Distribution System Evolution

describes an evolutionary framework for U


Evolving Electricity System
The U.S. electric system is undergoing significant change due to a range of drivers, including an evolution of federal, state, and local policies addressing climate mitigation and adaptation, as well as an increasingly diverse and distributed set of electricity resources.Today, the adoption of distributed energy resources (DERs) in the United States is uneven; certain areas have significant adoption, whereas others have a very low percentage.This is true even within a state or utility service area.This patchwork of adoption is currently driven by technological cost-effectiveness, local economic factors, consumer interest, and grid integration considerations.The adoption patterns observed in several states and countries over the past decade, along with the related impacts to distribution system planning and operation, can help identify the key issues and decisions.
There are a number of factors driving the scale and makeup of the future U.S. energy marketplace: DER adoption pace and scale, number of DER providers and aggregators, and growth of electrification, for example.In addition, there are several potential considerations for DER utilization (e.g., size threshold for wholesale market participation, wholesale and distribution rules for DER aggregation, scope of DER services eligible, how system and distribution planning incorporates DER services).These integration and participation factors, as well as future issues, will inform how the system will need to evolve from its current state.The prospective impact of higher levels of consumer and independently aggregated DERs on markets, planning, and operations will increase commensurate with their share of the resource mix.In particular, higher levels of DERs provide an opportunity to leverage these resources to optimize grid investments and improve overall power system performance, economic efficiency, and reliability.This paper describes an evolutionary framework for U.S. electric distribution systems to enable DERs and their evolving use as virtual power plants (VPPs) for a broad range of grid services while also offering grid planning considerations for state regulators, utilities, and stakeholders.VPPs can help address a broad range of challenges to modern grid operations by providing clean energy and demand flexibility to help minimize costs for a decarbonized future, improve resilience, and provide other consumer and grid benefits.

Figure 1. Distribution System Evolution
Figure 1 illustrates a three-stage evolutionary framework for the distribution system.This framework is based on the assumption that the distribution system will evolve in response to both top-down (public policy) and bottom-up (customer choice) drivers.The yellow line represents a classic technology S-curve as applied to DER integration and utilization.Each level builds upon the previous one.Due to higher levels of DER penetration and more ambitious policy goals, each subsequent level requires additional market and regulatory requirements as well as distribution system functionalities that create an increasingly complex system.
Stage 1 -Grid Modernization: Low DER adoption (<5% of distribution system peak).DER levels can be accommodated within existing distribution systems without material changes to infrastructure, planning, and operations.Grid modernization1 is undertaken to address reliability, resilience, safety, and operational efficiency and to enable forecasted requirements for DER integration and utilization.
Stage 2 -Operational Markets: Wider scale (e.g., 5% -<15% of distribution system peak) customer adoption of onsite DER/electric vehicle (EV) technologies for their energy management and resilience.DERs-individually and in aggregations-are increasingly used as load-modifying resources for both distribution non-wires alternatives (NWAs) and wholesale capacity and ancillary services.Integrated distribution system planning and grid modernization are needed to enable real-time observability and operational use of DERs.
Stage 3 -Virtual Power Plants: Large scale (e.g., >15% of distribution system peak) adoption of DER/EV technologies and utilization for wholesale and distribution services, plus community microgrids.Individual DERs and DER aggregations are optimized and orchestrated to support grid service requirements for distribution and transmission systems.Multi-use/community microgrids help support local energy supply and resilience.Ultimately, distribution system-level energy transactions are enabled.This third stage of DER utilization requires coordination across jurisdictions (e.g., Federal Energy Regulatory Commission [FERC] Order 22222 ) and infrastructure to support both grid and market operations.
Note: The percentages shown are rough approximations for the threshold levels at which significant institutional, business, and grid changes are required due to consumer actions, policies, and new business models.The term "market" in this paper applies to any transaction involving the use of DER services through one or more wholesale, retail, bi-lateral market, and compensation methods (e.g., tariff, program, procurement, bi-lateral trade, locational marginal price market, auction).

Evolutionary Stages
Stage 1: Grid Modernization In this stage, the level of DER adoption is relatively low and can be accommodated within the existing distribution system without material changes to infrastructure or operations.A primary focus of Stage 1 is addressing the need to replace aging distribution network infrastructure as well as to deploy new advanced grid technologies to address reliability, resilience, safety, and operational efficiency.These initial grid modernization investments, beginning in the 2000s, continue the transition from an analog to a digital network through smart grid initiatives.For example, they include network connectivity models, enhancing circuit level monitoring, related situational awareness, and power system analytics along with enhanced reliability and resiliency investments in automated field switches enabled by field communications and operational systems (e.g., distribution management system and Volt-var optimization).Foundational investments in aging infrastructure replacement and initial grid modernization also enable increased adoption of DERs and utilization in Stages 2 and 3. 3 Federal and state legislation has recognized the need to modernize the grid for over a decade. 4,5ilities in Stage 1 should proactively plan for an intelligent, flexible, efficient, open, and secure distribution system that can integrate transportation and building electrification as well as DERs.Advancing integrated distribution system planning, including hosting-capacity analysis, and investment prioritization provide immediate benefits and lay an important foundation for the future.This should also include addressing resilience needs based on an all-hazards threat risk assessment and understanding of resilience needs of critical facilities and vulnerable communities. 6terconnection standards should be updated to reflect current technical standards (e.g., IEEE 1547-2018, IEEE 2030.5, NIST cybersecurity).In addition, utility interconnection process reengineering and automation, along with more advanced modeling capabilities based on industry best practices, should begin to be implemented in anticipation of forecast DERs and electrification growth.These are essential elements in a distribution grid code. 7e use of flexible demand in Stage 1 involves traditional demand response, typically addressing bulk power system emergencies as part of operational remedial action, as well as management of peak load for wholesale and distribution systems.For example, the housing boom of the mid-2000s created annual peak demand growth of 5% in places like Southern California and Florida.Utility air-conditioning cycling programs and time-based rates were also expanded to address this need.
As a result, load as a capacity resource became the predominant program in 2012, reaching a total of 20 GW (more than double from 2010). 8This represented a shift in the use of demand response from traditional emergency demand response, which was the largest program two years earlier in 2010, at 13 GW. 9The maturity of load as a capacity resource was also an important step in the evolution of demand response and other flexible DERs to potentially provide a broader range of bulk power system services, providing operating reserves and regulation.These bulk power services and utility distribution programs continue to provide value today.

Considerations
• Establish state objectives and priorities and related distribution planning criteria and performance metrics.
• Identify best and leading practices regarding integrated distribution system planning, including stakeholder engagement, forecasting load and DERs (with consideration of EVs, flexible buildings, and climate parameters), power engineering analyses, and investment roadmaps leveraging DERs.
• Identify and implement hosting-capacity analysis and related public information-sharing platforms with increasing sophistication, as needed.10 • Establish a cost-effectiveness evaluation and cost-recovery framework for grid modernization investments.11 • Set requirements for data/device interoperability and cybersecurity protections.

Stage 2: Operational Markets
Stage 2 involves expansion of both DER adoption and use.The most common forms of DER adoption include growth of customer-sited storage, smart thermostats and other home automation, and EVs, in addition to solar photovoltaic (PV) cells.Stage 2 also involves front-of-the-meter independent community solar and storage developments.At this stage, DER adoption reaches a threshold (e.g., 5% of distribution system peak) at which regulators, stakeholders, and utilities recognize the need to enable integration of DERs and begin to utilize DER services provided by independent aggregators as a distribution NWA for some types of distribution system needs.This level of adoption typically results in pockets of high customer adoption in some neighborhoods and commercial districts.12Pacific Gas & Electric's experience in 2014 with DER capacity at the equivalent of 8% of distribution peak13 demonstrates an illustrative adoption pattern: • One percent (1%) of all feeders may have DER capacity levels at or near 100% of the feeder peak load; • Three percent (3%) of all feeders may have DER capacity levels exceeding 30% of the feeder peak; and • Eight percent (8%) of all feeders may have DER capacity levels greater than 15% of the feeder peak.
At this level, two drivers become prevalent.One is pockets of high customer solar PV adoption, commercial solar garden/farm development, and/or material levels of EV adoption (including fleets) in some neighborhoods and commercial districts.Hosting-capacity constraints emerge along with bidirectional power flows or voltage variations that become increasingly problematic.
The second driver is increasing levels of DERs at a scale that can be leveraged to provide bulk power system and distribution grid services.For example, FERC took a series of proactive steps starting in 2008 and continuing into the 2010s to promote the use of responsive demand and other DERs (such as storage) in wholesale markets, including Orders 719,14 745,15 and 755. 16These orders provided greater market competition for capacity reserves and ancillary services.Additionally, utility regulatory changes opened opportunities for DER service providers to offer distribution grid services in lieu of utility distribution investments.These NWA services are provided through a diverse set of DERs and microgrids combined with advanced information and control technologies.
DERs providing services to both the bulk power system and distribution system require the establishment of a coordination framework among the DER aggregator, independent system operator/regional transmission operator (ISO/RTO), and distribution grid operator.17Typically, this begins with a simple model proportional to the scale and scope of DER aggregations and wholesale and distribution services provided by DERs. 18However, these initial coordination processes do not scale to support the scope of services and number of transactions involved in Stage 3 of the evolutionary framework for the distribution system.

Figure 2. Evolutionary Progression in Several States
Additionally, as DER levels increase beyond 5% of distribution system peak, operational impacts may occur on the distribution system, including voltage variations and bidirectional power flows.These drivers create the need in Stage 2 for enhanced capabilities related to maintaining reliable operation of the grid and optimal use of DERs (Figure 2).Expanded distribution modernization though increased situational awareness, DER control, integrated distribution system planning, and distribution automation are typically required.These factors require changes involving new regulatory actions, utility business process reengineering, enhanced planning, and operational capabilities for reliable distribution operation and enabling and optimizing the use of DERs.

Signposts of Change
The following signpost examples illustrate a number of drivers of change from Stage 1 to Stage 2 that continue to be experienced in some regions throughout the United States.Each state and locale will have a unique set of signposts and pace of change.
• Consumer Solar Finance -Introduction of innovative consumer solar finance options (e.g., loans and leasing) spurred rapid consumer adoption of rooftop solar when combined with tax credits and net energy metering tariffs, where parity with retail rates exist. 19Federal and State Tax Credits -Applicable federal and state tax credits and other incentives to offset the initial cost of DERs.
• Consumer Technology -Smart phone launch in 2007, rapid expansion of internet commerce and "Internet of Things" and home automation (e.g., smart thermostats) beginning in the 2010s.
• Community Solar/Storage -State legislation and regulation that enable and incentivize development of community solar and storage projects.20 • Consumer Storage Incentives -Legislation and regulation that foster development of "storage connected at the distribution feeder level, associated with a cluster of customer load."21 • State Integrated Distribution System Plans NWA Regulation -State regulatory requirements for utility distribution planning, including the use of DERs as an alternative to traditional infrastructure solutions. 22FERC Order 719 -FERC first opened wholesale markets for an initial set of ancillary services to aggregated demand response as allowed by states.
• FERC Order 745 -FERC established its authority to compensate demand response resources at the same locational marginal prices that generating resources receive in the energy market.
• FERC Order 755 -FERC required grid operators in organized markets to compensate frequency regulation resources based on the actual service they provide, including separate payments for capacity and actual performance.

Considerations
In the past 15 years, this industry has seen considerable advancements in consumer technology, including DERs and federal and state policies enabling DER use and grid modernization across the United States.State regulations, wholesale electricity markets, and utilities are striving to catch up with innovation at the grid edge while dealing with an apparent inflection point in climate-related grid resilience and reliability challenges.
The following are key considerations for further expanding DER adoption and utilization as well as requisite enabling grid capabilities.These illustrative considerations should be addressed throughout Stage 2 as DER and electrification levels increase and the scope and scale of DER services expand.
• Apply Integrated Distribution System Planning23,24 to understand the evolution of consumer resources and their interaction with the grid and to align foundational grid investments. 25 • Identify the set of distribution grid services that DERs may provide and respective performance and compensation/participation models (e.g., pricing, programs, procurements, and markets). 26Leverage Grid Architecture 27 to provide insight into modern grid requirements and designs and address certain coordination issues, including the ability to scale markets and operations.
• Recognize that DERs owned by parties other than utilities require orchestration through a variety of price, control, and autonomous methods and enabling mechanisms (e.g., tariffs, programs, procurements/auctions, and real-time markets) as well as various entities (e.g., DER aggregators, manufacturers) at the grid edge for distribution and bulk power systems.
• Develop and implement a holistic set of distribution grid codes that address new regulations, business processes and practices, and technical standards to enable adoption and utilization of DERs at scale, including interconnection, data and information sharing, interoperability, cybersecurity, regulatory and commercial standardization, and governance. 28 • Consider DER tariff alternatives to address DER value potential, equity, and cost recovery of grid investments (e.g., cross-subsidization issues). 29,30age 3: Virtual Power Plants A characteristic of Stage 3 is a high level of DERs (e.g., solar PV nameplate capacity over 15% of distribution system peak).These high levels exist today in several states and utility service areas.For example, California and Hawaii are currently above this level and have considerable distributed storage and a growing number of EVs.At the Stage 3 threshold, a significant number of DERs are available to create VPPs.VPPs are aggregations of DERs, such as rooftop solar, EVs and chargers, energy storage systems, and smart buildings and equipment that are controlled to act like a traditional power plant.They are large enough to be utility scale and dependable enough to be utility grade.Unlike traditional power plants, VPPs may both export energy and manage demand.
Stage 3 involves advancing the use and sophistication of DER aggregation services to serve as increasingly continuous and automated flexible resources to address system dynamics.Specifically, the need for bulk power system ramping services and regulation, in addition to spinning reserves, is expected to expand significantly.Flexibility needs identified by Midcontinent Independent System Operator, Inc. (MISO), 31 other regional grid operators, and states involve DERs to "shape, shift, shed and shimmy" consumers' net electricity consumption through new flexible resource initiatives (Figure 3).

Figure 3. Flexible Consumer Resource Management Spectrum 32
In particular, there is a focus on shed-and shimmy-type flexibility that operates on shorter time cycles and more frequently to manage a significantly more dynamic grid.This means that DER requirements for grid services, energy dispatch, and load management systems operate more continuously, like a traditional power plant (Figure 4).FERC Order 2222 is a major milestone for enabling VPPs to more fully contribute their potential to address this flexibility need.Order 2222 ushers in a transition from Stage 2 to Stage 3 as it lays out a foundational set of enabling market design, utility, and aggregator business functions, as well as regulatory roles and responsibilities.As Order 2222 recognizes, VPPs may be used for both wholesale markets and retail applications as an energy supply option, as well as flexible alternatives to traditional investments in transmission and distribution systems.ISO/RTO compliance plans are targeting between 2026 and 2030 for launch of Order 2222 provisions.
This includes managing distribution system hosting capacity dynamically with high levels of solar PV, storage, and electrification.In the United States, an emerging vision is for the distribution grid operator to manage distribution capacity by orchestrating DERs-to enable full energy export from solar and distributed storage and energy use for EV charging.Orchestration in the United States in Stage 3 involves leveraging flexible loads and storage to offset distributed generation exports or EV charging load so that net power flows on the distribution system remain within operational limits (i.e., hosting capacity).This approach is unlike current efforts in Australia, where "dynamic operating envelope" is viewed as a DER curtailment and derate mechanism, throttling DER to stay within distribution operating limits. 34ditionally, wider adoption of distributed generation and storage can enable the formation of multiuser/community microgrids 35 to form an island of interconnected loads and DERs in a contiguous section of a utility distribution circuit during black-sky events.These community microgrids are an option to address specific local resilience needs or broader social objectives. 36 the latter part of Stage 3, a combination of high DER adoption and policy and regulatory decisions may provide an opportunity for development of distribution markets for multi-sided transactions between DER owners/operators and entities seeking to buy or trade energy at the distribution level.A prerequisite is high levels of DERs that can supply dispatchable energy and that are not encumbered by tariffs, interconnection rules, or other regulations that effectively prevent the resale of the energy produced to another party across the distribution system.The vast majority of energy-producing DERs installed in the United States (notable exceptions include Texas and Hawaii) is encumbered in that manner.It is unlikely that Stage 3 distribution energy markets will develop until regulators further reform DER rates and incentives.However, it is likely that some limited energy transactions will occur in Stage 3 related to multiuser microgrids and community-based energy suppliers (e.g., California Community Choice Aggregators, 37 Ann Arbor Sustainable Energy Utility, 38 Sunnova Microgrid Communities 39 ).
A formal distribution-level market structure is needed to facilitate such grid-edge energy transactions in addition to local markets within each local distribution area.This may, for example, involve a distribution substation as a distributed trading hub and interchange point for a bulk power market node.DER owners/operators may also want to transact across multiple distribution systems.That will entail utilizing the transmission system, as well as the distribution system, placing greater emphasis on coordination between distribution grid operators and ISOs/RTOs at transmission-distribution interfaces.
In summary, the evolution of DERs into VPPs has been a 40+ year journey that is about to make a significant step-change for a decarbonized future (Figure 5).This evolution will involve structural transformation across the electric industry.The industry has already entered a transitional period to address the dual challenges and opportunities associated with FERC Order 2222 and electrification.In effect, the industry is "crossing the Rubicon."• Develop Integrated System Planning (e.g., resource, transmission, and distribution) processes, as applicable, to properly evaluate a more distributed and electrified system as well as the value of VPPs across all levels of the electricity system.
• Adopt distribution grid codes that address the capability maturity needed for Stage 3 scale and complexity, including new institutional and business processes, commercial standardization, codes of conduct, technology interoperability, and regulatory governance.
• Develop alternative grid architectures and reference designs that reflect emerging multi-level energy systems (e.g., bulk power, distribution, community-based, and customer).
• Develop and implement coordination models that reflect the evolving and expanding landscape of market participants across multi-level energy systems.
• Implement foundational grid infrastructure and technologies necessary to enable deep decarbonization and climate adaptation 47 while also creating a delivery system for VPPs to deliver grid services by providing clean energy and demand flexibility to help minimize costs, improve resilience, and provide other consumer benefits.This model provides an effective way to assess both the required level of technical capabilities and the maturity of regulatory and business processes related to the integration and utilization of VPPs.Today, these processes for DERs are between model Level 1 (Initial -ad hoc processes) and Level 2 (Repeatabledefined and documented processes), depending on the state and utility service area.However, they are not scalable.

Conclusion and Next Steps
For example, several states in RTO/ISO markets that will be implementing FERC Order 2222 have not yet instituted hosting-capacity analysis, established integrated distribution planning, or updated interconnection rules that reflect current inverter standards (Level 1).Other states have implemented these elements and instituted distribution grid services through documented processes and procedures (Level 2).However, to satisfy Order 2222 requirements, the industry, including VPP aggregators, needs to advance to a minimum of Level 3 (Standardized) and preferably Level 4 (Managed), where processes and practices for VPPs, markets, and operational coordination are monitored and controlled-meaning there is effective performance evaluation and regulatory governance by FERC and state utility regulators.Ideally, the electric industry achieves Level 5 (Optimizing).Order 2222 identifies a number of these aspects and provides a useful reference on VPPs for jurisdictions outside an RTO/ISO region to consider.
Correspondingly, there is a need to upgrade utility capabilities for Stages 2 and 3.The electric distribution system in the United States today is based on the Edison-Tesla grid architecture of the 1890s, overlaid with a mix of 100 years of technological evolution in electric power delivery, control systems, and computing and telecommunication.Most of this infrastructure was installed over the past 50 years and is undergoing a significant analog-to-digital transformation.This includes, for example, replacement of electromechanical devices with digital devices such as protection relays.This infrastructure refresh started largely in the mid-2000s and will continue into the next decade given the expanse of the distribution system nationwide and the recognition of customer affordability challenges with such large capital investments.Distribution system operations will also necessarily need to evolve toward greater visibility regarding situational awareness and dynamic algorithmic optimization with human operator oversight, given increasing system dynamics.
Considering the implications of grid evolution, it is essential to move toward a common view of what functions the grid needs to enable and when those functions are needed.This requires proactive engagement between regulators, customers, utilities, DER aggregators, and other stakeholders.It is important to consider the pace of DER and EV innovation (approximately two-year product development cycles) compared to process times for institutional decision-making in the electric industry (about five to seven years).Innovation cycles are outpacing industry decision-making cycles for new rates and general rate cases by a factor of more than two, and that does not include implementation timelines.The industry is lagging behind and will need to find ways to leap ahead to manage the systemic changes underway (Figure 7).

Figure 7. Second Generation of Electric Industry Structure and Capabilities
A common understanding of grid investments to enable utilization of DERs and VPPs for both grid and market operations is needed.VPPs cannot deliver value if grids cannot deliver their services to intended markets.Further, reliability and resilience investments for the distribution system are crucial as resources at the grid edge contribute a significant portion of grid services over the next decade in a number of states pursuing distributed generation and storage policies. 51Failure to address foundational grid modernization capabilities in a timely manner will create significant barriers to a more distributed electricity system and impede development of VPPs and, perhaps most importantly, decarbonization through electrification. 33

Figure 5 .
Figure 5. Evolution of Flexible Load Management and Other Distributed Energy Resources

Figure 6 .
Figure 6.Electric Industry Capability Maturity Model for VPPs