In the first of a two-part series about the economics of CCUS, we'll examine the potential revenue streams applicable to a broad range of CCUS projects. The second part of this series will explore the typical capital costs associated with CCUS project investment.

Part 1: Generating Revenue from Carbon Capture

Let's start by examining the cornerstone of CCUS project revenue: the 45Q tax credit.

Using the 45Q Tax Credit

The 45Q tax credit was first added to the US tax code in 2008, but the Inflation Reduction Act (IRA) of 2022 eliminated its reliance on corporate tax liability and its competition with other tax deductions and credits. Before the IRA, the potential to claim credits was limited, so the financial viability of most CCUS projects was impaired. The IRA transformed the credit into a direct revenue source, broadly stimulating CCUS project development. It also opened additional avenues for viable CCUS business models.

During the first 5 years of carbon sequestration, the project operator may possess the full credit income (“direct pay”) from the Internal Revenue Service (IRS), regardless of what it owes in taxes, and tax-free. Credits can also now be transferred (“sold”) at any time during the 12-year collection period. Logically, it makes sense to leverage direct pay during the first 5 years because transferred credits will generally sell at a discount relative to their original value. The sale of future credits does not, however, impact the ability of the project developer to claim current credits. 

Additionally, because the credit price is fixed for the next few years, there is no volatility in the absolute credit value. However, in an interesting twist, although the current $85/MT (metric ton) is a static price through 2026, it will increase thereafter based on the Consumer Price Index (CPI). Therefore, projects that come online later may benefit from larger credit values per MT, barring any deflationary scenario. 

However, the 45Q credits will be collected a year after they are generated, much like filing your individual taxes and getting the return the following year. This means that the credits will only produce revenue in the calendar year following their generation, including any credits intended for transfer. Additionally, although the value of the credits doesn’t technically change, the present value of the credits will reduce due to the additional time required to collect them from the IRS. 

Presently, the current 45Q tax credit structure is authorized for only 12 years. This lack of long-term revenue potential creates a significant asymmetry between the total project revenue and the long-term liability that must be carried on these projects after the injection has ceased. The liability timeframe may be as short as 10 years in North Dakota to as much as 50 years for federal EPA projects. The credit has been modified before, so it’s possible that the 45Q tax credit structure could be authorized beyond the 12-year project timeframe. However, a present option to help reduce the revenue/liability asymmetry is the exploration and leveraging of carbon offset credits. 

Using Carbon (Offset) Credits

Carbon offset credits (i.e., carbon credits, offset credits) can be traded in perpetuity if geologic storage continues to cooperate. Therefore, they can be a long-term revenue source well beyond the current 45Q tax credit timeline and collected in addition to the 45Q tax credits, as the two are mutually exclusive. 

Unlike the 45Q tax credit, carbon offset credits trade through a market, meaning the value will be volatile and will fluctuate like a typical commodity. Historical carbon offset credit values have fluctuated from $5/MT to $25/MT for most carbon sequestration operations and more than $1,000/MT for direct air capture operations. Although carbon offset credit markets have been around for decades in varying degrees of viability (e.g., Kyoto Protocol’s Clean Development Mechanism, California’s LCFS Credit Market), the market for carbon offset credits is emerging. The market is anticipated to become more liquid over the coming years, but there is also a possibility that it may not be viable long-term if there is insufficient supply or demand. 

Impact of Increased Depreciation

Although not a form of revenue, increased asset depreciation enhances a project's cash flow by reducing the overall tax liability of its corporate developer(s). 

Before the IRA, the additional depreciation created by a CCUS project was largely counterproductive because it reduced the amount of tax credits that could be collected from the project, which in turn eroded the project’s value. That’s not the case now. As described earlier, the IRA detached 45Q from a company’s annual tax liability. The reduced tax liability created by the project’s additional depreciation now creates incremental project value for the developer(s).

However, because depreciation is related to the direct capital investment in a project, the higher the project's investment, or cost, doesn’t necessarily translate into a higher value for a project.  Depreciation only benefits a tax liability, and large investment costs are detrimental to project economics. 

Part 2: Associated Capital Costs

CCUS projects are capital-intensive, requiring multiple equipment installations for the operation and monitoring of a site. It is important to note that each project is different and may require some investments that others do not. However, at least one expenditure that all sequestration projects require is a well.

Injection Wells, Monitor Wells, and Test Wells

At its most basic, the injection well is the conduit that moves the carbon dioxide (CO2) from the surface to geologic storage below the surface. Externally, the well is constructed from multiple strings of casing and cement to prevent native and injected fluids from traveling to the surface. For CCUS projects, the Class VI permit addresses the construction of the injection well.

Monitor wells are constructed similarly to injection wells but serve to monitor either the injection zone or the confining zone for pressure, fluid leakage, or CO2. They are typically permitted through state agencies, and design criteria depend on whether the well is monitoring the injection zone or the confining zone and whether it will encounter CO2. 

Some, if not most, projects will also utilize a stratigraphic test well. These wells are drilled prior to project development and determine whether the geology is suitable for injection and storage and help fine-tune the final injection well design. Although it is an additional cost, a test well can help a potential project operator determine if the project will be technically and geologically feasible.

Regardless of the well type, the design should be similar for regulatory compliance and practical reasons. The well needs to be durable enough to resist corrosion caused by CO2, the natural fluids in the formation, and any other substances that will be injected with the CO2.

Surface Facilities

Surface facilities separate, purify, dehydrate, compress, and pump. Most designs begin with the source of the CO2 and its temperature and pressure, as well as the required pressure and temperature at the delivery point (i.e., the injection well). Other constituents in the gas stream, such as water, oxygen, or hydrogen sulfide, also impact the design. 

There’s an interplay between the surface facility and the injection well: the well should be designed to inject the fluid(s) delivered to it. A cleaner CO2 stream will reduce the cost of the injection well, but the higher purity may require additional facility costs. Additionally, if a pipeline is involved in the project, it may have a different requirement for the gas specification than the injection well.

It’s an erroneous assumption that CO2 needs to be supercritical to be injected; it can also be in a gaseous state. Gaseous CO2 will require less equipment to be installed than for supercritical CO2, and gaseous CO2 has the propensity for better flow in a reservoir than supercritical, which is helpful when the permeability of the injection reservoir is low. However, supercritical CO2 generates lower operational expenses since it reduces the surface pressure at the wellhead and facilities, reducing the surface equipment's pressure and horsepower requirements.

Finally, when reviewing engineering designs for the surface facilities, remember that manufacturing costs are separate from installation costs, and the latter can sometimes be overlooked to the detriment of a project budget.

Pore Space

The thickness of the injection formation and its native pressure, porosity, and extent play important roles in the size of the CO2 plume, and the plume size subsequently determines the amount of pore space that will be required.

The formation’s thickness and porosity impact the distance of the plume from the injection well. All things being equal, a reservoir with a lower pressure will have a larger plume than a reservoir with a higher pressure because the higher pressure compresses the CO2 more. Importantly, after injection ceases and the reservoir pressure begins to decrease, the plume will slightly expand. This expanded size will determine the overall pore space required for a project. One strategy to minimize pore space needs is to utilize more than one injection interval (if feasible), thereby stacking multiple plumes on top of one another and reducing the needed pore space.

If the CO2 is injected somewhere away from the source, the surface site will also need to be purchased or leased.

Testing & Monitoring Equipment

Testing and monitoring (T&M) are essential for tracking the pressure in the injection and confining zones, the movement of the CO2 plume, and the condition of the groundwater, soil, and air near the project site. A combination of techniques are often utilized to achieve T&M, including multiple well installations, 2D or 3D seismic surveys to track plume movement, and potentially passive seismic monitoring to detect formation fracturing. Additionally, an upfront seismic survey may be needed to help characterize the future injection site and to specifically look for potential geological risks such as faults or structures.

However, using wells to monitor a CCUS project is iatrogenic. Care should be taken to minimize the number of wells, since each well drilled through the confining formation creates another potential leak path to the surface. The more wells installed, the higher the risk of leakage and, thus, the larger the liability. 

Another cost-effective insurance policy is collecting groundwater, soil, and air data around the project site before development. By collecting a robust baseline data set and understanding how the natural environment varies seasonally and annually, elevated constituents detected during injection can be analyzed in the context of the natural system and can be used to evaluate if there is leakage created by the project.

Corrective Action on Existing Wells

Corrective action involves remediating wells (plugged or active) that may leak due to elevated pressure within the injection formation or when in contact with the CO2 plume. The risk is the same as that posed by leaking monitoring or injection wells: the more wells present, the higher the risk of leakage. 

Remediation generally requires re-entering and re-plugging those wells to a modern standard to withstand elevated pressure and/or potential CO2 corrosion. For wells that can’t be located at the surface, the process can be difficult and onerous if they can’t be re-engaged. A full technical assessment should be done to either find a way to re-enter the well, drill a T&M well near the other well, or insure against the risk of leakage in the financial assurance.

CCUS Permitting

Permitting a CCUS project is a multi-year effort and often requires coordinating with multiple state and federal agencies. Consulting and legal guidance are often necessary to help the project through the regulatory process to full operation. 

The obvious permit need is the injection well permit from either the EPA or a state agency (if the state has primacy). As part of the Class VI process, additional needs include public relations, an environmental justice evaluation, insurance and financial assurance funding, a Class V permit for the injection test, and a monitoring, reporting, and verification (MRV) plan to qualify for the 45Q tax credits, (specifically the Subpart RR MRV).

A note about the injection test: a lot of capital costs are dependent on a quality injection test, especially the well design(s), the number of injection wells required, the T&M, and the amount of required pore space. Although an injection test isn’t necessarily required for the injection well permit, it is generally better to know you have suitable geology and a solid project than to guess that you do.

Trihydro’s CCUS team can help you navigate the project opportunities. By combining technical proficiency with an understanding of potential financial drivers, we can help develop solutions tailored to your specific needs.