The current National Electricity Market (NEM) has had more than 150 rule changes since 2005, none of those changes, however, compares with the magnitude of the current proposal to change the market settlement period to five minutes from the existing 30 minutes. So how did this latest proposal emerge and what are the implications of a shift to a shorter settlement period?
The NEM is a gross pool market where all electricity supplied to the market and consumed by end users is transacted at the spot price. As it stands, market participants (generators and market-responsive loads) are “dispatched” (told their targets for operation) at five minute intervals. The price they receive is settled on a thirty minute basis, calculated as the average of the spot prices during the preceding six, five-minute intervals.
The Australian Energy Market Commission (AEMC) is considering a rule change, proposed by Sun Metals Corporation Pty Ltd, to change the settlement basis to five minutes, thereby aligning it with the dispatch interval.
The current NEM was introduced in 1998 and has had more than 150 rule changes since the AEMC was established in 2005. Many of those changes have been incremental, for example, clarifying the definition of Business Day, but there have been some notable material changes, such as the abolition of the Snowy Region. None of these changes compares with the scale of the proposal to replace the existing five minute dispatch–thirty minute time-weighted average settlement market with a five minute dispatch–five minute settlement market. The dispatch and settlement process is the “engine” of the wholesale market. It delivers 95-99 per cent of revenue to generators, and underpins the financial contracts for difference that stabilise the market.
At face value, aligning the dispatch and settlement intervals is more economically pure than the existing market design and would have the benefit of matching a market participant’s reward to its operation, however the spot market does not operate in financial isolation. Instead it is intrinsically linked to the underlying contract and derivatives markets and changing the settlement interval will not only disrupt these markets in the short-term, but will also have a marked effect on market participants’ risk profiles and risk management processes.
Acknowledging the fundamental nature of the intended change, the AEMC is proposing a transition period to mitigate the anticipated implementation and ongoing costs. While a transition period may assist in replacing short-term electricity contracts as they expire, long-term contracts, such as power purchase agreements, will receive no benefit from a transition period (and may in fact strike complications if a “change of law” clause is triggered), nor will the implementation costs reduce appreciably. In fact the proposed three year transition period may be manifestly inadequate for the anticipated unbudgeted IT system changes, since many market participants may be reliant on the same IT expertise and external service providers to conduct the necessary changes – a resource which may not be available due to the concurrent demands. In addition, the multiple systems affected, which include metering systems, bidding systems, trading systems, risk management systems and settlement systems, are deeply interrelated, and changes will be complex and carry a high risk of failure.
While there are questions about whether the benefits of the proposed change will exceed the implementation and ongoing costs, there are more serious concerns about the rule change’s effect on system security during the transition period and beyond.
Both existing fast-start plant and the newest generation of fast-start gas turbines have physical limitations in the speed at which they can respond to dispatch instructions, and they use the thirty minute settlement period to derive a return. If the settlement period is shortened, it is expected that price volatility will increase, and fast-start plant will be unwilling to respond, since it would be unlikely to derive a reasonable return for its minimum run time.
The ability of that plant to generate a return will therefore be compromised and ultimately its longevity shortened, as companies mothball or retire plants not producing sufficient return, and reconsider investment decisions in any future plant. Ignoring the fairness of changing the market basis under which such plants were planned, financed and built, this could be a tolerable outcome if alternative technologies were available to meet the market demand, but despite a bevy of press releases, the reality is far from clear.
In the absence of alternative payment mechanisms such as a capacity payment, existing fast-start plant will be squeezed out of the market and variations in demand will be addressed by either new technologies (to the extent they are able to do so on a large scale) or other existing technologies such as coal, which, while running as baseload, will have some ability to increase (if they have additional capacity available) or decrease supply at short notice. Perversely, this means that rather than encouraging the installation of new, greener technologies, five minute settlement may have the effect of keeping coal-fired generation (with its associated emissions) running longer than would otherwise be the case. That would hamper Australia’s move to a lower-emissions environment.
Other unexpected outcomes may also occur. For example, very responsive technologies, such as batteries, may generate for only a portion of a dispatch interval, thereby sustaining high prices and increasing their returns, but at the cost of system security and stability. This may mean that the very fast response from these technologies in response to price outcomes may result in a requirement to source additional ancillary services to manage frequency stability.
Problematically, unless the proposed new technologies are of sufficient size to warrant registration and scheduling in the NEM, then AEMO, which relies on accurate supply and demand information to run the wholesale market and ensure the security of supply, will be blind to a large part of the market. This will be exacerbated by increases in the amount of generation and storage installed behind the meter, with no oversight of its supply and demand profile or intentions. This problem could have been mitigated by two proposed rule changes, collectively known as the “Non-scheduled generation and load in central dispatch Rule”, that would have extended the dispatch obligation. Unfortunately, the AEMC have just issued a draft decision that they are not minded to make this rule[i].
The AEMC commissioned analysis from EnergyEdge on potential impacts in the contract market, which calculated that there is likely to be a 625MW reduction in the availability of cap ($300/MWh strike) products, and further volume reductions from bilaterally negotiated contracts. This reduction in the availability of cap contracts will have a detrimental impact on market participants’ ability to manage risk and would be felt, particularly by second and third tier retailers. As a consequence it would be expected that competition in the retail sector would decline, as second and third tier retailers would be at a significant disadvantage to large retailers, who have alternative means to manage their risk.
In summary, the draft determination for the proposed rule change is expected to be published in July 2017 with the final determination to be published in September this year. AEMC argues that the change will introduce a market where the price provides signals for supply to respond to demand in the shortest practicable timeframe, and this will drive more efficient outcomes[ii]. The shift will improve the pricing signals provided to NEM participants to encourage efficient market behaviour, but it is likely to result in:
[ii] AEMC Directions Paper
At the end of November each year, the AER and ESC publish their assessments of the performance of the retail market for the previous financial year.
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