A New Era for Microgrids
Universities and hospitals have long utilized on-site energy generation infrastructure to provide reliable, cost-effective power. Combined heat and power plants (CHP) serve as the cornerstone technology of these traditional systems, creating electricity from a fossil fuel-powered turbine and recovering the thermal energy to supply domestic hot water and space heating demands throughout the buildings. In the traditional model, district scale energy systems allow a campus to optimize operational energy cost savings year-round and power critical resources during a grid failure. The ability to operate in island mode without the utility is a core feature of a microgrid.
Over the last decade, a new approach to microgrids has emerged to serve private real estate developers. While reduced operating costs and island-able systems remain primary drivers for implementing microgrids, developers are now considering municipal and corporate greenhouse gas emissions reductions mandates. They are also considering a broader palette of technologies and ownership models to meet the needs of a diverse project size, phasing, and program mix. As solar PV and energy storage have proven to be reliable and cost effective in many markets across the US, they are often the cornerstone of modern district energy solutions because they can be controlled to operate economically in complex utility rate structures, provide resilient backup power, and reduce on-site GHG emissions.
It’s Happening in Boston
Boston is quickly emerging as an innovation center for microgrid implementation, due in large part to forward-thinking public policy. Over the last five years, the city of Boston has been investing in research and new policies to address the risk of climate change and aging infrastructure. One such initiative is the Boston Planning and Development Agency (BPDA) Smart Utilities Pilot Policy, which mandates that real estate developers complete a district energy and microgrid feasibility assessment for all masterplanning projects over 1.5M square feet of building area. The policy outlines requirements for development teams to study the technical, economic, regulatory, and environmental implications of deploying on-site energy generation that serves thermal and electrical power to multiple buildings.
BPDA implemented this policy in 2018 to harness the electrical power load reduction that district systems can bring to projects, reduce greenhouse gases, as well as promote resiliency for residents and businesses. Islanded microgrid systems can sustain lifesaving power to residents and commerce in the event of an extended utility outage. In light of its 2050 goal for carbon neutrality, Boston is the first city in the country to leverage their planning process to explore the public benefit of private investment in district energy.
Real estate developers in Boston are gaining fluency in the electrical power because they face more complex physical, environmental and regulatory obstacles to accessing utility power than ever before. The Smart Utilities Policy adds pressure on developers to incorporate on-site energy generation as part of their projects. There are considerable challenges in design thinking, the regulatory environment, and the market approach to this new form of microgrid deployment that will require novel ways of thinking to overcome.
Because the Smart Utilities Policy microgrid assessment is required in the concept design phase of projects, before the city has officially approved the development, the policy is pushing developers to beyond the scope of their typical design process. This, along with poorly defined prioritization of cost, environmental, and resiliency outcomes, creates new and significant risk for developers navigating this policy.
The policy is designed to get real estate developers to consider resilient backup power as project priority. However, defining the right level of resiliency is difficult when the market is not asking for it – developers in Boston do not see a mechanism to recover microgrid costs through lease rates or residential unit sale price. Furthermore, studying backup power using a range of technologies (CHP, solar, energy storage, fuel cells are called out specifically) requires more detailed building electrical and thermal load analysis than would typically be conducted in the concept stage of design. This costs developers more money upfront and embeds uncertainty in the microgrid feasibility assessment when aspects of the project are unknown, like phasing and the building program.
As it stands today, enforcement of the BPDA policy emphasizes conflicting outcomes without guidance on how to navigate them. For instance, given that today’s cost of natural gas is five times cheaper than electricity and produces half as much GHG per unit of energy, CHP appears to be the optimal solution for backup power on large projects. However, this approach is inconsistent with the City of Boston’s long-term goal for carbon neutrality and building electrification. There is no guidance on projected energy costs or grid emissions factors as the city gets closer to its 2050 goal, which makes it difficult to demonstrate the benefit of implementing of an all-electric approach like solar and batteries today.
The City of Boston faces major regulatory hurdles to adding distributed microgrid capacity behind the meter through private development projects. The most obstructive of all is the Massachusetts Department of Public Utilities (DPU) policy prohibiting submetering of electricity, which stems from a 1950’s court ruling designed to prevent landlords from re-selling electricity to tenants at a profit. Without the capability to submeter electricity users, district scale systems will not be economically viable because microgrid developers cannot accurately allocate and recuperate costs of delivering energy. The Smart Utilities Policy has enabled the BPDA to identify a pipeline of projects for which microgrids could provide economic, resiliency, and climate benefits to the city to make the case for a policy revision. However, the uncertain timeline for that outcome limits microgrid market expansion.
The utility business model for commercial customers as it stands today in Massachusetts also disincentivizes development of significant district energy resources behind the meter. For instance, CHP and energy storage systems designed into new construction projects to reduce peak electricity demand cannot be not accounted for in new electrical service applications. This represents a missed opportunity to capture the net load benefit of the new service with on-site energy generation because the owner cannot negotiate their tariff or mitigate cost of capacity improvements identified in the utility impact study.
Even as private developers become familiar with the technical challenges and opportunities of microgrids, they face difficulty in determining how to procure them. Plant ownership is a major consideration to developers as they study microgrid feasibility on large projects. Multi-year project phasing and uncertainty about long-term ownership of their assets makes it difficult for developers to justify the cost of a microgrid, especially in the concept stage when the Smart Utilities microgrid assessment takes place.
Third party ownership is an option, and energy service companies like Enwave, Engie, and Ameresco are stepping into the market in Boston to offer solutions to private developers. This is good for developers, because the major risk of owning the plant is losing revenue from plant failure. However, energy service companies will see limited market potential in developing electricity generating assets at the district scale in Massachusetts until state policy prohibiting retail energy sales to tenants is reversed.
A unique convergence of factors is setting the scene for a noteworthy energy market transformation Boston: the city is mandating microgrid and district energy assessments from private developers, energy costs are the highest in the country, and there is an incredible amount of large real estate development underway.
Because of the BPDA Smart Utilities Pilot Policy, Boston will serve as a proving ground for microgrid implementation at scale in an urban setting, testing whether the benefits of embedding district energy capacity into new real estate developments outweighs the burden of charting new waters in design, ownership, and policy.
These are the top priorities for reducing the aforementioned barriers to entry:
- The City of Boston should work with the development industry to standardize optional standby back up power targets for projects subject to the Smart Utilities Policy. This is one of the most crucial outcomes of the program, but there are no specific targets identified. Additionally, the BPDA needs to reconcile inconsistent direction related to adding natural gas capacity or building electrification.
- The Commonwealth should prioritize changes to the DPU policy so that the legal framework for electricity retailing supports shared microgrid infrastructure across multiple buildings. Massachusetts can look to the recent development of community microgrids by the Clean Coalition in Long Island, NY and Montecito, CA that focuses on the connection of multiple customers to shared energy resources.
- Energy service companies should standardize contract language for the Commonwealth as local laws change in favor of microgrid development. This will reduce the time and expense to developers, who need to make energy investment decisions early in the development process.
If utilities, developers, and regulators can come together to address these challenges, Boston is capable of unprecedented innovation in microgrid implementation that serves the complex goals of all three groups. This cross-sectoral collaboration is crucial to delivering privately funded microgrids in developments across the city, building electrical capacity in a strained grid, increasing backup power capability, and driving Boston towards carbon neutrality.
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