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National Electricity Market

Management Company LimitedABN 94 072 010 327

2006 Minimum ReserveLevel Recalculation


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1.1 INTRODUCTION

NEMMCO determines minimum reserve levels which are consistent with the ReliabilityStandard. Minimum reserve levels were last reviewed by NEMMCO in 2004, and sincethat time Basslink has been commissioned, Kogan Creek is well advanced, and

generator forced outage data has been refined and clarified. As a result of thesechanges NEMMCO began modelling to review the current minimum reserve levels. Thiswork was foreshadowed in the 2005 Statement of Opportunities.

The following sections of this document provide a summary of the:

process adopted by NEMMCO in the calculation of minimum reserve levels;

feedback provided by the jurisdictions following briefings on preliminary results;

additional work conducted to address those concerns raised by the jurisdictions,particularly with regard to input data assumptions;

the minimum reserve levels being considered for implementation;

an explanation of negative minimum reserve levels; and

a regional assessment of the reserve margin available (assuming just sufficient

generation to just meet the minimum reserve levels) to each NEM region at timeof its 50% POE Scheduled Maximum Demand.

1.2 PROCESS

In January 2006 NEMMCO contracted ROAM Consulting to calculate the minimumreserve level for each region of the NEM, with the exception of Tasmania1. ROAMperformed similar work for NEMMCO in the 2003 and 2004 assessments.

The previous minimum reserve level assessment was completed in 2004. In thatassessment, NEMMCO developed a methodology that aimed to determine:

- The minimum level of NEM-wide installed capacity required to deliver theReliability Standard in each region.

This methodology was reviewed by KEMA Consulting, who made a number ofrecommendations regarding the assumptions used in modelling generator performance.To address these recommendations, NEMMCO and the NGF created the ForcedOutage Data Working Group (FODWG). The recommendations of the FODWG havebeen incorporated in the calculation of the generator forced outage statistics used inROAMs assessment. For more information on the FODWG and its activities please referto the following URL: http://www.nemmco.com.au/powersystemops/240-0011.htmOne of the most significant aspects of the FODWG activities was the collection of a set

of historical forced outage data records on an event by event basis from each NEMscheduled generator. This collection provided NEMMCO with significantly moreinformation than had been collected previously and allowed forced outage rate (FOR)statistics to be calculated by NEMMCO on a consistent basis. Previously NEMMCOrelied on generators to aggregate their own data set into a format suitable for the

1An assessment of the minimum reserve levels for Tasmania was excluded from the studies.

Instead the studies focus on assessing the impact of Tasmanian reserve capacity being availableto Victoria and South Australia across Basslink.

5 October, 2006 Page 2
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calculation of FOR statistics. It is believed that generators may have been inconsistentin their approach to data reporting and aggregation.

NEMMCO was not confident in the accuracy of the FOR data being used in the 2004minimum reserve level assessment and decided to double the FORs in the

determination case

2

. Given the increased confidence in the recently collected FOR dataset, NEMMCO no longer believes it necessary to double the FORs. Table 1 provides ahigh level summary of the differences between the FORs used in the 2006 and the 2004assessments.

Note: In the 2006 assessment both a Full Forced Outage Rate (FFOR) and a PartialForced Outage Rate (PFOR) were modelled. For each partial outage a mean derating(MeanDer) was applied to the relevant generator. An Equivalent Forced Outage Rate(EFOR) has been calculated for 2006 statistics to facilitate a comparison between the2006 EFOR and 2004 FOR.

Table 1 Comparison of forced outage rates used in 2006 and 2004 assessments

2004 ASSESSMENT

FFOR PFOR MeanDer EFOR FFOR

QLD BASE 3.72% 4.42% 16.81% 4.46% 5.00%

QLD PEAK 7.76% 5.83% 63.69% 11.47% 8.92%

QLD HYDRO 8.18% 0.26% 40.60% 8.28% 0.24%

QLD INTER 2.81% 4.70% 20.33% 3.77% 8.88%

NSW BASE 1.95% 5.95% 16.34% 2.93% 5.22%

SNOWY 1.78% 0.00% 0.00% 1.78% 1.80%

VIC BASE 4.62% 19.92% 12.44% 7.10% 3.72%

VIC PEAK 4.19% 0.17% 10.77% 4.20% 2.30%

VIC HYDRO 2.90% 2.13% 27.29% 3.48% 1.80%

SA BASE 3.79% 2.88% 11.23% 4.12% 4.70%

SA INTER 2.81% 4.70% 20.33% 3.77% 8.88%

SA PEAK 16.73% 5.55% 60.00% 20.06% 8.92%

TAS 1.25% 5.43% 21.10% 2.39% n/a

NERC GADS - New plant 10.00% 0.00% 0.00% n/a n/a

2006 ASSESSMENT

In addition to the FOR data, NEMMCO also provided ROAM Consulting with all inputdata required for their calculation of minimum reserve levels and performed shadowstudies on key simulation cases.

ROAM performed Monte Carlo analysis using their market simulation tool 24C anditeratively adjusted the amount of installed generation in each region to:

approach 0.002% USE within each region simultaneously; maximise the capability for reserve sharing between regions; and

approach an outcome which achieves the minimum level of installed generationwithin the NEM as a whole .

For more information on the process please refer to the attached report MinimumReserve Level Recalculation 2006.

2The FOR for all plant was doubled with exception to QLD baseload plant



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ROAM provided NEMMCO with preliminary results including a draft set of recommendedminimum reserve levels in March 06 and NEMMCO briefed each of the NEM

jurisdictions on these results during April.

1.3 JURISDICTIONAL FEEDBACK ON PRELIMINARY RESULTS - APRIL

Following the Jurisdictional briefings in April, two Jurisdictions (New South Wales andSouth Australia) raised concerns over some key input data used in the NEMMCOstudies 3.

The issues raised by the New South Wales jurisdiction related to the assumed timing ofa committed transmission augmentation in New South Wales. Concern was raised thatstudies may have incorrectly modelled the commissioning date of a project, andsubsequent impact on network constraints. NEMMCO has since confirmed that theTransGrid augmentation timing that was used in the simulation studies is consistent withthe advice provided by TransGrid.

The South Australian jurisdiction raised concern over the forced outage rates (FOR)used in the simulations, particularly for the South Australian peaking class of plant. Toaddress these concerns NEMMCO, ESIPC and the FODWG developed an agreedapproach to re-calculate the FORs for this class of plant. This new approach was moreconsistent with the recently developed definitions by the FODWG and delivered achange in the FOR from 25.1% to 16.73% for the SA peaking plant. The primary driverbehind the change in FOR was the exclusion of loss of availability events due to fuelsupply related outages beyond the control of the generators

On account of the revision made to the SA peaking class of plant NEMMCO revisited theFOR assumed for new open cycle gas turbines, and existing plant of this type without

any forced outage data history. NEMMCO requested information from the proponents ofnew committed generation regarding the expected long term FOR of their plant andsourced information from the North American Electric Reliability Council (NERC) GADSwebsite. This work resulted in a change in the FOR for this class of plant from 25.9% to10%.

The impact of the revised input data on the calculated minimum reserve level was thenassessed. The revised minimum reserve level recommendation is presented in section1.4.

3As these concerns would take time to resolve and additional sensitivity studies were required,

this precluded the minimum reserve level results being incorporated in the 2006 SOO/ANTS inearly June 2006. The SOO/ANTS will now be published in October with the existing reservelevels as the basis for all conclusions. The impact of revised minimum reserve levels on the 10year supply-demand outlook will be provided in the Executive Briefing document released withthe 2006 SOO.



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1.4 REVISED RECOMMENDED MINIMUM RESERVE LEVELS

ROAM recalculated the minimum reserve levels following modifications to the FOR inputdata outlined above. Table 2 identifies the revised minimum reserve levels calculated by

ROAM to deliver 0.002% USE in each region of the NEM simultaneously4

.

Table 2 NEM-Wide Draft Minimum Reserve Levels

[MW Above M10 Regional Demand Forecast]

Year QLD* NSW VIC & SA SA*

2006-07 480 -1490 370 370

2007-08 560 -1430 360 390

* This is a local requirement and must be met by generation within the region assuming 0MW

support from neighboring regions.

Notes:

A requirement for a 370 MW (2006-07) minimum reserve level sourcedsolely from within SA was identified. That is, SA must source 370 MW ofgeneration capacity within its own region in excess of the SA 10% POEScheduled Maximum Demand (MD), assuming 0 MW support from VIC.

Similarly a requirement for a 480 MW (2006-07) minimum reserve levelsourced solely from within QLD was identified, assuming 0 MW supportfrom NSW.

The minimum reserve levels in Table 2 are consistent with just achieving the ReliabilityStandard in all regions. However, the practical difficulties associated with sourcing370MW of generation in SA in excess of the SA 10% POE Scheduled MD must berecognised. In the near term it is unlikely that a minimum reserve level of 370MW in SA

will be achievable. If implemented in market systems reserve trader is likely to betriggered, and may fail to deliver the required level of supply.

In recognition of this practical limitation NEMMCO has re-assessed the minimum reservelevel requirement in South Australia considering the committed level of plant likely to beavailable in Victoria for the 2006-07 and 2007-08 years. That is, ROAM has conductedfurther simulation studies which attempt to minimise the minimum reserve level in South

Australia through consideration of the capacity available in Victoria. This method:

increases the combined Victoria and South Australia minimum reserve level;

reduces the South Australian minimum reserve level; and

delivers the Reliability Standard in South Australia but better than the ReliabilityStandard in Victoria.

Table 3 provides a summary of the minimum reserve levels which have been calculatedin this process.

4Please refer to the attached report Minimum Reserve Level Recalculation 2006 for more

information regarding the actual simulated USE outcomes.



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Table 3 Reliability Reserve Levels To Be Implented

[MW Above M10 Regional Demand Forecast]

Year QLD* NSW VIC & SA SA*

2006-07 480 -1490 615 -50

2007-08 560 -1430 615 -50* This is a local requirement and must be met by generation within the region.

The minimum reserve levels in Table 3 were approved by the NEMMCO Board andnoted by the Reliability Panel in September 2006.

1.5 EXPLANATION OF NEGATIVE MINIMUM RESERVE LEVELS

NEMMCO notes from previous discussions with jurisdictions and market participants thatit may be necessary to provide an explanation of how a region may have a negativeminimum reserve level. Figure 1.5 illustrates the relationship between the requiredscheduled generation in each region and the minimum reserve levels in Table 3 for the

2006-07 year, assuming: regional transfers that are simultaneously feasible;

interconnector transfers used to determine the minimum reserve levels in Table 3;

spare capacity in Tasmania is fully allocated to Victoria;

Snowy generation is fully allocated to Victoria and New South Wales; and

scheduled generation capacity in the Snowy region equal to that when determining

the minimum reserve levels in Table 3.

Considering New South Wales minimum reserve level of -1490 MW:

NSW can have a negative minimum reserve level because NSW has the ability to share

spare generation capacity from QLD, Snowy and VIC/SA (480 MW + 615 MW) usingspare transfer capability on the interconnectors. The NSW minimum reserve level has

been determined assuming transfers from QLD and Snowy of 1878 MW. Assuming a

maximum import capability into NSW of approximately 4000 MW (2900MW on Snowy1

and 1100MW from Qld) there is 2122 MW spare import capability. This spare import

capability provides NSW with access to share significant spare capacity with neighboring

regions. As a result NSW can have such large negative minimum reserve level.



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Figure 1.5QUEENSLAND

Minimum reserve level 480

Transfers from NSW 0

0 Actual import capability into QLD from NSW 300

Spare import capability into QLD 300

NEW SOUTH WALES

Minimum reserve level -1,490

1,878 Transfers from QLD and Snowy 1,878

Actual import capability into NSW from QLD and Snowy 4,000

Spare import capability into NSW 2,122

SNOWY

No minimum reserve level requirement

1,900 Scheduled generation 3,778

VICTORIA AND SOUTH AUSTRALIA


Transfers from Snowy and TAS 2,510

610 Actual import capability into VIC and SA from Snowy and TAS 2,510

Spare import capability into VIC 0

TASMANIA


Transfers to TAS from VIC -610

Actual import capability into TAS from VIC 500

Spare import capability into TAS 1,110

All numbers in MW except as otherwise signed.

Scheduled generation required = QLD 10% POE Scheduled demand - QLD DSP + QLD minimum reserve level

(480) - transfers from NSW

Scheduled generation required = NSW 10% POE Scheduled demand - NSW DSP + NSW minimum reserve

level (-1490) - transfers from QLD and Snowy

Scheduled generation required = TAS 10% POE Scheduled demand - TAS DSP + TAS minimum reserve level

(144) - transfers from VIC

Scheduled generation required = VIC 10% POE Scheduled demand + SA 10% POE scheduled demand - VIC

and SA DSP + VIC and SA minimum reserve level (615) - transfers from TAS and Snowy

Snowy

VIC AND SA

TAS

NSW

QLD

1.6 REGIONAL RESERVE MARGIN AT TIME OF 50% POE SCHEDULED

MAXIMUM DEMAND

Figures 1.6.1 to 1.6.4 provide an illustration of the reserve margin available to each NEMregion (with Victoria and South Australia treated as a single region). Each regionsreserve margin has been assessed sequentially under the following conditions:

The Scheduled demand in the region matches the 50% POE Scheduled MD

projection for summer 2006/07 5 less any committed DSP in the region.

The Scheduled demand in other regions is lower than the 50% POE Scheduled MD

projection as peaks in regional demand do not generally occur simultaneously. To

account for this, the demand shown assumes a 95% coincidence factor6.

Spare capacity in other regions is made available across interconnectors up to the

assumed maximum transfer capabilities defined in Table 4 7.

5The reserve available to Tasmania is illustrated at the time of the Tasmanian 50% POE

Scheduled MD projection for winter 2007.6

The Scheduled demand shown in other regions is 95% of the 50% POE Scheduled MDprojection.



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Sufficient scheduled generation is available in each region to satisfy no more than

the minimum reserve level requirements specified in Table 3 for summer 2006/07 8

The Snowy generation capacity matches the committed scheduled generation

capacity forecast for 2006/07.

Table 4 Assumed Maximum Transfer CapabilityInterconnector

Assumed Maxi mumTransfer Capability (MW)

QLD->NSW (QNI and Terranora) 1,1001

NSW->QLD (QNI and Terranora) 300

SNOWY->NSW 2,900

SNOWY->VIC 1,900

TAS->VIC 610

VIC->TAS 500

1. Special switching of some 132kV circuits in Northern New SouthWales may be necessary to achieve 1,100 MW under certainconditions, provided system security can be maintained.

Figure 1.6.1 Available Reserve Margin During 50% POE Scheduled MD Project ion(Summer 2006/07) - Queensland (MW)Coincidence Factor

Reserve (% Scheduled Demand) 14% QUEENSLAND 100%Scheduled Demand - DSP 9,071

Generation 10,058

Support from NSW 300

Reserve 1,287

300NEW SOUTH WALES 95%

Scheduled Demand - DSP 13,070

Generation 11,661

Support from Snowy & QLD 2,600

Reserve 1,191

2,900

SNOWY 95%Scheduled Demand - DSP 0

Generation 3,426

VICTORIA AND SOUTH AUSTRALIA 95%


Generation 11,756

Support from Snowy 526

610 Support from TAS 610

Reserve 1,164

TASMANIA 95%


Generation 2,002

Support from VIC -610

All numbers in MW except as otherwise signed Reserve 26

QUEENSLAND

526

QLD

Snowy

NSW

TAS

VIC AND SA

Figure 1.6.2 Available Reserve Margin During 50% POE Scheduled MD Project ion(Summer 2006/07) - New South Wales (MW)

7Transfers at the assumed maximum transfer capability can only be achieved if neighbouring

regions have sufficient spare generation capacity, and under appropriate system conditions.8

The reserve available to Tasmania is determined based on the Scheduled generation capacityto satisfy no more than the minimum reserve level of 144 MW for winter 2007.



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Coincidence Factor


Generation 10,058

Support from NSW -1,100

Reserve 345

1,100NEW SOUTH WALES 100%


Generation 11,661


Reserve 1,902

2,900SNOWY 95%

Scheduled Demand - DSP 0

Generation 3,426

VICTORIA AND SOUTH AUSTRALIA 95%


Generation 11,756

Support from Snowy 526

610 Support from TAS 610

Reserve 1,164

TASMANIA 95%


Generation 2,002



526

NEW SOUTH WALES

QLD

Snowy

NSW

TAS

VIC AND SA

Figure 1.6.3 Available Reserve Margin During 50% POE Scheduled MD Project ion(Summer 2006/07) - Victoria and South Aust ralia (MW)

Coincidence Factor


Generation 10,058


Reserve 3451,100

NEW SOUTH WALES 95%


Generation 11,661


Reserve 1,217

1,526SNOWY 95%


Generation 3,426

1,900VICTORIA AND SOUTH AUSTRALIA 100%


Generation 11,756

Support from Snowy 1,900610 Support from TAS 610

Reserve 1,906

TASMANIA 95%


Generation 2,002



VICTORIA AND SOUTH AUSTRALIA

QLD

Snowy

VIC AND SA

NSW

TAS



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Figure 1.6.4 Available Reserve Margin During 50% POE Scheduled MD Project ion(Winter 2007) - Tasmania (MW)

Coincidence Factor


Generation 8,467


Reserve 0

1,035NEW SOUTH WALES 95%


Generation 11,093


Reserve 556

1,526SNOWY 95%


Generation 3,426

1,900VICTORIA AND SOUTH AUSTRALIA 95%


Generation 8,898

Support from Snowy 1,900500 Support from TAS -500

Reserve 780

TASMANIA 100%


Generation 1,988

Support from VIC 500


TASMANIA

QLD

Snowy

NSW

TAS

VIC AND SA


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