Australia is a canary-in-the-coalmine when it comes to DER reshaping the way the grid operates. With 1.6 million residential PV installations as of 2015, some of the highest retail electricity prices in the OECD largely driven by fixed network costs, Australia is faced with a unique challenging in solving for the value of DER on the grid.
The specific challenge is that the economic impact of unmanaged DER deployment is likely to have a much greater cost impact to Australian consumers at a much lower level of penetration than in other global markets, because far less cost is avoided from DER substitution of generation than in places with similar DER penetration levels, such as Hawaii, California, or parts of Europe. Therefore, unlike in markets such as Hawaii, the primary value driver of DER on the grid cannot be to offset variable costs, namely the cost of central generation. Rather, DER must be harnessed methodically to offset the need for new network infrastructure, and eventually to lower the delivered cost of electricity to consumers.
The stakeholder process involved a vigorous analysis of the role of markets vs. controls to harness the role of DER on the grid, and the conclusion of the analysis is that, in the long term, DER must be economically rewarded for the value they provide the grid. This can be accomplished through increasingly sophisticated price signals.
The result, Energy Networks Australia and CSIRO concluded, is a dynamic network optimization market where DER services are traded on both a locational and temporal basis, based on system conditions.
CSIRO asked Strategen to conduct a survey of future visions of the grid around the world, and to look at pilot DERMS projects and innovative DER service valuation and procurement mechanisms, in order to determine some of the global best practices that could be applied to the Australian context. The objective was to develop a roadmap over the next decade that enabled a balanced scorecard of outcomes underpinned by increased consumer choice and control.
The survey was eye-opening. While the concept of transactive energy and distribution markets are widely discussed as a key component to allow increased consumer choice, lower costs, and a cleaner energy future, the approaches being taken around the world are all across the board, and involve varying levels of markets and controls.
Globally, most approaches tested to date are pilot projects designed to test a particular technology or pricing structure; few if any are being done as part of a comprehensive roadmap towards a particular end state. New York and California are perhaps the two jurisdictions taking the most holistic approach, but neither are building the type of comprehensive roadmap informed by a thorough analysis of future grid outcomes. California is focused more on meeting state environmental policy objectives (including promulgating greater amounts of DER on the grid), while New York’s REV initiative started with a desired market design end state rather than an analytical assessment of likely grid outcomes and objectives of the power system
Australia, on the other hand, started from the perspective of creating the right tools to optimize the role and value of DER on the grid and enable greater consumer choice and control, while doing so in a no-regrets manner based on the likely range of potential grid outcomes in 2050.
Through this ‘balanced scorecard’ lens, CSIRO and Energy Networks Australia developed a roadmap of the standards, controls and communication infrastructure necessary to support Australia’s future grid, and the advanced retail markets necessary to enable DERs to be valued for the services they provide.
The roadmap makes a strong case for the development of network optimization markets, given the likely trajectory of Australia’s grid. Tariff reform, and ultimately the potential development of dynamic, digital “network optimization markets” at the distribution level will help bring down non-coincident substation peak demand, and in the long run provide more than $400 in savings to the average residential customer per year. All told, total electricity system expenditures in 2050 will drop by about 10% by following the roadmap (from $988 billion to $888 billion).
The roadmap lays out several stages of grid transformation required for the outlined market transformation. The first stage involves implementation of communication protocols between networks and DER, including smart meters, as well as implementation of advanced planning and DER valuation modeling work similar to what’s been happening in California. Once this basic infrastructure is in place, advanced forms of rate design can be put into place, enabling greater alignment of customer demand with supply and the grid’s capabilities.
Implementation of the second stage of the roadmap begins when moderate to high levels of DER are in the system. Stage two involves the provision of DER grid services, perhaps through procurement mechanisms beginning to emerge in places like California and New York – although it should be noted that California’s solicitations for DER to date are just the tip of the iceberg, given they are primarily focused on local capacity and wholesale market participation, with only a few cases of assets being procured for distribution deferral. In addition, distribution level asset optimization and transparent information dissemination is a requirement at this point in the grid transformation. The distribution network optimization market should be under development at this stage as well.
The third stage – likely not occurring for another decade – involves the potential launch of a digital network optimization market, enabling peer-to-grid and perhaps also capable of supporting peer-to-peer market transactions, for energy and potentially other grid services. In our view, some of the mechanisms put into place to manage wholesale market transactions and grid controls can be a good proxy for how the potential distribution-level markets might work. For example, long term needs (such as a peak shaving contract meeting a distribution deferral need) can be addressed through long term contracts with DER, but with a must offer obligation into the distribution level market once it comes into existence. Likewise, automated controls and functionality from smart inverters can be marketized, similarly to how an ancillary service is bought & sold on the market, but during commitment periods directly controlled by the wholesale market operator.
The unification of all forms of procurement mechanisms, controls, and other value streams for DER is, in our view, an essential component of achieving a vibrant, well-functioning grid in a high DER environment. This is because the patchwork of competing signals from various mechanisms being deployed today to value DER may have unintended grid impacts resulting in forecasting errors and higher costs to customers. In addition, these competing signals are much harder for DER operators to manage, and could result in sticker shock for end use customers if, for example, a demand charge threshold was triggered due to participation in a wholesale market.
1. Sources: AEMC, 2014 Residential Electricity Price Trends Report, 5 December 2014, Sydney. California Public Utilities Commission Advice Letters: PG&E “4805-E-A” (Mar. 22, 2016); SCE “3319-E-A” (Dec. 23, 2015). Hawaii Public Utilities Commission Docket No. 2010-0080 “Hawaiian Electric 2011 Test Year Rate Case.” Thalman, Ellen. "What German Households Pay for Power." Clean Energy Wire. N.p., 26 July 2016. Web.
2. Assumes AUD $1.30 per USD $1.00.