HOUSE BILL NO. 50 "An Act relating to the geologic storage of carbon dioxide; and providing for an effective date." 2:55:46 PM Co-Chair Johnson MOVED to ADOPT the proposed committee substitute for HB 50, Work Draft 33-GH1567\R (Dunmire, 1/22/24). Co-Chair Foster OBJECTED for discussion. 2:56:34 PM JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES, explained that the proposed committee substitute would delete a section of HB 50 that had already been enacted into law in the prior year. The section granted authority to pursue primacy to the Alaska Oil and Gas Conservation Commission (AOGCC). He introduced the PowerPoint Presentation "Recap: HB 50 Carbon Storage" dated January 25, 2024 (copy on file). He began on slide 2 and offered an overview of the presentation's agenda. Mr. Crowther continued to slide 3 and explained that the intent of HB 50 was to make Alaska's subsurface resources available for maximum use. The resources were already used in other ways, but the bill was focused on the sequestration of carbon dioxide. There were two key elements that remained in HB 50 that were core to the bill: enabling the Department of Natural Resources (DNR) to make state lands available through a leasing program, and to offer specific regulatory framework to AOGCC as it administered the program and sought to pursue primacy. Co-Chair Foster suggested holding questions until the end of the presentation. Mr. Crowther advanced to slide 4 and explained that the bill had nine hearings in the House Resource Committee (HRC) and five hearings in the House Finance Committee. The committee substitute passed out by HRC involved the following changes: several minor drafting style changes, a modified fund status to ensure that the funds would not be sweepable, adjusted commercial terms from statute and directed the terms to be established by regulations, removed federal 45Q tax credits from AS 43.20.036, and added carbon dioxide to AS 46.03.022(10)(B) to the Department of Environmental Conservation's (DEC) pipeline jurisdiction. Mr. Crowther continued to slide 5 and offered information of some developments in the carbon capture utilization and storage (CCUS) industry. There had been significant movement in the broad CCUS space in the state as well as the nation. For example, there were two new facilities in North Dakota that were actively injecting CO2. Additionally, Wyoming had issued its first Class VI well approval in December of 2023 and Louisiana had received Class VI well primacy from the Environmental Protection Agency (EPA) in December of 2023. In Alaska, grants had been issued through the federal Department of Energy (DOE) to start development on CCUS projects. 3:02:15 PM BRETT HUBER, COMMISSIONER, ALASKA OIL AND GAS CONSERVATION COMMISSION, ANCHORAGE (via teleconference), relayed that if he were to summarize his portion of the presentation, he would say "we are advancing and things are going well." He presumed that the committee would like him to go into more detail. Co-Chair Foster commented that it was a great summary but additional detail would be helpful. Mr. Huber continued to slide 7 and noted that SB 48 had passed in the prior year, which granted AOGCC the authority to pursue Class VI primacy from the EPA. The bill included funds for appropriation for one engineer position and one assistant position as well as funds for contractual and legal support. Mr. Huber continued to slide 8 and explained that for states that had completed the primacy process, the timeline ranged from three to six years. The state was presently in the pre-application phase and AOGCC's goal was to complete the process in the next two years. He relayed that AOGCC thought it would be helpful to look to other states to determine what worked and what did not work in order to meet the two-year timeline goal. He indicated that AOGCC only had control over a portion of the process and the EPA's interaction and approval was at the purview of the legislature. He added that AOGCC and EPA would collaborate on the "regulatory crosswalk," which was a comparison between federal and proposed state regulations. Only once AOGCC had submitted the complete application package would it be considered in the application phase with the EPA. Mr. Huber advanced to slide 9 and gave a brief history of EPA interactions with AOGCC pertaining to CCUS. Interaction began with a receipt of a letter of inquiry from EPA seeking states that were interested in primacy grants and pursuing Class VI primacy. He had received the letter in January of 2023 and he had replied on behalf of the state and submitted a letter of interest. He received notice of grant availability on November 2, 2023, and AOGCC attended the grant webinar on November 16, 2023. He relayed that AOGCC completed its grant application in December of 2023. He had heard that $1.93 million was allocated for each interested state and grant awards would follow in the coming spring or summer. The grant term was five years, which indicated that a protracted primacy process was still anticipated by EPA. 3:06:52 PM Mr. Huber continued to slide 10 and noted that as part of the primacy process, EPA and AOGCC would engage in a "crosswalk" process that compared state statute and regulation with federal code. The intent of the EPA was to confirm that the proposed state processes were as stringent as federal requirements. The EPA authority for CCUS was included in the Clean Drinking Water Act. The primacy process was meant to ensure that that the state was meeting or exceeding regulatory standards for the protection of fresh and clean drinking water. There were three areas of concern identified by the EPA in its initial review of the CCUS legislation in August of 2023 as listed on the slide: 1. Exceptions or waivers "for good cause" may lead to stringency questions vs. federal code 2. Liability transfer process and post-closure trust fund period could be inconsistent vs. federal code as the EPA requires liability to remain with the operator for the full, 50-year post-closure period 3. Penalty provisions AOGCC has since determined proposed penalties should meet or exceed federal code Mr. Huber relayed that AOGCC had been working closely with DNR to recommend a path forward. The approach made by Louisiana seemed like a good model for Alaska as it provided scrutiny and safeguards to the state through the end of the 50-year EPA-required monitoring period. He explained that AOGCC asked for an early review in order to avoid needing to return to the legislature year after year to ask for amendment necessary to achieve primacy; however, it was still possible that statutory amendments would be necessary in the future. Mr. Huber continued to slide 11 and remarked that AOGCC was well-resourced to pursue the primacy effort and for implementation of the program once primacy was achieved. There was a strong team dedicated to the process such as a legal team including support from DOL and contracted services with a former DOL regulatory attorney. The legal team would focus on developing the crosswalk and regulation package as well as the Memorandum of Agreement (MOA). The commissioners and staff were leading the regulatory package development, outreach, and public participation efforts, as well as providing technical input to the legal team. There were two new positions that would help in the regulatory package development and AOGCC was presently recruiting for the roles. Mr. Huber moved to slide 12 and explained that AOGCC released a request for information for consultant services and received six responses. The potential services included reservoir analysis, reservoir modelling and simulations, project management, and environmental justice activities assessments. Request for proposals would be issued nearer to the end of the primacy process in anticipation of AOGCC receiving a Class VI storage facility application. The anticipated issuance date was September of 2025. Co-Chair Foster suggested holding questions until the end of the presentation. 3:10:33 PM HALEY PAYNE, DEPUTY DIRECTOR, DIVISION OF OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES, continued the presentation on slide 14. There had been significant development in CCUS in other states since HB 50 had been introduced. After analyzing the strategies in other states, it became clear that there was not one particular leasing mechanism, public process, or suite of commercial terms that applied in every situation or in every state. There was significant variance between approaches. She noted that none of the other states had issued minimums in statute for commercial terms, which was also the case for HB 50. The Texas General Land Office (TGLO) put forward minimums, but the minimums were only in the lease sale process. An additional difference between the process in Texas as compared to a state like Wyoming or Louisiana was that when Texas passed carbon legislation in 2009, the state commenced TGLO into a study for site characterization for CO2 and the state was only offering for sale the tracks that were characterized. The site characterization study took five years from the time the legislation passed. She relayed that DNR's strategy would likely look more similar to Wyoming or Louisiana. Ms. Payne advanced quickly through slide 15 and moved to slide 16. The purpose of the slide was to bring forward the various phases of the CCUS process and legislation. The slide demonstrated the ways in which HB 50 addressed all of the CCUS phases from start to end. She stated that the majority of the components of the bill would be found in Section 16, which impacted DNR, and Section 33, which governed the AOGCC. 3:13:29 PM Mr. Crowther added that the section references on the slide were not updated to reflect the sections in the proposed committee substitute, but it would be updated if the committee substitute were to be adopted. Ms. Payne continued on slide 17, which detailed the four major authorizations under HB 50 broken out into the two different regulatory bodies: DNR and AOGCC. She explained that DNR would be licensing the state's core space which would begin with the issuance of a carbon storage exploration license. The license would allow an operator to delineate the subsurface and understand what could be used as a suitable reservoir for injection. The department would then apply to AOGCC for a carbon storage facility permit, which would involve a rigorous evaluation of the subsurface container to ensure the protection of other mineral and property interests. After a licensee could demonstrate to DNR that the permit was approved, the licensee would then be issued a carbon storage lease through DNR. The lease would authorize the injection of CO2 into the core space and would act as the governing contract for the duration of the operations into the post-closure period. The final authorization was the closure certificate, which would be issued by AOGCC. The certificate would be issued after an operator had ceased injection operations and had been able to demonstrate that the site was stabilized and met all regulatory requirements. Ms. Payne continued to slide 18, which included the expected timeline for the four authorizations detailed on slide 17. She relayed that the process would begin with the issuance of a carbon storage exploration license which would transition into a carbon storage lease once the AOGCC permit had been issued. She highlighted that the timeline was an estimate and was based on projects in North Dakota. The comparison was not perfect and it was possible that the process could take longer in Alaska. The slide also indicated the outlay of the number of capital expenditures that would be required prior to operations. Co-Chair Foster surmised that the major change in the committee substitute was the deletion of Section 3. He thanked the testifiers for the update on the CCUS field. He asked if members had questions. 3:17:19 PM Representative Josephson understood that the bill referred to the state taking ownership of the asset after ten years. The federal government had stated that ten years was an insufficient amount of time and that the industry should instead control the asset for 50 years. He asked how the ten-year timeframe was decided upon. Mr. Crowther responded that the intent with the bill as drafted was to induce and promote development by facilitating a company to plan for a ten-year obligation with the knowledge that the state would take over at the end of the obligation period. The department viewed the timeframe as a way to allow corporate entities to better plan for projects. He relayed that other states were looking at similar time frames. The restrictions from the EPA made projects more challenging but also increased the direct responsibility of the operator. The department was looking at potential amendments to ensure that the framework was consistent with EPA guidelines. Ms. Payne added that the bill was based upon the model that was developed by the Interstate Oil and Gas Compact Commission as the recommended best practices. The model also served as the basis for North Dakota's legislation. The ten-year period was more than just a demarcation as it required that an operator demonstrate the stabilization of the plume at the end of the time period. Representative Josephson noted that one issue that had been raised by a geologist in an HRC meeting was that CO2 could be used to enhance oil recovery. He remarked that there was a section of the bill on oil and gas recovery. He was concerned that credits could be "double dipping" in both regular oil development and in CCUS. He asked if the language in the bill was clear enough to ensure that credits could only be utilized once for purposes of deduction. 3:21:18 PM Mr. Crowther responded that the bill set appropriate clarity for when and how credits could be used. He noted that one of the categories was created by the underlying federal tax credit as opposed to the state framework. Operators could also potentially sequester CO2 in a pure sequestration method and receive a certain level of the 45Q tax credit. There were also options to sequester CO2 in certain manners associated with DOR if the CO2 met the criteria set out in the federal program, in which case an operator would receive a lesser tax credit. There were other pressure management activities that might not qualify for the tax credit but an operator could choose to pursue the activities. He thought that HB 50 set the correct framework amongst the various options. All operators were looking for federal guidance and clarity on some of the elements of the federal requirements. Representative Josephson suggested that it would be beneficial to include an illustration of the types of credits for the sake of clarity. He thought that a visual aid might help him understand the differences better. Production would impact the state's revenue and he wanted to ensure that the state was not mistakenly allowing credits to have a dual purpose. Co-Chair Foster agreed that the issue was new and complex. He wanted to ensure that committee members were comfortable with the topic before taking any action on the bill. 3:24:45 PM Representative Galvin referred to slide 16 and understood that the long-term monitoring timeframe had changed from the 50-year window to the 10-year window to help companies that needed to make plans within a scope that fit a business model. She wondered if there were any other considerations that went into the change. She asked for more detail on the costs of DNR overseeing the program and wondered if insurance was necessary. She was unsure of the types of liabilities that would be involved. Ms. Payne responded that it was envisioned that over the lifetime of a project, there would be an injection charge that would be put into a fund that would be available to pay for the post-closure period. The funds would be in addition to all the various levels of bonding that would be required under the Class VI permit. She noted that the EPA recommended a timeline of 50 years or until an applicant could demonstrate stabilization of the plume. The funds were imagined as another form of insurance. She emphasized that it would have to be proven that the subsurface was stabilized and it was important to remain nimble to the geology as well as recognize some corporate limitations. Representative Galvin wondered if there was any modeling of what the fund would look like and how it would function. She recalled that in the prior year, the committee had been told that sequestration would be a significant source of revenue. Ms. Payne responded that the fund was set on a project-by- project basis and it would depend on the size of the facility and the amount of CO2 being injected. The department had not done any modeling because site-specific plans were not yet available to evaluate, but there were examples in North Dakota and Louisiana. She reiterated that the department was looking closely at Louisiana because it had recently been granted primacy. Mr. Crowther noted that the committee substitute included the ten-year timeframe and the associated fund language, but it was the department's intent to adjust the timeframe through amendments in the future. Co-Chair Foster relayed that the committee was out of time but suggested that members could ask questions and the testifiers could respond in a follow up. Representative Hannan noted that the outline of the presentation spoke to an appendix with a sectional analysis but it was not in the presentation. She requested to receive the information. The comments about plume stability reminded her of the concern about seismic activity and she remarked that North Dakota and Wyoming had a different seismic environment than Alaska. She asked how the seismic activity might impact plume stability. She requested that her questions be answered in a follow up. 3:31:01 PM Co-Chair Foster WITHDREW the OBJECTION to adopting the committee substitute. There being NO further OBJECTION, Work Draft 33-GH1567\R was ADOPTED. Co-Chair Foster went over the agenda for the following day's meeting. HB 50 was HEARD and HELD in committee for further consideration.