The Australian Commonwealth Government confirmed yesterday that it will not be implementing the Clean Energy Target (CET) proposed by the Finkel Review.
Instead, it has outlined a new National Energy Guarantee (NEG) scheme which comprises:
- a reliability guarantee, which requires retailers to source a specified proportion of the electricity they sell to customers in the National Electricity Market (NEM) from reliable (i.e. dispatchable) generation; and
- an emissions guarantee, which requires retailers to ensure that, on average, the electricity they supply customers falls below a specified emissions intensity threshold.
In its letter to the Energy Minister, the Energy Security Board (ESB) recommended that the final design of the NEG mechanism be proposed to the Council of Australian Governments (COAG) in November 2017.
The objective is to achieve COAG agreement on the NEG and final approval of a change to the National Electricity Rules (NER) to facilitate the NEG by the end of 2018 with implementation of the reliability guarantee in 2019 and implementation of the emissions guarantee in 2020.
At the time of writing few details of the policy have been published and the information available gives rise to many questions that will need to be answered in order to fully understand the full implications of the NEG.
The reliability guarantee will apply to retailers and the few electricity customers (e.g. some major smelters) that register directly in the NEM as ‘market customers’. It will require those retailers and customers to ensure that a certain proportion of their electricity load is met by what the ESB describes as ‘dispatchable resources’.
Dispatchable resources are generators (or controllable loads) that can be controlled by the Australian Energy Market Operator (AEMO) in real time to respond to system requirements and will include coal and gas generators, pumped hydro, battery installations, and demand response (i.e. scheduled load) arrangements.
Retailers and other market customers can meet their obligations by owning dispatchable resources or by entering into forward contracts with the owners or operators of dispatchable resources in each of the NEM regions in which their customers are located.
The quantity of dispatchable resources that must be procured is to be determined on a NEM region by region basis. It will be calculated as a proportion of the load of the retailer’s customers in that region. The methodology for calculating this proportion has not yet been determined.
This methodology and its output will be a key driver of the impact the reliability guarantee has on market participants. It is likely to result in a greater impact, and therefore have greater cost implications, in regions such as South Australia where there are relatively low levels of dispatchable resources available within the State.
How dispatchable is “dispatchable”?
In addition to establishing how much dispatchable power the market customer needs to procure, the scheme will also need to set out criteria for determining whether a resource is a dispatchable resource. At a minimum the ESB anticipates that dispatchable resources will be registered as ‘scheduled’ with AEMO in the NEM (e.g. in comparison to wind and solar farms which are typically semi-scheduled). It remains to be seen how the quantity of “dispatchability” that a resource can provide will be measured.
There is likely to be a need to take into account energy output as opposed to capacity, for example, the “dispatchability” per MW of a baseload coal generator with a large stockpile compared to a peaking gas plant with limited access to gas or a battery with limited capacity. Further, the accreditation process may be one-off based on technology type or may include ongoing monitoring to confirm actual performance (e.g. to assess the impact of outages, unavailability of fuel or low levels of stored energy). If an ongoing process is adopted the timeframes and methodology for re-testing will need to be established.
Further work will be required at the policy implementation stage to settle the position.
Alignment of reliability guarantee with market structures
While the ESB envisages that the reliability guarantee will fit within existing contract and market structures, and the Commonwealth has announced that there will be no new ‘certificates’ as part of the NEG’s implementation, there are a number of questions to be addressed as to how the NEG will align with existing contract structures.
The structure of the NEM is such that particular generation is not tied to particular loads. Electricity is sold into and bought from a pool with dispatch managed by AEMO based on a merit order. This presents a problem for a scheme such as the NEG which seeks to allocate responsibility for ensuring that generation comes from particular sources to retailers who have no direct control over dispatch. The ESB seeks to overcome this problem by using forward contracts (entered into alongside market structures) as a proxy for control of physical generation.
This approach is itself problematic. Most contracts traded by NEM participants are financial in nature and while there are exceptions1 the majority of day to day energy trades are not required to be supported by the delivery of physical generation from a particular plant.
Further consideration will need to be given as to how these financial products can be used in such a way as to give sufficient comfort that reliable generation from a specific plant will be made available. It is likely that these contracts may need to be supplemented by, or linked to, a new standard form instrument which creates binding physical generation obligations. This approach is supported by the need to ensure that contracts that meet the reliability requirements will be tradeable.
Does the dispatchable resource need to be new?
There is no requirement under the reliability guarantee that dispatchable resources be newly available or newly constructed.
The ESB has noted that many large retailers (e.g. gentailers) may already hold excess dispatchable generation that could be traded with other retailers who are ‘short’ in a NEM region.
It is proposed that retailers’ compliance with the reliability guarantee will be assessed regularly based on evidence of their contract positions provided to the AER and that fines will be imposed for non-compliance. The process by which retailers will disclose to the AER a significant portion of their hedge book is yet to be outlined. Any such process will need to take into account the highly sensitive nature of this information and address pre-existing obligations of confidentiality to which retailers are subject.
The policy documentation also suggests that real time compliance with reliability commitments will be monitored and that the cost of non-compliance could be based on the real time spot price with further consequences for non-compliance including deregistration of the relevant retailer.
The compliance and penalty framework for the scheme is only briefly discussed in the materials currently available. The allocation of responsibility for generator performance as between retailers and generators is unclear and will require further careful consideration particularly where further penalties are linked to the spot price.
Interaction with Finkel Review recommendations
One of the key recommendations in the Finkel Review was the Generator Reliability Obligation which provided that if a “new” variable renewable energy (or VRE) generator wishes to connect in a region that is close to the limit of minimum dispatchable capacity, that new VRE generator must also provide an amount of new dispatchable generation capacity.
The Finkel Review also called for transmission network operators to be obliged to provide and maintain a particular level of inertia determined by the AEMO for each region or sub-region by mid-2018 by providing or contracting for inertia services, or synthetic inertia through fast frequency response services, under a modified Network Support and Control Ancillary Service framework.
Both these policies have a similar aim and effect as the reliability guarantee. At this stage it seems that the reliability guarantee arm of the NEG is intended to supplement rather than replace these policies.
The emissions guarantee will require retailers and customers that are directly registered in the NEM to demonstrate to the AER that the mix of electricity supplied to the market to meet their load over the compliance period met or fell below a particular average emissions level.
It seems that the average emissions level of a retailer or relevant customer for these purposes would be assessed by reference to:
- the emissions intensity of the generators with whom the retailer or customer has entered into forward contracts to hedge its load;
- the emissions intensity of its own generation plant to the extent it was used as a natural hedge for its or its customer’s consumption; and
- the emissions intensity of the pool for load that is not hedged under forward contracts or ‘owned’ generation.
In its letter to COAG the ESB suggests that “Australian carbon credit units and international units could be permitted to meet a proportion of the retailer’s guarantee and banking and borrowing across the compliance period would be allowed to a certain level”.
It is not yet clear what level of emissions intensity will be mandated as the target to be achieved by retailers and large customer market participants. At this stage we know that the overall target will be set by the Commonwealth Government and the emissions levels to be achieved by individual retailers will be calculated under the changes to the NER but we have very little real information about any hard numbers other than generic statements to the effect that the targets will be in line with Australia’s international emission reduction commitments.
This level of the target, and how it will change over time in the lead up to 2030, will be critical to determining the impact (if any) of the emissions guarantee on market participants and in particular the future of new renewable generation.
No RET Scheme Changes
The ESB’s letter to COAG states that the guarantees are not intended to change the RET scheme.
The ESB’s letter also states that the emissions guarantee would be implemented in 2020 “to replace the RET” and this language has caused some concern among industry participants. However, rather than referring to the repeal of the RET the “replacement” language is likely a reference to the NEG having the potential to replace the RET as the key policy driver for encouraging further new build investment in renewables from 2020. This is based on an assumption that from 2020 (when the 33,000 GWh target for renewable electricity generation is expected to be reached) the RET will provide little economic incentive for further construction prior to 2030 due to the risk of oversupply of LGCs.
The letter also leaves open the question of whether RET accredited generators constructed in the lead up to 2020 could be used by retailers to meet their obligations under the reliability guarantee and emissions guarantee.
Alignment of emissions guarantee with market structures
As for the reliability guarantee the relationship between forward contracting and physical generation requires clarification in the context of the emissions guarantee. In particular, the extent to which the notional quantities of electricity (i.e. the subject of typical energy market contracts) can be used to calculate deemed average emissions intensities despite the fact that they are not necessarily tied to physical generation will need to be addressed.
It seems likely that where a retailer has hedged its load under purely financial arrangements (i.e. without a link to electricity actually generated by an identifiable plant), the notional quantity the subject of that hedge would be deemed to have been obtained at the average emissions intensity of the pool.
While the policy is intended to work with existing contract structures a number of details will need to be worked through and market approaches updated given that most over the counter hedges and futures contracts do not specify a particular plant whose emissions intensity could be referenced to these purposes. Situations where retailers have entered into ‘black only’ hedges with renewable generators may also require special treatment.
What about WA and the NT?
As the NEG scheme (including both guarantees) only applies in the NEM it will not apply in the Northern Territory or Western Australia. The NEG itself is proposed to be implemented through changes to the NER and the Australian Energy Market Agreement.
From an implementation perspective this approach means that the Government should be able to put the NEG in place without a requirement for new federal legislation. At this stage the proposed changes will, at a minimum, require COAG support.
The extension to WA and the NT of the emissions guarantee mechanism, or at least an equivalent commitment to carbon emission reductions, will ultimately need to be addressed through further jurisdiction-specific regulatory changes or additional Commonwealth policy. Potential developers of renewable projects in WA and the NT will no doubt await announcements in this regard with considerable interest.
The interaction of the NEG with the RET Scheme, and with state-based schemes more generally, is another aspect that will require further consideration as the policy is developed and finalised.
The NEG is likely to be put to the COAG meeting in November 2017 for consideration. The support of the state governments that comprise the rest of COAG is not assured given conflict between Labor and Coalition energy policy generally and the specific policies supported by particular states to support renewables and address reliability issues.
If COAG supports the NEG we expect that the required NER rule change process will commence shortly afterwards. As part of that NER rule change process, market participants will have an opportunity to provide feedback on the detailed implementation of the NEG through the Australian Energy Market Commission’s usual submission and consultation process.
In preparation for the proposed rule change market participants should start to consider the potential implications of the NEG for any new projects under development and their existing operations including under current and future energy market contracts.
While the NEG shows promise as a means of addressing both the issues of reliability and reduced emissions its actual impact (including as to energy costs in the future) will be difficult to assess until a final landing is reached on:
- the proportion of ‘dispatchable generation’ that retailers will be required to own or contract; and
- the average emissions threshold that retailers will need to achieve across their portfolio of generation.
Until these fundamental aspects of the NEG are settled, market participants will continue to face considerable uncertainty as the process of energy market reform drags on for another round.
- Most renewables PPAs are generally written by reference to a single plant which is often owned by an SPV with the notional quantity linked to the metered output of the plant. Some OTC forward contracts will include specified ‘reference plant’ the outage of which may give rise to particular financial consequences under the contract however they would not normally link generation to a particular plant.