Modernizing the New York Energy Grid under Reforming the Energy Vision

Challenges of our grid and lessons learned from the Brooklyn-Queens Demand Management Program

In May 2019, Con Edison, the utility servicing New York City and one of the largest investor-owned utilities in the nation, installed a small energy storage system near Ozone Park in Queens.1  The system consists of lithium-ion batteries stored in eight shipping containers, and can power over 1000 homes for over five hours at a storage capacity of 2MV/ 2MWh. Like most storage solutions, ConEd’s newest pride and joy is meant to provide backup power during peak periods like hot summer afternoons. Because energy demand must always be met by a steadily generated energy supply, surges in electricity demand necessitate utilities to bring online additional plants and substations to meet this peak. As of yet, while batteries seem like such a given in daily household applications, large-scale solutions to store electricity for later use do not actually exist. However, a continued rise of 6% 2 in electricity demand in New York households over the past decade has pushed for new solutions to increase this peak capacity, and ConEd’s battery storage project is just one of many under the Brooklyn-Queens Demand Management Program (BQDM) rising to the challenge.3

Instead of building a traditional $1.2 billion substation, the utility is experimenting with non-wire solutions to increase efficiency in consumption and distribution. On the customer-side, this takes the form of incentivizing the installation of smart thermostats, efficient appliances, and energy storage technologies like batteries and fuel cells, which according to the third quarterly 2019 report, has reduced peak demand by a total of 40.5MV in the third quarter of 2019.4 On the utility-side, solutions include 16.5MV of conservation voltage optimization (CVO) and 2MV of energy storage systems such as this newly built one for a total of 18.5MV of load reductions (Fig 1). The program was initially slated for only a 5 year duration, but has since been continued indefinitely due to its preliminary successes. However, while the market-driven approach has shown compelling results, it is still a long way to go from 3000 MV state goal of energy storage by 2030.

Reforming the Energy Vision and the Challenges of our Grid

In 2018, New York Governor Cuomo announced in his State Address the goal of 3000MV (or 3GW) of energy storage by 2030, and an interim goal of 1.5 GW by 2025.5 To contextualize this, according to Wood Mackenzie data, the commercial storage sector grew 53 percent in 2018, ending with a record 30.5 megawatts deployed in the fourth quarter, which is only a fraction of the goal. 6 

All of this is under the larger umbrella of the Reforming the Energy Vision Initiative, which is New York’s comprehensive energy strategy with a goal of  “85% reduction in greenhouse gas emissions by 2050, 100% of clean electricity by 2040, and 12 GW of distributed solar and offshore wind energy by 2035.” 7 This vision tackles some of the fundamental challenges our grid increasingly faces, which can be summarized into three main buckets: 1) challenges with meeting peak periods, 2) lack of system resilience, and 3) incompatibility of renewable energy with the current grid. 

​At 5PM, when everyone heads home from work to switch on the stove and flip on the TV, power plants ramp up (Figure 2). This is also when wind slows down and when the sun starts setting. America’s evenings are powered by coal, natural gas and nuclear energy, and as utilities are forced to bring online old plants and extra generators to meet demand, electricity made at peak hours is much more expensive. 98% of the time, demand is within limits the utility can meet. The problem is that 10 percent of the utilities resources are devoted to the other 2 percent of the time; in New York, paying for this idle capacity year-round costs customers around $2 billion a year.9 The BQDM Program above is an example of one solution REV is deploying to tackle peak demand. Through government supported market activation, new technologies like smart thermostats and smartgrids can allow utilities to manage peak periods, as we often unknowingly use more energy than we actually need. They want us to pay them something for the electricity they are capable of producing all night long rather than using nothing during this time and worse, asking them to spend even more money to bring backup power. It can also provide us with sufficiently accurate information to enable us to monitor and control our own electricity use, giving us more autonomy in our own consumption.

As more than 60% of New York’s grid infrastructure enter into their fourth decade of use 10, we are seeing an increase in blackouts caused by anything from overgrown foliage to SuperStorm Sandy. It is estimated that for every minute of an electricity outage, businesses lose on average of $10,000 11. Thus, it is easy to see that the grid needs resilience not only for reasons like national security, but for the sake of the US economy. While resilience means infrastructure modernization and building new wires, which the US spent a total of 25 billion dollars doing in 2018,12 it also means backup systems that seamlessly integrate into primary systems. REV sees the solution as one requiring diversification: in the same way that we value diversification in our economic portfolios, sources of energy generation must be multifaceted, relying on big nuclear and hydro, backyard solar and wind, and also battery storage, fuel cells, and conservation and energy efficiency measures. 

​However, this is not as easily said than done, and one of the key challenges of both the physical and governmental infrastructures of the modern grid is its incompatibility with renewable energy. Firstly, sustainable energy is an inconsistent variable power with spikes and dips that our grid, hungry for consistency, is unprepared to take on at any moment. Secondly, our current utility regulations do not align incentives of utilities with those of customers, solar panel producers, and those pushing for more renewable energy. For a lot of solar panel installers, their electric bill is nullified because utilities are paying for the energy they feed back into the grid. As more people opt for panels and with no household electricity storage solution, the grid is flooded with electricity, yet simultaneously starving utilities of money to maintain it.13 The utilities’ solution is to raise rates on customers that still rely on the grid. People without panels end up paying much higher utility bills to maintain infrastructure that people with panels still use everyday - on days when there is no sun. More people, including some of the utilities’ biggest customers like Walmart and Ikea, have begun to purchase their own renewable resources through third-party Power Purchase Agreements.  A Navigant report estimated that microgrids could become a “$40 billion-a-year global business by 2020, siphoning about 6 GW of business away from utilities.”14 An EY report approximates electricity cost savings to commercial companies in twenty companies to be between $64 billion and $171 billion  in 2020 ––– savings that could often otherwise be utility revenues.15  As rates get increasingly expensive, more and more consumers are pushed to defect from the grid, further raising costs on fewer customers and resulting in what is known as “the utilities death spiral.”16 Regulatory reform must ensure that utilities’ profit incentives are aligned with the growth of renewable energy, and the REV tackles that by allowing utilities to become Distribution System Platform Providers that profit from the sale of technology like solar panels. 

​Looking at these challenges, it becomes apparent that storage is a cornerstone to resolving issues of energy efficiency, resilience, and renewable energy integration. Below, this paper will focus on the technological and regulatory changes the BQDM program under Reforming the Energy Vision attempts to excise, and how effective it has been in moving as many levers as possible.

The Brooklyn-Queens Demand Management Program

Program Overview

On December 12, 2014, the New York Public Service Commission approved of a $200 million budget for the Brooklyn-Queens Demand Management Program.17 A few months before, Con Edison had projected that a 69MV (Figure 5) of demand growth above existing capacities would overload existing infrastructure as early as 2018, and had proposed a traditional solution, at the estimated cost of 1 billion dollars, to upgrade infrastructure such as building a traditional substation by 2017, expanding an existing 345 kV switching station, and constructing a sub-transmission feeder to connect the two stations. The BQDM emerged as a non-traditional, less-costly solution to instead, focus on demand-side solutions instead of the traditional supply-side infrastructural changes.

​As mentioned above, the Program is divided into customer-facing “Behind-the-meter” (BTM) solutions such as installing smart home appliances, and utility-side “front-of-the-meter” (FTM) solutions including energy storage systems. The storage project detailed in the introduction is an example of a FTM solution, and upon its success, ConEd has requested funding for six more utility-owned energy storage projects totaling 31.5 MW / 120 MWh in a recent case filing.18 An example of a BTM solution is ConEd incentivizing a 300 kW / 1.2 MWh solar-plus -storage microgrid at the Marcus Garvey apartment complex in Brooklyn. To further accelerate deployment of energy storage projects in both retail and wholesale power markets to meet the goal of 1500 MV storage by 2025, NYSERDA has rolled out an incentive payment structure at a fixed amount per usable kWh, starting at $110/kWh in 2019 for bulk storage,19 and $2100/kW 20 for battery installations in Brooklyn and Queens. Working together, these solutions reduce peak hour energy consumption, and store energy generated in non-peak hours for use during congestion periods.

​Dr. Catalina Spataru, professor at UCL’s Energy Institute, says that for microgrids, “the first challenge is financing. Though microgrids have a proposed payback of six years to 10 years, nobody has actually gotten their money back so only an investor with vision will take the risk.” 21 New York’s solution is for utilities like ConEd to have a direct stake in building new microgrids. Historically, non-traditional solutions like energy reduction in households were treated as an operating expense passed on to end-consumers without any earnings. Now, with legislative changes under the REV, utilities are becoming distributed system platform providers, earning a direct cut from every microgrid or storage solution that is built. 22 

​Furthermore, utilities will earn “Earnings Adjustment Mechanisms” –– short-term performance-based incentives that reward utilities for areas including peak load reduction, energy efficiency, interconnection of DERs with the grid, and customer engagement.23 Under the BQDM, that manifests as basis points including 100 for their initial capital investments, 45 tied to successfully reducing 41 MW of demand with alternative measures, 25 to increasing diversity of DER in the marketplace, and 30 basis points are tied to achieving a lower $/MW value than traditional investment solutions,24 which translate to financial compensation from the state.

Program Performance

1. Peak load reduction

BQDM’s third quarterly report showed that deployments consisting of storage and conservation solutions have increased 32% quarter-over-quarter, driven by a rapidly growing front-of-the-meter segment and a roughly flat behind-the-meter market.25 Figure 3 shows that New York storage capacity is projected to rise to 1200MV by 2025, 26 contextualized by the projection that US energy storage annual deployments will reach 5.4 GW by 2024 (Figure 4). The diagrams show almost exponential growth to storage deployment, which will bring New York to the forefront in the national energy landscape for storage resources.

​

Cost-benefit analysis suggests this program has been economically beneficial. Since the program’s inception, ConEd has expended $105.96 million (83.51 million on customer-side solutions and 22.35 million on utility-side solutions), yet yielded a total of $747.8 million of benefits from delaying substation costs, 27 avoided capacity losses, and transmission investments (Figure 1). It is also worth noting that upon comparison, every million devoted to customer-side solutions has yielded 0.48MV of reductions (from total of 40.5 MV), while every million devoted to utility-side solutions has yielded 0.83MV (from total of 18.5 MV), which is almost twice the effectiveness of customer-side solutions. This raises the question of whether it would benefit utilities more to invest in utility-side solutions in the future, but also shows that transitioning away from utility-centric energy storage will require a large up-front investment that may not be initially profitable, but important for the long run customer autonomy of energy consumption.

2. Market efficiency through free-market incentives

Storage and microgrid solutions owned by consumers provide distribution loads while also testing the ability to churn in revenue by participating in wholesale electricity markets like the one run by the New York Independent System Operator (NYISO), an organization entering its second decade of existence with a purpose to select the lowest cost resources capable of most reliably meeting energy needs. Since its inception, NYISO harnessing the powers of free-market incentives has reduced power costs by 23%; 28 now, with the further integration of DERs, costs are likely to fall further as renewable resources, such as hydro, wind, and solar energy have no fuel costs, “making them more competitive in the NYISO energy market’s scheduling process than older and potentially less efficient fossil generators”. 29 Their drawback, as mentioned, is their variability as a result of changing weather conditions, and this is an area that NYISO promises further progress on as the installation of advanced metering systems will gather more data points that will allow utilities and markets alike to set time-variant rates that takes into consideration the increasing fluctuations of energy supply.

​In fact, under the REV, which mandated each utility to propose a test “Smart Home Rate”, Con Edison was the first utility in New York to have Advanced Metering Infrastructure (AMI) plan approved. 30 This rate is intended to rectify the dysfunctions in current pricing, which do not take into account the variability to cost in energy generation; consumers have no incentive to avoid high levels of consumption at times or locations when generation is most expensive, increasing costs for everyone involved. 31 Now, residential customers who are early adopters of new technologies that the BQDM incentivized them to install, will now further have the opportunity to manage their energy consumption in the cheapest and most efficient manner.

3. Renewable energy integration

At the core of the REV program is the “distributed system platform,” for which utilities liked ConEd are providers. This is a transactional platform that will allow for greater grid flexibility and intermittent energy usage compatible with renewable generation. By assigning utilities the important role of managing and facilitating the distributed platform for future energy production, utilities are able to shape the future marketplace. However, the platform is still in its early stages and success is hard to gauge. 

Nevertheless, one significant development is the wide-scale installation of new battery storage units as part of Con Edison’s Storage on Demand demonstration. In most parts, microgrids still typically use diesel generators to provide reliable backup. 32 The battery storage in Ozone Park is an example of the 2MW / 4 MWh mobile storage model that will deploy to areas of grid need in locations that may have otherwise been served by utility diesel generators. As discussed previously, storage systems are one of the easiest solutions that can handle the inconsistencies of renewable energy, and the goal of 1.5GW storage by 2025 will be a game changer in an energy landscape that expects an annual deployment of 6GW in distributed solar energy.

Lessons Learned and Further Considerations

Business Model for microgrids

The BQDM initiative illustrates the success of the hybrid ownership model, where battery producers and utilities co-own the storage projects, supply private end-users, while funded by public institutions. Installed just a few days ago, the 4.8 MW/16.4 MWh battery system located at Related’s Gateway Center in East New York illustrates this. 33 Battery producer Enel X installed, owns and operates the system, which was in part paid for by Con Edison through the BQDM Program. Enel X receives payments when the battery system delivers energy to the grid, and leases the land from Related Companies. 

​This kind of hybrid ownership is often called Public-private ownership (P3’s), 34 where responsibilities for design, construction, finance and long term operations and maintenance is bundled together and transferred to a private sector partner. It mimics the traditional separation of energy distribution from energy generation, as greater competition among private-sector solutions brings down overall costs. Hybrid ownership also allows for each stakeholder to focus on their singular objective –– to operate the microgrid, or finance it. 

​Another way utilities have financed microgrid construction is through rate bases. One example is in Illinois, where utility Commonwealth Edison tried to rate base a $25 million micrigrid it had proposed in Bronzeville, Chicago. 35 In some states like Illinois, generation and distribution must be separated; this is problematic for utilities in the generation sector that want to get into the distribution sector, which is arguably where the future of energy lies. This also means utilities like ComEd may not own microgrids as they combine elements of both generation and distribution. Nonetheless, ComEd argued that the Bronzeville project qualified as a distribution asset, which in 2018, overturned the initial ruling and granted ComEd the order to install the first utility-operated microgrid cluster. 

​In the past decade, the integration of microgrids in the energy scene has arguably been slow largely because utilities have been tasked to take the helm. While the Bronzeville case shows a success, especially as utilities also argue that a utility-owned and controlled microgrid can lead to more efficiency and system stability, a problem with utility-owned projects is their lack of a single customer to clearly bear the costs. The question then becomes whether costs should go to the entire rate base as in the case of Chicago, or just interconnected customers. 

​The two main drivers in the microgrid market are regulated utilities that see an opportunity to replace traditional infrastructure with more resilient deployments financed through the rate base, and private-sector business that are increasingly see financial opportunities in owning and operating a microgrid through long-term power purchase agreements. The success of the BQDM is that instead of pitting utilities against private-sector battery business, a multi-stakeholder ownership reduces costs for the end-owner, increases energy efficiency as utilities to use microgrids to strategically target congestions on the main grid, while ensuring that storage-solution companies and utilities are both financially compensated. One of the challenges listed in the beginning is the siphoning of profit away from utilities as large corporations begin island-ing themselves to their own microgrids; the BQDM model demonstrates that microgrids are indeed compatible with current infrastructure, and that when incentives are aligned, utilities are increasing interested in owning or co-owning smart grid deployments.

​In many instances, private funding on its own is not adequate and does not have a direction in which to flow, while public funding is constrained by policy. This blend of resources from different stakeholders can do things that meet both private and public purposes.

Power and perils of free-market dynamics

One of the most important takeaways from the Brooklyn-Queens Demand Program is the harnessing of free-market dynamics to increasingly give more power to the people in their energy choices at increasingly lower cost. Kenneth Horne, energy director at Navigant, says “The dilemma for microgrids, like storage, is that the technical value is way out in front of the market and regulatory environment that would allow that value to be monetized.”36 As government-funded programs like BQDM spur on customers’ installation of solar panels, battery storages and other DERS, the increased network effect will continue to lower costs as utilities gather more data points; meanwhile, regulations have kept up with the technological changes, and the economic incentive behind newest rate structures making early adoption profitable means that change is no longer just driven by environmentally conscious households. For utilities, the financial-incentive has come from a fundamental change in regulation that no longer mandates capital expenditures as the only source of profit margins, which is something that can be replicated in states that still have misaligned regulations. 

​Increased price transparency, more effective investment signals in the energy wholesale market and private ownership of distributed energy resources for shared use gives consumers more autonomy in their energy consumption. As we begin to choose the prices of the energy we are buying and selling, as suppliers of energy shift from remote utilities to the friendly solar panels in everyone’s backyard, new opportunities, benefits, and environmental and public health merits emerge for everyone. 

​However, we need to make sure that these positive results are equitably experienced among all participating members of society, as introduction of market forces also comes with insidious side effects. Historically, the construction of major infrastructure has always come with inequities, where communities of color and low-income households disproportionately have to bear the costs of the development, yet reap the least benefits. Even now, in its initial stages, BQDM has, to some extent, continued to exacerbate those inequities. 37 For example, low-income customers may have more difficulty demonstrating credit worthiness through conventional screenings, like FICO scores, and may not directly own the house or apartment they reside in to allow them to install new DERs. Achieving a just transition is not only important for the disadvantaged populace, but also for the  successful implementation of the REV program. If 40% of New York households are low-income 38, that means these policies are inaccessible to a large part of society whose participation is imperative. In addition to achieving environmental goals, the empowerment that comes with owning a source of energy generation has the potential to grant increasing economic opportunities too to disadvantaged groups, which could provide as an important stepping stone that previously did not exist. Hence, ensuring that all communities have access to renewable resources becomes not only a question of equitable energy distribution, but a matter of economic imperative. 

Profit structure of utilities 

One lesson that lawmakers are able to generalize from the success of BQDM program’s profit structure is its non-wires compensation approach, where utilities can profit from avoiding certain infrastructure upgrades. This represents a fundamental paradigm shift from traditional utility rate plans, where utilities spending less than it planned to on capital improvements have to return the difference to ratepayers in the next rate case. 39 This makes sense: utilities should not earn returns on uninvested capital. However, new policies are allowing utilities to retain earnings on unspent capital until the next rate case if they can demonstrate that a capital expenditure was reduced due to a non-wires alternative (NWA), like storage solutions and optimization of energy transmission. In New England, it is estimated that reducing transmission and distribution costs save up to $30 to about $200 per kW, 40 further emphasizing the benefits of NWAs.

​While utilities’ profit structures continue to converge with a future of greener energy consumption, there are still gaps within the system. One example is in the smart home rates that Con Edison pioneered within NY state but have been widely adopted elsewhere such as in California and Vermont. In New York, where the utility does not own electricity generation and the utilities main priority is to manage distribution costs, time-variant pricing may not actually have environmental effectiveness. Because there is a divergence in time of peak generation and the times of greatest stress on distribution infrastructure, utilities like ConEd will be incentivized to use Advanced Metering Infrastructure to reduce costs in distribution, which will do nothing to relieve peak demand in generation for which there is largest environmental concern. For example, in residential Brooklyn, the distribution system is most stressed in the evenings. However, generation is at its peak around noon, which is when backup plants are called into service due to high industrial and commercial consumption in other locations. 41 In other locations, like Manhattan, peak distribution and generation align well, which is where peak price targeting is the most effective. 

​This raises greater questions on the difference in policy approaches for vertically versus non-integrated utilities; on the one hand, a clear separation of incentives between generators and distributors of energy lead to lowest costs for consumers, but it also means that blanket solutions may not target root causes. Under REV, distribution utilities do not have economic interest in minimizing carbon dioxide output. While there are other policies that directly tackle that, it is worth noting that incentives under REV – Earnings Adjustment Mechanisms – exclusively focus on areas of energy efficiency, like peak load reduction. This reflects a fundamentally nearsighted understanding of our electricity system, where reducing electricity consumption becomes the goal, instead of minimizing carbon dioxide emissions as the ultimate goal. Less electricity consumption can contribute to results, but so can stable consumption; in fact, more consumption can do so too, if higher-emitting fossil fuels are replaced with environmental sources. 

Conclusion

As we look to what lays ahead, we should increasingly expect a future of higher electricity consumption, where customers reliance on the electric grid is changing alongside a shift in the role utilities play as our energy market becomes more democratized. The BQDM shows that a joint public and private effort can lead to great success in incentivizing the installation of demand-side solutions such as energy storage units, but it has also shown us the struggles to scale that many other states continue to face, including limited access to financing, burdensome approval processes, and limited consumer trust. 

​Indeed, within New York, battery storage in the short term is still insufficient to fully meet peak demand, even with the growth levels envisioned by policymakers over the next decade. Technological constraints such as lower capacity, intermittent reliability, and shorter-duration resources entail that non-wire alternatives will still require a full portfolio of resources –– from fossil fuel plants, to wind farms down the road –– that can be relied upon to maintain bulk power system reliability. We just have to make sure that those supplying this reliable source of energy are a part of the green future too.

​The Brooklyn Queens Demand Management Program is only the tip of the iceberg in levers we can pull, but it gives hope that utilities may be less rigid than we think as long as we give them the right incentives. It paints a preliminary picture of a future where energy transmission is multidirectional, where old-fashioned fossil fuels meet large-scale wind farms meet backyard solar panels and all outputs intermingle intelligently on the wires. This is also a future where consumers have more power, and the energy infrastructure as we know it today is replaced by a wholesale energy marketplace, regulated by utilities, but where we are all consumers and suppliers. 

​Even with the progress made, we have seen that financial incentives are not always aligned, private funding may not always move in parallel with public funding, and some communities may be left behind. We see progress on peak demand reductions, but we also must ask if it is enough of a change to meet the 2030 goals, or the wide scale overhaul of the energy sector that we gravely need. As we step foot into the next decade, let us take the lessons learned from Ozone Park to build a technological and regulatory system that gives more power to the people. 

​

Diagrams

Fig 1: BQDM Peak period energy reduction in third quarter 2019

Source: BQDM QUARTERLY EXPENDITURES & PROGRAM REPORT 

Fig 2: Peak Demand in 24 hours

Source: 

https://nystatesolar.com/con-edison-demand-management-program-brooklyn-queens/

Fig 3: US energy storage annual deployment 2012-2024    

Source: Wood Mackenzie Power & Renewables

Fig 4: New York storage capacity forecast

Source: NYISO Power Trends 2019 Report

Fig 5: Utility-side solutions for peak demand reduction across the country 

Source: NYISO Power Trends 2019 Report

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32. “Governor Cuomo Announces $3.6 Million Available to Help Low-to-Moderate Income Residents Access Clean, Affordable Solar Energy.” Governor Andrew M. Cuomo, December 7, 2016. https://www.governor.ny.gov/news/governor-cuomo-announces-36-million-available-help-low-moderate-income-residents-access-clean.

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