Benefits of solar + storage expand for small Ohio municipal utility

What started with the objective of diversifying supply resources for the village of Minster (Ohio) municipal utility has blossomed into what soon could be a full-fledged solar + storage microgrid with the capability of islanding for extended periods of time.

The 4.2-MW solar photovoltaic (PV) facility paired with a 7-MW/3-MWh battery storage unit (photos) has received much attention from the industry, and many accolades since it went online over a year ago. It is considered by some to be the first solar/storage facility serving a municipal utility in the US.

Perhaps more importantly, it is one of the first to demonstrate what grid-scale storage enthusiasts have been proclaiming for years: If you “stack” the financial benefits, you can earn a decent return on storage capital investments.

Minster Village Administrator Don Harrod confirms that projected benefits to the utility have been exceeded in the first 18 months of operation. So much so that negotiations are underway for a second phase, which will add islanding capability, another 4 MW of solar, and 7 MW of storage; and a third phase with 19 MW of storage.

At the same time, though, Minster’s facility partners have to wrestle with unexpected challenges in the PJM grid market.

“Our goal four years ago was simply to diversify our generation supply with some solar, but as we got into the project, we found several other significant benefits,” Harrod noted. That was essential, because after the project was initiated, the state of Ohio terminated its solar renewable energy credits mid-stream, squashing project economics.

According to S&C Electric Co, supplier of the integrated lithium ion (Li-ion) battery unit, power conditioning hardware (PCS), and grid interconnects, as well as the battery management and integrated system automation and software, the storage unit is designed for three functions: power-factor control, peak-load management, and Reg D frequency regulation in the PJM market (sidebar).

Harrod confirms that all three functions have been “exercised” and proven in commercial operations. The S&C design, coupled with third-party forecasting, identifies Minster’s two-hour peak periods and displaces grid-supplied power with battery-supplied megawatt-hours.

This is critical because Minster’s peak-demand charge for the next year is based on the highest of five two-hour demand levels experienced during PJM’s coincident peaks the previous year. “Sure enough,” Harrod said, “the system correctly forecasted three of the five peaks last year, one of which was the highest for the year, which reduced our demand charge.”

Regarding power-factor control, Minster’s system is fed by two lines from its wholesale supplier, Dayton Power & Light Co. One line has adequate voltage, the other less so. When supply is switched from one line to the other, the voltage drop can be considerable, and a potential reliability issue, especially for the village’s two primary industrial loads. One of those is the largest Dannon Co yogurt-making plant in the US. Together, those two loads demand 10-11 MW.

The utility was facing an expensive addition of capacitor banks to solve the problem. But the storage facility is able to mitigate this challenge as well. “Now, when the lines are switched on us, we don’t see the voltage drop in our system.” Nor do their large industrial customers, where the drop was apparently visible and potentially problematic.

The third function, frequency regulation, is managed by a third party, but Harrod confirmed that power was successfully being sold into the PJM Reg D market.

 Contractual arrangements. Minster owns none of the hardware; it buys services under a long-term power purchase agreement. The details:

Half Moon Ventures, a private company, owns the solar PV array and the storage system, and is responsible for O&M and performance.

S&C Electric provides regular maintenance and 24/7 monitoring and diagnostics to the storage system under a long-term services agreement.

Viridity Corp handles all of the trades into the PJM regulation market.

LG Chem Ltd, Korea’s largest chemical company, supplied the Li-ion batteries, but S&C takes responsibility for them.

American Renewable Energy & Power supplied the solar PV array.

It’s no secret that many grid-scale storage projects have suffered from poor contractual arrangements and system design. S&C avoids that by guaranteeing the integrated system. As importantly, the company not only has the decades of experience designing relay and protection systems for electricity distribution, it can factory test all the equipment at full electrical output.

“We don’t just test modules, or simulate the software,” noted S&C’s Jake Edie, during a tour of the company’s considerable testing and product display area at its Chicago headquarters facility, “we factory-test the fully integrated system and run it through all possible fault conditions, and test for EMI [electromagnetic interference] and EMC [electromagnetic compatibility] interferences and circuit loadings.” Most suppliers don’t have these resources, he added.

The PJM challenge. Shortly after the system went live, PJM changed things up in the frequency-regulation market. The original mode was that battery power would be dispatched on PJM’s signal on a 15-min energy-neutral basis, meaning that the charging and discharging of the battery would be equal over each 15-min period.

But PJM found that it needed even more flexibility and accuracy of response. The ISO changed to a 30-min conditional signal, meaning that the grid can keep pushing the battery to completely empty or past fully charged.

Harrod noted that this situation would only affect the utility if the batteries could not be discharged during a peak demand period because of interference from Reg D obligations. However, the more aggressive dispatch and operating mode does affect the battery system lifecycle.

Edie also said the challenge could be addressed with system modifications. “We could add more air conditioning to the system, because the batteries generate more heat on deep discharge; add battery capacity, or operate the system a little differently.”

The last option could impact the way revenue is earned. Revenues from PJM depend on how quickly and accurately participants can follow the signal, and each participant earns a “score” for this capability. When you bid into the market, you not only are bidding with your “price” but your performance score as well.

Changes to Reg D rules have generated controversy, according to an April 20 article in Utility Dive, and a complaint to FERC issued by the Energy Storage Association (ESA), which alleges that PJM changed Reg D rules without FERC review or approval. One of those changes was the elimination of energy neutrality, which caused “daily pegging” to remove excess generation from the system. The other was to cap the amount of Reg D resources PJM would procure. According to ESA, the changes disregard the favorable characteristics of limited energy resources that the Reg D signal was designed to respect.

Deciphering grid jargon: What ‘Reg D’ means in PJM

In the old days, utilities managed their own ancillary services—frequency regulation, for example—and cooperated to keep other utilities whole. Today, in a market like PJM, frequency regulation is another “purchased” service (like capacity and energy). Typically, the grid operator has several tiers of frequency regulation, such as spinning and non-spinning reserve provided by traditional resources.

Regulation and balancing is defined by PJM as a variable amount of generation under automatic control, independent of an economic cost signal, obtainable within five minutes to respond to frequency deviations. The last is called Area Control Error (ACE).

Importantly, regulation requires injecting power and/or “dumping” power. If you can “store” the dumped power, so much the better. In practice, traditional generating units (fossil, hydro) can qualify for frequency regulation if they can respond quickly enough. Batteries and hot-water heaters are good places to store dumped power.

A so-called Regulation A signal has always been used to dispatch traditional generators, which typically are energy rich but limited in their ramping capability. The Regulation D signal was initiated to take advantage of the almost instantaneous response of new technologies like batteries, but which are energy-limited (that is, they can be depleted quickly).

Reg D, in essence, rewards assets that can cycle frequently between injecting power into the grid and taking power out of the grid.

A Reg D participant’s ability to meet PJM’s requirements is qualified initially through a combination of self-test and tests administered by PJM. Once qualified, the asset owner has to continue bidding into the system and is paid based on how well the asset meets the performance criteria.

Without getting into the considerable financial engineering involved, the formula dings the bidder based on the historic performance score, or the average of last 100 hours of performance scores. In essence, the asset owner’s past ability to deliver and take the megawatts promised within the required response time is factored into the bid process.

Typically, regulation needs are calculated 60 minutes ahead of time and participants bid in commitments 30 minutes before the hour in which they will be dispatched.

Jason Makansi, chairman,
Editorial Advisory Board

Posted in WTUI |

Comments are closed.