20250207Direct D. MacNeil.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-25-02
OF ROCKY MOUNTAIN POWER FOR )
AUTHORITY TO IMPLEMENT CHANGES ) DIRECT TESTIMONY OF
TO NON-LEGACY CUSTOMER ) Daniel J. MacNeil
GENERATORS )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-25-02
February 2025

1 I . INTRODUCTION OF WITNESS
2 Q. Please state your name, business address , and present
3 position with PacifiCorp d/b/a Rocky Mountain Power.
4 A. My name is Daniel J. MacNeil . My business address is 825
5 NE Multnomah Street, Suite 600, Portland, Oregon 97232 .
6 My present position is Commercial Analytics Adviser.
7 II . QUALIFICATIONS
8 Q. Briefly describe your education and professional
9 experience.
10 A. I received a Master of Arts degree in International
11 Science and Technology Policy from George Washington
12 University and a Bachelor of Science degree in Materials
13 Science and Engineering from Johns Hopkins University.
14 Before joining PacifiCorp, I completed internships with
15 the U. S . Department of Energy' s Office of Policy and
16 International Affairs and the World Resources
17 Institute' s Green Power Market Development Group. I have
18 been employed by PacifiCorp since 2008, first as a member
19 of the net power costs group, then as manager of that
20 group from June 2015 until September 2016 . In my current
21 role, I provide analytical expertise on a broad range of
22 topics related to PacifiCorp' s resource portfolio and
23 obligations, including oversight of the calculation of
24 avoided cost pricing in PacifiCorp' s jurisdictions .
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Rocky Mountain Power

1 Q. Have you testified in previous regulatory proceedings?
2 A. Yes . I have provided testimony in California, Idaho,
3 Oregon, Utah, Wyoming, and FERC dockets .
4 III . PURPOSE OF TESTIMONY AND RECOMMENDATION
5 Q. What is the purpose of your testimony?
6 A. My testimony supports PacifiCorp' s proposal to update
7 Electric Service Schedule No. 136 - Net Billing Service,
8 ("Schedule 136") , to incorporate seasonal, time-of-
9 export credits applicable to the electricity generated
10 by an eligible customer and fed back to the electric
11 grid. I address two primary issues . First, I describe
12 the elements, methodology, and calculation of the export
13 credit value, including differentiation by season and
14 time of day. Second, I address how the export credit
15 will be updated going forward.
16 Q. Have you prepared a summary of the proposed export credit
17 values?
18 A. Yes . My calculations support an average annual export
19 credit of $42 . 30 per megawatt-hour ("MWh") with
20 variation by season and time of day as summarized in
21 Table 1 .
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1 Table 1 : Export Credit Summary
Summer Summer Winter Winter
Export Profile Annual On-Peak Off-Peak On-Peak Off-Peak
Volume (kWh per kW) 949 119 329 35 466
Capacity Contribution (%) 10.97% 8.69% 1.97% 0.03% 0.28%
Value by Element(cents/kWh)
Energy 2.415 4.007 3.063 2.934 1.513
- Integration (0.385) (0.638) (0.488) (0.467) (0.241)
+Avoided Line Losses 0.184 0.304 0.233 0.223 0.115
Generation Capacity 1.488 9.408 0.770 0.121 0.078
Transmission Capacity Deferral 0.069 0.437 0.036 0.006 0.004
Transmission System Cost 0.297 1.707 0.023 1.878 0.011
Distribution Capacity Deferral 0.162 1.023 0.084 0.013 0.008
Total 4.230 16.248 3.721 4.708 1.489
(i)Annual values far information only and reflect seasonal weighting from the historical
period.
2 IV. EXPORT CREDIT METHODOLOGY
3 Q. What elements are included in the customer generation
4 export credit?
5 A. As demonstrated in the Commission-acknowledged February
6 2024 Supplemental On-Site Generation Study' (the "On-
7 Site Generation Study") , there are several variables to
8 consider when assessing the value of the on-site
9 generation exports . Using the On-Site Generation Study
10 as a guide, the proposed export credit includes the
11 following elements related to the impact of exported
12 energy on PacifiCorp' s system dispatch:
13 • Avoided Energy Cost: when customer generation is
' See In the Matter of the Application of Rocky Mountain Power to Complete
the Study Review Phase of the Study and the Costs and Benefits of On-Site
Customer Generation. Case No. PAC-E-23-17 . Order No. 36286.
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Rocky Mountain Power

1 exported to the grid, PacifiCorp can reduce the
2 output of its generation resources or reduce the
3 volume of its market purchases . The resulting
4 reduction in fuel expense and purchased power cost
5 is the avoided energy cost .
6 • Integration Cost: PacifiCorp uses flexible
7 resources to accommodate fluctuations in the load
8 and resource balance of its system attributable to
9 load, wind, solar, and other non-variable energy
10 resources that are not under PacifiCorp' s control .
11 Integration costs represent the cost of holding
12 reserves with flexible resources to reliably
13 maintain the load and resource balance .
14 • Avoided Line Losses: line losses are the difference
15 between the total generation injected into the
16 grid, and the total metered volume at customer
17 sites . As a result, a kilowatt-hour ("kWh")
18 produced by a generator is not equivalent to a kWh
19 delivered to a customer. PacifiCorp' s avoided
20 energy costs are typically measured based on
21 generation and market purchases at transmission
22 voltages, while the metered volumes for residential
23 generation exports are measured at the secondary
24 voltage level . Each of the energy and capacity
25 elements are adjusted for avoided line losses .
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Rocky Mountain Power

1 • Avoided Generation Capacity: PacifiCorp must
2 maintain sufficient generating resources to ensure
3 that it can reliably meet retail load. Customer
4 generation can increase the reliability of
5 PacifiCorp' s portfolio and avoid the need for
6 additional generating capacity.
7 • Avoided Transmission and Distribution ("T&D")
8 Capacity: PacifiCorp must maintain sufficient
9 transmission and distribution capacity to deliver
10 generation resources to customer load. Because
11 customer generation is located close to customer
12 load relative to most utility-scale generation
13 resources, it can reduce the loading of
14 transmission and distribution lines and avoid
15 reliability upgrades .
16 A. Export Profile and Peak / Off-Peak Definition
17 Q. What export profile has PacifiCorp used in the
18 development of the proposed export credit rates?
19 A. PacifiCorp collects hourly export volumes for all
20 Schedule 136 customers with Automated Metering
21 Infrastructure ("AMI") meters . For this filing,
22 PacifiCorp proposes to use the mean Schedule 136 export
23 volumes for all Schedule 136 customers with AMI for the
24 twelve months ending June 2024 . At the end of that period
25 there were 1, 436 customers on this rate schedule and
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Rocky Mountain Power

I their mean rated capacity was 9 . 64 kilowatts (Direct
2 Current rating) .
3 Q. Please describe the export profile.
4 A. The mean exports of Schedule 136 customers total
5 approximately 7, 625 kWh per year, with a monthly range
6 from a low of 144 kWh in January to a maximum of 1, 071
7 kWh in June . This equates to a roughly 2 . 4 percent
8 capacity factor in January, and an 18 . 5 percent capacity
9 factor in June . These capacity factors are lower than
10 utility-scale single axis tracking solar modeling in the
11 2023 IRP, which has a capacity factor ranging from seven
12 percent in January to 48 percent in July. The capacity
13 factor of the export profile is reduced for two reasons .
14 First, exports primarily come from fixed tilt rooftop
15 solar panels that are aligned with the underlying
16 rooftop, rather than optimized for energy production
17 with tracking equipment . Second, exports are reduced by
18 customer load in any given interval .
19 Q. Is PacifiCorp proposing to differentiate export credit
20 rates across the year?
21 A. Yes . PacifiCorp is proposing that export credit rates
22 vary by season and by time of day using the definitions
23 in Schedule 36 (Optional Time of Day - Residential
24 Service) , effective starting June 1, 2025 . That schedule
25 reflects the following periods, all stated in Mountain
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1 Prevailing Time (MPT) :
2 • Summer (June through October)
3 o On-Peak: 3 : 00 p.m. to 11 : 00 p.m. , all days .
4 o Off-Peak: 11 : 00 p.m. to 3 : 00 p.m. , all days .
5 • Winter (November through May)
6 o On-Peak: 6 : 00 a.m. to 9 : 00 a.m. and 6 : 00 p.m. to
7 11 : 00 p.m. , all days .
8 o Off-Peak: 9 : 00 a.m. to 6 : 00 p.m. and 11 : 00 p.m.
9 to 6 : 00 a .m. , all days .
10 Q. What are the benefits of adopting the Schedule 36
11 definition, rather than creating a new definition?
12 A. Using the same definition for Schedules 36 and 136 will
13 reduce confusion for customers, as compared to having
14 two definitions that overlap in some periods but not in
15 others . Using the same definition also reduces
16 administrative burden as it ensures that PacifiCorp' s
17 standard AMI meters and billing systems are able to
18 automatically capture volumes and calculate rates for
19 customers that participate in both schedules .
20 Q. Please summarize the seasonal and on-peak/off-peak
21 variation of the export profile.
22 A. Table 2 provides a heat map that illustrates the pattern
23 of exports across each day for each month of the year,
24 with season and on-peak periods also shown. Table 3
25 provides another view of the export profile, presenting
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1 the average kWh exported by Schedule 136 customers by
2 month, season, and hour class . Table 2 reflects the
3 capacity factor relative to the nameplate capacity of
4 the generation (adjusted to reflect estimated
5 alternating current deliveries to the grid) . The pattern
6 is similar to a solar profile, with the highest capacity
7 factors in the middle of the day during the summer time
8 when the sun is closest to directly overhead and with
9 diminishing capacity factors in the winter as a result
10 of shorter days and reduced solar insolation. In the
11 winter, exports are low and primarily occur outside of
12 the on-peak period, though levels increase in April and
13 May. In the summer, the longer afternoon on-peak period
14 includes several hours of relatively high exports that
15 drop as sunset approaches . While most Schedule 136
16 customers have solar generation, a small portion of the
17 total comes from wind and other technologies, resulting
18 in occasional small export values outside of solar
19 hours .
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I Table 2 : Export Profile Hourly Average Capacity Factor By
2 Month
Hour Beginning(MPT) On-Peak On-Peak
Season Month 12a 1a 2a 3a 4a 5a 6a 7a 8a 9a 10a lla 12p 1p 2p 3p 4p Sp 6 7 8 9 10 11p
Winter 7 0% 0% 0% 0% 0% 0% 0% 0% D% 3% 6% 10% 12% 12% 8% 5% 1% 0.1%r7%
0% 0% 0% 0% 0%
Winter 2 0% 0% 0% 0% 0% 0% 0% 0.1% 2% 6% 11% 17% 20% 22% 19% 13% 6% 1'10% 0.1% 0% 0% 0%
Winter 3 0% 0% 0% 0% 0% 0% 0% 0.1% 2% 7% 16% 23% 29% 32% 31% 28% 20% 11% 0.2% 0.1% 0% 0% 0%
Winter 4 0% 0.1% 0% 0% 0% 0% 0% 1% 7% 20% 35% 46% 51% 55% 52% 44% 32% 19% 1% 0.1%0.1% 0% 0%
Winter 5 0% 0% 0% 0% 0% 0% 0% 4% 13% 27% 41% 50% 54% 54% 55% 50% 40% 25% 2% 0.3% 0.1% 0% 0%
Summer 6 0% 0% 0% 0% 0% 0% 1% 4% 14% 29% 42% 52% 59% N% 57% 51% 38% 24% 11% 3% 04% 0.1% 0% 0%
Summer 7 0% 0% 0% 0% 0% 0% D.2% 3% 11% 24% 37% 47% 52% 52% 51% 42% 3D% 19% 8% 2% 0.236 0% 0% 0%
Summer 8 0% 0% 0% 0% 0% 0% 0% 1% 7% 19% 31% 41% 46% 49% 46% 39% 26% 14% 5% 1% 0.1% 0% 0% 0%
Summer 9 0% 0% 0% 0% 0% 0% 0% 0.4% 6% 19% 32% 43% 50% 50% 47% 37% 24% 12% 3% 0.2% 0.1% 0.1% 0% 0%
Summer 10 0% 0% 0% 0% 0% 0% 0% 0.1% 2% 10% 22% 33% 39% 41% 38% 30% 19% 6% 1% 0% 0.1% 0.1% 0% D%
Winter 11 0% 0% 0% 0% 0% 0% 0% 0.1% 3% 9% 19% 25% 29% 29% 22% 11% 2% 0.1% 0% 0% 0.1% 0% 0% 0%
Winter h12 0% 0% 0% 0% 0% 0% 0% 0% 1% 4% 10% 14% 17% 16% 12% 6% 1% 0% 0% 0% 0.1% 0% 0% 0%
3 Table 3 : Average Export Volume By Month, Season, and Hour
4 Class (kWh)
Season Winter Summer Winter
Month 1 2 3 4 5 6 7 8 9 10 11 12 Annual
On-Peak 1 4 12 39 76 308 253 210 185 139 7 2 1,236
Off-Peak 142 265 493 852 985 764 691 593 595 464 351 194 6,388
Total 144 269 505 892 1,061 1,071 944 802 780 603 358 196 7,625
281 Winter On-Peak 955 Summer On-Peak
3,746 Winter Off-Peak 2,642 Summer Off-Peak
4,027 WinterTotal 3,597 SummerTotal
5 B. Avoided Energy
6 Q. How does PacifiCorp propose calculating avoided energy
7 costs?
8 A. PacifiCorp proposes that compensation for exported
9 energy be valued based on historical prices from the
10 Western Energy Imbalance Market ("WEIM") for the twelve
11 months ending June 2024, weighted based on Schedule 136
12 customers' historical export volumes . Specifically,
13 PacifiCorp proposes using the average of the locational
14 marginal prices ("LMPs") for two generation points
15 located in its Idaho service territory: Meadow Creek
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1 wind, interconnected to the Goshen substation, and
2 Oneida hydro, interconnected to the Oneida substation. 2
3 These two data points represent Goshen and Northern Utah
4 - Idaho, respectively, which are the load areas that
5 represent Idaho retail customer load in PacifiCorp' s
6 long term planning. The latter location is electrically
7 contiguous (i .e . normally unconstrained) with
8 PacifiCorp' s load in northern Utah and parts of western
9 Wyoming, with the area as a whole sometimes referred to
10 as "NUT" . The LMP reflects the connectivity of the WEIM
11 footprint and is specific to a point on that system
12 rather than the characteristics of the associated
13 resource .
14 Q. Why are energy values based on historical WEIM prices
15 appropriate?
16 A. The On-Site Generation Study included both forecasted
17 energy values from the IRP and historical energy values
18 from the WEIM. Using historical WEIM prices for
19 historical exports in the same intervals is the most
20 accurate way to maintain the relationships between these
21 data series . Historical export profiles are the result
2 The specific node definitions are: MEADOWCR_NODET and ONEIDA_NODE1.
PacifiCorp's On-Site Generation Study used an aggregate pricing node that
represents the entire PacifiCorp East balancing authority area
(ELAP PACE-APND) . The proposed node definitions are more specific to
PacifiCorp's Idaho service territory, and currently result in slightly
higher prices than the aggregate for PacifiCorp East.
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Rocky Mountain Power

1 of two components : customer generation, which is
2 dependent on a solar insolation, as influenced by
3 weather conditions, and customer load, which is impacted
4 by a variety of factors, including weather and a
5 customer' s pattern of energy consumption. For example,
6 if customer load increases on hot summer days, resulting
7 in lower exports, the historical WEIM pricing from that
8 same period may be higher if regional demand is also
9 relatively high, or could be lower if regional demand is
10 relatively low (or if regional resource supply is
11 relatively high) . The relationship between weather in
12 PacifiCorp' s Idaho service territory and the impact to
13 supply and demand across the WEIM footprint is
14 necessarily complex, but inherently captured by using
15 price and export volume data from the same historical
16 period. It is significantly more difficult to represent
17 the relationship between customer generation, customer
18 load, and market prices on a forecast basis . While
19 PacifiCorp' s 2025 Integrated Resource Plan (currently
20 available as a draft3) is expanding the use of historical
21 data to better represent the range and relationships of
22 weather-related variables, including wind, solar, and
3 PacifiCorp's Draft 2025 IRP, December 31, 2024. See p. 103-107.
Available online at:
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/en
ergy/integrated-resource-plan/2025-irp/2025 DRAFT IRP Vol.l.pdf
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1 hydro generation, load, and market prices, it cannot
2 match historical WEIM pricing in simplicity and
3 transparency.
4 Q. What is the proposed exported energy value for customer
5 generators?
6 A. The weighted average WEIM value of the export profile
7 during the 12 months ending June 2024 was 2 . 415 cents
8 per kWh. Values are further distinguished by season and
9 on-peak/off-peak period, as discussed later on in my
10 testimony.
11 C. Integration
12 Q. How does PacifiCorp propose calculating integration
13 costs?
14 A. PacifiCorp proposes that the solar integration values
15 approved in Case No . PAC-E-23-24 be applied to all export
16 volumes . While a small portion of customers on Schedule
17 136 use other generation types, the vast majority of
18 participants have solar generation.
19 Q. Are integration costs applicable to distributed
20 resources?
21 A. Yes . Utilities must maintain a balance between load and
22 resources at all times, and must have dispatchable
23 capacity available to compensate for moment to moment
24 variations and sustained changes . While offsetting
25 variations cancel out and can reduce balancing
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1 requirements, particularly for PacifiCorp' s large and
2 geographically diverse system, significant variation
3 remains, and all changes in loads and resources
4 contribute to these requirements, regardless of size,
5 based on their impact on the system as a whole .
6 Q. Are exports likely to exhibit relatively higher
7 variation than solar production overall?
8 A. Yes . Assume a customer has a 10 kW rooftop solar array.
9 When a passing cloud reduces solar output by from 8 kW
10 to 6 kW, it results in 25 percent less generation, and
11 would require deployment of 2 kW of reserve capacity to
12 compensate for the change . If a customer is using 4 kW
13 initially, and maintains that level of consumption, the
14 same conditions would result in exports dropping from 4
15 kW to 2 kW, a 50 percent reduction, even though the
16 variation in output is the same . This would still require
17 deployment of 2 kW of reserve capacity, but because
18 integration costs are applied on an energy basis (i .e .
19 a $/MWh rate) , the export volume provides less
20 compensation for integration requirements than the
21 entire output of a solar facility. The geographic
22 distribution of customer generation facilities may
23 offset this effect to an extent, as clouds will impact
24 different customers at different times, but PacifiCorp' s
25 integration costs already reflect a significant degree
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1 of diversity among its large portfolio of load, wind,
2 solar, and non-variable energy resources . Given these
3 offsetting factors, PacifiCorp proposes applying the
4 $/MWh utility-scale solar integration rate to customer
5 export volumes, just as it applies to overall solar
6 production.
7 Q. What is the proposed integration cost for customer
8 exports?
9 A. The solar integration cost approved in Case No . PAC-E-
10 23-24 for calendar year 2025 reduces the export rate by
11 0 . 385 cents per kWh. Values are further distinguished by
12 season and on-peak/off-peak period, as discussed later
13 on in my testimony.
14 D. Avoided Line Losses
15 Q. How does PacifiCorp propose calculating avoided line
16 losses?
17 A. The line losses incorporated in PacifiCorp' s current
18 rates are from its 2018 Electric System Loss Study for
19 Idaho, published in April 2020 . That study identified
20 demand and energy loss factors for transmission,
21 primary, and secondary voltages, as well as additional
22 detail on losses for components within the distribution
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Rocky Mountain Power

1 system. 4 PacifiCorp proposes that the loss rates
2 associated with customer exports vary based on the
3 element under consideration. Specifically:
4 • Avoided energy: primary energy losses plus
5 service transformer energy losses : 9 . 04 percent .
6 • Avoided generation capacity and avoided
7 transmission capacity: primary demand losses
8 plus service transformer demand losses : 9 . 78
9 percent .
10 • Avoided distribution capacity: primary demand
11 losses divided by transmission demand losses :
12 4 . 15 percent .
13 Q. Why does PacifiCorp propose combining losses at the
14 primary voltage level with service transformer losses?
15 A. PacifiCorp expects to apply the export credit to
16 resources interconnected at secondary voltage levels .
17 However, the exported energy must be transferred across
18 the secondary distribution system to other customers . As
19 a result, the exports will incur some line losses and
20 will not be avoiding the entire line losses associated
21 with serving load on the secondary distribution system.
22 PacifiCorp' s proposal balances the potential for reduced
4 The April 2020 Line Loss Study is part of the current rates from the
last general rate case (Case No. PAC-E-24-04) and was also used in the
previous rate case (Case No. PAC-E-21-07) .
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Rocky Mountain Power

1 losses at the secondary level with the additional losses
2 incurred as exports are transferred to other customers .
3 Q. Why does PacifiCorp propose reducing losses associated
4 with avoided distribution capacity?
5 A. By the time power reaches a distribution substation,
6 losses have already occurred on the transmission system
7 as power is transferred from distant generation
8 resources . Distribution equipment is sized to cover
9 downstream load and associated losses, so losses on the
10 transmission system do not impact distribution capacity
11 needs and can be excluded from the avoided distribution
12 capacity calculation.
13 Q. How are line losses incorporated in the export credit?
14 A. Much of the avoided line loss value is associated with
15 avoided energy costs, with an average value of 0 . 184
16 cents per kWh annually. Because the capacity related
17 items have smaller line loss impacts, the avoided costs
18 for those elements are presented inclusive of the
19 incremental line loss savings .
20 E. Avoided Generation Capacity
21 Q. How does PacifiCorp propose calculating avoided
22 generation capacity?
23 A. PacifiCorp proposes that avoided generation capacity
24 costs be calculated using the annualized fixed costs of
25 a simple cycle combustion turbine ("SCCT") , as assumed
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1 in the 2023 IRP. The annualized fixed costs consist of
2 the capital cost of $853/kW (2022$) , multiplied by the
3 annual payment factor of 6 . 456 percent, plus fixed
4 operations and maintenance costs, including pipeline
5 costs, of $48 . 47/kw-yr (2022$) . 5 After adjusting for
6 inflation to reflect the proposed rate effective period,
7 the resulting annual fixed cost is $111/kw-yr (2025$) .
8 The forced outage rate of the SCOT in the 2023 IRP was
9 5 . 6 percent, leaving an expected availability factor of
10 94 . 4 percent. To calculate the cost of generation
11 capacity at a 100 percent contribution, $111/kw-yr is
12 divided by 94 . 4 percent, resulting in generation
13 capacity value of $117/kw-yr.
14 Q. How do you propose calculating a generation capacity
15 contribution for Schedule 136 exports?
16 A. PacifiCorp proposes using the capacity factor
17 methodology based on loss of load probability ("LOLP")
18 data for calendar year 2024 derived from the 2021 IRP
19 preferred portfolio . The capacity factor methodology
20 reports a capacity value that reflects a resource' s
21 average output during hours with a potential for loss of
22 load events, weighted based on the probability in each
5 PacifiCorp 2023 Integrated Resource Plan. Volume I. May 31, 2023.
Table 7.1-7.2. Available online at:
www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/int
egrated-resource-plan/2023-irp/2023 IRP Volume I Final 5-31-23.pdf
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1 hour. A description of this methodology and accompanying
2 results are part of Appendix K: Capacity Contribution in
3 PacifiCorp' s 2021 IRP. 6 While the 2021 IRP and the On-
4 Site Generation Study presented capacity factor
5 methodology results for 2030, PacifiCorp has also
6 prepared results using the 2021 IRP preferred portfolio
7 for a series of years across the study horizon: 2024,
8 2028, 2032, 2036, and 2040 . The composition of the
9 resource portfolio is a major driver of loss of load
10 risk, as rising penetrations of wind and solar resources
11 can reduce or eliminate loss of load probability during
12 periods of high output, resulting in lower contributions
13 for incremental resource additions of the same type, and
14 loss of load probabilities evolve with the portfolio
15 across the study horizon. For the current export credit
16 calculation, PacifiCorp proposes using loss of load
17 probability data for 2024, which is the most closely
18 aligned with the historical data and the proposed rate
19 effective period.
6 PacifiCorp 2021 Integrated Resource Plan. Volume II. September 1,
2021. Available online at:
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/en
ergy/integrated-resource-plan/2021-irp/Volume%201I%20-
%209.15.2021%20Final.pdf
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1 Q. Is PacifiCorp proposing to include a capacity deficiency
2 period as part of the export credit methodology?
3 A. No . While capacity sufficiency and deficiency periods
4 are relevant for long term contracts, the nature of
5 Schedule 136 does not distinguish the initial
6 participation date of different participants, and doing
7 so would be administratively burdensome and could cause
8 confusion. Because customers are likely to remain on
9 Schedule 136 for the life of their generating equipment,
10 which can be twenty years or longer, most of the exports
11 over the life of the equipment would occur during what
12 was considered a deficiency period at the time the
13 equipment was installed. PacifiCorp also includes
14 projected increases in customer generation installations
15 as part of its load forecast used in IRP portfolio
16 modeling, so forecasted Schedule 136 participation is
17 accounted for as part of the load and resource balance
18 and helps to defer future capacity needs . With that in
19 mind, PacifiCorp is proposing that capacity payments
20 begin immediately.
21 Q. What is the capacity contribution for Schedule 136
22 exports under the capacity factor methodology?
23 A. The capacity contribution of Schedule 136 exports is
24 approximately 11 percent, with 7 percent of the total
25 contribution in July and 3 percent in August in the late
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1 afternoon and evening, plus a 1 percent contribution
2 across other periods, including small amounts in
3 September, June, December, and January. These results
4 are before accounting for the impact of line losses .
5 After accounting for line losses, the capacity
6 contribution increases to approximately 12 percent .
7 Q. What is the proposed generation capacity value for
8 customer generators?
9 A. The generation capacity value averages 1 . 488 cents per
10 kWh. Values are further distinguished by season and on-
11 peak/off-peak period, as discussed later on in my
12 testimony.
13 F. Avoided Transmission Capacity
14 Q. How does PacifiCorp propose calculating avoided
15 transmission capacity?
16 A. PacifiCorp has identified two components for avoided
17 transmission capacity value, with slightly different
18 applications and methodologies . First, PacifiCorp
19 includes the potential savings from deferral of
20 transmission capacity upgrades needed to increase load
21 serving capability as part of its modeling of energy
22 efficiency options in its IRP process, which is
23 consistent with the methodology presented in the On-Site
24 Generation Study. Second, PacifiCorp recovers the cost
25 of its overall transmission system from all customers
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1 based on their peak load requirements, both retail and
2 wholesale . This second transmission cost component is
3 incremental to what was presented in the On-Site
4 Generation Study.
5 Q. Please describe PacifiCorp' s proposed transmission
6 capacity deferral methodology.
7 A. PacifiCorp uses the costs and capacity increase values
8 of transmission capacity expansion projects from its ten
9 year planning process to estimate the incremental cost
10 of transmission needed to increase load-serving
11 capability. After applying an annual carrying charge,
12 the resulting costs reflect the potential value of
13 deferring transmission capacity increase projects . A
14 single transmission value of $5 . 09/kw-yr is used for the
15 entire system as presented in PacifiCorp' s 2023 IRP. 7
16 Q. What capacity contribution do you propose for
17 transmission capacity deferral?
18 A. PacifiCorp proposes using the same capacity contribution
19 previously described for avoided generation capacity,
20 resulting in a capacity contribution of 12 percent after
21 accounting for losses .
' PacifiCorp 2023 Integrated Resource Plan. Volume I. May 31, 2023.
Table 7. 9. Available online at:
www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/int
egrated-resource-plan/2023-irp/2023 IRP Volume I Final 5-31-23.pdf
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1 Q. What is the proposed transmission capacity deferral
2 value for customer generators?
3 A. The transmission capacity value averages 0 . 069 cents per
4 kWh. Values are further distinguished by season and on-
5 peak/off-peak period, as discussed later on in my
6 testimony.
7 Q. Please describe PacifiCorp' s proposed transmission
8 system cost methodology.
9 A. PacifiCorp Transmission' s Open Access Transmission
10 Tariff includes firm transmission costs for network load
11 and point-to-point transmission service that are updated
12 annually based on a formula rate . PacifiCorp proposes
13 using the most current transmission capacity cost as the
14 basis for this component. Effective June 1, 2024, the
15 annual transmission capacity cost is $53 . 53/kw-yr. 8
16 Q. What capacity contribution do you propose for
17 transmission capacity deferral?
18 A. Under the approved formula transmission rate
19 methodology, transmission costs are based on the
20 coincident monthly peak for all network load customers,
21 plus the long-term firm point-to-point transmission
22 reservations . The coincident monthly transmission system
8 Available online at: https://www.oasis.oati.com/ppw/. In sidebar, select
"PacifiCorp OASIS Tariff/Company Information", then "OATT Pricing" .
Select "2024 Transmission Formula Annual Update", and the file "2024
Projection". See tab "Summary of Rates", cell F28.
MacNeil, Di 22
Rocky Mountain Power

1 peaks have only been published for 2023, but because
2 PacifiCorp' s retail customers are far larger than third-
3 party customers of PacifiCorp Transmission, PacifiCorp' s
4 monthly retail load peaks are a reasonable
5 approximation. The highest load hours do not necessarily
6 coincide with hours of the greatest risk in the LOLP
7 distribution, and isolating the single highest load in
8 every month gives equal weighting to months in the spring
9 and fall with no loss of load risk. As a result of these
10 differences, the capacity contribution of Schedule 136
11 customer exports in the top system retail load hours is
12 4 . 8 percent, or 5 . 3 percent after accounting for avoided
13 line losses .
14 Q. What is the proposed transmission capacity deferral
15 value for customer generators?
16 A. The transmission capacity value averages 0 . 297 cents per
17 kWh. Values are further distinguished by season and on-
18 peak/off-peak period, as discussed later on in my
19 testimony.
20 G. Avoided Distribution Capacity
21 Q. How does PacifiCorp propose calculating avoided
22 distribution capacity?
23 A. PacifiCorp includes the potential savings from deferral
24 of distribution capacity upgrades needed to increase
25 load serving capability as part of its modeling of energy
MacNeil, Di 23
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1 efficiency options in its IRP process . This is
2 consistent with the On-Site Generation Study.
3 Q. Please describe PacifiCorp' s proposed distribution
4 capacity deferral methodology.
5 A. PacifiCorp uses the costs and capacity increase values
6 of distribution capacity expansion projects from its ten
7 year planning process to estimate the incremental cost
8 of distribution projects needed to increase load-serving
9 capability. Because distribution projects are sized for
10 future load growth and have a limited range of sizing
11 options, the distribution deferral value is adjusted to
12 reflect a utilization weighting, calculated based on the
13 sum of Idaho' s distribution load divided by total
14 distribution system capacity in Idaho . A high weighting
15 indicates that there is little unused distribution
16 system capacity, and means that load growth is more
17 likely to require distribution capacity upgrades . After
18 applying an annual carrying charge and utilization
19 weighting, the resulting costs reflect the potential
20 value of deferring distribution capacity increase
21 projects . A state-specific distribution capacity value
22 of $16 . 72/kw-yr is used for Idaho as presented in
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I PacifiCorp' s 2023 IRP. 9
2 Q. What capacity contribution do you propose for
3 distribution capacity deferral?
4 A. PacifiCorp proposes using the same capacity contribution
5 previously described for avoided generation capacity,
6 resulting in a capacity contribution of 12 percent after
7 accounting for losses .
8 Q. What is the proposed distribution capacity deferral
9 value for customer generators?
10 A. The distribution capacity value averages 0 . 162 cents per
11 kWh. Values are further distinguished by season and on-
12 peak/off-peak period, as discussed later on in my
13 testimony.
14 H. Avoided Environmental Costs and Renewable Energy
15 Credits
16 Q. Did the Company consider Renewable Energy Credits as a
17 component of the export credit rate?
18 A. Yes, as explained in the Company' s On-Site Generation
19 Study, Idaho does not have a renewable portfolio
20 standard ("RPS") , so the benefits of RECs would come
21 from REC sales . Only renewable generation delivered to
22 the electric grid can qualify for RECs, and there are
9 PacifiCorp 2023 Integrated Resource Plan. Volume I. May 31, 2023.
Table 7 . 9. Available online at:
www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/int
egrated-resource-plan/2023-irp/2023 IRP Volume I Final 5-31-23.pdf
MacNeil, Di 25
Rocky Mountain Power

1 administrative requirements to certify renewable
2 resources and assign RECs to their production. To create
3 RECs, the renewable energy generator must be registered
4 with the Western Electricity Coordinating Council
5 ("WECC") and the Western Renewable Energy Generating
6 Information System ("WREGIS") . Renewable energy cannot
7 be monetized through REC sales without this process in
8 the WECC region. Coordinating the certification and
9 tracking of the RECs would be complex and could require
10 a full-time employee to administer. The Company expects
11 the administrative costs would exceed any revenues
12 generated from REC sales .
13 Q. Should any additional environmental costs be
14 incorporated in the proposed export credit rate?
15 A. No . At this time PacifiCorp is not forecasting any
16 variable environmental compliance costs for the
17 resources in its east balancing authority area. To the
18 extent such costs did exist, they would be incorporated
19 in the bid prices used in the WEIM to optimize dispatch,
20 and whenever such units were marginal, the associated
21 cost increase would flow into the historical WEIM price
22 results proposed to set the avoided energy value .
23 Q. Does PacifiCorp propose to include an avoided
24 environmental compliance value for customer generators?
25 A. No . PacifiCorp does not expect to be able to economically
MacNeil, Di 26
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1 monetize the potential REC value associated with
2 customer exports, and expects any other environmental
3 compliance values to be captured as part of the avoided
4 energy component .
5 I . Seasonal On-Peak and Off-Peak Rates
6 Q. How did PacifiCorp differentiate rates between seasons
7 and on-peak and off-peak periods?
8 A. Most of the value elements in the proposed export credit
9 rate include at least one hourly component that can be
10 evaluated relative to the export profile :
11 • Energy: WEIM pricing
12 • Generation capacity, transmission capacity deferral,
13 distribution capacity deferral : LOLP
14 • Transmission system cost : system coincident peak load
15 hours
16 For these value elements, the export credit value
17 in the proposed seasonal peak periods can be thought of
18 as four independent subsets of data. Instead of
19 calculating the export credit based on a weighted
20 average of all hours in the year, the export credit can
21 be calculated to reflect a weighted average of only those
22 exports that occurred within each of the four seasonal
23 peak definitions from Schedule 36 :
24 • Summer (June through October)
25 o On-Peak: 3 : 00 p.m. to 11 : 00 p.m. , all days .
26 o Off-Peak: 11 : 00 p.m. to 3 : 00 p.m. , all days .
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1 • Winter (November through May)
2 o On-Peak: 6 : 00 a.m. to 9 : 00 a.m. and 6 : 00 p.m. to
3 11 : 00 p.m. , all days .
4 o Off-Peak: 9 : 00 a.m. to 6 : 00 p.m. and 11 : 00 p.m.
5 to 6 : 00 a.m. , all days .
6 Details on the seasonal and peak differentiation
7 for each value element are provided later on in this
8 section .
9 Q. Do any value elements require a different technique to
10 differentiate rates between seasons and on-peak and off-
11 peak periods?
12 A. Yes . PacifiCorp' s line loss and integration cost inputs
13 are not differentiated by season or time of day, so they
14 do not inherently vary across the seasonal peak
15 definitions . While the input itself does not vary, it is
16 relatively straightforward to apply the applicable line
17 loss percentage to the energy or capacity value for a
18 given period. As an example, applying the approximate 9
19 percent line loss factor for energy to the summer on-
20 peak value of energy results in a value for avoided line
21 losses of 0 . 304 cents per kWh in summer on-peak periods,
22 but only results in a value of 0 . 115 cents per kWh in
23 winter off-peak periods when energy values are lower.
24 A comparable technique can be used to account for
25 integration costs . Integration costs generally represent
26 the foregone margin between the market price and the
27 variable cost of the marginal flexible generating unit
MacNeil, Di 28
Rocky Mountain Power

1 that must be held back to provide reserves . As a result,
2 when market prices are high, integration costs are
3 likely to be higher, while when market prices are low,
4 integration costs are likely to be low (or could be
5 zero) . Absent significantly more detail about the
6 disposition of resources, it is reasonable to align the
7 integration cost with the relative energy value in each
8 seasonal peak period. Integration costs represent
9 approximately 16 percent of the annual energy value, so
10 the integration cost in each period represents 16
11 percent of the energy value in each period. As an
12 example, applying the 16 percent integration cost factor
13 to the summer on-peak value of energy results in a value
14 for an integration cost of 0 . 638 cents per kWh in summer
15 on-peak periods, but only results in a value of 0 . 241
16 cents per kWh in winter off-peak periods when energy
17 values are lower.
18 Q. Please summarize the seasonal and peak differentiation
19 for energy value, integration cost, and avoided line
20 losses .
21 A. Table 4 summarizes the differentiation of seasonal peak
22 pricing for energy, integration, and avoided line
23 losses . Energy prices are above the annual average
24 during both summer periods, as well as during winter on-
25 peak. Together these periods represent just over 50
MacNeil, Di 29
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1 percent of the annual export volume . The remaining 50
2 percent of exports occur during the winter off-peak
3 period, when energy values are below the annual average .
4 Table 4 : Energy, Integration, and Line Losses by Season and
5 Hour Class
Summer Summer Winter Winter
Annual On- Off- On- Off-
Row Peak Peak Peak Peak Units Description
a $24.15 $40.07 $30.63 $29.34 $15.13 $/ Historical
MWh WEIM Value
b -15.93% -15.93% -15.93% -15.93% -15.93% % Integration
Cost
c= a*b ($3.85) ($6.38) ($4.88) ($4.67) ($2.41) $/ Integration
MWh Cost
d(i) 109.04% 109.04% 109.04% 109.04% 109.04% % Line Loss Gross
up
e 100 100 100 100 100 cents/$ Dollars to cents
conversion
f 1000 1000 1000 1000 1000 kWh/ MWh to kWh
MWh conversion
(a+c)*d*e/f 2.214 3.673 2.808 2.689 1.387 kWh/ Energy
(i) Primary Energy losses plus Service Transformer Energy losses
6 Q. Please summarize the seasonal and peak differentiation
7 for generation capacity.
8 A. Table 5 summarizes the differentiation of seasonal peak
9 pricing for generation capacity. Capacity contribution
10 is highest during the summer on-peak period, which
11 encompasses approximately 74 percent of all LOLP events
12 but generally has relatively low export volumes . This
13 results in a high generation capacity credit for a
14 limited volume of exports . The export profile' s next
15 largest capacity contribution occurs in summer off-peak,
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I which has encompasses approximately 11 percent of all
2 LOLP events but has a relatively high coincidence of
3 exports with LOLP events . The low capacity contribution
4 and high export volumes during summer off-peak result in
5 a lower generation capacity credit relative to the
6 summer on-peak period. While approximately 16 percent of
7 LOLP events occur during the winter, very few exports
8 occur in those hours, and the generation capacity credit
9 is very small .
10 Table 5 : Generation Capacity by Season and Hour Class
Annual Summer Summer Winter Winter
Row On-Peak Off-Peak On-Peak Off-Peak Units Description
a $912.30 $912.30 $912.30 $912.30 $912.30 k/N Capital Cost
b 6.46% 6.46% 6.46% 6.46% 6.46% % Carrying Charge
c $51.84 $51.84 $51.84 $51.84 $51.84 k $/yr Fixed O&M
d 94.40% 94.40% 94.40% 94.40% 94.40% % SCCT Capacity
Contribution
(a*b+c) $117.31 $117.31 $117.31 $117.31 $117.31 $/ Annual Capacity
/ kW-yr Cost
d
CG Export
f 10.97% 8.69% 1.97% 0.03% 0.28% % Capacity
Contribution
Before Losses
g(*) 109.78% 109.78% 109.78% 109.78% 109.78% % Line Loss Gross up
h 100 100 100 100 100 cents/ Dollars to cents
$ conversion
i 949.12 118.91 328.89 35.01 466.31 kWh/ Annual CG Export
kW Energy
e*f*9*h/ 1.488 9.408 0.770 0.121 0.078
cents/ Generation
i
kWh Capacity Credit
(*) Primary Demand losses plus Service Transformer Demand losses
MacNeil, Di 31
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1 Q. Please summarize the seasonal and peak differentiation
2 for transmission and distribution capacity deferral .
3 A. Table 6 and Table 7 summarize the differentiation of
4 seasonal peak pricing for deferred transmission and
5 distribution capacity, respectively. Both of these value
6 elements are differentiated based on LOLP, so they
7 follow the same patterns as generation capacity shown in
8 Table 5 and as described above .
9 Table 6: Transmission Capacity Deferral by Season and Hour
10 Class
Annual Summer Summer Winter Winter
Row On-Peak Off-Peak On-Peak Off-Peak Units Description
a $77.86 $77.86 $77.86 $77.86 $77.86 $/kW Annual Capacity
Cost
b 6.99% 6.99% 6.99% 6.99% 6.99% % Carrying Charge
c= a*b $5.45 $5.45 $5.45 $5.45 $5.45 $/ Annual Capacity
kW-yr Cost
CG Export Capacity
d 10.97% 8.69% 1.97% 0.03% 0.28% % Contribution
Before Losses
e(i) 109.78% 109.78% 109.78% 109.78% 109.78% % Line Loss Gross up
f 100 100 100 100 100 cents/$ Dollars to cents
conversion
kWh/ Annual CG Export
949.12 118.91 328.89 35.01 466.31
g kW Energy per kW
h =
c*d*e*f/ 0.069 0.437 0.036 0.006 0.004 cents/ Transmission
g kWh Capacity Credit
(i) Primary Demand losses plus Service Transformer Demand losses
MacNeil, Di 32
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1 Table 7 : Distribution Capacity Deferral by Season and Hour
2 Class
Annual Summer Summer Winter Winter
Row On-Peak Off-Peak On-Peak Off-Peak Units Description
a $184.51 $184.51 $184.51 $184.51 $184.51 $/kW Capital Cost (after
utilization adj.)
b 7.29% 7.29% 7.29% 7.29% 7.29% % Carrying Charge
c= a*b $13.45 $13.45 $13.45 $13.45 $13.45 $/ Annual Capacity Cost
kW-yr
CG Export Capacity
d 10.97% 8.69% 1.97% 0.03% 0.28% % Contribution Before
Losses
e(i) 104.15% 104.15% 104.15% 104.15% 104.15% % Line Loss Gross up
f 100 100 100 100 100 cents/ Dollars to cents
$ conversion
kWh/ Annual CG Export
949.12 118.91 328.89 35.01 466.31
g kW Energy per kW
h =
c*d*e*f/ 0.162 1.023 0.084 0.013 0.008 cents/ Distribution Capacity
kWh Credit
g
(i) Primary Demand losses divided by Transmission Demand losses
3 Q. Please summarize the seasonal and peak differentiation
4 for transmission system capacity cost.
5 A. Table 8 summarizes the differentiation of seasonal peak
6 pricing for transmission system capacity cost . Capacity
7 contribution for this value element is based on the
8 exports during twelve monthly system coincident peak
9 load hours, which is very different from the LOLP
10 distribution. During the twelve months ending June 2024,
11 four of the monthly coincident system peak hours
12 occurred during summer on-peak periods while six
13 occurred during winter on-peak periods . In both the
MacNeil, Di 33
Rocky Mountain Power

1 summer and winter seasons, one of the monthly coincident
2 system peak hours occurred during off-peak, in October
3 and February. While the largest capacity contribution
4 based on monthly system coincident peak load hours
5 occurs in the summer, the high rate occurs in the winter,
6 as the capacity contribution makes up a greater
7 proportionate of the limited export volumes during that
8 period, resulting in a slightly higher rate than during
9 summer on-peak. Export volumes are very low during the
10 two monthly coincident system peaks that fall in the
11 off-peak, resulting in a small though non-zero capacity
12 credit . As a result, a slight change in the timing of
13 the peaks could result in zero monthly coincident system
14 peak hours fall during off-peak, but it would have little
15 impact on the all-in rate for those periods .
MacNeil, Di 34
Rocky Mountain Power

1 Table 8 : Transmission System Capacity Cost by Season and
2 Hour Class
Annual Summer Summer Winter Winter
Row On-Peak Off-Peak On-Peak Off-Peak Units Description
a $53.53 $53.53 $53.53 $53.53 $53.53 $/ Annual Capacity
kW-yr Cost
CG Export
b 4.79% 3.45% 0.13% 1.12% 0.09% % Contribution During
System Coincident
Peak, Before Losses
c(i) 109.78% 109.78% 109.78% 109.78% 109.78% % Line Loss Gross up
d 100 100 100 100 100 cents/ Dollars to cents
$ conversion
e 949.12 118.91 328.89 35.01 466.31 kWh/ Annual CG Export
kW Energy per kW
f=
a*b*c*d 0.297 1.707 0.023 1.878 0.011 cents/ Transmission System
kWh Capacity Credit
/e
(i) Primary Demand losses plus Service Transformer Demand losses
3 Q. What are the proposed export credit values combining all
4 of the value elements?
5 A. Details on the proposed export credit values by season
6 and by on-peak/off-peak are shown in the introduction to
7 my testimony in Table 1 .
8 V. UPDATE METHODOLOGY FOR EXPORT CREDIT RATES
9 Q. What did Idaho Public Service Commission Staff ("Staff")
10 recommend for updating the different components of the
11 export credit rate.
12 A. Staff proposed several different recommendations
13 regarding updates to different components of the export
MacNeil, Di 35
Rocky Mountain Power

1 credit rate . 10 Those recommendations, along with the
2 Company' s response to each recommendation is summarized
3 in Table 9 below:
4 Table 9: Proposed Export Credit Update Schedule
Component of Export Credit Staff Recommendation Company Proposal
Energy Value Because the WEIM is backward-looking July 1st annual update filing, historical period
measure, the Company should consider covers prior calendar year.The export profile
how often to update the energy value to would also be updated each year to maintain
maintain accuracy. alignment.
Capacity Value After the company files an IRP.Should be The July 11T annual update will reflect the
done in a separate filing seeking capacity price and LOLP distribution from the
Commission authorization as the most recently filed IRP for consideration by
Commission only provides the Commission and will not change between
acknowledgment of IRPs. IRPs except for an adjustment for inflation.
The effective rate will reflect changes in the
historical export profile each year.
Transmission and After the company files an IRP.Should be The July 11T annual update will reflect the
Distribution Deferral done in a separate filing seeking capacity price and LOLP distribution from the
Commission authorization as the most recently filed IRP for consideration by
Commission only provides the Commission and will not change between
acknowledgment of IRPs. IRPs except for an adjustment for inflation.
The effective rate will reflect changes in the
historical export profile each year.
Transmission System Costs [Not part of Staff recommendation] The July 1ST annual update will reflect the
most recent GATT formula transmission rate.
The effective rate will reflect changes in the
historical export profile and monthly load
peak hours.
Line Losses Updated in conjunction with a new line The July 11T annual filing will reflect the line
loss study. Line Loss study should be losses used in the most recently approved
done in conjunction with a routine filing general rate case.
that updates the ECR after it is updated.
Integration Costs Staff believes the QF authorized The July 1ST annual filing will reflect the
integration rates should be used because integration costs approved for use in
it would eliminate duplication of filings. standard QF rates.
However, the Company should consider
the timing of the QF integration cost
filing with updates to an ECR.
10 See In the Matter of the Application of Rocky Mountain Power to Complete
the Study Review Phase of the Study and the Costs and Benefits of On-Site
Customer Generation. Case No. PAC-E-23-17 . Order No. 36286 and June 13,
2024, Staff Comments.
MacNeil, Di 36
Rocky Mountain Power

1 Q. What are the advantages of updating the customer' s
2 export credit on an annual basis as proposed above?
3 A. Updating the export credit rate annually ensures that
4 the export credit payments continue to be consistent
5 with PacifiCorp' s avoided cost and that they are
6 consistent with the non-firm nature of the output .
7 VI . CONCLUSION
8 Q. Please summarize your recommendations for the
9 Commission.
10 A. PacifiCorp recommends that the Commission adopt the
11 seasonal, time-differentiated export credit values
12 contained in Table 1 of my testimony and adopt annual
13 updates based on the methodology and inputs described in
14 my testimony.
15 Q. Does this conclude your direct testimony?
16 A. Yes .
MacNeil, Di 37
Rocky Mountain Power