Frequently Asked Questions

How does the Value Stack work on Long Island? What are the differences in the tariffs?

The Long Island Power Authority (LIPA) established its own Value of Distributed Energy Resources (VDER) policy which is slightly different from the Value Stack in the rest of the State. The most notable differences include how CDG projects are credited, how the demand reduction value (DRV) is calculated, and how the capacity value (ICAP) is calculated.

How does the Value Stack work for New York Power Authority (NYPA) customers?

Behind-the-meter generation consumed onsite reduces NYPA purchases. The electricity that is injected into the grid receives the Value Stack. In the service territories of Con Edison and National Grid, Value Stack credits can be applied to NYPA bills.

Who can I speak to at a utility company that is knowledgeable about VDER?

Each utility has a dedicated ombudsman whose role is to act as a resource between distributed generation providers and the utility. Visit this DPS page  for the most up to date contact information.

If an existing net metered project opts into the Value Stack, will it receive the VDER compensation structure (treatment of DRV, fixed rates, etc.) at the time it was originally interconnected, or when it opts in?

If an existing net metered project opts into the Value Stack after interconnection, it will receive the VDER compensation structure in effect at the time it opts in.

Does the voltage of the line that I interconnect to impact my VDER eligibility?

No, a project’s Value Stack eligibility is not impacted by the voltage of the line that it interconnects to.

What are the differences between the three ICAP Alternatives and which is the most appropriate for a given project type?

A project’s ICAP component is based on how well it reduces statewide energy consumption during periods of high energy load. Distributed generation owners can choose from three payout alternatives:

• Alternative 1–paid out according to each kWh injected into the grid throughout the year. Intermittent resources, including PV, receive this Alternative by default.
• Alternative 2–paid out according to each kWh injected into the grid during a peak window. The peak window is non-holiday weekdays from June 24 to August 31 between the times of 2 to 7 PM (approximately 240 hours per year). Alternative 2 will result in a stronger, more predicable ICAP compensation for resources that are able to inject more energy to the grid during this window, such as PV projects paired with energy storage or mounted on trackers.
• Alternative 3–paid out according to each kWh injected into the grid during the single peak hour of the year. Project compensation is awarded each month of the year, based on the injections from the annual peak hour multiplied by the monthly ICAP Alternative 3 $/kW rate. Dispatchable technologies (stand-alone storage, combined heat and power [CHP], anaerobic digesters, and fuel cells) must receive Alternative 3.

ICAP Alternative 1 and 3 rates change monthly, and ICAP Alternative 2 rates are set annually. Distributed generation owners may change from Alternative 1 to Alternative 2 or 3, or from Alternative 2 to Alternative 3. This election is permanent and cannot be undone. We encourage you to view Historic Value Stack Credit Data [XLSX] or the Solar Value Stack Calculator to review capacity pricing data over the past several years.

How are unallocated credits treated for a community solar project?

Hosts of community solar projects have the ability to bank unallocated credits for up to 2 years without the Market Transition Credit (MTC) or Community Credit, after which the credits are lost. During that two year period, hosts can allocate banked credits to new or existing offtakers.

What forces will increase or decrease VDER rates? My customers are seeing lower savings than I modelled several years ago.

Projects lock in their Market Transition Credit (MTC), Community Credit, and Environmental values for 25 years, and lock in their Demand Reduction Value (DRV) rate for 10 years. DRV rates are based on utility-calculated estimates of the cost of upgrading their distribution network to accommodate new peak loads. Forces that decrease peaks, like energy efficiency and declining populations, could decrease DRV rates. Forces that increase peaks, like population growth and increased electric consumption during peak times (for instance from heat pumps and electric vehicles) could increase DRV rates. The methodology used to calculate DRV is under consideration as part of a Proceeding Examining the Utilities’ Marginal Cost of Service Studies .

ICAP rates are tied to the NYISO wholesale capacity markets. ICAP rates can increase if power plants retire or if the State experiences a high annual peak load. ICAP rates can fall if there is a surplus of power generation (new power plants coming online) or if the annual peak is low.

Energy pricing in the Value Stack is based on the NYISO zonal day-ahead hourly location based marginal pricing (LBMP). Factors that impact LBMP include the number of generators bidding into the market, the cost of fuels including natural gas and oil, the amount of renewables on the grid, and the hourly demand for energy in the State’s different zones. Energy demand is highly sensitive to weather, which drives air conditioner and electric heat usage. 

2019 and 2020 have had relatively low pricing for capacity and energy, due to an abundance of generating facilities, low natural gas pricing, mild peaks, and reduced energy consumption due to COVID-19.

Where can I find specific Value Stack source documents?

The Department of Public Service (DPS) publishes proceedings on their website. This includes all Orders, white papers, utility filings, and filed comments.

How can I get updates about changes or new developments?

There are many ways to be stay informed about new developments related to the Value Stack:

• Periodically check DPS’s website for new proceedings.
• Sign up for the NY-Sun mailing list.
• Join an industry trade group, like SEIA or NYSEIA.
• Join a working group:
  • Interconnection Policy Working Group
  • Interconnection Technical Working Group