Win, lose or draw: Three scenarios for the electricity system in 2030


Cast your mind back 15 years to 2016.
You probably don’t remember this, but 15 years ago people still debated whether the growth of distributed energy would fundamentally transform the Australian electricity system.
Sure, there were a million and a half operating solar projects. Elon Musk was selling shiny new batteries into the Australian marketplace along with a range of very fast electric cars. Google had purchased a smart home thermostat supplier for $3.2 billion. But most Australians had no idea that the electricity network’s makeover had begun and would soon upend a century-old industry.
Why not? Because 15 years ago the major players in the electricity industry — utilities, distributed energy providers, regulators and policymakers alike — had not yet firmed their own approaches to the growing wave of distributed energy. And as a result, multiple potential futures lay ahead.
Version one: Aimless transformation
It started with solar power. Solar technology had been around since the 1950s, but a combination of rapid cost declines, (overly) generous state incentives and new financing models led to an installation boom beginning in 2010. By the middle of 2016, Australia was home to over 5 gigawatts of solar power generating capacity, which had almost reached 2.5 percent of all electricity generation in the national market. Previous state and federal incentives, meant that solar was already cheaper than residential retail electricity, and new utility-scale solar cost less than AUD$0.10 per kilowatt-hour, making the technology competitive with traditional resources. Already, solar made up a significant share of all new generating capacity in Australia.
And costs continued to fall, trending toward AUD$1.20 per watt for a fully loaded utility-scale system by 2020.
Energy retailers developed a complex relationship with solar. On one hand, some retailers were happy to own and operate solar projects. The majority however signed power purchase agreements for the output from solar projects, increasingly doing so beyond consumer demand. The “PV as a service” market also proliferated with retailers providing residential installations for $0 upfront on fixed 10-year contracts.
Commercial and industrial solar PV proliferated as the relentless cost reductions forced even the most conservative businesses to adopt the cost savings from distributed generation. Fortunately, the Australian experience avoided the net-metering debates that raged across the US.
Electricity networks continued to connect each new solar installation, but were becoming increasingly nervous about the disparity between energy based income and demand driven expenditures.  This pent up nervousness began to exhibit itself with moves to alter tariff structures to target PV, limitations on PV exports and high connection charges.
Now, as 2020 approached, load defection threatened the networks from two sides. Residential consumers increasingly installed their own generation (mostly solar), reducing their net power consumption by 75 percent or more. As the residential solar market grew, this had a slight impact on other consumers’ bills, but a much larger one on the network earnings. Networks in many states sought to increase the fixed component of consumer bills. But with a few notable exceptions, the changes were incremental and insufficient to stem the flow of distributed solar growth.
In the isolated cases where high access charges or export prohibitions did stop solar in its tracks, the respite was brief. These changes simply added incentives for solar consumers to add battery storage and/or load control. The economics didn’t make sense initially, but by 2020 the residential solar market picked back up, this time largely incorporating energy storage and controllable loads which were optimized against these hastily designed tariff structures.
Meanwhile, retailers and networks also began to contend with load defection from their largest consumers. In many states, large end users took advantage of direct access tariffs, allowing them to purchase power directly from a renewable energy facility. Elsewhere throughout the country, large electricity consumers discovered a variety of mechanisms to procure their power directly from solar and wind facilities.
Initially, the biggest impacts were in the most rural areas with high power prices. But as time went on, the opposing trendlines — increasing electricity prices and decreasing solar/storage costs — opened up new markets throughout the country. Networks in Victoria and the ACT that had previously been insulated from the impacts of load defection suddenly had to contend with the same disruption their Northern peers had faced years earlier, and their South Australian counterparts before that.
We reached “peak network” in 2020, but this was no death spiral. It also didn’t make for a positive outlook in the network sector. From the networks’ perspective, their concerns about customer impacts and network reliability were going unheeded as the increasingly loud voices of solar advocates decried the utilities purely as profit-seeking monopolies.
In the early 2020s, the trend continued. The Clean Power Plan took effect early in the decade, and many state environmental plans incorporated further incentives for storage and solar. Residential consumers kept installing their own generation and energy storage, more than offsetting the new load coming from increasing adoption of electric vehicles. Large consumers found new ways to control their own power procurement through both on-site and off-site means. And utility earnings continued to erode.
It turned out that, as the networks (and their shareholders) suffered, so did consumers. First, as distributed solar penetration grew, cost-shifting became a real issue. When solar represented less than 5 percent of total generation, advocates convincingly argued that it provided a net benefit to the network, and thus to all consumers. But as solar’s share hit 15 percent and then 20 percent as 2030 approached, its value to the network decreased and rates for non-solar consumers increased. Real-time and locational electricity tariffs might have addressed this problem by incentivising load shifting and smart siting, but governments, networks and regulators were slow to adopt changes, and our tariff structures are largely the same today as they were 20 years ago.
Compounding this was the move of the system minimum demand from 2am at night to the solar peak (1-2pm) during the dat. The effect of this minimum was to constrain-off large generation plant with insufficient time for it to build back up to the evening peak. This created a both a huge call for fast response (ramp rate) services and exacerbated the already volatile energy price.
Less obvious (but just as problematic) was the gradual decline of technological innovation for the distribution network. With utility purchasing power waning and load declining, entrepreneurs and conglomerates alike focused less attention on building solutions to optimize energy delivery and maintain reliability. So while the share of intermittent resources increased, new solutions to manage these resources never quite emerged.
That’s how we find ourselves where we are today, in 2030. We have a lot more solar, but electricity prices remain high. Distribution network infrastructure is aging, and its technology has hardly kept up with the growth rate of these new resources. Meanwhile, climate change is a more immediate threat than ever, but we don’t have a clear vision for how to decarbonize the remainder of the electricity network.
Version two: The balkanized network
It started with solar power, but for a time the rooftop solar business seemed like it had been a short-lived fad. After the states drastically reduced the export value of residential solar, solar companies hoped it would be restored or that a new emissions trading scheme would make up for it. Instead, fixed charges on consumer bills were up, on average, 50 percent over the previous decade. And the generous PV export incentives were gradually removed or fell away.
The residential solar market, which had been growing at a rate of over 50 percent per year from 2013-2015, started to shrink beginning in 2017. Some consumers still signed up, mostly preferring to take out short-term loans to finance their rooftop systems and hoping their payback calculations would hold up. But solar companies faced a capital crunch as finance providers balked at the risk of further reducing export values leading to widespread consumer default. Debt service coverage ratios and yields increased, making new solar projects more expensive. Meanwhile, consumer acquisition costs continued to plague residential solar providers as reports of negative value from existing consumers started to reverse the diffusion effect that was prevalent in solar’s earlier days.
Where the residential solar industry installed half a gigawatt in 2015, it slowed to less than 50 megawatts by 2020. Although a couple number of states remained attractive solar markets, most of the country did not.
Apart from increasing fixed charges and decreasing solar export compensation, electricity tariff structures remained largely stagnant. Time-of-use rates were the exception rather than the norm and were structured based on long peak periods, rather than real- or near-real-time pricing. The incentives for load-shifting and energy storage remained limited, and those markets never quite got off the ground.
And so the Australian distributed energy market effectively went dormant by 2020. But energy is a global market, and other countries picked up the slack. Residential solar-plus-storage became the norm in Germany, Japan and the U.S. India became a major market for solar/storage combinations in the early 2020s. And remote island networks throughout the world installed micro-networks, finding them both cheaper and more reliable than traditional island network architectures. Costs for all these solutions continued to decline, businesses were built, and Australia largely missed out.
However, the underlying consumer demand for smarter, cheaper, cleaner energy that had fuelled the first wave of residential solar in Australia never disappeared. While network prohibitions and tariff structures sought to reduce DER installations, many customers were sourcing and installing in-house plug-and-play devices to circumvent these restrictions.
Distributed energy came roaring back to life in the mid-2020s — this time in the form of true network defection.
Three factors contributed to this sudden trend. First, declining global distributed energy resource (DER) technology costs, coupled with continually rising retail electricity rates, meant the economics of cord-cutting looked increasingly attractive for both individual consumers and small groups. Second, the changes enacted at the end of the previous decade — particularly rising fixed charges — increasingly rendered defection the only way to leverage the full value of on-site energy resources. Third, rather than bearing the risk of retroactive tariff changes later, capital providers began to prefer to finance projects that did not rely on the underlying network and its regulatory whims.
Networks also struggled to work out the level of reliability that customers wanted.  Customers with onsite storage had their own backup power, while those without storage sought increased reliability from the grid. The grid was not capable of providing neighbouring customers with different reliability and quality services and this resulted in a network that never really met the needs of any customer.
Network defection ultimately came in three forms. First, individual residential consumers began to defect in across the peri-urban and suburban fringes, and then in other areas with high electricity prices. Consumers in high bushfire risk areas were provided additional state-based incentives to cut the wires. Utilities and regulators were surprised to learn how many consumers would accept slightly lower reliability in exchange for cheaper, self-controlled power.
Second, local communities, neighbourhoods and housing developments extended the models of community choice aggregation and local power-sharing to fully islanded micro-networks. Some communities utilized blockchain technology to introduce novel methods of energy and cost sharing within a small network. Third, large consumers such as hospitals and university campuses found that, even with high reliability requirements, they could leverage their purchasing power and recent technology innovation to save money without relying on their local distribution network.
Since 2025, the electricity industry has been in crisis. The majority of defecting consumers have been in higher income brackets, while the remaining network consumers have been left with ever-increasing electricity costs. Electricity networks and customers in states with significant defection are facing real financial strain. Trials of grid-exit fees were hastily discarded after significant consumer backlash.
Moves to locational cost-reflective pricing could have preserved the centralised grid from customer defection and provided much clearer identification of inefficient fringe networks.  However, the political capital needed to enact this reform was simply too high and the grid became to resemble Swiss-cheese.
We reached a dubious milestone earlier this year, when the number of islanded networks in Australia exceeded the number of physical islands in Indonesia. How far this goes — and who gets left behind — is anyone’s guess.
Version three: Embracing the transformation
It started with solar power and then moved to storage, which led to a series of charged regulatory confrontations from 2014-2019. But as time passed the need to design a regulatory structure that would last gained acceptance. Learnings were drawn from overseas experiments with locational tariffs, smart metering, incorporation of distributed energy into wholesale markets and more. It took some time, but eventually the major parties (utilities, retailers, regulators, policymakers, DER providers, and advocates) agreed on a set of principles (colloquially now referred to as “grid-neutrality”).
They agreed that distributed energy resources should be compensated according to their value, including avoided distribution costs and societal/environmental externalities.
They recognized the need to protect the prior investments of existing consumers rather than applying changes retrospectively.
They agreed that the optimal long-term solution would retain both the electricity networks and the system operators as central components of a distributed energy system, and that profitable network enterprises would benefit the entire system.
They realized that tariff structures would need to evolve more quickly to become more location- and time-specific in order to maximize the value (and minimize the systemic cost) of all the new resources that would soon emerge on the network.
They expressed willingness to cross-subsidize or provide financial support where necessary to ensure equal reliability and affordability for all electricity consumers.
Though these principles were crystallized through the “Power of Choice 2” regulatory proceedings, they quickly spread throughout the national market as 2020 approached. Armed with these principles and newly crafted regulatory incentives intended to guide the future of DERs, networks and retailers felt emboldened to innovate.
Some retailers focussed on the aggregator role seeking to bundle DER services to whomever would buy them – any many did. Network augmentation was once the largest capital expenditure across the national grid. This fell to essentially zero as the aggregators bundled their customer DER into meaningful and cost-effective load management. Seeing the value and responsiveness of the aggregated DER, the market for ancillary services was fundamentally reset to facilitate the entry of these services.
Connection of new customers to the networks continued apace as new and old community schemes identified the value of grid-backup and export sales.
Some retailers acted as front-end consumer acquisition engines for the next wave of DERs, acting as their consumers’ trusted energy advisors. Some opened marketplaces based on the Network Opportunity Mapping of UTS, while others partnered with Google on Project Sunroof and consumer-facing services.
Network businesses incorporated DERs into their resource planning processes and began soliciting behind-the-meter resources as an alternative to capital investments in the distribution network. In support of lower-cost DER alternatives, regulators reinforced the mechanisms for networks to earn profit on their procured services.
At the urging of large consumers, retailers and networks worked together to tailor green tariff programs and site-specific power purchase agreements for individual consumers. The few consumers who had defected from their utility in the early days remained the exception as retailers and utilities increasingly offered differentiated service based on their large consumers’ needs.
In a few instances, networks transformed entirely into platform businesses, managing the network’s operations while facilitating millions of transactions amongst sources of load, generation, storage and ancillary services.
Meanwhile, across the country electricity rate structures were reformed based on the new set of shared principles. Rates became more time-variant and location-specific, sending signals for DERs to be sited where their value is highest. Retailers were well positioned to help ratepayers navigate these more complex rates, and many retailers developed a new form of energy auditing focused around savings optimization through DER investment.
By the mid-2020s, nearly every major investor-owned network had a new business architecture. Their sources of earnings diversified, which made their businesses more resilient to changes in load growth, commodity prices and technology evolution. Change was not a quick in the government owned networks, but the writing was on the wall.
Remote and isolated customers were provided rebates to actively disconnect from the grid. The removal of these most expensive-to-serve customers actually resulted in lower overall grid prices and the savings were shared between customers and the electricity networks under the new compact.
Today, the prototypical homeowner has some form of generation, load control and energy storage at her residence. Her personal network infrastructure is optimised for her own savings and load based on the needs of the network. An aggregator bids her capabilities into wholesale markets and periodically for network services. But she doesn’t much notice any of this. She’s just happy that her electricity is efficient, intelligent, automated and cheaper than it was a decade earlier.
ShareShare Win, lose or draw: Three scenarios for the electricity system in 2030

Cast your mind back 15 years to 2016.

You probably don’t remember this, but 15 years ago people still debated whether the growth of distributed energy would fundamentally transform the Australian electricity system.

Sure, there were a million and a half operating solar projects. Elon Musk was selling shiny new batteries into the Australian marketplace along with a range of very fast electric cars. Google had purchased a smart home thermostat supplier for $3.2 billion. But most Australians had no idea that the electricity network’s makeover had begun and would soon upend a century-old industry.

Why not? Because 15 years ago the major players in the electricity industry — utilities, distributed energy providers, regulators and policymakers alike — had not yet firmed their own approaches to the growing wave of distributed energy. And as a result, multiple potential futures lay ahead.

Version one: Aimless transformation

It started with solar power. Solar technology had been around since the 1950s, but a combination of rapid cost declines, (overly) generous state incentives and new financing models led to an installation boom beginning in 2010. By the middle of 2016, Australia was home to over 5 gigawatts of solar power generating capacity, which had almost reached 2.5 percent of all electricity generation in the national market. Previous state and federal incentives, meant that solar was already cheaper than residential retail electricity, and new utility-scale solar cost less than AUD$0.10 per kilowatt-hour, making the technology competitive with traditional resources. Already, solar made up a significant share of all new generating capacity in Australia.

And costs continued to fall, trending toward AUD$1.20 per watt for a fully loaded utility-scale system by 2020.

Energy retailers developed a complex relationship with solar. On one hand, some retailers were happy to own and operate solar projects. The majority however signed power purchase agreements for the output from solar projects, increasingly doing so beyond consumer demand. The “PV as a service” market also proliferated with retailers providing residential installations for $0 upfront on fixed 10-year contracts.

Commercial and industrial solar PV proliferated as the relentless cost reductions forced even the most conservative businesses to adopt the cost savings from distributed generation. Fortunately, the Australian experience avoided the net-metering debates that raged across the US.

Electricity networks continued to connect each new solar installation, but were becoming increasingly nervous about the disparity between energy based income and demand driven expenditures.  This pent up nervousness began to exhibit itself with moves to alter tariff structures to target PV, limitations on PV exports and high connection charges.

Now, as 2020 approached, load defection threatened the networks from two sides. Residential consumers increasingly installed their own generation (mostly solar), reducing their net power consumption by 75 percent or more. As the residential solar market grew, this had a slight impact on other consumers’ bills, but a much larger one on the network earnings. Networks in many states sought to increase the fixed component of consumer bills. But with a few notable exceptions, the changes were incremental and insufficient to stem the flow of distributed solar growth.

In the isolated cases where high access charges or export prohibitions did stop solar in its tracks, the respite was brief. These changes simply added incentives for solar consumers to add battery storage and/or load control. The economics didn’t make sense initially, but by 2020 the residential solar market picked back up, this time largely incorporating energy storage and controllable loads which were optimized against these hastily designed tariff structures.

Meanwhile, retailers and networks also began to contend with load defection from their largest consumers. In many states, large end users took advantage of direct access tariffs, allowing them to purchase power directly from a renewable energy facility. Elsewhere throughout the country, large electricity consumers discovered a variety of mechanisms to procure their power directly from solar and wind facilities.

Initially, the biggest impacts were in the most rural areas with high power prices. But as time went on, the opposing trendlines — increasing electricity prices and decreasing solar/storage costs — opened up new markets throughout the country. Networks in Victoria and the ACT that had previously been insulated from the impacts of load defection suddenly had to contend with the same disruption their Northern peers had faced years earlier, and their South Australian counterparts before that.

We reached “peak network” in 2020, but this was no death spiral. It also didn’t make for a positive outlook in the network sector. From the networks’ perspective, their concerns about customer impacts and network reliability were going unheeded as the increasingly loud voices of solar advocates decried the utilities purely as profit-seeking monopolies.

In the early 2020s, the trend continued. The Clean Power Plan took effect early in the decade, and many state environmental plans incorporated further incentives for storage and solar. Residential consumers kept installing their own generation and energy storage, more than offsetting the new load coming from increasing adoption of electric vehicles. Large consumers found new ways to control their own power procurement through both on-site and off-site means. And utility earnings continued to erode.

It turned out that, as the networks (and their shareholders) suffered, so did consumers. First, as distributed solar penetration grew, cost-shifting became a real issue. When solar represented less than 5 percent of total generation, advocates convincingly argued that it provided a net benefit to the network, and thus to all consumers. But as solar’s share hit 15 percent and then 20 percent as 2030 approached, its value to the network decreased and rates for non-solar consumers increased. Real-time and locational electricity tariffs might have addressed this problem by incentivising load shifting and smart siting, but governments, networks and regulators were slow to adopt changes, and our tariff structures are largely the same today as they were 20 years ago.

Compounding this was the move of the system minimum demand from 2am at night to the solar peak (1-2pm) during the dat. The effect of this minimum was to constrain-off large generation plant with insufficient time for it to build back up to the evening peak. This created a both a huge call for fast response (ramp rate) services and exacerbated the already volatile energy price.

Less obvious (but just as problematic) was the gradual decline of technological innovation for the distribution network. With utility purchasing power waning and load declining, entrepreneurs and conglomerates alike focused less attention on building solutions to optimize energy delivery and maintain reliability. So while the share of intermittent resources increased, new solutions to manage these resources never quite emerged.

That’s how we find ourselves where we are today, in 2030. We have a lot more solar, but electricity prices remain high. Distribution network infrastructure is aging, and its technology has hardly kept up with the growth rate of these new resources. Meanwhile, climate change is a more immediate threat than ever, but we don’t have a clear vision for how to decarbonize the remainder of the electricity network.

Version two: The balkanized network

It started with solar power, but for a time the rooftop solar business seemed like it had been a short-lived fad. After the states drastically reduced the export value of residential solar, solar companies hoped it would be restored or that a new emissions trading scheme would make up for it. Instead, fixed charges on consumer bills were up, on average, 50 percent over the previous decade. And the generous PV export incentives were gradually removed or fell away.

The residential solar market, which had been growing at a rate of over 50 percent per year from 2013-2015, started to shrink beginning in 2017. Some consumers still signed up, mostly preferring to take out short-term loans to finance their rooftop systems and hoping their payback calculations would hold up. But solar companies faced a capital crunch as finance providers balked at the risk of further reducing export values leading to widespread consumer default. Debt service coverage ratios and yields increased, making new solar projects more expensive. Meanwhile, consumer acquisition costs continued to plague residential solar providers as reports of negative value from existing consumers started to reverse the diffusion effect that was prevalent in solar’s earlier days.

Where the residential solar industry installed half a gigawatt in 2015, it slowed to less than 50 megawatts by 2020. Although a couple number of states remained attractive solar markets, most of the country did not.

Apart from increasing fixed charges and decreasing solar export compensation, electricity tariff structures remained largely stagnant. Time-of-use rates were the exception rather than the norm and were structured based on long peak periods, rather than real- or near-real-time pricing. The incentives for load-shifting and energy storage remained limited, and those markets never quite got off the ground.

And so the Australian distributed energy market effectively went dormant by 2020. But energy is a global market, and other countries picked up the slack. Residential solar-plus-storage became the norm in Germany, Japan and the U.S. India became a major market for solar/storage combinations in the early 2020s. And remote island networks throughout the world installed micro-networks, finding them both cheaper and more reliable than traditional island network architectures. Costs for all these solutions continued to decline, businesses were built, and Australia largely missed out.

However, the underlying consumer demand for smarter, cheaper, cleaner energy that had fuelled the first wave of residential solar in Australia never disappeared. While network prohibitions and tariff structures sought to reduce DER installations, many customers were sourcing and installing in-house plug-and-play devices to circumvent these restrictions.

Distributed energy came roaring back to life in the mid-2020s — this time in the form of true network defection.

Three factors contributed to this sudden trend. First, declining global distributed energy resource (DER) technology costs, coupled with continually rising retail electricity rates, meant the economics of cord-cutting looked increasingly attractive for both individual consumers and small groups. Second, the changes enacted at the end of the previous decade — particularly rising fixed charges — increasingly rendered defection the only way to leverage the full value of on-site energy resources. Third, rather than bearing the risk of retroactive tariff changes later, capital providers began to prefer to finance projects that did not rely on the underlying network and its regulatory whims.

Networks also struggled to work out the level of reliability that customers wanted.  Customers with onsite storage had their own backup power, while those without storage sought increased reliability from the grid. The grid was not capable of providing neighbouring customers with different reliability and quality services and this resulted in a network that never really met the needs of any customer.

Network defection ultimately came in three forms. First, individual residential consumers began to defect in across the peri-urban and suburban fringes, and then in other areas with high electricity prices. Consumers in high bushfire risk areas were provided additional state-based incentives to cut the wires. Utilities and regulators were surprised to learn how many consumers would accept slightly lower reliability in exchange for cheaper, self-controlled power.

Second, local communities, neighbourhoods and housing developments extended the models of community choice aggregation and local power-sharing to fully islanded micro-networks. Some communities utilized blockchain technology to introduce novel methods of energy and cost sharing within a small network. Third, large consumers such as hospitals and university campuses found that, even with high reliability requirements, they could leverage their purchasing power and recent technology innovation to save money without relying on their local distribution network.

Since 2025, the electricity industry has been in crisis. The majority of defecting consumers have been in higher income brackets, while the remaining network consumers have been left with ever-increasing electricity costs. Electricity networks and customers in states with significant defection are facing real financial strain. Trials of grid-exit fees were hastily discarded after significant consumer backlash.

Moves to locational cost-reflective pricing could have preserved the centralised grid from customer defection and provided much clearer identification of inefficient fringe networks.  However, the political capital needed to enact this reform was simply too high and the grid became to resemble Swiss-cheese.

We reached a dubious milestone earlier this year, when the number of islanded networks in Australia exceeded the number of physical islands in Indonesia. How far this goes — and who gets left behind — is anyone’s guess.

Version three: Embracing the transformation

It started with solar power and then moved to storage, which led to a series of charged regulatory confrontations from 2014-2019. But as time passed the need to design a regulatory structure that would last gained acceptance. Learnings were drawn from overseas experiments with locational tariffs, smart metering, incorporation of distributed energy into wholesale markets and more. It took some time, but eventually the major parties (utilities, retailers, regulators, policymakers, DER providers, and advocates) agreed on a set of principles (colloquially now referred to as “grid-neutrality”).

  • They agreed that distributed energy resources should be compensated according to their value, including avoided distribution costs and societal/environmental externalities.
  • They recognized the need to protect the prior investments of existing consumers rather than applying changes retrospectively.
  • They agreed that the optimal long-term solution would retain both the electricity networks and the system operators as central components of a distributed energy system, and that profitable network enterprises would benefit the entire system.
  • They realized that tariff structures would need to evolve more quickly to become more location- and time-specific in order to maximize the value (and minimize the systemic cost) of all the new resources that would soon emerge on the network.
  • They expressed willingness to cross-subsidize or provide financial support where necessary to ensure equal reliability and affordability for all electricity consumers.

Though these principles were crystallized through the “Power of Choice 2” regulatory proceedings, they quickly spread throughout the national market as 2020 approached. Armed with these principles and newly crafted regulatory incentives intended to guide the future of DERs, networks and retailers felt emboldened to innovate.

Some retailers focussed on the aggregator role seeking to bundle DER services to whomever would buy them – any many did. Network augmentation was once the largest capital expenditure across the national grid. This fell to essentially zero as the aggregators bundled their customer DER into meaningful and cost-effective load management. Seeing the value and responsiveness of the aggregated DER, the market for ancillary services was fundamentally reset to facilitate the entry of these services.

Connection of new customers to the networks continued apace as new and old community schemes identified the value of grid-backup and export sales.

Some retailers acted as front-end consumer acquisition engines for the next wave of DERs, acting as their consumers’ trusted energy advisors. Some opened marketplaces based on the Network Opportunity Mapping of UTS, while others partnered with Google on Project Sunroof and consumer-facing services.

Network businesses incorporated DERs into their resource planning processes and began soliciting behind-the-meter resources as an alternative to capital investments in the distribution network. In support of lower-cost DER alternatives, regulators reinforced the mechanisms for networks to earn profit on their procured services.

At the urging of large consumers, retailers and networks worked together to tailor green tariff programs and site-specific power purchase agreements for individual consumers. The few consumers who had defected from their utility in the early days remained the exception as retailers and utilities increasingly offered differentiated service based on their large consumers’ needs.

In a few instances, networks transformed entirely into platform businesses, managing the network’s operations while facilitating millions of transactions amongst sources of load, generation, storage and ancillary services.

Meanwhile, across the country electricity rate structures were reformed based on the new set of shared principles. Rates became more time-variant and location-specific, sending signals for DERs to be sited where their value is highest. Retailers were well positioned to help ratepayers navigate these more complex rates, and many retailers developed a new form of energy auditing focused around savings optimization through DER investment.

By the mid-2020s, nearly every major investor-owned network had a new business architecture. Their sources of earnings diversified, which made their businesses more resilient to changes in load growth, commodity prices and technology evolution. Change was not a quick in the government owned networks, but the writing was on the wall.

Remote and isolated customers were provided rebates to actively disconnect from the grid. The removal of these most expensive-to-serve customers actually resulted in lower overall grid prices and the savings were shared between customers and the electricity networks under the new compact.

Today, the prototypical homeowner has some form of generation, load control and energy storage at her residence. Her personal network infrastructure is optimised for her own savings and load based on the needs of the network. An aggregator bids her capabilities into wholesale markets and periodically for network services. But she doesn’t much notice any of this. She’s just happy that her electricity is efficient, intelligent, automated and cheaper than it was a decade earlier.

Credit: This article is based on the original work of Shayle Kann of GreenTechMedia (gtm). This article draws on Shayles work and recasts the analysis in the Australian context.

About our Guest Author

Anthony Seipolt is a senior utility consultant with extensive experience in the electricity distribution, retailing and transmission as well as significant international and local regulatory expertise.

Anthony has over 30 years experience in the utility industry and is currently the Director of Cadency Consulting.

Further background to Anthony can be found on Anthony’s LinkedIn profile.

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