Class II Injection Wells: Unlocking the Hidden Value of CO2 in Oil & Gas Production
Class II Injection Wells: Unlocking the Hidden Value of CO2 in Oil & Gas Production

Recent advances in carbon capture and sequestration (CCS) have dramatically changed the financial impacts, both positive and negative, for oil and gas upstream and midstream companies that manage produced CO2. While previously viewed as more of a nuisance or liability, that same volume of produced CO2 can now generate income. This potential revenue source consists of 45Q tax credits as well as income from carbon offset credits. While the attention has primarily been on utilizing Class VI wells for claiming the tax credits, an alternative, and possibly more advantageous option for oil and gas companies, are Class II Injection wells.

Financial Benefits and Long-Term Stability of 45Q Tax Credits and Carbon Offset Credits

To be eligible for the 45Q tax credit, an entity must store produced CO2 or other “qualifying oxides” underground. Currently, these credits are valued at $85 per metric ton (MT) for storage and $60 MT for utilizing the CO2 in enhanced oil or gas recovery. For reference, 0.05262 MT equals 1 MCF (thousand cubic feet). At $85 MT, this translates to $4.47 per MCF, while at $60 MT, it's $3.16 per MCF. 

The credit value also remains constant and is not influenced by geographic market factors or indexing. Although commodity prices fluctuate, these credit values have no inherent volatility because they are guaranteed through 2026. Starting in 2027, they increase in value based on the Consumer Price Index (CPI). 

For carbon capture and sequestration projects, the 45Q tax credits are available for a total of 12 years. It's important to note that while 45Q is labeled as a tax "credit," entities are not required to have any annual tax liability to collect these credits as they are now "refundable." In the initial 5 years of sequestration activity, the company can receive the full credit income ("direct pay") from the IRS, regardless of its tax obligations, and without any taxes on the credit income. Furthermore, during the subsequent 7 years, the company has the option to sell its credits to another interested party, although likely at a slight discount compared to the original value.

Although 12 years may be the maximum allowed for the 45Q credits, carbon offset credits can be obtained indefinitely, so long as the CO2 continues to be sequestered. As well, offset credits can be collected in addition to the 45Q credits. Although not valued as much as the 45Q credits, carbon offset credits can generate considerable revenue when sold. The advantage for an oil and gas entity is that the amount of CO2 being sequestered can be determined with accuracy. Many other carbon credits, such as those attached to forest sequestration, incur a large band of error and the volume of CO2 sequestered is realistically unknown.

Advantages of Class II Injection Wells for Oil and Gas Entities

For decades, oil and gas companies have used Class II wells to both manage their acid gas and produced water and for enhanced oil or gas recovery.  Class II Injection wells can also be an advantageous option to manage/store produced CO2 for sequestration:

  • The permitting timeframe for a Class II well is generally a year or less, whereas a Class VI permit process could require 3 to 5 years, depending on regulatory demands. Most oil and gas-producing states have Class II primacy, and therefore independently administer the permitting of those wells. For Class VI, however, permitting is still largely administered by the EPA, except in the states of Wyoming, North Dakota, and most recently Louisiana, which have primacy. 

  • Prior Class II knowledge is a tremendous advantage over trying to implement other well classes for injection. Each class of injection well is governed by its own set of regulations regarding the permitting, administration, construction, and operation of those wells. Existing Class II well operators are already familiar with the regulatory environment and the operation of those wells. 

  • The capital requirements for Class II wells are similar to other well classes, except for Class VI which tends to be much more intensive in both cost and scope. Class VI wells require expansive testing and monitoring infrastructure to be put in place to support carbon capture and sequestration. This infrastructure requires large expenditures of both time and capital for installation, and typically requires the use of multiple state or federal agencies for permitting, including the initial injection testing of the Class VI well.

  • Once a Class II CCS project has finished injecting, the well can be plugged and the bonding requirement can be lifted. For Class VI, the bonding obligation remains for another 50 years if EPA administered the permit (less if administered by Wyoming or North Dakota). Additionally, whereas state bonding for Class II is generally $500,000 or less, for Class VI the cost may be in the tens of millions of dollars. This asymmetry between the benefits and liabilities of the Class VI program creates a large hurdle for many projects to overcome. 

For those industries that aren’t oil and gas, Class II injection wells are unfortunately not a viable option for carbon capture and sequestration, and they must instead use Class VI wells. Additionally, there is a minimum threshold for eligibility (12,500 MT / 237.6 MMSCF annually), and the produced gas stream must contain less than 90% CO2. However, for those assets that do qualify, Class II carbon capture and sequestration projects can yield a substantial return.

Trihydro’s carbon sequestration services team has experience with the evaluation and permitting of these projects, and we would be happy to help you with yours.


Contact Us

Tug Eiden, P.E.
Principal CCUS Advisor, Lakewood, Colorado

Mr. Eiden has 20 years of energy and finance experience and specializes in the evaluation and management of CCUS, energy, and strategic/critical mineral projects and assets. His background includes engineering, finance, project management, and executive management for both private equity and corporate development. He has consulted for over 30 different CCUS projects throughout the continental US and Alaska across all phases, including project feasibility and strategy, financial evaluation and structuring, technical design and operations, Class VI permitting, and pore space valuation as well as financial assurance determination. He has experience advising corporate, regulatory, and legislative clients on the strategic management of CCUS projects and the costs and benefits of implementing complex projects such as CCUS.

Did you find this information useful? Click the icons below to share on your social channels.

facebook twitter linkedin
Other News


Receive the latest technical and regulatory updates in your inbox.