20240430Rocky Mountain Power Public Workshop Case No. PAC-E-23-17 Powerpoint.pdf

Workshop Participation
Online:
To open chat in WebEx, please select the icon.
Type questions and comments in the chat box;
Please use the “all panelists” option when using chat to ensure your message will be seen.
To speak, click on the hand in the lower right corner.
On the phone:
*3 is the command to raise and lower your hand;
When your line has been un-muted, you will hear an
announcement indicating that.
This PowerPoint is available on the commission’s homepage at puc.idaho.gov.
*This workshop is being recorded*
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Purpose of a Public Workshop
•Informational session to learn about the case
•Present an overview of the Rocky Mountain Power
application.
•Ask questions to Staff.
•Learn how to submit official comments to become part of
the case record.
(Note: This Public Workshop is not part of the official case
record.)
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•Established in 1913. Idaho Code Sections 61 and 62.
•The Commission regulates Idaho’s investor-owned utilities, ensuring adequate service and reasonable rates.
•The Commission is made up of three commissioners appointed by the Governor. The Commissioners make the decisions in each case.
•Commission Staff is made up of Auditors, Consumer Compliance Investigators, Engineers, Technical Analysts, and Admin.
•Commission Staff is one of the Parties in the case and will provide official Comments to the Commissioners.
What is the Idaho Public
Utilities Commission?
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What is the Commission’s role?
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State law requires that the Commission:
•Consider the evidence that is on the record, which includes:
1.The Company’s Application; and
2.Comments from Staff & Parties; and
3.Customers’ written comments (or oral testimony at Customer Hearings).
•Meet the statutory public interest standard that ensures customers have:
1.Adequate, safe, and reliable service; and
2.Just and reasonable rates.
Important points to consider:
•It is not in the public interest to have a utility that cannot adequately serve all
the customers in its assigned territory now and in the future.
•All Commission decisions must withstand Idaho Supreme Court appeals from
either utility or customer groups.
How are regulated utilities different
from other businesses?
•Regulated utilities are not like any other business. They are
assigned service territories and must serve every customer in that
territory.
•What they charge customers is determined by state regulators.
•In exchange for the utility’s guarantee to provide adequate, safe,
and reliable service, the state must provide the utility the
opportunity to:
1.Recover prudently incurred expenses necessary to serve
customers; and
2.Earn a reasonable rate of return on its investment.
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Event Date Location
Case Filed June 29, 2023
Public Workshop Today (April 30, 2024)Virtual
Staff & Intervenor Comments June 13, 2024
Public Comments File Now (deadline June 13, 2024)
Public Customer Hearing Monday, June 17, 2024
Idaho Falls Activity
Center, South Room,
1575 N Skyline Drive,
Idaho Falls, ID 83402
Company Reply Deadline July 3, 2024
Close of Case Final Order
Application
•Filed June 29, 2023
•Submitted a Study of the Costs and Benefits of On-Site
Customer Generation (“On-Site Generation Study” or “Study”).
•Requested that the Commission acknowledge that the Study
satisfies Order 34753.
•On February 8, 2024, the Company submitted a Supplemental
Report which replaced the original Study in its entirety.
This Workshop will review the contents of the updated On-Site
Generation Study.10
Disclaimer
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•The Company is not proposing any
changes to the existing net energy
metering structure.
•This filing is to submit a study that
may be used to inform a future
filing.
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Background…
PAC -E-19-08 – Request to Close Schedule 135 and Open
Schedule 136 (Net Billing)
Order 34752 Established ‘grandfathering’
Order 34753 Study On-Site Generation
“It is hereby ordered that Rocky Mountain Power conduct a
study of on-site generation, the scope of which is identified
by Attachment A hereto.”
PAC -E-23-17 – PAC’s On -Site Generation Study
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Grandfathered systems:
Interconnected under Schedule 135
Interconnected before August 26th 2020 or;
Applied for interconnection before August 26th 2020 and
successfully interconnected before August 26th 2021
Retain net energy metering structure
Systems interconnected after August 26th 2021 are under
Schedule 136: Net Billing service
Subject to future program changes
This study considers options that would only affect
Schedule 136 participants.
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Background…
An overview of the impact of different netting intervals.
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Section 3.0 – Netting Interval
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Monthly (the current “net metering” policy)
Hourly
Instantaneous
Impacts of intervals are considered on
Revenue Requirement
Class Export Payments
Bill Impacts
Administrative Costs
“ECR”
An overview of the components that may contribute value
to the ECR.
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Proposed Components
In accordance with the Commission Order, the Study examined
the following ECR components:
Sections 4.1 & 4.2 – Using Proxy Data
Section 4.3 – Avoided Energy Value
Section 4.4 – Avoided Capacity Value
Section 4.5 – Avoided Risk
Section 6.0 – Avoided Transmission and Distribution (“T&D”)
Section 7.0 – Avoided Line Losses
Section 8.0 – Integration Costs
Section 9.0 – Avoided Environmental Costs
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Sections 4.1 & 4.2 – Proxy Data
AMI meters were still being installed for Idaho customers
in 2023.
At the time the Study was prepared, insufficient AMI data
was available from Idaho on-site generation customers.
Therefore, the Company used AMI data from residential
on-site generation customers in Northern Utah as a proxy
to estimate a hypothetical ECR value.
Sections 4.1 and 4.2 of the Study discuss this data and
show why it is a reasonable proxy.
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Section 4.3 Avoided Energy Value
Definition:
This is the value for the cost of energy the Company does not have to generate using its own resources as a result of receiving exported energy from an on-site generation customer.
Two methods to determine the value:
Option 1 – Forecasted IRP wholesale energy prices.
Forward-looking forecast of prices.
Prices are for firm energy. Customers’ non-firm energy would need to be price adjusted downward ~15%.
The energy value could be established reasonably far into the future, but it may be less accurate over time.
Option 2 – Historical Energy Imbalance Market (“EIM”) prices.
Backward-looking historical prices.
EIM pricing is for non-firm energy, so no price adjustment is needed.
Future energy values would be unknown.
The energy value would lag actual market value, but it would track it over time and would be more accurate than option 1.
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Section 4.3 Avoided Energy Value
Seasonal Valuation:
The Company also explored different options on how to
allocate the energy value.
Option 1 – Evenly spread the value across all exports for the
year.
Option 2 – Allocate the value by summer and non-summer
seasons1.
21Note 1: The Company did not include this in the Study but performed the analysis as part of the case.
Section 4.3 Avoided Energy Value
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The energy values (¢/kWh) in 2022 for
each of the two options.
The value is evenly allocated to all exports in the
year. Seasonal values are not displayed.
Section 4.4 Avoided Capacity Value
Definition:
This is the value for the cost of the generation plant the Company does
not have to build due to the extra capacity that is contributed to the
Company's system from an on-site generation customer's exports.
Avoided capacity only has value during peak-demand periods
and when the Company has a system-wide capacity deficit.
At the time of this Study, the Company’s system does not have
a forecasted capacity deficit until 2026.
Therefore, avoided capacity value could potentially be
“zeroed” until 2026.
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Section 4.4 Avoided Capacity Value
Basis of Valuation:
The Company explored two ways to determine the avoided
capacity value.
Option 1 – Use a Loss of Load Probability Study and the
Capacity Factor approximation methodology (“CF
method”).
Option 2 – Use the top 10% of Idaho load peaks for 2021-
2022.
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Section 4.4 Avoided Capacity Value
Time-of-Use / Seasonal Valuation:
The Company explored four options for allocating the avoided
capacity value to exports.
Option 1 – Evenly spread the value across all exports.
Option 2 – Allocate the value by Time-of-Use (On-Peak and Off-Peak).
Option 3 – Allocate the value by Season (Summer and Non-Summer).
Option 4 – Allocate value by Time-of-Use and Season.
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Section 4.4 Avoided Capacity Value
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Comparison of Flat / Seasonal / Time-Of-Use values:
Note: Pre -2026 Values would be zeroed if there is still no system-wide capacity deficit.
Section 4.5 Avoided Risk
The value from the Study was 0.124¢/kWh.
Avoided Risk applies only if forecasted (IRP-based) energy
prices are used. It does not apply when actual market
prices (EIM) are used.
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Definition:
This is the value from the reduction in price uncertainty by
receiving exports from an on-site generation customer instead
of receiving generation from the Company's other resources, which
are affected by volatility in natural gas prices,market electricity
prices,hydro conditions, etc.).
Section 6.0 Avoided T&D Costs
Definition:
This is the value that results from delaying the construction
of T&D capacity due to customer-exported energy being
produced closer to where consumption occurs.
The Company used the Avoided T&D costs determined in
the 2021 IRP.
The value from the Study was 0.11¢/kWh.
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Section 7.0 Avoided Line Loss Value
Definition:
This is the value that results from a reduction in the amount of electricity that is lost from transmitting electricity over long distances (since exported customer generation is produced closer to where consumption occurs).
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For this Study, the Company used the values from its most recent line loss study, completed in 2018
Section 8.0 Integration Costs
Definition:
This is the cost the Company incurs by holding capacity in reserve to balance the variability of on-site generation exports, which cannot then be used to generate electricity to sell into the market or to meet customer demand.
Two sources proposed:
Option 1 – Integration costs are estimated in each IRP.
Option 2 – The Commission periodically reviews integration costs for Qualified Facility pricing.
For the Study, the Company used the solar integration costs determined in the 2021 IRP. The value varies by year.
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Section 9.0 Other Avoided Costs
The Study examined miscellaneous other areas whereby
customer exports might provide value. These included:
Grid stability benefits
Public health and safety
Economic benefits
Renewable Energy Credits (“RECs”)
The Study concluded that none of these can currently
provide realizable value that can be added to the ECR.
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ECR Results
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Should the current limit on the size of a
generation project be adjusted?
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Section 5.0 Project Eligibility Cap
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The Study evaluated determining a customer’s project eligibility cap according to their demand.
considered the pros and cons of maintaining a generic cap.
•ECR update frequency
•Accounting treatment
•Disposition of existing kWh credits
•Conversion of kWh credits to $ credits
•Treatment of excess credits
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Update Frequency
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Compares the impact of updates on an Annual, Biennial,
and 4-year cycle
Presents option that some components do not need to be
updated as frequently as others.
Considers how the different frequency of updates reflects
Idaho’s historical energy prices between 2014-2022
More frequent updates can be burdensome but is more
accurate
Less frequent updates are more stable but do not capture
price fluctuations
Accounting Treatment
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Accounting treatment of financial credits paid.
Tracked in the Energy Cost Adjustment Mechanism
(“ECAM”).
Recorded as a purchased power expense.
Treatment is like other energy purchases.
Expense is passed to all customers on the Company’s system
Existing kWh Credits
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Disposition of existing kWh credits.
As of December 31, 2022, an excess of 3,309,167 kWh.
Evaluation is approximately $325,386.06.
Totals include grandfathered and new customers.
Conversion of kWh credits to financial credits.
Used Average Energy Rate for each customer class.
Excess Financial Credits
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Treatment of excess financial credits.
payable at account closing.
transferrable to other accounts.
applicable to ALL charges.
Transfer of financial credits to customer’s other metered
sites charge a $10 administrative fee.
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Consumer Assistance
•Utility Compliance Investigators assist customers to
resolve issues and/or disputes with the Company.
•Investigators monitor compliance with laws,
commission rules, and the Company’s tariff.
•Investigators review issues from previous cases,
review previous complaints, review submitted
comments from customers, and investigate
consumer issues raised in the case.
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CUSTOMER COMMENTS
Customer written comments are due June 13, 2024.
(Reference Case Number PAC -E-23-17)
•Internet Website Address – puc.idaho.gov
•Online - Case Comment Form (once comments are submitted, they become part of public record)
•Email – Address: [e-mail]
•Mail – IPUC, PO Box 83720, Boise, ID 83720-0074
•Public Customer Hearing – Monday, June 17, 2024
COMMENTS ONLY
(QUESTIONS WILL NOT BE ADDRESSED)
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Idaho Public Utilities Homepage
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Comments Form Page
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PUC Home Page
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Electric Page
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Open Electric Cases Page
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Case Summary Page
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•Customers can subscribe to the Commission’s RSS feed to receive updates about all cases via email.
•Continue submitting your comments.
•Public Customer Hearing, Monday, June 17, 2024.
Idaho Falls Activity Center South Room
575 N. Skyline Drive
Idaho Falls, ID 83402
•The Commission will issue a final order which will close the case.
Where do we go from here?
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Workshop Participation
Online:
To open chat in WebEx , please select the icon.
Type questions and comments in the chat box;
Please use the “all panelists” option when using chat to ensure your message will be seen.
To speak, click on the hand in the lower right corner.
On the phone:
*3 is the command to raise and lower your hand;
When your line has been un-muted, you will hear an
announcement indicating that.
This PowerPoint is available on the commission’s homepage at puc.idaho.gov.
*This workshop is being recorded*
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