Oil and Gas Lawyer Blog
Since passage by Congress of the Inflation Reduction Act (IRA) in 2022, significant activities and developments have taken place in Texas regarding carbon capture and underground storage (CCUS) projects. The IRA provides tax credits for injection and underground storage of carbon dioxide. As a result, major companies have begun developing CCUS projects in Texas and other states. Landowners are signing agreements with these developers allowing use of their land for injection and storage.
Tax Credits for CCUS Projects
The economic benefits to developers of CCUS projects derive solely from the federal income tax credits granted for underground storage of CO2. The credits are granted based on tons of CO2 injected. The amount of the credit varies depending on the type of project.
- Permanent storage of CO2 from carbon capture at industrial and power generation facilities: $85/ton
- Injection of CO2 for enhanced oil recovery (EOR) projects from carbon capture at industrial and power generation facilities: $60/ton
- Direct air capture projects: $180/ton for permanent storage, $130/ton for EOR projects
- Credits are inflation-adjusted beginning in 2027, indexed to base year 2025
- Credits are given for tons of CO2 injected for 12 years after beginning of injection at a CCUS facility. Injection must begin by January 1, 2033.
- A “fully refundable direct payment” for first five years.
- Fully transferable credit, and cash paid for tax credits transferred is not taxable income.
The process to qualify a project for tax credits is set forth in Section 45Q of the Internal Revenue Code and the regulations thereunder.
Class VI Well Permits
A CCUS project developer must obtain a permit to drill a well for CO2 injection. Such permits are governed by the federal Clean Water Act and administered by the Environmental Protection Agency. The permits are classified as Class VI injection well permits; to date the EPA has issued only six Class VI permits, two of which were never used — none in Texas. Obtaining a Class VI permit from the EPA can take six years or more. The EPA has received multiple applications for Class VI permits, but only one so far in Texas — from Oxy, for a direct air capture project in Ector County.
The Clean Water Act entitles states to assume responsibility for issuing permits for Class VI injection wells — to obtain “primacy” over regulation of such wells. To obtain primacy a state must adopt rules that are at least as strict as the EPA’s rules governing such permits. Currently only North Dakota and Wyoming have obtained authority to issue Class VI permits. In 2021, the Texas Legislature passed HB 1284 granting the Texas Railroad Commission authority to issue Class VI permits and directing the Commission to apply for primacy. Last year the Commission adopted regulations intended to comply with EPA permit requirements, and those regulations are under review at the EPA.
CCUS projects must meet both 45Q regulatory requirements and requirements of EPA regulations for Class VI injection wells under the Safe Drinking Water Act. The regs are designed to assure safe, permanent and secure CO2 sequestration and are very detailed and technical.
“Secure” storage requires a showing that the project provides (1) geologic security, (2) mechanical security, and (3) title security for 99 years.
- Geologic security: geologic information (seismic, well control) and modeling to show that the proposed formation will permanently retain the injected CO2.
- Mechanical security: investigation of other existing wellbores that penetrate the proposed zone, possible re-plugging of those wells.
- Title security: Has the project developer acquired sufficient rights in the property to operate the project?
The applicant for a Class VI permit must post security to secure its obligations to operate the project, monitor the CO2 injected, and provide post-injection site care and monitoring. Monitoring wells must be drilled around the plume to assure stability of the plume.
Developers look for potential areas for CO2 projects for storage of CO2 from industrial or electric generation sources that:
- are near the facility where the CO2 will be extracted from the facility emissions.
- are in a geologically “dead” zone – where there has been no oil and gas development and geology shows little or no prospects for hydrocarbon production.
- contain pore space – generally saline formations – geologically suitable for permanent storage.
Projects for direct air capture need not be near emissions sources but must identify good geologic formations for permanent storage.
CO2 Storage Agreements
Recent Texas cases have confirmed that underground pore space is an attribute of the surface estate; that is, the owner of the surface has the right to enter into agreements to use underground pore space to store CO2. Developers of CCU projects are therefore obtaining storage rights from surface estate owners. A bill in the most recent legislative session proposed to codify the ownership of pore space, but it did not pass.
Although pore space is owned by the owner of the surface estate, there could be conflicts between owners of the surface and mineral estates in using pore space for CO2 storage. If the proposed storage zone contains hydrocarbons, use of the storage space would foreclose extraction of those hydrocarbons. If there are hydrocarbons below the storage space, enhanced drilling and casing requirements for wells drilled through the storage space could make development of those deeper horizons uneconomic.
Our firm has recently represent landowners in negotiating agreements with developers for use of their land for CCUS projects. The projects we have seen target saline aquifers along the gulf coast. In those zones, it is projected that one injection well can inject CO2 to create a plume that will spread out over 2000 acres or more. For developers, a single landowner with large acreage holding, owning both surface and minerals, is the ideal target. But geology is the key.
In 2022 the Texas General Land Office leased submerged lands near Jefferson County to Talos Energy and Carbonvert for a sequestration project. The GLO has identified and posted requests for proposals for CCUS projects in several other submerged areas near Galveston and Corpus Christi.
The landowner agreements we have helped negotiate are structured much like an oil and gas lease: a bonus paid upon execution, a primary term, and a royalty based on tons injected. The primary term – called development term – may be up to 10 years, time for the developer to obtain Class VI well permit and design the project. Annual payments during the development term are negotiable. The “operations term” begins when injection commences; royalty payments are expressed as dollars per ton injected. The dollar amount may escalate based on number of tons injected. Royalty rates are tied to increases in the 45Q credit, which is indexed to inflation. The agreement may also contain provisions allowing pooling or integration of the tract with other tracts in the project; compensation for surface uses such as well sites, roads, pipelines, etc.; insurance requirements, indemnity provisions, restrictions on assignability, and defining the depths covered by the agreement.
Legislation
Several states have adopted statutes addressing risks of CCUS. While these differ in particulars, the general structure is to create a trust fund to cover long-term liability issues of a project, and “transfer” liability for such obligations to the state after the project has been closed. Liability is transferred to a trust fund created with fees charged for permitting of CCUS projects and a fee charged for accepting the transferred liabilities. Supporters say such statutes are necessary for the success of CCUS projects. Operators are generally allowed to opt in to such transfers of liability. Some operators are opposed to such liability-transfer provisions.
Such legislation was proposed in the recent Texas legislative session, SB 2107 and companion HB 4484. Both died. They were opposed by landowner and environmental groups. These bills also contained language confirming surface ownership of pore space and provisions allowing for forced pooling, or forced integration, of unleased tracts into a pool. We expect similar legislation will be proposed in future sessions.
Risks of CO2 Projects
Some risks related to CCUS projects are those common to oil and gas operations: drilling wells, traffic, pipelines, etc.
CO2 injection wells are not new in Texas and have been in use for many years in EOR projects. Risks for CCUS projects include potential contamination of groundwater and pipeline leaks/explosions.
CO2 pipelines will likely transport CO2 as a liquid, under high pressure. CO2 is colorless and odorless and heavier than air and so can settle near the ground and choke off availability of oxygen.
For an example of risks from pipeline leaks, see: