In 2011, the California Capture and Storage (CCS) Review Panel issued recommendations to guide the development of legislation and regulations regarding CCS in California. In 2017, the California Air Resources Board issued a concept paper for a regulatory program on carbon capture and storage. In 2018, the California Air Resources Board finalized a Carbon Capture and Sequestration Protocol under the Low Carbon Fuel Standard.

Utility Cost Recovery Mechanism
Enacted in 2006, Colorado H.B. 06-128 provides a utility cost recovery mechanism for Integrated Gasification Combined Cycle (IGCC) power plants of 350 megawatts or less that use Colorado or other western coal to generate electricity and that demonstrate the capture and sequestration of a portion of the project’s carbon dioxide emissions. The cost recovery mechanism allows utilities to seek recovery of full life-cycle capital and operating costs; financial support for study, engineering, and development from a clean energy development fund; and support in obtaining federal funding.

Utility Cost Recovery Mechanism
Enacted in 2007, Florida House Bill 549 requires the Public Service Commission to implement rules related to integrated gasification combined cycle power plant cost recovery.

Forthcoming

Utility Cost Recovery Mechanism

P.A. 95-1027, of 2009, guarantees electricity purchase agreements for the first Illinois coal facility with CCS technology.

Financial Assistance for CCS Projects and CO2 Pipelines

Enacted in 2007, S.B. 1592, allows utilities to assess a Renewable Energy Resources and Coal Technology Development Assistance Charge to be deposited in a Coal Technology Development Assistance Fund. The Fund can be used to support the capture or sequestration of carbon emissions produced by coal combustion or to support research on the sequestration of carbon emission produced by coal combustion. S.B. 1592 also states that the Illinois Finance Authority, through the Illinois Power Agency, can give preference in issuing bonds for the construction and operation of electric generation facilities that use technologies that enable carbon capture and are located in sites where the geology is suitable for carbon sequestration.

Though not directly related to CCS, Illinois has a unique program called the Illinois Coal Demonstration Program. Created in 1981 and operated by the Illinois Department of Commerce & Economic Opportunity, the Coal Demonstration Program offers bonds to deploy innovative clean coal technologies.

Off-Take Agreements

Passed in 2008, P.A. 95-1027 allows the initial clean coal facility in Illinois, which obtains an air permit, to enter into thirty-year agreements with utilities to provide electricity.

State Assumption of Long-Term Liability for Sequestered CO2

Enacted in 2007, S.B. 1704 authorizes the State of Illinois to assume the title to and liabilities associated with CO2 injected by the FutureGen project. Title and liability for the CO2 are transferred upon injection and verification by the Illinois Environmental Protection Agency. Enacted in 2010, P.A. 96-1491 slightly amended the provisions of enacted by Senate Bill 1704.

Regulatory authorities
Enacted in 2006, SB 22 created a Pipeline Safety Division within the Indiana Utility Regulatory Commission to oversee CO2 pipeline safety.

Off-Take Agreements
In December 2010, the Indiana Finance Authority agreed to enter into a 30-year contract to purchase substitute natural gas (SNG) from Indiana Gasification, a SNG production plant that will capture 90 percent of its CO2 emissions. (State of Indiana Press Release, Indiana Finance Authority Resolution No. G34-2010)

State Assumption of Long-Term Liability for Sequestered CO2
Enacted in 2011, House Bill 259 allows a CO2 storage operator to transfer ownership and liability for a CO2 storage facility to the state’s Finance and Administration Cabinet, provided that there is no comparable federal agency to accept liability and following a required period of monitoring following project completion and plugging.

Regulatory authorities
Enacted in 2007, HB 2419 authorizes the Kansas State Corporation Commission to adopt specific rules for the safe and secure injection of CO2 and the maintenance of underground storage sites.

CO2 storage trust funds
Enacted in 2007, HB 2419 authorizes the Kansas State Corporation Commission to establish fees for a CO2 injection well and underground storage fund. The Commission may use the fund to pay for expenses related to permitting and monitoring active and long-term CO2 geologic storage sites, as well as the costs of mitigating any adverse environmental impacts of CO2 injection.

Enacted in 2007, HB 2419 defines a “carbon dioxide injection well,” as a well where CO2 is injected for either underground geologic storage or enhanced hydrocarbon recovery. Therefore, HB 2419’s additional regulatory provisions apply to both types of projects.

Regulatory authorities
Enacted in 2011, HB 259 designates the Division of Oil and Gas within the Department for Natural Resources as the agency to oversee long-term CO2 storage.

CO2 storage is declared to be in the public interest
HB 259 states that the geologic storage of CO2 is in the long-term interest of the Commonwealth.

Pore space
Enacted in 2011, HB 259 directs CO2 storage operators to make good faith attempts to acquire the rights to pore space needed for long-term storage. If an operator has made good faith efforts and acquired 51 percent of the interest in an area of pore space, the Department for Natural Resources’ Division of Oil and Gas can order the pooling of all associated pore space in an area to enable its use for CO2 storage. Compensation must be provided to pore space owners who do not consent to CO2 injection.

Regulatory authorities
Enacted in 2009, HB 661 authorizes the Commissioner of Conservation in the Louisiana Department of Natural Resources to regulate the development of CO2 storage projects and CO2 pipelines. See La. Stat. Ann. § 30: 1102(B); 1104.

CO2 storage is declared to be in the public interest
In 2009, through HB 661, Louisiana formally declared that “the geologic storage of carbon dioxide will benefit the citizens of the state and the state’s environment by reducing greenhouse gas emissions.” See La. Stat. Ann. § 30: 1102.

CO2 storage trust funds
Enacted in 2009, HB 661 creates a Carbon Dioxide Geologic Storage Trust Fund, to be operated by the Commissioner of Conservation, who collects fees for each ton of CO2 injected for storage. The trust fund is intended to fund operational and long-term inspecting, testing, maintenance, and monitoring of CO2 storage sites.

Rules for CO2 ownership
HB 661 designates the operator of a geologic storage facility as the party liable for injected CO2, though not necessarily the owner of injected CO2. Ownership of CO2 will be established by contract between private parties. The state of Louisiana may assume ownership of a CO2 storage location, but does not assume liability for injected CO2.

Pore space
Enacted in 2009, HB 661 authorizes parties seeking to conduct geologic sequestration to use eminent domain, provided that all conditions for operating a geologic sequestration site are met. Eminent domain may be applied in acquiring surface and subsurface rights, including property interests necessary for constructing and operating geologic sequestration facilities and pipelines. Eminent domain cannot be used to acquire lands with active or potential oil and gas operations.

Enacted in 2009, HB 661 states that the requirements for geologic sequestration adopted by the legislation do not apply to the use of CO2 in EOR. HB 661 also directs the state’s Office of Conservation to approve the conversion of CO2-EOR projects into CO2 storage-only projects when appropriate conditions are met.

State Assumption of Long-Term Liability for Sequestered CO2
Enacted in 2009, House Bill 661 enables CO2 storage operators to transfer liability for stored CO2 to the state. Ten years after CO2 injection has ceased, the Commissioner of Conservation will issue a certificate of completion of injection operations, provided that the CO2 storage operator can demonstrate that the storage reservoir “is reasonably expected to retain mechanical integrity and the carbon dioxide will reasonably remain in place.” After a certificate has been issued, the CO2 storage operator can transfer liability for the storage facility and stored CO2 to the state.

Utility Cost Recovery Mechanism
Enacted in 2013, the Mississippi legislature passed H.B. 894 and H.B. 1134. H.B. 894 authorizes the Mississippi Public Service Commission to approve of ratepayer recovery for the Kemper County Energy Facility. H.B. 1134 authorizes Mississippi Power, the developer of the Kemper County Energy Facility, to issue $1 billion in bonds to cover the costs of the project’s development that are also eligible for rate payer recovery.

Eligibility of CCS in Electricity Generation Portfolio Standards or Voluntary Goals
Signed into law on October 6, 2008, the Clean, Renewable, and Efficient Energy Act, S.B. 213, establishes an Integrated Renewable Portfolio Standard (RPS) that requires energy providers to provide 10 percent of electricity by 2015 through renewable energy generation, renewable energy credits, and energy optimization programs to increase energy efficiency. A coal-fired electric generating facility that captures and permanently sequesters 85 percent of CO2 emissions qualifies an “advanced cleaner energy system.” Advanced cleaner energy credits may be used to help meet the Integrated RPS target.

Regulatory authorities
Enacted in 2011, SB 2723 designates the Mississippi Oil and Gas Board as the agency responsible for promulgating and enforcing rules and regulations governing geologic sequestration.

CO2 storage trust funds
Enacted in 2011, SB 2723 directs the Mississippi Oil and Gas Board to collect a fee based on the amount of CO2 injected for geologic sequestration. Once the Board has covered its costs of overseeing geologic sequestration facilities, the remaining revenue will accumulate in a Carbon Dioxide Storage Fund. Once a geologic sequestration facility has contributed $2.5 million to the Fund, fees will only be collected to maintain that facility’s $2.5 million balance in the Fund. The Fund will be used to pay for the state’s on-going costs for monitoring and overseeing CO2 sequestration projects.

Requirements for CO2 responsibility
SB 2723 directs the Mississippi Oil and Gas Board to establish financial requirements for the operation of CO2 sequestration sites, including bonds, deposits, or other assurances, which are in line with federal requirements for UIC Class VI wells. The Board also determines when parties may be released from maintaining these measures.

Pore space
Enacted in 2011, SB 2723 directs the Mississippi Oil and Gas Board to approve the use of reservoirs as carbon sequestration facilities provided that a majority interest in the reservoir has provided its consent.

Enacted in 2011, SB 2723 specifies that rules applying to geologic sequestration of CO2 do not apply to CO2 injection for enhanced oil recovery. The Mississippi Oil and Gas Board has the authority to approve the conversion of a Class II EOR well to a Class VI geologic storage-only well. SB 2723 also specifies that the Oil and Gas Board shall be authorized to recognize a CO2-EOR project’s “incidental sequestration of carbon dioxide that is occurring during its enhanced oil or gas recovery project without requiring the project to qualify as a geologic sequestration facility.”

Regulatory authorities
Enacted in 2009, SB 498 designates the Montana Board of Oil and Gas Conservation to oversee CO2 injection and storage projects.  The bill directs the Board to solicit and consider comments from the Montana Department of Environmental Quality prior to issuing an injection permit and issuing a certificate of completion.

CO2 storage trust funds
Enacted in 2009, the Montana legislature enacted SB 498 which authorizes the Montana Board of Oil and Gas Conservation to collect a fee based on the amount of CO2 injected by geologic storage operators. The fees will be deposited into a geologic storage reservoir program account, which will be used by the Board for monitoring and maintaining geologic storage reservoirs. The state of Montana can assume liability for geologic CO2 storage sites beginning 15 years after CO2 injection for a given project has ceased, provided that a project meets necessary requirements to show that CO2 has been safely stored.

Rules for CO2 ownership
SB 498 designates the operator of a geologic storage facility as the owner of CO2 injected underground during operations and until a certificate of completion for the project is issued and ownership is transferred to the state.

Pore space
Enacted in 2009, SB 498 designates the owner of surface land as the owner of geologic storage reservoir unless deeds or severance documents establish ownership with a different party. SB 498 also establishes a process for the unitization of geologic sequestration sites. The Montana Board of Oil and Gas Conservation may authorize unitization upon receiving an application from parties owning at least 60 percent of a sequestration site.

Enacted in 2009, SB 498 states that none of the requirements for geologic sequestration introduced by the legislation shall impair the use of CO2 in EOR.

State Assumption of Long-Term Liability for Sequestered CO2
Enacted in 2009, S.B. 498 enables CO2 geologic storage operators to transfer liability for injected CO2 to the state. Fifteen years after CO2 injection has ceased, a CO2 geologic storage operator may apply to the Board of Oil and Gas Conservation for a certificate of project completion. The certificate will only be issued if the CO2 geologic storage operator is in full compliance with CO2 geologic storage regulations. Once the certificate has been issued, the CO2 geologic storage operator may transfer the title to the geologic storage reservoir and the stored CO2 to the state.

Regulatory authorities
Enacted in 2009, SB 2095 designates the North Dakota Industrial Commission to regulate the construction, operation, and closure of carbon dioxide geologic storage facilities.

CO2 storage is declared to be in the public interest
HB 2095 declares that the geologic storage of CO2 is in the public interest because it will benefit the state and the global environment.

CO2 storage trust funds
Enacted in 2009, SB 2095 creates a carbon dioxide storage facility administrative fund and a separate carbon dioxide trust fund. The North Dakota Industrial Commission is authorized to collect fees from CO2 storage operators based on the amount of CO2 injected for storage. Fees deposited in the carbon dioxide storage facility administrative fund will be used to pay for Commission expenses related to regulating CO2 storage facilities during construction, operations, and pre-closure phases. Fees deposited in the carbon dioxide trust fund will pay anticipated expenses associated with the Commission’s long-term monitoring and management of a closed storage facility. The state of North Dakota can assume liability for geologic CO2 storage sites 15 years after CO2 injection has ceased.

Pore space
Enacted in 2009, SB 2095 addresses multiple aspects of pore space in permitting geologic CO2 sequestration. Before receiving a permit for geologic CO2 sequestration, a storage operator must obtain at least 60 percent of a storage reservoir’s pore space. Non-consenting pore space owners must be compensated for pore space use. The Commission may rule that the pore space of non-consenting owners be subject to inclusion in a geologic storage site. Also enacted in 2009, SB 2139 forbids the owner of surface property from severing the title of subsurface pore space, though pore space may be leased. SB 2139 states, “Undivided estates in land and clarity in land titles reduce litigation, enhance comprehensive management, and promote the security and stability useful for economic development, environmental protection, and government operations.”

CO2 pipelines and/or eminent domain
The North Dakota Century Code (Chapter 49-19) for Common Pipeline Carriers includes CO2 pipelines among eligible pipelines.

Enacted in 2009, SB 2095 states that the law’s provisions involving CO2 sequestration do not apply to the use of CO2 in EOR. SB 2095 also directs the state’s Industrial Commission to establish rules and procedures that would allow a CO2-EOR project to transition to a CO2 storage-only project. The Industrial Commission is also directed to establish rules and procedures for determining the amount of CO2 that has been or is being stored in an EOR project for the purposes of “carbon credits, allowances, trading, emissions allocations, and offsets, and for other similar purposes.” to establish rules and procedures that would allow a CO2-EOR project to transition to a CO2 storage-only project. The Industrial Commission is also directed to establish rules and procedures for determining the amount of CO2 that has been or is being stored in an EOR project for the purposes of “carbon credits, allowances, trading, emissions allocations, and offsets, and for other similar purposes.”

State Assumption of Long-Term Liability for Sequestered CO2

Enacted in 2009, S.B. 2095 enables the operator of a CO2 storage facility to transfer the title to the CO2 storage facility and stored CO2 to the state. Ten years after CO2 injections end, the North Dakota Industrial Commission will issue a certificate of project completion to a CO2 storage project operator, provided that the operator has met all of legal and safety requirements for storing CO2. Once the certification of project completion has been issued, the CO2 storage facility operator may transfer title to the CO2 storage facility and stored CO2 to the state.

Financial Assistance for CCS Projects and CO2 Pipelines

The North Dakota Pipeline Authority is authorized (Chapter 54-17.7) to make grants, loans, or other forms of financial assistance to support the development of pipelines for CO2 transportation.

Regulatory authorities

In 2010, SB 165 established that the Division of Oil and Gas Resources Management has the authority to issue permits for underground injection of carbon dioxide for secondary or tertiary recovery of oil or natural gas.

Eligibility of CCS in Electricity Generation Portfolio Standards or Voluntary Goals
In May 2009, Ohio enacted broad electric industry restructuring legislation that includes a requirement for utilities to provide 25% of their retail electricity supply from alternative energy resources by 2025. This requirement is codified in the Ohio Revised Code Section 4928.64 et seq. A coal-fired electric generating facility that captures CO2 emissions qualifies as an “alternative energy resource.”

Regulatory authorities
Enacted in 2009, SB 610 designates the Oklahoma Corporation Commission to oversee CO2 injection for carbon sequestration into oil and gas formations, coal-bed methane reservoirs, and mineral brine reservoirs. The Department of Environmental Quality oversees CO2 injection for carbon sequestration in deep saline formations. The Corporation Commission will oversee any CO2 geologic sequestration facility that injects CO2 under a Class II permit.

CO2 storage is declared to be in the public interest
SB 610 declares that CO2 injection for the purposes of sequestration and storage in addition for enhanced oil recovery is in the public interest.

Rules for CO2 ownership
Enacted in 2009, SB 610 identifies the owner of a CO2 sequestration facility as the owner of the CO2 injected into geologic formation by that facility, unless another party is designated as the owner by contract or other legally-binding mechanism.

Enacted in 2008, SB 1765 affirms that Oklahoma’s existing laws and regulations related to the use of CO2 in EOR are sufficient to protect human health and the environment. SB 1765 establishes new and separate provisions for CO2 geologic sequestration. Enacted in 2001, SB 629, which directs the state’s Conservation Commission to verify and certify the amount of CO2 injected and stored underground by both EOR and non-EOR projects in the state.

Regulatory authorities
Enacted in 2009, HB 1129 designates the South Dakota Public Utilities Commission to oversee the integrity of CO2 pipelines used for transporting CO2 for enhanced oil recovery or geologic sequestration.

Regulatory authorities
In 2009, SB 1387 authorized the Railroad Commission of Texas to regulate the injection and geologic storage of carbon dioxide in reservoirs that are producing or may produce oil, gas, or geothermal resources or saline formations directly above or below such reservoirs.

CO2 storage trust funds
Enacted in 2009, SB 1387 creates a carbon dioxide trust fund. The Railroad Commission of Texas is authorized to collect fees for the trust fund and use collected fees to inspect and monitor existing CO2 injection wells and long-term geologic storage facilities.

Pore space
Enacted in 2009, SB 1387 provides the criteria under which the Railroad Commission of Texas may issue a permit for CO2 injection for geologic storage. In addition to health and safety criteria, there is a provision to only allow permitting when CO2 injection will not endanger any oil, gas, or other mineral formation.

CO2 pipelines and/or eminent domain
The SB 1387 (Chapter 111) extends common carrier status to CO2 pipelines. Once granted common carrier status, a pipeline operator may apply eminent domain to acquire necessary land for pipeline construction.

Enacted in 2009, SB 1387 clarifies that its provisions for CO2 injection for geologic storage do not apply to CO2 injection permitted under the EPA’s UIC Class II regulatory requirements.

Financial Assistance for CCS Projects and CO2 Pipelines
Enacted in 2007, H.B. 3732 authorizes financial grants and loans to clean energy projects. Projects that use technology to capture, sequester, or abate CO2 qualify as “advanced clean energy projects.”

Financial Assistance for CCS Projects and CO2 Pipelines
Enacted in 2005, H.B. 2201 approved $22 million in grants and incentives for a possible FutureGen project in the state, though Texas was subsequently not chosen for FutureGen.

State Assumption of Long-Term Liability for Sequestered CO2
Enacted in 2009, H.B. 1796 authorizes the development of an offshore deep subsurface geologic repository for storing anthropogenic CO2. The School Land Board will assume ownership and liability for CO2 injected in the repository.

Regulatory authorities
Enacted in 2008, the Utah legislature passed SB 202 which directs the Department of Environmental Quality’s Board of Water Quality and the Board of Air Quality, in collaboration with the Utah Division of Oil, Gas, and Mining and the Utah Geological Survey to recommend rules to the legislature relating to carbon capture and accompanying geologic sequestration of CO2.

Eligibility of CCS in Electricity Generation Portfolio Standards or Voluntary Goals
Enacted in 2008, S.B. 202 established a voluntary Renewable Portfolio goal to generate 20% of electricity from renewable or other qualifying sources by 2025. Electricity generated from a source that combines carbon sequestration can help meet this goal.

Utility Cost Recovery Mechanism
Enacted in 2007, S.B. 1416 and H.B. 3068 allow utilities to recover an enhanced rate of return on investments in certain projects, which may include projects utilizing carbon capture facilities.

Regulatory authorities
Enacted in 2009, HB 2860 tasks the West Virginia Department of Environmental Protection with permitting CO2 sequestration activities. In addition, HB 2860 designates the Secretary of the Department of Environmental Protection to oversee a carbon dioxide sequestration working group to develop additional regulations for permitting and regulating CO2 sequestration projects.

CO2 storage is declared to be in the public interest
HB 2860 declares that advancing carbon capture and storage technologies in the state’s energy portfolio is in the public interest.

Enacted in 2009, HB 2860 states that the use of CO2 in EOR is not subject to the legislation’s provisions regarding the geologic sequestration of CO2.

Regulatory authorities

The Wyoming Oil and Gas Conservation Commission regulates enhanced oil recovery (EOR) projects. Rules Wyo. Oil & Gas Conservation Comm’n, ch. 4, §§ 7 through 10. The Wyoming Department of Environmental Quality oversees the geologic sequestration of carbon that is not done for an EOR project. Wyo. Stat. Ann. §§ 35-11-313 through -317; Rules Wyo. Dep’t of Envtl. Quality, Water Quality, ch. 24.

CO2 storage trust fund
There is a geologic sequestration special revenue account to fund the Wyoming Department of Environmental Quality’s work in measuring, monitoring, and verifying CO2 sequestration after CO2 injection for sequestration at a facility or site has ended. The account is funded by fees collected from parties issued permits for CO2 sequestration. Wyo. Stat. Ann. § 35-11-318.

Rules for CO2 ownership

Carbon dioxide injected into an underground formation is presumed to be owned by the injector. This presumption may be rebutted. Wyo. Stat. Ann. § 34-1-153.No surface estate owner may be held liable for the effects of injecting carbon dioxide in pore space underlying the surface simply because they consented to the injection. Wyo. Stat. Ann. § 34-1-153.

Requirements for CO2 responsibility
Parties seeking a permit for carbon dioxide sequestration must comply with financial assurance requirements set by the Wyoming Department of Environmental Quality. Wyo. Stat. Ann. § 35-11-313.

Pore space
The owner of surface land also owns the pore space below. A surface owner may sever ownership of pore space. Wyo. Stat. Ann. § 34-1-152.

The Wyoming Oil and Gas Conservation Commission may unitize pore space at geologic sequestration sites. The Commission will authorize pore space unitization upon reviewing a unitization plan that has gained the consent of parties owning at least 80 percent of pore space capacity within the unit area. In some circumstances, the Commission will also authorize unitization with the consent of parties owning 75 percent of pore space capacity. Wyo. Stat. Ann. §§ 35-11-314 through -317; Rules Wyo. Oil & Gas Conservation Comm’n, ch. 3, § 43.

CO2 pipelines and/or eminent domain

All petroleum and other pipeline companies may exercise eminent domain in Wyoming. Wyo. Stat. Ann. § 1-26-814. In a 2013 Wyoming Supreme Court case discussing how to determine fair compensation for such a condemnation, the parties stipulated that a company seeking to construct a carbon dioxide pipeline “could properly obtain … easements [to construct the pipeline] by condemnation.” Barlow Ranch, Ltc. P’ship v. Greencore Pipeline Co. LLC, 2013 WY 34, 301 P.3d 75 (Wyo. 2013).

Carbon dioxide injected for long-term sequestration is regulated by the Wyoming Department of Environmental Quality. Wyo. Stat. Ann. § 35-11-313(a).

The injection of carbon dioxide for enhanced oil recovery purposes is instead regulated by the Wyoming Oil and Gas Conservation Commission. Wyo. Stat. Ann. § 35-11-313(b).

Financial Assistance for CCS Projects and CO2 Pipelines
The Wyoming Pipeline Authority is authorized to issue bonds and provide loans for pipeline infrastructure, including CO2 transportation pipelines. Wyo. Stat. Ann. § 37-5-101.