Christopher Hailstone brings a wealth of experience to the table when discussing the modernization of our power infrastructure. Having navigated the complexities of electricity delivery and grid security for years, he provides a crucial perspective on the evolving energy landscape in New England. As the region moves toward a future defined by the electrification of heating and transportation, Christopher helps us unpack the latest energy forecasts, exploring how shifting policies and a move toward dual-peaking demand will reshape how we generate and consume power. This conversation touches on the reversal of a twenty-year efficiency trend, the impact of legislative changes on electric vehicle adoption, and the vital role of behind-the-meter solar in maintaining a stable grid through 2035.
New England’s energy use has trended downward for decades due to efficiency, yet this trend is now reversing. How will the grid transition from managing efficiency gains to handling growth, and what operational challenges does this reversal create for utility providers?
The reversal of a trend that has held steady since 2005 is a massive operational shift that requires us to rethink the very architecture of the grid. For nearly twenty years, we relied on more efficient appliances and lighting to keep demand in check, but we are now entering an era where annual consumption is expected to climb from 116,679 GWh to 127,660 GWh by 2035. This 0.9% annual increase may sound modest, but it represents a fundamental change for utilities that have spent decades optimizing for a shrinking or stagnant load. The primary challenge lies in the physical infrastructure; we are transitioning from a system that simply maintains status quo to one that must actively expand to support the aggressive electrification of buildings and transportation. It is a high-stakes balancing act where we must integrate new capacity while ensuring that the distribution networks don’t become bottlenecked by the sudden surge in demand.
Forecasts for electricity growth have been scaled back to roughly 9% over the next decade due to shifting federal and state incentives. How do these policy fluctuations impact long-term infrastructure planning, and what metrics determine if these more conservative estimates are accurate?
Policy fluctuations act like a moving target for long-term planners, making it incredibly difficult to commit to multi-billion dollar infrastructure projects with absolute certainty. Just a couple of years ago, we were anticipating a 17% rise in energy use, which was then dialed back to 11%, and now sits at a more conservative 9% rise over the next decade. These adjustments are a direct response to the removal of federal incentives and changes in state-level expectations for different vehicle classes and heating systems. To determine if these conservative estimates are hitting the mark, we look closely at the actual pace of heat pump installations and the sales data for electric vehicles against the projected 127,660 GWh annual load. If the adoption of these technologies slows down more than expected due to expiring tax credits, we have to be ready to pivot our investment strategies so we don’t overbuild or, conversely, leave the grid underprepared.
Regional demand is shifting toward a dual-peaking system where winter peaks may soon match summer levels at 26.5 GW. What specific reliability risks emerge during this transition, and how must grid maintenance schedules adapt to accommodate two high-demand seasons instead of one?
The shift toward a dual-peaking system is perhaps the most significant reliability challenge we face, as it effectively eliminates the “off-season” traditionally used for major maintenance. Historically, we saw a massive gap between the summer peak—projected at 25.2 GW this year—and a much lower winter peak of 20.5 GW, but by 2035, both are expected to converge at approximately 26.5 GW. When both seasons demand near-maximum capacity, the window for taking plants offline for essential repairs or upgrades narrows dangerously. We risk a scenario where a cold snap in January puts as much stress on the system as a heatwave in July, leaving very little margin for error if a primary generator or transmission line fails. This requires a much more granular approach to maintenance scheduling, utilizing predictive analytics to ensure that every minute of “shoulder” season is used with surgical precision to keep the hardware ready for these twin peaks.
Projections for EV and heat pump contributions to peak load have been adjusted following the removal of certain tax credits. What step-by-step strategies can be used to maintain adoption momentum without these incentives, and how does this change the expected load profile for the 2035 winter season?
Maintaining momentum without the cushion of federal tax credits requires a transition toward more localized, utility-driven incentives and creative financing models that lower the entry barrier for consumers. We are looking at a future where heating electrification is projected to contribute a substantial 5,533 MW to the winter peak, while transportation adds another 1,509 MW, despite the recent downward revisions. To manage this load profile, we need to implement aggressive demand-response programs that encourage users to charge vehicles or run heat pumps during off-peak hours to flatten those 2035 spikes. By refining our forecasts—which previously saw EVs accounting for 1,764 MW—we can better prepare the grid for the actual 1,509 MW we now expect, ensuring that the infrastructure is sized correctly for the reality of the market. It’s about building a partnership with the consumer where “smart” technology manages the load automatically, preserving the grid’s integrity even as the financial landscape for these technologies shifts.
Behind-the-meter solar is expected to reduce winter peak demand by over 300 MW by 2035. How does the integration of distributed solar impact the broader stability of the grid, and what technical upgrades are necessary to ensure this capacity effectively offsets peak heating loads?
Integrating behind-the-meter solar is a double-edged sword; it provides a vital reduction of 316 MW during the winter peak, but it also introduces a level of variability that the grid wasn’t originally designed to handle. To make this 316 MW offset truly effective, especially during the 2035/2036 season, we need technical upgrades that focus on “grid-edge” visibility—essentially better sensors and software that allow operators to see what is happening at the household level in real-time. Without these upgrades, the surge of solar power on a bright, cold day can create backflows that strain local transformers, potentially leading to instability. We are moving toward a more decentralized model where the grid must be flexible enough to absorb this distributed energy while still providing a rock-solid backup when the sun goes down and the heating load remains high. It is about transforming the grid into a two-way street that can handle the complex dance between solar generation and peak heating demand.
What is your forecast for New England’s energy grid?
My forecast for the New England grid is one of a “complex convergence,” where the traditional boundaries between seasons and energy sources will continue to blur. We will see the region successfully navigate the 9% growth in consumption, but the real story will be our ability to manage the 26.5 GW dual-peak reality through massive investments in digital grid management and storage. While policy changes might cause short-term fluctuations in EV and heat pump adoption, the long-term trajectory toward electrification is irreversible. I expect that by 2035, the grid will be significantly more resilient and “smarter,” relying on a sophisticated mix of behind-the-meter resources and robust transmission upgrades to maintain stability in a much more demanding environment.
