CEC explains gas demand forecasting, AEE/AFS scenarios and gaps with CARB scoping plan

California Energy Commission staff outlined the CEC’s gas forecasting suite and the methods used to model additional achievable energy efficiency (AEE) and additional achievable fuel substitution (AFS) at a California Public Utilities Commission workshop, and explained why CEC scenarios show smaller early reductions in natural gas demand than the CARB 2022 Scoping Plan scenario.

CEC staff said the commission produces three principal gas products: the Integrated Energy Policy Report (IEPR) gas demand forecast (updated every two years and expressed in annual therms), longer‑term demand scenarios used to inform SB 100 and other planning, and a peak‑day gas forecast used for seasonal reliability assessments. The IEPR forecast is developed in coordination with the electricity forecast because fuel switching drives down gas and raises electric load.

Nicholas Janusch and Heidi Javanbakht described the IEPR’s additional achievable framework. CEC models AEE as incremental energy‑efficiency savings not in the baseline forecast and AFS as the incremental gas savings and electricity demand from fuel substitution (gas→electric). The commission’s Fuel Substitution Analysis Tool (FSAT) models zero‑emission space and water‑heating standards and other appliance impacts; those FSAT outputs are combined with programmatic AEE/AFS scenarios to produce IEPR modifiers.

CEC staff explained they produced multiple AFS scenarios for the 2023 IEPR ranging from conservative (programmatic actions only) to optimistic (wider deployments and regulatory actions). After stakeholder input and an observed gap between programmatic scenarios and scenarios that included zero‑emission appliance standards, CEC adopted an intermediate “gradual transformation” (GT AFS) scenario that assumes a slow, linear adoption reaching 100 percent by 2040 in modeled end‑uses.

When compared with CARB’s scoping plan scenario, CEC staff said the scoping plan assumes larger and earlier building electrification and thus projects larger near‑term reductions in natural gas use; CEC’s IEPR scenarios show smaller early reductions because they use different, more incremental assumptions about appliance turnover, program scale and regulatory timing. CEC staff emphasized that the IEPR and long‑term scenarios are intended to be usable inputs for resource planning and reliability work while further localized and rate‑level analyses are developed in coordination with CPUC and utilities.

On reliability, CEC staff noted the peak‑day forecast and seasonal reliability assessments consider pipeline maintenance, storage withdrawals and upstream interstate constraints. In response to stakeholder questions, CEC staff confirmed work is underway to model rate impacts: the CEC is analyzing a set of scenarios to estimate revenue requirement changes and rate outcomes and expected near‑term results after internal review.

Stakeholders asked about how CEC modeling treats technology choice and customer price sensitivity. CEC staff said adoption in the AFS standard scenarios is imposed top‑down rather than derived from granular price elasticity in the model; technology mixes for replacements are modeled as distributions of efficient to less efficient equipment for different building types to reflect real‑world variation.

CEC staff and CPUC commissioners discussed next steps for interagency coordination, the need for higher geographic and temporal resolution for gas planning, and the role of hydrogen and carbon‑removal assumptions in long‑term scenarios. CEC staff pointed to released model outputs and said the commission will continue to refine methods for use in integrated gas and electric planning.