be in respect of such Restructuring Event a Rating Downgrade that occurs during the relevant Restructuring Period and continues to exist at the end of the period of 60 days starting from and including the day on which the Rating Downgrade is announced by the relevant Rating Agency (subject to Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)); or (c) in the case of the occurrence of a Restructuring Event, where there shall be in respect of such Restructuring Event a Negative Rating Event that occurs during the Restructuring Period and continues to exist on the last day of the Restructuring Period (subject to Condition 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)); “Rating Agency” means Standard & Poor’s Credit Market Services Europe Limited, a division of The McGraw-Hill Companies, Inc., Moody’s Investors Service Ltd. and Fitch, Inc. or any of their respective Subsidiaries or successors or any rating agency substituted for any of them (or any permitted substitute of them) by the Issuer from time to time with the prior written approval of the Trustee (such approval not to be unreasonably withheld or delayed) and “Rating Agencies” shall be construed accordingly; a “Rating Downgrade” shall be deemed to have occurred in respect of a Restructuring Event if the then current rating assigned to the Notes by any Rating Agency (whether provided by a Rating Agency at the invitation of the Issuer or by its own volition) is withdrawn or reduced from an Investment Grade rating to a non-Investment Grade rating or, if the Rating Agency shall then have already rated the Notes below Investment Grade (as described above), the rating is lowered one full rating category; “Reference Treasury Dealer” means each of not fewer than four nationally recognised investment banking firms that are Primary Treasury Dealers selected from time to time by the Issuer; provided, however, that if any such firm shall cease to be a primary securities dealer in the sovereign or sovereign-equivalent security relevant to the Specified Currency (a “Primary Treasury Dealer”), the Issuer shall substitute therefor another nationally recognised investment banking firm that is a Primary Treasury Dealer; “Reference Treasury Dealer Quotation” means, with respect to each Reference Treasury Dealer and the Optional Redemption Date, the average, as determined by the Independent Investment Bank, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Bank by such Reference Treasury Dealer on the third Business Day preceding the Optional Redemption Date; “Relevant Licences” means the Generation Licence, the Transmission Licence and the Distribution Licence and in any such case, and from time to time any other licence(s), exemption(s), permission(s) or other authorisation(s) relating to the generation, transmission, supply or distribution of electricity granted under the Electricity Legislation to the Issuer or any wholly-owned Subsidiary as contemplated in the exception to paragraph (a) of the definition of Restructuring Event and “Relevant Licence” shall be construed accordingly; “Remaining Scheduled Payments” means, with respect to each Note to be redeemed, the remaining scheduled payments of the principal thereof and interest thereon that would be due after the Optional Redemption Date but for such redemption; provided, however, that, if the Optional Redemption Date is not an Interest Payment Date with respect to such Notes, the amount of the next succeeding scheduled interest payment thereon will be reduced by the amount of interest accrued thereon to the Optional Redemption Date;

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“Responsible Authority” means the Government of the Republic of South Africa or any subdivision thereof and the National Energy Regulator of South Africa or other regulatory department, body, instrumentality, agency or authority of South Africa or of any subdivision thereof having jurisdiction over the Issuer’s electricity generation, transmission, distribution or supply operations or a material amount of the Issuer’s assets or revenues, but excluding the Issuer acting in such capacity; “Restructuring Event” means the occurrence of any one or more of the following events: (a) (i) the Responsible Authority gives the Issuer or any Subsidiary of the Issuer written notice of revocation, termination or withdrawal of any Relevant Licence; or (ii) the Issuer or any Subsidiary of the Issuer agrees in writing with the Responsible Authority to any revocation, termination, withdrawal or surrender of any Relevant Licence; or (iii) any original or delegated legislation is enacted revoking, terminating or withdrawing any Relevant Licence, except in any such case in circumstances where a licence(s), an exemption(s), a permission(s) or an other authorisation(s) (as the case may be) on not materially less favourable terms is or are granted under the Electricity Legislation to the Issuer or one or more Subsidiaries (not being an Excluded Subsidiary) of the Issuer; or (b) any modification (other than a modification which is of a formal, minor or technical nature) is made to the terms and conditions of any Relevant Licence on or after 22 July 2013 unless two directors of the Issuer or two members of EXCO have certified in good faith in writing to the Trustee that the modified terms and conditions are not materially less favourable to the business of the Group and to the business of the member of the Group holding the Relevant Licence; “Restructuring Period” means, if at any time a Restructuring Event occurs, the period of 90 days starting from and including the day on which that Restructuring Event occurs; “Specified Office” has the meaning set out in the Agency Agreement; “Transmission Licence” means the transmission licence held or deemed to be held by the Issuer under the Electricity Legislation, including any such licence issued in substitution thereof; and “Treasury Rate” means, with respect to the Optional Redemption Date, the rate per annum equal to the semi-annual equivalent yield to maturity (computed as at the third Business Day immediately preceding the Optional Redemption Date) of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the Optional Redemption Date. 7.7 Early Redemption Amounts For the purpose of Condition 7.2 (Redemption for Tax Reasons) above and Condition 10 (Events of Default and Enforcement), each Note will be redeemed at its Early Redemption Amount calculated as follows: (a) in the case of a Note with a Final Redemption Amount equal to the Issue Price, at the Final Redemption Amount thereof; (b) in the case of a Note (other than a Zero Coupon Note) with a Final Redemption Amount which is or may be less or greater than the Issue Price or which is payable in a Specified Currency other than that in which the Note is denominated, at the amount specified in, or determined in the manner specified in, the applicable Final Terms or relevant Drawdown Prospectus or, if no such amount or manner is so specified in the applicable Final Terms or relevant Drawdown Prospectus, at its nominal amount; or

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(c) in the case of a Zero Coupon Note, at an amount (the “Amortised Face Amount”) calculated in accordance with the following formula: Early Redemption Amount = RP x (1 + AY)y where: “RP” means the Reference Price; and “AY” means the Accrual Yield expressed as a decimal; and “y” is the Day Count Fraction specified in the applicable Final Terms or relevant Drawdown Prospectus which will be either (i) 30/360 (in which case the numerator will be equal to the number of days (calculated on the basis of a 360-day year consisting of 12 months of 30 days each) from (and including) the Issue Date of the first Tranche of the Notes to (but excluding) the date fixed for redemption or (as the case may be) the date upon which such Note becomes due and repayable and the denominator will be 360) or (ii) Actual/360 (in which case the numerator will be equal to the actual number of days from (and including) the Issue Date of the first Tranche of the Notes to (but excluding) the date fixed for redemption or (as the case may be) the date upon which such Note becomes due and repayable and the denominator will be 360) or (iii) Actual/365 (in which case the numerator will be equal to the actual number of days from (and including) the Issue Date of the first Tranche of the Notes to (but excluding) the date fixed for redemption or (as the case may be) the date upon which such Note becomes due and repayable and the denominator will be 365). 7.8 Purchases The Issuer or any of its Subsidiaries may at any time purchase Notes (provided that, in the case of Definitive Bearer Notes, all unmatured Coupons and Talons appertaining thereto are purchased therewith) at any price in the open market or otherwise. Such Notes may be held, reissued, resold or, at the option of the Issuer, surrendered to any Paying Agent and/or the Registrar for cancellation. 7.9 Cancellation All Notes which are redeemed will forthwith be cancelled (together with all unmatured Coupons and Talons attached thereto or surrendered therewith at the time of redemption). All Notes so cancelled and any Notes purchased and cancelled pursuant to Condition 7.8 (Purchases) above (together with all unmatured Coupons and Talons cancelled therewith) shall be forwarded to the Principal Paying Agent and cannot be reissued or resold. For as long as the Notes are admitted to trading on the Luxembourg Stock Exchange and the rules of the Luxembourg Stock Exchange so require, the Issuer shall promptly inform the Luxembourg Stock Exchange of the cancellation of any Notes under this Condition. 7.10 Late payment on Zero Coupon Notes If the amount payable in respect of any Zero Coupon Note upon redemption of such Zero Coupon Note pursuant to Conditions 7.1 (Redemption at Maturity), 7.2 (Redemption for Tax Reasons), 7.3 (Redemption at the Option of the Issuer (Issuer Call)) or 7.4 (Redemption at the Option of the Noteholders (Investor Put)) or 7.5 (Redemption at the Option of the Noteholders (Change of Control/Restructuring Investor Put)) above or upon its becoming due and repayable as provided in Condition 10 (Events of Default and Enforcement) is improperly withheld or refused, the amount due and repayable in respect of such Zero Coupon Note shall be the amount calculated as provided in Condition 7.7(c) (Early Redemption Amounts) above as though the references therein to the date fixed for the redemption or the date upon which such Zero Coupon Note becomes due and payable were replaced by references to the date which is the earlier of: (i) the date on which all amounts due in respect of such Zero Coupon Note have been paid; and (ii) five days after the date on which the full amount of the moneys payable in respect of such Zero Coupon Notes has been received by the Principal Paying Agent or the Registrar or the Trustee and notice to that effect has been given to the Noteholders in accordance with Condition 14 (Notices).

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8. TAXATION 8.1 All payments in respect of the Notes or Coupons by or on behalf of the Issuer shall be made free and clear of, and without withholding or deduction for, or on account of, any present or future taxes, duties, assessments or governmental charges of whatever nature (“Taxes”) imposed, levied, collected, withheld or assessed by or within the Relevant Jurisdiction, unless the withholding or deduction of the Taxes is required by law. In that event, the Issuer will pay such additional amounts as may be necessary in order that the net amounts received by the holders of the Notes, Coupons after the withholding or deduction shall equal the respective amounts which would have been receivable in respect of the Notes or Coupons, as the case may be, in the absence of the withholding or deduction; except that no additional amounts shall be payable in relation to any payment in respect to any Note or Coupon for or on account of: (a) any tax, fee, duty, assessment or governmental charge of whatever nature which would not have been imposed but for the fact that the holder or beneficial owner was a resident, domiciliary or national of, or engaged in business or maintained a permanent establishment or was physically present in, the Relevant Jurisdiction or otherwise had some connection with the Relevant Jurisdiction other than by reason of the mere ownership of, or receipt of payment under, or enforcement of rights with respect to, such Note; or (b) any estate, inheritance, gift, sale, transfer, personal property or similar tax, assessment or governmental charge; or (c) any tax, assessment or other governmental charge that is imposed or withheld by reason of the failure by the holder or beneficial owner of such note to comply with any reasonable request by the Issuer addressed to the holder within 90 days of such request (i) to provide information concerning the nationality, residence or identity of the holder or (ii) to make any declaration or other similar claim or satisfy any information or reporting requirement, which in any such case is required or imposed by statute, treaty, regulation or administrative practice of the Relevant Jurisdiction to establish the entitlement of a holder to receive the relevant payment free and clear of and without a deduction for, or on account of, any Taxes, provided that this paragraph (c) shall not apply if the relevant holder is not able to establish such entitlement after reasonable efforts but so that nothing shall require a holder to organise its tax affairs in any particular manner; or (d) any withholding or deduction imposed on a payment to an individual that is required to be made pursuant to European Council Directive 2003/48/EC or any law implementing or complying with, or introduced in order to conform to, such Directive; or (e) any combination of items (a), (b), (c) and (d) above. Notwithstanding any other provision of these Conditions, in no event will the Issuer be required to pay any additional amounts in respect of the Notes for, or on account of, any withholding or deduction required pursuant to FATCA (including pursuant to any agreement described in Section 1471(b) of the Code) or any law implementing an intergovernmental approach to FATCA. 8.2 Interpretation For the purposes of these Conditions: (i) “Relevant Date” means the date on which the payment first becomes due, but if the full amount of the money payable has not been received by the Trustee or the Principal Paying Agent or the Registrar, as the case may be, on or before the due date, it means the date on which, the full amount of the money having been so received, notice to that effect has been duly given to the Noteholders by the Issuer in accordance with Condition 14 (Notices); and (ii) “Relevant Jurisdiction” means the Republic of South Africa or any political subdivision or any authority thereof or therein having power to tax to which the Issuer becomes subject in respect of payments made by it of principal and interest on the Notes or Coupons.

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9. PRESCRIPTION The Notes (whether in bearer or registered form) and Coupons will become void unless presented for payment within a period of 10 years (in the case of principal) and five years (in the case of interest) after the Relevant Date (as defined in Condition 8 (Taxation)) therefor. There shall not be included in any Coupon sheet issued on exchange of a Talon any Coupon the claim for payment in respect of which would be void pursuant to this Condition 9 (Prescription) or Condition 6.2 (Presentation of Definitive Bearer Notes and Coupons) or any Talon which would be void pursuant to Condition 6.2 (Presentation of Definitive Bearer Notes and Coupons). 10. EVENTS OF DEFAULT AND ENFORCEMENT 10.1 Events of Default The Trustee at its discretion may, and if so requested in writing by the holders of at least one-fifth in principal amount of the Notes of the relevant Series then outstanding or if so directed by an Extraordinary Resolution of the Noteholders of the relevant Series shall (subject in each case to being indemnified and/or secured and/or pre-funded to its satisfaction), give notice to the Issuer that the Notes are, and they shall accordingly thereby forthwith become, immediately due and repayable at their principal amount, together with accrued interest as provided in the Trust Deed, if any of the following events occurs and is continuing (“Events of Default”): (a) default is made in the payment of principal or interest in respect of the Notes or any of them or in the payment pursuant to Condition 6.1 (Method of Payment) of any purchase price in respect of the Notes or any of them and, in the case of a payment of interest, such default continues for a period of 14 days; or (b) the Issuer fails to perform or observe any of its other obligations under these Conditions or the Trust Deed and (except in any case where the Trustee considers the failure to be incapable of remedy when no continuation or notice as is hereinafter mentioned will be required) the failure continues for the period of 45 days (or such longer period as the Trustee may permit) next following the service by the Trustee on the Issuer of notice requiring the same to be remedied; or (c) any Borrowed Moneys Indebtedness (as defined below) of the Issuer or any of its Material Subsidiaries (as defined below) (i) becomes due and payable prior to the due date for payment thereof by reason of acceleration following default (howsoever described) by the Issuer or by any of its Material Subsidiaries or (ii) is not repaid at, and remains unpaid after, maturity thereof (as extended by an originally applicable period of grace) provided that the aggregate amount of Borrowed Moneys Indebtedness, or its equivalent for the time being in any other currency or currencies, in respect of which any one or more of the events mentioned above in this paragraph (c) has occurred equals or exceeds U.S.$100,000,000 or its equivalent for the time being in any currency or currencies and for the purposes of this paragraph (c) Borrowed Moneys Indebtedness shall exclude Project Finance Indebtedness; or (d) an encumbrancer takes possession of, or a liquidator, judicial manager, trustee, administrative receiver, receiver, business rescue practitioner or similar officer is appointed in respect of, all or a substantial part of the business or assets of the Issuer or any Material Subsidiary, or the Issuer or any Material Subsidiary is placed under judicial management or business rescue proceedings or a distress or any form of execution is levied or enforced upon or sued out against such assets or any encumbrance which may for the time being affect any such assets is enforced and in any of the foregoing cases is not discharged within 90 days of being levied, enforced or sued out or such longer period as the Trustee in its absolute discretion permits; or (e) the Issuer or any Material Subsidiary becomes unable to pay its debts as they fall due or suspends making payments or declares a moratorium with respect to all or any class of its debts (other than as a result of a restructuring in the electricity supply industry (including generation, transmission and distribution) in the Republic of South Africa); or

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(f) (i) the Issuer or (save for the purposes of a solvent winding up, dissolution or reorganisation within the Group (as defined in Condition 4.2 (Negative Pledge— Interpretation)), on terms approved by the Trustee or by an Extraordinary Resolution of the Noteholders or as a result of a restructuring in the electricity supply industry (including generation, transmission and distribution)) any Material Subsidiary convenes a meeting of its creditors or proposes or makes any scheme or arrangement or composition with, or any assignment for the benefit of, its creditors; or (ii) a petition is presented or (other than as described in paragraph (iii) below) other steps are taken for the winding up of the Issuer or (save for the purposes of a solvent winding up, dissolution or reorganisation within the Group on terms approved by the Trustee or by an Extraordinary Resolution of the Noteholders or as a result of a restructuring in the electricity supply industry (including generation, transmission and distribution)) any Material Subsidiary, save where the Issuer demonstrates to the satisfaction of the Trustee that such petition or other steps are frivolous or vexatious or otherwise unlikely to result in the winding up of the Issuer or such Material Subsidiary; or (iii) any order shall be made by any competent court or any resolution shall be passed for the winding up or dissolution or administration or business rescue proceedings of the Issuer, save for the purposes of amalgamation, merger, consolidation, reorganisation, reconstruction or other similar arrangement on terms previously approved by the Trustee in writing or by an Extraordinary Resolution of the Noteholders; or (iv) any order shall be made by any competent court or any resolution shall be passed for the winding up or dissolution or administration or business rescue proceedings of a Material Subsidiary, save for the purposes of amalgamation, merger, consolidation, reorganisation, reconstruction or other similar arrangement (A) not involving or arising out of the insolvency of such Material Subsidiary and under which all the surplus assets of such Material Subsidiary are transferred to the Issuer or any of its other Subsidiaries or (B) the terms of which have been previously approved by the Trustee in writing or by an Extraordinary Resolution of the Noteholders; or (g) anything analogous to any of the events specified in paragraph (d), (e) or (f) above occurs under the laws of any applicable jurisdiction; or (h) the Issuer or any Material Subsidiary shall cease to carry on the whole or substantially the whole of its business, save in each case for the purposes of amalgamation, merger, consolidation, reorganisation, reconstruction or other similar arrangement (i) not involving or arising out of the insolvency of the Issuer or such Material Subsidiary and under which all or substantially all of its assets are transferred to another member or members of the Group (other than an Excluded Subsidiary) or to a transferee or transferees which is or are, or immediately upon such transfer become(s), a Material Subsidiary or Material Subsidiaries and (ii) the terms of which have previously been approved in writing by the Trustee or by an Extraordinary Resolution of the Noteholders, provided that if neither the Issuer nor any Subsidiary holds a Relevant Licence (as defined in Condition 7.5 (Redemption and Purchase—Interpretation)), the Issuer shall be deemed to have ceased to carry on the whole or substantially the whole of its business (and exception (i) above shall not apply); or (i) it becomes unlawful for the Issuer to comply with, or it repudiates, its obligations under the Notes, provided that, in the case of an Event of Default as described in paragraphs (b) and (h) above the Trustee shall have certified in writing to the Issuer that the Event of Default is, in its opinion, materially prejudicial to the interests of the Noteholders.

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10.2 Interpretation For the purposes of these Conditions: (a) “Borrowed Moneys Indebtedness” means: (i) any indebtedness for moneys borrowed; or (ii) any indebtedness (actual or contingent) under any guarantee, security, indemnity, deferred consideration, preference shares or other commitment designed to assure any creditor against any loss in respect of any moneys borrowed from any third party; or (iii) any indebtedness under any acceptance credit; or (iv) any indebtedness under any debenture, note, bond, bill of exchange or commercial paper; or (v) any indebtedness for money owing in respect of any interest rate swap or cross-currency swap or forward sale or purchase contract; (b) “Material Subsidiary” means a Subsidiary: (i) the value of whose total assets or turnover on a consolidated basis equals or exceeds 15 per cent., of the aggregate total assets or turnover of the Issuer on a consolidated basis; or (ii) whose net operating income on a consolidated basis equals or exceeds 15 per cent. of the aggregate net operating income of the Issuer on a consolidated basis; provided that, if any of the events set out in paragraphs (c) to (h) of Condition 10.1 (Events of Default and Enforcement) has occurred in respect of more than one Subsidiary, each of which itself is not a Material Subsidiary but which, if their gross revenues or assets were aggregated, would together have satisfied either of the tests set out in paragraphs (i) and (ii) above, all of such Subsidiaries shall be Material Subsidiaries; and (c) “Subsidiary” means a company in which the Issuer or any of its Subsidiaries: (i) holds a majority of the voting rights; or (ii) has the right to appoint or remove directors holding a majority of the voting rights at meetings of its board; or (iii) has the control of a majority of the voting rights or the management whether in accordance with an agreement or otherwise. A certificate from two directors of the Issuer or two members of EXCO that in their opinion a Subsidiary of the Issuer is or is not or was or was not at any particular time or throughout any specified period a Material Subsidiary may be relied upon by the Trustee without further enquiry or evidence and, if relied upon by the Trustee, shall, in the absence of manifest error, be conclusive and binding on all parties. 10.3 Enforcement The Trustee may at any time, at its discretion and without notice, take such proceedings against the Issuer as it may think fit to enforce the provisions of the Trust Deed, the Notes and the Coupons, but it shall not be bound to take any such proceedings or any other action in relation to the Trust Deed, the Notes or the Coupons unless (i) it shall have been so directed by an Extraordinary Resolution or so requested in writing by the holders of at least one fifth in nominal amount of the Notes then outstanding and (ii) it shall have been indemnified and/or secured and/or prefunded to its satisfaction. No Noteholder or Couponholder shall be entitled to proceed directly against the Issuer to enforce the provisions of the Trust Deed unless the Trustee, having become bound so to proceed, fails so to do

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within a reasonable period and the failure shall be continuing, in which case the Noteholder or Couponholder shall have only such rights against the Issuer as those which the Trustee is entitled to exercise. 11. REPLACEMENT OF NOTES, COUPONS AND TALONS Should any Note, Coupon or Talon be lost, stolen, mutilated, defaced or destroyed, it may be replaced at the specified office of the Principal Paying Agent (in the case of Bearer Notes or Coupons) or the Registrar (in the case of Registered Notes) upon payment by the claimant of such costs and expenses as may be incurred in connection therewith and on such terms as to: (a) evidence of such loss, theft, mutilation, defacement or destruction, and (b) indemnity as the Issuer, Registrar and/or Principal Paying Agent may reasonably require. Mutilated or defaced Notes, Coupons or Talons must be surrendered before replacements will be issued. 12. AGENTS The names of the initial Agents and their initial specified offices are set out below. The Issuer is entitled, with the prior written approval of the Trustee, to vary or terminate the appointment of any Agent and/or appoint additional or other Agents and/or approve any change in the specified office through which any Agent acts, provided that: (a) there will at all times be a Principal Paying Agent and a Registrar; (b) so long as the Notes are listed on any stock exchange or admitted to trading by any other relevant authority, there will at all times be a Paying Agent (in the case of Bearer Notes) and a Transfer Agent (in the case of Registered Notes) with a specified office in such place as may be required by the rules and regulations of the relevant stock exchange or other relevant authority; and (c) there will at all times be a Paying Agent in a Member State of the European Union that will not be obliged to withhold or deduct tax pursuant to European Council Directive 2003/48/EC or any law implementing or complying with, or introduced in order to conform to, such Directive. In addition, the Issuer shall forthwith appoint a Paying Agent having a specified office in New York City in the circumstances described in Condition 6.5 (General Provisions Applicable to Payments). Any variation, termination, appointment or change shall only take effect (other than in the case of insolvency, when it shall be of immediate effect) after not fewer than 30 nor more than 45 days’ prior notice thereof shall have been given to the Noteholders in accordance with Condition 14 (Notices). In acting under the Agency Agreement, the Agents act solely as agents of the Issuer and, in certain circumstances specified therein, of the Trustee and do not assume any obligation to, or relationship of agency or trust with, any Noteholders or Couponholders. The Agency Agreement contains provisions permitting any entity into which any Agent is merged or converted or with which it is consolidated or to which it transfers all or substantially all of its assets to become the successor agent. 13. EXCHANGE OF TALONS On and after the Interest Payment Date on which the final Coupon comprised in any Coupon sheet matures, the Talon (if any) forming part of such Coupon sheet may be surrendered at the specified office of any Paying Agent in exchange for a further Coupon sheet including (if such further Coupon sheet does not include Coupons to (and including) the final date for the payment of interest due in respect of the Note to which it appertains) a further Talon, subject to the provisions of Condition 9 (Prescription). 14. NOTICES All notices regarding the Bearer Notes will be deemed to be validly given if published, so long as the Bearer Notes are listed on the official list of the Luxembourg Stock Exchange and admitted to trading on its regulated market, on the website of the Luxembourg Stock Exchange (www.bourse.lu) or in a

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leading newspaper having general circulation in Luxembourg (which is expected to be the Luxemburger Wort). The Issuer shall also ensure that notices are duly published in a manner which complies with the rules and regulations of any stock exchange or other relevant authority on which the Bearer Notes are for the time being listed or by which they have been admitted to trading. Any such notice will be deemed to have been given on the date of the first publication or, where required to be published in more than one newspaper, on the date of the first publication in all required newspapers. If publication as provided above is not practicable, a notice will be given in such other manner, and will be deemed to have been given on such date, as the Trustee may approve. All notices regarding the Registered Notes will be deemed to be validly given if sent by first class mail or (if posted to an address overseas) by airmail to the holders (or the first named of joint holders) at their respective addresses recorded in the Register and will be deemed to have been given on the second day after mailing and, in addition, for so long as any Registered Notes are listed on a stock exchange or are admitted to trading by another relevant authority and the rules of that stock exchange or relevant authority so require, such notice will be published in a daily newspaper of general circulation in the place or places required by those rules. Until such time as any Definitive Notes are issued, there may, so long as any Global Notes representing the Notes are held in their entirety on behalf of Euroclear and/or Clearstream, Luxembourg and/or DTC, be substituted for such publication in such newspaper(s) the delivery of the relevant notice to Euroclear and/or Clearstream, Luxembourg and/or DTC for communication by them to the holders of the Notes and, in addition, for so long as any Notes are listed on a stock exchange or are admitted to trading by another relevant authority and the rules of that stock exchange or relevant authority so require, such notice will be published in a daily newspaper of general circulation in the place or places required by those rules. Any such notice shall be deemed to have been given to the holders of the Notes on the second day after the day on which the said notice was given to Euroclear and/or Clearstream, Luxembourg and/or DTC. Notices to be given by any Noteholder shall be in writing and given by lodging the same, together (in the case of any Note in definitive form) with the relative Note or Notes, with the Principal Paying Agent (in the case of Bearer Notes) or the Registrar (in the case of Registered Notes). Whilst any of the Notes is represented by a Global Note, such notice may be given by any holder of a Note to the Principal Paying Agent or the Registrar through Euroclear and/or Clearstream, Luxembourg and/or DTC, as the case may be, in such manner as the Principal Paying Agent, the Registrar and Euroclear and/or Clearstream, Luxembourg and/or DTC, as the case may be, may approve for this purpose. 15. MEETINGS OF NOTEHOLDERS, MODIFICATION, WAIVER AND SUBSTITUTION 15.1 Meetings The Trust Deed contains provisions for convening meetings of the Noteholders to consider any matter affecting their interests, including the modification or abrogation by Extraordinary Resolution of a modification of the Notes, the Coupons or any of these Conditions or the provisions of the Trust Deed. The quorum at any meeting for passing an Extraordinary Resolution will be one or more persons present holding or representing more than 50 per cent. in principal amount of the Notes of a particular Series for the time being outstanding, or at any adjourned such meeting two or more persons present whatever the principal amount of the Notes held or represented by him or them, except that, at any meeting the business of which includes the modification or abrogation of certain of the provisions of the Notes or the Coupons or the Trust Deed (including modifying the date of maturity of the Notes or any date for payment of interest thereon, reducing or cancelling the amount of principal or the rate of interest payable in respect of the Notes or altering the currency of payment of the Notes or the Coupons), the necessary quorum for passing an Extraordinary Resolution will be two or more persons present holding or representing not less than three-quarters, or at any adjourned such meeting not less than one third, of the principal amount of the Notes of a particular Series for the time being outstanding. An Extraordinary Resolution passed at any meeting of the Noteholders shall be binding on all Noteholders, whether or not they are present at the meeting and on all Couponholders.

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The Trust Deed provides that a resolution in writing signed by or on behalf of the holders of not less than 75 per cent. in nominal amount of the Notes outstanding shall for all purposes be as valid and effective as an Extraordinary Resolution passed at a meeting of Noteholders duly convened and held. Such a resolution in writing may be contained in one document or several documents in the same form, each signed by or on behalf of one or more Noteholders. 15.2 Trustee’s Discretion The Trustee may agree, without the consent of the Noteholders or Couponholders to any modification of, or to the waiver or authorisation of any breach or proposed breach of, any of these Conditions or any of the provisions of the Notes or the Trust Deed, or determine, without any such consent as aforesaid, that any Event of Default or Potential Event of Default (as defined in the Trust Deed) shall not be treated as such, which in any such case is not, in the opinion of the Trustee, materially prejudicial to the interests of the Noteholders or may agree, without any such consent as aforesaid, to any modification which, in its opinion, is of a formal, minor or technical nature or to correct a manifest error or an error which is in the opinion of the Trustee proven. Any such modification shall be binding on the Noteholders and the Couponholders and any such modification shall be notified to the Noteholders in accordance with Condition 14 (Notices) as soon as practicable thereafter. 15.3 Regard to Noteholders’ Interests In connection with the exercise by it of any of its trusts, powers, authorities and discretions (including, without limitation, any modification, waiver, authorisation, determination or substitution), the Trustee shall have regard to the general interests of the Noteholders as a class but shall not have regard to any interests arising from circumstances particular to individual Noteholders or Couponholders (whatever their number) and, in particular but without limitation, shall not have regard to the consequences of any such exercise for individual Noteholders or Couponholders (whatever their number) resulting from their being for any purpose domiciled or resident in, or otherwise connected with, or subject to the jurisdiction of, any particular territory or any political subdivision thereof and the Trustee shall not be entitled to require, nor shall any Noteholder or Couponholder be entitled to claim, from the Issuer, the Trustee or any other person any indemnification or payment in respect of any tax consequence of any such exercise upon individual Noteholders or Couponholders except to the extent already provided for in Condition 8 (Taxation) or any undertaking given in addition to, or in substitution for, Condition 8 (Taxation) pursuant to the Trust Deed. 15.4 Substitution The Trustee may, without the consent of the Noteholders, agree with the Issuer to the substitution in place of the Issuer (or of any previous substitute under this Condition) as the principal debtor under the Notes, the Coupons and the Trust Deed of a wholly-owned subsidiary of the Issuer, subject to: (a) the Trustee being satisfied that the interests of the Noteholders will not be materially prejudiced by the substitution; (b) if the Trustee so requires, the Notes being unconditionally guaranteed by the Issuer to the satisfaction of the Trustee; and (c) certain other conditions set out in the Trust Deed being complied with. 15.5 Modification and Substitution Binding on Noteholders Any modification, abrogation, waiver, authorisation, determination or substitution shall be binding on the Noteholders and, unless the Trustee agrees otherwise, any modification or substitution shall be notified by the Issuer to the Noteholders as soon as practicable thereafter in accordance with Condition 14 (Notices).

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16. INDEMNIFICATION OF THE TRUSTEE AND TRUSTEE CONTRACTING WITH THE ISSUER The Trust Deed contains provisions for the indemnification of the Trustee and for its relief from responsibility, including provisions relieving it from taking action unless indemnified or secured to its satisfaction. The Trust Deed also contains provisions pursuant to which the Trustee is entitled, inter alia, (a) to enter into business transactions with the Issuer or any of its Subsidiaries and to act as trustee for the holders of any other securities issued or guaranteed by, or relating to, the Issuer or any of its Subsidiaries, (b) to exercise and enforce its rights, comply with its obligations and perform its duties under or in relation to any such transactions or, as the case may be, any such trusteeship without regard to the interests of, or consequences for, the Noteholders or Couponholders, and (c) to retain and not be liable to account for any profit made or any other amount or benefit received thereby or in connection therewith. 17. FURTHER ISSUES The Issuer shall be at liberty from time to time without the consent of the Noteholders or the Couponholders to create and issue further notes having terms and conditions the same as the Notes or the same in all respects save for the amount and date of the first payment of interest thereon and so that the same shall be consolidated and form a single Series with the outstanding Notes; provided that, in the case of Bearer Notes initially represented by interests in a Temporary Bearer Global Note exchangeable for interests in a Permanent Bearer Global Note or Definitive Bearer Notes such consolidation can only occur upon certification of non-U.S. beneficial ownership. Notwithstanding the foregoing, further notes that are not issued pursuant to a “qualified reopening” for U.S. tax purposes shall be issued with a CUSIP or ISIN separate from that of the original Notes. 18. CONTRACTS (RIGHTS OF THIRD PARTIES) ACT 1999 No person shall have any right to enforce any term or condition of this Note under the Contracts (Rights of Third Parties) Act 1999, but this does not affect any right or remedy of any person which exists or is available apart from that Act. 19. GOVERNING LAW AND SUBMISSION TO JURISDICTION The Trust Deed, the Agency Agreement, the Notes and the Coupons, and any non-contractual obligations arising out of or in connection with any of them, are governed by, and shall be construed in accordance with, English law. The Issuer has in the Trust Deed irrevocably and unconditionally agreed for the benefit of the Trustee, the Noteholders and the Couponholders that the courts of England are to have exclusive jurisdiction to settle any disputes which may arise out of or in connection with the Trust Deed, the Notes and/or the Coupons, or any non-contractual obligations arising out of or in connection with any of them, and that accordingly any suit, action or proceedings arising thereout or in connection therewith (together referred to as “Proceedings”) may be brought in the courts of England. The Issuer has in the Trust Deed irrevocably and unconditionally waived and agreed not to raise any objection which it may have now or subsequently to the laying of the venue of any Proceedings in the courts of England and any claim that any Proceedings have been brought in an inconvenient forum and has further irrevocably and unconditionally agreed that a judgment in any Proceedings brought in the courts of England shall be conclusive and binding upon the Issuer. Nothing in this Condition shall limit any right to take Proceedings against the Issuer in any other court of competent jurisdiction, nor shall the taking of Proceedings in one or more jurisdictions preclude the taking of Proceedings in any other jurisdiction, whether concurrently or not. The Issuer has in the Trust Deed irrevocably and unconditionally appointed St James’s Corporate Services Limited at its registered office for the time being (currently at 6 St James’s Place, London SW1A 1NP) (the “Process Agent”) as its agent to accept service of process on its behalf in England

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in respect of any Proceedings and has undertaken that in the event of such agent not being effectively appointed or ceasing so to act, it will appoint such other person in England to accept service of process on its behalf and shall immediately notify the Trustee of such appointment. Any failure by the Issuer to make such appointment within 15 days from the date of such notification, shall entitle the Trustee to appoint such a Person by written notice to the Issuer. The Trustee shall nevertheless be entitled to serve process in any other manner permitted by law. A copy of any notice or other documentation served on the Process Agent pursuant to such Proceedings will also be delivered to the address specified by the Issuer in the Trust Deed for the receipt of any notices thereunder. The Issuer has in the Trust Deed, irrevocably and unconditionally waived and agreed not to raise with respect to any Proceedings any right to claim sovereign or other immunity from jurisdiction and any similar defence, and has, to the extent permitted under South African law, irrevocably and unconditionally consented to the giving of any relief or the issue of any process, including, without limitation, the making, enforcement or execution against any property whatsoever (irrespective of its use or intended use) of any order or judgment made or given in connection with any Proceedings.

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APPLICABLE FINAL TERMS Set out below is the form of Final Terms which will be completed for each Tranche of Notes issued under the Programme. Text appearing in italics in this section does not form part of the Form of Final Terms but denotes directions for completing Final Terms.

Final Terms dated [•] ESKOM HOLDINGS SOC LTD Issue of [Aggregate Nominal Amount of Tranche] [Title of Notes] under the U.S.$4,000,000,000 Global Medium Term Note Programme PART A—CONTRACTUAL TERMS Terms used herein shall be deemed to be defined as such for the purposes of the Terms and Conditions of the Notes set forth in the Base Prospectus dated 23 January 2015 [and the supplement[s] to it dated [date] [and [date]]] which [together] constitute[s] a base prospectus (the “Base Prospectus”) for the purposes of EU Directive 2003/71/EC as amended (which includes the amendments made by Directive 2010/73/EU to the extent that such amendments have been implemented in the Relevant Member State) (the “Prospectus Directive”). This document constitutes the Final Terms of the Notes described herein for the purposes of Article 5.4 of the Prospectus Directive and must be read in conjunction with the Base Prospectus. Full information on the Issuer and the offer of the Notes is only available on the basis of the combination of these Final Terms and the Base Prospectus. The Base Prospectus has been published on the website of the Luxembourg Stock Exchange (www.bourse.lu). [The following alternative language applies if the first tranche of an issue which is being increased was issued under a Base Prospectus with an earlier date.] Terms used herein shall be deemed to be defined as such for the purposes of the Terms and Conditions of the Notes set forth in the Base Prospectus dated 22 July 2013 which are incorporated by reference in the Base Prospectus dated 23 January 2015[and the supplement[s] to it dated [date] [and [date]]]. This document constitutes the Final Terms of the Notes described herein for the purposes of Article 5.4 of the of EU Directive 2003/71/EC as amended (which includes the amendments made by Directive 2010/73/EU to the extent that such amendments have been implemented in the Relevant Member State) (the “Prospectus Directive”) and must be read in conjunction with the Base Prospectus dated 23 January 2015 which constitutes a base prospectus (the “Base Prospectus”) for the purposes of the Prospectus Directive. Full information on the Issuer and the offer of the Notes is only available on the basis of the combination of these Final Terms and the Base Prospectus. The Base Prospectus has been published on the website of the Luxembourg Stock Exchange (www.bourse.lu). [Include whichever of the following apply or specify as “Not Applicable” (N/A). Note that the numbering should remain as set out below, even if “Not Applicable” is indicated for individual paragraphs or subparagraphs. Italics denote directions for completing the Final Terms.] [If the Notes have a maturity of less than one year from the date of their issue, the minimum denomination may need to be £100,000 or its equivalent in any other currency]

1. (a) Series Number: [●] (b) Tranche Number: [●] (c) Date on which the Notes become [Not Applicable] [The Notes shall be consolidated, form fungible: a single series and be interchangeable for trading purposes with [provide issue amount/ISIN/maturity date/issue date of earlier Tranches] on [insert date/the Issue Date/exchange of the Temporary Global Note for

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interests in the Permanent Global Note, as referred to in paragraph [22] below [which is expected to occur on or about [insert date]]].] 2. Specified Currency or Currencies: [●] 3. Aggregate Nominal Amount: (a) Series: [●] (b) Tranche: [●] 4. Issue Price: [●] per cent. of the Aggregate Nominal Amount [plus accrued interest from [insert date] (if applicable)] 5. (a) Specified Denominations: [●] (N.B. Where Bearer Notes with multiple denominations above [€/£100,000/U.S.$200,000] or equivalent are being used the following language should be used: [€/£100,000/U.S.$200,000] and integral multiples of [€/£/U.S.$1,000] in excess thereof up to and including [€/£99,000/U.S.$199,000]. No Notes in definitive form will be issued with a denomination of integral multiples above [€/£99,000/U.S.$199,000]. (b) Calculation Amount: [€/£/U.S.$]1,000 (Applicable to Notes in definitive form.) (If there is only one Specified Denomination, insert that Specified Denomination. If there is more than one Specified Denomination, insert the highest common factor. N.B. there must be a common factor in the case of two or more Specified Denominations) 6. (a) Issue Date: [●] (b) Interest Commencement Date: [Issue Date/Not Applicable] (N.B. An Interest Commencement Date will not be relevant for certain Notes, for example Zero Coupon Notes.) 7. Maturity Date: [Fixed rate: specify date/Floating Rate: Interest Payment Date falling in or nearest to [specify month]] 8. Interest Basis: [[●] per cent. Fixed Rate] [[LIBOR/EURIBOR/USD-LIBOR] +/- [●] per cent. Floating Rate] [Zero Coupon] (further particulars specified below) 9. Redemption/Payment Basis: Subject to any purchase and cancellation or early redemption, the Notes will be redeemed on the Maturity Date at [100] / [ ] per cent. of their nominal amount. (N.B., the redemption amount will never be lower than 100%)

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. 10. Change of Interest Basis or Redemption/ [Applicable. Notes are [Fixed to Floating Rate Notes / Payment Basis: Floating to Fixed Rate Notes] [the date when change occurs]] / [Not Applicable] 11. Put/Call Options: [Investor Put] [Change of Control/Restructuring Investor Put] [Issuer Call] [(further particulars specified below)] [Not Applicable] 12. [Date of [Board] approval for issuance of [●] [and [●], respectively]] Notes obtained: 13. Method of distribution: [Syndicated/Non-syndicated] PROVISIONS RELATING TO INTEREST (IF ANY) PAYABLE 14. Fixed Rate Note Provisions: [Applicable/Not Applicable] (If not applicable, delete the remaining subparagraphs of this paragraph) (a) Rate(s) of Interest: [●] per cent. per annum on each Interest Payment Date in arrear (b) Interest Payment Date(s): [[●] in each year up to and including the Maturity Date] [There will be a [short/long] first interest period from, and including, the Interest Commencement Date to, but excluding, [ ] (the “[Short]/[Long] First Coupon”] [There will be a [short/long] final interest period from, and including, [ ] to, but excluding, the Maturity Date (the “[Short]/[Long] Final Coupon”)] (c) Fixed Coupon Amount(s): [●] per Calculation Amount[, other than in respect of the [Short]/[Long] [First]/[Final] Coupon] (Applicable to Notes in definitive form.) (d) Broken Amount(s): [[●] per Calculation Amount payable on the Interest Payment Date falling in/on [•].] [Not Applicable] (Applicable to Notes in definitive form.) (e) Day Count Fraction: [30/360 or Actual/Actual (ICMA)] (f) Determination Date(s): [●] in each year [Insert regular interest payment dates, ignoring issue date or maturity date in the case of a long or short first or last coupon N.B. This will need to be amended in the case of regular interest payment dates which are not of equal duration N.B. Only relevant where Day Count Fraction is Actual/Actual (ICMA)] 15. Floating Rate Note Provisions: [Applicable/Not Applicable]

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(If not applicable, delete the remaining subparagraphs of this paragraph) (a) Specified Period(s)/ Specified [●] [, subject to adjustment in accordance with the Interest Payment Dates: Business Day Convention set out in (c) below][, not subject to adjustment, as the Business Day Convention in (c) below is specified to be Not Applicable]

[There will be a [short/long] interest period from, and including, the Interest Commencement Date to, but excluding, [ ] (the “[Short]/[Long] First Coupon”)] [There will be a [short/long] final interest period from, and including, [ ] to, but excluding, the Maturity Date (the “[Short]/[Long] Final Coupon”)]

(b) First Interest Payment Date: [●] (c) Business Day Convention: [Floating Rate Convention/Following Business Day Convention/Modified Following Business Day Convention/Preceding Business Day Convention] [Not Applicable] (d) Additional Business Centre(s): [●] (f) Manner in which the Rate of [Screen Rate Determination][ISDA Determination] Interest and Interest Amount is to be determined: (f) Party responsible for calculating [●] the Rate of Interest and Interest Amount (if not the Agent): (g) Screen Rate Determination: [Applicable/Not Applicable]

• Reference Rate: [●]

• Interest Determination [●] Date(s): (Second London business day prior to the start of each Interest Period if LIBOR (other than Sterling or euro LIBOR), first day of each Interest Period if Sterling LIBOR and the second day on which the TARGET2 System is open prior to the start of each Interest Period if EURIBOR or euro LIBOR)

• Relevant Screen Page: [●] (In the case of EURIBOR, if not Reuters EURIBOR01 ensure it is a page which shows a composite rate or amend the fallback provisions appropriately)

• Reference Banks: [●] (h) ISDA Determination:

• Floating Rate Option: [●]

• Designated Maturity: [●]

• Reset Date: [●]

[Not Applicable/Applicable – the Rate of Interest for the

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(i) Linear Interpolation: [Long]/[Short] [First]/[Final] Coupon shall be calculated using Linear Interpolation (specify for each short or long Interest Period)]

(j) Margin(s): [+/ ] [●] per cent. per annum (k) Minimum Rate of Interest: [●] per cent. per annum (l) Maximum Rate of Interest: [●] per cent. per annum (m) Day Count Fraction: [Actual/Actual (ISDA) Actual/365 (Fixed) Actual/365 (Sterling) Actual/360 30/360 30E/360 30E/360 (ISDA)] (See Condition 5 (Interest) for alternatives) 16. Zero Coupon Note Provisions: [Applicable/Not Applicable] (If not applicable, delete the remaining subparagraphs of this paragraph) (a) Accrual Yield: [●] per cent. per annum (b) Reference Price: [●] (c) Day Count Fraction in relation to [30/360] Early Redemption Amounts: [Actual/360] [Actual/365] (Consider applicable day count fraction if not U.S. dollar-denominated) PROVISIONS RELATING TO REDEMPTION

17. Issuer Call: [Applicable/Not Applicable] (If not applicable, delete the remaining subparagraphs of this paragraph) (a) Optional Redemption Date(s): [●] (b) Optional Redemption Amount [[●] per Calculation Amount] [Make-Whole Amount] and method, if any, of calculation of such amount(s): [Applicable] [Not Applicable – the Notes are not (c) If redeemable in part: redeemable in part only] (i) Minimum Redemption Amount: [●]

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(ii) Maximum Redemption Amount: [●] (d) Notice period (if other than as set [●] out in the Terms and Conditions of the Notes): (N.B. If setting notice periods which are different to those provided in the Terms and Conditions of the Notes, the Issuer is advised to consider the practicalities of distribution of information through intermediaries, for example, clearing systems and custodians, as well as any other notice requirements which may apply, for example, as between the Issuer and the Agent or Trustee)

18. Investor Put: [Applicable/Not Applicable] (If not applicable, delete the remaining subparagraphs of this paragraph) (a) Optional Redemption Date(s): [●] (b) Optional Redemption Amount [[●] per Calculation Amount] and method, if any, of calculation of such amount(s): (c) Notice period (if other than as set [●] out in the Terms and Conditions of the Notes): (N.B. If setting notice periods which are different to those provided in the Terms and Conditions of the Notes, the Issuer is advised to consider the practicalities of distribution of information through intermediaries, for example, clearing systems and custodians, as well as any other notice requirements which may apply, for example, as between the Issuer and the Agent or Trustee) 19. Change of Control/Restructuring Investor [Applicable/Not Applicable] Put:

20. Final Redemption Amount: [[●] per Calculation Amount] 21. Early Redemption Amount payable on [[●] per Calculation Amount] redemption for taxation reasons or on event of default and/or the method of calculating the same (if required or if different from that set out in Condition 7.7 (Early Redemption Amounts)): GENERAL PROVISIONS APPLICABLE TO THE NOTES 22. Form of Notes: [Bearer Notes: [Temporary Bearer Global Note exchangeable for a Permanent Bearer Global Note which is exchangeable for Definitive Bearer Notes [on 60 days’ notice given at any time/only upon an Exchange Event]] [Temporary Bearer Global Note exchangeable for Definitive Bearer Notes on and after the Exchange

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Date] [Permanent Bearer Global Note exchangeable for Definitive Bearer Notes [on 60 days’ notice given at any time/only upon an Exchange Event/at any time at the request of the Issuer]]] (N.B. The exchange upon notice/at any time should not be expressed to be applicable if the Specified Denomination of the Notes in paragraph 6 includes language substantially to the following effect: “[€100,000] and integral multiples of [€1,000] in excess thereof up to and including [€199,000]. No Notes in definitive form will be issued with a denomination above [€199,000]”. Furthermore, such Specified Denomination construction is not permitted in relation to any issue of Notes which is to be represented on issue by Temporary Global Note exchangeable for Definitive Notes.) [Registered Notes: [Regulation S Global Note registered in the name of a nominee for a common depositary for Euroclear and Clearstream, Luxembourg] [Rule 144A Global Note registered in the name of a nominee for [DTC/a common depositary for Euroclear and Clearstream, Luxembourg]]] 23. Calculation Agent: [●]

24. Additional Financial Centre(s) or other [Not Applicable [•]] special provisions relating to Payment Days: (Note that this paragraph relates to the place of payment and not Interest Period end dates to which sub paragraph 15(d) relates) 25. Talons for future Coupons to be attached [Yes, as the Notes have more than 27 coupon payments, to Definitive Notes (and dates on which Talons may be required if, on exchange into definitive such Talons mature): form, more than 27 coupon payments are still to be made/No] DISTRIBUTION 26. Whether TEFRA D or TEFRA C rules [TEFRA D/TEFRA C/TEFRA not applicable] applicable or TEFRA rules not applicable: [RESPONSIBILITY STATEMENT [[Relevant third party information] has been extracted from [specify source]. The Issuer confirms that such information has been accurately reproduced and that, so far as it is aware and is able to ascertain from information published by [specify source], no facts have been omitted which would render the reproduced information inaccurate or misleading]. Signed on behalf of ESKOM HOLDINGS SOC LTD

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By:______Duly authorised

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PART B—OTHER INFORMATION

1. LISTING AND ADMISSION TO TRADING (i) Listing and Admission to [Application has been made for the Notes to be trading: admitted to trading on the Bourse de Luxembourg which is the regulated market in Luxembourg and listing on the Official List of the Luxembourg Stock Exchange with effect from [•].] [Not Applicable.] (ii) Estimate of total expenses related [●] to admission to trading: 2. RATINGS Ratings: The Notes to be issued have been rated:

[S & P: [•]]

[Moody’s: [•]] [The rating of the Notes has been endorsed by [name]:] (The above disclosure should reflect the rating allocated to Notes of the type being issued under the Programme generally or, where the issue has been specifically rated, that rating) [[Insert credit rating agency] is established in the European Union and is registered under Regulation (EU) No 1060/2009 (the “CRA Regulation”).] [[Insert credit rating agency] is not established in the European Union and has not applied for registration under Regulation (EU) No 1060/2009 (the “CRA Regulation”).] [[Insert credit rating agency] is established in the European Union and has applied for registration under Regulation (EU) No 1060/2009 (the “CRA Regulation”), although notification of the corresponding registration decision has not yet been provided by the relevant competent authority.] [[Insert credit rating agency] is not established in the European Union and has not applied for registration under Regulation (EU) No 1060/2009 (the “CRA Regulation”) but the rating issued by it is endorsed by [insert endorsing credit rating agency] which is established in the European Union and [is registered under the CRA Regulation] [has applied for registration under the CRA Regulation, although notification of the corresponding registration decision has not yet been provided by the relevant competent authority].] [[Insert credit rating agency] is not established in the European Union and has not applied for registration under Regulation (EU) No 1060/2009 (the “CRA

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Regulation”) but is certified in accordance with the CRA Regulation.] In general, European regulated investors are restricted from using a rating for regulatory purposes if such rating is not issued by a credit rating agency established in the EEA and registered under the CRA Regulation unless (i) the rating is provided by a credit rating agency operating in the European Union before 7 June 2010 which has submitted an application for registration in accordance with the CRA Regulation and such registration is not refused or (ii) the rating is provided by a credit rating agency not established in the EEA but is endorsed by a credit rating agency established in the EEA and registered under the CRA Regulation or (iii) the rating is provided by a credit rating agency established in the EEA which is certified under the CRA Regulation. 3. INTERESTS OF NATURAL AND LEGAL PERSONS INVOLVED IN THE ISSUE [Save for any fees payable to the [Managers/Dealers], so far as the Issuer is aware, no person involved in the issue of the Notes has an interest material to the offer. Amend as appropriate if there are other interests.] [(When adding any other description consideration should be given as to whether such matters described constitute “significant new factors” and consequently trigger the need for a supplement to the Base Prospectus under Article 16 of the Prospectus Directive.)] 4. YIELD (Fixed Rate Notes only) [●] 5. OPERATIONAL INFORMATION (i) ISIN Code: [●] (ii) Common Code: [●] (iii) CUSIP: [●] (iv) Any clearing system(s) other [Not Applicable/give name(s) and number(s)] than Euroclear Bank SA/NV and Clearstream Banking, société anonyme/The Depository Trust Company and the relevant identification number(s): (v) Delivery: Delivery [against/free of] payment (vi) Names and addresses of [●] additional Paying Agent(s) (if any): (vii) Name and address of Registrar [●]

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FORM OF THE NOTES The Notes of each series will be in either bearer form, with or without interest coupons attached, or registered form, without interest coupons attached. Bearer Notes will be issued outside the United States in reliance on the exemption from registration provided by Regulation S under the Securities Act (“Regulation S”) and Registered Notes will be issued both outside the United States in reliance on the exemption from registration provided by Regulation S and within the United States in reliance on the exemption from registration provided by Rule 144A under the Securities Act. Bearer Notes Each Tranche of Bearer Notes will be initially issued in the form of a temporary global note (a “Temporary Bearer Global Note”) or, if so specified in the applicable Final Terms or relevant Drawdown Prospectus, a permanent global note (a “Permanent Bearer Global Note”) which, in either case, will be delivered on or prior to the original issue date of the Tranche to a common depositary for Euroclear Bank SA/NV (“Euroclear”) and Clearstream Banking, société anonyme (“Clearstream, Luxembourg”). Bearer Notes will only be delivered outside the United States and its possessions. Whilst any Bearer Note is represented by a Temporary Bearer Global Note, payments of principal, interest (if any) and any other amount payable in respect of the Notes due prior to the Exchange Date (as defined below) will only be made (against presentation of the Temporary Bearer Global Note) outside the United States and its possessions and only to the extent that certification (in a form to be provided) to the effect that the beneficial owners of interests in such Bearer Note are not U.S. persons or persons who have purchased for resale to any U.S. person, as required by U.S. Treasury regulations, has been received by Euroclear and/or Clearstream, Luxembourg and Euroclear and/or Clearstream, Luxembourg, as applicable, has given a like certification (based on the certifications it has received) to the Principal Paying Agent. On and after the date (the “Exchange Date”) which is 40 days after a Temporary Bearer Global Note is issued, interests in such Temporary Bearer Global Note will be exchangeable (free of charge) upon a request as described therein either for (i) interests in a Permanent Bearer Global Note of the same series or (ii) for definitive Bearer Notes of the same series with, where applicable, interest coupons and talons attached (as indicated in the applicable Final Terms or relevant Drawdown Prospectus and subject, in the case of definitive Bearer Notes, to such notice period as is specified in the applicable Final Terms or relevant Drawdown Prospectus), in each case against certification of beneficial ownership as described above unless such certification has already been given. Bearer Notes will only be delivered outside the United States. The holder of a Temporary Bearer Global Note will not be entitled to collect any payment of interest, principal or other amount due on or after the Exchange Date unless, upon due certification, exchange of the Temporary Bearer Global Note for an interest in a Permanent Bearer Global Note or for definitive Bearer Notes is improperly withheld or refused. Payments of principal, interest (if any) or any other amounts on a Permanent Bearer Global Note will be made only outside the United States and its possessions through Euroclear and/or Clearstream, Luxembourg (against presentation or surrender (as the case may be) of the Permanent Bearer Global Note) without any requirement for certification in the manner described above. The applicable Final Terms or relevant Drawdown Prospectus will specify that a Permanent Bearer Global Note will be exchangeable (free of charge), in whole but not in part, for definitive Bearer Notes with, where applicable, interest coupons and talons attached upon either (a) not less than 60 days’ written notice from Euroclear and/or Clearstream, Luxembourg (acting on the instructions of any holder of an interest in such Permanent Bearer Global Note) to the Principal Paying Agent as described therein or (b) only upon the occurrence of an Exchange Event. For these purposes, “Exchange Event” means that (i) an Event of Default (as defined in Condition 10 (Events of Default)) has occurred and is continuing or (ii) the Issuer has been notified that both Euroclear and Clearstream, Luxembourg have been closed for business for a continuous period of 14 days (other than by reason of holiday, statutory or otherwise) or have announced an intention permanently to cease business or have in fact done so and no successor clearing system satisfactory to the Trustee is available or (iii) the Issuer has or will become subject to adverse tax consequences which would not be suffered were the Notes represented by the Permanent Bearer Global Note in definitive form and a certificate to that effect signed by two Directors of the Issuer is given to the Trustee. The Issuer will promptly

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give notice to Noteholders in accordance with Condition 14 (Notices) if an Exchange Event occurs. In the event of the occurrence of an Exchange Event, Euroclear and/or Clearstream, Luxembourg (acting on the instructions of any holder of an interest in such Permanent Bearer Global Note) or the Trustee may give notice to the Principal Paying Agent requesting exchange and, in the event of the occurrence of an Exchange Event as described in (iii) above, the Issuer may also give notice to the Principal Paying Agent requesting exchange. Any such exchange shall occur not later than 45 days after the date of receipt of the first relevant notice by the Principal Paying Agent. The following legend will appear on all Bearer Notes (other than Temporary Bearer Global Notes) (including unilateral roll-overs and extensions) (other than Temporary Bearer Global Notes) and on all interest coupons or Talons relating to such Notes where TEFRA D is specified in the applicable Final Terms: “ANY UNITED STATES PERSON WHO HOLDS THIS OBLIGATION WILL BE SUBJECT TO LIMITATIONS UNDER THE UNITED STATES INCOME TAX LAWS, INCLUDING THE LIMITATIONS PROVIDED IN SECTIONS 165(j) AND 1287(a) OF THE INTERNAL REVENUE CODE.” The sections of the Code referred to in the legend above provide that U.S. Holders (as defined in “Taxation— United States”), with certain limited exceptions, will not be entitled to deduct any loss on Bearer Notes or interest coupons and will not be entitled to capital gains treatment of any gain on any sale, disposition, redemption or payment of principal in respect of such Notes or interest coupons. Notes which are represented by a Bearer Global Note will only be transferable in accordance with the rules and procedures for the time being of Euroclear or Clearstream, Luxembourg, as the case may be. Notes may only be issued in bearer form in accordance with the requirements of South African law which includes the approval of the South African Minister of Finance. Registered Notes The Registered Notes of each Tranche offered and sold in reliance on Regulation S, which will be sold to non U.S. persons outside the United States, will initially be represented by a global note in registered form (a “Regulation S Global Note”). Prior to expiry of the distribution compliance period (as defined in Regulation S) applicable to each Tranche of Notes, beneficial interests in a Regulation S Global Note may not be offered or sold to, or for the account or benefit of, a U.S. person save as otherwise provided in Condition 2 (Transfers of Registered Notes) and may not be held otherwise than through Euroclear or Clearstream, Luxembourg and such Regulation S Global Note will bear a legend regarding such restrictions on transfer. The Registered Notes of each Tranche may only be offered and sold in the United States or to U.S. persons in private transactions to QIBs. The Registered Notes of each Tranche sold to QIBs will be represented by a global note in registered form (a “Rule 144A Global Note” and, together with a Regulation S Global Note, the “Registered Global Notes”). Registered Global Notes will either (i) be deposited with a custodian for, and registered in the name of a nominee of the Depository Trust Company (“DTC”) or (ii) deposited with a common depositary for Euroclear and Clearstream, Luxembourg and registered in the name of a common nominee of that common depositary, as specified in the applicable Final Terms or relevant Drawdown Prospectus. Persons holding beneficial interests in Registered Global Notes will be entitled or required, as the case may be, under the circumstances described below, to receive physical delivery of Definitive Notes in fully registered form. Payments of principal, interest and any other amount in respect of the Registered Global Notes will, in the absence of provision to the contrary, be made to the person shown on the Register (as set out in Condition 6.4 (Payments in respect of Registered Notes)) as the registered holder of the Registered Global Notes. None of the Issuer, any Paying Agent, the Trustee or the Registrar will have any responsibility or liability for any aspect of the records relating to or payments or deliveries made on account of beneficial ownership interests in the Registered Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. Payments of principal, interest or any other amount in respect of the Registered Notes in definitive form will, in the absence of provision to the contrary, be made to the persons shown on the Register on the relevant Record Date (as defined in Condition 6.4 (Payments in respect of Registered Notes)) immediately preceding the due date for payment in the manner provided in that Condition.

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Interests in a Registered Global Note will be exchangeable (free of charge), in whole but not in part, for definitive Registered Notes without interest coupons or talons attached only upon the occurrence of an Exchange Event. For these purposes, “Exchange Event” means that (i) an Event of Default has occurred and is continuing, (ii) in the case of Notes registered in the name of a nominee for DTC, either DTC has notified the Issuer that it is unwilling or unable to continue to act as depository for the Notes and no alternative clearing system satisfactory to the Trustee is available or DTC has ceased to constitute a clearing agency registered under the Exchange Act, (iii) in the case of Notes registered in the name of a nominee for a common depositary for Euroclear and Clearstream, Luxembourg, the Issuer has been notified that both Euroclear and Clearstream, Luxembourg have been closed for business for a continuous period of 14 days (other than by reason of holiday, statutory or otherwise) or have announced an intention permanently to cease business or have in fact done so and, in any such case, no successor clearing system satisfactory to the Trustee is available or (iv) the Issuer has or will become subject to adverse tax consequences which would not be suffered were the Notes represented by the Registered Global Note in definitive form and a certificate to that effect signed by two Directors of the Issuer is given to the Trustee. The Issuer will promptly give notice to Noteholders in accordance with Condition 14 (Notices) if an Exchange Event occurs. In the event of the occurrence of an Exchange Event, DTC, Euroclear and/or Clearstream, Luxembourg (acting on the instructions of any holder of an interest in such Registered Global Note) or the Trustee may give notice to the Registrar requesting exchange and, in the event of the occurrence of an Exchange Event as described in (iv) above, the Issuer may also give notice to the Registrar requesting exchange. Any such exchange shall occur not later than 10 days after the date of receipt of the first relevant notice by the Registrar. Transfer of interests Interests in a Registered Global Note may, subject to compliance with all applicable restrictions, be transferred to a person who wishes to hold such interest in another Registered Global Note subject to compliance with all applicable restrictions, be transferred to a person who wishes to hold such Notes in the form of an interest in a Registered Global Note. No beneficial owner of an interest in a Registered Global Note will be able to transfer such interest, except in accordance with the applicable procedures of DTC, Euroclear and Clearstream, Luxembourg, in each case to the extent applicable. Registered Notes are also subject to the restrictions on transfer set forth therein and will bear a legend regarding such restrictions, see “Subscription and Sale and Transfer and Selling Restrictions”. General Pursuant to the Agency Agreement (as defined under “Terms and Conditions of the Notes”), the Principal Paying Agent shall arrange that, where a further Tranche of Notes is issued which is intended to form a single series with an existing Tranche of Notes, the Notes of such further Tranche shall be assigned a common code and ISIN and, where applicable, a CUSIP number which are different from the common code, ISIN, and CUSIP assigned to Notes of any other Tranche of the same series until at least the expiry of the distribution compliance period (as defined in Regulation S) applicable to the Notes of such Tranche. Any reference herein to Euroclear and/or Clearstream, Luxembourg and/or DTC shall, whenever the context so permits, be deemed to include a reference to any additional or alternative clearing system specified in the applicable Final Terms or relevant Drawdown Prospectus or as may otherwise be approved by the Issuer, the Agent and the Trustee. No Noteholder or Couponholder shall be entitled to proceed directly against the Issuer unless the Trustee having become bound so to proceed, fails so to do within a reasonable period and the failure shall be continuing.

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BOOK ENTRY, SETTLEMENT AND CLEARANCE The information set out below is subject to any change in or reinterpretation of the rules, regulations and procedures of DTC, Euroclear or Clearstream, Luxembourg (together, the “Clearing Systems”) currently in effect. Investors wishing to use the facilities of any of the Clearing Systems are advised to confirm the continued applicability of the rules, regulations and procedures of the relevant Clearing System. None of the Issuer, the Trustee nor any other party to the Agency Agreement will have any responsibility or liability for any aspect of the records relating to, or payments made on account of, beneficial ownership interests in the Notes held through the facilities of any Clearing System or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. Book entry systems Euroclear and Clearstream, Luxembourg Euroclear and Clearstream, Luxembourg each holds securities for its customers and facilitates the clearance and settlement of securities transactions by electronic book entry transfer between their respective account holders. Euroclear and Clearstream, Luxembourg provide various services including safekeeping, administration, clearance and settlement of internationally traded securities and securities lending and borrowing. Euroclear and Clearstream, Luxembourg also deal with domestic securities markets in several countries through established depository and custodial relationships. Euroclear and Clearstream, Luxembourg have established an electronic bridge between their two systems across which their respective participants may settle trades with each other. Euroclear and Clearstream, Luxembourg customers are world-wide financial institutions, including underwriters, securities brokers and dealers, banks, trust companies and clearing corporations. Indirect access to Euroclear and Clearstream, Luxembourg is available to other institutions that clear through or maintain a custodial relationship with an account holder of either system. DTC DTC has advised the Issuer that it is a limited purpose trust company organised under the New York Banking Law, a “banking organisation” within the meaning of the New York Banking Law, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to section 17A of the Exchange Act. DTC holds securities that its participants (“Participants”) deposit with DTC. DTC also facilitates the settlement among Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerised book entry changes in the Participants’ accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organisations. DTC is owned by a number of its Direct Participants and by the New York Stock Exchange, Inc., the American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. Access to the DTC System is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). Under the rules, regulations and procedures creating and affecting DTC and its operations (the “Rules”), DTC makes book entry transfers of Registered Notes among Direct Participants on whose behalf it acts with respect to Notes accepted into DTC’s book entry settlement system (“DTC Notes”) as described below and receives and transmits distributions of principal and interest on DTC Notes. The Rules are on file with the SEC. Direct Participants and Indirect Participants with which beneficial owners of DTC Notes (“Owners”) have accounts with respect to the DTC Notes similarly are required to make book entry transfers and receive and transmit such payments on behalf of their respective Owners. Accordingly, although Owners who hold DTC Notes through Direct Participants or Indirect Participants will not possess Registered Notes, the Rules, by virtue of the requirements described above, provide a mechanism by which Direct Participants will receive payments and will be able to transfer their interest in respect of the DTC Notes. Purchases of DTC Notes under the DTC system must be made by or through Direct Participants, which will receive a credit for the DTC Notes on DTC’s records. The ownership interest of each actual purchaser of each DTC Note (“Beneficial Owner”) is in turn to be recorded on the Direct and Indirect Participant’s records.

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Beneficial Owners will not receive written confirmation from DTC of their purchase, but Beneficial Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the DTC Notes are to be accomplished by entries made on the books of Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in DTC Notes, except in the event that use of the book entry system for the DTC Notes is discontinued. To facilitate subsequent transfers, all DTC Notes deposited by Participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co. The deposit of DTC Notes with DTC and their registration in the name of Cede & Co. effect no change in beneficial ownership. DTC has no knowledge of the actual Beneficial Owners of the DTC Notes; DTC’s records reflect only the identity of the Direct Participants to whose accounts such DTC Notes are credited, which may or may not be the Beneficial Owners. The Participants will remain responsible for keeping account of their holdings on behalf of their customers. Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Redemption notices shall be sent to DTC. If less than all of the DTC Notes within an issue are being redeemed, DTC’s practice is to determine by lot the amount of the interest of each Direct Participant in such issue to be redeemed. Neither DTC nor Cede & Co. will consent or vote with respect to DTC Notes. Under its usual procedures, DTC mails an omnibus proxy to the Issuer as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the DTC Notes are credited on the record date (identified in a listing attached to the Omnibus Proxy). Principal and interest payments on the DTC Notes will be made to DTC. DTC’s practice is to credit the Direct Participants’ accounts on the due date for payment in accordance with their respective holdings shown on DTC’s records unless DTC has reason to believe that it will not receive payment on the due date. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name”, and will be the responsibility of such Participant and not of DTC or the Issuer, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal and interest to DTC is the responsibility of the Issuer, disbursement of such payments to Direct Participants is the responsibility of DTC, and disbursement of such payments to the Beneficial Owners is the responsibility of the Direct and Indirect Participants. Under certain circumstances, including if there is an Event of Default under the Notes, DTC will exchange the DTC Notes for definitive Registered Notes, which it will distribute to its Participants in accordance with their proportionate entitlements and which will be legended as set forth under “Subscription and Sale and Transfer and Selling Restrictions”. Since DTC may only act on behalf of Direct Participants, who in turn act on behalf of Indirect Participants, any Owner desiring to pledge DTC Notes to persons or entities that do not participate in DTC, or otherwise take actions with respect to such DTC Notes, will be required to withdraw its Registered Notes from DTC as described below. Book entry ownership of and payments in respect of Global Notes The Issuer has applied to each of Euroclear and Clearstream, Luxembourg to have Global Note(s) accepted in its book-entry settlement system. Upon the issue of any such Global Note, Euroclear and/or Clearstream, Luxembourg, as applicable, will credit, on its internal book-entry system, the respective nominal amounts of the interests represented by such Global Note to the accounts of persons who have accounts with Euroclear and/or Clearstream, Luxembourg, as applicable. Such accounts initially will be designated by or on behalf of the relevant Dealer. Interests in such a Global Note through Euroclear and/or Clearstream, Luxembourg, as applicable, will be limited to accountholders of Euroclear and/or Clearstream, Luxembourg, as applicable.

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Interests in such a Global Note will be shown on, and the transfer of such interests will be effected only through, records maintained by Euroclear and/or Clearstream, Luxembourg or its nominee (with respect to the interests of Euroclear and/or Clearstream, Luxembourg accountholders). Payments with respect to interests in the Notes held through Euroclear and Clearstream, Luxembourg will be credited to cash accounts of Euroclear and Clearstream, Luxembourg accountholders in accordance with the rules and procedures of Euroclear and Clearstream, Luxembourg, respectively, to the extent received by each of them. The Issuer may apply to DTC in order to have any Tranche of Notes represented by a Registered Global Note accepted in its book-entry settlement system. Upon the issue of any such Registered Global Note, DTC or its custodian will credit, on its internal book-entry system, the respective nominal amounts of the individual beneficial interests represented by such Registered Global Note to the accounts of persons who have accounts with DTC. Such accounts initially will be designated, by or on behalf of the relevant Dealer. Ownership of beneficial interests in such a Registered Global Note will be limited to Direct Participants or Indirect Participants, including, in the case of any Regulation S Global Note, the respective depositaries of Euroclear and Clearstream, Luxembourg. Ownership of beneficial interests in a Registered Global Note accepted by DTC will be shown on, and the transfer of such ownership will be effected only through, records maintained by DTC or its nominee (with respect to the interests of Direct Participants) and the records of Direct Participants (with respect to interests of Indirect Participants). Payments in U.S. dollars of principal and interest in respect of a Registered Global Note accepted by DTC will be made to the order of DTC or its nominee as the registered holder of such Note. In the case of any payment in a currency other than U.S. dollars, payment will be made to the Principal Paying Agent on behalf of DTC or its nominee and the Principal Paying Agent will (in accordance with instructions received by it) remit all or a portion of such payment for credit directly to the beneficial holders of interests in the Registered Global Note in the currency in which such payment was made and/or cause all or a portion of such payment to be converted into U.S. dollars and credited to the applicable Participants’ account. The Issuer expects DTC to credit accounts of Direct Participants on the applicable payment date in accordance with their respective holdings as shown in the records of DTC unless DTC has reason to believe that it will not receive payment on such payment date. The Issuer also expects that payments by Participants to beneficial owners of Notes will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers, and will be the responsibility of such Participant and not the responsibility of DTC, the Paying Agent, the Registrar or the Issuer. Payment of principal, premium, if any, and interest, if any, on Notes to DTC is the responsibility of the Issuer. Transfers of Notes represented by Registered Global Notes Transfers of any interests in Notes represented by a Registered Global Note within DTC, Euroclear and Clearstream, Luxembourg will be effected in accordance with the customary rules and operating procedures of the relevant clearing system. The laws in some States within the United States require that certain persons take physical delivery of securities in definitive form. Consequently, the ability to transfer Notes represented by a Registered Global Note to such persons may depend upon the ability to exchange such Notes for Notes in definitive form. Similarly because DTC can only act on behalf of Direct Participants in the DTC system who in turn act on behalf of Indirect Participants, the ability of a person having an interest in Notes represented by a Registered Global Note accepted by DTC to pledge such Notes to persons or entities that do not participate in the DTC system or otherwise to take action in respect of such Notes may depend upon the ability to exchange such Notes for Notes in definitive form. The ability of any holder of Notes represented by a Registered Global Note accepted by DTC to resell, pledge or otherwise transfer such Notes may be impaired if the proposed transferee of such Notes is not eligible to hold such Notes through a direct or indirect participant in the DTC system. Subject to compliance with the transfer restrictions applicable to the Registered Notes described under “Subscription and Sale and Transfer and Selling Restrictions”, cross market transfers between DTC, on the one hand, and directly or indirectly through Clearstream, Luxembourg or Euroclear accountholders, on the other, will be effected by the relevant clearing system in accordance with its rules and through action taken by the Registrar, the Principal Paying Agent and any custodian (“Custodian”) with whom the relevant Registered Global Notes have been deposited.

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On or after the Issue Date for any series, transfers of Notes of such series between accountholders in Clearstream, Luxembourg and Euroclear and transfers of Notes of such series between participants in DTC will generally have a settlement date three business days after the trade date (T+3). The customary arrangements for delivery versus payment will apply to such transfers. Cross market transfers between accountholders in Clearstream, Luxembourg or Euroclear and DTC participants will need to have an agreed settlement date between the parties to such transfer. Because there is no direct link between DTC, on the one hand, and Clearstream, Luxembourg and Euroclear, on the other, transfers of interests in the relevant Registered Global Notes will be effected through the Registrar, the Principal Paying Agent and the Custodian receiving instructions (and, where appropriate, certification) from the transferor and arranging for delivery of the interests being transferred to the credit of the designated account for the transferee. In the case of cross market transfers, settlement between Euroclear or Clearstream, Luxembourg accountholders and DTC participants cannot be made on a delivery versus payment basis. The securities will be delivered on a free delivery basis and arrangements for payment must be made separately. DTC, Clearstream, Luxembourg and Euroclear have each published rules and operating procedures designed to facilitate transfers of beneficial interests in Registered Global Notes among participants and accountholders of DTC, Clearstream, Luxembourg and Euroclear. However, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued or changed at any time. None of the Issuer, the Trustee, the Agents or any Dealer will be responsible for any performance by DTC, Clearstream, Luxembourg or Euroclear or their respective direct or indirect participants or accountholders of their respective obligations under the rules and procedures governing their operations and none of them will have any liability for any aspect of the records relating to or payments made on account of beneficial interests in the Notes represented by Registered Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial interests.

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TAXATION The following summary of certain South African, United States and European Union consequences of ownership of Notes is based upon laws, regulations, decrees, rulings, income tax conventions, administrative practice and judicial decisions in effect at the date of this Base Prospectus. Legislative, judicial or administrative changes or interpretations may, however, be forthcoming that could alter or modify the statements and conclusions set forth herein. Any such changes or interpretations may be retroactive and could affect the tax consequences to holders of the Notes. This summary does not constitute a legal opinion or tax advice. In addition this summary does not purport to address all tax aspects that may be relevant to a holder of Notes. Each prospective holder is urged to consult its own tax adviser as to the particular tax consequences to such holder of the ownership and disposition of Notes, including the applicability and effect of any other tax laws or tax treaties, and of pending or proposed changes in applicable tax laws as of the date of this Base Prospectus, and of any actual changes in applicable tax laws after such date: South Africa The following is a summary of the material South African tax consequences of the acquisition, ownership and disposition of the Notes by South African tax residents and non-residents who will be beneficial owners of the Notes. The summary does not cover all aspects of South African tax that may be relevant to, or the actual tax effect that any of the matters described herein will have on, the acquisition, ownership or disposition of the Notes by particular investors. In terms of the distribution of the Notes, there are restrictions applicable to sales of the Notes in South Africa. See “Subscription and Sale and Transfer and Selling Restrictions—South Africa”. Securities Transfer Tax The issue, transfer and redemption of the Notes will not attract securities transfer tax under the Securities Transfer Tax Act, 2007 (the “STT Act”) because the Notes do not constitute “securities” as defined in the STT Act. Any future transfer duties and/or taxes that may be introduced in respect of (or applicable to) the transfer of Notes will be for the account of holders of the Notes. Value-Added Tax No value-added tax (“VAT”) is payable on the issue or transfer of the Notes. The issue, sale or transfer of the Notes constitute “financial services” as defined in section 2 of the Value-Added Tax Act, 1991 (the “VAT Act”). In terms of section 2 of the VAT Act, the issue, allotment, drawing, acceptance, endorsement or transfer of ownership of a debt security as well as the buying and selling of derivatives constitute a financial service, which is exempt from VAT in terms of section 12(a) of the VAT Act. The Notes constitute “debt securities” as defined in section 2(2)(iii) of the VAT Act. However, commissions, fees or similar charges raised for the facilitation of the issue, allotment, drawing, acceptance, endorsement or transfer of ownership of Notes will be subject to VAT at the standard rate (currently 14%), except where the recipient is a non-resident as contemplated below. Services (including exempt financial services) rendered to non-residents who are not in South Africa when the services are rendered, are subject to VAT at the zero rate in terms of section 11(2)(l) of the VAT Act. Income Tax Under current taxation law effective in South Africa, a “resident” (as defined in section 1 of the Income Tax Act, 1962 (the “Income Tax Act”) is subject to income tax on his/her worldwide income. Accordingly, all holders of Notes who are residents of South Africa will generally be liable to pay income tax, subject to available deductions, allowances and exemptions, on any income (including income in the form of interest) earned in respect of the Notes. Non-residents of South Africa are subject to income tax on all income derived from a South African source (subject to domestic exemptions or relief in terms of applicable double taxation treaties). Under current law, interest income is derived from a South African source if it is incurred by a South African tax resident (unless it is attributable to a foreign permanent establishment of that resident) or if it is derived from the utilisation or application in South Africa by any Person of funds or credit obtained in terms of any form of “interest-bearing

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arrangement”. The Notes will constitute an “interest-bearing arrangement”. The Issuer is tax resident in South Africa as at the date of the Programme. Accordingly, if the Notes are not attributable to a permanent establishment of the Issuer outside of South Africa, the interest earned by a Noteholder will be from a South African source and subject to South African income tax unless such interest income is exempt from South African income tax under section 10(1)(h) of the Income Tax Act (see below). Under section 10(1)(h) of the Income Tax Act, any amount of interest which is received or accrued (during any year of assessment) by or to any Person that is not a resident of South Africa is exempt from income tax, unless: (a) that Person is a natural Person who was physically present in South Africa for a period exceeding 183 days in aggregate during the twelve-month period preceding the date on which the interest is received or accrued by or to that Person; or (b) the debt from which the interest arises is effectively connected to a permanent establishment of that person in South Africa. If a Noteholder does not qualify for the exemption under section 10(1)(h) of the Income Tax Act, an exemption from or reduction of any South African tax liability may be available under an applicable double taxation agreement. Furthermore, certain entities may be exempt from income tax. Investors are advised to consult their own professional advisers as to whether the interest income earned on the Notes will be exempt under section 10(1)(h) of the Income Tax Act or under an applicable double taxation agreement. In terms of section 24J of the Income Tax Act, broadly speaking, any discount or premium to the principal amount of a Note is treated as part of the interest income on the Note. Interest income which accrues (or is deemed to accrue) to a Noteholder is deemed, in accordance with section 24J of the Income Tax Act, to accrue on a day-to-day basis until that Noteholder disposes of the Note or until maturity, unless an election has been made by the Noteholder, which is a company, if that Noteholder is entitled under Section 24J(9) of the Income Tax Act to make such election) to treat its Notes as trading stock on a mark-to-market basis. The provisions of section 24J(9) of the Income Tax Act will not apply to company which is a “covered person” as defined in the Income Tax Act during any year of assessment ending on or after 1 January 2014, or in respect of any other company during any year of assessment commencing on or after 1 April 2014. The day-to-day basis accrual is determined by calculating the yield to maturity (as defined in section 24J of the Income Tax Act) and applying this rate to the capital involved for the relevant tax period. The premium or discount is treated as interest for the purposes of the exemption under section 10(1)(h) of the Income Tax Act. Section 24JB deals with the taxation of financial assets and liabilities for certain “covered persons” and applies in respect of years of assessment ending on or after 1 January 2014. Noteholders should seek advice as to whether these provisions may apply to them. Capital Gains Tax Capital gains and losses of residents of South Africa on the disposal of Notes are subject to capital gains tax unless the Notes are purchased for re-sale in the short term as part of a scheme of profit making, in which case the proceeds will be subject to income tax. Any discount or premium on acquisition which has already been treated as interest for income tax purposes under section 24J of the Income Tax Act will not be taken into account when determining any capital gain or loss. In terms of section 24J(4A) of the Income Tax Act, where an adjusted loss on transfer or redemption includes interest which has been included in the income of the holder, that amount qualifies as a deduction from the income of the holder during the year of assessment in which the transfer or redemption takes place, and should accordingly not give rise to a capital loss. Capital gains tax under the Eighth Schedule to the Income Tax Act will not be levied in relation to Notes disposed of by a Person who is not a resident of South Africa unless the Notes disposed of are attributable to a permanent establishment of that Person in South Africa during the relevant year of assessment. Purchasers are advised to consult their own professional advisers as to whether a disposal of Notes will result in a liability to capital gains tax.

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Withholding Tax A final withholding tax on interest (“WHT”) which will be levied at the rate of 15% will be introduced from 1 March 2015, applying to interest payments made from a South African source to foreign persons (i.e. non- residents), which are paid or become due and payable on or after that date. The legislation introducing the WHT contains certain exemptions (including an exemption for listed debt). South Africa is a party to Double Taxation Treaties that may provide full or partial relief from the WHT, provided that certain requirements are met. In terms of the applicable legislation, South African sourced interest that is paid to a foreign Person in respect of any listed debt will be exempt from the withholding tax on interest. In terms of the legislation, a “listed debt” is a debt that is listed on a recognised exchange as defined in the Income Tax Act. Also exempt from the withholding tax on interest will be any amount of interest from a South African source paid to a foreign Person if the debt claim in respect of which that interest is paid is effectively connected to a permanent establishment of that foreign person in South Africa and that foreign person is registered as a taxpayer in terms of Chapter 3 of the Tax Administration Act. Documentary requirements exist in order to rely on the latter exemption. Definition of Interest The references to “interest” above mean “interest” as understood in South African tax law. The statements above do not take account of any different definitions of “interest” or “principal” which may prevail under any other law or which may be created by the Terms and Conditions or any related documentation. United States The following is a summary of the principal U.S. federal income tax consequences of the acquisition, ownership, disposition and retirement of Notes by a Noteholder thereof. This summary does not address the U.S. federal income tax consequences relevant to Noteholders of every type of Note which may be issued under the Programme, and the Final Terms may contain additional or modified disclosure concerning certain U.S. federal income tax consequences relevant to Noteholders of Notes issued pursuant thereto as appropriate. This summary only applies to Notes held as capital assets and does not address, except as set forth below, aspects of U.S. federal income taxation that may be applicable to Noteholders that are subject to special tax rules, such as financial institutions, insurance companies, real estate investment trusts, regulated investment companies, grantor trusts, tax-exempt organizations, dealers or traders in securities or currencies, or to Noteholders that will hold a Note as part of a position in a straddle or as part of a hedging, conversion or integrated transaction for U.S. federal income tax purposes or that have a functional currency other than the U.S. dollar. Moreover, this summary does not address the U.S. federal estate and gift tax or alternative minimum tax consequences of the acquisition, ownership or retirement of Notes and does not address the U.S. federal income tax treatment of Noteholders that do not acquire Notes as part of the initial distribution at their original “issue price” (as defined herein). This summary is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury Regulations, administrative pronouncements and judicial decisions, each as available and in effect on the date hereof. All of the foregoing are subject to change, possibly with retroactive effect, or differing interpretations which could affect the tax consequences described herein. Any special U.S. federal income tax considerations relevant to a particular issue of the Notes will be provided in the relevant Final Terms. For purposes of this description, a U.S. Noteholder is a beneficial owner of the Notes who, for U.S. federal income tax purposes, is (i) a citizen or resident of the United States; (ii) a corporation (or entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States or any State thereof, including the District of Columbia; (iii) an estate the income of which is subject to U.S. federal income taxation regardless of its source; or (iv) a trust (1) that has a valid election in effect to be treated as a United States person for U.S. federal income tax purposes or (2)(a) the administration over which a U.S. court can exercise primary supervision and (b) all of the substantial decisions of which one or more United States persons have the authority to control.

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A Non-U.S. Noteholder is a beneficial owner of the Notes other than a U.S. Noteholder or a partnership (or an entity treated as a partnership for U.S. federal income tax purposes). If a partnership (or any other entity treated as a partnership for U.S. federal income tax purposes) holds Notes, the tax treatment of the partnership and a partner in such partnership generally will depend on the status of the partner and the activities of the partnership. Such partner or partnership should consult its own tax advisor as to its consequences. Bearer Notes are not being offered to U.S. Noteholders. A U.S. Noteholder who owns a Bearer Note may be subject to limitations under United States income tax laws, including the limitations provided in sections 165(j) and 1287(a) of the Code. Investors should consult their own tax advisor with respect to the U.S. federal, state, local and foreign tax consequences of acquiring, owning or disposing of Notes. U.S. Noteholders Interest Except as set forth below, interest paid on a Note, whether payable in U.S. dollars or a currency, composite currency or basket of currencies other than U.S. dollars (a “foreign currency”), including any additional amounts, will be includible in a U.S. Noteholder’s gross income as ordinary interest income at the time such interest is received or accrued in accordance with the U.S. Noteholder’s usual method of accounting for U.S. federal income tax purposes. In addition, interest, including OID (as defined below), on the Notes will generally be treated as foreign source income for U.S. federal income tax purposes. The limitation on foreign taxes eligible for the U.S. foreign tax credit is calculated separately with respect to specific “baskets” of income. For this purpose, the interest on the Notes should generally constitute “passive category income”, or in the case of certain U.S. Noteholders, “general category income”. Foreign Currency Denominated Interest Any interest paid in a foreign currency will be included in the gross income of a U.S. Noteholder in an amount equal to the U.S. dollar value of the foreign currency, including the amount of any applicable withholding tax thereon, regardless of whether the foreign currency is converted into U.S. dollars. Generally, a U.S. Noteholder that uses the cash method of tax accounting will determine such U.S dollar value using the spot rate of exchange on the date of receipt. No foreign currency gain or loss will be recognized with respect to the receipt of such payment. Generally, a U.S. Noteholder that uses the accrual method of tax accounting will determine the U.S. dollar value of accrued interest income using the average rate of exchange for the accrual period (or, in the case of an accrual period spanning two taxable years, the average rate of exchange for the portion of the accrual period within the taxable year) or, at the U.S. Noteholder’s election, at the spot rate of exchange on the last day of the accrual period (or, in the case of an accrual period spanning two taxable years, the last day of the taxable year) or the spot rate on the date of receipt, if that date is within five days of the last day of the accrual period. U.S. Noteholders should consult their tax advisors about making any such election. A U.S. Noteholder that uses the accrual method of accounting for tax purposes will recognize foreign currency gain or loss on the receipt of an interest payment if the exchange rate in effect on the date payment is received differs from the exchange rate applicable to an accrual of that interest. This foreign currency gain or loss will be ordinary income or loss and generally will be U.S. source provided that the residence of a taxpayer is considered to be the United States for purposes of the rules regarding foreign currency gain or loss. Additional rules for Notes that are denominated in more than one currency or that have one or more noncurrency contingencies and are denominated in either one foreign currency or more than one currency are described below under “Dual Currency Notes”. Original Issue Discount U.S. Noteholders of Notes issued with original issue discount (“OID”) will be subject to special tax accounting rules, as described in greater detail below. U.S. Noteholders of Notes issued with OID (including cash basis taxpayers) should be aware that, as described in greater detail below, they generally must include OID in income for U.S. federal income tax purposes as it accrues, without regard to the receipt of cash attributable to that income. However, U.S. Noteholders of such Notes generally will not be required to include separately in income cash payments received on the Notes, even if denominated as interest, to the

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extent such payments do not constitute “qualified stated interest” (as defined herein). Notes issued with OID will be referred to as “Original Issue Discount Notes”. Notice will be given in the relevant Final Terms when the Issuer determines that a particular Note will be an Original Issue Discount Note. Additional rules applicable to Original Issue Discount Notes that are denominated in or determined by reference to a currency other than the U.S. dollar are described under “Foreign Currency Discount Notes” below. For U.S. federal income tax purposes, a Note, other than a Note with a term of one year or less (a “Short-Term Note”), will be treated as an “Original Issue Discount Note” if the excess of the Note’s “stated redemption price at maturity” over its “issue price” equals or exceeds a de minimis amount (0.25% of the Note’s stated redemption price at maturity multiplied by the number of complete years to its maturity (or, in the case of a Note that provides for payments other than qualified stated interest before maturity, its weighted average maturity)). “Stated redemption price at maturity” is the total of all payments provided by the Note that are not payments of “qualified stated interest”. The “issue price” of each Note in a particular offering will be the first price at which a substantial amount of that particular offering is sold (other than to bond houses, brokers, or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers) for cash. The term “qualified stated interest” means stated interest that is unconditionally payable in cash or in property (other than debt instruments of the issuer) at least annually at a single fixed rate or, subject to certain conditions, based on one or more interest indices. Interest is payable at a single fixed rate only if the rate appropriately takes into account the length of the interval between payments. Notice will be given in the relevant Final Terms when the Issuer determines that a particular Note will bear interest that is not qualified stated interest. In the case of a Note issued with de minimis OID, the U.S. Noteholder generally must include such de minimis OID in income as stated principal payments on the Notes are made in proportion to the stated principal amount of the Note. Any amount of de minimis OID that has been included in income will be treated as capital gain. Certain of the Notes may be redeemed prior to their maturity at the Issuer’s option and/or at the option of the Noteholder. Original Issue Discount Notes containing such features may be subject to rules that differ from the general rules discussed herein. Persons considering the purchase of Original Issue Discount Notes with such features should carefully examine the relevant Final Terms and should consult their own tax advisors with respect to such features since the tax consequences with respect to OID will depend, in part, on the particular terms and features of the Notes. U.S. Noteholders of Original Issue Discount Notes with a maturity upon issuance of more than one year must, in general, include OID in income in advance of the receipt of some or all of the related cash payments. The amount of OID includible in income by the initial U.S. Noteholder of an Original Issue Discount Note is the sum of the “daily portions” of OID with respect to the Note for each day during the taxable year or portion of the taxable year in which such U.S. Noteholder held such Note (“accrued OID”). The daily portion is determined by allocating to each day in any “accrual period” a pro rata portion of the OID allocable to that accrual period. The “accrual period” for an Original Issue Discount Note may be of any length and may vary in length over the term of the Note, provided that each accrual period is no longer than one year and each scheduled payment of principal or interest occurs on the first day or the final day of an accrual period. The amount of OID allocable to any accrual period is an amount equal to the excess, if any, of (a) the product of the Note’s adjusted issue price at the beginning of such accrual period and its yield to maturity (determined on the basis of compounding at the close of each accrual period and properly adjusted for the length of the accrual period) over (b) the sum of any qualified stated interest allocable to the accrual period. OID allocable to a final accrual period is the difference between the amount payable at maturity (other than a payment of qualified stated interest) and the adjusted issue price at the beginning of the final accrual period. Special rules will apply for calculating OID for an initial short accrual period. The “adjusted issue price” of an Original Issue Discount Note at the beginning of any accrual period is equal to its issue price increased by the accrued OID for each prior accrual period (determined without regard to the amortization of any acquisition or bond premium, as described below) and reduced by any payments made on such Note (other than qualified stated interest) on or before the first day of the accrual period. Under these rules, a U.S. Noteholder will have to include in income increasingly greater amounts of OID in successive accrual periods. In the case of an Original Issue Discount Note that is a Floating Rate Note treated as a “variable rate debt instrument” for U.S. federal income tax purposes, both the “yield to maturity” and “qualified stated interest” will be determined solely for purposes of calculating the accrual of OID as though the Note will bear interest in all periods at a fixed rate generally equal to the rate that would be applicable to interest payments on the Note on its date of issue or, in the case of certain Floating Rate Notes, the rate that reflects the yield to

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maturity that is reasonably expected for the Note, subject to certain adjustments. Additional rules may apply if interest on a Floating Rate Note is based on more than one interest index or if the principal amount of the Note is indexed in any manner. Persons considering the purchase of Floating Rate Notes should carefully examine the relevant Final Terms and should consult their own tax advisors regarding the U.S. federal income tax consequences of the holding and disposition of such Notes. U.S. Noteholders may elect to treat all interest on any Note as OID and calculate the amount includible in gross income under the constant yield method described above. For the purposes of this election, interest includes stated interest, acquisition discount, OID, de minimis OID, market discount, de minimis market discount and unstated interest, as adjusted by any amortizable bond premium or acquisition premium. The election is made for the taxable year in which the U.S. Noteholder acquired the Note, and may not be revoked without the consent of the IRS. U.S. Noteholders should consult their own tax advisors about this election. Short-Term Notes In the case of Short-Term Notes (as defined above), all payments (including all stated interest payments) will be included in the stated redemption price at maturity and, thus, U.S. Noteholders generally will be taxable on the discount in lieu of stated interest. The discount will be equal to the excess of the stated redemption price at maturity over the issue price of a Short-Term Note, unless the U.S. Noteholder elects to compute this discount using tax basis instead of issue price. In general, individuals and certain other cash method U.S. Noteholders of a Short-Term Note are not required to include accrued discount in their income currently unless they elect to do so (but may be required to include any stated interest in income as it is received). U.S. Noteholders that report income for United States federal income tax purposes on the accrual method and certain other U.S. Noteholders are required to accrue discount on such Short-Term Notes (as ordinary income) on a straight-line basis, unless an election is made to accrue the discount according to a constant yield method based on daily compounding. In the case of a U.S. Noteholder that is not required, and does not elect, to include discount in income currently, any gain realized on the sale, exchange or retirement of the Short-Term Note will generally be ordinary income to the extent of the discount accrued through the date of sale, exchange or retirement. In addition, a U.S. Noteholder that does not elect to include currently accrued discount in income may be required to defer deductions for a portion of the U.S. Noteholder’s interest expense with respect to any indebtedness incurred or continued to purchase or carry such Notes. Foreign Currency Original Issue Discount Notes OID for any accrual period on an Original Issue Discount Note that is denominated in, or determined by reference to, a foreign currency will be determined for any accrual period in the foreign currency and then translated into U.S. dollars in the same manner as stated interest accrued by an accrual basis U.S. Noteholder, as described under “—Foreign Currency Denominated Interest”. Upon receipt of an amount attributable to OID previously included in income (whether in connection with a payment of interest, a partial principal payment or the sale or retirement of a Note), a U.S. Noteholder will recognize foreign currency gain or loss in an amount determined in the same manner as interest income received by a Noteholder on the accrual basis, as described above in “—Foreign Currency Denominated Interest”. For these purposes, all receipts on a Note will be viewed: first, as the receipt of any qualified stated interest payments called for under the terms of the Note; second, as the receipt of previously accrued OID (to the extent thereof), with payments considered made for the earliest accrual periods first; and third, as the receipt of principal. Notes Purchased at a Premium A U.S. Noteholder that purchases a Note for an amount in excess of the sum of all amounts payable on the Note after the purchase date other than qualified stated interest will be considered to have purchased the Note at a “premium”. A U.S. Noteholder generally may elect to amortize the premium over the remaining term of the Note on a constant yield method as an offset to interest when includible in income under the U.S. Noteholder’s regular accounting method. In the case of a Note that is denominated in, or determined by reference to, a foreign currency, bond premium will be computed in units of foreign currency, and amortizable bond premium will reduce interest income in units of the foreign currency. At the time amortized bond premium offsets interest income, exchange gain or loss (taxable as ordinary income or loss) is realized measured by the difference between exchange rates at that time and at the time of the acquisition of the Notes. Any election to amortize bond premium shall apply to all bonds (other than bonds the interest on which is excludable from gross income) held by the U.S. Noteholder at the beginning of the first taxable year to which

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the election applies or thereafter acquired by the U.S. Noteholder, and is irrevocable without the consent of the IRS. Special rules limit the amortization of premium in the case of debt redeemable at a premium. Bond premium on a Note held by a U.S. Noteholder that does not make such an election will decrease the gain or increase the loss otherwise recognized on disposition of the Note. Sale, Exchange or Retirement A U.S. Noteholder’s tax basis in a Note generally will be its U.S. dollar cost (as defined herein) increased by the amount of any OID (including de minimis OID) included in the U.S. Noteholder’s income with respect to the Note and reduced by (i) the amount of any payments that are not qualified stated interest payments, and (ii) the amount of any amortizable bond premium applied to reduce interest on the Note. The U.S. dollar cost of a Note purchased with a foreign currency generally will be the U.S. dollar value of the purchase price on the date of purchase or, in the case of Notes traded on an established securities market, as defined in the applicable Treasury Regulations, that are purchased by a cash basis U.S. Noteholder (or an accrual basis U.S. Noteholder that so elects), on the settlement date for the purchase. A U.S. Noteholder generally will recognize gain or loss on the sale or retirement of a Note equal to the difference between the amount realized on the sale or retirement (excluding any amount attributable to accrued but unpaid interest, which will be taxable as such) and the tax basis of the Note. The amount realized on a sale or retirement for an amount in foreign currency will be the U.S. dollar value of such amount on the date of sale or retirement or, in the case of Notes traded on an established securities market, as defined in the applicable Treasury Regulations, sold by a cash basis U.S. Noteholder (or an accrual basis U.S. Noteholder that so elects), on the settlement date for the sale. Gain or loss recognized on the sale or retirement of a Note (other than (i) gain or loss that is attributable to changes in exchange rates, which, to the extent described below, will be treated as ordinary income or loss and (ii) gain with respect to Short-Term Notes treated as ordinary income, as described above) will be capital gain or loss and will be long-term capital gain or loss if the Note was held for more than one year. Certain non-corporate U.S. Noteholders (including individuals) may qualify for preferential rates for U.S. federal income tax purposes with respect to long-term capital gains. The deductibility of capital losses is subject to certain limitations. Gain or loss recognized by a U.S. Noteholder on the sale or retirement of a Note that is attributable to changes in exchange rates will be treated as ordinary income or loss. However, exchange gain or loss is taken into account only to the extent of total gain or loss realized on the transaction. Gain or loss realized by a U.S. Noteholder on the sale or retirement of a Note generally will be U.S. source income or loss. Prospective investors should consult their tax advisors as to the foreign tax credit implications of such sale or retirement of Notes. A U.S. Noteholder receiving a partial principal payment on a Note that is denominated in, or determined by reference to, a foreign currency will be treated as if it had sold a pro rata portion of such Note. Accordingly, a U.S. Noteholder may recognize foreign currency gain or loss on the receipt of such partial principal payment. Sale or Exchange of Foreign Currency Foreign currency received as interest on a Note or on the sale, exchange or retirement of a Note will have a tax basis equal to its U.S. dollar value at the time such interest is received or at the time of such sale or retirement. As discussed above, if Notes denominated in, or determined by reference to, a foreign currency are traded on an established securities market, a cash basis U.S. Noteholder (or, upon election, an accrual basis U.S. Noteholder) will determine the U.S. dollar value of the foreign currency received upon such sale, exchange or retirement by translating the foreign currency received at the spot rate of exchange on the settlement date of thereof. Accordingly, no foreign currency gain or loss will result from currency fluctuations between the trade date and settlement date. Foreign currency that is purchased generally will have a tax basis equal to the U.S. dollar value of the foreign currency on the date of purchase. Any gain or loss recognized on a sale or other disposition of a foreign currency (including its use to purchase Notes or upon exchange for U.S. dollars) will be ordinary income or loss. Dual Currency Notes U.S. Noteholders of Notes that are denominated in more than one currency or that have one or more noncurrency contingencies and are denominated in either one foreign currency or more than one currency will be subject to special tax accounting rules applicable to “Multi-Currency Debt Securities”. A U.S. Noteholder generally would be required to apply the “noncontingent bond method” in the Multi-Currency Debt Security’s denomination currency, which for this purpose would be the Multi-Currency Debt Security’s predominant currency as determined by the Issuer. A description of the principal U.S. federal income tax consideration

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relevant to Noteholders of Dual Currency Notes, including specification of the predominant currency, will be set forth, if required, in the relevant Final Terms. Notes with Contingent Payments The tax consequences to a U.S. Noteholder of a Note with contingent payments will depend on factors including the specific index or indices used to determine payments on such Note and the amount and time of any noncontingent payments on such Note. A description of the principal U.S. federal income tax considerations relevant to Noteholders of such Note will be set forth, if required, in the relevant Final Terms. Substitution of the Issuer The terms of the Notes provide that, in certain circumstances, the obligations of the Issuer under the Notes may be assumed by another entity. Any such assumption might be treated for U.S. federal income tax purposes as a deemed disposition of Notes by a U.S. Noteholder in exchange for new notes by the new obligor. As a result of this deemed disposition, a U.S. Noteholder could be required to recognize capital gain or loss for U.S. federal income tax purposes equal to the difference, if any, between the issue price of the new notes (as determined for U.S. federal income tax purposes), and the U.S. Noteholder’s tax basis in the Notes. U.S. Noteholders should consult their tax advisors concerning the U.S. federal income tax consequences to them of a change in obligor with respect to the Notes. Reportable Transaction Reporting Under certain U.S. Treasury Regulations, U.S. Noteholders that participate in “reportable transactions” (as defined in the regulations) must attach to their U.S. federal income tax returns a disclosure statement on Form 8886. U.S. Noteholders should consult their own tax advisors as to the possible obligation to file Form 8886 with respect to the ownership or disposition of the Notes, or any related transaction, including without limitation, the disposition of any non-U.S. currency received as interest or as proceeds from the sale or other disposition of the Notes. Foreign Asset Reporting Certain U.S. Noteholders are required to report information relating to an interest in the Notes, subject to certain exceptions (including an exception for Notes held in accounts maintained by U.S. financial institutions), by attaching a completed IRS Form 8938, statement of Specified Foreign Financial Assets, with their tax return for each year in which they had an interest in the Notes. U.S. Noteholders are urged to consult their tax advisors regarding information reporting requirements relating to their ownership and disposition of the Notes. Medicare Tax A U.S. Noteholder that is an individual or estate, or a trust that does not fall into a special class of trusts that is exempt from such tax, is subject to a 3.8% tax on the lesser of (i) such U.S. Noteholder’s ‘‘net investment income’’ (or the relevant taxable year and (ii) the excess of such U.S. Noteholder’s modified adjusted gross income for the taxable year over a certain threshold (which in the case of individuals will be between $125,000 and $250,000, depending on the individual’s circumstances). A U.S. Noteholder’s net investment income will generally include its gross interest income and its net gains from the disposition of the Notes, unless such interest or net gains are derived in the ordinary course of the conduct of a trade or business (other than a trade or business that consists of certain passive or trading activities). Any U.S. Noteholder that is an individual, estate or trust is urged to consult its tax advisor regarding the applicability of this tax to its income and gains in respect of its investment in the Notes. Non-U.S. Noteholders Under U.S. federal income tax law currently in effect, subject to the discussions below under the captions “U.S. Backup Withholding Tax and Information Reporting” and “FATCA”, payments of interest (including OID) on a Note to a Non-U.S. Noteholder generally will not be subject to U.S. federal income tax unless the income is effectively connected with the conduct by such Non-U.S. Noteholder of a trade or business in the United States. Subject to the discussion below under the caption “U.S. Backup Withholding Tax and Information Reporting”, any gain realized by a Non-U.S. Noteholder upon the sale, exchange or retirement of

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a Note generally will not be subject to U.S. federal income tax, unless (i) the gain is effectively connected with the conduct by such Non-U.S. Noteholder of a trade or business in the United States or (ii) in the case of any gain realized by an individual Non-U.S. Noteholder, such Non-U.S. Noteholder is present in the United States for 183 days or more in the taxable year of the sale, exchange or retirement and certain other conditions are met. U.S. Backup Withholding and Information Reporting Backup withholding and information reporting requirements apply to certain payments of principal of, and interest on, an obligation and to proceeds of the sale or redemption of an obligation, to certain Noteholders of Notes that are U.S. persons. Information reporting generally will apply to payments of principal of, and interest on, an obligation, and to proceeds from the sale or redemption of, an obligation made within the U.S. to a Noteholder (other than an exempt recipient, including a payee that is not a U.S. person and that provides an appropriate certification and certain other persons). The payor will be required to backup withhold on payments made within the United States on a Note to a Noteholder of a Note that is a U.S. person, other than an exempt recipient, if the Noteholder fails to furnish its correct taxpayer identification number or otherwise fails to comply with, or establish an exemption from, the backup withholding requirements. Payments within the United States of principal and interest to a Noteholder of a Note that is not a U.S. person will not be subject to backup withholding and information reporting requirements if an appropriate certification is provided by the Noteholder to the payor and the payor does not have actual knowledge or a reason to know that the certificate is incorrect. The backup withholding rate is 28%. Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules generally will be allowed as a refund or a credit against a Noteholder’s U.S. federal income tax liability, provided that the required information is furnished by such Noteholder on a timely basis to the IRS. FATCA Sections 1471 through 1474 of the U.S. Internal Revenue Code of 1986 (“FATCA”) impose a new reporting regime and potentially a 30% withholding tax with respect to certain payments to any non-U.S. financial institution (an “FFI”) that does not become a “Participating FFI” by entering into an agreement with the U.S. Internal Revenue Service (“IRS”) to provide the IRS with certain information in respect of its account holders and investors or is not otherwise exempt from or deemed in compliance with FATCA and with respect to certain payments to any investor that does not provide information sufficient to determine whether the investor is a U.S. person or should otherwise be treated as holding a “United States account” of a Participating FFI (unless otherwise exempt from FATCA). The Issuer or any paying agent may be classified as an FFI. The new withholding regime currently applies to payments from sources within the United States and will apply to “foreign passthru payments” no earlier than January 1, 2017. This withholding would potentially apply to payments in respect of any Notes that are issued after the “grandfathering date”, which is the date that is six months after the date on which final U.S. Treasury regulations defining the term “foreign passthru payment” are filed with the Federal Register, or which are significantly modified after the grandfathering date. South Africa and the United States have entered into a Model 1 intergovernmental agreement (an “IGA”) to help implement FATCA for certain South African entities. Payments of U.S. source income to South African “financial institutions”, as defined under the IGA (which may include the Issuer) will not be subject to FATCA withholding provided that they are in compliance with the IGA. However, South African “financial institutions” (which may include the Issuer) are required to report certain information regarding their respective U.S. account holders to the Government, which information may ultimately be reported to the U.S. Internal Revenue Service. Passthru payment withholding is not currently required under the IGA. If an amount in respect of FATCA were to be deducted or withheld from interest, principal or other payments on or with respect to the Notes, the Issuer would have no obligation to pay additional amounts or otherwise indemnify a holder for any such withholding or deduction by the Issuer, a paying agent or any other party. As a result, investors may, if FATCA is implemented as currently proposed by the IRS, receive less interest or principal than expected. An investor that is not a Participating FFI that is withheld upon generally will be able to obtain a refund only to the extent an applicable income tax treaty with the United States entitles the investor to a reduced rate of tax

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on the payment that was subject to withholding under FATCA, provided the required information is furnished in a timely manner to the IRS. Significant aspects of the application of FATCA are not currently clear. Investors should consult their own advisers about the application of FATCA, in particular if they may be classified as financial institutions under the FATCA rules. European Union EU Directive on the Taxation of Savings Income (Directive 2003/48/EC) Under Council Directive 2003/48/EC on the taxation of savings income, Member States are required to provide to the tax authorities of other Member States details of certain payments of interest or similar income paid or secured by a person established in a Member State to or for the benefit of an individual resident in another Member State or certain limited types of entities established in another Member State. On 24 March 2014, the Council of the European Union adopted a Council Directive amending and broadening the scope of the requirements described above. Member States are required to apply these new requirements from 1 January 2017. The changes will expand the range of payments covered by the Directive, in particular to include additional types of income payable on securities. The Directive will also expand the circumstances in which payments that indirectly benefit an individual resident in a Member State must be reported. This approach will apply to payments made to, or secured for, persons, entities or legal arrangements (including trusts) where certain conditions are satisfied, and may in some cases apply where the person, entity or arrangement is established or effectively managed outside of the European Union. For a transitional period, Luxembourg and Austria are required (unless during that period they elect otherwise) to operate a withholding system in relation to such payments. The changes referred to above will broaden the types of payments subject to withholding in those Member States which still operate a withholding system when they are implemented. In April 2013, the Luxembourg Government announced its intention to abolish the withholding system with effect from 1 January 2015, in favour of automatic information exchange under the Directive. The end of the transitional period is dependent upon the conclusion of certain other agreements relating to information exchange with certain other countries. A number of non-EU countries and territories including Switzerland have adopted similar measures (a withholding system in the case of Switzerland).

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SUBSCRIPTION AND SALE AND TRANSFER AND SELLING RESTRICTIONS The Dealers have in a dealer agreement dated 23 January 2015 (the “Dealer Agreement”), agreed with the Issuer a basis upon which they or any of them may from time to time agree to purchase Notes. Any such agreement will extend to those matters stated under “Form of the Notes” and “Terms and Conditions of the Notes”. In the Dealer Agreement, the Issuer has agreed to reimburse the Dealers for certain of their expenses in connection with the establishment and any future update of the Programme and the issue of Notes under the Programme and to indemnify the Dealers against certain liabilities incurred by them in connection therewith. In order to facilitate the offering of any Tranche of the Notes, certain persons participating in the offering of the Tranche may engage in transactions that stabilise, maintain or otherwise affect the market price of the relevant Notes during and after the offering of the Tranche. Specifically, such persons may over allot or create a short position in the Notes for their own account by selling more Notes than have been sold to them by the Issuer. Such persons may also elect to cover any such short position by purchasing Notes in the open market. In addition, such persons may stabilise or maintain the price of the Notes by bidding for or purchasing Notes in the open market and may impose penalty bids, under which selling concessions allowed to syndicate members or other broker dealers participating in the offering of the Notes are reclaimed if Notes previously distributed in the offering are repurchased in connection with stabilisation transactions or otherwise. The effect of these transactions may be to stabilise or maintain the market price of the Notes at a level above that which might otherwise prevail in the open market. The imposition of a penalty bid may also affect the price of the Notes to the extent that it discourages resales thereof. No representation is made as to the magnitude or effect of any such stabilising or other transactions. Such transactions, if commenced, may be discontinued at any time. Under the laws and regulations of the United Kingdom, stabilising activities may only be carried on by the Stabilising Manager named in the applicable Final Terms or relevant Drawdown Prospectus (or persons acting on its behalf) and only for a limited period following the Issue Date of the relevant Tranche of Notes. Transfer restrictions As a result of the following restrictions, purchasers of Notes in the United States are advised to consult legal counsel prior to making any purchase, offer, sale, resale or other transfer of such Notes. Each purchaser of Registered Notes (other than a person purchasing an interest in a Registered Global Note with a view to holding it in the form of an interest in the same Global Note) or person wishing to transfer an interest from one Registered Global Note to another or from global to definitive form or vice versa, will be required to acknowledge, represent and agree as follows (terms used in this paragraph that are defined in Rule 144A or in Regulation S are used herein as defined therein): (i) that either: (a) it is a QIB, purchasing (or holding) the Notes for its own account or for the account of one or more QIBs and it is aware that any sale to it is being made in reliance on Rule 144A or (b) it is outside the United States and is not a U.S. person; (ii) that the Notes are being offered and sold in a transaction not involving a public offering in the United States within the meaning of the Securities Act, and that the Notes have not been and will not be registered under the Securities Act or any other applicable U.S. State securities laws and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons except as set forth below; (iii) that, unless it holds an interest in a Regulation S Global Note and either is a person located outside the United States or is not a U.S. person, if in the future it decides to resell, pledge or otherwise transfer the Notes or any beneficial interests in the Notes, it will do so, after a date which is one year after the later of the last Issue Date for the series and the last date on which the Issuer or an affiliate of the Issuer was the owner of such Notes, only (a) to the Issuer or any affiliate thereof, (b) inside the United States to a person whom the seller reasonably believes is a QIB purchasing for its own account or for the account of a QIB in a transaction meeting the requirements of Rule 144A, (c) outside the United States in compliance with Rule 903 or Rule 904 under the Securities Act, (d) pursuant to the exemption from registration provided by Rule 144 under the Securities Act (if available) or (e) pursuant to an effective registration statement under the Securities Act, in each case in accordance with all applicable U.S. State securities laws;

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(iv) it will, and will require each subsequent holder to, notify any purchaser of the Notes from it of the resale restrictions referred to in paragraph (iii) above, if then applicable; (v) that Notes initially offered in the United States to QIBs will be represented by one or more Rule 144A Global Notes and that Notes offered outside the United States in reliance on Regulation S will be represented by one or more Regulation S Global Notes; (vi) that the Notes, other than the Regulation S Global Notes, will bear a legend to the following effect unless otherwise agreed to by the Issuer: “THIS SECURITY HAS NOT BEEN AND WILL NOT BE REGISTERED UNDER THE U.S. SECURITIES ACT OF 1933 (THE “SECURITIES ACT”), OR ANY OTHER APPLICABLE U.S. STATE SECURITIES LAWS AND, ACCORDINGLY, MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES OR TO, OR FOR THE ACCOUNT OR BENEFIT OF, U.S. PERSONS EXCEPT AS SET FORTH IN THE FOLLOWING SENTENCE. BY ITS ACQUISITION HEREOF, THE HOLDER (A) REPRESENTS THAT (1) IT IS A “QUALIFIED INSTITUTIONAL BUYER” (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) PURCHASING THE SECURITIES FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF ONE OR MORE QUALIFIED INSTITUTIONAL BUYERS (B) AGREES THAT IT WILL NOT RESELL OR OTHERWISE TRANSFER THE SECURITIES EXCEPT IN ACCORDANCE WITH THE AGENCY AGREEMENT AND, PRIOR TO THE DATE WHICH IS ONE YEAR AFTER THE LATER OF THE LAST ISSUE DATE FOR THE SERIES AND THE LAST DATE ON WHICH THE ISSUER OR AN AFFILIATE OF THE ISSUER WAS THE OWNER OF SUCH SECURITIES OTHER THAN (1) TO THE ISSUER OR ANY AFFILIATE THEREOF, (2) INSIDE THE UNITED STATES TO A PERSON WHOM THE SELLER REASONABLY BELIEVES IS A QUALIFIED INSTITUTIONAL BUYER WITHIN THE MEANING OF RULE 144A UNDER THE SECURITIES ACT PURCHASING FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF A QUALIFIED INSTITUTIONAL BUYER IN A TRANSACTION MEETING THE REQUIREMENTS OF RULE 144A, (3) OUTSIDE THE UNITED STATES IN COMPLIANCE WITH RULE 903 OR RULE 904 UNDER THE SECURITIES ACT, (4) PURSUANT TO THE EXEMPTION FROM REGISTRATION PROVIDED BY RULE 144 UNDER THE SECURITIES ACT (IF AVAILABLE) OR (5) PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT, IN EACH CASE IN ACCORDANCE WITH ALL APPLICABLE SECURITIES LAWS OF THE STATES OF THE UNITED STATES AND ANY OTHER JURISDICTION; AND (C) IT AGREES THAT IT WILL DELIVER TO EACH PERSON TO WHOM THIS SECURITY IS TRANSFERRED A NOTICE SUBSTANTIALLY TO THE EFFECT OF THIS LEGEND. THIS SECURITY AND RELATED DOCUMENTATION (INCLUDING, WITHOUT LIMITATION, THE AGENCY AGREEMENT REFERRED TO HEREIN) MAY BE AMENDED OR SUPPLEMENTED FROM TIME TO TIME, WITHOUT THE CONSENT OF, BUT UPON NOTICE TO, THE HOLDERS OF SUCH SECURITIES SENT TO THEIR REGISTERED ADDRESSES, TO MODIFY THE RESTRICTIONS ON AND PROCEDURES FOR RESALES AND OTHER TRANSFERS OF THIS SECURITY TO REFLECT ANY CHANGE IN APPLICABLE LAW OR REGULATION (OR THE INTERPRETATION THEREOF) OR IN PRACTICES RELATING TO RESALES OR OTHER TRANSFERS OF RESTRICTED SECURITIES GENERALLY THE HOLDER OF THIS SECURITY SHALL BE DEEMED, BY ITS ACCEPTANCE OR PURCHASE HEREOF, TO HAVE AGREED TO ANY SUCH AMENDMENT OR SUPPLEMENT (EACH OF WHICH SHALL BE CONCLUSIVE AND BINDING ON THE HOLDER HEREOF AND ALL FUTURE HOLDERS OF THIS SECURITY AND ANY SECURITIES ISSUED IN EXCHANGE OR SUBSTITUTION THEREFOR, WHETHER OR NOT ANY NOTATION THEREOF IS MADE HEREON).”; (vii) if it is outside the United States and is not a U.S. person, that if it should resell or otherwise transfer the Notes prior to the expiration of the distribution compliance period (defined as 40 days after the later of the commencement of the offering and the closing date with respect to the original issuance of the Notes), it will do so only (a)(i) outside the United States in compliance with Rule 903 or 904 under the Securities Act or (ii) to a QIB in compliance with Rule 144A and (b) in accordance with all

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applicable U.S. State securities laws; and it acknowledges that the Regulation S Global Notes will bear a legend to the following effect unless otherwise agreed to by the Issuer: “THIS SECURITY HAS NOT BEEN AND WILL NOT BE REGISTERED UNDER THE U.S. SECURITIES ACT OF 1933 (THE “SECURITIES ACT”), OR ANY OTHER APPLICABLE U.S. STATE SECURITIES LAWS AND, ACCORDINGLY, MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES OR TO, OR FOR THE ACCOUNT OR BENEFIT OF, U.S. PERSONS EXCEPT IN ACCORDANCE WITH THE AGENCY AGREEMENT AND PURSUANT TO AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT OR PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT. THIS LEGEND SHALL CEASE TO APPLY UPON THE EXPIRY OF THE PERIOD OF 40 DAYS AFTER THE COMPLETION OF THE DISTRIBUTION OF ALL THE NOTES OF THE TRANCHE OF WHICH THIS NOTE FORMS PART”; and (viii) that the Issuer and others will rely upon the truth and accuracy of the foregoing acknowledgements, representations and agreements and agrees that if any of such acknowledgements, representations or agreements made by it are no longer accurate, it shall promptly notify the Issuer; and if it is acquiring any Notes as a fiduciary or agent for one or more accounts it represents that it has sole investment discretion with respect to each such account and that it has full power to make the foregoing acknowledgements, representations and agreements on behalf of each such account. Selling restrictions United States The Notes have not been and will not be registered under the Securities Act or the Securities laws of any State or other jurisdiction of the United States and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons except in certain transactions exempt from the registration requirements of the Securities Act. Terms used in this paragraph have the meanings given to them by Regulation S under the Securities Act. The Notes in bearer form are subject to U.S. tax law requirements and may not be offered, sold or delivered within the United States or its possessions or to a United States person, except in certain transactions permitted by U.S. Treasury Regulations. Terms used in this paragraph have the meanings given to them by the U.S. Internal Revenue Code of 1986 and the U.S. Treasury Regulations thereunder. In connection with any Notes which are offered or sold outside the United States in reliance on an exemption from the registration requirements of the Securities Act provided by Regulation S (“Regulation S Notes”), each Dealer has represented and agreed, and each further Dealer appointed under the Programme will be required to represent and agree, that it will not offer, sell or deliver such Regulation S Notes (i) as part of their distribution at any time or (ii) otherwise until 40 days after the completion of the distribution, as determined and certified by the relevant Dealer or, in the case of an issue of Notes on a syndicated basis, the relevant lead manager(s), of all Notes of the Tranche of which such Regulation S Notes are a part, within the United States or to, or for the account or benefit of, U.S. persons. Each Dealer has further agreed, and each further Dealer appointed under the Programme will be required to agree, that it will send to each dealer to which it sells any Regulation S Notes during the distribution compliance period a confirmation or other notice setting forth the restrictions on offers and sales of the Regulation S Notes within the United States or to, or for the account or benefit of, U.S. persons. Terms used in this paragraph have the meanings given to them by Regulation S under the Securities Act. Until 40 days after the commencement of the offering of any series of Notes, an offer or sale of such Notes within the United States by any dealer (whether or not participating in the offering) may violate the registration requirements of the Securities Act if such offer or sale is made otherwise than in accordance with an available exemption from registration under the Securities Act. Dealers may arrange for the resale of Notes to QIBs pursuant to Rule 144A and each such purchaser of Notes is hereby notified that the Dealers may be relying on the exemption from the registration requirements of the Securities Act provided by Rule 144A. To the extent that the Issuer is not subject to or does not comply with the reporting requirements of section 13 or 15(d) of the Exchange Act or the information furnishing

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requirements of Rule 12g3-2(b) thereunder, the Issuer has agreed to furnish to holders of Notes and to prospective purchasers designated by such holders, upon request, such information as may be required by Rule 144A(d)(4). This Base Prospectus does not constitute an offer to any person in the United States or to any U.S. person, other than any QIB to whom an offer has been made directly by one of the Dealers or its U.S. broker-dealer affiliate. Distribution of this Base Prospectus by any non-U.S. person outside the United States or by any QIB in the United States to any U.S. person or to any other person within the United States, other than any QIB and those persons, if any, retained to advise such non-U.S. person or QIB with respect thereto, is unauthorised and any disclosure without the prior written consent of the Issuer of any of its contents to any such U.S. person or other person within the United States, other than any QIB and those persons, if any, retained to advise such non-U.S. person or QIB, is prohibited. United Kingdom Each Dealer has represented, warranted and agreed and each further Dealer appointed under the Programme will be required to represent, warrant and agree that: (i) in relation to any Notes which have a maturity of less than one year, (a) it is a person whose ordinary activities involve it in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of its business and (b) it has not offered or sold and will not offer or sell any Notes other than to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or as agent) for the purposes of their businesses or who it is reasonable to expect will acquire, hold, manage or dispose of investments (as principal or agent) for the purposes of their businesses where the issue of the Notes would otherwise constitute a contravention of section 19 of the Financial Services and Markets Act 2000 (the “FSMA”) by the Issuer; (ii) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of the FSMA) received by it in connection with the issue or sale of any Notes in circumstances in which section 21(1) of the FSMA does not apply to the Issuer; and (iii) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to any Notes in, from or otherwise involving the United Kingdom. South Africa Each Dealer has severally represented, warranted and agreed, and each further Dealer appointed under the Programme will be required to represent, warrant and agree, that it will not offer or sell any Notes and/or solicit any offers for subscription for or sale of any of the Notes in South Africa other than on a reverse-solicitation basis and only on the basis that such offer or sale will not constitute an “offer to the public” as contemplated in section 95(1)(h) of the SA Companies Act. Accordingly, this Base Prospectus does not, nor does it intend to, constitute a “registered prospectus” (as that term is defined in section 95(1)(k) of the SA Companies Act) prepared and registered under the SA Companies Act, and accordingly no offer of Notes will be made or any Notes sold to any prospective investors in South Africa other than on a reverse-solicitation basis and pursuant to section 96(1) of the SA Companies Act and provided further that such offer or sale is in compliance with the Exchange Control Regulations and/or applicable laws and regulations of South Africa in force from time to time. General Each Dealer has represented, warranted and agreed and each further Dealer appointed under the Programme will be required to represent, warrant and agree that it will (to the best of its knowledge and belief) comply in all material respects with all applicable securities laws and regulations in force in any jurisdiction in which it purchases, offers, sells or delivers Notes or possesses or distributes this Base Prospectus and will obtain any consent, approval or permission required by it for the purchase, offer, sale or delivery by it of Notes under the laws and regulations in force in any jurisdiction to which it is subject or in which it makes such purchases,

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offers, sales or deliveries and neither the Issuer, the Trustee nor any of the other Dealers shall have any responsibility therefor. Certain of the Dealers have or may have, directly or indirectly through affiliates, provided investment and commercial banking, financial advisory and other services to the Issuer and its affiliates from time to time, for which they have received monetary compensation. Certain of the Dealers may from time to time also enter into swap and other derivative transactions with the Issuer and its affiliates. In particular, Deutsche Bank AG, London Branch or its affiliates has entered into cross-currency swap transactions and has engaged in lending transactions with the Issuer, its affiliates and counterparties in the ordinary course of business. In addition, certain of the Dealers and their affiliates may in the future engage in investment banking, commercial banking, financial or other advisory transactions with the Issuer and its affiliates. None of the Issuer, the Trustee and the Dealers represents that Notes may at any time lawfully be sold in compliance with any applicable registration or other requirements in any jurisdiction, or pursuant to any exemption available thereunder, or assumes any responsibility for facilitating such sale. With regard to each Tranche, the relevant Dealer will be required to comply with such other restrictions as the Issuer and the relevant Dealer shall agree and as shall be set out in the applicable Final Terms or relevant Drawdown Prospectus. These selling restrictions may be modified by the agreement of the Issuer and the Dealers following a change in a relevant law, regulation or directive. Any such modification will be set out in a supplement to this Base Prospectus.

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LEGAL MATTERS Certain legal matters in connection with the establishment of the Programme and the issuance of Notes thereunder will be passed upon for the Issuer by White & Case LLP, as to matters of United States federal law and English law. Certain legal matters will be passed upon for the Issuer in respect of South African law by Bowman Gilfillan Inc. and Ledwaba Mazwai Attorneys. Certain legal matters will be passed upon for the Arrangers and the Dealers as to United States federal law and English law by Allen & Overy LLP. Certain South African law matters will be passed upon for the Arrangers and the Dealers by ENSafrica and Poswa Inc.

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INDEPENDENT AUDITORS The financial statements of the Issuer as at 30 September 2014 and 2013, respectively, and for the six-month, periods then ended, which are incorporated by reference in this Base Prospectus, have been reviewed by SizweNtsalubaGobodo Inc. as stated in their review report appearing elsewhere in this Base Prospectus. The financial statements of the Issuer as at 31 March 2014, 31 March 2013 and 31 March 2012, respectively, and for the years then ended, which are incorporated by reference in this Base Prospectus, have been audited by KPMG Inc. and SizweNtsalubaGobodo Inc., independent auditors, as stated in their audit reports incorporated by reference in this Base Prospectus. KPMG Inc. and SizweNtsalubaGobodo Inc. are Chartered Accountants and members of the South African Institute of Chartered Accountants. The Auditors do not have any material interest in the Issuer.

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GENERAL INFORMATION Authorisation The establishment of the Programme was duly authorised by a resolution of the Board of Directors of the Issuer dated 13 February 2013. The update of the Programme was duly authorised at a meeting of the Board of Directors of the Issuer held on 17 February 2014. Listing of Notes The admission of Notes to the Official List will be expressed as a percentage of their nominal amount (excluding accrued interest). It is expected that each Tranche of Notes which is to be admitted to the Official List and to trading on the Market will be admitted separately as and when issued, subject only to the issue of a Global Note or Notes initially representing the Notes of such Tranche. Application has been made for Notes issued under the Programme to be admitted to the Official List and to be admitted to trading on the Market. Documents available For as long as the Programme remains in effect or any Notes shall be outstanding, copies of the following documents will, when published, be available for inspection at the Issuer’s registered office and from the specified office of the Principal Paying Agent for the time being in London, namely: (i) the constitutional documents of the Issuer and a copy of the Eskom Conversion Act, 2001; (ii) the consolidated reviewed interim financial statements of the Issuer in respect of the six months ended 30 September 2014 and 30 September 2013, respectively, together with the review report prepared in connection therewith; (iii) the consolidated audited annual financial statements of the Issuer in respect of the financial years ended 31 March 2014, 31 March 2013 and 31 March 2012, respectively, together with the audit reports prepared in connection therewith; (iv) the Trust Deed, the Agency Agreement and the forms of the Global Notes, the Notes in definitive form, the Coupons and the Talons; (v) this Base Prospectus; (vi) any future Base Prospectus, Drawdown Prospectus, prospectuses, information memoranda and supplements including Final Terms (save that the Final Terms or Drawdown Prospectus relating to a Note which is neither admitted to trading on a regulated market in the European Economic Area nor offered in the European Economic Area in circumstances where a prospectus is required to be published under the Prospectus Directive will only be available for inspection by a holder of such Note and such holder must produce evidence satisfactory to the Issuer and the Paying Agent as to its holding of Notes and identity) to this Base Prospectus; and (vii) in the case of each issue of Notes admitted to trading on the Market subscribed pursuant to a subscription agreement, the subscription agreement (or equivalent document). Clearing systems The Notes have been accepted for clearance through Euroclear and Clearstream, Luxembourg. The appropriate Common Code and ISIN for each Tranche of Notes allocated by Euroclear and Clearstream, Luxembourg will be specified in the applicable Final Terms or relevant Drawdown Prospectus. In addition, the Issuer may make an application for any Notes in registered form to be accepted for trading in book entry form by DTC. The CUSIP number for each Tranche of such Registered Notes, together with the relevant ISIN and (if applicable) Common Code, will be specified in the applicable Final Terms or relevant Drawdown Prospectus. If the Notes are to clear through an additional or alternative clearing system the appropriate information will be specified in the applicable Final Terms or relevant Drawdown Prospectus.

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The address of Euroclear is Euroclear Bank SA/NV, 1 Boulevard du Roi Albert II, B 1210 Brussels. The address of Clearstream, Luxembourg is Clearstream Banking, 42 Avenue JF Kennedy, L-1855 Luxembourg. The address of DTC is 55 Water Street, New York, New York 10041, United States of America. Conditions for determining price The price and amount of Notes to be issued under the Programme will be determined by the Issuer and the relevant Dealer at the time of issue in accordance with prevailing market conditions. Material contracts Neither the Issuer nor any member of the Group has entered into any material contract, other than in the ordinary course of business during the three years immediately preceding the date of this Base Prospectus. Significant or material change There has been no significant change in the financial or trading position of the Issuer, or the Group since 30 September 2014 and there has been no material adverse change in the financial position or prospects of the Issuer or the Group since 31 March 2014. Litigation Neither the Issuer nor any other member of the Group is or has been involved in any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Issuer is aware) in the 12 months preceding the date of this document which may have or have in such period had a significant effect on the financial position or profitability of the Issuer or the Group. Third Party Information Where information in this Base Prospectus has been sourced from third parties, this information has been accurately reproduced and, as far as the Issuer is aware and is able to ascertain from the information published by such third parties, no facts have been omitted which would render the reproduced information inaccurate or misleading. The source of third party information is identified where used. Interests of natural and legal persons involved in the offer Save for any fees payable to the Arrangers and the Dealers, so far as the Issuer is aware, no person involved in the issue of the Notes has an interest material to the offer. Dealers transacting with the Issuer Certain of the Dealers and their affiliates have engaged, and may in the future engage, in investment banking and/or commercial banking transactions with, and may perform services to the Issuer in the ordinary course of business. Certificates Any certificate of the Auditors or any other person called for by or provided to the Trustee (whether or not addressed to the Trustee) in accordance with or for the purposes of the Trust Deed may be relied upon by the Trustee as sufficient evidence of the facts set out therein notwithstanding that such certificate or report or any engagement letter or other document entered into by the Trustee in connection therewith contains a monetary or other limit on the liability of the Auditors or such other person in respect thereof and notwithstanding that the scope or basis of such certificate or report may be limited by any engagement or similar letter or by the terms of the certificate or report itself.

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ISSUER Eskom Holdings SOC Ltd Megawatt Park 2 Maxwell Drive Sunninghill Sandton 2157 South Africa TRUSTEE Citicorp Trustee Company Limited Citigroup Centre Canada Square Canary Wharf London E14 5LB United Kingdom PRINCIPAL PAYING AGENT, TRANSFER AGENT AND CALCULATION AGENT Citibank N.A., London Branch Citigroup Centre Canada Square Canary Wharf London E14 5LB United Kingdom REGISTRAR Citigroup Global Markets Deutschland AG Reuterweg 16 60323 Frankfurt Germany LISTING AGENT Banque Internationale À Luxembourg SA 69 route d’Esch L – 2953, Luxembourg

LEGAL ADVISERS To the Issuer as to English and U.S. law To the Issuer as to South African law White & Case LLP Ledwaba Mazwai Bowman Gilfillan Inc. 5 Old Broad Street Attorneys 165 West Street London EC2N 1DW 141 Boshoff Street Sandton 2146 United Kingdom Pretoria South Africa South Africa To the Arrangers, Dealers and the Trustee as to To the Arrangers and Dealers as to South African English and U.S. law law

Allen & Overy LLP ENSafrica Poswa Inc. One Bishops Square 1 North Wharf Square Gauteng Office London E1 6AD 1 Loop Street 1st Floor, Block A United Kingdom Cape Town Sandton Close 2 8001 Cnr 5th Street & Norwich South Africa Close Sandton Johannesburg South Africa AUDITOR To the Issuer SizweNtsalubaGobodo Inc. 20 Morris Street East Woodmead 2191 South Africa ARRANGERS AND PERMANENT DEALERS

Africa Rising Capital Proprietary Limited Basis Points Capital Proprietary Limited 85 Protea Road 1st Floor, Deutsche Bank Building Kingsley Office Park 87 Maude Street Chislehurston Sandton Sandton 2196 2196 South Africa South Africa

Deutsche Bank AG, London Branch Pamoja Capital Proprietary Limited Winchester House 10th Floor 1 Great Winchester Street The Forum Building London EC2N 2DB 2 Maude Street United Kingdom Sandton 2146 South Africa

Rand Merchant Bank, a division of FirstRand The Standard Bank of South Africa Limited Bank Limited (London Branch) 3rd Floor, East Wing Austin Friars House 30 Baker Street 2-6 Austin Friars Rosebank London EC2N 2HD Johannesburg United Kingdom 2196 South Africa