20200716Reply Comments.pdf

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1407 West North Temple, Suite 330
Salt Lake City, Utah &4116
July 16,2020
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Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,lD 83702
Re: CASE NO. PAC-E-19-08
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
TO CLOSE THE NET METERING PROGRAM TO NEW SERVICE &
IMPLEMENT A NET BILLING PROGRAM TO COMPENSATE CUSTOMER
GENERATORS FOR EXPORTED GENERATION
Dear Ms. Hanian:
Please find an electronic filing of Rocky Mountain Power's Reply Comments in the above
referenced matter.
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
Very truly yours,
"^-.D
Vice President, Regulation
Adam Lowney (ISB#I 0456)
McDowell Rackner Gibson PC
419 SW I lft Avenue, Suite 400
Portland, OR 97205
Telephone: [phone]
Fax: [phone]
Email: [e-mail]
Emily Wegener Qtro hac vice)
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone No. [phone]
Mobile No. [phone]
Email : Emil),.wesener@pacifi corp.com
Attorneys for Roclgt Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER TO
CLOSE TIIE NET METERING PROGRAM
TO NEW SERVICE & IMPLEMENT A NET
BILLING PROGRAM TO COMPENSATE
CUSTOMER GENERATORS FOR
EXPORTED GENERATION
CASE NO. PAC.E.l9-OE
REPLY COMMENTS OF
ROCKY MOUNTAIN POWER
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Pursuant to the Notice of Supplemental Application, Notice of Public Hearing, and
Notice of Comment Deadlines issued by the Idaho Public Utilities Commission
("Commission") on May 6, 2020, Rocky Mountain Power a division of PacifiCorp ("RMP" or
the "Company") hereby submits its reply comments in the above-referenced case.
I. BACKGROUNI)
l. On June 14,2019, the Company filed an application ("Application") for
authority to close Electric Service Schedule 135 - Net Metering Service ("Net Metering") to
new customer participation effective at midnight local time, December 31, 2019, and offer a
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new Electric Service Schedule 136 - Net Billing Service, ("Net Billing program" or "Schedule
136") for customers who apply to install customer generation after January 31,2020.
2. The Application does not seek to modi$ retail rates that customers pay for the
service the utility provides, the Application requests authorization to implement a new
customer generation program, Net Billing program, that credits customer generated energy
exported to the grid at a fair market based export credit rate, ("Export Credit"), rather than the
full retail rate. The Application provided customers with notice of the Company's proposal to
close Schedule 135 to new customer participation and implement a new program. The
Company issued a press release and customer letters were sent to all Schedule 135 customers
to inform them of the proposed changes and recommended grandfathering ffeahnent.
3. OnApril 23,2020, in accordance with an agreement reached with the parties to
process this case in fwo phases, the Company supplemented its Application by updating the
Export Credit rate ("Supplemental Application"). In the Company's original Application the
Export Credit was calculated at2.486 cents per kWh. When updated for the 2020 market prices
and the integration charge from the 2019 IRP, the Export Credit was2.234 cents per kWh. As
part of the Supplemental Application, the Company requested closure of Schedule 135 to new
customers effective July 3l ,2020, at midnight local time, as dictated under tdaho Code $61-
622,based on the original closure date requested in its Application.
4. On May 26,2020, the intervening parties filed comments on the study design,
("Phase I"), of the Application. The Company hosted a telephonic public workshop on June
16, 2020, where it shared its study design and solicited comments, and Commission staff
hosted a similar telephonic workshop on June 18,2020, where Staffshared their position. The
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Commission held a telephonic public customer hearing on June 22,2020. Parties filed Revised
Comments on July 3,2020.
5. In its Revised Comments, filed July 3, 2020,the Company modified its request
for grandfathering, seeking a fifteen year grandfathering period for Schedule 135 customers
instead of the ten years originally requested. The Company provided additional analysis
concerning the payback period to justify this modification. The Company also provided
information about the notice existing customers have been provided concerning potential
changes to the Net Metering Program.
6. Idaho Conservation League ("[CL") filed Revised Comments on July 3,2020,
which ldaho Clean Energy Association joined without further comment. Commission staffalso
filed Revised Comments on July 3,2020.
7. In response to those comments and others received from customers the
Company hereby files the following Reply Comments.
II. REPLY COMMENTS
8. The Company's Application addresses two issues: (l) fair treatment of existing
Net Metering customers by grandfathering them on their current schedule while closing the
program to new participants; and (2) implementation of a new Net Billing program utilizing
an Export Credit rate for energy exported from customers with on-site generation back onto
the Company's grid. The Application focuses on determining whether it is faiq just, or
reasonable to pay new customer generators the Company's full retail rate for their non-firm
energy exported to the grid.
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GRANDFATHERING OF EXISTING NET METERING CUSTOMERS
9. After the Company filed its Application, the Commission approved
grandfathering Idaho Power's existing net metering customers for 25 years.r The Company
agrees with the Commission that grandfathering is appropriate, but does not believe twenty-
five years is appropriate time period for the Company's customers, as demonstrated by its own
analysis and that of solar installers. The Company acknowledges the significant investment
made by customer generators and proposed they be grandfathered under the current Net
Metering program for a time period that gives them an opportunity to recoup their investment.
At the same time, it is important to mitigate the magnitude of cost shifting from the Net
Metering program. As stated in its Revised Comments, the Company supports a fifteen year
grandfathering period for all existing Schedule 135 customers.
PHASE-IN OPTION
10. Staff indicated in their comments that they do not believe that grandfathering
existing customers is necessarily mutually exclusive with a transition period for new
customers. Staff stated that because a future Export Credit rate could be significantly different
from the retail rate, it could be reasonable to adopt both policies to limit disruption and
facilitate an orderly phase-in of the new program structure.
I l. While this is an implementation detail that is probably best addressed in Phase
II when the specific details of a new program based on the study are determined, the Company
does not believe a phase-in is reasonable, necessary or appropriate. The Company's analysis
demonstrates that a fifteen year grandfathering period on the Net Metering program is
I In the Matter of the Petition of ldaho Power Company to Study the costs, benefits, and Compensation of Net
Excess Energt Supplied by Customer On-Site Generation, Case No. IPC-E-I8-15, Order No. 34509 (December
20,2019).
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sufficient. A transition period would confuse and disrupt the move to a cost-based program
structure. While there have been only a limited number of public comments, many who
commented demonstrated a lack of understanding that the Net Metering program was subject
to change. Customers also conflated the fact that the program is offered with it being cost-
based or fair, which is not the case. It's important to set expectations and send price signals for
the Net Billing program sooner rather than extend misconceptions and most importantly cost
subsidies for the Net Metering program.
APPLICATION FEE
12. In Staffs comments, they recommended that the Company provide the costs
incurred in processing applications for customer generators historically and then calculate an
average rate per application. The Company provided this information in its initial Application
filed on June 14, 2019, where it demonstrated that it expends $85 for each customer generation
application on administration, engineering review, and customer service.2
13. The Company identified engineering, administration, customer service, and
billing related costs that are directly attributable to interconnecting net metering customers.
These costs, shown in Exhibit No. 2 are cost-based, reasonable, and, as summarized in the
Company's Application compare well to the application fees charged by other investor owned
utilities in the state.
TRACKING NET METERING BILL CREDITS
14. Staffrecommended the Company explain the method it currently uses to record
Net Metering bill credits, the amount of these costs, and how these costs would change
depending on a range of possible Export Credit rates that may be approved by the Commission.
2 Direat testimony of Robert M. Meredith, pages20-21
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The Company should then analyze how these costs have been allocated and recovered between
rate classes historically and how they would be allocated and recovered through the proposed
ECAM method.
15. Paragraph 2 of Schedule 135 explains the method used to record net metering
bill credits. The Company's billing system measures energy usage and exported quantities, if
the net of the customer's usage and exported quantities recorded by the meter is negative
energy usage for the month the net kWh reduction for the month is multiplied by the Export
Credit rate, which is currently the retail rate. That process won't change under the Company's
proposed Net Billing program. Only the period of time and Export Credit rate would change.
16. The Company requested that the Export Credit be recovered through the
ECAM, it did not propose how those costs should be spread to customer classes. Rate spread
could be addressed as part of the ECAM application or Phase II of this proceeding.
MODELED DATAAS A PROXY FORACTUAL CUSTOMER EXPORT DATA
17. Staffhas raised concerns about the Company's use of modeled data to support
the Export Credit rate. However, the Company's proposal is not reliant upon an export credit
profile, modeled or otherwise. In the absence of a specific customer profile, and recognizing
customer behavior under the Company's proposal would vary from that of existing customer
generators, the Company's proposed Export Credit rate reflects uniform deliveries across all
hours.
AVOIDED ENERGY VALUE
18. Staff asserted they did not believe that the assumptions and adjustments the
Company used in its proposed avoided energy value align with the value the Company uses
for other resources. This is not accurate. As explained in the testimony of Mr. Daniel J.
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MacNeil, when customer generation is exported to the grid, the Company can reduce the output
of its generation resources or reduce the volume of its market purchases.3 The resulting
reduction in fuel expense and purchased power cost is the avoided energy cost.
19. The Commission has approved the Surrogate Avoided Resource ("SAR")
Methodology for determining avoided costs for standard qualiffing facility resources up to at
least 100 kW in nameplate capacity.4 Under the SAR Methodology, avoided energy costs
reflect forecast prices for natural gas and the assumed heat rate of a combined cycle combustion
turbine. Monthly weighting factors are used to differentiate avoided costs by month, and an
adjustment of 85 percent is applied to non-firm resources.
20. Unlike energy the Company purchases from a qualifuing faciliry customer
generators make no commitment to deliver energy, and so the Company cannot plan, rely on,
or depend on energy from their systems being available when it is needed. Energy exported
from customer generators is in the strictest sense non-finn energy.
21. Staffrecommended using the IRP to determine the Export Credit. The Company
has four concerns with using the IRP data to set the Export Credit: first, the Commission does
not approve the IRP-it only acknowledges that the Company met its filing requirements;
second, the IRP relies on less current data; third, the IRP is a planning process, it does not
represent the Company's avoided costs; and forth, there is no certainty to when the IRP will
be processed by the Commission so parties wouldn't know when the Export Credit rate would
change. For example, it is now the middle of 2020, but the last IRP acknowledged by the
Commission was the 2017 IRP, which used 2016 market prices.
3 Direct testimony of Daniel J. MacNeil, page 3.
a In the Matter of the Commission's Review of PURPA QF Contract Provisions Including lhe Surrogate Avoided
Resource and Integrated Resource Planning Methodologies for Calculating Avoided Cost Rates, Case No.
GNR-E-Il-03, OrderNo.32697 at 7-8 @ec. 18,2012).
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22. The prices under the SAR methodology are updated annually, approved by the
Commission, and intended to reflect the Company's avoided costs in compliance with
obligations under PURPA. Customers, solar installers, and the Company would know when
the rate will change. The SAR energy values are utilized to set rates for small qualified
facilities. Likewise, if a customer generator exports energy onto the Company's system that
generator should be treated the same as any other generator. Customers should be economically
indifferent if the energy they receive is from the Company, a qualified faciliry or a customer
generator. Using the current avoided cost is logical, as well as administratively efficient.
23. Similarly, the non-firm pricing adjustment of 85 percent is specified in the
current Schedule 135 tariff and is used to determine the pricing for excess monthly generation
for customers on all Schedules other than 1,36,23, and 23A. This adjustment to reflect the
non-firm nature of exported energy is appropriate to apply to customer generators.
AVOIDED CAPACITY VALUE
24. Staff recommends that the Company study the capacity value that customer-
generators, as a class, provide to the system. As an initial matter, the Company does not believe
customer-generators' non-firm energy exports add capacity value to the system. Moreoveq the
customer-generators avoid the full capacity value embedded in volumetric retail rates for all
energy they produce and consume onsite. Second, due to the non-firm nature of the exported
energy, the Company cannot plan on that energy so it must acquire resources to assure
sufficient supply to serve load. Third, the Company typically meets its peak requirements with
market purchases which is comparable to the value ascribed to the Export Credit by the
Company. Finally, customer-generators' exported energy typically aligns with all other solar
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production across the west. This means the market is saturated, with reduced prices, and excess
supply, such that no capacity payment is warranted.
INTEGRATION COSTS
25. The Company continues to support inclusion of an integration cost offset to the
value of the Export Credit. The impact of solar generation across the west has increased
significantly since 2016 when the Company's first integration study was included in the 2017
IRP and has since been updated in the 2019IRP. The Company included the integration costs
to reduce customer benefits from its own Energy Vision 2020 resources and believes it is
appropriate to account for these costs when determining the Export Credit rate. Customer
generation exports are primarily sourced from rooftop solar equipment, so the inclusion of a
solar integration cost is reasonable.
AVOIDED TRANSMISSION AI\D DISTRIBUTION COSTS
26. Customer generators' energy exports do not reduce transmission and
distribution costs because any value may be exceeded by additional costs imposed by customer
generation. In addition, the implementation of customer generation to defer capital investment
is difficult to quantify and places undue risk on the system.
27. The Company is required to build its infrastructure to accommodate peak load
conditions. The effect of distributed generation is not substantial enough to delay capital
investments. For instance, in a recent substation upgrade project in Salt Lake County, Utah,
where solar penetration is significantly higher than the Company's Idaho service territory it
was determined that distributed generation would have to increase by five times to delay the
construction of a new substation for only one year. Additionally, delaying capital investments
based on customer generation poses risk to the system because, as discussed above, customer
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generators are not required to provide any electricity so they cannot be relied on to meet system
load requirements. Finally, as noted customer generators already avoid these costs for the
energy consumed on-site, they rely on the facilities to provide ancillary services even when
their own systems are generating energy it is not appropriate to pay an avoided transmission
or distribution costs for a system they use to receive and export energy.
28. The additional costs to the system from customer generation are also diffrcult
to quantify, which makes the value of the deferral of capital investments difficult to quantiff.
Although the Company is aware that increased penetration of customer generation can cause
voltage variability issues and necessitates installing protective equipment, it is difficult to
predict the quantity and timing of infrastructure improvements. Voltage variability also likely
has an effect on the number of mechanical operations infrastructure such as load tap changers,
regulators and switched capacitor banks experience, but again the effects are diffrcult to
quantifu.
29. Staffalso identifies grid stability and resiliency as other areas of benefits that
should be quantified and valued. The Company designs and operates its electric system to meet
all reliability requirements, and any grid stability or resiliency concerns would be addressed
via transmission or distribution system upgrades, as previously discussed, so stability and
resiliency benefits would not be incremental.
AVOIDED ENYIRONMENTAL COSTS
30. Parties proposed that avoided environmental costs be studied, the Company
does not believe it is appropriate to include compensation for costs not currently borne by
customers. The Company does not include variable environmental costs in the natural gas plant
generation underlying the SAR methodology, and it currently does not face any greenhouse
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gas compliance costs associated with serving load in Idaho, so compensation for avoided
greenhouse gases or other environmental costs would not be appropriate. Likewise, consistent
with the SAR methodology, the Company cannot claim the renewable energy credits that could
potentially be associated with customer generation exports and should not include such
compensation.
OTHER BENEFITS
31. Parties indicated that the proposed study should account for enhanced
cybersecurity that results from more distributed generation. However, given its non-firm and
uncertain nature, customer-generator exports are unlikely to eliminate the Company's reliance
on networked generation and transmission facilities, so customer generation will not increase
cybersecurity.
32. Parties also urge the Company to include economic benefits of local job creation
and economic activity. As stated earlier, the Company does not believe it is appropriate to
include compensation for costs or benefits not borne by customers in rates.
SCHEDULE 136 IMPLEMENTATION ISSUES
33. Staff asserts that the Company's proposed Net Billing program, under which
exported energy would be measured instantaneously, could not be done until the Company has
deployed AMI. This is not correct. The Company can currently bill customers on the proposed
Net Billing program with non-AMI meters. Currently, the meters used for the Net Metering
program record total energy deliveries to the customer and total energy exports from the
customer to the Company, and the Company's billing system nets those values. While the
Company's Net Billing program would differentiate exported energy by time of day, this
structure can be entirely supported with existing meters using the current billing system.
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34. In its comments, Staff also asked the Company to explain how seasonal time
differentiated prices will help align exports with system needs. The Company clarifies that
such pricing will incentivize customer generators to build systems that maximize output when
the customer is expected to use it and/or when Export Credits are at their highest value. Further,
if a customer has load that can be shifted, like a dishwasher or electric water heater, the
customer will be incentivized to do so during the off-peak times, which will benefit the
Company's system by shifting loads to times when energy is less valuable.
FREQUENCY OF EXPORT CREDIT RATE UPDAIES
35. Staffrecommended that the Company study the impact of bi-annual updates as
compared to annual updates. The Company is willing to consider bi-annual updates, it is more
concerned with the source of data used for the updates than the difference between annual or
bi-annual updates. The Company does not anticipate that the Export Credit rate would change
dramatically from year to year under its proposal. As discussed above, the Commission should
adopt an Export Credit based on the avoided cost price approved in the annual SAR docket,
and not based on the IRP. Using the rates produced by the SAR method should adequately
address Staffs concern and is readily transparent.
SMART INYERTER TECHNOLOGY
36. Staff recommended that the Company analyze the benefits of applying smart
inverter technology in its Idaho service territory. Rocky Mountain Power, Utah State
University, and EPRI are evaluating the current state of smart inverter technology and its
implications for improving distributed energy resources integration. At this time, it is unclear
to the Company whether there is a quantifiable benefit related to smart inverters which would
accrue to non-participating customers. The Company is not opposed to continue to study
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whether any benefits are achieved from smart inverter technology but does not recommend
incorporating quantified benefits at this time.
CUSTOMER COMMENTS AI\[D NOTICE
37. Staff recommended that the Company distribute notice of its Supplemental
Application and public workshops broadly to all customers so that all interested customers, not
just Net Metering customers, have the opportunity to be heard on this issue.
38. On June 14,2019, when the Company filed its Application, a press release was
issued and a letter was sent to all existing Net Metering customers. On April 23,2020, when
the Company submitted its updated Export Credit rate to the Commission once again it issued
a press release and included bill inserts informing all customers of the Company's proposed
changes to the Net Metering program and of the public workshop the Company would be
hosting on June 16,2020 to explain its proposal and seek public input and comments.
39. Excluding Commission staff and other utility participants the Company had
three to five customers call into the Company's June l6th workshop. Commission Staff also
held a public workshop on June 18ft, and the Commission held a public hearing on June 22nd
with similar levels of participation. As of July 15,2020 there were 19 customer comments on
the Commission site. The Company has over 84,000 customers in ldaho, 1,300 net metering
customers, if the level of comments is an indication of concern with the Company's proposal,
it is very small.
AI\INUAL EXPIRATION OF EXPORT CREDITS
40. Staff recommended that the Company put forth a reasonable approach for
studying the timeframe over which export credits would expire. The Company is not opposed
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to analyzing longer periods, but believes that an annual expiration period is reasonable and will
discourage customer generators from overbuilding their systems.
41. To encourage customers not to oversize their generation systems, the Company
proposed that the export credit balance would be rolled over until March of each year for most
customers and until October for inigation customers. As noted, the purpose of both Net
Metering and Net Billing is for customers to offset some or all of their energy bill with onsite
generation, not for a customer to become a power producer. In Utah the value of any expiring
export credits is donated to non-profit organizations, and the Company proposes the same
treatment in Idaho.
REVISED COMMENTS OF COMI\{ISSION STAFF
42. On July 6,2020, Staffsubmitted Revised Comments, containing a list of topics
they would like the Company to evaluate. The Company believes it has responded to most of
these issues through its Application and comments and commits to continue to work with the
Parties to evaluate the items the Commission directs the Parties to evaluate in Phase 2.
IDAHO CONSERVATION LEAGUE ("ICL")
STUDY THE APPROPRIATE STRUCTURE OF NET METERING SERVICE
43. ICL recommends the study design phase assess the costs and benefits of the
Company's proposals. In particular, ICL recommends considering whether the administrative
costs, as well as the costs to providers and customers on the net metering sector, to implement
these changes are justified by any meaningful benefit.
44. When the Company implemented its Net Metering program, the Commission
order stated:5
s In the Matter of the Petition of NW Energt Coalition and Renewable Nonhwest Project to Establish Net
Metering Schedulesfor PacifiCorp. Case No. PAC-E-03-04, OrderNo. 29260.
14
The net metering tariffproposed by the Company provides its customers with
the opportunity to offset their electric loads and energy requirements. This
opportunity to run the meter backwards and offset usage is the primary purpose
of net metering... The purpose of net metering is not to encourage excess
generation. Developers of qualiffing renewable generation resources who wish
to get into the business of selling energy to the Company should, under PURPA,
request firm or non-firm energy purchase contracts.
Schedule 135 and the proposed Schedule 136 support the Commission's direction that the
purpose of Net Metering is not to encourage excess generation but to allow customer
generators to offset their own electric load.
45. The Company's recommendation to replace Schedule 135 - Net Metering
program with a new Schedule 136 - Net Billing program is designed to: pay Net Billing
customers the fair market value for the energy they provide, minimize the cost shifting
resulting from the Net Metering program, and to send appropriate price signals to the growing
population of customers interested in installing on-site generation. Under Schedule 135,
non-participating customers pay customer generators the retail volumetric rate for excess
energy exported to the grid when that energy is available at much lower wholesale prices. The
Company supports the development of cost-effective renewable energy and its customers'
desire to install on-site generation, but simply wants to ensure that other customers are not
adversely impacted through higher rates.
46. Regarding the alleged administrative burden that ICL believes such a program
may impose, such concerns are unfounded. Billing customer generators on the Net Billing
structure relative to the Net Metering structure is not incrementally more expensive. The same
meter type and billing system can be used for both programs. Further, Net Billing is not a new
program structure for the Company. The Company has an approved Net Billing program in
Califomia very similar to the one it has proposed in Idaho, under which it is currently billing
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customers. Moving to the Net Billing structure for new customer generators provides a path
forward to deal with the cost shifting that results from the current Net Metering program while
creating cost-based actionable price signals to participants. Net Metering in its current form
drives unsustainable cost shifting.
USE OF ROBUST AND VERIFIABLE DATA
47. ICL recommends that the Company conduct a fair, credible, and comprehensive
study using AMI. In the absence of AMI data, it recommends a load research study be
undertaken. Such a delay is unnecessary for the Commission to take action on the Application
now. The Company's forecast of customer generation is reasonable, robust, and incorporates
the data that is currently available. Further, the Company's proposed Export Credit rate does
not presently depend upon the profile of solar generation or exports for its derivation. The
Company's proposed Export Credit is based upon a flat profile, so that it may reflect the value
irrespective of resource, whether it be solar, wind, or small scale hydro. To reflect the
underlying variation in value that export profiles of different customer generators, the
Company has proposed time-varying export rates. Customers who export at higher value times
would therefore receive greater compensation for their exports.
48. Inasmuch as the Commission may require the Export Credit rate to be based
upon a particular profile, the Company proposes that the export profile of the Company's
customer generators in Northern Utah, who are on Schedule 136 in that jurisdiction, be used
as a proxy at this time for the export profiles of customer generators in Idaho. Northern Utah
is in the same climate zone as the Company's Idaho service area. As a result of the metering
requirements for Utah's Schedule 136 tariff, the Company has profile data for a large
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population in this group. When AMI data from customer generators is available, this source
could be modified in an Export Credit rate update filing.
ELIGIBILITY REQUIREMENTS THAT IMPACT VALUE
49. ICL recommends the study design consider whether adjusting the eligibility
caps based on a percentage of customer energy usage can address the allegations of cost-
causation and the need to expend public resources to value a small amount of exports.
Specifically, ICL recommends the study assess whether placing eligibility caps set at 100%;o
and l25Yo of customer loads is a more cost-effective way to address this entire issue. They
recommend l00yo to comply with the Commission's prior orders defining net metering service
as a program to enable customers to meet their own needs. They also recommend l25Yo to
account for potential increases in customer needs due to a trend towards electrification of
heating and transportation.
50. The Company disagrees with [CL's assertion that adjusting eligibility caps will
address cost shift. The Company believes that if the Net Billing program is designed correctly
to reflect a fair market value of exported energy and excess unapplied annual export credits do
not rollover, customers will be appropriately incentivized to size their systems correctly.
III. CONCLUSION
51. On June 20, 2003, when the Idaho Public Utilities Commission approved
Electric Service Schedule 135 - Net Metering program the Commission Order stated:
The net metering tariffproposed by the Company provides its customers with
the opportunity to offset their electric loads and energy requirements. This
opportunity to run the meter backwards and offset usage is the primary purpose
of net metering. Under the Company proposal, a customer's monthly kilowatt-
hour consumption is offset kilowatt for kilowatt at the customer's retail energy
price... The purpose of net metering is not to encourage excess generation.
Developers of qualifuing renewable generation resources who wish to get into
the business of selling energy to the Company should, under PURPA, request
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firm or non-firm energy purchase contracts...we expect a report from the
Company regarding the required level of subsidization by non-participants. The
Commission recognizes that the full cost of the program we approve today may
not be borne only by participants. Raising the cap as recommended by the Farm
Bureau would only increase the level of subsidization. As part of its report to
the Commission, the Company should provide the differential between the net
metering purchase price it pays at retail sales rates and the wholesale cost of
alternative power supplies. We also expect further information from the
Company regarding cost shifting and the Company's ability to recover
customer costs from program participants.6
52. On June 14,2019, the Company applied to the Commission to close Schedule
135 to new customer participation, grandfather existing customers on Schedule 135, and offer
Electric Service Schedule 136 - Net Billing program. Schedule 136 still provides customers
the opportunity to offset their electric loads and energy requirements, meeting the
commission's stated primary purpose of net metering, the same as Schedule 135.
53. Schedule 136 includes three changes to the existing Net Metering program:
First, the Company proposed implementing an Export Credit aligned with the wholesale cost
of alternative power supplies for non-firm energy. The Commission noted when they approved
Net Metering that the purpose was not to encourage excess generation. The Company believes
the Export Credit provides customers with the appropriate price signal to right size their
generation facilities to offset their own usage while not encouraging excess generation. Second,
the Company proposal includes an $85 processing fee to help offset the costs of processing
and interconnecting the Net Metering customer's generation facility. Both of these changes if
approved will help mitigate some of the cost shifting caused by net metering. And third, the
Company proposed that unused Export Credits expire annually.
6 In the Matter of the Petition of NII Enetgt Coalition and Renewable Northwest Project to Establish Net
Metering Schedules for PactfiCory.Case No. PAC-E-03-04, Order No. 29260.
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54, Over one year has passed since the Company filed its Application, well past the
statutory period required for resolution of an application under Idaho Code $61-622. The
proposals of parties and Commission Staff would delay, postpone, and study this issue
indefinitely without resolving the important underlying cost shifting issue. The Company's
Application is very simple: close schedule 135 to new customer participation; implement the
Net Billing program that utilizes a market based non-firm energy price to send appropriate
price signal to customers to right size their systems to offset their own usage; and finally use
the Commission approved SAR methodology to set the Export Credit, because it treats all
power producers the same and aligns closer with the Company's avoided costs.
IV. REQUEST FOR RELIEF
Rocky Mountain Power respectfully requests that the Commission issue an order
authorizing the Company to: (i) close Electric Service Schedule 135 to new customer
participation and cap it at the levels in place, effective at midnight local time, July 31,2020;
(ii) allow existing net metering customers and those that apply for or complete interconnection
before July 3 I , 2020 to continue to stay on the program at the site until July 3l , 2035; (iii) offer
a Net Billing program to new customer generators through Schedule 136 for those who apply
for interconnection starting September 1, 2020; (iv) implement an $85 application fee for
customers that apply to interconnect a customer generation system under the Net Billing
program that will reflect the one-time cost to the Company associated with processing and
reviewing customer generation interconnection requests; (v) require projects that apply for
interconnection before August I ,2020 to complete interconnection within a one year period of
application to be eligible to stay in the Net Metering program and (vi) recover the exported
l9
energy credits from the Net Metering and Net Billing program through the Company's annual
ECAM.
At the conclusion of Phase I of this proceeding, after participating as an intervener in
Case No. IPC-E-18-15, reviewing customer's written comments, and participating in the
Company's, Staffs, and Commission's public workshops, the Company's fundamental
position on the elements that should be included in the Export Credit has not changed. The
Export Credit should include: Avoided Energy Costs, Avoided Line Losses, and Integration
Costs, which have been quantified in the Company's Supplemental Application.
Parties would like the Commission to believe that exported energy from customer-
owned generation is somehow different and more valuable than any other energy the Company
can produce or provide, even though customer generators make no commitment to deliver
energy but impose a requirement to take exported energy even when the Company does not
need it. Customer generated exported energy is not more valuable, and there is no reason or
justification to create a new valuation methodology. The Commission and many ofthese parties
have already spent countless hours developing the SAR methodology to value developer-
provided energy. The inputs are updated annually and Commission approved. Customers
should be economically indifferent if the energy they receive is from the Company, a qualified
facility, or a customer generator.
20
DATED this l6m day of July,2020.
Respectfu lly submitted,
ROCKYMOI.JNTAIN POWER
Emily Wegener Qtro hacvice)
1407 WestNorth Temple, Suite 320
Salt Lake City, Utah 84116
Telephone No. (801) 2204526
Mobile No. (385) 227 A47 6
Email: [e-mail]
Attornayfor Roclcy Mountain Power
2t
CERTIFICATE OF SERVICE
I hereby certiff that on this l6th of July, 2020,I caused to be served, via electronic mail a
true and correct copy of Rocky Mountain Power's Reply Comments in Case No. PAC-E-19-08
to the following:
Service List
Idaho Irrigation Pumpers Association, Inc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Ave., Ste. 100
P.O. Box 6l 19
Pocatello,Idaho 83205
[e-mail]
Anthony Yankel
12700 Lake Avenue, Unit 2505
Lakewood, Ohio 44107
[e-mail]
Idaho Conservation Leaque
Benjamin J. Otto
Idaho Conservation League
710 N. 6th Street
Boise,Idaho 83702
botto@ idahoconservation.org
Idaho Clean Energy Association, Inc.
Preston N. Carter
Givens Pursley LLP
601 W. Bannock Street
Boise, lD 83702
prestoncarter@ qivenspurs ley.com
kendrah@ eivenspursley.com
Commission Staff
Edward Jewell
Deputy Attomey General
Idaho Public Utilities Commission
I l33l W. Chinden Blvd., Bldg No. 8,
Suite 201-A
PO Box 83720
Boise,lD 83720-0074
edward j ewell@puc. idaho.eov
Page 1 of2
Rockv Mountain Power
Ted Weston
Rocky Mountain Power
1407 WestNorth Temple, Suite 320
salt Lake city, utah 841l6
ted.weston@pac ifi corp.com
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR97232
datareq uest@pacifi corp.com
Emily Wegener
Rocky Mountain Power
1407 WestNorth Temple, Suite 320
salt Lake city, utah 841l6
emi ly.we gener@nacifi corp.com
Adam Lowney
McDowell Rackner Gibson PC
[e-mail]
Dated this 16ft day of July,2020
Ve,"
Katie Savarin
Coordinator, Regulatory Operations
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