As technology continues to disrupt how electric utilities operate, it also brings into question how regulations, costs, and other aspects of business should change or stay the same.
Central to the public power business model is the ability to engage in local decision-making about the ways in which communities get and pay for their electricity.
The tension around local control is particularly acute within regional transmission organizations, as they examine how to accommodate distributed energy resources and technologies, such as energy storage. Public power organizations within these regions are grappling with the push and pull of how they can take advantage of the benefits of these new technologies without inviting increased regulation on local operations while continuing to ensure affordable electricity for their customers.
Why get involved in DERs?
For Braintree Electric Light Department in Massachusetts, which has had a 2-megawatt battery energy storage system in operation for a few years now, the lure of such technology is about savings. Bill Bottiggi, general manager at BELD, explained that the system saves the public power utility about $30,000 per month — $10,000 from being able to cap its peak summer capacity, and $20,000 in avoided transmission costs.
In addition to the battery system, several commercial customers in BELD’s service area have installed solar arrays, totaling about 5 MW, which Bottiggi said helps the utility’s peak shaving efforts and contributes to the city’s overall environmental goals. BELD offers residential customers incentives to install rooftop solar, but Bottiggi said that there hasn’t been much use of the incentives, “probably because our rate is so much lower than the IOUs around us.”
BELD also installed a 4-MW natural gas generation peaking facility and is working to install a similar 4-MW generator at a large commercial customer site. Although the natural gas facility is primarily used for peak shaving, Bottiggi said that BELD does sometimes enter energy from the facility into ISO New England’s real-time market when the locational marginal price gets high enough. BELD has not entered the asset into the market for the past few months, as Bottiggi said that real-time prices for energy have been about half of what they typically are because of the decreased demand resulting from the shutdowns put in place to reduce the spread of COVID-19.
Bottiggi said that the drive to develop more distributed energy resources throughout New England stems from local and state goals to decarbonize the power supply. While public power utilities are exempt from meeting the renewable portfolio standard in Massachusetts, which calls for investor-owned utilities to be carbon neutral by 2050, “we know that if we don’t stay ahead of the game, then we will become regulated,” said Bottiggi. He said that public power utilities in Massachusetts are proposing legislation to institute a “self-imposed” standard, which, unlike the current RPS, would include nuclear within the portfolio of allowable sources.
As more utilities look to add storage across the region, incentivized in part by ISO-NE, Bottiggi said one concern is that the ISO might try to limit how much utilities can shave from their peak.
“Right now, we can shave around 10 MW. So we pay less, but someone else is paying more,” said Bottiggi. “If everyone started to do that, it would create quite the dynamic.”
Disparate impact to smaller utilities
A common concern surrounding the increased deployment of DERs is how doing so will affect public power utilities — both in terms of system management and in terms of cost.
On the operations side, DERs create more uncertainty about how much energy is on the system and how much is needed, opening up the possibility of imbalance in supply and demand. On the financial side, customers with DERs might be creating a “revenue imbalance” if energy generated from rooftop solar panels, for example, is compensated at a different value than the value of the generation.
Paul Zummo, director of policy and statistical analysis at the American Public Power Association, explained how some of these complications might be more acutely felt by small and community-owned utilities. As nonprofit entities, public power utilities are trying to set rates as close to cost-based as they can, so there is less room or margin for any revenue imbalance.
Adding to the complexity, DERs can sometimes participate in both retail and wholesale compensation programs, either on their own or as part of an aggregation of DERs. To ensure energy from distributed generation isn’t getting counted twice – both as a wholesale and retail sale – Zummo observed that utilities would need to have advanced metering infrastructure and other technology in place. Since smaller utilities aren’t as likely to have AMI, being able to support aggregated DERs would require an investment in new technologies that come with a significant cost.
“If you set up the rules in such a way as to make it much more economically viable for customers to do solar plus storage, it is going to increase the number of customers who choose this option, and if you are limited as a utility in how you can manage that, that’s going to create another cost impact and exacerbate any problems you already have,” said Zummo.
The Federal Energy Regulatory Commission is considering rules that would make it easier for aggregated DERs to participate in the markets. If FERC adopts these rules, it would add complexity to public power utility operations as the utilities would likely be required to interact with more with the RTO and FERC.
“Suddenly you are dealing with a major federal entity that you aren’t used to dealing with … and you have to deal with a set of rules that are perhaps more complicated than the rules you are used to,” said Zummo.
Reducing the financial impacts of regulation on public power utilities is a major reason that American Municipal Power, Inc. a joint action agency with members in nine states, has staff who stay engaged with FERC.
More change, more costs
Paul Beckhusen, senior vice president of power supply operations and energy marketing at AMP, echoed that the generation mix is changing to more renewable sources. He cited reasons including sustainability efforts by members and decreased costs that are making renewable sources much more competitive. He also said that technologies that can help with demand side management and demand response are poised for growth.
However, the changes are also bringing added costs.
Beckhusen said that transmission costs have doubled over the past decade and that some of the regions AMP serves have seen as high as a 10% increase in transmission costs over the past year.
“Transmission costs are probably the biggest risk we have on the escalating cost of the power supply right now,” he said. “For transmission, the only offset we have is peak shaving with behind-the-meter and demand response resources for the members.”
AMP has undertaken several peak shaving projects, including about 70-MW of behind-the-meter reciprocating internal combustion engines and about 60 MW of behind-the-meter solar assets installed in AMP member communities, said Beckhusen.
AMP also developed a transmission arm to have more direct ownership of the transmission lines.
“If you are a transmission owner, then you are just like every other transmission owner. It allows you to be part of the process, allows you to control that part of the cost,” he said. “Traditionally, on the power supply side, we owned and built generating assets to hedge our generation costs. [AMP Transmission] allows us to be a transmission owner and help mitigate those costs.”
Beckhusen said that one of AMP’s concerns is about how the minimum offer price rule in the PJM Interconnection capacity construct will affect the development of new projects and member capacity costs.
“Any new generation resource project would be subject to the MOPR, which would not have been the case in the past, and it also will cause capacity prices to go up,” he said.
Side effect on local choice
Increased regulation at the federal or state level could also change the dynamics of relationships utilities have with developers and other entities.
“It’s very important that we have local control … it just makes things so much more nimble,” said Bottiggi. “It’s much more expensive and time consuming [for IOUs], because they need to get approval from the state.”
Bottiggi noted that typically, only the utility board must approve projects for BELD before it can move into the permitting phase. He said contractors have mentioned that they like working with BELD “because they know we can get stuff done quickly.”
“Any mandate interferes with the ability to make the best decision locally,” said Zummo. “As the local utility, you have the best sense of what resources might make the most sense to be clean.”
Beckhusen added that AMP undertakes a lot of engagement to educate its members and their customers on opportunities for DER projects. He said that public power’s local decision-making model makes such projects easier as, “AMP works closely with member communities to understand their respective system needs and community goals to assure support when subscribing a project.”
Beckhusen stressed that AMP will continue to stay engaged with FERC and other federal entities on matters that can affect costs and operations for its membership.
“It comes down to the grassroots benefit of public power and doing what it has always done well — to communicate to legislators and elected officials the real impact of their decisions,” he said. “And that includes explaining and demonstrating impact on customers — residential and business.”