Economic Benefit Assessment

www.concept.co.nz

GeoFuture project: economic benefit assessment

Final report

July 2021

Disclaimer

Except as expressly provided for in our engagement terms, Concept and its staff shall not, and do not, accept any liability for errors or omissions in this report or for any consequences of reliance on its content, conclusions or any material, correspondence of any form or discussions, arising out of or associated with its preparation.

The analysis and opinions set out in this report reflect Concept’s best professional judgement at the time of writing. Concept shall not be liable for, and expressly excludes in advance any liability to update the analysis or information contained in this report after the date of the report, whether or not it has an effect on the findings and conclusions contained in the report.

This report remains subject to any other qualifications or limitations set out in the engagement terms.

Contents Executive summary ...... 0 1 Introduction ...... 2 1.1 Purpose ...... 2 1.2 Structure of report ...... 2 1.3 Information sources ...... 2 1.4 About Concept ...... 2 2 Project description and reference scenarios ...... 3 2.1 Current position ...... 3 2.2 Proposed consents ...... 3 2.3 Base and counterfactual cases ...... 4 3 Current and projected demand for electricity ...... 6 3.1 Summary – demand for electricity...... 6 3.2 Electricity is vital to economic and social well-being ...... 6 3.3 Recent levels of demand ...... 7 3.4 Implications if secure supply cannot be maintained ...... 8 3.5 Electricity usage expected to increase as New Zealand strives to cut emissions ...... 9 3.6 Covid-19 and Tiwai smelter future cause heightened near-term uncertainty ...... 10 3.6.1 Covid-19 uncertainty ...... 10 3.6.2 Tiwai closure ...... 12 4 Electricity sector regulatory arrangements ...... 14 4.1 Summary - regulation ...... 14 4.2 Electricity sector structure ...... 14 4.3 Electricity spot market underpins generation sector competition ...... 15 4.4 Retail and wholesale contract markets support generator competition ...... 17 4.5 Developers of new generation face competition ...... 17 4.6 Regulation of greenhouse gas emissions ...... 17 4.6.1 New Zealand has net zero target for emissions by 2050 ...... 18 4.6.2 Emissions trading scheme and carbon price ...... 18 4.6.3 Carbon ‘leakage’ ...... 19 4.6.4 Future carbon prices ...... 19 5 New generation - potential sources of supply ...... 21 5.1 Summary – potential sources of new supply ...... 21 5.2 Existing supply base provides foundation for future development ...... 21 5.3 New supply options - availability and costs ...... 22 5.3.1 Hydro stations ...... 23

5.3.2 Geothermal generation ...... 24 5.3.3 Wind generation ...... 27 5.3.4 Solar photovoltaic generation ...... 31 5.3.5 Gas-fired generation ...... 33 5.3.6 Coal ...... 34 6 Economic benefits from granting of Wairakei consents ...... 36 6.1 Summary – economic benefits ...... 36 6.2 Basis for economic assessment ...... 36 6.3 Economic effects have been assessed under a range of future demand scenarios ...... 37 6.4 Element 1 - Economic benefits of continued operation of Te Mihi, Poihipi and WBP ...... 38 6.5 Element 2 – Enable GeoFuture project to proceed ...... 40 6.6 Element 3 – Allow Wairakei A&B station to operate until GeoFuture is online ...... 42 6.7 Contribution to regional economy ...... 45 6.7.1 Contribution to regional economy during construction phase ...... 46 6.7.2 Ongoing contribution to the regional economy ...... 47

Executive summary

Current position The Wairakei Geothermal Field currently supports power generation at the following facilities:

1. Te Mihi Station – this station was commissioned in 2014 and currently generates around 1,320 GWh/year. 2. Poihipi Station – this station commenced operation in 1997 and generates around 380 GWh/year. 3. Wairakei Binary Plant (WBP) – this plant was commissioned in 2005 and generates around 90 GWh/year. 4. Wairakei A&B Station – this facility commenced operation in 1958 and currently produces about 930 GWh/year.

These facilities operate under resource consents which govern (among other matters) the total geothermal fluid take from the Wairakei Field. The current consents allow a maximum annual average daily take of 245 kt/day. These consents expire in 2026.

Proposed consents Contact is seeking new consents which would enable:

1. The existing Te Mihi, Poihipi and Wairakei Binary Plant (WBP) facilities to continue to operate from 2026-20571. 2. The development and operation of the new GeoFuture power stations with an expected commissioning date between 2026 and 2031. The new plant may produce up to around 1,450 GWh/year of electricity, which would produce a net increase of up to 520 GWh/year compared to the existing Wairakei A&B station. 3. The continued operation of the Wairakei A&B Power Station until the GeoFuture plant comes into operation (or 2031 at the latest).

The overall Wairakei Field fluid take in the proposed consents is 250kt/day (around 2% higher than the existing consents).

Economic benefits of granting consent Granting the consents is expected to have significant economic benefits for New Zealand and the region.2 First, granting of consents would allow continued operation of the Te Mihi, Poihipi and Wairakei Binary Plant facilities. These facilities generate sufficient power to meet the energy needs of more than 250,000 households. We expect economic benefits to New Zealand of around $808 million in present value terms from continued operation of these plants. These benefits stem from avoided investment costs in replacement renewable plants that would otherwise be required.

Second, granting of consents would allow the GeoFuture power stations to be developed to replace the Wairakei A&B plant. The GeoFuture stations would generate sufficient power to meet the energy needs of around 207,000 households – a net increase of 70,000 households compared to the Wairakei A&B plant. This is possible with only a modest (around 2%) increase in geothermal fluid

1 This assumes the decision on the consent application is made by the end of 2022, and consents are granted for a term of 35 years from 2022. 2 We have developed quantitative estimates of national benefits from electricity sector effects. We have not quantified non-electricity sector effects although we discuss them in qualitative terms.

take because the GeoFuture plant would be much more efficient in energy conversion than the Wairakei A&B station. We expect that allowing the GeoFuture plant to proceed would produce economic benefits to New Zealand of up to $70 million in present value terms. These benefits stem from the cost savings attributable to this plant, compared to the likely next best power generation alternative (i.e. alternative new geothermal and/or wind generation).

Third, we expect that providing flexibility to allow a seamless transition from Wairakei A&B to GeoFuture between 2026 and 2031 will yield benefits of up to $16 million in present value terms. This benefit arises because it allows Contact to optimise the transition date from the Wairakei A&B to GeoFuture in this window. This flexibility is particularly beneficial at present due to heightened uncertainties over future power demand caused by Covid-19, potential Tiwai smelter closure, and the uptake trajectory for electric vehicles and industrial process electrification. In addition, we expect that providing some flexibility over the transition date will reduce greenhouse gas emissions by up to approximately 540,000 tonnes of carbon dioxide equivalent, all other factors being equal.

Finally, we expect that allowing the GeoFuture development to proceed will produce benefits to the Waikato Region of $520 million to $600 million in revenue terms during the construction phase. Likewise, we expect the ongoing operations of the Te Mihi, Poihipi, Wairakei Binary Plant and GeoFuture plants will yield Waikato Region benefits of nearly $50 million per year in revenue terms over their lifetimes.

1 Introduction

1.1 Purpose

Contact Energy Ltd (Contact) is seeking a package of consents to allow operation of geothermal power generation after 2026 when most existing Wairakei Field and power plant consents expire. In broad terms, the consents being sought will enable:

• The existing Te Mihi, Poihipi and Wairakei Binary Plant facilities to continue to operate from 2026-2057 • The development and operation of new GeoFuture power stations with a commissioning date between 2026 and 2031 • The continued operation of the Wairakei A&B power station until the earlier date of when the GeoFuture plant comes into operation or 2031.

This report examines the expected economic benefits if the consents are granted.

1.2 Structure of report

This report is structured as follows:

• Project description and reference scenarios • Economic importance of reliable electricity supply • Overview of electricity sector arrangements • New generation - potential sources of supply • Economic benefits from granting of consents.

1.3 Information sources

In preparing this report, Concept has relied upon a number of documents and related sources for information provided by Contact. These documents are:

• GeoFuture Project - Wairakei Geothermal Field AEE – Project Description version 5

• Supplementary information on the GeoFuture project provided in emails (referenced at the relevant points in this report).

Concept has also drawn on other information sources in preparing this report. In most cases, these sources are identified by footnotes or specific references. Where information is not referenced to external sources, it is generally based on estimates or data that have been developed directly by Concept.

1.4 About Concept

Concept Consulting Group Ltd (Concept) is a consultancy business which specialises in energy and utilities sector. Since establishment in 1999, Concept has provided advice to regulators, energy businesses, and governments in New Zealand, Australia, and Singapore. Further information about Concept can be found at www.concept.co.nz.

2 Project description and reference scenarios

2.1 Current position

The Wairakei Geothermal Field currently supports power generation at the following facilities:

1. Te Mihi Station – this is the newest station and was commissioned in 2014. It currently has two units with a combined annual output of around 1,320 GWh/year. 2. Poihipi Station – this station commenced operation in 1997 and has a single unit with annual output of around 380 GWh/year. 3. Wairakei Binary Plant (WBP) – this plant was commissioned in 2005 and has annual output of around 90 GWh/year. 4. Wairakei A&B Station – this facility commenced operation in 1958 and formerly had 10 steam turbines with a nominal rated output of 153 MW(e), or about 1,300 GWh/year.3 Operation at this facility has scaled back over time and the station currently produces about 930 GWh/year.

2.2 Proposed consents

Contact is seeking new consents which would enable:

1. The existing Te Mihi, Poihipi and WBP facilities to continue operation from 2026-20574. 2. The development and operation of the new GeoFuture project with an expected commissioning date between 2026 and 2031. The preferred configuration of the GeoFuture plant is yet to be determined. It could include additional steam turbines similar to those at Te Mihi, and/or binary plant. It could also include some new plant located at the ‘old’ Wairakei A&B site. The new plant may produce up to around 1,450 GWh/year of electricity, a net increase of up to 520 GWh/year compared to the existing Wairakei A&B station. 3. The continued operation of the Wairakei A&B power station until the earlier date of when the GeoFuture plant comes into operation or 2031.

The overall Wairakei Field fluid take in the proposed consents is 250kt/day (around 2% higher than the existing consents). While there is only a small increase in the consent limit, electricity generation capability would lift by almost 20%.

The increase in generation is possible because:

• GeoFuture’s facilities would utilise modern high efficiency turbines and generator sets, and these would achieve better energy conversion rates than the machines at the Wairakei A&B Station. • GeoFuture’s facilities will be located closer to the production wells, reducing energy losses in piping geothermal fluids from wellheads to the Wairakei A&B Station turbines.

3 https://nzgeothermal.org.nz/nz_geo_fields/wairakei-geothermal-system/ 4 This assumes the decision on the consent application is made by the end of 2022, and consents are granted for a term of 35 years.

• GeoFuture’s facilities would be at a higher elevation than the Wairakei A&B station, and therefore require less electrical energy for pumping of geothermal fluid to reinjection wells. • GeoFuture would use proportionally more fluid from Te Mihi, which has higher energy content.

The preferred date for transitioning power generation from Wairakei A&B to GeoFuture is between 2026 and 2031. The exact date is difficult to forecast, because it is affected by a number of factors outside of Contact’s control including the pace of recovery post the Covid-19 pandemic, the underlying rate of future electricity demand growth, and uncertainty around when, and if, the Tiwai smelter closes. To reflect these uncertainties, Contact has sought consents to enable operation of the Wairakei A&B Station until 2031 (noting that the aggregate steamfield consented geothermal mass take limit of 250 kt/day would also apply from the date consents were granted).

2.3 Base and counterfactual cases

Our assessment of economic effects has been compiled by considering two cases:

1. Base case – expected outcomes if the consents are granted. 2. Counterfactual case – expected outcomes if the consents are not granted.

The difference between these cases is the benefit (or cost) of granting the consent.

The base case scenario assumes that electricity generation operations at Te Mihi, Poihipi and WBP continue to 2057. This date is used as the final year for the assessment because Contact has applied for consents for a 35-year term,5 and we assume a consent determination will be made in late 2022.

Our assessment also assumes that the GeoFuture facilities commence operation (and Wairakei A&B station closes) in the period 2026 to 2031. The basis for this assumption is discussed in more detail in the body of this report.

The counterfactual case assumes that all electricity generation operations based on the Wairakei geothermal field cease after 2026. The electricity generation profiles associated with these cases are shown in Figure 1.

5 We also assume that Te Mihi and Poihipi specific power station consents would be renewed before they expire in 2043.

Figure 1: Generation profile of base and counterfactual cases

3,500

3,000

2,500

2,000

1,500

1,000

500 Generation from Wairakeifield (GWh) -

Base case (early GeoFuture) Base case (late GeoFuture) Counter factual

Source: Contact Energy data

3 Current and projected demand for electricity

3.1 Summary – demand for electricity

Electricity is vital to economic and social well-being because it underpins many aspects of modern life. Renewable electricity is expected to become even more important as New Zealand strives to reduce its greenhouse gas emissions.

While the medium-term outlook is for strong electricity demand growth, three key factors make it particularly hard to predict demand. First, the Covid-19 pandemic is causing widespread economic disruption and uncertainty which could take some years to abate. Second, while the owners of the Tiwai aluminium smelter have signed a new electricity agreement with Meridian Energy that allows the smelter to continue operation until December 2024, it is by no means certain that the smelter will close at the end of 2024. While closure seems likely at some point, the smelter could operate past December 2024. Third, the drive to reduce emissions is expected to lift demand, especially with increased uptake of electric vehicles and industrial process electrification – but views about the rate of future uptake vary wildly.

3.2 Electricity is vital to economic and social well-being

Electricity is a critical factor in the daily lives of most New Zealanders. Many of the social and economic benefits we enjoy stem directly from technologies relying on electricity. Often there are simply no alternatives.

Figure 2: Electricity share of total direct energy use

Source: Energy in New Zealand 2020, MBIE.

In New Zealand, electricity currently accounts for around 25% of annual end-use energy consumption6 and around 40% of all non-transport related energy consumption. The historical contribution of electricity to total energy use over time is shown in Figure 2.

6 Source: Energy in New Zealand 2020, Ministry of Business, Innovation and Employment (MBIE).

Figure 3 depicts the historical relationship between electricity demand and economic growth. As shown in the chart, historically electricity demand growth has been closely associated with economic growth, as many of the technologies underpinning economic development rely on electricity.

However, in the past fifteen years, economic growth has outpaced growth in electricity demand due to a greater emphasis on energy efficiency. While economic activity continued to steadily increase between 2005 and 2019, annual electricity demand growth averaged just 0.4% between 2005 and 2019 compared to 2.7% between 1979 and 2004. In 2020 both economic activity and electricity demand fell (by 2.9% and 2.5% respectively), driven by large declines in the June 2020 quarter.7

Figure 3: New Zealand real GDP and electricity demand

Source: Statistics New Zealand and MBIE Energy in New Zealand 2020

We expect the focus on energy efficiency to be sustained, but there are other key factors that are likely to impact on future electricity demand. These factors and the implications for future electricity demand are discussed in sections 3.5 and 3.6.

3.3 Recent levels of demand

The total demand for electricity in New Zealand is currently around 40,000 GWh per year8. To put that into perspective, a typical New Zealand household consumes less than one hundredth of one GWh of electricity annually.

Figure 4 shows that industry accounts for almost half of national electricity demand, while residential use accounts for approximately 30% and commercial use for approximately 25%.

7 Most of New Zealand’s first Covid-19 lockdown occurred in the June 2020 quarter. 8 Energy Overview 2020, MBIE.

Figure 4: Shares of electricity demand (calendar 2020)

Source: MBIE Energy in New Zealand 2020

3.4 Implications if secure supply cannot be maintained

Although often taken for granted, the critical dependence on electricity is highlighted when electricity supply disruptions occur or are threatened. These disruptions can occur due to insufficient electricity supply to meet demand or from network failures (such as failures in transmission or distribution). For example, when droughts reduced hydro generation levels in the mid-2000s, there was concern over the risk of supply disruptions. Though forced supply cuts were not required9, there was a high level of public and government concern about the prospect of possible cuts in 2008. In 1998, electricity supply to the Auckland central business district (CBD) failed for five weeks due to distribution cable failures and caused substantial economic losses for many Auckland CBD-based businesses. While this 1998 blackout is not an example of insufficient supply to meet demand, it illustrates that electricity blackouts can be costly.

It is difficult to precisely measure the value of a secure electricity supply system in quantitative terms. An indication can be provided by looking at the so-called ‘value of unserved energy’. This measure seeks to estimate the cost of short-term supply disruptions to consumers. Such estimates are frequently used by planners and regulators in assessing the net benefits of possible grid enhancements.

The value of unserved energy will depend on the type of consumer, the timing and duration of the loss of supply, and the degree to which the disruption could be anticipated. Table 1 sets out estimates for the value of unserved energy used by the New Zealand Commerce Commission for transmission investment appraisal purposes, and estimates derived from some international studies.

9 Enforced cuts were not required in 2008, 2012 or 2014. However, they were used in the 1970s.

Table 1: Estimates of cost of non-supply or lost load10

Estimated cost of unserved Country Average cost of Source Comment energy ($NZ) electricity ($NZ)

$20/kWh New Zealand 12.93c/kWh Electricity Value used for (Excl GST) Authority transmission planning purposes $5 to $60/kWh International N.A. International Task Force11 $15.8/kWh12 Netherlands 25.96 c/kWh – (Excl M. de Nooij et al. Estimate from Dutch taxes & VAT) study, which uses a CBS/Eurostat, May 07 different methodology from that used in other studies Sources: MBIE, Electricity Authority, CBS/Eurostat, studies cited in table

While the estimates vary significantly, in all cases the cost of unserved energy is significantly higher than the average cost of energy. This highlights the benefit of electricity to consumers, and in turn the importance on ensuring secure, cost effective sources of supply.

3.5 Electricity usage expected to increase as New Zealand strives to cut emissions

As noted in section 3.2, historically electricity demand has tracked economic activity, but more recently improvements in energy efficiency have led to lower rates of electricity demand growth. However, over the medium-term electricity demand growth is expected to lift as electricity plays an increasing role in decarbonising the energy used for land transport and industrial process heat (such as for dairy processing).

Figure 5 depicts future demand projections published by Transpower in March 2021.13 The chart on the left is Transpower’s projections from March 2020 which assumes (other than the Tiwai exit scenario) that the Tiwai aluminium smelter does not close in the foreseeable future. The chart on the right is Transpower’s projection from March 2021 which assumes that the Tiwai aluminium smelter exits in 2025. 14 Transpower’s central projection (Accelerated electrification) is that

10 It is important to emphasise that the cost estimates noted in the table are for unexpected power interruptions. An outage that can be anticipated (e.g. because it arose from a progressively worsening hydro shortage) will generally have lower costs than ‘surprise’ interruptions because consumers can more easily plan and take mitigating actions. Nonetheless, the cost can still be significant, and is likely to be materially higher than the ‘normal’ cost of producing electricity. 11 From "Methods to consider interruption costs in power system analysis"; International Task Force convened by R. Billington of Canada; Electra 2001, 197 56-67. 12 From “The value of supply security: The costs of power interruptions: Economic input for damage reduction and investment in networks”. Michiel de Nooij and others. Energy Economics Volume 29, Issue 2, (March 2007) p277-295. The study reported an average value of lost load for all Dutch consumers of €8.6/kWh. This has been converted to New Zealand dollars at the prevailing exchange rate. 13 Transpower, Whakamana i Te Mauri Hiko – Monitoring Report, March 2021. 14 The projections in the first chart were done before Rio Tinto’s announcement on 14 January 2021 that it had reached an electricity agreement with Meridian that would allow the New Zealand Aluminium Smelter (NZAS) to continue operating the Tiwai Point smelter until 31 December 2024. Transpower’s ‘Tiwai Exit’ scenario in the first chart assumed a staggered exit of the Tiwai smelter between 2021 and 2025, which is sooner than Rio Tinto has since announced. The projections in the second chart assume that the Tiwai smelter closes from 2025, although we note that it is not certain that the Tiwai smelter will close in 2025. The potential impact of the closure of the Tiwai aluminium smelter on electricity demand is discussed in section 3.6.2.

electricity demand will increase by about 50% by 2050 even if the Tiwai smelter closes. This implies a significant lift in growth rates compared to the last decade.

Transpower’s range of scenarios show that while higher demand is expected, there is substantial uncertainty around the timing and extent of growth in the coming three decades. While climate change concerns are likely to drive electrification (particularly in transport and process heat) and therefore electricity demand growth, concerns about climate change may also cause some high emitting industrial companies to cease or reduce operation (therefore reducing electricity demand growth).

Figure 5: Electricity demand projections

Source: Transpower.

3.6 Covid-19 and Tiwai smelter future cause heightened near-term uncertainty

While electrification of the economy is expected to increase electricity demand over coming decades, two factors cloud the immediate demand outlook —the impact of the Covid-19 pandemic and the future of the Tiwai aluminium smelter.

3.6.1 Covid-19 uncertainty

The Covid-19 pandemic has had a significant impact on New Zealand’s economy. After two quarters of negative growth, New Zealand officially moved into a recession in the June quarter of 2020. In the September quarter of 2020 there was a strong recovery, although there was a return to negative growth in the December quarter and annual GDP growth for calendar 2020 was negative.

Looking ahead, there is still considerable uncertainty as to the speed of New Zealand’s recovery from the recession and COVID-19.

The Treasury and Reserve Bank of New Zealand (RBNZ) indicate high levels of uncertainty in their most recent GDP forecasts and the Treasury included upside and downside GDP forecasts (in

addition to the main forecast) to cover a range of possible outcomes.15 However, the Treasury’s GDP forecasts were developed prior to Stats NZ releasing both the September and December 2020 GDP data and all three of the Treasury’s forecasts underestimated the recovery in the September 2020 quarter.16

Figure 6: GDP growth forecasts

Sources: Reserve Bank of New Zealand, Treasury.

The International Monetary Fund (IMF) predicts a similar trend for the world economy. The IMF estimates the world economy contracted by 3.3% in calendar 2020, but projects it will grow by 6.0% in 2021 and 4.4% in 2022.17 However, the IMF notes that there is high uncertainty around these forecasts and future developments will depend on the path of the health crisis.

While vaccines are now being deployed in many countries, it will likely take many months for a large proportion of the global population to be vaccinated. New Zealand is currently in the early stages of its vaccine roll out and there continues to be the risk of re-emergence of community transmission of Covid-19. Uncertainty around how long and to what extent border controls will remain in place and the impact of Covid-19 on global supply chains also contributes additional economic uncertainty. This uncertainty is likely to feed through into electricity demand growth, although only time will tell how much of an impact this will have.

15 At the time of writing the RBNZ’s latest GDP forecast was in its February 2021 Monetary Policy Statement and the Treasury’s latest GDP forecast was in its Half Year Economic and Fiscal Update 2020, released in December 2020. 16 The Reserve Bank of New Zealand’s latest GDP forecast was released in February 2021 and incorporated data from Stats NZ’s GDP data release for the September 2020 quarter (and therefore reflects the strong rebound in GDP that happened in that quarter). 17 IMF, World Economic Outlook Update, April 2021.

3.6.2 Tiwai closure

In July 2020 the owners of the Tiwai aluminium smelter announced their intention to close the smelter from August 2021. However, in January 2021 it was announced that Meridian and the owners of the Tiwai aluminium smelter had signed a new agreement that would keep the smelter operating until the end of 2024.18

The smelter makes up about 13% of New Zealand’s electricity demand. If the smelter were to close it could have significant implications for the supply side of the industry. In particular, if there were no new sources of electricity demand in the South Island, it would increase the volume of energy which can typically be exported from the South Island to the North Island. This in turn would likely trigger the retirement of some baseload thermal generation in the North Island. However, even after accounting for reduced thermal generation, we expect a net increase in generation supply to occur even if Tiwai closes at the end of 2024. That in turn would defer the time when additional new generation is required in New Zealand.

However, we do not regard closure of the Tiwai smelter at the end of 2024 as certain. The smelter does have some competitive advantages. It produces a high grade of metal which commands a price premium. Aluminium from the smelter also has relatively low emissions by world standards because it uses renewable hydro electricity. This factor may become more important as the international effort to reduce emissions intensifies.

In addition, we are aware that Meridian and Contact are actively pursuing initiatives to stimulate new sources of electricity demand, such as accelerating the uptake of electric boilers for industrial process heat. Demand growth from these initiatives has the potential to partially offset the effect of a Tiwai smelter closure.

In light of these factors, our central scenario assumes a Tiwai closure at the end of 2024. However, we also consider a scenario in which the Tiwai smelter continues to operate beyond 2024.

3.7 Uncertainty in near- and medium-term demand outlook is greater than normal

The combination of all the factors noted in sections 3.5 and 3.6 means that the near- and medium- term demand outlook is more uncertain than normal. There is potential for these factors to reduce or increase electricity demand growth. Figure 7 shows in a stylised form the impact that each of these factors could have on electricity demand.

18 https://www.riotinto.com/news/releases/2021/NZAS-reaches-deal-with-Meridian-to-extend-operations-to- 2024.

Figure 7: Uncertainty in demand outlook

4 Electricity sector regulatory arrangements

4.1 Summary - regulation

Regulation of the electricity generation sector has been designed to encourage competition.19 Generators offer their supply into an auction-based spot market, and those with the lowest offer prices are selected to satisfy demand in each half hour. This system creates strong incentives on generation owners to minimise costs.

Likewise, when considering whether to develop new power projects, developers have strong incentives to minimise lifecycle (whole of life) costs and properly account for project risks. The key reason being that any cost over-runs will be borne by the owner of the new power station, not electricity consumers.

The regulatory regime is also designed to account for cost of any greenhouse gas emissions associated with power generation. Owners of stations that emit greenhouse gases are required to surrender emission units to cover their emissions.20 These units have risen steeply in price, and further increases (alongside other climate policies) are expected to be required to help achieve the net zero emission target by 2050. This ‘carbon price’ mechanism creates strong incentives to choose generation forms which have low or zero emissions, and to retire forms with higher emissions (such as baseload gas and coal-fired plant).

4.2 Electricity sector structure

The electricity supply chain can be divided into four main segments as shown in Figure 8.

19 This section focuses on regulation which is specific to the power generation sector (or has a specific effect on it such as greenhouse gas emission policy). Other regulations (e.g. covering environmental and planning issues, workplace safety) also affect the sector, but are more generic in nature. 20 In addition, the Resource Management Act amendment in 2020 allows local authorities to consider greenhouse gas emissions in their plan-making and consenting decisions once national direction on climate change mitigation is promulgated under the Zero Carbon Act. The default date for this amendment to come into effect is 31 December 2021.

Figure 8: Overview of electricity industry structure.

Source: Ministry of Business, Innovation and Employment

The transmission and distribution segments are not subject to competition because it is generally uneconomic to replicate networks. These businesses are regulated under Part 4 of the Commerce Act. This provides for price control of their services, except where there is strong alignment of supplier and consumer interest via community ownership of a network.

Competition is possible in the generation and retailing segments and regulation by the Electricity Authority of these sectors has been focussed on facilitating competition.

4.3 Electricity spot market underpins generation sector competition

The central platform which underpins generation sector competition is the electricity spot market. This is an auction-based system in which all generators connected to the grid are required to participate. In essence, an auction is conducted in the lead up to each half hour to determine which generators will supply electricity to meet demand in that 30-minute trading period. Generators are required to submit their supply offers ahead of time, and the cheapest combination of offers is selected to meet demand.

Supply and demand conditions can vary substantially within a day and across the year. For example, demand during a winter evening can be three times higher than in the low point of a summer day. As a result, the cost of generating power in peak demand periods is typically much higher, as shown by Figure 9. It is important to signal these differences, to provide greater reward for suppliers who can reliably produce power during periods of peak demand and vice versa.

Figure 9: Spot prices – winter day versus summer day

200 180 160 140 120 100

$/MWh 80 60 Winter 40 Summer 20 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Trading period

Source: Electricity Authority data

The auction process takes account of physical transmission losses (i.e. shrinkage caused by heating of wires and transformers) which occur when electricity is transmitted over long distances. This ensures that if two or more generators offer electricity into the market at the same price, the generator closest to where supply is needed most by consumers would be selected first. This is important for economic efficiency reasons so as to minimise electricity transmission losses. Generally, the further a generator is from where the supply is needed (i.e. the location of demand), the greater the electricity lost in transmission. Incremental losses can be high when extra supply travels along highly loaded lines at times of peak demand.

The spot market also plays an important role in sending price signals to market participants where elements of the transmission system reach their physical operating limits. Prices will rise downstream of a transmission constraint to indicate to generators located there that they should increase production or to retailers/ purchasers that they should reduce consumption to relieve the effects of the constraint and to avert loss of supply to customers in the region.

By reflecting the cost of transmitting electricity from generators to where customers are located nodal prices also send important long-term signals. Generators who are located a long way from large concentrations of customers, such as the major cities, generally receive lower prices for their electricity than generators who are nearby.

In the long run, these price signals encourage investors to build new power stations close to where the electricity is required or, conversely, to build factories and the like, which use electricity, closer to where the generation is located. Importantly, nodal prices also signal the relative merits of investing in transmission or local generation alternatives. Likewise, the spot market creates a premium signal for ‘firm’ sources of supply, and this premium changes over time to reflect the relative value of firm and non-firm capacity (as discussed further in section 5.3.3).

4.4 Retail and wholesale contract markets support generator competition

As noted above, the electricity spot market establishes a price for every half hour, at each pricing node on the national grid. Most electricity customers do not want to deal with the complexity of half hour price variations. Nor do most generators wish to be reliant on the spot market with prices which are uncertain and constantly varying.

To reflect these factors, the great majority of electricity volume is sold on contracts of various types which smooth out short term price volatility. These contracts can be in the form of a retail supply contract where the generator-retailer organises the transmission and distribution services (most customers chose this option), or a bilateral ‘hedge’ contract which only smooth spot price volatility, with the customer retaining responsibility for organising transmission and distribution services. This contract form is used by some larger industrial customers and by independent retailers.

While such contracts provide generators and consumers with insulation from short-term variation in spot prices, this only lasts for the contract duration (typically 1-3 years). More generally, when contracts are being negotiated, the price will be affected by the parties’ expectations about future spot prices. This is because buyers and sellers each have multiple counterparties they can deal with, and each also have a choice about whether to contract or not for their future requirements.

In summary, irrespective of whether generators sell their output into the spot, contract and/or retail markets, they will face competition. This creates strong incentives to operate existing power plants in an efficient manner.

4.5 Developers of new generation face competition

The spot market auction mechanism and competition in the retail and contract markets create strong competitive pressure on developers of new generation. This is because prospective developers know that once a plant is built and operating, it will be totally reliant on sales into the spot, contract and retail markets for revenue. Developers also know that if they build a plant that is later undercut by a competitor’s cheaper new project, they will bear the consequences via lower revenues and lower returns on investment.

Developers will keep a close eye for signs that new generation may be required. Often, this will be signalled by a rise in contract prices for future years (NZX Electricity Futures), indicating that increased operation of higher cost ‘swing’ supply is expected (i.e. plant which would normally be used to cover temporary tight situations such as hydro droughts is increasingly likely to be needed to meet demand growth). If future contract prices are sufficiently high, that will trigger new investment by one or more developers. That in turn will tend to soften contract prices until a new stable outlook is re-established.

Overall, the arrangements in the electricity market create strong incentives on developers to only commit to a new development if they are reasonably confident the project is required (i.e. there is sufficient sustained demand) and their project is cheaper than all the alternatives. As we discuss in section 6.5, this dynamic has important implications for the current consent application.

4.6 Regulation of greenhouse gas emissions

While this chapter focusses largely on electricity sector regulation, it is also important to describe regulation relating to greenhouse gas emissions. This topic is increasingly important for generation

investment and retirement decisions. It also has important implications for electricity demand – either spurring demand (as discussed in section 3.5 via electric vehicles etc) or reducing demand (if some industries such as steel production were to shut down and move offshore).

4.6.1 New Zealand has net zero target for emissions by 2050

In November 2019 New Zealand’s Parliament passed the Climate Change Response (Zero Carbon) Amendment Act 2019. In summary, this legislation:

• Set a new domestic greenhouse gas emission reduction target for New Zealand to: o reduce net emissions of all greenhouse gases (except biogenic methane) to zero by 2050. o reduce emissions of biogenic methane to 24–47 per cent below 2017 levels by 2050, including to 10 per cent below 2017 levels by 2030. • Established emissions budgets to act as stepping stones toward the 2050 target. • Required the Government to develop and implement policies for climate change adaptation and mitigation. • Established a new, independent Climate Change Commission to provide expert advice and monitoring to help keep successive governments on track to meeting the legislated long- term goals. The Government has indicated that the net zero target can be met through a combination of measures to reduce gross emissions and initiatives to sequester carbon such as increased planting of forests. The Climate Change Commission noted in its advice that current government policies do not put New Zealand on track to meet the 2050 targets. They considered that priority areas for action included increasing the number of electric vehicles on our roads, increasing our total renewable energy, improving farm practices, and planting more native trees to provide a long-term carbon sink.21

4.6.2 Emissions trading scheme and carbon price

A key instrument for achieving the net emission target is the Emissions Trading Scheme (ETS). In essence, this scheme requires greenhouse gas emitters to purchase emissions units issued by the New Zealand government to offset their domestic greenhouse gas emissions.22 The volume of units available for purchase is set by the government. Emission units can also be generated by carbon removal activities, such as the permanent planting of forests to act as carbon sinks.

The market clearing price for emission units in New Zealand is discovered by trading among the parties, such as those who need to buy units to acquit their emission liabilities and/or who generate units. The price of an emission unit has increased in recent years and was just under NZ$40/tCO2 in early-2021.

21 Climate Change Commission, Ināia tonu nei: a low emissions future for Aotearoa, 31 May 2021, p12.. 22 Strictly speaking, the obligation to purchase and surrender units may fall on a party other than the final emitter (e.g. gas producers rather than consumers). Nonetheless, in such cases, final emitters are likely to bear the cost of acquiring the emission units when they purchase gas from producers.

Figure 10 - New Zealand carbon price

Source: https://github.com/theecanmole/nzu

4.6.3 Carbon ‘leakage’

Under the ETS, some industrial activities which are emissions-intensive and trade-exposed (EITE) qualify for the Industrial Allocation mechanism. This reduces the effective carbon price for qualifying parties and is intended to reduce carbon ‘leakage’. That is, a situation where New Zealand industrial production is reduced due to the domestic carbon price, but is replaced elsewhere by more carbon- intensive production in a country that has not imposed a carbon charge. For example, the New Zealand steel mill at Glenbrook is classified as an EITE consumer.

Activities classed as EITE currently qualify for around 80% free allocation of units.23 This allocation reduces the effective carbon price to these industries to around 20% of the market price. The future terms of the EITE mechanism are subject to ongoing review.

4.6.4 Future carbon prices

To help meet the legislated net emissions target, most forecasters expect carbon prices to rise significantly in future years. However, the precise trajectory is unclear. In part this is due to physical uncertainties. For example, the costs to achieve emission reductions are uncertain, especially as technological advances may significantly affect abatement costs over time. There is also considerable uncertainty about how the policy goals in new legislation will be expressed in detailed policies.

One issue will be the balance between lowering gross or net emissions. There appears to be considerable potential for ‘carbon farming’ in New Zealand, with conversion of land from pastoral farming to forestry for carbon sinks. Higher levels of carbon farming would allow higher gross emissions (at least for a time), all other things being equal. However, the prospect of widespread and rapid land conversion to forestry is raising concern among some sector groups and the Climate

23 The free allocation was 90% in 2012 and declines at 1 percentage point per annum. See Climate Change Response Act 2002, clause 82.

Change Commission has noted that relying on the planting of exotic forests to reduce net emissions was not sustainable.24

Various agencies have sought to model or estimate the carbon prices necessary to achieve New Zealand’s emission reduction targets, as well as the prices required to achieve international targets. Key recent estimates are summarised in Table 2. Each agency’s modelling has its own unique focus and uses a different approach to form its carbon price estimates, resulting in a wide range of projected prices.

Table 2: Future carbon prices for emission reduction targets

25 International / Carbon price NZ$NZD /tCO2e Target Agency domestic price 2020 2025 2030 2040 2050 Carbon Pricing Leadership 55 - Paris agreement 70 - 135 Coalition26 110 International International Energy Paris agreement 86 192 Agency27 Business NZ Energy Council 60 - 115 Paris agreement Westpac 111 - 147 Concept and MOTU for the 157 - 250 Domestic Productivity Commission Net-zero by 2050 NZIER 227 - 2,092 Climate Change 140 250 Commission28 Source: Concept analysis and estimates

To reduce uncertainty about the future level and trajectory of carbon prices, the Government has recently announced that a price floor and a price capping mechanism will apply for the 2020-2025 period (the first five-year measurement period as New Zealand moves toward 2050).

For 2020 the price floor has been set at 25 $/tCO2e and the cap at 50 $/tCO2e. Both values will increase at 2% per year to reflect expected inflation.29 Looking further ahead, we expect carbon prices to continue to increase, otherwise it is very hard to see how New Zealand will achieve the legislated emissions targets. This is the case even with new measures already announced by the Government to reduce emissions (such as the recently announced Clean Car Discount) and the potential for further climate policies to be enacted.

24 However, the Climate Change Commission has also noted that new permanent native forests can provide an enduring carbon sink. Climate Change Commission, Ināia tonu nei: a low emissions future for Aotearoa, 31 May 2021, p91 and p318. 25 These assume a long-term exchange rate of 0.73 US$/NZ$. 26 See www.carbonpricingleadership.org/report-of-the-highlevel-commission-on-carbon-prices/. 27 Sustainable Development Scenario from its World Energy Outlook 28 Climate Change Commission, Ināia tonu nei: a low emissions future for Aotearoa, 31 May 2021, p101. The figures shown are emission values rather than carbon prices, but the two concepts are closely related. 29 See www.beehive.govt.nz/sites/default/files/2020-06/NZETS%20Q%26A.pdf.

5 New generation - potential sources of supply

5.1 Summary – potential sources of new supply

Geothermal and wind power projects are likely to account for most growth in supply over the next 10-15 years because of their low relative cost. Geothermal stations also have the advantage of providing firm capacity which does not vary with weather conditions, unlike wind, solar (and to a lesser extent) hydro power. Geothermal stations do produce some greenhouse gases emissions,30 but these are generally much lower than fossil fuel stations. For example, the emission rate from the Te Mihi Power Station is only 10% that of an equivalent baseload gas-fired station, and 3% that of a coal-fired plant.

5.2 Existing supply base provides foundation for future development

The existing generation base provides the foundation for future development. Figure 11 shows how New Zealand’s electricity supply mix has changed over time.

Figure 11: New Zealand electricity supply – by generation type (stacked)

Source: Analysis of MBIE data. Excludes electricity from stations not connected directly to the national grid.

30 This is because some of the naturally occurring greenhouse gases dissolved in the geothermal fluid are released to the atmosphere in the power generation process.

Figure 12: New Zealand electricity supply – by generation type

Source: Analysis of MBIE data. Excludes electricity from stations not connected directly to the national grid.

Key points to note are:

• Hydro generation rose between 1974 and the mid-1990s, but since then has fluctuated around an average level of approximately 24,000 GWh/year. This reflects a stabilisation in the level of hydro capacity in the system, with fluctuations now being largely driven by variations in rainfall over time. • The share of supply from geothermal rose strongly in the ten years to 2015 – but has been relatively stable since then. • Similarly, the level of wind generation rose substantially in the decade to 2015 and has been relatively stable in recent years. • Between 1980 and 2008 there was a progressive upward trend in thermal generation. However, thermal generation has fallen sharply since then – and was around 50% lower in 2018 when compared to 2008. • Within these longer-term trends, there has been significant year-to-year fluctuation – particularly between hydro and thermal generation levels which have moved in opposite - directions. This reflects the important role that thermal generation has played in acting as a balancer to offset lower hydro generation in dry periods and vice versa.

5.3 New supply options - availability and costs

This section surveys the range of possible sources of new generation, and comments on their relative costs.31

31 Energy efficiency is also expected to increase and is often considered to be a hidden source of supply. However, this report does not discuss energy efficiency because it is focussing on how to meet increases in grid demand.

5.3.1 Hydro stations

Although hydro stations provide the backbone for New Zealand’s electricity supply, most were developed in the mid-20th century. The last large-scale32 hydro development was the Clyde dam, with the bulk of the construction occurring during the 1980s. That project encountered strong community opposition at the local and national levels. The project also suffered severe cost overruns, in part because additional works were required to address the risk of landslides which could have been triggered by the filling of Lake Dunstan. This also delayed commissioning of the project, with full generation only being achieved from September 1993.

In the early-2000s Meridian pursued a large canal-based hydro development in the Waitaki basin (Project Aqua). This project was abandoned in 2004 due to uncertainties around water access and geotechnical issues.

Meridian switched focus to a much smaller development on the same river. The North Bank proposal was expected to generate about 1,400 GWh a year,33 and had an estimated cost of between $900 million and $1.2 billion. This project also encountered strong opposition. Meridian put the project on hold in 2013 and ultimately abandoned the project, citing rising cost estimates as the principal reason.

Also in the early 2010s Meridian abandoned their Mokihinui hydro project on the West Coast and Contact shelved its plans to develop additional dams on the lower Clutha.

Since then, developer attention has focussed on smaller scale hydro projects such as the Amethyst station (8 MW) commissioned in 2013. A range of other similar projects have been considered such as Arnold (46 MW) and Hawea gates (17 MW)34 and may yet proceed if development economics become attractive.

Looking ahead, it appears unlikely that any new large-scale hydro generation developments will proceed in the foreseeable future. This may change if concern about greenhouse gas emissions causes a re-evaluation of the role of hydro generation. In the meantime, hydro development is likely to focus on enhancements to existing schemes and/or smaller scale projects – neither of which is likely to make a substantial contribution to meeting growth in electricity demand. There is also potential for output from some existing hydro generation to erode over time, if more stringent conditions are imposed as existing schemes are progressively reconsented.

Recently, a large pumped-storage development in the Onslow Basin has received significant media attention. This was first proposed in 2005 but was not developed further due to the high capital cost. The project has received renewed attention as a possible enabler of the government’s “100% renewable by 2030” target35, and the government has committed to a feasibility study. The exact specifications for the project are yet to be determined, but one option is 1,200 MW of generation capacity with storage of 5,000 GWh.

32 Larger than 50 MW. 33 A similar quantity to the proposed maximum output of GeoFuture. 34 We understand construction consents for this project have expired. However, Contact could presumably reapply if the project appeared viable in the future. 35 During the 2020 election campaign, the Labour Party committed to bringing forward the target of 100% renewable electricity generation by five years to 2030 with a review in 2025. Source: 100% renewable electricity generation by 2030 - NZ Labour Party

An important point to note with pumped storage projects is that they do not add to total energy supply in net terms. This is because such schemes require power to run pumps which fill the storage lake. Typically, the facility will pump water uphill into storage during periods of abundant electricity supply, and then use the stored water to run as a generator in periods of tighter supply. In net terms, the facility will consume power because of electrical losses and friction in the pumping system. However, the storage facility allows generation to occur at times when it is most useful, and this is valuable for the overall power system, particularly to offset the effects of varying demand and intermittent power sources such as wind generation.

5.3.2 Geothermal generation

New Zealand is an international leader in the development of geothermal power generation. New Zealand currently has over 1,000 MW of installed geothermal capacity, most of which is located in the Taupō Volcanic Zone as shown in Figure 13.

Figure 13: Location of geothermal resource

Source: Analysis of data from NZ Geothermal Association

Early development centred on Wairakei and Kawerau in the 1950s and 1960s. More recently there has been a surge of development after natural gas prices rose in the mid-2000s.

Geothermal power has been attractive because of its cost-effectiveness, its ability to provide firm (i.e. ‘always on’) energy, and its relative proximity to the main centres of electricity demand in the upper North Island.

Geothermal development is capital intensive, with a very large proportion of total (lifecycle) cost being incurred upfront for drilling of production and injection wells, pipelines, generation plant and equipment. Moreover, geothermal investments are typically highly tailored to reflect the specific conditions of each resource, unlike wind and solar generation where projects are more modular and standardised in nature.36 Developers will often seek to stage the development of power generation investment, so that it can scale up as knowledge about the geothermal resource accumulates. These factors mean that geothermal development processes tend to be more complex and have longer lead-times than wind generation projects.

Geothermal generation emits some greenhouse gases because the hot fluid produced from a geothermal reservoir contains naturally occurring carbon dioxide and methane. After geothermal fluids are used for power generation, they are reinjected into the ground but much of the greenhouse gases are discharged to the atmosphere.

The level of greenhouse gas emissions varies across different geothermal stations and fields. Having said that, emissions are typically much lower than for thermal power stations. For example, the emission intensity at Te Mihi is 10% that of an equivalent baseload gas-fired station and 3% that of a coal-fired plant as shown in Figure 14.37

Figure 14: Greenhouse gas emissions for geothermal plant compared to gas and coal plant

Source: Analysis of data from NZ Geothermal Association

Looking ahead, there is significant potential to develop more geothermal generation. A recent report for the Ministry of Business, Innovation and Employment estimated that there was a technical potential to develop a further 1,035 MW of geothermal capacity by 2060.38

36 This is particularly the case for steamfield infrastructure and power stations that use steam turbines. Having said that, binary plants involve a higher degree of standardisation. 37 We note, however, that some geothermal fields (namely Ngawha and Ohaaki) have high emissions from their geothermal fluid. 38 Lawless Geo-Consulting and others, Future Geothermal Generation Stack, March 2020, p.1.

Our analysis of the cost data in the report indicates these projects would be very competitive against the other major source of new supply – being wind generation. New carbon capture technologies may also reduce emissions from geothermal and make it more competitive in the future.

5.3.3 Wind generation

New Zealand is recognised as having a world class wind resource. There is currently over 680 MW of installed wind generation capacity, with most windfarms in the lower North Island.

Wind turbine production costs have fallen substantially over the last 20 years as the global manufacturing base expanded. This factor, coupled with increased supplier competition (especially from Chinese manufacturers) has led to steep reductions in turbine prices in the last decade.

This trend has a major positive impact on wind generation economics because turbines typically account for over half of total project costs, with the balance being made up of other plant (e.g. transformers), civil works (e.g. roads), and costs for electrical connections to the grid.

The trend in wind turbine prices is illustrated by Figure 15 which is reproduced from a recent report by the International Renewable Energy Association.

Figure 15: Trends in wind turbine prices 1997-2019

Source: International Renewable Energy Agency, 2019

Alongside falling costs, there has been a trend toward turbines which achieve higher average generation levels for a given wind speed (i.e. capacity factors).39 Together these factors have driven down the levelised cost of energy40 from wind generation. For example, wind generation costs for better sites in New Zealand were estimated to be around 8-11 c/kWh in the mid-2000s.41. This compares with current estimated costs of 6-6.5 c/kWh for the recent developments at Waipipi and Turitea.42

Wind generation does not produce greenhouse gas emissions from its operations. This is a further benefit in an environment of rising carbon costs. Another factor that has assisted wind generation development is the relatively short build time for projects once consents are obtained and other preparatory design work is complete. For example, the decision to build the Waipipi windfarm development occurred in September 2019 and it is expected to be fully operational within 18 months of project commencement.

A recent report for the Ministry of Business, Innovation and Employment estimated that there is potential to develop a further 8,000 MW (about 28,000 GWh/yr with typical capacity factors) of wind generation in New Zealand. Most of this additional capacity is from onshore wind farm projects, but the report also identified offshore wind development as being potentially attractive over the longer term.43

The main drawback with wind generation is that it can be highly variable from hour to hour. For an electricity system with a relatively low penetration of wind generation this is not an issue because there are ample other power sources to compensate for reduced wind generation in calm periods. However, as the proportion of wind power on a system increases, the usefulness of each additional unit of wind generation tends to decline. This arises because the wind generation from different windfarms tends to be correlated. Put another way, if it is windy at one windfarm, it tends to be windy at other farms (especially those nearby), and vice versa.44 Accordingly, with high levels of wind penetration, the system as a whole tends to be abundantly supplied when it is windy (causing low spot prices) but experiences tighter supply when it is calm (causing high spot prices).

For this reason, wind generation tends to earn a generation-weighted average price (GWAP) which is lower than the simple time-weighted average price (TWAP) for the system as a whole. In effect, the level of discount provides an indication of the cost of ‘firming’ the intermittent output from wind generation. As the share of production from wind generation increases, that cost tends to rise.

This is illustrated by Figure 16 which is reproduced from a report for the Interim Climate Change Commission. It shows GWAP/TWAP ratios for different electricity systems with varying levels of wind

39 This is because the swept area of a turbine has typically risen faster than its rated capacity – resulting in higher utilisation of capacity. 40 A measure of the average cost of electricity generation over the lifetime of a development, expressed as total costs divided by total electrical output. 41 Meridian Energy, Options Choices Decisions, 2006, with costs adjusted into 2020 dollars to account for general price inflation. 42 Based on analysis of information published by the developers (Tilt Renewables and Mercury Energy respectively). Estimates are for the levelized cost of energy production and need to be adjusted for ‘firming costs’ to compare with a baseload electricity price. 43 Roaring40s Wind Power, Wind generation stack update, March 2020, p.1. 44 This is particularly true for windfarms located in the same region (such as the lower North Island). This can also increase the attractiveness of wind farm development in regions where wind patterns are less highly correlated with existing wind generation.

penetration. Each year is shown by a separate dot, and various modelled scenarios are shown by white dots with a coloured outline. Systems with relatively low penetration (e.g. New Zealand and New South Wales) have recorded GWAP/TWAP ratios of around 90-95%. Systems with higher wind penetration (e.g. Germany, Spain, South Australia) have typically recorded lower GWAP/TWAP ratios. Indeed, the ratio in South Australia has been below 75% in a year reflecting the relatively limited range of flexible supply resources (such as hydro generation) in that region.

As a broad guide, the report for the ICCC estimated that New Zealand’s GWAP/TWAP ratio would decline by around 3% for each 5% increase in wind generation penetration. This is shown as the sloped grey line on the chart. The report also noted the slope would be influenced by the cost of backup supply and the extent of constraints on the system. Reductions in the cost of batteries and increased demand side flexibility could reduce the slope. Conversely, factors such as any restrictions on gas-fired backup peaking capacity could increase the slope.

Figure 16: Wind GWAP/TWAP ratio compared to wind generation share of total supply45

Source: Report for Interim Climate Change Committee (2019)

At present, the GWAP/TWAP ratio for wind generation in New Zealand is around 0.9. This means a windfarm with a levelised generation cost of (say) 6 c/kWh requires an average wholesale electricity price of 6.67 c/kWh to breakeven.46 Looking ahead, new windfarm investments will likely take account of the expected GWAP/TWAP ratio over their future economic life – noting these are likely to be lower than 0.9 and progressively decline over time.

Overall, it appears likely that wind generation will play an increasing role in meeting future demand growth. However, as wind penetration increases, the cost of firming is likely to rise. This factor is likely to counter some of the cost reduction that would otherwise be expected from gradually improving wind turbine technology.

45 Interim Climate Change Committee, Estimated System Incremental and Marginal Costs in 2035 – Final Report 2019, April 2019. 46 This is because 6 / 0.9 = 6.67.

5.3.4 Solar photovoltaic generation

New Zealand currently has around 150 MW of installed solar photovoltaic (PV) generation – most of which is rooftop solar panels.47 While uptake is growing, solar PV generation is still small compared to total power demand. A key reason for the limited uptake to date has been economics – with the effective cost of power being well above other generation sources.48 However, when solar PV is installed at a consumer’s premises, it can be attractive for the consumer because they may be able to reduce their energy and network charges.

Having said that, the incentive for uptake of this distributed generation can be strongly influenced by the structure of electricity tariffs at the consumer level, especially if the costs of providing distribution and network services (which are largely fixed49) are recovered via variable per kWh charges. Where this applies, it can provide an artificial incentive to install solar PV at a consumer’s premises, since a consumer can reduce its energy and network charges (with the latter potentially being reallocated to other non-solar consumers). This dynamic has been a source of debate in some other countries leading to redesign of electricity tariffs to better reflect the genuine value of solar generation to distribution networks, and it remains to be seen how it will play out in New Zealand.

47 Source: http://www.emi.ea.govt.nz/Retail/Reports/GUEHMT?_rsdr=ALL&Show=Capacity&_si=v|3&FuelType=solar&Fu elType=solar, downloaded 2 July 2020. 48 The cost of power from solar panels is currently well above 10 c/kWh. For example, see Concept Consulting Group Ltd, Electric cars, solar panels, and batteries in New Zealand Vol 2: The benefits and costs to consumers and society, June 2016, Figure 9. 49 This is because network costs are typically driven by peak demand on the coldest evening of the year.

Figure 17: Solar PV module prices

Source: International Renewable Energy Agency, 2019

Putting this issue aside, there have certainly been dramatic falls in the cost of solar PV modules. Figure 17 shows the reduction in costs over the last ten years. Given the relative immaturity of the technology, further cost reductions are likely to occur.

In some ‘high sunshine’ jurisdictions such as Australia, grid-connected solar is starting to become economic with other generation sources. While sunshine levels are lower in New Zealand, the same downward trend in costs is expected to make utility-scale solar competitive at some point. For example, the central estimate in the report for the ICCC projected levelized costs to fall to 8 c/kWh by 2035. At that level, it is still expected to be more expensive than wind or geothermal but it is approaching the range where it would start to become competitive, especially as the better wind and geothermal sites become utilised.

When calculating the economics of solar power, different levels of sunshine (and therefore generation) are accounted for by using a capacity factor approach. In addition to correcting for the quantity of generation, it may also be necessary to consider the “GWAP/TWAP ratio” discussed above when considering the economics of wind power. Currently the GWAP/TWAP ratio for solar in Auckland is slightly above 1, reflecting that electricity prices are normally higher during the day when the sun is shining. However, in jurisdictions with high penetration of solar power the GWAP/TWAP ratio can be significantly lower, and even negative at times. While we do not foresee this happening in New Zealand in the near future, such a situation may occur if the uptake of solar generation is higher than expected.

5.3.5 Gas-fired generation

A swathe of new natural gas-fired stations were built from the mid-1990s, underpinned by relatively low-cost gas in New Zealand. However, since 2010, developer attention has switched away from gas- fired baseload stations that run most of the time to peaking plant that only operate during times of tight supply and/or high prices. This reflects a range of factors including:

• rising gas costs • declining costs for some renewable sources • increasing need for generation sources which can ‘flex’ upward when intermittent renewable generation is reduced (such as in dry periods) • rising carbon costs which lift the operating costs for thermal stations, especially for baseload operation.

The last factor has been particularly important. For many years carbon prices have been $10-

15/tonne CO2e, but they have moved upward in recent time and were nearly $40/tonne CO2e in early-2021.

As shown in Figure 18, the cost of baseload power from gas-fired stations is quite sensitive to carbon prices. For example, a carbon price increase of $25/tonne CO2e would add around 1 c/kWh to the cost of generating from a baseload gas-fired station. A change of that magnitude could easily alter the viability of a future project.

The combination of carbon price sensitivity and uncertainty over future carbon prices means it is very unlikely that developers will seek to build new baseload gas-fired stations. Indeed, the more likely outcome is that there is further reduction in baseload operation of existing gas-fired stations over time.

Figure 18: Effect of carbon prices on cost of baseload power from gas-fired generation

2 Total cost Total of (c/kWh) generation

Cost of gas at power station

Carbon price $/t CO2e $25 $50 $75 $100 GeoFuture AEE.xls Source: Concept estimates

5.3.6 Coal

New Zealand’s only existing coal-fired generation50 is from the Huntly station owned by Genesis Energy.51 Generation from coal has been particularly important at times when gas supply was short, such as the early and mid-2000s, and more recently during extended periods of interruption to gas supply. Coal is a more reliable fuel because it is relatively easy to import and stockpile until needed.

Development of additional coal-fired capacity was considered by Genesis, Fonterra and Mighty River Power in the 2000s, but those plans were abandoned. The key drivers for those decisions have been the reduced availability of locally mined coal and rising carbon prices.

Coal-fired generation is even more sensitive than gas-fired plant to carbon prices. Each $25/tCO2e increase in carbon price adds around 2.3 c/kWh to the cost of generating power from a coal station.

Given this sensitivity, it is extremely unlikely that any new baseload coal-fired generation will be developed in New Zealand. Indeed, it is likely that existing coal-fired generation will reduce over time as carbon prices increase. In this context, we note that in February 2018 Genesis announced its intention to phase out coal-fired operation entirely at the Huntly station by 2030,52 while the Climate Change Commission’s assumption is that coal-fired generation at Huntly will cease in the

50 Numerous additional sites use coal generate primarily to generate industrial heat and may also produce some electricity. 51 More specifically, the Rankine units at the Huntly site can operate on coal and/or gas. 52 Genesis Energy, market announcement to NZX, 18 February 2018.

2020s.53 While this would have the benefit of eliminating emissions from coal-fired generation,54 the loss of firm controllable generation is likely to pose a significant challenge from an electricity system perspective. It is unclear at this time what alternative source of generation or flexible demand response will be developed to replace coal operations at Huntly.

53 Climate Change Commission, Ināia tonu nei: a low emissions future for Aotearoa, 31 May 2021, page 113.. 54 We note that coal may be used in some smaller scale co-generation facilities.

6 Economic benefits from granting of Wairakei consents

6.1 Summary – economic benefits

Granting the consents is expected to have significant economic benefits for New Zealand and the region.55

First, granting of consents would allow continued operation of the Te Mihi, Poihipi Road and WBP facilities. These facilities generate sufficient power to meet the energy needs of more than 250,000 households. We expect economic benefits to New Zealand of around $808 million in present value terms from continued operation of these plants. These benefits arise because it is significantly more efficient to continue to use existing sources of generation than to build new ones from scratch.

Second, granting of consents would allow the GeoFuture power stations to be developed to replace the Wairakei A&B stations. The GeoFuture stations would generate sufficient power to meet the energy needs of around 207,000 households – a net increase of 77,000 households compared to the Wairakei A&B stations. This is possible with only a modest (around 2%) increase in geothermal fluid take because the GeoFuture plant would be much more efficient in energy conversion than the Wairakei A&B stations and hotter part of the reservoir at Te Mihi would be utilised more. We expect that allowing the GeoFuture plant to proceed would produce economic benefits to New Zealand of up to $70 million in present value terms. These benefits stem from the cost savings attributable to this plant, compared to the likely next best power generation alternative (i.e. alternative new geothermal and/or wind generation).

Third, we expect that providing flexibility to allow a seamless transition from Wairakei A&B stations to GeoFuture between 2026 and 2031 could yield benefits of up to $16 million. This benefit arises because it allows Contact to optimise the transition date from the Wairakei A&B stations to GeoFuture in this window. This flexibility is particularly beneficial at present due to heightened uncertainties over future power demand caused by Covid-19, if and when the Tiwai smelter will close, and the uptake trajectory for electric vehicles and industrial electrification. In addition, we expect that providing some flexibility over the transition date could reduce greenhouse gas emissions by up to 540,000 tCO2e, all other factors being equal. This is because a supply shortage during the period between the retirement of existing geothermal assets and the construction of new ones will likely be met by increased generation from thermal sources.

Finally, we expect that allowing the GeoFuture development to proceed will produce regional benefits of $520 million to $600 million in revenues terms during the construction phase. Likewise, we expect the ongoing operations of the Te Mihi, Poihipi Road, WBP and GeoFuture plants will yield regional benefits of nearly $50 million per year in revenue terms over their lifetimes.

6.2 Basis for economic assessment

Although Contact is seeking a unified package of consents for generation operations at the Wairakei steamfield, to evaluate the economic impact of granting those consents it is useful to consider three distinct elements:

55 We have developed quantitative estimates of national benefits from electricity sector effects. We have not quantified non-electricity sector effects although we discuss them in qualitative terms.

1. Allowing continued operation of the Te Mihi and Poihipi Road stations and WBP beyond 2026. 2. Allowing the GeoFuture power generation project to be developed and start operating between 2026 and 2031. 3. Allowing for Wairakei A&B stations to keep operating until GeoFuture comes online between 2026 and 2031.

In the following sections we discuss the expected economic benefits associated with each of these elements. We make this assessment by considering two supply cases:

1. Base case – expected outcomes if the consents are granted. 2. Counterfactual case – expected outcomes if the consents are not granted.

The analysis is undertaken from a national economic perspective – i.e. the benefits that are expected to flow to New Zealand as a whole, rather than simply to the consent applicant. This approach is adopted because it captures all economic benefits, including those expected to flow to power consumers and taxpayers.

The analysis considers effects over the period to 2057. This timeframe is used because the consents if granted will run for 35 years, commencing around 2022.56

A discount rate of 6% (real, pre-tax) is used to convert benefits in future years into present value terms in 2021 dollars.57

6.3 Economic effects have been assessed under a range of future demand scenarios

As discussed in sections 3.5 and 3.6 there is uncertainty about future electricity demand. To reflect this uncertainty our economic assessment has considered three demand scenarios:

1. Lower growth – Tiwai exits at end of 2024. Otherwise ‘business as usual’ demand growth. 2. Central case – Tiwai exits at the end of 2024. Otherwise ‘Accelerated electrification’ demand growth. 3. No Tiwai exit – Tiwai stays indefinitely. Otherwise ‘Accelerated electrification’ demand growth.

These scenarios are based on demand projections in Transpower’s March 2021 Te Mauri Hiko monitoring report.

Scenario 1 (‘lower growth’) assumes Tiwai will exit at the end of 2024, and otherwise growth will be similar to that seen historically. Scenario 2 (‘central case’) is an upside scenario to this, where significantly higher demand growth occurs due to electrification of more of the economy, such as transport and industrial heat. We believe this outcome is more likely if Tiwai exits, as this will lead to an oversupply situation that will encourage additional demand growth. Scenario 3 (‘no Tiwai exit’)

56 This assumes a consent application is lodged in late 2021 and a determination is made in 2022. 57 See https://treasury.govt.nz/information-and-services/state-sector-leadership/guidance/financial-reporting- policies-and-guidance/discount-rates. Treasury has recommended a 6% discount rate be used to assess benefits for infrastructure and energy projects in recent years. In September 2020 Treasury lowered the recommended rate to 5% and indicated it would likely be reviewed again after 12 months. However, it now appears that rates in September 2020 were at the ‘bottom of the cycle’. Since October 2020 10-year government bond rates have increased by over 1%. Given this factor, we have continued to use a 6% rate.

assumes Tiwai will not exit and demand growth will be higher than historical levels (as in Scenario 2).58 We believe these demand scenarios cover the realistic range of potential outcomes.

We note that Transpower’s forecasts are for national demand, but if Tiwai exits there will be significant transmission constraints limiting the amount of energy capable of reaching the North Island for a period. For this reason, our Scenarios 1 and 2 assume that initially not all ‘freed up’ generation in the South Island reaches the upper North Island. We assume that transmission upgrades will increase this quantity over time.

6.4 Element 1 - Economic benefits of continued operation of Te Mihi, Poihipi Road and WBP

Granting of consents would allow power generation from the Te Mihi, Poihipi Road and WBP facilities to continue after expiry of the existing resource consents in 2026. Conversely, if consents are not granted, power generation from these facilities would cease in 2026. That would cut around 1,800 GWh per year from base load supply for New Zealand – enough power to supply over 250,000 households.

If the cost of replacement generation is higher than the lost generation, there is an economic benefit to New Zealand in allowing continued operation of Te Mihi, Poihipi Road and WBP beyond 2026. To gauge the size of that impact, we have considered how the lost generation would be replaced and the expected cost of such replacement generation.

Figure 19 shows the extent and timing of additional energy needs in the upper North Island if the Te Mihi, Poihipi Road and WBP plants were to cease operation from 2026. The chart measures the need relative to the position in mid-2020, when the system was in broad balance in energy terms.

Below zero the system is not in need of new investment, but above zero (a positive value for additional energy need) the system requires new investment.

58 Scenario 3 (‘no Tiwai exit’) could also reflect a case where Tiwai exits but its demand is completely taken up by alternative industrial and/or commercial users. However, we note that it is unlikely that Tiwai’s demand will completely and immediately be taken up by an alternative user – it is likely that there will be at least some transition period and/or alternative users only partially replace Tiwai demand.

Figure 19: Need for additional energy if Te Mihi, Poihipi Road and WBP are not available

Under the lower growth scenario (Tiwai closure at the end of 2024, “business as usual” demand growth) there is an initial period between 2020 and 2025 where there is minimal additional energy required (shown by the green line being close to or below the black dotted line during this period). This is because the committed new generation projects coming onstream59 are nearly sufficient to satisfy underlying demand growth until 2024 and then the assumed Tiwai smelter closure at the end of 2024 reduces the need for new generation further.

However, the closure of the Te Mihi, Poihipi and WBP plants would significantly tighten the system after 2026. We expect this would be met for a transitional period by tighter supply margins and greater running of existing thermal generation. Additional new generation would be needed from about 2027 to meet demand growth and displace existing thermal generation.

We note that the lower growth scenario has the lowest electricity demand profile, but even in this case the closure of Te Mihi, Poihipi Road and WBP would trigger a need for new investment to provide additional energy production relatively soon after 2026.

In the no Tiwai exit scenario (Tiwai stays indefinitely, “accelerated electrification” demand growth) more generation is needed almost immediately. This is because additional demand growth is occurring in a system that has no appreciable freeboard. In this scenario, we expect new renewable generation would be required as soon as closure of Te Mihi, Poihipi Road and WBP plants occurs.

The central case scenario follows the trajectory of the no Tiwai exit scenario until the assumed Tiwai closure at the end of 2024. Therefore, like the no Tiwai exit scenario, new generation is needed almost immediately. However, once Tiwai closes at the end of 2024 there is a short and shallow energy surplus, followed by a sharp increase in the requirement for new renewable generation.

In the above scenarios, generation lost due to closure of the Te Mihi, Poihipi Road and WBP plants is replaced by differing combinations of new supply, reduced spill and harder running of existing thermal plants. Our economic analysis recognises that new supply and harder running of existing thermal stations have economic costs:

59 The Waipipi and Turitea wind farms.

1. Construction and running of new renewable generation - we expect geothermal or wind generation will account for the bulk of new generation development for the next decade or so. As discussed in Chapter 5, these resources have similar GWAP/TWAP adjusted LRMC ranges and we expect a significant volume to be available at costs of 6-7 c/kWh. For the purposes of this analysis, we have assumed the new renewable generation to substitute for Te Mihi, Poihipi Road and WBP will have a levelised cost of 6.5c/kWh. 2. Increased operation of existing thermal plant – this captures the cost (including fuel and CO2 costs) of running thermal plant (i.e. the short-run marginal cost). For the purposes of this analysis, we have assumed a cost of 7.5 c/kWh.

Our analysis also takes account of the costs that would be avoided if Te Mihi, Poihipi Road and WBP were to close from 2026. These avoided costs principally relate to drilling, well maintenance and other stay-in-business capital costs that would not be incurred post 2026. These costs are assumed to be 2.4c/kWh in levelised terms. This is based on the average geothermal operating cost estimate in the recent study conducted for MBIE.60

The net economic benefit of allowing continued operation at the Te Mihi, Poihipi Road and WBP facilities is computed by calculating the costs which are avoided by not replacing these plants, less the cost incurred from their continued operation. A net cost is calculated for the each of the years between 2026 and the end of the expected lifetime of each plant61, and then these converted into present value terms using a 6% real pre-tax discount rate.

We estimate that the net benefit of continued operation of Te Mihi, Poihipi Road and WBP post 2026 is about $808 million in net present value terms.

Finally, we note the above analysis may be conservative because it only considers the need to replace lost energy production (i.e. generation to meet annual demand) if the Te Mihi, Poihipi Road and WBP facilities were to close in 2026. These plants also provide firm capacity (i.e. contribute to meeting power demand during peak usage periods such as cold winter evenings). If capacity constraints were to emerge in the period after 2026, then the economic benefits associated with continued operation of Te Mihi, Poihipi Road and WBP would be even higher.

6.5 Element 2 – Enable GeoFuture project to proceed

Granting of consents would allow the GeoFuture project to proceed with a commencement date between 2026 and 2031. The project would provide up to 1,450 GWh per year from baseload supply for New Zealand.62 To help place this in context, GeoFuture’s output would be sufficient to meet the annual needs of over 200,000 (or approximately 11% of all) households.63

60 Lawless Geo-Consulting and others, Future Geothermal Generation Stack, March 2020, p.20, cites $190,000/MW/year as an average value for operating costs including replacement wells. This equates to 2.4c/kWh with a 90% capacity factor. 61 We assume that each geothermal plant has a lifetime of another 35 years from when the consent is issued. Consistent with section 2.2 the consents are assumed to be issued in 2022. 62 Relative to the existing output of Wairakei A and B this would be a net increase of 525 GWh per year. However, Wairakei A and B will cease operation under all scenarios. Hence, so the net increase from granting consent for GeoFuture is up to 1,450 GWh per year relative to a scenario where consent is not granted. 63 This assumes an annual total energy demand of 7,000 kWh/year per household based on “Electricity in NZ 2018” – Electricity Authority.

From an overall New Zealand economic perspective, it is important that new stations are built in the correct ‘merit order’, i.e. least cost stations are built first, and so on. If this does not occur, it will result in the diversion of valuable national resources into inefficient uses.

There are two ways that ‘out of merit order’ development could occur:

• Type I Error – a higher cost project is developed ahead of a lower cost project.

• Type II Error – a project that is least cost does not proceed.

In our view, it is unlikely that a Type I Error will knowingly occur in the case of GeoFuture. This is because generation output from GeoFuture will be competing with production from other stations. If GeoFuture is sub-optimal and Contact proceeds nonetheless, the cost of that poor decision is likely to fall on Contact’s shareholders. As a result, Contact has a strong incentive to not commit to GeoFuture unless it is relatively confident the project is economic.

While a Type I Error is unlikely, the picture is less clear-cut for a Type II Error. Contact cannot ensure the project will proceed even if it is economic, as some pre-requisites for a development lie outside of Contact’s control.

In the present context, the key risk is an inability to move forward because the project lacks the requisite approvals under the Resource Management Act. If that were to occur, then future demand would need to be met from another source.

It is obviously not possible to define the cost associated with such an outcome with certainty. It would depend on the costs of the substitutes that proceed instead and the final cost that could have been achieved from GeoFuture.

While there is uncertainty around these variables, there are good grounds to believe that alternatives to the GeoFuture project are likely to have a higher cost. This view is based on the following factors:

• As discussed in Chapter 5, geothermal projects as a class appear very competitive relative to most other forms of new generation.

• Within the category of new geothermal options, so-called ‘brownfield’ projects, which are extensions of an existing operation, tend to have lower costs and risks. For example, the Future Geothermal Generation Stack report prepared for MBIE in March 2020 commented that “Larger brownfield projects should have slightly lower unit costs”.64

• Of the brownfield geothermal options in New Zealand, the GeoFuture project is likely to be one of the best opportunities available because the project would be based on a geothermal resource with a proven track record. The Wairakei geothermal resource has been used for power generation for over 60 years, providing an extensive body of information on the geothermal reservoir. This significantly reduces one of the key risks associated with geothermal development.

64 Lawless Geo-Consulting and others, Future Geothermal Generation Stack, March 2020, p.19.

Contact has indicated that the levelised cost of electricity from the GeoFuture project is likely to be in the range 6 – 6.5 c/kWh in 2020 dollar terms.65 This is consistent with our own analysis and implies the project is toward the lower end of the cost range for new projects.

In light of these factors, if the GeoFuture project could not proceed due to lack of consents, we think it likely that the replacement generation source(s) would have a higher cost. While we cannot be certain what that magnitude would be, we consider a credible range would be 0-0.5 c/kWh.

Table 3 shows differing levels of unit cost advantage within this range. The table also shows the benefits that would be accrue each year, and the total benefits over an assumed effective 30-year consent lifetime and in present value terms.66

Table 3: Potential benefit of allowing GeoFuture to proceed

Economic benefit over 30 Economic benefit in GeoFuture - level of cost advantage Economic benefit per year year life time present value terms c/kWh $m $m $m (2020 dollars) 0.00 $0.0 $0.0 $0.0 0.10 $1.5 $43.6 $14.1 0.20 $2.9 $87.1 $28.2 0.30 $4.4 $130.7 $42.3 0.40 $5.8 $174.2 $56.4 0.50 $7.3 $217.8 $70.4 GeoFuture AEE.xls Source: Concept estimates

Key points to note are:

• Allowing GeoFuture to proceed could provide benefits which range up to $70 million67 in present value terms (or up to $218 million over the project lifetime in undiscounted terms). • The expected worst-case scenario is that allowing GeoFuture to proceed will yield no benefit. This is because if the project is expected to be uneconomic, Contact is very unlikely to proceed because it would bear the consequent losses.68 For this reason, the granting of a consent to develop the GeoFuture project is a low risk decision from an economic perspective – it has significant potential positive value, and the downside is close to zero.

6.6 Element 3 – Allow Wairakei A&B station to operate until GeoFuture is online

This section assumes that consent will be granted to:

• Allow continued operation of the Te Mihi, Poihipi Road and WBP facilities to 2057. • Enable development of the GeoFuture project with a commissioning date between 2026 and 2031.

65 Information provided by Contact via email dated 26 June 2020. 66 Because the analysis is considered from a national New Zealand perspective, a public discount rate of 6% in real pre-tax terms has been used - this aligns with the rate recommended by Treasury for such projects. 67 The analysis indicates benefits of up to $100 million in 2026 dollars. Discounting these at 6% over six years reduces them to $70 million in 2020 dollars. 68 It remains possible for the project to yield actual net costs, if there are unexpected factors which alter outcomes from those anticipated at the time of project commitment. However, it is reasonable to expect that Contact will take these factors into account when deciding whether to commit to a project.

Against this backdrop, we now consider whether granting flexibility in the consent for continued operation of the Wairakei A&B Stations until GeoFuture commences is likely to yield an economic benefit.

In our view, absent the granting of this aspect of the consent there is a real potential for a ‘gap’ to emerge between the closure of the Wairakei A&B Stations and the commencement of the GeoFuture facility. This potential arises because:

• The closure date of Wairakei A&B Stations operation is hard-wired to 2026 unless new consents are granted. • The preferred start date for GeoFuture will be affected by future demand conditions which are particularly difficult to forecast at present due to uncertainties over Covid-19, when and if the Tiwai smelter will close, and the uptake trajectory for electric vehicles and industrial process electrification. • Contact is unlikely to commit to building the GeoFuture plant until there is sufficient demand to justify it. This judgement is based on the incentives operating on developers (see section 4.5 and discussion of Type I Error in section 6.5). It is also supported by empirical evidence. In the late 2000s, Contact became keen to develop the Te Mihi power project. It was granted consents in September 2008 by which time electricity demand growth had slowed due to the Global Financial Crisis.69 Ultimately, the project was delayed until 2010 when demand justified the investment, and the plant came on stream in mid-2014.

To analyse the potential benefits from allowing Wairakei A&B Stations flexibility to operate until GeoFuture is online, we have used the same framework as that used in section 6.4 to analyse the benefits of continued operation at the Te Mihi, Poihipi Road and WBP plants.

The three demand scenarios are the same as those discussed earlier. On the supply side, we assume the Te Mihi, Poihipi Road and WBP facilities continue post 2026, and that Wairakei A&B Stations cease operation after 2026.

The resulting need for additional energy is shown in Figure 20. Also shown on the chart is the amount of energy (up to around 1,450 GWh/year) that could be generated by the GeoFuture project (dotted orange line). This line is added because GeoFuture is unlikely to come online until the need for additional energy production is near this level.

69 See: www.mfe.govt.nz/rma/proposals-national-significance/historic-call-ins/te-mihi-geothermal-power- station

Figure 20: Need for additional energy with exit of Wairakei A&B Stations in 2026

Key observations from the chart are:

• In Scenario 1 (lower growth – Tiwai closure at the end of 2024 and modest underlying demand growth) the need for new generation reaches 1,450 GWh/year around 2031. Hence we would expect GeoFuture to be commissioned around 2031 if scenario 1 demand conditions are expected to prevail and consents are available. • In Scenario 3 (no Tiwai exit – Tiwai continues operation and accelerated electrification demand growth) there is need for new generation before 2026. Hence, we would expect GeoFuture to be commissioned in 2026 if consents are available, all other factors being equal. • In Scenario 2 (central case – Tiwai closure at the end of 2024 and accelerated electrification demand growth) the results are between those described above. There is need for some new generation in 2026, but slightly less than the full output from GeoFuture. We would expect GeoFuture to commence operation from about 2027/2028 if consents allowed.

The above analysis clearly shows that the optimal date to replace Wairakei A&B Stations with GeoFuture is very sensitive to the demand growth outlook. Allowing Wairakei A&B Stations to continue to operate until GeoFuture is online would provide option value by allowing Contact to seamlessly replace Wairakei A&B Stations with GeoFuture when, and if, it is optimal to do so (within the period 2026-2031).

We have estimated the value of this option by considering economic costs that would arise if a lack of flexibility were to lead to a gap between the decommissioning date of Wairakei A&B Stations and the start-up of GeoFuture. Such a gap could quite plausibly be up to two years given the lead-time to build a new plant and the likelihood that demand uncertainty will only recede gradually. We would expect increased operation of existing thermal stations during any gap years.

The economic costs would be the difference between the operating costs of Wairakei A&B and the substitute thermal plant.70 These costs are estimated at $16 million in present value terms.71 We have not identified any electricity system costs that would arise from granting the flexibility to allow a seamless transition. Hence, we estimate the electricity system economic benefits from granting the flexibility to be between $0 and $16 million. In addition, we would expect greenhouse gas emissions to be higher by around 540,000 tonnes if there were a two-year gap between Wairakei A&B Stations retirement and replacement renewable plant being commissioned.

In conclusion, while the precise numbers are sensitive to input assumptions, we expect that providing flexibility over the transition date from Wairakei A&B Stations to GeoFuture is likely to minimise the economic costs of meeting future power demand, and reduce greenhouse gas emissions, all other factors being equal.

6.7 Contribution to regional economy

If the GeoFuture project goes ahead, construction of the power stations would be a sizeable undertaking. Although the larger electrical and mechanical plant items would be imported, there would be significant civil and fabrication work undertaken locally which would contribute directly to the regional economy in the Waikato Region72 through opportunities for employment, contracting, support services and the like.

Once commissioned, the GeoFuture project is expected to provide ongoing positive economic benefits to the local economy. This would add to the expected regional benefits from the ongoing operations of the Te Mihi, Poihipi Road and WBP plants over their lifetimes.

Construction and operation of the GeoFuture stations is also likely to have indirect flow-on regional economic benefits. For example, local contractors engaged in construction of the GeoFuture stations will have increased incomes, some of which is expected to be spent locally (e.g. on accommodation services). This spending will in turn raise incomes for other local providers (e.g. for suppliers of food and other goods and services to accommodation providers), who in turn will spend some of their increased incomes. The ongoing operation of the Te Mihi, Poihipi Road and WBP plants would also provide indirect economic benefits to the Waikato Region.

A common method of quantifying the regional economic benefit of a project is to do a multiplier- based economic impact assessment. Such an assessment uses information on the direct impact of a new development (such as the GeoFuture project) and historical data on the structure of the local economy (which show the interdependencies between different sectors or industries in the regional economy) to estimate the flow-on effects of the project across the region.

71 For this analysis, we have used the same cost assumptions for thermal operation and SRMC at Wairakei A&B Stations as those used in section 6.4. For the period after 2026, we have assumed that Wairakei A&B Stations has the same unit cost of generation as GeoFuture. This assumption is made so the analysis can focus on the effect of the generation output increase from commissioning GeoFuture on economics. For the GeoFuture plant, we assume power generation costs of 6.25 c/kWh, i.e. the mid-point of the estimated range in Section 6.5.

72 Henceforth we use the term ‘local’ and ‘regional’ to refer to the Waikato region, which of course includes the Taupo district.

Economic impact analysis is useful as it provides an indication of the economic benefits a project could have on a region over-and-above the direct impact. However, it is important to recognise that economic impact assessments by their nature are unable to estimate net regional benefits, because it is impossible to know what alternative activities might occur if a particular project does not proceed. For example, a new retirement village development may attract resources (land, capital etc) which may otherwise be used to develop a school or residential housing.73 While it is important to bear this caveat in mind, economic impact analysis is nonetheless useful to gauge the size of gross economic impact on a region.

We have estimated the direct and indirect economic impacts of the GeoFuture project (both construction and operation phases) on the Waikato Region using economic impact analysis. We have also used economic impact analysis to estimate the direct and indirect economic impacts of the continuing operation of the Te Mihi, Poihipi Road and WBP plants on the Waikato Region. The results of this analysis are set out in the next two subsections.

6.7.1 Contribution to regional economy during GeoFuture construction phase

Information provided by Contact indicates that the overall capital expenditure for the GeoFuture project is expected to be between $650 million and $750 million, of which Contact expects about 33 percent will be spent in the Waikato Region74. This Waikato-based capital expenditure (of between $215 million and $248 million) will be a direct benefit for the Waikato regional economy during the construction phase.

In employment terms, we understand the construction phase will require approximately 2.3 million person-hours of labour, spread over an approximate 27-month period.75 Contact estimates that about 70 percent of this employment (1.6 million person-hours) will be in the Waikato Region.76 This would equate to nearly 400 employees working full time for 27 months.

We have estimated the indirect flow-on effects of the construction of the GeoFuture stations. For this analysis we have used multiplier estimates for economic and employment effects from a 2010 study into a geothermal development.77 As far as we are aware, this is the most recent published study which contains multiplier estimates for a geothermal power project. While those multiplier estimates were calculated some years ago, multipliers do not tend to change much over time because the structure of economies is relatively stable except over the very long term. We therefore

73 See, for example, Peter Clough’s critique of the Application for Plan change and Resource consent for Summerset Group Limited’s proposed Boulcott Farm Retirement Village (available here: http://iportal.huttcity.govt.nz/Record/ReadOnly?Tab=3&Uri=4122108). 74 Contact expects 38 percent to be spent in the rest of New Zealand and remaining 29 percent to be spent offshore. 75 Contact’s expectation is based on person-hours required for Te Mihi phase 1 (construction of Units 1 and 2 including associated drilling and steamfield). The person-hours required for the construction of the GeoFuture stations are expected to be lower than what was required for Te Mihi phase 1 because it only requires the construction of one steam turbine unit (rather than two). 76 Contact expects about 20 percent of the construction employment to be in the rest of New Zealand and 10 percent offshore. 77 Bevin and others, Proposed Tauhara II Geothermal Development: Regional Impact Analysis, February 2010, Appendix 2.

expect the multiplier estimates in that study to provide a reasonable basis for calculating indirect regional flow-on effects from the GeoFuture project.

Table 4: Waikato economic impact – GeoFuture construction phase

Revenue ($m) Employment (person-hours (m)) Low estimate High estimate

Direct impact 215 248 1.6 Indirect flow-on benefit 305 351 1.8 Total impact 519 599 3.4 (equivalent to about 800 people working full time for 27 months)78

Multipliers for Waikato 2.42 2.42 2.11 Sources: Contact estimates, Bevin and others, Proposed Tauhara II Geothermal Development: Regional Impact Analysis, February 2010, Appendix 2.

Table 4 indicates that the total impact of the construction of the GeoFuture stations on the regional economy is expected to be between $520 million and $600 million in revenue terms and 3.4 million person-hours in employment terms. This would equate to around 800 people working full time for 27 months.

6.7.2 Ongoing contribution to the regional economy

The preceding section described the expected benefits to the Waikato Region during the construction of the GeoFuture stations. This is expected to occur over approximately 27 months.

Once in operation, the GeoFuture project will also create ongoing benefits to the regional economy. Furthermore, granting of the new consents for the Wairakei Steamfield will allow continued operation of the Te Mihi, Poihipi Road and WBP stations beyond 2026. The combined direct benefit for the Waikato Region from operation of these stations is estimated to be $21.4 million per year.79 This assumes that 70 percent of the general operating expenditure for all these stations is spent in the Waikato Region.

Once again, we have used multiplier estimates from the 2010 study to estimate the indirect flow-on effects of operating the GeoFuture and other existing stations.80 The indirect flow-on effects are considered in two parts – employee induced consumption linkages and industry supplier linkages. The former estimates the impact that increased incomes will have on local expenditure by the employees, and also on expenditure by other local businesses (and their employees) where

78 Assuming full time is 46 weeks/year at 40 hours/week. 79 This is based on Contact’s estimate of general operating costs (excluding carbon) of $13.0 million for the GeoFuture stations and $17.6 million (in total) for the Te Mihi, Poihipi Road and WBP. As noted in the subsequent sentence, it is assumed that 70 percent of general operating expenditure is spent in the Waikato Region. 80 Bevin and others, Proposed Tauhara II Geothermal Development: Regional Impact Analysis, February 2010, Appendix 2. The report did not directly report any multipliers for the ongoing contribution to the regional economy, but that can be inferred from the two tables on page 3 of Appendix 2.

GeoFuture’s employees spend. The latter estimates the impact of increased expenditure by local suppliers that provide inputs to the GeoFuture stations.

We have not calculated an indirect employment impact from the granting of consents. This is because we have not identified multiplier estimates which would be suitable for this purpose. However, we note that Contact expects the operation of the GeoFuture stations will have a direct employment impact of 15 FTE employees. We estimate the continued operation of the Te Mihi, Poihipi Road and WBP will have a direct employment impact of 45 FTEs.81 Although we have not quantified them, we would expect there to be material indirect flow-on effects on employment in the Waikato Region.

Table 5: Waikato economic impact – operation phase

Revenue ($m p.a.)

GeoFuture Te Mihi, Poihipi Road and TOTAL Wairakei Binary Plant

Direct impact 9.1 12.3 21.4 Indirect flow-on benefit (a) employee induced 2.1 6.2 8.3 consumption linkages (b) industry supplier linkages 9.3 10.4 19.8 Total impact 20.5 29.0 49.5

Multipliers for Waikato

(a) employee induced 2.8 consumption linkages (b) industry supplier linkages 2.2 Sources: Contact estimates, Contact estimates, Bevin and others, Proposed Tauhara II Geothermal Development: Regional Impact Analysis, February 2010, Appendix 2.

Table 5 indicates that the total impact of the operation of the Te Mihi, Poihipi Road, Wairakei Binary and GeoFuture stations on the regional economy is expected to be nearly $50 million per annum in revenue terms.

81 This estimate is derived from information provided by Contact.