eskom 2018/19 revenue application - nersa.org.za · pdf fileadjustments made in preceding...
Post on 22-Mar-2018
216 Views
Preview:
TRANSCRIPT
Where we are coming from
• This revenue application is being made for the year 2018/19, after the EnergyRegulator maintained its revenue decision made in 2013 for the 2017/18 year, whereit approved total allowable revenue of R205 billion.
• The allowed revenue resulted in an average increase of 2.2% due to baseadjustments 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 inelectricity 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 MYPDmethodology 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 3period. Eskom understands that NERSA will process RCAs for years 2, 3 and 4 of theMYPD 3 period at a later stage. The adjustments will be applicable from 1 April 2019onwards in a phased manner
1
Eskom’s revenue application is completed within the legislative and NERSA’s regulatory framework
2
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
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)
Framework Requirements
Depreciation
The MYPD methodology through the allowable revenue formula was applied
3
+ + + + + =
Primary
Energy(incl imports and
DMP)
IPPsOperating
expenditure(incl R &D)
Integrated
Demand
Management
Return on
AssetsRevenue
+
Tax &
Levies
Return on assets = % cost of capital allowed X depreciated replacement asset value
𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴
Based on the MYPD Methodology the total allowable revenue is R219.5 billion for FY2018/19
4
• Absolute Revenue
increase of R14.3 bn
(7%) from previous
Nersa decision
• Standard tariff
customers contribute
to 3.6% increase in
allowed revenue
• Export and NPA
revenues account for
3.4% increase in
allowed revenue
• About 15% of allowed
revenue related to IPP
costs
Regulated Asset Base
WACC (%)
Returns
Expenditure
Primary energy
IPPs (local)
International purchases
Depreciation
IDM
Research & development
Levies and taxes
RCA
Total Allowable Revenue
763 589
2.97%
22 690
62 221
59 340
34 209
3 216
29 140
511
193
7 994
-
219 514
×
+
+
+
+
+
+
+
+
+
RAB
ROA
E
PE
PE
PE
D
I
R&D
L&T
RCA
Allowable Revenue (AR) Application
FY2018/19 (R’m)Fx
Application of the NERSA Allowable Revenue formula indicates a revenue growth of R14.3 billion
5
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
R219.5
MYPD3Revenue
2017/18
IPPs Operating Cost
Primary Energy
InternationalPurchases
R11.2b
Depreciation Returns Total Allowable
Revenue2018/19
Evironmentallevy
Rand
billi
ons
R205.2b
R13.2bR1.0b
R2.8b R0b
-R12b-R1.8b
Revenue requirement grows by R14.3 bn
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 2018.
– This is due to the Municipal Finance Management Act (MFMA) requiring Municipal tariff changes to be made only from 1 July each year.
6
Standard tariff revenue
Standard tariff sales volumes
Standard tariff price
198 954
Standard tariff price adjustment 2.2%
206 205
192 953
106.87
19.9%
2017/18 2018/19
223 217
89.13
R’m
%
Unit
GWh
c/kWH
Standard tariff
Factors influencing the overall price increase
7
19.9%
30
26
5
GW
hR
26
97
4m R
10
81
2m
Vo
Gro
Sales volumes
rebasing
IPPs International Purchases
9.4%
5.5%
1.4% 16.3%
Price before operating costs
changes
Generationown PE costs
7.0% 0.5% 23.8%
Opex Price after operating
costs
-6.0%
Adjustments Operating costs Depr , Returns , SPAs & Exports
Overall Price
Increase
Pri
ce Im
pact
%
SPAs &Exports
2.1%
Depr &Returns
With average 2.2% increase in 2017/18 and 19.9% proposed average increase in 2018/19
Average for two years is 11%
Conservative assumption have been used for RAB, migration of ROA towards WACC, and depreciation
8
𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴
• 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
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
• 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.
Assets
Working capital & WUC
Eskom RAB
592 104
171 485
763 589
Regulatory Asset Base (R’m) Return on Assets (R’m) Depreciation (R’m)
Ave RAB
Return on Assets (ROA)
Returns
763 589
8.4%
64 142
Phased in ROA 2.97%
Phased in Returns 22 690
Returns sacrificed -41 452
Generation
Transmission
Distribution
19 062
3 833
6 245
Total Depreciation 29 140Generation
Transmission
Distribution
549 527
109 371
104 691
Primary Energy costs assumptions
9
𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴
50.000
90.000
60.000
80.000
70.000
110.000
20.000
100.000
40.000
0
10.000
30.000
8.087
49.991
2018/19
21.720
3.127
7.242
44.652
8.152
2.681
2016/17
3.216
8.6588.156
2017/18
24.450
45 642
34.209
7.994
Other Eskom PE
OCGT Fuel Cost
Coal
IPPs
Environmental Levy
International Purchases
Rand m
illio
ns
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
Cost of generation
Demand forecast
Unconstrained
schedule
(Cheapest mix)
Network constraints
Constrained schedule
Day ahead contract
Day-Ahead Generation Scheduling Process
Operating reserve requirement
Renewable Forecast
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
profile
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
20000
21000
22000
23000
24000
25000
26000
27000
28000
29000
30000
31000
32000
33000
34000
35000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Monday 15 May 2017 - Actual Demand
16
Highest difference between peak demand and night minimum during winter 2017
The difference between
minimum and peak
demand was over 13 000
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
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
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
3 086 MW
342 MW
600 MW
Varies
2 024 MW
2 hours
* 2 hours
Fuel
dependent
Fuel
dependent
Fuel
dependent
DWS
dependent
2 hours
Rotational
The merit
order varies
depending on
magnitude and
Anticipated
duration of the
emergency
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
19
Operating costs mix in 2018/19
25,00%
29,00%
46,00%
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.
(R28.3bn)
( R17.7bn)
(R15.8bn)
Operating Costs increase by average of 7.3% over the period
20
• Employee benefits- CAGR of 4.9% p.a. - 2013/14 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)
𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴
2014/15 2015/16 2016/17 2017/18
7.3%
2018/192012/13
R’m
2013/14
Employee benefits
Operations & Maintenance
4.9%
21
• 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
• 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
Level of remuneration is aligned to market
Employee benefit costs remain flat
28,363
39,186
2017/18
28,213
41,238
2016/17
27,902
41,940
2015/16
24,721
43,640
2018/19
R’m
Num
be
r
Staff complement Employee benefits
Employee benefit costs will escalate by 5% to FY2018/19
Opex (Rm)(nominal) Actual
2016/17
Projections
2017/18
Application
2018/19
Maintenance 14 087 15 610 17 665
Other operating costs 17 938 15 385 15 796
22
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.
Eskom maintenance and other operating cost trends
14
16
18
15
13
17
2017/182016/17 2018/19
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).
14
16
18
15
13
17
Maintenance
Other operating costs
23
• 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
2018 . 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
NERSA MYPD 3 decision for Operating costs - did not reflect efficient costs during MYPD 2 period - but maintained MYPD 2 decision as basis
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 assoon 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 theshort term. This will require consideration and balancing of socio economic factors whichmust be considered before making a final decision
• Eskom’s debt commitments have increased significantly over the last few years with amajor portion that has been guaranteed by Government.
• Our debt maturities reflect a step change in the near term that requires a strong balancesheet to cover these commitments
• Eskom, believes that this revenue application has taken these factors into account in aimingto keep cost escalations close to inflation and phasing in of returns to mitigate impact on thecustomer
24
top related