20250129IPC to Staff 1 - Attachment 7 - Marginal Cost Methods.pdf

Attachment 7-Response to Staff Request No.1
IDPW
&�,.POMR®
An IDACORP Cnmpany
Methods for Determining
Marginal Cost
For Discussion Purposes Only
January 2023
© 2023 Idaho Power

Idaho Power Company Methods for Determining Marginal Cost
Table of Contents
Tableof Contents..............................................................................................................................i
Listof Tables .....................................................................................................................................i
Background ............................................................................................................................... 1
IRP Demand Side-Management (DSM) Avoided Cost Averages............................................... 2
How is marginal cost calculated under this method? ........................................................ 2
Application.......................................................................................................................... 2
Benefits............................................................................................................................... 3
DiscussionPoints................................................................................................................. 3
Power Cost Modeling with Incremental Load Increase —AURORA.......................................... 4
How is marginal cost calculated under this method? ........................................................ 4
Application.......................................................................................................................... 4
Benefits............................................................................................................................... 5
Power Cost Modeling with Incremental Load Increase —Op Plan ........................................... 5
MarketPrices............................................................................................................................ 6
How is marginal cost calculated under this method? ........................................................ 6
DiscussionPoints................................................................................................................. 6
EmbeddedEnergy Mill Rate...................................................................................................... 7
How is the embedded energy mil rate calculated?............................................................ 7
DiscussionPoints................................................................................................................. 7
List of Tables
Table 1
DSM Avoided Cost Averages calculated in the 2021 IRP............................................................. 2
Table 2
Marginal cost rate based on power cost modeling in AURORA with incremental load
increase........................................................................................................................................ 4
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Idaho Power Company Methods for Determining Marginal Cost
Table 3
Energy-classified costs included in rates ..................................................................................... 7
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Idaho Power Methods for Determining Marginal Cost
Background
Following Order No. 35428 received in Idaho Power's application to establish a new schedule to
serve speculative high-density load customers', Idaho Power was directed, in advance of filing
its next GRC, to "evaluate and compare other methods for determining a marginal cost of
energy in addition to the use of [Avoided Cost Averages] ACA in the IRP for setting the Schedule
20 energy rate."
The Company has evaluated three methods, including the current Demand-Side Management
ACA used in Schedule 20, as potential approaches for determining the marginal cost of energy.
The chosen method will be used to calculate the marginal cost of energy for Schedule 20 rates
and may further be applied to customers taking service under a Special Contract which includes
energy priced at a marginal rate.
The three methods evaluated include:
1. IRP Demand-Side Management (DSM)Avoided Cost Averages
2. Power Cost Modeling with Incremental Load Increase
a. AURORA
b. Op Plan
3. Market Prices
In addition to these, for comparative purposes, Idaho Power has also included a section
describing the embedded energy mill rate.
1 Docket No. IPC-E-21-37
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Idaho Power Methods for Determining Marginal Cost
IRP Demand Side-Management (DSM) Avoided Cost Averages
DSM Avoided Cost Averages (also referred to as DSM Alternate Costs) are calculated marginal
cost rates used to evaluate the cost-effectiveness of the Company's DSM measures and
programs. They are calculated every two years with each Integrated Resource Plan (IRP).
How is marginal cost calculated under this method?
1. Using the load and resource balance from the most recently acknowledged IRP
preferred portfolio, Idaho Power uses the AURORA tool to simulate the Company's
power supply system and calculate estimated net power supply expenses (NPSE) on an
hourly basis.
2. The output from this simulation is an hourly resource stack, which includes the resource
generating the last unit of power in each hour and the associated cost of that resource.
3. The data is then condensed to show the marginal resource and cost for every hour.
4. These hourly prices are then averaged by time-block (Summer On-Peak, Summer Mid-
Peak, Sumer Off-Peak, Non-Summer Mid-Peak, Non-Summer Off-Peak) for each year
that the simulation is run (20-year IRP planning period).
Application
If this method is applied to a marginal cost rate in a tariff or special contract, the Company
would use the Avoided Cost Average(s) for the year that the rate is in effect. If it were to apply
this method to a contract being evaluated in 2023, it would use the rates (or an annual average
rate) for the 2023 year in Table 1. Underlying hourly calculations have been provided to Staff in
Workpaper 1.
Table 1
DSM Avoided Cost Averages calculated in the 2021 IRP'
Summer Summer Summer Non-Summer Non-Summer Annual
Year e
On-Peak Mid-Peak Off-Peak Mid-Peak Off-Peak Average
2022 $ 32.83 $ 26.70 $ 23.62 $ 26.41 $ 23.64 $ 25.57
2023 $ 47.75 $ 40.76 $ 35.04 $ 36.78 $ 33.10 $ 36.31
2024 $ 49.14 $ 41.34 $ 36.00 $ 36.46 $ 33.57 $ 36.57
2025 $ 49.63 $ 41.03 $ 36.28 $ 34.61 $ 32.32 $ 35.43
2026 $ 50.40 $ 40.01 $ 34.38 $ 35.11 $ 32.97 $ 35.61
2027 $ 50.75 $ 35.14 $ 31.16 $ 30.71 $ 31.06 $ 32.41
2028 $ 54.17 $ 36.81 $ 32.71 $ 31.79 $ 33.55 $ 34.19
2029 $ 53.51 $ 36.42 $ 33.44 $ 33.05 $ 35.85 $ 35.49
'Published DSM Avoided Costs (excluding annual average) included in the 2021 IRP Appendix C:
https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2143/CaseFiies/20211230IRP/`2OAppendix%20C.pdf
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Idaho Power Methods for Determining Marginal Cost
2030 $ 51.51 $ 30.48 $ 30.30 $ 30.44 $ 36.23 $ 33.57
2031 $ 54.93 $ 31.80 $ 32.57 $ 31.69 $ 37.22 $ 34.97
2032 $ 55.88 $ 32.56 $ 33.72 $ 33.05 $ 39.16 $ 36.46
2033 $ 55.06 $ 29.37 $ 33.17 $ 31.75 $ 40.52 $ 36.01
2034 $ 57.35 $ 31.20 $ 34.77 $ 32.64 $ 41.68 $ 37.24
2035 $ 57.24 $ 31.79 $ 35.03 $ 34.11 $ 43.54 $ 38.52
2036 $ 58.88 $ 32.54 $ 36.79 $ 36.38 $ 44.18 $ 40.00
2037 $ 56.64 $ 29.74 $ 35.62 $ 30.80 $ 39.90 $ 35.84
2038 $ 58.93 $ 32.09 $ 38.00 $ 32.12 $ 42.51 $ 37.82
2039 $ 61.82 $ 34.40 $ 40.23 $ 32.53 $ 42.10 $ 38.46
2040 $ 62.84 $ 35.36 $ 41.54 $ 32.02 $ 42.16 $ 38.57
Benefits
- The IRP is a published document, and the preferred portfolio is vetted via IRPAC
meetings.
- It is a repeatable and transparent process.
- Hourly data is available, which allows for flexibility of rate design in the future.
Discussion Points
- DSM Avoided Costs are calculated every two years with IRP filings, resulting in
potentially outdated modeling assumptions (load, fuel prices, etc.).
o Idaho Power could calculate DSM Avoided Costs on off-IRP years using the same
preferred portfolio but with an updated load forecast and updated fuel
assumptions.
- There is no incremental load increase with this method, as DSM Avoided Cost Averages
are meant to represent an avoided cost as a result of a reduction in load due to energy
efficiency activities. In other words, while this method is reasonable to determine the
value of DSM programs and/or energy efficiency activities, it does not calculate the cost
of the additional energy generated as a result of increased load to the system.
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Idaho Power Methods for Determining Marginal Cost
Power Cost Modeling with Incremental Load Increase — AURORA
The calculated change in NPSE divided by the change in generation as a result of adding
incremental load to the system.
How is marginal cost calculated under this method?
Using the AURORA tool, the Company would calculate forecast NPSE and generation for a test
year under two scenarios:
- forecast load
- forecast load + incremental load increase
The test year would align with the PCA year (forward looking April — March). This time period
allows the Company to more accurately forecast expected water conditions based on the
winter snowpack.
The below table shows total NPSE and total generation calculated for both scenarios. For this
example, the Company used an incremental 50 MW increase in load. Underlying hourly
calculations have been provided to Staff in Workpaper 2.
Table 2
Marginal cost rate based on power cost modeling in AURORA with incremental load increase
Scenario Type Total
Base Case Energy(MWh) 14,008,633
Base Case Cost $236,097,560
+50 aMW Energy(MWh) 14,447,834
+50 aMW Cost $253,672,560
Application
If this method is applied to a marginal cost rate in a tariff or special contract, the Company
would use the below formula to calculate an annual marginal cost rate for the test year.
Marginal Cost Rate — ($253,672,560 — $236,097,560)
(14,447,834 MWh — 14,008,633 MWh)
Marginal Cost Rate = 40.02 $/MWh3
a Because expected hydro conditions are not available yet for the 2023—2024 test year, normal or average hydro
conditions were used for this analysis.The Company expects that due to lower than normal expected hydro
conditions for the upcoming test year,actual calculated marginal cost rates will be higher.
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Idaho Power Methods for Determining Marginal Cost
Benefits
- Idaho Power is currently calculating net power supply expenses (base case scenario)
annually for use in the Oregon Power Cost filing.
- Follows methodology consistent with how marginal energy costs are developed for the
Company's energy marginal cost weighting in the cost-of-service model. The
incremental load increase method (50 aMW) is based on the National Economic
Research Associates Inc (NERA) marginal cost model used for cost-of-service.
- It is a repeatable and transparent process.
- Hourly data is available, which allows for flexibility of rate design in the future
- A forward-looking test year coincides with the PCA process (April — March test year with
rates in effect June 1).
- This method is based on adding incremental load to the system
o Staff comments in Brisbie case: "Staff agrees that a marginal energy rate is
appropriate since it is based on the cost of the next increment of electricity
beyond what is needed by the Company's core customers."
Power Cost Modeling with Incremental Load Increase — Op Plan
Idaho Power currently forecasts NPSE as a part of the Op Plan process for use in PCA filings.The
Company evaluated the possibility of using the Op Plan process to calculate a marginal cost rate
based on the same method described above (the difference between a base case NPSE and
incremental load increase NPSE compared to the difference in generation). Throughout this
evaluation, the Company determined that the Op Plan process is not designed to run different
load forecast scenarios, and therefore, wouldn't be a good solution to calculate a marginal cost
rate.
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Idaho Power Methods for Determining Marginal Cost
Market Prices'
The Company evaluated two different pricing sources for use in a marginal cost rate. These are
the Mid-C forward curve at a point in time or historical EIM prices.
How is marginal cost calculated under this method?
- Forward Mid-C curve: at an agreed upon date, the Company would pull the daily
forward Mid-C heavy load and light load prices for the test year. These could be
averaged into an annual rate or time-blocked rates.
- EIM prices: the Company could use historical EIM prices to come up with an annual or
time-blocked rate.
Discussion Points
- While market prices might be used as a proxy for a marginal cost rate, the Company
does not believe it is the best representation of the marginal cost paid by the Company.
- Market prices have been volatile over the last year.
- Assuming a market purchase is the marginal resource does not consider potential
transmission constraints.
- The EIM does not reflect the likely market in which Idaho Power would transact to
purchase additional energy to meet Schedule 20 or Special Contract customer load
requirements.
4 Because the Company doesn't believe market prices are the preferred method, it has not included actual or
forward market prices for review in this document.
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Idaho Power Methods for Determining Marginal Cost
Embedded Energy Mill Rate
Costs classified as energy-related through Idaho Power's cost-of-service allocation process (fuel
is considered 100% energy-related, for example). Certain production plant accounts and
purchased power expenses utilize Idaho Power's jurisdictional load factor to classify costs
between demand-related and energy-related.
How is the embedded energy mil rate calculated?
- The Idaho Power jurisdictional load factor is determined at the time of a general rate
case; calculated as normalized test year sales, generation level including line losses;
divided by system coincident demand at the generation level for same test year.
- In the 2011 GRC, the jurisdictional load factor was 53.897 percent.
- Where the jurisdictional load factor is applied to allocate FERC accounts, 53.897 percent
is classified as energy-related, with the remaining 46.103 percent classified as capacity-
related.
Discussion Points
- Use of the jurisdictional load factor approach varies from a more traditional, accounting
basis approach to classify fixed and variable expenses. As an example, purchased power
on an accounting basis is likely to be classified as 100 percent energy-related, while
hydro plant is more likely to be considered 100 percent demand-related as the majority
of hydro-production cost is incurred independent of the amount of energy the plant
produces.
- This contrasts with application of the jurisdictional load factor which considers both
purchased power and hydro plant to be 54%/46% energy/demand classified. While the
Company's net power supply expense is traditionally thought of as a variable cost, the
cost-of-service allocation methodology has a different basis in cost assignment. Thus,
Idaho Power's net power supply expenses are unlikely to completely align with costs
allocated by the jurisdictional load factor as energy-classified.
Table 3
Energy-classified costs included in rates
Schedule Description Energy-Classified as of June 1,
2022(1 per KWh)
1 and 5 Residential Service 3.0995
7 Small General Service 3.1403
9S Large General Service 3.0473
9P and 9T Large General Service 2.7819
19 Large Power Service 2.8136
24 Irrigation Service 2.7150
26 Micron Special Contract 2.5518
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Idaho Power Methods for Determining Marginal Cost
29 Simplot Special Contract 2.5678
30 DOE Special Contract 2.5225
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