20190614Meredith Direct.pdf

o RECEIVED
::OI9 JUH IE PH 3: 20
,,, r',Ti * #ct*ffi i8u,o*
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER TO
CLOSE THE NET METERING PROGRAM
TO NEW SERVICf, & IMPLEMENT A
NET BILLING PROGRAM TO
COMPENSATE CUSTOMER
GENERATORS FOR EXPORTED
GENERATION
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CASE NO. PAC.E.19.O8
DIRECT TESTIMONY OF
ROBERT M. MEREDITH
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ROCKY MOUNTAIN POWER
CASE NO. PAC-E-19-08
o June 2019
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Please state your name, business address, and present position with PacifiCorp,
dba Rocky Mountain Power ("the Company").
My name is Robert M. Meredith My business address is 825 NE Multnomah Street,
Suite 2000, Portland, Oregon 97232. My present position is Director, Pricing and Cost
of Service.
Meredith, Di-l
Rocky Mountain Power
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Qualifications
A.
Briefly describe your educational and professional background.
I graduated from Oregon State University in 2004 with a Bachelor of Science degree
in Business Administration and a minor in Economics. In addition to my formal
education, I have attended various industry-related seminars. I have worked for the
Company for 14 years in various roles of increasing responsibility in the Customer
Service, Regulation, and Integrated Resource Planning departments. I have over nine
years ofexperience preparing cost ofservice and pricing related analyses for all ofthe
six states that PacifiCorp serves.
Have you testified in previous regulatory proceedings?
Yes. I have previously filed testimony on behalf of the Company in regulatory
proceedings in Idaho, Utah, Wyoming, Oregon, Washington, and California.
What is the purpose of your testimony in this proceeding?
My testimony supports the Company's application requesting to (i) create separate
customer classes comprised of residential and Schedule 23 customer generators; (ii)
close the net metering program ("Net Metering program") and corresponding tariffto
new service - Schedule 135; and (iii) create a new different, successor program for
customer generators and corresponding tariff, Schedule 136 - Net Billing program, too
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I I replace the Net Metering program. I provide justification for the Company's request
based on the results of the class cost of service study the Company performed.
How is your testimony organized?
First, I present the results of the class cost of service study that shows customer
generators participating in the Net Metering program on their own separate classes. My
testimony then discusses why residential and Schedule 23 customer generators should
be on separate customer classes. My testimony presents the Company's proposed new
Schedule 136, Net Billing Service, a different, successor program to Schedule 135, Net
Metering Service, for customer generators. Finally, my testimony explains an
alternative transition plan to move compensation for exported energy to a cost-based
level over three years, if the Commission decides that existing customer generators may
not be treated differently than new customer generators.
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t2o13 Cost of Service Study
t4a Please describe the cost of service study the Company performed for this filing.
To beffer understand the relationship between the revenue provided from customers
who participate in the Net Metering program and their cost of service, the Company
prepared a class cost of service study where net metering customers were segregated
from the class in which they presently participate ("NEM COS Study"). The NEM COS
study, which is based upon the December 2017 Results of Operation report, includes
classes for residential net metering, Schedule 23 net metering, and Schedule 6 net
metering, along with the other customer classes the Company has traditionally
included.
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Rocky Mountain Power
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a. How did the Company prepare the NEM COS Study?
A. Separate classes were created for the residential, Schedule 23, and Schedule 6 net
metering customers ("NEM classes"). For these different NEM classes, the
characteristics of their cost of service were identified, removed from the overall class
from which they were separated, and applied to the NEM classes. The characteristics
for the NEM classes include different customer counts, revenues, energy values, system
coincident peak demand values, distribution coincident peak demand values, non-
coincident peak demand values, number of customers per transformer, and metering
costs.
a. How were loads determined for the separate net metering classes?
A. To determine loads for the separate net metering classes, it was first necessary to
estimate full requirements usage. Figure I illustrates how full requirements usage is
determined for net metering customers.
Figure 1. Illustration of IIow Full Requirements Usage Can Be Determined
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(A)
Full Requirements
Customer
(B)
Energy
Delivered to
Customer from
the Energy Grid
(B) and (D) are known
(E) can be estirnated
(A) Full Requirements Usage: (B) + [(E) - (D)]
(E)
Customer
Generation
Production
Meredith, Di-3
Rocky Mountain Power
(D)
(c)
"Behind the
Meter"
Energy
Exported
from
Custorner
to the
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Grid
o I The bills for net metering customers are based upon the energy delivered to
them from the energy grid, net of the energy exported lrom their customer generation
system to the grid. Both of these values, which are represented by (B) and (D) in Figure
1, are measured by a bi-directional meter. Customer generation production, represented
as (E) in Figure 1, is calculated by multiplying estimated solar generation from National
Renewable Energy Laboratory's ("NREL") online PWVatts@ calculatorl by the
nameplate capacity of each customer's generation system. For wind based customer
generation systems, a sample of net metering wind customers was relied upon to
calculate production (E). To develop full requirements energy usage, shown as (A) in
Figure 1, the difference between (E) and (D) is added to (B).
To derive profiles for the net metering classes, the full requirements energy for
each customer by month was shaped to the monthly standard class profile. Each
customer's estimated customer generation production profile based upon individual
system sizes was then superimposed on top of estimated full requirements profiles to
estimate delivered and exported energy on an hourly basis.
The determination of system coincident peaks and distribution coincident peaks
were based upon energy deliveries to the customer. Non-coincident peak was estimated
by scaling the non-coincident peak for the overall class by the proportion of full
requirements energy for net metering customers to the overall energy for all customers.
I The Company used the default assumptions in PWVatts for a 1 kW system at the Idaho Falls, Idaho location.
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Rocky Mountain Power
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What other important changes were necessary to separately break out the NEM
classes in the NEM COS Study?
To develop the Company's proposed Schedule 136 application fee that I describe in
more detail later in my testimony, the Company identified engineering, administration,
and customer service/billing related costs that are directly attributable to
interconnecting net metering customers. These costs which are shown on Exhibit No.
2 were directly assigned to the different NEM classes.
Also, NEM classes were allocated energy-related costs for the energy that is
delivered to them and receive credit to their cost of service lor the excess generation
that they deliver to the Company.
Why does the Company allocate to net metering customers energy-related costs
based upon their delivered energy instead of their net energy?
Net metering customers use the system in a way that is fundamentally different than
other customers. Unlike other customers who consume only energy that is delivered to
them from the energy grid, net metering customers may at different times be receiving
energy from the energy grid, consuming their own generation onsite, or exporting the
excess energy from their generation to the energy grid Like with any other customer,
the Company allocates its costs based upon the volumes of energy and the magnitude
of demands the Company delivers to net metering customers. Inasmuch as net metering
customers consume their own generation onsite, the profile and overall quantity of
energy delivered to them is reduced and the allocation of costs is also consequently
reduced. The concept of net energy is a billing construct that is used for net metering.
Net energy does not reflect a net metering customer's physical time-based relationship
Meredith, Di-5
Rocky Mountain Power
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1 with the energy grid. Even though a net metering customer may produce as much total
energy as that customer consumes over a period of time, in real time that customer still
relies upon the energy grid to both import and export energy. The NEM COS Study
appropriately assigns costs to net metering customers based upon their usage of the
Company's system.
Please describe how net metering customers receive credit for energy they export
to the grid in the NEM COS Study.
For the energy that net metering customers export to the energy grid from their
customer generation systems, a credit is assigned to them based upon the $24.86 per
megawatt hour export credit value supported in Company witness Mr. Daniel J.
MacNeil's testimony Exhibit No. 3 includes the calculation of export energy credits
for each NEM class. In total, the value of the energy credits for all NEM classes is
$29,588.
Please describe how the Company applies export energy credits to the cost of
service of the NEM classes.
The Company directly assigns export credits to each NEM class. It allocates an
offsetting cost for the export credits to all classes based upon Factor 30 - Energy. Both
the export credits and the offsetting costs are functionalizedto the Production function.
Why is there an offsetting cost for the export credits?
To balance out the credits directly assigned to net metering customers in the cost of
service model, it was necessary to include a cost that offsets that credit. The export
credits in the NEM COS Study reflect a fair value of the energy that net metering
customers export to the energy grid for other customers to use. All customers, including
Meredith, Di-6
Rocky Mountain Power
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net metering customers, benefit from this excess generation in the form of reduced net
power costs. It is reasonable that all customers receive an increased allocation of cost
proportional to that benefit to offset the value assigned to the NEM classes for their
exported energy. With this treatment of exported energy, customers are economically
indifferent between whether they receive a kilowatt hour from a customer generation
system or from some other source.
Why does the Company allocate the offsetting cost for the export credits on the
basis of energy?
As shown in Mr. MacNeil's testimony, the primary component in his export credit value
analysis is an energy-related benefit.
Why does the Company allocate the offsetting cost for export credits to NEM
classes as well as to the other non-net metering classes?
Customer generation that is exported to the grid may be consumed by both customers
who do not participate in net metering as well as those who do. Also, net power costs
in total are reduced as a result of exported customer generation. It is reasonable to
assign some of the offsetting cost of exported energy to net metering customers in
proportion to the energy that is delivered to them.
What were the results of the NEM COS Study?
Exhibit No. 4 and Table 1 below show the results of the NEM COS Study:
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Rocky Mountain Power
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Thble 1. NEM COS Study Results
Table I shows that both non-net metering residential classes require a total 3.9
percent rate reduction to achieve an equal rate of return. In contrast, residential net
metering requires a 34.8 percent increase. The study shows that the present
under-collection of revenue relative to cost of service from residential net metering is
about $378 per customer per year.2
Table 1 also shows that Schedule 23 net metering requires a 16.2 percent
increase. This represents an under-collection of about $651 per customer per year.3 The
results for the Schedule 6 net metering class show a smaller difference with other
customers on Schedule 6.
The results for residential and Schedule 23 net metering reflect the ability of
these customers to avoid paying their full cost of service by receiving compensation
for each kWh generated at the full retail energy rate. Within the rate design for
2 the $:ZS per customer value for residential net metering under-collection is calculated by dividing the
$93,825 increase that the NEM COS Study indicates rvould be required for the residential net metering class by
the 248 residential net metering customers included in the NEM COS Study test period.
3 the $65 t per customer value for Schedule 23 net metering under-collection is calculated by dividing the
$14,314 increase that the NEM COS Study indicates would be required for the Schedule 23 net metering class
by the 22 Schedule 23 net metering customers included in the NEM COS Study test period.
Meredith, Di-8
Rocky Mountain Power
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Class
Arurual
Revenue
$000
Total Cost of Service
$000
Incrcase / (Decrease)
to = ROR $000
Percentage
Change fiom
Current Revenues
Residential
Residential - TOD
54,542
19,941
51,479
20.095
(3,063)
153
-s.62%
0.77o/o
Total Residential 74,483 71.573 (2,910)-3.91%
Residential - NEM
Schedule 6/35
Schedule 6 - NEM
Schedule 23
Schedule 23 - NEM
270
28,870
156
19,599
88
363
29,599
152
17,942
103
94
730
(3)
(1,657)
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34.81%
253%
-2.21%
-8.46%
r6.t8%
Other Classes 155,000 158,733 3,733 2.41%
Idaho Total 278,465 278,465 0.00%
o 1 residential and Schedule 23 customers, costs that are fixed which are related to demand
2 at the time of the Company's different peak periods are largely recovered through
3 volumetric energy charges. When net metering customers receive credits equal to the
4 full retail energy rates, but do not fully offset their peak demands, there is a potential
5 for costs to be shifted to non-participating customers.
6 Separate Class Treatment for Residential and Schedule 23 Customer Generators
7 Q. Why should the Commission separate residential and Schedule 23 customer
8 generators into a different class from other residential and Schedule 23 customers
9 for ratemaking purposes?
10 A. The Commission should order separate class treatment for residential and Schedule 23
11 customer generators for two reasons. First, residential and Schedule 23 customer
12 generators exhibit characteristics of service which are different from other classes.
13 Second, the NEM COS Study shows that when residential and Schedule 23 net
14 metering customers are in their own classes, their current levels of revenue are well
15 below cost of service indicating that they are shifting costs to other customers.
16 0. Why are residential and Schedule 23 net metering customers different than other
17 customer classes?
18 A. The profile of energy delivered to residential and Schedule 23 net metering customers
19 varies significantly from the overall profiles for all other residential and Schedule 23
20 customers. Figures 2 and3 below compare average profiles during the Company's peak
21 month of July for residential and Schedule 23 customers respectively.
Meredith, Di-9
Rocky Mountain Power
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1 Figure 2. Average Hourly Profile in July 2017 for
Residential and Residential Net Metering Customers
60"/"
0"h 1 3 5 7 9tr 131517 192123
Hour Ending
-ResidentialNetMetering -Residential
Figure 3. Average Hourly Profile in July 2017 for
Schedule 23 and Schedule 23 Net Metering Customers
80"/"
7olJ
60lJh
50o/o
40o/o
30,/,
20,h
100
0"1 3 5 7 9 11131517192123
Hour Ending
-sch 23 Net Metering
-Sch
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Figures 2 and 3 both show that the peak time for net metering customers is
different than the peak time for the entire class. Both figures also show that energy
delivered to net metering customers is significantly less in the middle of the day than
it is for the entire class.
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Rocky Mountain Power
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I The relationship between net metering customers and the grid is also
fundamentally different than it is for other customers who do not have customer
generation. Unlike most customers who only receive energy from the grid, customer
generators both receive energy from and export energy to the grid This unique two-
way relationship on its own justifies separate class treatment.
Why is the Company not requesting separate class treatment for Schedule 6
customer generators?
Separate class treatment for Schedule 6 is unnecessary for two reasons. First, the rate
structure for Schedule 6 includes demand, energy, and customer charges, while
residential and Schedule 23 include only energy and customer charges. Consequently,
rates for Schedule 6 recover far less fixed costs through volumetric energy charges than
rates for residential and Schedule 23 customers do. Second, Schedule 6 customer
generation is very small. As of May 1, 2019, the Company had only lour Schedule 6
net metering customers with customer generation that have overall installed nameplate
capacity of 42 kWDC. Table 2 below shows how customer generation compares to full
requirement usage for each of the net metering classes.
Ihble 2.
Comparison of Customer Generation to Full Requirements Usage in2017
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Class
Eneryy
Delivered
(Mwh)
Eneryy
Expofied
(M!Vh)
Est. Energl'
Generatetl
(M!Vh)
Full
Requircnrcnts
Usage M!Vh)
Residential NEM 3.510 905 1,855 4.460
Schedule 23 NEM 1.245 280 536 1.501
Schedule 6 NEM t,936 6 l5 t^946
Generation as a %o of
F'\rIl Requirernents
Usage
4r.6%
35 7%
08%
While residential and Schedule 23 net metering customers each have customer
generation that is close to 40 percent of full requirements usage, customer generation
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Rocky Mountain Power
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I 1 for Schedule 6 net metering customers is less than one percent of full requirements
2 usage. In other words, the presence of customer generation systems is not a very
3 significant driver of the billing and service characteristics for these customers.
4 The less volumetric intensive rate structure for Schedule 6 and relatively small
5 size of customer generation produces a cost ol service for this class that is relatively
6 close to the revenue that they provide, as shown on Table 1.
7 Q. What are some of the other practical benefits of separate class treatment for
8 residential and Schedule 23 customer generators?
9 A. Including residential and Schedule 23 customer generators in their own separate classes
10 will allow these two groups to be tracked in various ratemaking proceedings over time.
11 While the Company believes that the tariffchanges I recommend later in my testimony
12 will mitigate cost shifting, having separate cost of service classes increases
13 transparency and helps the Company, the Commission, and interested parties track cost
14 shifting as the characteristics of this population continues to evolve over time.
15 Proposal for Existing Schedule 135 Customers
16 a. What does the Company propose for existing customer generators on the Schedule
17 135 Net Metering program?
l8 A. The Company proposes that existing customer generators remain on the Net Metering
19 program, taking service under Schedule 135 until June 1, 2029, roughly a 10 year
20 period from the date of this filing The new Net Billing program under proposed
2l Schedule 136 is a new separate service offering to new customers, different from the
22 existing Net Metering program. Therefore, having different program-related
23 compensation mechanisms for exported energy for existing Net Metering customer
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Rocky Mountain Power
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generators and new customer generators for a limited period of time is reasonable and
appropriate. Although the proposed Net Billing program would better reflect costs and
benefits for existing customer generators, the Company recognizes that these customers
have made investments based on the current Net Metering program structure. A ten
year period for which existing customer generators may stay on the Net Metering
program is reasonable and is consistent with the customer payback analysis that I
describe later in my testimony. The generator site itself would remain under the Net
Metering program so customers would be able to retain the value if they sell the
property in the future.
When does the Company propose to close the current Net Metering program to
new service and begin offering new customers the alternative Net Billing
program?
The Company requests the Net Metering program be closed to service for any
interconnection applications received after December 3 1, 2019. Customers who submit
their application before the cutoffwould have one calendar year to interconnect in order
to be eligible for the Net Metering program. For one month after the cutoff date, the
Company would not accept customer generation applications so that it could make
system changes necessary to process application fees. Therefore the Company proposes
a February 1,2020 effective date for its proposed Schedule 136 tariff. New prospective
customer generators who submit interconnection applications at that time would
participate in the Net Billing program. Exhibit No. 5 includes proposed revisions to
Schedule 135, which closes itto new applications afterDecember 31,2079 and sets an
end date to Net Metering service of May 31, 2029.
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o I Proposed Schedule 136
2 a. Please describe the Company's proposed new Schedule 136, Net Billing Service
3 tariff.
4 A. The Company's proposed Net Billing program is set forth in tariff Schedule 136, Net
5 Billing Service, provided as Exhibit No. 5. The new program would provide export
6 credits to customer generators for all energy exported to the grid from their generation
7 system. At the same time, all energy usage provided by the Company to the customer
8 would be billed under the standard applicable tariff. Energy generated and consumed
9 on-site would serve to offset kilowatt-hours that would otherwise have been imported
l0 from the Company to the customer.
I I a. Why is the Company proposing these changes?
12 A. The Company's cost of service analysis described earlier in my testimony shows that
13 each additional customer generator who participates in the Net Metering program shifts
14 a significant level of cost onto other customers. The proposed Net Billing program
15 would help to correct the cross-subsidy that customers with customer generation
16 impose upon customers who do not have customer generation. Under the Company's
17 proposed tariff, the customer pays cost-based rates for energy taken from the Company
18 and receives compensation for energy the customer generates and exports to the system
19 that fairly and accurately reflects the value of that exported energy.
20 a. What is the proposed export credit rate for exported energy?
2l A. As described by Mr. MacNeil, the overall value for exported energy is 2.486 cents per
22 kilowatt-hour for the 12 month period ending lr/ray 2O2O.a The Company proposes that
4 Direct Testimony of Daniel J. MacNeil. Exhibit No. I
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Rocky Mountain Power
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this value be billed as an export credit rate to be applied to energy based upon the season
and time at which it is exported. For the summer season of June through September, an
export credit of 3.926 cents per kilowatt-hour would apply to energy exported during
the on-peak hours of 4.00 p.m. to 10:00 p.m. on weekdays excluding holidays and an
off-peak export credit of 2. 1 83 cents per kilowatt-hour would apply to energy exported
during all other hours in the summer season. For the winter season of October through
May, an export credit of 3. 1 13 cents per kilowatt-hour would apply to energy exported
during the same on-peak hours as the summer season and an off-peak export credit of
2.356 cents per kilowatt-hour would apply to energy exported during all other hours in
the winter season.
Will the Company credit or charge customers for kilowatt-hours which are
generated by the customer and consumed on-site?
No. Kilowatt-hours generated and consumed on-site will lower the customer
generator's imported energy needs from the Company, thereby lowering their electric
bill. There will be no other charge or credit for these kilowatt-hours under the proposed
Net Billing program.
Under what interval will energy exported to the grid and energy delivered from
the Company be netted against each other?
Energy exported to the grid and energy delivered from the Company would not be
netted against each other over an interval period. Customers' billings would be based
upon all energy exported and all energy delivered. This measurement would be real-
time or instantaneous and would not rely upon a specific interval period such as a 15
minute or hourly interval.
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Rocky Mountain Power
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Why does the Company propose that exported energy credit prices be
differentiated by time of export?
As discussed in Mr. MacNeil's testimony, differentiating the price of exported energy
sends an appropriate price signal for customer generators. Valuing exported energy at
different time-varying prices encourages customer generators to build and operate their
systems in ways that are the most beneficial to the power grid.
What is the basis for the Company's proposed on-peak period of 4:00 p.m. to
10:00 p.m.?
As discussed by Mr. MacNeil in his direct testimony,s the proposed on-peak definition
of 4:00 p.m. to 10:00 p.m., Monday through Friday excluding holidays, provides a
strong differential between the prices for the on- and off-peak periods. Offering higher
prices fairly compensates customers who export more energy during these times.
How often would export credit values be updated on proposed Schedule 136?
The Company proposes that export credit rates would be updated annually. Consistent
with the timing of the Company's annual Surrogate Avoided Resource ("SAR") update
for avoided cost prices, the Company would make an advice filing annually, around
mid-April with updated prices going into effect June 1.
Why is it appropriate for the export credit values to be updated annually instead
of providing multi-year, long-term pricing?
As discussed in Mr. MacNeil's testimony, updating the export credit values annually
ensures that new customer generators would receive accurate, up-to-date pricing for
their exported energy. If the value rises year-over-year, customer generators would
5 Direct Testimony of Daniel J. MacNeil at7-ll
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Rocky Mountain Power
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receive this higher value. Conversely, if the value declines, other non-participating
customers are protected from paying too much for that excess generation. Routine
updates of the value would help to ensure that the Net Billing program is fair for all
customers.
Under the Company's proposed Net Billing program, will export credits ever
expire?
Yes. The purpose for the Company's proposed Net Billing program is for customers to
offset some or all of their energy bill with onsite generation, not for a customer to
become a power producer. Customers who wish to be a power producer should go
through the applicable process to become a qualifying facility. To encourage customers
not to oversize their generation systems, the Company proposes that export credits may
be rolled over until March of each year for most customers and until October for
irrigation customers.
Will customers be able to offset their entire monthly bill with export credits?
Not entirely. The Company proposes that customers have the ability to offset energy
and power charges with export credits on their monthly bills. However, the customer
service charge will still be required to recover fixed costs that are not avoidable with
customer generation.
If the Company is not requesting separate class treatment for Schedule 6 customer
generators, why is it still proposing that all customer generators going forward be
subject to Schedule 136 - Net Billing Service?
The value of exported energy from customer generators is not equal to retail energy
charges. Mr. MacNeil's testimony shows that the value of exported energy rs2.486
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Rocky Mountain Power
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o 1 cents per kilowatt-hour. In comparison, the average energy charges for residential,
2 Schedule 6, and Schedule 23 are 9.963,3.988, and 8.841 cents per kilowatt-hour,
3 respectively. Providing all new customer generators going forward with credits for their
4 exported energy at a price that reflects their fair value instead of a net energy credit that
5 is priced at retail energy charges which include recovery of fixed costs that are not
6 avoidable with customer generation is just, reasonable, in the public interest, and
7 ensures that, over time, customer generators are paid appropriately for the value that
8 they provide.
9 Customer Impacts
10 a. Will the Company's proposed Net Billing program have an impact on existing
11 customer generators?
12 A. Not immediately. As described above, customers on the current Net Metering program
13 would remain on the program and face no immediate impact as a result of the proposed
14 new program and tariff.
15 a. How will participating in the Net Billing program impact the electric bill of
16 participants compared to the bill they would have paid under standard tariff
17 before installing their own generation?
18 A. ANet Billing program participant will see their bill impacted in two ways compared to
19 the bill they paid before installing their own generation. First, on-site consumption will
20 serve to lower their overall monthly energy imported from the Company and thereby
2l lower their monthly electric bill The second impact to the participant's bill is the
22 exported energy credit which will serve to further lower the net monthly bill.
Meredith, Di-18
Rocky Mountain Power
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o 1 a Taking into account the benefit of both the lower quantity of energy imported and
the exported energy credit, what is the estimated overall compensation for each
generated kilowatt-hour for the typical residential customer generator?
The Company estimates the total compensation for generated energy for the typical
residential customer generator is 8.5 cents per kilowatt-hour under its proposed Net
Billing program.
How does this compensation level compare to the compensation per generated
kilowatt-hour under the current Net Metering program?
The Company estimates the compensation for generated energy for the typical
residential customer generator under the current Net Metering program is 12.5 cents
per kilowatt-hour.
Ilave you prepared an exhibit showing the calculation of these estimates?
Yes. The estimated calculations are shown in Exhibit No. 6.
With these estimates, what impact could the Company's proposed changes have
on the economics for a residential customer considering customer generation?
Under the Net Metering program, the Company estimates a typical residential
customer generator could have a simple payback period ofjust over 9.6 years. Under
the proposed Net Billing program, the Company estimates the same system could have
a simple payback period of about 74.4 years. Exhibit No. 7 includes the calculations
and assumptions that the Company used to estimate system payback rates.
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Rocky Mountain Power
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1 Proposed Application Fee
2 a. Please explain the Company's proposed application fee for customers seeking
3 service on Schedule 136.
4 A. The Company proposes a onetime non-refundable fee of $85 to be submitted with the
5 customer application This fee reflects the administrative cost associated with
6 processing and approving applications for interconnection.
7 Q. IIow was this application fee calculated?
8 A. Exhibit No. 2 sets forth how the Company calculated the fee. The Company reviewed
9 actual costs incurred to process applications for customer generation interconnections
10 in20l7. These costs include administrative review and processing, engineering reviews
11 and handling customer service requests. The Company's overall cost to process
12 customer generator applications for Idaho was $12,169. Dividing this overall cost by
13 143 applications that were received in Idaho rn2017 yields a cost of approximately $85
14 per application.
15 0. Why is an application fee the appropriate mechanism to recover these costs?
16 A. The cost of processing customer generator interconnection applications is driven by the
17 volume of those applications and it is therefore appropriate and sensible for the costs
18 to be recovered from the customers who cause the costs, at the time those costs are
19 incurred. An application fee can also limit the number of unnecessary applications,
20 thereby lowering the costs associated with their processing and approval. For example,
2l a customer or installer may submit an application even if the customer is not very
22 serious about installing a customer generation system, because he or she faces no cost
23 to apply. The Company would still incur costs related to that application even if no
Meredith, Di-20
Rocky Mountain Power
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customer generation system is ever installed. Charging a small application fee may
screen those customers from the process who are not serious about installing a new
customer generation system.
How does the Company's proposed application fee compare to application fees for
other utilities in Idaho?
The Company's proposed application fee is less than the application fees charged by
other investor owned utilities in Idaho, as shown in Table 3 below.
Thble 3.
of Customer Generation A Fees
9 Cost of Service under Net Billing Program
Please quantify how the cross subsidy would have been reduced if net metering
customers would have been on the Company's proposed Net Billing program.
Exhibit No. 8 shows how cost of service for the NEM Classes would change if those
customers had been on the Company's proposed Schedule 136. This would have
included both an increase in revenues from export credits whose price is lower than
retail energy rates and increased revenue from interconnection application fees. Exhibit
No. 8 shows that residential customer generators would have moved from needing a
$93,825 increase to needing a $10,637 increase or about an 89 percent reduction in the
subsidy that residential customer generators impose upon other customers. Exhibit No.
8 also shows all NEM Classes would be within a reasonable range of their cost of
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Meredith, Di-21
Rocky Mountain Power
Utility Application Fee
Rocky Mountain Power (Proposed)s85.00
$100.00Idaho Power
Avista $100.00
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service with no one of the NEM classes more than four percent away from their cost of
seruce.
Alternative Transition Plan
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If the Commission declines to allow existing customer generators to remain on the
Net Metering program, what is the Company's recommendation?
If the Commission makes this determination, the Company recommends that all
residential customer generators be subject to a Net Billing program whose export credit
price transitions over a three-year period from average retail energy charges to the cost-
based level that Mr. MacNeil supports in his direct testimony ("Alternative Transition
Plan").
Why is a three year transition period appropriate, if a higher export price results
in cost shifting to other customers?
For the typical residential customer on the Net Metering program, moving to the
Company's proposed Net Billing program would result in a monthly bill increase of
$27.70 or about 32 percent. While fairness and economic efficiency are desired goals
for the Net Billing program, gradualism and avoiding having existing customer
generators experience large bills increases are also important. The Alternative
Transition Plan strikes a reasonable balance between these different objectives and
spreads the impact of higher bills for existing customer generators out over time.
Please describe the timing, rates, and typical bill impacts of the Alternative
Transition Plan.
Exhibit No. 9 shows the timing, rates, and typical bill impacts of the Company's
Alternative Transition Plan. Beginning February 1,2020, existing customer generators
Meredith, Di-22
Rocky Mountain Power
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currently on the Net Metering program and new customer generators would be subject
to the Net Billing program and would be credited for exported energy. The initial rate
for exported energy would be set equal to average base energy charges. The price for
energy exported during the summer months of May through October would be I 1.2683
cents per kilowatt-hour and the price for the winter months of November through April
would be 8.9055 cents per kilowatt-hour. Under the existing Net Metering program,
customer generators receive a kilowatt-hour credit within the month for exported
energy. For residential customer generators on Schedule 1, the value of this credit is
higher as a result of the residential inverted tier block rate design which prices greater
monthly usage at a higher rate. Consequently, the initial change to exported energy
being credited at average energy charges would result in a $3.66 average monthly bill
increase for the typical residential customer generator.
After customer generators move to the Net Billing program, the export credit
would transition each June I for the next three years in conjunction with the proposed
annual export credit update that would coincide with the SAR update. On June 1,2027,
the export credits would move one third of the way from average energy charges to the
cost-based export level. This change would result in an $8.14 estimated6 monthly bill
increase for the typical customer generator. On June 1,2022, the export credits would
move two thirds of the way from average energy charges to the cost-based export level.
At this time, export credits would also be differentiated by time period. Export credits
would not be time varying before the June 7, 2022 transition, because this would
necessitate changing out meters for existing customer generators before the Company's
6 The annual export credit update in June would result in export credit prices that are based upon the most recent
information at that time each year.
Meredith, Di-23
Rocky Mountain Power
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o 1 expectations for deploying advanced metering infrastructure ("AMI"). The seasonal
definitions of summer and winter would also change from the summer definition of
May through October, currently in rates, to June through September, which better
prioritizes the higher value third quarter peak period. The final transition would move
export credits all the way to a cost-based level on June 1,2023.
Under the Alternative Transition Plan, would export credits transition for non-
residential custom er generators?
The Company recommends that the same transition timing and export credit transition
logic be applied to Schedule 23 customer generators who would also face potential
large bill increases from moving to the Net Billing program. The Company
recommends that there be no transition for Schedule 6 customer generators and any
other schedule that may interconnect customer generation in the future. Existing
Schedule 6 customer generators would be subject to the Net Billing program effective
February 1,2020 and would be credited fortheir exported energy at the Company's
proposed cost-based prices. Table 4 below shows that Schedule 6 customer generators'
exported energy is far less prominent than customer generators on other schedules and
that their energy charges are also closer to the value of exported energy.
Thble 4. Significance of Exported Energy for Customer
Generators and Average Energy Charges by Rate Schedule
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Class
Expfied Energ;' as a
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Requirtrnents Usage
Average Energ-v
Chanqes (d/kWh)
Residential NEM 20.3yo 9.96
Schedule 23 NEM 18.6Yo 8.84
Schedule 6 NEM 0.3Yo 3.99
Meredith, Di-24
Rocky Mountain Power
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I This indicates that a movement to the Net Billing program for Schedule 6 customer
generators would have a far smaller bill impact than for residential and Schedule 23
customers.
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Conclusion
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What is your recommendation for the Commission?
The Company recommends that the Commission approve separate customer classes
comprised of residential and Schedule 23 customer generators; close the Net Metering
program and corresponding tariff - Schedule 135 to new service, and approve the
creation ofa new different, successor program and corresponding tariff, Schedule 136
- Net Billing program, to replace the Net Metering program. If the Commission
determines that existing customer generators must be on the same program as new
customer generators, the Company recommends that the Commission approve its
Alternative Transition Pl an.
Does this conclude your direct testimony?
Yes.
Meredith, Di-25
Rocky Mountain Power
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