The numbers and assumptions included in some answers below are based on Idaho Power’s current service offering. Ongoing cases with the Idaho Public Utilities Commission (IPUC) could change the billing and compensation structure for on-site generation in the future. Existing residential and small general service on-site generation customers as of Dec. 20, 2019 have been grandfathered into the current offering by the IPUC.
Investments for homes in San Jose and Boise with identical energy use
|San Jose, California||Boise, Idaho|
|Average monthly electric use:||500 kWh||500 kWh|
|Average monthly bill:||$150||$50|
|System size to offset nearly 100% of use:||4 kW||4.3 kW|
|System net cost after tax credit:||$12,300||$9,000|
|Simple Savings1 Calculation|
|Estimated break even point:||7 years||17 years|
|Total 20 year payback:||$27,000||$1,700|
|NET PRESENT VALUE1 CALCULATION|
|Estimated break even point:||8 years||Beyond 20 years|
|Total 20 year payback:||$14,400||-$1,400 (loss)|
*For simplicity, the chart shows a pure yellow color. However, the home may still rely on the grid even when solar is at its midday peak. For example, when a cloud goes by or a large appliance needs a boost, the grid is there to meet the home’s energy needs.
Idaho Power’s on-site generation tariffs are not contracts and are subject to change. The current rules do not represent a guarantee of future pricing. Modifications to the tariff’s billing or compensation structure, including measurement interval and the credit value of excess energy generation, will affect the amount a customer would be compensated. As stated in the Idaho Residential Energy System Disclosure Act, legislative or regulatory actions can affect or eliminate one’s ability to sell or get credit for any excess power generated by the system and may affect the price or value of that power.
Connecting Your System
Excess Energy Credit Transfers
- Excess energy credits must be available.
- Service agreements must be held by the customer and be for the customer’s use.
- Service agreements must be on the same contiguous property and be served by the same primary feeder as the customer generation (i.e., on-site generation or net metering) service agreements.
- Transfers can only occur between Residential and Small General Service accounts (Schedules 1, 6, 7 and 8) or between Large Commercial, Industrial and Irrigation accounts (Schedules 9, 19, 24 and 84).
- If multiple service agreements are eligible for aggregation, excess credits must first be applied to eligible service agreements on the same rate schedule as the on-site generation/net metering service agreement. Remaining excess credits may then be applied to offset consumption at eligible service agreements on differing rate schedules in accordance with the criteria detailed above. For example, if the transfer is occurring from a Schedule 6 (Residential) service agreement to two eligible service agreements, one Schedule 1 (Residential) and the other Schedule 7 (Small General Service), you must transfer some portion of your credit to the Schedule 1 service agreement to be eligible to transfer a portion to the Schedule 7 service agreement.
Schedule 84 Customer Generation (Case IPC-E-20-26)
Idaho Power proposed two modifications to Schedule 84:
- To modify the metering requirement in Schedule 84 for new commercial, industrial and irrigation (CI&I) customers from a two-meter system to a single-meter system, simplifying the interconnection process.
- To grandfather existing Schedule 84 customers in Idaho under the current 1 kilowatt-hour (kWh) to 1 kWh net monthly compensation structure.
In its Order No. 34854 issued on December 1, 2020, the commission ruled:
- To modify the metering requirement in Schedule 84 for new CI&I customers from a two-meter system to a single-meter system, as proposed by Idaho Power.
- To grandfather existing Schedule 84 customers in Idaho under the current 1 kWh to 1 kWh net monthly compensation structure for 25 years.
CI&I customers taking service under Schedules 9, 19 and 24 in Idaho and Oregon.
- CI&I customers currently taking service under Schedule 84.
- Customers with an active application to take service under Schedule 84 received by Idaho Power on or before December 1, 2020, who interconnect their system within one year of the Feasibility Review.
Grandfathered systems are subject to the existing two-meter design standard. Systems are grandfathered at the originally installed nameplate capacity of the system.
Existing customers or applicants may choose a single-meter option; however, grandfathered status would be forfeited.
A customer who moves into a property with a grandfathered system will “inherit” the grandfathered status of the system. Grandfathered status does not travel with a customer if they move.
If a system is offline for longer than six months, or is moved to another site, the grandfathered status is forfeited.
To allow for the replacement of degraded or broken panels, customers may increase the capacity of their grandfathered system by no more than 10% of the originally installed nameplate capacity or 1 kW, whichever is greater. The total number of panels must remain the same as the originally installed system.
Grandfathering applies to the original approved nameplate capacity of the system. Customers who want to expand their system have two options:
- Keep the grandfathered system behind the second meter and place the new system behind the load meter.
- Combine the systems and follow the rules in effect at that time (lose grandfathered status) and place the combined system behind a single meter.
Customers should note that Idaho Power’s on-site generation tariffs — Schedules 6, 8 and 84 — as with all tariffs, are not contracts and are subject to change at any time upon order of the IPUC. The IPUC noted that “the program fundamentals are likely to change in the not too distant future,” so customers should expect program changes as a result of ongoing evaluation. Changes to the on-site generation tariff in the future may include, but are not limited to, modifications to rates, billing components, billing structure, compensation structures, and the value for excess energy produced by the customer’s on-site generation system (which affects the amount a customer would be compensated).
Yes. The company intends to submit a filing to formally initiate a comprehensive study of the costs and benefits of distributed on-site generation upon completion of Case Nos. IPC-E-20-26 and IPC-E-20-30, which address changes to Schedule 84 and customer generation interconnection requirements, respectively.
Establishing Interconnection Schedule 68 (Case IPC-E-20-30)
The primary objectives of this case are to: (1) implement an interconnection tariff schedule applicable only to retail customers who have distributed energy resources (DERs), (2) establish a smart inverter standard for all new DER interconnections, and (3) establish interconnection requirements for customers with DERs who do not wish to export excess net energy to Idaho Power.
The proposal asks the Idaho Public Utilities Commission (IPUC) to move the interconnection requirements for customer-owned on-site generation from Schedule 72 (Interconnections to Non-Utility Generation) to its own schedule, Schedule 68 (Interconnections to Customer Distributed Energy Resources). Schedule 72 includes requirements that don’t apply to customer generation. We believe moving the customer generation section to its own schedule will make it easier for customers and installers to navigate the requirements.
Yes, in preparing the filing, Idaho Power evaluated existing processes to determine whether improvements could be made to streamline existing processes and/or increase operational efficiencies. Idaho Power has requested the IPUC approve the following:
- Modified or added language intended to improve administrative clarity in the interconnection process
- Removal of the three-year recertification requirement
- Additional time for Feasibility Reviews in limited circumstances
- Additional time for a customer to bring an unauthorized system into compliance or to choose to permanently disable the system
- Implementation of a return trip charge billed to the customer if Idaho Power is unable to complete the inspection after the customer or installer has submitted a completed System Verification Form certifying the system is ready
Smart inverters provide the functionality to support the ongoing stability and reliability of Idaho Power’s distribution system. They can mitigate circuit voltage deviation in a cost-effective manner. In May 2018, the Commission ordered Idaho Power to submit a filing within 60 days of the final adoption of the Institute of Electrical and Electronics Engineers (IEEE) standards 1547 and 1547.1 regarding smart inverters. Those final IEEE smart inverter standards were issued in May 2020. Idaho Power is proposing to require smart inverters for new on-site generation systems or when existing inverter-based systems need to replace old inverters.
Some customers do not want to export power to the grid and would prefer to remain on a standard rate schedule. However, these systems are still grid-connected and, as such, need rules in place to ensure they do not negatively impact the grid. The proposed tariff schedule outlines: (1) technical solutions to prevent export; (2) an interconnection and application process so Idaho Power can verify compliance with the interconnection requirements and (3) mitigation efforts should the customer export power beyond inadvertent export limits. The proposed interconnection requirements for a non-export customer are subject to review and approval by the IPUC.
Under both the export and the proposed non-export options, residential (Schedule 01) and small general service (Schedule 07) systems are limited to a maximum size of 25 kilowatts (kW) (or kilovoltampere [kVA]). They also have similar equipment requirements. This limit will allow these customer groups to elect to transition between non-export and export by submitting an application, and without having to make costly retrofits to their systems. The proposed system size limitations are subject to review and approval by the IPUC.
There are two configurations for Energy Storage Devices (such as batteries), those that share an inverter with a Generation Facility (direct current [DC] Coupled), and those that have a standalone inverter (alternating current [AC] Coupled). Idaho Power’s proposal requires that Energy Storage Devices that are not coupled with a Generation Facility taking service under Schedule 6, 8, or 84 (exporting system) may not export energy onto Idaho Power’s system. The Company’s proposal outlines the total nameplate capacity will determined as follows:
- DC Coupled: For Energy Storage Devices that are DC Coupled, the total nameplate capacity of the system is defined by the inverter (kVA or millivolt ampere [MVA]).
- AC Coupled: For energy storage devices that are AC Coupled with an exporting system, the total nameplate capacity of the system is the aggregate of all [DER] at the point of delivery [POD]. An Energy Storage Device, coupled with a non-export Generation Facility, is considered a separate
Under the current tariff, Idaho Power inspects current on-site generation systems to ensure the system still complies with our requirements every three years. The most common issues include unauthorized system expansions or disabled systems. The company has identified other means it can utilize, at a lower cost for customers, to identify locations where changes have occurred without company notification and has requested the removal of the three-year inspection requirements. Examples include metering data and sample inspections.
Customers connecting in parallel to Idaho Power’s grid are required to follow the interconnection process, even if they do not intend to push power back to the grid. Also, customers that expand their systems beyond the initially approved nameplate capacity are required to follow the interconnection process for the expansion. The current tariff has timelines for customers with unauthorized systems to bring their system into compliance or permanently disable it. However, these timelines are not always feasible given local and state permitting requirements, weather and other impediments. Idaho Power proposes extending the timeframe to one year, the same as a new application. Under this proposal, the customer must disable the system through the AC disconnect or other means until it complies or is permanently disabled.
Many customers do not realize adding solar panels or turbines or upgrading the inverter constitutes a system modification. System modifications must come through the interconnection application process so Idaho Power can ensure continued compliance with the applicable interconnection requirements. In addition to changing the inverter capacity, the following are also considered modifications:
- For systems approved based on the nameplate capacity of the generation source (generally applications received before May 1, 2020), any increase to the Generation Facility Nameplate capacity is considered an expansion.
- For systems approved under an AC nameplate rating (generally applications received on or after May 1, 2020), any change to the total maximum AC capacity is considered an expansion.
Please note that any changes to system capacity may also require a state or city electrical inspection.
Idaho Power is required to ensure the distribution system can accommodate the customer generation system and has seven business days to complete this review. However, some projects require additional engineering review, especially if multiple applications are received for the same feeder. In these cases, Idaho Power is requesting 15 additional business days to complete the Feasibility Review.
After an on-site generation system is installed and has passed its electrical inspection, Idaho Power conducts a site visit to complete the system inspection. This action occurs after the submittal of a System Verification Form where the customer or installer certifies that the system is operational and ready for inspection. The form asks for certification that the system has passed its electrical inspection, inverters are programmed, the breaker is on and all signage is in place. Idaho Power has noted that approximately 10% of projects are not ready when we arrive, and Idaho Power cannot complete the inspection because one of the criteria that was indicated to have been completed has not been. The return trip charge will help recover the costs when our crews must return for a new inspection.