Eskom 2018/19 Revenue Application

Transcription

1 Eskom 2018/19 Revenue Application Nersa Public Hearings Klerksdorp 13 November 2017

2 Where we are coming from This revenue application is being made for the year 2018/19, after the Energy Regulator maintained its revenue decision made in 2013 for the 2017/18 year, where it approved total allowable revenue of R205 billion. The allowed revenue resulted in an average increase of 2.2% due to base adjustments made in preceding years following approved RCA balances for Eskom (12.69% for 2015/16 for MYPD2 and 9.4% for 2016/17 for first year of MYPD3). The 2.2% average increase resulted in consumers receiving an effective decrease in electricity prices, in a situation where costs to produce electricity are increasing. Eskom, in this revenue application for the 2018/19 year has applied the NERSA MYPD methodology of 2016, with a phasing-in of return on assets being applied Allowed revenue and price adjustments decisions will be applicable from 1 April 2018 This revenue application does not include any RCA applications for the MYPD 3 period. Eskom understands that NERSA will process RCAs for years 2, 3 and 4 of the MYPD 3 period at a later stage. The adjustments will be applicable from 1 April 2019 onwards in a phased manner 1

3 Eskom s revenue application is completed within the legislative and NERSA s regulatory framework Framework Electricity Pricing Policy (EPP) Electricity Regulation Act (ERA) Municipal Finance Management Act (MFMA) Multi-Year Price Determination (MYPD) Methodology Eskom Retail Tariff & Structural Adjustment (ERTSA) Methodology Requirements Provides guidelines to NERSA in approving prices and tariffs for the electricity supply industry Enable an efficient licensee to recover full cost of its licensed activities, including a reasonable margin Avoid undue discrimination between customer categories May permit cross subsidy of tariffs Only implement tariffs determined by NERSA Eskom consults with SALGA & National Treasury prior to submission to NERSA Municipal tariffs tabled in Parliament by 15 Mar for 1 July implementation Determines allowable revenue (AR) for efficient costs and fair return where AR = (RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA RCA not included in this revenue application Allows for NERSA determined allowed revenue to be recovered by the assumed volume of sales for each year of the revenue period. Determines rate adjustments to tariffs applicable to customer groups and schedule of standard prices applicable to different Eskom tariffs Notes: Regulatory asset base (RAB); Primary energy (PE); Service Quality incentives (SQI); Expenditure (E); Levies & Taxes (L&T); Research & Development (R&D); Weighted Average Cost of Capital (WACC); Integrated Demand Management (IDM); Regulatory Clearing Account (RCA) 2

4 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 3

5 Based on the MYPD Methodology the total allowable revenue is R219.5 billion for FY2018/19 Allowable Revenue (AR) Fx Application FY2018/19 (R m) Regulated Asset Base WACC (%) Returns RAB ROA % Absolute Revenue increase of R14.3 bn (7%) from previous Nersa decision Expenditure Primary energy IPPs (local) E PE PE Standard tariff customers contribute to 3.6% increase in allowed revenue International purchases Depreciation IDM Research & development Levies and taxes RCA PE D I R&D L&T RCA Export and NPA revenues account for 3.4% increase in allowed revenue About 15% of allowed revenue related to IPP costs Total Allowable Revenue

6 Rand billions Application of the NERSA Allowable Revenue formula indicates a revenue growth of R14.3 billion R13.2b R1.0b R2.8b R0b R11.2b -R12b -R1.8b R219.5 R205.2b Revenue requirement grows by R14.3 bn MYPD3 Revenue 2017/18 IPPs Operating Cost Primary Energy International Purchases Depreciation Returns Evironmental levy Total Allowable Revenue 2018/19 Increases in allowed revenue when compared to MYPD 3 (2017/18) decision mainly due to: Increases in IPP costs due to additional IPP programmes; marginal increase in other PE costs Increases in operating costs (compared to previous MYPD decision close to inflation increases for actuals Change in MYPD methodology in treatment of cost of imports (with concomitant increase in import revenue) Decrease in allowed revenue when compared to MYPD 3(2017/18) decision mainly due to : Further sacrifice in return on assets Decrease in environmental levy due to lower energy sent out 5

7 Electricity price impact in 2018/19 Standard tariff revenue has increased by R7 251 million which equates to revenue increase of 3.6% from NERSA s decision for the 2017/18 year. As the revenue is recouped from a lower sales volume, the overall price increase required is 19.9% for 2018/19. The 19.9% average increase translates to a 1 July 2018 local-authority tariff increase of 27.5% to municipalities. Municipalities continue to pay at the 2017/18 rates for the period 1 April 2018 to 30 June This is due to the Municipal Finance Management Act (MFMA) requiring Municipal tariff changes to be made only from 1 July each year. Standard tariff Unit 2017/ /19 Standard tariff revenue R m Standard tariff sales volumes Standard tariff price GWh c/kwh Standard tariff price adjustment % 2.2% % 6

8 Price Impact % Factors influencing the overall price increase 7.0% 0.5% 23.8% -6.0% 5.5% 1.4% 16.3% 2.1% 19.9% 9.4% Adjustments Operating costs Depr, Returns, SPAs & Exports Sales volumes rebasing IPPs International Purchases Price before operating costs changes Opex Generation own PE costs Price after operating costs Depr & Returns SPAs & Exports Overall Price Increase With average 2.2% increase in 2017/18 and 19.9% proposed average increase in 2018/19 Average for two years is 11% 7

9 Conservative assumption have been used for RAB, migration of ROA towards WACC, and depreciation AR= (RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA Regulatory Asset Base (R m) Return on Assets (R m) Depreciation (R m) Assets Ave RAB Generation Working capital & WUC Return on Assets (ROA) 8.4% Transmission Eskom RAB Returns Distribution Generation Phased in ROA 2.97% Total Depreciation Transmission Phased in Returns Distribution Returns sacrificed Opening RAB balance for FY2019 is based on the MYPD 3 decision which is then adjusted for the latest capital expenditure forecasts for the period FY2014 to FY2018. Eskom will revalue the RAB for subsequent revenue application in accordance with Nersa condonation decision MYPD methodology allows for ROA as proxy for interest costs, tax and equity return to the shareholder In accordance with Nersa decision migration of ROA towards full WACC is phased over a longer period. NERSA MYPD 3 decision of 4,7% for FY2017/18 is reduced to 2.97% for FY2018/19 revenue application. In accordance with the MYPD methodology, depreciation is computed by dividing RAB over remaining life of respective assets. Therefore depreciation amounts have remained relatively similar to 2017/18 as a similar RAB value is used for the FY2018/19 revenue application 8

10 Rand millions Primary Energy costs assumptions AR= (RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA Environmental Levy International Purchases / / /19 IPPs Other Eskom PE OCGT Fuel Cost Coal 9

11 Further in- depth details to be shared at this public hearing System Operations Operating Costs 10

12 System Operator is in Process of Implementing Scheduling and Dispatch Rules (SDR) The process starts with the day-ahead hourly demand forecast: Key factors are historical seasonal demand profile, weather patterns, day of the week, public and school holidays, labor unrest etc. Renewable energy (as forecasted) is regarded as negative load, residual load is the net day-ahead forecast to be supplied by conventional generators. In terms of the SDR, thermal and hydro power plants are then optimized and dispatched based on economic merit order of each unit s marginal cost of production, while considering system security Emergency resources such as ILS and gas turbines are scheduled by the SO to manage system emergencies and in line with other contractual obligations Ancillary services reserves (currently about 2000MW) are also co-optimised in order to minimize the total cost of production Night minimum load is managed through Mingen, Pumping and Curtailments 11

13 Day-Ahead Generation Scheduling Process Cost of generation Unconstrained schedule (Cheapest mix) Constrained schedule Day ahead contract Demand forecast Operating reserve requirement Network constraints Renewable Forecast

14 Reliability of Solar PV and Wind have an impact on generation dispatch PV Wind 13

15 Seasonal Load profile Outages are planned around the peak demand The summer load profile is a lot flatter than the winter profile In winter there is a higher probability of problems over the peak periods Peaking plant is required for many more hours during the day in summer than in winter due to the high maintenance of base load units during the summer months and the flat load

16 Meeting the demand on a typical day The bulk of the demand is met by base load coal, nuclear and imports via HVDC OCGTs and Pumped Storage plants are mainly required to manage peak demand The renewable generators are starting to make a substantial contribution, peaking at just under 2500 MW (sent out) during 2017 (so far). Unfortunately Solar PV disappears as we start climbing the evening peak Coal and hydro are the main providers of flexibility at present

17 Highest difference between peak demand and night minimum during winter 2017 Monday 15 May Actual Demand The difference between minimum and peak demand was over MW The above graph illustrates the difference between the minimum and peak demand that needs to be supplied by dispatchable plant Thermal plant will be reduced to minimum stable region to avoid shutting them down Pumping, two shifting and (on rare occasions) curtailment will be implemented to manage night minimum 16

18 Emergency merit order deployment MCR, all units to maximum continuous rated output Emergency Level 1, some units exceed MCR for short duration Virtual Power Station, customers paid to reduce The merit order varies depending on magnitude and Anticipated duration of the emergency Request mutual assistance from other power companies Withdraw non-firm exports Dispatch Open Cycle Gas Turbines (diesel) Dispatch Gas Turbines Use emergency hydro generation hours Interruptible Load Shedding contracts Declare SAPP emergency Load curtailment (NRS048-9) Load shedding (NRS048-9) 240 MW * 700 MW 126 MW Varies MW 342 MW 600 MW MW Varies 2 hours * 2 hours Fuel dependent Fuel dependent Fuel dependent DWS dependent 2 hours Rotational

19 Conclusion on SDR Generation dispatch is guided by the Grid Code The Scheduling and Dispatch Rules (SDR) Economic dispatch is achievable but is also subject to network and generation plant constrains As more renewables (both grid-tied and behind-the-meter) are integrated, the role of the SO will become crucial and more challenging Currently the costs of balancing and flexibility are currently socialized, these may have to be explicit in future Additional resources will be required to fully meet the requirement of the SDR 18

20 Operating costs mix in 2018/19 25,00% (R15.8bn) 46,00% (R28.3bn) 29,00% ( R17.7bn) Other Opex Maintenance Employee benefit costs Almost half of the operating cost is attributable to employee benefits (46%) with the maintenance (29%) and other operating costs (25%) making up the remainder Significant efficiencies would be achieved for employee benefits over the period by reducing the number of employees without compromising the required skills As the business strives to accelerate maintenance programmes, and with the ageing plant it is expected that maintenance costs should increase. Eskom will ensure that maintenance is carried out prudently and efficiently. The growth in other operating costs is less than inflation after 2016/17. Included in this category are costs such as insurance, information technology, operating leases, materials, equipment repairs, facility service costs, fleet costs, legal and audit services, security, travel expenses, billing costs, connection/disconnection costs, meter reading, vending commission costs and telecoms. 19

21 R m Operating Costs increase by average of 7.3% over the period AR= (RAB WACC)+E+PE+D+R&D+IDM±SQI+L&T±RCA Employee benefits- CAGR of 4.9% p.a /14 to 2018/19 on back of declining staff complement Opex escalate by CAGR of 7.3% after normalising for once off transactions 2018/19 Opex Employee benefit of R28.3bn (46%); Maintenance of R17.7bn (29%); Other opex of R15.8bn (25%) 2018/19 Maintenance cost includes long duration outages for both Koeberg Units (R1.6bn) Operations & Maintenance Employee benefits 7.3% 4.9% 2012/ / / / / / /19 20

22 R m Employee benefit costs will escalate by 5% to FY2018/19 Level of remuneration is aligned to market Eskom s remuneration levels for (bargaining unit) staff reflects packages which are higher than combined market reference based on unions requests being premised on improving living standards of members. At managerial level Eskom is either tracking market or below Employee benefit costs remain flat 43,640 41,940 41,238 39,186 24,721 27,902 28,213 28, / / / /19 Number Total employee benefits costs: FY19 - R28.4bn Escalation of 1% to FY18 & 0.5% growth to FY19 Employee benefit expenses consist of both direct & indirect expenses (such as training & development). Dividing gross employee benefit expenses by permanent headcount would overstate average cost per head. Gross employee benefit costs directly incurred for capital projects are allocated to the projects (capitalised) and recovered over life of capital asset through amortisation when asset is depreciated Staff complement Employee benefits 21

23 Eskom maintenance and other operating cost trends Opex (Rm)(nominal) Actual 2016/17 Projections 2017/18 Application 2018/19 Maintenance Other operating costs Maintenance Common feature for Eskom s system is the ageing network and power stations. As new power stations are commissioned they initially require lower maintenance costs than older power stations. Expansion of transmission and distribution network requires additional maintenance costs. Accelerated electrification results in additional assets that need to be maintained. A steady increase in maintenance costs are evident over the three years. The 2018/19 Maintenance cost includes long duration outages for both Koeberg Units (R1.6bn) / / /19 Other operating costs The trend in other operating costs have decreased over the three year period as reflected in table. Included here Insurance, security, transport, contractor costs, IT (information technology), fleet costs, legal and audit services, security, travel expenses, billing costs, connection/disconnection costs, meter reading, vending commission costs, allocation of decommissioning costs and telecoms

24 NERSA MYPD 3 decision for Operating costs - did not reflect efficient costs during MYPD 2 period - but maintained MYPD 2 decision as basis Operating costs reflect efficient costs with 0.2bn increase for 2019 from 2018 projections However there is a variance of R13bn between MYPD 3 decision and projections for The basis of MYPD 3 decision was MYPD 2 decision, - Not efficient cost through MYPD 2 period - Certain opex in MYPD 3 were lower in MYPD 3 than in MYPD 2 decisions - Lower opex determination exacerbated over 5 year period 23

25 In conclusion, Eskom will supply electricity which comes at a cost that needs be recovered Eskom has delivered R47billion of savings over the first 4 years of MYPD3 We have continuously been striving to improve operations, commission new capacity as soon as possible and aim to extract cost efficiencies over the period Our business contains a substantial element of fixed costs that are not easily reduced in the short term. This will require consideration and balancing of socio economic factors which must be considered before making a final decision Eskom s debt commitments have increased significantly over the last few years with a major portion that has been guaranteed by Government. Our debt maturities reflect a step change in the near term that requires a strong balance sheet to cover these commitments Eskom, believes that this revenue application has taken these factors into account in aiming to keep cost escalations close to inflation and phasing in of returns to mitigate impact on the customer 24

26 Thank you