Research

Watch out!Congestion ahead

Grid management in times of customer centricityA point of view for the power utilities sector in North America

Distribution grid: For the purposes of this paper, the distribution grid means all assets that transport and distribute energy from transmission substations to the edge of the grid. This encompasses the substation and the primary distribution lines, which operate normally at around 13kW and are a common location to connect medium-sized PV installations. Depending on grid layout, the secondary distribution lines (feeder lines including feeder transformers) that directly connect to consumers, can also be affected by congestion, for example, if the connected households have installed private photovoltaic or charging stations for electric vehicles.

Distributed energy resources (DERs): Small to medium scale resources that are connected primarily to the distribution grid behind the meter assets.

Here comes trouble As more distributed energy resources (DERs) are added to the grid, congestion in the network will occur at the times of day when power production from those resources peaks. Unless carefully managed, this congestion will become increasingly severe, leading to a host of problems for the distribution system operator and for its customers.

Trouble in the distribution grid Distribution system equipment may become loaded above rated operating limits, causing damage to circuit segment cables, fuses, transformers and other equipment. In severe cases, fires can occur, presenting a risk to citizens, utility workers and emergency personnel. The damage caused by these blow-outs and fires results in outages in service that incur costs related to repair, fines from the regulator and damage to reputation.

Trouble across the T&D value chain Increasing output from DERs has the potential to cause reverse power flows in the distribution system, resulting in operating patterns that were not considered during planning, design and protection studies. Where no protection provision has been made for reverse power flows, the in-place relays may not function, leading to equipment damage and wide-spread outages. When these flows become large enough, similar problems may occur in the bulk power transmission system, resulting in reduced grid reliability1.

Trouble at the customer Customers might also see the negative impacts of congestion in their homes and business premises. The intermittency of power production from DERs can lead to voltage variability, possibly outside of the safe operating limits of the customer’s equipment. This can result in unsatisfactory service, such as flickering lighting, and even damage to equipment—such as refrigerators, air conditioners, pumps and electronic equipment—in the home or office.

1 Distributed Energy Resources: Technical Considerations for the Bulk Power System FERC Staff Report. Docket No. AD18-10-000, February 2018.

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Is all that’s green, good? Most utilities in North America, whatever their size, have as their mission to provide affordable, safe, secure and reliable access to electricity (perhaps also to gas and water) while protecting the environment. An increasing number of DERs are being integrated into the energy mix and therefore onto the grid. These carbon neutral, sustainable sources of generation are good news when energy-related emissions account for more than 90% of North America’s total greenhouse emissions2. Nevertheless, it is becoming increasingly clear that the prolifer-ation of DERs on the network is causing complexity at the grid edge. For utilities managing the grid, congestion—previously a transmission challenge—is starting to occur in the distribution network and could compromise system reliability going forward.

A story was told in a 2018 DistribuTECH breakout about how, having purchased a new refrigerator—previously the most energy thirsty appliance in the family home—families in the 1940s would directly inform their electricity company about the purchase. This allowed the utility to make provision for the load increase. Fiction? Probably not. Today, when consumers drive an electric vehicle (EV) out of the showroom, there is no obligation to inform their electricity provider. Because they have no way of knowing where the EVs are, utilities cannot plan for infrastructure upgrades or improvements. Only when EV penetration reaches a critical mass and reliability becomes a problem, do they have the required visibility to act. This is just one example of the unpredictable strain on the distribution grid.

The fact that the distribution part of the network has traditionally been equipped with fewer sensors, generating less data and as a result, less intelligence, contributes to this blind spot. In the new energy system, the loads and capacities are highly volatile: the intermittency of photovoltaic (PV), e-mobility, storage, etc. creates repercussions that are hard to manage. Load and generation patterns at the grid edge are also impacted by new market players such as aggregators or prosumer-oriented service providers who are taking advantage of new technologies, market mechanisms, and more active consumers. Tesla’s plan to deploy solar roof tiles packaged with battery storage is one example. Realistically, the risks to system reliability and security are going to increase as distributed energy resources at the grid edge continue to become more readily available and prevalent.

Watch out! Congestion ahead

Congestion happens when too much electricity demand or too much electricity generation adversely affects voltage and frequency. Both a surplus or a shortfall can exceed the capacity of the installed assets such as cables and transformers and lead to physical damage, grid instability, reduced power quality, and even black-outs that can have repercussions at the transmission level.

Congestion in the distribution grid is a local phenomenon. Its characteristics vary greatly, depending on geographic location, existing grid infrastructure and renewable installations, load characteristics, maturity of the energy market, and the regulatory environment. While all executives managing the distribution grid face the same challenge—to accommodate a continually growing number of DERs in an increasingly decentralized, digital and divergent energy landscape—no one has yet formulated a “one-size-fits-all” solution.

What’s to be done? Reinforcement of the network is one means of ensuring sufficient capacity to meet supply and demand. This solution can however be costly and time-con-suming to realize, and highly disruptive for businesses and citizens, particularly in urban areas. While investments in upgrades to the grid are an inevitable part of running a distribution company, operators need to balance network reinforcements with smart controls that have the potential to solve many congestion problems. Building physical infrastructure to provide for peak loads, which only occur for a fraction of the total operating hours each year, may not be the optimal use of capital investment.

This point of view seeks to explore the topic of congestion in the distribution network in North America, to better understand the implications and risks, and elaborate recommendations for utilities.

54% of morethan 100 utilitiesworldwide stated

in a survey that they think the hosting

capacity for distributed generation could be

exhausted withinthe next ten years3

Introduction

2Climate Watch for Canada: https://www.climatewatchdata.org/countries/CAN?source=33 and USA: https://www.climatewatchdata.org/countries/USA?source=333Accenture: Digitally Enabled Grid 2017: Reap the benefits of smarter distributed generation integration https://www.slideshare.net/accenture/digitally-ena-bled-grid-2017-reap-the-benefits-of-smarter-distributed-generation-integration 2

At OMNETRIC, our vision is for a new energy economy that is smarter, stronger, greener and more diverse. To us, solving the burgeoning problem of congestion seems to be fundamental to that vision. While congestion may not be a priority for utilities today, we know from discussions with our customers that they see this as a looming issue on the not-too-distant horizon. Because change takes time, and in certain circumstances needs regulatory approval, by the time the issues present themselves it may be too late for the utility to act. This is why they need to start taking action now. This report aims to explore the shape and magnitude of the challenge ahead and what next steps toward a resolution might be. With this report, our intention is also to stimulate discussion and drive awareness. Only by bringing multiple stakeholders to the table, can implications and options be effectively assessed.

To compile the report, we followed a two-phase approach, commencing with desk research on the topic of congestion in the distribution network. We drew on industry reports from analysts, case studies and thought leadership publications from different market experts. This phase helped

clarify the status quo. During the second phase of the research, between January 24 and March 23, 2018, we conducted 45-minute telephone interviews with nine experienced utility executives. These executives came from both the business and engineering sides of their respective organizations, underlining the fact that there is no standard role assigned to managing the risk of congestion.

The geographical focus of the study was the United States. The interviews followed a semi-structured format to ensure that all relevant questions were discussed, while also providing an open platform for each interviewee to share their thoughts, ideas and comments. We took these insights, complemented them with the learnings from the desk research and then discussed the outcomes of the research within OMNETRIC. This allowed us to reflect on the findings and enrich them further with our first-hand experience garnered on projects. This report is a combination of these different perspectives and opinions.

Methodology

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Our thanks to industry executives who accepted to contribute to this point of view.

Christopher Jones, Consolidated Edison Company of New York, Inc., Department Manager - System Design, Distribution Engineering Department

Thomas Langlois, Consolidated Edison Company of New York, Inc., Project Manager

Damian Sciano, Consolidated Edison Company of New York, Inc., Director, Distributed Resource Integration

Thomas Magee, Consolidated Edison Company of New York, Inc., General Manager, Smart Grid Implementation Group

Derek Kirchner, DTE Energy, Principal Supervisor - Demand Response

Mike Grant, Duke Energy Corporation, Lead Engineer, Grid Monitoring, Control and Intelligence

Raiford Lawrence Smith, Entergy, Vice President, Energy Technology & Analytics

Michael Brown, NV Energy, Manager, Demand Response & Distributed Energy Resources

Dawid Zydek, NV Energy, Supervisor, Demand Side Management Technical Services

Key findings Page

1. Flexible in every way 52. It’s about the data, but software 6 is not the silver bullet 3. Divide and conquer but keep control 74. Value-based mechanisms change the game 85. Regulators must keep up 9

Next steps–switching perspective 10

Our congestion mitigation model 11

Recommendations 15

Conclusion 16

Contents

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It’s a principle of physics that there’s little about electricity that’s flexible. Fortunately, until recently, generation, distribution and consumption were relatively predictable, so flexibility was not a requirement. Today, DERs create unpredictable power flows in the distribution grid and thispresents a congestion risk. On the plus side, DERs have the potential to provide flexibility, enabling the utility to operate the grid more efficiently, even economically. Flexibility in this context was recently defined in a report by a group of European DSO associations as the modification of generation injection and / or consumption patterns on an individual or aggregated level, often in reaction to an external signal, in order to provide a service within the energy system or maintain stable grid operation4.

Taking advantage of this flexibility requires the utility to take a more active role in the operation of the distribution grid. There are three areas that can be orchestrated: assets, behavior and software. Utilities need to blend all three, but increasingly diminish the emphasis on assets and increase focus on non-wire alternatives.

Nevertheless, it makes sense that the grid operator will initially leverage the technical solutions that are directly within its sphere

of control. The first approach to leveraging flexibility to manage congestion will likely involve installing switches and using a SCADA system to operate them remotely to reconfigure the grid and more evenly load grid assets. Another approach would leverage meters, communication and SCADA to enable reconfiguration actions such as load adjustment through EV charging or curtailment. Storage will undoubtedly become an important piece of the puzzle, especially as it becomes more economically viable. Storage can be implemented by the utility at all levels of the electricity system, including at the distribution level and behind the meter, with installations such as Tesla Powerwalls. Storage is particularly relevant to managing congestion because it is suitable for balancing reserves and voltage control services as well as frequency regulation reserves, all of which require rapid response time. Flexibility opportunities afforded by EVs as mobile batteries will gain increasing focus, as in models such as Grid-to-Vehicle (G2V) and Vehicle-to-Grid (V2G).

In addition to direct load control of reg-ulated and non-regulated assets, utilities can drive flexibility through indirect load control via smart tariffs and other market mechanisms. Tariff-based solutions combine multiple parameters (timing, location, capacity vs consumption), but fundamentally, the simpler the tariff

structure, the more effective it usually is. Another model, currently being considered in Europe, could be variable network access agreements or flexible network connection agreements. These could potentially create win-win opportunities for network operator and user.

Building on current initiatives such as demand response, utilities will look for flexibility by adding more diverse and specific tools to optimally influence the behavior of different stakeholders such as consumers and aggregators. Many utility executives already see significant potential in demand response programs, energy efficiency programs, controlled thermostats and services for the smart / connected home. Over two thirds of utilities see these behavioral actions—enabled by increasingly effective software—as becoming important in the next three to five years5.

The spectrum of software-based actions utilities can implement to achieve flexibility is broad. They would do well to ensure that they are as flexible as the outcomes they seek to achieve: modular and interoperable, platform-like solutions that can ultimately become a fully-fledged system to manage distributed energy resources and combine asset-, behavior-, and software-based actions.

“Consumers should go through a solar interconnection process that makes them aware of the consequences their installation could have on the grid.”

“With our AMI, we can now tap into advanced rate concepts and leverage that not only for peak shaving but many more use cases.”Research respondents

Key findings

Finding 1

Flexible in every way

4Flexibility in the energy transition: A tool box for electricity DSOs 5Zpryme (2017): The Connected Home: Programs and Products to Empower Customers, page 3: https://etsinsights.com/reports/the-connected-home-programs-and-products-to-empower-customers/ 5

Finding 2

If flexibility is to become a new reality for utilities, insight will be essential to the constant adjusting and optimizing of the system. It is no surprise that the insight will be data-driven. Feedback from utilities has been consistent and clear: data is the distribution operator’s most valuable asset. If data is the lifeblood, software becomes the heart of the utility of the future, controlling assets and influencing customers’ behavior based on the status of the grid. That said, utilities best placed to master the grid and handle the threat of congestion recognize that software alone will not solve the problem.

First there’s the hardware that generates intelligence: meters and sensors. Getting the right hardware in place and developing as much knowledge as possible about customers, their behavior, and their impacts on the grid should not be overlooked. Data scientists are right when they say that every utility has enough data to get started with generating insight, but if the utility needs to drive at a more holistic view of the network, combining customer behavior information with events at the grid edge will yield richer results.

So, the edge of the grid needs to become smarter—both more intelligent and faster.

There’s a multitude of small assets and interconnections within the distribution grid that cannot be controlled by a central intelligence system. It makes sense to collect the right data and enable autonomous management of smaller events, directly at point of need. Initiatives such as Coalition of the Willing and the promotion of architectures such as Open-FMB, while some five years old, have never been more relevant. Utilities must be able to see where current problems are located, predict where potential problems could arise and identify the right mechanisms to fight them. Based on this, utilities are making investments in new hardware, such as smart inverters and intelligentsubstations, as well as control software and behavioral programs. And despite a lengthy coming of age, the data generated by smart meters—of which more and more will be in near real time—is starting to provide utilities with unprecedented capabilities for reducing costs and enhancing customer choice. In our work with utilities, we’ve only started scraping the surface of how data can transform utilities’ response to grid management.

Utilities are combining software, hardware and customer behavior insights into a convincing masterplan. Platforms, such as distributed energy resource management solutions (DERMS), that combine data from different sources, allow direct or indirect control of assets, and address customers through price signals, are good examples of an integrated approach to fighting congestion. Close understanding and keen alignment with the utility’s future business and grid strategy has always been key to technology investments that deliver value and are future proof. All too often today, utilities want to have conversations about which products will help manage renewables penetration, and not about the future scenarios and capabilities they need to fulfill. Some utilities are breaking down the problem and starting with (good, old-fashioned) use cases. Resulting data can then help scale the solution, determining focus and investment.

“The approach should not only be about a software solution. We must define use cases, based on our strategy and ‘chunk up’ the problem. The solution will probably be a DERMS-like platform, but considered from the outcome and not the technological specifications.”

“Assets, software and behavior are the three major levers that need to be integrated into a comprehensive approach. You cannot just rely on software, because at the same time you need to ‘harden’ your grid and influence customer behavior.”

Research respondents

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It’s about the data, but softwareis not the silver bullet

Key findings

Congestion happens when there is more activity on the grid than it was designed to handle. That activity comes from many different players, often located at the grid edge, close to end-use customers at their homes and businesses, behind the meter. The result is a digitized, networked and dynamic energy ecosystem with bi-directional power flows.

Prosumers, aggregators, utility service providers, independent PV developers, car manufacturers with EVs, charging-infrastructure providers, etc. all come with their own needs, motives and behaviors that utilities can feel ill-equipped to understand or accommodate. The complexity and diversity of the energy landscape that results from this grid edge activity is a far cry from what many utilities are accustomed to: central intelligence, incremental optimization, stringent management processes—perhaps also a siloed structure and outlook. This unfamiliar territory requires a holistic strategy to handle it. Nevertheless, utilities are ultimately responsible for the health of the grid and must find ways to manage and nurture this multi-dimensional landscape. The good news is that despite being the incumbent experts, they do not need to do everything themselves. Service providers and consumers can share the burden of management. The operation of

virtual power plants by aggregators is one example. However, there are prerequisites for a decentralized approach. Given the ultimate responsibility they bear for grid health and safety, utilities need to ensure that they maintain balance. This can be achieved contractually or via direct intervention. Incentives can also help influence behavior, as can service agreements with aggregators. Bundling these measures in an innovative DERMS lendsmaximum impact to these initiatives.

It is utilities who must set the framework in which other parties need to operate, for example, defining the hardware and software standards that enable easier engagement across the ecosystem. Utilities need to have in-depth insights into their grid and know which assets and players are active and can be leveraged. Working in an ecosystem requires them to acquire new skills and adopt an inside-out mindset. In addition, utilities also need to bridge their internal silos. All departments need to share information, create the big picture of the system and work together to manage the grid.

“The grid is more and more becoming a bandstand, and everybody is dancing around at their own pace. Utilities need to be the orchestra leader who sends the signals to coordinate everybody and keep order within the system.”

“We want to work together with aggregators, as our service providers for clearly defined problems, and use their expertise.”Research respondents

Finding 3

Divide and conquer but keep control

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Finding 4

Value-based mechanisms change the game The multitude of new players entering the energy system, coupled with a new generation of digital technology, fundamentally changes the shape of the market: transforming it from a centrally fueled and controlled system to a network of different entities that produce, consume or manage energy and have significant impact on certain (local) parts of the grid. Simply reimbursing the energy consumed and leaving the cost of managing and keeping up the grid to the utilities doesn’t cut it any more.

To effectively manage congestion, a truly customer-centric system that follows a value-based approach must emerge. In this new reality, every action is evaluated according to the positive and negative consequences it has on the grid, and is charged accordingly. Utilities and regulators can help side-step congestion by developing and establishing market mechanisms that compare the value a certain asset has for the management of the grid versus the cost it represents for the system. For example, while greater adoption of EVs will increase total electricity consumption and could be perceived positively by the utility, it will create grid stress. How much will EV manufacturers pay network operators for the net new load (and pressure) on the grid? What are the imperatives for establishing this value-based market? In this agile, less predictable environ-ment, rigid regulations aimed at limiting participation to ease congestion are counterproductive.

Prohibiting a new PV installation, for example, has negativeconsequences on the utility’s image and in addition, significantly dampens the enthusiasm for alternative energy generation. It’s also often simply impossible to stop.

What is important is having clear visibility of the location and impact of each new asset on the grid (PV, storage, EV, etc.) in order to calculate its value—be that the demand opportunity or congestion risk it represents. Utilities need, for example, a GIS for the asset locational data, hardware and software components to control them, planning and simulation software to understand the engineering impact, and the right tariff-structure in place to reimburse each player for their contribution.

All of this will certainly require change management programs to bring about a conscious shift. These should promote more active participation in energy markets and a greater understanding of related costs. Communication should also move participants beyond the “everything green is good” stance by raising awareness of the negative impacts and engendering a responsibility to the system.

Early pilot projects are already testing new technologies, such as block-chain, to arrive at a truly transactive energy market. As an example, LO3 in Brooklyn uses blockchain technology to enable peer-to-peer trading of privately generated PV electricity across a limited, local system.

“Real demand charges for residential and commercial and industrial consumers alike could be a solid first step to make the system more value-based.”

“We need a close collaboration between all the different players to manage the ecosystem. Incentives need to be truly value-driven to sustainably change participants’ behavior.” Research respondents

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The ability of utilities to react to the threat of congestion in the energy grid is potentially limited—or enabled—by the regulatory framework in which they operate. In many ways, regulators have the potential to set the pace for utilities’ response to congestion, as well as other challenges associated with the energy transition, determining, as they do, business conditions and funding priorities.

“Right now, the regulator treats all DER participants equally. But, they are not equal; some are more important than others and we do not have the means to exert control over them.”

“The regulator should set the frame that defends the grid against abuses and stimulates innovation.”Research respondents

Finding 5

Regulators must keep up

Key findings

Utilities wishing to equip themselves to manage congestion down the line can find themselves limited by the regulatory framework, or frustrated if regulators do not share their own sense of urgency to create and shape the energy system of the future. Utilities can be deterred, for example, from introducing new solutions or innovations by regulators’ rate case cycles that delay the recovery of investment costs.

Without the timely collaboration and anticipative forward planning of regulators, utilities risk being ill-prepared for congestion in the grid when it inevitably becomes a reality. What’s more, neither regulators nor utilities generally have the agility to fund and implement counter-measures quickly once congestion occurs, leaving utilities—and customers—to suffer the consequences. Despite these challenges, utilities can ready them-selves for arising challenges, such as congestion, within the limitations of

the regulatory framework. Small pilots for example can present regulators with demonstrated technological solutions as well as positive business cases that can stimulate progress.

With the right mindset, regulators can become ambassadors and enablers of an age of customer centricity. Some are already demonstrating that a collaborative, innovative approach is possible. Reforming the Energy Vision (REV) in New York is an example that is actively spurring energy innovation. Similarly, California regulators have demonstrated a progressive approach, approving proof-of-concept pilots, and rules that require the state’s utilities to shift their focus to solar, wind and other renewable sources, while respecting an absolute limit on carbon pollution through 2020.

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Switching perspective: the era of Z to A

Getting to the heart of solving congestion in the distribution grid reveals the need for a profound change at the utility.

For over a century, energy operators have thought of what they do in a linear, downstream way from central generation to transport to load—from A to Z. Utilities have optimized this flow, and the last wave of customer-focused innovations has helped them to further streamline and improve this value chain. However, that configuration has forged a mindset that could prevent the action required to combat congestion, because central intelligence, optimization, and rigid management processes are not fast or flexible enough to control all the disruption at the grid edge. As congestion in the distribution grid results from activities from multiple parties, often located behind the meter, the traditional system view cannot grasp them. Even if they can be identified, understanding their motives and behavior, essential to efficient grid management, is not possible.

As an activity, grid management must factor in the customer in a way not done to date. Utilities will need to flip their perspectives and start thinking from Z, the consumer, to A, any kind of potential solutions to meet demand. Quite simply, customers are no longer the exclusive reserve of those handling retail. Managing assets and systems in the distribution grid will no longer be an engineering task alone. With sufficient understanding on the customer side, utilities will start to conceive new, innovative services and solutions for their customers, while managing the constraints of the physical grid. Those services might even extend to ancillary services offered

to the transmission operator. During this research, speaking to utility executives who are considering the congestion risk in the distribution grid, there was no single role or profile. These executives were often working across their organiza-tion to educate and evangelize and ensure a cross match of information that will underpin a more complete network picture. Managing the grid in times of customer centricity requires a holistic view of the energy system. This will entail close cooperation across the utility value chain, as well as across functional depart-ments within a company. Armed with information about the customer, in practical terms, utilities will need to formulate and test potential use cases and future capabilities. How the current system can be used to meet customers’ needs will be the second step, because success will not be about optimizing what utilities already do, but rethinking the process according to that new Z to A perspective.

“As a utility we have to flip the process of how we think about our business.We must start with the customer and

then we will find completely new approaches to grid management

and business models.”Research respondent

Next steps

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Gladville has historically been a bedroom community for Big Metro City. Recently, Gladville was also voted as #5 in the “Top 10 Small Towns to Live in the US” and is seeing rapid growth. Furthermore, with its proximity to three major universities and a major metro airport, Gladville has made the short list of cities identified by online retailer Mega River, Inc., as a potential site for a second hub.

How do utilities deal with congestion? There is no single solution. Each player will need to define its own strategic and operational way forward. We have modeled four simplified scenarios that outline different approaches to the threat of congestion in the imaginary town of Gladville.

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Model parameters:1. The utility is a regulated local distribution company focused on distribution of electricity to the end customer. It is the single source of supply in its service territory and does not have the charter to provide deregulated value-added services. The utility does not have any additional ways to drive economic benefit such as special tariff packages or flexibility services. Therefore, the distribution utility needs to be incentivized to operate efficiently through its distribution rates.

2. The utility’s regulatory ratemaking process allows it to recover all capex and O&M expenditure associated with enabling integration of customer or third-party energy resources under the various scenarios described. It also allows for recovery of lost energy revenue from integrating customer-side resources via a lost revenue adjustment mechanism. This does not automatically mean that customers will have to pay for grid upgrades in all cases, because the rate increase could be mitigated by competitive market mechanisms. However, in this simplified model, we have assumed a favorable regulatory environment, wherein the utility is able to maintain cost and revenue neutrality for infrastructure investments and the reliable integration of third party energy resources.

Gladville70% urban / 30% rural

20,000 residents

85GWh energy consumption per year

8,500 households

20% with smart meters

40% with HVAC

750 C&I customers

20MW grid capacity

8MW averageload over time

15MW (fossil) and 10MW (renewable) generation capacity

Our congestion mitigation model

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Gladville’s current generation capacity of 25MW connected to its distribution network will almost double over the course of the next three years.

Model parameters:3. The financial implications for the distribution utility were calculated over a time span of ten years. This reflects an average, market-compliant scope for investments and business case calculations, considering the projected life of inverters and battery systems. The ten-year approach may be conservative for certain classes of utility assets, but caps the benefit streams to realistic timeframes and simplifies the modeling for the out-years (when additional investments may be needed to address increased demand and equipment end-of-life).

4. The model incorporates a multitude of further key assumptions (e.g. regarding cost structures, technological feasibility and market acceptance) that are based upon data from well established, market-leading sources like EPRI and NREL.

Here comes trouble! Congestion ahead

of rooftop solar capacity will be added to the grid in year one thanks to an incentive program.

of solar capacity will be added to the grid via an investor-owned solar farm to be installed over three years, adding 5MW of additional capacity per year.

The utility serving Gladville realizes that the increased local generation may help mitigate some of the demand growth, but that the current grid set-up will not be able to cope with the impact of these developments. The utility is evaluating four options to master the congestion threat:

Infrastructure enhancements Battery storage integration Demand response program Distributed energy resource management system (DERMS)

5MW

15MW

Infrastructure enhancements

Battery storage integration

Demand response program

In this scenario, infrastructure reinforcement is the only action taken by the utility. This includes traditional capacity upgrades such as transformers, but also increased monitoring capability and circuit modifications via smart switches and voltage regulation.

Benefits

• All costs are completely recovered via rate relief and while there are no incremental financial benefits to the utility, it remains revenue neutral.

• The utility can maintain or improve its reliability metrics even in the context of increased demand and increased generation on the distribution network.

• This initiative represents business as usual for the utility because the processes and action plans are in place and optimally tailored to the utility’s specific situation.

Challenges

• This solution does not yield any financial benefit beyond cost recovery.

• In high density residential areas or areas with underground networks, where infrastructure enhancements are more complicated and cost- intensive, this scenario could be less attractive financially and in terms of customer perception.

• While seemingly straightforward, this solution will necessitate a multitude of adjustments to the grid and its future management, to enable remote monitoring and operation.

In this scenario, the utility adds 1MW / 4MWh of battery storage in year one. By charging the battery during periods of excess generation and discharging during periods of peak demand, the utility is able to smooth out its demand curve and mitigate against “duck curve” effects.

Benefits

• Financial benefit over ten years is in the region of $1.5M. This translates to a yield of $7K per MW of DER capacity added to the grid (from renewables and storage) per year.

• The utility can measure and quantify improvements in reliability metrics and confirm that the battery storage provides equivalent or better reliability than its benchmark.

• Battery discharge can be used to alleviate peak demand and periods of congestion, thereby representing a more dynamic solution than traditional infrastructure enhancements. Thanks to the increased flexibility in grid management, the utility benefits from avoided capacity charges as well as avoided distribution infrastructure and system capacity operations and maintenance (O&M), which accumulate to just over $1M over the course of the ten years (discounted).

• Costs associated with battery storage and ongoing O&M are continuously decreasing over time, improving the solution viability.

Challenges

• The battery storage solution incurs almost double capital expenditure investments compared to the infrastructure enhancements route, but ongoing O&M costs are lower.

• The industry does not have extensive experience with the technical, performance and financial characteristics of battery storage over time.

• Examples of utility-scale storage in the US to date are limited and it is difficult to determine whether regulation would currently fully support recovery of all battery costs via rate relief.

The utility implements a demand response program for commercial and industrial and residential customers together with the same infrastructure enhancements as described in the first scenario.

Benefits

• Financial benefit over ten years is in the region of $3M–twice that of the battery storage integration route. This translates to a yield of $14K per MW of DER capacity (from renewables and demand response) added to the grid per year.

• The utility can measure and quantify improvements in reliability and confirm that the demand response provides equivalent or better reliability than its historic benchmark.

• The utility and rate payers realize the benefits of deferred capital expenditure for distribution grid upgrades, and avoided capacity charges, infrastructure and O&M expense that may otherwise be needed to meet the projected demand

• Environmental and societal benefits result from reducing the energy and demand footprint.

• This approach adds 2MW of additional capacity.

• The costs associated with demand response programs can be recovered in many regulatory environments via adjusted rates, whereas cost recovery for storage is currently less clear. As such, this option could feel a safer bet than the storage solution.

Challenges

• Because the behavioral programs involved in a demand response solution affect load, this solution not only includes the cost of the demand response program, but also the cost of infrastructure enhancements (as in the first scenario).

• Demand response programs require new skillsets to establish and manage an incentive-based grid management mechanism.

• A key success factor is the utility’s ability to promote the demand response program to the different target groups and engage them over time. This calls for an open and informed dialogue between the utility and its customers.

Four options to master the congestion threat

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Distributed Energy Resource Management System

Summary

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Our simplified modeling shows that utilities can take a number of approaches to mitigating congestion, and that these approaches can also deliver financial benefit.

The model shows that the most convincing solution in economic terms is the implementation of a DERMS. This approach optimally leverages the potential of software-, behavior- and asset-driven actions to offer the flexibility required for increased capacity and resilience.

Nevertheless, all scenarios represent viable options to improve grid capacity, optimize grid management and counter congestion.

The model does not factor in the scarcity of resources (e.g. investment, personnel) and lack of experience with new technologies that could impact the feasibility and success of the DERMS route. Indeed, implementing a DERMS could call for a multi-stage approach with pilot projects to determine the optimal combination of asset-, behavior- and software actions.

The utility implements a distributed energy resource management system (DERMS) as the core platform to manage the different grid assets and information. This option incorporates a demand response program for commercial and industrial and residential customers, and infrastructure enhancements in the form of battery storage.

Benefits

• The financial benefit over ten years is in the region of $4.5M–50% more than the demand response route and three times more than the battery storage integration route. This translates to a yield of $20K per MW of DER capacity (from renewable generation, storage and demand response) added to the grid per year.

• The utility can quantify the benefits of congestion avoidance in terms of its typical reliability and quality-of-service benchmarks in the context of increased demand.

• A DERMS hedges against capacity charge increases and serves as a distribution system investment deferral strategy that may equate to 10% additional incremental benefits compared to the infrastructure enhancements route.

• The only major infrastructure reinforcement measure is the addition of 1MW / 4MWh of battery storage.

• This approach incorporates the same demand response program as the previous solution that adds 2MW of additional capacity.

• The operational experience gained in battery storage management and demand response program execution provide a foundation for future flexibility.

Challenges

• The upfront investment exceeds the other alternatives. However, the average yearly cost for the DERMS approach runs at almost the same level as the other scenarios over time.

• This is the most far-reaching transformation in terms of design and implementation. The requirements for each hardware and software element must be determined in the context of the full system to ensure optimal interplay and efficiency.

• DERMS represents a new area of expertise for many utilities, and demands that they design and implement their system in a highly collaborative way, drawing on the inputs of business, engineering and technical teams.

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All scenarios assume that the utility can fully recover capital expenditure, and operational expenditure associated with infrastructureimprovements, enablement of DERs and demand response programs. Additionally, it is assumed that regulatory policy allows for a lost revenue recovery mechanism for enablement of demand response and third party DER integration. See the “Modeling parameters” footnote on pages 11 and 12 for additional information.

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Flip the focus

Utilities must break out of the mindset engendered by decades of one-way energy supply. The shift is fundamental and involves them flipping their world around—away from central intelligence and manage-ment processes to a more agile approach with the customer at the center. With a shared understand-ing of the implications of congestion down the line, strategies can be formu-lated and clear responsi-bilities assigned across the utility. It is no longer about optimizing what they do, but about rethinking how the organization is doing it. All discussion and ideation around alleviating con-gestion must begin from the customer side of the system, with an analysis of demand and behavior and mobilization of the whole energy system to build a response.

Test the possibilities

Solving congestion demands the transformation to a cus-tomer-centric energy system. But what does customercentricity entail and what does the optimal solution look like? The answer is not clear, but the role of data in determining a way forward is. Data will feed the trans-formation, providing the fuel for scenario planning to model the grid of the future and identify the most urgent measures. Utilities need to strengthen internal data analytic capabilities, and better embrace the software and modeling techniques that can help plan a way forward. By launching pilot projects, they can test potential tools and business models for the transformation to a congestion-proof customer-centric energy system.

Evolve the market message

Utilities can use their pivotal role in the energy ecosystem to influence customer behavior and regulator priorities in ways that can alleviate congestion. Communication with customers will be more important than ever. This will require detailed knowledge of the customer, either through classical methods such as customer research, or more technology-led methods such as data analytics of network and/or meter data. Both the message and the means of conveying it will need to evolve. Today, individual responsibility for the environment is largely understood and is more or less acted upon by citizens. Utilities will need to layer onto this an additional message, probably less about individual responsibility for the system and more about the benefits of flexibility. In tactical terms, utilities can take inspiration from other industries, where new tariffs and services incentivize behavioral shifts. Meanwhile, efforts to understand customer motivation and behavior will also provide evidence for regulators that a value-based market model is emerging for the energy system and encourage them to evolve accordingly.

Collaborate widely in order to lead

No single party can solve the threat of congestion on its own and collaboration is critical. This is as true inside the utility—where teams must formulate an integrat-ed response by consoli-dating expertise across the energy value chain—as it is across the broad energy ecosystem. Open dialogue and exchange between all players is an essential driver of transformation and pro-gress. Teams managing the distribution grid can and should play a pivotal role in orchestrating a coordinated, synergistic response, so that they can oversee and coor-dinate the impacts of coun-ter-congestion programs on their networks. Across countries and markets, this response should tap into the expertise, insights and assets of service providers, aggregators, energy start-ups and ESCOs, among others, to manage the grid.

Recommendations

Our discussions with utility executives and our work with utilities across North America suggest that congestion in the distribution grid is not currently considered a problem. But there is a growing aware-ness that congestion has the potential to become problematic quickly. Once that happens, measures to mitigate will take time to implement and remedy the pain points, resulting in a challenging period of adaptation.

We believe that utilities can start to prepare now for the changes ahead by laying the groundwork in a number of areas:

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Conclusion

It’s time for a new perspective

Security of supply, the distribution operator’s mission, is about fulfilling the promise to customers to provide electricity when and where it is needed. Always. So to suggest that distribution operators have ignored the customer to date would be inaccurate. But going forward, they will need to understand the customer in ways not previously required or even desired. Only by switching their perspective entirely—and envisaging solutions from the customer side of the system, with an analysis of demand and behavior—will they have the insight to design (and keep designing) solutions that will ensure enough flexibility in the system to manage peaks and counter congestion.

Why now?

Technological advancementThe proliferation of renewable technologies is causing the problem. And in the main, grid reinforcement as a solution will struggle to keep pace, let alone remain viable in economic terms. Moreover, in a digital era, most utilities will logically be asking themselves questions about software-based solutions. Software provides the potential to enable flexibility by scaling at speed in a way not possible in physical terms. The software options vary in maturity—from emerging, such as distributed energy resource management products, to mature, such as demand response management products. While utilities themselves might not have all of the capabilities required to pursue a digital solution alone, the broader industry ecosystem serving utilities is working to further products and build implementation experience.

Economic viability Greater flexibility in the system can be achieved and can be economically viable. The OMNETRIC congestion mitigation model indicates that flexibility can even potentially yield economic benefit. However, the biggest economic gains result from a sophisticated mix of asset, plus behavior and / or market measures that could take time to hone.

Mindset shift The report identifies three main protagonists when it comes to solving distribution-level congestion: the distribution operator, the customer and the regulator. To enable the energy system of the future, all three need to shift their perspective. The change in mindset required of the distribution operator is arguably the most challenging, requiring a 180-degree shift from distribution-centric to customer-centric. Customers too will need to be influenced to change their behavior through incentives and penalties, and a greater awareness of their actions—generation as well as demand—on the grid. Finally, the regulator would do well to embrace the notion of market facilitator, rather than market law enforcer. Nevertheless, utilities will no doubt need to lead the charge in this change management journey.

In our conversations with utilities, we see a growing awareness of that responsibility. Utilities will need to apply focus and investment in order to be successful. On a positive note, while the industry has been talking theoretically for some time about new business models, congestion might be the trigger for action: by actively working to unleash system flexibility utilities can not only generate cost benefits, but also enable tools for future grid stability and reliability. This is likely to motivate many executives to switch their perspective.

An invitation to collaborateAt OMNETRIC, open dialogue and exchange is at the core of how we do business. We’d like to issue an open invitation to those interested in this topic to reach out to us if you have ideas or questions, or simply want to challenge the opinions shared.

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Further reading

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Executive sponsor

Craig Cavanaugh

CEO—North America, OMNETRIC

craig.cavanaugh@omentric.com

For more information

Sachin Gupta

Senior Sales Director—North America, OMNETRIC,

responsible for distributed energy resource management

sgupta@omnetric.com

Contributors

Jürgen Benkovich

Ryan Collins

Shailendra Grover

Sachin Gupta

Louise Preedy

Mayur Rao

Dileep Rudran

Tobias Schnitzer

Melanie Stetter

Jim Waight

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