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
The following questions or comments were submitted via email or by using the form above. Responses are from Idaho Power’s IRP team.
Please explain how the AURORA model treats carbon costs in determining the hourly marginal price of PNW power when performing simulations.From: Stop B2H
In the Aurora model, the marginal resource within each Area’s resource stack sets the Area price. The Area price is then evaluated against the marginal resources in other Areas. If another Area has superior economics after evaluating the wheeling charge, line losses, and available transmission import capacity, imports are made.
The dispatch cost of a resource is impacted by many things including the marginal heat rate of the generating unit, the carbon content of the fuel and the carbon dioxide (“CO2”) emissions price per ton (if applicable). Aurora has the emissions intensity for each fuel type in the model, expressed as CO2 lbs per mmbtu of fuel. Using the emissions information Aurora calculates the increase in the dispatch price of the unit per MWh to pay for the CO2 emission. The resulting price is used to determine the least cost resource to serve the marginal load which sets the Area per MWh cost.
For each Portfolio, please provide a table and graph showing the total carbon content of market purchases from the PNW for each year of the AURORA simulation.
The carbon content of purchases is not calculated or reported in Aurora and therefore not available.
For each Portfolio, please identify the average price of PNW market purchases for each year and the year-on-year increase in the PNW market price. For each annual price change, please identify the relative contribution to the annual price change caused by changes in the assumed price of natural gas and by the effect of carbon costs respectively. From: Stop B2H
Please see pages 1-24 in the attached PDF, which contains spreadsheets showing the aggregate and annual market purchases and prices as reported in Aurora for each of the natural gas and carbon price scenarios. The total portfolio costs do include the impacts of the changes in the carbon and natural gas price assumptions, however the relative contribution of natural gas and carbon prices impact on market price changes over the study period is not calculated or reported in the Aurora output.
In Idaho Power’s high carbon cost portfolios that include B2H, Idaho Power’s AURORA optimizations result in fewer “carbon free” renewable purchases and sharply higher PNW market purchases. Please explain, on a year by year basis, the increase in total portfolio carbon emissions in the B2H case compared to the same Portfolio without B2H, for each discrete year of the simulation.From: Stop B2H
Although preliminary portfolio emissions data was shared at the April 11, 2019, IRPAC meeting, the portfolio carbon emissions analysis is not complete. Idaho Power will supplement this response when the final information is available.
Idaho Power recently announced that it will deliver 100% power clean energy by 2045. This means that a portfolio that relies on market purchases (and associated carbon content) to supply a large portion of power to Idaho Power customers is inconsistent with your 100% clean energy pledge. Please explain the following:
a. For each scenario pair (i.e., with and without B2H), please provide a table showing on a year-by-year basis, the annual NPV revenue requirement for Portfolios 1-12, and the change in annual NPV revenue requirements resulting from the addition of B2H (Portfolios 13-24).
b. For each scenario pair, please provide a table showing on a year-by-year basis, the annual net present value requirements resulting from the addition of B2H to the Portfolio.From: Stop B2H
a. Please see pages 25-26 in the attached PDF showing the NPV of the total portfolio costs under the Planning Case scenario for each portfolio without B2H.
b. Please see pages 25-26 in the attached PDF showing the NPV of the total portfolio costs under the Planning Case scenario for each portfolio with B2H
Because an expanded market purchase strategy based upon B2H is inconsistent with a low- or zero-carbon portfolio strategy, please explain why you believe that B2H should be considered a 55-year resource in your IRP, instead of a 20-year resource whose value to Idaho Power ratepayers is sharply reduced, if not largely eliminated after 2045.From: Stop B2H
Idaho Power disagrees that a low- or zero-carbon future is inconsistent with the need for transmission lines such as B2H. In fact, the Company believes the contrary is true – that transmission lines are necessary to facilitate a clean, affordable and reliable energy future.
The 345-kilovolt transmission line between Idaho Power and Nevada is a perfect example of transmission infrastructure facilitating affordable clean energy opportunities. Idaho Power built its share of the transmission line in 1980 to import power from the North Valmy power plant. Idaho Power will be exiting its share of the Valmy plant by 2025, but the transmission line is still valuable beyond the useful life of the plant.
Specifically, the transmission line is what will facilitate the interconnection of the Jackpot Ranch solar project, which is the 120 MW solar project that Idaho Power recently signed at among the lowest costs in the nation. The Jackpot solar project will benefit Idaho Power customers for at least the 20-year contract life of the project and potentially longer if the contract is renewed (until at least 2042, or 62 years from the construction date). The Jackpot solar project could not connect to the system at its current location, and at its affordable cost without the existing transmission line infrastructure. This example demonstrates that transmission lines have benefits to customers for more than 55 years and are necessary to facilitate a clean, reliable and affordable energy future.
Why has Idaho Power has chosen to simplify the Aurora representation of the Idaho Power system in this 2019 IRP compared to the 2017 IRP? From: Jim Kreider, Stop B2H
For portfolio evaluation, Idaho Power did not simplify the Aurora representation of the Idaho Power system in the 2019 IRP compared to the 2017 IRP; the transmission topology used for portfolio evaluation will be identical to that used in the 2017 IRP. The less granular zonal system diagram referenced by StopB2H reflects the diagram that will be used for the Company’s long-term capacity expansion (LTCE) simulations to develop the portfolios, which represents an additional step that was not utilized in the 2017 IRP. Aurora has the functionality to switch between various system diagrams for different purposes in the model. A simpler diagram enables complex modeling to be completed in a reasonable timeframe, which is necessary to perform the LTCE simulations. More complex diagrams are used once the resources are defined, i.e. for evaluating resource portfolios. It’s important to note that the underlying data in the model is the same regardless of the system diagram used.
To summarize, the less granular zonal setup referenced by StopB2H is necessary to facilitate the complex calculations to develop portfolios through the LTCE simulations. Once the optimized portfolios have been developed, the Company will use the same zonal setup as the 2017 IRP to evaluate the portfolios.
With the exception of the LTCE modeling, B2H will be evaluated in the same manner as the 2017 IRP. As discussed at the Jan. 10, 2019, Integrated Resource Plan Advisory Council (IRPAC) meeting, through the LTCE modeling Idaho Power will develop 28 portfolios, 14 with B2H and 14 without B2H. Once these portfolios have been developed, B2H will be evaluated in the same manner as the 2017 IRP.
Please identify the zone or zones from which load was extracted and moved into the new 51 IPC zone, and the specific amount of load moved into the 51 IPC zone from each discrete default zone or zones from which the new 51 IPC zone was created.
As discussed during the Dec. 13, 2018, Aurora workshop, an area is defined as a load area for a specific geographic area. A single area or multiple areas can be combined to form a zone. The default Aurora setup combined the Idaho Power, BPA and PacifiCorp Eastern Idaho areas to form the “5 IDSo” zone. In order to isolate Idaho Power’s load, resources and transmission constraints, the Company developed a new zone, “51 IPC.” The “5 IDSo” zone reflects the Aurora default load forecast for BPA’s and PacifiCorp’s Eastern Idaho load.
(Excel file was provided to the sender.) The output from Aurora for the 2019 IRP is not yet available for Idaho Power to provide the requested summary table or graph.
STOP understands that this slide represents the zonal loads and prices on the hour of the Idaho Power system peak load in 2019. The total Idaho Power zonal load is shown as 3,340 MW, which does not appear to include all the network loads placed on Idaho Power on a peak day. According to Idaho Power’s Transmission formula rate filing for transmission rates that became effective on Oct. 1, 2018, Idaho Power’s peak day network loads in July are expected to total 3,740 MW, including 352 MW of BPA loads in Idaho that are network transmission customers of Idaho Power. It appears Idaho Power has not included the BPA network loads as loads on the Idaho Power system (51 IPC). If this is the case please confirm that Idaho Power has not included these BPA network loads in the Idaho Power zone in the Aurora model, the reason these BPA network loads are not included in the 51 IPC zone, and into which Aurora Zone the BPA network loads on Idaho Power have been placed.
Idaho Power load is included in the 51 IPC zone, while loads served by BPA and PacifiCorp are included in the 5 IDSo zone. As discussed at the Dec. 13, 2018, IRPAC meeting, the 51 IPC zone is specific to Idaho Power loads, as the intent of the IRP is to determine a 20-year plan for serving Idaho Power’s load in the least-cost, least-risk manner. Therefore, including loads served by another entity in the same zone as Idaho Power would not be appropriate for this purpose.
Please provide a spreadsheet containing actual hourly flows over WECC Path 14 (Idaho to Northwest path) for the last five years 2014-2018. Please explain how the integrated hourly flows were calculated (i.e., based upon 2-second SCADA readings, etc.) In addition to the hourly data for Path 14, please summarize the data provided into five graphs depicting annual hourly flows for each discrete year 2014 to 2018. From: Jim Kreider, Stop B2H
The attached file shows the hourly values for WECC Path 14 from 2014 to 2018.
The hourly values provided in the Excel spreadsheet were calculated by averaging the real-time megawatts (MW) for WECC Path 14. The real-time values are calculated every five seconds in the energy management system (EMS) using supervisory control and data acquisition (SCADA) readings. Positive values represent flow in the East to West direction (export) and negative values represent flows in the West to East direction (import). Please note that the scale on the vertical axis changes in year 2017 and 2018 as a result of increased imports in those years.
For each of the approximately 15 exceedances in 2017-2018:
- What were the system conditions that caused the Path 14 flows to exceed the import SOL of Path 14?
- Why was the Path 14 flow allowed to exceed the 1200 MW import SOL?
- Why didn’t Idaho Power reduce flows to below SOL within the maximum 20 minutes required for exceeding a stability limit?
- What generation redispatch actions did the EIM operator take during the period of these exceedances, and what effect did the EIM operator’s redispatch decisions have on increasing or decreasing the real-time severity of these Path 14 exceedances in 2017 and 2018.
- Why did the SOL exceedances frequently persist for four or more hours without correction?
- Were there any exceedances that were not reported to WECC and Peak Reliability?
- What actions have been taken by Idaho Power to avoid future SOL exceedances?
- What actions have been taken by the other owners of Path 14 (PacifiCorp, BPA and Avista) to avoid future SOL violations on Path 14.
- What actions, if any, have been taken by WECC and/or FERC, in response to these persistent SOL exceedances?
- Has Idaho Power been fined, or otherwise sanctioned at any time for these exceedances, or otherwise penalized for unsafe operation of Path 14? If so, what were the dollar amounts of these fines and/or the specific sanctions imposed upon Idaho Power, and which regulatory authority imposed the sanctions?
From: Stop B2H
The instances when Idaho Power operated Path 14 actual flows in excess of 1,200 MW west-to-east were not reliability violations due a modification in requirements implemented by the Reliability Coordinator (“RC”) in 2017. As discussed in more detail below, beginning April 1, 2017, Idaho Power was no longer subject to a strict 1200 MW SOL on Path 14.
Historically all WECC paths were operated to static limits known as the accepted Path Rating. These static ratings were developed using power flow models that often included conservative system conditions to ensure system reliability. On April 1, 2017, the RC implemented a new SOL Methodology for the Operations Horizon that uses real-time system conditions and monitors individual lines within the paths as opposed to aggregate path flows. Contingency analysis is run on a power flow solution of the real-time transmission system every 5 minutes and any pre- or post-contingency violations are addressed with the appropriate Transmission Operator. Under the new SOL methodology, an aggregate path flow can exceed its accepted Path Rating without producing contingency analysis violations; in this case, no SOL violation is recorded.
The accepted Path Rating static limit, 1,200 MW west-to-east for Path 14, is still applicable to the Planning Horizon. Also, the accepted Path Rating is used as the total transfer capability for scheduling. In other words, Idaho Power cannot schedule above 1,200 MW. As demonstrated in the graphs previously provided, actual flows can differ from scheduled flows.
The Peak RC SOL Methodology can be found at: https://www.peakrc.com/whatwedo/sol/Pages/default.aspx
With regard to the final question , Idaho Power has never been fined, penalized, or otherwise sanctioned for unsafe operation of Path 14.
Given the wide range of cost estimates available in our region, we recommend that Idaho Power Company refine and further explore cost estimates through utilizing a utility specific RFP. Avista just completed an RFP for renewable projects and received 48 bids totaling 900 aMW. NV Energy has an open RFP for between 20–350 MW of renewables with bids due December 10. Utilizing such an approach can help better inform the accuracy of price assumptions included in the placemat. From: Zack Waterman, Idaho Sierra Club; Chad Worth, Snake River Alliance; Ben Otto, Idaho Conservation League
An RFP to determine at what cost could Idaho Power procure renewable projects will be taken under advisement. Idaho Power has been discussing the concept internally. A notable consideration is the timing of Idaho Power’s resource needs relative to the referenced RFPs.
Please reflect solar capital costs net of ITC benefits in the placemat values. The placemat values will likely be included as a table in the IRP and a fair comparison of costs needs to identify ITC tax benefits. If the models IPC is using for analysis address capital costs and tax matters separately then we request it be documented with a footnote to the placemat entry. From: Zack Waterman, Idaho Sierra Club; Chad Worth, Snake River Alliance; Ben Otto, Idaho Conservation League
The placemat overnight plant capital costs do not include ITC benefits. The placemat notes ITC qualifying resources, including utility-scale solar PV; Idaho Power’s analysis of utility-scale solar PV accounts for ITC benefit in a manner similar to that expressed in this request (i.e., capital costs and tax matters are addressed separately). Idaho Power agrees that a footnote clarifying the ITC treatment is appropriate. The costs net of ITC benefits are assumed in the Aurora portfolio development which is consistent with the total cost approach of comparing resources.
Note: The placemat is a draft list of supply-side resource options included at the end of the Jan. 10 IRPAC meeting materials.
Given ATB overnight capital costs referenced in the figure above, please explain why the Company believes $1,334/kW for a project that would not come online until 2023 is an appropriate cost assumption and how that value was derived. From: Zack Waterman, Idaho Sierra Club; Chad Worth, Snake River Alliance; Ben Otto, Idaho Conservation League
To arrive at the PV cost of $1,334/kWac in 2023 we started with the 2016$ ATB Mid Case of $881/kWdc and multiply by a 1.3:1 DC:AC ratio. The DC:AC ratio is the amount of DC that is assumed built to support 1kWAC of nameplate output. The ratio of 1.3:1 is consistent with back of the envelope input from project developers (EDF, EDP) and is consistent with RFP results from regional utilities for utility scale PV-Battery projects. Also, the NREL ATB assumes a 1.3:1 DC:AC ratio. The resulting $881 x 1.3 = $1,146 in 2016$ is escalated at a 2.2% annually for the 7 years to account for inflation which results in the solar PV cost of $1,334/kWac. ($1,146 x (1.022^7)).
Please explain why the Company thinks the battery/storage combo (40 MW solar/ 10 MWh lithium ion) needs a $2.70. MWh variable O&M. What maintenance needs are there that justify this ongoing costs? From: Zack Waterman, Idaho Sierra Club; Chad Worth, Snake River Alliance; Ben Otto, Idaho Conservation League
The NREL ATB is the source of the battery cost assumptions. The variable O&M (VOM) of $2.70/MWh is assumed to apply only to MWh discharged from the battery. (VOM) for the MWh sent to the grid directly from the solar array is assumed zero. For perspective, the following table and graph provides total O&M (fixed and variable) for the battery part of the solar/battery coupled resource for a range of annual discharges in 2023. The annual fixed O&M (FOM) costs of nearly $97k are independent of the number of discharges. The annual VOM costs range up to nearly $38k for a usage of the battery where it is fully discharged 350 times per year. The total annual O&M cost (fixed and variable) ranges up to nearly $135k, which equates to $13.48/kW-year. IPC views this amount of total O&M, ranging from slightly less than $10/kW-year to about $13.50/kW-year, as reasonable and within expressed ranges. For example, a recent HDR study of energy storage provides FOM for a lithium battery ranging from $6-14/kW-year, and VOM of $0.30/MWh.
|FOM ($)||tot O&M cost||tot O&M cost
Were other combinations of solar to storage ratios considered? For example, the solar: battery ratio on the current placemat is 25%, (40 MW solar and 10 MW battery) though other common combinations include 50% and up to 100%? Each of these arrangements are designed to meet a certain grid need. For IPC, why was the 25% ratio chosen? From: Zack Waterman, Idaho Sierra Club; Chad Worth, Snake River Alliance; Ben Otto, Idaho Conservation League
Several battery to solar project size ratios were considered. The 1:4 ratio of battery to solar nameplate was selected as typical combination for providing peaking capacity and system regulation. However, after further consideration, we’ve decided to also include a 1:2 ratio and a 3:4 ratio (battery to solar).
The planned portfolio modeling methodology will not use a fixed integration cost for use in valuing portfolios. The 2019 IRP uses the 2018 VER analysis as a guide to determine the system hourly regulating reserve requirements which are included in the Aurora model. The Aurora model holds dynamic reserves associated with load, wind and solar output and dynamically determines the increased costs associated with changing load, wind and solar on the system.