The concept of NWS as a vehicle for distributed energy resources (DER) sourcing gained traction across the U.S. electric sector over the past five to 10 years, spurred by technology advancements as well as state and ISO/RTO-level policies that require consideration of NWS within the distribution and transmission planning processes.
Projects like Con Edison’s Brooklyn Queens Demand Management Program captured the industry’s imagination early on. Since then we’ve seen other successful examples such as Southern California Edison's virtual power plant, a load reduction project by Consumers Energy in Michigan, a reliability solution by Eversource Energy in New Hampshire, and a distribution deferral project by Arizona Public Service. However, despite the real success that these projects represent, the pace of NWS implementation remains low, challenges persist, and project failure rates remain stubbornly high.
The number of NWS projects moving to implementation has fallen short of expectations as the reality of solution requirements and the challenges of design, procurement, and implementation were discovered. However, we continue to see advances in methods for quantifying the value of distributed energy resources (DER), defining case studies to meet specific applications, as well as implementing frameworks to enable NWS implementation in states like Colorado and Oregon. Although it’s clear that non-wires solutions are not a silver bullet for broader deployment of DER, they are essential in that they connect the dots between DER performance and system planning criteria. To see how we forge a path forward, it is helpful to take a close look at the challenges of implementing NWS projects across the stages of project development and implementation (Table 1).
Identifying NWS opportunities
The first step in any NWS process is to forecast the future reliability needs of the transmission or distribution system, identify any necessary grid upgrades, and evaluate where an NWS could be a viable candidate to meet system needs in place of traditional grid investments. In the context of California’s Distribution Investment Deferral Framework (DIDF) process (Figure 1), NWS viability depends on the ability to cost-effectively procure DER within the timeframe to meet the need. For example, PG&E found that in their 2021 DIDF cycle, this timing criteria reduced the number of potential NWS projects by over 80% from 254 to 45.
Load and DER forecast uncertainty can also narrow the scope of opportunities for NWS projects. Load forecasts are a critical driver of future grid needs, and low levels of certainty about future load or changes to load forecasts during the development process can obviate the need or require major adjustments to project scope. In the 2021 DIDF cycle, PG&E scored each of the remaining 45 candidate deferral projects according to forecast certainty of the reliability need; high forecast certainty increased the likelihood of that project receiving a Tier 1 designation and moving forward.
A NWS that looks promising in one planning cycle may no longer be prudent as forecast horizons shorten and more accurate information becomes available. We can look to the Oakland Clean Energy Initiative (OCEI) as an example of such a moving target. Originally defined in the 2017-2018 cycle of the California Independent System Operator’s (CAISO) Transmission Planning Process (TPP), subsequent load forecasts required significant increase to the energy and capacity needs between the 2018-2019 and 2019-2020 planning cycles for the area as a whole, as well as for the Oakland L substation pocket in particular (Table 2). CAISO’s viewpoint also evolved on resource type eligibility, both in terms of technology class (e.g., storage) as well as allowable services (e.g., dedicated transmission asset vs. market participating resource).
Options to address this complexity could include probabilistic forecasting of load and DER that considers both customer propensity as well the interactions between customer load and DER output. By leveraging data analytics and advanced planning methods, utilities can produce a greater understanding of system needs across a range of plausible scenarios to provide a clearer view of investment needs and NWS opportunities in the face of expanding uncertainty.
Following the identification of a reliability need suitable for NWS, the utility must seek cost-effective solutions. The structure of the procurement and the scope of viable options can vary by state and utility. For example, in New York, the utilities announced NWS opportunities that meet suitability criteria designed to promote project success. But with a well-designed process and a clearly laid out need, projects must still meet requirements designed for a traditional grid solution with multiple points at which NWS projects can fail due to factors such as technical feasibility, contractual terms, and cost-effectiveness.
Firstly, in a procurement context, the utility needs to receive at least one offer that meets the identified reliability need and is technically feasible (e.g., a solar-only project is not going to meet a nighttime grid need, and an energy storage system can only meet the need if it has sufficient opportunity to recharge). The locational nature of NWS also makes it more challenging than traditional energy or capacity procurement, which can source resources from anywhere in the utility’s service territory. An NWS location is much more granular (e.g., downstream of a specific transmission or distribution substation), which constrains the available land, interconnection capacity, and participants for a customer-sited solution.
Meeting the technical system functions of a traditional solution can imply a significantly high bar for resource performance. Requiring a portfolio of DER to defer the need for a traditional investment like a distribution transformer sets a challenging performance standard for that aggregated resource if there is uncertainty as to whether the resource will materialize and meet the performance requirements despite the possibility of dispatch fatigue or other failure modes. But by benchmarking DER performance against system requirements, NWS projects provide valuable data on DER system value and connect the dots between DER performance characteristics and distribution system planning criteria (Figure 2).
Procurement of DER to defer the need for a traditional investment is one way to implement an NWS, but it is not the only option. An alternative approach can leverage market signals rather than contracted arrangements. For example, the Independent Electricity System Operator in Ontario proposed a TSO-DSO energy market coordination process for operating DER as a non-wires solution to address distribution system needs as part of their York Region Demonstration Project. This approach would extend price formation to the distribution system by producing distribution locational marginal prices that reflect the cost of marginal losses and distribution system constraints. This approach does not rely on procurement mechanisms to ensure that a resource meets a specific planning need. However, it does introduce a market-based approach with other technical requirements.
Secondly, for the NWS to come to fruition, the vendor must be willing to accept the terms of the utility contract, including any penalties for delays or non-performance. These terms reflect the importance of meeting contractual performance criteria and ensuring operation ahead of the projected need date to maintain system reliability. However, DER providers—particularly those more accustomed to behind-the-meter customer program implementation—might not wish to take on the financial risk associated with such terms. If a vendor can secure revenue for their product offering through less risky utility/market services, they could pass on the NWS opportunity, further narrowing the field of potential solutions for the utility to consider.
Finally, the NWS needs to be more cost-effective than the traditional grid solution. The goal of an NWS is to provide customers with grid reliability at a lower cost than they would otherwise pay. This requires comparing the costs for the traditional solution to the costs of the NWS and clearly demonstrating cost savings. This can include additional benefit streams such as avoided energy and local air quality improvements.
The success of an NWS relies on the ability of a DER provider, or the utility themselves, to package a solution that will meet all those criteria while costing less than the traditional grid solution. An apples-to-apples comparison can be complex depending on what product(s) the utility is sourcing from the NWS provider, when the NWS is coming online vs. the traditional solution and the nature of the grid need(s), and to what extent the NWS is fully replacing vs. deferring the traditional solution until a future date.
Where relatively inexpensive traditional solutions exist, it will be difficult for NWS to compete financially, even with a value-stacking approach. For example, PG&E sought offers for a deferral project at their Blackwell Bank 1 and did not receive any offers that were less than the deferral value cost cap. The allocation of costs relative to the traditional solution can also be relevant. For example, the utility cost recovery mechanisms for a substation transformer are likely different than for a market-participating third-party energy storage system, and that difference in cost allocation amongst customer classes can create hurdles for regulatory approval.
Review and approval by a decision-making body, whether a state-level public utility commission (PUC) or an RTO/ISO, is a critical step in deploying utility NWS. NWS proposals are subject to scrutiny in the context of regulatory approval processes at the PUC or RTO/ISO as public stakeholders, grid planners, and regulators evaluate their costs and benefits. These decision-making entities can have different priorities and approaches for evaluating the feasibility and reasonableness of a proposed project. Approvals across multiple jurisdictions may be necessary, depending on what investment the solution is replacing, and the type of solution proposed. Furthermore, each jurisdictional entity has access to certain pieces of information but cannot necessarily see the “full picture” based on their specific regulatory authority and the limited coordination frameworks that are currently in place.
In California, for example, the California Public Utilities Commission (CPUC) approves distribution-level NWS both at the opportunity identification stage and the procurement stage through the DIDF process. For transmission-level NWS, the CAISO evaluates NWS proposals alongside traditional reliability solutions and selects which projects should move forward to meet identified grid needs through their transmission planning process. Value stacking—providing multiple energy/grid services from the same project—is a good strategy to communicate complex costs and benefits that may not fit into traditional regulatory frameworks. Value stacking attempts to maximize revenue streams and improve NWS project economics. While value stacking can improve project viability, it can create an incredibly complex web of local, state, and federal jurisdictional authority entities must navigate to obtain project approval. In the case of OCEI, the services served by the proposed energy storage projects included the provision of local transmission reliability to the ISO (overseen by the CAISO Board and FERC), “reliability services” to the utility (overseen by the CPUC), and Resource Adequacy to a local Community Choice Aggregator (overseen by their board of directors).
These decision-making entities can have different priorities and approaches for evaluating the feasibility and reasonableness of a proposed project. For one, ISOs/RTOs plan the transmission system to avoid constraints in a range of uncertain future conditions, which means ensuring there is enough capacity that energy can flow unrestricted from the least-cost resources to the relevant load pocket. Under this paradigm, operating a transmission asset below its full capacity is normal, and part of prudently running a reliable grid. By contrast, state regulatory agencies tend to use a “right-sizing” paradigm when evaluating utility energy procurement to prevent customers from paying unnecessary costs that require the proposed NWS project to match exactly with the expected energy and/or capacity need. Thus, an investment that a grid planner may regard as a reasonable buffer to manage risk around uncertainty could face approval risks if the relevant regulatory entity views that excess capacity as unnecessary spending.
Regulatory requirements and coordination can be a hurdle when regulators and stakeholders evaluate the appropriateness of an NWS. In the case of OCEI, for example, neither the CPUC, the CAISO, nor the utility were privy to the resource adequacy contract terms (including price) that the Community Choice Aggregator and OCEI NWS providers agreed to, which stakeholders saw as a critical missing data point. Also notable is that a transmission-level reliability need identified by CAISO drove the need for OCEI. So unlike utility procurement driven by Integrated Resource Planning or the Renewable Energy Portfolio Standard, for example, the CPUC does not own or approve the modeling tool used to define the need for OCEI. Getting state regulators and stakeholders comfortable with the transmission planning process and underlying assumptions is a challenge but is necessary to make a successful case for approving this type of NWS.
Like any other new build energy project, an NWS must navigate the practical challenges of permitting, interconnection, equipment procurement, and construction. For a customer-sited solution, customer acquisition is an additional implementation requirement. Project sponsors should plan and budget for these elements in the initial stages of the NWS project design, but unforeseen delays and cost overruns can occur for a variety of reasons. While timeline delays and increased costs are undesirable for any project, they can represent significantly more risk for an NWS that has specific required online date and price cap that it must achieve to be more cost-effective than the next best solution. In addition, a modest delay in the online date for the project could mean the NWS will not be operating in time to meet the identified reliability need. The utility may decide that the delayed NWS is no longer viable and deploy the wires solution instead to maintain system reliability.
The path forward
As we look at the number of failed projects that never came to fruition and the scope of challenges that utilities must overcome to successfully implement an NWS, one might conclude that the complexities are simply too great, and that this is destined to remain a niche solution space. While the scale of NWS potential may not fulfill the hopes of industry proponents, there’s plenty of opportunity if utilities, along with state regulators and ISOs/RTOs, can address these complexities in a systematic way by better aligning procurement and transmission planning processes, exploring new procurement paths, and taking advantage of innovative approaches to load forecasting and propensity modeling. For example, the CA IOUs are piloting two novel approaches to procuring DER to avoid or defer distribution investments— a 5-year tariff pilot and a Standard Offer Contract to decrease the transactional costs and risks present in the current RFO process.
But it’s also important to remember that while NWS provide an important means to directly capture the distribution system value of distributed resources, they should be viewed in the context of a broad portfolio of options that also include customer DER programs, new aggregator paradigms, retail tariff designs, managed charging approaches, and DER participation in wholesale markets. This kind of broad portfolio can better capture the value that distributed resources provide to the system, the value the system provides to DER, and help identify the kinds of technologies and solutions that will form the backbone of tomorrow’s power grid.