Review of national power system and 2008 winter prognosis
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Review of National Power System and 2008 Winter Prognosis. Presentation to Public Enterprises Portfolio Committee 20 th May 2008. Contents. Review of recent history Need for a reserve margin Evolution of the reserve margin Generation fleet performance Winter 2007 Review

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Review of national power system and 2008 winter prognosis

1

Review of National Power System and 2008 Winter Prognosis

Presentation to Public Enterprises Portfolio Committee

20th May 2008


Contents

Contents

  • Review of recent history

    • Need for a reserve margin

    • Evolution of the reserve margin

    • Generation fleet performance

  • Winter 2007 Review

    • Original Prognosis and Actual Performance

    • Coal Stockpile movement

    • Operating Challenges

  • Eskom’s Recovery Programme

  • Review of Load Shedding & Energy Savings to date

  • Winter 2008 Prognosis

2


Review of recent history

3

Review of Recent History


Why should electrical systems be operated with a reserve margin and other buffers

Why should electrical systems be operated with a reserve margin and other buffers?

4

The Electrical Power System is considered the most complex system around. It is a mix of electrical, communication, mechanical, civil, information and management systems.

A comprehensive list of things that could go wrong and the possible impact on other risks cannot be modelled. The ability to continuously visualise the current risk status is incredibly difficult and stressful.

The impact of failures can be significant to catastrophic (i.e. blackout). There are various global examples of where this has occurred.

Buffers in the system such as operating reserves, stockpile days, transmission and distribution network redundancy and resources allow the System Operator to deal with multiple events in real time while enabling sustainable medium to long term performance

By continuously operating “on the edge”, you will not need many things to go wrong before you test your defence systems. You do not want to test your defence systems too often as the increased exposure will increase the likelihood of something going wrong and these barriers failing.

South Africa’s ability to deal with a nationwide black out is untested and we cannnot rely on our neighbours to assist.

4


There are two key components to the reserve margin

Operating Reserve Margin

Generation Capacity Net Reserve Margin

There are two key components to the reserve margin

  • Meet demand and supply side deviations instantaneously and then in the short to medium term replenish resources that have been utilised.

  • Deal with the loss of the single largest unit on the system or single point of import provision.

  • Deal with credible cascading events in the short term (<1 day).

  • Operating reserve margin plus the ability to cater for additional situations and circumstances including:

  • Deal with longer term loss of major units or significant disruptions in capacity provision (strike at a mine)

  • Ability to cater for short to medium term economic growth

  • Account for major seasonal variations

5

5


Various inputs typically determine the level of generating capacity net reserve margin

Various inputs typically determine the level of Generating Capacity Net Reserve Margin

29

Reserve margin build up

Comments

KEMA, in a study for NEMCO, indicated that a reserve level of 4 - 6% should be maintained for system security, if necessary, by curtailing customer load in some manner

Operating Reserve Margin

4-6%

Short term economic growth

5%

Reserve margin allows space for growth

Generation performance variation

High range due to varying capabilities of different systems

3-13%

Weather variations as seen during cold spells starting in May

Extreme weather

3-5%

  • Recommendations from KEMA, CIGRE and other Benchmarks done

Total Reserve margin

15-29%

Total Reserve margin

6

6


How did the reserve margin situation evolve over time

How did the reserve margin situation evolve over time?

5.1

Net Reserve Margin (%)

  • In 2004, with the colder winter, started to make more use of contracted interruptible loads and contracted demand side products over evening peak periods

  • Evolution of Net Reserve Margin has put us in a position where we can actually only cover Operating Reserve (4-6%)

  • System stability is of concern

  • Greater use is made of demand side resources to deal with system incidents.

1999

2000

2001

2002

2003

2004

2005

2006

2007

Note:The increase in reserve margin in 2005 was as a result of low peak demand for that year. Peak demand for these years was as follows: 2004 – 34.20 GW; 2005 – 33.46 GW; 2006 – 35.31 GW. ; 2007 – 37.10 GW. This low demand for 2005 was driven by the commodity market and a mild winter

7


As reserve margin declines the frequency of use of emergency reserves rises dramatically

As reserve margin declines, the frequency of use of emergency reserves rises dramatically

74

Usage of EL1

Usage of key types of emergency reserve

Usage of interruptible

load

1999

2000

2001

2002

2003

2004

2005-6

2006-7

2007-8to Dec 31

  • Since 2004, annual growth for using Generator above maximum rating (EL1) has been >110%, and has been >130% for usage of interruptible load

  • The figures do not take into account the last 3 months of FY2007-8

  • In addition to EL1 and interruptible power, there are other emergency reserve mechanisms that showed similar trends

8

8


Three year generator performance review

Three Year Generator Performance Review

Unplanned system losses per day – Last 3 years (MW)

  • These points represent the daily average of all the hours. The fluctuation within a day has a significantly wider variation (as with load fluctuation)

  • There are natural season fluctuations with UCLF peaks during the summer months

9

9


This year s generator performance

This year’s Generator Performance

Unplanned system losses per day – Last 4 months (MW)

Days within daily limit of 2 500 MW of UCLF:

- Past 3 years = 68%

- Past 4 months = 44%

- April alone = 87%

A key driver of the figures in January and February was availability and quality of coal

10

10


Re establishing the buffers eskom s recovery programme

Re-establishing the Buffers – Eskom’s Recovery Programme

11

Supply Side Initiatives

  • Focus on key areas of plant performance and ensure resources and maintenance windows are provided to improve performance. To date 17 of the 23 identified units that required additional essential maintenance have been accommodated. As further assessments are done, more units will be identified. External benchmarking and reviews by other utilities has helped and will continue to be utilised (from the US, France and Germany).

  • Focus on managing the coal supply and handling. Currently the system stockpile days is at 17.4 days with 5 of the 12 power stations above 20 days, 3 between 15 and 20 days and 4 between 13 and 15 days. This has been on a steady upward trend. Challenge is delivery of the additional emergency coal purchases.

    Demand Side initiatives

  • Established separate task teams with key industrial customers and the top 11 municipalities to assess demand reductions and work on activities to accelerate energy savings.

  • Engagement with various government departments and other stakeholders on an energy conservation programme.

    Planning and Expansion

  • Integration of Transmission and Generation expansion planning and development of adequacy standards that will be entrenched in regulations. Plans review short, medium and long term in some detail.

  • Three programmes to attract non-Eskom generation; Pilot National Co-generation programme, Medium Term Power Purchase Programme programme and Base load IPP programme. Other programmes will be considered.

  • Focus on meeting current commitments on Return to Service programme, Gas1, Medupi, Ingula and Bravo projects.

  • Working with Government on streamlining decision making processes.

11


Winter 2007 review

12

Winter 2007 Review


Colour coding

Colour Coding

  • Green (sufficient operating reserves – 1800MW to 1900MW)

    • It is likely one may only have to use our scheduled generation resources and normal operating reserves. Green means we have the required level of operating reserves at our disposal.

  • Yellow (Between1800 and 800MW of operating reserves)

    • It is likely one will make extensive use of whatever DMP contracts we have and use EL1 extensively (i.e. generate above maximum capability rating at certain power stations). One may also make use of the interruptible load contracts over peak periods.

  • Orange (Up to 200MW short of meeting demand)

    • It is likely one will make extensive use of the interruptible load contracts and use the Open Cycle Gas Turbines in short bursts.

  • Red (between 1200MW and 200MW short of meeting demand)

    • It is likely one will resort to a high level of use of the Open Cycle Gas Turbines and Interruptible Loads and possibly have emergency load shedding in short bursts.

  • Brown (more than1200MW short of meeting demand)

    • It is likely one will have to resort to emergency load shedding.

13


Original prognosis review

Original Prognosis & Review

Assumptions used for actual classification of a week

  • This is a comparison of version 5 of the 18 month winter plan

    • Prepared mid May 2007

  • The actual load is that before any reduced load is added back

  • The contribution to variation from “planned color” is a combination of a number of factors

    • Although initial classification may be “brown”, where possible action are taken to reduce the risk of load shedding in real time

    • The reasons indicated here are merely indicative of likely key contributors for that specific week

14


Peak and energy comparisons 2006 2007

Peak and energy comparisons 2006/2007

  • A growth in the peak demand of 1706MW

  • During this peak contracted customers reduced demand by about 500MW

  • Load was shed at other times in winter 2007 for transmission constraints (late May 2008) in Mpumalanga and Gauteng

  • Potential Peak demand of just over 37 000MW

15


Operating challenges meeting demand in winter

Operating Challenges – Meeting Demand in Winter

  • The peak demand indicated is the average for the hour. Within that hour there could be an instantaneous peak up to 1000MW higher than the average. Instantaneous demand in 2007 was about 38 000MW.

  • The demand increase rapidly between 5:30pm and 6:15pm as lighting, cooking and heating load throughout the country is switched on. Up to 3000MW of demand is introduced with an hour. This requires vigilance and rapid reaction capability at National Control.

  • The Transmission network requires extensive management to deal with this surge, with significant switching of reactive power devices to ensure that the network remains stable and an adequate quality of supply is provided.

16


Coal stock pile days april july 2007

Coal stock pile days: April – July 2007

  • Main challenge is trucking in coal to Majuba and Tutuka Power Stations to keep up with consumption in winter.

  • Also need “tiered” collieries to meet supply obligations and quality requirements.

17


Generation performance april 2006 july 2007

Generation Performance: April 2006 – July 2007

  • 3% is about 1200 MW

  • 6% is about 2400 MW

  • Winter 2006 and 2007 has seen better than average performance.

18


Ability to meet the demand and energy required

Ability to meet the demand and energy required

  • The step change in demand of about 1700MW from 2006 was a significant operational challenge that the control centre had to adapt to.

  • Good generation performance improved the ability to meet the demand of winter 2007

  • Strong reliance on customer contracts to reduce load almost daily

  • The performance of the OCGT’s was good and they were used extensively

  • The extensive pre-planning helps to actively contain a large supply/demand mismatch to manageable levels

  • The security of the primary energy levels after the winter was a major concern

  • The planning and procurement process to ensure sufficient liquid fuels worked well.

  • The energy usage was significant in winter 2007 with very high daily load factors

19


Review of load shedding and energy saving

20

Review of Load Shedding and Energy Saving


Why was planned or scheduled load shedding stopped

Why was planned or scheduled load shedding stopped?

We are seeing evidence of increased energy savings from municipalities and Eskom is optimistic that further reductions to reach our 10% savings target are possible.

A task team of senior Eskom executives and top officials of municipalities from around South Africa is to meet early next week to discuss the way forward in driving further energy savings.

Recent savings, particularly from industry, have shown that it should be possible to achieve this objective sustainably through a concerted and committed effort by all of us. This is the spirit of Eskom’s engagement with municipalities and we would hope that it will not be necessary to reinstate scheduled load shedding.

However, should the national grid come under unexpected pressure, there may be occasions where brief periods of load shedding could be required.

Extract from Media Release – 30 April 2008

  • We initially began load shedding because we were not seeing movement in the municipalities towards savings and there was a disproportionate burden on the direct Eskom switchable customers (specifically Key Industrial Customers).

  • After we introduced pre-emptive (scheduled) load shedding, we saw movement that resulted in initial savings by the municipalities and other customers. There were concerns about the consequences of load shedding from some stakeholders.

  • Although these do not yet amount to the required 10%, the direction of these savings indicated that with continued focus the required targets can be reached without further scheduled load shedding.

  • We acknowledge that coal stock piles and generation performance remains an operational risk and therefore a dedicated focus on achieving the 10% savings target is still required.

  • Mechanisms such as pricing and rationing will further support and drive the savings initiatives.

21

21


Measurement and verification points

Measurement and Verification points

  • Distribution customer metering. Not verified. Sent directly to billing system by the 3rd working day of a month.

  • Verification occurs in billing system. View provided is for an accounting month and not a calendar month.

  • Further verification occurs in an analysis tool incorporating forecasts and budgets.

  • Analysis can only be done between 2 weeks to a month later.

  • 80% of the customer demand is measured by remote metering while the remaining is physically read or estimated.

  • Generation sent out metering.

  • Not as accurate as other metering systems.

  • Information sent directly to National Control and Generation systems.

  • Available instantaneously and can be assessed against forecasts an hour later.

  • Ultimate indication of savings required.

  • Transmission boundary metering.

  • Sent to National Control and verified within 7 days. Can be assessed in various segments of the month (i.e. weekly, calendar month or accounting month.).

  • Energy usage after transmission losses.

  • Can provide indicative provincial, distribution region and international usage.

  • Can be used to correlate savings seen on system level using Generation sent out metering within 7 days of the current calendar month.

International

Customers

X

X

X

~

~

X

X

X

X

X

Key Industrial

Customers

X

X

X

X

X

Dx

Gx

Tx

Tx

Dx. Customers

22


Overall weekly energy review

Overall Weekly Energy Review

General trend of reductions against forecast of 2 to 9%. Average of close to 5% in April improving from 3% in March.

23


Scenarios for energy savings

Scenarios for Energy Savings

Actual Energy demand tracking Scenario B and will need to be monitored against Scenario A and the Medium Term forecast

Scenario A:

Original forecast adjusted for a Cold Winter

Scenario B:

Original forecast less 2000 MW Reduction

Scenario C:

Original forecast less 3000 MW Reduction

Scenario D:

Includes Scenario C as well as a warmer winter

24

24


Overall weekly peak demand review

Overall Weekly Peak Demand Review

General trend of maximum demand reductions against forecast of 2 to 11%. Average of close to 7% in April.

25


Evidence of savings

Evidence of Savings

  • Overall System Savings

    • March and April billing information is showing evidence of savings but not 10%. April data shows between 4 and 5% of energy savings against forecast.

    • April real time system information show a saving of between 4 and 5% on energy and 4 to 7% on maximum demand.

  • Top 12 Metros and Municipalities

    • Evidence of between 4 and 5% savings in energy demand in April based on billing data. This is against forecasted demand.

  • Key Industrial Customers

    • Evidence of up to 8% savings in energy demand in April based on billing data and this has been confirmed by metering data. This is against forecasted demand.

26


Engagement with top 11 metros and municipalities

Engagement with Top 11 Metros and Municipalities

  • Issues with Municipal Load Shedding

    • Not all municipal customers were load shed (inequity)

    • Shedding outside of stipulated scheduled load shedding periods

    • Load shedding did not take place 6 days a week as requested

    • Load shedding durations did not average 6 hours per week

    • Some municipalities did not shed their allocated load

    • Some municipalities had stopped load shedding without formal agreement from Eskom that 10% savings had been achieved

  • Eskom/Municipal Task team (Top 11 Metros and Municipalities)

    • This team met on 06 May 2008. It was agreed that the following issues will receive priority attention

      • Measurement and baselines

      • Tariffs and incentives (specifically for the crisis)

      • Water heating management – priority technology

      • DSM funding process – Global application for funding for key issues

      • New Connections, dealing with this consistently

      • Communication – Consistent message, Customer education

      • Non – payment (Non-technical losses)

      • Technologies – smart metering, lighting etc.

      • Legal framework

    • A small Task Team has been established to look at the key high impact activities with a common approach and the funding requirements. A follow-up meeting has been convened for 23rd of May 2008.

27


Engagement with key industrial customers and other customers

Engagement with Key Industrial Customers and other Customers

  • Industry Task Team chaired by representative from Industry set up after the January load shedding incidents to advise Eskom’s Chief Executive.

  • Developed various work streams to provided forums for discussion and where necessary agreement on certain protocols.

  • Weekly meetings of some of the streams and the task team meets every 2 weeks.

  • Agreement reached on protocols to measure and verify savings against various baseline consumptions.

  • Information is shared on current power system status and prognosis.

  • Debate occurs on the various streams of Eskom’s recovery programme and input received on possible lines of action.

28


Winter 2008 prognosis

29

Winter 2008 Prognosis


Assumptions for planning purposes

Assumptions for Planning Purposes

  • Load Forecast

    • Scenario A - Pessimistic

      • No more savings and cold winter starting in mid-May

    • Scenario B

      • Sustain savings at the current level (about 4 to 5% energy and up to 7% on peak demand)

      • Cold winter starting in mid May

    • Scenario C

      • Achieve required savings rapidly through conservation programme and engagement process.

      • Cold winter starting in mid May

    • Reality is probably somewhere around Scenario B

      • Others shown to indicate potential impact

      • Short term (May forecast) is slightly lower than Scenario B

    • Strong dependence on customer response

  • Supply Side

    • Generation maintenance plan as of 6th May 2008

    • Allowance for 1850MW to 1900MW of operating reserves in real time

    • Sensitivities of 2000, 3000, 4000 MW unplanned outages and output reductions of Generation plant

30


Colour coding1

Colour Coding

  • Green (sufficient operating reserves – 1800MW to 1900MW)

    • It is likely one may only have to use our scheduled generation resources and normal operating reserves. Green means we have the required level of operating reserves at our disposal.

  • Yellow (Between1800 and 800MW of operating reserves)

    • It is likely one will make extensive use of whatever DMP contracts we have and use EL1 extensively (i.e. generate above maximum capability rating at certain power stations). One may also make use of the interruptible load contracts over peak periods.

  • Orange (Up to 200MW short of meeting demand)

    • It is likely one will make extensive use of the interruptible load contracts and use the Open Cycle Gas Turbines in short bursts.

  • Red (between 1200MW and 200MW short of meeting demand)

    • It is likely one will resort to a high level of use of the Open Cycle Gas Turbines and Interruptible Loads and possibly have emergency load shedding in short bursts.

  • Brown (more than1200MW short of meeting demand)

    • It is likely one will have to resort to emergency load shedding.

31


Load shedding will be the last mechanism used to manage the system under any scenario

Load shedding will be the last mechanism used to manage the system under any scenario

32

32


Coding for may august 2008

Coding for May – August 2008

  • Continued and further Energy Savings is essential to ensure a stable system

  • Generation performance will still have a significant impact on the risk of manual load shedding

  • Planned maintenance will continue to optimised in the short term as far as possible depending on actual system status to minimise risks

33


Specific areas of concern on transmission network

Specific areas of concern on Transmission Network

  • Gauteng

    • The rapid growth in the recent history and the lack of significant investment in network infrastructure means that during peak periods in winter, a single fault in certain corridors or supply points (substations) will result in localised interruptions of supply.

    • Capacitor banks are being added which will mitigate some of the risks but will not eliminate many of the risks. The problem will take at least 5 years of continuous investment to alleviate.

  • KwaZulu-Natal

    • The network is vulnerable to any one of several 400kV lines faulting over peak periods and could result in a regional outage. Some of the risks have been mitigated by recent additions of capacitor banks but the network is still vulnerable to more than one fault.

    • Investments scheduled to be completed in the third quarter of 2009 will alleviate many of the current risks but continued investment is then required to keep up with projected growth.

  • Mpumalanga

    • The network east of Nelspruit is vulnerable to single faults on particular corridors.

  • Limpopo

    • Parts of the network supplying rural areas north of Polokwane are vulnerable to single faults.

  • General

    • There are still possibilities that multiple failures of plant result in localised interruptions of supply. The focus is on ensuring there are sufficient emergency spares to reduce the outage times to a minimum.

34


Conclusions on winter 2008 prognosis

Conclusions on Winter 2008 Prognosis

  • Energy savings are required to manage the network constraints as well as maintain an adequate supply demand balance. However it is still possible for single equipment failures in the transmission network to cause localised interruptions of supply which could persist for several days especially over peak periods. The focus is on minimising the possibility of plant failures through preventative maintenance where identified, elimination of specific risk factors (such as vegetation under certain lines) and location of certain spares where there is no redundancy.

  • The coal stockpile days have improved in April and are healthier with no stations under 13 days. There has been improved deliveries and lower burn at the various stations. There will be pressure on the stockpiles if the demand reduction is not maintained. Plans for deliveries to the stations have been made taking into account a high demand. It is anticipated that the stock days will slowly climb through winter to nearly 20 days. This will require detailed management of the various risks on a daily basis.

  • The supply demand balance is still very vulnerable and a continued focus is needed on maintaining the current level of savings and as quickly as possible achieving the targeted level of savings while focusing on generation and transmission plant performance.

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