by Jeff St. John
June 01, 2018

Not every utility has enough rooftop solar and utility-scale renewables to have to worry about “congestion” on the edges of its distribution grid. But the hypothetical town of Gladville does, and Omnetric Group, a joint venture of Siemens and Accenture, thinks a distributed energy resource management system (DERMS) could help solve its problems. 

That’s the scenario played out in a white paper released by Omnetric this week, centered on measuring the cost-effectiveness of various solutions to a problem that’s already emerging for a handful of U.S. utilities today. That’s the rise of distributed energy resources — rooftop solar PV now, but electric vehicles, behind-the-meter batteries and net-zero-energy homes and businesses in the future. 

If left untended, these DERs can overload distribution system equipment, create two-way power flows that today’s protection equipment wasn’t designed to handle, and create voltage variability that can harm motors, appliances and electronics at homes and businesses, Omnetric noted. 

To be sure, these issues have arisen in only a tiny handful of utility jurisdctions to date — Hawaii is one example. But a 2017 poll of more than 100 utilities conducted by Accenture found that more than half feared their hosting capacity for DERs would be exhausted within the next decade without steps to mitigate these problems, indicating the scope of the future challenge. 

And “without the timely collaboration and anticipative forward planning of regulators, utilities risk being ill-prepared for congestion in the grid when it inevitably becomes a reality,” Omentric wrote. “What’s more, neither regulators nor utilities generally have the agility to fund and implement counter-measures quickly once congestion occurs, leaving utilities — and customers — to suffer the consequences.”

The white paper, based on conversations with utility partners including Duke Energy, Con Ed, DTE, Entergy and NV Energy, lays out four broad responses available to utilities facing these challenges: traditional upgrades, energy storage, demand response, and a DERMS implementation that integrates all of the above, minus the traditional upgrades. 

The four choices facing Gladville

To assess the cost-effectiveness of each option, Omnetric models the hypothetical city of Gladville, population 20,000 — a city of 8,500 residential and 750 commercial and industrial utility accounts, with 20 megawatts of grid capacity served by 15 megawatts of fossil-fueled generation and 10 megawatts of renewable generation capacity. 

But due to a booming economy, Gladville is expecting to see big growth in energy demand over the next five years. At the same time, it’s expecting to see 5 megawatts of rooftop solar PV come online in the next year due to an incentive program, as well as a 15-megawatt utility-scale solar farm that will come online in 5 megawatts-per-year increments over the next three years — growth that will make solar its predominant electricity resource. 

Looking at the four options, Omnetric notes that traditional capacity upgrades such as transformers, as well as “increased monitoring capability and circuit modifications via smart switches and voltage regulation,” will allow full cost recovery for Gladville’s utility, and would be simpler to implement as a “business as usual” upgrade. 

But it also offers no benefits beyond cost recovery to customers, while putting the burden on the utility to manage the “multitude of adjustments to the grid and its future management.” As for customers, “in high density residential areas or areas with underground networks, where infrastructure enhancements are more complicated and cost-intensive, this scenario could be less attractive financially and in terms of customer perception.”

Adding a hypothetical 1-megawatt/4-megawatt-hour battery to Gladville’s arsenal would allow it to absorb excess solar capacity at midday and discharge it during times of peak demand, as well as provide a more dynamic solution than grid upgrades alone. The financial benefit for this solution is about $1.5 million over 10 years, or about $7,000 per megawatt of DER capacity per year, compared to nothing for grid upgrades alone.

But despite falling battery prices, it’s still twice as expensive as the grid upgrade solution — although ongoing operations and maintenance costs are lower, it noted. What’s more, “It is difficult to determine whether regulation would currently fully support recovery of all battery costs via rate relief,” the report noted — an important factor, given that Omentric’s analysis relies on the assumption that Gladville will be able to recover costs for “enabling integration of customer or third-party energy resources,” as well as recover lost energy revenue from integrating customer-side resources through a lost revenue adjustment mechanism. 

The third option is a residential and C&I demand response program aimed specifically at alleviating some, but not all, of the grid upgrades envisioned in the first scenario. That yields about $3 million in financial benefits over 10 years, or about $14,000 per megawatt of DER capacity per year — twice that of the battery storage integration option. It also allows for some deferral of capital expenditure for distribution grid upgrades, and avoided capacity charges or infrastructure and O&M expenses that may otherwise be needed. But it also carries drawbacks, most notably the need for some grid upgrade spending to cover for the fact that demand response relies on customer participation and well-designed incentives to succeed.

The pros and cons of DERMS as a solution

Installing a DERMS to integrate the energy storage of Option 2 and the demand response of Option 3 yields the highest financial benefits, according to Omnetric’s study — $4.5 million over 10 years, or $20,000 per megawatt of DER capacity per year. It also allows the utility to hedge against capacity charge increases, and “serves as a distribution system investment deferral strategy that may equate to 10 percent additional incremental benefits compared to the infrastructure enhancements route.” 

The challenges to DERMS include its higher upfront cost, although average yearly costs end up being roughly level with the other options, and the fact that it’s “the most far-reaching transformation in terms of design and implementation.” While we’ve seen many utilities announce pilot projects to test DERMS platforms, none have taken the step of implementing DERMS across their entire service area. 

That may be why Omnetric’s model doesn’t factor in utilities’ “scarcity of resources” in money and personnel and lack of experience with new technologies that “could impact the feasibility and success of the DERMS route. Indeed, implementing a DERMS could call for a multi-stage approach with pilot projects to determine the optimal combination of asset, behavior and software actions” — just the approach being taken by utilities in California, Hawaii, New York and other states pushing for integration of DERs.