House Bill H-3102.1 (House Bill 2642) amends RCW 70A.65.080 to clarify which persons are treated as covered entities under the state's cap-and-invest program, generally using a 25,000 metric ton CO2e threshold for facility owners/operators, electricity generators or importers, fossil fuel suppliers (other than natural gas), natural gas suppliers and users, waste-to-energy facilities, and railroad companies. The amendment adds an explicit exemption so emissions from the combustion, oxidation, other process, or end use of a lubricant (as defined in 40 C.F.R. Sec. 98.6 (2025)) are not covered by the program regardless of whether a supplier demonstrates the lubricant was combusted or oxidized. The law also includes timing and notification rules for entities whose reported emissions fall near or below threshold levels, special rules and time-limited provisions for farm fuel exemptions, a requirement that the department adopt, by rule and by October 1, 2026, a methodology for addressing imported electricity associated with a centralized electricity market (in consultation with any linked jurisdiction, the Department of Commerce, and the Utilities and Transportation Commission), and a prohibition on assigning multiple covered-entity compliance obligations to the same emissions while authorizing agreements among refineries, fuel suppliers, facilities using natural gas, and gas utilities to assume obligations (with at least 12 months’ advance notice to the department). The bill also changes procedural requirements for state environmental review under chapter 43.21C RCW: a lead agency conducting review must evaluate and attribute any potential net cumulative greenhouse gas emissions from a proposed project compared to existing facilities or best available technology, including best-in-class facilities and emerging lower‑carbon processes; the department may adopt rules setting the threshold for when that analysis applies. The provision says covered emissions from an entity that is or will be a covered entity may not be used as the basis to deny a permit for a new or expanded facility, but those covered emissions must be included in the required analysis. A lead agency or permitting agency must allow a new or expanded facility that is a covered or opt‑in entity to satisfy mitigation requirements for its covered emissions by submitting to the department compliance instruments equivalent to those emissions during a compliance period. The language also explicitly states that nothing in the subsection requires a permitting agency to approve a permit application. Important contextual information is missing from the provided text: the specific state department referenced is not identified in these excerpts; definitions for key terms used throughout (for example, “covered emissions,” “covered entity,” “opt-in entity,” “compliance instruments,” “compliance period,” “first jurisdictional deliverer,” and “first transfer deadline”) are not included here; subsection (c) that is referenced is not provided; and the excerpt ends mid-sentence in one place, so additional provisions or clarifications may exist elsewhere in the bill text.

If enacted, the law will reduce compliance obligations for anyone reporting emissions tied to the combustion or use of lubricants by explicitly exempting those emissions, and it keeps the existing 25,000 metric ton CO2e cutoff for determining covered entities so large facility owners, electricity generators/importers, fossil fuel and natural gas suppliers, refineries, waste-to-energy operators, and rail companies remain the primary parties affected. Fuel suppliers and farm fuel sellers get a temporary broader exemption for certain agricultural uses through the end of 2029 and a narrower motor-vehicle-only exemption after January 1, 2030, which likely lowers their near-term costs but may increase obligations and costs starting in 2030. The bill lets refineries, fuel suppliers, facilities using natural gas, and gas utilities arrange among themselves to shift who holds compliance obligations (with the department notified 12 months before the compliance period), which can change who pays or manages emissions compliance; the department must also adopt, by October 1, 2026, a methodology that may alter responsibilities for imported electricity tied to centralized markets. For permitting and new projects, lead agencies must evaluate a project’s net cumulative greenhouse gas emissions against existing or best-in-class lower-carbon alternatives, and permitting bodies must allow applicants to meet mitigation requirements by submitting compliance instruments equal to covered emissions, so project proponents will likely face added mitigation costs but have a clear option to satisfy those requirements rather than be automatically blocked; however, covered emissions cannot be used as a basis to deny a permit. Key implementation details are missing here—the specific department named, how compliance periods and allowance transfers work, and precise definitions of covered/opt-in entities and compliance instruments—so the exact timing, cost impacts, and administrative responsibilities for many parties remain uncertain.