Microgrid Regulation Challenges and Opportunities
Vicious storms and destructive wildfires are becoming increasingly frequent and leaving people without electricity to power their homes. Microgrids, independent energy grids that pair local clean energy generation with storage, are a ground-breaking option for shoring up the resilience and efficiency of our aging national grid. However, their commercialization will not be successful until we have regulations that give people the certainty and structure necessary to develop projects.
States have been struggling with figuring out exactly how to regulate microgrids, and with good reason. Microgrids contain multiple technologies and often have complex ownership structures. Currently, California and Hawaii are the only states that have approved preliminary microgrid tariffs. But what should a successful tariff even look like? Here are two main goals to consider:
- Streamline development and interconnection processes. Some microgrids only operate in “island mode” and are wholly independent of the grid. Most can operate in “grid-connected mode” where they sell excess generation or buy electricity when needed. This requires interconnection to the grid which is currently prohibitively cumbersome, expensive, and opaque.
- Fairly compensate entities operating microgrids. Many of the ancillary benefits microgrids provide, including energy resilience, deferral of grid upgrades, and demand-side management, are difficult to quantify yet valuable. Also, microgrid operators must receive fair prices for excess electricity sold back to the grid.
Tariffs can vary which sections of a microgrid lifecycle are in their scope. Some, such as PG&E’s Community Microgrid Enablement Program in California cover the whole lifecycle, whereas others, such as Hawaiian Electric’s Microgrid Services tariff, focus on development.
On the development side, there are debates over the degree of control utilities should have. An illuminating case is California’s “over-the-fence rule”, which prohibits non-utility developers from building microgrids serving commercial buildings on neighboring properties. In January 2021, the California Public Utilities Commission cautiously decided that developers would need to contract with utilities if they wished to serve multiple customers. Utilities argue that this rule ensures safe, reliable electric services, while non-utility stakeholders contend it is an undue burden, and regulatory capture is influencing decision making. States will need to decide how much they trust private enterprises to build this infrastructure, effectively influencing how quickly microgrids can permeate the market.
Determining how microgrids should be compensated for electricity sold to the grid is similarly thorny. With net-metering policies, electricity meters could essentially run backwards when the customer is providing electricity. Feed-in tariffs are a more sophisticated, but harder to implement, alternative. They track consumption and generation separately, leading to greater rates of return for customers. Dynamic electricity pricing varies prices depending on supply and demand, allowing for efficient energy trading markets and eliminating the need for centralized dispatch systems.
We can hypothesize all we want about the best incentives to promote microgrid growth, but ultimately can only really learn by modelling and doing. Digital twin modelling and pilot projects trialing these ideas would allow regulators to gain valuable insights, which could then be used to shape policies nationwide.
This insight is a part of our Undergraduate Seminar Fellows’ Student Blog Series. Learn more about the Undergraduate Climate and Energy Seminar.