Electricity industry economics are highly complex and uncertain. This is not surprising, given that the industry must match variable and unpredictable supply to similarly variable and unpredictable demand at all times and all locations for an invisible and intangible “commodity.” Demand arises from the diverse, changeable, and only partially predictable behavior of energy end users to provide desired energy services of widely varying perceived value. The “commodity” itself flows instantaneously through a specialized grid according to complex network physics (with the exception of site-specific pumped hydro), lacks cost-effective direct electricity storage options, and has specific power quality requirements.

There is a range of existing and potential future generation options to meet this demand, with sometimes very different technical and economic characteristics. Conventionally, there have been significant economies of scale, and generation assets have been large, lumpy, and irreversible. The electrical network itself is highly asset-intensive and shared by all electricity providers and consumers. Given this investment intensity, it can be useful to think of the economic value (net benefits) of electricity as having two key components: an energy (supply) value and a network (delivery) value. These components have both fixed and operational costs. Typically, demand has been widely variable and not responsive to changing supply conditions, meaning that large amounts of generation and network are required to supply only occasional periods of particularly high demand. There are also a range of significant environmental and social “externalities” associated with current electricity provision, such as regional air pollution and climate change emissions from key generation technologies.

The real cost and value of electricity, therefore, varies by time and location within the network, depends in large part on the industry's wider social and environmental impacts, and is subject to a wide range of uncertainties. Electricity industry arrangements invariably only capture some aspects of these underlying economics. In some restructured electricity industries, wholesale electricity prices (and associated futures prices) exhibit the temporal and spatial variability and uncertainty of electricity's energy and network value to some extent (MacGill, 2010). However, commercial arrangements for retail electricity consumers are generally far less reflective of these costs and benefits. Many energy users have only basic meters that report cumulative energy consumption, and pay flat electricity tariffs that combine energy and network costs, which have often been set to achieve broader societal objectives within a framework of overall industry cost recovery.

By comparison, mini-grid system economics may be considerably less complex and uncertain, given a much smaller number of generators and loads, and far simpler networks. Still, full economic modeling of these systems remains challenging. In conclusion, the electricity industry has extremely complex and uncertain economics, within which the specific economics of PV and energy storage, and their combination, must be assessed.

10.2.2 PV Economics

PV economics add further challenges to economic assessments. PV technologies convert a highly cyclical, variable, and somewhat unpredictable solar resource with no inherent storage into electricity through a solid-state device with virtually no energy storage either. PV's generation can often exhibit a useful, and hence economically valuable, correlation with daytime periods of higher demand. Furthermore, it is by far the most scalable of all current generation technologies, ranging from appliance level (Watts) through residential (kWs) onto commercial and industrial (hundreds of kWs) to utility scale (tens to hundreds of MWs). It can also be easily integrated into the built environment. Hence, it can be located close to loads and potentially reduce network peaks and losses. Furthermore, it has no operational regional air polluting greenhouse emissions, uses no water or other consumables in operation, and produces no solid wastes (other than the system components themselves at the end of their useful life) (Oliva et al., 2013).

Still, the variability and uncertainty of PV generation has implications for its energy and network value, given the need to precisely match supply and demand. In general, variable and unpredictable technologies without inherent energy storage have lower energy value than those with some measure of storage in their primary fuel supply or energy conversion process, and some level of dispatchability (MacGill, 2010). This needs to be appropriately weighed against the locational flexibility and wider environmental and social benefits that the technology can provide. Another key factor is the level of PV deployment. Generally, the marginal economic value of PV, and any other generation technology, will decline as its penetration grows, although there are particular circumstances, such as the potential role that sufficient PV deployment might play in delaying or averting lumpy network investments, where the reverse can be true.

The present private commercial arrangements for potential PV developers have only limited alignment with these underlying economics. Utility-scale PV systems in a restructured industry such as the NEM will certainly see time-varying and to a lesser extent location-varying and uncertain wholesale energy prices. As penetrations grow, it is likely that the merit order effect will see times of high PV generation associated with generally lower prices as well. However, the NEM does not properly price the environmental externalities of competing, almost entirely fossil-fuel generation. Instead, there is an effective shadow price provided through the Renewable Energy Target (RET), which provides additional cash flow to eligible renewable generation. In other industries, these broader environmental, social, and economic (investment and jobs) externalities may be priced through feed-in tariffs or capital subsidies for PV.

At the retail market level where household and commercial PV systems are deployed, existing customer electricity tariffs, as noted earlier, don't generally capture underlying electricity economics to any real extent. Instead, the private attractiveness of PV deployment depends on nonreflective electricity tariffs and any other explicit PV support measures. Around 140 countries have implemented policies to support renewable power generation, with many of these targeted toward PV (REN21, 2014). Feed-in tariffs (FiTs), which provide a defined payment for eligible renewable generation, have been the most widely implemented policy mechanism. In Australia, recent support has involved an effective capital grant subsidy provided through the small-scale component of the RET and, for a short time, various state government feed-in tariffs (Watt and MacGill, 2014). Now, however, net metering of PV is near universal and sees customers offsetting their own load, or being paid a market set (low or zero) rate for exported PV generation. In a similar manner, FiTs are being wound back in many other jurisdictions, given falling PV costs and hence attractiveness, and budget pressures.

The economics of PV in mini-grids can be extremely compelling, as noted earlier, and system design will often be based around underlying system economics. However, there are fuel subsidies and unpriced externalities that do not always get appropriately factored into decisions regarding the deployment of PV. The most important factor in PV economics, however, has been the marked fall in system costs over the past decade. These price reductions—more than 75% in Australia over four years (Watt and MacGill, 2014)—have entirely transformed PV economics and driven very widespread uptake, even when explicit PV policy support is being reduced or entirely eliminated.

10.2.3 Energy Storage Within the Electricity Industry

Energy storage has always had an important role in the electricity industry in various forms. In a general sense, energy storage is the storing of some form of energy that can be drawn upon at a later time to perform some useful operation. Given the need to match supply and demand, this is a critical function At present, most energy storage within the electricity industry resides in fuel supplies for the major generation technologies—coal stockpiles, gas reservoirs, and pipelines for fossil-fuel plants, and water reservoirs for hydro generation. Interestingly, the large fossil-fuel plants effectively have an energy storage problem in terms of minimum operating levels, ramping rate constraints, and high start-up and shutdown costs and time frames. Early efforts at electricity energy storage, including pumped hydro (discussed elsewhere in this book), were intended to help meet varying demand with somewhat inflexible plants. In recent years, however, such electricity storage was displaced somewhat by fast response gas peaking plants.

Now, of course, electricity industry developments in numerous jurisdictions, including Australia, have raised new challenges yet also opportunities for the electricity industry and its operation (Kind, 2013). One development has been the growing deployment of highly variable and somewhat unpredictable renewable energy, primarily wind and solar. Another challenge is that of increasingly peak demand in the residential (and to a lesser extent commercial) sectors, where average demand has been falling due to a range of reasons including energy efficiency and distributed generation, yet peak demand has not, or certainly not to the same extent. The distribution network assets, and hence associated capital expenditure, required to ensure that projected future peak demands can be met have seen growing network expenditure and hence overall industry costs. Technologies that can assist in better managing such peaks therefore offer potential network value in avoiding or deferring such expenditure.

At the same time, a range of emerging distributed energy storage technologies has seen growing technical and commercial progress. These particularly include a range of battery technologies whose development has been driven by factors including portable electronics and electric vehicles. Others include compressed air storage and flywheels. There is also a range of thermal energy storage options. More generally, there are other emerging technologies such as remotely controlled end user appliances (Commonwealth Scientific and Industrial Research Organisation, 2013) (e.g., “peaksmart” remotely controllable air-conditioning now being deployed in Queensland) that effectively take advantage of the inherent energy storage available with some end user energy services such as heating and cooling. Some of these technologies, particularly the battery and smart load options, are highly scalable from residential to commercial, industrial, and utility applications within the distribution network.

There is nothing new about variable and uncertain electrical loads and unpredictable generation, nor peak demand challenges in terms of both supply balance and network management. Neither is there anything fundamentally new in the use of battery technologies for electricity supply; they have been in use for stand-alone systems in remote areas as well as in uninterruptible power supplies (UPS) for critical end user loads for decades. However, trends with both these electricity challenges and energy storage technology opportunities would seem to have created a potentially valuable role for greater deployment of distributed energy storage in the electricity industry (Roberts, 2009).

Perhaps unsurprising, the economics of storage are very challenging to assess. In part, this reflects the broad range of technologies and activities that provide some measure of energy storage, or equivalent service, including demand management as well as these new electrical energy storage technologies. It also reflects the very wide range of potential value that storage can bring to the electricity industry. Storage can add value at the point of the energy consumer by providing greater customer reliability against possible supply interruptions and more economically efficient demand profiles; at the wholesale level as supply costs and demand value vary across time, from periods of seconds (ancillary services) to days to potentially months; at the network level by reducing peak demands and hence network expenditure; and at the retail market level through changing customer patterns of demand upon the system. There is an important question around which of these roles are most valuable (Sue et al., 2014), and how these values are changing as new consumer technologies enter the market.

Storage also poses particular challenges for commercial arrangements, again in part due to the varied technologies and roles it can play. For example, electric storage is both a load and a generator, depending upon particular circumstances. A particular opportunity would seem to lie in distributed applications because of the potential network and customer value that distributed storage can provide, and the lesser competition in these roles posed by conventional large-scale storage options. However, it faces the same disconnect between commercial incentives and underlying economics faced by PV in retail markets.

For the particular context of the Australian NEM, one study has suggested that, economically, the most significant storage applications currently appear to be for increasing end user reliability and deferring network expenditure, although energy arbitrage in the wholesale electricity market also offers potential value. The value of particular projects is very dependent of course on customer values of reliability and network constraints (Sue et al., 2014). Other work has also highlighted the potential role of storage for wholesale energy arbitrage (Wang et al., 2014). Another identified area for high-value storage applications, particularly relevant to this chapter, is in stand-alone and remote mini-grid applications, largely in partnership with PV, as discussed in the next section.

10.3.1 Household Systems

As noted earlier, residential PV deployment has generally occurred within the context of immature and somewhat dysfunctional retail market arrangements, featuring significant cross-subsidies across and within customer classes (Outhred and MacGill, 2006). Tariffs are largely consumption based and generally still involve flat rates (c/kWh) for residential and small business customers, although there are growing moves toward time-of-use (TOU) rates as metering infrastructure is upgraded. Small businesses had the same commercial arrangements until recently, when demand components have been increasingly added to tariffs.

Complex and challenging interactions can arise with household PV, depending on the metering and tariff arrangements they face. Gross metering and Feed-in Tariffs (FiTs) for PV provide payments based only on the total generation of the system and do not create a commercial case for storage.

However, net metering arrangements, where less-than-load PV generation during a given period effectively offsets consumption (and the corresponding retail tariffs) while periods of net-PV export see the exported PV generation paid at a different tariff, can create a number of commercial possibilities for storage. If the export and retail tariffs are the same, as seen in many US states at present, then there is no value in moving PV generation (or load) across time. However, there are examples of FiT arrangements where the export FiT is far lower, or far higher than the retail tariff. Under such circumstances, there are potentially significant financial advantages in deploying electricity storage and/or load management.

The commercial value of this will depend greatly on the retail electricity market and PV support arrangements in place. It will also depend greatly on the actual performance of the PV system, household load pattern, and the match between them.

Some work has explored these issues for the Australian National Electricity Market (NEM), given a range of retail electricity tariff options (flat and TOU rates) and different PV net FiT tariffs for households with PV and load management options (Oliva and MacGill, 2014). It found that households can certainly deploy load management to either reduce or increase PV generation exports to increase the financial returns of the PV. The extent of these returns depends on the particular households' PV generation and load profiles.

Other work has modeled the use of battery storage systems in the NEM under a similar context (Goel and Watt, 2013). Lead-acid battery systems were added to a sample of Australian households with PV systems. It was found that at current PV and battery system costs and retail and net FiT PV tariffs, battery storage only improved payback periods for larger PV system sizes (above 4 kW) when significant PV exports would occur at very low net FiT rates.

Another finding of both studies was that there were potentially adverse or beneficial impacts on the network service providers under these circumstances of battery storage or load management. PV systems alone had almost no impact on reducing peak network demand. However, load management to shift evening load into the day or charging the battery system when PV was generating could both reduce PV exports and significantly reduce household peak demand in the evening, and hence necessary network infrastructure. Conversely, load management to shift load from daytime to evening to maximize PV exports could worsen impacts. This work highlights the possibility that private commercial arrangements may work toward improving or worsening underlying industry economics, depending on the price signals proved to customers.

10.3.2 Commercial and Industry PV

Larger retail customers such as commercial and industrial facilities typically have more sophisticated metering and tariff arrangements. In the Australian NEM, they generally have separate regulated network tariffs and competitive retail energy contracts. These network tariffs generally have TOU consumption and peak demand components. Retailer energy tariffs also typically have TOU rates. Generally, connection at higher voltages and larger consumption mean lower energy tariffs that reduce the competitiveness of PV to displace load. However, falling PV costs are changing this equation, and the good match between PV and typical commercial load profiles adds value via peak demand reduction. There are often fewer commercial incentives to greatly oversize systems above typical levels of demand, and prohibitions on export are typical, hence there is less question of PV export rates.

However, there are other opportunities for energy storage—for example, the widespread use of uninterruptible power systems (UPS) on critical business loads that already represent some local level of electricity storage. As penetrations of renewable energy grow, so will the likely need for additional energy storage, and commercial arrangements will likely have to be changed to better incentivize its deployment.

10.3.3 Distribution Network-Driven PV

Although PV doesn't contribute to network peaks, it doesn't generally play a large role in reducing them, certainly in predominantly residential networks with typically evening peak demands and no tariff incentives to change consumption patterns. There are certainly potential roles for storage to assist in this regard, and storage deployed with PV systems could add further value. However, high PV penetrations in the network can certainly raise some other concerns, which are also seen with other distributed generation technologies. Reverse power flows at times of high PV export in networks designed and operated for unidirectional power flows can cause issues, including high voltages, harmonics, phase imbalance, and challenges for protection systems (Passey et al., 2011). Voltage rise has been identified as a particularly important challenge (Braun et al., 2012).

We are now seeing new policy developments to facilitate greater battery deployment with PV. Germany has recently introduced an energy storage financing program to facilitate the deployment of PV systems with battery storage for residential and commercial customers (Parkinson, 2013; Colthorpe, 2014a,b). Japan now also offers subsidies to support the installation of battery storage along with PV systems (Colthorpe, 2014a; Wilkinson 2014). Such battery systems can of course offer potential value beyond that of managing adverse impacts of PV. However, as noted earlier, commercial arrangements in current retail electricity markets do not necessarily provide appropriate financial incentives for such actions, and there are also a number of technical challenges in effective coordination.

Furthermore, battery storage systems and load management are only one possible means of addressing adverse impacts on distribution networks from PV deployment. Other approaches, including reactive and active power management utilizing the capabilities of PV system inverters, tap changers on transformers, and network reconductoring, can also be used (Braun et al., 2012). Battery storage systems may not be the lowest cost means of addressing adverse impacts in many circumstances (Tant et al., 2013), a common theme in the economics of PV with storage systems. Battery storage systems are highly capable but also currently expensive compared with a range of other options, and because the simpler and cheaper grid inverters must be replaced by more costly bidirectional inverters. It is notable that the uptake of the German support scheme for battery storage to date appears to have been relatively slow due to the less than compelling economics, even with subsidy support, although the complexity of the scheme has also been identified as an issue (Colthorpe, 2014b). With time, the value of such approaches should become clearer.

10.3.4 Utility PV and Storage Systems

It may sometimes be the case that the optimal location of storage in the distribution network isn't at the site of the PV systems themselves, creating a case for their deployment at strategically chosen parts of the network. Australian utility Ergon Energy is starting to deploy storage across its network, with a view to reducing costs of service provision in low-density areas (Ergon Energy, 2014). The general challenges of integrating greater levels of renewable generation (particularly solar) at the system-wide level, and the potential role of energy storage, have received some attention (Denholm and Margolis, 2007; Denholm et al., 2010), and motivate a number of chapters in this book. Several complicating factors for such estimations include the potential mix of other generation and level of demand-side participation, and hence the range of options that can be used to assist in ongoing supply-demand balance.

It should not necessarily be assumed that energy storage will be required. For example, a number of scenarios for 100% renewable electricity generation for the Australian NEM have been undertaken that do not include load management or additional electricity storage systems beyond existing hydropower, yet still achieve the required levels of reliability (Elliston et al., 2013). Instead, a range of technologies, including a number with inherent energy storage in either the fuel source (biogas turbines) or through additional thermal storage (concentrating solar plant with molten salt storage), can suffice. Another study for the Australian NEM undertaken by the Australian Energy Market Operator (AEMO, 2013) found additional value from some level of load management, but concluded that additional electricity energy storage through battery systems was not cost-effective at expected prices.

There has been some research on the potential to integrate energy storage into larger commercial and industrial sites through to utility-scale PV systems. For such applications, private commercial incentives are of key importance, and these depend critically on the market arrangements in place. Key aspects of these include time and locational wholesale pricing, and the management of short-term supply-demand deviations through ancillary services. Some work, for example, has looked at the use of battery storage to smooth PV output (Ellis et al., 2012). There is, of course, the potential for storage to be deployed quite separately from particular renewable energy projects. In idealized market arrangements where all potential values of PV and storage are appropriately priced, energy storage might be considered entirely separately. In practice, there are advantages to be had in collocating the PV and storage, including the ability to share site and network infrastructure. Furthermore, there are still potential mismatches between commercial arrangements and underlying economics that may support local storage—one example is the use of storage to cover ancillary loads at PV plants in the NEM (Wang et al., 2014).

10.3.5 Mini-Grids

Mini-grids represent an interesting and important midway point between stand-alone and major grid electricity systems. They typically serve remote communities that are not economical to connect to large grids due to their isolation, but that have a sufficient density and diversity of end users so that it makes sense to connect them together rather than supply them all with stand-alone systems. The use of a mini-grid also permits the use of generation technologies that might not be feasible or economical at smaller scale, such as multiple diesel gensets or biomass or small hydro facilities.

The International Energy Agency (IEA), among others, foresees a critical role for mini-grids in providing universal energy access in developing countries that still haven't achieved near complete electrification (Yadoo and Cruickshank, 2012). There are also some mini-grid deployments in developed countries for isolated communities, such as those on islands, or those located in particularly harsh and remote locations. Australia has a number of these.

Many of these systems are currently based on diesel gensets, given their relatively low capital costs, operational flexibility, and controllability. However, diesel fuel is expensive and, in many of these locations, difficult and expensive to get to site. The cost of diesel genset electricity is, therefore, generally considerably higher than electricity from large-scale grids, although less than for stand-alone systems. There is growing interest in PV deployment, and a growing view that the savings in diesel fuel can more than offset the capital costs of these PV systems.

To maximize the benefit of PV, therefore, the systems need to maximize the displacement of diesel operation. However, conventional diesel gensets have operational difficulties when continually run at low operating levels. The gensets are easy to start and stop, and any interruption to the PV generation when completely supplying the load will lead to supply interruptions. There is, therefore, considerable interest in electrical energy storage in such systems through battery and other technologies. In Australia, there are PV-diesel-storage systems deployed on King Island and Cape Barren Island (battery systems), and a number of isolated diesel grids in Coral Bay and Marble Bar (flywheel systems).

While there have generally been reasonably attractive economic cases for these systems, there have been some challenges in practice. In part, these reflect ongoing technical challenges with batteries, and to an even greater extent, flywheel technologies. However, there is also the high cost of the energy storage systems that, together with these technical risks, makes the commercial case challenging (Hazelton et al., 2014). Furthermore, there are other options that can offer some level of equivalent supply-demand rebalancing, including low-run diesel gensets and load management, potentially with considerably less technical complexity and costs. The economics of diesel genset operation are also complex and not well incorporated into analysis at present—for example, the costs associated with periods of low-output operation or increased stops and starts.

Interestingly, there may even be a move away from the use of storage systems toward straight PV-diesel systems, given their technical simplicity and rugged performance, while still providing useful diesel savings (Corporation, 2014). This might suggest some level of caution regarding uptake of storage with PV systems on the main grid.

Still, recent work for high-value applications of storage in the Australian context has highlighted what is seen as a material opportunity for supporting fringe and remote electricity systems to assist in mitigating unreliable supply, reduce expensive fuel dependence, and assist in managing supply-demand balance, including ramp-rate control of PV and protection of system stability (Marchment Hill Consulting, 2012). In countries like Australia, it may make increasing technical and economic sense to establish local mini-grids centered in regional or suburbs that are interconnected, at least in the short term, via existing electricity distribution networks.

The future for both PV and storage within the electricity sector falls within the broader context of potentially revolutionary change toward a smarter and cleaner power industry. A key factor here has been the emergence of a range of distributed technologies—generation, storage, and load—that may transform the industry entirely from its present large-scale and highly centralized supply and network infrastructure.

PV has been argued to be the most disruptive technology of these, in large part due to its scalability and wide range of possible end user roles. That would certainly seem to be the case to date (Schleicher-Tappeser, 2012). Should it continue to progress, the need to better match electricity demand with PV's daily cycles and weather-dependent generation will become a growing issue and require progress in demand-side technologies, such as controllable loads and electrical energy storage technologies.

There is considerable expectation of continuing falling battery technology costs (BNEF, 2012; Fuhs, 2014) driven, in large part, by the growth and technology development currently seen in electric vehicles. Indeed, an analogy to the extraordinary price reductions seen with PV is often made. However, there are some different characteristics to the technologies, notably that PV is a semiconductor, not a chemical technology, so that similar progress is not assured. It is perhaps surprising, and hence telling, that the venerable lead-acid battery technology that was first developed more than 100 years ago is still widely used in applications such as conventional car electrics, despite its many apparent disadvantages. Lithium-ion batteries have seen remarkable progress over the past decade, initially driven by mobile information and communications technology (ICT) applications and now mobile power applications such as electric vehicles. Battery costs of a range of technologies are certainly falling; however, major cost reductions will also need to see progress in other related balance of system technologies, estimated by Bronski et al. (2014) to represent around two-thirds of the costs of current battery storage systems, and almost three-quarters of residential system costs. Such progress has been seen with PV balance of system costs, so there is some precedent here.

A range of parallel smart technology developments, falling within the broad term “smart grid” and including smart meters and household Wi-Fi Internet connections, also promise to greatly improve the technical capabilities, while reducing the cost of monitoring and controlling distributed energy technologies. The implications for battery storage systems are mixed—these developments will reduce the costs of integrating these technologies, but also enable potential competition through greater demand-side participation, such as smart scheduling of loads with inherent energy storage.

There is a range of policy developments that might drive rapid progress, in a similar manner to that seen with PV FiT schemes in key countries. Recent German and Japanese policy measures for PV and storage were noted earlier. There is also a range of notable policy developments in the United States, which include (Bronski et al., 2014)

• FERC Orders 755 and 784, which facilitate utility-scale grid storage by defining grid-level use and accounting for frequency regulation and ancillary services that appropriately value the highly advantageous characteristics of fast-response battery storage

• AB 2514, which sets a storage target of 1.3 GW in California by 2020, including provisions to facilitate consumer owned or sited grid-connected storage

• California's Self-Generation Incentive Program, which provides subsidies for various generation and energy storage technologies (in particular, an approximate US$2/Watt credit for energy storage systems is facilitating solar and storage solutions)

Beyond these and perhaps additional efforts, the underlying economics of PV and energy storage will likely be the key factors. It is important to note that Schleicher-Tappeser (2012) argues that progress toward such transformation will depend largely on governance of the regulatory frameworks and the ability of key market players to develop appropriate business models. It is certainly possible that storage will have relatively little impact in countries where the deployment of distributed generation is slowing or where there are adverse changes in these regulatory arrangements. Clearly, there are some changes underway by utilities and their regulators in jurisdictions including the United States and Australia to reduce the attractiveness of distributed generation—notably by reducing incentives for DG, and changing underlying energy user tariffs, with greater fixed charge components. However, this does raise the intriguing possibility of utility and regulator attempts to block progress, driving a radical energy storage transformation through grid defection.

10.4.2 Grid Defection

There is growing discussion of whether new battery storage technologies might rid a growing number of energy users entirely of the need to remain connected to the main grid. The compelling economics of grid connection for almost all customers within areas served by the grid have made connection a given. However, this may be changing. The Rocky Mountain Institute (Bronski et al., 2014) has highlighted five forces driving the increased adoption of off-grid hybrid distributed generation and storage systems, even in areas that are served by the grid:

• Interest in reliability and resilience, notably given what would seem to be growing risks to secure grid supply from extreme weather events and increasingly stressed infrastructure

• Demand for cleaner energy, sometimes in the context of only limited mainstream support for cleaner energy by incumbent large-scale electricity industry players

• Pursuit of better economics, particularly in contexts where the economics of grid supply are marginal, including for remote, currently fringe-of-grid electricity provision

• Utility and grid frustration, a growing issue with some incumbent utility players seemingly directly impeding the uptake of innovative distributed energy options

• Regulatory changes by policy makers struggling in many cases to keep up with the rate of change being seen with distributed resources and often under pressure from incumbent players seeing their existing business models being damaged

Bronski et al. (2014) consider a scenario where more than 20 million residential customers in parts of the United States with high residential tariffs could “find economic advantage” in PV with storage systems within a decade, given moderate technology improvements in both solar and storage. Related work in the Australian context has also identified potential opportunities for customers to unplug from the grid (Szatow and Moyse, 2014).

Other work, such as that of the CSIRO future grid forum (Commonwealth Scientific and Industrial Research Organisation, 2013), has also explored possible scenarios that include substantial grid defection as distributed generation and storage costs fall, while the incumbent electricity industry fails to respond effectively.

This is not to say that grid defection will necessarily present the most societally economic outcome. After all, the grid represents a substantial public investment over more than a century and provides important opportunities to take advantage of the considerable diversity across generation and demand. However, there are currently considerable disconnects between societal value and private incentives under retail market arrangements, and some of the proposed changes to these might actually make this worse.

Riesz et al. (2014) highlights some possible future implications of this—in particular, the question of whether network connection remains the highest societal value approach for energy services delivery to particular customer classes, or whether distributed solutions disconnected from the grid become a lower societal cost. Given the apparently different drivers between public and private costs and benefits within the electricity industry, and broader motivations for some key stakeholders, it is of course possible to envisage futures where customers remain connected even when disconnection is more economical, and where customers disconnect even when this is not the economically highest value.

Even if disconnection is not the public or private least-cost option, the possibility of grid defection provides a potentially useful discipline on network operators and the regulators who are meant to regulate them for the greatest public good. Inevitable transition issues between the two are also likely.

10.4.3 What happens next?

The short answer, of course, is that nobody knows. The economics of PV and storage seem likely to play a key, although by no means sole, role. Together, the technologies offer the millions of energy users on the grid the opportunity to participate far more actively in delivery of their energy services. The private incentives they see from retail electricity market arrangements and any explicit support policies will likely play an important role in their decision making. Some might argue that the most important task ahead for policy makers is to better align underlying industry economics with such private incentives. Beyond the complexity of this, there are many reasons why there are limits to what may be achieved. Ideally, policy makers will look at how additional policy measures might better align stakeholders with societally valuable outcomes.

Falling PV and storage costs will of course improve both the social and private economics of deployment. However, that is unlikely to drive appropriate change in the absence of broader policy and regulatory efforts.

The International Energy Agency provides a suitably cautious assessment (IEA, 2014), noting that while electricity storage could play a wide range of roles in future energy systems, it is unlikely to be transformative given current costs and performance, in the presence of competing options both on the supply side (notably flexible and highly dispatchable plants) and demand side (including demand-side response and smart-grid options). However, the IEA also notes that electricity storage offers unparalleled modularity, controllability, and responsiveness, while current drivers for electricity storage (including the challenge of integrating growing variable renewable generation but also system planning and end user applications) are highly context-specific and will likely require changes to market and broader regulatory frameworks. It also notes that off-grid applications represent the most economically attractive deployment opportunities, offering sufficient additional value to offset their high costs. Such options provide, of course, an opportunity to better understand the technical and economic performance of such technologies.

For widespread grid deployment, however, the hard work of market and regulatory change, including the institutional and governance frameworks to direct such change (Sue et al., 2014; Passey et al., 2013), should not be underestimated, regardless of underlying economics.