The Emerging Relationship between Distributed Energy Resources and the Transmission System.
Allison Clements | NRDC
Part 1 of this series can be found here.
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wind and solar power long distances and that we don’t build too much infrastructure or unnecessarily lock-in an outdated and often uneconomic coal fleet.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.
What would a non-wires, DER solution to a transmission system need look like? Assume a hypothetical localized reliability issue on the transmission grid due to the retirement of a low-use coal plant. Through the regional planning process, the RTO decides the best option is a substation upgrade and one or more additional short transmission lines to increase connectivity in the area. As an alternative to this transmission-centric approach, it may be possible for one or more non-wires solutions, like a combination of geographically-targeted energy efficiency, demand response (compensating customers for altering energy use at specific periods, and some rooftop solar generation), and some rooftop solar, to eliminate or defer the need of at least the substation upgrade, or maybe both the upgrade and the new lines, at much lower cost than would have been spent on the transmission.
Technical issues make the use of DERs to address transmission grid needs inappropriate or impossible in some cases. For example, while DERs can address more localized congestion or reliability issues, they cannot replace the need for the high-voltage transmission lines necessary to transport large amounts of utility-scale wind and solar power from where it is produced to where it is needed. However, in some cases the reliability gap or need from a retiring plant is small, and centered on a few peak demand days during the year.
In these cases when DER integration is an appropriate alternative, incorporating DERs in the transmission planning context is difficult since DERs interconnect to the local distribution system, while the needs that regional transmission system planners are trying to address exist on the higher voltage transmission system. A lack of coordination in planning cycles between regional transmission planning and state-level resource planning make identifying and engaging in actual DER solutions to transmission system needs difficult. If transmission planning process identifies grid needs that might be more cheaply addressed in whole or part by DER options, there isn’t necessarily or even likely a parallel process happening at the state utility commission level that might develop and feed DER options into the regional process. An additional impact of separately planned and operated systems is a lack of operational awareness and coordination between transmission grid operators and those operating the distribution system where DERs are located. Awareness and coordination issues can be overcome, but their existence may deter otherwise willing DER providers.
On the legal front, there are at least three issues.
- First, FERC interprets the Federal Power Act to require that grid planners consider non-wires alternatives to transmission investment only when interested parties propose them, not proactively. Since regional planners are uniquely equipped with specific information about the region’s grid needs, FERC’s interpretation represents a significant missed opportunity.
- Second, the Federal Power Act provides for the sharing of costs of new interstate transmission development across customers who benefit from the development, but it doesn’t similarly provide for the sharing of costs of non-wires alternatives. So, if the costs of a transmission solution to an identified reliability need can be shared across several states, individual states otherwise conceptually supportive of non-wires options are not interested in their customers taking on the entire cost for a DER solution for which other states’ customers would benefit.
- Third, in what appears to be an effort to protect utilities, several states and municipalities have banned third-party “aggregators” necessary to bundle a significant enough volume of DERs (for example, an entire neighborhood of rooftop solar or a dozen factories willing to provide collective demand response by curtailing their electricity use when needed) to address transmission system needs in lieu of transmission investment.
In addition to the legal issues, institutional barriers arise. Most state regulators are not focused on the potential contributions their utilities and customers can make to addressing regional needs more cost-effectively than traditional transmission fixes. This is often due to resource constraints that make participation in regional planning efforts difficult. Further, in many cases transmission planners are accustomed to addressing transmission system needs with transmission solutions and are reticent to consider DERs. We hope this concern evolves as DERs continue to rack up robust demonstrations of reliability. Transmission-owning utilities that stand to rake in guaranteed rate of return on transmission investments also yield significant influence in regional planning processes.
What policy changes are needed?
Success in achieving any material level of DER integration into transmission system planning will not be easy. However, the potential benefits—big customer savings, avoiding ecological impacts and contributions to clean air and the fight against climate change, to name a few—make it worth the effort. In order to remove barriers to the use of non-wires alternatives:
1. FERC should strengthen Order 1000 regional and interregional processes to require planning (not just consideration) of public policies that both increase and decrease the need for system infrastructure.
2. FERC should require true comparability for non-wires alternatives to transmission in the planning process by requiring system planners to proactively consider DERs as solutions, even when stakeholders do not propose them.
3. Regional transmission planners, states, and utilities should engage directly to address incompatibilities between state resource planning timelines and regional transmission system planning, as well as operational and awareness coordination, so that states and utilities are in a position to bring forward non-wires. Engagement could be facilitated by the U.S. Department of Energy as part of its grid modernization effort, through a FERC collaborative with the National Association of Regulatory Utility Commissioners and the North American Electric Reliability Corporation or by other means.
4. Congress should amend the Federal Power Act to encourage states to develop compacts or agreements to share the costs of non-wires alternatives, and if agreement can’t be reached, empower FERC-jurisdictional regions to allocate the costs of non-wires alternatives across regions.
Consideration of these policies should take place as part of a bigger-picture policy framework that recognizes a clean energy future will require development of new transmission. We will not achieve the magnitude of carbon and other pollution reduction we need without a combination of clean DERs and high-voltage transmission necessary to transport large-scale solar and wind power. The goals of realizing both sufficient transmission and the opportunities provided by DERs as non-wires solutions (saving customers’ money, providing new business opportunities to DERs and avoiding unnecessary ecological impacts) are wholly compatible.
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