This is part 1 of a 2 part series. This article explains the nature of the proposed reform to how generators will obtain access to transmission capacity. Part 2 will explain its implications for large scale renewable energy generators.
The Australian Energy Market Commission is currently deliberating over what is arguably the most significant market reform since the establishment of the National Electricity Market. Despite the magnitude of the proposal on the table, it appears to have gone somewhat under the radar, with the renewables industry far more focused on other forums such as the critical Renewable Energy Target Review process.
Under the Transmission Frameworks Review, the AEMC is at present considering a range of market reforms related to transmission planning frameworks, arrangements for connecting generation to networks, and network access pricing. Under this last aspect, it has proposed two options.
The first option is to leave the present NEM design essentially as-is, with some minor clarifications to the rules. The second option is to implement the Optional Firm Access (OFA) model.
Under the OFA model, generators would have the option to purchase firm network access from their network service provider. In exchange for a fee, the network service provider would be required to plan and operate the network to deliver that contracted level of firm access to that generator. If a network constraint binds, the rules determining the physical dispatch would remain unchanged from the present system. However, if a generator without firm access is dispatched ahead of a generator with firm access, “compensation” payments would be made, with the non-firm generator paying compensation to the firm generator (via AEMO).
This is illustrated in Figure 1, with more details provided at the end of the article for those who like to work through the numbers. The end result is that:
-- Firm generators become relatively indifferent to whether they are physically dispatched or not when network constraints bind – they will receive profits equivalent to receiving the Regional Reference Price regardless.
-- Non-firm generators will have to pay compensation payments when constraints bind, if they are dispatched ahead of a firm generator. However, they will never ‘regret’ being dispatched in any particular period, because their total payment (minus compensation payments) will always equal or exceed their bid price.
The AEMC is exploring the OFA model because it believes it has the potential to address several shortcomings of the existing NEM design:
-- Generator certainty – Generators would have the option to secure (and pay for) greater financial certainty, leading to lower risk and financing costs for generators. This will be of particular interest to peaking generators seeking to sell cap contracts, since it provides greater certainty of access to the market during peak pricing times (when they could be exposed to significant losses if they do not have market access due to a binding constraint).
-- Market-led transmission investment – Transmission investment would be partially driven by generators choosing to pay for firm access, rather than the “central planning” approach to transmission investment currently utilised in the NEM.
-- Generator locational signals – Generators would have stronger locational signals about where to locate, because the price they would pay for firm access would depend upon the incremental cost to upgrade the network to provide that access at each location.
-- Disorderly bidding – Incentives for disorderly bidding during network constraints would be reduced, since generator revenues would be less dependent upon physical dispatch.
However, the introduction of the OFA model would not be without challenges.
The AEMC recognises that implementation of the OFA model would be the most significant market change since the original creation of the NEM. Its implementation would be a highly complex and multi-faceted task over multiple years, requiring changes to institutional arrangements, regulatory frameworks, market settlement functions and extensive rule changes.
Furthermore, challenging and complex questions would need to be addressed around factors such as the manner in which access pricing would be determined. The AEMC proposes a ‘Long Run Incremental Costing (LRIC)’ methodology, which requires the necessary network upgrades to be costed and compared with a baseline in the absence of the new generator. This would be sensitive to assumptions about load growth and other generation connections over the lifetime of the generator, which is likely to make the LRIC methodology challenging to accurately implement in practice.
There are also questions around how much value firm access would provide to generators in practice. Even under the OFA model, firm generators would still be exposed to forced outages.
Forced outage rates (especially associated with unit start-ups) can be very significant for peaking units, and often will be a more significant limiting factor on their willingness to contract. This would not be addressed at all under the OFA model, potentially limiting its value in improving the liquidity of the contracts market and in minimising generator financing costs.
It is also important to appreciate that firm access does not imply guaranteed access. The OFA model requires the definition of a “Firm Access Standard (FAS)”, such that generators will only receive 100 per cent of their purchased access during “System Normal” conditions.
If a transmission outage or other event occurs the system will move into a different “Normal Operating Condition (NOC) tier” and the generator’s access to the market will be scaled back, possibly to zero in the event of serious network conditions. Thus, even if they have purchased firm access, generators would still need to take into account the potential for lack of access to market, and contract accordingly.
This could limit the value of the OFA model. Determination of the various NOC tiers and the Firm Access Standard will also be a highly challenging and complex process. Network Service Providers will have a significant incentive to make the standards as lenient as possible (undermining the value of firm access), and asymmetry of information could be a barrier to effective stakeholder participation in the process.
The AEMC will need to determine whether the significant implementation costs that are likely to be involved will be outweighed by the benefits they claim this model will bring. The AEMC is currently considering submissions to the second interim report, and preparing recommendations to the Standing Council on Energy and Resources (SCER).
The final report is due with the SCER by March 31, although the AEMC currently anticipates delivery prior to that date.
More detailed explanation of settlements under the OFA Model
Generator settlements under the OFA model would be as given by the equation below. RRP is the Regional Reference Price, LMP is the Local Marginal Price, “Dispatch” refers to the dispatched capacity of a generator, and “Network Access” refers to the quantity of network access purchased by a firm generator.
To illustrate how this works, an example is given in Figure 2, with the resulting dispatch and payment outcomes illustrated in Table 1.
In this example, Generator 1 would be dispatched to 200 MW, Generator 2 would be dispatched to 300 MW (limited by the binding constraint), and Generator 3 would be dispatched for the remaining 200 MW required to meet the load.
The Regional Reference Price (RRP) is set by Generator 3 to be $50/MWh. The Local Marginal Price (LMP) at the other node is set by Generator 2 to be $30/MWh. Compensation payments in this example would be equal to 200 MW (the amount of firm access purchased by Generator 2, but not being received in physical dispatch), multiplied by the difference between the RRP and the LMP ($50 - $30 = $20, in this example).
Thus, Generator 2, who has purchased firm access, receives a total ‘profit’ equivalent to if they had been dispatched to their full 500 MW (taking into account the fact that they did not have to operate to the full 500 MW, and therefore avoided their operating expenditure, which is expected to be similar to their bid price of $30). Generator 2 still makes a profit, albeit lower than they would have under the present NEM model (due to the payment of compensation).
Figure 2 - Example to illustrate settlements under OFA Model.
Table 1 - Example settlement outcomes under OFA Model.
Dr Jenny Riesz is a Senior Consultant in the Energy Strategic Advisory team at AECOM, a global provider of professional technical and management support services to a range of industries and clients worldwide. Jenny’s focus is on renewable energy and climate policy.