The installed capacity of small-scale solar PV is expected to grow steadily for the foreseeable future, particularly with new financing and business models emerging that provide solar with low or no upfront costs. Origin Energy has estimated that Australia could have as many as 5.3 million rooftops that are suitable for solar, but are currently without installations (Keane, 2015), and Jacobs (2016) forecasts that installation rates will remain high until the early 2030s when market saturation will be reached in some regions. Morgan Stanley (2016) observes: “Given the unlimited supply, large market size, and the compelling economics, the only remaining constraint is rooftop space.” Fig. 14.1 presents historical installations and a range of forecasts to 2030, all of which predict that the installed capacity will more than triple over this period. Bloomberg New Energy Finance (BNEF, 2015) predict that by 2040, around half of all residential buildings will have rooftop solar and 18% of all generation will occur behind the meter.

There are several battery storage product offerings already available to Australian households, including from the NEM’s three large, vertically integrated electricity providers: AGL Energy, Energy Australia, and Origin Energy; several smaller energy retailers; and independent solar installers. Morgan Stanley (2016) predicts that the average installed cost of a 7-kWh residential battery system could drop by around 40% in 2 years, from almost A$10,000 in 2016 to around $5,500 in 2018, mostly due to falling battery pack costs.⁵ This indicates a potential market size across the NEM of 1–2.2 million homes by 2020—between 11% and 25% of households—including half a million “retrofits” of battery storage units to existing solar installations. A range of forecasts are shown in Fig. 14.2. While these analysts all agree that battery technology will play a significant role in energy markets, their predictions about when installations will accelerate are somewhat divergent.

The main reason that customers give for being interested in home energy storage is the potential to reduce grid power use and thereby cut energy bills. For many households, solar generation and household demand are not closely correlated, and battery storage provides the opportunity to store surplus daytime generation for use in the evening when demand typically peaks. Dissatisfaction with traditional energy providers and a strong desire to control energy spending may encourage some households to install battery storage, even if the economics are not considered to be conventionally viable.⁶ If technology costs drop to the point that a home energy storage system can be installed for less than A$5000, mainstream uptake may expand quickly, becoming a “credit card” purchase for many households, rather than an economic decision based on cost benefit. Solar installations in Australia accelerated rapidly once the typical out-of-pocket expense for households fell below this threshold, and the payback period of the investment was less than 3 years, and similar trajectories have been forecast for battery storage if these conditions are met. Households may also seek to install energy storage systems to avoid “bill shock” when their premium solar FiTs expire, suddenly exposing them to much higher energy bills. For example, the New South Wales Solar Bonus Scheme⁷ closed in December 2016 for over 146,000 customers, many of whom have paid low or no electricity bills for several years. The ability to maintain power supply during blackouts may also motivate some customers to install home storage.⁸

The structure of energy tariffs will also influence storage installation. In 2014, the Australian Energy Markets Commission (AEMC) made rules requiring networks to provide more “cost-reflective” pricing, and as shown in Table 14.1, most will begin offering demand tariffs for residential customers from 2017 on an opt-in basis. Both demand and Time-of-Use tariffs can improve the economics of battery storage, by providing incentives for pricing arbitrage; charging the battery when prices are low for use when prices are high, or using stored energy to moderate or eliminate demand from the grid during peak times. New storage products are already being developed to help customers optimize usage under new tariff arrangements, such as from Sunverge Energy (2016), which recently added demand charge management to its platform, which it estimates could reduce power bills for Australian customers by up to 50%.

Despite forecasts of rapid deployment for behind-the-meter energy storage, coexistence with the grid, rather than full substitution is the most likely outcome for most customers (Nelson and McNeil, 2016). Wood and Blowers (2015) found that for typical customers to achieve 99.9% reliability with an “off-grid” system—equivalent to around 9 h of outage per year—5 kW of solar PV and 85 kWh of storage would be needed, at an estimated cost of A$72,000; both the large area of roof space required and the system expense would be prohibitive for most households. Hence most customers are likely to remain connected to the grid for the foreseeable future; although for households with solar and storage, this may no longer be a major source of energy supply.

Few EV models are currently available to Australian consumers, and costs are high and adoption rates low. Australia has not introduced national policies to support EV uptake, which have proved effective in other global markets, such as vehicle emission standards, capital subsidies, exemptions from charges and taxes, preferential access to transit lanes and parking spaces, or government subsidized charging infrastructure. EV manufacturers have, therefore, been reluctant to invest in the small Australian market, and many popular models internationally are not available in Australia, including the Nissan LEAF Gen 2, Chevrolet Volt and Bolt, and Renault ZOE (ClimateWorks, 2016). While vehicle availability and customer choice remain low, mass adoption of EVs in Australia appears unlikely, and may lag behind other global markets.

EVs are likely to have a fairly minor impact on electricity demand in the NEM. Projections prepared for the Australian Energy Market Operator (AEMO) show that even if uptake is high, 2035 electricity demand would only increase by 4% (Jacobs, 2016). However, for individual households, EV ownership can increase electricity use by 30%–50%. It is therefore unsurprising that energy retailers are beginning to develop new products tailored to the needs of early EV adopters. In June 2016, AGL Energy announced that it would offer an “all you can eat” EV plan, where EV customers receive unlimited vehicle charging, with carbon offsetting, for A$1 per day. Click Energy has also launched a new energy plan for EV drivers, offering lower energy rates for the household’s total energy purchase, not just vehicle charging.

As mobile energy storage devices, EVs also have the potential to discharge energy for use during peak times, or to provide grid-support services. To date these kinds of “vehicle-to-home” or “vehicle-to-grid” applications have generally not been supported by vehicle manufacturers. For example, Tesla has developed a range of both stationary energy storage products and EVs rather than combining their functionality into a single product. However, if new markets emerge for these services that could provide significant value to EV owners, vehicle specifications may follow.

DERs may offer a range of services simultaneously, allowing value created in wholesale markets, networks, and within the home to be “stacked” to maximize customer benefit. Under such arrangements, Morgan Stanley (2016) estimates that home energy storage could become cost effective in the NEM by approximately 2018, with the value of network services comprising around half of the potential revenue pool; the remainder being from solar self-consumption, tariff arbitrage, and a relatively small wholesale component accessed via VPP aggregation.

Energy Networks Australia (ENA, 2016), an industry group representing network companies, states that the consumer value of DERs could be “unlocked” through the implementation of demand tariffs for all customers on an opt-out basis, and by giving customers with DERs the option to opt-in to providing network services, incentivized by dynamic and location-specific pricing, which would target regions where infrastructure is constrained. ENA estimates that if networks buy grid services from DER customers, this “orchestration” could replace the need for $1.4 billion in conventional network investment by 2026, and $16.2 billion by 2050. A number of distribution networks across the NEM are conducting small trials of distributed battery storage to demonstrate the technology’s capabilities. In the longer term, networks will be required to strictly ring-fence their nonregulated energy services from regulated “poles-and-wires” work. This will be important for facilitating consumer choice and innovation (AER, 2016b).

At an aggregated level, the output from a large number of distributed systems can become a VPP, able to dispatch power to the grid to be traded at wholesale pool prices. VPPs could provide hedges for retailers, to limit their exposure to volatile wholesale pricing, either through traditional financial instruments, such as “cap” contracts, or by reducing exposure to high prices by directing homes to use stored energy from batteries rather than grid supplies. Reposit Power has begun offering a “GridCredits” product, provided in partnership with selected renewable energy retailers, which links customer batteries to wholesale energy markets and enables the export of power when prices spike, for a premium payment of A$1.00 per kWh. Batteries may also be suitable to provide a range of ancillary services, which have, to date, been mostly provided by thermal generators with “spinning reserve,” such as fast-response frequency control.

In August 2016, AGL Energy announced that it was developing the world’s largest solar VPP demonstration plant, involving 1000 homes and businesses in South Australia equipped with solar PV and battery storage systems, linked through a cloud-connected control system (AGL, 2016). Once in place, the VPP will provide the equivalent of 5 MW of peaking capacity. In return for a heavily discounted home energy storage system—A$3499, including hardware, software, and installation—customers enter into an agreement that allows AGL to occasionally direct the batteries to discharge to the home or to the grid, at times of high demand or grid instability. For the majority of the time, the batteries will be used to help customers self-consume their stored solar power. Projects, like this VPP, will help to demonstrate how relationships between networks, retailers, consumers, and the market operator can create and access new value streams.

Within the NEM, the South Australian market has, by far, the highest concentration of intermittent wind and solar generation, and with the recent closure or mothballing of aging thermal plant, there are concerns about system stability and a potential shortfall of “firm” capacity available to meet peak demand (Nelson and Orton, 2016). As a result, average wholesale energy prices are higher and more volatile than in other jurisdictions. VPPs may represent a new way of managing energy peaks and grid stability, to support energy systems with high penetrations of intermittent renewable generation. If successful, this would provide an alternative to building new thermal generation, or increasing interconnection with other regions, which in a disruptive market environment, are investments that could become stranded before the end of their design lives. DER assets, with multiple potential revenue opportunities, could prove to be a more flexible and adaptable solution.

Alternative VPP models are also being trailed in the NEM, albeit at smaller scale. Ergon Energy is installing grid-connected battery and solar systems at 33 customers’ premises, but is retaining ownership and charging a fixed service fee in return for cooptimizing several value streams. Cloud-controlled demand response can also behave as a VPP by reducing energy demand during peak periods in an orchestrated way. During the summer of 2015–16, AGL Energy and United Energy undertook a trial involving the installation of “smart” air conditioners for 68 customers. During certain hot weather events, the devices were sent commands to slightly increase the set point temperature, with the aim of reducing peak demand by 25 kW.

The high level of activity in this space involving technology trials by both competitive and regulated industry participants would suggest that Australian utilities see a significant potential for VPPs to deliver customer and shareholder value in a distributed energy system. Recent findings from the AEMC (2016) suggest that behind-the-meter battery storage should be defined as “contestable”—and therefore delivered by entities appropriately ring-fenced from regulated participants. This should facilitate the development of competitive markets for services along the supply chain, and the emergence of new service providers—aggregators—to bundle these into compelling consumer products.

Fig. 14.4 illustrates how the averaged load profile would change if a 3-kW solar PV system were installed. During daylight hours, the system generates more electricity than the household consumes, with the surplus exported to the grid. While the electricity consumed by the home remains the same, the solar system now supplies most of the home’s daytime energy needs, reducing energy demand from the grid by 48%. The volume, time, and shape of grid demand are significantly different from the previous example.

When a home energy storage system—with 6-kWh useable capacity¹⁰—is installed in conjunction with the solar system, dependence on the grid is further reduced. On a typical summer day, the household’s solar generation could supply 88% of its own energy needs, either consumed directly or stored for later use, with the home drawing from the grid for only a few hours in the early morning once the battery is discharged, as shown in Fig. 14.5. For the remainder of the day, the home neither needs to import or export power to the grid.

In this simple configuration, surplus solar generation is used to charge the battery, and power stored in the battery is subsequently discharged to the home in preference to drawing supply from the grid. Once the battery is fully charged, any additional solar generation is exported, and once the battery is fully discharged, supply from the grid resumes. In this scenario, the household self-consumes as much of their solar generation as possible. The battery does not discharge directly to the grid, and nor has its use been optimized for specific tariff structures or to provide grid support services –however reducing evening demand peaks would likely occur in all cases.

Considering the household that has installed a 3-kW solar PV system, on the hot summer day the home, both, uses more electricity and generates more solar power than on the mild day, as shown in Fig. 14.7. The use of solar reduces peak energy demand from the grid by 20% relative to the nonsolar household; however, during the middle of the day when solar production exceeds the household’s energy use, surplus energy must be exported to the grid. In fact, the household’s peak use of grid capacity is now for exporting solar generation, rather than importing power supply; the maximum capacity required by the home has only fallen by 1% compared to Fig. 14.6. In the Foreword, Conboy discusses that in some Australian neighborhoods, 50% of households have rooftop solar systems. As solar penetration continues to grow, solar exports, rather than energy imports may increasingly define the network capacity required in these areas.

When home energy storage is added to solar in the same configuration as previously discussed, on the hot summer day the household is able to self-supply 84% of its energy requirements, and its peak demand is 52% lower, as shown in Fig. 14.8. Importantly, during the hours when the grid is most strained on peak demand days—typically 3–8 p.m. in South Australia—the home is largely self-sufficient, and draws no energy from the grid at all.

The addition of EV charging can also significantly change the shape of a household’s energy-demand profile. If charged during the overnight off-peak period, the EV increases energy use on the hot summer day by 28%—or 56% on a typical day—and almost doubles the household’s peak grid demand, as illustrated in Fig. 14.9. However, this peak occurs well outside of the problematic system-wide peak demand period, when there is likely to be surplus available capacity.

New service agreements may need to be developed to reflect changing customer expectations, such as the ability to both import and export energy and to be compensated for the value created for networks and wholesale markets. While the application of more cost-reflective demand tariff structures could provide additional flexibility, with costs faced by customers more representative of the services they actually use, new pricing models may also evolve. For example, customers with low grid use could be offered a new grid “subscription” product, such as a fixed fee for a defined level of grid capacity access. The importance of utility pricing structures for DERs in the Australian market is further described in chapters by Biggar & Dimasi, MacGill & Smith, and Mountain & Harris.

Between 2012 and 2015 the National Energy Consumer Framework (NECF) was adopted in all NEM states except Victoria, to harmonize obligations and retail requirements. To be licensed, electricity retailers must comply with NECF requirements or equivalent regulations, including maintaining supply for customers who are having difficulty paying their bills. Customers are guaranteed access to an offer of supply for electricity and gas, minimum contractual terms, access to ombudsman and dispute resolution services, and energy-specific marketing rules that ensure customers provide “explicit and informed consent” before entering into a contract. Retailers must provide flexible payment options, hardship programs, and energy efficiency advice, and strictly enforced rules govern how and when energy services can be disconnected. Additional support measures are targeted to vulnerable customer groups, such as government-funded energy rebates for low-income households, concession cardholders, and those who require electricity to power life-support equipment.

While these requirements typically apply to the “sale of energy,” they do not easily accommodate the proliferation of behind-the-meter technologies and evolving business models. The sale of energy devices, such as solar PV, energy storage, and energy-management systems, is not covered by energy consumer protection frameworks, rather the Australian Consumer Law (ACL) provides customers with the generic protections, which apply to the sale of all goods and services nationally.¹³ The Australian Energy Regulator (AER) and Victorian Government have also developed approaches to exempt some nontraditional energy sellers from NECF provisions that are not applicable or overly onerous relative to the type and level of supply. Examples include the on-selling of power to a small number of customers within a microgrid, such as apartment complexes, retirement villages, or shopping centers, and the sale of energy from solar PV via “power purchase agreements” (PPA) to customers that are connected to the national electricity grid. A hierarchy of consumer protections has therefore been established: supply from, and connection to, the national electricity grid are “primary,” whereas supplies from other sources and technologies are considered as “supplementary” and subject to lesser consumer protections.

As a result, the business model by which a technology is sold to a customer is a key determinant of the level of protections afforded for the supply, including eligibility for energy rebates and concessions, rather than the degree to which the customer depends on the source to meet their energy needs. Table 14.3 presents a summary of how this framework currently applies to different solar energy products currently available to customers in the NEM.

As energy-supply arrangements for customers become more complex, and with grid-supplied energy likely to represent a shrinking share of total electricity use for many households, this framework may not be sustainable; recall from Section 4 that customers with solar PV and battery storage systems may source as little as 12% of their daily energy supply from the grid. Some customers may seek multiple trading relationships with retailers, for example, to charge an EV separately from household supply, raising questions of primacy, while others may wish to leave the grid altogether. Under the current pricing structures, customers that are exclusively supplied from the grid, including low-income households with limited access to DERs, would bear a disproportionate share of the costs of providing a consumer protections safety net for all customers. Opportunities for regulatory arbitrage also arise when suppliers are required to comply with different standards for the provision of products that are effectively in competition with one another. Distributed technologies are often marketed as favorable compared to the cost of grid supply, but consumers may not realize that a reduced obligation to provide consumer protections forms part of the cost differential.

While efforts have been made to streamline these connection processes for retail customers—such as requiring DNSPs to provide a connection offer for all “basic” installations and to publish relevant information on their websites—application processes are not standardized and each DNSP has established different technical requirements, with jurisdictional safety regulations in some cases overlaying additional complexity. The level of technical information required for applications, associated costs, and processing times vary widely. In some distribution network areas, solar PV systems up to 10 kW are considered to be basic, while in others the threshold can be as low as 3 kW. Some DNSPs in the NEM regularly process simple applications within 24 h, while others take the maximum 10 business days allowed by the National Electricity Rules, and a couple of DNSPs have introduced fees of up to A$200 to process new connection applications.¹⁵ Upon application, some consumers are being informed that they cannot install solar systems of a certain size, or cannot install systems at all, in some cases because the network is already saturated. With continued technology uptake, this experience may become more common, particularly given that networks in the NEM are not required to publicly disclose the level of available capacity at the local feeder or transformer level. Long and complex application processes, additional costs, connection refusals, or other limitations on the use of DERs—such as system-size restrictions or output curtailment—may pose barriers to optimal technology installation.

Under current rules, connecting new energy-consuming devices, such as air-conditioning units or swimming pool pumps, does not typically require network approval, despite the potential for high coincident demand to strain infrastructure and necessitate additional augmentation. This may be changing, with some DNSPs proposing that home EV charging be placed on a “controlled load” circuit, where customers receive lower electricity rates, but are restricted as to the times they could charge their vehicle. However, this may not provide customers with the flexibility they desire. While the introduction of dynamic and cost-reflective pricing can incentivize customers to optimize their use of both demand- and supply-side technologies, a technology-neutral framework for grid connections should also be considered.

As consumer preferences change, regulatory frameworks may need to evolve to define a “right” for customers to install behind-the-meter technologies, particularly where primarily intended for self-consumption. The community may not consider connections processes to be equitable or reasonable if they result in some customers being granted permission to install devices that reduce their energy costs, while neighboring properties are denied the same opportunity. Likewise, it is unclear why safety and technical requirements for simple connections should vary significantly between jurisdictions, presenting an opportunity for standardization. With distributed technologies offering a partial or full substitute for grid supplies, policymakers could also consider whether it is appropriate to establish an independent arbiter to assess connection applications to ensure that information asymmetry is not being used to prevent legitimate deployment of new technology. New tools that provide transparent and granular information concerning the grid’s capacity to host DERs, similar to those being developed in California as described by Picker in this volume, could also be valuable in the NEM.