Nanotech Plus, LLC - CT Renewable Energy Transition Roadmap

Executive Summary

The Challenge: Like all states, Connecticut faces the daunting task of transitioning from fossil fuels which have powered the economy for well over a century to an economy powered by solar and wind power. If we continue on the current path, this will cost state taxpayers and ratepayers billions. But, if Connecticut faces the challenge of transitioning to renewables successfully, this will provide strong economic and quality of life advantages for the future, while providing jobs building this infrastructure now. Currently there are matching federal funds available through DOE programs that reward novel approaches such as what has been outlined in this white paper of providing safer storage at the commercial and industrial scale.

States that quickly adopted renewable generation such as California, Texas, and Hawaii have shown that there are a number of pitfalls along the way. New York has taken a more measured approach and has developed a complex roadmap with an extensive plan that was first drafted in 2019 (See: Climate Act). Connecticut should consider the approach that New York took, but it is clear that New York’s roadmap could be improved.

The Problem:

On its current track, Connecticut will not come close to meeting its stated 2030 goals:

Reduce greenhouse gas (GHG) emissions by 45% from 2001 levels (PURA Docket No. 17- 12-03RE05)
1 GW (As of mid-2023, we had less than 50 MW, PURA Energy Storage Solutions)
65,000 EV charging ports (DEEP EV Roadmap for Connecticut)
Over 500,000 vehicles to be EVs (As of late 2024, we have less than 40,000, DEEP EV Roadmap for Connecticut)

Our electric grid positively and negatively directly impacts local economy, lifestyle and affordability.

Even though production costs of renewable energy and storage are decreasing, ratepayer costs and EV charging rates will continue to be among the nations’ highest.

Such high costs disproportionately impact disadvantaged neighborhoods and make it more difficult for the legislature to attract new businesses to the state and to keep existing businesses in Connecticut.

If Connecticut’s grid becomes unreliable, this will provide a further disincentive for businesses to operate in Connecticut and will decrease the quality of life. (At a recent conference, representatives of one of Connecticut’s major EDCs remarked that rolling blackouts are looking likely in the next few years. EDCs cannot increase rates, yet are unable to formulate a plan to deal with the coming increased demand of rising temperatures, heat pumps and EVs without additional generation and transmission.)
Utilities have been unable to account for the economics of energy storage for decades with their current business model.

The state legislature’s next few sessions will be critical for the future of Connecticut’s energy, transportation, and other industries for the foreseeable future. Businesses and residents need to feel confident that Connecticut has a plan to ensure that the price of electricity will decline while delivery will become more reliable. The legislature has a critical role to play here:

The utilities business model was never intended to support such a transition.
Other than fossil fuel companies and the utilities, there are no other large stakeholders in the state that would be adversely affected by this transition. With the correct business model- utilities could profit as well.
With input from critical stakeholders, the legislature could craft legislation that would be a win-win for the utilities, businesses and residents in the state.

The Solution:

Establish a Study Committee will allow a deeper study of Connecticut electrification allowing all interested parties to gather at the table and develop a roadmap. Include science and financial experts from outside the highly regulated utility industry.
CT Utilities are not as economically efficient as utilities in less regulated states such as Texas. There was 43 TWh generated in the state in 2022, but only 28 TWh was sold. Other states are far more efficient at selling the power that is generated. If this unsold power is stored for when it is needed, then the state could reduce fossil fuel generation and save money, while simplifying the task of adding new renewables generation. Debacles in other states have shown that it is vital to install storage prior to renewable generation.
Distributed storage offers significant benefits of resiliency and energy efficiency not available from utility scale storage. Business models need to account for these benefits.
Although electricity is a commodity that has to be produced, transported and occasionally stored, finding data to understand the relative costs of these steps is quite challenging. The difficulty in developing new business models should not be underestimated as California took nearly four years to work out a plan to integrate residential solar and storage into its existing grid (See: California’s new rules allow solar and batteries to help out the grid). However, Connecticut can learn from other’s mistakes to construct its own roadmap.

How to Construct a Roadmap

The transition to renewables requires an “all hands on deck” approach. Ideas from academia, finance, construction, and manufacturing, as well as the utility industry are needed to come up with new business models so that Connecticut can develop a flexible and efficient roadmap for the transition to renewable generation. One of the less understood aspects of this transition is the vital role that storage must play. While utilities have failed to price storage correctly for decades, they are now facing competition as solar and storage costs drop which may provide an additional incentive.

Business owners may decide that having their own storage which provides resiliency and the ability to arbitrage- to purchase electricity when prices are low and use it when prices are high is worthwhile. This means that utility scale storage would have to compete with commercial and industrial (C&I) storage and this competition is likely to bring costs down. Solar generation at C&I scale as well as residential scale will also provide competition for utilities. Deregulating some aspects of utility operation should be considered to encourage more innovation. Thus, while there are many challenges ahead, there is also the enticing carrot of lower cost electricity which will help the state be competitive economically and to improve quality of life.

Introduction:

The US confronts a major challenge: how to transition from a fossil fueled economy to an economy powered by renewable forms of generating electricity. While the technology exists to do so, business models have yet to be developed. Existing utility business models reward capital spending rather than economic efficiency and because renewable generation is more efficient when distributed rather than centralized, less large infrastructure is required threatening the utilities existing business model.

This white paper suggests a novel business model of siting storage for electricity (battery energy storage systems or BESS) close to where the electricity will be used, i.e. businesses. For example, this will be especially important in the new business of charging EVs. Local businesses are in a far better position to decide what their needs are for electricity storage rather than utilities. If the correct incentives are put in place, a thriving competitive marketplace for storage will develop that may also eventually incorporate renewable generation as well. By providing the correct incentives, the costs of electricity in Connecticut should get closer to the national average which will reduce the state’s economic disadvantage and spur economic and job growth.

The transition to renewable energy can seem pretty daunting, but here’s the good news: at the end of the day not only will there be environmental benefits but the cost of energy should decrease as well- which is vital to economic growth. All the needed products: solar cells, wind turbines, power electronics, batteries and electric vehicles are available and relatively affordable. Furthermore, costs of several of these key products are coming down significantly in the next few years. Transitioning to renewables from fossil fuels is an opportunity to save money in several sectors: transportation, electricity, and health care- the impact of which should not be underestimated. Fewer emissions from fossil fueled power plants and vehicles will not only reduce CO2 and some other greenhouse gases, it will also reduce particulate matter that leads to respiratory diseases and other illnesses.

The bad news: the incumbent industry players have strong incentives not to change the current system and often communicate in what can be politely described as industry jargon. This process obscures assumptions which often have grievous flaws.

A Brief History of the Power Industry

The modern power industry evolved post WWII as by the 1950s, nearly all the country’s farms had access to electricity, while in 1942, only half did. This rapid electrification of rural areas meant that extensive generation and transmission had been quickly constructed. Power production was based upon large centralized power plants which were the heart of the electrical grid. The use of alternating current (AC) at a uniform frequency ensured that neighboring grids could be connected with no ill effects (Ensuring the stability of a grid entails making sure that loads and generation are balanced. Either excessive demand or excessive generation can cause problems. Utilities monitor their grids from centralized control rooms and generally perform this task well). These centralized power plants used a variety of fuels such as coal, oil, natural gas, and uranium to produce heat and hence are referred to as thermal plants. These plants had economies of scale so they increased in size over decades to a maximum of about 1-2 gigawatts (GW) and power became cheap and plentiful for several decades. However, emission requirements were not part of the original planning and it has proven to be very difficult to modify existing plants to meet these additional constraints. With the exception of nuclear power, all thermal plants emit large volumes of greenhouse gases. Transitioning to power plants at smaller scales (most renewable energy projects are smaller than 1 GW) and with more distributed resources does not work well with the centralized power business model.

The Failure to Develop an Economic Model for Storage

A technology to store electricity on a large scale has been available for decades, i.e. pumped hydro storage. Water is pumped up to a higher reservoir when there is excess power available and used to spin a turbine and generate electricity as it flows to the lower reservoir when power is needed. Currently there are 550 GWh of pumped hydro storage in the US, mostly built between 1960 and 1990 (See: How Does Pumped Storage Hydropower Work?) which is roughly an order magnitude greater than battery storage today . However, while there are a number of new Battery Energy Storage System (BESS) installations planned, new pumped hydro installations are few and far between and it is likely that by 2030, BESS will dominate storage technology in the US. While CT Greenbank has helped finance 3 small hydro projects (See: Connecticut Green Bank), this does not amount to a significant fraction of the states’ storage needs (See: National Hydropower Association)).

Unfortunately, good economic models to value storage have not been developed, even though a viable technology was in place. Since storage can serve as both a generation asset and a transmission asset (One of the challenges is to actually get good data on the costs of storage. As an example, this work: Energy Storage Cost and Performance Database omits two battery technologies that are well suited for Connecticut’s needs, i.e. iron flow and nickel-hydrogen) correctly valuing storage requires looking at reduced transmission requirements which are avoided costs, while also including the value of both unpaid generation and grid ancillary services. Recent work focused on this former aspect of storage has shown that storage can often replace transmission at a fraction of the cost (See: Energy storage is a cost-effective alternative to transmission to integrate renewables: study).

This failure to correctly value storage is perhaps the largest stumbling block today in the transition to greater use of renewable generation to replace fossil fuels. Battery storage is becoming increasingly economical, (roughly an order of magnitude less expensive than pumped hydro capital costs) but the question of who pays and who benefits still remains. Renewable generation (wind and solar) is now less expensive than large thermal plants, but requires storage to be practical. Without storage, the intermittent nature of renewable generation would be difficult to tolerate. Clearly, utilities have not solved this problem of how to correctly value storage either in Connecticut or on a national basis for decades. This failure strongly suggests an alternative approach is needed which will be a key aspect of the roadmap.

Nonalignment of Utilities Goals - ISO/RTOs

The country is divided into a number of Independent System Operators (ISOs), Regional Transmission Operators (RTOs) and Independent Power Producers that operate their own grids. Connecticut is part of the New England ISO which consists of the 6 New England states. All states in the NE-ISO have some of the highest retail prices on electricity in the country (taken from 2022 EIA data: www.eia.gov/electricity/state/), often above $0.20 per kWh, while the average cost of electricity in the US is ~$0.125 per kWh. This strongly suggests that membership in the NE-ISO has a much stronger effect on electricity rates than how many programs the state has to promote renewable energy. Within the NE-ISO, Vermont and Massachusetts have a number of innovative programs, while New Hampshire lags other states significantly, see, State Portfolio Standards Are Rising (See: New England Power Grid State Profiles). A non-profit group, Acadia Center, has suggested that the current business models of the NE-ISO, where transmission projects that meet with NE-ISO approval are funded by all 6 states, while projects that do not meet the requirements of the organization are funded solely by the state supporting the project strongly influence transmission planning and drive overcapacity. Looking at the costs of transmission in the NE-ISO provides support for the contention that there are poor incentives in the program to save money, while costs of transmission in the NE-ISO are more than double other regions (See: Assessment of the ISO New England Electricity Markets). Recent announcements that major transmission upgrades are needed through 2050 provide support for the contention that NE-ISO planning continues to use an outdated business model as there is no mention of the role that additional storage could provide to decrease the need for additional transmission (See: 2050 Transmission Study). Further support for this idea comes from a recent study by NY BEST which concluded that storage could obviate the need for much of the proposed new transmission (See: Storage as Transmission Asset Market Study).
N.B. The replacement of existing thermal plants by wind and solar plants will certainly require new transmission. However, this requirement suggests a near term buildout of transmission, with diminished construction by 2050, if as the report assumes, that renewable plants have largely replaced existing generation.

The Acadia Center has also pointed out that utilities favor capital expenditures over efficient energy delivery (See: Utility Innovation). This group has worked with various state legislators to improve the economics of grid modernization for various regions including New England.

Roadmaps for Renewable Generation - Scarce and with Numerous Blank Spaces

When you want to go somewhere, it’s helpful to have a road map. One of the reasons that there have been consistent advances in computer technology (Moore’s Law) is that the semiconductor industry uses roadmaps developed by SEMI- the industry organization. There has been very little deviation from these plans- “disruptive” is not a word that’s used in the development of computer chips.

The electricity industry doesn’t have that kind of rigid plan. In fact, what’s become pretty clear is that the power industry doesn’t have a very good idea of how to get to a grid powered by renewable energy as this type of innovation is not “in their wheelhouse”. The financial incentives of the utility industry are rather unique and strive to increase capital spending to earn a return rather than a conventional business model of growing sales or reducing costs to increase profitability. Because renewable energy generation is now less expensive than traditional thermal plants, utilities lose money installing renewable generation rather than thermal plants. Recent announcements in the Southeast that demand was growing faster than forecast led the utilities to propose new thermal plants to meet this demand- not renewables (See: More demand, more gas: Inside the Southeast’s dirty power push).

Development of Connecticut’s roadmap will provide more guidance than what is happening today, but the roadmap needs to be flexible enough to account for unforeseen factors.

Progress Is Maddeningly Slow

The utility industry has been dragging its heels in terms of moving to renewables and progress has been at a snail’s pace. One way the industry slows the process down is through the connection process which takes a lot of time and money- the median wait time for connecting a utility scale project to the grid is 5 years. Obviously, building a renewables plant or storage facility is useless without a way to connect to the grid. One way to connect to the grid is to utilize an existing connection from a shuttered thermal plant, but this can place a lot of constraints on the size of the project and also often requires storage so that the utility can consider the resource “dispatchable”.

Most of the projects in the interconnection queue will not make it through- currently less than a quarter today are successful (See: US grid interconnection backlog jumps 40%...). This of course, drives up the cost of developing these projects. To deal with this problem, DOE has recently released a roadmap which strives to reduce queue times to less than 12 months by 2030 and increases the approval rates to 70% (See: DOE releases new transmission interconnection roadmap to address clean energy backlog).

Unfortunately, long queue times will be inevitable for the next few years which means that if Connecticut is to meet its storage goal of 1 GW by 2030, a new pathway must be found.

Connecticut’s Position

At first glance, Connecticut’s position with respect to transitioning to a grid powered by renewables appears laggardly, but actually, Connecticut has a strategic advantage. We can learn from the mistakes of the early adopters. For many years, California led the country in renewable generation installations, although recently, the number of installations in Texas last year was higher. Grid operators and regulators in California and Texas did not understand that renewable generation would require storage and that has led to some debacles. For example, California’s recent about face on the economic provisions for residential solar has led to a nearcollapse of the rooftop solar industry (See: California’s rooftop solar policies threaten progress on climate). Expected reductions in emissions did not appear because without additional storage, rooftop solar provided power when it was not needed (driving power prices negative (See: Rooftop solar panels are flooding California's grid) and could not supply power during peak demand- the so called “duck curve”- which is getting worse (See: As solar capacity grows, duck curves are getting deeper in California). Unfortunately, California did not adopt the rules promulgated in Hawaii which required that new residential solar generation be coupled with sufficient storage (See: Hawaii utility wants to pay households to share clean energy). It took nearly 4 years for the stakeholders in California to hammer out an agreement involving solar and storage to support the grid by absorbing power when demand was low and selling power back when demand was high (See: California’s new rules allow solar and batteries to help out the grid). Prior to this agreement, utilities had viewed residential solar and storage as a threat to their monopoly, but now California may be able to reduce some of the economic and emissions burden of the deepened “duck curve” and allow utilities to focus on hardening the grid from wildfires.

The Texas blackouts of 2021 were the result of a freak snowstorm when numerous grid failures occurred including all types of generation going offline (See: Texas Electric). If there had been sufficient storage in the state, this cascade of events might have been prevented. Needless to say, Texas is now adding storage at a furious pace (See: San Antonio Express-News).

Getting storage right is critical to the transition to renewable energy (See: MIT News). The policy failures in California, and Texas showed that It’s vital to have a large enough base of storage before increasing renewable generation. Installing renewable energy generation prior to installing storage provides a number of benefits:

Reduced Emissions from Existing Generation. Even without adding renewable energy sources, storage will allow more efficient use of existing generation assets. In 2022, CT generated ~43 TWh of electricity but sold less than 28 TWh (See: State Electricity Profiles). All of this generated electricity goes into the grid unless it’s produced on a captive basis but that’s a small fraction. Additional generation from rooftop residential solar has resulted in negative prices for power as seen in March 2024 (See: Is CT’s electric grid ready to handle more power?). By both reducing generation and storing the power until it can be sold, CO2 emissions can be reduced by over 500 lbs per MWh (EIA data from this spreadsheet: State Electricity Profiles).

Avoided Transmission and Distribution (T&D) Costs (See: Fluence). T&D upgrades are expensive and if the anticipated loads do not arrive, then these assets are stranded. In contrast, storage can be added in a modular fashion to overcome line congestion thereby reducing long term T&D upgrades. Calculations of the value of storage for these avoided costs requires proprietary utility data, however, NY-ISO data has shown that storage can significantly reduce transmission requirements (See: Energy storage is a cost-effective alternative...). The generous subsidies that Connecticut provides for residential storage (subsidies for low income households will cover ~ ½ the cost of an installation) show how significant these avoided T&D costs are.

Increased Resilience. Distributed storage resources means that in the event of grid failure, “islands” of power will still exist without the use of diesel or natural gas generators. While increased transmission may be unavailable if there is a widespread grid failure, distributed storage will still provide power for emergency services- and for long periods of time if coupled with solar generation. Storage can provide additional resilience at a fraction of the cost of transmission upgrades, however, there is no direct mechanism to financially compensate businesses for the value of their storage towards resiliency.

Highly Flexible Grid Support. Compared to a couple of decades ago, the grid has evolved in a way that makes engineers worry. There is far more variability in demand and generation. Variability in demand is driven by increasing electrification of both residences and businesses (Also driving increasing demand are new data centers, however, their power requirements are relatively static in comparison with HVAC and EVs. While data centers do require increased generation and transmission, their needs are well suited to large thermal plants). More homes and businesses are relying on heat pumps and replacing either natural gas or oil furnaces which means that there is both increased seasonal and hourly fluctuations in demand as well as increased air conditioning demands during warmer summer months. Charging EVs represents another major increase in the demand for electricity which may also fluctuate. Traditionally, the response of utilities to increasing variability in demand is to ramp up their reserve generation capacity that is available during the day and to build new transmission lines. Determining how much reserve generation is needed is what makes engineers worry because there are significant time delays- often at least a ½ hour to bring reserves online. In contrast, BESS can be available in a fraction of a second. Not only demand has increasing variability- so does generation as more wind and solar come online. Fortunately, there are a variety of mechanisms (See: The Importance of Flexible Electricity Supply) where storage can play a role to support the grid in a very efficient manner involving both the existing fleet and new renewable generation. If there is sufficient storage on the grid that can deal with the increasing variability of both loads and generation, then the grid will be stable and function efficiently while simple natural gas plants (There are two types of natural gas plants: simple and combined cycle gas turbines. Simple plants respond quickly but have an overall efficiency of ~25%, while combined cycle plants have an efficiency closer to 40% but are most economical when operated at peak capacity - hence they don’t respond to variable demand well.) will not be needed. Thus, even with the existing fleet, adding storage can reduce emissions significantly. Learning from the mistakes of both California and Texas, had both states installed more storage prior to adding renewables, then using renewables to replace the existing fossil fuel generation would have gone far more smoothly. The flexibility of BESS makes storage far more cost effective than new transmission since it can serve multiple functions. In contrast, transmission, which if it sits unused because there is no congestion, is just a large capital expense.

A Better Approach to Storage in Connecticut

To do storage correctly in Connecticut requires more than just a simple goal of “1 GW by 2030” (See: Connecticut beefs up energy storage...). There are three other critical aspects to storage:

Battery chemistry. Batteries used for battery energy storage systems (BESS) are NOT interchangeable- they have very different performance characteristics which dramatically affects the design, performance and economics of storage systems. While alternatives to lithium ion batteries ( Although slightly dated, this article shows some of the choices: Battery Energy Storage in Stationary Applications. Today several of those technologies and an additional technology- nickel hydrogen, are now commercially available at scale.) are now commercially viable, most utilities have chosen to stay with the market leader. Lithium ion batteries caused several fires at 15 MW and larger storage facilities in NY state in 2023 (In response, NY state convened a working group to make changes to the fire codes in the state. See: New York governor’s working group on BESS safety recommends changes to state Fire Code. We submitted comments to this working group.) as well as other locations around the globe (See: BESS Failure Incident Database) which should make utilities hesitant about these installations, but surprisingly, these fires have not raised red flags based on most of the projects underway. At least two far safer battery technologies, nickel-hydrogen and iron flow have already been demonstrated at utility scale and offer a highly competitive alternative to lithium ion.

Location. Identifying the correct locations for BESS to reduce line congestion and reduce T&D upgrades is critical to obtain the best economic benefit from storage. Location is also critical to increase resiliency. Because batteries have different size, noise and maintenance characteristics, some locations may favor one battery technology over another. One commercially available stationary BESS can conceivably be buried underground since it should need no maintenance for its design lifetime of 30,000 cycles or 30 years. Another BESS technology can be mobile as it is contained within a truck trailer.

Size. Both the utility and the battery industries consider the largest market for BESS to be utility scale installations (See: Enabling renewable energy with battery energy storage systems) which can be 1 GW per installation. Yet there are a number of advantages of smaller installations at the Commercial & Industrial (C&I) scale which is in the tens of MWh discussed below (This is not a novel concept and was being discussed at conferences back in 2016, often referred to as Community Energy Storage (CES). See: Economic feasibility analysis....)

The need for distributed storage in the state is clear as there are generous incentives for residential storage (See: Connecticut Green Bank). The program demonstrates the important concept that there are additional benefits from distributed storage which cannot be realized with centralized utility scale storage. But is residential storage the correct location?

There are three scales of storage: residential, commercial and industrial (C&I) and utility scale.

Residential storage is very expensive and has limited utility due to the small size of the batteries (typically 10-15 kWh). The benefits for stationary residential storage are murky for most home owners because if they own an EV, a vehicle to home (V2H) connection converts their EV to residential storage if needed during an emergency. Only if the home has solar generation sufficient for both the home and charging an EV does storage make sense, otherwise, how would you charge your car after work when the sun is down? In this case, the battery for residential storage needs to be on par with the size of the battery in the EV which is about 65 kWh- not the 10-15 kWh of most residential storage today. Residential scale storage is quite expensive- an average installation costs $1300/kWh. At those prices, a residential storage battery the size of what is found in an average EV would cost $85,000. Clearly, for most home owners, an EV is a far more economical form of storage as not only is the battery far cheaper- it comes with a car too!

Utility Scale is where market analysts predict batteries will be used for storage as ~90% of battery sales are forecast for this market. However, the lesson of Hawaii makes it clear that this assumption may be deeply flawed as it is far faster to deploy BESS at either residential or commercial and industrial scale. Currently there is a median wait time of 5 years in the interconnection queue for utility scale storage (See: Energy Markets & Policy) which means that if only utility scale is considered, Connecticut will not get close to its goal of 1 GW of storage by 2030. This long time frame means that most utility scale projects don’t make it through the queue which drives up development costs. Nor does utility scale storage provide the same resiliency benefits as more distributed storage since during a widespread grid failure, the storage is as unavailable as generation when the lines are down.

Advantage of Commercial and Industrial (C&I) Scale BESS Installations

Commercial and Industrial storage installations are a very attractive proposition when examined more closely.

Compared to residential scale, these installations have lower cost batteries. While residential scale batteries can cost 5x or more utility scale batteries, the cost premium for C&I is more modest- about 50%. It is possible that at larger volumes, C&I battery costs will approach the battery costs of utility scale.
Larger size than residential scale. At the C&I scale envisioned, the batteries are on the order of 5-20 MWh rather than 10-15 kWh. A single 10-15 MWh C&I battery has the same amount of storage as 1000 homes with typical 10 kWh battery installations which will drastically reduce operational expenses since there are fewer connections to the grid needed and the utilities control problem is greatly simplified.
Increased resiliency compared to utility scale storage. If there is a grid failure, the utility scale storage goes offline as well, while distributed storage (whether residential or C&I scale) can still provide power for emergency services. However, the much larger size of C&I batteries provides far more resiliency than residential scale systems. There may be an opportunity for federal dollars here as well (See: CT Department of Energy & Environmental Protection).
Fast pace of installation. Connecticut utilities may require 12 to 18 months to put in a 480V line necessary for larger scale C&I storage installations, but smaller scale installations can use existing 208-240V infrastructure. In either case that’s a lot shorter than the 5 year wait for project approval in the utility scale queue. The smaller scale of these installations means that if there are unforeseen issues, then the challenge of fixing these issues is much less burdensome.
Lower cost planning than utility scale. On a per MWh installation cost utility scale installations have the benefit of 50% less expensive batteries with current pricing models. Conversely, since over three quarters of these utility scale projects never reach fruition, there is a great deal of time and money wasted. Given the reduced planning requirements and much shorter time frames, project planning costs at C&I scale may be lower on a per MWh installed basis. N.B. If C&I scale proves to be a major market, then the battery price differential between utility scale and C&I scale will shrink.
Higher utilization rates than residential scale. Residential batteries are often going to sit idle but C&I batteries are likely to be used on a frequent basis. This makes the economics of C&I batteries far more attractive.
Higher efficiency than utility scale installations. C&I installations with the storage near the load will need fewer AC/DC interconversions if there are DC loads such as EV charging. Integration from rooftop or community solar also can reduce the number of AC/DC interconversions which reduces the capital expense and improves efficiency.

Currently residential storage in Connecticut has substantial subsidies for underserved communities and low income individuals of $450 and $600 per kWh respectively. These subsidies would essentially pay for the cost of a C&I BESS at current battery prices. N.B. As US battery manufacture of stationary batteries matures, there should be significant cost reductions as volumes increase and gigafactories come online in the next year. A cost reduction of 1/3rd is not unreasonable in a few years, which would drop the prices of stationary US batteries (ex. Iron flow, nickel hydrogen) well below lithium ion. Thus C&I scale battery installations have the virtues of both utility scale and residential scale storage. Pricing of C&I installations should be much closer to utility scale, while the virtues of distributed storage seen in residential installations are available at much lower cost.

The Lesson from Hawaii- Don’t Underestimate the Power of the Incumbents!

Hawaii shows a different cautionary tale than California or Texas- the strength of the incumbents. Since Hawaii’s electric rates are ~4-5x the national average, residential solar and storage makes a great deal of economic sense. After some missteps, Hawaii basically got it right for the past two years and was able to replace a coal fired plant with residential solar and storage which was built out remarkably quickly. The program to add storage paid homeowners the same price for electricity that the utility charged which drove a very rapid adoption of storage. Unfortunately, the utility in Hawaii put pressure on the regulators and a recently announced plan changes the incentives for homeowners drastically as this article makes clear (See: Hawaii used rooftop solar to shore up the grid). The program is now very difficult for the average homeowner to understand and creates a protected market for the utility as it becomes the only entity that can sell electricity at retail rates. This creates a perverse incentive for homeowners who if they supply electricity to the utility are forced to sell at a discount, while if they buy it back, have to pay full price. Hence, there is no incentive to sell to the utility at all.

About the CT IES Program

The CT-IES program has some lofty goals of driving the transition to renewables in the state and drastically reducing emissions. Unfortunately, based on the projects that have been approved from the first two cycles of the program, these lofty goals are very far from being achieved. Most of the approved projects involve software which can be funded with the relatively modest individual project amounts of up to $5 million, but emissions will not be reduced without major capital expenditures on storage, renewable generation, and transmission. Some of the projects approved have obvious flaws such as trying to charge EVs outdoors during a Connecticut winter, while the economic benefits of other projects appear murky when other competitive technologies are considered. Clearly, relying on this program to meet Connecticut’s emission, storage, and EV goals is not prudent.

Connecticut’s Failure to Obtain DOE Money

The GRIP program from DOE provides financial help to accomplish the tasks of increasing resiliency, especially amongst disadvantaged communities with funding of $10.5 billion. There have been two tranches so far, with a third tranche probably coming up in November 2024. To date, Connecticut has received none of this money. Applying to the GRIP program is challenging since the time frames for proposals are short. While IES participants were urged to participate, there was little direct assistance from PURA to do so. If Connecticut is going to receive some of this federal funding, it will require a concerted effort well beyond what PURA has done in the IES program.