eskom 2018/19 revenue · pdf fileeskom 2018/19 revenue application ... page 10 2 •...
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Where we are coming from Page 9
• 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
• This revenue application does not include any RCA applications for the MYPD 3 period. Eskom awaits guidance from NERSA on the processing of RCAs for years 2, 3 and 4 of the MYPD 3 period.
1
Depreciation
Allowed revenue in accordance with MYPD methodology is increased by 3.6% for Standard Tariff Customers - Page 10
2
• 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
+ + + + + =
Primary
Energy (incl imports and
DMP)
IPPs Operating
expenditure (incl R &D)
Integrated
Demand
Management
Return on
Assets Revenue
R62.6bn R34.2bn R62.4bn R0.5bn R29.1bn R22.7bn R219.5bn
+
Tax &
Levies
R8.0bn + + + + + = +
Return on assets = % cost of capital allowed X depreciated replacement asset value
Based on the MYPD Methodology the total allowable revenue is R219.5 billion for FY2018/19 Page 10
3
• 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
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 Page 29
4
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
224 752
211 721
244 318
140000
160000
180000
200000
220000
240000
260000
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Eskom Sales Trend (GWh)
Historic actual sales 10 Year Sales Forecast MYPD3 Budget
Declining sales trend over MYPD 3 period indicates requirements to rebase due to sales volumes – Page 42
Source: Forecasting consolidation.
Key drivers for declining sales
• Decrease in reliance on Eskom electricity
• Lower competitiveness of SA industries internationally
• Low investor confidence (Eskom & SA), system
constraints, price elasticity, IDM initiatives, weak GDP
growth, low commodity prices & cheap imports
resulted in a decline in consumption & customer
closures since 2012
5
MYPD3 Decision
Realistic Forecast
Even with a 0% increase in Allowable Revenue - rebasing of sales from MYPD 3 results in a 9.4% price increase Page 31
6
• The ERTSA methodology does not adjust for volume changes during a MYPD cycle
• It is only at the next cycle that adjustments can be made
• Thus the sales volume gap of about 30TWh would need to be implemented in the 2018/19 decision
• Assuming the same allowed revenue in 2018/19 as was for 2017/18; recovered over lower volume (of
30TWh) results in 9.4% price increase (after incorporating primary energy savings)
• MYPD methodology requires recovery of allowed revenue (consisting of fixed and variable costs)
through assumed sales volume
• If sales volume drop the related fixed costs are not recovered (primary energy costs are saved)
• The converse is true if the sales volume is higher than assumed
22
3.2
19
19
2 9
53
20
6.4
12
20
8.4
42
2015/16 2013/14 2016/17 2014/15 2017/18
21
3.5
45
19
4.7
62
19
5.2
58
19
2.0
89
18
9.8
45
21
8.1
94
GWh Act/Proj Std
Tariff sales
MYPD 3
Sales Decision Standard tariff revenue as at FY18
Savings on PE due to lower sales
Revised standard tariff for FY19
198 954
Standard tariff volumes (GWh) 223 217
Standard tariff ave electricity price
(revenue/sales volumes - c/kWh)
89.13
Price adj for rebasing sales volumes
198 954
-10 812
188 142
192 953
97.50
9.4%
Decision vs actual standard tariff sales Rebasing of sales volumes (R’m)
2017/18 2018/19
In order to increase sales volumes Eskom has implemented
a local demand stimulation strategy – Page 48
7
Factors influencing the overall price increase - Page 30
8
19.9%
30
26
5 G
Wh
R2
69
74
mR
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
Electricity price impact in 2018/19 Page 14
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.
9
Standard tariff price impact Unit
MYPD3
Decision
2017/18
Application
2018/19
Standard tariff revenue R'm 198 954 206 205
Standard tariff sales volumes GWh 223 217 192 953
Standard tariff price c/kWh 89.13 106.87
Standard tariff price adjustments % 2.2% 19.9%
Conservative assumption have been used for RAB, migration of WACC and depreciation Page 59 to 62
10
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 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
RAB has not changed
significantly.
• MYPD methodology allows for
ROA as proxy for interest
costs and equity return to the
shareholder
• In accordance with Nersa
decision and EPP, migration of
WACC is phased over a longer
period.
• NERSA MYPD 3 decision of
4,7% is reduced to 2.97%.
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 29 140 Generation
Transmission
Distribution
549 527
109 371
104 691
Primary energy costs reflects CAGR 8.5% p.a. but the position improves when local IPPs are excluded Page 66
11
• Between 2013/14 to 2018/19 , primary energy costs escalate with CAGR of 1.5% p.a.
• Primary energy costs peaked during FY2015 & FY2016 when OCGTs were utilised to
minimise load shedding
• IPPs played vital role during supply challenges – however under the current
environment the growth in IPPs are displacing Eskom power stations
• Total primary energy costs reflects CAGR of 8.7% p.a. once local IPPs are incorporated
𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴
2014/15 2013/14
R’’m
2012/13
+8.7%
2018/19 2017/18 2015/16 2016/17
IPPs
Gx Primary Energy 1.5%
Primary Energy costs assumptions Page 66
12
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
8.658 8.156
2017/18
24.450
45 642
34.209
7.994
Other Eskom PE
OCGT Fuel Cost
Coal
IPPs
Environmental Levy
International Purchases
Ra
nd
mill
ion
s
IPP portfolio mix assumptions Page 68
13
Assumptions on IPP
portfolio mix for
2018/19:
• DOE Peaker
projects –
contractual
assumptions
• REIPP - seven bid
windows (bid
window 1, 2, 3,
3.5, 4, 4.51 and the
first bid window of
the Smalls
programme)
• Eskom WEPS
programme
(STPPP/MTPPP)
20.000
15.000
10.000
5.000
0
2018/19
424
17.828
2017/18
424
11.661
2016/17
4.235
7.227
2015/16
3.968
5.002
2014/15
3.005
3.017
2013/14
3.421
250
GWh
STPPP/MTPPP
Renewables
DOE Peakers
Note: 1) NERSA to review the assumption of up to BW 4,5 and will require an alignment to the DoE Ministers decision of up to BW 4
Average delivered coal costs for FY2018/19 is forecasted to be ~8% Page 77
14
• Consists of ex-mine cost of coal
(majority of cost) and transport cost
• Other costs, such as take or pay
payments and laboratory fees,
comprise about 2%.
• The average increase in FY2018/19
is 8%.
- The increase in long term cost
plus coal is 8%,
- long term fixed price coal is
14%,
- and short/medium term coal is
8%.
335
58
370342
5156
393 398
+5%
2016/17 2018/19
430
9
2017/18
Transport Ex-mine Other*
Planned average delivered coal costs
(R/t)
Change 1% 8%
Operating Costs increase by average of 7.3% over the period Page 88
15
• Employee benefits- CAGR of 4.9% p.a. from 2013/14 to 2018/19 on back of a
declining staff complement
• O&M costs escalate by CAGR of 7.3% after normalising for once off transactions
• 2019 Opex – Employee benefit of R28.3bn (46%); Maintenance of R17.7bn (29%);
Other opex of R15.8bn (25%)
𝐴𝑅= (𝑅𝐴𝐵×𝑊𝐴𝐶𝐶)+𝐸+𝑃𝐸+𝐷+𝑅&𝐷+𝐼𝐷𝑀±𝑆𝑄𝐼+𝐿&𝑇±𝑅𝐶𝐴
2014/15 2015/16 2016/17 2017/18
7.3%
2018/19 2012/13
R’m
2013/14
Employee benefits
Operations & Maintenance
4.9%
Employee benefit costs will escalate by 5% to FY2018/19 Page 93
16
• 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 payroll
& non-payroll expenses (indirect costs such as
training and 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
Nu
mb
er
Staff complement Employee benefits
Macroeconomic impacts of alternative scenarios to meet Eskom’s five-year revenue requirement – Deloitte Page 118
17
• Annual tariff increase of 19% is expected to have a slightly negative impact on GDP and employment
growth relative to the baseline scenario (tariffs rise by 8% a year and government borrows shortfall).
• Eg, under 19% tariff scenario (1B),
• GDP forecast to expand at average rate of 2.0% y/y, 0.3 percentage points lower than 2.3% y/y
growth forecast in baseline (BAU1).
• Total employment is expected to grow at average rate of 0.9% y/y under 19% tariff increase
compared to 1.2% y/y in BAU1. This implies that under a 19% tariff increase scenario, 137000
fewer jobs will be created and sustained annually over period 2017 to 2021, relative to BAU1.
0.0
1.0
2.0
3.0
4.0
201
2
201
4
201
6
201
8
202
0
202
2
202
4
202
6
202
8
203
0
y/y
%
Real GDP growth
1A: 13%, debt
1B: 19%, tariff
BAU2: 8%, downgrade
3A: 8%, VAT
BAU1: 8%, debt
The impact of the 5 scenarios were modelled and the outcomes are illustrated below
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
20
16
20
18
20
20
20
22
20
24
20
26
20
28
20
30G
row
th in
to
tal e
mp
loym
ent
(y/y
%)
Employment growth
Eskom’s revenue application is completed within the legislative and NERSA’s regulatory framework Page 15
19
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
Potential macroeconomic, environmental, and social consequences of energy subsidies Page 121
• Energy subsidies crowd-out growth-enhancing or pro-poor public spending. such as on social welfare, health, and education) and place an unnecessary burden on public finances. Energy subsidies (unless specifically targeted) are a poor instrument for distributing wealth relative to other types of public spending.
• Energy subsidies discourage investment in the energy sector and can precipitate supply- crises. Energy subsidies artificially depress the price of energy which results in lower profits for producers or outright loses. This makes it difficult for state-owned enterprises to sustainably expand production and removes the incentive for private sector investment. The result is often an underinvestment in energy capacity by both the public and private sector that results in an energy supply crisis which in turn hampers economic growth. These effects have been felt in SA.
• Energy subsidies create harmful market distortions. By keeping the cost of energy artificially low, they promote investment in capital-intensive and energy-intensive industries at the expense of more labour-intensive and employment generating sectors.
• Energy subsidies stimulate demand, encourage the inefficient use of energy and unnecessary pollution. Subsidies on the consumption of energy derived from fossil fuels leads to the wasteful consumption of energy and generate unnecessary pollution. Subsidies on fossil-fuel derived energy also reduces the incentive for firms and households to invest in alternative more sustainable forms of energy.
• Energy subsidies have distributional impacts. Energy subsidies tend to disproportionately benefit higher-income households who consume far more energy than lower income groups. Energy subsidies directed at large industrial consumers of energy benefit the shareholders of these firms at the expense of the average citizen.
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