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Update:
State of the Power System
Spring 2011
Mr Brian Dames
Chief Executive
25 August 2011
Table of contents
Introduction
Review of Year To Date performance
Winter events and issues
Outlook for next few months
Partnering to keep the lights on
In support of
2
Overview
• This is the third quarterly briefing, delivering on our promise to keep stakeholders informed
and to update you regularly on the state of South Africa’s power system
• We are managing a tight power system. We are on alert and will be for the next five and
especially the next two years, while we build new capacity.
• Eskom has managed to keep the lights on during a tough winter, thanks to lower than
expected demand, and initiatives put in place to manage a tight system . But the risks to the
system in summer require even more careful management.
• Local supply interruptions, due to overloading caused by illegal connections, as well as to
severe weather conditions in some areas, were challenges during this winter
• Summer is maintenance season: while demand is lower, units must be taken out of service for
maintenance; space must be created to adequate maintenance.
• Eskom is resolved to keep the lights on. But our resolve will be tested and we cannot do it
alone. Energy efficiency is essential to ensure enough capacity to meet demand and to
address the maintenance backlog and provide a reserve to protect the system.
• Our build programme is making good progress and will deliver a more robust power system for
SA in future.
In support of
3
Eskom at a glance
•
Strategic 100% state-owned electricity utility, strongly
supported by the government
•
Supplies approximately 95% of South Africa’s electricity and
more than 40% of Africa’s electricity
•
41 778 employees as at 31 March 2011
•
Serves 2 857 industrial, 1 110 mining, 49 090 commercial,
84 393 agricultural and more than 4.5 million residential
customers
•
27 (including 1 nuclear) operational power stations with a net
maximum capacity of 41 194MW as at 31 March 2011
•
Total electricity sales of 224 446GWh and gross electricity
revenues of R90.38bn for the year ended 31 March 2011
(R69.83bn for the year ended 31 March 2010)
•
Infrastructure includes 395 419km of power lines and cables
(all voltages) as at 31 March 2011
•
Committed to build 17.1GW new generation capacity expected
by 31 March 2018. This includes 5.2GW already
commissioned as at 31 March 2011
•
Baa2 (Stable)/ BBB+ (Stable) rating by Moody’s and S&P
Eskom electricity sales by customer for the
year ended 31 March 2011 (31 March 2010)
Eskom’s net capacity mix – 31 March 2011
Pump
storage
3.4%
Nuclear
4.4%
Hydro
1.5%
Wind
0.0%
Gas
5.8%
Coal
84.9%
In support of
4
Table of contents
Introduction
Review of year to date performance
Winter events and issues
Outlook for next few months
Partnering to keep the lights on
In support of
5
We took action to address the challenges we
identified at the beginning of the year
What we said
What we did
Demand would be back at 2007 levels and would increase by
2% in 2011
Demand is up 1.4% compared to 2010
We would improve coal handling and coal quality to reduce
load losses
Coal-related production losses were reduced by 26% for the
first 5 months of the year compared to 2010; coal stockpiles
being rebuilt after coal industry strike.
We targeted to improve generation output by 1%-2% over
three years
Although the plant availability improved over the last four
months, year to date deteriorated compared to the previous
year from 91.9% to 90.6%. The Duvha unit 4 incident
contributed to this deteriorating performance. A sustainable
availability improvement requires execution of more planned
maintenance: every opportunity for maintenance is utilised
We would sign up about 400 MW of co-generation and own
generation by April
891MW contracted of which 376 MW from IPP’s and about
515 MW of municipal generation
We needed to undertake significant maintenance during
summer
Critical maintenance has been prioritised , with lower than
expected winter demand enabling some maintenance to be
done during winter
We would execute the demand side programme
Reduced demand by 113 GWh during the first quarter
We would communicate with our stakeholders on the state of
the system
Extensive programme of engagement with stakeholders
In support of
6
Winter demand has been below expectations
•
The peak demand and total energy sent out for 2010 was almost back to levels seen in 2007, before
the recession
•
The summer demand in 2011 was generally higher than that previously experienced. However there
has been a drop in the winter load compared to that expected.
•
The peak demand for 2011 to date was 37 064 MW at the end of May, including non Eskom
generation. This is marginally higher than the 36 970 MW in peak 2010 but lower than our forecast of
37 500 MW for this winter
•
Year to date energy growth of about 1.4% compared to this time last year, lower than forecast of 2%
Weekly Energy Production
In support of
7
Weather, strikes, pricing impacted on demand
• Demand has been below our forecasts throughout most of winter, with
peak demand of 37 064 MW at the end of May, below the 37 500 MW
at which demand was expected to peak during July
• Strikes in the metals and mining sectors took significant load off the
system during some of the coldest winter weeks
• Demand from large power users was significantly below expectations:
large power users reduced load in response to winter tariffs (winter
peak tariffs are 3.5 times higher than summer peak tariffs while
average winter average tariff is 2.5 times higher than average summer
tariff)
• Winter cold snaps were relatively brief
• Demand patterns also reflect weaker than expected economic activity
In support of
8
Coal strike impact managed
• Strike at coal mining members of the Chamber of Mines from 24 July to 1
August, with mines back to normal operations on 4 August 2011
• Prior to the strike, Eskom increased coal deliveries to build stock.
• An integrated team was set up to manage the risk during the strike.
• Opportunities to source coal from non Chamber of Mines operations were
maximised
• During the strike the road and rail conditions for coal deliveries, control room
operation, and reclaim capability were tracked, monitored closely with risk
mitigations in place.
• 1.8 days of total system stock was lost
during the strike period
• Post strike plans are in place to
recover lost deliveries
In support of
9
Coal stocks being rebuilt after the strike
•
Coal stockpiles are around 36 days and are projected to build to 40 days by the third quarter.
•
To maintain stock days at projected levels a process has been implemented to source an additional
4 Mt of coal during this financial year. Due to the strike impact this has increased to 5 Mt.
•
Coal stockyard operating procedures are being reviewed to reduce coal handling challenges during
the wet season.
•
There will be a continued focus on optimising processes for coal handling and coal quality
management
Actual Stock days 2008 – 2011 vs Projection 2012
2007/8
(Actuals
:April – Jul ) (Proj: Aug- Mar)
2011/12
2010/11
Actual Stockdays 2008 - 2011 vs Projection 2012
50
46
40.3
39.1
40
35
Stock days
35
30
46
43
45
24.9
25
35
39.2
37
45
42
40
40
40
41
36.3
24.6
22.0
20
19.8
19.3
18.4
17.2
17.9
14.9
15
12.2
13.3
12.8
10
5
0
APR
MAY
JUN
JUL
AUG
SEP
OCT
Months
NOV
DEC
JAN
FEB
MAR
In support of
10
Success in reducing production losses
Full and Partial Load Losses: 01 April 2011 – 14 August 2011
•
Eskom provides a 3,600 MW allowance for unplanned outages and production losses in its generation
fleet, to cushion the system
•
There was an improvement in generation performance during winter period, but some of this was
eroded by the Duvha Unit 4 outage. There was an increase in production loss at the end of July and
beginning of August
•
Eskom continues to work to improve performance of generation plant.
In support of
11
Independent Power Producers
In total about 600 MW of non-Eskom generation was in production through winter.
Eskom supporting two municipalities to operate their
generation plant – 515 MW signed up and about 300 MW
operational in the last month.
Final Medium Term Power Purchase agreement signed,
bringing total to 376 MW (agreements with Sasol (240
MW), Sappi (35 MW), Ipsa (13 MW), Tangent (85 MW)
and TSB Sugar (2.9 MW))
• Average cost of 76c/kwh for non-Eskom generation (53c for
Eskom) indicates real price of generating electricity
• Government’s Integrated Resource Plan creates framework for
introducing further IPPs; Renewable Energy IPP programme has
taken a major step forward with the issuing of Request for
Proposals
Kelvin
power
station
In support of
12
Table of contents
Introduction
Review of year to date performance
Winter events and issues
Outlook for next few months
Partnering to keep the lights on
In support of
13
Local outages a winter challenge
• No national load shedding, but local distribution
interruptions to supply in certain regions
Ingula in the snow
• Severe weather – snow storms, heavy winds - caused
short supply interruptions in parts of KwaZulu Natal,
Eastern Cape
• Majuba power station cut off by snowfall
• Local outages caused mainly by overloading and illegal
connections in densely urbanised areas
• Protest sparked by tamper-proof “split” electricity meters
and perceived high tariffs
• We are strengthening network infrastructure, investing
about R10 billion a year in Eskom’s distribution network
• Working with stakeholders in Gauteng: Joint task team
with local government under the leadership of DPE
• Strategy to combat illegal connections and electricity
theft showing results
In support of
14
Tariff structure
•
•
•
•
•
Electricity tariffs moving up towards cost reflective
levels, but NUS survey indicates South African tariffs
remain competitive
2011
Rank
2010
Rank
Country
Cost in
US¢ per
kWh
One Year %
change
1
1
Italy
19.70
9.4%
After almost two decades of below inflation tariff
increases, this winter highlighting issues around the
structure of tariffs for large power users and for low
income households
2
2
Germany
18.56
24.8%
3
5
Spain
15.37
16.4%
4
4
Belgium
15.23
14.9%
5
7
United Kingdom
15.10
24.5%
6
3
Austria
14.58
7.5%
7
6
Netherlands
14.37
13.2%
Inclining Block Tariff (IBT), which was intended to
provide relief for low income households was
experienced as causing higher cost for many poor
households during the high-consumption winter
months
8
8
Portugal
13.51
14.5%
9
11
Finland
12.11
24.8%
10
9
Sweden
11.94
17.1%
11
10
Poland
11.87
21.0%
We will look at the lessons learned
12
14
Australia
10.02
15.7%
13
13
France
9.61
10.0%
14
12
United States
9.48
2.2%
15
16
South Africa
8.55
27.8%
16
15
Canada
7.98
3.1%
Time of use tariffs for large power users, intended to
provide a signal to reduce load during peak hours,
reduced total demand by large power users during
the winter tariff months
In support of
15
Inclining Block tariff (IBT) - Residential Customers
• Inclining Block Tariff (IBT) was introduced by NERSA in 2010 for residential
customers
• Designed to protect poor households from the impact of electricity price increases
• Unintended consequences:
• Consumers experienced high electricity cost compared to previous financial
year;
• Inadequate education drive on IBT and its impact on customers
• Multiple dwellings per stand mean households do not benefit from lowest tariff.
Monthly level consumption
c/kWh
c/kWh
c/kWh
Including VAT
2010/11
2011/12
2012/13
Block 1
<= 50 kWh
62.4
65.7
69.3
Block 2
51 – 350 kWh
66.7
75.4
85.6
Block 3
351 – 600 kWh
87.0
109.5
137.9
Block 4
> 600 kWh
95.5
120.1
151.2
In support of
2016-06-27
16
Update on Duvha Unit 4 incident
• On 9 February 2011 Unit 4 at Duvha Power station was damaged extensively during a
statutory turbine overspeed protection test.
• The process for dealing with the incident runs in phases: a technical investigation, the
recovery of the unit to return it to service, then concluding the insurance process and then
taking follow up action based on the technical investigation report.
• A recovery project has been initiated to expedite the return to service of Unit 4. Progress
has been substantial and the project is projected for completion by winter 2012 subject to
engineering challenges. Timely return of the Unit as planned will reduce system constraints.
• Once the process is concluded, Eskom will be in a position to share the cause of the
incident and any further remedial measures we are taking as a result.
In support of
17
Table of contents
Introduction
Review of year to date performance
Winter events and issues
Outlook for next few months
Partnering to keep the lights on
In support of
18
Summer is maintenance season
•
We do planned maintenance in summer, when demand is lower, so that maximum capacity available in
winter. The maintenance season usually starts in September and ends in about mid-May, but this year some
maintenance was done during winter
•
A colder-than-expected winter puts added pressure on the system: for every 1 degree Centigrade decrease in
winter temperature, electricity demand increases by 600 - 700 MW during the evening peak
Typical winter and summer load profiles
38,000
Typical Winter Day
Typical Summer Day
Peak demand at
37,000MW, compared
to this year’s summer
peak of 33 064 MW
(and last year’s winter
peak of 36,970 MW)
36,000
34,000
32,000
28,000
02:00
23:00
17:00
08:00
05:00
02:00
20,000
14:00
22,000
Winter load profile is very ‘peaky’.
Peak demand exists for only a few
hours per day – but we have to
have enough capacity in the
system to meet it
11:00
24,000
20:00
26,000
23:00
Peak demand (MW)
30,000
In support of
19
Summer is maintenance season
Capacity available
for maintenance
including Liquid-fuel
Open Cycle Gas
Turbines (OCGTs)
Capacity available for
maintenance
excluding Liquid-fuel
Open Cycle Gas
Turbines (OCGTs)
•
Planned outage requirements exceed
the capacity available for maintenance
•
As a result, liquid-fuel Open Cycle Gas
Turbine (OCGT) usage and demand
side management become critical
•
Planned outages are ranked on scope
and risk, to enable prioritisation of
outages within the available capacity
•
Lower risk outages (inspections and
interim repairs) have had to make way
for high risk high pressure pipe-work
replacements, low pressure turbine
blade inspections and major
refurbishment outages
•
All outages that are “deferred” are
monitored for increasing risk until they
can be accommodated
MW
In support of
Expected system status
A green week indicates that demand and all
reserve requirements can be met with all
installed capacity (including the Open Cycle
Gas Turbines).
A yellow week indicates that there is up to
1,000 MW shortage of meeting the demand
and reserves. There is an increased
probability of requiring some emergency
reserves to meet the peak demand
A orange week indicates that there is
between 1000 and 2000 MW shortage of
meeting the demand and reserves. There is a
high probability of requiring substantial
emergency reserves to meet the peak
demand
•
•
Demand reduction or additional supply options will improve the situation for the tighter
weeks as indicated in the various columns above.
The status indicated above may change if there is a change in the demand or supply
from that forecast, which is dependant predominantly on weather and large customer
behaviour.
In support of
21
This is Medupi
In support of
22
Our build projects are powering ahead
• With more than a year to the planned first power from
Medupi, we are doing a detailed assessment of the
schedule ensuring that contractors meet timelines
• We are focusing systematically on supplier performance,
so we can pick up and mitigate any risk factors early on;
also understanding impact of labour situation on the
project
Medupi
Kusile
Bothaville line
Ingula dam wall
• Significant milestones reached: first generator at Medupi, dams at Ingula, Grootvlei
completed, Komati three units operational
• These are big projects with big risks: we are on alert
In support of
23
Table of contents
Introduction
Review of year to date performance
Winter events and issues
Outlook for next few months
Partnering to keep the lights on
In support of
24
Reserve margin since 1999
• The reserve margin is simply a snapshot of the amount of installed capacity at the time of
system peak
• All installed capacity is included, including peaking plant which is not intended to run for
long periods of time.
• On its own, the reserve margin does not give any indication of the amount of capacity
available for maintenance.
Percentage Reserve Margin
% Reserve Margin
30
25
20
• * In particular this year’s
peak occurred before the
traditional winter period.
27.1
24.6
23.2
19.2
16.4
15.9
15
11.2
10
8.2
16.8
14.9
*
10.6
6.7
5.6
5
0
In support
of
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
25
Keeping the lights on: The next seven years
Energy Supply Gap assuming the Base Case assumptions
Energy Gap (TWh)
2.0
-
2011
2012
2013
2014
2015
2016
2017
1
-2.0
2
3
-4.0
-6.0
6
-8.0
-10.0
9
In support of
26
A number of levers have been identified and
explored to help close the gap
Supply side levers to help close gap
Demand side levers to help close gap
• Increase generation capacity in
• Increase Eskom’s internal energy
existing fleet
efficiency
*
• Improve Eskom generation
performance
management programme
• Bring in additional co-generation
and own generation
• Deliver on demand side
*
• Sign up municipal and other
backup generators
• Work with government to bring in
renewable energy producers
• Roll out of government’s 1 million
solar water heating by 2014
• Implement demand response
programme
*
• Implement smart systems and
load limiting technologies for
residential customers
*
In support of
* Subject to government approval
27
A “safety net” is required as a last resort in
case further risks materialise*
1. Open cycle gas turbine use
•
The OCGTs in South Africa will have to be run at higher load factors incurring significant
cost
2. Demand response initiatives
•
Incentive-based demand response programme in place already for our largest customers;
achieves about 500 MW
•
Imminent placement of contract with aggregator to obtain nearly 500 MW from the larger
commercial and smaller industrial customers. This can be ramped up to 2,000 MW in the
next 3 to 6 years
•
Investigation into technologies for residential demand response completed
3. Energy Conservation Scheme
•
A voluntary Energy Conservation Scheme involving the 500 largest electricity users is the
preferred route. Already, 134 large customers are participating in a voluntary scheme and
have saved 5% against the baseline
•
An ECS would provide certainty of demand (for at least 7 years from those customers that
consume between 50% and 60% of the electricity)
•
Eskom has proposed that a mandatory scheme may be necessary as a last resort to
prevent disruptive load shedding, but this would be a government decision
In support of
* Subject to government approval
28
Achieving the Energy savings target for
2011/12 could power a city for a year
either of
1,280
Buffalo City
(1,305 GWh consumed )
Mangaung
(1,397 GWh consumed )
Gigawatt hours
or
Sol Plaatjie
(514 GWh consumed )
for 2½ years
for ~1 year
Source: Annual electricity consumption/sales as reported in the State of Cities 2006, City Energy Support Unit, Sustainable Energy Africa, 2006
In support of
29
Mass Roll-Out and Rebate Programmes
Initiative
Year to Date
MW
GWh
CFL’s
473,000 bulbs installed
14.6
36.4
LED’s
20,685 bulbs installed
0.3
1.9
SWH – Low Pressure
40,694 units installed
7.3
10.2
SWH – High Pressure
2,493 units installed
1.5
2.2
Heat Pumps –
Residential
75 units installed
0.1
0.1
Commercial and
Industrial projects
11 projects
7
64
30
113
Total
In support of
30