20220921Comments.pdf

RILEY NEWTON
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720.0074
[phone]
IDAHO BAR NO. II2O2
Street Address for Express Mail:
1 I33 I W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 837I4
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
. /1 1
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION TO
COMPLETE THE STUDY REVIEW PHASE
OF THE COMPREHENSIVE STUDY OF
COSTS AND BENEFITS OF ON-SITE
CUSTOMER GENERATION & FOR
AUTHORITY TO IMPLEMENT CHANGES
TO SCHEDULES 6,8" AND 84
CASE NO. IPC.8.22.22
COMMENTS OF THE
COMMISSION STAFF
)
)
)
)
)
)
)
)
Staff of the Idaho Public Utilities Commission, by and through its Attorney of record,
Riley Newton, Deputy Attorney General, and submits the following comments.
BACKGROUND
Idaho Power ("Company" or "Idaho Power") offers net energy metering ("NEM")
programs under which customers can generate electricity to meet their own demand and export
any excess electricity back to the Company's grid in exchange for an energy credit that can offset
the customer's monthly energy consumption. Currently, customers who wish to install on-site
generation can interconnect an exporting system under the terms of Schedule 6 - Residential
Service On-Site Generation ("Schedule 6"), Schedule 8 - Small General Service On-Site
Generation ("Schedule 8"), and Schedule 84 - Commercial, Industrial, and Irrigation ("Schedule
84").
1STAFF COMMENTS SEPTEMBERZI,2022
On May 9,2018, in Case No. IPC-E-17-13, the Commission ordered the Company to
prepare and file a credible and fair study on the costs and benefits of on-site generation to the
Company's system, as well as proper rates and rate design, transitional rates, and related issues
of compensation for net excess energy provided as a resource to the Company. Order No. 34046
at 31.
On December 20,2019, in Case No. IPC-E-18-15, the Commission clarified that the
study: (l) must use the most currentdatapossible and must be readily available to the public, and
in the Commission's decision-making record; (2) must be designed in coordination with the
parties and the public, and the Commission will determine the final scope of the study; and (3)
the study must be written so it is understandable to an average customer, but its analysis must be
able to withstand expert scrutiny. Order No. 34509 at 9.
On December 30, 2021, in Case No. IPC-E-21-21, the Company filed an application to
initiate a multi-phase process for the study of costs, benefits, and compensation of net excess
energy associated with customer on-site generation. Included in the application was a proposed
study scope and a study design schedule including time for public workshops. In that case, the
Commission received intervening party and public comments on the different elements included
in the scope. Based on those comments, the Commission provided additional direction and
specific requirements for each element to be included in the study. Order No. 35284.
On June 30,2022, the Company submitted an application to Complete the Study Review
Phase of the Comprehensive Study of Costs and Benefits of On-Site Customer Generation and
for Authority to Implement Changes to Schedules 6, 8, and 84 ("Application"). These comments
are a result of Staff s review of the Application, which included the Value of Distributed Energy
Resource Study ("VODER Study" or "Study") and supplemental information included in the
filing.
STAFF REVIEW
The purpose of Staff s review is to analyze whether the VODER Study complies with the
Commission's decisions relative to the Study Scope in Order No. 35284. In that Order, the
Commission directed what components related to valuing the export of customer generation to
the Company's system should be included in the Study. Below is a summary of StafPs
conclusions on whether each component was sufficiently addressed:
2STAFF COMMENTS SEPTEMBERZI,2022
l. Measurement Interval - The Study complied.
2. Export Credit Rate ("ECR").
a. Avoided Energy Value - The Study complied in part but Staff
recommends that the Company submit an amendment to the Study that
provides additional explanation and data for two issues outlined below.
b. Avoided Capacity Value - The Study complied, with two exceptions that
should be addressed by an amendment to the Study.
c. Avoided Transmission and Distribution Costs - The Study complied.
d. Avoided Line Losses - The Study complied, with exceptions regarding
transformer line losses and adjustments to avoided cost of capacity that
should be addressed by an amendment to the Study.
e. Integration Costs - The Study complied.
f. Avoided Risk - The Study complied.
g. Environmental and Other Benefits - The Study complied, but Staff
recommends that the Company submit an amendment to the Study that
provides additional explanation for one issue.
3. Frequency of ECR Updates - The Study Complied. Participating customer-
generators' need for stability, and accurate rates, should be balanced with the need
for regular updates to accurately track avoided costs.
4. Compensation Structure - Under scenarios, moving from current NEM program
to a net billing program, customer-generators will see lower generator export bill
credits and will see higher electric bills.
5. Class Cost of Service ("CCOS") and Rate Design - The Study complied.
However, the Company is not collecting its full share of revenue requirement
from Schedule 6 and Schedule 8 customer-generators. Future studies of CCOS
and rate design must be evaluated and implemented in the Company's next
general rate case.
6. Recovering ECR Expenditures - The Study complied.
7. Project Eligibility Cap - The Study complied with Order Nos. 35284,34046, and
34509, but Staff recommends that the Company submit an amendment to the
Study that provides the following: (1) the Study be supplemented with
JSTAFF COMMENTS SEPTEMBER 2I , 2022
information received through discovery; (2) the policy factors identified be
considered in setting the cap; and (3) an evaluation of potential gaming and
manipulation between Public Utilities Regulatory Policies Act of 1978
("PURPA") and customer-generation be conducted.
8. Other Areas to Consider - The Study complied.
9. Implementation Considerations - The Company did not offer any transition
guidelines and Staff will present recommendations in any implementation process
for a new program.
10. Public Input - Customer comments for the most part offered thoughts and
opinions, and most did not offer separate findings they wanted introduced for
consideration.
In determining these conclusions, Staff weighed the sufficiency of the Study based on
criteria provided in Order Nos. 34046,34509, and 35284, which included elements of
transparency, inclusion of public input, and ability to be comprehended by the public but able to
withstand expert scrutiny, etc. Staff also considered the tradeoff between accuracy and rate
stability of the ECR.
If the ECR is not accurately developed and maintained at the Company's avoided cost,
exports will shift costs to the Company's non-generating customer classes, or compensation for
customer exports will not be commensurate with the value provided to the system. Alternatively,
Staff and customer-generators believe that predictability and rate stability is important, even if it
comes at the expense of accuracy.
The principle of cost causation entails that customers pay for the costs incurred by the
Company in delivering benefits to the customer. For consumption of electricity, the allocation of
the Company's costs to individual customer classes and the rates for each class are generally
based on the costs caused by the customers in each class.
Staff believes that these cost causation principles also apply to customers who export
electricity, who should be compensated for the benefits they provide to the system based on the
costs they avoid for the system. The cost of customer exports through an ECR should be
included in net power costs ("NPC") that are allocated to all customers through the Company's
Power Cost Adjustment ("PCA"). However, if the ECR is not accurately developed and
4STAFF COMMENTS SEPTEMBER 2I , 2022
maintained at the Company's avoided cost, one of two results will likely occur: (l) other
customers will be harmed due to an allocation of cost higher than what they would have paid
without the existence of customer exports if the ECR is set above the Company's avoided cost;
or (2) customer-generators will be undercompensated for the value they provide to the system if
the ECR is set below the Company's avoided cost. The Federal Energy Regulatory Commission
("FERC") used these same principles when propagating rules used to establish avoided cost rates
for PURPA qualiffing facilities ("QF").r
Measurement Intervals
The information presented in the VODER Study complies with Order No. 35284. The
data provided is transparent, understandable, and the Company presented its findings of the
monthly, hourly, and real-time measurement intervals for customer-generators as directed by the
Commission.
In the VODER Study, the Company evaluated the length of time between meter reads
(measurement intervals) to measure the energy delivered and received by: (l) hourly, and (2)
real-time. The Company evaluated the class revenue requirement and considered revenue
collection for existing customer generators under each proposed measurement interval. The
Company also conducted a bill impact analysis which compares how each measurement interval
impacts existing and future customers with on-site generation.
Net Billine
Net billing is an alternative compensation method to the current NEM program and does
not allow banking of kilowatt-hour(s) ("kWh(s)"). Instead, net billing calculates the difference
between energy exported and consumed in each hour and applies an applicable rate for any net
energy exported. The VODER Study outlines that each kWh will have a monetary value
applied. For energy exported, net billing applies a credit at an ECR. Similarly, for each kWh
I Avoided costs under PURPA means the incremental costs to an electric utility of electric energy or capacity or
both which, but for the purchase from the qualiffing facility or qualif,ing facilities, such utility would generate itself
or purchase from another source. See 18 C.F.R. S 292. l0l (bX6). Order No. 25884 states that "[r]atepayers should
be indifferent to whether a resource serving them was constructed by a utility or an independent developer. The cost
and quality of service provided by either should be the same. Ratepayers should not be asked to subsidize the QF
industry through the establishment of avoided cost rates that exceed utility costs that would result from an effective
least cost planning process." Order No. 32262 states that "PURPA entitles QFs to a rate equivalent to the utility's
avoided cost, a rate that holds utility customers harmless - not a rate at which a project may be viable."
5STAFF COMMENTS SEPTEMBER 2I , 2022
consumed, net billing applies the applicable customers retail rate (i.e., Schedule I rates for
Residential customers).
When evaluating hourly and real-time measurement intervals, the Company outlines the
key differences between the measurement intervals. For hourly measurement intervals, a
customer would be billed for net energy consumption or credited a dollar amount for net exports
during each hour. For example, in a one-hour timeframe, if a customer-generator exports more
kWh than they consume, they may be credited an ECR. The measurement on a real-time basis is
more accurate than on a hourly basis.
Unfortunately, the hourly measurement and real-time interval comparison could not be
applied to Schedule 84 customer-generators because most Schedule 84 customer-generators do
not have a single meter like Schedule 6 customers. All legacy2 Schedule 84 customers have two
meters; one meter reads all energy consumed and the second meter reads all energy exported. In
Order No. 34854, Case No. IPC-E-20-26, the Commission ordered new Schedule 84 customer-
generators to have a single meter but allowed existing customers to maintain a two-meter system.
With a single meter, the Company will be able to easily determine if a customer-generator is
exporting and/or consuming instantaneously. Due to timing, however, there were no Schedule
84 single-meter systems with twelve months of data in202l. See Response to Production
RequestNo. laand lb.
Thus, the Company was unable to perform a real-time and hourly net billing analysis for
Schedule 84 customers due to the meters measuring all generation and consumption separately.
Once the Company has more data available for single meter customer systems under Schedule
84, Staff expects to review it.
Export Credit Rate
Staff s analysis of the avoided cost components that can potentially be included in the
ECR focused on two questions:
l. Did the Company's Study comply with Commission orders; and
2 Grandfathering, or legacy status, is granted ifan installed solar system is an existing system under Schedule 6, 8,
or 84 or the customer made a f,rnancial commitment as of 1212012019 and interconnect their system within one year,
from 1212012020 for Schedule 6 and 8, or one year from l2lll2020 for Schedule 84. See Order Nos. 34509,34546,
and 34854.
6STAFF COMMENTS SEPTEMBER 2I , 2022
2. What are the important considerations in evaluating the options for determining
the value of the different components.
Avoided Energy Cost
Compliance with Commission Orders
Staff believes that the Study complied with Order No. 35284 for determining the avoided
cost of energy component in the ECR. However, Staff recommends that the Company include
an amendment to the Study that provides additional explanation and data that supports: (l) the
firm to non-firm energy adjustment; and (2) the proposed "On Peak" high-value time window.
The Company provided several methods for determining the avoided cost of energy for
exported energy on a dollar per kilowatt-hour ("$/kwh") basis, ranging from a single flat rate to
a seasonal time-variant rate. The Company included a reasonable adjustment to the value based
on the non-firm nature of customer exports. The Company utilized multiple methods for
determining the avoided energy value including forecasted prices from the latest Integrated
Resource Plan ("[RP") and market indices. This section of the Study also evaluated fuel price
risk as required by the Order, reasoning that the market energy prices inherently incorporate fuel
price risk.
Evaluation of Options
There are two main considerations in the valuation of avoided energy cost: (l) whether to
use actual market pricing or a weighted-average of established energy prices; and (2) the source
of pricing information.
The Study proposed three sources of pricing information: (1) the IRP pricing forecast, (2)
the Intercontinental Exchange Mid-Columbia ("ICE Mid-C") day-ahead market, and (3) the
Energy Imbalance Market ("EIM") Load Aggregation Point ("ELAP") - real time market.
Staff believes actual market pricing would be the most accurate means of assigning value,
but it is the least stable and predictable option for the customer. Conversely, a weighted average
of established energy prices would be stable and predictable, but less accurate. However, the
Study only mentions actual market pricing as a possibility and does not explore its feasibility or
its advantages and disadvantages.
7STAFF COMMENTS SEPTEMBER 2I , 2022
The Study identified three considerations if using weighted-average energy pricing data:
(l) the source of the data; (2) the number of years of pricing data to incorporate; and (3) whether
to use a weighted average method that focuses value into critical hours (Seasonal Time Variant
rate) or spreads it evenly throughout the year (Flat Annual rate).
Regarding the source of pricing data,IRP pricing is likely the least accurate because it is
a forecast, especially over time. The two market indices would be more accurate, but the
accuracy would be delayed since current market fluctuations would not be reflected in the ECR
until the ensuing year. All three pricing sources would be equally stable and predictable since
they are predetermined values.
Regarding the number of years of pricing data to incorporate, more years would enhance
price stability but would reduce accuracy in the short term. Over time, the value accuracy should
even out.
Regarding the weighted averaging method, the seasonal time variant method is a more
accurate assignment of the time-value of exports because the higher value of energy during the
critical hours would be assigned only to those hours, instead of being evenly spread across the
whole year. The seasonal time variant method would provide price signals to incentivize
customer behavior to enhance grid reliability. Some customer-generators would presumably try
to maximize exports during the critical hours, including by use of stored energy. This
arrangement would favor customers with battery storage if many of the critical hours are after
the sun goes down.
If a seasonal time variant option is chosen, the time windows used to differentiate the
value of energy need additional consideration in the Study. The Company has proposed "On-
Peak" and "Off-Peak" time windows that are aligned with its critical capacity needs but are not
necessarily aligned with time windows for valuing energy. Critical capacity needs are based on
the capacity needs of the Company's system. However, avoided energy cost is valued based on a
comparison of market prices to the cost of energy from resources dispatched at the top of its
resource stack. Staff does not believe the Study provides information and justification as to why
On and Off-peak time-differentiation windows used for valuing capacity is appropriate for
valuing energy. Staff recommends the Company provide, as an amendment to the Study, a
comparison for the amount of cost paid for avoiding the cost of energy using two sets of time
8STAFF COMMENTS SEPTEMBER2I,2022
windows: (1) windows with enough resolution to differentiate the avoided cost of energy; and (2)
the proposed "On-Peak" and "Off-Peak" time windows.
Avoided Capacity Value
Compliance with Commission Orders
Staff believes that the Study complied with Order No. 35284 for determining the avoided
cost of capacity component in the ECR with two exceptions. First, the Company did not account
for the impact to the avoided cost of capacity as the first deficit year changes. Second, Staff does
not believe that the Company's method used to calculate the avoided capacity cost for the
seasonal time variant scenario is correct.
The Study did not explicitly address the first deficit year as required by Order No. 35284
at 18. However, because the Study assigned value for avoided capacity cost, it implies that the
first deficit year is in effect, which the Company confirmed. See Response to Production
Request No. 30. The Company should amend the Study to explicitly address how this
component's value may be affected with respect to the first deficit year.
The Company utilized the same compensation formula in its flat annual rate scenario as it
did for its seasonal time-variant scenario. Staff believes that these two rate structures are
fundamentally different, and the calculations need to align to the underlying structure. The
contribution of capacity in the time-variant scenario is embedded in the energy actually delivered
and does not require a separate capacity contribution estimate as required in the flat annual rate
scenario. Staff recommends that the Commission order the Company meet with Parties and
amend the Study, if necessary.
Evaluation of Options
The main consideration in determining avoided capacity value is whether to use a flat
annual rate structure or a seasonal time variant rate structure.
The true value of avoided capacity is derived only when energy is exported during the
On-Peak period. The seasonal time-variant approach keeps the value assigned only to the On-
Peak exports. This approach more accurately assigns value to individual exporters, and also
9STAFF COMMENTS SEPTEMBER 2I , 2022
provides price signals to incentivize customer behavior to enhance grid reliability.3 the flat rate
would accurately assign value to the class, but not to individual exporters. Both structures would
provide stable pricing since they would be derived from historical data.
Within the flat annual rate structure is an additional option regarding the calculation
method for capacity contribution. Capacity contribution can be estimated using the Effective
Load Carrying Capacity ("ELCC") algorithm, or the National Renewable Energy Laboratory
("NREL") 8760 algorithm. The Company has used both methods in the past, using the NREL
8760 in the 2019IRP, and the ELCC in the 2021 IRP.
The ELCC is increasingly used by the power industry because it is considered a more
accurate representation of the capacity contribution for each specific utility system, which has
been implemented in the Company's 2021 IRP. Its downside is that it is a complex calculation
made by the Company using Aurora software and is therefore not transparent to the customer.
Conversely, the NREL 8760 method is less accurate than the ELCC because it is a
method for providing a rough estimate across a broad range of utility systems but is more
transparent since it can be calculated with a spreadsheet and a simple algorithm.
Avoided Transmission and Distribution ("T&D") Capacitv Costs
Compliance with Commission Orders
Staff believes that the Study complied with Order No. 35284 for the evaluation of
avoided T&D capacity costs. The Study provided a credible method to assess exports that
contribute to avoiding capacity limits on each segment of the T&D systems, and it provided
detailed information to support its analyses in Appendix 4.13.
Evaluation of Options
The main consideration in determining Avoided T&D Capacity Costs is whether to use a
flat annual rate structure or a seasonal time-variant rate structure.
Like the avoided generation capacity cost in the preceding section, the true value of
avoided T&D capacity is derived when energy is exported during the On-Peak period. The
seasonal time-variant approach keeps the value assigned only to the On-Peak exports. This
3 Behaviors include shifting consumption patterns or investing in energy storage to allow higher levels of exports to
the grid during On-Peak periods.
STAFF COMMENTS l0 SEPTEMBEP.ZI,2022
approach more accurately assigns value to individual exporters, but because the value of this
component is small, the impact on customer-generator behavior should be negligible. The flat
rate would accurately assign value to the class, but not to individual exporters. Both structures
would provide stable pricing since they would be derived from historical data.
Avoided Line Loss
Compliance with Commission Ordirs
Staff believes that the Study complied with Order No. 35284 for the evaluation of
avoided line loss with three exceptions. First, the Company derived the value for line loss from a
2012 study but proposed ignoring transformer losses. Staff is not convinced that transformer
losses should be ignored, nor can Staff reconcile the proposed reduction with data in the 2012
study. Second, the VODER Study was ambiguous about whether line loss applied to energy or
capacity or both. The Company clarified that line loss is attributable to both, but the Study only
calculated the energy line loss adjustment in the avoided line loss component. Third, according
to the Company, the line loss adjustment for capacity was incorporated into the avoided
generation capacity cost component. If Staff s method for calculating the capacity contribution
for the seasonal time-variant rate is appropriate, the line loss adjustment factor would need to be
explicitly applied. Staff recommends the Commission order the Company meet with Parties on
these three issues and provide an amendment to the Study.
Evaluation of Options
This component does not have any options to consider. The line loss adjustment factor
should be applied consistently to the avoided energy cost regardless of its rate structure.
Avoided Environmental Costs
Compliance with Commission Orders
The Commission stated that the Study should include "an evaluation of all benefits and
costs that are quantifiable, measurable, and avoided costs that affect rates." Order No. 35284 at
27. The Study identified three potential costs that could be avoided under the Order: Renewable
Energy Credits ("REC"), carbon taxes, and fulfillment of Renewable Portfolio Standard ("RPS").
Staff believes that the Company complied with the Commission's Orders with one minor
STAFF COMMENTS t1 SEPTEMBER 2I , 2022
exception and recommends that the Company amend the Study to further justiff its conclusions
related to RECs.
The Study analyzedthe administrative and legal barriers to monetize RECs with
individual customer-generators and concluded that the administrative burden on both the
Company and each customer would be high in comparison to the value that could be included in
the ECR. Because of this, the Company did not propose a value to be included. Staff asked the
Company to provide information to explain the requirements to obtain and track RECs for
customer-generators. See Response to Production Request No. 46. To comply with the
Commission directive, the Study "must use the most current data possible and must be readily
available to the public." Order No. 34509 at 9. Staff recommends that the information from the
Response to Production Request No. 46 be included in an amendment to the Study to provide
transparency to the public. The explanation should provide the public with information related
to the intricacies and requirements to obtain and track RECs.
Evaluation of Options
The environmental avoided cost component does not have any options to consider, since
there are currently no environmental costs that the Company could feasibly avoid. However, this
component should be revisited should legislative requirements change imposing a cost that
would be included in the Company's rates.
Integration Costs
Compliance with Commission Orders
The Study complied in its evaluation of Integration Cost, including evaluation at different
levels of variable energy resource ("VER") penetration. It utilized integration cost information
from a 2020Yariable Energy Resource Integration Study performed by an independent
contractor. The results of that study are adequate for the VODER Study analysis because the
baseline scenario was targetedto2023 and it reasonably approximates the existing resource
portfolio. The Company plans to perform a new integration study after the 2023 or 2025 IRP.
Evaluation of Options
STAFF COMMENTS t2 SEPTEMBER 2I , 2022
This component does not have any options to consider. The integration cost factor
should be applied to the ECR, regardless of the rate structure (single annual flat rate, or seasonal
time variant rate structure) to develop an accurate avoided cost. Integration rates should not
adversely affect the stability of the ECR when updated, since the Company only recalculates
them every two to four years.
Frequency of ECR Updates
The Commission ordered "the study needs to consider the impact of timing of updates
and identifu potential processes, cases, or mechanisms for identiffing updates to the export credit
rate." See Order No. 35284. Staff believes that the Company complied with Order No. 35284
and feels that the updates to the ECR should be transparent, understandable, and provide the
impacts when each ECR component is updated.
The Company looked at the impact of updating each component of the ECR. During the
implementation process, Parties' recommendations should include a schedule that outlines when
ECR component updates may occur. Customer-generators' need for stability and accurate rates
should be balanced with the need for regular updates to accurately track avoided costs in the
ECR.
Compensation Structure
The Company included additional information regarding compensation structures that
was not outlined in prior Commission orders. Staff is confident the material presented is
transparent, understandable, and provides impacts to current non-legacy customer-generators.
During the implementation process, Staff recommends that the compensation structure be
expanded to show impacts of various ECRs for all non-legacy customer-generators. The
VODER Study outlines what the compensation structure could be when applying one specific
ECR using the measurement intervals. The VODER Study evaluated NEM, used as a base, to
net billing hourly and to net billing real-time. The measurement intervals, which were discussed
above, refers to the measurement for both energy consumption and energy generation. Under the
scenarios presented in the Compensation Structure section of the Study, moving from current
NEM to a net billing scenario, customer-generators will see lower generator export bill credits
and will see higher electric bills under the hypothetical ECR proposed by the Company.
STAFF COMMENTS l3 SEPTEMBEP.ZI,2022
Class Cost-of-Service
Staff evaluated the CCOS presented in the VODER Study and believes it complied with
Order No. 35284. The Company provided information that is accurate, transparent,
understandable, and showed results that the Company has not recovered its authorized revenue
requirement from customer-generators. The Company provided a comparison of two CCOS
methodologies. The results showed that the Company is not collecting its full share of revenue
requirement from Schedule 6 and 8 customer-generators. Rate design must be addressed in a
general rate case to align Schedules 6, 8, and 84 customers to cost of service.
Recovering ECR Expenditures
In Order No. 35284, the Commission stated that the Study must include the annual costs
for different ECR values and include how these costs would be recovered by rate class. 1d at 11-
12. The VODER Study complied with these requirements, identifying a range of annual costs
from $309,933 to $590,947. Study at94. The Study also included a proposal that the value of
the credits would be recorded in FERC Account 555 - Purchased Power and included in the PCA
without any sharing band, similar to QF expenses. The Study proposes that the program
administration costs be recovered through base rates. Study at93-95.
Project Eligibility Cap
Staff believes that the Project Eligibility Cap section in the Study has met the
Commission's expectations in OrderNos.34046,34509,and35284. However, Staff has
identified additional factors to be considered in setting the cap. Staff also recommends that the
Study be supplemented with information on the Project Eligibility Cap received through
discovery, as discussed below.
Compliance with Commission Orders
Staff believes that the Study addressed Commission orders by providing a thorough
evaluation of existing eligibility caps and by identiffing factors that need to be considered for
modifuing existing caps. Specifically, the Study includes an analysis of average system sizes of
each exporting customer class compared to the respective existing caps and has examined
demand-based caps in terms of interconnection requirements, distribution system operations, and
STAFF COMMENTS t4 SEPTEMBER 2I ,2022
implementation considerations. Staff believes the study has met the Commission's expectations
in Order Nos. 34046,34509, and35284.
Customer Interest in Setting Eligibility Cap
The Study included an analysis of active and pending exporting system counts, total
capacity, and average system sizes for Schedule 6, 8, and 84 customers. The results showed that
the average system sizes as percentages of existing caps for Schedule 6, Schedule 8, and
Commercial and Industrial customer within Schedule 84 customers are 30yo,3lYo, and 33Yo,
respectively. However, for irrigation customers in Schedule 84, the average system size is 9lYo
of their cap. Study at 98. These results and the comments, particularly from irrigation
customers, indicate that irrigation customers under Schedule 84 are more interested in raising
their existing 100 kW project eligibility cap.
Safew and Reliabiliff Factors
According to the Company, regardless of the size of the project, every project
interconnection point needs to be evaluated for its safety and reliability impact to the system. As
long as each project's interconnection point is evaluated and the proper investments and
upgrades to harden the system are implemented based on these evaluations, the size of the
eligibility cap from a safety and reliability perspective is not an issue. See Responses to Staff
Production Request Nos. 4, 7, 10, and I 1. These incremental costs to harden the system are
already addressed in Schedule 684, and should be recovered from each customer causing the
additional cost. To ensure transparency, the information should be readily available to the public
to show compliance with Commission Order No. 34509. Staff recommends that the VODER
Study be amended to include the information from the aforementioned production requests.
Policy Factors
Eligibility Cap Used to Limit Cost Shifts
The Study included considerations for setting the cap based on current subsidies that exist
under the current net-metering framework where credits are rewarded on a one-for-one kWh
a Schedule 68 (tnterconnections to Customer Distributed Energy Resources) is the Company's service schedule
which provides for interconnection to customer generation.
STAFF COMMENTS l5 SEPTEMBER 2I , 2022
basis. Study at97. This is an important consideration if credits are awarded on a dollar per kWh
basis through an ECR that is set higher than the Company's avoided cost. The size of the cost
shift to non-generating customers will depend on (l) how much higher the ECR is above the
avoided cost, and (2) the amount of customer exports allowed in the system. It is important to
properly set the ECR so potential cost shifts are limited. If the ECR rate is higher than the
avoided cost of the Company's system, one way to minimize the amount of the cost shift is to
limit the size of the eligibility cap to hold down the total amount of customer exports into the
Company's system.
Overlap of PURPA and Customer-Generotion
Staff also identified PURPA as a consideration in setting the eligibility cap. Because
customer-generation projects could be implemented as PURPA qualifring facilities and vice
versa, gaming could occur, especially if PURPA rates, terms, and requirements are different than
those for customer-generators, thus providing an incentive for customer-generators or PURPA
projects to manipulate the rules to achieve more favorable rates and terms.
For example, this type of gaming historically occurred when large PURPA solar and
wind projects that should have qualified as lRP-based projects disaggregated into smaller
published rate projects in order to receive higher rates. This was resolved by lowering the
published rate eligibility cap from ten average-megawatt to 100 kW. Order No. 32697 at 13-14.
Staff recommends that an evaluation of potential gaming between PURPA and customer-
generation be conducted during the next phase of the case to prevent unfavorable manipulation
of requirements and rules.
De mand- B as e d El i gib il ity Cap
The Study briefly explored four areas associated with the implementation of demand-
based caps by posing the following questions:
a. Should a demand-based system size cap apply to all customer-generators or only
commercial, industrial, and irrigation customers?
b. What is the definition of a customer's demand for purposes of a system size cap?
c. How will a demand-based system cap be defined for a customer without historical
usage data? (Response to Production Request No. I I states "[a] customer's
STAFF COMMENTS t6 SEPTEMBER 2I , 2022
demand, irrespective of the definition or criteria used, is not a technical factor that
will define a project eligibility cap to ensure that the Company's system remains
safe and reliable.")
d. How do changes in system ownership that result in considerable changes in
customer demand impact a customer-specific and demand-related cap?
Staff believes these questions are important to consider if a demand-based eligibility cap
is implemented.
Implementation Timing
The implementation timing for changing the eligibility cap is a consideration to protect
non-generating customers from cost shifts. As discussed above, subsidies exist under the current
NEM framework where credits are rewarded on a one-for-one per kWh basis. If the eligibility
cap is increased prior to an avoided-cost-based ECR being implemented, it would result in more
customer generation capacity being added with additional cost shifts to non-generating
customers.
Other Areas of Study
In Order No. 35284, the Commission stated that the Study must: (l) quantifu the
magnitude, duration, and value of accumulated credits; (2) show how the Company does or does
not benefit from expiration of credits; and (3) show how non-customer-generators are harmed or
benefited from expiration of customer export credits. Id at28.
In the VODER Study, the Company states as of December 3l ,2021, it had 17.1 million
kWh credits owed to customer-generators. The credit balance owed has grown at an annual rate
of approximately 66Yo since 2014 when the Company had 0.5 million kWh owed to customer-
generators. Study at 104. To monetize the credits, the Company assumedT.5 million kWh
would be used by the customer-generators and removed that amount from the calculation. To
calculate the monetary value of the remaining credits, the Study uses the average energy rate of
each class adjusted for the effects of the Fixed Cost Adjustment ("FCA") and the Sales Based
Adjustment ("SBA"). These credits are now used to reduce overall consumption which affects
both the FCA and SBA. The value of the credits would be $290,116. Study at 104.
STAFF COMMENTS t7 SEPTEMBER 2I ,2022
Of the 17.1 million kWh accumulated, 2.1 million kWh were generated from non-legacy
systems. The Company proposes that these credits would convert to a financial credit when the
customer is moved to a financial compensation structure. Study at 105. These credits would be
exchanged at aflat ECR because the Company does not have the records identifring when each
kWh was generated, and therefore could not apply a variable ECR. Using the ECR from Section
6 of .03781 per kWh, the results would be a value of $77,823. The Company also included the
value of these credits on differing ECRs in Appendix 10.1. Due to the FCA and SBA, this
expiration and change to financial credits would benefit other customers by $76,759. The
Company would also receive a$45,433 financial benefit from the conversion of kWh credits to
financial credits. Study at 105-106 and Appendix 10.1
Staff believes there may be some scenarios for pricing that are feasible but not included
in the Study. These include allowing non-legacy systems to keep the kWh credits instead of
exchanging them for financial credits and allowing legacy systems to exchange the kWh credits
for financial credits.
The Company included additional items in Section 10.2 of the VODER Study that were
included but not required to be studied in Order No. 35284. This section details resources
available to the public on the Company's website to assist in making informed decision about the
economics of on-site generation, including customer usage, rates, solar energy information,
hourly energy production, sample payback, and interconnection requirement.
Implementation Considerations
Staff evaluated implementation considerations in Section l1 of the VODER Study. The
Company provided information that is transparent, understandable, and showed that the
Company is awaiting final input from all Parties and the public to make implementation process
recommendations. Although, the Company did not offer any transition guidelines, the Company
anticipates filing such recommendations in the next phase.
The Company outlined additional implementation considerations in Section 1 l, such as
billing system updates, tariff language, and communication materials for both installers and
customers. The Company states it will need additional time, following a Final Order in this case,
to finalize the full implementation of a new net billing program.
STAFF COMMENTS l8 SEPTEMBER 2I , 2022
PUBLIC INPUT
Public Workshops
Idaho Power held a virtual public workshop on August 31,2022, and Staff held two
virtnal public workshops. The first Staff workshop was held the evening of September 6,2022,
and the second was held on the aftemoon of September 7,2022. Among the topics discussed at
the workshop were the VODER Study, history of the case, and grandfathering. Where
appropriate, Staff addressed customers' comments and concems in these areas.
Customer Comments
ln Case No. IPC-E-I8-15, the Commission weighed the importance of public input. In
fact, public comments weighed heavily "against the Settlement Agreement, the parties'
comments in support of the Settlement Agreement, and the parties' briefs regarding treatment of
existing customers." Order No. 34509 at 4.
Knowing the weight of the public's concern, Staff encourages the Company to present
additional review of the public's comments and outline the important topics that may or may not
beincludedintheirreplycomments. AsofSeptemberT,2022,55gpubliccommentshavebeen
filed in this case. Of these comments, 170 (30% of total) were received from customers who
acknowledged owning a solar system and effolled in NEM.
Staff will continue to review public comments and looks forward to hearing further
feedback from the public about the VODER Study. Customer comments offered included
thoughts and opinions, while not offering separate findings they wanted introduced for
consideration.
Of the total (559) customer comments received to date, the following were the five main
views expressed by customers:
Public Hearines
Three hundred eighty-eight customer comments (69%o of total) requested opportunities to
attend a public hearing throughout the state to be conducted at various times to allow maximum
publrc partrcrpatron.
STAFF COMMENTS l9 SEPTEMBER2I,2022
Grandfatherins
Even though previous cases and Commission Orders have clearly addressed
grandfathering, customers continue to express concerns and the need for additional
grandfathering, which can affect compensation for customers who have recently installed
systems or are considering the payback period of a future installation. One hundred nineteen
customer comments (21%o of total) mentioned the date of grandfathering as an issue which was
addressed in OrderNos. 34509,34546 and 34854. See footnote2to these Comments.
Compensation and Structure
The issue of compensation and structure was raised in 331 customer comments (59% of
total). Compensation affects the payback period for all customers who have not been
grandfathered. Systems have an anticipated thirty-year life and a lower compensation level that
requires the customer or potential customer to reevaluate the financial burdens and weigh the
financial and the environmental and societal benefits against the cost. Should a customer sell the
property before a loan has been paid, the remaining debt decreases the value of the sale.
Environmental and Societal Costs or Benefits
The VODER Study does not identi$ specific environmental costs or benefits. Two-
hundred forty-nine customer comments (44o/o of total) expressed their concern that a lack of
environmental benefits included for compensation of the ECR discourages investment in solar
power. Customers suggest that the environmental and societal benefits of solar will benefit their
extended families and society as a whole and should be included for compensation in the ECR.
Reject the Company's VODER Study and Have a Third-Pa4v Independent Stud), Completed
Eighty-eight customer comments (15% of total) asked that the Commission reject the
VODER Study, with several of them asking for a third-party to conduct an independent study
STAFF RECOMMENDATIONS
Staff recommends approval of the Study, as it complies with Order Nos. 34046 ,34509,
and35284, contingent on the following modifications if approved by the Commission as outlined
below:
STAFF COMMENTS 20 SEPTEMBER 21 ,2022
I. ECR.
a. Avoided Energy Value - submit an amendment to the Study that provides
additional explanation and data for: (1) the firm to non-firm energy
adjustment; and (2) comparison for the amount of cost paid for avoiding the
cost of energy using two sets of time windows with enough resolution to
differentiate between the proposed "On Peak" high-value and "Off-Peak"
value.
b. Avoided Capacity Value - two exceptions that should be addressed by an
amendment to the Study: (l) how the Company accounts for the impact to the
avoided cost ofcapacity as the first deficit year changes; and (2) update the
Company's method used to calculate the avoided capacity cost for the
seasonal time-variant scenario.
c. Avoided Line Losses - Submit amendments to the Study after meeting with
Parties regarding (l) appropriate application of transformer line losses, (2)
inclusion of line losses in the avoided cost of capacity; and (3) applying the
line loss adjustment using Staff s capacity contribution for the seasonal time-
variant rate.
d. Environmental and Other Benefits - submit an amendment to the Study that
provides additional explanation of RECs provided in Company's Response to
Staff s Production Request No. 46.
2. Class Cost of Service ("CCOS") and Rate Design - future studies of CCOS and
rate design must be evaluated and implemented in the Company's next general
rate case.
3. Project Eligibility Cap - submit an amendment to the Study that provides the
following: (1) the Study be supplemented with information received through
discovery; (2) the policy factors identified be considered in setting the cap and
include an evaluation of potential gaming and manipulation between PURPA and
customer-generation be conducted.
4. Implementation Considerations - transition guidelines be submitted during an
implementation process.
STAFF COMMENTS 2l SEPTEMBER2I,2022
Respecttully submitted this Ll* day of Septe mber 2022.
Riley Newton
Deputy Attomey General
Technical Staff: Travis Culbertson
Chris Hecht
Jolene Bossard
Matt Suess
Yao Yin
Joseph Terry
i:umisclcommentVipce22.22mtroohjbrr.ryyjt oomments
STAFF COMMENTS )')SEPTEMBER2I,2022
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 2I't DAY OF SEPTEMBER 2022,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-22.22, BY E.MAILING A COPY THEREOF, TO THE FOLLOWING:
LISA NORDSTROM
MEGAN GOICOECHEA ALLEN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
mgoicoecheaallen@idahopower. com
[e-mail]
C TOM ARKOOSH
AMBER DRESSLAR
ARKOOSH LAW OFFICES
PO BOX 2900
BOISE ID 83701
E-MAIL: [e-mail]
amber.dresslar@ arkoosh.com
KELSEY JAE
LAW FOR CONSCIOUS LEADERSHIP
920 N CLOVER DR
BOISE ID 83703
E-MAIL : [e-mail]
ERIC L OLSEN
ECHO HAWK & OLSEN PLLC
PO BOX 6119
POCATELLO ID 83205
E-MAIL: [e-mail]
TIMOTHY TATUM
CONNIE ASCHENBRENNER
GRANT ANDERSON
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
caschenbrenner@ idahopower. com
[e-mail]
MICHAEL HECKLER
COURTNEY WHITE
CLEAN ENERGY OPPORTUNITIES
3778 PLANTATION RTVER DR
SUITE IO2
BOISE ID 83703
E-MAIL:
mike@cleanenergyopporlunities. com
courtney @cleanenergyopportunities.com
ELECTRONIC ONLY
ERIN CECIL
E-MAIL: [e-mail]
LANCE KAUFMAN PhD
48OI W YALE AVE
DENVER CO 80219
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE