Study of Australia’s Future Electricity Supply, Optimised
for Cost, Reliability and Carbon Intensity
Gabriel Rioseco1 , Simon Smart1, Joe Lane1, Stephen Wilson1 , Mark Ho2
1 University of Queensland
2 Australian Nuclear Science and Technology Organisation

Australia

FNCA 2023 STUDY PANEL, TOKYO

Context• Greenhouse Gas (GHG) Emissions must be reduced to limit global temperature rise to within 2 ºC average.
• Australia’s GHG emission reduction target: 43% by 2030 (below 2005 levels)… translating to 83% of electricity from renewable energy.
• There are current Federal and State legislative bans on nuclear energy in Australia.
Roadmap• Power System models are required to understand the Opportunities, Challenges and Costs of this clean
energy transition.
• Some power system models focus on the long term investment implications (eg. Capacity planning models)• Other power system models capture operational aspects of the system (eg. Unit commitment and dispatch
models)FNCA 2023 STUDY PANEL, TOKYO

Context• The Australian National Electricity Market (NEM) is expected to undergo
a large and significant transformation for reducing greenhouse gas
emissions (GHG).

• Electrification is a common strategy for decarbonising other sectors.
• It is a sector that must be transformed for achieving deep
decarbonisation.

• The Challenge: deploy a Low-carbon, Reliable AND Affordable
electricity system.

Australian NEM

FNCA 2023 STUDY PANEL, TOKYOThe Australian NEM is changing

Main renewable and GHG targets by states in the NEM:

• Queensland: 70% renewable energy generation by 2032.
• New South Wales: 50% emission reduction target by 2030.
• Victoria: 50% renewable energy generation by 2030.
• Tasmania: 200% renewable energy production by 2040.
• South Australia: 100% renewable generation by 2030.

source: Clean Energy Australia Report, 2021

FNCA 2023 STUDY PANEL, TOKYOThe Australian NEM is changing: AEMO’s official plan
Forecast NEM Capacity by 2050. AEMO 2021 ISP Report• Between 70% and 100% of existing Coal capacity is•

expected to retire in the coming decades.
A small portion of Gas plants are expected to remain in
the system.

A significant amount of retiring capacity must be replaced
EA NUCLEAR ENGINEERING PANEL JULY 2022

Considerations
Electricity systems are Complex systems with a range of technologies (each with different technicaland economic parameters) operating together to match electricity demand at ALL TIMES.
Different technologies have different investment and operating costs, but they also pose a different
value to the system:
Solar PV and Wind have low costs (estimated LCOE ~$50 to $60 /MWh), but they are variable andlocation specific, thus they required additional support services and investment (e.g., storage, backup,
transmission, etc) to firm their generation.
Dispatchable low carbon electricity generation technologies (as nuclear and hydro) have higher costs(estimated LCOE for NuclearSMR ~$100/MWh), but they can provide firm dispatchable generation.

EA NUCLEAR ENGINEERING PANEL JULY 2022

Modelling Approach•

For capturing the whole system implications of decarbonising the NEM, we need to simultaneously capture,1) investment and, 2) operation dimensions of the system.

•

This will allow to determine the full system impacts and the most cost-effective approach for achieving deep
decarbonisation.

•

For this, we developed a long-term electricity capacity planning model with an embedded short-term operational/unitcommitment formulation.

•

The model is applied to the whole NEM, and different runs were conducted for different GHG limits and capital costs(CAPEX)
Main features of our Investment and Operations Electricity system model:

MILP LeastCost
Optimisation

Model type

Investment &operations

2040/
hourlyRenewables,
coal, gas, hydro,
among others

Nuclear
SMR

System dimensions
capturedTime horizon &Time resolution

Generation
technologies

Additional caseevaluatedinstantaneous &near-real-time
CAPACITY, systemstrength andstability issues

UNIT COMMITMENT MODELS• SRMC: Short-Run Marginal Costs• Operational constraints and costs• Fixed and variable O&M• Fuel costs• Ramping and cycling costs• Unit commitment constraints• …etc.

..but usually long-term investments
and divestments are not captured

One Century

One Decade

One Year

One Quarter

One Month

One Week

One Day

One HourOne minutesystem investment simultaneously optimised
over five regions with 24x365 = 8760 hourly dispatch
One second

One millisecond

Model Definition – which time domains does our model address?

CAPACITY PLANNING MODELS• LRMC: Long-Run Marginal Costs• Capacity mix• Investment• Divestments• Storage, transmission capacity
and investment, etc..but usually these models lack theresolution to capture operational
constraints

Approach of this study: Long-term capacity planningmodel with operational constraints captured through anembedded unit commitment formulation and interregion transmission

7Model overview
Model Objective Function - Minimize Total System Costs:
𝑓𝑓𝑓𝑓𝑓𝑓 𝑂𝑂&𝑀𝑀

𝑖𝑖𝑖𝑖𝑖𝑖
𝑀𝑀𝑀𝑀𝑀𝑀 𝑍𝑍 = � 𝐶𝐶𝑝𝑝,𝑟𝑟+ � 𝐶𝐶𝑝𝑝,𝑟𝑟
𝑝𝑝,𝑟𝑟

𝑝𝑝,𝑟𝑟

CAPEX new plants

Fixed O&M
costs

𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓

𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠.𝑢𝑢𝑢𝑢

𝑣𝑣𝑣𝑣𝑣𝑣 𝑂𝑂&𝑀𝑀+ � 𝐶𝐶𝑝𝑝,𝑡𝑡,𝑟𝑟+ � 𝐶𝐶𝑝𝑝,𝑡𝑡,𝑟𝑟 + � 𝐶𝐶𝑝𝑝,𝑡𝑡,𝑟𝑟
𝑝𝑝,𝑡𝑡,𝑟𝑟

Variable costs

𝑝𝑝,𝑡𝑡,𝑟𝑟

Fuel costs

𝑝𝑝,𝑡𝑡,𝑟𝑟

𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐
𝑠𝑠𝑠𝑠𝑠𝑠𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡𝑡+ � 𝐶𝐶𝑠𝑠,𝑟𝑟+ � 𝐶𝐶𝑟𝑟,𝑟𝑟𝑟𝑟+ � 𝐶𝐶𝑝𝑝,𝑡𝑡,𝑟𝑟Start-up costs

𝑠𝑠𝑠𝑠𝑠𝑠,𝑟𝑟

Storage costs(CAPEX and
OPEX)

𝑟𝑟,𝑟𝑟𝑟𝑟

Transmission
costs

𝑝𝑝,𝑡𝑡,𝑟𝑟

Carbon costs(if a carbon
tax is levied)

Subject to a set of CONSTRAINTS on:
CAPACITY :• Supply = demand at every hour
• Generation < Capacity (orcommitted capacity for thermal
plants)• Generation > min stable
generation for thermal plants• VRE and Hydro generation <resource availability

STORAGE :• Storage level (min max)
• In and outflows• Round trip efficiencies
TRANSMISSION :• Interconnector capacities• Flow less than capacity

THERMAL :
•
•
•
•
•
•

Heat rates and fuel use (dependent
on output)
Ramping up and down limits
Min UP and DOWN times
Min Stable Generation
Emission limits
Maintenance requirements

UNIT COMMITMENT(with individual units grouped inclusters):• Committed capacity< installed capacity minus
units in maintenance• Committed capacity increases
with capacity coming online
and decreases with capacity
turned off, among others..

8

Main Inputs
CAPEX
Technology
Brown Coal VICBlack Coal QLDBlack Coal NSW

Low

CentralLimited to Existing
Capacity

VOM ($/MWh)

FOM

Fuel Price

Start up Costs($/kW yr)($/GJ)($/MW Start up)$5.50$131.5

$0.7

$120

$4.30

$53.9

$3.0

$120

$4.30

$53.9

$3.0

$120

CASE

NuclearSMR CAPEX($/MW)

NUC_LOW$4,698,000

NUC_CENTRAL$6,641,000

NUC_HIGH$7,955,000

NUC_VERY_HIGH$9,912,000

NuclearSMR

OCGT$1,407$1,407

$4.10

$12.6

$10.0

$100

CCGT

$1,675$1,675

$3.70

$10.9

$10.0

$25

Operational parameters

SolarPV

$569

$778

$0.00

$17.0

$0.0

$0

FOM (A$/MW yr)$100,000Wind$1,492$1,732

$2.90

$25.0

$0.0

$0

VOM (A$/MWh)

$5.3

$51.3

$0.0

$0

Fuel cost (A$/GJ)$0.60

Limited to Existing
Capacity$0.00

Efficiency (%)

33%

$8.40

$131.0$0.0$0Ramp rate (% per hour)

40%

$0.00

$0

Min Stable Gen (%)

30%

Hydro reservoir
Biomass

Value

CST

$4,449$5,234$0$86.10

Pump Hydro

$214

$214

$0

$18.5

Min up and Down times (hr)12Batteries li-Ion 2h

$194

$253

$0

$8.1

Start up costs ($/MW start up)$350

source: GenCost (2021). CSIRO & AEMO report
for Central and Low 2040 Costs projection

source:What would be required for nuclear energy
plants to be operating in Australia from the 2030s.
Stephen Wilson. The University of Queensland

Model Outputs•

The model capture Long-term capacity planning decisions of the system (that occur at an yearly time resolution),but also the technical/operation constraints that occur at an hourly time resolution••

Long-Term economic aspects:•

Total System costs to reach a certain GHG or renewable target.

•

Resulting Generation (Capacity Mix) in the system.

•

Resulting Storage Mix in the system (batteries, Pumped Hydro, Solar Thermal, Hydrogen?).

•Investment in transmission Lines, etc. -> Only considering additional interstate connections at the moment.

Short-term operational aspects the model can capture:•

Dispatch decisions: how much to dispatch and what technology to meet hour-to-hour demand.

•

Ramping, start up, min stable generation limitations of the plants in the system.

•

How technologies behave in the system: Base load operation, level of flexibility, peaking plants etc.

•

Requirements of firming Low-Carbon generation sources, etc.

FNCA 2023 STUDY PANEL, TOKYOResults: 1) Decarbonising with renewables and Storage
$200
$190

1st Scenario
Seeking to decarbonise the NEM only withRenewables and Storage (ie. pump hydroand batteries).

REN&STO_CENTRAL_CAPEX$180

Average electricity system cost ($/MWh)

$170
$160
$150

Electricity System costs increase as
decarbonisation limits get more stringent.

2019 NEM Emissions: ~650 kgCO2/MWh

$140
$130

Sharp increase seen as a fully decarbonised
electricity system is approached(0 kgCO2/MWh).

$120
$110
$100

Electricity system costs increases ~2.5 times
from a 300 GHG limit (which represents around
50% decarbonsiation) to a fully decarbonised
system.

$90
$80
$70
$60
$50

300

200

100

50

25

0

CO2 emissions Limit (kgCO2/MWh)

FNCA 2023 STUDY PANEL, TOKYOResults: 1) Decarbonising with renewables and Storage
225
Wind

Installed Capacity (GW)

200

SolarPV

175

Batteries

150

Pump Hydro
Hydro

125

Biomass

100

OCGT

75

CCGT

50

Coal

25
0

2022 Installedcapacity
300

200

100

50

25

0

GHG emissions limit (KgCO2/MWh)

FNCA 2023 STUDY PANEL, TOKYO

System size increases ~1.5 times whencomparing the 300 GHG system versus thecurrent installed capacity.
System size increases ~4 times whencomparing the fully decarbonised systemversus the current installed capacity.

Results: 1) Decarbonising with renewables and Storage
Electricity system cost ($ million AUD)

$40,000
Transmission
Costs$35,000

Storage Costs$30,000
VRE curtailment
Costs$25,000

Ramping Costs$20,000

VRE Inv&Op Costs$15,000

Hydro&Biomass$10,000

Coal and Gas
Inv&Op Costs$5,000$0

A considerable increase in Storage,
Transmission and VRE curtailment costs
is seen as the fully decarbonised system isapproached.

300

200

100

50

25

0

GHG emissions limit (kgCO2/MWh)

FNCA 2023 STUDY PANEL, TOKYOFor fully decarbonised system - around 50%
of total system costs are incurred toaccommodate VRE variability andlocation-specificity.

Results: 1) Decarbonising with renewables and Storage
70%
Utilisation factor decreases drastically for all units as
decarbonisation is fully realised.

50%
Coal
CCGT
hydro
wind
solarPV
OCGT

40%
30%
20%

50
25
0

100

0%

200

10%
300

Utilisation factor (%)

60%

Reduced utilisation have a direct impact on capitalutilisation, and specific capital costs.
For instance: at the 50 kgCO2/MWh, the long-term
generation cost estimated for Coal and CCGT is$232/MWh and $157/MWh respectively.
At the Zero carbon emission limit, long-term generation
cost of SolarPV is $98/MWh and for Wind is $186/MWh.
In a market based system, these technologies will need torecover that costs to remain in business.

GHG Emissions limit (kgCO2/MWh)

FNCA 2023 STUDY PANEL, TOKYOResults: 2) Decarbonising with Nuclear SMR as an option

Average electricity system cost ($/MWh)$200
REN&STO_CENTRAL_CAPEX$180

REN&STO_LOW_CAPEXNUC_INC_VERY_HIGH_CAPEX$160

NUC_INC_CENTRAL_CAPEX

$140
$120

Allowing Nuclear SMR in the Mix

NUC_INC_HIGH_CAPEX

Nuclear SMR High and VERY HighCAPEX cases.

NUC_INC_LOW_CAPEX
2019 NEM Emissions: ~650 kgCO2/MWh)

$100
$80
$60
$40

300

200

100

50

25

0

CO2 emissions Limit (kgCO2/MWh)

FNCA 2023 STUDY PANEL, TOKYOResults: 2) Decarbonising with Nuclear SMR as an option
Average electricity system cost ($/MWh)$200
REN&STO_CENTRAL_CAPEX$180

REN&STO_LOW_CAPEXNUC_INC_VERY_HIGH_CAPEX$160

NUC_INC_CENTRAL_CAPEX

$140
$120

Across most of the cases the model chooses todeploy NuclearSMR, as it results in a lower
electricity system cost.

NUC_INC_HIGH_CAPEXNUC_INC_LOW_CAPEX
2019 NEM Emissions: ~650 kgCO2/MWh)

As GHG limit approaches zero →Average electricity system cost is between 60%240% higher without nuclear.

$100

SMRs can play a KEY role in containing the sharp
increase in cost as the grid approaches fulldecarbonisation.

$80
$60
$40

300

200

100

50

25

0

CO2 emissions Limit (kgCO2/MWh)

FNCA 2023 STUDY PANEL, TOKYOResults: 2) Decarbonising with Nuclear SMR as an option

$180
$160

160
120
80

$140
$120
$100
$80

40
0

0 kgCO2/MWh limit

200
Installed Capacity (GW)

200

$200
Electricity System Costs ($/MWh)

Installed Capacity (GW)

240

240

solarPV

$180

wind

$160
160
120
80

$140
$120
$100
$80

40

$60
$40

$200

0

$60

Electricity System Costs ($/MWh)

300 kgCO2/MWh limit$40•

When carbon emission limit is reduced (from 300 to 0 kgCO2/MWh), a significant increase in total installed capacity (GW) is
seen for the case without nuclear in the energy mix(increasing between 2 and 2.5 times).

•

The system with nuclear in the mix, reduces the need to overbuild solarPV, wind and storage.

batteries
pump hydrohydrobiomass
OCGT
CCGT
Coal
NuclearSMRElec System
Cost

Results: 2) Decarbonising with Nuclear SMR as an option

Annual utilisation factor of NuclearSMR: 93%

As the emission limits become more
stringent, SMRs adopt a peaking role tosmooth out the variability of VRE
resources.
Most SMR ramping events occur during the
day when solar PV is generating.
SMR can operate flexibly to firm VREs andstabilize transmission grid frequency .

Annual utilisation factor of NuclearSMR: 82%

Conclusions
As suggested in this model …
1. How we model the NEM is crucial to ‘see’ total system costs and not overlook (some of) them
2. If we try to decarbonise only with renewables and storage, total system costs will become very high
3. Allowing SMR nuclear in the mix can reduce the cost of a fully decarbonised system

Thank you for your attention!

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