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The NYSolar Smart Team frequently conduct workshops and roundtables for solar installers in New York State and New York City facilitated by NY Solar Ombudsmen. Below are 'Frequently Asked Questions' about interconnection and large scale solar projects in New York that resulted from a recent workshop with NYS Utility Companies. The ombudsmen worked with our NY utility partners to develop the responses. If you would like to join the NYC and/or NYS Installer Roundtable, please send a request with your solar company email to

Department of Public Service 2/28/2018 Presentation: Distribution Level Interconnection in New York

Why don’t small companies get a dedicated liaison for their own project discussions?
The amount of dedicated attention that will be given to each applicant is dependent upon the number of applications coming through the Distributed Generation group within each utility, and also the resources that are allocated to reviewing applications.

Are there plans for tracking an application through the interconnection process?
This is currently done through email. The communication outlines that actions that are needed, and how much time each step is allowed. It was recommended by the NYC Department of Public Service (DPS) that all utilities implement an online portal that includes an application tracking protocol.

Besides account numbers, are there any criteria to populate the customer information?
Yes, all of the required pieces of information that are required to submit an application are outlined in the SIR. There are different requirements for the pre-application report, the full application report, and a CESIR study. The document can be found at the following location:

Do utilities have plans to automate the final approval for Permission To Operate (PTO)?
A report was developed by the Electric Power Research Institute (EPRI), which lays out the plan for interconnection online application portal (IAOP) functional requirements in detailed steps. The report can be found on the DPS website at the following location:$FILE/EPRI%20Task%201%20Memo%20Report_Final%209-9-16.pdf

In the online utility portal, applicants enter the account number. Will that populate all the customer information? Will the applicant be able to see customer details by entering random account numbers? How can confidentiality be ensured?
This is not currently available through the utilities in the state of New York State. When online portals are used, customer information is safeguarded using cyber security best practices.

Can local 'Authorities Having Jurisdiction' (AHJ) communicate with the utility company?
Currently this information must be submitted by the system installer, and the utilities do not communicate directly with the AHJs.

What is the NYS vision for beyond net metering?
DPS is currently developing the framework that will replace net metering in New York State. Earlier in the year, organizations submitted comments related to the Value of Distributed Energy Resources (DER), Net Energy Metering (NEM).  The filing on the DPS website received almost 200 document submissions.  The recommendations from DPS are expected to be released late in 2016 for public comment, with rulings to be adopted in 2017.  All proposals, working papers, comments and orders related to this REV proceeding are available on the PSC website here:

Treatment of capital investment tax for large solar projects?
There is a federal investment tax credit (ITC) of 30% for residential and commercial projects, MACRS accelerated depreciation for commercial projects, and other tax benefits such as the Property Tax Abatement in New York City, but the organization owning the system must have a tax liability in which to benefit from these incentives.  If projects are being developed on government or other non-taxed entities, these incentives cannot be captured.  There are ownership structures that can be leveraged to bring in third part tax equity partners to own and capture tax credits for non-taxed partners.  There is more information on the NY Solar Map and Portal regarding the incentives that are available to different parties:  

Where are the best community shared solar learning resources?

Although the overall guidelines and rules of community DG in New York are governed by the orders of the Public Service Commission, each utility has its own set of procedural requirements.  These are available for on the utility websites and on the NY Solar Map. 

How are community shared solar projects metered? Example: a 100 unit townhouse development has one main common area meter and there are 100 individual meters. The roofs will be maxed out with solar. How is the generation split between each meter?
In this example, there would be one main meter tied to the solar array and then 101 members each with an existing meter.  Each member would purchase a percentage of output from the solar array.  The sponsor would submit an allocation form to the utility indicating what percentage of the total output each customer had purchased.  When the meters are read, the utility would take the total generation of the solar array and allocate the appropriate percentage of generation to each member’s bill.  The financial agreements between the sponsor and member are completely between the two parties and do not include the utility.


If an applicant paid for a CESIR in October 2016, after the queue reset, do they need to go through CESIR again assuming that the interconnection costs will be lower?
No, however, there may be some change in the utility upgrade requirements after the pre-March 2016 queue has been cleaned out. 

Why have CESIR costs increased 4x in 12 months?
Different utilities have different processes, and costs may be different across the state. The cost of a CESIR study is a direct cost that is recouped by the utility without a markup. Any cost increases are due to increasing analysis costs.


What do the utilities plan on doing near term and long term to improve DG customer billing, particularly as Community Distributed Generation (CDG) expands?
Some utilities have looked at third party software solutions, and evaluated internal programming changes to existing billing systems, but as of now the process is done manually. Currently there are not a large number of CDG customers, so as the number of customers increases the process may change.

Step 1
: Lines of communication are established between the applicant and the utility.

Step 2: The utility informally reviews the inquiry to determine the nature of the project.

Step 3: The applicant flies an interconnection application with a pre-application fee of $750.

Step 4: The utility performs a preliminary screening analysis and develops a cost estimate for the coordinated electric system interconnection review (CESIR) if required. The utility will return a pre-application report within 10 business days.  Based on the results of the pre-application, the applicant may move forward or withdraw the application. 

If the applicant moves forward with the application within 15 business days, the $750 pre-application fee is applied toward the cost of a full application. If the result of the preliminary analysis show that the proposed system passes all of the relevant technical screens, then the utility will return an interconnection contract and the system may proceed with the interconnection process.

If the results of the preliminary analysis show that the system cannot pass all of the technical screens, then the utility will provide technical reasons. The applicant can then proceed to a preliminary analysis meeting, a supplemental review, proceed to a full CESIR, or withdraw the application.  

Step 5: The applicant commits to the completion of the CESIR. The CESIR package includes additional information about the system, and an advanced payment of the costs associated with completing the CESIR.

Step 6: Utility completes the CESIR. The CESIR will be returned to the applicant in 60 business days.

Step 7: Applicant commits to the utility construction of utility’s system modification. The advanced payment of 25% of the estimated costs will give the applicant 120 business days to pay the remaining balance. 

Step 8: Project is constructed.

Step 9: The applicant’s facility is tested in accordance with the standard interconnection requirements (SIR) guidelines. The applicant has 10 days from complete installation to perform testing. 

Step 10: The system is interconnected.

Step 11: Final acceptance and utility cost reconciliation. Within 10 business days of completion of testing, the utility will issue a formal acceptance for interconnection. 

A more detailed description of this process can be found on the DPS website under the distributed generation page.


The process for solar+storage is the same as the process for solar alone. The SIR applies to all distributed generation under 5 MW.  The systems may need to be filed on separate applications depending on the way that the solar+storage system is coupled.  

Is there a real need for DTT and 3V0? How close are we to an alternative to DTT, such as PLC? When? Rules/explanations/exceptions that are needed?
Direct transfer trip (DTT) is required for islanding concerns. When there are large PV systems (>2 MW), there is the opportunity for them to miss the fault.  Typically this is on lightly loaded circuits where the DG production is significantly higher than load.  Using the Red Zone utility maps can help to determine where there may be circuits with capacity or load issues. 

When there is reverse power flow on a feeder due to generation which is enough to backfeed a substation transformer, additional protection known as zero sequence voltage (3V0) protection is required when the substation transformer is a delta (transmission side) wye-grounded (distribution side) connection. This is because a delta wye-grounded transformer cannot contribute zero sequence ground fault current during a phase to ground fault on the transmission side, and as a result can cause voltage on the unfaulted phases to rise significantly which can damage substation and transmission equipment. 3V0 protection is thus installed on the primary side of the transformer to protect against these overvoltage conditions. This is usually required in locations where the substation transformer is a delta-wye grounded connection and the transformers are fed by a single source (either radial or tapped transmission lines).

These protections are required by the DPS in certain cases, alternatives are being investigated but there is no timeline for adoption.

Why does it cost so much money to get to the point of an interconnection quote?
Under the new SIR, the cost to get a price on interconnection could be as low as $750. If a CESIR study is required, then the applicant must pay for the analysis required to develop the report.

Will new interconnection reports include a breakdown of interconnection costs, so that installers have some insights into how costs scale with project size?
Yes, the reports that are prepared by the utility will have detailed cost breakdowns into equipment requirements, material needs, labor, overhead, and other categories. The applicant can also meet with the utility team during a preliminary analysis meeting and a supplementary analysis meeting to discuss how costs may change if project sizes are modified.  

How do solar installers/developers get a handle on cost estimating interconnection faster? Can a process be refined and posted on the utility websites?
The results of the interconnection studies (including cost estimates for interconnection) are given to the applicant as soon as they come available, with the upper timeframe outlined in the SIR. The process is continually improved to find efficiencies, with different processes implemented across different utility territories.

How is the delivery charge determined?
Delivery charges are different for each service territory. They are released as part of the tariff, and can be found on the DPS website at the following location that gives a breakdown of the costs associate with the delivery charge:

The charge is typically billed on a volumetric basis.

Will the utility need to increase the monthly service change and delivery charge when more customers implement DG?
Yes, as more DG is implemented, the utilities will need to re-coup grid investments. This changes with project characteristics, such as system size, system output, customer class, etc.  

Would it be possible to post lessons learned or common mistakes manual for consumers to see on the website, which shows common interconnection issues encountered in your daily work?
Lessons learned and common mistakes were presented at the Interconnection Workshop & Roundtable. The presentations can be found at the NY Solar Map:

Some of the utilities have lessons learned and FAQs that can help answer some questions as well.

Con Edison -

National Grid -

Central Hudson -

Orange & Rockland -

New York State Electric & Gas -

PSEG - Long Island -

Grid penetration guidelines in NY are not consistent with other states. Is NY planning to adopt best practices from other places where higher penetrations have been shown to work?
Guidelines are developed at the NY Public Service Commission (PSC) level, typically based on reports from EPRI or Sandia National Laboratory, or the National Renewable Energy Laboratory. Guidelines have referenced reports as footnotes or appendices.  

Has DPS put time constraints in the interconnection agreement for timelines to complete solar projects?
The new SIR that was adopted this spring has binding timelines for completing activities, responding to reports, and paying fees. Projects that do not meet these timelines will be removed from the interconnection queue.

A more detailed description of this process can be found on the DPS website under the distributed generation page:

How can applicants split costs between projects, when an upgrade is required on a line with multiple projects?
A proposal has been put forward to cost share upgrades to utility infrastructure between multiple projects. The ruling from DPS is expected to be released in late 2016.  The DPS Interconnection Policy Working Group has been leading the development of this proposal, and information from the meetings, including the draft proposal, can be found at the following location:  

Integration of storage into ‘behind the meter’ projects?
Storage can be integrated behind the meter for a number of potential site and grid benefits. In the coming years, it is expected that the energy storage market will grow substantially in both residential and commercial applications.   

Is there an easy way to find correct information for utility representatives?
NYSERDA maintains contact information for each of the utility distributed generation programs. The information can be found at the following website:


Can ‘zombie’ projects be removed from site-specific queues?
A proposal has been put forward to clean out old queue projects that may no longer be active. Once this has been adopted, inactive projects will be removed.  In the meantime, project developers can work with their utility contacts on a case-by-case basis.  Progress on this topic can be followed on the Interconnection Policy Working Group page:

How long will the old queue cleanup take?
The applications that are in the old SIR will reach their deadline for project progress by April 29th of 2017. At that time the projects will be removed if they do not move forward. In addition to this deadline, the PSC has proposed a process by which inactive project may be removed sooner. Once the proposed process is adopted, the ‘20 day’ clock will begin on a number of ways that project progress must be proven:

  • Within 10 business days, produce proof of property ownership or lease
  • If in the preliminary review phase, have 5 business days to submit a full application.
  • If in the application phase, have 15 business days to move to the CESIR phase.
  • If CESIR has been completed, have 30 business days to pay the 25% expected upgrade cost and execute the interconnection contract with the utility.    

Progress on this topic can be followed on the DPS Interconnection Policy Working Group page: