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Market Surveillance & Compliance Panel Annual Report 2009

Contents

Executive Summary 1

Introduction 2

Market Monitoring

Catalogue of Data and Catalogue of Monitoring Indices 4

Indicators of Market Performance 4

Supply Indices Capacity Ratio 5 Supply Cushion 6 Market Share 8 Outages 10

Demand Indices Accuracy of Pre-Dispatch and Short-Term Load Forecast 14 Accuracy of Real Time Load Forecast 15

Price Indices Vesting Contract Hedge Price and Wholesale Electricity Price 16

Energy Metered Energy Quantity 17 Correlation Between the WEP and Metered Energy Quantity 18 Frequency Distribution of the WEP 20 Correlation Between the VCHP, Electricity Tariffs and Fuel Oil Prices 22

Ancillary Service Prices Reserve Prices 23 Interruptible Load as Reserve Provider 24 Regulation Prices 25

Econometric Model and Outlier Prices 27 Identification of Outlier Prices 28

Investigations Summary of Investigation Activities 35

Sections 50 and 51 of The Electricity Act 37

Assessment of the Wholesale Electricity Markets State of Competition and Efficiency of the Wholesale Electricity Markets 39 State of Compliance Within the Wholesale Electricity Market 41

Conclusion 43

User Guide 44

ExpressingEnergy:

Layer upon layer of translucent light bands suggest the infinite possibilities that lie within the living energy of electricity. Our design team created the images for this report using a translucent light band in a darkened studio to draw images captured on camera.

1

Executive Summary

DemandIndices

• The accuracy of demand forecasts in 2009 continued to see an improvement for the second consecutive year. The average forecast error declined from 3.78 percent to 3.46 percent.

• Average half-hourly electricity demand peaked in October at 4,686 megawatts (MW), slightly over the previous year’s peak of 4,654 MW (May 2008).

This annual report by the Market Surveillance and Compliance Panel (MSCP) covers the period from 1 January to 31 December 2009. Based on the analysis of data and monitoring indices that the Panel has collected and compiled to help it assess the performance of the wholesale electricity market, the MSCP has made the following observations for 2009:

SupplyIndices

• The supply cushion in 2009 declined to 23.9 percent from 24.3 percent in 2008. At the same time, average plant availability declined (-0.23 percent) while demand grew (+0.32 percent).

• The capacity ratio for Open Cycle Gas Turbine (OCGT) units increased from 0.1 percent to 0.5 percent, reflecting increased scheduling.

• The combined market share of the three largest generation companies edged up slightly from 77.1 percent in 2008 to 77.7 percent in 2009.

• Compared to 2008, generation outages increased by 23.6 percent, reflecting more frequent Steam Turbine (ST) unit outages.

MarketPrices

• Subdued demand in the first quarter of 2009, a result of the economic recession, kept the average wholesale energy price (WEP) at $85.30/megawatt hour (MWh), compared to the yearly average of $148.79/MWh.

• The highest single-day average WEP was $210/MWh in April 2009, when a combination of tight supply and rising demand resulted in multiple periods of price spikes.

• The average WEP remained primarily in the $130-$160/MWh range for the remainder of the year.

• The highest Uniform Singapore Energy Price (USEP) recorded for the year was $4,499/MWh. In four periods in 2009, the USEP rose to $4,000/MWh and above.

• Our econometric model identified a total of 29 days with outlier USEPs in 2009, a significant increase over the four days with outlier prices in 2008.

• Reserve prices rose in 2009 in line with an increase in the reserve requirement. This rise also coincided with more frequent forced outages.

In reviewing the state of compliance, competition and efficiency of the wholesale electricity markets, the MSCP further observes the following:

• The number of offer variations made after gate closure increased in 2009, but a majority of these instances did not breach the Market Rules.

• The MSCP needed to make only six determinations on rule breaches in 2009, down from 12 in 2008.

2

Introduction

Supported by the Market Assessment Unit (MAU) of EMC, the role of the MSCP is to monitor and investigate activities in the wholesale electricity markets and the conduct of market participants (MP), the Market Support Services Licensee (MSSL), the Power System Operator (PSO) and EMC to:

• identify breaches of the Market Rules, market manual or system operation manual;

• assess whether the underlying structure of the wholesale electricity markets is consistent with the efficient and fair operation of a competitive market; and

• recommend remedial actions to mitigate the conduct and inefficiencies referred to above.

The Market Rules provide for the Market Surveillance and Compliance Panel (MSCP) to prepare and submit to Energy Market Company (EMC) an annual report on the conduct of its monitoring and investigation activities. The report is then furnished by EMC to the Energy Market Authority (EMA). This is the eighth report by the MSCP on the wholesale electricity markets of the National Electricity Market of Singapore (NEMS).

The current report covers the period 1 January to 31 December 2009. This review provides the panel with the opportunity to address some important observations and concerns gathered over the year.

The current MSCP members:

• Thean Lip Ping, Chair;• Lee Keh Sai;• Professor Lim Chin;• TPB Menon; and• Philip Chua.

The Market Rules require this annual report to include a summary of routine reports on MSCP monitoring and investigation activities, and a summary of any reports regarding the possibility of anti-competitive agreements or the abuse of a dominant position contrary to sections 50 or 51 of the Electricity Act. The report also includes a summary of all complaints or referrals filed and investigations commenced, and a summary of any investigations conducted by the MSCP concerning offer variations after gate closure reported by EMC. The Market Rules require the report to contain the general assessment by the MSCP of the state of competition and compliance within, and the efficiency of, the wholesale electricity markets.

3

Market Monitoring

4

Market Monitoring: Catalogue of Data and Catalogue of Monitoring Indices

To carry out monitoring effectively, the Market Rules provide for the MAU, under the supervision and direction of the MSCP, to develop a catalogue of the data it acquires and a catalogue of the monitoring indices that it uses to evaluate data acquired.

On 29 August 2003, a catalogue of data was adopted by the MSCP after public consultation. It took effect from 1 October 2003. Data is collected according to this catalogue, with the assistance of market players.

On 29 July 2004, a catalogue of monitoring indices was adopted by the MSCP after public consultation. It took effect from 1 August 2004. The catalogue of monitoring indices is used to evaluate the market data collected.

Market Monitoring: Indicators of Market Performance

The MAU submits regular monitoring updates to the MSCP. These updates include observations of several indicators of market performance. These indicators can be broadly classified into supply, demand and price indices. In the following sections, the MSCP reports its observations from these indices for the year under review.

5

Market Monitoring: Supply Indices: Capacity Ratio

Average capacity ratio for Combined Cycle Gas Turbine (CCGT) units was 78.2 percent in 2009 (see Table 1), a 1.3 percentage point drop from 2008. This decline reflects a higher average maximum capacity, the result of two additional CCGT units which began commissioning in October and December 2009. More frequent CCGT maintenance led to a lower average scheduled generation output and decreased average CCGT capacity ratio.

OT = other facilities, i.e. incineration plants that convert energy from incinerated refuseOCGT = open-cycle gas turbine

In contrast, Open Cycle Gas Turbine (OCGT) units saw an increase in average capacity ratio from 0.1 percent in 2008 to 0.4 percent in 2009. Notably, in April 2009 OCGT capacity ratio peaked at 1.82 percent. This peak coincided with lower CCGT and Steam Turbine (ST) offer availability during that month.

Meanwhile, average capacity ratio for ST units rose slightly by 1.9 percentage point to 20.9 percent in 2009 compared to 2008. One ST unit was decommissioned in February and another ST unit had its maximum capacity revised to 0MW in October 2009, resulting in a decrease in average maximum capacity. Despite having two fewer units available, and higher ST planned maintenance, average scheduled ST generation output was higher compared to 2008, contributing to the higher average ST capacity ratio.

Chart 1 shows the capacity ratios for CCGT and ST units. The monthly pattern of CCGT capacity ratios for 2009 was similar to that of 2008 but generally lower on average. December 2009 also saw the largest decline of 5.33 percentage point in CCGT capacity ratio as compared to December 2008. Meanwhile, capacity ratios for the ST units from June to December 2009 were higher than during 2008.

Table1:CapacityRatio(in%)2009 Chart1:ComparisonofCapacityRatioforSTandCCGT

CCGT ST OT OCGT

Jan 09 75.9 13.6 46.7 0.0

Feb 09 77.0 17.1 47.0 0.2

Mar 09 77.3 16.2 43.5 0.3

Apr 09 78.4 20.3 45.2 1.8

May 09 81.4 20.6 43.0 0.6

Jun 09 78.9 27.0 47.5 0.5

Jul 09 80.5 22.0 45.7 0.4

Aug 09 81.7 20.5 46.4 0.2

Sep 09 83.3 20.5 34.2 0.5

Oct 09 79.0 27.3 39.5 0.6

Nov 09 74.3 24.2 39.8 0.2

Dec 09 71.2 22.2 39.9 0.0

Average 78.2 20.9 43.2 0.4

The capacity ratio of generation registered facilities, i.e., the ratio of scheduled generation output to maximum generation capacity of generation registered facilities.

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6

Chart 2 shows the relationship between the USEP and the supply cushion, which measures the level of spare capacity available after dispatch. The supply cushion decreased from 24.3 percent in 2008 to 23.9 percent in 2009. This decrease was the result of a 0.23 percent decrease in plant offer availability and a 0.32 percent increase in demand.

Historically, more occurrences of high prices were observed when the supply cushion fell below 15 percent. However, for 2009, of the 241 occurrences of the USEP at $500/MWh and above, 157 occurrences were observed when the supply cushion was at or above 15 percent (see Chart 3). These high prices reflect a significant increase over 2008, when of the 91 occurrences of the USEP at $500/MWh and above, 48 occurrences were observed when the supply cushion was at or above 15 percent.

Supply cushion: the ratio between (a) the supply and demand gap (i.e., the difference between total offered volume and system demand); and (b) supply.

Market Monitoring: Supply Indices: Supply Cushion

Chart2:RelationshipbetweentheUSEPandtheSupplyCushion—2003to2009 Chart3:RelationshipBetweentheUSEPandtheSupplyCushion—2009

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7

Market Monitoring: Supply Indices: Supply Cushion

Table 2 shows that with the supply cushion below 15 percent, the average USEP was $599.42/MWh in 2009. When the supply cushion rose to 15 percent and above, the average USEP decreased to $140.73/MWh. The maximum USEP when the supply cushion was below 15 percent increased from $1,126.03/MWh in 2008 to $4,499.41/MWh in 2009. Similarly, the maximum USEP when the supply cushion is at or above 15 percent increased from $955.52/MWh in 2008 to $1,572.58/MWh in 2009.

Table2:RelationshipBetweentheUSEPandtheSupplyCushion

Supply Cushion < 15% Supply Cushion ≥ 15%

Year No. of Periods Average USEP Max USEP No. of Periods Average USEP Max USEP

2003 319 272.91 4,500.00 17,201 89.00 1,904.56

2004 74 339.50 4,500.00 17,494 81.26 1,624.68

2005 109 607.48 4,430.65 17,411 106.79 2,229.61

2006 191 477.21 4,500.00 17,329 128.62 930.77

2007 278 332.54 4,500.00 17,242 121.22 988.06

2008 127 391.43 1,126.03 17,441 160.59 955.52

2009 268 599.42 4,499.41 17,252 140.73 1,572.58

8

Market Monitoring: Market Share

Chart 4 shows the yearly market share of the different generation types based on metered energy. Chart 5 shows the yearly market share based on maximum plant capacity. The distribution of market share based on metered energy quantity by each generation type in 2009 was similar to 2008. Meanwhile, based on maximum capacity, CCGT units’ market share was 1.6 percentage point higher than 2008. This increased market share was mainly due to the introduction of two new CCGT units in 2009. In contrast, ST units’ market share declined by 1.9 percentage point, as one ST unit was decommissioned and a second had its maximum capacity revised to zero in 2009.

Chart4:MarketShareBasedonMeteredEnergyQuantitybyGenerationType Chart5:MarketShareBasedonMaximumCapacitybyGenerationType

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9

Market Monitoring: Market Share

Charts 6 and 7 show the yearly market shares of all generation companies by metered energy and maximum generation capacity. Two new generation facilities (both incineration plants) entered the market in 2009, in September and October 2009*.

The combined market share of the three largest generation companies based on metered energy was 77.7 percent. This was 0.6 percentage point higher than the combined share in 2008.

Chart6:MarketShareBasedonMeteredEnergyQuantitybyGenerationCompany Chart7:MarketShareBasedonMaximumCapacitybyGenerationCompany

* The combined market share of the two incineration plants is less than 0.25 percent.

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G7 G8

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10

Total outages rose by 246MW to 1,266MW in 2009 compared to 2008 (see Table 3). This amount was based on an average installed capacity of 10,236MW and accompanied by an average demand of 4,476MW. Average planned outage quantity increased from 682MW in 2008 to 1,091MW in 2009. The increase was mainly contributed by ST planned outages. Conversely, average unplanned outages saw a decrease of 139MW compared to 2008. Meanwhile, average forced outage quantity rose from 12MW in 2008 to 38MW in 2009.

Chart 8 provides the breakdown of plant outages by planned, unplanned and forced outages. Planned outages made up 86.1 percent of total outages in 2009, while unplanned and forced outages made up 10.9 percent and 3.0 percent, respectively. This is in contrast to 2008, where planned, unplanned and forced outages made up 66.9 percent, 31.9 percent and 1.2 percent respectively.

Market Monitoring: Outages

Chart8:CompositionofTotalPlantOutages

Table3:AverageOutagesbyGenerationTypeandTechnologybyMW(perperiod)

Anticipated Outages (MW) Forced Outages (MW) Total Outages (MW)

Planned Outages Unplanned Outages

Year ST CCGT OCGT OT ST CCGT OCGT OT ST CCGT OCGT OT

2003 425 167 5 30 0 0 0 0 4 45 0 1 677

2004 982 204 14 3 64 2 2 0 2 37 0 0 1,309

2005 915 363 22 26 0 1 1 0 7 35 0 0 1,370

2006 854 283 51 17 0 2 1 0 4 21 1 0 1,234

2007 761 348 28 32 159 94 1 7 6 27 0 0 1,464

2008 439 236 1 6 298 26 0 2 2 10 0 0 1,020

2009 826 250 2 13 108 29 0 2 20 7 10 1 1,266

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Planned Unplanned Forced

2003 2004 2005 2006 2007 2008 2009

11

Despite more anticipated outages in 2009, the average USEP was lower in the first three quarters compared to the same period in 2008 (see Chart 9). However, in the fourth quarter, the average USEP increased to $160.75/MWh, a 40.6 percent increase over $114.36/MWh in fourth quarter 2008. The increased average USEP coincided with higher fuel oil prices in fourth quarter 2009, 62.1 percent higher than in fourth quarter 2008. Demand was also higher by 6.4 percent for fourth quarter 2009 than for fourth quarter 2008.


Chart9:AverageQuarterlyAnticipatedOutagesvstheAverageUSEP2003/2009

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12

Since 2005, the MSCP has been monitoring the USEP in excess of $1,000/MWh and its relationship with outages and the supply cushion. In 2009, a total of 43 periods were observed in which the USEP exceeded $1,000/MWh. These peaks are shown in Table 4, which also shows the prevailing supply conditions measured by anticipated outages, forced outages and supply cushion.

Most high price incidents occurred in the shoulder and peak periods, with the exception of one incident that occurred during an off-peak period on 10 June 2009. Of the 43 periods of price spikes, 23 occurred when the supply cushion fell below 15 percent.

28 March 2009

There were two periods of price spikes on Saturday, 28 March 2009. During these periods, one CCGT unit was out on maintenance, so offer availability of CCGT units was low. Demand was also higher than on three previous Saturdays in the month. Thus, the day’s high demand set off price spikes.

20 to 23 April 2009

17 periods of price spikes were observed for four consecutive days—20 April to 23 April 2009. During these four days, anticipated outage quantity was high and a forced outage occurred on 22 April 2009. However, no forced outage occurred in the remaining three days. Offer availability of CCGT units was lower than usual, as three CCGT units were taken out for maintenance. Only one CCGT unit resumed operations on 22 April. The tight supply condition coupled with higher than average demand resulted in the supply cushion falling below 15 percent. Lower volume of low-priced offers also contributed to the price spikes.

13 May 2009

On 13 May, three periods of high prices coincided with the forced outage of three CCGT units and higher demand. The supply cushion was tight at below 10 percent.


Table4:OutagesandSupplyCushionforPeriodsWhentheUSEPwasHigherThan$1,000/MWh

Anticipated Forced Supply Period USEP Outages Outages Cushion Date Period Type ($/MWh) (MW) (MW) (%)

28 Mar 09 23 Shoulder 1,005.32 1,108.0 0 16.74

28 Mar 09 24 Shoulder 1,005.36 1,108.0 0 17.33

20 Apr 09 31 Peak 3,021.54 1,755.3 0 12.16

20 Apr 09 32 Peak 1,655.13 1,755.3 0 12.02

20 Apr 09 33 Peak 1,639.66 1,755.3 0 12.08

21 Apr 09 25 Peak 3,326.14 1,755.3 0 12.20

21 Apr 09 26 Peak 3,424.30 1,755.3 0 11.68

21 Apr 09 27 Peak 3,576.15 1,755.3 0 10.38

21 Apr 09 28 Peak 3,674.28 1,755.3 0 11.16

21 Apr 09 29 Peak 3,948.97 1,755.3 0 10.99

21 Apr 09 30 Peak 3,947.96 1,755.3 0 11.16

21 Apr 09 31 Peak 3,621.70 1,755.3 0 11.49

21 Apr 09 32 Peak 1,008.14 1,755.3 0 12.63

22 Apr 09 26 Peak 4,029.06 1,542.8 206 11.99

22 Apr 09 27 Peak 4,029.36 1,542.8 206 11.50

22 Apr 09 28 Peak 4,499.41 1,542.8 206 9.67

22 Apr 09 29 Peak 4,485.03 1,542.8 206 11.65

23 Apr 09 32 Peak 1,156.78 1,542.8 0 15.69

23 Apr 09 33 Peak 1,109.40 1,542.8 0 15.83

13 May 09 30 Peak 3,521.67 500.0 590 9.72

13 May 09 31 Peak 3,521.41 500.0 343 9.70

13 May 09 34 Peak 1,832.39 500.0 343 8.87

13

10 June 2009

One period of price spike also occurred during an off-peak period on 10 June. This spike was caused by a sudden dip in the supply cushion when the decline in supply outstripped the decline in demand.

16 and 17 August 2009

In August 2009, two instances of price spikes occurred on 16 and 17 August 2009, the result of higher demand and tight supply conditions.

4 and 13 September 2009

Four periods of price spikes occurred on 4 September 2009 following the forced outage of a ST unit. The sudden decline in supply together with higher demand resulted in a tight supply cushion. A further six periods of price spikes occurred on Sunday 13 September 2009 that coincided with an unexpected rise in demand. Lower volume of low-priced offers also contributed to the price spikes.

6, 9, 13 and 20 October 2009

In October, a total of five price spikes occurred across three consecutive Tuesdays (6, 13 and 20 October 2009). One price spike occurred on 6 October 2009 following the forced outage of two ST units; one CCGT unit was also down for partial maintenance on that day. The resulting tight supply coupled with higher demand pushed the supply cushion below 15 percent. On 9 October 2009, two consecutive price spikes due to higher demand were observed.

On the following Tuesday, 13 October 2009, a CCGT unit experienced forced outage in period 26. With two other CCGT units already out on maintenance, CCGT offer availability was significantly reduced. Consequently, two periods of price spikes were triggered when demand peaked for the day. Two price spikes also occurred on 20 October during periods 25 and 43, mainly due to a sudden dip in the supply cushion when decline in supply exceeded decline in demand.

2 December 2009

On 2 December 2009, one price spike was triggered as a result of higher demand and a tighter supply.


Table4:OutagesandSupplyCushionforPeriodsWhentheUSEPwasHigherThan$1,000/MWh

Anticipated Forced Supply Period USEP Outages Outages Cushion Date Period Type ($/MWh) (MW) (MW) (%)

10 Jun 09 2 Off-Peak 1,303.26 1,142.5 31 15.20

16 Aug 09 42 Shoulder 1,007.01 1,578.5 0 19.63

17 Aug 09 28 Peak 1,007.85 1,578.5 0 15.44

4 Sep 09 32 Peak 1,503.30 876.0 361 11.11

4 Sep 09 33 Peak 3,363.39 876.0 361 9.22

4 Sep 09 34 Peak 1,503.21 876.0 361 10.11

4 Sep 09 35 Peak 1,007.33 876.0 361 11.93

13 Sept 09 39 Shoulder 1,003.76 1,248.0 0 17.40

13 Sept 09 40 Shoulder 1,003.75 1,248.0 0 17.17

13 Sept 09 41 Shoulder 1,268.20 1,248.0 0 16.91

13 Sept 09 42 Shoulder 1,204.14 1,248.0 0 17.05

13 Sept 09 43 Shoulder 1,394.22 1,248.0 0 16.81

13 Sept 09 44 Shoulder 1,207.42 1,248.0 0 16.89

6 Oct 09 17 Shoulder 1,007.40 962.5 578 10.60

9 Oct 09 27 Peak 1,007.52 1,365.0 0 15.56

9 Oct 09 28 Peak 1,007.55 1,365.0 0 15.39

13 Oct 09 28 Peak 1,572.58 1,507.5 271 15.03

13 Oct 09 29 Peak 1,510.48 1,507.5 271 15.58

20 Oct 09 25 Peak 1,007.60 1,142.5 0 16.24

20 Oct 09 43 Shoulder 1,139.36 1,142.5 0 17.42

2 Dec 09 27 Peak 1,004.27 1,370.0 100 17.34

14

Market Monitoring: Demand Indices: Accuracy of Pre-Dispatch and Short-Term Load Forecast

In the NEMS, three forecast schedules with different time horizons are made available to MPs. Accuracy of forecast schedules is important for efficient market operations, allowing generation plants to respond appropriately in real time.

Table 5 shows the accuracy of the load forecast as measured by the mean and standard deviations of the differences between forecast and actual real-time load. Similar to the previous year, the difference between the Short Term Schedule (STS) forecast and real time is smaller than that between Pre-Dispatch Schedule (PDS) forecast and real time by four to five times. This difference is within expectation, as STS forecasts are updated every half-hour, with a forecast horizon of up to six hours, compared to PDS forecasts which are updated every two hours, with a forecast horizon of between 12 to 36 hours.

Average differences in 2009 between PDS and STS forecasts with real-time forecasts were slightly higher compared to 2008 (see Chart 10).

Table5:AccuracyofLoadForecasts2009 Chart10:AverageMeanDifferenceBetweenLoadForecast&RealTime

Difference between PDS & Real Time Difference between STS & Real Time

Mean (in MW) Standard Deviation Mean (in MW) Standard Deviation (in MW) (in MW)

Jan 60 50 12 9

Feb 53 39 12 9

Mar 35 26 8 6

Apr 36 29 8 6

May 31 26 7 6

Jun 37 31 8 7

Jul 35 31 8 7

Aug 40 29 9 6

Sep 54 31 12 8

Oct 47 36 10 8

Nov 35 28 8 6

Dec 33 29 7 5

Average 41 32 9 7

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15

Market Monitoring: Demand Indices: Accuracy of Real Time Load Forecast

The accuracy of the load forecast used in generating real-time dispatch and pricing schedules is important for efficient pricing outcomes and system security.

A small amount of difference between real-time load forecast and actual demand (metered energy quantities) is expected. A number of factors contribute to this difference. The metered energy quantity furnished by the MSSL excludes the station load and auxiliary load consumption, while the real-time load forecast includes these components. Other factors include loss factors and metering errors.

As Table 6 shows, the average forecast error in 2009 was 3.46 percent, considerably lower than the 3.78 percent in 2008. This year marked the second consecutive year of improvement in average load forecasts.

Table6:DifferenceBetweenRealTimeLoadForecastandMeteredDemand(%)

2005 2006 2007 2008 2009

Jan 3.65 3.96 4.29 3.93 3.46

Feb 3.64 4.28 4.52 4.01 3.48

Mar 3.78 3.88 4.25 3.77 3.40

Apr 3.33 4.02 4.40 3.97 3.50

May 3.62 4.18 4.20 3.89 3.41

Jun 3.73 4.18 4.11 3.76 3.93

Jul 3.85 4.33 4.05 3.96 3.45

Aug 4.10 4.15 3.94 3.68 3.54

Sep 4.27 3.98 3.94 3.70 3.34

Oct 4.24 4.21 4.21 3.74 3.54

Nov 4.23 4.18 3.88 3.40 3.28

Dec 4.38 4.12 3.74 3.60 3.24

Average 3.90 4.12 4.13 3.78 3.46

16

Market Monitoring: Price Indices: Vesting Contract Hedge Price and Wholesale Electricity Price

The average vesting contract hedge price (VCHP) was $145.76/MWh in 2009, 23.1 percent lower than the VCHP of 2008. This decline was due to a lower average price of the benchmark 180-centistoke high sulphur fuel oil (180-CST HSFO), which decreased by 26.6 percent from US$78.90 per barrel (bbl) in 2008 to US$57.91/bbl in 2009. Daily volume weighted average wholesale electricity price (WEP) also dropped by 7.1 percent, from $163.46/MWh to $151.90/MWh.

Chart 11 shows the relationship between the daily volume-weighted average WEP and the VCHP. The WEP was significantly higher than the VCHP for seven consecutive months (April to October) in 2009, as compared to six consecutive months (April to September) in 2008. As in 2008, the latter observations coincided with high fuel oil prices during that period.

The highest average daily volume weighted WEP reached a record level of $210.05/MWh in April 2009. The previous record was set in May 2008 when the WEP reached $204.81/MWh. The high WEP in April 2009 was due to a number of factors. Demand growth for April 2009 was the highest in the year at 5.0 percent. Conversely, supply only rose by 1.0 percent in that period. Average CCGT outage quantity was also at one of its highest. These factors, together with a 2.9 percent drop in low-priced offers over March 2009, contributed to the high WEP in April 2009.

April 2009 was also the first time the WEP exceeded the VCHP by 82.2 percent. The high WEP coincided with the highest number of periods (90 periods) in which OCGT units were scheduled to run in one month for 2009. These 90 periods made up almost a quarter (24.3 percent) of the total number of periods OCGT units were scheduled to run in 2009.

For the next 6 months, the WEP remained high. This was partly due to stronger demand, peaking at 4,686 MW in October 2009. The rate of demand growth had outstripped the rate of supply increase for May, June and September 2009. High CCGT maintenance was also experienced in June, July and October 2009. Meanwhile, the highest number of occurrences of forced outage was observed in August and October 2009. Thirteen occurrences were observed in both months. In addition, the volume of low priced offers declined continuously from May to September. These factors combined to put upward pressure on the WEP. OCGT units were scheduled to run an average of 37 periods per month from May to October 2009.

In November 2009, the WEP moderated to $145.22/MWh, considerably below the VCHP of $161.70/MWh. Compared to October 2009, the WEP decreased by 26.6 percent during that month. This decline in the WEP was largely due to demand decreasing significantly by 3.0 percent, as compared to supply which only declined by 0.4 percent. The volume of low-price offers also increased by 0.5 percent in November 2009 compared to the preceding month.

Chart11:DailyVolume-WeightedAverageWEPvstheVCHP

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17

Chart 12 shows the actual demand (computed from the metered energy quantity) from 2003 to 2009. The growth in average system demand in 2009 was 0.52 percent, compared to 1.24 percent in 2008 and 4.49 percent in 2007.

Demand in the first two quarters of the year was lower than the previous two years, an expected result of the economic recession. It began to grow year-on-year only in June. The peak average system demand was 4,686 MW and was recorded in October 2009.

Market Monitoring: Energy: Metered Energy Quantity

Chart12:ComparisonsofActualDemand

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18

The correlation coefficient r in Table 7 measures the strength of the relationship between the WEP and metered energy quantity. A positive correlation indicates that as demand increases, the energy price tends to increase and vice versa. The square of the correlation coefficient r2 can be interpreted as the proportion of variance in prices that can be explained by variation in the demand.

As with 2008, low r values can be observed in April to June, while a high r value can be observed in November. There are 250 days in 2009 when r > 0.5.

Market Monitoring: Energy: Correlation Between the WEP and Metered Energy Quantity

Table7:MonthlyAverageCorrelationCoefficientoftheWEPandMeteredEnergyQuantity

2008 2009

Number of Number of Correlation Days with Correlation Days with Coefficient, r r2 r > 0.5 Coefficient, r r2 r > 0.5

Jan 0.52 0.27 19 0.59 0.35 21

Feb 0.48 0.23 16 0.66 0.44 23

Mar 0.63 0.40 25 0.61 0.38 24

Apr 0.30 0.09 10 0.38 0.14 14

May 0.43 0.18 12 0.41 0.17 14

Jun 0.54 0.29 20 0.39 0.15 11

Jul 0.63 0.39 25 0.56 0.32 21

Aug 0.64 0.40 24 0.53 0.28 17

Sep 0.48 0.23 15 0.62 0.38 24

Oct 0.69 0.47 25 0.63 0.39 21

Nov 0.73 0.53 27 0.86 0.74 30

Dec 0.55 0.30 19 0.80 0.64 30

Average 0.55 0.32 237 0.59 0.37 250

19

Market Monitoring: Energy: Correlation Between the WEP and Metered Energy Quantity

Chart 13 illustrates the correlation between the WEP and metered energy quantity in 2009. The highest correlation so far can be observed in November 2009, where the r2 value reached 0.74 and there are 30 days where r is greater than 0.5. Low r2 values of 0.14, 0.17 and 0.15 can be observed in the months of April to June 2009, which also coincides with the highest average WEP of the year. This implies that during April to June 2009, the movement of the WEP was heavily influenced by factors other than simple demand.

Chart 14 shows the correlation between the WEP and metered energy quantity between 2003 and 2009. After a sharp decline from 2003 to 2005, there was a steady increase in both the square of correlation coefficient and the number of days with r > 0.5.

In 2008 and 2009, the correlation between the WEP and the metered energy quantity fell below the 2007 level. Price changes were more heavily influenced by factors such as fuel oil prices, offer behaviours and outage levels.

Chart13:CorrelationBetweentheWEP&MeteredEnergyQuantity—2009 Chart14:CorrelationBetweentheWEP&MeteredEnergyQuantity—2003/2009

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20

Chart15:PercentageofHoursWhentheWEPFallsIntoaParticularPriceRange Chart16:PercentageofEnergyQuantityWhentheWEPFallsIntoaParticularPriceRange

Frequency distribution of the WEP by (a) percentage of hours of occurrence and (b) percentage of energy quantity affected.

Chart 15 illustrates the distribution of the WEP based on percentage of hours of occurrence in 2009. In the first quarter, the mean level of the WEP was in the $70–$90/MWh tranche. The mean level of the WEP then shifted to the $130–$150/MWh tranche in the second, third and fourth quarters. The widest spread of offer distribution can be observed in the second quarter.

Chart 16 illustrates the distribution of the WEP based on percentage of energy quantity. The distribution is similar to that of the distribution of the WEP by percentage of hours of occurrence (Chart 15).

Market Monitoring: Energy: Frequency Distribution of the WEP

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21

Chart17:PercentageofHoursWhentheWEPFallsIntoaParticularPricerange—2003/2009

Chart18:PercentageofEnergyQuantityWhentheWEPFallsIntoaParticularPriceRange—2003/2009

Chart 17 juxtaposes the historical price distribution curves with the price distribution curve of 2009, allowing us to examine longer-term trends. From 2004 to 2008, the average WEP has gradually shifted to the right.

The trend changes in 2009, as the two clusters of prices shifted to the left, indicating lower prices in general. Prices clustered around $70-$90/MWh and $130-$150/MWh, with the first cluster representing about 17 percent and the second cluster 26 percent.

Chart 18 shows the long-term trend in the distribution of the WEP based on percentage of energy quantity, permitting the same observations as with Chart 17.

Market Monitoring: Energy: Frequency Distribution of the WEP

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22

Chart19:IndexofVCHP,WEP,FuelOil(I8O-CSTHSFO),TariffChart 19 shows the correlation between the fuel oil price (180-CST HSFO), the VCHP, the WEP and domestic electricity tariff. Beginning January 2009, fuel oil prices increased steadily across the year. As the VCHP and electricity tariff are pegged to three-month fuel oil forward prices, rising fuel oil prices had a lagged effect. However in 2009, the WEP did not track the fuel oil prices as closely as it did in 2008. Instead, changes in the WEP were inversely related to changes in fuel oil prices for the months of May, September, November and December 2009.

Fuel oil prices rose on a month-on-month basis in May and November 2009 by 19.6 percent and 5.9 percent, respectively. However, the corresponding WEP dropped 15.8 percent and 25.5 percent, respectively. Conversely in September 2009, fuel oil prices declined by 0.8 percent while the WEP increased by 7.1 percent. This situation reflected demand growth outstripping supply. There was also a 3.6 percent drop in low-priced offers.

Similarly in December 2009, fuel oil prices decreased by 0.3 percent while the WEP increased by 3.4 percent. The increased WEP reflected supply declining more than demand.

On a different note, the WEP in April 2009 saw a significant month-on-month increase of 126.8 percent despite fuel oil prices increasing by only 17.6 percent.

In April 2009, the fuel component of the quarterly VCHP was reviewed and then pegged to the three-month fuel oil forward price established in the first two-and-one half months of the preceding quarter. The change was implemented in third quarter 2009.

Market Monitoring: Energy: Correlation Between the VCHP, Electricity Tariffs and Fuel Oil Prices

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23

Chart20:AverageReservePrices

After reaching a low in 2008, reserve prices rose significantly in 2009 (see Chart 20). This increase in reserve prices was partly due to an increase in reserve requirement, 1.7 percent higher in 2009 compared with 2008 (see Chart 21). The higher reserve requirement in 2009 also coincided with a higher average forced outage quantity, which increased by 198.5 percent when compared with 2008. On the whole, the average primary reserve price increased from $0.39/MWh in 2008 to $1.70/MWh in 2009. Both secondary and contingency reserve prices also hit record highs of $8.46/MWh and $17.52/MWh, respectively. The high total reserve payment by generation companies in 2009 reflected the high reserve prices.

Chart21:AnnualReserveCostandRequirement

Market Monitoring: Ancillary Service Prices: Reserve Prices

Reserve Prices ($/MWh)

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Chart23:TotalPercentageContributionfromILinThreeClassesofScheduledReserve

Chart22:NumberofILActivationsin2009

In 2009, Interruptible Load (IL) was activated on eight occasions to provide reserve (see Chart 22). In July 2009, one IL provider exited the market, leaving two IL providers with a combined reserve capacity of 21MW for each class of reserve.

Compared to 2008, the total percentage contribution from IL in the three classes of scheduled reserve decreased significantly and receded to near-2005 levels (see Chart 23).

Market Monitoring: Ancillary Service Prices: Interruptible Load as Reserve Provider

Number of IL Activations

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25

Chart24:RegulationAvailabilityvsRegulationPrice

The EMA revised the cap on the regulation price from $2,750/MWh to $300/MWh on 14 May 2009. The average regulation price in 2009 increased 73.5 percent over 2008 to $54.75/MWh. For 2009, regulation prices reached their peak in June and October, with highs of $92.21/MWh and $96.01/MWh respectively. The last time the regulation price exceeded $90/MWh at an average of $356.64/MWh was during January to March 2007.

Chart 24 shows the regulation offer patterns in various offer price tranches. Since June 2009, no regulation offers above $300/MWh were made. Nevertheless, a shift in regulation offers toward offer prices at $50.01/MWh and above was observed. Regulation offers priced $50/MWh and below declined by 9.7 percent. Meanwhile, regulation offers priced between $50.01/MWh and $100/MWh increased 7.6 percent. Offers priced between $100.01/MWh to $200/MWh increased 65.1 percent. Finally, offers between $200.01/MW to $300/MWh showed the greatest increase, 1,217.5 percent over 2008. This overall change in regulation offer pattern contributed to generally higher regulation prices in 2009.

Market Monitoring: Ancillary Service Prices: Regulation Prices

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Econometric Model and Outlier Prices

27

Table8:EstimationResults—January2003toDecember2008Since 2007, the MSCP has been using an econometric model to identify and analyse high price incidents*. The model provides a means of estimating the average USEP through the use of independent variables, including the CCGT supply, ST supply, energy supply cushion, offers lower than $100/MWh, energy demand, reserve cushion and lagging fuel oil prices. The model is also adjusted to differentiate planned outages from generation companies with different portfolios, and forced outages by month, day-of-week, and year via the use of dummy variables.

As part of our efforts to review and enhance the model, following the publication of the 2008 MSCP Annual Report we tackled the issue of multicollinearity between variables within the model. While multicollinearity does not affect the predictive and detection powers of the model, it may misrepresent the explanatory power of the variables in the model. In particular, the coefficients of the independent variables may be distorted to some degree. In addition, some variables may be statistically insignificant.

After conducting a correlation study between the “independent” variables, we found that high collinearity exists between some variables in the econometric model. This is not particularly surprising since generation companies would likely base many of their business decisions on

Econometric Model and Outlier Prices

costs. For example, as fuel price increases, we can expect a higher supply of offers from CCGT units and lower supply of offers from ST units. This would likely be due to the fact that CCGT units are more fuel-efficient than ST units. High fuel prices will compel generation companies to make use of the more fuel-efficient technology. Moreover, higher fuel prices will mean a lower proportion of offers below $100/MWh, as generation companies seek to pass the higher fuel costs on to consumers.

To reduce multicollinearity in the model, we use a stepwise regression. Stepwise regression is a statistical technique in which variables are added to a model in a forward selection or backward elimination procedure to determine their contribution to the regression model. The statistical significance of the variable is measured by its additional contribution to the residual sum of squares (RSS). If the RSS is not improved significantly by the addition of a variable, the variable is left out of the final model.

By employing stepwise regression, we found that selecting three variables would create a model with a R-square value of 74.4 percent. The three variables selected are: lagged fuel oil price, supply cushion and CCGT planned outages dummy B.

Variable Coefficient P-value

Constant 11.92 0.00

LOG (CCGT supply) -0.32 0.00

LOG (ST supply) -0.04 0.17

LOG (Supply cushion) -0.62 0.00

LOG (Offers) -1.36 0.00

LOG (Demand) 0.41 0.00

LOG (Reserve cushion) -0.19 0.00

LOG (Lagging fuel oil price) 0.25 0.05

CCGT planned outages dummy A -0.02 0.00

CCGT planned outages dummy B 0.07 0.00

Forced outages dummy 0.02 0.00

Model Diagnostics

R-squared 0.91

Adjusted R-squared 0.91

Number of observations 2,162

* Details of the model and its methodology can be found in the paper, “How Market Fundamental Factors Affect Energy Prices in the NEMS—An Econometric Model”, available on www.emcsg.com.

28

Table9:EstimationResults—January2003toDecember2009

Econometric Model and Outlier Prices: Identification of Outlier Prices

Table 9 shows the following observations, in line with expectations:

• one unit increase in the logarithm of the lagged fuel oil price will bring about a 0.58 unit increase in the logarithm of the USEP and

• one unit increase in the logarithm of the supply cushion will bring about a 0.66 unit decrease in the logarithm of the USEP.

Chart 25 illustrates the actual daily average USEP, the upper and lower bands of the estimated USEP, and the outliers identified by the econometric model, using data from January 2005 to December 2009. For 2009, there were 29 days in which high prices were detected by the model. Periods of high prices over consecutive days were typically caused by one set of factors. Five distinct cases are discussed in the following sections.

Chart25:ActualvsPredictedLogUSEPWithinThreeStandardErrorBands

Variable Coefficient P-value

Constant 4.64 0.00

LOG (Lagged fuel oil price) 0.58 0.00

LOG (Supply cushion) -0.66 0.00

CCGT planned outages dummy B 0.15 0.00

Model Diagnostics

R-squared 0.74

Adjusted R-squared 0.74

Number of observations 2,527

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Log USEP Prediction + 3sds OutliersPrediction - 3sds

29


Chart 26: Demand and Supply Conditions — 21 April 2009

Summary

The high USEP experienced from 20 April to 23 April 2009 was due to the high level of planned maintenance, which was at an average high of 1,755MW, with two CCGT units that offer cheaper offers out of the action.

Moreover, there was a shift in supply from the remaining generators, with a decline in offers under $500/MWh. The combination of factors led to a high USEP observed on 21 April 2009.

Date Tuesday 21 Apr 2009 All Tuesdays in Apr 2009

Average USEP ($/MWh) 848.09 325.39

Max USEP ($/MWh) 3,948.97 3,948.97

No. of USEP ≥ $1,000/MWh 8 8

Demand (MW) 4,725.93 4,708.05

Supply Cushion (in %) 20.65 21.15

Offers ≤ $1,000/MWh (in %) 70.41 71.80

DemandUSEPOther SupplyST SupplyCCGT Supply

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Chart27:DemandandSupplyConditions—13May2009

Summary

The high USEP on 13 May 2009 was mainly the result of the forced outage of a CCGT unit in period 30, which led to a high USEP price of above $3,500/MWh for multiple periods.

During periods 30 to 34, the higher-than-usual demand and the unexpected reduction of supply caused the supply cushion to dip below 10 percent. The multiple periods of high prices in turn cause the average USEP to reach $389.59/MWh.


Date Wednesday 13 May 2009 All Wednesdays in May 2009


Max USEP ($/MWh) 3,521.67 3,521.67

No. of USEP ≥ $1,000/MWh 3 3

Demand (MW) 4,948.96 4,926.77


Offers ≤ $1,000/MWh (in %) 72.44 71.81

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31

Chart28:DemandandSupplyConditions—1June2009

Summary

From period 17 to period 34 of 1 June 2009, the USEP hovered in the region of $500/MWh. One CCGT unit and three ST units were down for maintenance, accounting for 1,150 MW of planned outage. Coupled with the higher-than-usual demand, the supply cushion hovered near 15 to 16 percent.

The daily average USEP on 1 June 2009 reached $342.43/MWh.


Date Monday 1 Jun 2009 All Mondays in Jun 2009


Max USEP ($/MWh) 643.69 667.66

No. of USEP ≥ $1,000/MWh 0 0

Demand (MW) 5,037.85 4,952.79


Offers ≤ $1,000/MWh (in %) 66.97 61.96

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32

Chart29:DemandandSupplyConditions—4Sep2009

Summary

From period 32 to period 35 on 4 Sep 2009, the USEP exceeded $1,000/MWh and reached $3,363.39/MWh. From period 36 to 40, the USEP hovered around $500/MWh.

A planned maintenance on 876MW coincided with the forced outage of 361MW of a ST unit, reducing the supply cushion to below 15 percent for period 32 to period 40.

At the same time, the proportion of offers below $100/MWh was around 56.77 percent, pushing the average USEP to $361.92/MWh.


Date Friday 4 Sep 2009 All Fridays in Sep 2009


Max USEP ($/MWh) 3,363.39 3,363.39

No. of USEP ≥ $1,000/MWh 4 4

Demand (MW) 4,928.92 4,916.95


Offers ≤ $1,000/MWh (in %) 56.77 56.56



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Chart30:DemandandSupplyConditions—20Oct2009

Summary

On 20 October 2009, USEP exceeded $500/MWh in 12 periods. During period 43, the USEP spiked to $1,139.36/MWh.

While no forced outages occurred on 20 October 2009, the day’s planned outage was a high 1,142.5MW, for the planned maintenance of three ST units and one CCGT unit.

At the same time, a higher than usual level of demand (of 5,083.62MW) caused the supply cushion to drop to 21.35 percent, pushing the high daily average USEP to $367.67/MWh.


Date Tuesday 20 Oct 2009 All Tuesdays in Oct 2009


Max USEP ($/MWh) 1,139.36 1,572.58

No. of USEP ≥ $1,000/MWh 2 5

Demand (MW) 5,083.62 4,994.34


Offers ≤ $1,000/MWh (in %) 54.59 54.51



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Investigations

35

Investigations: Summary of Investigation Activities

Table10:InvestigationandEnforcementStatistics

Under the Market Rules, the MSCP may initiate an investigation into any activities in the wholesale electricity markets or into the conduct of a MP, the MSSL, EMC or the PSO that is brought to the attention of the MSCP by way of a referral or complaint from any source, or that the MSCP of its own volition determines as warranting an investigation.

The MSCP may refuse to commence or may terminate an investigation when the MSCP is of the view that a complaint, referral or investigation is frivolous, vexatious, immaterial or unjustifiable, not directly related to the operation of the wholesale electricity markets, or within the jurisdiction of another party.

Table 10 reflects the position with regard to investigation and enforcement activities from market start on 1 January 2003 to 31 December 2009, with the last column focusing on the period under review.

Reports of determinations of breach made by the MSCP are published in accordance with the Market Rules.

1 Jan 2003 to 1 Jan to Rule Breaches 31 Dec 2009 31 Dec 2009

(A) Total number of offer variations after gate closure received 26,893 1,802

Total number of cases closed 26,177 1,256 - cases in which the MSCP determined a breach 119 14 - cases in which the MSCP determined no breach 6,543 1,192 - cases in which the MSCP took no further action 19,515 50

(B) Origin of cases (excluding offer variations after gate closure) 141 7

- self-reports 124 7 - referrals or complaints 10 0 - initiated by the MSCP 7 0

Total number of cases closed 139 6 - cases in which the MSCP determined a breach 99 5 - cases in which the MSCP determined no breach 10 0 - cases in which the MSCP took no further action 30 1

(C) Number of formal MSCP hearings 1 0

(D) Enforcement action

- highest financial penalty imposed on a party in breach $66,000 $12,500 - total financial penalties imposed on parties on breach $161,000 $12,500

(E) Costs

- highest award of costs imposed on a party in breach $23,000 $1,300 - total costs imposed on parties on breach $122,200 $7,300

1 Jan 2003 to 1 Jan to Market Efficiency and Fairness 31 Dec 2009 31 Dec 2009

Total number of cases: 7 3

- referrals or complaints 2 0 - initiated by MSCP 5 3

Total number of cases closed: 7 3

Sections 50 and 51 of The Electricity Act

37

Sections 50 and 51 of The Electricity Act

InformationRequirementstoAssisttheAuthority

The Market Rules provide for the MAU, under the supervision and direction of the MSCP, to develop a set of information requirements to assist the EMA to fulfill its obligations with respect to prohibiting anti-competitive agreements and abuse of a dominant position under sections 50 and 51 of the Electricity Act.

The first set of information requirements was finalized in consultation with the EMA and published on 27 March 2003. As the market evolved, modifications to the information requirements were published on 18 August 2003 and 28 January 2004.

The MAU regularly provides data to the EMA according to the information requirements.

ReportstotheAuthority

The Market Rules provide for the MSCP to include in its report a summary of reports that have been made to the EMA regarding any complaint that may have been received or any information that may have been uncovered that may indicate the possibility of anti-competitive agreements, or the abuse of a dominant position, contrary to sections 50 or 51 of the Electricity Act.

In the course of monitoring and investigative activities carried out from January 2009 to December 2009, the MSCP referred to the EMA observations that the average USEP levels in April-June 2009 exceeded the long-run marginal cost (LRMC) and appeared to be inconsistent with competitive market fundamentals.

Assessment of the Wholesale Electricity Markets

39

Assessment of the Wholesale Electricity Markets: State of Competition and Efficiency of the Wholesale Electricity Markets

Under the Market Rules, the MSCP is required to provide a general assessment of the state of competition and compliance within, and the efficiency of, the wholesale electricity markets. The Panel’s assessment is as follows:

MarketStructureandCompetition

Entry of New Market Participants and New Facilities

Several new market participants (MP.) joined the NEMS in 2009. ISK Singapore, with a maximum generation capacity of 9.6MW, joined the NEMS as a non-injecting generation facility. Banyan Utilities registered a 5MW facility. In addition, Keppel Seghers Tuas Waste-To-Energy also registered a new 22MW incineration plant.

2009 also saw the transfer of a 55MW incineration plant from the National Environment Agency (NEA) to Senoko Waste-To-Energy Pte Ltd.

Apart from new MPs joining the NEMS, other generation facilities were registered in the NEMS in 2009. These include two new PowerSeraya CCGT units of maximum generation capacity 370.6MW each and a 85MW repowered OCGT unit from Senoko Power.

Deregistration of Facilities

As of 1 January 2010, one 240MW ST unit from PowerSeraya and three 250MW ST units from Senoko Power were deregistered. In addition, a 16MW NEA incineration plant in Ulu Pandan was also deregistered.

40

Assessment of the Wholesale Electricity Markets: State of Competition and Efficiency of the Wholesale Electricity Markets

MarketPriceBehaviour

High Prices in Second Quarter of 2009

Energy prices in 2009 were generally lower than in 2008. This was largely due to the economic recession, which caused system demand to fall below 2008 levels in the first five months of the year. Despite lower average prices and lower average system demand, there were many individual days when high prices were observed. Our econometric model picked out 29 days where energy prices were unusually high. Of the 29 days, 20 of the days were observed in the second quarter of 2009.

In a report to the EMA, the MSCP observed that despite similar fundamental conditions (such as demand, fuel oil price, outage and planned maintenance, etc.) as in 2007, energy prices in Q2 2009 were significantly higher. There was an obvious inconsistency between competitive fundamentals and observed market prices, particularly in April and May 2009. The MSCP noted that the high prices were the result of a combination of tight supply, high price bids and rising demand. The MSCP became concerned about insufficient competition in generation offers when the overall supply tightens because some generators are taken out for maintenance.

After the multiple high-price instances in the second quarter of 2009, energy prices began to stabilize and hovered around the $130/MWh–$150/MWh tranche in the third and fourth quarters.

EfficiencyoftheElectricityMarket

Productive Efficiency

While there was little change in the composition of total metered energy by fuel types in 2009, the market share of CCGT units based on maximum capacity increased by 1.4 percent compared to 2008. Generally, the introduction of two new CCGT units and the decommissioning of older ST units in 2009 imply a further increase in productive efficiency in the future.

Pricing Efficiency

Generally, prices in 2009 reflected supply and demand conditions, with the exception of the multiple instances of high prices in the second quarter.

FutureChallenges

Demand and Generation Forecast

Based on forecasts published by the EMA in the fourth quarter of 2009, after a contraction in 2009, electricity demand is expected to increase at an annual rate of between 2.5 and 3.0 percent from 2009 to 2018*. Assuming an average system demand of 5,000MW, this forecast implies that average system demand would grow by 1,500MW by 2018.

On the supply side, several new generation plants are expected to come online by 2014, increasing supply by about 2,000MW:

• ExxonMobil’s 220 MW cogeneration plant

• Tuas Power’s Tembusu Multi-Utilities Complex fuelled by biomass and coal

• Island Power’s 800 MW gas-fired plant and

• Keppel Merlimau Cogen’s two generation plants of 450 MW.

Liquefied Natural Gas Supply for Power Generation

To enhance energy security, Singapore has invested in a liquefied natural gas (LNG) terminal to import LNG, most of which will be used for power generation. Excess capacity will be built into the terminal to support opportunities for LNG trading.

BG Asia Pacific Pte Ltd (BG) was appointed as the LNG aggregator, whose role will be to consolidate local demand for LNG. BG will have the exclusive rights to import LNG and sell regasified LNG to end users in Singapore, up to 3 million tons per annum.

* Demand and generation forecast published in, “Statement of Opportunities for the Energy Industry 2009”, published by the EMA.

41

Assessment of the Wholesale Electricity Markets: State of Compliance Within the Wholesale Electricity Market

Ensuring compliance with the Market Rules is important in the operation of a competitive and reliable electricity market. MPs who breach the rules may be subject to sanctions if the MSCP considers it appropriate.

Our assessment of the state of compliance within the wholesale electricity markets is set out below.

OfferVariationsAfterGateClosure

Table 11 compares the number of offer variations after gate closure submitted by market participants in 2009 and the previous year.

The 121.9 percent increase in offer variations after gate closure was mainly due to one generating company making offer variations after the natural gas supply pressure to its CCGTs dropped to a predetermined level that triggered its Natural Gas Operation Procedure to lower CCGT output.

The MSCP was also satisfied that the offer variations made after gate closure did not give rise to any significant concerns.

RuleBreaches

For the period 1 January to 31 December 2009, the MSCP made six determinations regarding rule breaches. The determinations were made against EMC and PowerSeraya Ltd.

The rule breach determinations against EMC were made for the following reasons:

• Failure to release and publish information relating to dispatch schedules or failure to do on time (three cases) and

• Failure to release on time to the PSO the real-time dispatch schedule (two cases).

There was one rule breach determination made against PowerSeraya for its offer variations made after gate closure.

The MSCP notes that these breaches were all self-reported. The rule breaches by EMC did not have any significant impact on the wholesale electricity markets, but the rule breach by PowerSeraya had contributed to a high USEP for the period concerned.

Overall, there were no major compliance issues arising within the wholesale electricity markets.

Table11:OfferVariationsAfterGateClosure

TABLE

Number of offer variations made after gate closure 812 from 1 Jan 2008 to 31 December 2008

Number of offer variations made after gate closure 1,802 from 1 January 2009 to 31 December 2009

Percentage increase in offer variations made 121.9% after gate closure for 2009 from previous year

Conclusion

43

Conclusion

The MSCP is generally satisfied with the state of compliance in the NEMS in 2009. In particular, the number of determinations on rule breaches that the MSCP had to make declined by half from 12 in 2008 to 6 in 2009.

On the production front, the technological shift from the less-efficient ST generation to the more-efficient CCGT generation has continued in 2009 with the addition of two CCGT units and the decommissioning of four ST units. These imply further improvements to production efficiency.

On the pricing front, 2009 again saw dramatic movements in prices. While subdued demand in the first quarter kept the WEP under $100/MWh, sustained high prices above the LRMC in the second quarter was a concern for the MSCP. In studying those instances, the MSCP observed them to appear inconsistent with competitive market fundamentals. While prices were generally well-behaved and appeared to re-align with fundamentals in the second half of 2009, the MSCP remains concerned about insufficient competition in the generation sector when some generating units are taken out for maintenance.

The MSCP notes that in response to the instances of very high prices in April 2009, the Authority has taken steps such as implementing a “Vesting Relief” scheme to assist non-portfolio generators to manage their vesting contract obligations during maintenance periods. The MSCP also notes that the EMA has begun to study market power mitigation tools and has consulted MPs on some possible measures. We look forward to positive outcomes from these studies.

44

User Guide

Data

• All real-time and forecast prices and settlement data are provided by Energy Market Company (EMC).

• Vesting contract hedge prices (VCHP) are computed by SP Services based on a formula set by the Energy Market Authority (EMA).

• Fuel oil data is based on the monthly Oil Market Report published by the International Energy Agency. A copy of the report is available from www.oilmarketreport.org.

• Data for forecast demand and outages are compiled from reports prepared by the Power System Operator (PSO), including advisory notices.

• Metered energy quantities are supplied by SP Services as the Market Support Services Licensee (MSSL). All metered data used in this report is final data, derived after any settlement reruns.

• Throughout this document, the demand figures are based on the forecast demand supplied by the PSO, except where metered energy quantities are indicated.

SupplyIndices

• Capacity ratio measures the scheduled (by the Market Clearing Engine [MCE]) output of energy, reserve and regulation as a ratio of a generation registered facility’s maximum generation capacity at a given time.

• Supply cushion is the ratio between (a) the supply and demand gap (i.e., the difference between total offered volume and demand) and (b) supply. This index measures supply adequacy. It indicates the level of unused capacity that was offered but not scheduled, and could be called up if required. The total offered volume refers to the total amount of energy offered by all generation registered facilities. Demand refers to the demand forecast by the PSO used to determine the real-time dispatch schedule for energy.

• Market share is computed based on the generation output of each company. The maximum capacity for each generation company is the registered maximum capacity in the standing data.

• Under the Market Rules and SOM, outages of generation registered facilities are defined as follows:

a. planned outage is defined in the SOM to “include both the Annual Outage plan for overhaul, retrofitting or inspection and the Short-term Outage Plan for urgent repair or maintenance”;

b. unplanned outage is defined in the SOM as “the case in which the generation licensee has to carry out immediate rectification works and has less than 1 business day to inform the PSO before intentional de-synchronisation of the generation unit”; and

c. c) forced outage is defined in the Market Rules as “an unanticipated intentional or automatic removal from service of equipment or the temporary de-rating of, restriction of use or reduction in performance of equipment”.

Anticipated outage is the sum of planned and unplanned outages.

There may be slight differences in the calculation of outages in the Annual Report of the MSCP and the NEMS Market Report due to differing methodologies.

VestingContracts

The VCHP is calculated by the MSSL every three months. It is determined using the long-run marginal cost (LRMC) of the most efficient technology in the Singapore power system, i.e., the combined-cycle gas turbine (CCGT). EMC’s settlement system uses the VCHP to settle the vesting quantity between the MSSL and the generation companies.

Periods

Each day is divided into 48 half-hours periods. Period 1 is from 0000 to 0029 and Period 48 is from 2330 to 2359.

Table 11: Definition of Peak, Shoulder and Off-peak Periods*

Sunday Weekday Saturday

Peak – Period 18–41 –

Shoulder Period 22–33 Period 1 Period 1–2 Period 38–47 Period 16–17 Period 17–48 Period 42–48

Off-peak Period 1–21 Period 2–15 Period 3–16 Period 34–37 Period 48

* Source: MSSL

45

Disclaimer

The Market Surveillance and Compliance Panel has made every effort to ensure that the information contained in this report is accurate. This report is prepared and provided for general information purposes only. As such, you should always consult a suitably qualified professional and independently assess the information provided in this report. If you have any specific queries about this report or its contents, contact us at [email protected].

CopyrightNotice

© Energy Market Company Pte Ltd 2010. All Rights Reserved.

Reproduction, transmission and distribution of this report for reference purposes only is authorised provided that such reproduction, transmission and distribution is in respect of the whole and complete report. This report shall not be reproduced, transmitted or distributed in parts. Full acknowledgement of the Energy Market Company Pte Ltd as the source of this report must be given at all times.

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