Contracts to support deployment of carbon capture
Support contracts seek, in effect, to provide payment for an environmental service (reduced emissions). They are legally binding, so they can provide certainty to investors. The counterparty will usually be government, or a government-supported entity such as a government-backed company. Such contracts have already successfully supported the deployment of renewables.
One form of contract, a contract for difference (CfD) on the carbon price, is being introduced or examined in a number of jurisdictions. CfDs are part of the Netherlands SDE++ system, the UK’s planned support for Industrial Carbon Capture (though with modifications), and have been proposed for the EU’s Innovation Fund. Because the contracts are written on the carbon price they are sometimes referred to as Carbon Contracts for Difference (CCfDs).
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This article looks at how such contracts may be used to support industrial carbon capture. It does not consider regulation or pricing of transport and storage. It also excludes consideration of incentives or risk sharing across the chain – for example, what happens if transport or storage is unavailable – although such issues will be important in realizing projects.
Contract eligibility and the exclusion of CCU
Contracts are intended to support certain classes of technology, and there will be limits on eligibility. For example, the UK government has recently decided to exclude Carbon Capture and Use (CCU) projects at least from the first set of CCS support contracts.
The EU proposal
In July 2021 the European Commission proposed a CCfD design to support projects under the Innovation Fund, as part of its ‘Fit for 55’ package. The proposal illustrates the form of such a contract very clearly. It takes the form:
Yearly support = (strike price – average ETS price) * (ETS benchmark – actual emissions) * annual production
The level of price support is the difference between a set price (the strike price) and the carbon price under the EU ETS. The number of tonnes of CO2 on which payment is made is calculated on the basis of benchmark minus remaining uncaptured emissions, per tonne of production. This represents the emissions reduction from an efficient factory.
The description of the proposals refers to a producer selling surplus allocated allowances, implying continuing free allocation of allowances to producers. However, the proposal would also be suitable under a regime of carbon border adjustment mechanisms (CBAMs).
Payments per tonne
Payment per tonne of CO2 will likely form part of any contract because it provides incentives to operate the capture plant. Without such incentives the capture plant would risk remaining idle. This would, in turn fail to maximize the environmental benefits of the project. Technology learning would also be reduced.
An example of what can happen in the absence of such payment is given by the Petra Nova coal-fuelled power plant in the USA in 2020. The capture unit operated on the basis of revenues from enhanced oil recovery (EOR). When EOR became uneconomic because of falls in the oil price during 2020, the plant temporarily stopped capturing. It had not applied for incentives under the 45Q programme, which provides a credit of $35 per tonne stored for EOR projects (the payment is $50 per tonne stored for non-EOR projects). Had these payments been in place, the capture unit would have likely continued operating.
The design of the payment per tonne can have a significant effect on incentives. In contrast to the EU’s proposal, some systems base payments on tonnes of CO2 captured or stored. For example, the SDE++ support payments in the Netherlands are based on tonnes captured, as are volumes under the UK’s proposed industrial carbon capture support contract.
However, this creates inefficient incentives, because it provides incentives for production of additional CO2. If a factory reduces output of its main product while energy is cheap, it may continue to burn fuel and run it through the capture process because it’s profitable. It may also switch to a higher-carbon fuel. It may essentially get into the CO2 production and capture business – a ‘CO2 factory’. Similarly, energy efficiency projects can become less profitable, because increased efficiency reduces energy use, and so leads to a loss of capture payments.
A better approach is to base payments on the reduction in emissions due to the operation of the CCS plant, as in the EU’s proposal. This represents much more closely the actual environmental benefit of the project (excluding some lifecycle emissions). Payments are not dependent directly on tonnes captured, so give no incentives for additional CO2 to be produced. Instead, they do give incentives for increased capture rates, increased energy efficiency, or other changes that reduce residual emissions (the 5–10 per cent or so typically not captured). Residual uncaptured emissions need to continue to be priced and should not, for example, be excluded from a carbon pricing system because emissions fall below a certain volume threshold.
This approach requires the emissions that would have happened without the capture plant to be estimated (the counterfactual). This will usually be the benchmark emissions per tonne of product. However, historical emissions per tonne of product from that particular plant can also in principle be used.
Price per tonne
In principle, as carbon prices rise over time and the costs of new-build CCS decrease, avoiding paying carbon prices may be sufficient in itself to incentivize the installation of CCS at industrial facilities, provided CO2 transport and storage infrastructure is in place. This could avoid the need for subsidy entirely, although regulatory involvement in the CCS chain will still be required and allocation of risks will remain an important issue.
While costs of CCS remain above the carbon price, payments under a CfD seek to provide support, while recognizing the value of carbon pricing to low-carbon projects. CCfD payments decrease as the carbon price rises, so there is a presumption that projects benefit from higher carbon prices. This may happen if higher carbon prices are reflected in higher product prices, for example higher steel prices. This may be the case in the following circumstances.
Non-trade exposed product. In non-emissions-intensive trade exposed sectors, carbon prices may be passed through because international competition is not enough to prevent this, and so the threat of ‘carbon leakage’ is much lower.
Carbon border adjustment mechanisms (CBAMs) may lead to the carbon price being reflected in product prices because all producers – importers and local producers – will pay a carbon price. CBAMs remain under discussion in the EU and UK.
Carbon regulation in other countries may increase the prices for a commodity. This may not necessarily be in the form of carbon pricing in other jurisdictions. Other mechanisms, for example product standards, may increase costs.
Markets for low-carbon products. There may be a market premium from regulations which limit the carbon content of a product. For example, building regulations may require the use of low-carbon steel.
Free allocation of allowances
There are various choices for whether or not the free allocation of allowances is retained, and whether these are accompanied by a CfD or a fixed-price support contract. These choices affect the required level of contract support for a carbon capture project, and create different exposures to price and volume risk. Any CfD will need to be robust in the face of regulatory changes affecting the carbon price, for example if other taxes are implemented.
1. Retention of free allocation – no CfD but other subsidy such as a fixed price support contract
In this case subsidy, for example a fixed price support contract or capital subsidy, meets part of the costs of the capture project. The remainder is absorbed by the project owner, or met by revenue from the sale of those free allowances that are no longer needed because the CCS plant is operating. Carbon price risk remains with the project, because the revenue from sale of free allowances depends on the carbon price.
Something like this approach is applied in the Norcem capture project, part of the Norwegian Longship project. The project is subsidized by government (though not by a contractual payment per tonne), with subsidy covering 75–80 per cent of expected costs. The project retains free allowances, which can be sold to cover remaining costs. (The site will also need allowances to cover other emissions it makes, as only about half of its emissions are part of the capture project.) As there is no CfD on the carbon price, the project retains carbon price risk.
One important consideration is whether implementing CCS results in a change of benchmark for free allocation under an EU ETS, and if any resulting loss of free allocation is compensated for by additional support. If the benchmark is reduced, support based on the assumption of continuing free allocation of allowances may not provide sufficient funding.
2. Free allocation is retained along with a CfD
In this case a CfD in effect largely fixes the value to the project of freely allocated allowances, removing carbon price risk from the project, although risks from changing volumes of free allowances may remain. This is similar to the approach used in the SDE++ programme in the Netherlands as well as the EU’s current proposals.
3. Removal of free allocation and allowances aren’t issued
If free allowances are removed from the project owner, the subsidy will need to meet the cost of CCS in full. This removes carbon price risk from the project because there are no free allowances to vary in price.
If allowances are never issued, they are not available for government or others to auction. This increases the net cost to the taxpayer compared with the case where allowances are issued and can be auctioned (assuming no significant effects on the market price).
4. Removal of free allocation and allowances are issued and auctioned by government
The net cost of the subsidy to government is potentially reduced by auction revenue from selling allowances not allocated to projects. However, to secure this there is a need to ensure that the allowances are issued, and that they return to government, and can subsequently be sold.
Proposals in the UK include a provision that free allowances will be removed, but payments will be given to the project to represent the value of the removed free allowances at an assumed carbon price path. However, because this payment is determined in advance, it becomes rather like any other form of contractual payment independent of the carbon price.
Other contract terms
Other features of the contract will need to be specified. These include the following.
Whether there is an annual fixed payment. This does not depend on volumes of CO2, but is paid anyway, for example as a fixed monthly or annual amount. It may be made unconditionally, provided only that the capture plant remains open, or it may be based on availability of the capture plant (a capacity charge). This type of payment is usually intended to allow repayment of a portion of capital costs irrespective of the utilization of the capture plant. It has some potential benefits similar to a capital grant, which may also be part of a support package.
Costs of energy used in capture. Some proportion of the per tonne payment, most likely corresponding to the energy costs of running the capture plant, may be indexed to energy prices. This can reduce financial risks to the capture plant, because energy costs may have quite different trends from other operating costs, and from general inflation.
Transport and storage costs. These will normally be set by regulation, and most likely be remunerated on a pass-through or similar basis.
Contract duration. To ensure value for money for tax payers (assumed to be the ultimate provider of funds for the contract payments), contracts should run for long enough to gain the value from operation of the plant – including the benefits of reducing emissions, and technological learning.
There is some convergence of length of support amongst existing or proposed arrangements, even though the type of support varies. Contracts for Norway’s Longship project run for ten years from the start of operation, the Netherlands SDE++ runs for 15 years, the UK’s current proposal is for 10–15 years although with a shorter capex repayment period. The 45Q tax credit in the USA runs for 12 years.
Some industrial investors look for shorter paybacks on investment. However, very short contract durations, for example five years, that fully remunerate total capital are unlikely to be optimal. If the plant closes after only a few years, the cost per tonne of CO2 usually becomes very high. There will also be a loss of environmental benefits. Similarly, a short period of operation will lead to a loss of learning benefits that would come from a more prolonged operation. It risks leaving transport and storage infrastructure investment stranded if capture plants cease operation early.
Changes to payments over time
Contract parameters may change in various ways.
Changes over time. For example, payments may reduce over time to reflect expected learning both within and outside the project.
Changes in market conditions or regulation. For example, payments may change if market CO2 prices under a carbon tax or emissions trading system go outside certain ranges. Similarly, contract provisions may change if there is a change in the form of carbon pricing, for example the introduction of carbon border adjustments.
As a means of risk sharing. For example, there may be reduced payments if rates of return exceed given levels, or outturn costs are lower than expected. Similarly, there may be an increase in payments if returns fall below a specified level, or costs are higher than expected. There may also be risk sharing through changes being passed through only in part. For example, only a portion of CO2 prices may be passed through.
Changes may be written into the contract, or be subject to re-negotiation in certain conditions (re-openers).
Contracts to remunerate the use of low-carbon technologies can be a powerful mechanism for stimulating their deployment, because they give a firm revenue stream that enables companies to invest. However, as with many commercial contracts, there is a range of risks that need to be allocated and a variety of incentives that will be created. Careful consideration of contract structures and terms is necessary in designing effective policy in this area.
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