Small Power, Big Grid: Part 2
The Emerging Relationship between Distributed Energy Resources and the Transmission System
DERs AND REGIONAL LOAD FORECASTING: Getting Full Bang for Our Bucks
This blog is the second in a series on the relationship between distributed energy resources or “DERs” (energy efficiency, demand response, rooftop solar, electric vehicles and other storage and other customer-driven resources) and the transmission system.
To ensure reliable and affordable service to America’s homes and businesses, regional transmission system operators try to predict how much electricity customers will need by as much as a decade into the future. The goal is to ensure there is a sufficient supply of energy to meet predicted demand and enough transmission infrastructure to deliver that supply. In recent years, the rapid increase in consumers reducing their energy waste via energy efficiency and installation of rooftop solar panels generating power locally is having a significant impact on these regional load forecasting process—but not all of the system operators and load forecasting processes they follow are adequately reflecting this DER rise (some regions, like the Northeast, California and the Mid-Atlantic, have already started to make progress in this area). A huge opportunity exists to capture DERs in regional load forecasting across the country and lower overall demand—and, as a result, enhance DERs’ value stream, buffer customers’ wallets and support the fight against climate change.
The Mid-Atlantic grid operator PJM, for example, recently lowered its regional load forecast by thousands of megawatts (MWs) after modifying its forecasting methodology to account for customers’ energy efficiency in the 13-state region. Our calculations, based on an estimate by the research firm UBS, show that the new forecast—which is more than 5,000 megawatts lower in 2019 than before the modifications (the rough equivalent of 7-10 mid-sized coal plants)—could reduce the cost of ensuring future electricity supply in the region by more than $2 billion.* Lower future electricity supply costs (known as “capacity costs”) will ultimately flow through to customers’ electricity bills because the predominant customers in PJM’s wholesale capacity auctions—utilities—pass these costs (and savings) onto their customers. Capacity savings are on top of the utility bill savings customers already realize by reducing their electricity use through efficiency (the cheapest supply resource by a significant margin), and the indirect savings that follow because lower consumption avoids the need for new grid infrastructure investment.
What is regional load forecasting?
Based on their predicted energy demand forecast, regions attempt to understand how much transmission infrastructure (and related wholesale energy generation) will be required as far as 10 years into the future. Regional load forecasts look so far ahead because it takes several years to develop and construct new transmission lines if they will be needed to maintain a reliable system.
In the regions of the country with interconnected electric grids operated by regional transmission organizations known as Regional Transmission Operators (RTOs) or Independent System Operators (ISOs), the RTOs and ISOs engage in load forecasting on behalf of all the utilities in their region. Some regions take a top-down approach, in which the RTO or ISO leads the forecasting process. In other regions, the RTO or ISO simply combines the separate load forecasts of each of its member utilities. Thanks to a 2011 Federal Energy Regulatory Commission (FERC) rule known as Order 1000, neighboring utilities in regions without RTOs or ISOs also engage in regional load forecasting, generally using the simpler combining approach. Whatever method is used, the point is to predict how much energy the homes, businesses and industries in the region will use, year over year, for the next decade.
