Battery Systems <5 MW begin capturing New York VDER revenue
May 3, 2023
Andrew Kinross, Ketan Lakhani, Brady Yauch & Wesley Stevens
The amount of operational battery storage in New York is relatively small but poised for significant growth. A New York Public Service Commission press release indicated that just 130 megawatts of energy storage in total was operating in the state as of November 2022. A wide variety of incentive programs, such as the Bridge Incentive program, have supported these projects.
But soon batteries will be collecting revenue from the Value of Distributed Energy Resource (VDER) program (for non-residential systems 5 MWAC and below). Developers NineDot, Summit Ridge Energy, Greenbacher, Nexamp and Agilitas, among others, are all readying portfolios of such projects that they expect will become operational in 2023 or 2024.
The cost and availability of batteries has been a significant roadblock in projects reaching commercial operation. In fact, NYSERDA reported that among storage projects awarded NYSERDA incentives, the average total installed costs for non-residential, retail projects averaged $567/kWh for installations occurring in 2022 and 2023, up from $464/kWh for installations in 2020 and 2021, a 22% increase in total costs. But supply chain issues are expected to begin resolving, and commodity prices have begun to recede, paving the way for more projects to move forward.
Power Advisory has experience in forecasting VDER revenue for solar only, solar+battery and battery only projects. Below we provide some observations and insights about the latter two categories involving batteries, and how projects capture – and maximize – revenue.
Observations and Insights regarding optimizing NY VDER battery revenue
Environmental (not applicable)
Demand Reduction Value (DRV)
Demand Reduction Value (DRV)
The chart below shows illustrative revenues from battery only systems. These revenues are discussed below.
Outside of ConEd territory (NYC and Westchester), net energy revenue is not likely to be significant. In most areas, the battery should be charged and discharged only on days when it can earn Demand Reduction Value (DRV) and/or Capacity revenue. The battery may earn some additional revenue from energy arbitrage (charging during low-market-price hours, discharging during high-market-price hours) but this could involve additional costs to monitor the market, and may not be worthwhile. ConEd is an exception, where more active energy arbitrage may be viable.
Careful attention should be given to when to charge the batteries in order to minimize distribution charges. This will depend on the specific rate applicable to the battery system. For example, in PSEG (Long Island), the battery should be charged only overnight (11 pm to 7 am).
Risks for Energy Revenue: o Risks are minimal, because energy revenue will not account for a significant portion of the system’s net revenue.
For a standalone battery, Capacity Alternative 3 is the only option
Revenue depends solely on the output during the one hour each year that turns out (in retrospect) to be the hour with the highest Net Hourly Demand in the zone in which the project operates. If the project is able to maximize generation during that one hour in the year, then it could generate nothing in the other 8,759 hours of the year, and still get 100% of the available capacity revenue. On the other hand, if the battery happened to have a problem during that one hour and wasn’t able to generate anything, the project gets zero.
Once that Peak Hour has been determined (i.e., on December 31 of that year), the capacity revenue for the following year is the output during that one hour, multiplied by the capacity price in each month of the next year. For example, if the Peak Hour in 2024 is 4:00-5:00 pm on August 17, 2024, and the battery injects 1 kWh into the grid during that one hour, then capacity revenue for January 2025 is 1 kWh times the capacity auction price for January 2025; capacity revenue for February 2025 is 1 kWh time the capacity auction price for February 2025; etc. for the rest of the year. Sometime in 2025, there will be a new peak hour, but that won’t affect the project’s revenue until 2026.
In theory, the Peak Hour could be any time. In practice, for all zones except for Zone D, it’s almost certainly going to be between 3 and 6 pm on a hot July or August day, at least for the next several years. It’s unlikely to move outside of that range, but it’s possible. It’s also possible that these zones flip to winter peaking once electrification of heating kicks in, although that would be years away.
By contrast, Zone D is winter peaking. The Peak Hour will generally be sometime during January or February from 2-7 pm.
Capacity rates on a $/kW basis are highest in New York City and Long Island.
Risks for Capacity Revenue: o The main risk for capacity revenue is that capacity auction prices are difficult to predict. In particular, as more offshore wind comes into service (providing both energy and capacity), capacity auction prices could be driven quite low in some months. o For shorter-duration battery systems (e.g., with only 2 hours of storage), there is some risk of missing the peak hour and getting no capacity revenue for the next year, but this can be mitigated by discharging at less than full capacity over all hours that could reasonably be the peak hour.
Battery-Only systems don’t get Environment Revenue.
There are six different DRV schedules which generally have windows in the afternoon/evening time period from June to August. For a full calendar year, these DRV windows range between 234 hours (ConEd) and 334 (NYSEG).
DRV values on a $/kWh basis are the highest in New York City and Long Island. The rates in $/kWh and $/kW-year are shown below.
Taking PSEG-Long Island as an example, o DRV revenue is based on the project’s generation between 2:00 and 7:00 pm on weekdays between June 1 and August 31. That’s 64 or 65 days (depending on where the weekends fall) for 5 hours a day, for a total of 320 or 325 hours per year (3.7% of the hours in a year). o DRV revenue for each June, July and August is the generation during all the DRV windows in that month, multiplied by the DRV rate for that month.
It doesn’t matter exactly when the project generates, as long as it’s within that DRV window.
The project’s DRV rate is locked in for 10 years. After that, it’s whatever the posted rate is. In theory, that rate could change each month. (Historically, the DRV rate has changed only rarely, and only slightly.) During the first 10 years, you’re locked in both ways: if the posted DRV rate goes down, you still get your original rate; if it goes up, you still get your original rate.
Risks for DRV Revenue o The program could greatly reduce, or even eliminate, DRV after 10 years. Power Advisory’s forecast shows DRV remaining the same through 2040, then gradually falling to zero. o There is essentially no volume risk as long as the battery system is working. The battery just needs to be fully charged by the start of the DRV period (in the case of Long Island, for example, 2:00 pm), and fully discharged by the end of it (for Long Island, 7:00 pm) o The cost of charging is unpredictable, but probably small compared to DRV revenue.
The chart below shows illustrative revenues from a solar + battery system. These revenues are discussed below.
A project’s energy revenue is what it injects into the grid (in kWh) multiplied by the energy price in that hour. The project can maximize that revenue by using solar to charge the battery (rather than sending the solar energy directly to the grid) when prices are low, and discharging the battery when prices are high. However, when the project does that, it incurs losses – i.e., the total amount injected into the grid goes down, because batteries aren’t 100% efficient. The project also loses Environmental Revenue because of those losses, but it may increase its Capacity and DRV Revenue. All of that must be considered when deciding whether to charge the battery or send solar energy directly into the grid.
The distribution charges should be very low. This is mostly a fixed charge. But the project will also pull some electricity from the grid for lights, controls, etc. when there’s no sun. The project is not allowed to charge the battery from the grid.
Risks for Energy Revenue: o The main risk is wholesale market prices. It is possible that, as more and more solar is built in New York (and surrounding states), market prices may go down whenever it’s sunny – so most of the project’s output may occur at times of low prices.
For a solar+battery, Capacity Alternative 2 is the only option.
The project gets capacity revenue for all output (injections into the grid from either solar or battery) during the “capacity window”. The capacity window is very much like the DRV window: summer weekdays between 2 pm and 7 pm. The only difference is that the capacity windows go from June 24 to August 31 (whereas the DRV windows start June 1). There are 48 or 49 capacity days in the year, so a total of 240 or 245 hours (depending on when the weekends fall). All capacity days are also DRV days, but there are some DRV days (the first 3 weeks of June) that are not capacity days.
The project gets the same revenue no matter when within that window you operate, so its best to try to maximize the project’s output during the hours with the highest energy prices.
The Alt 2 capacity price is set early in the year and remains the same for the whole summer.
The project gets paid based on its output each month and that year’s capacity price (unlike Alt 3, where the project gets paid based on last year’s success in catching the “golden hour”, and this month’s price.)
The project only gets capacity revenue in June, July and August (unlike Alt 3, where you get revenue every month).
Capacity values in New York City and Long Island are the highest in the state.
Risks for Capacity Revenue: o Capacity auction prices are difficult to predict. In particular, as more offshore wind comes into service (providing both energy and capacity), capacity auction prices could be driven quite low in some months.
Solar+Battery systems get Environment Revenue for everything they inject into the grid, whether from the battery or directly from the solar array.
If the project charges the battery (in order to maximize Energy, Capacity or DRV Revenue), it incurs losses, and injects less into the grid. This reduces the Environmental Revenue.
The EV rate is locked in for 25 years. If the EV rates increases or decreases, the project still gets the 25 year fixed rate (currently $0.3103/kWh). Beyond 25 years, the EV rate is likely to be much lower, and could disappear.
Risks for Environmental Revenue: o None in the first 25 years, high after that given that we don’t know what the REC market will look like at that time. It’s unlikely that New York RECs could sell into ISO-New England or PJM because the power and RECs must be scheduled and that is normally only for larger projects.
Exactly the same as Battery-Only above: the project gets paid for output during the DRV windows. In PSEG-Long Island example, between 2:00 and 7:00 pm on weekdays between June 1 and August 31. There are similar but different windows for other utilities.
The project will often use solar energy outside of DRV hours (i.e., before 2 p.m.) to charge the battery, in order to maximize DRV and Capacity Revenue.
The project will receive DRV Revenue during June, July, August and September (except PSEG-Long Island) only, based on its output during the DRV windows, multiplied by the DRV price.
The DRV rate is locked in for 10 years. After that, it can change, or even disappear.
DRV values on a $/kWh basis are the highest in New York City and Long Island
Risks for DRV Revenue o The program could greatly reduce, or even eliminate, DRV after 10 years. Power Advisory’s forecast shows DRV remaining the same through 2040, then gradually falling to zero. o Volumes (combined injections from solar and battery) should be highly predictable.
Please reach out to Andrew Kinross (email@example.com) to discuss our services in New York. We provide electricity market analysis and forecast all VDER components (energy, capacity, E-Value, DRV, LSRV). We have a production cost model to determine supply / demand balance and ultimately price outcomes. We then optimize charging and discharging of the battery to maximize revenue. We support project developers, investors, utilities, and government agencies, among others. Further information on Power Advisory can be found at poweradvisoryllc.com.