TOPIC #2
Distributed Resources and Electrification Drive a Planning Rethink
Integrated distribution planning gains traction as more states consider grid needs given electrification, clean energy, and environmental justice.
Distribution Investment Continues Apace
- Transmission and distribution (T&D) investment has been growing steadily for at least a decade and is expected to comprise the most significant portion of utility capital spending over the next two years.
- Still more investment is expected over the next decade. Key drivers include:
– Replacements and upgrades of well-depreciated T&D facilities for safety, reliability, and resilience and to incorporate new and improved technologies
– Electrification, as some utilities and jurisdictions (including federal policy) encourage electrification of transportation and heating and cooking applications
– Growth in distributed energy resources (DERs), given lower costs of photovoltaic solar, and policy support for non-carbon-emitting resources such as demand response and storage
- With this increased distribution investment, a growing number of states are requiring longer-term planning that accounts for these growing DERs and evolving policy priorities, including decarbonization and environmental and energy justice.
Note: DERs can be defined to include energy efficiency, demand response, distributed generation, combined heat and power, electric vehicles, and energy storage.
KEY TAKEAWAYS
Electric distribution investment is growing, driven by replacement of aging infrastructure, electrification, and promotion of distributed energy resources.
To guide investment and achieve certain policy goals, such as incentivizing noncarbon-emitting resources on the grid, regulators are setting expanded objectives for planning.
Utilities are using new, integrated distribution planning approaches that account for uncertainty, transparency (for both carbon reduction and cost control/ equity), locational value, and complexity as they try to tie all these moving parts together.
Electric distribution investment is growing, driven by replacement of aging infrastructure, electrification, and promotion of distributed energy resources.
To guide investment and achieve certain policy goals, such as incentivizing noncarbon-emitting resources on the grid, regulators are setting expanded objectives for planning.
Utilities are using new, integrated distribution planning approaches that account for uncertainty, transparency (for both carbon reduction and cost control/ equity), locational value, and complexity as they try to tie all these moving parts together.
Figure 2.1: Investor-Owned Electric Utility Construction Expenditures for Transmission and Distribution ($ Millions)
Sources: Edison Electric Institute; S&P Global Market Intelligence; ScottMadden analysis
Figure 2.2: Projected Capital Expenditures of Selected Electric, Gas, and Multi-Utilities by Business Category (2022-2024)
Sources: S&P Global Capital IQ Pro/Regulatory Research Associates
A Bit of History
- DERs and grid modernization are not new, but their evolution is instructive in understanding how and why distribution planning is changing.
- During the first wave of “smart grid” investments, turbocharged as part of the 2009 economic stimulus during the Great Recession, the industry’s focus was on automation, control, and “self-healing.” Those investments were, for example, in system control and data acquisition (or SCADA) monitoring and control, distribution automation, and advanced metering infrastructure (AMI).
- Soon thereafter, in the mid-2010s, there was discussion about the utility “death spiral” as the photovoltaic solar cost curve began to decline significantly, and there was some fear that customers would self-supply, leaving remaining customers to pay for the grid.
- Policymakers in some jurisdictions that perceived potential grid value in DERs (e.g., New York) and places where conditions were more favorable for rooftop solar (e.g., California, Hawaii) began requiring distribution and/or grid modernization plans.
- The list of jurisdictions requiring distribution system plans has grown (see Figure 2.3 below). In jurisdictions where utilities are formulating and implementing multi-year grid plans, utilities are being directed to go beyond considerations of reliability and resilience. They are being asked to consider policy and other factors and increase transparency and information sharing with stakeholders.
Figure 2.3: States with Distribution Planning Requirements
Source: Grid Modernization Laboratory Consortium
Integrated Distribution Planning Is Highly Dependent Upon Policy Objectives
- Integrated distribution planning (IDP) goes beyond internal, engineering-led, static planning to open engagement and an objectives-based model.
- Regulatory goals and objectives—often set out in enabling legislation—will drive the scope and types of options to be considered in grid modernization and expansion. These may vary widely. For example:
– Under the Reforming the Energy Vision proceedings, New York has pursued grid modernization that envisioned, among other things, a roadmap for technology investment to improve grid intelligence and prepare for higher DER penetration levels.
– Minnesota does not have such a mandate and explicitly includes in its objectives, “Keep customer bills low.”
– Illinois’ Multi-Year Integrated Grid Plan objectives include “support[ing] efforts to bring the benefits of grid modernization and clean energy, including, but not limited to, deployment of distributed energy resources to all retail customers, and support efforts to bring at least 40% of those benefits to Equity Investment Eligible Communities.”
– California, seeing that battery storage, customer-sited solar, demand-side management, and electric vehicle infrastructure is growing significantly, recently declared an objective of “optimiz[ing] the integration of millions of DERs within the distribution grid while ensuring affordable rates” by way of a distribution system operator model.
- Policy objectives are evolving, too:
– More jurisdictions are interested in DER integration to reduce overall grid costs (e.g., non-wires alternatives) and in planning the distribution system to accommodate electrification and DERs in an equitable manner.
– Climate change concerns may begin to drive resilience as an objective of IDP as well, as regulators are increasingly interested in planning the future T&D system to withstand more frequent and severe storms and rising temperatures.
- Objectives can change over time. In New York, for example, Con Edison noted that its distributed system implementation plans were evolving: “The clean energy policy focus in New York has expanded beyond an emphasis on distribution-connected, small-scale energy resources to one which includes advancing decarbonization through larger-scale resources such as offshore wind and utility-scale solar and fundamental shifts of demand toward electrification of transportation and building heating.”
Figure 2.4: Selected IDP Objectives/Goals/Visions by Jurisdiction: Drivers of IDPs May Vary
Note: *Equity Investment Eligible Communities are geographic areas throughout Illinois which would most benefit from equitable investments by the state designed to combat discrimination and foster sustainable economic growth.
Sources: Smart Electric Power Alliance; Climate and Equitable Jobs Act (Ill. Public Act 102-0662); ScottMadden analysis
What Changes for Planning?
- “Integration” in IDP can involve parts of the value chain adjacent to the distribution grid alone, e.g., transmission and sub-transmission and end-user DERs.
- Traditional distribution planning is driven by expected, deterministic customer and demand growth based on drivers such as population growth, economic growth, and energy usage trends. Historically, it has focused on reliability objectives and planning to system and local peaks.
- The new IDP planning paradigm expands beyond traditional planning drivers, incorporating objectives noted earlier. It considers investments beyond reliability, incorporating evolving and emerging grid features such as:
– DER deployment trends and net load (i.e., demand net of portion served by DERs) and related uncertainty
– Electrification, as some applications—such as fleet electrification—can bring significant point load in a matter of months rather than over years, as might happen with the construction of a new building. With this shorter development cycle, planning for higher voltage infrastructure (transmission and substations) must maintain line of sight to distribution activity, often residing in different utility departments or divisions.
– Hosting capacity – the ability of discrete parts of the distribution grid to accommodate interconnecting DERs without impacting reliability, requiring specialized inverter settings, or without requiring system modifications. This capacity is location dependent, feeder and circuit dependent, and time varying. Regulators and stakeholders demand more transparency under IDP regarding this grid topography and locational value to inform siting and development decisions.
Figure 2.5: Transitioning to Integrated Distribution Planning
Source: GridLab
What Changes for Planning? (Cont.)
– Head-end systems – hardware and software that receive meter data from AMI and other sensors. Understanding and using end-user data enables both distributed systems operations and controllable, fungible load that can operate as demand-side resources.
– Investments in new capabilities, which looks beyond current systems, telecommunication infrastructure, and field assets. IDPs often require utilities to detail their current capabilities and outline the investments needed to achieve customer and grid benefits in the future.
Figure 2.6: Differences Between Traditional Distribution Planning and Integrated Distribution Planning
Source: Smart Electric Power Alliance
Some Considerations for Grid Investment Decisions
- A goal for distribution planning has long been to identify projects necessary to maintain reliability and safety standards. More recently, policymakers have introduced additional objectives to be achieved through the distribution planning process, such as environmental attributes, capex reduction (or at least making utilities capex/opex indifferent), and energy justice.
- As planning migrates from a standards-based approach to a multiobjective process, determining the prudency of investments is a more complex question. Some projects may require a benefit-cost analysis, while others may use the traditional “just and reasonable” approach.
- Most jurisdictions adopting IDPs envision multi-year plans to accommodate stakeholder processes and to provide stability and consistency as DER adoption, technology development, capital availability, and rate impacts unfold. Some utilities use scenario analysis to reflect a potentially more dynamic planning environment with more input variables.
Ratemaking Implications
- Ratemaking and rate design approaches are changing—both for multi-year IDPs and for some traditional distribution plans as well—factoring in various potential features of an IDP, such as:
– Potential stranding of upstream assets with demand-side options
– “Used and useful” distribution infrastructure built in anticipation of DER evolution
– Effect on sales volumes where utility rates are kWh volume driven
– Changing cost (and benefit) drivers and interest in making value of demand reductions and grid locations transparent
– Balancing affordability and fair and equitable cost allocation
- Performance metrics tied to desired regulatory outcomes are also a growing trend with grid modernization and IDP. These can take the form of enhancements (or reductions) of allowed returns on equity.
Figure 2.7: Some Key Features and Issues in IDPs
Source: ScottMadden analysis
IMPLICATIONS
First, utility planning must accommodate a variety of factors beyond reliability and affordability; planning is expanding to include a variety of policy objectives as well.
Second, IDPs require a coordinated approach from various utility groups (engineering, energy efficiency, rates,
and electric vehicles, among others) as well as stakeholders.
Similarly, IDPs must be aligned with other utility plans (e.g., a multi-year energy efficiency plan or rate case). Moreover, utilities are being asked to integrate stakeholder feedback and input, so engaging stakeholders effectively will become critical to IDP outcomes.
Finally, distribution planning and investment activity is driving upstream impacts to transmission, presenting
challenges to the refresh frequency and lead time necessary for planning these long-lived assets.
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