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OTB-HAY Bypass Line Economic Benefit Study

Transpower NZ Limited

HVDC Bypass Line Economic Benefit Study

RZ024300_01 | B

09 December 2016

SUP-9506-28

HVDC Bypass Li ne Economic Benefit Study

Transpower NZ Li mited


RZ024300_01 i

OTB-HAY Bypass Line Economic Benefit Study

Project No: RZ024300

Document Title: HVDC Bypass Line Economic Benefit Study

Document No.: RZ024300_01

Revision: B

Date: 09 December 2016

Client Name: Transpower NZ Limited

Client No: SUP-9506-28

Project Manager: Project Manager

Author: Cameron Parker

File Name: I:\ZPINA\Projects\RZ024300 - Transpower OTB bypass\Deliverables\Final

Report\Transpower HVDC Bypass Line Economic Benefit Study (Final -

09Dec2016).docx

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upon, this report by any third party.

Document history and status

Revision Date Description By Review Approved

A 28/10/2016 Draft Final HVDC Bypass Line Economic Benefit Study C. Parker W. Gerardi R. McDougall

B 9/12/2016 Final HVDC Bypass Line Economic Benefit Study C. Parker W. Gerardi R. McDougall


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Contents

Executive Summary ............................................................................................................................................... 4

1. Introduction .............................................................................................................................................. 11

2. Background .............................................................................................................................................. 12

3. Modelling Approach ................................................................................................................................ 13

3.1 Model verification ....................................................................................................................................... 13

3.2 Simulations ................................................................................................................................................ 13

3.2.1 Market benefits based on generation costs............................................................................................... 13

3.3 Calculating market benefits ....................................................................................................................... 14

4. Key Modelling Assumptions .................................................................................................................. 16

4.1 Generators ................................................................................................................................................. 16

4.1.1 Thermal units ............................................................................................................................................. 17

4.1.2 Hydro ......................................................................................................................................................... 17

4.1.3 Geothermal ................................................................................................................................................ 18

4.1.4 Wind........................................................................................................................................................... 18

4.1.5 Embedded generators ............................................................................................................................... 18

4.1.6 Generation expansion plans ...................................................................................................................... 18

4.2 Fuel and carbon prices and generation costs ........................................................................................... 19

4.2.1 Transportation charges.............................................................................................................................. 19

4.2.2 Generation costs ....................................................................................................................................... 20

4.2.3 Carbon prices ............................................................................................................................................ 20

4.3 Load ........................................................................................................................................................... 21

4.4 Transmission ............................................................................................................................................. 21

4.4.1 HVDC limits and line losses ...................................................................................................................... 21

4.5 Reserve Market ......................................................................................................................................... 22

4.5.1 Reserve Requirement................................................................................................................................ 23

4.5.2 Risk subtractor formula.............................................................................................................................. 24

4.5.3 OTB-HAY outage configuration and the risk subtractor formula ............................................................... 24

4.5.4 Reserve Provision ..................................................................................................................................... 25

4.6 Hydro scenarios ......................................................................................................................................... 26

5. Modelling Results .................................................................................................................................... 28

5.1 Gross Market Benefits ............................................................................................................................... 29

5.1.1 Gross market benefits – Business as Usual (BAU) ................................................................................... 29

5.1.2 Gross market benefits – Huntly Retires ..................................................................................................... 30

5.1.3 Gross market benefits – Tiwai Closes ....................................................................................................... 31

5.1.4 Gross market benefits – BAU (U5) ............................................................................................................ 32

5.1.5 Gross market benefits – BAU (1987) ........................................................................................................ 33

5.2 HVDC Flows .............................................................................................................................................. 35

5.2.1 Daily HVDC Flows – Business as Usual (BAU) ........................................................................................ 35

5.2.2 Daily HVDC Flows – Huntly Retires .......................................................................................................... 36

5.2.3 Daily HVDC Flows – Tiwai Closes ............................................................................................................ 37


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5.2.4 Daily HVDC Flows – BAU (U5) ................................................................................................................. 38

5.2.5 Daily HVDC Flows – BAU (1987) .............................................................................................................. 39

5.3 Reserve Costs ........................................................................................................................................... 40

6. Conclusions ............................................................................................................................................. 43

6.1 Reserve Costs ........................................................................................................................................... 45

Appendix A. Overview of PLEXOS

A.1 SPD and Reserve Management Tool

A.2 PLEXOS Algorithms

A.3 Aggregating the model

Appendix B. Existing Power Plants

Appendix C. Maximum Generator Reserve Provision

Appendix D. Generation expansion Plans


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Executive Summary

Introduction

This report presents an evaluation of the potential market benefits arising from the installation of different

bypass options during a planned outage required in order for Transpower to re-conductor the Oteranga Bay

(OTB) to Haywards (HAY) circuits in early 2020. An evaluation of gross market generation costs when

considering the bypass options will assist Transpower to determine the optimum configuration when planning

for its OTB_HAY re-conductoring work in 2020.

This study evaluates the gross market benefits associated with a range of options presented by Transpower,

taking account of three key market scenarios.

The bypass options that Transpower has considered are:

Option 1: Installation of a 700 MW bypass line;

Option 2: Installation of a 500 MW bypass line and reconfigure the HVDC to ensure that pole 2 is

always on the bypass;

Option 3: Do not install a bypass line, balancing the required outages across each pole one outage at

a time; and

Option 4: Do not install a bypass line but reconfigure the HVDC to ensure that pole 2 is always the

pole taken out of service.

The three market scenarios initially considered are as follows:

Business as Usual (BAU): The remaining units at Huntly are not retired;

Huntly Retires: The final Huntly coal-fired units retire as initially planned, one in 2018 and the second

by 20201; and

Tiwai Closes: The NZAS aluminium smelter at Tiwai Point shuts down in combination with the

remaining Huntly units also retiring.

In addition to the above two further scenarios were developed whilst modelling was taking place and have also

been considered, these being:

BAU (U5): Business as usual, as above, however with a scheduled one week outage for Huntly Unit 5

during the OTB-HAY work; and

BAU (1987): Business as usual but with the 1987 hydrology pattern applied, representing a dry North

Island and wet South Island hydrology scenario in order to evaluate higher anticipated northward

transfers on the HVDC.

Discussion

An existing PLEXOS model of the New Zealand Electricity Market (NZEM) has been used to evaluate the

market outcomes related to each bypass scenario, taking account of the snapshot calendar year 2020.

Key assumptions agreed with Transpower prior to undertaking the final modelling include:

Three generation expansion planning scenarios provided by Transpower (committed, new entrant and

retiring generation);

Thermal unit constraints including Huntly Power Station’s likely future configuration;

1 It is noted that on 28 April 2016 Genesis Energy announced its intention to extend the life of the Huntly coal-fired units until

December 2022, however it was agreed to continue this analysis based on the 2018 date.


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Generation profiling for renewable generation and projected profiles by technology, including demand

side reduction;

Generation costs, fuel costs and carbon prices;

Load forecasts, including Tiwai Point aluminium smelter;

Market reserve requirements, formula and inputs;

HVDC limits, line losses and risk subtractor option configuration; and

An agreed hydro scenario representing an average hydrological year (except in BAU (1987)).

For each market scenario the gross market costs in year 2020 and associated benefits have been calculated

drawing on the following components:

Fuel costs of electricity production;

Variable operating and maintenance costs;

Emission costs;

Costs of unserved energy (the product of unserved energy and VoLL2); and

Costs of reserve shortage (the product of reserve shortage and VoRS3).

Gross market benefits of each option have been calculated by comparing total system costs under each

scenario, where Option 1 is considered the base case. Net market benefits could be calculated by subtracting

the cost of installing the relevant bypass solution or HVDC reconfiguration cost from the gross market benefits

however Transpower has not provided these and for this reason Jacobs has focused on gross market benefits

only.

Results

At a high level the annual gross market costs appear intuitive, see Table 1 below. Option 1 presents the highest

overall capacity on the HVDC, with Option 2 marginally reducing this capacity. We note that this marginal

reduction in capacity does not differentiate gross market costs between these two bypass options. This is

consistent across all market scenarios.

Option 3 and Option 4 represent no bypass line installed and OTB-HAY outages either balanced between poles

or restricted to pole 2. This effectively reduces the transfer capacity of the HVDC resulting in an increase in

overall gross market generation costs. The increases in costs are small or insignificant when considering

Business as Usual, Huntly Retires and BAU (U5) scenarios however can be seen to increase when a higher

level of energy transfer is required under the Tiwai Closes and BAU (1987) scenarios.

Table 1 Annual gross market costs (all scenarios)

Annual Gross Market Costs ($m)

Scenario Option 1 Option 2 Option 3 Option 4

Business as Usual (BAU) $ 540.14 $ 540.14 $ 540.49 $ 540.53

Huntly Retires $ 521.94 $ 521.94 $ 522.11 $ 522.14

Tiwai Closes $ 232.57 $ 232.57 $ 233.21 $ 238.93

Additional Scenarios

BAU (U5) $ 540.99 $ 540.99 $ 541.35 $ 541.11

BAU (1987) $ 395.03 $ 395.03 $ 439.92 $ 425.01

2 Value of Lost Load: Typically assigned a value of $20,000/MWh in New Zealand. 3 Value of Reserve Shortage: Typically assigned a value of $5,000/MWh in New Zealand.


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Gross Market Benefits

Annual gross market benefits are set out in Table 2 below. This table draws comparison of annual gross market

costs, assuming Option 1 as the base case. We note there is no differentiation between Options 1 and Option

2, in terms of benefits. Benefits are read as negative i.e. Options 3 and 4 represent an increase in gross market

costs, suggesting benefits associated with Option 1, or negative benefits associated with Options 3 and 4.

Table 2 Annual gross market benefits

Annual Gross Market Benefits ($m)


Business as Usual (BAU) $ - $ - -$ 0.35 -$ 0.39

Huntly Retires $ - $ - -$ 0.17 -$ 0.20

Tiwai Closes $ - $ - -$ 0.64 -$ 6.36


BAU (U5) $ - $ - -$ 0.37 -$ 0.13

BAU (1987) $ - $ - -$ 44.89 -$ 29.98

Results suggest annual gross market benefits associated with Business as Usual, Huntly Retires and BAU (U5)

scenarios are particularly small, given an average hydrology year. Benefits range from between 0.02% to

0.07% of their respective annual gross market costs, are noted as statistically insignificant, and in recognition of

the potential for variability that can occur on such a system could be assumed as zero.

Tiwai Closes and BAU (1987) scenario results, representing an increased level of electricity supply for the

NZEM from the South Island, largely from hydro generation, suggest benefits between 0.02% and 10.2% of

annual gross market costs.

Given the low level of market benefits identified further analysis has been undertaken to determine where the

benefits might be occurring in relation to the OTB-HAY outages and if any potential model optimisation could be

at play. Analysis has focused on the timing of the OTB-HAY outages compared with gross market benefits

arising, HVDC flow comparisons and an assessment of market reserve costs (refer to Section 5).

Conclusions

Our analysis shows that the gross market benefits associated with installing a bypass to facilitate the required

OTB-HAY re-conductoring work are small. Noting the small level of benefits, modelling results reveal evidence

of a level of “noise” or model optimisation that is unlikely to be removed entirely. Restricting calculation of gross

market benefits to the nominated OTB-HAY outage periods is deemed a suitable approach to draw comparison

between the HVDC bypass and configuration options, and the gross market benefits that arise.

Business as Usual, Huntly Retires and the additional BAU (U5) scenarios present gross market benefits

associated with installation of a bypass in the range of $1.2m to $3m. Tiwai closes and BAU (1987), which

simulate an increased level of available hydro generation from the South Island, provide for a greater measure

of gross market benefits. Installation of a bypass relating to the Tiwai Closes scenario represents benefits of

approximately $23.2m over Option 3, and $12.5m over Option 4. Installation of a bypass relating to the BAU

(1987) scenario represents gross market benefits of approximately $17.9m over Option 3 and $11.8m over

Option 4.

Without comparing the gross market benefits against nominal bypass investment costs a measure of the net

cost or benefit cannot be drawn.

Table 3 provides the gross market benefits (read as negative) when comparing the bypass base case, Option 1,

with the total generation costs in Options 2, 3 and 4. We note there is no difference in total generation costs

between Option 1 and Option 2.


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Table 3 Gross market benefits (restricted to OTB-HAY outage period4)

Outage Period Gross Market Benefits ($m)



Huntly Retires $ - $ - -$ 3.01 -$ 2.99

Tiwai Closes $ - $ - -$ 23.18 -$ 12.46


BAU (U5) $ - $ - -$ 1.43 -$ 1.21

BAU (1987) $ - $ - -$ 17.87 -$ 11.79

For illustrative purposes the following charts show weekly total generation costs for each market scenario over

the year 2020. Benefits arise from the least cost generation solution.

Figure 1: Weekly total generation cost – Business as Usual

Figure 2: Weekly total generation cost – Huntly Retires

4 An OTB-HAY outage start date of 15 January 2020 was nominated for the first outage, lasting six weeks to 25 February

2020. A second outage is run from 4 March to 14 April 2020

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Figure 3: Weekly total generation cost – Tiwai Closes

Figure 4: Weekly total generation cost – BAU (U5)

Figure 5: Weekly total generation cost – BAU (1987)

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Reserve Costs

Although unlikely to be a determining factor in decision making for Transpower reserve costs provide an

indication of market tension, particularly in regards to the optimisation of energy and reserves in market

dispatch.

Table 4 Market reserve costs

Reserve Costs ($m)



Huntly Retires $ 0.29 $ 0.29 $ 0.37 $ 0.39

Tiwai Closes $ 2.28 $ 2.28 $ 42.85 $ 21.63

BAU (U5) $ 0.39 $ 0.39 $ 0.51 $ 0.41

BAU (1987) $ 5.08 $ 5.08 $ 28.33 $ 28.17

Market reserve costs for scenarios Business as Usual, Huntly Retires and BAU (U5) range from $0.3m to

$0.6m, and are noted as insignificant, refer to Table 4 above.

Annual reserve costs under the Tiwai Closes scenario equate to approximately $2.3m for Options 1 and 2,

$42.9m for Option 3 and $21.6m for Option 4. Annual reserve costs under the BAU (1987) scenario equate to

approximately $5m for Options 1 and 2, and $28m for both Options 3 and 4.


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Important note about your report

The sole purpose of this report and the associated services performed by Jacobs is to assess the market

benefits associated with installing a temporary bypass line on the New Zealand transmission grid Cook Straight

link in accordance with the scope of services set out in the contract between Jacobs and Transpower (‘the

Client’). That scope of services, as described in this report, was developed with the Client.

In preparing this report, Jacobs has relied upon, and presumed accurate, any information (or confirmation of the

absence thereof) provided by the Client and/or from other sources. Except as otherwise stated in the report,

Jacobs has not attempted to verify the accuracy or completeness of any such information. If the information is

subsequently determined to be false, inaccurate or incomplete then it is possible that our observations and

conclusions as expressed in this report may change.

Jacobs derived the data in this report from information sourced from the Client (if any) and/or available in the

public domain at the time or times outlined in this report. The passage of time, manifestation of latent conditions

or impacts of future events may require further examination of the project and subsequent data analysis, and re-

evaluation of the data, findings, observations and conclusions expressed in this report. Jacobs has prepared

this report in accordance with the usual care and thoroughness of the consulting profession, for the sole

purpose described above and by reference to applicable standards, guidelines, procedures and practices at the

date of issue of this report. For the reasons outlined above, however, no other warranty or guarantee, whether

expressed or implied, is made as to the data, observations and findings expressed in this report, to the extent

permitted by law.

This report should be read in full and no excerpts are to be taken as representative of the findings. No

responsibility is accepted by Jacobs for use of any part of this report in any other context.


RZ024300_01

1. Introduction

Transpower New Zealand Limited (Transpower) is considering the market benefits associated with installing a

temporary bypass line during an outage required in order to re-conductor the Oteranga Bay (OTB) to Haywards

(HAY) circuits in early 2020.

The OTB-HAY transmission lines connect the Haywards Substation to the northern end of the High Voltage

Direct Current (HVDC) link, in Oteranga Bay, southeast of Karori in Wellington (Figure 1-1 below). When one of

the OTB-HAY circuits is out of service, transfer between the North and South Island is limited to one HVDC pole

only. Furthermore, a pole outage on the HVDC would result in zero transfer capacity resulting in an increase in

reserve risk to the market.

Figure 1-1: Transmission Map (source Transpower, Transmission Map: North Island)

This report provides the background, approach and methodology, key assumptions and findings from our

evaluation.

The remainder of this report has the following structure:

Chapter two provides high level background to Transpower’s study requirements;

Chapter three presents our approach to modelling market benefits;

Chapter four outlines the key assumptions incorporated in the PLEXOS database;

Modelling results are captured in Chapter five; and

Chapter six provides the study’s conclusions drawn from our analysis of results.

Also included, in Appendix A, is an overview of PLEXOS and how it has been applied to the New Zealand

Electricity Market (NZEM) and reserve function of the System Operator when undertaking this study.


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2. Background

Transpower is proposing work to re-conductor its OTB-HAY transmission lines, part of the HVDC that links New

Zealand’s North and South Island high voltage electricity systems. Transpower is seeking to identify the market

benefits associated with installing various bypass options during the planned outage and reconfiguring the

HVDC in a manner that enables the necessary work to be completed.

Jacobs has evaluated the gross market benefits associated with a range of options presented by Transpower,

taking account of three key market scenarios.

The bypass options that Transpower has considered are identified below:





a time; and



The options presented by Transpower ultimately represent a change in HVDC capacity and therefore the

available transfer of energy and reserves between the North and South Islands.

The five market scenarios considered are as follows:

Business as Usual (BAU): The remaining units at Huntly are not retired;

Huntly Retires: The final Huntly coal-fired units retire as initially planned, one in 2018 and the second

by 20205; and

Tiwai Closes: The NZAS aluminium smelter at Tiwai Point shuts down in combination with the

remaining Huntly units also retiring.

BAU (U5): Business as usual, as above, however with a scheduled one week outage for Huntly Unit 5

during the OTB-HAY work; and

BAU (1987): Business as usual but with the 1987 hydrology pattern applied, representing a dry North

Island and wet South Island hydrology scenario in order to evaluate higher anticipated northward

transfers on the HVDC.

The re-conductoring of OTB-HAY is expected to be managed over two specific periods for duration of

approximately six weeks each, and is likely to be carried out during the summer period in 2020 thus avoiding

higher winter period electricity demand. An outage start date of 15 January 2020 was nominated for the first

outage, lasting six weeks to 25 February 2020. A second outage is run from 4 March to 14 April 2020.

The resolution of PLEXOS modelling is 30 minute periods, reflecting real-time market intervals.

An evaluation of gross market generation costs when considering the bypass options will assist Transpower in

determining the optimum configuration when planning for its OTB_HAY re-conductoring work in 2020.




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3. Modelling Approach

An existing PLEXOS model of the New Zealand Electricity Market (NZEM) has been used to evaluate the

market outcomes related to each bypass scenario, taking account of the snapshot calendar year 2020.

3.1 Model verification

Prior to undertaking the final market simulations, testing and review was undertaken so that the System

Operator could verify whether results and outcomes from the modelling emulated actual market outcomes. In

order to verify the modelling, the following summary data was provided to Transpower:

Generator dispatch and capacity factors;

HVDC Pole 2 & 3 flow;

Market energy price in both islands;

Market reserve cost; and

Reserve sharing quantities across the HVDC.

During this verification phase, simulations were undertaken for all options and scenarios. Additional checks

undertaken through discussion with Transpower included: spill; generator outages; Fast and Sustained

Instantaneous Reserve provision; and NFR and risk subtractor assumptions.

3.2 Simulations

The purpose of the analysis was to determine the market benefits associated with installing a temporary bypass

line during an outage of the OTB-HAY circuits during 2020.

3.2.1 Market benefits based on generation costs

Table 3-1 provides a description of the bypass options modelled, and both the HVDC configuration and potential

bypass capacity. A total of 12 simulations were initially required, each in the year 2020, with a further 8

simulations considering Huntly U5 and the 1987 hydrology scenario added for inclusion in the analysis.

Table 3-1 The OTB-HAY outage bypass options

Options Outage 1 (6 weeks) Outage 2 (6 weeks)

Option 1: 700 MW

bypass

Both poles in service.

Pre-contingent limit: 1200 MW

Post-contingent limits:

4 weeks at BAU

2 weeks with post-contingent flow limited to 350 MW by single earthwire




4 weeks at BAU

2 weeks with post-contingent flow limited to 350 MW by single earthwire

Option 2: 500 MW

bypass with HVDC

reconfiguration always

connected to pole 2.




4 weeks with post-contingent flows limited to 500 MW due to bypass capacity.

2 weeks with post-contingent




4 weeks with post-contingent flows limited to 500 MW due to bypass capacity.

2 weeks with post-contingent


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flow limited to 350 MW by single earthwire

flow limited to 350 MW by single earthwire

Option 3: No bypass

with alternate Pole

outages

Pole 3 out of service.

Pre-contingent limits:

4 weeks with pre-contingent flows limited to 700 MW by pole 3

2 weeks with pre-contingent flow limited to 350 MW by single earthwire

Post-contingent limit: 0 MW






Option 4: No bypass

and reconfigure HVDC

so outage is always on

pole 2











Previous risk subtractor modelling results suggested some variation in translation of hydro volumes from the

PLEXOS MT to ST models making it difficult to determine which costs are attributable to constraints we were

evaluating and which costs are attributable to modelling artefacts, particularly when cost differences between

the risk subtractor options were small. To minimise this variation, in the modelling reported in this study

includes a single, average year, hydro volume scenario thus attempting to eliminate this potential noise in

modelling outcomes.

“Unit commitment” refers to a sequence of generating unit on and off decisions made across time. The unit

commitment problem is to find the optimal (least cost) combination of these on/off decisions for all generating

units across a given time horizon, taking start costs into account. Constraints such as a generating unit’s

minimum stable level and ramp up and down rates apply to the unit commitment problem.

The difficulty with optimising generator unit commitment in power systems modelling is that it requires Mixed

Integer Programming (MIP). The decision to commit a unit, or not, is represented by a binary variable.

Introducing MIP brings another layer of complexity and can have a significant impact on model run times,

however following discussions with Transpower, in our previous studies, it was agreed unit commitment

constraints would be enforced, therefore avoiding unrealistic dispatch of thermal units and any partial

commitment from Huntly Power Station.

3.3 Calculating market benefits

For each generation and demand scenario the total costs have been calculated incorporating the following

components:

Fuel costs from production;


Emission costs;

Costs of unserved energy (the product of unserved energy and VoLL); and


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Costs of reserve shortage (the product of reserve shortage and VORS).

Costs, if any, of unserved energy have been checked to ensure that the capacity expansion plans are

consistent with market outcomes. If the costs of unserved energy were greater than the cost of building an

additional OCGT, then additional OCGTs would need to be added. No additional OCGTs were needed.

Gross market benefits of each option have been calculated by comparing total system costs under each

scenario, where Option 1 is considered the base case. Net market benefits could be calculated by subtracting

the cost of installing the relevant bypass solution or HVDC reconfiguration cost from the gross market benefits.

The cost of the options would need to be provided by Transpower but have not and for this reason Jacobs has

focused on gross market benefits only.


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4. Key Modelling Assumptions

This section outlines the key generation, transmission, fuel, load and reserve assumptions that have been used

in the analysis.

4.1 Generators

The NZEM currently consists of a mix of thermal, hydro, geothermal and wind power plants. In 2014, hydro

power stations represented 54% of total installed capacity, thermal generation made up 29% of total installed

capacity, and 17% of installed capacity came from power plant using wind or geothermal resources, as shown

in Figure 4-16.

Figure 4-1 Estimated generating capacity by fuel type, 2014

As at the end of 2014 there was approximately 9,700 MW of installed capacity in the NZEM. Since then

Contact Energy and Mighty River Power both decommissioned combined cycle gas fired plant. This reduces

the total by 380 MW (Otahuhu B) plus 170 MW (Southdown). In addition the second of Genesis Energy’s coal-

fired units at Huntly was put into storage, leaving only the two remaining 250 MW units available.

Appendix B provides a summary of existing generators in the NZEM that are included in the PLEXOS database

for this study.

In PLEXOS, the method for determining generation dispatch is dependent on the technology. Though subject

to constraints, this is generally as follows:

Steam, open cycle gas turbines (OCGTs) and combined cycle gas turbines (CCGTs) are dispatched in

merit order, with lowest cost resources being dispatched first;

Host load profiles are assumed for cogeneration units and, if available, these generators must

generate to meet this host load (or to meet take-or-pay contract obligations);

Hydro units are treated as energy-constrained units or managed within storage limits, and the use of

water is optimised over the year such that the resource is available when it is most needed;

Wind is modelled using an expected hourly power profile, providing for stochastic variation – unless a

deterministic profile is preferred; and

Geothermal is modelled using expected hourly generation profiles.

6 Ministry of Business, Innovation and Employment, Energy Statistics, Electricity data tables: http://www.mbie.govt.nz/info-

services/sectors-industries/energy/energy-data-modelling/statistics/electricity.

Hydro 54%

Geothermal 10%

Oil 2%

Coal 6%

Gas 20%

Other (Biogas, Waste Heat,

Wood) 1%

Wind 7%

http://www.mbie.govt.nz/info-services/sectors-industries/energy/energy-data-modelling/statistics/electricity

http://www.mbie.govt.nz/info-services/sectors-industries/energy/energy-data-modelling/statistics/electricity


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Assumptions, including operating constraints relating to each technology, are discussed in more detail in the

next sections.

4.1.1 Thermal units

To reflect the market operation, there are a number of constraints imposed on thermal units in the system, as

discussed below.

The two “available” Huntly coal units have maximum generation constraints applied during the summer months

to reflect river heating consent obligations. Table 4-1 provides assumed capacity limit to avoid river heating

over the summer months7.

Table 4-1 Huntly Units 1 to 4 cooling constraints

Month Day (08:00 - 24:00) Night (00:00 – 07:59)

January 440 MW 470 MW

February 440 MW 470 MW

March 440 MW 470 MW

The Huntly units are not treated as must-run and do not have a start-up cost imposed. The only limit on

flexibility is the minimum stable level at around 50MW (depending on the unit, and gas firing). These units are

assumed to be running on gas only by 2020 (i.e. Huntly’s coal stockpile has been exhausted).

CCGTs are modelled with minimum stable levels set at a portion of the installed capacity of plant, approximately

50 percent of capacity. These are dispatched by the model when price is greater than the plants short run

marginal cost (SRMC). Transpower has supplied additional plant rules where they may be material to the

outcomes of this study (e.g. heat rates).

We assume that the electricity output of cogeneration plants is driven by the host load, rather than price signals.

Therefore, historical generation profiles are used to predict future hourly generation profiles. New cogeneration

plant are assumed to be available approximately 85% of the time.

Gas and diesel peakers are also assumed to be capable of providing FIR and SIR when operating. Small

minimum stable levels (estimated to be approximately 10% of maximum capacity) have therefore been specified

for these units to ensure that the model does not allow reserve provision without generation.

4.1.2 Hydro

The hydro river chains are modelled as storages and inter-connecting waterways. Several of the river sections

have minimum or maximum flow limits applied to match the physical reality. This setup is the same as previous

work carried out for Transpower such as the LSI Wind impact study, T2040 work and risk-subtractor

assessments.

The smaller existing plants and some new hydro units have annual energy limits or maximum capacity factors

applied.

For new run-of-river hydro generators, we assume a constant 50% rating based on advice previously received

from Transpower, and often more broadly accepted. These units are a relatively small component of the total

hydro system which uses the large storages to reflect the flexibility in dispatch.

New storage-based hydro plants are connected to storages as appropriate.

7 Summer months are represented by January, February and March.


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Hydro inflows are discussed further in Section 4.6.

4.1.3 Geothermal

The projected geothermal profiles have been derived by averaging three years of historic hourly generation

profiles, preserving any weekday/weekend or diurnal pattern, but interpolating over periods of obvious plant

outages. The geothermal profiles have been reviewed by Transpower previously and where applicable these

have been updated to reflect more recent data, provided by Transpower.

4.1.4 Wind

The rating profiles for wind generators were previously provided by Transpower and are generated from

synthetic wind speed time-series data that the Electricity Commission had developed in 2009. The

transformation from wind speed to turbine capacity factor was completed by Transpower based on the

assumption that wind farm output grows quadratically for wind speeds up to 14.5 m/s, is flat from 14.5 to 20 m/s,

and falls quadratically between 20 and 25 m/s. The ratings profiles were also scaled by Transpower to achieve

the expected generation capacity factor for each site.

Each wind generator is matched to one of the profiles from a nearby location. Locations with several current or

proposed wind farms have up to three profiles defined for them. This provides both a degree of diversity and

correlation between the wind generation sites.

A deterministic wind profile is used in the modelling to reduce noise in modelling outcomes.

4.1.5 Embedded generators

The following embedded generators are modelled explicitly, and included in the load:

Aniwhenua (25 MW hydro)

Highbank (35 MW hydro)

Kaimai (42 MW hydro)

Rotokawa (40 MW geothermal)

Tararua_Bunnythorpe (34 MW wind)

Tararua_Linton (34 MW wind)

Ngawha (27 MW geothermal)

Tauha1 (25 MW geothermal)

White Hill (70 MW wind)

Glenbrook (74 MW cogen)

In addition Waipori is partially embedded (34 MW of 84 MW), with embedded load included in the demand

assumptions and full output modelled explicitly.

4.1.6 Generation expansion plans

Transpower has supplied generation expansion8 plans for each of the three market scenarios to be considered,

these being:

The remaining units at Huntly are not retired;

The final Huntly coal-fired units retire as planned, one in 2018 and the second by 20209; and

8 Expansions plans may include new generation, plant upgrades, decommissioned generation plant and demand side

response or any combination of. 9 On 28 April 2016 Genesis Energy announced its intention to extend the life of the Huntly coal-fired units until December

2022, however it was agreed to continue this analysis based on the 2018 date.


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The NZAS aluminium smelter at Tiwai Point shuts down in combination with the remaining Huntly unit

retiring.

The generation expansion plans provided have been transferred into the PLEXOS database and generation

profiles constructed where necessary for new geothermal, wind and hydro generation. Any new profiles created

are based on existing data, such as typical geothermal or wind generation profiles and existing run of river

inflow profiles, and scaled to fit each generators installed capacity.

The three generation expansion plans provided by Transpower are included in Appendix D.

4.2 Fuel and carbon prices and generation costs

The fuel prices, shown in Figure 4-2, have been provided by Transpower for the purposes of this study, and are

aligned with the draft Electricity Demand and Generation scenarios (Draft EDGS 2015) developed by the

Ministry of Business, Innovation & Employment10.

Figure 4-2 Fuel price assumptions

4.2.1 Transportation charges

In addition to the fuel prices discussed above, some thermal units also incur a transportation charge to get the

fuel delivered to the gate. The transportation charges assumed in the database are summarised in Table 4-2

and are consistent with previously provided modelling assumptions. New build transportation charges provided

by Transpower have been updated in the table.

10 http://www.mbie.govt.nz/info-services/sectors-industries/energy/energy-data-modelling/modelling/electricity-demand-and-

generation-scenarios/draft-edgs-2015

http://www.mbie.govt.nz/info-services/sectors-industries/energy/energy-data-modelling/modelling/electricity-demand-and-generation-scenarios/draft-edgs-2015

http://www.mbie.govt.nz/info-services/sectors-industries/energy/energy-data-modelling/modelling/electricity-demand-and-generation-scenarios/draft-edgs-2015


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Table 4-2 Transportation charges for thermal units

Fuel Region Generator Fuel delivery cost

Natural gas

Waikato

HlyUnit6

HuntlyG1-4

Te Rapa Cogen

$0.50/GJ

HlyUnit5 $1.00/GJ

Generic OCGT Peaker

(Huntly or Otorohanga)

$2.60/GJ

Hamilton Proposed Cogen $0.50/GJ

Taranaki Stratford peaker

ToddPeaker_McKee

ToddPeaker_npl

Generic OCGT peaker

(Junction Rd)

$2.00/GJ

Woodwaste Kinleith Cogen (Waikato) $1.00/GJ

4.2.2 Generation costs

Variable and fixed operating and maintenance costs and heat rate assumptions are consistent with the

modelling assumptions provided by Transpower.

The Electricity Authority’s recently proposed Transmission Pricing Methodology (TPM)11 represents a change in

market cost structure which will affect participants to varying degrees, including generators. Specific TPM

changes are not accounted for in this study. It is assumed that the final TPM results in no penalty on South

Island generation.

4.2.3 Carbon prices

The New Zealand Emissions Trading Scheme (ETS) places an obligation on CO2-emitters to surrender units

each year, according to the level of emission production. The scheme is no longer internationally linked, as of

June 2015, now a domestic-only scheme where NZ units (NZUs) can be surrender.

Transpower has provided the price assumptions as shown in Figure 4-3, based on EDGS 2015, IEA Current

Policies Scenario.

11 http://www.ea.govt.nz/industry/transmission/transmission-pricing/

http://www.ea.govt.nz/industry/transmission/transmission-pricing/


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Figure 4-3 NZU Carbon Price assumptions

4.3 Load

Transpower has supplied load forecasts based on the Base Case (Mixed Renewables) scenario from the draft

EDGS 2015 for use in this study, allocated by node (including TWI which reflects demand from New Zealand

Aluminium Smelter). Load growth modelling within PLEXOS has not been included as part of this study.

4.4 Transmission

Three levels of transmission detail can be modelled in PLEXOS: regional, zonal and nodal.

At the nodal level, the transmission network can be formulated using a linearised DC approximation of OPF

equations, with or without losses.

At the regional and zonal level, a transportation model is used to represent the network, with transmission limits

being applied to flow between regions/zones, but not within regions/zones.

For the purposes of this study we have modelled the NZEM system as two regions: North and South Island.

The DC losses on the HVDC link are modelled explicitly, and AC losses approximated using generator loss

factors and including an estimate of losses in the load forecasts.

It is assumed that when modelling the NZAS closure any inter-regional constraints would be alleviated without

delay through Transpower’s existing and approved grid investment authorisation. The focus of this study is

solely on market benefits brought about by change to the HVDC cable transfer limits as a result of the proposed

bypass line options and outage requirements.

4.4.1 HVDC limits and line losses

The capacity of the HVDC transfer prior to any potential outages in year 2020 is assumed to be 1,200 MW.

Losses represented when modelling HVDC transfers are the same as those line losses implemented in

Transpower’s SPD model, as previously supplied by Transpower:


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Table 4-3 HVDC line losses

DC transfer (MW) Line losses (MW)

50 0.228735

100 0.914939

200 3.659755

300 8.234449

400 14.63902

500 22.87347

600 32.93780

700 44.83200

The HVDC line losses applied in PLEXOS are expressed as the quadratic function of flow on the line, derived

by fitting a polynomial (Figure 4-4) to the data provided in Table 4-3:

f(x) = 0.000915x2 + 0.000x

The HVDC is modelled as two cables with respective capabilities of 500 MW and 700 MW sent. Internally,

PLEXOS represents this quadratic function as a number of piece-wise linear segments.

Figure 4-4 HVDC transfer losses

This loss function is applied to all configurations of the HVDC and is deemed to be a reasonable representation

of HVDC transfer losses in the context of this study.

4.5 Reserve Market

Historically each of the North and South Island has had its own reserve market; however since 2014

Transpower has begun implementation of its Reserve and Frequency Management Programme (RFM). The

y = 0.0000915x2 + 0.0000000x

0

5

10

15

20

25

30

35

40

45

50

0 100 200 300 400 500 600 700 800

Lin

e L

oss

es

(MW

)

DC Transfer (MW)


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goal of this programme is to achieve a fully co-optimised national market for reserves and frequency

management, using the HVDC capability to facilitate the sharing of reserves between islands.

This study has assumed a national market for Fast and Sustained Instantaneous Reserve in 2020, of up to approximately 200MW able to be shared across the HVDC. Further, with respect to frequency keeping, modelling assumptions are that no national market exists and therefore same-island frequency keeping provision only exists. However it is assumed that the frequency-keeping controller has a reduced requirement of 15 MW per island (reduced from 50MW per island), and that when using the frequency-keeper controller, a modulation risk of 30 MW applied to the HVDC, and is added to the DC CE risk calculation, as included the following section.

4.5.1 Reserve Requirement

There are three types of reserve requirements in the NZEM: Fast Instantaneous Reserve (FIR), Sustained

Instantaneous Reserve (SIR) and Frequency. The same capacity can be offered for the FIR and SIR markets,

but not for frequency control. FIR capacity must be online within 6 seconds and maintained for 60 seconds, SIR

capacity must be on within 60 seconds and maintained for 15 minutes.

In any half-hour period the amount of FIR and SIR reserve on the system must be sufficient to cover three

identified risks: AC CE risk, DC CE risk, and DC extended contingent event (ECE) risk, taking into consideration

net free reserve (NFR) which, for ECE, includes Automatic Under-Frequency Load Shedding (AUFLS).

Accordingly, in the PLEXOS formulation, the FIR and SIR requirements is the greater of:

FIR/SIR ≥ largest generator - NFR

FIR/SIR ≥ ∑HVDC(received) + Modulation Risk (30 MW) – risk subtractor(received) – NFR

FIR/SIR ≥ ∑HVDC(received) – AUFLS – NFR

For each of the reserve types and risks, typical values for NFR (including AUFLS) have previously been

provided by Transpower and these formulae are used in this study.

The FIR NFR applicable to the three risks identified above is set out in the following tables. NFR applicable to

AC and DC CE risk is split into two distinct time periods, day (06:00 to 21:30) and night (22:00 to 05:30), stated

as a constant in PLEXOS formulation.

NFR applicable to ECE CE risk takes into account AUFLS and is stated as a function of either North or South

Island load (NIPS or SIPS), less non-compliant generation. That is, generation that trips before minimum

frequency is reached. Once AUFLS are calculated each island’s total NFR can be determined.

All SIR NFR values for CE risk are set to zero. SIR NFR relating to DC ECE risk is equal to the AUFLS

formulation included in Table 4-6, dependant on island.

Table 4-4 AC CE risk NFR

Time (period starting) North Island South Island

06:00 to 21:30 150 60

22:00 to 05:30 120 25


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Table 4-5 DC CE risk NFR


06:00 to 21:30 125 35

22:00 to 05:30 95 0

Table 4-6 AUFLS as a function of load

Island Formula

North Island AUFLS 0.2976 * (NIPS) - 65

South Island AUFLS 0.288 * (SIPS) - 106

South Island AUFLS (NZAS exit)12 0.288 * (SIPS) - 106

The Tiwai Point load has been included in the South Island AUFLS formula and all current North Island

exemptions from AUFLs have been removed from the North Island formula. Should the NZAS exit the market a

secondary South Island AUFLS function is used in PLEXOS, as stated in Table 4-6.

Table 4-7 DC ECE risk NFR (including AUFLS)


06:00 to 21:30 NI AUFLS + 125 SI AUFLS + 35

22:00 to 05:30 NI AUFLS + 95 SI AUFLS + 0

4.5.2 Risk subtractor formula

In both the North and South Island, the amount of FIR and SIR provided must be greater than the combined

flow on the HVDC plus modulation risk for frequency keeping, less the risk subtractor and the net free reserve

(NFR) – assuming the HVDC is setting the reserve risk. That is:

FIR >= HVDC flow + Modulation Risk – FIR risk subtractor – DC CE NFR

SIR >= HVDC flow + Modulation Risk – SIR risk subtractor

The risk subtractor varies depending on the amount of overload capacity assumed on the HVDC pole 2, and

whether unbalanced pole operation is allowed. The risk subtractor to be included in this study is stated on a

MW received basis as indicated in Table 4-8, and assumes balanced pole operation.

Table 4-8 The assumed risk subtractor input

Risk subtractor for FIR (MW sent) Risk subtractor for SIR (MW sent)

560 (528 received) 560 (528 received)

4.5.3 OTB-HAY outage configuration and the risk subtractor formula

The OTB-HAY transmission outage options are to be modelled as two separate six week outages, and are likely

to be carried out during the summer period in 2020, thus avoiding higher winter period electricity demand. Each

12 If the exit of NZAS from the market is staggered its calculated AUFLS, as a function of load, may not be correct, although it

is unlikely to be materially different.


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six-week outage accounts for a four week period where the pole conductor is out and two weeks where the pole

conductor and the earthwire are isolated.

The pole conductor is required to be isolated whilst the earthwire is safely replaced and a single earthwire

further reduces capacity. It only reduces the post-contingent limits in bipole configuration but will reduce the

pre-contingent limits in the monopole cases.

The impact of the described approach on pre-contingent and post-contingent flows is summarised in the Table

3-1. Translation of these options into the risk subtractor formula is stated below.

Table 4-9 The assumed risk subtractor formula for OTB-HAY outage bypass options

Option Definition Outage 1 Outage 2

Option 1: 700

MW bypass

Configuration

Pre-contingent limit

Risk-subtractors (received)

Both poles in service

1,200 MW

4 weeks: 528MW

2 weeks: 350MW


1,200 MW

4 weeks: 528 MW

2 weeks: 350 MW

Option 2: 500

MW bypass

(Pole 2

connected)

Configuration

Pre-contingent limit



1,200 MW

4 weeks: 500 MW

2 weeks: 350 MW


1,200 MW

4 weeks: 500 MW

2 weeks: 350 MW

Option 3: No

bypass

Configuration

Pre-contingent limits


Pole 3 outage

4 weeks: 500 MW

2 weeks: 350 MW

0 MW

Pole 2 outage

4 weeks: 700 MW

2 weeks: 350 MW

0 MW

Option 4: No

bypass (Pole

2 outage)

Configuration

Pre-contingent limits


Pole 2 outage

4 weeks: 700 MW

2 weeks: 350 MW

0 MW

Pole 2 outage

4 weeks: 700 MW

2 weeks: 350 MW

0 MW

4.5.4 Reserve Provision

For the purpose of this study, it is assumed that a national reserve market will be fully implemented by the year

2020, enveloping both the North and South Island markets, but excluding frequency. This enables generators

from one island to provide FIR or SIR to meet a CE risk in the other island, subject to availability of spare

capacity across the HVDC. ECE risk is still required to be met from generation in the island importing power.

In order to account for the provision of reserve between the two islands taking into consideration potential time

delay differences between different generators, reserve provided by South Island generators to meet a North

Island AC CE risk is discounted13

. For example, for each MW of reserve provided by a North Island generator,

approximately 1.2 MW of reserve would need to be provided by a South Island generator.

The appropriate ratio to apply has been provided by Transpower previously (see Table 4-10) and has been

reapplied in this study.

13 Discounting of generator reserve provision is limited to South Island generators for two reasons; (1) flow on the HVDC is

predominantly northward flowing, and (2) North Island generators represent a higher level of risk to the market where additional reserves may be of benefit.


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Table 4-10 CE risk reserve provision ratios

Reserve Provision Reserve Sent Reserve Received

North Island FIR 1 1 (SI)

North Island SIR 1 1 (SI)

South Island FIR 1 0.81 (NI)

South Island SIR 1 1 (NI)

Transpower has provided a basis for determining the maximum reserve provision for both FIR and SIR.

Thermal generators provide FIR based on 5% of capacity and SIR based on 10% of capacity. Hydro plant

reserve provision is based on 10% of capacity, relating to a single turbine/unit, for both FIR and SIR reserve

types. Frequency keeping is provided from existing plant, without change, throughout the planning horizon.

The maximum reserve provision stated in MWs by generator and reserve type is provided in Appendix C and

includes new entrant generation.

In addition to generator reserve provisions, purchasers of electricity can offer quantities of consumption to be

disrupted for a given price per MW, thus providing Interruptible Load (IL).

Transpower has also previously provided typical quantities and taken account of the expected position of the IL

reserve in the FIR and SIR offer stacks. North Island IL is typically a price taker in the market however South

Island IL, largely provided by the NZAS, provides IL based on price signal, at approximately $10/MW. Provision

of IL included in the model is presented below in Table 4-11 including the adjusted scenario accounting for

NZAS exiting the market.

Table 4-11 Interruptible Load (IL)

Reserve Provision Offer Quantity Offer Price

North Island FIR IL 150 $0.02/MW

North Island SIR IL 210 $0.02/MW

South Island FIR IL 170 $10.00/MW

South Island SIR IL 170 $10.00/MW

South Island FIR IL (NZAS Exit) 20 $10.00/MW

South Island SIR IL (NZAS Exit) 20 $10.00/MW

For the avoidance of doubt, Interruptible Load does not contribute to reserve sharing across the HVDC.

In the NZEM, where there can be insufficient capacity to meet both energy and reserve requirements, FIR and

SIR reserves are shed first to maintain energy and frequency. Beyond that, load is shed before frequency

keeping constraints are violated.

4.6 Hydro scenarios

Hydrology has a significant impact on the utilisation of the HVDC, therefore impacting on potential market

benefits. For the purposes of this study each generation scenario is accompanied by a fixed hydro scenario,

representing an average year before and during outages to be modelled.

For the purposes of this study we have used the year 1956 to represent average inflows. Figure 4-5 shows

inflows for the major storage lakes for this average hydrological year.


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Figure 4-5: Mean inflows for major storage lakes

To better understand the magnitude of change in benefits associated with hydrology an additional scenario has

been considered. The 1987 hydrology pattern has also been applied, against the Business as Usual Option,

representing a dry North Island and wet South Island hydrology scenario in order to assess the effect of higher

anticipated northward transfers on the HVDC.

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Manapouri Taupo Tekapo Pukaki Hawea


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5. Modelling Results

For each market scenario the gross market costs in year 2020 and associated benefits have been calculated

drawing on the following components:

Fuel costs of electricity production;


Emission costs;

Costs of unserved energy (the product of unserved energy and VoLL ($20,000/MWh)); and

Costs of reserve shortage (the product of reserve shortage and VoRS ($5,000/MWh)).

A comparison of gross market costs associated with each bypass option and based on each of the identified

market scenarios is shown below (Table 5-1).

For ease of reference the bypass options considered are:





a time; and



Table 5-1 Annual gross market costs (all scenarios)

Annual Gross Market Costs ($m)



Huntly Retires $ 521.94 $ 521.94 $ 522.11 $ 522.14

Tiwai Closes $ 232.57 $ 232.57 $ 233.21 $ 238.93


BAU (U5) $ 540.99 $ 540.99 $ 541.35 $ 541.11

BAU (1987) $ 395.03 $ 395.03 $ 439.92 $ 425.01

At a high level the annual gross market costs shown in Table 5-1 appear intuitive. Option 1 presents the

highest overall capacity on the HVDC, with Option 2 marginally reducing this capacity. We note that this

marginal reduction in capacity does not differentiate gross market costs between these two bypass options. This

is consistent across all market scenarios.

Option 3 and Option 4, represent no bypass line installed and OTB-HAY outages either balanced between poles

or restricted to pole 2. This effectively reduces the transfer capacity of the HVDC resulting in an increase in

overall gross market generation costs. The increases in costs are small when considering Business as Usual,

Huntly Retires and BAU (U5) scenarios however can be seen to increase when a higher level of energy transfer

is required under the Tiwai Closes and BAU (1987) scenarios

The magnitude of these result are discussed in the following sections.


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5.1 Gross Market Benefits

Annual gross market benefits are set out in Table 5-2 below. This table draws comparison of annual gross

market costs, assuming Option 1 as the base case. We note there is no differentiation between Options 1 and

Option 2, in terms of benefits. Benefits are read as negative i.e. Options 3 and 4 represent an increase in gross

market costs, suggesting benefits associated with Option 1, or negative benefits associated with Options 3 and

4.

Table 5-2 Annual gross market benefits

Annual Gross Market Benefits ($m)



Huntly Retires $ - $ - -$ 0.17 -$ 0.20

Tiwai Closes $ - $ - -$ 0.64 -$ 6.36


BAU (U5) $ - $ - -$ 0.37 -$ 0.13

BAU (1987) $ - $ - -$ 44.89 -$ 29.98

Results suggest annual gross market benefits associated with Business as Usual, Huntly Retires and BAU (U5)

scenarios are particularly small, given an average hydrology year. Benefits range from between 0.02% to

0.07% of their respective annual gross market costs.

Tiwai Closes and BAU (1987) scenario results, representing an increased level of electricity supply for the

NZEM from the South Island largely from hydro generation, suggest benefits between 0.02% and 10.2% of

annual gross market costs.

Given the low level of market benefits identified further analysis has been undertaken to determine where the

benefits might be occurring in relation to the OTB-HAY outages and if any potential model optimisation could be

at play.

The following sections explore each market scenario in more detail.

5.1.1 Gross market benefits – Business as Usual (BAU)

The Business as Usual scenario reflects the current NZEM generation fleet with the addition of 200 MW of gas

fired plant and approximately 160 MW of renewable plant prior to year 2020. Approximately 100 MW of

demand side response is also added prior to 2020.

Trading interval gross market benefits associated with the Business As Usual scenario have been aggregated

to the daily level in order to make the data more manageable and assist with analysis. Figure 5-1 provides an

indication of when the daily benefits occur for each scenario throughout the year, when compared to Option 1.

Transpower’s nominated OTB-HAY outage period is identified by the red circle on the chart.

Differences in benefits identified across the various HVDC configurations are particularly small and the anomaly

at the tail end of the year is noted. This is understood to be linked with hydrological patterns at this time of year

and model optimisation of water storage targets.


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Figure 5-1: Daily gross market benefits – Business as Usual14

Average daily generation costs for the BAU scenario are estimated at approximately $1.5m per day. Figure 5-2

provides a closer look at the benefits restricted to the OTB-HAY outage periods, so excluding days external to

the planned outages and their associated benefits.

Figure 5-2: Restricted gross market benefits – Business as Usual

Options 3 and 4 present reasonably consistent negative benefits over both six week OTB-HAY outage periods.

Based on this restricted view, gross market benefits attributed to Option 1 and 2 when compared to Option 3 are

estimated at $1.5m, and Options 4 $1.55m – noting there is no difference between Options 1 and 2.

5.1.2 Gross market benefits – Huntly Retires

The Huntly Retires scenario sees the last of Huntly’s coal-fired units retire before 2020, 400MW of North Island

gas fired plant enter the market between 2017 and 2019, and a further approximately 400MW of renewable

generation come on line. Demand side response of approximately 100MW is also available prior to 2020.

Daily gross market benefits identified under the Huntly Retires scenario for the year 2020 are identified in Figure

5-3 below. As in Figure 5-1, Transpower’s OTB-HAY outage periods are circled in red (see Figure 5-3).

14 Benefits are read as negative numbers i.e. a negative number represents a higher generation cost.

-$150

-$100

-$50

$0

$50

$100

$150

$200

Be

ne

fits

('0

00

)

Diff Option 1 & 2 Diff Option 1 & 3 Diff Option 1 & 4

-$140

-$120

-$100

-$80

-$60

-$40

-$20

$0

$20

$40

$60

Be

ne

fits

('0

00

)



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Negative benefits are apparent over the outage periods, as a result of the HVDC capacity reduction under

Options 3 and 4 and the requirement for North Island thermal generation to respond to demand.

Figure 5-3: Daily gross market benefits – Huntly Retires

Considerable “noise”, at a low level, due to model optimisation remains present. Figure 5-4 provides a

restricted view on gross market benefits for each scenario. Options 3 and 4 shows negative gross market

benefits of approximately $3m each, over the nominated OTB-HAY outage periods.

Figure 5-4: Restricted gross market benefits – Huntly Retires

5.1.3 Gross market benefits – Tiwai Closes

The Tiwai Closes scenario allows for an increase in available generation from Manapouri hydro station given

closure of the Tiwai aluminium smelter in the South Island. Huntly’s last coal –fired unit is retired prior to 2020

and a single gas peaker plant is added to the North Island.

Negative benefits associated with Options 3 and 4 over the OTB-HAY outage period are pronounced in the

Tiwai Closes scenario. Limited transfer capacity on the HVDC means costly thermal generators in the North

Island are needed to meet demand.

The positive benefits associated with Option 3 and 4 following the OTB-HAY outage periods suggest some

ability for water to be stored during the outage periods and run later in the year, thus providing a level of benefit

post the designated outage periods.

-$150

-$100

-$50

$0

$50

$100

$150

Be

ne

fits

('0

00

)

Diff Option 1 & 2 Diff Option 1 & 3 Diff Option1 & 4

-$120

-$100

-$80

-$60

-$40

-$20

$0

$20

$40

Be

ne

fits

('0

00

)

Diff Option 1 & 2 Diff Option 1 & 3 Diff Option1 & 4


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Figure 5-5: Daily gross market benefits – Tiwai Closes

Figure 5-6 shows the gross market benefits associated with the identified outage periods only. This suggests

Options 1 and 2 provide benefits of approximately $23.2m over Option 3 and $12.5m over Option 4.

Figure 5-6: Restricted gross market benefits – Tiwai Closes

5.1.4 Gross market benefits – BAU (U5)

The BAU (U5) scenario seeks to identify the effect on benefits when introducing an outage to major North Island

thermal generation during the planned OTB-HAY outages. Huntly Unit 5 has been taken out of service for a

week in late January, 25th January 2020 to 1

st February, with all else in the initial scenario remaining

unchanged.

Daily gross market benefits are shown in Figure 5-7, the OTB-HAY outage period highlighted by the red circle.

Overall, benefits again appear small with a level of market cost reduction noted given high cost thermal plant

withdrawn from the market.

We note again the model optimisation at the tail end of the year, as per the initial BAU scenario.

-$600

-$500

-$400

-$300

-$200

-$100

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Figure 5-7: Daily gross market benefits – BAU (U5)

Examining the OTB-HAY outage periods in isolation of the rest of year provides an indication that the impact of

Huntly U5 not being available during the planned OTB-HAY outage has minimal effect. Figure 5-8 shows

negative benefits are in fact reduced for Option 4, given the withdrawal of Huntly Unit 5s costly generation and

great utilisation of capacity of the HVDC. However Option 3s negative benefits increase as a shift in reserve

risk from thermal generation to the HVDC occurs and higher cost thermal units are brought on to meet demand

– see section 5.3 below for further discussion on reserve costs.

Figure 5-8: Restricted gross market benefits – BAU (U5)

5.1.5 Gross market benefits – BAU (1987)

Our last scenario provides for an alternative hydrological pattern added to the Business as Usual study. The

1987 hydrological scenario represents a dry year in the North Island and a wet year in the South Island, thus

increasing the need for a greater level of transfer northward across the HVDC, both for evacuating energy from

the southern reservoirs and supplying North Island demand.

Figure 5-9 shows a greater level of negative benefits associated with Options 3 and 4 than observed in previous

scenarios (similar to Tiwai Closes), meaning an increased level of costly thermal generation exists. In addition

to the outage period, highlighted by the red circle, daily negative gross market benefits are evident immediately

following the OTB-HAY outages (identified in the blue circle).

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Investigation into the strong surge of negative benefits directly following the second OTB-HAY outage reveals it

is driven by an increase in northward transfer on the HVDC for sustained periods, along with an increase in

reserve risk that allows thermal generators to operate at higher levels without having to balance their own

reserve risk requirements, as was evident throughout the OTB-HAY outage periods.

Figure 5-9: Daily gross market benefits – BAU (1987)

Figure 5-10 provides a restricted view on gross market benefits for the BAU (1987) scenario meaning benefits

are limited to OTB-HAY outage intervals only. Results translate into gross market benefits of approximately

$17.9m for Option 1 or 2 over Option 3, and benefits in order of $11.9m for Option 1 or 2 over Option 4.

Figure 5-10: Restricted gross market benefits – BAU (1987)

Examination of the modelling results above suggest a level of optimisation occurring in the model when

balancing water volumes across the market over the 12 month period, whilst taking account of the HVDC

constraint calculations applied in each Option, thus resulting in a level of variability unlikely to be removed. The

“noise” identified impacts perceived gross market benefits when taken as an annualised figure. A suitable

approach to isolating this variability, to the extent where possible, and consistently applied across all options is

to restrict the aggregation of gross market benefits to the planned OTB-HAY outage periods only.

Table 5-3 provides the gross market benefits when restricted to outage periods only for the year 2020 across all

options.

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Table 5-3 Gross market benefits (restricted to OTB-HAY outage period)




Huntly Retires $ - $ - -$ 3.01 -$ 2.99

Tiwai Closes $ - $ - -$ 23.18 -$ 12.46


BAU (U5) $ - $ - -$ 1.43 -$ 1.21

BAU (1987) $ - $ - -$ 17.87 -$ 11.79

Restricted gross market benefits associated with Business as Usual, Huntly Retires and BAU (U5) scenarios are

in the range between 0.2% to 0.7% of their respective annual gross market costs (or approx. $1.2m to $1.6m).

Under scenarios Tiwai Closes and BAU (1987) restricted gross market benefits range between 2.8% and 10.0%

of annual gross market costs, or approximately $11.8m to $23.2m.

5.2 HVDC Flows

This section provides a brief illustration of the HVDC flows observed in each scenario modelled.

5.2.1 Daily HVDC Flows – Business as Usual (BAU)

Figure 5-11 shows that the daily HVDC flows under the Business as Usual scenario separate for Options 3 and

4 once the OTB-HAY outages commence in mid-January. Between the first and second OTB-HAY outage

HVDC flows increase markedly, and again immediately following the second outage.

Figure 5-11: Daily HVDC flows – Business as Usual

Convergence of HVDC flows appears to occur well beyond the completion of the second outage in mid-April,

closer to June 2020. This suggests ability for the system to store constrained water and use this to generate at

a later time.

Figure 5-12 provides an alternative view of the same data, illustrating the difference in daily HVDC flows

between options. HVDC outage constraints are clearly defined in the Option 3 and 4 data, followed by dramatic

increases in flow as capacity is increased on the link, and then convergence noted earlier.

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Figure 5-12: Daily HVDC flow differences – Business as Usual

5.2.2 Daily HVDC Flows – Huntly Retires

Similarly to the previous scenario, Figure 5-13 illustrates the separation of Options 3 and 4 daily HVDC flows

under the Huntly Retires scenario and convergence of flows across all options over an extend period.

Figure 5-13: Daily HVDC flows – Huntly Retires

Figure 5-14 provides an alternative view of HVDC flows where an increase in volatility is noted, and in general

HVDC flows appear stronger for Options 3 and 4 over the long term. This is likely to be a result of model

optimisation and is largely considered to be “noise”.

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Figure 5-14: Daily HVDC flow differences – Huntly Retires

5.2.3 Daily HVDC Flows – Tiwai Closes

Daily HVDC flows relating to the Tiwai Closes scenario can be observed in Figure 5-15 below. A similar pattern

to previous scenarios exist however given the increased availability of generation available to the market from

the South Island considerably more pressure is placed on the HVDC.

Option 3s Pole 3 outage from mid-January to the end of February is clearly identifiable, along with the additional

capacity that is provided by Option 4. Options 1 and 2 remain indifferent to each other.

Figure 5-15: Daily HVDC Flows – Tiwai Closes

Figure 5-16 provides a similar illustration, from a differential point of view, and notably the time it takes for

HVDC flow differences to converge with Option 3 showing signs of simply not settling.

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Figure 5-16: Daily HVDC flow differences – Tiwai Closes

5.2.4 Daily HVDC Flows – BAU (U5)

The nominated outage in late January for Huntly Unit 5 has a minor effect on daily HVDC flows. Figure 5-17

illustrates a small change in daily flows compared to the Business as Usual scenario presented in 5.2.1 above.

The Huntly Unit 5 outage period is identified by a red circle.

Figure 5-17: Daily HVDC Flows – BAU (U5)

Figure 5-18 provides a comparison of HVDC flows to Option 1, and indicates an increase in HVDC flows for

Option 4 during the Huntly Unit 5 outage period, where additional capacity on the HVDC appears to be utilised

in order to meet demand in the North Island.

Option 3 daily HVDC flows appear to decrease further when Huntly Unit 5 is out of service, coupled with an

increase in reserve costs (see also Figure 5-24: Daily reserve cost – BAU (U5)). The remainder of the HVDC

flows under this scenario are not largely dissimilar to our initial Business as Usual scenario, noting a level of

model optimisation or variability exists.

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Figure 5-18: Daily HVDC flow differences – BAU (U5)

5.2.5 Daily HVDC Flows – BAU (1987)

The 1987 hydrological pattern included in this scenario utilises much of the HVDC capacity to export electricity

from the South Island to the North Island, particularly over the first half of the year where inflows are high.

Figure 5-19 provides a clear illustration of the different HVDC flows and constraints modelled under each option

– noting Option 1 and 2 remain indifferent.

Figure 5-19: Daily HVDC Flows – BAU (1987)

Option 3 is highly constrained over the first OTB-HAY outage period, noting Pole 3 is out of service and flow is

limited to Pole 2. Option 4 provides a consistent illustration of transfer limited to Pole 3 alone over both outage

periods.

Interestingly the modelling outputs reveal elevated HVDC flows for both Options 3 and 4 prior to the outages,

between outages, and again following the second outage. This reflects an ability to evacuate energy from the

South Island at times outside of the nominated OTB-HAY outage periods given high availability of South Island

generation as a result of high inflows.

Figure 5-20 illustrates the BAU (1987) scenario HVDC flows based on differences between the Option 1 as the

base case and Options 2, 3 and 4. Convergence of all option HVDC flows is noted as being particularly swift

and understood to relate to the pressure on the HVDC to utilise its capacity to meet demand.

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Figure 5-20: Daily HVDC flow differences – BAU (1987)

5.3 Reserve Costs

This section provides a brief summary of the NZEM reserve costs observed in model results. Daily reserve

costs have been plotted for each option under each market scenario.

A common occurrence in results from the Business as Usual and Huntly Retires scenarios is the increase in

reserve costs for Option 3s first outage, where Pole 3 is taken out of service and HVDC transfers rely on Pole 2

alone, with no bypass installed. Reserve costs to the market are observed at $5k to 20k per day.

Figure 5-21 and Figure 5-22 show the increase in reserve costs during OTB-HAY outage periods for both the

noted scenarios. Winter peak reserve costs are somewhat variable across the different options, and in part this

is to be expected given the optimisation of hydro storage apparent in the NZEM.

Figure 5-21: Daily reserve cost – Business as Usual

Annual reserve costs for both the Business as Usual and Huntly Retires scenarios range between $300k per

annum to approximately $600k per annum.

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Figure 5-22: Daily reserve cost – Huntly Retires

The Tiwai Closes scenario illustrated in Figure 5-23 below shows HVDC constraints applied under Option 3 and

4 translate into substantial reserve costs during the OTB-HAY outage periods. The excess of available energy

in the South Island due to closure of the Tiwai aluminium smelter appears to exacerbate reserve market

outcomes and are in line with the high level of HVDC flows observed in the previous section for this scenario.


$42.9m for Option 3 and $21.6m for Option 4.

Figure 5-23: Daily reserve cost – Tiwai Closes

Winter peak reserve costs can also be seen to be higher than in other scenarios, as HVDC flows remain

significantly higher throughout the year, and optimisation of energy and reserve comes under pressure during

this peak demand period.

Daily reserve costs in the BAU (U5) scenario (see Figure 5-24 below) appear similar to both the Business and

Usual and Huntly Retires scenarios. A small increase in reserve costs is observed during Huntly Unit 5s outage

in the end of January and optimisation of energy and reserve influences market costs during Option 3s Pole 3

outage.

Reserve costs for this scenario range from approximately $400k to $500k per annum and are not considered

significant.

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Figure 5-24: Daily reserve cost – BAU (U5)

Much like the Tiwai Closes scenario, Figure 5-25 illustrates the increased reserve costs driven by pressure on

the HVDC to transfer energy up to its capacity, impacting on energy and reserve trade-offs and the ability for a

constrained HVDC to effectively share reserves between islands.

The winter period reserve costs under this scenario are largely reduced. Transfer on the HVDC appears to drop

back to a comfortable level post early year inflows and HVDC outages, meaning energy and reserve sharing on

the HVDC are able to be optimised over the peak demand period without significant impact on costs.

Figure 5-25: Daily reserve cost – BAU (1987)

Annual reserve costs under the BAU (1987) scenario equate to approximately $5m for Options 1 and 2, $28m

for both Options 3 and 4.

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6. Conclusions

Our analysis shows that the gross market benefits associated with installing a bypass to facilitate the required

OTB-HAY re-conductoring work are small. Noting the small level of benefits, modelling results reveal evidence

of a level of “noise” or model optimisation that is unlikely to be removed. Restricting the calculation of gross

market benefits to the nominated OTB-HAY outage periods is deemed a suitable approach to draw comparison

between the HVDC bypass and configuration options, and the gross market benefits that arise.

Market scenarios Business as Usual, Huntly Retires and the additional BAU (U5) scenario present gross market

benefits associated with installation of a bypass in the range of $1.2m to $3m. Market scenarios Tiwai closes

and BAU (1987), which simulate an increased level of available hydro generation from the South Island, provide

for a greater measure of gross market benefits. Installation of a bypass relating to the Tiwai Closes scenario

represents benefits of approximately $23.2m over Option 3, and $12.5m over Option 4. Installation of a bypass

relating to the BAU (1987) scenario represents gross market benefits of approximately $17.9m over Option 3

and $11.8m over Option 4.

Without comparing the gross market benefits against nominal bypass investment costs a measure of the net

cost or benefit cannot be drawn.

Table 6-1 provides the gross market benefits (read as negative) when comparing the bypass base case, Option

1, with the total generation costs in Options 2, 3 and 4. We not there is no difference in total generation costs

between Option 1 and Option 2.

Table 6-1 Gross market benefits (restricted to OTB-HAY outage period)




Huntly Retires $ - $ - -$ 3.01 -$ 2.99

Tiwai Closes $ - $ - -$ 23.18 -$ 12.46


BAU (U5) $ - $ - -$ 1.43 -$ 1.21

BAU (1987) $ - $ - -$ 17.87 -$ 11.79

For illustration purposes the following charts show weekly total generation costs for each market scenario over

the year 2020. Benefits arise from the least cost generation solution.

Figure 6-1: Weekly total generation cost – Business as Usual

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Figure 6-2: Weekly total generation cost – Huntly Retires

Figure 6-3: Weekly total generation cost – Tiwai Closes

Figure 6-4: Weekly total generation cost – BAU (U5)

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Figure 6-5: Weekly total generation cost – BAU (1987)

6.1 Reserve Costs

Although unlikely to be a determining factor in decision making for Transpower reserve costs provide an

indication of market tension, particularly in regards to the optimisation of energy and reserves in market

dispatch.

Table 6-2 Market reserve costs

Reserve Costs ($m)



Huntly Retires $ 0.29 $ 0.29 $ 0.37 $ 0.39

Tiwai Closes $ 2.28 $ 2.28 $ 42.85 $ 21.63

BAU (U5) $ 0.39 $ 0.39 $ 0.51 $ 0.41

BAU (1987) $ 5.08 $ 5.08 $ 28.33 $ 28.17

Market reserve costs for scenarios Business as Usual, Huntly Retires and BAU (U5) range from $0.3m to

$0.6m, and are noted as insignificant.


$42.9m for Option 3 and $21.6m for Option 4. Annual reserve costs under the BAU (1987) scenario equate to

approximately $5m for Options 1 and 2, and $28m for both Options 3 and 4.

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Appendix A. Overview of PLEXOS

PLEXOS is a mixed integer programming model that optimises dispatch using the same techniques that are

used in the Scheduling, Pricing and Dispatch model (SPD) to clear the NZEM.

Generation dispatch, transmission power flow and ancillary services are co-optimised and integrated with hydro

and emissions modelling, providing a versatile suite of features that may be adapted to accommodate most

electricity markets.

Prior to optimising dispatch, PLEXOS schedules planned maintenance and randomly pre-computes a user-

specified number of forced outage scenarios and/or stochastic samples for Monte Carlo simulation.

Dispatch is then optimised to meet load and ancillary service requirements at minimum cost subject to a number

of operating constraints, which may include:

Generation constraints – availability (planned and unplanned outages), unit commitment and other

technical constraints;

Transmission constraints – availability (planned and unplanned outages), linearised DC optimal power

flow (OPF) equations, interconnector ratings, and other transmission constraints that may be a function

of load, generation or line flow;

Hydrology constraints – hydro units may be energy-constrained, or more detailed storage models may

be represented with stochastic hydro inflows;

Fuel constraints – for example, daily fuel limits or annual take-or-pay constraints;

Ancillary service constraints – maximum unit response, calculation of dynamic risk; and

Emission constraints – limits on emission production may be imposed, or carbon prices specified.

In determining this least-cost dispatch, generators formulate bids that are offered into the market to be cleared.

These bids may be manually input, or they may be derived dynamically by PLEXOS based on either the short-

run marginal cost (SRMC) of the unit, or strategic objectives. For the purpose of this analysis, SRMC bidding is

assumed. Therefore, competition benefits are not captured in our market benefit analysis.

A.1 SPD and Reserve Management Tool

The steady state operation of the NZEM power system is based on the SPD model. As part of the scheduling

and dispatch process, reserve offers are co-optimised with the energy offers from generators. The System

Operator uses the Reserve Management Tool (RMT) to calculate the instantaneous reserves required to meet

the markets Reserve Management Objective, see Figure 6-6 (Source: Transpower – RMT Functional

Specification, 2011).


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Figure 6-6 Role of RMT in the SPD Process

When calculating the instantaneous reserve requirements RMT determines the net free reserve (NFR)

according to the risk in each island. The NFR must represent the reserve requirement offset from the risk.

PLEXOS uses typical NFR values, provided by Transpower, as input to determining the risk and reserve

requirement in each island and, as in the SPD RMT interaction, the NFR represents the reserve requirement

offset from the risk.


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A.2 PLEXOS Algorithms

To enable modelling of long-term objectives and short-term constraints, PLEXOS includes four integrated

algorithms:

PASA/preschedule – optimising maintenance scheduling, and prescheduling unplanned outages for

Monte Carlo simulation;

Long-term simulation (LT) – using load duration curve (LDC) analysis to allow modelling of horizons

spanning more than one year in a single step. Suitable for long-term planning where decisions need to

take account of future market changes;

Mid-term simulation (MT) – using LDC analysis to model up to one year in a single step. Suitable for

mid-term operational planning; and

Short-term simulation (ST) – modelling chronological dispatch in every trading period (typically one

hour or half-hour). Suitable for operational decision making.

Users may select any combination of these four algorithms to fit their modelling requirements. For the NZ

system, expansion plans are an input to the model rather than be determined by the LT. Of importance is the

integration of the algorithms, with results from the MT being used to inform the ST, such as hydro storage

trajectories. This flow of information from one algorithm to another, used for this study, is demonstrated in

Figure 6-7.

Figure 6-7 Integration of PLEXOS algorithms for the NZ study

A.3 Aggregating the model

It is important that the length of each step used in the MT at least spans the duration of all inter-temporal

constraints. For example, if there is an annual hydro energy constraint in the model, the MT must be able to run

at least one year in a single step in order to determine when best to use the available hydro throughout the

year.

There is often a trade-off that must be made between the complexity of the model and the length of the horizon

that can be spanned in one step. To enable months or years to be spanned in a single step in the MT, hourly

load profiles are aggregated into blocks, whereas in the ST the full chronology is modelled.

Mid - term simulation

Short - term simulation

Annual storage

trajectories decomposed

to weekly end storage

targets

Detailed weekly

chronological dispatch

PASA and

preschedule

Mid - term simulation

Short - term simulation

PASA and

preschedule

Forced outages

and maintenance

schedule


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For hydro systems such as the NZEM, it is generally recommended that the length of the period over which load

is aggregated is equal to the length of the step used in the ST simulations. For example, if load is aggregated

into blocks using weekly load duration curves in the MT, then the ST should ideally model one week at a time,

with weekly storage targets passed down from the MT simulation. This ensures that the weekly end storage

targets in the ST are consistent with the outcomes from the MT modelling.


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Appendix B. Existing Power Plants

Power station Size (MW) Plant type

HlyUnit5 1 x 385 Thermal

HlyUnit6 1 x 50 Thermal

Huntly U1 1 x 250 Thermal

Huntly U2 1 x 250 Thermal

MangaTodd 1 x 10 Thermal

Stratpeaker 1 x 200 Thermal

TaranCC 1 x 380 Thermal

ToddPeak_McKee 2 x 50 Thermal

Whirinaki 3 x 155 Thermal

Aniwhenua 1 x 25 North Island Hydro

Arapuni 8 x 24.6 North Island Hydro

Atiamuri 4 x 21 North Island Hydro

Kaimai 1 x 42 North Island Hydro

Kaitawa 2 x 18.5 North Island Hydro

Karapiro 3 x 32 North Island Hydro

Mangahao 1 x 39 North Island Hydro

Maraetai 10 x 36 North Island Hydro

Matahina 2 x 40 North Island Hydro

Ohakuri 4 x 28 North Island Hydro

Patea 3 x 10.2 North Island Hydro

Piripaua 2 x 22.5 North Island Hydro

Rangipo 2 x 60 North Island Hydro

Tokaanu 4 x 60 North Island Hydro

Tuai 3 x 19.3 North Island Hydro

WaikHyd_ARA 3 x 28 North Island Hydro

Whakamaru 4 x 25 North Island Hydro

Wheao 2 x 13 North Island Hydro

Amethyst 1 x 6 South Island Hydro

Aviemore 4 x 55 South Island Hydro

Benmore 6 x 90 South Island Hydro

Clyde 4 x 108 South Island Hydro

Cobb 1 x 32 South Island Hydro

Coleridge 1 x 41 South Island Hydro

Highbank 1 x 34.5 South Island Hydro

Manapouri 6 x 121.7 South Island Hydro

Manapouri MTAD 1 x 75 South Island Hydro

Ohau A 4 x 66 South Island Hydro

Ohau B 4 x 53 South Island Hydro

Ohau C 4 x 53 South Island Hydro

Paerau 1 x 12 South Island Hydro

Roxburgh1_5 5 x 40 South Island Hydro

Roxburgh6_8 3 x 40 South Island Hydro


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Tekapo A 1 x 25 South Island Hydro

Tekapo B 2 x 80 South Island Hydro

Waipori 1 x 84 South Island Hydro

Waitaki 7 x 15 South Island Hydro

Glenbrk 1 x 74 Cogen

Hawera 1 x 70 Cogen

Kapuni 1 x 25 Cogen

Kinleith 1 x 40 Cogen

TeRapa 1 x 44 Cogen

Kawerau1 1 x 90 Geothermal

Mokai 1 1 x 72 Geothermal

Mokai 2 1 x 38 Geothermal

Nga Awa Purua 1 x 138 Geothermal

Ngatamariki 1 x 83 Geothermal

Ngawha 1 x 5 Geothermal

Ohaaki 1 x 69 Geothermal

Poihipi 1 x 53 Geothermal

Rotokawa 1 x 34 Geothermal

Tauha1 1 x 25 Geothermal

TeMihi 1 x 166 Geothermal

Wairaki (after Te Mihi is commissioned) 1 x 114 Geothermal

Mahinerangi 1 x 36 Wind

MillCreek 1 x 60 Wind

TararWd3 1 x 93 Wind

TaraW12 1 x 32 Wind

Te Rere Hau 1 x 48 Wind

TeApiti 1 x 91 Wind

TeUku 1 x 64 Wind

WestWnd 1 x 143 Wind

WhiteHill 1 x 58 Wind


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Appendix C. Maximum Generator Reserve Provision15

Existing Generators NI FIR NI SIR SI FIR SI SIR Freq

Arapuni 2.46 3.69 2.46 3.69 Yes (NI)

Atiamuri 2.1 3.15 2.1 3.15 Yes (NI)

Aviemore 4.46 4.46 5.5 5.5 Yes (SI)

Benmore 7.29 7.29 9 9 Yes (SI)

Clyde 8.75 8.75 10.8 10.8 Yes (SI)

HlyUnit5 19.25 38.5 19.25 38.5 -

HuntC1 12.15 24.3 12.15 24.3 Yes (NI)

HuntC2 12.15 24.3 12.15 24.3 Yes (NI)

Kaitawa 1.85 2.78 1.85 2.78 -

Karapiro 3.2 4.8 3.2 4.8 Yes (NI)

Manapouri 9.72 9.72 12 12 -

Manapouri MTAD 7.29 7.29 9 9 -

Mangahao 3.2 4.8 3.2 4.8 -

Maraetai 3.6 5.4 3.6 5.4 Yes (NI)

Matahina 4 6 4 6 -

Ohakuri 2.8 4.2 2.8 4.2 Yes (NI)

Ohau A 5.35 5.35 6.6 6.6 Yes (SI)

Ohau B 4.29 4.29 5.3 5.3 Yes (SI)

Ohau C 4.29 4.29 5.3 5.3 Yes (SI)

Patea 1.02 1.53 1.02 1.53 -

Rangipo 6 9 6 9 -

Roxburgh1_5 3.24 3.24 4 4 Yes (SI)

Roxburgh6_8 3.24 3.24 4 4 Yes (SI)

Stratpeaker 10 20 10 20 -

TaranCC 19 38 19 38 -

Tekapo A 2.03 2.03 2.5 2.5 Yes (SI)

Tekapo B 6.48 6.48 8 8 Yes (SI)

Tokaanu 6 9 - - -

ToddPeak_Mckee 2.5 5 2.5 5 -

Waitaki 1.22 1.22 1.5 1.5 Yes (SI)

Whakamaru - - - - Yes

IL0 50 50 No

Total Existing 272.7 424.2 238.7 390.2

New Generators NI FIR NI SIR SI FIR SI SIR Freq

HaweaCG 1.38 1.38 1.7 1.7 -

Lake Pukaki 2.84 2.84 3.5 3.5 -

OCGTPkrG6 10 20 10 20 -

ToddPeak_Otor 5 10 10 10 -

ToddPeakJnctnRd 5 10 10 10 -

Wairau 5.67 5.67 7 7 -

WhkmruExp 2 2 2 2 -

Total Existing 31.88 51.88 34.2 54.2 -

15 The reserve provision figures stated exclude effectiveness of NI FIR being provided by SI generators (refer Section 4.5.4).


RZ024300_01

Appendix D. Generation expansion Plans

Three key market scenarios have been considered as follows, and applied to the four options above resulting in

a total of 12 market modelling runs:

The final Huntly coal-fired units retire as planned, one in 2018 and the second by 202016;

The remaining units at Huntly are not retired; and

The NZAS aluminium smelter at Tiwai Point shuts down in combination with the remaining Huntly unit

retiring.

The three market scenario generation expansion plans shown below:

Scenario 1 – Huntly coal-fired stations retire as originally planned.

Installed MW / Year

Station / DSR 2016 2017 2018 2019 2020

CCGTCHP1 40

OCGTPkrG6 200

ToddPeak_Otor 100

ToddPeakJnctnRd 100

GGeoNgawh1 25

KA22TeAhi 20

Tauha2 250

HaweaCG 17

LakePukaki 35

CastleHill_s1 60

WhkmruExp 20

DSRchch1 22.4

DSRnthd1 8

DSRnshr1 6

DSRotag1 8

DSRakld1 40

DSRslnd1 5

DSRwaik1 6

Huntly unit 1 -250

Huntly unit 2 -250

Scenario 2 – Business as usual and the coal-fired units at Huntly are not retired

Installed MW / Year

Station / DSR 2016 2017 2018 2019 2020

ToddPeak_Otor 100

ToddPeakJnctnRd 100

KA22TeAhi 20

Rotoma 35




RZ024300_01

HaweaCG 17

Wairau 70

WhkmruExp 20

DSRchch1 22

DSRnthd1 8

DSRnshr1 6

DSRotag1 8

DSRakld1 40

DSRslnd1 5

DSRwaik1 6

Scenario 3 - NZAS aluminium smelter at Tiwai Point retires by 2020, along with Huntly

Installed MW / Year

Station / DSR 2016 2017 2018 2019 2020

Huntly unit 1 -250

Huntly unit 2 -250

ToddPeakJnctnRd 100

KA22TeAhi 20

WhkmruExp 20

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