Change is coming to the electric utility industry in every state. Five, however – California, Hawaii, Massachusetts, Minnesota and New York – have undertaken strategic, formalized regulatory processes to push the evolution forward.
One of them is not like the others.
A customer in Hawaii is more than 2,000 miles away from the next state. New York and California both operate within their own regional power markets. As those states work to revamp their utility systems and industries, at times re-imagining business models and markets, they have great latitude to make changes. Minnesota, on the other hand, is mostly making proactive moves, and isn't yet feeling direct market pressures to significantly alter utility business models, analysts say.
Massachusetts, on the other hand, suffers from some of the highest electricity prices in the nation and faces persistent reliability threats from storms and frigid winters. In response, regulators last year directed investor-owned utilities to file grid modernization plans and time varying rate proposals. But the Department of Public Utilities' orders were short on specific goals, requiring 10-year strategies and five-year short-term infrastructure plans to reduce outages, integrate distributed resources and optimize demand.
New York's plan doesn't look like California's, as West Coast utilities have to deal with a much higher penetration of distributed resources and more ambitious state energy mandates. Massachusetts, still earlier in the evolution of the utility business model than its bigger partners, has taken a customer-targeted approach, with a focus on advanced meter infrastructure and variable rates to make the system more efficient, while not causing wider disruptions in the ISO New England market.
National Grid's advanced metering push
National Grid proposed four different scenarios with widely-varying price tags – up to $1 billion in a “balanced approach” that captures all of the grid modernization ideas set out by the DPU, including a push to install advanced metering in every home within five years.
The advanced meter functionality would collect customers’ interval usage data, in near real time, so that it would be usable for settlement in the ISO-NE energy and ancillary services markets. Other functions include automated outage restoration and notification, two-way communication between
customers and the electric distribution company; and the possibility to control in-home appliances.
“Advanced distribution technologies are proposed to manage the operations of the grid, provide faster
restoration of service in outage events and manage voltage on selected feeders which will serve to reduce customer’s bills, improve efficiency of the operation of the grid and facilitate interconnection of distributed generation,” National Grid said.
Advanced metering functions “will improve the ISO settlement process. Accurate hourly settlement of load and generation at the ISO-NE level is essential,” National Grid said.
Most National Grid customers are currently settled at the ISO level using a demand profile based on load data that shows the average hourly use of customers on distinct rates.
“These profiled load customers likely have different actual load patterns versus the average, so having specific interval data for each customer will provide the detail for more accurate settlement, more detailed analysis of system losses and more accurate assessment of local losses on the system,” National Grid said.
The plan also calls for an Advanced Distribution Management System and a Distribution Supervisory
Control and Data Acquisition System, allowing system operators to monitor and control distribution circuits remotely and in real time. The two systems would enable more efficient grid operations and help integrate distributed energy resources, National Grid said.
Advanced distribution automation would “create a self-healing grid that automatically re-routes power in the event of an outage and thereby minimizes the impact of outages,” the utility said.
Eversource tries to ease implementation of variable rates
The DPU required utilities to consider a default product with a time of use pricing structure and a critical peak pricing component, with an alternative flat rate with a peak time rebate. But all utilities also suggested opt-in time-of-use rates, arguing they are more cost-effective.
Eversource said it developed a targeted, opt-in time-variable rate that “provides for a more cost-effective solution than an opt-out program” while also serving to introduce customers – who may be wary of fluctuations on their bills – to variable rates.
The utility is proposing a targeted opt-in variable rate designed to “create a community of customers to bridge the entire peak load period,” and is focused on taking customers unfamiliar with variable rates and introducing them to the concept in a gradual manner.
Eversource said it would propose a time-of-use and critical peak pricing plan, as well as a targeted time-of-use plan. Residential customers would have the option of electing a TOU/CPP rate or targeted TOU rate based on their load profiles and level of risk aversion. Customers with central air conditioning and other discretionary load may benefit most from a TOU/CPP rate, Eversource said, as they can respond to peak day events called by the company, while other customers may elect the targeted TOU option which utilizes “Target Peak hours” that are only two hours in duration to allow for greater price certainty.
“These two options balance the department’s desire to more closely match price signals in the wholesale market with Basic Service prices with the need to recognize that many customers may not be comfortable with the potentially extreme price swings that accompany CPP pricing or the long duration of traditional peak period pricing,” Eversource said.
Illustrating the spread between the plans, off-peak prices would run about 5 cents or 6 cents/KWh, depending on the time of year, while peak pricing would be about 27 cents/KWh. Critical peak prices would run about 56 cents/KWh in the first half of the year or 87 cents/KWh in the second.
The plans would be open to about 95% of Eversource's 1.3 million residential and small C&I customers in Massachusetts, with the remaining 5% being large industrial and street lighting.
Under Eversource's TOU/CPP option, customers would be subject to pricing at three time periods: off-peak, peak, and critical peak. The utility defines the peak period as weekdays from noon to 6 p.m.
Peak-period pricing would be designed to reflect the relative price differentials observed in the ISO-NE wholesale energy market, Eversource said, with a six-hour peak window compared to a more traditional eight-hour or longer peak period.
Eversource would target twelve peak days per year in establishing a trigger for critical peak events, which it said would offer a “good introduction” to customers unfamiliar with TOU pricing. The frequency could be ramped up in the future, if needed, and the utility proposed a MW threshold for a critical peak event. If the load forecast for the ISO-NE Day Ahead market shows that the MW threshold will be exceeded, Eversource will then communicate that to customers.
“Critical peak hours will be subject to a very high price reflecting the scarcity of capacity during the period,” the utility said. Eversource would review the hourly demands at ISO-NE to determine the average of the twelve peak days over the most recent three-year period, and the highest observed hourly demand in the lowest peak day will become the MW threshold.
Unitil embraces the third-party platform concept, worries about DR subsidization
The grid modernization plan that most closely reflects the concepts being examined in New York and California came from Unitil, which said its “long-term view is to transition the distribution operations to serve as a platform for Distributed Energy Resources.”
The utility wants to develop a a Distributed Energy Resource Management System (DERMS) designed to monitor and control DERs across its service territory. The technology could be implemented as a module to work with a distribution management system or as a stand-alone system, the company told regulators.
“As the penetration density of DER continues to increase on the grid, the utility as the grid operator has less insight into the real time conditions of the system,” Unitil said.
The DERMS system would provide Unitil with the information and control “necessary to effectively manage the technical challenges posed by a more complex grid,” the company said. “A DERMS can be particularly effective in areas where there is a great deal of intermittent renewable resources such as wind and solar. The DERMS system provides the utility the ability manage the impact of DER and operate the system more efficiently. “
Other grid modernization plans call for installing zero sequence voltage relay and regulator controls at substations to alleviate voltage control and equipment damage concerns caused by reverse power flows from DERs on feeders. Unitil said it will also look at the existing capacity of each substation and mainline circuit to determine how much distributed generation could be added without system upgrades.
But Unitil also said it wanted to revamp how distributed resources are compensated – a dicey topic of debate across the nation. The utility said it expects distributed resources to play an increasing role, but must ensure customers with DERs are not being subsidized by other ratepayers.
“The majority of DG customers are providing a supply service yet being compensated at close to near full retail rates rather than the market value of supply,” Unitil said, but DG customers do not pay the full cost of the facilities that they continue to depend on to receive and deliver power.
“The current policies were intended to stimulate investment in the solar industry and have been successful,” Unitil told the DPU. “The range of options available to customers has expanded dramatically over the past decade and the cost of solar systems has declined. However, rather than spreading the burden across all citizens that benefit from clean energy, the costs have been assigned to the subset of customers which do not or cannot afford to install solar (or other DG) generation.”
Unitil said customers sending power back into the grid would be compensated at the Fitchburg ISO-NE pricing point, and that the tariffs should be designed so that “customers should pay for distribution, supply, and other services provided by the electric utility at rates that reflect the fixed and variable costs incurred to serve them.”
