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AMP CAPITAL INFRASTRUCTURE 1

The evolution of Australia’s future electricity distribution networks

insightpaper

August 2017

2 AMP CAPITAL INFRASTRUCTURE Editorial credit: Yurii Andreichyn / Shutterstock.com BMW museum building on June 06, 2016, Munich, Germany.

Key Points > Rapid technological development will enable major changes in how networks are managed and unlock significant latent capacity reducing the need for future peak-driven capital investment will also facilitate large increases in rooftop photovoltaic generation and efficient low cost energy storage devices (collectively Distributed Energy Resources, or DERs) within the network.

> The future utility model will provide a new suite of investment opportunities as changes are made in network operations, tariff structures and regulatory controls.

> The future network will be substantially focused on the proactive management of all network connected assets, irrespective of whether the network owns these assets or energy flows in or out of the connection. The need for high speed communications and controls will increase exponentially. This will drive increased investment in communication and control systems and enable active management of power quality and supply reliability in the network.

> The advent of significant electric vehicle penetration, widely forecast within 15 years, is likely to result in:

a. further capital expansion of the networks to meet increased demand after all latent capacity is utilised.

b. Increased options for demand management which can further improve network asset utilisation.

> The change in the balance between capital and operating costs will likely require a change in the regulatory approach - to reduce potential biases in network investment allocations and properly reward investors for the increased operating risk.

> We anticipate that regulatory change will also be needed to allow networks to invest more efficiently in the installation and co-ordination of DERs, to maximise the pace of reform and the subsequent delivery of benefits to consumers.

> We expect that within 20 years, the network structure will change from a large inflexible monolith distributing power from central generators, to a series of small, interconnected micro-grids will be well underway. These micro-grids will supply a significant fraction of their energy requirements from local DERs.

> The role of the network service provider will change from being essentially the sole deliverer of electricity, to being: a inter-connected platform to many customers; a provider of low voltage transmission services; the maintainer of overall power quality; and the assurer of overall supply reliability.

> The overall gains in efficiencies will help cap increases in energy costs to consumers, while the growth of DERs will materially contribute to the decarbonisation of the electricity generation sector.

> From an investors perspective, change brings both risks and opportunities. We expect modest medium term growth in core distribution utility valuations, until the impact of electric vehicles becomes apparent. Regulatory changes should also lower risk.

> The growth of DERs and micro-grids will see similar levels of expenditure as core distribution. These could potentially offer distributors, and other investors, an alternative, unregulated opportunity.


Introduction:The rapid development of technologies that directly or indirectly impact electricity networks will drive significant changes in both network operations, tariff structures and economic regulatory controls. In turn, this will provide investors with different options from today’s utility model. Consequently, these are often referred to as ‘disruptive technologies’.

Additionally, as the electricity generation sector is the largest contributor to the nation’s greenhouse gas emissions, integrating higher levels of renewable generation will also be a major driver of disruption in distribution networks.

Two recently released reports provide some considered insights into the likely future evolution of Australian distribution networks. The Electricity Network Transformational Roadmap – April 2017, referred to hereafter as the Network Roadmap, is a collaborative work between the CSIRO and Energy Networks Australia1. It was commissioned by the Council of Australian Governments (COAG)2 in 2015, with the objective developing tools that allow an assessment of the impact of disruptive technologies and sector decarbonising on distribution networks.

The Independent Review into the Future Security of the National Electricity Market – June 2017, better known as the Finkel report, was also commissioned by COAG in response to significant blackouts in South Australia in September 2016. Further signs of electricity supply fragility during extreme weather events in February 2017 added urgency to this work.

Although very different in scope, the two reports are complementary.

The Network Roadmap:

> rigorously models the impact of disruptive changes and policy settings across all Australian electricity distribution networks.

> developed tools that will provide an essential resource for future policy makers, regulators, distributors, consumer groups and investors.

The Finkel review:

> identifies lack of investor confidence, brought about by a decade of policy vacillation by government, as the biggest single threat to future energy supply security. It proposes a mechanism for emission reduction which may, at last, attract bipartisan political support and so provide investors with the policy continuity necessary to re-establish confidence.

> provides a wide range of recommendations on the integration of higher levels of renewables into transmission and distribution networks.

> models a range of future scenarios to gauge the likely levels of renewable penetration in the future generation mix. While similar, there are differences between the scenarios modelled by Finkel versus the Network Road.

Using these reports as a base, this paper attempts to outline the emerging challenges and opportunities for investors in Australia’s utility sector.

1 ENA is the peak national body representing gas distribution and electricity transmission and distribution businesses in Australia.2 COAG – the Council of Australian Governments is the peak intergovernmental forum in Australia. Its role is to manage matters of national significance or matters that need co-ordinated action by all Australian governments. The members of COAG are the Prime Minister, state and territory First Ministers and the President of the Australian Local Government Association (ALGA).

4 AMP CAPITAL INFRASTRUCTURE

The future role of electricity distribution networks (DNSP’s)A wave of technology advances is changing the face of many traditional businesses. The electricity distribution business model is not immune to these influences and will have to adapt by both accommodating and exploiting the new technology.

Investments in new, operationally focussed, technologies will increase the utilisation of existing network assets. This will:

> Potentially permit a reduction in future network charges and real costs savings to consumers;

> Likely lead to a structural shift in relative spending from asset development to spending on recurring operations.

Global issues, particularly Australia’s response to climate change, will also drive substantial changes in how networks operate.

Broadly, we expect the role of distribution networks to evolve as follows:

1. Australia’s commitments to de-carbonising its economy under the Paris protocols, together with continued efficiency improvements will favour the rapid adoption of small scale renewable energy generation distributed throughout the network (principally rooftop solar photo voltaic).

2. Low cost, efficient energy storage devices will allow excess energy from distributed generation devices to be stored for subsequent use in high energy demand periods.

3. High speed communications and controls will facilitate the incorporation of these Distributed Energy Resources (DERs) into the active management of power quality and supply reliability in the network.

4. In parallel, active promotion of cost reflective tariffs will drive consumer behaviour, reducing the growth in peak demand in established network areas and increase the average utilisation factor – in turn putting downward pressure on average network prices.

5. Revised regulation concepts will remove biases towards network capital investments and properly reward investors for operating risk.

6. Subsequently, multiple DERs will be incorporated in micro-grids capable of supplying a significant proportion of local energy requirements. Connection to the broader network will allow the micro-grid to import energy, to make up shortfalls, and export excess energy as necessary.

7. This will mean that the future network will handle two directional energy flows, rather than in a single direction, as is currently the case. This will require additional investment but, overall, network capacity will increase.

8. Active management of all network connected assets will unlock significant further latent capacity, reducing the need for expansion capex.

9. The advent of significant electric vehicle penetration likely within 15 years, will result in:

a. Increased options for demand management which can further improve network asset utilisation in combination with cost-reflective tariffs;

b. Further capital expansion of the networks to meet increased demand after all latent capacity is utilised.

Consequently, the role of the network within 20 years will change from being essentially the sole deliverer of electricity, to being:

> a inter-connected platform to many customers to many customers;

> a provider of low voltage transmission services;

> the maintainer of overall power quality, and;

> the assurer of overall supply reliability.


Editorial credit: Sebastien DURAND / Shutterstock.com La Defense (France), July 5, 2017. Experimentation of autonomous and electric shuttles on the esplanade of La Défense, next to Paris in July 5, 2017.


The Network Roadmap is this model. All of Australia’s 15 regulated DNSP networks are modelled at a high level of resolution (down to zone substation level, more than 2000 substations). It allows assessment of the impacts of:

> consumer engagement;

> tariff design;

> regulatory reform;

> carbon abatement targets;

> energy generation mix, and;

> broader technology changes, including the impact of electric vehicles.

The Final Report presents two scenarios3, which are described in Box 1. A wider range of alternative scenarios are described in supporting documentation, making it possible to mix and match scenarios to a degree.

In general, the Network Roadmap demonstrates that the improved efficiency in network asset utilisation, will materially enable the transition to a low carbon future. It suggests that this can be achieved while reducing the real cost of delivered energy.

Reform of the distribution sector will yield sufficient savings to significantly offset the cost of complete decarbonisation of the electricity generation sector by 2050.

The Network Roadmap

Box 1: Scenario Description

Roadmap scenario

The Roadmap scenario includes a combination of factors that support each other to deliver lower costs, decarbonisation, fairer prices and rewards for energy services and improved reliability.

In summary:

> Price and incentive reform plus optimised networks and

markets enables DER adoption.

> These factors increase the efficiency of network asset

utilisation reducing future capital requirements.

> Managed charging will allow networks to absorb 20%

adoption of electric vehicles by 2035 with little impact on

network capacity requirements.

> 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).

Counterfactual scenario

Conversely, the Counterfactual scenario includes the following broad key elements:

> Today’s approach to pricing and incentive environment prevails and results in a slow and incomplete adoption of incentives for demand management.

> No further adoption of electric vehicles.

> Electricity sector delivers abatement of carbon emissions of 35% by 2030 and 65% by 2050 reflecting ongoing greenhouse gas management policy.

> Uncertainty and lack of confidence in the ability to manage high variable renewable energy (VRE) penetration with high power system security performance.

Summarised from Electricity Network Transformation Roadmap: Final Report.

3 http://www.energynetworks.com.au/sites/default/files/entr_final_report_web.pdf

Electricity networks will have to keep pace with …… changes in the way Australians use electricity. It’s important that we model the future environment to allow industry to respond appropriately, and so we can implement policies that support innovation and maintain consumer confidence.”IAN MACFARLANE, FEDERAL MINISTER FOR INDUSTRY AND SCIENCE; JULY 2015.


However, a review of its assumptions suggest that it is more an aspirational statement than a realistic business case.

The Counterfactual scenario assumes greenhouse gas emission only meet Australia’s minimum obligations with no change to the business environment or regulation. Additionally, its assumption of no further EV vehicle penetration is logically flawed. These assumptions are also unrealistic. Investors and networks are already adapting to future change and EV uptake may lag overseas trends but seems inevitable.

A scenario based on the Finkel report4 recommendations would include:

1. greenhouse gas emission reductions broadly in line with the Counterfactual scenario;

2. regulatory reform consistent with the Roadmap scenario;

3. electric vehicle (EV) penetration consistent with the Roadmap scenario, but with no restrictions on charging

4. Additional system security protection to allow the seamless integration of high levels of renewable generation. Consequently, this addresses one of major shortcomings of the Counterfactual scenario (refer Box 1).

Therefore, a “Finkel scenario” appears to be a better fit with observable trends than either of the Network Roadmap scenarios. Unfortunately, at the time of writing, no attempt has been made to model the “Finkel scenario”, using the tools developed for the Network Roadmap5.

4 http://www.environment.gov.au/energy/publications/electricity-market-final-report5 Private communication with CSIRO.

The Finkel scenario describes a probable future more convincingly than either Roadmap scenario


Figure 1: Projected large-scale and onsite generation by technology type under the Roadmap scenario

Source: CSIRO & ENA: Economic benefits of the Electricity Network Transformation Roadmap: Technical report.

Major external drivers of changeApart from technological changes in the way electricity is distributed, two external factors are expected to have major impacts on future networks.

Climate change obligations.

Under the Paris Accord, Australia has committed to:

> a 26 to 28% abatement target over 2005 level by 2030;

to achieve carbon neutrality in the second half of this century.

The CSIRO comments that Australia is currently on track to reach its 2020 emissions target but will require additional measures to reach the 2030 target and subsequent carbon neutrality.

In the medium term, these commitments will drive a major restructuring of utility scale electricity generation and facilitate the accelerated penetration of distributed renewable generation within the networks themselves. The Network Roadmap allows the impact on generation mix under the two scenarios, as indicated in figures 1 & 26.

6 CSIRO & ENA: Economic benefits of the Electricity Network Transformation Roadmap: Technical report.

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Key observations are:

> Under the Roadmap scenario:

• Electricity consumption increases by more than 50% to 365 TWh by 2050;

• 100% renewable generation is achieved by 2050.

• Additionally, the high penetration of electric vehicles by 2050 (40%) materially assists the decarbonisation of the transport sector.

• After fully exploiting available rooftop solar PV resources, utility scale wind energy takes up most of the slack when fossil fuelled generation plants are phased out.

> Under the Counterfactual scenario:

• Electricity consumption increases by about 26% to 295 TWh by 2050. The difference from the Roadmap scenario primarily (45TWh lower) results from the assumption that there is no further uptake of electric vehicles. The remaining 20TWh shortfall results from a negative demand response to higher delivered energy prices.

• Greenhouse gas emission reductions for the sector are reduced by 65% against the 2005 level by 2050. This meets current obligations. Fossil fuelled generation (25% coal, 25% gas) in 2050 still accounts for 50% of the generation mix.

• Utility scale renewable generation is not competitive, losing market share to rooftop PV and gas fuelled generation.

> The big winner, under both scenarios, is rooftop PV with forecast penetrations of between 100 and 120 TWh by 2050. That is, the fore-cast for rooftop PV is largely independent of the scenario.

Figure 2: Projected large-scale and onsite generation by technology type under the Counterfactual scenario


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The Network Roadmap modelling suggests that utility scale renewables will be competitive in scenarios in which Australia elects to exceed its Paris commitments, but would, otherwise, lose out to gas.

Similar uptake levels of rooftop PV were also found in the Finkel review. While generation mix broadly is broadly similar7 to the Counterfactual scenario, adjusted for EV penetration, there is a somewhat higher reliance on gas fired generation.

The cost of utility scale renewable generation is increased by the review’s recommendation that new renewable generators be required produce a “dispatchable” output by coupling their intermittent output with either fast response gas fired generation or storage devices. This will remove much of the uncertainty concerning the integration of large amounts of renewable energy into the generation mix.

Some indication of the new challenges created by increased complexity can be seen in figures 3 & 48 which show how high levels (80%) of renewable energy could be integrated to supply demand in South Australia in the near term. The redline shows system demand and the coloured stack shows how a range of generation and storage options have to be manipulated to meet demand while achieving an overall renewable penetration of 80%, with no deterioration in reliability standards.

Distributed generation (rooftop PVs), especially when coupled with local electricity storage devices can provide both network management and energy generation benefits.

The graphs illustrate that high levels of renewables are sustainable in the generation mix. Storage devices play a critical role in achieving a seamless integration under both summer and winter scenarios.

Effective integration of high future levels of rooftop PVs and associated storage will require management of individual small scale assets to maintain local system resilience and assure power quality.

Figure 3: South Australia 2036, 80% renewables, three sample days, summer


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7 Jacobs, Report to the Independent Review into the Future Security of the National Electricity Market, 2017.8 CSIRO & ENA: Economic benefits of the Electricity Network Transformation Roadmap: Technical report.

Figure 4: South Australia 2036, 80% renewables, three sample days, winter


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Distributed generation (rooftop PVs), especially when coupled with local electricity storage devices can provide both network management and energy generation benefits.


Electric and autonomous vehicle penetrationIn the longer term, the forecast rapid adoption of electric vehicles (EVs) will both challenge network capacity but also provide enhanced opportunities to balance loads in the network. The EV penetration level assumed in the Roadmap scenario is indicated in the figure 59. The uptake in EV’s is unlikely to be significantly impacted by marginal differences in the cost of supplied electricity and, in our view, significant electric vehicle penetration should be considered in any reasonable future scenario and has been included in the Finkel review.

The additional energy required by 40% EV penetration to 2050 is shown in the Figure 5. This indicates about 45 TWh, or almost 20% of current consumption.10

9 CSIRO & ENA: Efficient capacity utilisation: transport and building services electrification.10 CSIRO & ENA: Efficient capacity utilisation: transport and building services electrification.11 CSIRO & ENA: Efficient capacity utilisation: transport and building services electrification.

The impact on network peak demand modelled for this level of penetration is shown in figure 611, for two scenarios:

a. Unrestricted charging for convenience (scenario 2), that is consumers charge at high rates (7.2 KW) at any time for their own convenience without consideration of tariff incentives for off peak charging;

b. Controlled overnight charging (scenario 4), in which all vehicles trickle charge overnight (3.6 Kw) under the control of the distributor.

Box 2: Lessons from New Zealand

New Zealand has a target to achieve 64,000 EVs - or 2 per cent of the car fleet - by 2021. DNSP Powerco’s Eric Pellicer says that it is likely that some parts of the country could have far higher EV take-up.

He reports that modelling shows that charging relatively few electric vehicles at the same time could have a significant impact on network peak loads, with as little as 10 to 20 per cent EV penetration in a street raising evening peaks “significantly”.

“We can expect some neighbourhoods to exceed this target much quicker than 2021,” he says. “This could ultimately impact our views on network investment.”

The firm has found that simply shifting the time of charging to off-peak periods can “potentially create a secondary peak later in the evening”.

Pellicer says there are opportunities to achieve and improve utilisation of network assets. To help achieve much smoother EV usage profiles the firm is putting out an “open call to the marketplace” to share information and research.

“Our success in this research will depend heavily on working with our retailer customers and technology providers,” Pellicer says.

“This would be a win-win for all parties involved. EV charging, to a certain extent, is a discretionary load. When paired with the fact this load moves around the networks, it creates exciting opportunities for improved utilisation of distribution networks.”

Summarised from Powerco press releases June 2017.

AMP Capital manages 42% of powerco.

Figure 5: National electric vehicle projections in electricity consumption (TWh), million electric vehicles and electric vehicles share of total vehicles

Source: CSIRO & ENA: Efficient capacity utilisation: transport and building services electrification.

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Figure 6: The impact of electric vehicle charging on Australian NEM network peak demand is substantial if it is unrestricted

Source: CSIRO & ENA: Efficient capacity utilisation: transport and building services electrification.

The 12GW peak growth estimate for the unconstrained charging scenario is approximately one third of current network capacity.

In contrast, the low impact scenario indicates only a minimal impact on network capacity.

This suggests that the level of EV charging control could have a major impact on peak demand. Charging for convenience could create a need to invest capital for network expansion.

We believe both scenarios are unrealistic.

> The high impact scenario assumes all charging is done for convenience. Realistically, consumers can be expected to take advantage of concessional tariffs where possible.

> The low impact scenario assumes all recharging is done overnight under network control, when vehicles are garaged and network loads assumed to be at their minimum.

It ignores the very high penetration of forecast solar PV which potentially could result in minimum network loads in the middle of the day, when vehicles may not have access to a controlled charger. The New Zealand experience (see Box 2) also suggests consumers value convenience over marginal electricity tariff differences.

Additionally, the impact of autonomous vehicles has not been considered in the Network Roadmap work. These should be making a significant appearance by the mid 2030’s, initially in commercial applications. They will be high mileage vehicles with operators placing a premium on availability. Hence, they will require the ability to charge for convenience at the highest possible charge rates. Level 3 chargers which can charge at rates up to 100 KW, or 15 to 30 times faster than the rates used in the modelling are already available.

For private owners, Level 2 chargers with charge rates up to 22KW are also readily available for less than $200012. This would reduce charge times by a factor between 3 to 6 times relative to the modelled scenarios, but increase demand by the same amount.

Future EV battery developments will focus on reducing charging time and are likely to permit even higher charge rates

If charging for convenience at high rates becomes the norm, it would put additional stress on network capacity, especially in high density urban areas. New Zealand experience also suggests that this impact could be felt much earlier than from about the mid 2030’s assumed in the Roadmap modelling. Higher rates of EV uptake than assumed would compound the issue.

Overall, these considerations suggest that EV’s and autonomous vehicles have the potential to lead to a surge in spending on network capacity analogous to that caused by the recent growth in domestic air conditioning installations.

More research is required to quantify the potential impacts.

12 https://www.evse.com.au/

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13 AEMO Applies to the National Energy Market (NEM), representing all states and territories barring Western Australia and the Northern Territory.

Australian Energy Market Operator

(AEMO)

Produces electricity and gas forecasts for the National Energy Market (NEM)

for eastern Australia,

and oversees strategic development of the NEM power system.

Australian Energy Market Commission

(AEMC)

Establishes the rules and undertakes energy market reviews.

COAG Energy Council (CER)

Council of Australian Governments

(COAG)

Australian Energy Regulator

(AER)

The national energy market regulator, which:

oversees economic regulation and compliance with the National laws

and rules;

reports on generator bidding behaviour in the NEM;

and regulates electricity and gas transmission and distribution systems.

Figure 7: Composition of the COAG Energy Council

Source: www.aer.gov.au

Regulatory implicationsElectricity supply and distribution is subject to economic regulation under the National Electricity Law and Rules. These rules are set by the COAG Energy Council which comprises Commonwealth, state and territory ministers responsible for energy and resources. AEMO, AER, and the AEMC, in turn, report to the COAG Energy Council, as shown in figure 7.13

Current regulation is based on a strict separation of network operations from large scale generation and electricity retailing. This separation stems from concerns that vertical integration of the supply chain could lead to abuses of market power and poorer consumer choice.

For a detailed description of the regulatory approach, please refer to the AER website (https://www.aer.gov.au)


14 For a general review of incentive regulation experiences refer to Incentive Regulation: Professor Flavio M Menezes School of Economics, The University of Queensland in collaboration with Kian Nam Loke and John Fallon; August 2014.15 http://www.energynetworks.com.au/sites/default/files/entr_final_report_web.pdf16 AMP Capital modelling.

a. Adjusting regulated returns to better reflect emerging risks.

Under the original pre 2013 approach, most returns were derived from the return on capital used to develop the Regulated Asset Base (RAB) of the business. This approach rewarded operators for investing in capital assets which grew the RAB.

In contrast, any operating savings in a regulatory period were handed back to consumers at the beginning of the next five year regulatory period, through lower tariffs. Consequently, unless an improvement offered large and immediate benefits at the beginning of a regulatory period, the operator had little incentive to deliver operating efficiencies beyond that determined by the Regulator.

In recognition of these short comings, in 2013 the AER introduced incentive schemes to reward improved operational and capital efficiency (Efficiency Benefit Sharing Scheme (EBSS) and Capital Efficiency Sharing Scheme (CESS), respectively. While, in our view, these schemes partially addressed the shortcomings of the legacy regulatory process, they do not go far enough to address the needs of the future operating environment.

The future environment will emphasise maximising the performance of existing assets. It will be capital light and operations heavy. Under the current regulatory environment, this structural shift would increase business risk by failing to recognise the increased exposure to operating risk.

A possible solution, flagged in the Roadmap scenario, is to introduce Total Expenditure (Totex) regulation14. Appropriate returns would be calculated on total expenditure and remove incentives to maximise capital investment. This would bring Australia into line with the UK, which is generally considered to have the most efficient distribution sector.15

b. Adjusting the regulatory framework to efficiently accommodate the new technology.

Many of the proposed network restructuring developments will improve customer choice, and create value for both network support services and energy trading. This is shown conceptually in Figure 816 which compares the potential network and energy trading values created by a range of future Distributed Energy Resources (DERs). The size of the bubble gives an approximation of the size of the opportunity. The graph is for illustrative purposes only.

The trend to develop assets with both high network and trading value is already well underway in micro-grid development, especially in remote areas (see Box 3).

The regulator estimates the revenues a network business needs for efficient operations over a five year regulatory period. Using a building block approach, allowances are made for capital expenditure, operations, tax and depreciation plus a fair return on the capital employed.

In our opinion, efficient network restructuring will require significant changes to regulation, including:

Image credit: https://www.youtube.com/watch?v=_MkPu6K0IIk


Figure 8: Future Distributed Energy Resources

The network operator is currently permitted to develop small scale distributed generation systems as an unregulated investment. Conceptually, numbers of these could be combined, through the provision of advanced information and control systems, to allow energy to be “wheeled”17 through existing distribution assets. This would create a Virtual Power Station (VPS).

These could reach a scale capable of selling energy in competition to retailers, while at the same time providing essential distribution services.

In many cases, by utilising existing assets more effectively, the network operator could develop a VPS at a fraction of the cost of traditional generation assets. That is, the network operator is the natural developer of such integrated systems.

Ring fencing distribution from this form of energy retailing may no longer be appropriate for delivering outcomes in the best long term interest of consumers.

This brings potential conflict with the strict separation of distribution from energy trading that underpins the current regulatory framework. The current Australian Energy Regulator (AER) ring-fencing18 guideline states:

“a DNSP may provide distribution services and transmission services, but must not provide other services.”

An arm’s length investment by an affiliate in other services is permitted. However, the rules of separation may not allow the benefits of complete integration to be achieved, particularly the network management benefits.

17 https://www.csiro.au/en/Research/EF/Areas/Electricity-grids-and-systems/Intelligent-systems/Virtual-power-station18 https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/electricity-ring-fencing-guideline-2016.18 https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/electricity-ring-fencing-guideline-2016.

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Where does the new technology fit?

Any move by networks (or their affiliates) into significant competitive energy trading activities can be expected to bring a fierce reaction from “gentraders” (retail service providers with traditional generation assets).

Most gentraders have a large exposure to traditional fossil fuelled generation and delays in the network reform process would, presumably, maximise the commercial life of their generation assets.

Other retailers may be happier to work with distributors in “arms length” joint ventures, but their balance sheet position may preclude meaningful involvement.

We believe that the pace of network reform would be accelerated and consumer benefits realised more rapidly, if network operators were given an incentive to aggressively invest in the reform process. The regulatory challenge will be to develop guidelines that balance the clear advantages of exploiting the network’s incumbency against the risk of abusing this incumbency. We also note that in New Zealand, the regulators have taken a more pragmatic “wait and see” approach before rushing in with rash decisions. We think this a much more sensible approach to assess the long term interests of consumers.

Ring fencing distribution from energy retailing may no longer be appropriate

Source: AMP Capital.


19 http://www.energynetworks.com.au/sites/default/files/entr_final_report_web.pdf

Future Micro Grid Structure

Battery storage

Solar Photo-Voltaic Generation

Grid connection

Investment Opportunities

Technology disruption will create major opportunities for improving both the efficiency of distribution networks and the decarbonisation of the generation sector.

The premise of the Roadmap scenario is that the savings in efficiency can significantly offset the cost of remixing the generation sector with a bit of cost savings left for the consumer.

This implicitly suggests negative real growth in network revenues/customer from traditional services. While we are of the view that this scenario is not realistic, there are clearly many opportunities to improve the capital and labour productivity of networks. More probably growth in network revenues from regulated activities will be constrained until increasing penetration of EV’s will require significant network investment from the 2030’s, and onwards.

This will vary from region to region with strong growth still expected to continue for example in Endeavour’s Energy area in the greater western Sydney due to the new airport and related economic activity. Networks with modern assets and/or significant excess capacity will have more secure future revenues and less urgency to initiate rapid reform than networks with assets nearing their expiry date and/or capacity constraints.

Some idea of the impact of the reform process on overall sector spending can be gauged from Figure 819, which shows an estimate of total spending for both the Counterfactual and Roadmap scenarios to 2050.

It is apparent new opportunities, especially centralised generation, will attract the major share of expenditure.

However, expenditure on grid-connected on-site generation (which includes rooftop PVs, the development of micro-grids and VPS’s) is forecast to match expenditure on traditional network services.

The modelling suggests that investment in related grid connected assets offer an opportunity of roughly the same size as pure network investment. The collective total equals the forecast cost of generation sector restructuring. Consequently, we expect network operators to increasingly focus on non-regulated activities especially those which support and leverage off their network operations.


Figure 9: Cumulative electricity system total expenditure to 2050 (in real terms) under the Roadmap and Counterfactual scenarios

Centralised generation Connected onsite generation Distribution

Transmission

The Roadmap

Off grid (metering, control, storage and disconnected generation

$888 billion

Counterfactual

$988 billion

The accelerated uptake of EV’s has the potential to be a game changer. There are simply not enough rooftops available to provide the amount of energy that will be required to service even moderate levels of EV penetration. Additional utility-scale renewable or gas fired generation will be required. The delivery of this additional energy will require significant expansion of traditional network capital assets.

The new investment opportunities will have different risk profiles to a traditional utility investment. In order of increasing levels of risk, options include:

a. Investment in a pure play distribution utility. In the shorter term, a pure utility investment will more strongly resemble a bond offering than current network investments, due to the increased security provided by Totex style regulation when coupled with lower real, regulated revenue growth.

In the medium term, EV penetration should see a significant expansion of network capacity and higher revenues.

b. Investment in an unregulated network development. This is a major growth opportunity, although an improved regulatory environment could accelerate this.

Assuming an arm’s length arrangement with the network operator, network embedded micro-grids and VPS’s, would receive both network support and energy sales revenues.

Additionally, the Finkel review suggests that additional support payments may be available from the developers of utility-scale renewable generation assets as part of their network security obligations.

Source: http://www.energynetworks.com.au/sites/default/files/entr_final_report_web.pdf

Box 3: Networks And Micro Grids

Western Power is developing a concept to create interconnected micro-grids in remote areas, supported with a “thin wire” connection to a main grid.

Other networks with obligations to service remote communities are watching with interest.

In more built up areas, Endeavour Energy is investing micro-grids with a trial likely include about 200 homes, fitted with between 3kW and 5kW of rooftop solar PV and a centralised battery storage unit.

It follows another Endeavour tender earlier this year for a 1MWh battery storage system to be installed at the proposed West Dapto Zone Substation to service a new housing development west of Illawarra. The system is expected reduce network costs by $1 million a year.

Summarised from Western Power and Endeavour press releases 2017 Feb.

AMP Capital manages an investment in Endeavour Energy.

The development of these assets would be subject to competition primarily from energy retailers.

c. Investment in distributed generation. Both the Network Roadmap and Finkel review modelling suggests that this is the big winner in all scenarios. Such assets fall outside of the regulatory process as their development is open to competition.

Box 4 provides a case study of how investors are already gaining exposure to this opportunity.

d. Investment in utility-scale renewable generation. The penetration of EV’s will throw a lifeline to utility-scale renewable generation developments, which would otherwise lose out to roof top PVs.

The Network Roadmap suggests that utility-scale wind will prove more cost-effective than utility-scale PV. However, there is considerable overlap depending on location; and both types of renewable generation are likely to see significant developments. The supply security requirements recommended by Finkel (see above) may slow the uptake, and support further development of gas fired plants, although this in turn is impacted by the future domestic gas price.


Box 4: Rooftop PV/Battery Start Up - Evergen Case Study

In 2015 AMP Capital and the CSIRO undertook a joint investigation into the potential disruption that emerging technologies could cause on current utility business models. The objectives were twofold:

1. Identify vulnerabilities of existing investments and;

2. Identify potential investment opportunities.

The research indicated that integrated domestic scale solar PV and energy storage systems were commercially viable for larger households at the then installed equipment costs and subsidies. Projected future installed cost savings suggested that system viability would continue to improve and be increasingly applicable to smaller installations – especially with increasing retail prices.

Additionally, installation on commercial installations where generating potential generally matched consumption were found to be viable.

The research also indicated that intelligent remote control of the battery charging and discharging could add significant further value.

Subsequently, AMP Capital and CSIRO set up a joint venture company, Evergen, to exploit this opportunity.

Currently:

> Evergen is among the leading installer of integrated rooftop PVs and battery storage;

> their proprietary intelligent control has enhanced net savings by up to 30% under Time Of Use tariffs;

> installed cost savings have tracked ahead of the initial projections.

Private discussions AMP Capital and Evergen.

AMP Capital is an investor in Evergen.

In summary our view is that there will be an evolution from a one-way, analogue, electricity distribution system to an interconnected, digital energy platform.


Conclusions 1. Irrespective of scenario assumptions, both the Network

Roadmap and the Finkel review provide visions of a different, yet recognisable future network. Electricity networks have always evolved in response to external requirements. The connectivity provided by the network is the key in delivering the benefits identified in the modelling. Consequently, networks will continue to play a critical, if not more important role in the future.

2. An improvement in efficiency, enabled by new technologies, is a feature of all viable future scenarios. Broadly, this means, that the growth in network revenues will be less than if technology does not advance.

3. Proactive management will markedly improve the efficiency of the network, as measured by the ratio of energy distributed to network capacity at equivalent levels of security and electricity quality.

4. Efficiency gains in asset management will continue to optimise the need for future network capital investment, particularly regarding peak demand and network security. The need to invest in control and communication systems to enable these efficiency improvements will partially offset the savings in traditional hardware costs.

5. The emergence of EV’s will offset this trend to a greater or lesser extent depending on the rate of EV uptake. It has the potential to initiate a new period of capital investment in networks.

6. Control and communications requirements will increase exponentially. While much of this can be automated at either a local or centralised level, the management requirements for other services, including day-to-day customer interactions, are likely to also increase, leading to higher proportional operating costs.

7. The change in the balance between capital and operating costs will need a change in the regulatory approach to reduce potential biases in investment incentive. A move to Totex (total expenditure) regulation, as pioneered in the UK, is an option. Totex not only removes the potential for investment bias but also provides increased security to investors.

8. The future network will be substantially focused on the proactive management of all network connected assets, irrespective of whether the network owns these assets. Communications advances will allow control at a much higher level of resolution, down to the management of a single roof top PV inverter, for example. This also implies a marked increase in day-to-day customer engagement.

9. The core of a successful electricity network of the future will, therefore, be a more agile, consumer-oriented organisation, which still meets the definition of utility infrastructure.

10. The disruption, however, will also bring a wealth of opportunities for investors with risk profiles ranging from a high yielding bond proxy to high growth assets with some demand exposure.

11. Importantly, while the cumulative change foreseen is great, the rate of change is relatively moderate, which should allow both investors and operators ample time to adjust.

Greg MacleanHead of Research, Infrastructure

Michael CummingsHead of Infrastructure Funds, Australia & NZ

AUTHORS

Important note: While every care has been taken in the preparation of this document, AMP Capital Investors Limited (ABN 59 001 777 591, AFSL 232497) makes no representation or warranty as to the accuracy or completeness of any statement in it including, without limitation, any forecasts. Past performance is not a reliable indicator of future performance. This document has been prepared for the purpose of providing general information, without taking account of any particular investor’s objectives, financial situation or needs. An investor should, before making any investment decisions, consider the appropriateness of the information in this document, and seek professional advice, having regard to the investor’s objectives, financial situation and needs. This document is solely for the use of the party to whom it is provided and must not be provided to any other person or entity without the express written consent of AMP Capital. © Copyright 2017 AMP Capital Investors Limited. All rights reserved.

CONTACT DETAILS For more information on how AMP Capital can help grow your portfolio, visit our website, www.ampcapital.com

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