Eskom MYPD4 Revenue Application Focus on Coal and Independent Power Producer Costs Nersa Public Hearings Durban 17 January 219
The MYPD methodology through the allowable revenue formula was applied AR= (RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA Primary Energy (incl imports and DMP) IPPs Operating expenditure (incl R &D) Integrated Demand Management Depreciation Return on Assets Tax & Levies Revenue + + + + + + = Return on assets = % cost of capital allowed X depreciated replacement asset value 1
Eskom allowed revenue application for 3 year period is R763 billion Allowable Revenue (R'million) AR Formula Application 219/2 Application 22/21 Application 221/22 Regulated Asset Base (RAB) RAB 1 268 31 1 336 12 1 41 56 WACC % ROA X -1.32% -.21% 1.45% Returns -16 687-2 765 2 314 Expenditure E + 56 619 59 82 62 663 Primary energy PE + 73 386 75 876 79 561 IPPs (local) PE + 29 59 34 324 41 2 International purchases PE + 3 533 3 734 3 957 Depreciation D + 64 651 72 919 75 649 IDM I + 189 193 22 Research & Development R&D + 176 187 198 Levies & Taxes L&T + 8 272 8 198 8 147 RCA RCA + Total R'm 219 73 252 485 291 692 Corporate Social Investment (CSI) - - 192-193 - 151 Total Allowable Revenue 219 537 252 292 291 542
PRIMARY ENERGY COAL COSTS
Eskom is navigating a dynamic coal environment with many challenges to manage Coal supply shortfall at several power stations with long term contracts coming to an end Cost of mining coal consistently increasing above inflation and export prices influence on the domestic market Competition by the export market for Eskom grade coal within the 42-55kcal range Lack of new mining investment in large scale coal mines and execution of current mining rights Flexibility in coal procurement to match older power stations production ramp down Increased pressure from local communities for localization of Eskom goods and services procurement Growing Renewable Energy sector disrupting Eskom s business model and no demand growth Investors and Funders migration away from coal technology. Signal - disinvestment in the South African coal industry by multinationals
Within this environment - Eskom has three primary objectives Optimal cost of coal Contribute to the lowest cost per MWh sent-out for Eskom by delivering pit to boiler optimal coal costs Security of coal supply Meet volume requirements with a safety margin above coal demand to enhance flexibility in absorbing burn variance Support transformation in coal procurement spend Eskom will continue to support transformation of its coal procurement spend in line with the Mining Charter and implemented through compliance to the Preferential Procurement Policy Framework Act and Broad-Based Black Economic Empowerment Act 5
6 Critical success factors for objectives to be met include The NERSA tariff determination based on market cost of mining and coal prices Availability of capital funding for investment in cost plus mines Eskom s ability to send a strong signal to procure coal on a long term basis to achieve prices projected in the application Policy and legislation certainty to stimulate investment in new coal mines
Cost of coal burn to generate electricity over FY2 FY22 period is projected to be R198.5bn (Rbn) 64 +1% 66 69 Demand as per 11 year supply plan Insights 45 47 52 The difference in volumes between coal purchases and coal burn in: FY17 FY18 FY19* FY2 FY21 FY22 FY19: Due to contractual volumes at Lethabo & Medupi exceeding burn requirements Building stock at individual power stations Coal burn volumes (Mt) 113.74 115.49 112.93 116.16 113.81 113.54 Coal purchases volumes (Mt) 12.25 115.25 12.44 118.44 116.7 116.18 FY2 FY22: Primarily due to contractual coal volumes at Lethabo & Medupi Power Stations being higher than the burn requirement * FY19 YE projection as at end Nov 218
Eskom needs to secure up to 1318 Mt of coal in long term, (if no Cost Plus investments are made) and 195 Mt should investments in Cost Plus mines are possible and made 2 15 1 5 95 9 85 8 75 7 65 6 55 5 45 4 35 3 25 2 15 1 5 Secured Supply WITH Cost-plus CAPEX Mtpa Additional 223Mt secured through cost plus investments Shortfall Cost plus with investment Cost plus Medium term Fixed price Shortfall reduces from 1 318 to 1 95 Mt with cost plus mine investments 22 225 23 235 24 245 25 Secured contracts fixed and cost plus For foreseeable future Eskom is largely contracted at: Matimba - fixed price Medupi - fixed price Duvha - fixed price Lethabo (New Vaal) will require investment & extension Demand Shortfall as with per cost 11 year plus supply investments plan as per draft IRP 195Mt Eskom needs to procure coal by: Providing long term large volume RFP s to the market, to trigger long term contracts with mines and investments into coal mining Revitalising and continuing investment in cost-plus mines Managing flexibility of demand will be done through Medium term contracts. These contracts may be at market related prices, however it provides flexibility for Eskom to navigate risks involved
In 218, Eskom has secured 91.8Mt of additional coal to be supplied over a number of years Percentage contribution of contracted coal vs. requirement 1 1 1 1 1 2% 4% 18% 18% 26% 29% 4% Demand as per 11 year supply plan Insights Coal requirement compared to that contracted will always fluctuate depending on a number of factors including: Electricity demand and outlook. 98% 78% 76% 71% 68% Demand forecast per power station and variations to that demand on a daily, weekly, monthly and any other periodic basis. Performance of contracted coal suppliers. Realization of projected coal purchases that are not yet contracted at time of presentation 22 221 222 223 224 Uncontracted Flexibility Pipeline Secured 9
Recovery base plan and projection up to March 22 Base plan is official recovery plan and tracked on a weekly basis. KEY INSIGHTS Actual stock days end Dec 27.5 days vs base plan of 21.8 due to new contracts accelerated delivery and lower burn from (Gx plant performance) Based on high confidence new contracts, forecast to end F219 at 32 days (5 stations below 2 days but none below 1 days) All power stations recover to expected levels between Sep 219 and Mar 22 1
1 power stations are currently below prescribed minimum stock days Coal fleet stock levels on 13 January 219 Power station Arnot Camden Duvha Grootvlei Hendrina Kendal Komati Kriel Kusile Lethabo Majuba Matla Matimba Medupi Tutuka Minimum Alarm Expected Recovery Date 26 3 35 Dec 219 2 2 25 Oct 219 22 26 3 Mar 22 2 23 25 Feb 22 2 25 3 Feb 22 25 3 35 Sep 219 7 7 11 Sep 219 32 38 44 Mar 22 25 3 35 N/A 24 27 3 N/A 4 45 5 Nov 219 27 31 35 Dec 219 2 24 28 N/A 2 24 28 N/A 32 36 4 Nov 219 Below Minimum level Above minimum level Total System* 26 3 37 1 Power Stations are below the prescribed Minimum level 5 stations (viz Arnot, Camden, Hendrina, Kriel and Matla) are below 1 days Total stock excluding Medupi and Kusile = 27.3 days * Total System excludes Medupi and Kusile 11
SA s historic bituminous coal production = local + export sales. (No surplus availability) 3 25 2 15 1 5 Sales vs Production of bituminous coal (Mt) 223 222 219 238 242 243 245 245 251 249 255 248 256 253 258 249 248 71 68 71 68 67 69 69 69 59 6 66 75 68 73 73 74 72 182 154 157 168 178 173 176 182 196 184 185 177 184 181 177 18 152 2 21 22 23 24 25 26 27 28 29 21 211 212 213 214 215 216 Comments No surplus coal in system. All bituminous coal produced is either sold locally or exported. Production in 216 is almost the same as in 26, but export volume is higher This is after five years of confusion, after five years of the mining moratorium because no one was going to invest... Sikonathi Mantshantsha, deputy editor at Financial Mail, on intention to revoke MPRDA amendment bill. Exports facilitated by increasing Transnet rail capacity to RBCT. Production Export sales Local sales Eskom purchases Eskom burn South African Coal Roadmap steering committee chairperson Ian Hall: Burn vs Purchases (Mt) 113 15 92 93 11 89 7 1 1 2 3 31 28 29 3 133 12 124 122 12 112 117 122 126 126 122 119 115 38 16 2 26 31 37 4 45 44 44 46 45 44 31 31 31 3 3 3 31 29 28 31 33 33 31 62 59 6 68 71 65 67 63 65 6 6 53 52 5 47 4 42 41 FY FY1 FY2 FY3 FY4 FY6 FY7 FY8 FY9 FY1 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 From 213 to 219, 12-million tons of new capacity need(ed)to come on stream. This did not occur The current coal supplies to State electricity utility Eskom will decline rapidly after 215, when existing large-scale mines' suppliers reach the end of their lives and require (expansion) recapitalisation. ST/MT Source: SAMI; Eskom PED FP CP Burn SA s exports expanded from India & China to include The Netherlands, Italy, Morocco, Egypt & Senegal.
Furthermore, bulk of export grade coal competes with Eskom s boiler specifications South African thermal coal exports from all ports Million ton >6,2 kcal/kg, NAR 5,-5,6 kcal/kg, NAR 5,6-6,2 kcal/kg, NAR 4,2-5, kcal/kg, NAR <4,2 kcal/kg, NAR Eskom Grade Coal 78 2 52 18 6 215 76 2 39 25 1 216 82 8 79 78 77 2 2 2 2 2 26 25 24 24 23 35 36 36 35 34 18 17 17 17 17 217 218 219 22 221 Minerals Council of SA (nee Chamber of Mines) Coal Strategy 218, forecasts that India s coal demand will continue to increase in the foreseeable future, best case will be that exports remain constant Investment capital may also not be available in the future, as financing for coal based energy is reducing, thus coal mining investment is uncertain which will further constrain coal supply as Eskom will be competing against the export market for this limited supply Eskom must guard itself in this limited supply environment by signing long term coal supply agreements which will ensure security of coal supply and hedge against price fluctuations Source: IHS Markit
Eskom faces a coal supply shortfall, however has a plan to remedy the problem on long term basis Causes of coal supply shortages Long term coal strategy pillars Unsuccessful negotiations to extend Arnot Power Station tied colliery coal supply agreement Kusile long term tied colliery coal contracts did not materialize (makes up the bulk of the 1 318Mt shortfall) Contract negotiations to extend the Hendrina tied colliery coal contract discontinued Lack of capital investment in the at four of the five cost plus mines resulting in reduced production mines producing at 68% of contractual Limited investment in RSA in opening new large scale mines Increased export volume of Eskom grade coal Extension of cost plus mines for total reserves to match power stations life. Investment in cost plus mines to access remaining reserves for contractual volumes Extension of the tied long term fixed price collieries Expansion of domestic rail infrastructure for Eskom by Transnet Coal open tenders to source coal for the remaining life of power stations
It is critical for Eskom to recapitalise cost plus mines to stem the production decline R bn CP production (Mtons) Reinvestment in mines Reinvestment in equip Beneficiation Water treatment Logistics Other R5.65bn 2,58 3,93 Investment No investment 34,63 34,35 1,93 6,65 38,33 8,13 36,85 8,55 35,43 9,34 2,13 3,79 1,23,88,94 2,1 2,43 1,31,8 32,7 27,7 3,2 28,3 26,9,19,11 FY17,8,26,16 FY18,7,18 FY19,12,5,92,2 FY2,12 FY21,1 FY22,5,5,8 FY23,43,8 FY24 FY2 FY21 FY22 FY23 FY24 With investment in CP mines, an additional 34.6 Mt is forecast over FY2 FY24 More than 9% of capital expenditure over FY2 FY22 is for reinvestment in the cost plus mines. Investing in cost plus mines is integral to Eskom s long term coal strategy. Investment in cost plus mines and extension of cost plus agreements is required to secure coal volume. Steady state coal supply and costs is anticipated from about FY23/24 based on investments taking place as planned Impact of not investing in cost plus mines will result in further reduction in coal from these mines and an increase in expenditure on short/medium term coal.
and manage increases in cost of coal burnt to generate electricity RSA has experienced limited investment in new coal mines, especially new large mines. Eskom has been increasingly competing for coal with other buyers, especially seaborne. Annual increases in coal R/ton cost have been impacted by lower production at cost plus mines and increasing costs of replacement coal due to associated transport costs. Eskom intends to: Increase or contract coal from suppliers closest to the Eskom Power Stations Invest in Cost Plus mines Secure long term coal contracts through life of Power Station open tenders Procure coal through transparent coal procurement mechanisms in line with Preferential Procurement Policy Framework Act regulations. Seek and strive to manage coal cost increases over MYPD application periods estimated at less than 1% per annum on a CAGR basis
Independent Power Producer Costs
Policy implementation Regulations for New Generation Capacity Integrated Resource Plan Developed By DoE DoE Accountable Approved IRP Cabinet Approval Gazetted Minister of Energy Determination Minster of Energy, with Minister of Finance IPP Eskom Eskom procure or build Eskom responsible for ownership, engineering, procurement and construction Procurement (bid evaluation, negotiating PPAs) Procurer- DoE, Buyer - Eskom 219/1/17 18
Principles of Section 34 procurement In Terms of Regulations of Electricity Regulation Act (ERA), Minister of Energy makes a determination that Eskom be buyer of energy from IPP s Before signing a Power Purchase Agreement (PPA), the Regulations also require Eskom to ensure that it meets requirement for value for money and also ensure PPA meets requirements of Electricity Regulation Act, Public Finance Management Act, Companies Act and all applicable legislation before signing in line with Board s fiduciary duties When Eskom makes an MYPD revenue application, Eskom estimates future costs of actual purchases of power from IPPs as well as administration costs (employee benefits, depreciation, travel and subsistence, legal costs, office costs). NERSA assesses costs as forecasted by Eskom for future period covered by the particular MYPD revenue application, and if NERSA deems it appropriate it will substitute a different assumption regarding these future costs, for the purpose of its revenue determination. IPP costs are included in the revenue allowance made to Eskom and are subsequently included in the calculations of the Eskom tariffs to customers. Therefore, Eskom recovers these costs through revenue when customers pay Eskom, same as for Eskom s other costs. After the end of the financial year, when Eskom submits the Regulatory Clearance Account (RCA) application, a comparison is made of the assumed costs as included in the MYPD revenue determination versus the actual costs incurred i.e. payments to IPPs for the year, to determine if there was an over recovery or under recovery Eskom will be refunded (by virtue of an add-on to future allowed revenues thus tariffs) for an under recovery and for an over recovery Eskom will have a reduction of the RCA amount (thus a deduction from future allowed
Primary energy indicates an increasing trend in IPPs and decreasing trend in coal AR= (RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA 114,781 9% 122,131 132,667 Generation own primary energy costs have a compounded average growth rate (CAGR) of 6.4% per annum from 218/19 to 221/22 62% 6% 58% Non-Eskom primary energy costs reflect a CAGR of 14.8% per annum between 218/19 to 221/22. Of this, local IPPs have a CAGR of 15.6%. 26% 28% 31% 1% 1% 1% 7% 7% 6% % 1% 3% 1% 3% % 1% 3% % FY219/2 FY22/21 FY221/22 Coal Environmental levy Nuclear DMP IPPs International purchases OCGT Total primary energy reflects a CAGR of 9.% per annum between 218/19 to 221/22 Coal burn costs reflect a CAGR over the period of 7.8% per annum 2
IPP portfolio mix assumptions energy GWh 2. 15. 1. 5. DoE Peakers Renewables STPPP/MTPPP 67 15 7.228 9.479 4.235 216/17 217/18 169 11.282 218/19 88 12.1 219/2 88 14.947 22/21 88 18.577 221/22 Assumptions on IPP portfolio mix for MYPD4: DOE Peaker projects contractual assumptions REIPP - five bid windows (bid window 1, 2, 3, 3.5, 4) No short-term Eskom programmes 21
IPP portfolio mix assumptions costs 45. 4. 35. 3. 25. 2. 15. 1. R million DOE Peakers Renewables STPPP/MTPPP 2.186 15.582 2.291 19.8 2.648 23.79 2.422 26.928 2.463 31.67 2.513 38.22 IPP portfolio mix Assumptions for MYPD 4 DOE Peaker projects contractual assumptions REIPP - Signed (BW 1, 2, 3, 3.5 and 4) using PPA prices &expected energy 5. 3.952 216/17 217/18 218/19 219/2 22/21 221/22 No short-term Eskom programmes 22
IPP programme details Renewable IPP programme Five bid windows (bid window 1, 2, 3, 3.5, 4) concluded. Costs for BW 1 through 4 are based on finalised power purchase agreements (PPAs) Costs associated with the Small Renewable IPP programme are not included in this application DoE Peaker The Peaker programme has been fully operational from 2 July 216 with capacity of 1 5 MW. These power stations are compensated for available capacity on system and energy produced. They are fully dispatched by System Operator. Expected load factor of 2 stations is 1%, leading to an expected energy output of 88 GWh per year. Co-generation One contract was announced under the Co-generation programme but has never been finalised. Co-generation costs are not included in this application. Base-load Coal Two preferred bidders were announced under the Coal programme but these contracts have not been finalised. Costs associated with the Coal programme are not included in this application. Wholesale Electricity Pricing System (WEPS) programme The application does not include any allowance for Eskom short term programmes. 23
Renewable energy determinations Minister of Energy designates RE for IPPs; Eskom is Buyer Renewable Energy Independent Power Producer Procurement Programme (REIPP) 1st determination 211 (3725 MW) 2nd determination 212 (+ 32 MW) 3rd determination 215 (+ 63 MW) IRP 21 capacities and status of determinations to allocate them for implementation Operational Contracted Approved Announced TOTAL 8 127 635 635 3876 BW1 1425 1424 1424 1415 BW2 14 141 141 133 BW3 1457 1435 1435 1428 BW3.5 2 2 2 BW4, 4.5 225 225 225 BW 5 18 Smalls 1 49 211 determinations Eskom commitments (pre IRP) 212 determinations 215 determinations 24
Average energy price (R/MWh, 218 ZAR) IPP procurement prices Steady decline in Wind and PV costs CSP PV Wind 4 5 4 3 5 3 971 4 64 3 97 3 588 3 2 5 2 46 2 1 5 1 72 1 322 1 1 373 995 5 979 825 - BW1 BW 2 BW 3 BW 4 Source: SBO estimated payment in April 223 (when all operating), adjusted to 218 ZAR. Some BW 2 and BW 3 projects have partial indexation (leading to over-estimation of cost relative to others not using partial indexation). CSP average prices reflect expected generation over peak which carries substantial price premium. 219/1/17 25
Renewable Portfolio (for FY 221/22) Expected energy output (GWh) Technology BW1 BW2 BW 3 + 3.5 BW 4 Total Wind 1 973.4 1 741.93 2 83.8 3 96.96 1 48.1 Solar PV 1 324.57 988.7 959.56 2 133.1 5 45.93 CSP 52.28 232.94 1 584.73. 2 319.95 Other. 93.8 53.64 224.51 371.24 Total 3 8.26 3 56.66 5 41.74 6 318.57 18 577.22 Average price (R/MWh) (218 ZAR) Technology BW1 BW2 BW 3 + 3.5 BW 4 Total Wind 1 72.17 1 373.8 978.68 825.29 1 122.5 Solar PV 3 97.8 2 459.71 1 321.57 995.4 2 5.14 CSP 4 63.84 3 97.45 3 588.33-3 723.32 Other - 1 47.59 1 289.53 1 777.53 1 63.5 Total 2 85.4 1 92.67 1 88.28 916.55 1 727.37 Note: Impact of additional CSP (2 MW) from BW 3.5 counters the price reduction in PV and Wind from BW 2 to BW 3 Additional cost of BW 4 at 91,7c/kWh (not R2.22/kWh mentioned in media) 26
Annual PPA cost (Rm, 218 ZAR) Average REIPPP price (R/kWh, 218 ZAR) REIPPP Bid Window Costs (Real) 35, 3 3, 2,5 25, 2 2, 1,5 15, 1, 1 5,,5 - BW 4+ BW4 BW3.5 BW3 BW2 BW1 Avg price (rhs) 27
Trends in IPP revenue increase (nominal) CAGR increase of 15.6% over MYPD 4 application period
Capacity factor (%) Seasonal output patterns - REIPPP 6 REIPP Monthly Capacity Factor 5 4 3 2 1 CSP Wind PV Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 29
Average REIPPP prices per technology 3
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