California policymakers are searching for ways to rein in the cost of expanding the state’s power grid, which is necessary to combat climate change. Experts warn they’re missing an opportunity that’s right in front of them — taking advantage of the growing number of clean energy technologies owned by utility customers.

California ended its legislative session last month unable to pass a proposed legislative package to address rising electricity rates for customers of Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric, which serve about three-quarters of the state’s residents.

Lawmakers also failed to pass several bills aimed at boosting the role battery-backed rooftop solar systems, electric vehicles, and electric heat pumps and water heaters can play in balancing the power that’s available on the grid.

Replacing fossil-fueled vehicles with EVs, and gas heating systems with heat pumps, will increase statewide electricity demand, requiring utilities to invest billions of dollars to upgrade their grids. But those same technologies can shift when they use power to avoid the handful of hours per year when demand spikes. That’s important, because the cost of building power grids is largely determined by the size of those spikes — and in turn is a core driver of California’s energy affordability crisis.

If the state can use distributed energy resources to shave a bit of demand from grid peaks, it stands to save big. One example: In an April report, consultancy Brattle Group projected that virtual power plants, which can shift when EVs and electric appliances draw from the grid or tap into customer solar and battery systems, could provide more than 15 percent of the state’s peak grid demand by 2035. That would amount to around $550 million per year in consumer savings. 

About $500 million of that would flow directly to the customers who own the devices, which could help defray the cost of buying EVs and heat pumps, two technologies that need to be rapidly adopted to meet climate goals. But because tapping into those devices would cost less than making large-scale investments, utilities — and by extension all of their customers — would save about $50 million per year by 2035, Brattle found.

“California’s affordability challenges are years in the making and are worsened by climate-driven impacts like heat waves and wildfires,” said Edson Perez, who leads trade group Advanced Energy United’s legislative and political engagement in California. ​“However, there are critical steps we can take now: optimizing our existing grid, maximizing the cost-effectiveness of essential grid upgrades, and fully leveraging available technologies like distributed energy resources.”

But as it stands, California isn’t putting the full weight of policy support behind these types of distributed energy programs.

Pilot programs have petered out, seen their budgets clawed back, or have been outright canceled. The scale of demand-side resources operating in the state has actually declined over the past decade, even as the state’s grid stresses have increased. And efforts to create statewide targets for distributed energy — like those that helped spur California’s rooftop-solar and home-battery leadership — have failed to gain traction, including a proposed bill in the state’s just-concluded legislative session.

Advocates say it’s time for the state to change that — especially since there’s an expiration date for capturing the value of DERs. Without policies to encourage utilities and customers to work together to realize the grid benefits of these technologies, utilities will simply build expensive, centralized infrastructure to meet rising electricity demand. Once that money is spent, potential savings can’t be realized, undermining the economic case for VPPs.

Unfortunately, utilities have clear incentives to discount the potential of VPPs as a money-saving tool, because they earn guaranteed rates of profit on capital investments like grid buildouts, but don’t for alternatives like VPPs. Plus, they’re held responsible for failing to keep pace with growing power demand — and are loath to rely on decentralized assets owned by customers in place of tried-and-true grid investments.

California’s VPP policy landscape

This utility reluctance may well explain why a roster of bills aimed at enlisting DERs to combat rising grid costs stalled in this year’s regular legislative session.

SB 1305 proposed requiring the California Public Utilities Commission to determine targets for utilities to ​“procure generation from cost-effective virtual power plants,” and then mandate that the utilities meet them.

Similar targets for rooftop solar and batteries have been valuable for boosting early-stage deployments in California, said Cliff Staton, head of government affairs and community relations at Renew Home, the company formed by the merger of Google Nest’s smart-thermostat energy-shifting service Nest Renew and California-based residential demand-response aggregator Ohmconnect.

“If you set the targets, you begin to provide the certainty to the industry that if you invest, there will be a return for your investment over time,” Staton said.

An early version of SB 1305 set hard percentage targets for VPP procurements by 2028 and by 2035. Those percentages were stripped from the bill later in the session, leaving the final targets up to CPUC discretion. The bill failed to clear a key legislative committee anyway.

Another bill that died in committee, AB 2891, would have expanded options for VPPs to capture the value of the peak load reductions they can provide. The legislation would have ordered the California Energy Commission to create methods for VPPs to reduce how much generation capacity each utility in the state must secure to meet peak grid demands in future years.

Only a handful of California’s community choice aggregators — the public entities that supply power to an increasing number of customers of the state’s major utilities — are using this approach today. But those CCAs have been able to start paying customers with solar and batteries for the value they can provide by reducing reliance on increasingly expensive contracts with centralized grid resources — mostly fossil-gas-fired power plants.

For more than a decade, state laws have called on the CPUC to create programs that reward customers for the energy and grid values provided by their solar panels, backup batteries, electric vehicles, and remote-controllable devices like smart thermostats and water heaters.

But these efforts have been plagued by an on-again, off-again approach from regulators and utilities. The California Energy Commission set a goal in 2023 of achieving 7 gigawatts of load flexibility from VPPs and other customer-owned resources by 2030; two of the CEC’s key contributions to that effort saw their budgets slashed this year.

Meanwhile, many of the programs launched by the CPUC over the past decade have stalled out due to overly complicated structures, or had their budgets reduced or canceled due to concerns over their cost-effectiveness.

The CPUC and the California Independent System Operator (CAISO), the entity responsible for managing California’s transmission grid and energy markets, argue that these programs have failed to perform as promised. Relying on them more would run the risk of eroding rather than improving grid reliability, they say.

But the companies engaging in these VPP programs — smart-thermostat providers like Renew Home and ecobee; solar and battery installers like sonnen, Sunrun, Sunnova, and Tesla; and demand-response providers like AutoGrid, CPower, Enel X, and Voltus — argue that overly complex and restrictive rules and compensation structures are to blame.

Adding to these challenges for would-be VPP providers is the declining value of rooftop solar. Major changes in California’s net-metering policies over the past two years have slashed the value of customer-owned solar systems, slowing the growth of the state’s leading rooftop solar market.

That’s a problem for VPP providers and advocates who see rooftop solar as an important way to help meet demand from households and businesses with EVs and heat pumps — and to charge up batteries with clean electricity that VPP programs can tap into later.

A host of bills were proposed to reset state policy to restore more value to customer-owned solar during this year’s legislative session. But only one — SB 1374, which restores compensation for schools that install solar — made it through.

California’s new rooftop solar regime does reward customers for adding batteries to store surplus solar power during the day and discharge it in evenings, when the grid faces its greatest and most costly stresses.

But solar and battery advocacy groups argue that those rewards haven’t counterbalanced the broader erosion of rooftop solar values — and that the VPP opportunities that have emerged in the state can’t yet be trusted to make up the remaining difference.

“It’s important for customers to find value in the investment they’ve made, and to help the grid and lower cost for all consumers,” said Meghan Nutting, executive vice president of government and regulatory affairs at Sunnova. ​“One of the problems with VPP programs so far is that it’s really tough to talk about that value proposition up front because programs are so short, you can’t count on them, or the funding isn’t there.”

Why grid costs and VPPs are intertwined 

At the same time, California policies that encourage people to buy other distributed energy resources — namely EVs and heat pumps — are under threat from rising electricity rates, which are eroding the benefits of switching from fossil fuels.

A controversial policy enacted this year to reduce the per-kilowatt-hour rates paid by customers of the state’s big three utilities in exchange for higher fixed costs may or may not ease that pressure. But both opponents and supporters of the policy agree that shifting the balance of fixed and variable electricity costs does little to address the underlying problems.

Programs that enlist those exact same distributed energy resources to ease grid stresses have a much clearer value proposition, on the other hand.

About half of the electricity bills of customers of California’s three big utilities is made up of fixed costs like grid investments. A majority of those investments are tied to building a grid robust enough to supply power not just for average needs, but during the few hours per year when electricity use peaks.

Those peaks are getting bigger as California’s climate goals encourage more EVs and heat pumps to come online, and the costs of dealing with that have only just begun to be built into utilities’ broader grid investment plans. A series of studies ordered by the CPUC found that adding demand from EVs and heat pumps to the grid could increase ratepayer costs by more than $50 billion by 2035 — or, depending on the approach taken, costs could be contained to less than half of that over the same timespan.

One key variable in those distinct cost forecasts is whether EVs can be programmed or incentivized to avoid charging all at once and overwhelming the grid. ​“Smart charging” programs that encourage EV owners to shift when they charge their cars could save California ratepayers tens of billions of dollars over the coming decade.

With the right policies and technologies in place, big new grid demands like EVs could actually become valuable resources for energy in their own right. SB 59, a bill that passed in this year’s legislative session after failing to make it last year, orders state agencies to study the proper role for regulation that could require automakers to enable their EVs to support ​“vehicle-to-grid” charging — sending power from EV batteries back to homes, buildings, or the grid at large.

The challenge for utilities and regulators is finding the right mix of approaches that can allow them to take advantage of EVs, heat pumps, residential solar and batteries, and other distributed resources such that they avoid either overbuilding or underbuilding the grid, said Merrian Borgeson, policy director for California climate and energy at the environmental nonprofit Natural Resources Defense Council.

“We have to be really careful with any new investment — but we do need to make new investments,” she said. ​“If we pull back too far on energizing loads like electric homes or EV trucks, we miss out on getting those loads connected.” 

California could cut utility bills with distributed energy. Why isn’t it? is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Two years after opening the gates for small-scale renewable development in Maine, officials now have to figure out how to situate new projects in prime spots on the grid.

A group of industry members, advocates, utility stakeholders and state officials is preparing to issue the first of two reports that will help lawmakers in Maine craft new renewable incentive policies and plan grid upgrades for the coming years. This comes after the legislature in 2019 lifted project size limits for the state’s net metering program and implemented other policies that led to a crush of new project applications awaiting utility approval.

That high level of interest by developers “was very robust and possibly beyond initial expectations” when the laws were passed, said Dan Burgess, director of the Governor’s Energy Office.

“I think it’s fair to say we didn’t know exactly what we would see when the law was passed,” said Jeremy Payne, executive director of the Maine Renewable Energy Association. “What is clear is that the policy has made Maine a highly desirable place to deploy capital, create jobs and bring in new taxable value.”

Few projects have actually come online since the 2019 laws were passed, partly due to interconnection delays and the pandemic, as well as the typical timeline for project development. 

The laws mostly paved the way for new solar generation development. As of now, developers have sought interconnection approval from Maine’s two investor-owned utilities for about 2,400 megawatts of solar, including 1,350 megawatts under the state’s net metering program — which in Maine is called “net energy billing” — according to the Governor’s Energy Office. 

It’s likely many of those projects won’t be built, Payne said. Central Maine Power, the larger of Maine’s two investor-owned utilities, this year recorded annual peak demand of 1,810 megawatts. Versant Power last recorded 382 megawatts, in 2019.

Adjusted for service territory size and the number of customers, “we’re exceeding anything that any utility has seen before in terms of processing 1- to 5-megawatt [photovoltaic] projects,” said Jason Rauch, a policy manager at Central Maine Power.

With high interest and long wait times for developers seeking approval, officials and industry members now want to find ways to make the process by which utilities study project viability more efficient. They want to make it easier for developers to propose solar and other renewable installations in places where they’ll benefit the grid, particularly by avoiding transmission costs for consumers.

But that will also likely require changes to the data utilities collect, and to the access developers have to that data. Discussion of what those changes would entail is still very early on, but members of the stakeholder group hope their meetings can advance progress toward a solution.

“I think it’s clear that we’re going to need some upgrades to the grid, and those upgrades need to consider both the clean energy development that’s happening and also the electrification that’s coming in the transportation and building sectors in particular,” said Phelps Turner, a senior attorney at Conservation Law Foundation and a member of the new group.

The group was established by law this past summer and is known as the Distributed Generation Stakeholder Group. “Distributed generation” refers to renewable and storage projects up to 5 megawatts in size. Such projects, Turner noted, have implications most immediately for the distribution grid — though they ultimately affect the transmission grid too.

The group began meeting in September and must deliver the first of two reports to the state legislature by Jan. 1. That report will include preliminary recommendations for grid upgrades and new distributed generation incentive programs, like net billing, to begin in 2024. The group is supposed to determine a target amount of distributed generation under a new incentive program that would account for 7% of the state’s anticipated electric load. The law passed this summer set a non-binding goal of having 750 megawatts of commercial distributed generation projects 2 to 5 megawatts in size operating by the time the current net billing program is over.

Other expert groups have made recommendations over the past year and a half for grid modernization and renewable development in Maine. The new stakeholder group will build on that work, said Burgess, who’s a member of the group.

“What we’re going to do is seek to take what we’ve heard and learned from all these processes and also look at what is already being done and try to understand where the gaps are,” Burgess said.

Matching supply with demand

“We’re dealing with a grid that was not designed for a lot of distributed generation,” said Philip Bartlett, chair of the Public Utilities Commission and a member of the stakeholder group. The group’s discussions, as well as a complementary docket at the commission, aim to help figure out how to incentivize resources where and when they’re needed, he said.

Both of Maine’s investor-owned utilities are conducting assessments to evaluate both distribution- and transmission-level impacts. But Bartlett noted it’s unclear whether all these studies are necessary to comply with requirements by ISO-NE, the regional grid operator.

He added that these questions could be avoided to some extent by identifying from the beginning where projects can be placed on the grid to reduce transmission impacts — thus reducing the need for ISO-level assessments. That is, after all, the point of distributed generation, he said: building generation where demand is, rather than building it in one location and then delivering it to another via transmission lines.

“It would benefit everybody to locate these projects in places where they can connect the easiest and not impact the system negatively,” said Catharine Hartnett, manager of corporate communications at Central Maine Power.

“Certainly we want to provide the information, the data that would be helpful, that could move this along the most efficiently for everybody,” said Hartnett, who noted the stakeholder group discussions are still in their early stages. “We’re just not quite sure what that is and how we can best provide it.”

Payne, at the Maine Renewable Energy Association and a member of the stakeholder group, said the renewable industry would like more transparency and efficiency from Central Maine Power in its interconnection study process. 

“As we have said to CMP time and time again — and I truly believe this — their success is our success,” Payne said. “If they’re doing their jobs more efficiently … that’s better for everyone, including ratepayers as well as developers.”

Assessing costs

The possibility that new distributed generation projects will necessitate grid upgrades raises a longstanding question of who should pay for the upgrades: developers, or utilities — and therefore ratepayers. Critics also argue that programs like net metering drive up electric bills for customers who aren’t able to pay for solar panels or subscribe to community-based programs that offer bill credits.

“Versant Power is willing and eager to support the state’s energy policy goals,” Arielle Silver Karsh, director of legal and regulatory affairs at Versant Power, Maine’s other investor-owned utility, wrote in emailed comments. She’s also a member of the stakeholder group. “If the stakeholder group can set forth a list of agreed-upon priorities and acknowledge the likely costs associated with implementing solutions, then the utilities will have some certainty about moving forward. We need to chart a course forward and do so methodically and strategically to soften any rate impact to the greatest extent possible.”

Disagreements over costs tend to hinder discussions on how to plan distributed generation development, said Rebecca Schultz, a senior advocate at the Natural Resources Council of Maine who’s been observing the stakeholder group meetings. “Cost,” she noted, can include program administrative costs and bill credits under net billing, as well as grid upgrades necessitated by distributed generation projects.

“I think there has been a tendency to use misleading and inaccurate ways of communicating the impacts of these programs, whereby program costs equate to lost revenue for the utilities,” Schultz said.

Costs as they’re reported often don’t reflect the benefits of these programs to individual participants or to ratepayers generally, she said. For example, she said, some benefits of distributed generation, like avoided costs in the regional capacity market, accrue to ratepayers naturally through reduced electric rates.

“Clean distributed resources also help fortify us against fossil fuel price volatility, like what we’re seeing in Maine and across the region, where electricity rates are skyrocketing due to our reliance on natural gas generators,” Schultz added.

Having a method of evaluating program costs and benefits will make it easier for stakeholders to decide what projects to incentivize and how to allocate costs, she said. Turner, at Conservation Law Foundation, noted that as part of his work on the group, he’s pushing for a more comprehensive analysis of project costs and benefits.

After the stakeholder group delivers its initial report, it will have another year to develop a second, more in-depth report, which is expected to have more detailed recommendations for new programs to incentivize distributed generation development in Maine.

By the time that report comes out, there should be more clarity about how many of the projects currently waiting for approval will actually move forward, Payne noted. He said that in the coming year and a half, the state will likely see many more projects come online.

“I think what we have is tremendous amounts of investment capital poised to flow into Maine,” he said. “We’re just in the early process.”

Amid a flood of solar applications, Maine seeks a more targeted approach is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

State regulators dealt a setback to solar developers last month, but some think it could become a blessing in disguise. 

Editor’s note: This article has been updated to clarify that Consumers Energy’s increased distributed generation cap was not part of the Michigan PSC ruling.

A disappointing ruling for Michigan’s solar industry last month likely nudged the state closer to a potentially “game-changing” tipping point in the economics of distributed clean energy, experts and developers say.

As part of Consumers Energy’s latest rate case, the Michigan Public Services Commission in December approved the utility’s request to cut the rate it pays for solar generation sent back to the grid by 46%. 

Critics say the commission undervalued the benefits Consumers Energy sees when home solar users add energy to the grid, and underestimated the amount of pain that the new rates could inflict on the industry, particularly for residential installers.

“It definitely makes things harder and will increase how long it takes customers to recover their investment in the system,” said Will Kenworthy, regulatory director for Vote Solar, a national solar industry group.

Some developers, however, see a potential silver lining if the changes cause producers to turn to storage technology that immunizes rooftop solar from rate cuts. Rob Rafson, president of Muskegon-based solar developer Chart House Energy, is among those who think the ruling could mark the start of a “positive story.” 

“I really think this is going to help drive large-scale adoption of storage, and that ultimately is a super good thing for the grid,” Rafson said.

One option is for home producers to install smaller systems so they aren’t effectively penalized for sending too much electricity to the grid.

But Rafson said a better option is to make use of lithium-ion battery technology that has come down in price to the point that it’s starting to be affordable for use with home arrays. The batteries’ storage space is large enough that residential producers could store their own energy in a battery and use it when the sun is down or the weather isn’t suitable. 

When that happens, Consumers Energy’s outflow rates don’t matter because the producer isn’t sending energy to the grid, and that could be a game-changer, Rafson said. If the commission and utilities keep chipping away at home solar’s financial incentives when arrays can store enough power for users to leave the grid, then “people won’t put up with it anymore.” The changes could trigger a wave of “grid defections” in which solar users leave Consumers’ grid altogether, Rafson said.

“The industry is adapting very rapidly, and storage is becoming a very important part of the puzzle,” he added.

Dave Strenski, founder of the Solar Ypsi nonprofit, which promotes rooftop solar in Ypsilanti and around the country, said he once opposed using batteries because they were too expensive, inefficient and had too short of a life. He agrees with Rafson, though he doesn’t think batteries are quite yet cheap enough.

“We’re going to get there pretty soon — the next five to 10 years,” Strenski added.

Critics charge that the changes are part of private utilities’ larger ongoing effort to kill the burgeoning distributed energy industry and retain near-monopoly control over the state’s energy production. Utilities are willing to produce solar energy, but they want to do it at utility scale so they make money, Strenski said.  

“They’re not in the business of selling power — they’re in the business of managing facilities,” he added. “So the last thing they want is to not own the facilities.” 

Consumers Energy has repeatedly said it’s not “anti-solar” while touting its Clean Energy Plan that calls for significant investment in utility-scale solar. It has also received some praise from clean energy advocates for its work on that front, but the company is still criticized for its opposition to distributed energy.

A spokesperson for the Michigan Public Services Commission declined to comment but noted that the commission offered its rationale in the order. The commission wrote that its decision is supported by prior approval of inflow/outflow rates and said the solar industry didn’t provide proof that the energy it sent to the grid offset Consumers’ expenses.

The order also led to two changes that the solar industry applauded. Utilities have been only required to pay customers for energy sent to the grid until the sum of that energy reaches 1% of a utility’s average peak demand. Consumers Energy voluntarily raised its cap to 2% in exchange for the commission approving the outflow rate changes that the company wanted. Regardless, the cap change allows for further solar growth, but clean energy advocates still say the cap should be higher or eliminated altogether.

The order also calls for a workgroup with a mission of effectively determining the value of distributed energy that small-scale producers send to the grid. That could bring an end to the regular battles between the solar and utility industries over rooftop arrays.

The commission plans to hire a third-party company to conduct the study. Kenworthy cautioned that the process’s credibility depends on who the commission selects. Similar processes around the country have been tainted by commissions choosing utility-linked groups to help settle debates.

Environmental groups and intervenors will have a place at the table, and advocates say the key to a compromise is for distributed energy to be left intact and utilities to find a way to still make money off it.

“Maybe there’s a way that the utilities can participate in distributed generation,” Kenworthy said. “We look forward to the working group and talking about how to facilitate distributed generation.”

Michigan solar ruling could expand the role of residential energy storage is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

A new presidential administration in 2021 will change the policy landscape for states that are working toward realizing ambitious carbon neutrality goals. This fall, Gov. Gretchen Whitmer issued an executive order that made Michigan the latest state to adopt a goal of carbon neutrality by 2050. Realizing that goal will involve some big changes. One of the most important is moving toward a new kind of electricity grid — one that facilitates the continued deployment of renewable energy, energy storage, electric vehicle charging, energy management software and other innovations. 

It was easy to miss, but in the weeks before the announcement of the carbon neutrality target, Michigan regulators took a small step toward ultimately realizing that grid of the future. This summer the Michigan Public Service Commission (MPSC) ordered the state’s major utilities to craft new plans for the distribution grid that are consistent with Gov. Whitmer and the MPSC’s recently-launched MI Power Grid initiative, which seeks “to maximize the benefits of the transition to clean, distributed energy resources,” as the governor’s office said when the initiative was unveiled late last year. 

For Michiganders who work in advanced energy jobs like rooftop solar installation or electric vehicle engineering—which stood at over 125,000 jobs in Michigan alone pre-pandemic, according to E2’s Clean Jobs America report — this order is great news. But as the saying goes, old habits die hard. Planning for the energy transition has the potential to disrupt the status quo business and regulatory environment under which utilities have operated and have grown accustomed to over many decades. Advances in the costs and efficiencies of distributed energy resources (DERs), like rooftop solar and on-site battery storage, are reshaping how we think about the energy infrastructure that makes modern life possible, and Michigan energy consumers would miss out if they are not able to reap the benefits of this shift. The MPSC’s order on distribution system planning is the perfect opportunity to make sure Michigan does not get left behind as other states reform how they regulate the grid to take advantage of these developments.

Traditional distribution grid planning is focused on capital-intensive infrastructure projects designed to move power in one direction, from power plants to customers. But increasingly, alternatives exist that can unlock more efficient and affordable ways to maintain the reliability of electric service while also opening up opportunities for customers to better control their own electricity use and costs. New strategies for grid planning have emerged with the rise of DERs. A quick look at Michigan’s distribution grid reveals big problems that more sophisticated distribution grid planning that incorporates DERs could help address. 

Michigan’s distribution grid sorely needs new investments. The state ranks as one of the worst in the country for electric reliability and the length of power outages. Much of that problem is related to utilities’ ability to manage the grid, such as regularly trimming trees so they do not knock down power lines, but it is also caused by aging infrastructure. Michigan utilities want to spend billions to fix the grid. DERs could defray the need for some of that spending by, for example, cutting electric load at peak times, which allows grid infrastructure to last longer. The investment will be large no matter what, but smarter planning could potentially save a chunk of those billions.

An example of how this can be done is through non-wires alternatives (NWAs), which use DERs, such as batteries, energy efficiency and demand response, to meet grid needs instead of using traditional “poles-and-wires” solutions. If a section of the grid is approaching its capacity limits, NWAs can provide a combination of local electricity generation as well as demand reductions that together can defer or avoid a traditional upgrade. Instead of investing in infrastructure, the utility would contract for services (e.g., capacity relief) from DERs. Grid operators should consider these flexible and innovative technologies any time a grid upgrade is required to accommodate more load. If the NWA is a more cost-effective solution, it should be pursued.

DTE Energy, Michigan’s largest electric utility, has piloted several NWA projects, but ultimately concluded that NWAs cannot be considered “a useful, practical and safe application” without further study, as the utility said in a filing with state regulators.

This conservative assessment may have been true a few years ago when the electric grid was largely centralized and distributed resources were more expensive, but that reality has changed this decade. Several states have already implemented innovative projects that integrate DERs into grid planning. Most notably, since 2014 New York City utility Consolidated Edison’s Brooklyn Queens Demand Management NWA project has saved money for ratepayers by delaying the need to build a substation and associated infrastructure to serve a densely populated part of the city experiencing load growth. 

Each state is different and practically all of Michigan is less densely populated than New York City, but NWAs have also demonstrated value in suburban areas. In the mid-Hudson River Valley north of New York City, Central Hudson Gas & Electric Corp. has been running its Peak Perks demand management program, which helps participating customers reduce their peak load in the summer through tools like two-way WiFi thermostats. By cutting peak loads, the program “helps all of us in the Hudson Valley avoid the costs of constructing additional transmission lines and power plants built primarily to operate only during times of very high electricity demand for a handful of hours per year,” according to the utility. The program, which targets 16 MW of electric load, is substantially larger than any NWA pilots pursued by DTE and Consumers Energy to date.

Even though New York has a headstart on incorporating DERs into the grid, there are promising examples right here in Michigan. In October 2017 Consumers Energy launched the Swartz Creek Savers Club pilot project in a town near Flint. The project seeked to enroll residential customers into demand response programs that pay those customers to reduce their electric use on peak demand days. The result is that on hot summer days electric bills are lower and there is less strain on the grid than there would be if the Savers Club program did not exist. 

The Swartz Creek project also enrolled residential and commercial customers into efficiency programs such as air conditioner tune ups and replacements and more efficient lighting and refrigeration. While utility efficiency programs are commonplace, those programs are aimed at achieving system-wide increases in efficiency. The differentiating feature of the Swartz Creek project is that it targets specific customers at specific points on the grid where, if load is reduced, expensive investments can be avoided. 

A specific case where innovative solutions for the grid might be particularly helpful is Michigan’s Upper Peninsula (U.P.). U.P. ratepayers face some of the highest electricity rates in the country. The region makes up nearly 30% of the state’s land area but only about 3% of the population. Therefore, the high costs of electric infrastructure — not just the distribution grid, but also transmission lines and power plants — are spread out over a small number of ratepayers. At the same time, the U.P. is a particularly fertile ground for distributed energy. A 2016 Michigan Technological University study found that it could be economic for 65% of single-family homes in the U.P. and over 90% of seasonally-occupied homes to rely on their own energy from a combination of rooftop solar, batteries and combined heat and power generators — all examples of DERs. This is not to say that all of these ratepayers should cut themselves off from the grid, but more distributed energy could mitigate the problem of expensive electric service in the U.P. But as of now, DERs are not well integrated into the planning process for the electric grid in Michigan. 

The problem is that with the current cost-of-service regulatory model, our investor-owned utilities (IOUs) are incentivized to favor the capital-intensive infrastructure approach. Without changes in the way the state regulates IOUs, alternatives to traditional utility infrastructure solutions may be treated more as an afterthought or remote future opportunity. And there would be little financial incentive for IOUs to scale-up promising programs that are currently being piloted, if they result in foregone opportunities to make future capital investments that are the primary driver of utility earnings.  

That needs to change. One goal of the MPSC’s efforts under MI Power Grid should be to explore innovative utility incentive models so IOUs have just as much incentive to plan the grid around DERs as they currently do around traditional poles and wires. The goal is not to favor one or the other, but to put them on equal footing so that the most efficient, least-cost option wins out.

Commentary: Distributed energy plays a critical role in Michigan’s carbon-neutral goal is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

The state recently became the first in the nation to adopt a new national standard for connecting to the electric grid.

Minnesota recently became the first state in the nation to adopt a new national interconnection standard that could spur more clean energy projects.

Interconnection standards provide “rules of the road” processes and procedures that must be followed by solar, storage and other clean energy providers and utilities serving them. Updated standards allow for more clean energy, storage and the introduction of smart grid capabilities.

Minnesota chose to incorporate IEEE 1547-2018, an emerging national standard designed by the Institute of Electrical and Electronics Engineers. Several organizations advocated for the standard, including the Interstate Renewable Energy Council.

“This establishes modern, clear, and more efficient interconnection standards for distributed generation in Minnesota,” said Sky Stanfield, partner with Shute, Mihaly & Weinberger, attorneys for IREC. “It’s good for the grid and distributed generation in the state.”

Driven by demand for clean energy and bolstered by new technology that makes for a more efficient and reliable grid, many states have begun updating interconnection standards, among them Michigan, Iowa, Illinois and Maryland.

IREC and other clean energy organizations believe refreshed interconnection standards will jumpstart greater penetration of distributed energy resources. Many states operate with rules designed for a time when the grid had few clean energy generators. A more sophisticated standard would allow for higher growth of solar and storage, advocates say.

Minnesota regulators managed a two-stage process for updating interconnection standards. The first round of changes that involved policies and procedures for connecting to the grid took effect in summer 2019. The second part — technical guidelines — received approval recently from the Minnesota Public Utilities Commission but will not take effect until the summer of 2020.

The commission’s technical standard includes a variety of details on new and existing technologies and requires utilities to create “technical service manuals” available to clean energy developers. The manuals will have information specific to each utility in Minnesota.

Perhaps most prominently, the new interconnection standards include rules on “smart inverters” that allow the grid to absorb more distributed generation while maintaining safety and reliability, said Brian Lydic, IREC’s chief regulatory engineer.

More sophisticated smart inverters are an emerging technology that mitigates the problem of rising and dropping voltage and frequency, allowing more distributed generation without additional infrastructure, he added.

They perform the same function as standard models — transferring power from direct to alternate current — while providing the advantage of adding more features that benefit grid stability, he said.

Though Minnesota’s standard is a significant improvement over the previous version, regulators could have gone even further in anticipating future issues, Lydic said. The standard does not promote a technology called “volt/VAR” that allows for more sophisticated voltage regulation in smart inverters.

Despite not being included in the interconnection standard, California and Hawaii have incorporated volt/VAR. Greentech Media reported the volt/VAR market grew 39% between 2014 and 2018 to more than half a billion dollars.

Stanfield said the new standard does little to clarify how energy storage will be incorporated into the grid in the future. The standard added few procedural or technical details related to storage.

But regulators declined to add much detail because no national standards exist for volt/VAR or storage, said Craig Turner, senior principal and regulatory engineer for Dakota Electric Association. The state did not want to move forward with a standard that might not be in line with a national one being developed now, he said.   

David Shaffer, executive director of the Minnesota Solar Energy Industries Association, said among his members “we’ve seen a lot of excitement for phase two. We believe a lot of good stuff will come out of it. It will be interesting to see how it’s actually put into practice.”

Minnesota began the process of redesigning its decade-old interconnection standard in 2016 after regulators were petitioned by IREC, working in a partnership with the Environmental Law & Policy Center and Fresh Energy, publisher of Energy News Network.

The initiative came as a result of many interconnection fights brought on by the rapid growth of Minnesota’s community solar garden program, the largest in the country, said Isabel Ricker, senior policy associate at Fresh Energy. Many developers and Xcel Energy, which operates the community solar program, wanted updated regulations.

The new standard’s inclusion of rules for smart inverters will “automatically stabilize the grid and that should be a good thing,” she said. “It will allow more distributed generation to be installed.”

Benjamin Stafford, Clean Energy Economy Minnesota’s director of policy and public affairs, said solidifying the interconnection standard creates a predictable process for businesses and homeowners interested in adding solar.

“For our members, the kind of clarity the new interconnection standard offers is a good thing,” he said. “It’s really been improved. This is a positive step forward and I’m encouraged by what the commission did here.”

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Minnesota solar installers expect new standard to streamline interconnection is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.