Small Power, Big Grid: Part 3
he Emerging Relationship Between Distributed Energy Resources and the Transmission System
DERs AND TRANSMISSION SYSTEM PLANNING: Dreaming the (Not-So) Impossible Dream
This blog is the third 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.
Electric transmission system planning, which is necessary to ensure grid reliability at fair costs to customers, is also essential to ensuring that sufficient transmission gets built to transport wind and solar power long distances and that we don’t build too much infrastructure or unnecessarily lock-in an outdated and often uneconomic coal fleet. That’s why it’s important to identify—and, to the extent technically and legally possible, remove—existing barriers to incorporation of DERs like energy efficiency and local solar generation into the system planning process. The need for better incorporation of DERs holds true not only at the load forecasting stage but also in the consideration of solutions to identified transmission grid reliability and economic needs.
First, how does regional transmission system planning work?
Through the Federal Energy Regulatory Commission (FERC), the federal government regulates the interstate transmission system while states are in charge of their intrastate distribution systems. Think about the transmission system as the high voltage backbone of our electric grid.
High-voltage transmission lines connect to utility substations, at which point the power flow is stepped down in voltage and then (under the regulation of states) pushed out across distribution lines into our homes and businesses. Under federal law and regulation, entities that own transmission infrastructure that cross state lines, known as transmission-owning utilities, may be separate from, affiliated with, or part of the same company as distribution utilities that supply power to consumers. For example, BG&E and ComEd are utility members of the broader Exelon family; both own transmission and distribution and are therefore regulated by both FERC and their states. ITC, differently (which operates in Michigan and other Midwestern states), is independent from any distribution-level affiliates but is regulated by FERC as a transmission-owning utility. FERC requires all transmission-owning utilities subject to its jurisdiction (which excludes cooperatives and municipalities) to do planning within their own footprints, as well as at the regional level (thanks to a 2011 FERC rule known as Order 1000). Regions are also required to “coordinate” but not engage in full-fledged planning with their neighboring regions.
Regional transmission system planning is not dissimilar from the resource planning that takes place at the state level. At a high level, it involves a two-part process: identifying transmission system needs—future reliability or congestion issues, or public-policy driven needs, and then developing solutions to meet those needs. Grid planners take into account many different factors affecting the grid’s current and future operation to identify these needs, including predicted customer demand, existing, planned and retiring power plants, and environmental and clean energy standards. Based on these and other factors, transmission owners and grid planners determine whether they need to upgrade existing, and/or build new power lines.
Most regions plan on an annual or biannual basis resulting in plans that look ten years forward. Since the transmission-owning utilities remain subject to state jurisdiction when it comes to getting certificates of need and siting permits for new transmission lines that cross through their borders, the regional plan is not as much a mandate to build as it is a playbook for the utilities and competitive transmission developers to follow. It is difficult, however, to imagine that new transmission projects or significant infrastructure upgrades will be built without first being included in one of these regional plans.
How do DERs play into regional system planning (or not)?
Once transmission system planners have gone through step one of the planning process – identifying future grid needs – they move on to looking for cost-effective solutions. Although technically DERs—which are non-transmission wire ways to provide transmission grid reliability, ease grid congestion or otherwise ensure transmission service—can provide solutions to some reliability or congestion-driven grid needs in lieu of new transmission development, almost no DERs have been proposed as potential solutions (a few notable exceptions in Maine and other locations mentioned here). The Brooklyn-Queens demand management project is a model non-wires alternative on the distribution system that involves planned spending of $200 million on a combination of fuel cells, energy efficiency, and local solar generation in lieu of spending $1.2 billion on a new substation on the distribution system – similar scales of savings are likely possible on the transmission system.