Losses and Constraints Excess Projections

Transcription

1 Losses and Constraints Excess Projections Prepared by Energy Link for The Electricity Authority March 2011

2 Quality Assurance Information Name EA LCE projections Mar-11 FINAL.doc File reference E-EA-917 Issue Status Issue Date February 2011 Client Electricity Authority Definitions The following abbreviations and acronyms are used in this report. %ile BEN BHEQ EA ETS FIR FTR HRC HVDC LPR LCE OTA PCC PPI SIR SO Percentile Benmore 200 kv node Bunneythorpe_Haywards equation constraint Electricity Authority Emissions Trading Scheme Fast instantaneous reserves (a.k.a. 6 second reserves) Financial transmission right Hydro risk curve High voltage DC link Locational price risk Losses and constraints excess (a.k.a. losses and constraints surplus, losses and constraints rentals, pool surplus) Otahuhu 220 kv nodes Public conservation campaign Producers price index Sustained instantaneous reserves (a.k.a. 60 second reserves) System operator EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd (ii)

3 Contents DEFINITIONS 1 INTRODUCTION 1 2 SUMMARY 2 3 METHODOLOGY AND ASSUMPTIONS SIGNIFICANT CHANGES IN ASSUMPTIONS SINCE THE 2009 REPORT GRID ASSUMPTIONS Line Variation Details Modelled equation constraints FORECAST DEMAND RESERVES MODELLING NEW GENERATION BASE MODEL ASSUMPTIONS ENERGY LINK S MODELS EMarket I-Gen RESULTS LOSSES AND CONSTRAINT EXCESS HVDC EXCESS AC EXCESS DISCUSSION UNCERTAINTIES COMMENTS ON CONSTRAINT FREQUENCY THE IMPACT OF SCARCITY PRICING ON THE LCE ROLLING OUTAGE LOAD SHEDDING GRID EMERGENCY LOAD SHEDDING IR SHORTFALLS RESULTS AND DISCUSSION II EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd (iii)

4 1 Introduction The EA is currently undertaking consultation on the introduction of inter-island FTRs which are intended to assist market participants manage LPR. Part of this work stream is to assess the actual degree of inter-island LPR and, along with it, the likely magnitude of the LCE (which is used to fund FTRs) in future years. In March 2009 Energy Link produced an analysis of the LCE in a report titled Long Term Projection of the Constraints Surplus ( the 2009 report ) which contained background on the LCE in addition to projections of the LCE based on a number of key assumptions, for example the expected capacity of the HVDC link. The purpose of this new report is to update the long term projections of the LCE using the latest information available. The focus of this report, however, is on the portion of the LCE created by price differences across the grid which contribute to inter-island LPR and not on projecting the entire LCE, and intra-island LPR due to constraints is ignored. In particular, the focus was on modelling price differences between Otahuhu (OTA) and Benmore (BEN) which are currently the two nodes which the FTRs are likely to reference. In producing this report, Energy Link undertook a modelling study using our EMarket model and projected the LCE from Apr-11 to Mar-26. The modelling assumptions are based on our latest quarterly Price Path Base Case, with a number of significant additions and modifications to the modelling scope and key assumptions. Due to the long forecast period of 15 years, and to the number and scope of additional assumptions in the modelling, the study is not exhaustive, but instead attempts to paint a broad picture of how the LCE may evolve over time. The study included the following major tasks: 1. Careful preparation of modelling assumptions that are likely to impact the price difference between BEN and OTA, including: a. approved transmission investments by Transpower, including the commissioning of HVDC Pole 3; b. new generation projects forecast to be built over the forecast period; c. instantaneous reserves in both the North and South Islands; d. the transfer of the Tekapo A and B power stations from Meridian Energy to Genesis Power, currently expected to occur by mid 2011; 2. Market simulation runs using EMarket based on three scenarios selected from our Price Path Base Case run with all inflows: the high, low and medium demand growth scenarios were used, all with our median gas price assumptions, but each modelled with all 79 inflows available to us; 3. Processing and reporting of the scenario results for the LCE. Section 3 describes the modelling methodology and key assumptions and the results of the modelling are presented in section 4. In addition to the three demand scenarios outlined above, a fourth scenario was run as a variation on the medium demand growth scenario, and included the scarcity prices for EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 1

5 energy and reserves that are currently being consulted on. The methodology and results for this work are contained in section 6. In this report all dollar values are New Zealand dollars exclusive of GST, expressed in nominal terms with underlying PPI inflation of 2.0% assumed on certain inputs to the modelling (refer section 3.6). 2 Summary In March 2009 Energy Link undertook statistical and modelling analysis to forecast the likely magnitude of the HVDC and AC constraints excess. This report updates and extends those forecasts using the latest information publicly available, and a consistent methodology across the DC and AC grids. EMarket was used to model three demand growth scenarios over the 15 year period from April 2011 through March 2026, and each of these scenarios was run with 79 historical inflow sequences, thus capturing the potential impact on the LCE of variations in demand and inflows from year to year. The medium demand scenario assumes demand growth of 1.8% per annum whereas the low and high demand scenarios assume growth of 1.6% and 2.0% per annum, respectively. All modelling used night-day resolution, which means that the frequency of constraints may be underestimated because peak demand periods are not fully represented where demand is averaged during the night and day periods. The 2009 report modelled the HVDC link s capacity below its rated capacity to allow for the potential for reserves to constrain flows on the link. In the latest modelling, however, the link is modelled at its expected capacity throughout the forecast period, and reserves are modelled explicitly in both islands. The link is modelled as having a capacity of 900 MW northward until 2012 (with the ability to provide 200 MW of its own reserve cover) but then at 1,000 MW from 2012 and 1,200 MW from 2014, with the ability to provide 500 MW of reserve cover from 2012 then 600 MW from In the southward direction the link is modelled at 666 MW with no reserve cover, then 1,000 MW from 2012 with reserve cover of 400 MW assumed thereafter. A number of AC grid upgrades are modelled explicitly, including the impact of these on existing equation constraints. Only lines and equation constraints which might be expected to create price differences between Otahuhu and Benmore are modelled, thus intra-island LPR created by constraints (and its impact on the LCE) is ignored in this study. For each of the three demand scenarios, a new build schedule was calculated showing the new plant expected to be built over the forecast period. The underlying assumption in creating build schedules is that investors build plant only when they expect the new plant to recover its full costs, including an appropriate return on investment, over its lifetime. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 2

6 Figure 1 shows the total annual average LCE over all three demand scenarios, broken down into its four major components. A key driver of higher prices over the forecast period is the assumption that the ETS will remain intact, and that carbon prices will trend toward $50 per tonne by 2020, impacting on prices to the tune of $7/MWh in the near term, rising to over $20/MWh by Rising prices increase the losses excesses in proportion to price, and also contribute to increases in constraint excesses. Figure 1 - Components of the Annual Average LCE $350,000,000 $300,000,000 $250,000,000 $200,000,000 $150,000,000 $100,000,000 $50,000,000 $- Annual Average LCE AC Constraints Excess AC Losses Excess HVDC Losses Excess HVDC Constraints Excess The latest modelling has confirmed the general trend in the HVDC constraint excess, with a sharp reduction in 2013 when Pole 3 is commissioned. However the latest results show the HVDC constraints excess rising in the latter half of the forecast period. The AC constraints excess is initially small 1, but then rises toward a peak in 2021/22 which is caused primarily by the Bunneythorpe_Haywards equation constraint (BHEQ) binding more frequently with increasing levels of southward transfer. From 2021/22 more plant is built in the South Island and the occurrence of constraints between Bunneythorpe and Haywards reduces accordingly. 1 Note that the 99th percentile is included in the AC chart below, but not in the HVDC chart. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 3

7 Figure 2 - Forecast HVDC and AC Constraints Excesses HVDC Constraints Excess $90,000,000 $80,000,000 $70,000,000 $60,000,000 $50,000,000 $40,000,000 $30,000,000 $20,000,000 $10,000,000 $0 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile Year (April-March) AC Constraint Excess $90,000,000 $80,000,000 $70,000,000 $60,000,000 $50,000,000 $40,000,000 $30,000,000 $20,000,000 $10,000,000 $0 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile 99th %ile Year (April-March) Even though intra-island LPR was ignored in the modelling, the modelled grid also included most AC lines in both islands, so it was possible to detect all lines that ran over their rated capacity, and hence when they would have constrained. After making a number of assumptions, analysis of this data suggests that inter-island LPR will continue to dominate intra-island LPR throughout most of the forecast period, albeit at a significantly lower level in most years than has occurred in the last 3 years. Scarcity prices are proposed during rolling outages (a floor of $3,000/MWh for spot prices) and in the event of a shortfall in reserves. While precise details on how these will be implemented are not yet available, modelling assumptions were developed and run with medium demand growth. Scarcity pricing has the potential to push prices up under certain conditions, for example if supply tightens, due principally to the impact of the $3,000/MWh prices on the water valuations of the large hydro generators. Scarcity pricing was modelled with all other assumptions the same as the medium demand growth scenario, including the original build schedule. In reality, the advent of scarcity pricing may cause a change in the timing of new generation and the nature of the plant that is built, for example more peaking-capable plant may be built. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 4

8 Nevertheless, the average prices produced were not significantly different to those obtained from the medium demand growth scenario, as shown below in Figure 3. Figure 3 - Increases in Prices with Scarcity Pricing $/MWh 4.0 Increase in Average Annual Prices with Scarcity Pricing BEN Change - OTA Change However, the introduction of scarcity pricing did increase the total LCE by an average of $6 million per annum, as shown in Figure 4. Figure 4 - Increase in LCE Due to Scarcity Pricing Incease in Annual Average LCE with Scarcity Pricing $25,000,000 $20,000,000 $15,000,000 $10,000,000 $5,000,000 $- -$5,000,000 -$10,000,000 -$15,000,000 AC Constraints Excess AC Losses Excess HVDC Losses Excess HVDC Constraints Excess The following figures show the impact of scarcity pricing on the forecast HVDC and AC constraint excesses. The increases are largely a function of greater flows between the islands: scarcity pricing tends to cause more conservative management of hydro storage in autumn and in dry winters (with more southward transfers on the HVDC link and from Bunneythorpe to Haywards), but also higher northward flows in spring and wet summers. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 5

9 Figure 5 - Increases in HVDC & AC Constraint Excess with Scarcity Pricing $50,000,000 HVDC Constraint Excess Difference $40,000,000 $30,000,000 $20,000,000 $10,000,000 $0 -$10,000,000 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile -$20,000,000 Year (April-March) AC Constraint Excess Difference $30,000,000 $25,000,000 $20,000,000 $15,000,000 $10,000,000 $5,000,000 $0 -$5,000,000 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile -$10,000,000 Year (April-March) The impact on the LCE and its components is significant: the LCE rises on average by 7% over the forecast period with scarcity, and the 95 th percentile LCE rises by 15%. Similarly, the HVDC constraints excess rises by 7% on average and the AC constraints excess rises by 75% on average. Taken overall, the modelling indicates that scarcity pricing is likely to increase price volatility and LPR. 3 Methodology and Assumptions The total LCE can be split into a number of components depending on the requirements of any particular analysis. The 2009 report contained projections of the AC and HVDC constraints excess, the impact of constraints being the primary source of motivation for the development of hedges against LPR. The HVDC constraints excess is the excess resulting only from constraints on the HVDC link, whereas the AC constraints excess arises when lines in the AC grid constrain. However, an excess also results from losses on all lines. The relationship between the various components is as follows: EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 6

10 LCE HVDClosses excess HVDC constraints excess AC losses excess AC constraints excess We can also define Total lossesexcess HVDClossesexcess AC losses excess The HVDC constraints excess actually arises in two different ways: 1. when the HVDC link reaches its limit of capacity; and 2. when the HVDC link sets the reserve risk in an island: in this case we say the HVDC is link is constrained by reserves. In the 2009 report the AC constraints excess was estimated using a relatively subjective assessment, and the HVDC constraints excess was estimated using data from modelling which was based around Energy Link s quarterly Price Path at the time. In this report, however, all excess components were estimated using modelling based on the core Base Case scenario from our latest Price Path, but with significant modifications tailored specifically to the needs of this analysis, in particular the modelling of reserves throughout the forecast period. The latest modelling has produced significantly higher AC constraints excesses due to the change in methodology. 3.1 Significant Changes in Assumptions since the 2009 Report The latest modelling includes more detailed modelling of the grid and the modelling of reserves in both islands, updated with the latest information concerning the market and future grid upgrades. In the 2009 report the impact of reserves on the operation of the HVDC link was modelled by reducing the capacity of the link below what was actually expected to be available. In this report, however, the link is modelled at its full expected capacity throughout the forecast period, but with reserves fully enabled. The impact of the reserves modelling is to constrain transfers on the link below its full operational capacity. In the 2009 report the HVDC link s northward capacity was modelled as 700 MW without Pole 1 being available for operation. For this modelling exercise it has been modelled as 900 MW with 200 MW of this offered through Pole 1. In the 2009 report, the HVDC link s southward capacity until 2012 was limited to 350 MW without Pole 1. In this report it is modelled as 666 MW on Pole 2 only. There has also been a change to the HVDC upgrade timetable. In the 2009 report the first upgrade was modelled at 2012 with northward capacity of 1,000 MW and southward capacity 750 MW, and the second upgrade was in 2016 with northward capacity 1,200 MW and southward capacity 750 MW. In this report the first upgrade is still modelled for 2012 but the second upgrade is modelled for The upgraded southward capacity has been increased to 1,000MW. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 7

11 Similarly, in this report the core AC grid has been modelled with key lines constrained to operate at no more than their rated capacity, thus capturing the impact of constraints in the AC grid on the LCE. In the 2009 report very few lines limits were enforced. Since 2009 EMarket has had several major upgrades, the most significant of which is the change in the way that the large hydro systems calculate their water values 2. This has had a significant change in the timing and flows over the HVDC, to more realistically reflect the actual operation of the electricity market. In this report, and pursuant to market reforms and the Electricity Act 2010, Tekapo A and B power stations are also separated out of the Waitaki hydro system and Lake Tekapo storage is optimised as an entity belonging to or under the control of Genesis Energy (it currently still belongs to Meridian Energy). The current market reforms (including real and virtual asset swaps) have potentially created new regional imbalances between generation and contract positions for the three large SOE market participants, with the potential to significantly alter market behaviour, and in particular the operation of Tekapo under new ownership. However, in this report it is assumed that any such imbalances are either small, or are mitigated over a short period of time: this allows the operation of Tekapo to be modelled without distorting an otherwise rational value-optimising strategy. 3.2 Grid Assumptions The base grid for EMarket is taken from Transpower data dated 24 January For future year modelling, the base grid (as described above) continues to be used, however approved Transpower grid upgrades have been explicitly modelled. These include: North Island Grid upgrade; Wanganui_Stratford upgrade; West Coast Grid upgrade; Wairakei Ring grid upgrade; Lower South Island renewable project; Lower South Island reliability project; HVDC Pole 3 project; North Auckland and Northland project Line Variation Details The following lines were upgraded during the modelling. In the following tables the resistance and reactance values are estimated using data from existing lines. The Winter, Shoulder and Summer Capacity columns give the default line capacities for each line based on time of year, and the Enforce Limits column indicates whether the lines are constrained to their maximum capacity in the EMarket modelling 4. 2 The water value of a large hydro reservoir is the expected value of the next cubic metre of water released through a dam for generation. 3 Published through the em6 online information system. 4 Lines that are not expected to constrain, or that would not significantly impact on the price difference between OTA and BEN if they did constraint, are left to run free. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 8

12 Table 1 Upgraded Line Details Name Year From Node To Node Resistance Reactance Winter Capacity (MW) Shoulder Capacity (MW) Summer Capacity (MW) WGN_SFD upgrade 2012 WGN WVY No WGN_SFD upgrade 2012 HWA WVY No WGN_SFD upgrade 2012 HWA SFD Yes NI Grid upgrade 2013 OTA PAK Yes NI Grid upgrade 2013 PAK PEN Yes Wairakei Ring 2013 PPT WKM ,996 1,900 1,804 Yes Wairakei Ring 2013 PPT WRK ,996 1,900 1,804 Yes Lower SI Renewables 2015 NSY ROX Yes Lower SI Renewables 2015 LIV NSY Yes Lower SI Renewables 2015 CYD ROX ,560 1,460 1,420 Yes Lower SI Renewables 2015 AVI BEN ,340 1,250 1,218 No Lower SI Renewables 2015 AVI WTK No Lower SI Renewables 2015 LIV WTK No Lower SI Renewables 2015 CML TWZ ,236 1,184 1,132 Yes Enforce Limits Table 2 HVDC Upgrade Details Name Year From Node To Node Resistance Northward Capacity (MW) Southward Capacity (MW) Enforce Limits BEN_HAY 2012 BEN HAY ,000 1,000 Yes BEN_HAY 2014 BEN HAY ,200 1,000 Yes The following new lines were added to the model. Table 3 New line Details Name Year From Node To Node Resistance Reactance Winter Capacity (MW) Shoulder Capacity (MW) Summer Capacity (MW) NI Grid Upgrade 2013 BNH OTA ,250 1,250 1,250 Yes NI Grid Upgrade 2013 BNH PAK ,250 1,250 1,250 Yes NI Gid Upgrade 2013 BNH WKM ,237 1,180 1,124 Yes WestCoast upgrade 2012 DOB RFN No LSI Reliability 2016 NMA GOR Yes LSI Reliability 2016 GOR TMH Yes LSI Reliability 2016 ROX BAL No Enforce Limits The following lines were deleted from the model. Table 4- Deleted Lines Name Year From Node To Node NI Grid Upgrade 2010 ARI PAK LSI Reliability 2016 BAL GOR LSI Reliability 2016 NMA TMH LSI Reliability 2016 GOR ROX Modelled equation constraints The grid is constrained when individual lines reach their respective limits, but there are also important equation constraints which limit the total flow through a group of lines. Equation constraints are now used extensively because they help to ensure that grid utilisation is maximised. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 9

13 The impact of grid upgrades on equation constraints is difficult to predict in advance because of the large number of factors that potentially come into play when calculating the constraint limit values. Therefore we have assumed that the modelled equation constraints either remain in place or are removed when they are no longer required after an upgrade. The equation constraints actually chosen for modelling are those which either have a history of creating price differences in the core grid, or might be expected to do so in the future. Table 5 - Modelled Equation Constraints Equation Constraint Equation Summer Shoulder Winter Bunnythorpe_Haywards 1 * BPE_HAY + -1 * HAY_LTN + 1 * LTN_WIL 1,047 1,047 1,047 Naseby_Roxburgh * NSY_ROX * CML_TWZ Stratford_Huntly -1 * HLY_SFD + 1 * SFD_TMN Upper NI Stability 1 * HLY_TAK + -1 * DRY_HLY + 1 * OHW_OTA + -1 * OTA_WKM * BOB_HAM + 1 * ARI_BOB 2,300 2,300 2,300 Upper NI Stability is only in place in the modelling until 2013 when the new BNH_WKM line is expected to be commissioned. Naseby_Roxburgh is only in place in the modelling until 2016 when the Lower SI Renewable project is expected to be commissioned. 3.3 Forecast Demand The scenario forecast demand is modelled as follows: Table 6 Forecast Demand on Grid in GWh per Annum Demand Increase High Demand 75% 2.02% 40,522 41,608 42,641 43,671 44,698 45,725 46,748 47,752 48,573 49,443 Mean Demand 1.77% 40,263 41,130 41,966 42,805 43,650 44,500 45,354 46,206 46,934 47,670 Low Demand 25% 1.63% 40,175 40,675 41,425 42,182 42,945 43,715 44,490 45,346 46,074 46,772 Demand High Demand 75% 50,255 51,097 51,921 52,763 53,579 Mean Demand 48,412 49,164 49,922 50,689 51,464 Low Demand 25% 47,464 48,176 48,901 49,624 50,369 These demand forecasts are based on our independent analysis of the drivers of demand growth past and present, however they are in line with other published forecasts, for example those of the EA. 3.4 Reserves Modelling EMarket has the functionality to model reserve offers and their impact on overall dispatch. For this report, each of the five largest hydro systems including Waitaki, Clutha, Manapouri, Waikato and Tongariro, has fast (6 second) and sustained (60 second) reserve offers. These are based on the average historic reserve offers that these hydro systems made over the last 2 years. All reserve quantities were varied by day and night, but these quantities remained the same for the entire forecast period. Reserve offers were not escalated through time. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 10

14 Thermal generation reserve (with the exception of Huntly) was offered through a dummy North Island generator: these offers also reflect average offers over the last two years. Interruptible load reserve (ILR) was also offered at historic levels. ILR offered by large consumers is included in the modelled reserve offers, although actual offered quantities do vary over time and there is evidence to suggest that more may be available in dry years. For example, there is no ILR offered in the South Island in the modelling, based on recent offers, but some ILR was offered during the 2008 dry period at Tiwai. The offer quantities and price range are shown in Figure 6 to Figure 9 below. Figure 6 SIR Offers (Day) Generator Manapouri Clutha Waitaki North Island ILR Other NI Waikato Tongariro Huntly Reserve Offers - 60s (Day) MW offered Reserve Offer Price Range Range $ $0.99 Range $ $1.99 Range $ $4.99 Range $ $9.99 Range $ $19.99 Range $ $49.99 Range $ $99.99 Range $ $ Range $ $ Range $ $ Range $ $10000 Figure 7 SIR Offers (Night) Generator Manapouri Clutha Waitaki North Island ILR Other NI Waikato Tongariro Huntly Reserve Offers - 60s (Night) Reserve Offer Price Range Range $ $0.99 Range $ $1.99 Range $ $4.99 Range $ $9.99 Range $ $19.99 Range $ $49.99 Range $ $99.99 Range $ $ Range $ $ Range $ $ Range $ $ MW offered EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 11

15 Figure 8 FIR Offers (Day) Generator Manapouri Clutha Waitaki North Island ILR Other NI Waikato Tongariro Huntly Reserve Offers - 6s (Day) Reserve Offer Price Range Range $ $0.99 Range $ $1.99 Range $ $4.99 Range $ $9.99 Range $ $19.99 Range $ $49.99 Range $ $99.99 Range $ $ Range $ $ Range $ $ Range $ $ MW offered Figure 9 FIR Offers (Night) Generator Manapouri Clutha Waitaki North Island ILR Other NI Waikato Tongariro Huntly Reserve Offers - 6s (Night) MW offered Reserve Offer Price Range Range $ $0.99 Range $ $1.99 Range $ $4.99 Range $ $9.99 Range $ $19.99 Range $ $49.99 Range $ $99.99 Range $ $ Range $ $ Range $ $ Range $ $ New Generation New generation for the EMarket modelling runs is created using Energy Link s I-Gen model, which constructs a build schedule based on demand, fuel prices and LRMC of new plant. For the purpose of this report, three build schedules were required based on the high, mean and low demand forecasts. Table 7 shows new generation projects which are currently committed, while Table 8, Table 9 and Table 10 show the build schedules for each of the three demand scenarios. Table 7 Committed Projects Scenario: M, Base Case - Committed Projects (Installed Capacity) Year Station 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 Total (MW) McKee_II M Amethyst_Project M Mahinerangi_WindFarm_Stage_1 M EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 12

16 Table 8 Medium Demand Growth Build Schedule Scenario: A2, Base Case - Medium Demand: New Generation (Installed Capacity) Year Year (Apr-Mar) 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 Total (MW) Committed WRK_S WMG_H DOB_H WRK_S ONG_H WRK_S ROT_S MCH_H KAW_S WKM_S HKK_H ROT_S TWZ_H LTN_W KAW_S ASB_H CML_H OKE_H OTA_G HTI_H GOR_W BEN_H WIL_W TMH_W GOR_W TUI_H ROX_H MNI_G1 9 WHI_W1 225 HLY_W1 170 EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 13

17 Table 9 - Low Demand Growth Build Schedule Scenario: A1, Base Case - Low Demand: New Generation (Installed Capacity) Year Year (Apr-Mar) 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 Total (MW) Committed WRK_S WMG_H WRK_S WRK_S ROT_S DOB_H KAW_S MCH_H HKK_H ROT_S TWC_W ONG_H LTN_W TWC_W OKE_H TWZ_H NMA_H BPE_W MST_W TWC_W CML_H HTI_H TKU_H OTA_G BEN_H WIL_W EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 14

18 Table 10 High Demand Growth Build Schedule Scenario: A3, Base Case - High Demand: New Generation (Installed Capacity) Year Year (Apr-Mar) 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 Total (MW) Committed WRK_S WMG_H WRK_S DOB_H BLN_H WRK_S MCH_H HLY_G KAW_S TWC_W WKM_S HKK_H TWC_W ROT_S WPA_W TWZ_H LTN_W COL_W BEN_H KAW_S TWC_W CML_H ROX_H OTA_G TKU_H HTI_H WIL_W GOR_W GOR_W NSY_W WHI_W1 225 GOR_W3 120 TMH_W1 160 TNG_W1 125 TUI_H Base Model Assumptions The following summarises the key assumptions made in all three demand scenarios: 1. all scenarios cover the period of 1 April 2011 to 31 March 2026; 2. our GMarket median gas price scenario is used for gas-fired thermal offers; 3. the ETS is assumed to remain in place throughout the forecast period, with the impact on electricity rising from $12.50/tonne CO 2-e at the end of 2012 to just over $50/tonne CO 2-e in 2020; 4. modelling includes reserve calculations, reserve offers are based on historical offers; 5. all offers and resulting prices are expressed in nominal terms; 6. forecast PPI of 2.0% pa is assumed on certain inputs: generators operations and maintenance costs, gas transmission costs, and fuel costs (gas and coal); 7. no extra mandatory costs directly affect spot prices; EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 15

19 8. hydro generators will manage reservoirs to achieve the equivalent of at least 1-in- 60 dry year security; 9. reservoir storage is started at actual levels from early February 2011, and for all other years starting storage is determined from the end of the previous year s modelling runs; 10. there is no consideration of any short-term generator strategy that may influence spot price outside of normal market conditions; 11. dry year reserve generation initially offered as 155 MW at $387/MWh at Whirinaki, but in later years the offer price is increased (on the assumption that Whirinaki remain available to generate) 5 ; 12. small generators are offered to ensure dispatch to realistic schedules; 13. all generators offer below maximum capacity to reflect planned and unplanned outages; 14. two units at the 1,000 MW Huntly power station are progressively decommissioned from ; 15. HVDC maximum flow was modelled as 900 MW (including 200 MW on Pole 1) northward and 666 MW southward until upgrades in 2012 and beyond. For the 2012 the HVDC s ability to cover its own reserve risk is 500MW northward, 400MW southward, then from 2014 onwards it is 600MW northward and 400MW southward. 3.7 Energy Link s Models 6 The wholesale market simulation runs were undertaken with Energy Link s EMarket and I-Gen models: I-Gen produces the build schedule and EMarket accepts the build schedule, and other inputs, to simulate the operation of the wholesale market. Energy Link s long term modelling process is shown in Figure 10 which shows that two other models are also employed. Demand is calculated by the Demand model which projects demand growth based on historic trends 7. The GMarket model indirectly uses demand for gas for electricity generation in its forecasts, and it outputs an expected gas price, along with high and low range gas prices, which are used in calculating LRMC s in I-Gen and generator offers in EMarket. 5 Whirinaki s offer is set at a level that reflects its use in dry years. It s standing offer of $5,000/MWh applicable to short term dispatch, is not modelled. 6 More information is available on MED s web site at aspx. 7 Since 1974 demand has grown at a more or less constant annual increment. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 16

20 Figure 10 Energy Link s Modelling Process Demand Model GMarket Price of gas Demand for electricity I-Gen Supply EMarket Wholesale electricity prices Gas demand for generation EMarket The market-driven build schedule of new plant from I-Gen is used within EMarket for longer term price forecasts. However, in Energy Link s modelling, generator offers are not simply a function of plant LRMC. Instead, offers are sculpted to reflect a number of constraints and limitations on offers, which mimics observed behaviour. For example, a typical offer strategy for a large new gas-fired thermal plant might include: 1. a must-run offer band priced at zero: this reflects the need for a large thermal plant to run at an output at least as large as its minimum safe output, which for CCGT plant, for example, can be around 40% of maximum rated output; 2. one or more offer bands priced at SRMC: these might reflect a take-or-pay gas contract, or perhaps to the need to generate enough to at least match a market participant s total contract (hedge plus retail load) commitments; 3. higher priced offer bands: these might reflect the plant s LRMC, or perhaps higher fuel costs when contract limits are exceeded. For most of Energy Link s purposes, prices are required at a much finer level of resolution than annually, so it is important that generator offers provide a realistic degree of variation in prices between periods of low and high demand, for example, or between wet and dry periods. All other generators are offered at realistic market prices: for example, wind farms, embedded generation (which is typically smaller scale than grid-connected generation) and geothermal plant are offered at or near zero. Peaking plant is offered using an offer strategy that is consistent with their need to recover fixed costs from the market over the course of their relatively short and unpredictable operating regimes. The large hydro generators are modelled using water values which reflect the marginal value of water in hydro storage lakes. Water values are optimised using mathematical EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 17

21 techniques for maximising returns under conditions of uncertainty, the major source of uncertainty being the hydrological inflows into storage lakes. EMarket also has dispatch and pricing aligning with that employed by the New Zealand electricity market and Transpower, including marginal losses, line constraints and instantaneous reserves; a DC power flow model of the grid featuring 184 nodes; and detailed river chain modelling for the Clutha, Waitaki, Waikato and Manapouri-Te Anau major hydro schemes. For this study, three scenarios were each run with 79 years of historical inflow data over the full 15 year forecast period: using all inflows has the advantage that it captures the substantial impact of inflow uncertainty on prices I-Gen The underlying assumption in I-Gen is that rational investors will build new plant when they expect that their investment will provide a reasonable return over its life time, and not before. The I-Gen model only uses projects that are actually on the drawing board, to a greater or lesser extent. However not all projects are available for selection at all times over the forecast period, implemented using a randomising factor, reflecting the many factors which can impact on investors willingness to commit funds at any given time. An I-Gen run forecasts prices in a limited sense, based on demand, fuel prices and other factors. In simple terms, when the forecast price exceeds a project s LRMC, then that plant is deemed as being committed, with commissioning occurring some time later. The run continues building plant until the end of the forecast period. Once the run is complete, I-Gen (using the forecast prices from the last run), repeats the forecast to create a new plant build schedule, resulting in a build schedule which may be different to the previous run. This process continues to be repeated until the build schedule converges to a narrow band, and the final build schedule is selected from one of the last few runs. 4 Results The modelling for this report produced three series of market simulations for the period April 2011 through March 2026, one series each for high, low and medium demand growth, and each year in each series is modelled with 79 years of historical inflow data: this gives a total of 237 modelled demand-inflow years for each of the 15 years in the forecast period 8. For convenience, the following results are calculated from the three series assuming all demand scenarios and hydro inflows are equally likely. The modelling included an inflation assumption of 2.0% per annum in terms of the PPI and all dollar values below are presented in nominal terms (refer section 3.6). 8 Which gives a grand total of 3,555 modelled years. At approximately 6 minutes per modelled year, this represents 15 days of uninterrupted modelling on one PC. The modelling was actually undertaken using 6 copies of EMarket on 3 multi-processor PCs. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 18

22 4.1 Losses and Constraint Excess Figure 11 below shows the average prices obtained from the modelling for Benmore and Otahuhu, and the Benmore-Otahuhu price difference in red. The average prices obtained from the modelling are on a rising trend, albeit with plateaus as major new generation is built. Generation continues to be built primarily in the North Island until around 2020/21, evidenced by the widening price differential between BEN and OTA, after which a number of renewable projects go ahead in the South Island, resulting in less southward transfers on the HVDC link and a reversal in the direction of the Benmore-Otahuhu differential after 2022/23. This new generation in the South Island is built sooner in the high demand growth scenario (starting 2018/19) and later in the low demand growth scenario (starting 2022/23). A key driver of price increases is the assumption that the ETS will remain more or less intact after 2012, and that carbon prices will rise to around $50 per tonne of CO 2-e by The impact of this on spot prices is around $7/MWh in 2012 (8% - 9% of the average annual price shown below), rising to the low to mid $20/MWh bracket in the first half of next decade (15% - 20%). Figure 11 Average Annual Prices $/MWh $180 $160 $140 $120 $100 $80 $60 $40 $20 $0 -$20 Average Annual Price - BEN, OTA BEN OTA BEN-OTA Year (April-March) Figure 12 uses percentiles to show the volatility in the average monthly price difference between Benmore and Otahuhu. The high percentile Benmore-Otahuhu price differences are the result of dry years, and hence tend to occur in winter, or leading into winter, along with high levels of power flow from north to south. On the other hand, the low percentile Benmore-Otahuhu price differences occur with high levels of power flow south to north during spring and summer. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 19

23 Figure 12 Average Monthly Price Difference Benmore-Otahuhu Benmore - Otahuhu Monthly Averages $80.00 $60.00 $40.00 $20.00 $0.00 -$ $ $ th percentile 25th percentile 50th percentile Average 75th percentile 95th percentile The total LCE results are shown below and exhibit a generally rising trend. The contribution of losses to the LCE is proportional to price, so as prices rise so does the losses component of the LCE. The impact of the ETS on prices translates into a significantly larger total LCE compared to having no carbon charge. The hump in 2020/21, particularly in the 95 th percentile, is a result of increasing flows from the North to the South Island. After 2020/21 there is more renewable plant built in the South Island, creating a more balanced north-south flow regime, and resulting in a lower probability of constraints. Figure 13 Total Annual Losses and Constraint Excess Losses and Constraints Excess $500,000,000 $450,000,000 $400,000,000 $350,000,000 $300,000,000 $250,000,000 $200,000,000 $150,000,000 $100,000,000 $50,000,000 $0 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile Year (April-March) Table 11 shows the data from Figure 13 along with the actual LCE for the years 2004/05 through 2010/11 (although 2010/11 is missing the month of Mar-11). The Average/Purchases column shows the magnitude of the LCE relative to the total purchases from the spot market. Due to the influence of demand, wet and dry years, grid capacity and other factors, the total LCE can vary significantly from year to year, but the forecast average is the average over all modelled demand-inflow scenarios in each year and thus has a much smoother trend. The percentile values indicate the EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 20

24 potential range of variation in future years, depending on demand, hydrology and expected grid capacity. The Average/Purchases values effectively normalise the total LCE with respect to price, and are an indication of how the LCE is expected to change over time once the impact of rising prices is removed. The actual values shown from 2004/05 through 2010/11 slightly underestimate 9 the relative magnitude of the LCE because the denominator in this ratio is the total receipts from spot market purchasers and therefore include significant amounts which are additional to the total value of purchases at spot price, including constrained on payments and ancillary service charges. The forecast Average/Purchases denominator, however, includes only the total value of purchases at spot price. Table 11 Losses and Constraint Excess ($millions) Year (Apr-Mar) 5th Percentile 50th Percentile Average 95th Percentile Average/Purchases 2004/05 $59 3.0% 2005/06 $92 2.2% 2006/07 $61 2.1% 2007/08 $67 2.0% 2008/09 $ % 2009/10 $ % 2010/11 Missing March 2011 $84 3.4% 2011/12 $72 $104 $110 $ % 2012/13 $79 $106 $111 $ % 2013/14 $87 $126 $135 $ % 2014/15 $89 $122 $132 $ % 2015/16 $83 $123 $134 $ % 2016/17 $93 $138 $151 $ % 2017/18 $100 $153 $165 $ % 2018/19 $110 $178 $195 $ % 2019/20 $127 $195 $220 $ % 2020/21 $137 $216 $238 $ % 2021/22 $154 $217 $238 $ % 2022/23 $157 $223 $237 $ % 2023/24 $177 $249 $263 $ % 2024/25 $195 $265 $277 $ % 2025/26 $219 $286 $298 $ % 4.2 HVDC Excess Figure 14 and Figure 15 show the contribution of the HVDC link to the LCE, the second chart breaking this down to show the HVDC constraints excess (which includes the impact of reserves when the HVDC link sets the reserve risk, and the impact of the HVDC link reaching its maximum rated capacity). The HVDC s LCE remains elevated until Pole 3 is commissioned in 2012/13, after which the link has a much greater capacity to cover its own reserve risk. 9 To the tune of 0.1%, e.g. 2.0% equates to 2.1% of the total spot electricity purchases. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 21

25 Figure 14 Annual HVDC Losses and Constraints Excess HVDC Losses and Constraints Excess $100,000,000 $90,000,000 $80,000,000 $70,000,000 $60,000,000 $50,000,000 $40,000,000 $30,000,000 $20,000,000 $10,000,000 $0 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile Year (April-March) The main driver of the HVDC constraints excess is the requirement to provide reserves in the island receiving power from the link: the HVDC link rarely reaches its rated capacity in the model. The link s capability to cover its own risk is currently quite limited in the northward direction (only 200 MW) and is nil in the southward direction. However from 2012 this situation improves dramatically, but as demand continues to grow, especially in the high demand growth scenario, eventually the frequency with which the link sets the reserve risk increases and the HVDC constraints excess increases from around 2018/19. The hump in the 95 th percentile in 2020/21 is caused by drier years when the HVDC link constrains, but once again the incidence of constraints in the north-south direction falls as more renewable plant is built in the South Island. Overall, the HVDC link is more likely to constrain in drier periods when power flows from north to south. Figure 15 Annual HVDC Constraints Excess HVDC Constraints Excess $90,000,000 $80,000,000 $70,000,000 $60,000,000 $50,000,000 $40,000,000 $30,000,000 $20,000,000 $10,000,000 $0 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile Year (April-March) EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 22

26 Figure 16 Monthly HVDC Constraints Excess $35,000, HVDC Constraints Excess Monthly Averages $30,000, $25,000, $20,000, $15,000, $10,000, $5,000, $0.00 5th percentile 25th percentile 50th percentile Average 75th percentile 95th percentile The timing of the high percentile HVDC monthly excess varies with the average level of power transfers south to north. With little new plant built in the South Island, the peak in the 95 th percentile moves slightly toward the winter, which suggests that dry years are the cause. As more plant is built in the South Island after 2020/21, and southward transfers reduce, the peak in the 95 th percentile moves back toward the summer and early autumn. 4.3 AC Excess The capacity of the AC grid is currently not as limited, in relative terms, as the capacity of the HVDC link, so Figure 17 below does not exhibit abrupt changes in total LCE as the AC grid is upgraded. The key driver of the AC LCE is losses, the impact of which increases over time in proportion to average prices. Figure 17 Annual AC Losses and Constraints Excess AC Losses and Constraints Excess $450,000,000 $400,000,000 $350,000,000 $300,000,000 $250,000,000 $200,000,000 $150,000,000 $100,000,000 $50,000,000 $0 5th %ile 50th %ile Average 95th %ile 25th %ile 75th %ile Year (April-March) However, the AC constraints excess shown in Figure is initially small or zero, but from 2014/15 it rises steadily as grid congestion increases through to 2020/21, after 10 Unlike other charts which include percentiles up to the 95th, this chart includes the 99th percentile curve. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 23

27 which significantly more generation is built in the South Island and alleviates congestion associated with dry years, in particular. Figure 18 Annual AC Constraints Excess $90,000,000 $80,000,000 $70,000,000 $60,000,000 $50,000,000 $40,000,000 $30,000,000 $20,000,000 $10,000,000 $0 AC Constraints Excess 5th %ile 50th %ile Average 95th %ile 25th %ile 95th %ile 99th %ile Year (April-March) Figure 19 Monthly AC Constraints Excess 11 $25,000, AC Constraints Excess Monthly Averages $20,000, $15,000, $10,000, $5,000, $0.00 5th percentile 25th percentile 50th percentile Average 75th percentile 99th percentile The AC constraints excesses are largely a function of the BHEQ which constrains in the north-south direction during dry winters, in particular. 5 Discussion Work carried out by the EA has shown that inter-island LPR dominates intra-island LPR as a source of risk to market participants. When interpreting the results of this study, therefore, it is important to keep in mind that only lines and equation constraints which might be expected to create price differences between Otahuhu and Benmore are modelled, and that intra-island LPR created by constraints (and its impact on the LCE) is ignored The monthly chart above shows the 99th percentile instead of the 95 th percentile values. 12 The pricing impact of the equation constraint between Bunneythorpe and Haywards can also be interpreted as creating intra-island LPR. Whether this would be interpreted by a market participant as inter-island or intra-island LPR might depend on where their generation and load are located. EA LCE projections Mar-11 FINAL.doc Copyright Energy Link Ltd 24