The electrical grid is undeniably essential to our society and economy. The electric transmission and distribution (T&D) network moves energy from multiple sources of generation to homes, businesses, hospitals, universities, schools, and government agencies. It is the utility’s responsibility within its regulatory compact to ensure that power is transmitted safely and reliably to the end-use customers it serves within its territory. Under current regulations this responsibility will continue, even when an increasing share of generation is at the “grid edge.”
While we are relying more on the grid, and with emerging requirements for two-way power flow, it is aging – 70% of the grid’s transmission lines and power transformers are over 25 years old.[1] This aging infrastructure, coupled with increasing frequency of major weather events, have contributed to increasing utility outages. Traditionally, utilities use investment capital to repair or expand the grid (i.e. new substation, high voltage transmission lines etc.).
Historically, regulators worked closely with utilities through a series of regularly scheduled rate cases to approve capital investments and the associated rate of return (ROR) on capital that permit utilities to recover their T&D investments. Since utilities can collect both the invested capital and a ROR on it, there is an incentive for more capital-intensive investment. Today, an increasing number of regulators require that utilities consider alternatives to these traditional T&D investments in meeting their customer electric service needs, while simultaneously achieving other state policies related to renewable energy and decarbonization targets.
With the declining costs for many renewable energy technologies and growing demand by consumers for increased choice regarding how their electricity is generated, there is more decentralization of generation. This decentralization has required increased investment in grid devices (such as distributed automation) to control the bi-directional and real-time flow of electricity arising from the growth in digital and smart devices at the grid edge. Now, when utilities look to make grid upgrades in “poles and wires” as part of their rate cases, they are increasingly being asked to compare the cost of these solutions in parallel with those of newer, innovative (and often less capital intensive) technologies.
These alternatives technologies, referred to as non-wires alternatives (NWAs), can be categorized most broadly through the lens of either supply-side or demand side management solutions, and generally take the form of a distributed energy resource (DER). A supply-side solution might involve the application of solar PV (either rooftop or community) and battery storage to avoid disruptions in power delivery, and/or alleviating congestion on circuits with additional current or forecasted power needs. By siting power generation close to the site of consumption (grid edge) and making it available when most needed through battery application, the need for substation upgrades, new poles, and wires can be deferred. A similar end point may be reached by enrolling a number of customers with smart thermostats in a demand-side management program whereby an aggregator calls an “event” and adjusts the thermostats in a way that helps shed load in a way that individuals may barely notice, while in aggregate it can avoid the previously mentioned upgrades to substations, poles, and wires to serve this “peak” event.
As regulators push to deploy DER technologies through avoided cost comparisons they can also achieve other state policy objectives. For example, since the technologies often associated with NWAs are carbon-free on the supply side, or avoid carbon emissions on the demand side, CO2 mitigation is yet another marker of the value where NWAs provide societal and end-customer benefits.
As utilities explore how to scale their adoption of NWAs meaningfully across their service territories and include them in rate cases, they currently encounter a series of challenges. These challenges are often related to how avoided costs and related benefits are calculated. Regulator guidance may not be particularly clear or cover all manners of NWA solutions, especially given how rapidly some of these technologies are changing. Even when there is guidance from regulators, recognizing and capturing those benefits fully, accurately, and with internal utility consensus from a financial planning and analysis standpoint may be difficult. However, achieving NWA implementation at scale from a physical standpoint may be challenging as well. Customer willingness to provide rooftop access for solar, willingness to participate in demand curtailment events, and shading/land ownership of sites are amongst the factors that can keep NWAs from being implemented behind the meter and on the distribution network.
Looking away from retail power transactions, and turning attention upstream to the bulk power market, there have been a number of shifts in how independent system operators and regional transmission organizations (ISO/RTO) have shifted their own operations in response to the growing penetration of renewable energy on the distribution grid. Additionally, developers of such projects are also leveraging battery technology at scale to firm up revenues from their generation assets and participate in the ancillary services markets that were previously not an option (reactive power, reserve capacity, etc.). These entities have also started to pilot the idea of allowing multiple DERs on a node to deliver wholesale market services in aggregate.[2]
While such pilots represent a step in the right direction, and provide yet another mechanism by which NWAs may economically defer larger capital investments, the emphasis lies yet again on the supply-side of the equation and does not provide means for the demand-side avoided megawatt of consumption to be valued equally. Furthermore, such pilots operate under the assumption of “one-asset, one market value stream”, which precludes the ability of a battery asset to provide both power during peak evening hours in addition voltage support.
If bulk power markets evolve to more comprehensively enable NWAs to participate beyond their roles as grid investment deferrals and leverage the full range of NWA capabilities and value (see figure), it is not farfetched to think that NWAs may present a more attractive rate of return as compared to traditional solutions. Coupled with the potential for revenue generation in the market, NWAs can also enable utilities to leverage their customers’ engagement and participation in grid deferral to generate system level grid value without relying on rate-based operations. While such market-based programs are still being developed, the price signals from a market operator (ISO/RTO) are more bankable and thus more scalable to developers who would construct such NWA solutions to meet utility needs.
While this sort of paradigm shift in a distribution utility’s business model would require a massive overhaul in market and utility operations, and would require a largely new regulatory frameworks, the possibility remains that this is yet another means by which NWAs can play a central role in a more reliable, resilient, clean, and cost-effective grid.
Source: energycentral
