The California Public Utilities Commission (CPUC) has issued a Ruling in its Integrated Resources Plan (IRP) proceeding that proposes to meet a significant portion of new capacity for electricity generation with “green” or “renewable” hydrogen rather than fossil fuels.
The unambiguous and audacious goal of the IRP Ruling’s renewable hydrogen mandate is “to help support a transition toward greater use of renewable hydrogen to replace natural gas” in California.
Requiring new renewable hydrogen-powered electric generation comes on the heels of Governor Newsom’s Proclamation of a State of Emergency issued on July 30, 2021. That Proclamation directed the CPUC to accelerate work on deployment of new clean energy projects to decrease the risk of capacity shortages and increase the availability of carbon-free energy at all times of day.
A Slow Pace of Hydrogen-Related Regulatory Action Thus Far
While California has a variety of laws, regulatory programs, and incentives related to hydrogen in the transportation sector, few regulatory decisions exist regarding hydrogen use in other sectors. Public Utilities Code section 400.3 requires the CPUC, California Air Resources Board, and California Energy Commission (CEC) to “consider green electrolytic hydrogen an eligible form of energy storage, and shall consider other potential uses of green electrolytic hydrogen.”
But so far, the only significant action taken by the CPUC to promote green hydrogen was the CPUC’s recent decision in the self-generation incentive program (SGIP) that identifies the types of renewable hydrogen that would be eligible for SGIP incentives when used for behind-the-meter electricity generation.
A Potentially Significant Move Forward
The CPUC Ruling proposes that to the extent the CPUC orders procurement of resources fueled by natural gas to ensure reliability in the mid-decade, some portion of that capacity be required to be met by “green” or “renewable” hydrogen. Specifically, the Ruling proposes the following for procurement of natural gas fueled resources:
- Require half of the fossil-fueled facilities to utilize at least 30 percent renewable hydrogen when the contract term begins, 60 percent renewable hydrogen by 2031, and transition to 100 percent renewable hydrogen by no later than 2036.
- Require facilities using renewable hydrogen to maintain or reduce the actual emission of nitrogen oxides (NOx) compared to the use of natural gas, and also to employ equipment to reduce NOx emissions, to the maximum extent possible.
- Procurement from a fuel cell could also be used to satisfy any fossil-fueled procurement requirement, using the same renewable hydrogen percentages and timeframes as described above.
The Ruling further proposes that eligible renewable hydrogen projects should be consistent with the requirements in the recent SGIP decision, which defines “eligible renewable hydrogen fuel” as:[H]ydrogen … that was produced through non-combustion thermal conversion of biomass, or electrolysis using 100 percent renewable electricity, as defined by the Renewables Portfolio Standard, with the addition of large hydropower and excluding purpose-grown crops; require, if the renewable electricity is not generated on-site, the purchase program or load serving entity to provide bundled Renewable Energy Credits to the electricity purchaser.
However, the Ruling proposes to modify the last phrase to account for the difference between using renewable hydrogen behind the meter for self-generation and in a utility-scale power plant for capacity procurement. Namely, the generating facility would have to provide documentation to the procuring load serving entity (LSE) that bundled renewable energy credits were retired for the electricity used to generate the renewable hydrogen.
The proposed definition does not allow use of “directed” renewable hydrogen (i.e., renewable hydrogen injected into the existing utility natural gas distribution system), because standards for doing so, along with a tracking process, are still under development.
The Ruling proposes that hydrogen production using non-combustion thermal conversion of biomass would be allowed as an eligible feedstock, so gasification and/or pyrolysis of woody biomass may produce the renewable hydrogen. However, hydrogen produced from steam-reformed biomethane would not be authorized, due to other higher priority direct uses for the limited supplies of biomethane for clean vehicle fuels and/or direct displacement of natural gas use in industry.
Stakeholders interested in participating in this CPUC rulemaking can move to become parties to the proceeding and may file comments on the Ruling by September 27, 2021.