A EPA
State and Local Climate
and Energy Program
State Energy and Environment
Guide to Action:
Maximizing Grid Investments
2022
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State and Local Climate
and Energy Program
Maximizing Grid Investments
Table of Contents
Preface and Acknowledgments ii
Policy Description and Benefits 1
Summary 1
Benefits 2
Electricity System Benefits 3
Environmental Benefits 3
Equity Benefits 3
Quantifying and Communicating the Benefits 4
Technical Background on Key Opportunities 5
Distribution System Efficiency Opportunities 6
Clean Energy Integration Opportunities 8
New or Enhanced Planning 11
Current Landscape 13
Designing Effective Policy to Maximize Grid Investments 15
Participants 15
Key Design Issues and Constraints 17
Evaluating Current Systems and Future Needs 17
Gaining Operational Experience 18
Making the Business Case 18
Funding and Cost Recovery 18
Interaction with Federal Programs and Regulations 19
Interaction with State and Local Programs 20
Implementation, Oversight, and Evaluation 21
Implementation 21
Oversight 21
Evaluation 22
Conservation Voltage Reduction (CVR) Evaluation Example 22
Evaluation Resources 23
Action Steps for States 23
State Examples 24
Connecticut 24
New York 25
Michigan 27
Pacific Northwest 27
Information Resources 29
Understanding the Modern Grid and Its Benefits 29
Resources from Government Agencies, Institutes, and Networks 30
Resources from Energy Industry Associations 30
References 31
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Preface and Acknowledgments
The U.S. Environmental Protection Agency (EPA) State Energy and Environment Guide to Action offers real-
world best practices to help states design and implement policies that reduce emissions associated with
electricity generation and energy consumption. First published in 2006 and then updated in 2015, the Guide is
a longstanding EPA resource designed to help state officials draw insights from other states' policy innovations
and implementation experiences to help meet their own state's climate, environment, energy, and equity
goals.
As part of the 2022 update, each chapter reflects significant state regulatory and policy developments since
the 2015 publication. Guide chapters provide descriptions and definitions of each featured policy; explain how
the policy delivers energy, climate, health, and equity benefits; highlight how states have approached key
design and implementation issues; and share best practices based on state experiences.
Unlike earlier Guide editions, which were released as a complete set of chapters comprising a single document,
the 2022 update is being released in phases of collected chapters. This chapter is one of seven addressing
state-level utility policies that support clean energy and energy efficiency:
• Overview of Electric Utility Polices
• Electricity Resource Planning and Procurement
• Electric Utility Regulatory Frameworks and Financial Incentives
• Interconnection and Net Metering
• Customer Rates and Data Access
• Maximizing Grid Investments
• Energy Efficiency Programs and Resource Standards
Guide chapters are available online on the Guide to Action webpage.
All Guide chapters were developed by the Climate Protection Partnership Division's State and Local Climate
and Energy Program within EPA's Office of Atmospheric Protection. Phil Assmus managed the overall update of
the Guide and provided content and editorial support for all chapters. David Tancabel served as the chapter
lead for six utility policy chapters, and Cassandra Kubes led a crosscutting effort to address equity issues across
all Guide chapters. Maggie Molina provided technical review and editorial support across all chapters and led
the development of the energy efficiency chapter. We thank additional EPA staff, namely Erica Bollerud, Joe
Bryson, Beth Conlin, James Critchfield, Risa Edelman, Maureen McNamara, and Neeharika Naik-Dhungel, who
provided guidance for one or more chapter's initial development, early draft review, or final content.
We thank the following experts who commented on draft versions of the Guide chapters. Their contributions
helped to revise and improve one or more Guide chapters but do not imply endorsement of the final content:
Miles Keogh of the National Association of Clean Air Agencies, Lisa Schwartz and Ian Hoffman of Lawrence
Berkeley National Laboratory, Ben Kujala of the Northwest Power and Conservation Council, Jeff Loiter of the
National Regulatory Research Institute, Forest Bradley-Wright of the Southern Alliance for Clean Energy, Greg
Dierkers of the U.S. Department of Energy, Commissioner Abigail Anthony of the Rhode Island Public Utilities
Commission, Doug Scott of the Great Plains Institute, Weston Berg and Rachel Gold of the American Council
for an Energy-Efficient Economy, Cara Goldenberg of the Rocky Mountain Institute, Lon Huber of Duke Energy,
Radina Valova of the Interstate Renewable Energy Council, Christopher Villarreal of Plugged In Strategies,
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Rodney Sobin of the National Association of State Energy Officials, Alex Bond of the Edison Electric Institute,
Julie Michals of E4TheFuture, Dan Lauf of the National Governors Association, and Cyrus Bhedwar of the
Southeast Energy Efficiency Alliance.
We also thank the many state officials and regulatory staff who reviewed state-specific policy examples
highlighted in each of the chapters.
A multidisciplinary team of energy and environmental consultants provided research, analysis, and technical
support for this project. They include: Abt Associates (Rubenka Bandyopadhyay, Juanita Barboa, Heather
Hosterman, Amy Rowland, James Schroll, Elizabeth Shenaut, Christine Teter, and Christina Davies Waldron),
Efficiency for Everyone (Marti Frank), and Regulatory Assistance Project (Jeff Ackermann, David Farnsworth,
Mark LeBel, Richard Sedano, Nancy Seidman, John Shenot, and Jessica Shipley).
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Policy Description and Benefits
Summary
Policies that modernize the electric distribution system1 are critical to
accelerate clean energy adoption and realize its benefits. State
policymakers, electric utility regulators (often called public utility
commissions or PUCs), and utilities are making progress toward goals for
affordability, resilience, energy efficiency, and renewable energy
through interrelated technology investments, grid management
strategies, and planning approaches. This chapter provides state
policymakers, regulators, and stakeholders with technical background
and examples of established, near-term opportunities for grid
investments that support a modern electric distribution system, such as the deployment of clean and
distributed energy resources (DERs). DERs are customer-side electric generation, demand response, energy
efficiency, or energy storage systems located on the distribution grid, typically close to load, used individually
or aggregated to provide more value. This chapter highlights three strategies for states to maximize grid
investments:
Many modern grid investments can
support a state's environmental,
clean energy, and climate goals. A
range of emerging grid technologies,
management strategies, and new
and enhanced planning paradigms
can support greater energy
efficiency, renewable energy, and
flexible resource integration.
• Distribution system efficiency. Policies and technologies that reduce energy loss and increase efficiency in
the electricity distribution system can meet demand increases and defer or negate larger capital
investments. Electricity delivered over long distances is accompanied by energy losses due to factors such
as infrastructure condition, ambient temperature, conductor temperature (influenced by load), and
weather. These "line losses" can be mitigated by voltage management or asset management practices
ranging from engineering adjustments (e.g., voltage optimization and conservation voltage reduction, or
CVR) to accelerated replacements (e.g., efficient distribution transformers).
• Clean energy integration. Technologies, planning approaches, and grid management practices can increase
grid flexibility and support grid integration of intermittent renewables and DERs. Strategies to integrate
the growth of intermittent sources and DERs include the use of advanced metering infrastructure (AMI),
inverter systems, demand response and storage deployment, and participation in energy supply markets
or a larger regional transmission grid organization.
• Enhanced grid planning. Comprehensive electricity planning approaches and tools can inform strategic grid
investment decisions, which may last for 15 to 50 years, so they align with state policy priorities around
affordability, reliability, resilience, and clean energy. Examples of these approaches and tools include
assessments of timing and locational value of energy efficiency savings, consideration of non-wires
alternatives (NWAs, sometimes called non-wire solutions or NWS), hosting capacity analysis (HCA), and
integrated distribution system planning (IDSP). These approaches can support investment decisions that
improve equitable outcomes for customers and service reliability. For example, decisionmakers can weigh
the locational value of a distribution system upgrade(s), which can change over time, with data on how the
upgrade would improve resilience or affordability for the low-income households it would serve.
1 This chapter is focused on the distribution system, which is directly affected by state actions and state utility regulators. The
transmission system and some federal policies are discussed to provide context. Many of the engineering principles and
technologies presented in the chapter are relevant and applicable to both the transmission and distribution systems.
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This chapter reviews each of the above grid investment strategies, provides detailed examples, and identifies
the benefits they provide.2 This chapter also identifies the action steps states can take to achieve these
benefits, and highlights complementary resources such as those available from the joint National Association
of Regulatory Utility Commissioners (NARUC) and the National Association of State Energy Officials (NASEO)
Task Force on Comprehensive Electricity Planning (NARUC & NASEO n.d.). Lastly, this chapter describes
examples of how these strategies have been employed in Connecticut, New York, Michigan, and the Pacific
Northwest.
The following are several examples of action steps states are using to inform grid modernization investments:
• Investigate grid modernization needs and opportunities. Understanding the perspectives of multiple
stakeholders become increasingly important as grid modernization efforts mature and DERs become more
widely adopted. States can convene a stakeholder process and consider the proceedings of leading states
to understand emerging issues. States that have already gained operational knowledge with modern grid
deployments can review the role of existing utility policies in either inhibiting or encouraging optimizing
grid investments to achieve energy efficiency or enhance integration of distributed renewables (e.g.,
revenue decoupling and performance-based regulation).
• Assess and pursue opportunities for distribution system efficiency and clean energy integration.
Distribution system efficiency has not always been included in energy efficiency potential studies. States
can consider including it in efficiency potential studies and/or consider allowing distribution system
efficiency to count toward mandatory or voluntary energy efficiency standards. Other ways states
accommodate and leverage the value of DERs on the grid include using inverters to support voltage and
reactive power management and complementary deployment of demand response3 and storage assets
when making grid modernization investments.
• Adopt new or enhanced grid planning. States can direct utilities to use several interrelated analyses and
grid planning paradigms to help better inform the value of DERs to the distribution system.
• Implement Expeditious Deployment Programs. Pilot studies, and similar programs such as regulatory
sandboxes, can help utilities gain operational knowledge and understand costs and benefits prior to
broader implementation. For many technologies, the development of best management practices is
needed to help unlock their fuil potential. These programs can provide utilities and their third party
partners the opportunity to improve grid performance or solve problems with new solutions with fewer
administrative restrictions.
Benefits
Maximizing modern grid investments to increase distribution system efficiency and support renewable
generation integration and clean energy deployment can improve energy efficiency, reduce air pollution
including greenhouse gas (GHG) emissions, improve system reliability, and provide economic and
environmental benefits to communities including those with environmental justice concerns. This section
summarizes many of the benefits and identifies tools to quantify and communicate the benefits. Subsequent
2 This chapter does not attempt to cover the wide range of state actions to promote customer DER adoption, such as policies and
programs on electricity rate design, community solar and storage, electric vehicles, and energy efficiency. Many state policy best
practices on these topics are discussed in other chapters of the Guide.
3 Demand response is a program that uses time-varying rates, financial incentives, or other customer feedback or interactive
technology to enable participating customers to reduce their electricity usage during peak periods to help utilities balance grid
supply and demand during those times (LBNL n.d.).
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sections in this chapter, including Technical Background on Key Opportunities, provide additional details about
specific grid strategies.
Electricity System Benefits
Modern grid technology investments, grid management strategies, and planning and communications
approaches can provide a range of electricity system benefits. These include reduced fuel inputs and related
operating costs, reduced energy consumption on the customer-side of the meter, enhanced system reliability
and flexibility, reduced outage response time, reduced renewable energy curtailments,4 and greater system
transparency for utility and customer decision-making. Modeling of distribution-level impacts has
demonstrated that smart grid5 technology deployments can provide both direct benefits, such as energy
savings from distribution system efficiency opportunities, and indirect benefits by enabling clean energy
integration (e.g., demand response or distributed wind and solar generation) (PNNL 2012a).
Grid investments in distribution system efficiency can result in energy savings for the utility and customers.
Utilities participating in smart grid demonstration projects involving voltage and power optimization and CVR
have saved energy and reduced peak power in the range of one to four percent of delivered energy (Short
2016; DOE 2015). For example, the utility AEP Ohio documented results of two to four percent reduction in
both energy and demand, and three percent reduction in peak load (DOE 2015).
Grid investments that increase transmission and distribution system efficiency, support strategically located
renewable resources, and enable demand response capabilities can help reduce peak load and alleviate grid
congestion. This also benefits ratepayers by reducing a utility's capacity costs or need to upgrade distribution
systems by, for example, delaying or negating the need for investment in new generation infrastructure
(NARUC 2016). For example, grid investments can enable greater integration of renewable energy resources
and deploy complementary resources such as storage or demand response during periods when renewable
resources wane (e.g., when solar production is interrupted due to cloud cover). The flexibility of energy
storage can reduce the need to dispatch more expensive and often higher polluting conventional generation
resources that often need advanced notice to come online.
Environmental Benefits
Grid investments that produce electricity system benefits can, in turn, result in environmental benefits
including reduced air emissions if less electricity is generated from fossil fuels. Through reduced electricity
losses, increased system efficiencies, decreased use of fossil-fired peaking units, and increased renewable
energy on the grid, states can decrease fossil fuel combustion for power generation. Renewable energy
produces no GHG emissions from fossil fuels and reduces some types of air pollution (EPA n.d.). A national
laboratory study estimated that grid investments to manage distribution system voltage could reduce carbon
dioxide emissions by more than 63 million tons, based on annual energy savings of approximately three
percent (PNNL 2012b).
Equity Benefits
Investments to modernize the grid can help advance equity by providing social, environmental, and economic
benefits to historically marginalized communities. Minority, low-income, and indigenous populations
4 Curtailment is the intentional reduction of power generation or load. It is commonly associated with an oversupply attributable to
intermittent wind and solar power, when more electricity is available to the grid from generators than needed to serve customer
demand (NREL 2022). It can also be associated with demand-response. A utility can send a load curtailment request to customers to
help maintain grid balance during peak periods (BPA 2018).
5 A "smart" grid is capable of two-way communication between the utility and its customers and incorporates sensors and control
systems to detect and respond to grid needs, including changing electricity demand, power quality, and equipment failures.
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frequently bear a disproportionate burden of environmental harms and adverse health outcomes, including
from power plants operating near their communities (EPA 2022b). Grid investments that reduce or shift peak
demand can reduce the need for fossil-fired peaking plants near these communities (PEAK 2020). NWAs, for
example, can improve equity in the power system by reducing environmental and health risks, decreasing the
cost of the energy, or providing backup power during outages (Tarekegne et al. 2021). Community-owned
storage in particular is promising for equitable distribution of benefits (PNNL 2021a). Some grid investments,
such as voltage optimization and CVR, reduce the financial burden of electricity bills for low-income customers
because most of the electricity savings from these strategies occur as end-use efficiency gains on the customer
side. The resulting energy efficiency can help to reduce customer energy burdens and enhance household and
community resilience. Energy efficiency is an important tool to support equity in electricity bill impacts (refer
to the Energy Efficiency Programs and Resource Standards chapter of the Guide).
EPA Environmental Impacts and Health Benefits of Clean Energy Tools
EPA has a range of free tools available to support states and stakeholders with analyzing and quantifying the
environmental impacts and health benefits of clean energy, including but not limited to the following:
• AVoided Emissions and geneRation Tool (AVERT) is a tool designed to meet the needs of state air quality
planners and other interested stakeholders. Non-experts can use AVERT to evaluate county, state, and regional
emissions displaced at fossil fuei power plants by policies and programs that support efficiency, clean DERs, and
utility scale renewable energy.
• CO-Benefits Risk Assessment (COBRA) Health Impacts Screening and Mapping Tool is a tool that helps state
and local governments estimate and map the air quality, human health, and related economic benefits of ciean
energy policies and programs at the national, state, and county ievels. Analysts assessing the impacts of changes in
rate design can enter corresponding changes in emissions from the electric utility sector and use the results from
COBRA to inform benefit-cost analyses and other decision-making processes,
• Health Benefits Per Kilowatt-Hour (BPK) is a set of values that help state and local government policymakers and
other stakeholders develop screening-levei estimates of the outdoor air quality-related public health benefits of
investments in energy efficiency and other clean DERs.
• Energy Savings and Impacts Scenario Tool (ESIST) is a customizable and transparent Excel-based planning tool
for analyzing the energy savings and costs from customer-funded energy efficiency programs and their impacts on
emissions, public health, and equity. ESIST enables users to develop, explore, and share energy efficiency
scenarios between 2010 and 2040.
• Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive source of data on
environmental characteristics of electric power plants in the United States. The interactive eGRID Explorer
dashboard offers data, maps and graphs on electric power generated, emissions, emission rates, heat input,
resource mix, and more.
• Quantifying the Multiple Benefits of Energy Efficiency and Renewable Energy describes methods, tools, and
steps analysts can use to quantity these benefits so that they can compare costs and benefits and comprehensively
assess the value of energy policy and program choices.
Quantifying and Communicating the Benefits
Many of the grid investment strategies in this chapter are intended to increase the deployment of DERs and
other clean energy resources. To help states and stakeholders analyze and quantify the impacts of clean
energy resources, EPA has a range of tools highlighted in the text box. For example, EPA's AVoided Emissions
and geneRation Tool (AVERT) allows users to quantify the emissions benefits and energy savings related to
energy efficiency programs, such as grid improvements (EPA 2020). EPA's Co-Benefit Risk Assessment (COBRA)
model can then be used to evaluate and quantify the health impacts of these emissions changes. With these
tools, state environmental regulators can quickly and easily evaluate the impacts of one or more policies and
their associated changes to load and emissions at different temporal (hourly to annual) and spatial (county to
region) scales.
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Understanding the benefits and how to quantify
those benefits enables stakeholders to develop,
implement, and justify programs and policies like
modern grid management strategies and
technologies, and investments that enable
greater integration of energy efficiency,
renewable energy, demand response, and
storage. For jurisdictions that consider or
account for health benefits in their decision-
making processes, EPA's COBRA tool and Health
Benefits-per-Kilowatt-hour (BPK) values give
health officials, utilities, and utility regulators the
ability to quantify and monetize the health
benefits of demand reduction from increased
clean DER deployment. In addition to tools, EPA
offers the detailed resource Quantifying the
Multiple Benefits of Energy Efficiency and
Renewable Energy: A Guide for State and Local
Governments (EPA 2018). Also, EPA's ENERGY
STAR program supports state and local
governments in communicating the value
streams of efficiency under three pillars: enabler
of growth, mitigator of risk, and protector of the
public good, and offers resources to harness the
power of storytelling (EPA n.d.). The following
sections, which describe in detail each of three
key grid modernization opportunities, list
additional benefits specific to each opportunity.
Technical Background on
Key Opportunities
Modern grid investments can enable better
visibility into grid conditions throughout the
distribution system, allow two-way
communication between the utility and
customers or their devices, and permit
automation to respond to grid conditions in real
time. However, no single technology or
combination of technologies delivers modern
grid benefits automatically. How technologies
and grid assets are managed is critical to
achieving the promise of a modern grid. This
section provides a technical overview and discusses
using to realize the benefits of clean energy, and hig
Tools for a Modern Grid
No single technology or combination of technologies delivers
modern grid benefits. How technologies and grid assets are
managed is critical to achieving the promise of a modern grid.
The following are some of the tools grid operators use to
monitor, evaluate, and respond to grid connections in real time.
System controls include load tap changers, which are
installed on transformers and raise or lower voltage at the
beginning of the feeder; voltage regulators, which are installed
on substations or feeders, and raise or lower downstream
voltage; and capacitor banks, which are installed at the
substation or feeder, and manage reactive power and voitage.
Control packages are installed on capacitor banks and voltage
regulators and programmed to turn on and off based on
system conditions or via remote signal.
Monitoring devices include voltage sensors on distribution
lines, synchrophasers on transmission systems for
synchronized measurement of voltages, and (increasingly) AM!
meters for voltage reaching consumer premises.
Communications and automation are enabled by distribution
management systems that (1) receive information from multiple
utility information systems (e.g., supervisory control and data
acquisition (SCADA) systems that monitor and control
distributions systems and information systems that collect and
store AMI data) and (2) analyze the data (online or offline) to
determine how to optimize the distribution system and send
control signals. An advanced distribution management system
(ADMS) is a software platform that facilitates communication
and automation to integrate DERs, improve resilience and
reliability, and optimize grid performance. A distributed energy
resource management system (DERMS) is a complementary
tool originally developed by the National Renewable Energy
Laboratory (NREL) that can provide greater control in
managing peak loads by forecasting, aggregating, and
dispatching DERs. DERMS and ADMS are increasingly
important as distribution systems become more sophisticated
in operations and DER integration.
Sources:
• DOE Smart Grid Investment Program, Application of
Automated Controls for Voltage and Reactive Power
Management - Initial Results
• NREL Advanced Power Electronics and Smart
Inverters
• NREL Renewable Energy Integration
• NREL Advanced Distribution Management
• IEEE Smart Grid - Grid Management System
hree approaches to grid modernization that states are
Mights tools for a modern grid (refer to the text box).
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Distribution System Efficiency Opportunities
The U.S. Energy Information Administration estimates that on average 5 percent of the electricity produced to
serve customers is lost in transmission and distribution (EIA 2021). When accounting for both the electricity
that did not need to be delivered and the resultant improved efficiency of delivering electricity, the total
savings (i.e., reduction in total line losses) from high DER penetration during peak demand can be as high as 15
to 20 percent of the energy value (IREC 2013). Voltages in the transmission and distribution system can be
adjusted to reduce system losses and/or to reduce customer load level to manage peak demand or to achieve
broader energy efficiency benefits. Customer meter data also can be used strategically by grid operators,
energy efficiency program managers, and customers to reduce consumption. This section describes energy
efficiency opportunities in the distribution system.
Improved voltage management Electricity must be delivered to most customers within a defined range of
voltages. For example, residential customer voltage is typically between 114 and 126 volts (for normal 120-volt
service).6 Because some electrical equipment consumes less energy when operated at the lower end of the
acceptable voltage range, delivering electricity closer to the lower end of this range can save energy in homes
and buildings by increasing the efficiency of customer appliances and devices (IET Smart Grid 2020). Operating
the distribution system at lower voltages to achieve energy efficiency benefits has historically been referred to
as CVR. Factors such as equipment type and local distribution system conditions affect the actual energy-
saving potential of CVR.
While CVR is a mature approach and can be deployed without advanced technology, modern grid technologies
enable a better understanding of the exact voltage at different points in the transmission and distribution
system and increases operational confidence among grid managers and regulators. Rapid communication with
controls, as well as the ability to automatically respond to grid conditions, offers the potential for greater
energy savings.
CVR reduces peak loads and total annual energy use. While performance can vary by distribution feeder,
climate zone, load type and other factors, modeling results found that CVR reduces peak load and total annual
energy use by one half to four percent. Extrapolation of those results in a simulation of nationwide
deployment demonstrated that CVR could provide a three percent reduction in annual energy consumption for
electric power generation (PNNL 2010). Research from utility pilot projects and modeling of voltage
optimization and CVR found that 90 to 95 percent of the electricity savings come from end-use equipment
efficiency improvements on the customer side.
The 2016 Illinois Future Energy Jobs Act (IL S.B. 2814 2016), required utilities to create a voltage optimization
plan. The Illinois utility Ameren's 2018 plan includes implementation at feeders in ZIP Codes that include
20 communities where over 50 percent of households are low-income. Although details on low-income
household energy savings were not reported, the cumulative persisting annual energy savings of Ameren's
voltage optimization plan is projected to be 1.5 percent in 2025 (Ameren 2018).
Improved reactive power management. In alternating current (AC) systems—almost universally used in the
United States to deliver electricity—current and voltage can get out of phase from equipment like motors and
other devices that require magnetic fields to operate.7 This is referred to as reactive power. Since motors are
ubiquitous in equipment found in factories, businesses, and homes, transmission and distribution system
6 ANSI CS4.1, "Electric Power Systems and Equipment—Voltage Ratings (60 Hertz)," specifies the nominal voltage ratings and
operating tolerances for 60-hertz electric power systems above 100 volts.
7 Most devices that need magnetic fields will cause current and voltage to be out of phase. Besides motors, this will include some of
the equipment used in transmission and distribution systems, such as transformers.
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operators need to provide reactive power to maintain electric power flow. Some of the same technologies and
strategies used to adjust system voltage can be used to better manage reactive power. Like voltage
management, reactive power can be managed without modern grid technologies; however, modern grid
technologies allow utilities to better monitor voltage and reactive power in real time along the entire delivery
path from generator through transmission and distribution to the ultimate customers. Better communications
and control equipment allows operators to adjust settings to control both factors all along the delivery path.
This is a big improvement over adjusting settings manually and at infrequent intervals. Better reactive power
management can reduce the fuel needed to operate the grid and can improve power quality.
Volt/var optimization. When utilities manage and optimize both voltage and reactive power simultaneously, it
is referred to as volt/var optimization.8 Since the flow of reactive power affects power system voltages,
management of costs and operational performance of a power system may improve if voltage control and
reactive power are well integrated (PNNL n.d.).
More efficient distribution transformers. Distribution transformers transfer current from one circuit to
another and change the value of the original voltage or current as needed. Distribution transformers are the
source of a significant amount of all electricity network losses. More efficient medium voltage, liquid-
immersed distribution transformers can provide large energy and cost savings over the infrastructure's lifetime
(EPA 2017). Energy savings can be achieved by optimizing transformer design to in-field load, which is utility
and/or location specific, and purchasing based on total ownership costs (TOC). EPA estimates that replacing 20
percent of U.S. transformer stock with transformers purchased based on TOC and designed for their intended
load could save an estimated 1.4 TWh annually (EPA 2017).
Beneficial use of customer data. AMI9 coupled with sensors along distribution circuits give utilities access to
system and customer data that are critical for future grid design and smart grid functionality. AMI enables
utilities to read meters without having to go to customer addresses and provides a range of other benefits. For
example, AMI facilitates same-day stop/start service when tenants move, helps detect outages during storms
to speed service restoration, and enables utilities to offer their customers information, monitoring tools, and
programs to save energy and manage costs. AMI meters can deliver consumption data at various intervals
(e.g., every 5, 15, or 60 minutes). AMI data access policies and issues are also discussed in the Customer Rates
and Data Access chapter of the Guide. Utilities continue to explore how to capture, store, analyze, and take
advantage of these data to inform many applications, including the following:
• Customer-level voltage and reactive power monitoring.10 AMI can be used to record voltages and reactive
power flow periodically or on demand. This information can provide assurance that voltage and reactive
power optimization efforts are performing as planned. For example, voltage readings can confirm that
customers are receiving power at the intended voltage for equipment operation and energy efficiency.
8 Vars or var is the unit of measurement of reactive power in electric transmission and distribution systems. The term is derived from
"volt-ampere reactive."
9 AMI is a system of utility-owned two-way communication devices, wireless electricity meters, and data management systems that
connects customer-site meters to utility-side meter data management and billing software. The Energy Information Administration
defines AMI as "electricity meters that measure and record usage data at a minimum, in hourly intervals, and provide usage data to
both consumers and energy companies at least once daily" (EIA n.d.).
10 States can direct utilities to use advanced, behind-the-meter energy management systems such as distributed energy resource
management systems (DERMS) and advanced distribution management systems (ADMS) to support distribution system operation
and DER integration. Refer to the Tools for a Modern Grid text box for more on DERMS and ADMS and links to additional resources
for energy management systems.
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• Utility asset management. AMI data can inform transformer location-specific load factors and load trends.
This information supports asset management planning, such as distribution transformer maintenance
scheduling, or replacement timing and sizing (discussed previously in this section).
• Customer data services. Utilities offer their customers energy usage information in varying levels of detail
and through a variety of channels, such as customer bills, utility customer dashboards online, and
automated data transfer services. The AMI data allows customers to make informed decisions about how
much and when they consume electricity to meet daily needs. The large-scale information technology
projects that are often part of AMI and other grid modernization investments present an opportunity for
utilities to incorporate the development of improved data access for customers.
• Behavior-based energy efficiency programs. Utilities are combining insights from behavioral science with
detailed energy use information to inform energy efficiency programs that use economic and non-
economic incentives, education, and feedback to change how people use energy. Utilities may combine
multiple behavioral insights within an energy efficiency program offering such as peer comparisons,
competitions, goal-setting, and rewards. Behavior-based energy efficiency programs, which are enabled by
customer data, can reduce annual average residential energy use up to three percent (NREL 2020).
• Facilitating change in energy use in response to price signals. Though not yet common in all deployments,
some AMI systems can facilitate demand response programs and dynamic pricing programs. When
coupled with time-varying rates that better reflect the cost of generating and delivering electricity, which
varies throughout the day, AMI meter information can encourage customers to shift consumption to
lower-cost periods and support efforts to reduce peak demand. In 2019, over a million customers
nationwide, representing a 12.1 percent annual increase, enrolled in a retail demand response program,
resulting in total enrollment for all census divisions of 10.9 million customers. In the same year, 1.7 million
customers nationwide, representing a 18.9 percent annual increase, enrolled in a retail dynamic pricing
program, resulting in total enrollment of 11.0 million customers (FERC 2021c). Time-varying rates are
discussed further in the Customer Rates and Data Access chapter of the Guide.
• Energy efficiency program planning, implementation, and evaluation. AMI data can be analyzed for usage
patterns to inform energy efficiency opportunities. PG&E in California (PG&E n.d.) and ConEd in New York
(ConEd n.d.) have used pilots to analyze data to provide virtual energy audits for interested customers.
Programs that use more detailed energy usage data from AMI can be used to inform evaluation,
measurement, and verification of energy efficiency programs (ACEEE 2017).
Clean Energy Integration Opportunities
Generally, transmission and distribution system losses increase as the distance between generation and
customer load increases. Increasing DER penetration on the distribution system can reduce losses but also
introduce other challenges. Planning tools like Hosting Capacity Analysis (HCA)11 can be used to determine the
amount of DER penetration that can be accommodated by a system before it experiences voltage and
reliability issues from exceeding operational performance limits (Ismael et al. 2019). Because DERs can affect
reliability, utilities have an interest in direct visibility, participation, ownership, or operation of DERs. To
maximize the benefits of the increasing amount of distributed and renewable resources in the distribution
system, state utility regulators are developing policies for utilities to better manage and integrate DERs in the
system. Strategies that can help maximize the clean energy contribution of DER include improved voltage and
11 Additional discussion of HCA is covered in the Interconnection and Net Metering chapter of the Guide.
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reactive power management using inverters12 and complementary deployment of demand response and
storage technologies.
Improved voltage and reactive power management with inverters. Some utilities, potentially as a
requirement from state utility regulators, develop strategies to manage voltage and reactive power to regulate
power quality at the distribution feeder level with the goal of integrating increased levels of distributed
renewables on their distribution grids (APS 2020). Distribution feeders are the final stage in the delivery of
electric power to individual consumers. These feeders were originally designed for one-way power flow—from
substation to customer. Like the branches of a tree, feeders have their heaviest loading near the substation
with decreased loading as the various branches reach their end-use customers. Generally, the voltage on
distribution feeders also falls at points farther from the substation. Adding distributed generation with modern
inverters can provide locational benefits by boosting voltage on longer circuits. This strategy can keep all
points on the distribution systems within acceptable levels, as today's inverters can set the power output
voltage when converting from DC to AC.
Use of smart inverter systems. In addition to use of inverters to set DER output voltage, states can accelerate
the use of inverters with smart functionality that provides real-time voltage and reactive power management.
Combined with other modern grid technologies, inverter systems used with solar and wind generation have
the potential to further benefit the system by real-time control of feeder voltages. As noted, voltage tends to
be higher closer to substations, and under some grid conditions, conventional inverters disconnect solar
resources to avoid overvoltage to the system. Advanced inverter systems have the potential to tailor the
output of solar and wind resources to meet system needs and provide grid services such as voltage or reactive
power support and can respond very quickly when needed. As of 2021, much of the installed base of inverters
in the United States has smart capabilities that are not yet in use. The IEEE Standard for Interconnection and
Interoperability of Distributed Energy Resources with Associated Electric Power Systems Interfaces, which
includes requirements for smart inverter functionality, will lead to greater uniformity in performance and
functionality. Because IEEE standards are voluntary, state regulators and utilities decide if and when to test
and deploy that functionality in the distribution system (IEEE 2018; NERC 2020).
Complementary deployment of demand response and storage. Since customer demand for electricity is
variable, grid system operators have historically balanced generation and demand by relying on fossil fuel fired
power plants that can ramp up or down relatively quickly. This balancing happens on time scales from seconds
to hours. As the amount of intermittent renewable generation increases, balancing becomes more challenging.
Adding demand response and storage provides flexibility with the potential to help system operators balance
supply and demand without the need to start up peaking power plants for short periods solely to provide
additional balancing capability.
When DERs can be aggregated and connected to form a virtual power plant (VPP), they offer an alternative to
fossil fuel peaking plants, which can be more expensive and higher polluting. In a VPP, the DERs can be
controlled as a demand flexibility13 resource to create more value for the grid than the sum of independent
DERs. In Massachusetts, the Mass Save ConnectedSolutions VPP program lets customers with battery storage
devices to earn incentives for allowing the utility Eversource to use their battery's energy during peak periods
12 An inverter is a devise that converts direct current (DC) to alternating current (AC). Transmission and distribution lines use AC.
Because some DERs including solar photovoltaic panels produce DC power, inverters are used to convert the DC output to AC for use
in homes and businesses.
13 Demand flexibility is the ability of electricity loads on the distribution system to change their usage patterns by the hour or other
time increment in response to price signals or utility controls to take advantage of available renewable energy resources (LBNL n.d.).
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(Mass Save n.d.), In 2022, the first residential VPP completed a summer season of operation in ISO-NE,
successfully transferring 1.8 gigawatt-hours of energy to the grid across New England (Sunrun 2022).
Traditional demand response programs, which are offered by many utilities nationwide, provide financial
incentives in return for customers reducing consumption during certain conditions, e.g., periods of peak load.
Historically, most utilities call on these customers to respond to peak events for a limited number of hours per
year. Refer to the Customer Rates and Data Access chapter of the Guide for more information.
Automation of demand response offers great promise for customer participation, not only in peak load
reduction events but also in serving as a flexible resource to provide other grid services for shorter periods of
time (NREL 2018). Utilities have used pilots to automate demand response by communicating with the building
energy management systems of participating commercial customers. A case study with a commercial real
estate company using PG&E's Automated Demand Response Program demonstrated bill savings from energy
efficiency and time savings for facility engineers (PG&E 2017). The emergence of ENERGY STAR products with
connected functionality (refer to the ENERGY STAR Products with Connected Functionality text box) may
increase the availability of products with connected features and the willingness and ability of residential
customers to participate in automated demand response initiatives.
Energy storage is increasingly being used to
support renewable energy integration. For
example, storage can store excess renewable
energy for later use; it can be installed close
to where energy will be consumed,
potentially alleviating congestion and line
losses on transmission and distribution
systems during peak periods; and certain
storage technologies with rapid response
capabilities can help manage fluctuations on
the electricity grid caused by the
intermittency of some renewable energy
resources. Due to their flexibility and ability
for rapid response, automated demand
response and storage are being explored by
system operators for better integrating
distributed renewable energy resources.
ENERGY STAR Products with Connected Functionality
As of May 2022, ENERGY STAR Connected Criteria are optionally
available for 14 product categories, with more on the way.
Products recognized as ENERGY STAR Connected provide a mix
of user convenience, tools for saving energy, and grid services.
Connected criteria are required for certain controls products
(e.g., thermostats, smart home energy management systems)
where data from the field is needed to verify energy savings.
In particular, ENERGY STAR Connected Criteria for large loads
(water heaters, central air conditioning and heat pumps, pooi
pumps, electric vehicle charging equipment, ice makers, ana smart
thermostats) require open communication standards and
functionality to receive and respond utility curtailment signals
issued to the aggregators and service providers they work with to
manage demand response programs. Connected criteria for large
loads are designed to advance interoperability and increase user
awareness of consumption, maintenance, and operation.
Utility participation in ISO/RTO. State public utility commissions and electric cooperative and municipal
boards sometimes have a role in approving utility participation in independent system operators (ISOs),
regional transmission organizations (RTOs), or voluntary energy imbalance markets (ElMs), such as those
operated by the California Independent System Operator (CAISO) and Southwest Power Pool (SPP). Similarly,
state legislatures have introduced bills to require utilities to join or explore joining an ISO/RTO to advance
clean energy objectives (NV S.B. 448 2021; CO S.B. 72 2021; OR S.B. 589 2021).
When utilities participate in an ISO or RTO, they are better able to accommodate and integrate higher levels of
intermittent renewable energy deployment like wind and solar. This is because an ISO/RTO represents a larger
"balancing area" (i.e., the area within which energy demand and generation must be balanced at all times)
than the territory of any one utility. Being in a larger balancing area reduces the aggregate variability in
renewable energy generation, while increasing the portfolio of dispatchabie generation resources that are
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available to adjust their output in response to fluctuating renewable generation (Utility Dive 2021; NV S.B. 448
2021).14
Participation in an Energy Imbalance Market. An EIM is a real-time energy supply market that offers
electricity generation and transmission service to balance demand and dispatch power based on lowest cost.
Market participants include multiple balancing authorities and utility territories (PSE n.d.). An EIM can support
greater deployment and integration of renewable energy resources because those resources often have near-
zero marginal operating costs. Unlike a typical wholesale electricity market run by an ISO/RTO, an EIM makes
participation available to entities outside of its ISO territory without the same requirements and financial
obligations required to be part of the ISO. Having a larger balancing area provides economic efficiency and can
help reduce renewable curtailments by the access to more resources for supply and demand balancing across
a larger area.
New or Enhanced Planning
The growth of DER comes with many benefits but also challenges for management and integration. States are
using new planning systems and approaches to address some of the issues such as lack of visibility into
customer DER (discussed further in this section) and need for better understanding of the value of DER on the
grid in place and time. NARUC and NASEO have developed a joint Task Force on Comprehensive Electricity
Planning; which helps states develop policies to improve grid resilience and reliability by addressing the growth
of DERs, storage, energy efficiency, demand management, and the implementation of new technology
solutions (NARUC & NASEO n.d.).
Many DERs have been adopted by customers over time without explicit coordination with the utility operator,
who may lack visibility into where these resources are deployed, what capabilities they have, and in some
cases (e.g., storage resources) how they are operated by customers at different times. Furthermore, utilities
often lack the ability to dispatch or control these resources. Due to utilities' responsibility to ensure that
service is delivered to customers in a safe and reliable manner, utilities may seek to have a role or to stay
informed of planning, siting, and controlling DERs that are integrated into the distribution system. Not all DER
are equally valuable in all locations or in all hours of the day. For example, a DER located at the end of a
distribution feeder providing electricity in the middle of the day to an unoccupied home would be less valuable
to the grid if there is not a plan in place to productively store and/or use that electricity (LBNL 2021).
Conversely, a DER that is strategically located with known performance attributes can be extremely valuable to
the distribution system, particularly when bundled together to provide complementary services that meet an
identified need.
States and utilities are taking several interrelated approaches to help better inform the value of DER to the
distribution system:
• Assessing timing and locational value of energy efficiency and demand flexibility can provide additional
value particularly if those savings address air quality concerns or electrical grid needs at necessary times
and locations. The timing of energy savings and demand flexibility is determined by collecting and
analyzing data on how the operating characteristics of the efficient equipment reduce or shift energy
consumption predictably during certain periods of time. For example, efficient air conditioners can reduce
energy consumption during peak summer use. The location of energy savings is determined by collecting
14 For more details, refer to the National Renewable Energy Laboratory's 2015 resource, Balancing Area Coordination: Efficiently
Integrating Renewable Energy Into the Grid.
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and analyzing data on the geographic distribution of energy efficiency projects and measures. Locations of
interest may vary from the regional level to neighborhood-level grid distribution points (EPA 2019).
• Hosting capacity analysis (HCA) is an analytical "pre-screening" process used to determine the distribution
system's ability to accommodate new distributed generation at specific grid locations without exceeding
operational performance limits or requiring feeder upgrades. HCA increases transparency into the
distribution grid's current operational conditions and limits through maps and supporting datasets. The
information can help commissions, utilities, or developers identify where new DER could provide beneficial
services and support longer term strategic DER investment decisions. The insight from HCA maps and data
on current grid conditions and operational constraints allows a utility customer or DER developer to more
efficiently target specific grid locations (IREC 2018). A hosting capacity analysis considers thermal, voltage,
and protection limits and establishes the baseline for the maximum distributed generation the grid could
accommodate safely (ICF 2016). After the initial process of identifying operating limits, a hosting capacity
analysis may also consider the locational value in additional DER on the grid (ICF 2016). Several states now
require utilities to conduct HCA, as summarized in Table 1. Additional discussion of HCA is covered in the
Interconnection and Net Metering chapter of the Guide.
• Assessing non-wires alternatives (NWAs) involves strategically evaluating and planning for options other
than traditional capital investments in distribution system infrastructure. Some utilities assess the physical
and operational needs of a project and determine whether DERs with different attributes can be bundled
to avoid or defer the infrastructure investment at a cost savings. For example, a DER bundle to relieve a
congestion bottleneck might include CVR or volt/var optimization under the direct control of the utility,
automated demand response through smart thermostats in the congestion area provided by a third-party
service provider (also referred to as an aggregator), and strategic use of battery storage owned either by a
customer or the utility. Research by a national laboratory has found that with thoughtful siting and energy
storage, NWAs have the potential to improve energy equity, reduce environmental and health hazards, or
provide backup power during outages (refer to the Equity Benefits section in this chapter). In Maine, a
2019 law requires the state's public advocate office, which represents the interests of utility ratepayers, to
analyze NWA options as alternative to transmission and distribution system investments (LBNL 2021; ME
L.D. 1181 2019).
• Integrated Distribution System Planning (IDSP) is a more comprehensive approach that expands on
analyses described above. IDSP, which can include scenario analysis, locational benefit analysis, and
hosting capacity analysis, can help utilities develop a distribution investment roadmap to prioritize grid
improvements (ICF 2016). IDSP "assesses the physical and operational changes to the electric grid
necessary to enable safe, reliable, and affordable services that satisfies changing customer expectations
and use of DERS" (ICF 2016). Due to utilities' responsibility and accountability for the distribution system's
safety and reliability, utilities have an interest in maintaining final decision-making authority that is
informed by this framework. IDSP "includes stakeholder-informed scenarios on expectations on growth of
DERS over time, and is coordinated with other planning scenarios to identify:
Necessary investments to enhance safety, reliability, and security, including replacement of aging
infrastructure and grid modernization
Changes to interconnection processes and integration investments to support DER adoption
The value of DER and opportunities to realize net benefits for all customers through use of DER-
provided services" (DOE 2018).
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While states have not adopted integrated distribution planning uniformly, some states have developed plans,
such as California; Delaware; Indiana; Hawaii; Maryland; Michigan; Minnesota; Nevada; New York; Rhode
Island; and Virginia (LBNL 2020).
There is increasing attention on the benefits and need to better coordinate distribution system planning with
bulk power system planning processes, such as utility integrated resource planning (IRP)15 or the resource
adequacy planning done by some ISO/RTOs16 (for more on planning processes, refer to the Electricity Resource
Planning and Procurement chapter of the Guide). This attention is driven in part by Federal Energy Regulatory
Commission (FERC) Orders that have enabled the participation of DER in wholesale electricity markets (refer to
the Interaction with Federal Programs and Regulations section in this chapter for discussion of FERC orders).
Although DER can potentially provide energy, capacity, or ancillary services, a DER providing a distribution
system service to the local utility may preclude the resource from providing the same or a different service at
the same time to the ISO/RTQ. For example, if an energy storage device is discharging energy to relieve local
congestion on the distribution system, it is likely unavailable at that time to provide frequency regulation for
the bulk power system. Those who plan and operate the grid at either level need to see when resources are
available to meet system needs and to know their location and capabilities. Enhanced visibility and planning
also helps regulators protect ratepayers by taking steps to ensure that DER owners are not paid twice (by their
utility and by the ISO/RTO) for the same service.
Current Landscape
State governments and utility regulators use planning to deploy additional DERs, make the grid more resilient
and reliable, and increase energy efficiency. A combination of interrelated planning, management,
technologies, and engineering decisions ensure that modern grid investments complement energy efficiency
and support the growth in renewable resources. These decisions are not captured by any single policy and
comprehensive data on the extent of these efforts are not widely available. Notable efforts in California,
Hawaii, Oregon, Massachusetts, and Minnesota have convened multiple stakeholders to address diverse
perspectives including environmental considerations in planning grid modernization efforts (LBNL 2020).
Table 1 highlights states with policies to promote energy efficiency, renewable energy integration, and
enhanced planning in grid investments, and the State Examples section presents a selection of case studies.
Some states' grid modernization planning efforts use principles of inclusive stakeholder engagement (Racial
Equity Tools n.d.). One objective is to ensure that grid modernization plans lead to benefits for and address
concerns of communities that are the most vulnerable to bill increases or electricity outages. For example, the
Massachusetts Energy Efficiency Advisory Council has an Equity Working Group that provides guidance to
utilities on behalf of moderate-income customers, renters, small businesses, and customers with limited
English proficiency. Examples of emerging efforts of the working group include outreach by National Grid to
multilingual-focused community based organizations to develop relationships that will help increase
participation among limited English proficiency customers (MA EEAC 2020). New York has a Climate Justice
15 Integrated resource planning includes the review of current and future resource options for meeting customer demand for
electricity services under a range of scenarios. In addition to supply-side, demand-side, and transmission and distribution system
resources, states can require utilities to consider environmental and social factors, incorporate input from communities and
stakeholders, and align planning and procurement processes with state policy priorities. Some states require utilities to develop an
integrated resource plan. I RP can be used to refer to the planning or the plan.
16 The National Association of Regulatory Utility Commissioners and the National Association of State Energy Officials Task Force on
Comprehensive Electricity Planning develops and curates resource lists for members to learn more about the evolving planning
process. Resources are available across 15 topic areas, including Distribution System Planning (DSP), Emerging Practices in DSP, and
Utility Best Practices for Integrated Planning (NARUC n.d.).
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Working group with local and regional advocates advising the state's Department of Environmental
Conservation priorities (NY State n.d.). The state previously convened a Storm Hardening and Resiliency
Collaborative focused on resiliency to extreme weather, with members including community and consumer
groups (Georgetown Climate Center n.d.). The resulting order from New York's Public Service Commission
adopted stakeholder strategies to keep costs low and improve resilience for vulnerable communities (NY PSC
2014a). The utility ConEd indicates efforts have avoided almost 700,000 customer outages from 2014 through
2020 (ConEd 2021a). California offers funding for low-income customers and those with medical needs to
install solar plus battery storage as a way to maintain electricity service during wildfire events (CPUC 2020).
Table 1: States with Policies to Advance Energy Efficiency, Renewable Integration, and Enhanced Planning in Grid
Investments
Policy
Description
State Examples
Energy Efficiency Opportunities
Provide incentives/remove
disincentives to grid-side
energy efficiency investment in
the distribution system
Enable grid-side energy efficiency to be
credited toward energy efficiency goals or
resource standards. Alternatively, provide
performance incentives to utilities for grid-
side efficiency and reduced line losses.
Includes CVR as energy efficiency portfolio
option: MD, NC, OH, OR, PA, WA
(Willoughby 2015)
Has policies providing energy efficiency
credit for efficient distribution transformers:
MD, WA, OR, MN BPA, (EPA 2017)
Time and locationai value of
energy efficiency savings
Assess time and/or locationai value of
energy savings from energy efficiency
measures.
CA, NY (Synapse 2018)
Incorporate time and/or locationai value of
DERs in benefit-cost framework.
Refer to (NESP 2022) for a description of
these states calculating locationai
distribution capacity impacts:
MN, NH, NY, Rl
Automated demand response
for efficient connected
products to support
renewables integration
Pilot or implement a program to use efficient,
connected products, which may be
controlled by the utility.
CT (ACEEE 2019), OR (PGE n.d.)
Renewable Energy Integration Opportunities
Updated interconnection
standards and processes
Update standards and processes to conform
with IEEE 1547-2018 and activate full
capability of DER inverters.
MN (MN PUC n.d.)
Refer to the Interconnection and Net
Metering chapter of the Guide for additional
information.
DER potential studies
Investigate the potential of individual and
DER bundles to meet system needs while
reducing renewable curtailments.
CA, Tennessee Valley Authority (TVA
2020), Bonneville Power Authority
(BPA 2019)
Expanded balancing area
Study the benefits and costs of participating
in a larger market such as an EIM or
RTO/ISO to better accommodate and or
increase renewable energy.
Western EIM (Western EIM n.d.)
New and Enhanced Planning
Grid modernization proceeding
Convene or initiate a proceeding to plan for
and implement grid modernization.
CA, HI, OR, MA, OH, (LBNL2020)
MD (MD PSC n.d.), DC (DCPSC n.d.)
Hosting capacity analysis
Require utilities to analyze and communicate
distribution system's ability to accommodate
new DER at specific locations without
upgrades.
DC (Pepco n.d.), CA, HI, MN, NV, NY
(IREC 2018), CT (PURA 2020)
Refer to the Interconnection and Net
Metering chapter of the Guide for additional
information on HCA.
Non-wires alternatives
Evaluate combinations of DER as a potential
cost-saving alternative to grid infrastructure
investments on a pilot or routine basis.
AZ, ME, NY (LBNL2021), Rl
(Rl H. 8025 2006)
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Policy
Description
State Examples
Integrated Distribution System
Planning
Institute a transparent process requiring
utilities to periodically file long-term
distribution system plans.
CA, Ml, MN, NV, NY (LBNL 2020)
Note: State examples provide a sample, not an exhaustive list.
Designing Effective Policy to Maximize Grid Investments
Efforts to advance grid modernization involve many participants and depend on highly technical design issues.
Some states and utilities are reconsidering who participates and expanding communication about different
aspects of grid modernization.
Participants
Many participants are involved in policy design associated with grid investments. Key players include:
• State executive and legislative bodies. At the state level, the governor's office, state legislature, and state
energy offices are often involved in policy- and goal-setting that includes or is facilitated by modern grid
investments. Depending on how utilities are regulated by their state and the issue at hand, state
legislatures may become involved in modifying existing legislation to accommodate modern grid
investments. For example, state energy efficiency resource standard legislation may be created or revised
to include grid-side efficiency investments.
• State electric utility regulators/utility boards. Utility regulators and boards of municipal or cooperative
utilities oversee goals, investments, planning processes, and ratemaking for electric utilities. Most of this
oversight is found in regulatory proceedings, including those for modern grid investments. These
proceedings may approve pilots, define which resources count toward energy efficiency resource
standards, determine AMI investment, or modify rate structures. For investor-owned utilities, regulators
also deliberate on a range of topics—such as transmission and distribution capital plans and planning
standards—through periodic general rate case proceedings. Utility regulators and oversight boards are
faced with new challenges as the volume and complexity of proceedings increase.
• Electric utilities. Electric utilities are the primary purchaser of modern grid technologies and need to make
the internal and external business case for modern grid investments while also responding to regulatory
mandates or board directives. In the changing landscape of modern grid technologies and operations,
utilities are often concerned about investing in technologies that may become obsolete before their costs
can be fully recovered. Utilities may also seek compensation between rate cases for lost revenues
associated with reduced electricity use due to grid-side energy efficiency or increased customer reliance
on distributed generation (including renewables). While utilities have the expertise to execute grid
modernization initiatives, absent permission or guidance from their regulators, their tendency may be to
avoid risk or delay deployment. Some states have used a test bed approach to allow some managed risk in
the interest of innovation (refer to the Regulatory Sandbox text box). Because of their ability to reach
every customer, utilities are well suited to ensure equal customer opportunity and access to technology
programs and equal realization of the benefits. Utilities also have an interest in the size, location, and
operation of DERs on the distribution grid due to their responsibility and accountability for the system's
safety and reliability.
• Regional transmission organizations (RTOs)/independent system operators (ISOs). Regional balancing
authorities coordinate the transmission of electricity across states. In some areas of the country, where
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wholesale markets are
restructured, this coordination
takes place through
organizations known as ISOs or
RTOs. Approximately two-thirds
of U.S. electricity demand is
served in RTO regions17 (FERC
2021a). RTOs/ISOs use long-
term planning to identify
effective and cost-efficient ways
to ensure grid reliability and
system-wide benefits.
Coordination and cooperation
between utilities, utility
regulators, and RTOs/ISOs is
often required to advance
energy efficiency and renewable
energy integration goals in grid
modernization.
• Consumer advocates,
community-based organizations,
and environmental advocates.
Groups representing consumers,
environmental interests, and
other public interests are often
involved in offering technical
expertise as well as public
perspectives. Equitable outreach
strategies for groups that have
not historically participated in
proceedings include holding
proceedings at times outside of
traditional working hours, at locations that are transit-accessible, with translation services, and with the
option to receive financial compensation for time invested providing input for the policy. Some consumer
advocates may support policies that help to maintain low rates and ensure equitable treatment of all
customer classes. Environmental advocates may promote topics such as pursuit of all cost-effective energy
efficiency, robust funding for traditional energy efficiency programming, or transmission and distribution
investments to support renewable energy integration. Some organizations may have an interest in privacy
and data access issues associated with AMI, as well as alignment of utility business models are with public
interest goals. Customer engagement will vary by customer size and class and/or interest in key issues such
as rate impacts and pricing structures, power quality, ability to participate in providing demand response
and other grid services, renewable energy, and data access and privacy. In general, it is advisable to
17 In the rest of the country, which operates in the traditional vertically integrated utility model, the same entity (a utility) is
responsible for electricity generation, transmission, and distribution to retail customers within the utility's defined geographic
service area and with oversight by utility regulators at the state level. For more background, refer to the Overview of Electric Utility
Policies chapter of the Guide,
Regulatory Sandboxes: Expeditious Pilots
A regulatory sandbox is a program or regulatory structure that offers
regulated utilities and potentially unregulated entities to try innovative
solutions to challenges with fewer administrative requirements than pilots,
enabling faster innovation and results. Sandboxes can enable innovative
ways to increase DER integration, such as using electric vehicles as
storage assets or improving distribution system efficiency. The sandbox
approach can involve new technologies or dynamic programs. Participants
may test streamlined or expected approval processes, removing
contacting or procurement requirements, or providing assurances for cost
recovery. Below we highlight two examples:
Hawaii Pilot Process. In 2018, Hawaii Public Utility Commission
implemented a new process to "foster innovation with an expedited
implementation process" to test new technologies, programs, and
business models for larger scale implementation. The approach exempted
companies from the traditional restrictive contract bidding and selection
processes and relieved them of some administrative reporting burdens.
The program caps costs at $10 million and incorporates them into a
revenue requirement of an annual review process, rather than addressing
them in separate mechanism that would need to be justified and iitigated.
Portland General Electric (PGE) Smart Grid Test Bed. The Oregon
Public Utility Commission authorized PGE's Test Bed project in the utility's
2016 Integrated Resource Plan. The project was designed to test and
learn from innovative demand response resources that could be
developed to eventually replace generation resources. The Commision
authorized the use of technology and customer incentives to achieve their
goals. PGE's efforts evolved into the Smart Grid Test Bed, and in 2021,
the Department of Energy selected PGE for a $6 million grant to renovate
500 buildings in historically underserved neighborhoods with the goal of
reducing energy burdens through energy efficiency and connected
devices. As part of the program, PGE offers customers a a rebate and
montly credits for connecting their battery to the grid as part of the Smart
Battery Pilot.
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provide customers with proactive education and outreach on the installation of AMI meters and any
changes to billing or rate structures.
• Vendors and service providers. Vendors of smart grid technologies and software may be called on to
provide expertise during public proceedings, to respond to formal requests for information or proposals
from utilities or states, or to participate directly in public dialogue to advance the interests of their
organization. Service providers that acquire and aggregate demand response and distributed solar
resources may be interested in regulatory proceedings that will affect how distributed resources will be
valued and compensated by regulators, utilities, and capacity markets. Other service providers, such as
those wishing to offer integrated home energy management services, may be interested in data access and
privacy issues.
Key Design Issues and Constraints
Many existing policies affecting electricity generation, transmission and distribution, renewable energy, and
demand-side management (e.g., energy efficiency and demand response) have been designed independently
from one another. As a result, programs are often planned and managed by different departments within a
utility—each with unique expertise and regulatory drivers. Successful planning and management of modern
grid investments to achieve broader energy efficiency and renewable energy benefits requires some
integration of utility functions and policy goals to achieve the multiple objectives of grid modernization. Key
considerations during the design of state policies for modern grid investments include:
• The prudent level of investment considering the state of the market, local conditions and system needs,
existing investments, the availability of funding (e.g., federal grants), and experience with key
technologies.
• How the need to engage multiple functional departments within a utility will affect timing and success.
• The best way to gain operational experience using modern grid technology to maximize energy efficiency
benefits and distributed resource integration.
• When, where, and how to take proven pilot initiatives to scale.
• How to apportion costs given the multiple benefits of technologies and practices.
• How to balance customer rates and utility revenue requirements.
The following section provides more information on these key policy design considerations and constraints
that states and utility regulators can consider when providing oversight for grid investment processes and
strategies.
Evaluating Current Systems and Future Needs
Before making investment decisions, representatives from multiple departments within a utility meet to
discuss existing system assets and operations, anticipated future system needs, the purpose of pilots, and key
design considerations (refer to the Implementation, Oversight, and Evaluation section in this chapter). During
this phase, participants review technical data about the system such as the configuration of the distribution
system and substations; equipment ratings; historical data on usage, voltage, costs, reliability, and risk; and
current operating criteria and practices such as how temperature is monitored and controlled at the
transformer to avoid overheating and to extend equipment life. State and federal regulatory requirements also
are discussed to ensure a clear understanding of what various parties are legally required to do and to identify
any regulatory issues, such as how property rights for new assets will be assigned, that will require further
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legal review or action. Utility regulators are not normally involved at this stage but can influence whether such
evaluation occurs. For example, regulators can require an assessment of grid-side energy efficiency potential
or request utilities to consider pilots to deliver grid-side efficiency or to improve the integration of distributed
renewables.
Gaining Operational Experience
Most utilities conduct pilots or use a regulatory sandbox (refer to the Regulatory Sandbox text box) to gain
experience with new technologies and operational practices before making larger-scale investment. Many
utilities have gained operational experience with one or more modern grid investments through participation
in Federal Smart Grid Investment Grants and Demonstration Programs, as well as through demonstration
projects in partnership with the Electric Power Research Institute (refer to the Interaction with Federal
Programs and Regulations section and the Information Resources section, respectively). Pilots and
demonstration projects may be subject to regulatory or board approval. During pilots, it is helpful to establish
clear objectives, milestones, and a process for reviewing progress and tracking actual costs and benefits. With
proven costs and benefits from a real-world pilot, the business case for full deployment gains credibility for
approvals within utilities and with regulatory bodies.
Making the Business Case
When evaluating the benefits of investing in modern grid technologies and related changes to operations and
management, state policymakers, utility regulators, and utilities have found it helpful to apply a
comprehensive benefit-cost analysis that accounts for the benefits, costs, and risks associated with some of
these investments.
Note that costs and benefits will vary by location and specific operating situations. The same technology can
have a different implementation cost and benefit in a rural area with low customer density than in an urban
area with high customer density and significant commercial loads. Service territories need to be examined by
similar groupings of circuits, which can then be separately analyzed for costs and benefits, and the analysis
should account for how modern grid investments are managed as well as how they interact with one another.
For example, investment in one technology can help avoid costs in the implementation or operation of another
technology. In addition, investment in technology may provide a limited benefit unless it's managed to specific
objectives such as energy efficiency or increased DER integration. Some states are using system controls,
monitoring devices, and communications and automation tools (refer to the Tools for a Modern Grid text box),
which enable increases in distribution grid efficiency, and reduce the cost to integrate clean energy. The
National Standard Practice Manual for Benefit-Cost Analysis of Distributed Energy Resources (NSPM for DERs)
provides methodologies and principles for jurisdictions to assess and compare the cost-effectiveness of energy
efficiency - including distribution system efficiency - and other DERs. NSPM for DERs was designed to help
make the business case for clean energy integration (NESP 2020).
The Bonneville Power Administration (BPA), which operates the federal power and transmission grid in pacific
northwest states, summarized its business case for each of the 35 strategic grid modernization projects in
2022. The project summaries explain how the investments reduce future costs, create new market
opportunities, and support increases in system efficiency and reliability. One anticipated benefit of the load
and renewable forecasting project is more accurate, consistent forecasts, which could reduce the cost of water
management within the federal hydropower system (BPA 2022b).
Funding and Cost Recovery
Electric utility regulatory frameworks and financial incentives have a strong influence on utility investment in
modernizing the electric grid. The traditional utility cost of service regulation model creates financial incentives
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for regulated utilities to maximize the volume of electricity sales (throughput incentive) and use capital-
intensive solutions to meet grid needs (capital bias). Some state regulators have established or reinforced
policies to help curb the throughput incentive and capital bias, ensure clean energy program cost recovery,
and define shareholder performance incentives (refer to the Electric Utility Regulatory Frameworks and
Financial Incentives chapter of the Guide). In many parts of the country, utilities are years away from
experiencing significant revenue impacts from the high penetration of distributed renewables or grid-
controlled energy efficiency, but some states with higher renewables penetration and/or a strong interest in
improving grid resiliency to respond to increasing severe weather events have begun to discuss an evolving
utility business model in the context of grid modernization (refer to the State Examples section in this chapter).
Utilities and their regulators are evaluating how to fund modern grid investments, absent a full rate case, since
transmission and distribution planning investments are typically recovered through rates. Additional or
unforeseen investments in grid technology require utilities to risk that these investments will not be recovered
through future rate cases. Other issues include ensuring that benefits are widely distributed among customers
and whether regulators will compensate utilities for lost revenues when the modern grid investment delivers
end-use energy efficiency benefits to customers.
Interaction with Federal Programs and Regulations
A range of federal initiatives and regulations, including FERC orders, are relevant to state grid modernization
planning and investments. State utility regulators oversee local electricity distribution and in-state
transmission while FERC has authority over interstate electricity transmission. In addition to FERC activities,
federal agencies and national laboratories conduct research and support the development of grid technologies
and implementation of state planning efforts. Relevant and recent FERC orders are summarized as follows:
• Public Utility Regulatory Policy Act (PURPA) requires that utilities allow interconnection by qualifying
facilities. States have significant flexibility in administering PURPA, although amendments made in 2005
and several subsequent FERC decisions have affected the applicability of PURPA in some regions (FERC 132
2010) In 2020, FERC amended PURPA through Orders 872 and 872-A in response to the many changes in
the energy landscape in recent decades. Some of the changes gave state regulators more flexibility, for
example, by allowing states to incorporate market forces in establishing avoided cost rates for qualifying
facilities (FERC 2020d; 2020c). Refer to the Interconnection and Net Metering chapter of the Guide for a
more detailed discussion of PURPA.
• FERC Order 792 addresses storage interconnections. In 2013, FERC updated the Small Generators
Interconnection Procedures (SGIP) through Order 792. Among other changes, these updates added energy
storage to the list of resources eligible to interconnect under FERC procedures. States may want to
consider how state interconnection standards accommodate storage assets and how they interact with
existing FERC orders (FERC 2020a). While FERC's updates are not binding for states, they can provide useful
models for establishing provisions that anticipate and enable higher DER penetration.
• FERC Order 841 advances energy storage. In 2020, the U.S. Court of Appeals for the D.C. Circuit upheld
FERC Order 841 and in doing so removed market barriers to energy storage. Order 841 permits energy
storage to compete with traditional fossil fuel generators in wholesale power markets.
• FERC Order 2222 enables DER aggregation. In 2020, FERC Order 2222 enabled DER aggregators to compete
in each of the regional organized wholesale electric markets. This action further authorizes DER resources
to participate in the regional markets for capacity, energy, and ancillary services, alongside traditional
resources. Multiple distributed resources that are bundled together, such as in a VPP, can satisfy minimum
size and performance requirements that they might not meet individually (FERC 2020b). In a 2021
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rehearing of Order 2222, FERC ruled that demand response can combine with other aggregated DERs, and
that grid operators may not forbid the participation of demand response (FERC 2021b).
• FERC Order 745 requires wholesale market operators to compensate energy efficiency and demand
response providers at the same rate as electricity generation (FERC 745 2011). In 2016, the U.S. Supreme
Court ruled that FERC acted within its authority to regulate interstate wholesale markets, allowing Order
745 to take effect and for demand response to compete with all electricity resources in the wholesale
market (RMI 2016).
The federal government also provides funding for projects that catalyze grid modernization. Examples include:
• The U.S. Department of Energy (DOE) Connected Communities program provides funding to projects for
"grid-interactive efficient buildings" that deploy DERs and serve as assets to the grid (DOE n.d.). DOE and
its national laboratories also produce research, policy evaluation, technology development, and innovation
in grid modernization, in areas such as inverters for the future electric grid, and sensors and controls for
grid-interactive loads. In addition, the Energy Act of 2020 advances grid modernization goals by
establishing an energy storage and microgrid grant and technical assistance program at the DOE. This
program aims to help rural electric cooperatives and public utilities design storage and microgrid projects
that incorporate renewable energy, improve system reliability, and support resilience (US H.R. 133 2020)
• The Infrastructure Investment and Jobs Act, known as the Bipartisan Infrastructure Law (BIL), provides $62
billion to be administered by DOE "for investment in energy infrastructure that can support a pathway to a
clean, yet resilient and equitable energy future." This includes enhancing the reliability, resilience, and
efficiency of the electric grid (NETL n.d.).
• The Inflation Reduction Act (IRA) provides significant incentives to encourage clean energy development as
well as transportation electrification and efficient electrification of homes and buildings, both of which will
impact electricity demand and related utility planning efforts. The IRA provides tax credits for net-zero
emission generation and energy efficiency improvements, funds states' greenhouse gas reduction planning
and implementation, creates a $27 billion Greenhouse Gas Reduction Fund, and funds programs and
groups advancing environmental justice (EPA 2022a).
EPA also provides multiple resources that identify federal funding opportunities for green infrastructure
investments, many of which support energy sector projects.
Interaction with State and Local Programs
States and municipalities can use policy levers and establish programs to advance and support modern grid
investments, which frequently interact with and advance other priorities such as reducing costs, improving the
environment, promoting innovation, and enhancing reliability. One step that states and municipalities can take
is to determine whether existing energy efficiency resource standards and savings targets allow investments in
modern grid technologies to count towards compliance (refer to the Energy Efficiency Programs and Resource
Standards chapter of the Guide). Jurisdictions can similarly examine renewable portfolio standards and other
renewables policies to identify opportunities to simultaneously advance demand response and flexible loads
(refer to Electricity Resource Planning and Procurement and other chapters of the Guide). Another step that
states and municipalities can take is to assess and expand the deployment of customer information programs
that use AMI data to improve energy efficiency deployment and encourage energy-saving behaviors. For more
on states that are using and protecting customer data and deploying AMI to realize the benefits of energy
efficiency, refer to other chapters of the Guide such as Interconnection and Net Metering, Customer Rates and
Data Access.
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Implementation, Oversight, and Evaluation
Implementation
Engaging senior leadership and multiple operating units within a utility is often critical to the success of efforts
to deploy, manage, monitor, and evaluate programs or initiatives that leverage grid modernization
investments for load reduction, energy efficiency, and other DER integration. Utilities have cited the
importance of deepening coordination across departments as a key step for success. It is helpful for states and
their utility regulators to understand these operational complexities in setting realistic timeframes for pilots or
larger-scale deployment. The following are examples of how different operating departments within a utility
may be engaged in modern grid deployments or pilot initiatives:
• Electric distribution operations staff are directly engaged in planning and operations. They know critical
system data; understand the mix of residential, commercial, and industrial customers along various
feeders; and are responsible for ensuring that grid operations deliver expected services within allowable
voltage levels.
• Electric forecasting departments are instrumental in understanding and planning future load
requirements, including seasonal, peak, time-of-day, or customer class impacts.
• Energy efficiency and demand-side management program staff are interested in the implications of grid-
side efficiency programs and the potential to count customer impacts toward program goals. As such, they
provide valuable insights on how to track and monitor costs and benefits.
• Key account managers are usually engaged in any demonstration that could potentially affect service to
large customers or customer groups.
• Customer call centers and billing departments manage customer contact, usage history, and other
information necessary for pilot design and measurement, depending on the project being implemented.
They are often a first point of contact for any service or billing accuracy complaints, such as those
associated with new AMI meter deployments
• Regulatory and public affairs staff become involved in developing the strategy for raising customer
awareness of new technologies, making the business case for implementing modern grid investments, and
engaging in related regulatory proceedings.
Oversight
The oversight of utility distribution system modernization efforts is primarily through the state utility regulator
or board, depending on utility type (RAP 2016). The regulator or board generally approves capital investments,
establishes the policies that govern investment and operation of the electric grid, and ensures fair treatment
and equity between the ratepayer and the utility and among ratepayers.
Decisionmakers generally have both formal and informal options available for oversight. For example, formal
utility regulatory processes are often handled through dockets with evidence-based hearings and
opportunities for public comment. These formal processes are generally used to approve or disapprove a
specific grid investment proposal. For a deeper exploration of the pros and cons of a range of grid
modernization options, oversight organizations—on their own or at the request of interested parties—may opt
to initiate an informal process, such as workshop or stakeholder collaboration. Informal proceedings may be
an alternative option but they are authorized or limited based on state statute. Informal processes may lead
to formal processes, but in the meantime, they allow decisionmakers to engage and learn without the
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limitations associated with rules of evidence, enabling a deeper exploration of the advantages and
disadvantages of the full range of opportunities.
Evaluation
Utility regulators in some states are requiring evaluation of modern grid investments. This includes estimating
the potential for grid investments to achieve energy savings and other benefits, as well as conducting
evaluation, measurement, and verification (EM&V). These evaluation approaches are already in place for most
demand-side energy efficiency investments. The goals of evaluation for modern grid technologies are the same
as for existing efficiency programs: understanding the magnitude of savings and other benefits under different
scenarios, while ensuring that publicly funded technologies are operating properly and achieving critical
electricity reliability, cost savings, and other policy goals. While the specifics of how evaluation is applied may
differ slightly for each grid technology, establishing such approaches ensures that key processes and impacts
are assessed in a manner that is robust, transparent, and well documented. A CVR example is provided in this
section, along with key EM&V resources.
Conservation Voltage Reduction (CVR) Evaluation Example
• Estimating potential. The potential of CVR to deliver energy efficiency to customers will vary by circuit. It is
typically estimated by examining groups of circuits in a service territory that are similar in length, voltage
levels, customer class, and other technical characteristics. Utilities typically conduct modeling to inform
which circuits are best suited to voltage management. Once operational experience is gained on a range of
circuits, utilities can understand and target high-value circuits for future deployments.
• Developing tracking metrics and systems. Evaluations of modern grid technologies can be complemented
by developing tracking metrics and systems in advance of deployment. In the case of CVR, such metrics
and systems are critical to managing the data generated at each phase of deployment, from assessing the
impacts of pilot projects, to oversight of established programs, to retrospective evaluation and EM&V. The
most effective CVR tracking metrics and systems are typically informed by a clear understanding of the
multiple objectives of a CVR project or program. Data tracked may include technical performance, such as
customer counts by circuit or transformer, historical load or energy usage, as well as interval energy and
voltage data. Equity metrics are another way to measure success in terms of the distribution of benefits of
grid investments. These metrics are useful for identifying target populations (such as a measure of
program accessibility), making decisions about investments (such as a measure of workforce impact), and
assessing program impact (such as a measure of energy burden change) (PNNL 2021b). Within its new
performance-based regulation (PBR) framework, the Minnesota Public Utilities Commission (PUC)
identified metrics for the utility Xcel Energy to track reliability and customer service by geography, income,
and other key equity benchmarks. In their 2019 order, the MN PUC directed the application of equity
metrics to modern grid technologies, which could apply to the state's CVR investments (MN PUC 2019). For
more information on performance metrics, refer to the Electric Utility Regulatory Frameworks and
Financial Incentives chapter of the Guide.
• Establishing baselines. As with other customer-side energy efficiency investments, establishing credible
energy-usage baselines is critical to estimating program impacts. Since weather and season affect
customer energy use, CVR baselines are typically established by cycling voltage control on and off for a
sufficient duration at different times throughout the year. Depending on system type, utilities usually
follow either a day on/day off or week on/week off protocol. Because data gained from these operations
are often used as proxy data for other system-wide planning efforts, it is important that they be regularly
refreshed. For example, if a particular circuit experiences rapid load growth, the usefulness of its data for
broader estimation purposes will quickly be reduced.
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• Assessing benefits and costs. As discussed previously, it can be beneficial to understand the additional
costs, savings impacts, and other benefits that can be realized from modern grid technology versus
traditional approaches. For example, CVR can be implemented in tandem with conventional grid
technology, however, additional energy savings that is realized when implemented with modern grid
technologies. It is also important to include difficult-to-quantify benefits such as increased operational
confidence that come from modern grid investments.
• Understanding how benefits are allocated. With modern grid technology, customers can increasingly
consume and generate electricity, benefit from and provide grid services, and participate actively or
passively in energy efficiency and demand response programs. As a result, utilities and regulators are
examining opportunities to track costs and benefits at a more granular level. Depending on the policy and
regulatory environment, the distribution of impacts can vary—either between ratepayers and the utility,
or among different ratepayer groups. The use of multiple methods can help establish these distributional
impacts. For example, comparing CVR impacts at the substation to CVR impacts at the customer meter, in
combination with engineering simulations, is a useful approach for estimating the proportion of energy
savings realized by the customer (compared to the energy savings the utility will realize from operational
improvements).
Evaluation Resources
For additional information, EPA offers resources for state and local government staff on EM&V for energy
efficiency policies and initiatives. Also, the State and Local Energy Efficiency (SEE) Action Network maintains an
EM&V Resource Portal that identifies and describes the key EM&V techniques for DERs, including energy
efficiency and demand flexibility. The SEE Action Network also describes five important considerations when
assessing the performance of buildings that participate in demand flexibility programs: assessment objectives,
defining boundaries of an assessment, performance metrics, how the metrics will be calculated, and reporting
requirements (SEE Action 2020).
For utilities interested in gaining energy efficiency credit for grid-side efficiency programming, use of a third-
party evaluator will be beneficial for making the case to their oversight authority. Many states require use of
third-party evaluators for energy efficiency program impact evaluations.
Action Steps for States
State policymakers and utility regulators seeking to advance grid modernization to achieve affordability,
resilience, and clean energy benefits and to better accommodate growing renewable resources may consider
the following actions:
• Convene a stakeholder process. Understanding the perspectives of multiple stakeholders will become
increasingly important as grid modernization efforts mature and distributed resources become more
prevalent. Stakeholders may benefit from tracking the proceedings of leading states from their region and
around country to gain insights on emerging issues.
• Assess the potential for additional grid-side efficiency. Grid-side energy efficiency has not historically been
included in the energy efficiency potential studies that quantify the magnitude of efficiency that is
achievable, cost-effective, and/or technically feasible. States can include grid-side efficiency deployments
such as CVR in existing potential studies, or in a standalone analysis.
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• /Assess and pursue additional opportunities for clean energy integration. States can facilitate DER
integration by using inverters to support voltage and reactive power management, accelerating the use of
smart inverter functionality to support real-time grid management, and complementary deployment of
demand response and storage assets.
• Integrate grid investments in new or enhanced resource/procurement planning. Including modern grid
investments in routine utility planning efforts, such as integrated resource plans and integrated
distribution plans, can increase operational confidence in grid-side energy efficiency, demand-responsive
resources, and the ability of the distribution system to integrate and benefit from distributed generation
and storage. As such, these resources deserve increased attention in long-term integrated resource and
procurement planning efforts. For more information, refer to the Electricity Resource Planning and
Procurement chapter of the Guide.
• Review and modify existing policies to encourage investment. Stakeholders interested in expanding the
role for modern grid investments can review existing utility policies to determine whether they
inadvertently inhibit modern grid technologies, and whether modifications or amendments are needed to
facilitate additional investment. For example, utilities have found that crediting customer-side savings
from CVR as part of their energy efficiency resource standards can incentivize additional deployment.
Similarly, utilities in territories with "decoupling" policies in effect are neutral to the revenue losses from
reduced sales associated with both CVR and customer-sided renewables. In addition, newer performance-
based regulations can incentivize (and remove disincentives for) utilities to employ customer and third-
party owned distributed resources (refer to the Electric Utility Regulatory Frameworks and Financial
Incentives chapter of the Guide).
• Conduct pilots. Pilots can help utilities gain operational knowledge and an understanding of costs and
benefits prior to broader implementation.
State Examples
Connecticut
Connecticut has taken several steps to modernize its
electricity grid. In 2019, the Connecticut Public Utilities
Regulatory Authority (PURA) established the Equitable
Modern Grid Framework to foster innovation in solving grid
challenges including hosting capacity, and exploring new
opportunities like electric storage deployment, while also
promoting equitable outcomes. The Framework is a four-
phased process that includes deep dive investigations into
eleven near-term topics with the objective of collectively
and comprehensively growing Connecticut's green
economy, cost-effective decarbonization across all sectors,
improving grid reliability and resilience, along with
cybersecurity, and enhancing affordable service for
underserved communities. PURA initiated formal
investigations into all eleven topics between the fourth
quarter of 2019 and the fourth quarter of 2022, as has
completed nine of those investigations as of November 2022
(PURA 2021b).
Connecticut Highlights Efforts to Develop
an Equitable Phased Grid Modernization
For more information, refer to the following:
• PURA Framework for an Equitable Modern
Grid
• Energy Storage Solutions Program
® PURA-Approved Clean Energy Programs
• Low-Income Heat Pump Water Heater Pilot
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The Framework process addresses many topics, from interconnection transparency and best uses of hosting
capacity maps to electric storage and light-duty electric vehicle program design. Within both the electric
storage program (or Energy Storage Solutions Program) and the light-duty electric vehicle charging program (or
EV Charging Program), PLIRA has incorporated equity into its objectives by prioritizing increased resilience
and/or financial benefits for low- and moderate-income customers in environmental justice or economically
distressed communities (PURA 2021a). Specifically, both programs include incentive adders above the typical
program compensation for low- and moderate-income customers, with additional measures to encourage
deployment of energy storage resources on distribution circuits impacted most by extreme weather. PURA has
updated the interconnection standards (PURA 2020) and the regulatory guidance to incentivize electric energy
storage (PURA 2021a). One initiative-the Innovative Energy Solutions (IES) program-will test technologies,
products, and services to help achieve the state's clean energy and climate goals (PURA 2022).
Relatedly, in 2020 PURA established new programs specifically for behind-the-meter applications of renewable
energy projects located on residential and commercial and industrial customers' premises. Both programs, the
Residential Renewable Energy Solutions (RRES) and Non-Residential Renewable Energy Solutions (NRES)
Programs, include provisions to promote the flow of benefits to low- and moderate-income customers
consistent with the Biden Administration's Justice4Q initiative. Specifically, the RRES Program includes financial
adders for both low-income customers and customers located in distressed municipalities. The RRES Program
also allows for direct payments between the electric utilities to project developers for the production from the
renewable energy project, eliminating the perceived issue for solar developers of low-income customer credit
worthiness. Similarly, under the NRES Program, which is conducted as a twice-annual reverse auction, includes
bid preferences for project that provide financial benefits to customers environmental justice communities
Connecticut's grid modernization planning and investments began prior to PURA's Framework. For example, in
2017, PURA approved the utility Eversource's spending proposal for HCA and mapping tools that facilitate DER
interconnections. The funding also supported an online portal to improve transparency and streamline the
utility's application and tracking process for customers and developers seeking to interconnect DERs to the
grid (Eversource 2017).
In 2018, the state's Department of Energy and Environmental Protection established a pilot program to
provide connected ENERGY STAR electric heat pump water heaters (HPWHs) to low-income households at no
cost (ACEEE 2019). At the time of the pilot, water heaters were the second highest source of home energy use
and ENERGY STAR HPWHs had potential to reduce energy costs associated with water heating by up to 50
percent (ACEEE 2019). The pilot evaluated 108 homes, installed 65 HPWHs, and generated over $91,000 in
yearly savings for the installed HPWHs (ACEEE 2019).
New York
New York has taken a series of planning and investment steps to establish policies and frameworks to ensure
that its transmission and distribution infrastructure can reliably and cost-effectively support clean energy
resources. The state has adopted policy to ensure grid modernization activities are aligned with its state clean
energy and climate goals established in its Climate Leadership and Community Protection Act (CLCPA) (NY S.B.
6599 2020). Recent state actions require utilities to consider NWAs before developing traditional grid
solutions, including policies to support locational value for DERs and the development of an Integrated Energy
Data Resource (IEDR) (NY PSC 2021; 2019; NYSERDA 2021).
In 2020, New York passed the Accelerated Renewable Energy Growth and Community Benefit Act, which
creates a State Power Grid Study and Investment Program (NYSERDA 2020), This Act requires the New York
Public Services Commission (PSC) to use the findings of the Power Grid Study to support the identified needs
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for transmission and distribution system upgrades and
planning necessary for, and aligned to, the goals established
in the CLCPA. The Accelerated Renewable Energy Growth and
Community Benefit Act creates an approach to accelerate
grid infrastructure planning and construction to ensure
renewable energy integration, while using input from, and
providing benefits to, local communities (NYSERDA 2020).
New York's NWA policy has roots in the PSC's foundational
"Reforming the Energy Vision" (REV) initiative, introduced in
2014, which proposed transformative changes to the state's
energy industry and regulatory practices (NY PSC 2Q14b). The
REV framework helped advance the role of the utility as a
distribution platform company and encouraged customers
and third parties to partner with utilities in modernizing the
distribution grid and integrating clean energy (NYSERDA
n.d.). REV required utilities to identify at least one NWA
project and allowed utilities to propose NWA investments in
lieu of traditional system upgrades. For this REV NWA
program, the PSC adopted a regulatory framework and
implementation plan (NY PSC 2015).
The REV initiative built upon a 2013 rate case settlement in
which the PSC required a utility to achieve demand reduction
goals through investment in NWAs. The PSC directed the utility ConEd to develop the Brooklyn Queens
Demand Management (BQDM) program to mitigate the projected increases in electricity demand in Brooklyn
and Queens (NY PSC 2014c). The program required a reduction of 69 megawatts (MW) of peak demand
through 41 MW of customer-side energy reduction, 11 MW of utility-side reductions, and 17 MW of traditional
solutions (NY PSC 2014c). By 2021, the BQDM program had saved over 59 MW of peak of generation (ConEd
2021b). Through the success of the BQDM program, the PSC approved an extension in 2017, which allowed
ConEd to continue the program but not exceed the initial $200 million cap on program expenditures (NY PSC
2017). Since the development of the BQDM program, other utilities in the state have made investments in
NWAs (Joint Utilities n.d.).
The New York PSC also developed the Value of Distributed Energy Resources (or "Value Stack") methodology,
which compensates DER customers based on several characteristics, including the demand reduction value and
locational benefit of the energy resource (NY-SUN n.d.). The NY PSC issued an order in 2017 that provides a
framework for establishing the value of a particular DER using the Value Stack (NYPSC 2017). Projects are also
eligible for credits that recognize other benefits, such as avoided emissions (NYPSC 2017; NY-SUN n.d.). The
PSC restricted the eligibility of the credits based on regional capacity limits with defined tranches (NYPSC
2017). The NY PSC updated the Value Stack order in 2019 to incorporate other compensation mechanisms,
including a Community Adder to incentivize projects in certain regions (NY PSC 2019). New York State has been
reviewing its compensation framework for the value of DERs and has been considering modifications in
response to critiques regarding how the regional capacity tranches affected project finance for DER projects
(NY-SUN 2021).
In addition to state policy developments and PSC actions that help maximize grid investments, the New York
State Energy Research and Development Authority (NYSERDA) funds smart grid opportunities to support DER
New York Has Developed Programs to
Encourage Non-Wires Alternatives,
Policies to Support Locational Value for
DERs, and a Framework to implement
an Integrated Energy Data Resource
A
For more information, refer to the following:
i New York Power Grid Study - Initial Report
• New York - Non-Wires Alternatives
i NY-SUN - Value of Distributed Energy
Resources (Value Stack)
• NYSERDA - Integrated Energy Data
Resource (IEDR)
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integration and other grid technologies and has been involved in scoping and developing an IEDR. IEDR is a
new framework for data access that streamlines third-party access to customer usage and system data, which
is critical to many energy efficiency and demand response programs, including building energy benchmarking
(discussed elsewhere in the Guide). The IEDR is part of the New York State PSC Proceeding on Motion of the
Commission Regarding Strategic Use of Energy Related Data (NYPSC 2021).
Michigan
Michigan has pursued multiple policies to drive greater grid
integration of energy efficiency and renewable energy,
including a grid modernization initiative launched by its Public
Service Commission (PSC) and a climate executive order.
In 2019, the Michigan PSC launched Ml Power Grid initiative, a
three-phased approach to distribution and transmission
planning, to provide a transition to a cleaner energy grid (Ml
PSC 2021). Phase I focused on electric distribution planning and
included engagement of key stakeholders—utilities, customers,
and state agencies—to consider issues such as NWAs and
hosting capacity analysis for DERs (Ml PSC 2021).
In 2020, Governor Whitmer issued an executive directive that
ordered the Department of Environment, Great Lakes, and
Energy to require IRPs filed with the state's PSC to include an
analysis of their consistency with state emission targets and
adding the requirement to consider environmental justice and
health impacts (Ml ED 2020-10 2020). The PSC accepted
recommendations from a PSC staff report based on
stakeholder collaboration for the Ml Power Grid initiative to
ensure compliance with the executive directive and to include
more in-depth analysis of NWAs with IRPs (Ml PSC 2020).
Michigan Launched a Multi-year
Stakeholder Initiative, Power Grid, to
Integrate Higher Levels of Renewable
Energy and Energy Efficiency and
Maximize the Benefits of the State's
Clean Energy Transition
For more information, refer to:
• Ml Power Grid Initiative
• Phase I - Electric Distribution Planning
• Phase II - Integration of Resource/
Distribution/Transmission Planning
• Phase III - IRP filing requirements,
demand response study, and energy
waste reduction study
Phase II of the Ml Power Grid initiative addressed the integration of the IRP process with distribution and
transmission planning that is critical for utilities to meet the state's GHG and energy goals. In December 2020,
the PSC filed a report recommending two options for near-term filings for utilities in addition to what is
required for IRPs (Ml PSC 2020). The first option requires utilities to conduct modeling to show a path toward
achieving 28 percent carbon reduction by 2025 relative to 2005 with a 2 percent annual load growth rate (Ml
PSC 2020). The second option, which responded to stakeholder feedback for more aggressive decarbonization,
requires utilities to model a 32 percent carbon reduction by 2025 relative to 2005 levels, assuming a 2 percent
annual load growth rate (Ml PSC 2020). Phase III of the Ml Power Grid initiative focused on IRP parameters and
filing requirements, and included energy waste reduction and demand response potential studies and ongoing
IRP cases (Ml PSC 2022).
Pacific Northwest
States in the pacific northwest coordinate their electricity system planning and contribute to grid investments
in multiple ways. State utility regulators oversee the electric utility companies' planning for the operation and
maintenance of distribution systems and authorize programs such as utility pilots that involve the regional
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transmission service provider, Bonneville Power Authority
(BPA). BPA invests in transmission grid projects including those
that support system energy efficiency and demonstrate grid
integration of new technologies
Under the Pacific Northwest Electric Power Planning and
Conservation Act (Act), Idaho, Montana, Oregon, and
Washington formed a council - the Northwest Power and
Conservation Council - for the purpose of developing the
Northwest Power Plan (Plan), a 20-year electric plan that is
revised and updated with public input every 5 years. The plan
promotes collaboration with the regional Western electric grid
to amplify cost savings and system efficiency (NWPCC 2021a).
Congress passed the Act in 1980 and revised it in 2011 (16
U.S.C 839~839h 2011). In addition to grid efficiency, the Act
promotes power reliability, public participation, and regional
management of the hydropower dams and their impacts on
the environment and wildlife (NWPCC 2021b). The Council's
2021 Northwest Power Plan is the eighth update to the Plan,
and it prioritizes acquisition of cost-effective energy efficiency
and cost-effective renewable energy. The Act requires BPA, a
self-funding federal power marketer and transmission service
provider in four northwest states, to acquire all necessary
energy resources, ensure energy efficiency, and deploy
renewable energy (NWPCC 2021b). BPA makes grid
investments in a variety of categories—including voltage
optimization and distribution transformer replacements, NWA, and demand response through connected
products, summarized as follows:
Grid modernization. BPA invests in a range of grid projects to improve reliability and modernize assets and
operations (BPA n.d.). In 2022, BPA had a modernization project portfolio of at least 12 completed projects and
another 20 grid upgrades in progress (BPA 2022a). Certain grid modernization projects were prerequisites for
BPA's participation in the Western Energy Imbalance Market (EIM), which BPA joined in May 2022 (BPA 2020;
2022c). The EIM is a centralized, real-time energy market that helps address and balance energy fluctuations
across the power system systems of participating entities. Participation in the Western EIM, which is operated
by the California Independent System Operator, provides BPA with additional grid management tools such as
Bid and Base Scheduling (BPA 2022c; n.d.).
Distribution system efficiency. BPA acquires energy savings from the distribution utilities that it serves through
a portfolio of energy efficiency programs, which include improvements to the electric grid. Voltage
Optimization and replacement of distribution transformers with high efficiency transformers are two included
measures (BPA 2021).
Non-wires alternatives. An early pioneer of the concept, BPA investigates NWA and other tools that can help to
defer or avoid a major transmission infrastructure investment (ACEEE 2018). After substantial research and
analysis of the construction of a 79-mile, $700 million high-voltage transmission line in Washington and
Oregon, BPA canceled the project, based in part on NWA and grid congestion management tools (PNNL 2018;
LBNL2021; BPA 2017).
Pacific Northwest states of Washington,
Oregon, Idaho, and Montana are
coordinated in their investments in grid
modernization, voltage optimization,
distribution transformer replacements,
NWA, and demand response.
For more information, refer to:
• Northwest Power Conservation
Council's "Council Brief 2021"
• Bonneville Power Administration's
Grid Modernization information
resources
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Connected products. BPA participates in pilot projects on emerging technologies to mitigate peak loads and
inform future investments. For instance, BPA teamed with DOE's Pacific Northwest National Laboratory
(PNNL), the Northwest Energy Efficiency Alliance (NEEA), Portland General Electric, and other northwest
utilities to study CTA-2045, the demand-response control technology,18 and demonstrate and evaluate the
load-shifting and energy storage potential of heat pump water heaters. The study involved recruiting
customers to test their electric resistance or heat pump water heaters, installing communications on the CTA
2045-equipped water heaters, and running demand response events - over 600 events including multiple
demand response events every day for 220 days (BPA 2018). The results demonstrated that connected heat
pump water heaters can shift load and reduce peak demand at various times of day and seasons. For example,
controlled electric resistance water heaters compared to connected heat pump water heaters reduced evening
peak load by 90 percent. Reduced loads in turn reduce capacity risk for utilities and energy costs for
customers. The BPA team's research contributed to the Northwest Power and Conservation Council approval
of a load-shifting analysis methodology19 for water heaters in 2019 (DOE 2019).
Information Resources
Understanding the Modern Grid and Its Benefits
Title/Description
National Association of State Energy Officials (NASEO) and National Association of Utility Regulatory Commissioners
(NARUC). Grid-Interactive Buildings Working Group. Grid-interactive Efficient Buildings: State Briefing Paper. (2019). This
report provides a summary of how grid-interactive efficient buildings can help states manage load on the grid and ensure
greater reliability.
National Association of Utility Regulatory Commissioners (NARUC) and the National Association of State Energy Officials
(NASEO). The Task Force on Comprehensive Electricity Planning, (n.d.). This site offers extensive resources and provides
states with a forum to discuss pathways to a more resilient grid, including optimizing DERs, storage, and grid reliability.
National Association of Utility Regulatory Commissioners (NARUC). Energy Infrastructure Modernization. Smart Grid.
Center for Partnerships and Innovation (n.d.). This website contains resources about smart grid deployment, benefits,
learning modules, and links to other resource.
National Governors Association. Grid Smarts: State Considerations for Adopting Grid Modernization Technologies. (2017).
This paper looks at considerations in developing a modern grid, including technologies and policies that can advance this
objective.
National Renewable Energy Laboratory (NREL). Advanced Distribution Management Systems, (n.d.). The website
provides NREL's research regarding how advanced distribution management systems can improve reliability and
resilience. The site contains a description of a partnership with the Pacific Northwest National Laboratory to develop open-
source software which can help utilities test ADMS applications cheaply.
National Renewable Energy Laboratory (NREL). Advanced Power Electronics and Smart Inverters, (n.d.). NREL's
research addresses how the use of advanced technologies can help provide stability to the grid by managing voltage and
frequency, which can help with the integration of DERs, such as solar and storage.
National Renewable Energy Laboratory (NREL). Renewable Energy Integration, (n.d.). The website provides links to
resources and tools developed by NREL for integrating DERs into the grid.
National Renewable Energy Laboratory (NREL). Smart Grid-Enabled CVR: Advanced Application for Distribution
Management Systems. (2018). Provides an overview of the research and methodologies used to conduct an analysis of
the energy savings obtained through CVR.
U.S. Department of Energy. What Is the Smart Grid? (n.d.). This is a resource for information about the smart grid
concepts and government-sponsored smart grid projects.
18 ANSI/CTA-2045 is a standardized grid-customer communication interface designed for appliances that have flexibility in when they
use electricity (BPA 2018).
19 To quantify the demand response impacts of residential water heaters during a demand response event, the Regional Technical
Forum (RTF) of the Council developed maximum obtainable per-household technical potential estimates (NWPCC 2019).
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Resources from Government Agencies, Institutes, and Networks
Title/Description
Federal Energy Regulatory Commission (FERC). Federal Energy Regulatory Commission (n.d.). FERC's website provides
information on smart grid advancements, including annual assessments of demand response and advanced metering
potential.
National Energy Screening Project. National Standard Practice Manual for Benefit-Cost Analysis of Distributed Energy
Resources (2020). The NSPM for DERs provides methodologies and principles for jurisdictions to assess and compare the
cost-effectiveness of energy efficiency and other DERs.
National Institute of Standards and Technology (NIST). Smart Grid Group, (n.d.). This website provides an overview of
smart grid technology and the development of interoperability standards to make it possible.
State and Local Energy Efficiency Action Network (SEE Action). Determining Utility System Value of Demand Flexibility
from Grid-Interactive Efficient Buildings. (2020). The report discusses methods and practices to determine the economic
value of grid-interactive efficient buildings to the utility system. The document includes enhancements to current evaluation
practices that policymakers can use, along with ways to prioritize implementation of these suggested improvements.
U.S. Department of Energy. Advanced Metering Infrastructure and Customer Systems: Results from the Smart Grid
Investment Grant Program. (2016). This DOE report provides the results of projects implementing AMI to help
decisionmakers weigh the costs and benefits associated with AMI for the grid.
U.S. Department of Energy. SmartGrid.gov. (n.d.). This website is the gateway to information on federal initiatives that
support the development of technologies, policies, and projects to transform the electric power industry.
U.S. Department of Energy. Voluntary Code of Conduct (VCC) Final Concepts and Principles (2015). Utilities and third
parties can adopt these concepts and principles voluntarily in order to address privacy related to customer data.
U.S. Environmental Protection Agency. Conservation Voltage Reduction/Volt VAR Optimization EM&V Practices. (2017).
This EPA technical resource provides background on methods for assessing energy savings potential, data tracking
considerations, and current impact evaluation processes associated with the energy efficiency impact of CVR and WO.
Resources from Energy Industry Associations
Title/Description
Advanced Energy Management Alliance (AEMA). AEMA. (n.d.). AEMA is a demand response advocacy group that
maintains a directory of industry demand response resources.
Association for Demand Response & Smart Grid (ADS). Reports and Research, (n.d.). The ADS website provides links to
ADS-generated reports and case studies, as well as major reports issued by government and others.
Green Building Elements, LLC. Smart Grid Interoperability Panel (SGIP). (2022). SGIP is a public-private partnership with
a mission to accelerate the implementation of interoperable smart grid devices and systems. Members develop standards
to help educate key stakeholders on best practices, lessons learned, and vectors of influence affecting successful
integration of next-generation smart grid technologies.
Institute of Electrical and Electronics Engineers. Grid Management System - A Key Enabler of Grid Modernization. (2019).
The resource provides an overview of the components of a grid management system, which replaces an Outage
Management System, and is composed of an advanced distribution management system and distributed energy resource
management system. The resource also shows how Southern California Edison, one of the nation's larger utilities,
implemented a grid management system in its territory.
National Electrical Manufacturers Association (NEMA). NEMA maintains information on smart grid solutions, which include
smart meters and high-tech sensors. In addition, the NEMA Utility Products and Systems Division provides information on
standards, products, and resources to support DERs and grid modernization.
American Clean Power (formerly the Energy Storage Association). State Energy Storage Filings, (n.d.). ESA maintains a
list of state legislative and regulatory proceedings that relate to energy storage.
The Gridwise Alliance. Gridwise Alliance, (n.d.). Gridwise is a coalition of stakeholders that works to transform the electric
grid by creating a venue for collaboration across the electricity industry. Gridwise provides a broad range of online
resources about smart grid technologies and policies.
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