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

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

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

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

Roadmap outcome…

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

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

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

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

Electricity generation by technology

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

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

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

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 (2009-10) 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

Price outcomes Generation

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

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

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, %

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

Demand management modelled at zone substation scale Decade in which a zone reaches 40% rooftop solar as a share of demand 2020 2030 2040 2050

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.

Price outcomes Networks

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

Calculating impacts on fairness