Enabling NZ’s transition to 100% renewable generation

Strategic Review15 November 2021CENUtilities

contactenergy.co.nz

15 November 2021

Thermal Co: Enabling Aotearoa’s transition to
100% renewable electricity generation

Contact has released a report outlining the benefits of establishing of an industry-wide,
market-based solution to manage the retirement of thermal electricity generation.

The ‘Crafting a path for New Zealand’s 100% renewable electricity market’ report
supports a key pillar of the company’s strategy to lead the decarbonisation of New
Zealand. It outlines what Contact believes is the most effective way to decarbonise
thermal generation at the lowest cost.

New Zealand currently relies on thermal electricity generation from gas, coal and
diesel during periods of peak demand or when there is insufficient water, wind and sun
to meet demand from renewable sources.

Contact CEO Mike Fuge said the Climate Change Commission had highlighted the
significant challenge ahead to reduce New Zealand’s emissions rapidly and meet our
climate obligations.

“Renewable electricity has a key role to play in supporting decarbonisation across the
economy. Electricity generation is currently responsible for five per cent of New
Zealand’s carbon emissions.

“Our proposal focuses on how we can expedite the transition away from the current
reliance on electricity generated from fossil fuels, without disrupting the secure,
affordable supply of electricity to New Zealanders.

“We have proposed the establishment of a new, industry-wide entity which we have
called ‘Thermal Co’. This could own, operate and retire all of New Zealand’s major
thermal generation assets as new renewable generation is built, reducing carbon
emissions into the atmosphere by 1.2 million tonnes per annum by 2030.”

Mr Fuge said Contact’s view was that adopting a market-led, co-operative approach
would result in significant benefits for New Zealand.

“Getting the transition towards a fully renewable electricity system right could unlock
a significant opportunity for New Zealand with benefits for the environment, people
and communities. It will also deliver a competitive advantage for NZ businesses.”

“And on the flipside, ad hoc and uncoordinated closures of thermal generation assets
could be problematic and create a raft of potential issues. This includes market
uncertainty which would delay investment in renewables at precisely the time when
we need this to be proceeding with pace.

contactenergy.co.nz
“We’re looking forward to constructive engagement from key stakeholders across the
sector as we consider how best to deliver a low-carbon electricity system.”

-ends-

ADDITIONAL INFORMATION

1/ The report
The full report and the executive summary can be downloaded from the Contact
website

2/ Investor enquiries: Matt Forbes
matthew.forbes@contactenergy.co.nz
+64 21 072 8578

3/ Media enquiries: Leah Chamberlin-Gunn
leah.chamberlin-gunn@contactenergy.co.nz
Ph +64 212277991

---

Crafting a path
for New Zealand’s
100% renewable
electricity market
Proposal for industry-wide engagement on the
future of New Zealand’s thermal assets

Executive summary
An opportunity for Aotearoa
to take a leadership position
New Zealand can become the world’s
first large-scale, competitive electricity
market to reach 100% renewable electricity.
Our advantageous starting point, with a
highly decarbonised market powered by
our enviable geothermal, hydro and wind
resources, gives us a strong competitive
advantage over the next two decades.
Electricity generation is today responsible for
5% of New Zealand’s carbon emissions, and has
the potential to support significant emission
reductions across the economy. This report
explores how we can make the transition away
from our current reliance on electricity generated
by fossil fuels, without disrupting a secure and
affordable supply of electricity to New Zealanders.
Contact aims to lead the decarbonisation of
New Zealand. We are committed to kaitiakitanga
– to care for New Zealand’s tiaki tiao
1
and its tiaki
tangata
2
. This will support our country's progress
towards a 100% renewable electricity market and
a carbon-neutral economy by 2050. The Climate
Change Commission (CCC) has recently outlined
a pathway to achieve this national goal, which
recognises that electricity will be the main enabler
of our economy’s decarbonisation. We agree with
this, but the questions is: how?
The transition towards a 100% renewable
electricity market can unlock significant
opportunities for our country, benefiting
our environment, our people and our
communities, while creating competitive
advantages for New Zealand businesses.
New Zealand still relies on fossil-fueled thermal
generation during periods of peak demand or
when there is insufficient water, wind and sun
to meet demand. As new lower-cost renewable
projects are built, thermal assets will be used
less and less. The CCC predicts that reduced
1 environment
2 people
thermal generation, and the corresponding
growth in renewable generation, will reduce
emissions by ~1.2Mt C02-e per year between
2022 and 2030.
The CCC model also finds that most existing
thermal assets will still be required at critical
times over the next decade to meet electricity
demand as we transition to renewable
alternatives. It will be important that the costs
to operate and maintain these thermal assets
can be recovered, to ensure they continue to be
available when needed for security of supply.
We assessed several market options that have
been used in other countries and evaluated their
ability to mitigate the challenges the transition
away from fossil-fueled generation may present.
Our preferred option is the
establishment of ThermalCo:
an entity that would own and
operate all New Zealand’s
existing thermal assets. It
would have the mandate
to sell risk management
products (for both dry-year
and peak demand) to industry
participants. Our view is that
the ThermalCo proposal could
be implemented relatively
quickly and would facilitate
an orderly phasing out of
thermal assets over time.
The consolidation of thermal
generation assets would
ensure the optimisation of
the thermal portfolio and help
balance the energy trilemma:
secure supply, affordability,
and environmental factors.
3

Maintaining the balance to
ensure an orderly transition
New Zealand’s electricity market is one of only
nine countries globally with a ‘triple-A’ rating
in the World Energy Council Energy Trilemma
index, demonstrating a world-class balance of
decarbonisation (environmental sustainability),
security of supply (energy security) and
affordability (energy equity). Within these
nine countries, New Zealand is one of the best
positioned to embark on the transition towards
the 100% renewable electricity goal, given
its leading renewable electricity penetration
and the high quality of renewable resources.
During the transition, New Zealand will need
to pursue two main objectives:
1. Maintain its world-class balance across the
trilemma, as more renewables economically
replace fossil fuelled generation; and
2.

E
nsure an orderly transition of New Zealand’s
electricity market to 100% renewable generation.
1. Maintaining the world-class
equilibrium across the trilemma
• Decarbonisation is well on track, with market
analyses
3
demonstrating that the integration of
an additional 8.5TWh of renewable generation
by the CCC under the Tiwai stays scenario
4

would be economic. The price received by
generators is expected to be enough to
encourage ongoing investment (i.e. will be
above long-run cost). Provided new projects
can find cost efficient network access, nodal
market incentives will guide them to the
locations where they are required. The main
risks that could prevent capacity coming
online would be regulatory uncertainty or very
unpredictable market conditions. International
experience shows how regulatory intervention
in well-functioning markets can result in
suppressed investment signals.
•

S
ecurity of supply will be increasingly
challenging as new renewables enter the
market and utilisation of thermal plants
falls. According to CCC modelling, by 2030
New Zealand will need around 4.5TWh of
flexible energy in a dry year (which is currently
3 Jarden September 2021; Concept Consulting; Climate Change Commission; Meridian Energy
4 New Zealand Aluminium smelter have an electricity supply contract to the end of 2024. For simplicity we have assumed that a closure of the
smelter would facilitate an equivalent replacement load.
5

T
ranspower’s North Island Capacity Margin test recommends a 630MW to 780MW margin above peak demand
6
N
ew Zealand dollars unless otherwise stated
supplied by fossil fuelled generation). In
addition, 1300MW to 1450MW of incremental
firm capacity (beyond the 4,600MW provided
by renewables and the HDVC) will be required in
the North Island to cover winter peak demand
and the "safety" margin
5
. CCC modelling
suggests ~1150MW of existing gas power plants
will provide these firming requirements after
the closure of TCC and the Rankines, leaving
a 150MW to 300MW firm capacity gap in the
North Island. Low utilisation of these flexible
thermal plants, which would only operate
in peak periods or dry years, could lead to
early closure or lack of upstream fuel supply
investments, putting security of supply at risk.
Additionally, for thermal plants, recovering the
fixed costs across fewer and fewer hours of
operation may lead to periods of very high price
volatility in the wholesale market.
•

E
nergy affordability for consumers will
be the most challenging element of the
trilemma to balance during this transition.
Today, the fixed costs of the thermal assets
required to guarantee security of supply are
$100 million to $150 million per annum
6
. Failing
to recover these costs could lead to early
closures and unstable market conditions,
putting affordability at risk. Multiple solutions
to replace these thermal assets are currently
being assessed by government, consultants,
and market participants - from hydrogen
flexibility, biomass, and batteries, to pumped-
hydro or large-scale demand response. All
these solutions still have a high degree of
uncertainty in costs for consumers and trade-
offs for the electricity market. New Zealand’s
market structure must ensure a balanced,
equitable reward mechanism for the flexible
energy and capacity to ensure security of
supply at the lowest possible cost. At the same
time, New Zealand’s electricity market must
continue to attract investment in the most
efficient technologies so affordability
for consumers is maintained.
2. Ensuring an orderly transition
New Zealand’s transition to 100% renewable
electricity is going to be one of the first in the
4

world. Market signals will need to continue to
attract renewables as they have been doing
to date, while also incentivising cost-effective
solutions to guarantee security of supply. These
signals should ensure an orderly transition of
assets, providing enough certainty to attract
alternatives, and should evolve together with
market demands and technology improvements
to secure the best outcomes for Aotearoa.
Decisions on decommissioning individual assets
need to consider cascading effects for New Zealand.
Disorderly exit of thermal assets may put security
of supply and jobs at risk – in both the power
plants and the upstream fuel supply industry.
Equally important, the lack of visibility on the
long-term outlook in the sector would delay
investments, putting the potential development
of new skilled jobs in regional New Zealand at risk.
Annual metrics20222030Description
Thermal emissions2.0 Mt CO2e0.8Mt CO2e
Emissions from thermal generation (excl. cogeneration)
Cost of emissions$52/TCO2$138/TCO2
Cost forecast for CO2 emissions
Share of renewables
excl. cogen (incl. cogen)
88% (86%)96% (93%)
Share of energy generation that is from renewables
Renewable gen.35.5TWh43.7TWh
Forecast generation from hydro, geothermal, wind and solar
Hydro productionDry: 21TWh
Avg: 24TWh
Wet: 27TWh
21TWh
24TWh
26TWh
1

The amount of hydro generation forecast, by the level of rain
in the year
Thermal productionDr y : 7. 5 T Wh
Avg: 4.6TWh
Wet: 2. 3TWh
4.5TWh
1.9TWh
0.3TWh
The forecast requirement for thermal generation (excluding
cogen), depending on the level of rain in the year
Winter metrics
(1-Apr-30-Sep)
20222030Description
Energy demand 22.6TWh25.6TWh
The forecast amount of energy required over winter
Energy supply28.1TWh29.9TWh
Energy generation potential over winter an average rainfall using
Transpower's methodology
Energy margin (optimal
range 14-16%)
5.5TWh
(25%)
4.3TWh
(17%)
The difference between potential generated electricity (in an
average rainfall year) vs. energy demand. Optimal range calculated
using Transpower’s methodology
Fuel demand in dry year41PJ27PJ
The quantity of fuel (energy) required over winter to cover the
optimal Energy Margin
Fuel availability41PJ20PJ
The quantity of gas, diesel and coal available over winter (coal in 2022 only),
assuming the provision of gas flexibility from existing assets only.
NI Peak demand4600MW5250MW
Peak electricity demand in the North Island
NI Firm Capacity5850MW5750MW

T
he amount of firm capacity in the North Island based on
Transpower's methodology
NI Capacity Margin
(optimal range 630-
780MW)
1250MW500MW
The margin between the amount of firm capacity and the peak
electricity demand in the North Island. Optimal range calculated
with Transpower's methodology
Key assumptions and modelling fact base, based on CCC
Tiwai stays scenario
CogenWindHydroThermalGeothermalSolar
1
.Tiwai stays scenario, as modelled by Energylink for the CCC. Excludes smaller scale embedded generation.
1.0
(11%)
5.2
(55%)
9.4
1.9
(20%)
1.0
(11%)
0.3
(2%)
0.9
(8%)
1.2
(11%)
2.7
(24%)
5.2
(45%)
1.2
(10%)
11.4
1
(3%)
24
(58%)
8
0
(19%)
5
(11%)
3
(8%)
2022
1
(3%)
2
(4%)
9
(19%)
24
(51%)
9
(20%)
2030
41
47
2022
2030
0.3
(3%)
2
(3%)
CCC forecast generation mix
1
, TWhCCC nameplate capacity mix
1
, GW
1 Higher renewable generation in 2030 results in more spill in wet years
CogenWindHydroThermalGeothermalSolar
1
.Tiwai stays scenario, as modelled by Energylink for the CCC. Excludes smaller scale embedded generation.
1.0
(11%)
5.2
(55%)
9.4
1.9
(20%)
1.0
(11%)
0.3
(2%)
0.9
(8%)
1.2
(11%)
2.7
(24%)
5.2
(45%)
1.2
(10%)
11.4
1
(3%)
24
(58%)
8
0
(19%)
5
(11%)
3
(8%)
2022
1
(3%)
2
(4%)
9
(19%)
24
(51%)
9
(20%)
2030
41
47
2022
2030
0.3
(3%)
2
(3%)
CCC forecast generation mix
1
, TWhCCC nameplate capacity mix
1
, GW
5

Three potential pathways to
support the transition and
improve the status-quo
To maintain the energy trilemma balance
in New Zealand as the market transitions
towards 100% renewable electricity, we believe
there are challenges that need consideration
over the transition period. We have studied
three market structures that aim to mitigate
these challenges, drawing from international
markets as they transition a high proportion
of renewables: Capacity Markets, Reserve
Payments in energy-only markets, and
Energy-Only markets supported by risk
management products.
In the specific context of New Zealand, which
has a relatively small share of thermal capacity
left in the market, we have explored which
ownership structures could better enable an
orderly transition: independent ownership,
independent ownership with Government
support and consolidated ownership.
The combination of the market structures with
their most natural ownership structure led us to
define three potential alternative pathways to
support New Zealand’s transition mitigating the
status-quo risks outlined above.
•

S
et up a Capacity Market: Create a new market
in New Zealand to trade firm capacity to supply
winter peak and dry-year demand, and work in
parallel to the existing energy market. A market
operator – potentially the System Operator –
would define the firm capacity requirements
in the market (demand) and how each type
of power plant contributes to its supply. All
existing and new plants wanting to enter the
market would bid in reverse auctions to receive
a fixed, annual capacity payment ($/ firm MW).
The frequency and payment duration of these
auctions would be defined by the market
operator; typically, this would be yearly auctions
with products ranging from 1 to 10 years ahead.
The costs of these capacity payments would
be passed through to all customers in their
bills as a market levy. With a Capacity Market,
ownership structure of fossil fuelled assets
would be maintained as is, with fossil fuelled
plants aiming to recover most of their fixed
costs through capacity payments. This is the
pathway adopted by United Kingdom, France
and several states in the US.
•
Establish a Strategic Reserve: The
establishment of a strategic reserve would entail
Government entering into an agreement with
one or more of the owners of strategic assets to
ensure security of supply in New Zealand. These
agreements would consist of reserve payments
- long-term contracts between the strategic
assets owners and the System Operator. These
contracts must ensure assets are available
to provide both firm and flexible capacity
in exchange for a payment to recover fixed
costs and like Capacity Markets, are recovered
via a customer levy. The Strategic Reserve
agreement would also come with limits in the
operation of the plants in the energy market,
where they could only bid an agreed price (likely
Short Run Marginal Cost) and are dispatched as
required by the System Operator. The objective
is to provide a stable source of income to
strategic assets, to maintain security of supply
in the system. Based on international examples,
assets under a Strategic Reserve arrangement
could maintain their existing ownership, be
transferred to the System Operator, or operate
under a combined ownership model, as seen in
Scandinavia or Germany.
•

E
stablish a ThermalCo: The establishment
of a ThermalCo is predicated on maintaining
the existing energy market, where generators
receive a price per MWh of electricity produced,
supported by derivative and insurance
contracts. ThermalCo would be an entity that
consolidates ownership and operation of all
existing thermal assets and upstream fuel
supply contracts, with the mandate to offer
transparent and liquid risk management
products (for both dry-year and peak demand)
to all purchasers. Consolidation would make the
provision of derivatives and insurance products
more efficient as new renewables enter the
market, diminishing the utilisation of thermal
6

plants. ThermalCo could also offer these risk
management products through a platform,
further increasing the transparency and
accessibility in the market. A ThermalCo would
support the orderly phasing out of the thermal
capacity when more efficient technologies
emerge. When demand for risk management
products is not enough to recover a plant’s
fixed costs, this will be a clear decommissioning
signal from the market, giving ThermalCo
sufficient time to react. The objective of
ThermalCo’s risk management products would
be to provide sufficient upfront revenues to
asset owners while keeping the appropriate
market signals to promote an orderly execution
of the transition.
These pathways and the associated combinations
of market structures that led us to them are
outlined in Exhibit 1.
While there are multiple implementation choices
that combine elements of the different pathways, we
have anchored on specific definitions outlined above
to help understand the different trade-offs the
New Zealand electricity market faces. Against
the pillars of the trilemma, all three pathways
provide some benefits towards promoting
decarbonisation of the electricity market and
ensuring security of supply, with differences
7 Based on analysis of FY21 dispatch information, assuming most efficient thermal plants are available to run in each interval
emerging around affordability. We also saw
differences in the contribution towards an orderly
transition for the electricity market, as well as
variations on implementation feasibility. Exhibit 2
summarises the comparative merits of each pathway.
•

O
n affordability, Strategic Reserve would
enable an equitable share of fixed system costs
while Capacity Markets would remunerate
all capacity available in the market. However,
incentives for the System Operator are too
biased to maintain high capacity margins in
both Strategic Reserve and Capacity Markets,
likely leading to overcapacity scenarios as seen
in Germany and the United Kingdom. This could
result in an expensive alternative to support the
flexibility required to cover dry-year swing and
winter peak demand in New Zealand. Energy
affordability during the transition period could
be best maintained through ThermalCo as its
risk management products will be closely and
dynamically linked to market needs. ThermalCo
will also enable an equitable split of the fixed
system costs across market participants and
facilitate operational synergies across thermal
generators (e.g. up to 4.5% fuel savings through
co-optimised dispatch).
7
• With regards to supporting an orderly
transition for New Zealand’s electricity and
Exhibit 1: Three pathways for New Zealand’s transition to 100% Renewable electricity
Market structures
Keep the energy trilemma
balance
Identified pathways
1
Capacity Market: Introduce a
new market for firm capacity
to operate in parallel with the
energy market
Reserve Payments: Pay for firm
capacity centrally through the SO
or market operator
Energy only market: Maintain
the energy market and enhance
price insurance product market
Thermal ownership structure
Ensure an orderly transition
for thermal assets
2
Independent ownership:
Maintain current ownership
structure
Independent ownership with
Government support: Set up
individual agreements between
Government and asset owners
Consolidate ownership:
Consolidate thermal assets into
one company with a mandate to
manage the transition
Independent ownership:
Maintain current ownership
structure
Set up a Capacity Market
Establish a Strategic Reserve
Establish ThermalCo
Status Quo
7

its people, the shared ownership structures
that could be provided by ThermalCo and
Strategic Reserve pathways will deliver greater
transparency and clear accountability as there
will be a single entity managing the transition.
Both could also decrease the operational risk
of maintaining low utilised assets and provide
more demand certainty to the upstream gas
industry. In contrast, while Capacity Markets will
guarantee recovery of most fixed costs for the
thermal assets, the risk will solely reside with
individual players, whose individual decisions
can be rapidly affected by changes in capacity
auction rules or capacity demand thresholds
determined by the System Operator.
•
On implementation feasibility, Capacity
Market will require new regulation, and
international experience suggests a time
frame in excess of 5 years to establish a
new equilibrium between capacity and
energy markets. Strategic Reserve will
need to legislate a change in mandate
for the System Operator and will require
the development of new skills, bringing
additional complexity that will take time to
embed. By operating within existing market
rules, ThermalCo presents the least disruptive
and fastest implementation pathway,
assuming industry consensus and the
approval from the Commerce Commission.
Exhibit 2: Comparison of pathways for New Zealand’s transition
Maintaining
balance in energy
system
Decarbonisation
Creates a new revenue source for renewable
energy, but this may be minimal for
intermittent generation projects
Security of supply
Ensures sufficient capacity is in the system
through capacity payments but does not
provide assurance that capacity will actually be
available when required
Energy
Affordability
Skews incentives for least cost generation
through introduction of new value stream
Does not always result in lower wholesale
energy prices, due to the introduction of
new system costs
Does not benefit from operational synergies
of existing assets
Orderly transition
Does not directly guarantee the staged and
planned shutdown of thermal plants, but it
provides long-term transparency through
market results
Feasibility
Requires a new market to be introduced and
regulated, which typically needs years to find
an equilibrium
Capacity market
8

ThermalCo: A market-based
pathway for Aotearoa
After exploring three potential pathway's to
keep the energy trilemma in balance during
the transition to 100% renewables, we
propose the establishment of ThermalCo.
ThermalCo will be an entity that owns and
operates all existing thermal assets and
upstream fuel supply contracts, with the
mandate to:
•
offer transparent, liquid and accessible
risk management products (for both
dry-year and winter peak) to all market
participants, while
•
ensuring an orderly phase out of the
thermal capacity as more reliable low
emission technologies become economic.
ThermalCo’s ownership structure could comprise a
broad range of industry participants, from existing
thermal asset owners, to infrastructure funds
or large-scale electricity purchasers, as can be
seen in global examples such as Scandinavia or
Germany. Critically, the successful implementation
of ThermalCo will require industry-wide alignment
and commitment to ensure liquidity of risk
management products.
The benefits of ThermalCo are sound and will help
Aotearoa capitalise on its renewable electricity
opportunity during the last step of the journey
while ensuring an orderly transition.
Ngā tapuae ō inanahi rā, hei huarahi mō āpōpō
The steps of our forbears, form the pathways for tomorrow.
10

The establishment of ThermalCo will
maintain the energy trilemma balance as:
• The offer of risk management products
to cover all thermal capacity in an open
platform will be a further evolution of
the hedging market helping to support
transparency and liquidity for all
market participants to cover dry-year
and winter peak risk
•

Co
nsolidated ownership of thermal
assets increases the availability
of capacity that could be offered to
derivative markets, as outage risks are
spread across a larger portfolio
•

S
ecurity of supply risks, priced through
hedging contracts, will provide
the price signal to incentivise the
market-led investments of the
lowest cost, reliable technologies
that address these risks. Long-term
hedge premiums will support dry-year
coverage, while short-term strike prices
will provide price signals for new flexible
capacity
•
Fixed cost recovery through premium
on risk management contracts will
reduce volatility in the spot market
as only variable costs will need to be
recovered. Most market participants
will likely prefer to cover their risks
rather than be exposed to price
spikes, providing a more equitable
distribution of fixed costs.
The establishment of a ThermalCo will
ensure an orderly transition of New
Zealand’s electricity market as:
• Consolidated ownership will provide
greater certainty in the mid- and
long-term demand for thermal
assets, allowing for more effective and
coordinated planning of the transition
of these assets when new technologies
can displace them
•

I
t maintains a stable regulatory
framework that works well today.
We invite support from stakeholders
that want to collaborate and
contribute to building a market-
led solution for a 100% renewable
electricity market in New Zealand
that not only achieves environmental
targets, but also meets the
challenges of security of supply
and affordability while ensuring an
orderly transition for all.
11

contact.co.nz

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Crafting a path
for New Zealand’s
100% renewable
electricity market
Proposal for industry-wide engagement on the
future of New Zealand’s thermal assets

Executive
summary
An opportunity for Aotearoa
to take a leadership position
New Zealand can become the world’s
first large scale competitive electricity
market to reach 100% renewable electricity.
Our advantageous starting point, with a
highly decarbonised market powered by
our enviable geothermal, hydro and wind
resources, gives us a clear competitive
advantage over the next two decades.
The transition will reduce yearly emissions by
~1.2 Mt CO2-e
1
per annum. For people and
communities, a more renewable based energy
market would potentially support over 350 new
permanent jobs and 7,500 construction jobs
over the next 10 years, with a strong concentration
in regional New Zealand. For some businesses,
decarbonisation will not only reduce costs but
also presents an upside opportunity to create
differentiation in the market, such as sustainable
tourism or carbon-free premium exports like
agriculture, dairy or metals. As cross-border
carbon taxes start to emerge, low-cost
100% renewable electricity can become a clear
competitive advantage for some industries.
Looking beyond our shores, new businesses
could also be attracted by our clean, reliable, cost
competitive electricity, as already demonstrated by
the Southern Green Hydrogen project expressions of
interest, and the recent data centre announcements
by Contact Energy (Lake Parime), Meridian Energy
(DataGrid) and Amazon Web Services, which would
further support high value jobs.
In a world where green, reliable, firm, cost
competitive energy is a scarce resource, Aotearoa’s
natural endowments have allowed the creation of
a highly renewable and cost-efficient electricity
market which has strong foundations to execute
the last step of the journey to move from 85%
to 100%. As an industry, we have the resources,
expertise and capabilities to get this transition
right, and Kiwis are expecting us to do so.
1 2030 compared to 2022. From CCC decarbonisation modelling,
Tiwai stays scenario.
3

Exhibit 1: Comparison of pathways for New Zealand’s transition
Maintaining
balance in energy
system
Decarbonisation
Creates a new revenue source for renewable energy, but
this may be minimal for intermittent generation projects
Security of supply
Ensures sufficient capacity is in the system through
capacity payments but does not provide assurance that
capacity will actually be available when required
Energy
Affordability
Skews incentives for least cost generation through
introduction of new value stream
Does not always result in lower wholesale energy prices,
due to the introduction of new system costs
Does not benefit from operational synergies of existing
assets
Orderly transition
Does not directly guarantee the staged and planned
shutdown of thermal plants, but it provides long-term
transparency through market results
Feasibility
Requires a new market to be introduced and regulated,
which typically needs years to find an equilibrium
Capacity market
Maintaining the balance to
ensure an orderly transition
New Zealand’s electricity market is one of
only nine countries globally with a ‘triple-A’
rating in the World Energy Council Energy
Trilemma index, demonstrating a world
class balance of decarbonisation, security
of supply and energy affordability. During
the transition, New Zealand will need to
pursue two main objectives:
1.

M
aintain its world class balance across
the trilemma, as more renewables
economically replace fossil fuelled
generation; and
2. Ensure an orderly transition of New
Zealand’s electricity market to 100%
renewable generation.
1. Maintaining the world class
equilibrium across the trilemmaa
• Decarbonisation is well on track, with
the CCC forecasting 8.5 TWh of additional
renewable generation under the 'Tiwai stays'
scenario by 2030. The price received by
generators is expected to be enough to allow
ongoing investment. The main challenge will
be to enable a stable and secure regulatory
environment for these investments to happen.
• Security of supply will be increasingly
challenging as new renewables enter the
market and utilisation of thermal plants falls.
According to CCC modelling, by 2030 New
Zealand will need around 4.5TWh of flexible
energy (currently supplied by fossil fuelled
generation). In addition, 1,300MW to 1,450MW
of incremental firm capacity (beyond the
4,600MW provided by renewables, batteries
and the HDVC) will be required to cover
North Island winter-peak demand (and a
'safety' margin). Low utilisation of thermal
plants, which would only operate in peak
periods or dry years, could lead to early closure
or lack of upstream fuel supply investments,
putting security of supply at risk.
•
Energy affordability for consumers will be
the most challenging element to balance.
Today, the fixed costs of the thermal assets
required to guarantee security of supply are
4

Positive contributionModerate contributionMinor contribution
Maintains energy market price signals to attract new
renewable projects in the locations where they are most
needed through nodal pricing
Maintains energy market price signals to attract new
renewable projects, with moderate risk of muting
scarcity price signals which attract investments in clean
flexibility
Market participants pay for risk management products
to ensure their energy needs are covered, incentivising
enough capacity online in the system
SO ensures security of supply by directly contracting
(reserve payments) with strategic assets
Market dynamics put downward or upward pressure on
risk management product pricing to ensure capacity
mix adapts to system needs
Limits impact of volatility to only unhedged market
participants
Benefit from operational synergies (e.g. 4.5% fuel savings
through dispatch co-optimisation
Risk of reserve payments to be extended beyond the
actual need of the assets, leading to uneconomical
support of stranded assets
May disincentivise the attraction of flexible technologies
Allows one entity to plan and stage shutdown of thermal
plants, benefiting from synergies and learnings
Gives one point of communication for government and
communities
Ensures there are no shock thermal exits but SO
decisions can change wholesale market price outcomes
and investment decisions
Market and regulation already exists and requires no
changes
Requires wide-industry agreement and Commerce
Commission approval
No market change required, but it requires change
of mandate to SO to be able to source and dispatch
capacity, as well as building capabilities
Strategic ReserveThermalCo
$100 million to $150 million per annum
2
. With
utilisation falling, these plants will require
higher prices to recover their fixed costs,
leading to increasing volatility in wholesale
energy prices. Failing to recover these fixed
costs could lead to early closure of some
plants, which would further increase volatility
and system insecurity.
2. Ensuring an orderly transition
To ensure the best outcome for Aotearoa in the
transition to 100% renewable electricity, market
signals will need to continue to attract renewables
as they do currently, while also incentivising cost
effective solutions to guarantee security of supply.
Critically, these signals should provide enough
certainty to develop and fund alternatives.
Decisions on decommissioning individual
assets need to consider cascading effects for
New Zealand. A disorderly exit of thermal assets
may put security of supply and jobs at risk – in
both the power plants and the upstream fuel
2 New Zealand dollars unless otherwise stated
supply industry. Equally important, the lack of
visibility on the long-term outlook in the sector
would delay investments, putting the potential
development of new skilled jobs in regional
New Zealand at risk.
Three potential pathways
to support the transition
improving the status-quo
To maintain the energy trilemma balance we
have studied three market structures used in
international markets: Capacity Markets, Reserve
Payments in energy-only markets, and Energy-
Only markets supported by risk management
products.
In the specific context of New Zealand we
have explored which ownership structures
could better ensure an orderly transition:
Independent ownership, Independent ownership
with Government support, and Consolidated
ownership. The combination of the market
5

structure with their most natural ownership
structure led us to define three potential pathways
to support New Zealand’s transition.
•
S
et up a Capacity Market trading firm
capacity to supply peak demand and dry-year
demand, in parallel to the existing energy
market. All existing and new plants can enter
by bidding in reverse auctions to receive a
fixed, yearly capacity payment ($/ firm MW)
allowing for the recovery of fixed costs;
•

E
stablish a Strategic Reserve where
Government enters into an agreement with
owners of strategic assets to ensure security
of supply. These agreements would confirm
assets are available to provide firm and flexible
capacity in exchange for reserve payments to
ensure recovery of fixed costs;
•
Establish a ThermalCo while maintaining the
existing energy-only market supported by risk
management products. ThermalCo would be
an entity that consolidates ownership of and
operates all thermal assets. ThermalCo’s sale
of risk management products would provide
sufficient capital to cover fixed costs.
Expected outcomes from the
three pathways
Against the dimensions of the trilemma, all
three pathways promote decarbonisation of
the electricity market and help ensure security
of supply. The differences emerged around
affordability, achieving an orderly transition, as well
as implementation feasibility. Exhibit 2 summarises
the comparative merits of each pathway.
ThermalCo: a market-based
pathway for Aotearoa
After exploring the three potential pathways
to keep the energy trilemma balanced
while ensuring an orderly transition for New
Zealand’s electricity market, we propose
the establishment of ThermalCo. ThermalCo
will be an entity that owns and operates all
existing thermal assets and upstream fuel
supply contracts, with the mandate to offer
transparent and liquid risk management
products, while ensuring an orderly phase out
of the thermal capacity when more reliable
low emission technologies become economic.
6

The establishment of ThermalCo
will maintain the energy trilemma
balance as:
• The offer of risk management products to
cover all thermal capacity in an open platform
will be a further evolution of the hedging
market helping to support transparency and
liquidity for all market participants to cover
dry year and peak demand risk;
•

Co
nsolidated ownership of thermal assets
increases the availability of capacity that
could be offered to derivative markets, as
outage risks are spread across a larger portfolio;
•
Security of supply risks, priced through
hedging contracts, will provide the price signal
to incentivise the market-led investments
of the lowest costs, reliable technologies
that address these risks. Long-term hedge
premiums will support dry-year coverage,
while short-term strike prices will provide
arbitrage signals for new flexible capacity;
•
F
ixed costs recovery through premium on risk
management contracts will reduce volatility
of the spot market as only variable costs will
need to be recovered. Most market participants
will likely prefer to cover their risks rather than
be exposed to price spikes, providing a more
equitable distribution of fixed costs.
The establishment of a ThermalCo
will ensure an orderly transition of
New Zealand’s electricity market as:
• Consolidated ownership will provide greater
certainty in the mid- and long-term
demand for thermal assets, allowing for
more effective and coordinated planning
of the transition of these assets when new
technologies can displace them;
•

I
t maintains a stable regulatory framework
that works well today.
We invite support from
stakeholders that want to
collaborate and contribute to
building a market-led solution
for a 100% renewable electricity
market in New Zealand that not
only achieves environmental
targets, but also meets the
challenges of security of supply
and affordability while ensuring
a smooth and orderly transition
for all.
7

Contents
Crafting a path for New Zealand’s
100% renewable electricity market 1
Executive summary 3
A
n opportunity for Aotearoa
to take a leadership position
1
0
Maintaining the balance to
ensure an orderly transition 16
Three potential pathways to
support the transition improving
the status-quo 27
Contact’s preferred pathway:
ThermalCo, a market-based
solution for New Zealand 42
9

Successfully executing on the Government’s
ambition to achieve 100% renewable
electricity presents a unique opportunity
for Aotearoa to take a leadership role in the
fight against climate change. The reduction
in emissions will benefit our people,
communities, and businesses.
Aotearoa’s natural endowments have allowed
the build of a highly renewable and cost-efficient
electricity market over the last century. Between
600mm and 1600mm annual rainfall and
combined with a rugged topography create ideal
conditions for hydro power generation, while our
geothermal resources have seen the development
of one of the world’s largest geothermal power
generation industries. And with most of the
country situated in the roaring forties latitudes,
New Zealand is also well placed to continue
growing competitive wind generation, with
intermittency absorbed by hydro reservoirs.
These conditions give Aotearoa a competitive
advantage over most developed economies
around the world in our drive towards a 100%
renewable electricity system. In the World Energy
Council’s (WEC) Trilemma ratings New Zealand
has the highest proportion of renewables of the
countries rated ‘AAA’ (Exhibit 2). The Trilemma
measures how a country manages the trade-
offs between energy security, energy equity
(accessibility and affordability) and environmental
sustainability. Most other OECD countries seeking
high penetration of renewables will rely mainly on
intermittent wind and solar generation, requiring
significant investments in expensive storage and
flexibility technologies.
An opportunity for
Aotearoa to take a
leadership position
Norway
46%
Luxemberg
Germany
New Zealand
Switzland
S
weden
Finl
and
20%
Italy
Unite
d Kingdom
61%
Spain
38%
Austria
Austra
lia
Iceland
Costa R
Denmark
100%
21%
99%98%
86%
82%
78%
77%
59%
40%
40%
38%
Fr
ance
Source: Enerdata & World Energy Council (https://trilemma.worldenergy.org/)
Triple A rated by WEC
100%
BAA
AAAAAAAAA
AAAAAA
AAA
AAAAAA
AAA
ABA
ABA
AAC
Proportion renewable generation, 2019
Percent
CABCBACAA
AAA
Energy
security
Energy
equity
Environment
sustainability
Exhibit 2: Global comparison of renewable generation and WEC Energy Trilemma rating
10

We are well on the way to 100%
Aotearoa has already demonstrated a willingness
and ambition to lead the world’s decarbonisation
efforts. The Climate Change Response Amendment
Act 2019
3
saw New Zealand become one the
world’s first countries with a 2050 carbon neutral
legislated objective.
In the electricity sector, the 100% renewable
generation by 2030 policy cements this national
goal. Practical actions towards these objectives
are already underway, including:
•
the feasibility study of the New Zealand
Battery Project;
•
the extensive research and modelling
undertaken by He Pou a Rangi, the Climate
Change Commission (CCC)
4
;
•
t
he Electricity Authority Future security and
resilience project; and
• the Ministry of Business Innovation and
Environment (MBIE) work to outline
economically efficient measures to
achieve these goals.
Today, New Zealand is already well on track
toward the 100% renewable electricity goal. In the
last decade, renewable capacity increased from
6.8GW to 7.4GW, mostly driven by wind additions,
increasing the share of renewables in the market
from ~75% to the current ~85%. The market has
proven highly effective in balancing the energy
trilemma with sufficient flexibility to secure supply
during dry-year, winter and intra-day peaks.
However, the final steps on the path to 100%
renewables will be harder to traverse. With the
thermal generation that guarantees the security
of supply having an increasingly lower utilisation
as renewables replace them over the next 5 to
15 years, the risk of uncoordinated phase outs
and volatile prices will increase. These final steps
will require us to bring innovative ideas over the
next few years to continue to balance the energy
trilemma: secure market decarbonisation while
preserving security of supply at the lowest
possible cost. The market will need to provide the
3 Climate Change Commission (2019) Climate Change Response
Amendment act 2019
4 Climate Change Commission (2021), A low emissions future for
Aotearoa
5 McKinsey & Company (2021), Net zero by 2035: A pathway to rapidly
decarbonize the US power system
right signals to ensure an orderly transition where
thermal capacity is phased out as new more cost-
effective technologies come online. This will likely
require investment in diverse generation assets
and new technologies, as shown in recent studies
in global markets
5
.
To do this, New Zealand will need to carefully
craft a path for the transition to meet two
primary objectives:
1.
Maintain its world class balance across the
trilemma, as more renewables economically
replace fossil fuelled generation; and
2.
Ensure an orderly transition of New
Zealand’s electricity market to 100%
renewable generation.
Choosing the right path and implementing well
will not only achieve the underlying value of the
transition, but also unlock additional opportunity
to Aotearoa.
The opportunity for Aotearoa
Getting the transition right presents a unique
opportunity for Aotearoa, benefiting our
environment, people, communities, and businesses.
For the environment, yearly thermal generation
emissions could be reduced by ~1.2Mt C02-e
per annum from 2022 to 2030, in part due to
the addition of ~8.5TWh of new renewable
electricity (according to the CCC). For people and
11

communities, these new renewable electricity
projects can potentially support over 350 new
permanent jobs and 7,500 construction jobs over
the next 10 years, with a strong concentration in
regional New Zealand, as shown in Exhibit 3.
New Zealand businesses are now intensifying
their efforts to decarbonise their operations, as
we are starting to see with dairy processing
6
. For
some industries, decarbonisation can go beyond
reducing costs (coal boiler electrification for
process heat could be cost efficient in the South
Island at carbon prices over $60/tonne), to also
present an upside opportunity. New Zealand’s
largest two sources of export are agriculture
and tourism. Both could benefit from a ‘green
premium’
7
. For example, the green premium
on dairy products could be worth between 5%
and 45%
8,9
of the price paid for certain products.
Likewise, New Zealand’s world class tourism
destination brand would further enhance its
sustainability reputation in the bounce back
from the Covid-19 pandemic. As cross-border
6 Contact energy (2021), Capital Markets Day 2021
7 McKinsey & Company (2020), The ESG premium: New perspectives on value and performance
8 Wei Yang et. al. (2012), Impact of delivering ‘green’ dairy products on farm in New Zealand
9 McKinsey & Company (2021), Prioritizing sustainability in the consumer sector
10 Southern Green Hydrogen (2021), Huge Interest in Southland Green Hydrogen Project
11 Meridian (2020), Datagrid and Meridian partner to build NZ’s first hyperscale data centre in Invercargill
12 NZ Herald (2021), Amazon says it will spend '$7.5 billion' on giant data centres in Auckland
carbon markets emerge over the next decade,
today’s point of differentiation through a green
premium could become a significant competitive
advantage for other industries like agriculture,
metals or manufacturing.
New businesses could also be attracted to
our shores, as the Southern Green Hydrogen
10

project expression of interest demonstrates with
over 80 responses, including from renowned
international companies. Additionally, emerging
industries globally are now showing strong
interest in New Zealand’s clean, reliable power.
The data infrastructure industry is a case in
point, with examples like our contract with
Data Centre company Lake Parime to enter
New Zealand, Meridian’s partnership with
DataGrid to build New Zealand’s first hyperscale
data centre
11
or the recent Amazon Web Services
announcement to open its Aotearoa
New Zealand infrastructure region
12
.
2021
1650
46%
2000
22%
21%
12%
5%
20%
37%
28%
8%
100% Renewables
+23%
GeothermalSolarWindHydroCoal & Gas
1. Does not include construction
≤20
20-50
50-100
100-200
>200
Capacity
MW
GeothermalHydroWind
Employment impacts from shift
Jobs by generation type
1
, jobs (FTE)Generation project by region
at
Source: Press reports; Employment study: solutions on lack of skilled workers in the geothermal sector & results of the questionnaires; Clean energy
at work, Clean Energy Council Report; Internal analysis on Haywood
Exhibit 3: Potential new jobs created in the transition towards a 100% Renewable Market
12

An industry-wide, market-
based pathway towards 100%
renewables
At Contact Energy, we believe decarbonisation
is both an environmental imperative and a great
opportunity for Aotearoa, and this holds strong
to our commitment to tiakitanga – to care for
New Zealand’ tiaki taiao and tiaki tangata. In
early 2021, we refreshed our strategy to lead
New Zealand’s decarbonisation through
‘Contact26’. In line with this strategy, we are
growing demand for 100% renewable electricity
with projects like Southern Green Hydrogen
13
,
while growing renewable development with
the Tauhara power plant, and decarbonising
our portfolio to contribute to contribute to our
100% renewable target.
This report builds on our portfolio
decarbonisation strategic pillar and is the
culmination of our research into crafting a
path towards New Zealand’s 100% renewable
electricity market. Our analysis builds on the
Climate Change Commission’s detailed modelling
13 Contact and Meridian (2021), The New Zealand hydrogen opportunity
of New Zealand’s decarbonisation scenarios,
particularity focusing on the ‘Tiwai stays’ scenario
(see page 15: Research Methodology).
In the report we describe what it will take for
New Zealand to get to 100% renewable electricity
while achieving the two objectives of keeping the
energy trilemma – decarbonisation, security of
supply and affordability – in balance, and ensuring
an orderly transition of fossil fuelled assets. We
examine the challenges the electricity market
faces meeting these objectives; specifically, we
assess potential market structures to address the
challenges and analyse how each would perform
against them. Finally, we offer a proposed path
forward: the establishment of a ThermalCo –
an industry-wide, market-based solution for
New Zealand.
This path is not without complexity; we now
invite the broader New Zealand energy industry
to collaborate in building an industry-wide,
market-led solution that will facilitate
New Zealand's transition away from fossil
fuelled electrictiy generation.
13

How New Zealand’s electricity
market covers consumers
electricity demand
In New Zealand today multiple technologies
compete in a single, energy-only, marginal
market, in which the price is set in 30-minute
intervals by the most expensive generation plant
required to meet consumers' demand in each
time slot. Generally, in the course of a year:
•

T
he baseload demand is covered by ~8TWh
of geothermal and ~1.2TWh of highly efficient
cogeneration power plants;
•

W
hen wind blows, it provides ~3TWh of
generation;
•
T
he remaining gap to meet the demand
is typically covered by stored hydro power
and river flows, which provides the bulk
of our energy generation through the day,
generating between 21 and 27TWh a year
depending on rainfall.
When it is not economic to use hydro, the final
gap to meet demand and cover the hydro swing
(the difference in generation due to rainfall) is
provided by fossil fuelled thermal power plants.
This ‘thermal gap’ (i.e. the share of demand that
needs to be covered with thermal generation)
in a mean hydro year is currently around 4.5TWh
(excluding cogen), but this can fall to ~2TWh in
a wet hydro year, and rise to ~8TWh in a dry
hydro year.
When the power plants cannot cover the demand,
there are ‘demand response’ mechanisms in place.
This is where large scale consumers disconnect
part of their loads to maintain system stability.
Different technologies are currently being
discussed as potential alternatives to using fossil
fuelled generation to cover the ‘thermal gap’ and
winter demand peak in the North Island, including
Lake Onslow, a hydrogen fuelled demand
response, or the conversion of Huntly to biomass.
Hydro (opportunity cost)
Short run marginal cost (SRMC) supply curve
01,0002,0004,0006,0008,0007,00010,0003,0005,0009,000
Capacity, MW
Wind
Cogeneration and
biomass
Geothermal
Thermal
SRMC,
$/MWh
Demand
Price for period
Illustrative short run marginal cost (SRMC) supply curve
14

Research methodology
In this report, we have based all market modelling
on the Climate Change Commission's (CCC)
report: ‘Ināia tonu nei: a low emissions future for
Aotearoa’. This is the Climate Change Commission
advice to Government on climate action in
Aotearoa and details the paths Aotearoa can
take to meet its climate targets. We are using
the ‘Tiwai-stays’ sensitivity as our base case. We
have assumed that a closure of the smelter would
facilitate an equivalent replacement load.
Hydro-thermal stochastic optimisation modelling
was undertaken by Energylink on behalf of the
CCC. We have used the resulting modelling
outputs, at a 3-hourly dispatch granularity.
We have overlayed Transpower energy and
capacity margin methodology to perform security
of supply calculations. LCOEs (Levelised Cost of
Energy) from MBIE and CCC have been used as a
reference for the potential cost of development of
new renewable electricity projects.
Desktop research and internal Contact Energy
analytical capabilities have been used to
investigate and simulate alternative pathways,
in conjunction with the support of local and
international consultants.
15

Maintaining the
balance to ensure an
orderly transition
In the journey towards 100% renewable
electricity, New Zealand will need to
maintain its world-class balancing of the
energy trilemma: decarbonisation, security
of supply, and affordability, while ensuring
an orderly transition of New Zealand’s
electricity market.
New Zealand’s ‘triple-A’ rating in the World
Energy Council’s Energy Trilemma Index
14
reflects
the energy industry’s enviable track record of
maintaining an environmentally sustainable,
reliable, and affordable energy supply. In the last
step of our journey towards a 100% renewable
electricity market, our industry must continue to
get this balance right. Kiwis will expect nothing
less as their electricity demand is expected to
increase faster than in the last 20 years
15
.
14 World Energy Council (2020), Energy Trilemma Index, 2020 Country rankings
15 Climate Change Commission (2021), A low emissions future for Aotearoa
The transition towards a renewable electricity
market will not be straightforward to navigate. Few
countries globally have achieved levels of renewable
power close to 100%, and even fewer operating
in liberalised energy markets. For New Zealand,
the transition approach will need to be tailored
to our very specific needs and unique hydrology
characteristics and resources, while learning from
comparable highly renewable electricity markets
as well as other markets under deep renewable
transitions (see page 24: Learnings from other
markets transitioning to high renewables).
New Zealand’s electricity market is currently
in good shape with a 1GW capacity margin to
cover winter demand and intra-day peaks, and
enough flexibility to meet demand in dry years.
However, this safety net could be jeopardised by
increasing renewables penetration which results
in the utilisation of the thermal fleet halving to
16

below 20% by 2030 (according to CCC modelling).
Lower thermal utilisation makes it more difficult to
recover fixed costs in the spot market. This would
push asset owners to set higher prices in the few
hours they could run the assets, thereby increasing
the market volatility, or in the worst case leading to
an abrupt decommissioning of thermal assets and
putting security of supply at risk.
In the next 10 years, the focus for New Zealand’s
energy industry must be on keeping the trilemma
of decarbonisation, security of supply and
affordability balanced as it approaches the
100% renewable electricity mark.
Maintaining the energy
trilemma balance
Decarbonisation
Decarbonisation of the power sector is well
on track, with ~8.5TWh of new renewables
identified that could be economically
developed by 2030 if demand conditions allow.
Achieving a 100% renewable electricity market will
reduce CO2-e emissions by around 3Mt per year. A
first step towards this goal, as outlined by the CCC,
would be to achieve ~96% renewable electricity
penetration attracting ~8.5TWh of new renewable
generation from 2022 to 2030 (in the Tiwai stays
scenario). The new generation will most likely come
from a mix of geothermal, wind and solar and
would reduce yearly emissions by 1.2Mt.
There are a number of factors that need to be
considered when making an investment in
renewables, including availability of resources,
environmental impacts, network access, grid
constraints and locational risk. There are diverse
renewable electricity resources scattered
throughout all New Zealand’s regions. The main
challenges for renewable electricity projects to
come online will be securing resource consent,
access to the transmission network, avoiding grid
constraints and preventing an overbuild effect
that could cannibalise the output of new projects
in the short to medium term.
The New Zealand nodal energy market
provides the right incentives to overcome
these challenges, as prices in nodes where the
network is constrained, or there is an overbuild of
renewables, will rapidly fall (especially in periods
of high renewable generation). This reduces the
Generation Weighted Average Price (GWAP) and
therefore the attractiveness of new projects.
For new renewable electricity projects to enter
the market, the expected Generation Weighted
Average Price (GWAP) must be equal to or higher
than the expected Levelised Cost of Energy
(LCOE) of new generation. Expected LCOEs for
new renewable generation heavily depend on
location and project specific configurations, with
the CCC estimates for 2021 ranging from:
•
$60-85/MWh for wind (intermittent/unfirmed);
• $70-125/MWh for geothermal (baseload/
firmed); and
• $85-120/MWh for solar (intermittent/unfirmed).
The CCC ‘Tiwai stays’ scenario is projecting
an average wholesale electricity price of
17

$89/MWh
16
from 2022 to 2035 in a mean hydro
year. Other market analysts
17
are also projecting
long-term average electricity prices above
$80/MWh. Expected wholesale energy prices
give an indication that renewable projects with
lower LCOE are already viable (Exhibit 4); this is
supported by projects like Tauhara, Turitea and
Harapaki being announced recently.
The transition towards a 100% renewable
electricity market must ensure these pricing
signals are maintained and market equilibrium
is not lost, to continue to give confidence to
investors and see a growing pipeline of new
renewable electricity projects.
Regulatory and policy uncertainty is another
key risk for a full decarbonisation of the market,
increasing the risk premium for investors. In
markets such as Germany, Italy and the UK
18

this uncertainty has resulted in the temporary
freezing of new investment activity (see page
24: Lessons from other markets transitioning to
high renewables).
16 Real 2021 NZ dollars, referenced off the Haywards Grid Exit Point (GXP).
17 Jarden ~$80/MWh: (2021) NZ electricity generators: with large decisions ahead, sector still stacks up; Meridian ~$80/MWh: (2021) Power
without the carbon?
18 Florian Elgi (2020), Renewable electricity investment risk: An investigation of changes over time and the underlying drivers
Security of supply
To maintain security of supply New Zealand
needs both energy flexibility to address dry-
year risk and firm capacity in the North Island
to cover peak demand. This flexibility needs
to be backed with a reliable and flexible fuel
source until alternative technologies or large-
scale demand response become available.
The transition towards a 100% renewable electricity
market will require new sources of flexibility to
become available to replace the flexibility that
thermal currently provides.
Currently ~5TWh of thermal energy (not including
cogeneration) is required to meet demand in a
mean hydro inflow year (Exhibit 5). According to
the Climate Change Commission modelling, in
the scenario where the Tiwai smelter stays (or
equivalent demand replaces it), further renewable
development will reduce the thermal requirement
by 2030 to:
•
2TWh in a mean hydro year;
• ~4.5TWh in a dry hydro year;
• ~0.3TWh in a wet hydro year.
140
0
60
20
40
80
100
120
2022
GWA
P
2022
LCO
E
2030
GWA
P
2030
LCO
E
100
80
20
0
120
40
60
140
2022
GWA
P
2022
LCO
E
2030
GWA
P
2030
LCO
E
140
0
20
40
120
100
60
80
2022
GWA
P
2022
LCO
E
2030
GWA
P
2030
LCO
E
Main investment driver – GWAP vs LCOE for wind, solar and geothermal $/MWh
GWAP is higher than LCOE
of the lowest cost projects
GWAP is higher than LCOE
of the lowest cost projects
GWAP is higher than LCOE
Wind
1. Generation Weighted Average Price
2. Levelised Cost of Energy
GeothermalSolar
Exhibit 4: Expected Generation Weighted Average Price (GWAP) versus LCOE of new renewable generation
18

In wet years, we should expect there will be
excess energy that cannot be stored, resulting in
spillage of hydro and wind. This excess of spilled
energy results in a decrease in the thermal energy
requirements from wet to dry years (i.e. 'hydro
swing') from 5.2TWh today to 4.2TWh by 2030,
as shown in Exhibit 5.
To provide this large swing in energy it is essential
there is a reliable and flexible fuel source. Currently
this flexibility is provided by the Huntly coal
stockpile, coal imports, domestic gas production,
the Ahuroa Gas Storage (AGS) facility and industrial
demand response. Should coal no longer be a
major contributor to this energy swing
19
, up to
36PJ of gas will be required to generate the
4.5TWh of electricity during dry years. In a mean
hydro year, the gas demand would fall to 14PJ and
in a wet year to just 3PJ. The 33PJ of gas flexibility
required cannot be met from current fuel storage
or contract arrangements, requiring additional
flexibility in both domestic gas production and
from industrial gas users.
Alternatively, new energy flexibility sources able to
store over 4.5TWh of energy could be developed
in the transition, such as pumped hydro storage,
biomass, biogas, hydrogen, or large-scale
industrial demand response.
19 The CCC assumes the Rankine units are closed in 2026
During winter, the North Island experiences peak
electricity demand periods during a few hours
in the evenings, when Kiwis get home and turn
on heaters and appliances. These periods are
especially pronounced in the coldest days of
the year. In a 100% renewable electricity market,
where wind generation is ~20% of total electricity
supply, winter supply could be at risk in the
periods when Kiwis need it most.
We have assessed security of supply using
Transpower’s 'Security of Supply Annual
Assessment' methodology and overlaid the CCC
modelling assumptions. In 2030, peak North
Island demand is expected to be 5,240MW, and
in order to cover the safety margin of 630MW
to 780MW, around 5,870MW to 6,020MW of
firm generation capacity is required. 4,600MW
of firm peak capacity could be provided in the
North Island by new and existing renewables,
cogeneration, batteries and the HDVC
interconnector, according to the CCC. This leaves
a 1,300-1,430MW gap to be covered with thermal
generation or no-carbon alternatives (including
more batteries) to stay within security of supply
safety limits (Exhibit 6). The CCC modelling
assumes 1,150MW of firm thermal capacity is
5
6
0
2
20222420302628
1
3
4
8
7
23252729
Dry
Averag
e
Wet
Thermal energy required (TWh)
5.24.53.84.54.24.14.04.04.2
Swing between
dry and wet
Source: Contact analysis based on CCC data
Exhibit 5: Hydro generation swing
19

available in 2030, which falls short of Transpower’s
safety limits.
To maintain the security of supply in the transition
towards a 100% renewable electricity market,
New Zealand must ensure enough flexible fuel
is available in the system to meet the dry-year
risks, while enough capacity remains online to
cover winter peak demand periods. This would
require thermal operators to continue to maintain
plants for long periods of time while they are not
generating electricity. A predictable and stable
revenue stream for thermal operators would
enable them to cover the ongoing maintenance
costs over these periods when they are not
earning revenue in the wholesale spot market.
Affordability
Competitive market pressure will be necessary
to achieve decarbonisation and security of
supply at the lowest cost for customers
The current wholesale market does provide the
right price signals to attract new renewable
electricity projects and investment that
outcompete more expensive thermal generation.
20 Jarden (2021), NZ electricity generators: with large decisions ahead, sector still stacks up
21 WSP on behalf of MBIE (2020), 2020 Thermal Generation Stack Update Report
22 Contact Energy (2021), 2021 Full Year Results
23 Genesis (2021), Annual Report 2020-2021
If demand growth outpaces supply growth then
prices rise, which sends a signal to increase
investment (and prices fall if supply growth
outpaces demand).
However, New Zealand will also have to keep
thermal capacity online until other flexible
generation sources are available to ensure
security of supply. Today, the 1,900MW of thermal
capacity available (excluding cogen) requires
$100 million to $150 million of spending to cover
fixed costs
20,21,22,23
every year to keep operating,
which represent $2-3/MWh for the entire market.
Fixed costs are recovered during the hours when
they operate, but this will become increasingly
challenging as more renewable generation enters
the market and drives prices down. The Climate
Change Commission projects utilisation of gas
peaking plants dropping <15% most years
(Exhibit 7), requiring higher prices (above >$400/MWh
in median years) to cover their fixed costs.
The challenge of recovering these costs over
fewer and fewer periods will lead to increasing
price volatility in the wholesale spot market.
The impact of this is an less stable environment
Current NZ winter capacity (NI), MWPotential capacity supply solutions for 2030
ActualOptimal rangePeak demand
150-300MW
gap
2030 capacity
investigated
Source: CCC Modelling
Winter capacity margin in CCC Demonstration
27202024
2.5
2125222326
4.0
28292030
3.0
3.5
4.5
5.0
5.5
6.5
6.0
6.0
3.0
5.5
2.5
3.5
4.0
4.5
5.0
6.5
7.0
0.1
New embedd-
ed
0.1
0.2
New Battery
0.9
E
xisting RE (mean
hydro) & cogen
HVDC
Whirinaki
0.4
E3P
0
P40
0.1
0.1
0.2
Junction Rd
0
Stratford peak
ers
0.2
0
McKee
2.9
Rankines
0.6
New Peaker
New RE
TCC
+1.3-1.4
Thermal Capacity
Efficient capacity margin of 630-780MW over Peak Demand
Peak demand 5,240MW
Firm capacity
Peak demand
Optimal range
Huntly Rankines retiredTCC retired, Tiwai stays
1.3 – 1.4 GW required to reach the
optimal capacity margin without
taking into account thermal capacity
Exhibit 6: Capacity margin evolution
20

for all stakeholders that may increase
prices for consumers:
• Thermal asset owners would be facing
higher carbon prices and the prospect of not
recovering fixed costs in some years (when
rainfall is above mean). There may also be
higher operational risk of their assets, given
the greater impact of unplanned outages
on the decreasing hours of utilisation. The
increased risks will likely result in an increase in
risk premiums that would be reflected in the
derivative markets, raising cost for consumers.
•

A v
ery volatile market creates an unstable
environment for renewable electricity
investors – who in general seek predictable,
stable cash-flows in markets with regulatory
stability. Exposing New Zealand’s energy
market to high volatility and potential risk of
regulatory intervention could see renewable
investments slow down. New renewable
projects are often underwritten with Power
Purchase Agreements (PPAs) which provide
a stable cashflow for the generation output,
however greater regulatory intervention risks
may limit buyers' appetites to enter into long
term, fixed price agreements. Furthermore, in
markets with high volatility and uncertainty
the risk premium on any hedge products
would rise, increasing the cost to consumers.
Sustained high volatility can be a market signal
for the investment of flexible ‘green’ energy
solutions, however these can take years to
design, fund, and build with consumers and
retailers incurring high costs in the interim.
•
Volatility and exposure to sustained periods
of high wholesale prices would also increase
pressure on energy purchasers and retailers,
who may not have the ability to rapidly pass-
through market changes to customers as a
mechanism to keep their books balanced.
Retailers would also price the risk derived from
volatility into their tariffs, which may result in
higher costs for consumers. At the extreme,
this could lead to a similar situation where
small retailers that could not adequately cover
their market risk exposure due to an extreme
and sustained price increase, like seen in
Australia or the United Kingdom.
No-carbon alternatives to thermal generation
are emerging as technology evolves. Over recent
months, we have seen different analyses and
proposals from Concept Consulting, Genesis,
Meridian and MBIE focusing on which technologies
could best substitute the current thermal asset
base. The portfolio of solutions that could be
applicable in New Zealand are aggregated in
Exhibit 8. While today maintaining the existing
fleet seems to be the most affordable option,
batteries, green fuels in existing plants, large-
scale demand response (e.g. in hydrogen) or
Exhibit 7: Long-run marginal cost of gas peakers under different utilisations
21

pumped hydro appear likely to be the key potential
competitive candidates by the end of the decade
and possibly sooner.
New Zealand must ensure volatility and market
uncertainty is properly managed during the
transition. This will maintain the market signals
needed to attract the most efficient investments
in technologies to cover both bulk energy supply,
dry-year and winter peak demand. Providing
greater certainty and equitably sharing the
fixed costs required to ensure security of supply
would be the most effective way to keep energy
affordable for consumers, while attracting new
technology investments in a timely manner will
reduce overall system costs.
TechnologyDescriptionProsCons
Fossil Gas
Peaker
Retain a small amount of gas-fired
peaker generation in the North Island
in combination with other sources of
flexibility e.g. batteries, DSR1
Low fixed costs
Located in North Island matching
demand
Carbon emissions
Green PeakerConvert gas-fired peakers to run on
biofuel
Scalable as per demand
Neutral carbon emissions
High fuel costs
Coal reserveRetain the coal-fired Huntly station,
but only run when lakes are low
Located in North Island matching
demand
Carbon emissions
Not as flexible as other
technology
Renewable
electricity
overbuild
Size renewable electricity capacity
to have just enough in periods of
scarcity and spillage in periods of high
renewable electricity output
Larger share of firm capacity provided
by renewable electricity
Spillage increases
consumer prices
(needs to be partially
paid back to asset
owners)
Hydrogen /
Aluminium flex
Set up a large scale demand response
from a hydrogen production facility
or the Tiwai aluminium smelter,
e.g. curtail plant demand based on
opportunity cost between electricity
and commodity price
Low capital cost
Large scale resource
Good fit with renewable electricity
Located in South
Island
Pumped hydroBuild a pumped hydro storage facility
in the South Island that pumps
water up to the reservoir at times of
renewable electricity excess
Large scale resource
Good fit with renewable electricity
High capital costs and
low efficiency
Located in South
Island
Long development
times
Green RankinesRun the existing 500MW Rankine
cycle plant (units 1,2,4) on biodiesel,
biomass, or green hydrogen fuel
Scalable to demand
Neutral carbon emissions
Existing generators
High fuel costs
Exhibit 8: Potential decarbonisation solutions
22

• Price volatility would be exacerbated,
Whilst this would send a signal to increase
investment in alternative technologies, a
'disorderly' transition would see market risk
premiums increase as a result of the price
volatility, which could make energy less
affordable during the transition;
•
S
ecurity of supply may be compromised, or
may be provided by more costly alternatives
to thermal (until alternative technologies are
developed and the market finds its long-term
equilibrium);
•
The upstream fuel supply would suffer from
lack of demand certainty, potentially leading
to delays in investments required to guarantee
a secure fuel supply.
We believe the current market structure will
provide the price signals to incentivise the
new investment required, however the sort
of outcomes we might see from a disorderly
transition may tempt regulators to intervene.
Any intervention that blunts pricing signals will
have a cascading effect on investment decisions,
creating even more pressure on regulators.
Conversely, providing transparency and visibility
through a more coordinated decommissioning
plan will alleviate most of these challenges,
making the transition smoother. Risks will be
lower for thermal asset owners which will help to
keep volatility within acceptable levels that will still
attract the required investments. Transition plans
for the people and communities will be made and
coordinated with the development of alternative
economic activity in the regions, and there will be
certainty for the upstream fuel supply industry.
Ensuring an orderly
transition for New Zealand
An orderly transition for New Zealand’s
electricity market avoids the cascading
impacts that uncoordinated decisions
on assets can have on security of supply,
affordability, jobs and investments.
New Zealand’s transition to 100% renewable
electricity is going to be one of the first in the
world, especially amongst liberalised electricity
markets. Market signals will need to continue to
attract renewables as they have to date, while also
incentivising cost effective solutions to guarantee
security of supply. These signals should herald
a smooth transition of assets, providing enough
certainty to find alternatives, and should evolve
together with the market requirements and
technology improvements to ensure an approach
that benefits all of Aotearoa.
With thermal asset utilisation under pressure,
there is a growing risk in decommissioning
decisions being taken by individual asset owners
who do not want to carry the risk of increasingly
uncertain cost recovery. Uncoordinated
decommissioning would have cascading
effects for New Zealand:
•

T
here may not be sufficient time to create
robust transition plans for the people,
regions and communities that depend
on these assets – resulting in a lack of
readiness of alternative technologies to
mitigate the energy security risk; and/or
inadequate planning and development of
new opportunities, for example jobs in new
industries or in the construction phase of
alternative energy solutions;
23

Learnings from other markets
in the transition towards high
renewables
New Zealand is not alone in managing
the complex set of trade-offs required to
transition to a renewable electricity market.
Governments across the world are taking
action and pushing legislation to address
the transition issues, such as the
implementation of Capacity Markets or
Reserve Services offered by the System
Operator (SO). Understanding the impact
of different pathways taken by other
countries and taking key learnings from
each international experience can help
New Zealand get the transition right.
Capacity Market in the United
Kingdom got off to a bumpy start:
low prices and 1 year suspension due
to legal challenges
In the UK capacity was expected to drop
significantly due to the closure of several firm
capacity power plants. In 2014, the government
approved the implementation of a technology-
neutral Capacity Market, with the official delivery
start in 2018 and the objective to maintain the UK
capacity margin within a safety range.
However, by the end of 2018, the Capacity Market
was suspended by European Court of Justice after
a legal challenge alleging it discriminated against
demand response. As a consequence, £1.1 billion of
contracts awarded in 2014 with expected delivery
between October 2018 and September 2019 were
at risk.
A review from the Institute of Energy Economics
and Financial Analysis calculated the scheme
had cost ~NZ$7.4 billion, with 83% of the funds
going to operators of existing power plants, and
only 3.5% awarded to operators to build new
generation.
There are three key learnings for New Zealand:
•
A capacity market takes time to implement
and deliver impact (4+ years to reverse capacity
margin downward trend in the UK), making it
less suitable as a transitional measure.
•
It does not ensure regulatory certainty as it is
exposed to constant scrutiny of the regulator to
ensure fair competition among technologies,
putting investments at risk if suspended
•
It limits the intake of new capacity in the
market if clearing prices are not sufficiently
high (a significant share of capacity awarded
in the UK was from existing generation).
Germany opted for a SO-owned
Strategic Reserve which had to
continuously evolve the services
offered to accommodate market
needs
The German government has had a complex
decade as it pursues an accelerated transition
agenda which requires the closure of its large fleet
of brown coal and nuclear power plants. Germany
faced the same two fundamental issues that
New Zealand does: how to maintain a balanced
24

market with increasing renewables while ensuring
a fair transition away from thermal assets.
Germany has avoided capacity markets, stating
that they ‘can be expensive and inefficient.’
1

Instead, it has relied on new reserve markets
where energy imbalances are traded intra-day to
ensure the market remained balanced. There are
currently four different types of Reserve Markets:
Grid Reserve, Capacity Reserve, Safety/ Climate
Reserve and Special Grid Reserve.
In some cases, reserve markets or services
implemented have been proven unnecessary.
For instance, in 2015 Germany established a
strategic reserve of eight brown coal generators
to help stage the thermal shutdowns. Under
this scheme the generators were mothballed
and kept separate from the market, only to
be used in an extreme event where all market
options had been exhausted. This was done at
a cost of ~€230 million a year, with the intention
of ensuring that some firm thermal capacity
remained in the market. The fear of all thermal
capacity rapidly exiting the market proved to
be unfounded, and now in 2021 Germany is
holding reverse auctions in which the remaining
coal generators bid their minimum price to
shut voluntarily.
Further, market changes can lead to high volatility
if pricing design is not done correctly. In 2018
due to some market inefficiencies, Germany
introduced a new ‘mixed’ pricing system. This
led to a sevenfold increase in reserve price
and increased the number of events requiring
intervention. Within 2 years Germany reverted to
their original pricing system.
1 Clean Energy Wire (2016), Germany’s new power market design
There are two key learnings for New Zealand:
• A strategic reserve market requires iteration
and continuous evolution to achieve a
balanced market
•
It relies on the planning and optimisation
capabilities of the SO, which could lead to
unnecessary intervention given the limited
price signals from the market.
Australia is proposing a capacity
mechanism based on mandated
peak capacity coverage from
retailers
Australia has an Energy-Only wholesale market,
similar to New Zealand. Recently, the Energy
Security Board (ESB) proposed to establish the
Physical Retailer Reliability Obligation (PRRO).
Under this new scheme (PRRO), capacity
certificates would be allocated to physical
resources based on their expected availability
during supply stress periods. Liable entities
(retailers and consumers) would be required to
hold sufficient capacity certificates (rather than
sufficient qualifying financial contracts) to cover
their share of actual peak electricity demand.
This aims to provide investment signals to timely
increase capacity or orderly phase it out.
The Australia ESB proposal is very similar
to how ThermalCo would operate, with the
main difference being how the PRRO will be
established as a new regulated market, while
ThermalCo would rely on existing derivative
markets backed by the high amount of flexibility
already available in New Zealand. This proposal is
currently under review and impact on the system
is still unknown.
25

We have explored three alternative
pathways that could keep the energy
trilemma balanced whilst transitioning
to a 100% renewable electricity market:
1.
The setup of a Capacity Market
maintaining current asset ownership
structure
2.
The establishment of Strategic Reserve
with support from Government
3.
T
he establishment of a ThermalCo which
consolidates all thermal assets operating
in an Energy-Only market supported by
risk management products.
Market structures to keep the
trilemma in balance
In the previous chapter we have considered how
the market might evolve under the status quo.
Under the status quo there is a risk of a disorderly
transition which leads to sub-optimal outcomes
for affordability and security of supply. In this
chapter we explore three alternative market
constructs to support the energy trilemma
balance in New Zealand, drawing from examples
in international markets (see Exhibit 9) as they
transition to high shares of renewables: Capacity
Markets, Reserve Payments and Energy-Only
Markets supported by risk management products.
Energy Markets connect generators and
purchasers to trade energy in MWh, and are
often negotiated in the short term, close to
delivery as the generation and consumption
certainty increases. Long-term contracts and risk
management products are available, driven by
risk aversion of purchasers to high market prices
or the need to ensure long-term price certainty,
offering multiple ways to source the electricity
linked to its physical delivery in the energy spot
market. This market structure is reflected in this
report as the Energy-Only Market and is the one
in place in New Zealand today.
Capacity Markets trade capacity in MW and
usually connect generators, procuring long-
term stability in their investments, with market
operators, regulators, or governments seeking
to secure the system stability in the mid- and
long-term. Some countries, like the UK, Italy and
France, leverage Capacity Markets together with
the energy market, to maintain security of supply
in the long term while ensuring efficiency in the
short-term dispatch. In this report we refer to this
combination as the Capacity Market.
Other countries like Spain, Germany and the
Nordics (NordPool market) have a predominant
Energy-Only Market supported with additional
strategic reserve mechanisms to maintain system
stability. Strategic reserves can be articulated
differently depending on the level of regulation
in place. A more regulated setup with discrete
government intervention is what we refer to in this
report as the Reserve Payments structure.
Three potential
pathways to support
the transition
improving the
status-quo
27

Exhibit 9: Market structures in Europe, 2021
Source: ACER based on information from NRAs and the EC, National Regulator's, TSOs; S&P Global Platts; Press Miteco; BMWi, Next Kraftwerke;
RWE; Press; Elia
Strategic reserveCapacity marketEnergy only
a
;
-
Iceland
Energy only market since 2003.
It is 100% renewables with ~75%
Hydro and 25% geothermal
Norway
Is part of the Nord Pool energy only
market. It is made up of ~99%
renewable energy, generated from
largely hydro power (95%) and wind
France
Capacity requirements in place
(capacity market operational since
2017). Capacity certificates traded
through organised market
sessions or OTC transactions
Germany
Grid reserve for pronounced
(regional) high-demand situations
Capacity reserve as main future
element with 2 GW (technology
neutral) procured by SOs every 2 years
2.7 GW lignite-fired power plants in
reserve
SOs procure a total of I.2 GW active
power via tender
Spain
Capacity payments (since
2008) comprising investment
incentives (only for generation
capacity installed before 2016)
The minister considers new
capacity mechanism as a key
instrument for meeting the
objectives of the Energy Storage
Strategy (20GW by 2030)
Italy
Capacity market since 2019: first 2
auctions for 5.8 GW new capacity were
held in November 2019
35 GW of existing capacity were
auctioned respectively for 2022 and
2023 delivery period
Ongoing discussions about new
tenders for the delivery period
2024-2025.
High-level overview of capacity mechanisms in Europe in 2021
Thermal ownership structure to
ensure an orderly transition of
New Zealand’s electricity market
In the specific context of New Zealand, which has
a relatively small share of thermal capacity left in
the market, we have explored which ownership
structures could better ensure an orderly
transition for the electricity market and for the
people of New Zealand: Independent Ownership,
Independent Ownership with Government
support, and Consolidated Ownership.
Independent Ownership refers to maintaining
the ownership of existing thermal assets
by independent companies. Independent
Ownership with Government support involves
the Government entering into bi-lateral
deals with thermal asset owners to agree on
decommissioning dates and plans. Consolidated
Ownership refers to the consolidation of existing
thermal assets and its fuel supply contracts into
a single entity.
Defining three potential
pathways to support
New Zealand’s transition
The combination of the market structure
constructs with their most natural ownership
structure led us to define three alternative
pathways to support New Zealand’s transition:
1.
Set up a Capacity Market, based on continuing
the Independent Ownership of the assets
2.

E
stablish a Strategic Reserve, based on
Independent Ownership with Government
support
3.
Establish ThermalCo, based on Consolidated
Ownership.
These pathways and the combinations of market
structures that led us to them are outlined in
Exhibit 10.
Below we outline each pathway in detail: Capacity
Market, Strategic Reserve and ThermalCo. We
then review the effectiveness of each in solving
the trilemma of decarbonisation, security of supply
and affordability, as well as how the pathways
contribute towards an orderly transition. Finally, we
assess the implementation feasibility of each.
28

Set up a Capacity Market
Under this pathway, New Zealand would set up a
Capacity Market to work jointly with the existing
energy market, leaving the current Independent
Ownership structure untouched.
The Capacity Market would remunerate power
plants for the capacity they provide to the market,
instead of for the energy they generate. The
objective is to incentivise the installation and
maintenance of firm capacity in the market, in
exchange for fixed payments ($/MW) that are
organised through auctions. These auctions
ensure that the most cost-effective capacity is
operational in the market to cover demand (winter
peak and dry year demand) in the mid and long
term. In capacity markets, contracted capacity
will need to provide the required firm electricity
in periods defined by the System Operator. The
demand for capacity would be set by the System
Operator (SO), which would decide the frequency
(typically yearly) and duration of capacity
payments (typically with auctions ranging from
1 year to 10 year offers).
All existing and new power plants could bid
into these auctions to offer their firm capacity
contribution (calculated by System Operator) and
be entitled to receive the capacity payments if
they are awarded. The total cost of the Capacity
Market would be passed to customers in their bills
through a Capacity Market levy.
Power plants still participate in the energy market
to cover their variable costs and capture additional
returns not covered through the capacity
payments. Also, asset owners maintain ownership
and dispatch control of the asset, which is still
driven by short-term market signals.
The Capacity Market approach has been one
of the most common mechanisms in Europe
to mitigate the impact of an abrupt increase
of renewables penetration, given the ambitious
targets set by the European Union. Capacity
Markets are a fundamental shift from an
Energy-Only market and are used to solve
structural market deficiencies. This market
typically takes a long time to achieve results,
especially when capacity markets are added
to operational energy markets as both markets
need to operate in conjunction, providing the
right signals for both the short and long term
to achieve efficient outcomes.
Exhibit 10: Three pathways for New Zealand’s transition
Market structure
Keep the energy trilemma
balance
Identified pathways
1
Capacity Market: Introduce a
new market for firm capacity
to operate in parallel with the
energy market
Reserve Payments: Pay for firm
capacity centrally through the SO
or market operator
Energy only market: Maintain
the energy market and support
the price insurance product
market
Thermal ownership structure
Ensure an orderly transition
for thermal assets
2
Independent ownership:
Maintain current ownership
structure
Independent ownership with
Government support: Set up
individual agreements between
Government and asset owners
Consolidate ownership:
Consolidate thermal assets into
one company with a mandate to
manage the transition
Independent ownership:
Maintain current ownership
structure
Set up a Capacity Market
Establish a Strategic Reserve
Establish ThermalCo
Status Quo
29

Establish a Strategic Reserve
Under this pathway New Zealand would establish
a Strategic Reserve anchored on existing thermal
assets. The ownership structure could:
•
m
aintain existing Independent Ownership
complemented by targeted Government
support; or
•
be consolidated as a single Strategic
Reserve company.
Strategic Reserve would be supported by Reserve
Payments, which are long-term contracts between
strategic asset asset owners and the Government or
System Operator. These contracts are designed to
ensure assets are available to provide firm and flexible
capacity in exchange for a payment to cover fixed
costs. The process to award contracts can be through
regular auctions or tenders, or negotiated bilaterally.
The objective is to provide a stable source of income
to strategic assets to keep sufficient capacity in the
system, so they remain operational when the system
needs them. The duration and eligibility of assets
would be at the discretion of the Government or SO.
Typically, these reserve mechanisms come with
specific guidelines on how the power plants
receiving these payments can operate in the
energy market. For example, in Germany or the
NordPool (the common energy market for all
Scandinavia), the power plants receiving reserve
payments can only operate in the market if
dispatched by the System Operator. This would
happen only in situations when supply is scarce,
and the variable costs of operations will be
recovered at an agreed price. New Zealand had
24 MBIE (2015), Chronology of New Zealand Electricity Reform
a system similar to Strategic Reserve, through
the Whirinaki power plant. This approach was
eventually discontinued in 2010 as it reduced
incentives on market participants to manage their
own risk, distorted market signals for investments
on new capacity, and caused regulatory
uncertainty according to the Ministerial Review of
the Electricity Market
24
Ownership of assets subject to reserve payments
vary by country. In some implementations, System
Operators or government owned Strategic Reserve
companies are established to isolate these plants
from the rest of the market, as is the case for
some specific reserve services in Germany (such
as Climate or Safety Reserves). In other scenarios,
such as in the NordPool example in Scandinavia,
ownership of the strategic power plants is private
with large utilities, large industrial consumers,
energy purchasers or financial investors being
the owners of these assets. For New Zealand, we
explored pathways where thermal asset ownership
is maintained with bilateral government support or
consolidated with government support.
There are examples of Strategic Reserve
approaches which fall mid-way between a
Capacity Market and Reserve Payments, such
as the availability payments approach used in
Spain. In these schemes, the government pays
a fixed payment to selected plants that provide
availability in times of scarcity, but it is done at
the regulator’s discretion instead of following the
auction-based, market-wide process characteristic
of Capacity Markets. For the purpose of this
report, the Strategic Reserve pathway takes the
more stringent definition of this approach in
30

the comparison of alternatives, acknowledging
that certain implementations of it could provide
outcomes that are mid-way to capacity payments.
Establish a ThermalCo
ThemalCo builds on New Zealand’s existing
Energy-Only Market structure supported by
financial risk management contracts to guarantee
long- and mid-term energy supply. The main
difference of ThermalCo versus the status-quo
would be the establishment of an independent
vehicle that consolidates ownership and
operates all existing thermal assets and upstream
fuel supply contracts, with the mandate to sell
transparent and liquid risk management products
(for both dry-year and peak demand) to all
purchasers, while ensuring an orderly phasing
out of the thermal capacity when more efficient
technologies emerge.
Under a ThermalCo, upfront revenues to asset
owners are obtained from risk management
products (see Exhibit 11), which will also deliver
sufficient returns on the assets to recover fixed
costs. As the transition unfolds and new flexible
technologies emerge as a competitive alternative
to thermal assets, purchasers will reduce the
number of hedges with ThermalCo, gradually
phasing out thermal capacity.
ThermalCo targets electricity purchasers willing
to hedge their exposure to dry years and demand
peaks. ThermalCo purchasers will hedge their
exposure in advance by buying risk products
that, at a certain strike price, can be called so that
ThermalCo covers the customer consumption.
Risk products offered to ThermalCo customers
would cover long-term and short-term needs,
with hedging fees directly proportional and strike
prices inversely proportional to product tenure
(e.g. long-term products will be composed by a
high hedge fee and a low strike price).
The Consolidated Ownership structure could
be composed of current thermal asset owners,
private/ infrastructure investors and potentially
other stakeholders in the power sector interested
in being part of it, such us retailers, large
consumers, or other generators.
ThermalCo builds on New Zealand’s existing
regulations and draws on the types of products
that have worked well in the past, adding the latest
industry trends around asset type specialisation.
Recent European examples show how major
utilities are de-merging thermal assets, (such
as E.ON), which are then being consolidated in
companies that aim to focus on providing flexibility
or managing thermal assets, like Uniper or Fortum
(see page 41: Consolidation of thermal portfolios).
$0/MWh
$50/MWh
$100/MWh
$150/MWh
Spot price
Strike price
Retailer pays spot
price for electricity
Retailer pays spot
price for electricity
Retailer pays the strike price
for the price insurance product
($80/MWh in this example) and
ThermalCopays the remainder
to get to the spot price
Time
ThermalCo pays
Retailer pays
Price insurance products allows a retailer to set a maximum price for electricity that they expect to
purchase, regardless of the spot price
Exhibit 11: Example of the mechanics of price insurance products
31

Comparing expected outcomes
from the three pathways
Below we explore how these three pathways
could support New Zealand’s energy trilemma
balance in an increasingly renewable electricity
market while ensuring an orderly transition for the
electricity market. A synthesis of these findings is
shown in Exhibit 12.
Maintaining
balance
in energy
system
Definition
Capacity market operates
in parallel to energy market
through capacity auctions,
remunerating available
firm capacity through fixed
payments ($/MW)
Demand for firm capacity
defined by SO and open
for new and existing
generators
Consolidation of existing
thermal assets into an
entity to offer risk
management products
to market participants
Continuation of existing
market dynamic driven by
energy only market supported
by hedging products
Establishment of contracts
between SO and strategic
assets to provide firm
capacity to the system
through regular auctions or
LT contracts
Dispatch typically regulated
and limited to emergency
situations
Decarbon-
isation
Creates a new revenue
source for renewable
energy, but this may be
minimal for intermittent
generation projects
Maintains energy market
price signals to attract
new renewable projects in
the locations where they
are most needed through
nodal pricing
Maintains energy market
price signals to attract new
renewable projects, with
moderate risk of muting
scarcity price signals which
attract investments in
clean flexibility
Security of
supply
Ensures sufficient capacity
is in the system through
capacity payments but
does not provide assurance
that capacity will actually
be available when required
Market participants pay for
risk management products
to ensure their energy needs
are covered, incentivising
enough capacity to remain
in the system
SO ensures security
of supply by directly
contracting (reserve
payments) with strategic
assets
Energy
Affordability
Skews incentives for least
cost generation through
introduction of new value
stream
Does not always result in
lower energy prices, due
to the introduction of new
system costs
Does not benefit from
operational synergies of
existing assets
Market dynamics put
downward or upward
pressure on risk
management product
pricing to ensure capacity
mix adapts to system needs
Limits impact of volatility
to only unhedged market
participants
Benefit from operational
synergies
Risk of reserve payments
to be extended beyond the
actual need of the assets,
leading to uneconomical
support of stranded assets
May disincentivise the
attraction of flexible
technologies
Orderly transition
Does not directly
guarantee the staged
and planned shutdown
of thermal plants, but
it provides long-term
transparency through
market results
Allows one entity to plan and
stage shutdown of thermal
plants, benefiting from
synergies and learnings
Gives one point of
communication for
government and communities
Ensures there are no
shock thermal exits but
SO decisions can change
wholesale market price
outcomes and investment
decisions
Feasibility
Requires a new market
to be introduced and
regulated, which typically
needs years to find an
equilibrium
Market already exists and
requires no changes.
Requires wide-industry
agreement and Commerce
Commission approval
No market change
required, but it requires
change of mandate to SO
to be able to source and
dispatch capacity, as well as
building capabilities
Positive contributionModerate contributionMinor contribution
Exhibit 12: Comparison of pathways for New Zealand's transition
Capacity marketStrategic ReserveThermalCo
32

Renewable electricity investment
attraction
Emissions reduction will be mainly achieved
through the substitution of thermal capacity with
renewables. Renewable electricity investment
is expected to occur under the current market
structure, driven by the investment conditions
already described in Chapter 2 such as market
prices and grid stability.
ThermalCo and Strategic Reserve would both
help maintain the balance in the system by
securing sufficient capacity to ensure security
of supply. ThermalCo would secure capacity
based on purchasers’ willingness to hedge their
risk exposure; while the Strategic Reserve would
secure capacity based on thorough analysis of
the system needs. On the other hand, Capacity
Market would need to coordinate capacity needs
determined by the System Operator with the
energy needs defined by the market, which
could pose some challenges to strike the right
technological balance at different points in time
as the transition progresses.
All three pathways should increase certainty
in revenues: ThermalCo through long-term
risk management products, Strategic Reserve
through long-term contracts with asset owners,
and Capacity Market directly through fixed
payments on capacity, which could include
renewable plant.
Overall, all pathways would drive investment in
renewable electricity by maintaining the market
equilibrium, although Capacity Market will
require an additional effort to coordinate capacity
(incentivised by the capacity payments) with
energy needs to avoid oversupply.
Emissions reduction through
operational efficiency
Beyond the increase in renewable penetration,
emissions can also be reduced by increasing the
efficiency of the thermal capacity operating in
the market.
Increasing the overall thermal efficiency of
the market would require a joint optimisation
approach with all assets participating to
determine the optimal operation point of the
whole portfolio. That could be achieved if thermal
assets are consolidated into one portfolio to
ensure that the next thermal MWh is delivered
by the cheapest plant/asset available.
It should be noted that in New Zealand players
already optimise their thermal portfolio by
establishing bilateral agreements to cover
Heat rate (GJ/MWh)
Two generators running
to produce 150MW at an
average of ~12.2GJ/MWh
One generator running
to produce 150MW at an
average of ~11GJ/MWh
In this example 10% fuel savings
can be achieved by moving to
one generator
Unit 3Unit 1Unit 2
Illustrative scenario
Total impact in the system
from July 2020 to June 2021
could be:
~4.5%
$18M
gas and CO2
costs avoidance
0350300150
15
50250
20
100200400450
0
5
10
25
30
35
MW
emissions
reduction
Exhibit 13: Potential operational efficiency gains
All pathways would support
market decarbonisation, with
additional upside from Consolidated
Ownership of thermal assets
33

demand more efficiently. This is demonstrated
by tolling deals between thermal generators,
25

where a CCGT plant from one generator
displaces another generator’s peakers. This
clearly indicates an appetite among players
to optimise their thermal asset base and the
desire to seek innovative solutions to reduce
fuel consumption and carbon emissions. The
advantages of consolidated ownership are that
these synergies occur by default, with much
lower transaction costs.
Exhibit 13 illustrates how two assets operating
at the same time at a non-optimal heat rate
could jointly balance their production to achieve
a higher efficiency. Over the last 12 months an
additional $18 million
26
could have been saved
through fuel savings and reduced emissions
(from a 4.5% efficiency increase) if the whole
portfolio of gas peakers and CCGTs were
25 Contact operating report (2019)
26 This is a theoretical value and may not account for all real time operational constraints
optimised as a single fleet. This assumes there
are no operational constraints, so is likely to be at
the upper end of the potential synergy gains. Out
of the three pathways, ThermalCo and Strategic
Reserve would be best positioned to capture
these operational synergies available through
consolidated ownership. In a Capacity Market,
the optimisation continues to be carried out
separately by each asset owner, and ownership
consolidation appears less likely.
At a global level, there is also a trend to de-
merge thermal assets and consolidate them
into specialised vehicles or companies. This is
done to achieve a higher operational efficiency,
and to isolate the carbon footprint from other
business and project a more sustainable image
to the market (see page 41: Consolidation of
thermal portfolios).
Status quoCapacity MarketStrategic ReserveThermalCo
Remuneration
mechanism
to maintain
capacity
Spot market, e.g.
continuous energy
markets combined
with frequency
markets
Government auctions
with fixed payments
per MW of firm capacity
installed/ maintained
and spot revenues
LT contracts with SO
with regulated fixed
return on assets and
pass through OpEx at
an agreed cost
Sales of risk management
products with target
return on assets
Capacity phase-
out drivers
Determined
by spot market
revenues and some
bilateral hedging
Determined by
government planning,
e.g. duration of capacity
payments to maintain
capacity
Determined by SO
based on expected
system balancing needs
and portfolio stress-tests
to identify capacity gaps
Determined by market
demand for swaptions
(e.g. profile hedges) and its
competitiveness versus
other flex technologies
AdvantagesIncentivises capacity
to be delivered
by the cheapest
technology
available
Secures capacity as
long as there is political
will
Maintains capacity and
fuel storage based on
a central view on the
system needs
Maintains capacity and
ensures smooth phase-
out to cheaper sources of
flexibility
DisadvantagesSecurity of supply
is less certain,
especially during
the transition to
renewables
Does not avoid a
potential excess of
thermal (and other)
capacity sitting idle
in the system or
incentivise fuel storage
for dry-years
Abrupt phase out based
on the termination
of LT contracts and
potential to undermine
investment incentives
Capacity installed
depends on purchasers
understanding of load
and flexibility needs
across time
Solves
for...
Dry-
year
Winter
peak
Exhibit 14: Pathway outcomes by hydro variability
Does not solve Partially solves Solves
34

Implementing the Capacity Market pathway
would secure capacity through System Operator
organised auctions. Auctions could vary in terms
of duration of capacity payments, time ahead
of the delivery and frequency. Asset owners are
incentivised to keep their assets running or to
install new capacity, as fixed costs should be
recovered by fixed payments and variable costs
can be recovered in the energy market. However,
due to the trade-off between complexity and
effectiveness, a Capacity Market would typically
take more than 5 years to achieve results, as seen
in the United Kingdom.
The ThermalCo and Strategic Reserve pathways
would deal with security of supply in a more
targeted manner, relying on the demand for
flexible, thermal generation in the market.
This demand can be provided by either risk
management products in the case of ThermalCo,
or by the System Operator in the case of
Strategic Reserve.
ThermalCo would ensure security of supply
provided sufficient upfront revenues are collected
through risk premiums contracted by purchasers.
This is dependent on large consumers and
retailers accurately pricing the risk they are
exposed to. ThermalCo would only phase out
capacity if the risk perception of purchasers
decreased, reducing thermal demand.
Strategic Reserve would secure supply by sizing
the market needs and contracting the necessary
capacity with thermal asset owners to meet
demand. Capacity would only be phased out
when the System Operator determines that the
market does not need it and stops the payments.
Decrease in price volatility to reduce
prices for consumers
To keep market price volatility within acceptable
bounds, asset fixed costs would need to be
recovered through alternative mechanisms than
the energy spot market alone. In a spot market,
with fewer periods of high prices (as reviewed
in Chapter 2), those periods will have all energy
paid at very high prices so thermal generators
cover their fixed costs, raising risk premiums that
ultimately get paid for by consumers. Hence, the
chosen pathway should ensure the recovery of
fixed costs without distorting market dynamics
and ensuring the least cost for the market.
All pathways reinforce security
of supply, with varying impact on
the market
Of the pathways, ThermalCo
provides better market signals and
affordability for consumers
Status quo scenario
Price formation in the spot market
Price, $/MWh
Energy,
MWh
Width of low-price-bidding volumes
increase as renewable energy penetration
is higher throughout time
Status quo
Price = <1010 < Price < ~200
Scarcity
Price > ~200
1
2
3
2%97%1%
2022
7%89%4%2030
Demand < "must run" renewables supply (e.g.
Wind, solar, hydro run-of-river, geothermal)
Demand met by hydro reservoirs
and/or thermal variable cost
Exhibit 15: Price drivers
35

Spot price formation and its potential effect on
volatility are illustrated in Exhibit 15, with three
differentiated sections in the ‘price ladder’.
1.
In periods with lower demand than 'must-
run' generation, prices will likely go low, as
geothermal generators offers need to ensure
they keep running and wind or hydro will start
to spill.
2.
When demand is met by hydro reservoirs,
prices are set by the water value (next best
alternative), which is usually determined by
the offers of the thermal assets that could be
dispatched instead. As renewable electricity
penetration increases throughout time,
thermal offers will increase unless fixed costs
are recovered alternatively.
3.
In periods of scarcity, when all peaking capacity
in the market is deployed, remaining hydro
reservoirs or last resort thermal peakers can set
the price at values close to unserved energy
or demand response leading to extreme price
spikes.
To fully understand price formation in the spot
market, it is key to analyse how the different
pathways may lead to power plant offers in the
market, and what the pricing structure and logic
to recover fixed costs over varying time horizons
would be (Exhibit 16).
•

T
hermalCo pricing structure would be
composed of two elements: a fixed hedge
fee, as a service fee for the hedging service,
and the strike price, which would be the
price at which the ThermalCo would cover
Possible pricing outcomes to recover costs
ThermalCo
Fix cost fee: ThermalCo through hedge fee, Capacity market through capacity payment and Strategic Reserve through long term contract fee
Capacity
Market
Strategic
Reserve
Price formation
Strike Price: impact on spot pricing behavior outcomes based on contracting decisions under different market structures.
Less active participation in these markets
Long-termMid and short-termSpot
LRMC
SRMC
LRMC
SRMC
LRMC
SRMC
Contract Fee
($/MWh)
Strike
($/MWh
Contract Fee
($/MWh)
Strike
($/MWh
Contract Fee
($/MWh)
Strike
($/MWh
Exhibit 16: Pricing structure to recover fixed costs
36

the retailer demand in case the spot market
price goes above the strike price. Strike prices
would be inversely proportional to product
tenure as the risk premium increases when
delivery time approaches, e.g. a 5-year hedge
would have lower strike prices than a week-
ahead hedge that reflected expected tight
market conditions over the next week. On the
other hand, the hedge fee would be directly
proportional to the risk product tenure, as
offering a prolonged service should be more
expensive than only doing it for a brief period
like a week or a day. Overall, the combination
of the two elements would provide the right
level of economic cost recovery.
•
Capacity Market would move players to
form their prices taking into account the
capacity payment they are already receiving
in the long term. Hence, players may reduce
their activity in the derivative or hedging
markets as most of their costs would be
already recovered. Instead, they would focus
their activity on the spot market to capture
additional scarcity opportunities to further
monetise their flexibility.
•

S
trategic Reserve would also reduce the
activity of players in the hedging market for
these assets as they would already recover
the fixed costs through long-term contract
fees and the operation of their capacity
would be at the discretion of the System
Operator. In the spot market, price spikes
would be capped by the capacity contracted
by the Strategic Reserve, limiting additional
opportunities for new peaking capacity.
Based on this pricing logic, but also acknowledging
that spot price formation is highly uncertain in a
close to 100% renewable electricity market, our
analysis suggests that the influence of the three
pathways versus an Energy-Only market without
risk hedging products could play out as follows
(Exhibit 17):
•
An Energy-Only market without hedging
products will have a price ladder driven
by LCOE of thermal assets, which will
vary significantly between dry and wet
year conditions
•

T
hermalCo would have moderate strike prices
in the middle of price curve, as fixed costs are
recovered by long- and mid-term hedging
fees. Risk averse buyers who secure energy
in advance will pay higher premiums but will
likely benefit from strike prices close to SRMC.
On the other hand, more risk tolerant buyers
will wait until risks are closer to manifest,
when ThermalCo will recover less of their
costs though premiums and more through
higher strike prices. In this scenario, even
when scarcity pricing is evident, most buyers
would have had the chance to hedge their
purchases at lower prices. Therefore, this
ThermalCo
Capacity Mkt
Status Quo
Strategic Reserve
Price, $/MWh
Number of trading periods
Exhibit 17: Illustrative spot price formation for different pathways compared to status quo
37

pathway forms a more continuous price curve
and will likely improve the outcome of the
market as it operates today.
•
A Capacity Market pathway would slightly
lower prices offered by thermal generators
in comparison with an Energy-Only market,
as fixed costs will be recovered with capacity
payments and energy prices required to
recover LCOE will be lower. However, since
fixed costs are already recovered in a Capacity
Market, there is less incentive to offer hedges
(when compared to ThermalCo). So as scarcity
develops, Capacity Markets will tend to offer
relatively more unhedged volumes into the
spot market (at the prevailing scarcity prices).
•
The assets comprising the Strategic Reserve
would be offered in at SRMC when they
are called on. So prices near the top of the
duration curve would tend to be capped by
these offers. Any thermal units held outside of
the Strategic Reserve would still be trying to
recover fixed costs in the energy only market
so prices in the mid-section of the curve could
follow the status Quo more closely.
Bring the most competitive
technologies to keep an affordable
supply mix
When assessing the impact on system costs and
the affordability of each pathway, a key element to
be addressed is how the market would incentivise
investment in new flexible technologies to replace
existing ones when they become economic.
In this area, pathways diverge. While Capacity
Market and Strategic Reserve opt for a more
central-planning logic based on the mandate of
a regulated authority (Government, Regulator
or System Operator), a ThermalCo would drive
capacity replacement through market pricing of
its risk products (see Exhibit 18).
In the Capacity Market, the decision on which
type of capacity is incentivised and which should
be phased out would depend on the Capacity
Market rules. If regulators unintentionally
underestimate the firm capacity contribution
of new technologies, new technologies could
be at a disadvantage. On the other hand, if
regulators unintentionally overestimate the firm
capacity contribution of new technologies, new
technologies could benefit from it, but security
of supply could be at risk. The duration of the
capacity contract may also limit investment
signals from market changes, especially if
auctions are not held regularly.
Exhibit 18: Illustration on how different pathways can drive capacity mix
6) That increase in flex supply by cheaper capacity will reduce price levels and volatility decreasing the
willingness of retailers to hedge their profile
1) Data Centre opens
accounting for 3-5%
of demand
2) Capacity margin
decreases as there
is an increase in
demand
3) System is short and prices of periods with high demand increase as well as price volatility,
pushing retailers (including the Data Centre) to adopt hedging strategies
Capacity
margin / Dry-
year coverage
Phase out of
Thermal Capacity
Swaption premium
ThemalCo
Lower revenue to cover fixed costs
LT contract prices
Strategic Reserve
Capacity payments
Capacity market
Winter
or dry-year
risk
38

Strategic Reserve would also have some
challenges responding to market changes and
would require a thorough analysis from the
System Operator to identify capacity needs in
the system. The selection of strategic assets
may bias the technologies selected to traditional
sources of flexibility where its performance is well
known, reducing the incentives for innovation
and new technologies to come online. Typically,
reserve payments are long-term contracts, which
limits the flexibility to adapt to sudden market
changes, which could result in non-competitive
assets being kept online during the duration of
the contracts.
In the ThermalCo pathway, phasing out
thermal capacity would be determined by the
demand for hedges and willingness of energy
purchasers (large consumers and retailers)
to be short on supply. If the capacity margin
decreases, swaption strike prices will increase
along with the risk perception of purchasers,
providing positive investment signals for new
flexible capacity. Under this pathway, the mix
of long- and short-term hedges will ensure
stability for the most competitive assets to
remain online securing supply – while keeping
the less competitive assets dependent on
short-term hedges with high strike prices,
putting them in direct competition with new
emerging technologies.
With regards to supporting an orderly transition
for the electricity market and for New Zealanders,
the key to success will be providing transparency
in the phase-out plans so that the transition can be
adequately managed. Transparency and visibility
will be critical for upstream gas supply industry to
guide their investment decisions, for employees
in the power plants and for the communities that
live around these assets, and could be heavily
impacted by decommissioning decisions.
The shared ownership structures that could be
provided by a consolidated Strategic Reserve and
the ThermalCo pathways will necessarily deliver
greater transparency and accountability. This will
eliminate any game theory involved in delaying or
accelerating decommissioning decisions based
on portfolio strategies by individual players during
this short transition period, limiting the possibility
of negative cascading effects that could put
security of supply at risk. It will also decrease the
operational risk of maintaining low utilised assets
and give more demand certainty to the upstream
gas industry. More importantly, there will be a
clear point of accountability and coordination
with Government and communities. Additionally,
An orderly transition is more likely
with a consolidated ownership
of thermal assets provided by
ThermalCo or Strategic Reserve
4) Market based
competition to
provide the most
efficient solution to
cover the risk
Price signal
for new flex
technology
5) The increase in demand by the
Data Centre will be compensated by
the new flex capacity installed
3) System is short and prices of periods with high demand increase as well as price volatility,
pushing retailers (including the Data Centre) to adopt hedging strategies
Capacity margin
/ Dry-year
coverage
ThemalCo
Swaption premium
Strategic Reserve
LT contract prices
Capacity market
Capacity payments
Winter
or dry-year
risk
Example for ThermalCoIncreaseDecreaseRemains constant
39

the learnings in planning and managing
decommissioning of thermal assets, including
finding alternative economic activities for the
regions, will be more easily shared as a single
company rather than as individual companies,
benefiting people and communities.
In contrast, while Capacity Markets will
guarantee recovery of most fixed costs for the
thermal assets, the risk will solely reside with
individual players, whose decisions can be rapidly
affected by changes in capacity auctions rules or
capacity demand thresholds set by the Capacity
Market operator.
In considering the feasibility of the three
pathways there are several elements to consider:
market disruption, stakeholders involved, and
time to implement.
Implementation feasibility would depend on the
required changes in the current market structure
and regulation. The ThermalCo pathway is the
less disruptive option as it leverages currently
available tools for all market participants, such
as existing risk management products. Strategic
Reserve would require a larger regulatory effort
as it would require the change in the System
Operator mandate. The SO would potentially
need to incur additional costs to upgrade its
capabilities and develop a new market-based
function. The Capacity Market pathway could be
the toughest solution to implement as it would
imply the creation of a new market, and would
require coordination between the Government,
SO and market participants to align capacity
and energy needs, as well as the design and
operationalisation of the auctions.
The stakeholder participation required for
the successful operational functioning of
each pathway is also a determining factor
in the implementation feasibility. Capacity
Market and Strategic Reserve are solutions
that require deep involvement from multiple
stakeholders; in addition to thermal asset
owners, participation from the Government and/
or the System Operator would be required to set
up new market rules. Further, while these two
solutions could be immediately launched with
Government mandate, it is likely they will require
broad industry syndication to be effective.
ThermalCo would be more independent in this
sense and would only require the participation
of thermal asset owners in the process to find
consensus on an industry solution (and only
after that seek approval from the Commerce
Commission to operate). However, for ThermalCo
to efficiently run, broad industry alignment will
be needed to ensure appetite from buyers of risk
management products.
The ThermalCo pathway would be the
fastest solution to implement as it leverages
existing tools in the market such as risk
management products or hedges, with no
need to adjust regulation and therefore
minimising implementation risks. However,
an additional legal and financial effort would
be required to demerge assets from current
owners and consolidate them in the ThermalCo;
this would include pricing of assets, sizing
decommissioning liabilities and developing a
clear operational mandate.
All pathways have different feasibility
implications, with ThermalCo the
least disruptive to the current market
40

Consolidation
of thermal
portfolios
E.ON and AGL are some of the largest utility
providers in Germany and Australia respectively. Both
were seeing mounting pressure on their thermal
generation assets, driven by the rapid increase in
renewable generation, while the assets were still
critical to maintain security of supply in the system.
Both companies decided to demerge their portfolios
and create specialised companies to manage the
transition of the thermal assets into renewables.
E.ON carved out its thermal
portfolio into Uniper to then
divest its shares
E.ON carved out in 2016 its thermal generation
assets (nuclear and coal) into Uniper, following
mounting pressure on the accelerated closure
of nuclear plants in Germany. Two years later, in
2018, E.ON sold its remaining shares of Uniper to
Fortum, to fully decarbonise its footprint. Fortum’s
new business unit is specialised in managing
thermal assets through their transition.
Five years after the carve out was announced
(2016), E.ON market capitalisation has increased
92%. The market also had a positive reaction to
Uniper absorption of thermal assets increasing
its market capitalisation by 219% since the carve-
out execution
AGL announced demerger
aims to split thermal assets
into Accel Energy
AGL reached maximum share price in 2017-
2018 period, following a series of successful
acquisitions of coal power plants and maximum
historical wholesale prices in the National Energy
Market. As renewables gain a higher presence
and market prices decrease, AGL’s value in the
market decreased. In March 2021, with wholesale
prices following a sharp decline, AGL announced
a demerger to split its thermal generation assets
and renewables operations into Accel Energy,
leaving its retail, flexibility and renewable PPAs
into AGL Australia. To date, market reaction
has not reversed the downwards trend of the
share price, which remains 42% down in market
capitalisation since the decision was announced.
41

After exploring three potential pathways
to keep the energy trilemma balanced in
a transition to a close to 100% renewable
electricity market, we propose the
establishment of ThermalCo
During the transition, New Zealand will need
to pursue two main objectives:
1. Maintain its world class balance across the
trilemma, as more renewables economically
replace fossil fuelled generation; and
2.
E
nsure an orderly transition of New
Zealand’s electricity market to 100%
renewable generation.
While all three pathways present benefits
for the New Zealand market in terms of their
contribution towards decarbonisation and
security of supply, we believe ThermalCo has the
strongest potential to lower system costs while
simultaneously ensuring an orderly transition.
ThermalCo also presents the best trade-off
in implementation feasibility, as it builds on
a market that works effectively today. It will
operate within existing market rules, minimising
the risk of unintended consequences in an
already well-functioning market, as well as
reducing the need to modify regulation.
Given New Zealand is well underway towards a
100% renewable electricity market, we believe
ThermalCo can be a fit-for-purpose transition
vehicle that drives Aotearoa all the way there
•
with low establishment costs; and
• reducing the risk of losing the energy
market balance through an uncoordinated
transition; while
• providing fair remuneration to security of supply
services by sharing the costs across most
market participants that benefit from them.
The establishment of ThermalCo
will maintain the energy trilemma
balance as:
• The offer of risk management products to
cover all thermal capacity in an open platform
will be a further evolution of the hedging
market helping to support transparency and
liquidity for all market participants to cover
dry-year and winter peak risk.
•
Consolidated ownership of thermal assets
increases the availability of capacity that
could be offered to derivative markets, as
outage risks are spread across a larger portfolio
•
Security of supply risks, priced through
hedging contracts, will provide the price signal
to incentivise the market-led investments
of the lowest costs, reliable technologies
that address these risks. Long-term hedge
premiums will support dry-year coverage, while
short-term strike prices will provide arbitrage
signals for new flexible capacity
•
F
ixed costs recovery through a premium on
risk management contracts will reduce price
ThermalCo: a market-
based pathway for
New Zealand
ThermalCo is an independent
entity that owns and operates
all existing thermal assets and
upstream fuel supply contracts,
with the mandate to offer
transparent and liquid risk
management products (for both
dry-year and winter peak) to all
market participants, while orderly
phasing out the thermal capacity
when more reliable low emission
technologies become economic.
42

volatility in the spot market as only variable
costs will need to be recovered. Most market
participants will likely prefer to cover their
risks rather than be exposed to price spikes,
providing a more equitable distribution of
fixed costs.
The establishment of a ThermalCo
will ensure an orderly transition of
New Zealand’s electricity market as:
• Consolidated ownership will provide greater
certainty in the mid- and long-term demand
for thermal assets, allowing for a more optimal
planning of the transition of these assets when
new technologies can displace them
•

I
t maintains a stable regulatory framework
that works well today.
Continued development of
the hedging market to further
support access to all market
participants
One of ThermalCo’s foundational objectives and
a key commercial driver will be to support the
continued development of the hedging market
in New Zealand. We envisage a ThermalCo which
acts as a derivative market maker, putting its
entire capacity available through long- and mid-
term risk management products in a visible and
transparent platform. Any market participant keen
to cover its position could buy long-term products
to cover their dry-year risk and peak shaped
products to cover specific peak demand risks.
Products would follow standardised structures
to simplify market access for all participants,
reducing transaction costs. Products could consist
of a combination of premium (fixed payment) and
strike price (variable cost at which the plant will
bid into the market).
The transparency of risk management products
will provide accurate price signals for hydro
reservoirs to calculate their hydro storage
opportunity cost, providing a transparent, risk-
based expectation of future price outlook in case
of scarcity. The transparency will also promote
competition across other risk management
products that are not linked to thermal power
plants – like batteries or demand response –
where a transparent and liquid trading platform
will set the benchmark for negotiation.
Increased availability of assets
for hedging products
Liquidity of hedging products will increase as
ThermalCo would be able to offer more capacity
given the lower absolute safety margin required
for unplanned outages.
For example, assuming all thermal asset owners
follow a N-1 security criterion in their hedging
strategy (always keeping one contingent
unit to cover for an unplanned outage on the
largest operating unit), Exhibit 19 illustrates how
ThermalCo could increase available capacity by
8%. Under individual ownership, excluding bilateral
agreements, each player will keep some assets on
hold for contingency, resulting in ~69% of capacity
being offered for long-term risk management.
With a Consolidated Ownership model enabled by
ThermalCo, keeping three Whirinaki units and one
Rankine on hold would be sufficient, resulting in
77% of capacity in the market.
We should note that today, the market operates
with some bilateral agreements between thermal
assets owners to increase the capacity available,
but a ThermalCo Consolidated Ownership
structure could further increase the efficiency
of these contracts.
43

Price signals to incentivise
lowest system cost
The balance between guaranteed cost recovery
through premiums versus spot market prices for
energy required can provide a dynamic signal for
the addition or retirement of different sources
of supply. When the premium is not enough to
cover the fixed costs of the plant providing the
services, capacity will be retired, increasing the
spot price until equilibrium is achieved with new
generation. Alternatively, if new technologies can
provide the same long or short term risk coverage
at lower costs, they will be able to enter the market
securing long-term revenue streams through lower
premiums and displacing existing thermal plant.
Equitable fixed costs recovery
through risk premiums
Risk management contracts do not only provide
the price signals to attract new technology
investments and industrial consumers, but also
enable a more equitable recovery of the system
fixed costs.
The creation of a transparent platform with
market-based pricing for thermal based risk
management products sets the right incentives for
all market participants to hedge their position and
mitigate security of supply risks. The alternative
will be to remain exposed to a very small fraction
of the unhedged capacity, where emergency
mechanisms like load-shedding services could
result in pronounced price spikes, or invest in
alternative means to cover this exposure. These
spikes will have a very limited effect on the
consumers, as they will only affect the small
share of participants that choose not to cover
their physical supply risk position. Conversely, all
participants that choose to cover their true delivery
risks will be contributing to the fixed costs required
to keep the thermal plants available for the times
when they are needed.
The more that fixed costs are recovered by
premiums, the lower wholesale price volatility
will be. While market participants could decide
not to hedge their exposure and benefit from the
lower prices without incurring in any fixed costs
(known as the free-rider effect), their downside
risk of being exposed to scarcity pricing could
be significant. It is expected the standardisation
of risk management contracts and reduced
transaction costs, in addition to the scarcity
price risk, will provide the right incentives for
purchasers to cover their risks. Alternatively, whilst
mandating retailers to purchase hedge cover is
not part of our preferred approach, it is being
considered in other jurisdictions (see page 25 on
Australian reliability obligations) as a solution to
avoid this free-rider effect.
Higher certainty in the mid-
and long-term outlook of
thermal assets
The proposed consolidation of the thermal assets
into a single entity, and the transparent provision
of risk management products across a range of
time horizons, will provide clear market based
price signals for when thermal capacity and
associated fuelling requirements are no longer
required. This will support clear decommissioning
decisions, helping to support security of supply.
Individual owner hedge profile without bilateral agreements:
Potential future:
69%
Capacity
77%
Capacity
Non-hedge selling gen
Hedge selling gen
% participation in hedge market
Genesis
400MW
Huntly e3P
250MW250MW
250MW
400MW
Huntly e3P
50MW
250MW
Huntly Rankines
250MW250MW
Source: 20151030 Existing Generation Plant; Press releases
Nova
McKee
51MW
51MW
McKee
51MW
50MW
Junction Rd
50MW
50MW
Contact
ThermalCo
100MW
100MW
50MW
50MW
50MW
Stratford
Whirinaki
TCC
380MW
TCC
380MW
Not included,
closing in 2023
Not included,
closing in 2023
50MW
Huntly
Huntly Rankines
51MW
50MW
100MW
100MW
50MW
50MW
50MW
Stratford
Whirinaki
Huntly P40
Exhibit 19: Simulation of capacity available for derivatives under single ownership versus individual ownership
Source: 20151030 Existing Generation Plant; Press releases
44

Further, a single point of accountability will
minimise the need of coordination across multiple
parties. ThermalCo will be the single point of
coordination with all other stakeholders, working
directly with the government and collaborating
with communities in forming their transition plans
– applying learnings from one asset to the next.
Maintain a stable
regulatory framework
A key benefit of ThermalCo against the alternative
pathways is the ability to be implemented within
the current regulatory framework. Given the
transitional nature of the thermal assets in New
Zealand in the journey towards 100% renewable
electricity and the significant regulatory change
the other solutions would entail, ThermalCo
would bring the least disruption to the market.
This pathway would avoid a period of unstable
regulation, which can lead to periods of decreased
investment, and/or increases the costs of
investment, and may result in a longer, less
affordable transition.
The consolidation of thermal assets could increase
the efficiency of the current market structure,
as scarcity pricing insurance coverage would
be readily available for all market participants.
The hedge disclosure system could be further
enhanced with ex-ante details reported in a
ThermalCo platform. These products will still
be subject to competitive dynamics, both from
other existing sources of flexibility, such as hydro
reservoirs and large-scale demand response,
or from new rapidly emerging technologies
like batteries. The New Zealand energy market
already has the regulation in place to avoid any
potential non-competitive abuse from any player
under scarcity pricing situations through the High
Standard of Trading conduct provisions and the
Undesirable Trading Situation (UTS) mechanism
that would ensure fair outcomes for customers.
In fact, ThermalCo could start operating today
within the current regulatory framework, requiring
only to get the Commerce Commission approval
and to secure a broad consensus in the industry
around the ThermalCo consolidation structure
and its operational mandate.
Exhibit 19: Simulation of capacity available for derivatives under single ownership versus individual ownership
Individual owner hedge profile without bilateral agreements:
Potential future:
69%
Capacity
77%
Capacity
Non-hedge selling gen
Hedge selling gen
% participation in hedge market
Genesis
400MW
Huntly e3P
250MW250MW
250MW
400MW
Huntly e3P
50MW
250MW
Huntly Rankines
250MW250MW
Source: 20151030 Existing Generation Plant; Press releases
Nova
McKee
51MW
51MW
McKee
51MW
50MW
Junction Rd
50MW
50MW
Contact
ThermalCo
100MW
100MW
50MW
50MW
50MW
Stratford
Whirinaki
TCC
380MW
TCC
380MW
Not included,
closing in 2023
Not included,
closing in 2023
50MW
Huntly
Huntly Rankines
51MW
50MW
100MW
100MW
50MW
50MW
50MW
Stratford
Whirinaki
Huntly P40
45

Our analysis suggest that ThermalCo is a
robust transition pathway, providing a market-
based, low risk way to advance the journey
towards a 100% renewable electricity market
in New Zealand, and could be implemented
immediately. ThermalCo is an industry-wide,
market-based solution with benefits that meet
the two primary objectives of keeping the
energy trilemma balanced while ensuring an
orderly transition of New Zealand’s electricity
market. A balanced market will allow Aotearoa
to capture the opportunity that a close to
100% renewable electricity market could provide
as global decarbonisation pressure mounts.
Broad industry-wide alignment will be required
to implement ThermalCo. In addition to
agreement between current thermal asset
owners, buy-in and contribution of all market
participants (gentailers, independent retailers,
generators and large customers) will be a key
success factor to its success. As previously
described, ThermalCo’s efficient operation
requires all purchasers of electricity contributing
to cover their supply risks through derivative
products. As industry-wide alignment is
reached and appetite from industry participants
confirmed, it will be critical to work closely with
regulators to set up all the required framework
for ThermalCo operations.
Ngā tapuae ō inanahi rā, hei huarahi mō āpōpō
The steps of our forbears, form the pathways for tomorrow.
46

We invite support from
stakeholders that want to
collaborate and contribute to
building a market-led transition
to a 100% renewable electricity
market in New Zealand that not
only achieves environmental
targets, but also meets the
challenges of security of supply
and affordability while ensuring
an orderly transition for all
47

contact.co.nz

October 2021 Operating Report D&O Ongoing Disclosures

Data sourced from publicly available filings. Our datasets may not be complete. Automated analysis can produce errors. If you believe any data on this page is incorrect, please contact us at hello@nzxplorer.co.nz. For informational purposes only. Not investment advice.

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