Assuming the effective design and implementation of a final policy framework, the government’s announced National Energy Guarantee (NEG) provides an alternate approach to maintain reliability in the NEM, and contribute to Australia’s emissions reduction commitment under the Paris Agreement.
Below we outline our initial analyst response and implications for energy and carbon market dynamics.
A CARBON PRICE BY ANOTHER NAME?
- While it may be more efficient to establish a market mechanism with certificate prices for emissions reductions that could be traded transparently, the attributes of the NEG will in effect establish a de facto price on greenhouse gas emissions from the power sector, and provide a robust source of demand for Australian Carbon Credit Units (ACCUs).
- A 26 per cent cut in electricity sector emissions (on 2005 levels) would not equate to Australia meeting its Paris commitment. Modelling indicates that such a cut would reduce national emissions by around 40 Mt of CO2e in 2030, an 8 per cent cut on 2005 emissions levels. This would leave a shortfall of 119 Mt to meet Australia’s 2030 target. The cumulative reduction from the electricity sector would therefore be approximate to forecast emissions growth from non-electricity sectors over the same period, leaving national emissions flat.
- Should a 26 per cent target be applied across all sectors of the economy, modelling indicates that the burden to reduce emissions would fall disproportionately on the direct combustion of oil and gas and transport sectors – Australia’s emissions growth sectors. These sectors would be liable for 31 and 32 per cent of all emissions reductions to meet the 2030 target, despite making up only 17 and 18 per cent of all emissions. Comparably, the electricity sector would contribute only 20 per cent of all abatement.
- Nonetheless, should the NEG be designed and implemented to succeed, it is likely to be an effective mechanism to define an emissions reductions pathway for the electricity generation sector, while maintaining system reliably.
- The availability of large volumes of domestic Australian Carbon Credit Units (ACCUs), at low prices, will provide Australian policymakers with significant flexibility in designing a mechanism that is able to keep compliance costs low for electricity retailers (and all sectors of the economy), while appealing to the environmental lobby’s desire for domestic action.
SUPPLY AND COST IMPLICATIONS FOR CARBON OFFSETS (ACCUS)
- An obligation to reduce emissions in line with the Paris Agreement will place at least part of the compliance obligation to reduce emissions on participants active in wholesale electricity markets (e.g. retailers), establishing an effective source of demand for ACCUs.
- Australia has ample domestic abatement to meet a 2-degree target under the Paris Agreement, with around 600 million tonnes (Mt) of emissions reductions available across the economy by 2030. This is equivalent to Australia’s emissions in 2005, the baseline year for Australia’s contribution to the Paris Agreement.
- As noted in earlier modelling, such a cut could be reached by implementing all abatement measures below $20 per tonne of carbon dioxide equivalent (CO2-e) in 2030, representing the marginal cost to industry of meeting a 2 degree target. Modelling indicates the marginal cost would rise to $60 per tonne of CO2-e to meet a target consistent with limiting warming to 1.5 degrees.
- We continue to project rapid growth in ACCU generation, with issuance projected to double to approximately 20 million per annum to fulfil mandatory delivery contracts under the ERF. Without additional demand for ACCUs beyond the ERF, issuance is forecast to remain relatively stable beyond next year, with supply growing towards 2022 due to the accelerated growth of a number of sequestration projects.
- Under current policy, ACCU issuance will be surrendered under the ERF rather than enter the wider supply pool. Subsequently, by entering into 7-10 year delivery contracts, the ERF will lock away ACCU supply away from high emitting companies. This is projected to heavily influence ACCU availability and prices. To access our full ACCU supply forecast, please click here.
RELIABILITY OBLIGATIONS MAY IMPOSE GREATER COSTS ON DEVELOPERS
- How much dispatchable generation is required in any region will depend on many factors, with a minimum dispatchable capacity required to maintain system reliability likely to be defined for each region.
- This is likely to encompass: capacity closure schedules, concentration of available generators, expected future trends in peak power demand, the extent of variation in VRE generation, penetration of behind-the-meter solar PV, size and interconnections with other NEM regions, strength of the network, the load profile, total regional VRE generation relative dispatchable capacity, wholesale and contract market considerations.
- In practical terms, the GRO will impact investment decisions for new generation projects, potentially imposing greater costs on VRE generators to provide dispatchable capacity by pairing projects with flexible storage – or firm power contracts – when and where flexibility may be needed.
- The constraints and objectives of the GRO will therefore need to be integrated into existing planning and investment decision making, meaning service providers, generators and large consumers must be able to make efficient decisions on the value, and optimal location and monetisation of flexible resources.