IRP Questions and Responses

Relevant questions or comments submitted using the form below or via email will be made public, along with Idaho Power’s responses, on this page.

We will respond to questions within two weeks.

IRP Questions, Comments and Responses

Following are IRP-related questions from members of Idaho Power’s IRP Advisory Council or other members of the public, either at IRPAC meetings or via email or using the form above. More information is available at idahopower.com/irp.

How much does the cloud seeding add up to per year?
Our target control analyses and hydrologic modeling indicates that, on average, cloud seeding adds approximately 1 million acre-feet of water to the Snake River basin above the Hells Canyon Complex. Approximately 600,000 acre-feet of the benefit occurs in the Payette, Boise and Wood River basins, and 400,000 acre-feet in the Upper Snake River basin. Water supply increases are variable in any given year depending on the nature of incoming storms and opportunities for cloud seeding.

Current operational costs are shared among the State of Idaho, Idaho Power, and other stakeholders. Program costs have remained stable over the last four years with fiscal year 2019 costs totaling $3.3 million. The Legislative Services Office 2020 Report estimates the program cost at “$2.36 per acre-foot of additional estimated snowpack in fiscal year 2019.” By comparison, an acre-foot of storage in the upper Snake River basin rented for up to $30/acre-foot in 2019.

Additional information regarding cloud seeding can be found here.

Have the materials in cloud seeding been researched for toxicity?
Silver iodide has been used as a seeding agent around the world for decades without any known harmful effects. Silver iodide is insoluble in water which is a characteristic that keeps it from having harmful effects.

Idaho Power works closely with federal, state and local authorities to ensure our cloud seeding operations comply with all relevant environmental and land-use guidelines.

Additional information regarding cloud seeding can be found here.

What approvals are necessary for the cloud seeding program at Idaho Power? What is the risk of losing those approvals and what would the impact be to Idaho Power’s hydrology modeling assumptions?
During the 2021 legislative session, the legislature passed House Bill 266. The passing of HB 266, in part, requires the Idaho Water Resource Board to authorize local or statewide cloud seeding programs, including Idaho Power’s cloud seeding program. Prior to the passing of HB 266, no approvals for cloud seeding were required in the State.

The risk of not receiving the Idaho Water Resource Board’s approval is extremely low. HB 266 recognizes that augmenting water supplies through cloud seeding is in the public interest. As such, the company is confident that the Idaho Water Resource Board will continue to recognize the public benefits of cloud seeding, and support the company’s program into the future.

What peak accreditation for hydro was used in the 2019 IRP?
For the 2019 IRP analysis, the following peak accreditations were used:

  • Hells Canyon Complex: 0.85 to 1
  • Run of river hydro: 0.49

What are the risks to the transmission and distribution systems that transport hydro energy associated with climate change?
Transmission lines are rated based on extreme ambient conditions. Idaho Power utilizes 40 degrees Celsius (104 degrees Fahrenheit) to establish continuous summer ratings. The lines can operate in higher temperatures for a period of time also.

If climate change results in many days in excess of 40 degrees Celsius, this may cause future transmission de-rates.

We study extreme events as part of our risk assessment. We account for a transmission corridor taken out by an extreme event such as wildfires, floods, etc. We perform this assessment annually.

How does Idaho Power plan to handle runoff in the event that it exceeds reservoir capacity?
During high water supply years, it’s not uncommon for spring season flows to exceed the hydraulic capacity of the powerplants through the mid-Snake River or at the Hells Canyon Complex. Hydropower systems generally are not designed to capture these infrequent high flows fully within powerhouse capacity.

Excessive runoff is managed with spillway facilities, and our projects have Emergency Action Plans and regional flood risk management guidelines to address high flow rates. Brownlee Reservoir is specifically coordinated with the US Army Corps of Engineers for spring season flood risk management, with specified space reservation and refill targets.

Regarding excessive runoff, why doesn’t Idaho Power consider batteries to capture some of the increased flows?
During excessive runoff periods, Idaho Power’s hydroelectric facilities can only generate up to their powerplant capacity. Excess water above those capacities is either stored (in the case of Brownlee Reservoir) or spilled and cannot be converted into hydropower.

Idaho Power continues to evaluate energy storage in the context of the entire system. Storage evaluations need to consider the timing and magnitude of excess energy from all sources (hydro, variable resources, market, etc.), system load characteristics, and the capacity (MW), energy storage (MWh), and time shifting capabilities of the storage system.

How are/will customers be compensated for managed recharge? Is there a name for that compensation program, analogous to Demand Response for irrigators and A/C?
Managed aquifer recharge is conducted by the Idaho Water Resource Board (IWRB) and its partners according to natural flow water rights that are administered according to the prior appropriation doctrine and Water District 1 accounting. There is no compensation for the program to Idaho Power, since the diversions are conducted within the IWRB rights.

For the purposes of Aurora modeling, do you presume the Bridger coal units are must-run at their minimum generation level (say 30-40%) and then economically dispatched for the segments above minimum load?
For the 2019 IRP analysis, Bridger coal units were modeled as you described. They were must-run at their minimum generation levels and dispatched at higher levels when economical.

While we consider those assumptions reasonable, we are in the process of reviewing these assumptions for the 2021 IRP analysis. We want the model to reflect actual operations as closely as possible.

It would be great to hear about the details of the final agreement with NV Energy for the early exit at Valmy Unit 1, as an “example” of what the agreement could potentially look like for Unit 2 and/or for Bridger with PacifiCorp. Can that be provided please?
While the Agreement with NV Energy is confidential, the direct testimony of Tom Harvey, filed in Idaho Case No. IPC-E-19-08 and Oregon Docket No. UE 363, describes the provisions of the North Valmy Project Framework Agreement between NV Energy and Idaho Power dated February 22, 2019.
Idaho Case Link: 20190308Harvey Direct.pdf (puc.idaho.gov)
Oregon Case Link: UE 363, TESTIMONY & EXHIBITS, 7/3/2019 (puc.state.or.us)

Slide 3 of this presentation indicates that operating and capital costs are shared proportional to ownership. However, in the 2019 IRP, OPUC staff found and confirmed that PacifiCorp and Idaho Power have different O&M costs for the Bridger units. Would you explain this discrepancy? (OPUC staff final comments PDF, page 32)
Regarding Bridger O&M costs in AURORA, Idaho Power developed the O&M costs for Idaho Power’s one-third share of the plant, whereas the AURORA model vendor developed the O&M costs for PacifiCorp’s two-thirds share. The Company typically does not adjust model vendor inputs for other companies’ units because other companies may have different O&M versus capital upgrade methodologies or different regulatory approaches. Idaho Power remains responsible for ensuring that it is calculating its best estimate of the costs that the Company will incur, while PAC remains responsible for ensuring that it is calculating its best estimate of the costs they expect to incur.

While Idaho Power appropriately relied on actual fixed O&M costs as the basis for the Company’s modeling, the Company does not necessarily believe that there is only one correct method to estimate different companies’ future fixed costs.

The approximate 15,000 MW energy requirement for 2021 seems low by comparison to the Second Amended 2019 IRP’s energy forecast for 2021 (greater than 16,000 MWh). Is this due to load impacts from the pandemic? Or are there other changes with regard to energy forecasts between the 2019 and 2021 IRPs?
The 2021 IRP load forecast takes into account the impacts of use per customer changes from COVID throughout the IRP forecast period. It is estimated that change in use per customer will be most impactful in the near term.

Has Idaho Power looked at the cold-climate highly-efficient air-source heat pumps? Colorado is using these in climates similar to Idaho. I don’t buy this need for a heat strip, if CO can do this. Could Idaho work with the legislature to add to federal rebates? I just got a $300 rebate for my heat-pump hot water heater. Colorado is using air-source heat pump space heaters in places as cold as any in Idaho. They were looking at temperatures below zero. For the vast majority of the winter, we’d all come out way ahead.

The Idaho Power Heating and Cooling Efficiency Program began incentivizing heat pumps for space heating in 2007 that span just above federal efficiency minimums up to the highest-efficiency heat pumps.

Idaho Power has been involved at a regional level and local level with what are being referred to as ‘cold climate heat pumps’ since 2012 when Mitsubishi began producing a ‘Hyper Heat’ series of ductless heat pumps. The Hyper Heat series are variable capacity/speed ductless heat pumps (VCHP) with a special feature called a ‘flash injection circuit’ that extends the full heating capacity down to lower outdoor ambient temperatures when compared to heat pumps without the special feature. This extended heating capacity with a flash injection circuit can outperform heat pumps without the feature including variable capacity/speed heat pumps, single stage heat pumps, or two stage heat pumps.

The term ‘cold climate’ is not an officially defined industry term. The term was created by North American stakeholders interested in increasing awareness, education, usage, and manufactured product breadth of colder climate systems.

In 2018, NEEA (Northwest Energy Efficiency Alliance) started a Heat Pump Coalition made up of North American stakeholders of which Idaho Power is a member. Its focus is mainly on VCHPs and the cold climate technology. Idaho Power is further involved in VCHPs with a new NEEA Variable Speed Heat Pump initiative. VCHPs, whether they are ‘colder climate’ rated or not, have a reduced dependency on backup/supplemental heat. However, that dependency is not eliminated for defrost and emergencies.

Is the increase in winter load taken into account when considering heat pumps?
The load forecast, limited to the residential class forecast, does include the impacts of the existing stock and incremental heat pump conversions as applicable.

The solar-only ELCC chart showed that it is not very effective at meeting net peak load, but solar + storage is, which makes sense. Does that mean that the solar-only ELCC curve will be dramatically lower than the solar accreditation curve outlined in the last IRP? I recall the next marginal solar project (without storage) would have an approximate 45% capacity value, then the next one just a few percentage points lower, etc. Sounds like that curve is now blown up to very low values?
That is correct. Stand-alone solar is reducing summer peak demand during daylight hours to an extent where, in the near future, net peak demand will occur at a later time when solar generation is not available. Solar-only ELCC will be low for this reason.

There’s a body of evidence demonstrating that well-designed Time-of-Use rate design change usage patterns and reduce peak loads. How is that option being evaluated within the IRP process?
The company has committed to conduct a comprehensive review of its Demand Response (DR) programs (including DR program timing, parameters, and pricing changes) concurrent with the 2021 IRP process. The Company will engage with Staff and interested stakeholders throughout the evaluation and agrees that an evaluation of a behavioral-type DR program, such as a critical peak pricing program, should be included in that review of potential DR-program modifications/enhancements.

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