Rising to the Challenge of Renewables & DERs: Orchestrating Across the Electric Grid & Its Prosumers

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The advent of Distributed Energy Resources (DERs) has strained the traditional way of doing things across the electric grid. Most utilities have run pilot projects, looking to anticipate and adapt to the many impacts of renewable power and prosumers. These experiments brought many learnings. Yet now, across the grid, utilities must fully incorporate the rise of renewable energy sources (solar and wind), electric vehicles, battery storage, heat pumps as well as new types of controllable load devices, or risk being overtaken.

Transmission operators perform a balancing act with grid supply and demand every day. Meanwhile Distribution operators work to ensure quality and continuity of service to end-users. Customers and regulators expect this to be done flawlessly. But DERs are creating unprecedented challenges for the electric grid. Every legacy power engineering

“With their current rate of growth, DERs can no longer be managed in a silo. Electric utilities need DER-awareness and orchestration across their full IT/OT network.”

- Jim Walsh, GM, Grid Software Solutions, GE Digital

paradigm is now being turned upside down. In some geographies, there is now more energy being fed directly at the Distribution level than there is at the Transmission level. Utility leaders need an end-to-end solution to coordinate how they model, monitor, forecast, and ultimately control and dispatch these new DER objects, across all internal and external systems and stakeholders.

This white paper will examine the complex challenges DERs represent for transmission and distribution before outlining the need for a coordinated solution to represent and manage them across the modern power grid. Managing DERs can no longer be one department’s pet project. When examining today’s situation, we can see that every single grid operator business process is impacted by DERs. Therefore, DER Orchestration needs to reach throughout every corner of a utility’s organization in a transverse, consistent manner.

Every legacy power engineering paradigm is now being turned upside down. In some geographies, there is now more energy being fed directly at the Distribution level than there is at the Transmission level.

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DERs may well prove to be the single most disruptive influence in the history of the electric grid with respect to Distribution and Transmission network operations and their underlying utility business models.

Renewables have quickly grown to represent the world’s second-largest source of electricity1. Dramatic expansion is likely to continue as countries look to meet long-term climate and air quality goals2. In Europe, for instance, many traditionally coal-powered countries are setting ambitious goals to help the continent reach climate-neutrality by 20503.

The IEA predicts the world’s total renewable-based power capacity will grow by 50% between 2019 and 2024. That’s an increase of 1,200 gigawatts — “equivalent to the current total power capacity of the

United States.” Solar, in particular, will see “spectacular growth” accounting for 60% of the rise4. Globally, we are also seeing a rise in energy storage, with annual deployment doubling from 2017 to 2018, reaching more than 8 GWh5. While on the EV front, global sales totaled just over 2 million in 2018, an increase of 64% over 20176.

The move in recent years towards distributed generation (DG) has been driven, to some extent, by regulatory changes and new climate impact awareness. Yet the market shift also reflects significant cost and efficiency improvements in DER technology and the emergence of third-party aggregators. These fast-growing companies leverage DER technologies to develop and offer new housing services, new transportation services, new energy efficiency services, etc. They package DERs into a wide variety of innovative

commercial product and service offerings — all for the benefit of the prosumers.

DER aggregators don’t concern themselves with the operations of the electric grid. Their business is green car sharing, zero emissions buildings, energy bill reduction, public parking lot differentiation, venture capital, etc. The rise of individual and business prosumers leveraging these services is heavily challenging the traditional electrical grid operating model. Power used to be predictably top down with the utility at the center of the producer-consumer relationship. Now electricity can come from the bottom, and erratically, with flow tied to how the wind blows and the sun shines, as well as based on how prosumers wants to consume/generate/store energy for its related service. The next section will discuss DERs impact on T&D in more detail.

Dramatic Growth for DERs

Aggregators package DERs into a wide variety of innovative commercial product and service offerings — all for the benefit of the prosumers. DER aggregators don’t concern themselves with the operations of the electric grid.

Distributed generation is shaping the energy future. DERs support energy independence, facilitate sustainability, and deliver cost savings and exciting new services to prosumers. The momentum can’t be reversed.

However, DERs are disrupting utility business models and operations at their most fundamental. Instead of transmitting and distributing power onto a grid that they own and control entirely, electric utilities must adapt to a new power paradigm7.

At the Transmission level, the challenges are linked to installed capacity, balancing, reserves, stability, lack of inertia, and lack of visibility to what is happening at Distribution level. Utilities had years and years of history with which to forecast system load and control big conventional generators to meet national or regional demand. Now the wind- or solar-powered generators are a wild card. Generation is dictated by uncontrollable weather.

Also, instead of being able to count upon the robust grid inertia that the spinning masses of conventional thermal generators provide, they now need to manage a grid where the rate-of-change-of-frequency can be much higher. Renewable generators not only create disturbances themselves, by lowering the grid inertia they allow any disturbance — whatever its root cause — to last longer

and propagate further. With renewable generation, the carefully balanced grid can be overburdened by sudden spikes or drops of power, either coming from bulk renewable generators connected at the Transmission level, or by the aggregation of myriads of those much smaller but much more numerous distributed generators connected at the Distribution level.

At the Distribution level, challenges are hidden load, backfeeds, and voltage issues. Hidden load refers to the share of consumption covered by embedded generation, therefore not directly visible to the grid operator whose traditional operation systems only manage “net load”, the net flow on the power lines. However, accurate visibility of the two components of the net load (native consumption and embedded generation) is essential to many core Distribution grid management processes. For instance, upon a fault, ensuring that a faulty feeder is de-energized is paramount for the safety of workers in charge of the repair. As such, operators must be aware of every single PV rooftop and fully comprehend its connection/disconnection status. Normally, the smart inverters which connect wind or solar power to the grid will trip upon a fault as they sense a loss of primary voltage. This means that, when running a fault isolation and service restoration logic, utilities need to take into account the fact that the load to pick-up

Accurate visibility of the two components of the net load (native consumption and embedded generation) is essential to many core Distribution grid management processes.

Impacts of the Changing Power Paradigm

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is not the net load level that was running before the fault, but the (much higher) native load — the hidden load has disappeared. This actually makes the cold-load pickup phenomenon even worse. Not only is there more load to pick-up, but also there is no more embedded generation to help.

Also, protection setting schemes are upside down with embedded generation, i.e., a DER that can provide substantial current during a short circuit fault can change the fault current pattern.

In further examining backfeed, imagine an entire neighborhood investing in rooftop kits. Mid-day, the sun beats down on those solar panels, but no one is home using the energy. The utility’s transformer feeding the neighborhood, which had initially been architected for a load of “X” MW going down, now sees a load of “2X” pushing back into the grid. The machinery wasn’t built for that. Finally, voltage profiles which used to decrease alongside a feeder, from feeder head to feeder end, now start to feature much more varied profiles, going up and down and up again depending on where new

Every single system in grid asset and operations management needs to be involved in the management of DERs. Geospatial Information System (GIS), Planning, Advanced Distribution Management Solution (ADMS), Advanced Energy Management System (AEMS) and Advanced Market Management System (AMMS) all have a role to play.

It all starts with registration

DERs can’t be marginalized. Some utilities may not yet be experiencing the significant impacts on energy flows and voltages profiles that the previous section depicted. But utilities can’t wait for the day they start to experience those impacts. The utility will suddenly open its eyes and realize that it has a huge backlog of devices on its grid

embedded generators or storage devices are injecting power.

As these Distribution level challenges aggregate up to the interface with the Transmission level, DERs are pushing Transmission System Operators (TSOs) and Distribution System Operators (DSOs) to coordinate. In some countries, there is now more power being injected directly at the Distribution level than there is flowing from the Transmission level. Still, Transmission remains responsible for ensuring that enough power is running on the grid to match instantaneous consumption. In such a context, TSOs and DSOs need very tight coordination.

With such a breadth of challenges ahead, no wonder Navigant estimates the Distributed Energy Resource Management (DERM) market will exceed $2 billion by 2029 with a 20% CAGR over the next five years8. Some specialized DERMS platforms emerged to manage and integrate DERs. Yet leading electric utilities are clearly demonstrating that creating separate and siloed DERM systems can’t tackle DERs at scale.

and its unaware of where or what they are. The utility will not send workers door-to-door canvassing for rooftop PV or battery storage nameplate info and details on how they’ve been connected. Not for the 10s or 100s of thousands of these devices out there.

Therefore, utilities need to start by ensuring they enforce a clear connection acceptance process, involving every DER hardware or services marketer (retailer, aggregator) within their service territory.

This may require some regulatory enforcement. In some geographies, due to the lack of such a regulatory framework, utilities have started to market DERs themselves. At least this way they know what those devices are and where they are.

Managing the DER Disruption: Every Grid System Needs to Get Involved

The utility will suddenly open its eyes and realize that it has a huge backlog of devices on its grid and its unaware of where or what they are.

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A mature connection acceptance process should enable the utility to gather all the parameters required to model a given DER in a way that is comprehensive enough to allow operators to dispatch it someday. A mature connection process should also enable the utility to start influencing/guiding DER connections to mitigate grid impacts: limiting a solar PV capacity, proposing a battery storage device be co-located to a PV array, imposing a particular type of smart inverter, or setting contractual conditions to the DER connection (e.g., ability to dispatch the DER during peak hours, ability to curtail the PV kit in emergency conditions against a particular compensation, etc.).

GIS enters the picture

DSOs and TSOs need a shared source of truth for all DER parameters, modeled consistently from the GIS. While in the past the utility would need only understand its own asset parameters and geographic locations, now every new DER must be added. Even though they are not owned by the utility, each new generation/storage component influences

the grid. To complicate matters further, these DERs can have as many as 30 times more parameters than traditional grid assets.

• Who does the DER belong to? • Who is the aggregator? • What technology/protocol can it

be interfaced with for status, for measurements or to send out controls?

• What are the limitations and obligations outlined in the interconnection/aggregation contract?9

A DER-ready GIS enables utilities to model and manage all types of DERs in the same manner as every other asset of the utility grid. This is foundational to the work being done in the ADMS and AEMS.

When carefully looking at the DER lifecycle, one realizes that the utility is not the prime customer. More often, the retailer/aggregator who packaged, marketed and sold the DER owns and manages the DERs key technical and contractual parameters. Beyond the initial registration process, every change in a DER’s technical parameter (e.g., a residential

owner elects to increase the size of its PV rooftop) or contractual parameter (e.g., a commercial site owner elects to change the contract it has with its retailer, moving from tariff A to tariff B) initially happens in these systems, outside of the boundaries of the utility.

Yet these changes still need to be reflected in the utility GIS to ultimately reach the ADMS and AEMS. Technical changes will alter the situation awareness, and contractual changes will impact the operational constraints for dispatching the DER (e.g., maximum number of times the DER can be dispatched per day/week/month/year, maximum ramp-up time, minimum advanced notice period before a dispatch, etc.). Multiply these types of changes in DER modeling by the sheer number of DERs in the grid and the utility is faced with thousands of changes every day. All of which affect the DERs influence on the grid.

Therefore, capturing DERs parameters is not something utilities can do on their own, and it is not a one-time task. A constant

flow of static and semi-static data, coming from external systems, needs to be initially captured and then maintained as the DERs evolve. For the entire electrical grid industry, supporting this type of data flow between all actors cannot be done without very strong data and data communication standards.

The ADMS needs to be DER-aware

Central to DER management, the ADMS is actually one of the systems most impacted by these changes. The ADMS model first needs to add DERs with all their technical and contractual parameters, coming from the GIS, and ensure that all the contractual operational constraints mentioned previously are well captured and represented. Then, the ADMS needs to interface with these devices, which are connected to the distribution grid.

The DSO may think that SCADA communications will do. It has traditionally been used to interconnect with any breaker, transformer, etc., device on the distribution grid. Unfortunately it isn’t economical to connect each and every DER

Capturing DERs parameters is not something utilities can do on their own, and it is not a one-time task. A constant flow of static and semi-static data, coming from external systems, needs to be initially captured and then maintained as the DERs evolve.

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with a SCADA protocol. For small DERs, SCADA communications and dedicated Remote Terminal Unit (RTU) hardware are prohibitively expensive. A residential DER owner will never be equipped with the same type of communications as an electrical substation. What a residential DER owner has available is the Internet. With that in mind, what ADMS operators needs a communication protocol that runs on the Internet. The most advanced protocol offering this service is IEEE 2030.5, built for Internet-based coms for very large number of small devices. Based on the most advanced DER data model currently available this protocol borrows from CIM, from IEC61850, and goes way beyond, to represent all the technical and contractual parameters of DERs, throughout their lifecycle:

• DER ownership• DER modeling• DER connection acceptance• DER programs• DER registration• DER provisioning• DER capability

• DER availability• DER monitoring• DER dispatch• DER forecast• DER schedule• Etc.

This data model has been built to cover the spectrum, from the smallest thermostat to an aggregator head-end. It is well suited to the Russian-doll pattern of prosumers and aggregators, often with several layers of aggregation.

IEEE 2030.5 and its underlying data model are by far the most advanced standard to represent and manage DERs across the utility and non-utility ecosystem, in a coordinated fashion. The largest of distribution-connected DERs will still be able to use SCADA, when affordable. But IEEE 2030.5 vastly expands the range of devices that can be monitored and controlled.

After modeling and interconnection, the DER-aware ADMS needs to have all of its algorithms comprehensively enhanced and tested, to

faithfully represent and manage the new power engineering paradigms of DERs. As discussed above, the ADMS needs to understand the difference between native load (actual consumption) and net load (which remains after part of the load is covered by embedded generation). Its Fault Location Isolation and Service Restoration (FLISR) algorithm needs to model the fact that prior to the fault there was the net load, but after the fault what needs to be picked up is the native load. It also models the fact that after some time, part of the smart inverters will come back on-line and reconnect. The DER-aware Powerflow needs to understand that there can now be backfeed situations and solve accordingly. The voltage optimizer needs to understand that now, with DERs, voltage profiles can be fully different from what they used to. Further, it should be able to propose voltage optimization plans which co-optimize all levers at hand, not just DERs as a silo, but together with switching, taps, and caps. Finally, the DER-aware ADMS should be able to operate the distribution grid in look-ahead, nurtured by forecasting, and act on DER flexibility via bilateral contracts or markets, in synch with AEMS.

The most advanced protocol offering this service is IEEE 2030.5, built for Internet-based coms for very large number of small devices.

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At the Transmission level

The AEMS also needs to significantly evolve to take DERs into consideration. Not only representing and managing bulk renewable farms connected at the Transmission level, but also representing the aggregate of DERs connected at the Distribution level. Representing a distribution grid just like a load equivalent is not enough. The DSOs and TSOs need to add equivalent distributed generation and equivalent storage to fully understand the dynamics and dispatch. State Estimation, Contingency Analysis, etc., all need to be DER-aware. For example, they must account for backfeeds coming from the distribution grids. They also must enable the dispatch of battery storage devices (in addition to and in conjunction with conventional generators). In the

past, conventional generators ran with the hypothesis of unlimited stock. Now, batteries state of charge needs to be accounted for.

The AEMS needs to evolve to more detailed forecasting and look-ahead analysis in order to better understand the effect of wind force and irradiation on grid stability and security. This system also needs to gain a deeper understanding of the dynamics of the grid, as measured by Phasor Measurement Units (PMUs). These enable operators to scan grid behavior at stunning rates of 60, 100 or even 200 measurements per second. This suddenly opens a view to a whole range of dynamic phenomenon which the traditional three to five seconds scan rate of SCADA communications, never allowed.

After all, the grid is the largest dynamic system ever built. To use a mechanical analogy, it is like a vast network of springs and shock absorbers. With Wide Area Monitoring Systems (WAMS) in AEMS, disturbances propagation, islands formation, regions de-synchronization, phase angle shifting, lack of inertia and its quantifiable impact to rate-of-change-of-frequency, and more elements become monitorable, understandable and actionable phenomena.

Advanced Market Management Systems (AMMS)

These systems also need DER orchestration to run the market for Transmission and coordinate DER flexibility transactions across Transmission, Distribution, Aggregators and Peer-to-peer players. With open market

regulation, the industry is questioning how best to orchestrate flexibility products to be declared, bid upon, cleared, reserved, dispatched and settled, in a fair and transparent manner. Depending on local regulations, different priority principles are emerging relating to TSO, DSO and free market needs. Digital DER orchestration would help accommodate for various priority schemes depending on use case and severity of violation.

Lastly

DERs are forcing further convergence and a transition towards grid automation via the Internet of Things (IoT). Artificial intelligence (AI) and machine learning (ML) enable simulations of various scenarios that could play out on the grid, in both the planning and

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operational domains. Weather impacts as well as prosumer arbitrage impacts dictate the need for very advanced techniques to understand and forecast native load behaviors and embedded generation and storage, all depending on a wide range of explanatory variables.

Ultimately, no matter the subsystem and/or business process, utilities face challenges linked to modeling and orchestrating these new devices. From each different viewpoint, everyone must have visibility on the same DER objects, consistent with the other systems in the enterprise. Managing DERs, at whichever stage in their lifecycle, must be done in synch with all the other systems, adding value for Transmission, Distribution and prosumer coordination.

Because DERs challenge both Transmission and Distribution, and involve multiple parties internal and external to the utility organization, DERs need to be orchestrated throughout the entire grid. We’ve seen in the previous section that GIS, planning, ADMS, AEMS, AMMS, analytics, as well as third-party aggregator systems, all need to contribute. But what additional value, what additional use case needs to be carried throughout? DER orchestration supports grid operators in stepping back and looking at the entire chain from a more holistic perspective.

Modeling

Everything the utility does relies on a model-centric view of the entire electrical grid – often referred to as a network digital twin. The foundational digital network view ensures accurate electrical connectivity, provides a consistent and shared network model representing the as-built and

as-operated statuses, and supports a solid understanding of relationships and dependencies between assets.

DER model orchestration ensures the DER digital models feeding into the ADMS and AEMS are accurate and powerful, and kept in full synch with all changes occurring on the prosumer side. Changes to DER capacity or technical characteristics, contracts, operational constraints and more are captured by registration, commissioning and provisioning. This data is fed into the GIS, connection acceptance, ADMS, and the Distribution grid equivalents modeled in the AEMS. This harmonized modeling enables operational coordination. Planning or connection acceptance studies can be performed also with an accurate representation of the operational levers available in the ADMS or AEMS to alleviate DER impacts, in synch with the prosumer, without the need for traditional grid reinforcement.

Cross-silo Comprehensive DER Orchestration

After all, the grid is the largest dynamic system ever built.

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Interconnecting

Both Transmission and Distribution operators need to understand the instantaneous heartbeat of all types of DERs – large or small. Monitoring in the ADMS at the Distribution level needs to flow upwards directly into the AEMS, so that real-time situation awareness is shared consistently between both levels.

The shared source of truth via DER orchestration lets the operators answer the questions, “what is the renewable generation right now?” and “what is the storage capacity available right now?” Taking into account both the technical and contractual capabilities and limitations. Then, they can act consistently. Especially when monitoring and managing numerous DERs that have an intermittent impact,

traditional levers (switches, taps, caps) would not be enough.

Forecasting & Look-ahead Analysis

Because DERs are intermittent and hard to predict, grid operators need to anticipate variation issues to try and solve them. With full DER management in both real-time and look-ahead modes, operators gain the ability to try to solve issues proactively.

More and more countries are forecasting load and distributed generation in a coordinated way. TSOs and DSOs are sitting together to share, compare, and align their forecasts. Breaking down the old boundaries, they use DER orchestration forecasting to ensure they have the same view of the coming hours.

Plugging into the shared aggregated/disaggregated view from any point in the orchestrated system, operators can run any use case at whichever level, to make sure both Transmission and Distribution are covered. These DER-orchestrated forecasts account for both the native load (actual consumption) and the net load (native load minus what is covered by the embedded distributed or renewable generation). With this, look-ahead analysis can be consistent between Transmission and Distribution, and the potential call for third-party DER flexibility can be made with clear anticipation of needs.

Controlling and Scheduling

The prosumer, the aggregators representing them, and the Distribution and Transmission grid operators all have different objectives. At any given point in time, each will have different actions they would take regarding the same DERs. Transmission may want to shave load peaks during the day. Distribution may want to consume excess PV generation by increasing load to avoid backfeeds and voltage issues during the peak irradiance

DER model orchestration ensures the DER digital models feeding into the ADMS and AEMS are accurate and powerful, and kept in full synch with all changes occurring on the prosumer side.

The prosumer, the aggregators representing them, and the Distribution and Transmission grid operators all have different objectives. At any given point in time, each will have different actions they would take regarding the same DERs.

in the afternoon. At the same time, the prosumer wants the car charged as quickly as possible.

Solving for these conflicting objectives requires coordinated flexibility and expression of needs.

Traditional levers are not enough. Solving the controlling and scheduling problems DERs present requires action on the DERs themselves. But one does not want to create or exacerbate a problem at the Distribution level when solving one at the Transmission level, and vice-versa. For example, DER orchestration enables definition of boundaries acceptable for Distribution, that are valid during a pre-defined period of time (e.g., 30 minutes), during which Transmission can freely dispatch DER flexibility.

DER orchestration offers the opportunity to extends DER flexibility over time and geographical location. The solution enables orchestrating the best possible tradeoffs between the various actors’ positions for successful collaboration in the DER environment.

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GE Digital features more than 10 years’ experience working on DERs, in both pilot and actual operational deployments. We have been working with the countries featuring the highest penetration of renewables worldwide. Our DER Orchestration solution leverages the breadth of GE Digital’s Grid Software Solutions portfolio. It provides the ability — in GIS, Planning, ADMS, AEMS, AMMS and Analytics — to manage DERs in related business processes and systems. Our solution adds value by sewing all of these systems together: modeling, monitoring, forecasting, and scheduling across the board, in a consistent and orchestrated manner. We also know that scaling requires the maximum use of standards. This is what GE Digital does; CIM modeling, GRIB for weather forecasts, IEEE 2030.5 for DER interconnection and data models — to name a few. As a maker of power generators, a grid builder and a software developer, GE knows what it takes to manage objects throughout the chain.

“DERMS” systems reproducing all DER-related functions in single siloed system were practical for setting up pilot projects without risking disturbance of the main operational systems. Now, in a world where DERs are growing at an exponential rate, uncontrolled by grid operators, utilities need DER capabilities in every one of their existing business processes. A standalone solution can neither optimize DERs in combination with all other grid levers (switches, taps, caps) nor with all the customer-centric energy efficiency/services/tariffs etc. DER orchestration reaching throughout every corner of a utility’s organization is essential.

Reach out today to further discuss the sequence that makes the best sense in your utility regulatory framework and commercial context when introducing DER orchestration.

Partner with GE References

Conclusion

1. IEA. Mar. 2019. Global Energy & CO2 Status Report 2019. https://www.iea.org/reports/global-energy-co2-status-report-2019/renewables

2. Kellner, T. Feb. 19, 2020. Setting the Pace: How Smart-Grid Technology is Powering the Global Shift to Renewables. GE Reports. https://www.ge.com/reports/setting-the-pace-how-smart-grid-technology-is-powering-the-global-shift-to-renewables/

3. European Commission. Dec. 11, 2019. A European Green Deal. https://ec.europa.eu/info/strategy/priorities-2019-2024/european-green-deal_en

4. IEA. Oct. 21, 2019. Global Solar PV Market Set for Spectacular Growth Over Next Five Years. https://www.iea.org/news/global-solar-pv-market-set-for-spectacular-growth-over-next-5-years

5. IEA. May 2019. Tracking Energy Integration. https://www.iea.org/reports/tracking-energy-integration/energy-storage

6. EII. Apr. 2019. Electric Vehicle Sales: Facts & Figures. https://www.eei.org/issuesandpolicy/electrictransportation/Documents/FINAL_EV_Sales_Update_April2019.pdf

7. Wauquiez, F. Nov. 26, 2018. Distributed Energy Resources — What’s On Your Grid Today (and Will be Tomorrow). https://www.linkedin.com/pulse/distributed-energy-resourceswhats-your-grid-today-frédéric-wauquiez/

8. Navigant Research. Mar. 2020. Navigant Research Leaderboard: DERMS Vendors. https://www.navigantresearch.com/reports/navigant-research-leaderboard-derms-vendors

9. Wauquiez, F. Feb. 4, 2019. The Post-Pilot Era: DERs Becoming Business as Usual for Utilities. https://www.linkedin.com/pulse/post-pilot-era-ders-becoming-business-usual-utilities-wauquiez/

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