1. Paul Graham and Thomas Brinsmead
Minimising customer bill increases in a decarbonising and decentralising electricity system
Paul Graham and Thomas Brinsmead
IAEE Singapore June 2017
CSIRO Energy

2. 2017-27 Electricity Network Transformation roadmap
CSIRO- ENA public facing collaboration
Evidence-based (Qual + Quant)
Informs specific, purposeful actions (‘Milestones’ + ‘Actions’)
Central focus on balanced outcomes for customers and society

3. Status today …
1.5 million microgenerators, 15% average Solar PV penetration
Highest per capita emissions, generation sector reliant on coal
Significant increase in av. retail bills since 2008
Cross-subsidies between customers drive by technology (A/C, solar) and diverse use.
Blunt incentives to DER, regardless of location, time.
System security and stability challenges with with loss of synchronous generation and millions of DER

4. Roadmap outcome… Almost 2/3 of customers have DER
1/3 customers on ‘stand alone power system’ tariff
COP 21 aspiration of Zero Net Emissions by 2050 is met
Reduce total system spend by $101 BN by 2050
Save Households $414 pa
Efficient solutions for new NEM services avoid security & stability risks.
Real time balancing, reliability & quality of supply with millions of DER participants
Avoid over $18 BN in cross subsidies
Means $600 pa. for mid size family without DER
Networks pay over $2.5 BN pa for DER services

5. Roadmap outcome…

6. Roadmap and counterfactual scenarios
Price and incentive reform plus optimised networks and markets means distributed energy resources adoption is enabled and delivering network capacity reduction tuned to each zone substation
Efficient capacity utilisation is achieved through 20% adoption of electric vehicles by 2035 with managed charging
Electricity sector decarbonisation does more than its proportional share of current national abatement targets (i.e. achieving 40% below 2005 levels by 2030) and accelerates that trajectory by 2050 to reach zero net emissions (100% abatement) due to strong power system security performance assisted by distributed energy resources orchestration
Counterfactual:
Today’s approach to pricing and incentive environment prevails (relying on customer opt-in to fair and efficient tariffs) resulting in slow and incomplete adoption of incentives for demand management
No adoption of electric vehicles, consistent with current national electricity system planning assumptions
Electricity sector delivers abatement of 35% by 2030 and 65% by 2050 reflecting ongoing carbon policy uncertainty and lack of confidence in and coordination of resources for delivering lower emissions and high VRE penetration with high power system security performance

7. Roadmap approach to carbon abatement
Incentive-based policy options capable of enabling least-cost carbon abatement are supported by options for maximising capacity utilisation.
Assumed greenhouse gas pathways under the Roadmap & counterfactual scenarios

8. Modelling framework Tariff options / system cost recovery
System expenditure
Consumption & demand
Customer choices
Tariff options / system cost recovery
Tariff offering /system prices
SAPS & micro-grids
Off-grid demand
Tariff/ technology choices
Network & state loads
DNSP expenditure
Generation & TNSP expenditure
Substation loads

9. Modelling framework Three different generation models:
Long term investment model: annual time step, load curve represented as blocks, run to 2060
Dispatch model: solved through sequential solving of half hours, Energeia
Back-up/storage optimisation model for given renewable share (all hours solved simultaneously within a snapshot year)
Loop back to ensure long term investment model includes cost of back-up required for different levels of VRE penetration

10. Electricity generation by technology

11. Total battery requirements (building and grid scale)
Finding 3: Battery storage may begin to contribute to an optimised energy mix when renewable shares are in the range of 30 to 50 percent
Projected ratio of battery capacity to variable renewable generation capacity to achieve energy balancing for a given renewable energy share, by state

12. Total battery requirements (building and grid scale)
Finding 4: Gas or biogas peaking plant are more cost effective than adding additional storage capacity in circumstances where a substantial renewable generation shortfall extends for more than a third of a day.
Projected hours of battery storage required to achieve energy balancing for a given renewable energy share, by state

13. Power System Security
South Australia, 2036, 80% Renewables, three sample days - summer
Finding 1: The roadmap supports the four priority technical challenges identified by AEMO:
Frequency control
Management of extreme power system conditions
Visibility of the power system (information, data, and models)
System strength
Finding 2: New forms of system architecture can be adopted to provide system security
Finding 3: Multiple combinations of strategies will be needed
South Australia, 2036, 80% Renewables, three sample days - winter

14. The role of state interconnectors
Finding 5: The diversity of variable renewable generation, particularly wind generation, across regions during summer and winter peaking conditions, suggests a stronger role for state transmission interconnections.
Historical ( ) coincident wind generation capacity factors on winter and summer maximum demand days in selected states
To keep the modelling task simple we did not increase the use of state interconnectors in our system balancing solution. However, we decided to look at the renewable generation diversity to see what it could tell us about how the states might support each other during summer and winter peaks.
We focussed on wind power at night because we see night time as the most critical time where we are likely to encounter low renewable output events, given the expected prevalence of solar power.
What this chart shows is that in QLD, Vic, NSW and SA there will be times of the year when they could benefit from access to wind output in other states.
In this example, Queensland and Victoria would benefit from connection to NSW and SA during the night of their summer peaks. Conversely, during their winter peaks NSW and SA would benefit from connection to other states

15. Price outcomes
Generation

16. Efficient capacity utilization – electric vehicles
Projected additional national electricity consumption from electric vehicles
Finding 1: Electrification of transport could make a substantial contribution to efficient capacity utilisation
Finding 2: Orchestration maximises electric vehicle contribution to decarbonisation and efficient capacity utilisation
Projected additional national aggregate non-coincidental zone substation load under no management

17. Efficient capacity utilization – electric vehicles
Projected reductions in average residential electricity bills due to EV adoption
Electrification of transport reduces electricity bills
..and is projected to
reduce Australian road transport emissions by
22 MtCO2e per year by 2050

18. Pricing and Incentives
Finding 1: A fairer system of prices can only be achieved in a reasonable timeframe with changes to tariff assignment policy
Share of customers on fair and efficient tariffs, %

19. Pricing and Incentives
Finding 2: Smart meters are essential to ensuring a fair system of prices
Finding 3: Over $16bn in network savings can be achieved by 2050 through improving existing tariffs, introducing new tariffs and establishing frameworks for networks to buy grid services from customers with distributed energy resources

20. Demand management modelled at zone substation scale
Decade in which a zone reaches 40% rooftop solar as a share of demand

21. Avoided network expenditure
Counterfactual
Roadmap
Feedback received:
Some stakeholders were concerned that, with low, or declining, growth in peak demand in some states, and with significant recent investment in capacity in others, that there could not be many significant opportunities to avoid network augmentation to justify the savings estimated from the Roadmap.
Action taken:
The final Roadmap Reports have been updated to clarify that, in the modelling undertaken for the roadmap, the avoided network expenditure in the shorter term is mostly reduced replacement expenditure (i.e. building networks back smaller). In the longer term, as peak demand starts to grow relative to capacity in some states, the major opportunities are both in reduced REPEX (replacement network investment) and AUGEX (network investment in new augmentation). The final reports have been modified to ensure the Roadmap does not over-emphasise avoided augmentation benefits to better reflect the results of the Roadmap modelling.

22. Price outcomes
Networks

23. Comparing the roadmap outcomes
Projected savings in average residential bills under the roadmap scenario
Cumulative electricity system total expenditure to 2050 – Roadmap & counterfactual

24. Calculating impacts on fairness