What might the electricity market look like in a Physical RRO world? 10 min read
The Physical Retailer Reliability Obligation (the Physical RRO) – a signature piece of the 2025 National Electricity Market (the NEM) recommendations of the Energy Security Board (the ESB) – points to a fundamental market change for the NEM: moving from an energy-only market to a hybrid energy-plus-capacity market.1 The ESB's in-principle support for a capacity market, which has been endorsed by the Energy Ministers, entails crucial detailed design work to follow over the next 18 months.2
With many of the key capacity mechanism design elements yet to be resolved, we explore the magnitude of the proposed changes via a hypothetical glimpse into the future. What might the electricity market look like in a Physical RRO world, from the perspective of a generator, a retailer and the market?
Key takeaways
- Generators – reliability will be key for generators to secure capacity certificates and, over time, low-emissions reliable generation will be increasingly rewarded.
- Retailers – the ability for retailers to meet their certificate obligations while delivering efficient outcomes for consumers will come down to accurate demand forecasting, real-time demand response and the tradability of certificates.
- Market dynamics – the Physical RRO will create a new market for capacity certificates that are traded via a range of platforms, and various measures will mitigate the risk of potential market power and hoarding of Australian Reliability Certificates (ARCs).
Background
In March 2019, the ESB was tasked with advising on the required changes to the NEM, to ensure it can accommodate an increasingly diverse and distributed generation mix, while ensuring ongoing reliability of supply (see our overview).3
In August 2021, the ESB's final advice on the NEM redesign (the ESB Advice) was publicly released. In its advice, the ESB considers a proposal for a capacity mechanism achieved through physical certificates – the Physical RRO – where liable entities would be required to hold sufficient qualifying capacity certificates to underwrite their share of actual peak electricity demand.4
At their September 2021 meeting, the Energy Ministers agreed to 'progress further design work on a mechanism that specifically values capacity in the NEM', which is to be 'underpinned by principles that ensure the design for a market mechanism delivers investment in an efficient mix of variable and firm capacity that meets reliability at lowest cost'.5 This work is likely to take around 18 months.
With so many combinations of policy choices potentially available, this Insight seeks to explore some of the key design elements of a capacity mechanism by taking a (hypothetical) peek into the future – what might the NEM look like if the ESB's 'straw proposal' Physical RRO were implemented, from the perspective of a generator, a retailer and the market.
So, let's hop in our DeLorean and race forward to 2028 – our cities are buzzing again, the Los Angeles Olympics are underway and a Physical RRO is now embedded in the NEM.
The future of electricity capacity markets
Eligibility, certification of capacity and reassessments
The first thing we notice in 2028 is that all types of facilities are eligible to earn ARCs, issued by the Australian Energy Market Operator (AEMO). The ESB Advice prevailed in its push that certificates would be assessed for all types of resources which contribute to reliability, including renewable and conventional generators, demand side and storage.
Example 1: The gas-fired power station
Our first generator is a gas-fired power station, which, with its high fuel costs, only generates on one or two days a year, when the spot price is high enough to cover its fuel costs. However, it remains profitable, thanks to the Physical RRO and the ARCs that AEMO issues to it each year, which are linked to its ability to contribute to reliability during 'at risk' periods (with less 'firm' – ie less reliable – generators being de-rated).
The gas-fired power station is assessed as being very likely to dispatch electricity in 'at risk' intervals during the relevant period and is therefore allocated ARCs corresponding to its full capacity.
Mind you, the gas-fired generator had a difficult experience in last year's recertification process, following a failure to generate on a high-demand summer day that required AEMO market intervention. The failure led to uncomfortable questions about why the generator was not available, despite receiving ARCs on the basis that it would be available on peak days.
Example 2: The large wind farm
In contrast, while our second generator (a large wind farm) still earns ARCs, it is a less 'firm' generator and therefore is allocated ARCs on a de-rated basis relative to its installed capacity. As a result, it still relies on pool price revenue, the wholesale contract market and the sale of renewable energy certificates for its revenue. Notably, the days of renewable generators bidding into the market at a nominal price are long gone. Our wind farm now bids at a substantial (positive) price and is eyeing the looming expiry of renewable energy certificates with some concern.
Example 3: The new utility scale battery
Our third facility is a new utility scale battery, specifically designed to optimise output on peak demand days, matched to the Physical RRO design. The annual ARC allocation was a large value item in its business case. Its major challenge was a debate with AEMO about how its recharge policy and contractual commitments should affect its ARC allocation. But, now that is over, the long-term battery tolling agreement it signed means the offtaker pays the agreed fixed price each year for the ARCs that the battery produces.
Allocating certificates and tenor
After a few initial teething issues, the process for issuing ARCs for generators has now settled into a regular operating rhythm:
- ARCs are issued by AEMO annually, following an audited compliance self-assessment by each generator;
- each ARC is issued for 1 megawatt (MW) of available capacity (de-rated where applicable);
- each ARC has a vintage; it is only 'good' for a specified year;
- within each year, the vintage is further subdivided into eight sub-vintages, reflecting quarterly vintages split into peak and off-peak hours each day. Not surprisingly, while all ARCs have some value, the vintage covering peak hours in the summer quarter have quickly become the most sought after (and valuable) ARCs; and
- the ARCs are issued on a rolling three-year basis, with each generator receiving one-third of its approved ARCs for each of the following three years; Y1, Y2 and Y3.
Carbon discount
One twist in the Physical RRO is that, to address concerns the scheme might incentivise generators with the highest emissions intensity, it incorporates a 'carbon discount', where each generator's 'standard' ARC allocation is discounted to reflect emissions above the agreed benchmark. The discount increases over time, providing an increasing advantage to low-emissions reliable generation.
Teething issues
While the transition to the Physical RRO is now behind us, there were a number of challenges for the market to manage. Chief among these was the impact on legacy offtake agreements and wholesale market contracts, and on matters such as whether offtakers should receive ARCs for no additional charge; and the impact of the scheme on the electricity spot price.
The rule changes did not provide any statutory mechanisms to solve these issues, leaving it to market participants to sort things out themselves. Thankfully, a general consensus emerged across the market and, despite a handful of notable disputes, most contracts were updated without controversy.
Meanwhile, across town, electricity retailers are implementing their Physical RRO compliance strategies.
Like many of its predecessor energy policy schemes, the Physical RRO model imposes the compliance obligations mostly on electricity retailers, who have the twin attributes of being easy to identify and operating sophisticated billing systems. As the liable entities, retailers (along with some large customers and other customers who opt in) are required to hold sufficient qualifying ARCs to underwrite their share of actual electricity demand each year.
In preparing their compliance strategies, retailers ask themselves a few key questions.
What will demand look like for the relevant period?
Demand assessment: retailers are required to purchase ARCs to cover their actual load – rather than something close to it – which incentivises compliance and creates demand for certificates. However, retailers risk 'over procurement' of certificates if their forecasting over-estimates at-risk periods – which increases compliance costs for the retailer and, potentially, consumers.
Long-term planning: while large, integrated 'gentailers' have the benefit of being able to create their own certificates, other retailers have to consider what the optimum approach to certificate procurement is in the long term. For example, some large retailers have decided that it is most efficient to underwrite a new plant or storage system with firm supply rather than trade certificates on the market.
What is the risk of non-compliance?
Compliance assessment: under the Physical RRO, holding sufficient qualifying capacity certificates is an ongoing obligation. And, to complicate things, last year involved a reliability shortfall in the summer quarter (triggering Reliability and Emergency Reserve Trader activation/dispatch or unserved energy), which means all retailers are now caught up in a detailed ex-post compliance assessment process. If a retailer is found to have been short on ARCs for the summer quarter, it faces an enforcement action by the AER.
Penalties: under the Physical RRO model, the consequences of non-compliance are a combination of fines and penalties (consistent with the previous 'contract' RRO) and a hefty per-MW penalty for each MW of ARC shortfall. While the per-MW penalty quickly became a price ceiling in many ARC trades, a number of retailers are willing to pay above the (tax-adjusted) penalty rate, to ensure full compliance.
If I'm short on certificates, what can I do?
Curbing demand: demand response is commonly used in many jurisdictions to promote grid stability during peak usage periods. The Physical RRO model has increased the incentive for retailers in the NEM to engage in real-time demand response, so as to reduce non-compliance. Retailers effectively need to weigh the costs and benefits of incentivising consumers to reduce or shift electricity usage on the one hand, or bearing the penalties of non-compliance on the other. The widespread take-up of household batteries provides another avenue for retailers to incentivise and manage load-shifting away from peak times.
Trading certificates: the bulk of compliance is achieved by purchasing ARCs, which can be traded bilaterally (ie direct trades between parties) as well as through a central exchange. For most retailers, bilateral trading is the most cost-effective approach (often linked to offtake agreements that underwrite new facilities), while the central exchange facilitates spot trades to rebalance the ARC position.
In our hypothetical 2028, the Physical RRO has spawned a deep and liquid market in ARCs, which are traded via a range of platforms, including:
- ARCs tied to long-term offtake contracts, which typically comprise a combination of a contract for differences (matching the energy output) and a fixed price for the ARCs allocated to the generator;
- an over-the-counter market, including standalone trades of ARCs between market participants, which has seen the emergence of active financial trading participants and active ARC brokers; and
- exchange-traded ARC contracts, structured to match the vintages and quantities of the ARC and compliance requirements.
Fears of potential market power and hoarding of ARCs have been mitigated by a number of measures, including:
- a limited ex-post trading window, which allows market participants to rebalance their long and short ARC positions once they know what their actual requirements are;
- an ARC market liquidity obligation, which requires large generator groups to offer a minimum quantity of ARCs across all vintages for sale via the Exchange-traded ARC contracts. This provides smaller participants with a transparent, if sometimes clunky, mechanism to source ARCs; and
- the jurisdictional investment schemes also support market liquidity, with states offering for sale the ARCs they have sourced from generators they have underwritten. But the fragmented nature of these schemes has sparked calls for a coordinated procurement and sale of ARCs.
The ARCs themselves are:
- certificated and recorded on a central registry, in which market participants hold accounts;
- recognised as tradeable personal property;
- capable of being priced against a benchmark, thanks to the published prices for the exchange-traded ARC contracts; and
- treated as financial products for limited purposes, meaning they can be sold by the original generator without an Australian Financial Services Licence (AFSL), but will require an AFSL for secondary market transactions.
Actions you can take now
- Review the ESB Advice and engage with the upcoming consultation on the detailed design of the capacity mechanism.
- Carefully review new generator power purchase agreements and offtake agreements, to ensure the parties are clear about who owns any capacity certificates and how these are valued.
Footnotes
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ESB Post 2025 Market Design Final Advice to Energy Ministers Part C, Energy Security Board, 26 August 2021.
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Minister for Energy and Emissions Reduction, 'Energy National Cabinet Reform Committee' media release, 24 September 2021.
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ESB Post 2025 Market Design for the National Electricity Market (NEM), 22 March 2019.
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ESB Post 2025 Market Design Final Advice to Energy Ministers Part C, Energy Security Board, 26 August 2021, p 6.
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Minister for Energy and Emissions Reduction, 'Energy National Cabinet Reform Committee' media release, 24 September 2021.