The Large-scale Renewable Energy Target (LRET) requires liable entities to meet their compliance obligations by acquiring a proportion of their electricity from renewable energy sources. This occurs in the form of large-scale generation certificates (LGCs), which are created by accredited large-scale renewable energy projects and sold to liable entities to surrender against their LRET obligations.
The last two years have been a rollercoaster ride for LGC spot prices, with large project delays, persistent curtailments, below average wind output, and concern about reduced electricity demand due to COVID-19, causing large swings in spot prices.
Over the medium-term, the projected LGC surplus is likely to weigh more heavily on the market, with spot prices likely to decline as more renewable energy is commissioned beyond the LRET’s legislated demand. As this occurs, we expect the LGC floor price to ultimately be set by the carbon equivalent value of an LGC to the price of Australian Carbon Credit Unit (ACCU) offsets.
This could see ACCU and LGC prices converge in the 2020s, with large-emitting entities able to secure more easily obtainable LGCs to meet their carbon offset obligations (for electricity use and voluntary emissions reductions), while the long-run price of ACCUs could also support continued investment in renewable energy generation.
In this article, we take a closer look at current and future dynamics in the LGC market, and the longer-term interaction between LGCs and carbon offset prices.
Current LGC spot price and medium-term dynamics
In March, concern about potentially severe reductions in electricity demand due to COVID-19, along with a projected surplus for 2020, saw spot prices drop sharply though the $30 level, before recovering in April.
From June, this trend reversed, as concerns about delays in the commissioning of new very large wind farms from partial to full generation, and continued connection delays for solar, reduced the full year 2020 forecast for new renewable generators.
Even as some of these concerns subsided, below average wind output in early winter significantly shrank projected LGC supply, while curtailments led to the underperformance of existing renewable generators. As a result, despite more than 4.7GW of new large-scale renewable generation capacity being accredited in 2019-20, just 7 million LGCs were validated in Q2 relative to the previous year.
Revised expectations for LGC supply for 2020 are now around 32 million, depending on variable hydro, solar, wind production through the second half of the year.
Although this could technically result in a shortfall against a legislated demand of 33.7 million, after accounting for the LGC surplus at
the end of last year (7.4 million), and demand side variables like forecast voluntary demand and uncertainty around shortfall charges, there could also be a relatively small surplus in LGCs at the end of the year.
As we saw in 2019, LGC prices increased on news of lower than expected supply and persistent growth in demand, again reaching $50 in September, before a rapid descent that saw liquidity dry up and the spot price close at $43. Cal 21 prices have also fallen to $33, while Cal22 and 23 prices have seen small rises to around $24 and $13, respectively.
The shrinking differential between spot and forward prices suggests that participants are opting to pay penalty price instead of surrendering LGCs and deferring the obligation for up to three compliance years, when the LGCs can be purchased and acquitted with the $65 received back from the government.
Medium-term interaction between LGCs and carbon offset prices
While uncertainty remains about whether the LRET’s 33,000 GWh of renewable electricity will technically be met this calendar year, it is certain that the target will eventually be met by constructed projects.
As more renewable energy capacity is commissioned and annual supply exceeds the LRET’s legislated demand, the supply of LGCs is expected to grow considerably. Fundamentally, this should lead to a significant surplus in LGCs over the medium-term, growing to tens of millions each year after 2022. Therefore, barring a change of policy, or a significant increase in voluntary demand, spot prices are expected to decline over the long-term.
In the next few years, as the market works through the tail of under compliance, we expect the LGC floor price to ultimately be set by the carbon equivalent value of an LGC relative to the price of Australian Carbon Credit Units (ACCUs).
In our current policy outlook, we forecast this to happen indirectly, such as the voluntary offsetting of emissions by substituting LGCs in place of ACCUs on the demand side, or the financing of medium-scale solar PV on the value of being credited with seven years of ACCUs on the supply side.
This may see ACCU and LGC prices converge in the 2020s, with large-emitting entities able to secure more easily obtainable LGCs to meet their carbon neutrality goals, or to offset compliance obligations under the Safeguard Mechanism.
Ultimately, such a scenario is dependent on the secondary LGC supply-demand balance as legislated demand stabilises after 2020. Voluntary LGC purchasing volumes are growing, but from a small base relative to the forecast for LGC creation. Therefore, on current policy, the outlook for forward LGC prices after 2022 remains low.
ACCU prices likely to rise under the Paris Agreement
As we discussed in our recent webinar, we forecast long-term ACCU prices to decline under current policy. Therefore, while the ACCU market could serve as a floor price for LGCs, this floor is also forecast to decline by the end of the decade, with the market almost inevitably becoming oversupplied in the absence of a long-term source of industry compliance demand.
Despite this, Australia’s climate ambition is anticipated to eventually come into line with the objectives of the Paris Agreement, which could see the forecast value of ACCUs to rise over the decade.
In particular, the Paris Agreement is a key driver of our long-term offset price expectations, with our long-run ACCU price scenarios underpinned by the cost and availability of external offsets to meet a 1.5-2°C carbon budget through to 2050.
While our Base Case forecast reflects a current policy pathway, in practice, Australia will ultimately be required to transition towards net zero emissions. As a result, we consider our Base Case forecast to be a ‘low’ price scenario, reflecting an assumed ‘lowest possible’ value for ACCUs.
Should Australia’s emissions reduction ambition be formally scaled up to be compatible with a 2°C pathway, our recent carbon outlook indicates a modest increase in ACCU prices is possible, with pricing growing to $30 in 2050, averaging of $23 over the period.
Under a more ambitious 1.5°C scenario, the increased volume of required emissions reductions coupled with the short timeline for reaching net-zero emissions could lead to carbon offset prices well in excess of $100/t.
As policymakers, large-emitting companies and renewable energy project developers seek to make informed long-term decisions, the long-run price of ACCUs under the Paris Agreement therefore provides a more applicable reference point for future investment and the longer-term uptake of
renewable energy generation.
However, while Australia has the market-based tools in ACCU and LGC credits to achieve further emissions reductions, long-term investment will remain uncertain until a more robust and integrated climate and energy policy framework is developed.
Hugh Grossman is executive director of RepuTex, Australia’s largest energy and emissions market analyst, with customers at over 150 power, energy, metals, mining, land-use, waste, financials and government agencies.