*This is part two of a two-part series of the legal challenges of switching to Direct Action. For part one, click here.
Yesterday we looked at the benefits, in terms of legal management, of the switch from a market system to government contracts in addressing climate change in Australia. Today we look at some of the legal challenges...
Under the Direct Action approach to promoting emissions reduction, the tender and contracting process will be, in the initial stages, much more time and resource intensive than carbon pricing.
One of most expensive and time consuming processes will be developing new abatement methodologies for approval by government. This has been one of the key roadblocks and frustrations of the existing Carbon Farming Initiative.
There is some suggestion that the process around the approval of methodologies will be relaxed but there is a limit by how much; if the government wants to count abatement towards its targets, section 133 of the CFI Act requires the methods be consistent with those required under the Kyoto Protocol and used in the National Inventory Report.
Judgements will also need to be made by companies and their advisers as to what the term of the contract they require to attract investment and what risk profile they are prepared to carry given payment will not be until delivery of abatement but investment will is required up front. The Environment Minister Greg Hunt recently indicated contracts would be for five years with an opportunity for that term to be extended. Five-year term contracts are unlikely to be sufficient for long-life assets – in the land and energy sectors - and so the clarity around the conditions for extension will be required. If not, contracts of this length are more likely to favour investments with a shorter pay-off period – such as in the property sector.
Then there’s the risk of a change of government. It doesn’t seem presently likely now but what would happen to the contracts if Labor was to return to government and reintroduce carbon pricing?
Another problem will be one of permanence of the contracted emissions reduction. There is little point paying a business to act, if – when the contract is over – the company can increase emissions back to business-as-usual levels. Similarly, how does the contractual obligation to abate survive the sale or restructure of a business? Both of these issues will need to be carefully dealt with in the contract.
The closest analogy to the new Direct Action contracts is government clean technology grants. However, while payment under technology grants can occur at defined project milestones, under Direct Action payment occurs only on delivery, or more particularly non-delivery, of abatement so putting greater risk onto the seller.
One of the key risks that will need to be taken into account in the structuring of any contractual arrangements is events beyond a party’s control that prevent it from meeting its contractual commitments. Under the CFI, project proponents are required to provide a 5 percent “risk of reversal” buffer to allow for events such as bushfire which destroy carbon stores. In the manufacturing sector, how should the risk of unforeseen change in market conditions leading to an increase in production or change in outputs that has the effect of increasing emissions or emissions intensity be dealt with?
This in turn raises the problem of how to set a company’s emissions baseline against which abatement is measured. Is it done at a facility level? If so, how does the contract deal with the possibility of a company shifting activity to another of its facilities?
Setting baselines may be relatively straightforward for large emitters that currently report their emissions under the National Greenhouse and Energy Reporting Scheme and produce relatively homogenous products. But things get more complex when polluters produce different products and have different production lines and practices. A simple change in product mix can alter the emissions outcome.
Another fundamental issue is the question of additionality – what abatement activities should a company be entitled to be paid for? If a company already had a proposal on its book to invest in new clean technology, should it now be paid by taxpayers to do it even though it has the end result of reducing emissions? If companies have already commenced projects under the carbon price scheme, are these now genuinely additional? A recent report from carbon analysts Reputex suggests should emissions intensity baselines be set based on historical levels, most Australian companies would be likely to find themselves below their five-year historic emissions intensity average given improvement over the past five years. As a result, more than 75 per cent of all abatement bid into the ERF could be attributed to 'grey' credits – credits obtained by industry despite not achieving any additional emissions reductions.
The structuring of the so-called reverse auction process will also be critical. Yet to be determined is whether all types of abatement activity – regardless of cost – go into the same auction. This would naturally favour low-cost abatement like energy efficiency – that can have an implicit carbon price of less than $10 a tonne – over land sector abatement, which is estimated to require an implicit price of around $20-$30 a tonne to get off the ground.
According the Business Council of Australia, the Emissions Reduction Fund should not be technology or methodology specific, with separate streams for different abatement types. However, the Australian Industry Group highlights that unless the government “price discriminates” it will pay the marginal cost of abatement to all, thereby rewarding those with a much lower cost of abatement.
Such issues will all need to be quickly considered and resolved by companies and government, if Direct Action is to commence from July 1 next year.
Marcus Priest is a lawyer at Sparke Helmore.