Carbon capture terms
Interest in carbon capture projects has soared over the past year. To document commercial terms, some parties are re-purposing concepts from gas and refined coal deals. Others are cutting brand new agreements from whole cloth. The market will eventually coalesce around a set of standard terms, but it is not there yet.
This article describes key terms we are seeing parties negotiate in carbon capture agreements.
There are as many as five roles in a carbon capture project. Multiple roles may be filled by the same entity depending on its technical capabilities, financial wherewithal and risk appetite.
There is the emitter of carbon dioxide (CO2), which is the owner of a plant at which CO2 is generated as a byproduct of an industrial or manufacturing process. It may take responsibility for capturing the CO2 because the equipment to do so will be on site and tied into its existing facility. It will install compressors, pipes and other equipment to pressurize, dehydrate and typically liquefy the CO2 for transport.
However, not every emitter takes on this role. There are companies in the business of installing and owning capture equipment. Emitters are more likely to capture the CO2 themselves if they have tax capacity to use the tax credits the federal government offers for capturing and disposing of CO2.
Next, there may be a separate entity responsible for disposing of and storing the CO2 underground. Only land with certain characteristics is suitable for CO2 storage. To be a good CO2 storage reservoir, the subsurface must contain permeable rock with millimeter-sized spaces called pores. The CO2 is injected through a well into the porous rock deep underground.
If the storage site is not immediately adjacent to the plant, then a pipeline will be built to transport the emissions. The sequestration company could sub-contract construction of the pipeline so that there is only one entity facing the emitter. Alternatively, the emitter could separately contract for the transportation and sequestration services. Splitting up the contracts this way will lead to greater finger-pointing risk if something goes wrong, but back-to-back indemnities can mitigate the risk.
The land on which the pipeline and storage facility are sited may be owned by one or more third parties, especially if the route is long distance or passes through multiple states. The landowners are typically paid a combination of a fixed lease or easement payment and a royalty tied to sequestration volumes. Real estate rights for the pore space can get complicated depending on whether the sequestration company’s subsurface estate is severed from the landowner’s surface rights. Real estate issues are governed by state law.
The fifth potential role is a tax equity investor. The federal government allows the owner of the carbon capture equipment tax credits for capturing carbon emissions and doing one of three things with the emissions. The emissions can be permanently stored underground, used for enhanced oil recovery or put to a permitted commercial use. The value of the tax credit is highest if the CO2 is sequestered permanently underground. (For more details, see “Tax Credits for Carbon Capture” in the February 2021 NewsWire and “Stalled Carbon Capture Projects” in the August 2021 NewsWire.)
If the capture company does not have enough tax appetite to make use of the credits itself, it can monetize them in a tax equity transaction. Only one significant tax equity transaction has closed to date, but others are moving to market. The early deals are borrowing from a coal synfuel and refined coal transaction template as well as working with guidelines that the Internal Revenue Service issued in Revenue Procedure 2020-12.
Carbon capture projects turn concepts from power projects on their head.
In a power project, the a utility or corporate buyer of electricity pays the project company for the right to take delivery of the product, electricity.
In a carbon capture project, the project company may pay a sequestration company to take and dispose of the product, CO2.
The fee can be structured as a dollar per metric ton of CO2, analogous to a tipping fee in waste-to-power deals. Tax credits are based on the quantity of CO2 injected, so it makes sense for the tipping fee also to be based on injected CO2. In that case, the risk of line losses along the pipeline is borne by the pipeline or by the sequestration company if the latter also takes responsibility for moving the CO2 to the storage site. The sequestration company only gets paid based on whatever quantity makes it into the ground.
If the pipeline owner is a different entity from the sequestration company, the emitter may need to pay a transportation fee based on how much CO2 it puts into the pipeline and a separate sequestration fee based on how much CO2 is injected at the wellhead. In that scenario, the maximum allowable line loss should be capped. From what we see, 0.25% to 1% is reasonable, depending on the length of the pipeline and meter accuracy.
Another way to structure fees is as a percentage of the value of the projected tax credits for quantities sequestered in the previous month or quarter. A fee structured this way will have to remain subject to adjustment if tax credits are disallowed or recaptured later by the IRS.
A fundamental question that should be answered at the outset is who will keep the section 45Q tax credits because this will in turn affect how the economics flow.
In practice, the federal government puts a lot of money on the table in the form of tax credits. The credits run for 12 years after the capture equipment is first put in service. Every party with a role in the transaction wants a share of the value. Thus, how a deal is structured and how money flows ultimately turn on who starts with the tax credits and how the parties decide to split the value.
The tax credits belong in the first instance to the entity that owns the capture equipment and physically or contractually ensures the disposal or use of the CO2.
The owner of the capture equipment can transfer some or all of the tax credits to another person that disposes of the CO2 permanently underground, uses it for enhanced oil recovery or puts it to a permitted commercial use. The election is made annually under section 45Q(f)(3)(B) of the US tax code. The capture equipment owner can decide to pass through all or part of the tax credits in a single year or multiple years. If it does so, it should negotiate a reduction in the fees paid to the third party to take the CO2 emissions.
Congress is debating whether to increase the section 45Q tax credit amount. The parties should agree in advance how any such increase will be shared.
The sequesterer will want the emitter to commit to delivering a minimum volume or mass of CO2 a year to ensure capital recovery within an acceptable time frame. The rate of return and time frame will be agreed in the term sheet.
The minimum volume can be expressed as a fixed volume or a percentage of base volume, so that if post-combustion emissions are captured, the minimum volume also increases.
The emitter will pay a deliver-or-pay fee for the volume by which CO2 delivered falls short of the minimum. The deliver-or-pay fee should be lower than the fee due the disposal company pays for volumes above the minimum volume requirement. The emitter should be excused from the minimum requirement if the plant is affected by force majeure and for periods when the plant is offline for maintenance or repairs. If the plant has a good year, it should be able to roll over the excess delivered volume to future years. The emitter should get credit for non-deliveries due to the sequesterer’s inability or refusal to take delivery.
Some industrial processes emit a relatively pure native CO2 stream as well as a stream of CO2 resulting from combustion processes. At this time, post-combustion CO2 is too expensive to capture and purify to reach pipeline standards at the current tax credit rate of $50 a metric ton, but costs will come down as the technology matures.
It can be complicated to secure rights to deliver post-combustion gas because the pipeline and storage facility need to be overbuilt or at least there will need to be an agreement to expand existing capacity to accommodate the additional volume. In CO2 roll-up deals, where emissions from multiple sources are transported and disposed using the same pipeline and storage site, the emitter may be able to put additional volumes on the pipeline above the base quantity to use up spare capacity when another customer of the pipeline is experiencing an outage.
In a carbon capture project, the emitter, pipeline company and sequestration company will be reluctant to make large capital outlays until they are sure the others will follow through on their commitments.
Construction of the capture equipment must start for tax purposes by the end of 2025 to claim tax credits. In addition, the 12 years of tax credits start to run once the capture equipment is placed in service. It may be in service once it is ready for use, even if the pipeline and wells are not ready to receive the captured CO2 emissions.
In an ideal world, the capture facility, pipeline and storage facility would all be completed at the same time. In practice, this is a difficult feat to accomplish.
The pipeline and storage facility are more likely to be late due to their relative complexity compared to the capture equipment.
There is usually a tug of war between an aspirational target, favored by the pipeline and sequestration company, and a hard deadline on final completion, favored by the emitter. A substantial completion deadline should be accompanied by penalties for delay. Delay liquidated damages are one option. There are others. Like in any large-scale civil work, each party should develop a detailed construction schedule outlining the sequence and duration of key milestones, which should be appended to the agreement as an exhibit.
There are at least three compliance obligations on the part of the sequesterer that should be expressly spelled out in the agreement.
The first is annual filing of a Form 8933 with the IRS. The existence of each contract and the parties involved must be reported on Form 8933 annually. The entity that captures the CO2 and the entity that disposes of the CO2 must each file Form 8933 with a timely-filed federal income tax return. Among other information, the disposal site operator must certify metric tons captured and securely stored and metric tons the owner, operator or regulatory agency determined has leaked from the containment area of the reservoir during each previous year.
The second set of compliance obligations is owed to the Environmental Protection Agency (EPA). EPA’s requirements under the underground injection control (UIC) program are focused on ensuring protection of underground sources of drinking water where CO2 is injected through an injection well for geologic sequestration. The requirements focus on the siting, permitting, operation, testing and monitoring, post-injection site care and site closure of a class VI well, which is one used for geologic sequestration of CO2.
In addition to the UIC program, EPA requires reporting under “subpart RR” regulations (40 CFR Part 98, Subpart RR), which are rules requiring reporting of greenhouse gases from facilities that inject CO2 underground for geologic sequestration. Subpart RR facilities are required to report basic information on the mass of CO2 received for injection, develop and implement an EPA-approved monitoring, reporting and verification plan, report the mass of carbon dioxide sequestered using a mass balance approach and report annual monitoring activities. Information gathered or developed and submitted for compliance with UIC class VI technical requirements can also be used to meet subpart RR requirements.
A third regime of compliance obligations arises if the project will claim credits under California’s low-carbon fuel standard (LCFS) program. LCFS credit generation can be supersized as a result of carbon capture and storage. If the project is making vehicle fuel such as ethanol or hydrogen, then the addition of capture and sequestration can give the project access to sell the fuel for a premium price in California even if the capture and sequestration do not take place in California.
Direct air capture projects that store CO2 underground do not need to have a fuel component to be issued LCFS credits. For LCFS crediting purposes, carbon capture project operators are required to submit quarterly or annual (depending on how often the project elects to undergo verification) reports of greenhouse gas emissions reductions and ongoing monitoring results to the California Air Resources Board.
Local counsel should advise on state and local law compliance obligations.
An indemnity is a way to customize risk allocation. In a carbon capture contract, the sequesterer’s indemnity for breach of contract is one of the most heavily-negotiated provisions in the contract.
There are several points of contention.
The first is the measure of recoverable damages. Recoverable damages may or may not equal the full value of the lost revenue associated with section 45Q tax credits, LCFS credits, carbon credits and other environmental attributes, depending on the reasons for the breach. There is a strong argument for full recovery if the breach was knowing or involved negligent conduct.
Liability to government agencies for environmental damage should always be covered by the indemnity because government agencies have the ability to come after any party associated with a leak, including the original source. There is room for argument over whether the source has a good defense that any release of materials from the underground reservoir falls within the federally permitted release exemption to liability under the Superfund law (officially the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 or CERCLA).
Damages owed under the indemnity may be limited by incorporating liability caps or deductibles like thresholds and baskets. The indemnity could be paid on a pre-tax or after-tax basis. It is important to specify that the indemnity covers both direct and third-party claims so as to overcome a general presumption that an indemnity clause is meant to apply exclusively to third-party actions. (For more information, see a 1996 federal district court decision called DRR, L.L.C. v. Sears, Roebuck and Co.)
The indemnifying party typically asks the indemnified party to mitigate damages, but in a carbon capture project, the ability to mitigate is limited. If CO2 is not being sequestered, no tax credits or LCFS credits will accrue, and it is probably not going to be practical to find an alternative use for the CO2 in the short term.
Close attention should be paid to the indemnity trigger events. They should include failure to transport and leakage from the pipeline or storage facility, subject to specific excused events. The pipeline and storage facility will need to be offline for routine maintenance. Some pipeline and sequestration companies may be willing to provide an availability or uptime guarantee. Force majeure is not always an excused event. In cases where it is not, the pipeline and sequesterer can seek insurance to help cover the risk.
Change in Law
Change-in-law risk in carbon capture transactions is significant.
Pipeline and sequestration companies will size their fees based on the estimated cost to provide services under current law, which presents a problem because the regulatory framework is evolving. If new regulations are issued or agencies’ interpretation of existing regulations changes, the pipeline and sequestration company will want to pass through some or all of their compliance costs to the emitter.
Congress is debating changes in section 45Q tax credits, including whether to increase the amount of the credits, reduce minimum capture thresholds for some types of industrial facilities and deny tax credits for emissions used for enhanced oil recovery. IRS interpretations could change. Changes in the tax credit regime could have significant effects on expected economic returns.
Parties sometimes resort to material-adverse-change thresholds to trigger relief for change in law. There are many ways to define material adverse effect. One way is a percentage change in net profits or in the expected economic return of one or more of the parties. Consider whether the party claiming tax credits should have the ability to walk away from the deal if there is an unfavorable change in tax law or action by the IRS that lowers the value of tax credits it has claimed.
No matter what the trigger, there should be a negotiation period during which the parties attempt to amend the documents or enter into a separate agreement to neutralize the effect of the change in law and restore the affected party to its initially anticipated economic position.
The pipeline and sequestration company is likely to be a special-purpose entity whose sole business and assets consist of the pipeline, wells and pore space leases and that has no prior business track record. Until the pipeline and storage facility are built, this entity will not have any assets other than permits and contract rights.
The emitter will be spending money to install capture facilities in reliance on the promise that the rest of the project will be built. The emitter is therefore likely to require performance security, in the form of a letter of credit, a performance bond or a guarantee from a creditworthy parent or affiliate, from the sequesterer at least until the pipeline and storage facility are built.
While bonds and guarantees are not as liquid as letters of credit, for larger and financially secure contractors with a history of executing similar projects, guarantees are probably acceptable.
There are drawbacks to a performance bond in that many common law protections have developed for sureties, and some surety bonds are written so as to require recourse first against the primary obligor before having recourse to the surety. (For more detail, see “Surety Bonds Compared to LCs” in the August 2020 NewsWire.)
A performance bond from a surety may be appropriate for a modestly-sized project, but for larger ones, a guarantee is preferable. The guarantee should require a parent or affiliate of the sequestration company that has the financial and technical resources to perform the company’s obligations under the agreement no matter what circumstances arise.
A letter of credit is the most liquid form of credit support (besides a cash deposit), but will cost the sequestration party more than a bond or guarantee. Banks charge a letter of credit issuance fee as well as commitment fees. Like it or not, the cost of the letter of credit is a pass-through cost with markup to be reflected in the tipping fee.
Credit support cuts both ways. The sequesterer might ask for a payment guarantee from the emitter once deliveries start to backstop the minimum delivery and payment requirement. The emitter should try to negotiate a step-down in the amount since the counterparty’s exposure will decrease over time. Financial assurances may be triggered if the credit support provider’s financial condition deteriorates.