New England's energy system is constrained in ways that make routine grid management genuinely difficult: limited transmission capacity, restricted natural gas pipeline throughput, and accelerating electrification of heating loads that push winter peaks into unfamiliar territory. Into that situation, researchers from Simon Fraser University and Stanford University introduced a detailed model of multi-sector demand response and asked a practical question: how much can it actually help, and under what conditions?
The study, published May 8, 2026 in PLOS Climate, applied the open-source PyPSA-USA energy planning model to both New England and California, running 156 scenarios across different demand response cost levels, pricing strategies, and natural gas price assumptions. The results are not uniformly optimistic, but they are specific in ways that matter to facilities managers and energy procurement teams operating in regions where grid headroom is shrinking.
Thermal Demand Response Reduces Heating Capacity Requirements in New England by More Than 80%
The most striking finding involves thermal demand response, specifically the ability of commercial and residential facilities to pre-heat or pre-cool in advance of grid stress events rather than drawing power during peak hours. In New England scenarios, thermal demand response reduced total heat pump capacity requirements by more than 80% in several modeling runs, while still meeting the same annual heating load. This is not a marginal efficiency gain. It reflects the degree to which load-shifting flexibility in the heating sector can substitute for expensive physical infrastructure. The researchers note that even with conservative participation assumptions, the capacity reductions remain significant.
Cost Savings Reach Up to 40% in Constrained Grids at Low DR Participation Rates
For procurement and finance teams tracking energy cost exposure, the sensitivity analysis is the most useful part of the study. System cost savings in New England scenarios peaked near 40% under favorable conditions, but the researchers note that significant savings appeared well before full program adoption. Participation rates below 20% were enough to capture the largest marginal gains, because demand response targets the most expensive peak events first. Beyond that threshold, savings continue but the marginal return per additional participant flattens. The implication is that organizations do not need to overhaul their energy management programs entirely to see real cost impact. Early, targeted participation in the right load categories delivers most of the available benefit.
Carrier-Specific DR Pricing Consistently Outperforms Blanket Rate Structures
The study compared two approaches to pricing demand response: a uniform rate applied across all energy types versus rates set separately for electricity, space heating, and space cooling based on each carrier's marginal cost. The carrier-specific approach reduced system costs more effectively in nearly every scenario. The reason is structural. Electricity is significantly more expensive than thermal energy, so applying an electricity-weighted blended rate to thermal loads effectively overprices those loads and leads system planners to build additional capacity rather than shift demand. Utilities and large energy buyers designing demand response contracts may want to review whether their current rate structures are capturing the full flexibility value of thermal loads or inadvertently pricing that flexibility out of reach.
