20200401Testimony and Exhibits.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $21.2
MILLON NET POWER COST DEFERRAL
) CASE NO. PAC-E-20-02
)
) DIRECT TESTIMONY OF
) DAVID G. WEBB

ROCKY MOUNTAIN POWER

CASE NO. PAC-E-20-02

April 2020
RECEIVED
2020 April 1,PM1:23
IDAHO PUBLIC
UTILITIES COMMISSION

Webb, Di-1
Rocky Mountain Power
Q. Please state your name, business address, and present position with PacifiCorp 1
d/b/a Rocky Mountain Power (“Rocky Mountain Power” or the “Company”). 2
A. My name is David G. Webb and my business address is 825 NE Multnomah Street, 3
Suite 600, Portland, Oregon 97232. My title is Manager, Net Power Costs. 4
QUALIFICATIONS 5
Q. Please describe your education and professional experience. 6
A. I received a Master of Accountancy degree from Southern Utah University in 1999 and 7
a Bachelor of Science degree in Business Management from Brigham Young 8
University in 1994. I am a Certified Public Accountant licensed in the state of Nevada. 9
I have been employed by PacifiCorp since 2005 and have held various positions in the 10
regulation, finance, fuels, and mining departments. I assumed my current role 11
managing the regulatory net power cost group in 2019. 12
Q. Have you testified in previous regulatory proceedings? 13
A. Yes. I have previously provided testimony to the public utility commissions in Utah, 14
Wyoming, and Oregon. 15
PURPOSE OF TESTIMONY 16
Q. What is the purpose of your testimony in this proceeding? 17
A. My testimony presents and supports the Company’s calculation of the Energy Cost 18
Adjustment Mechanism (“ECAM”) balancing account for the 12-month period of 19
January 1, 2019 through December 31, 2019 (“Deferral Period”). More specifically, I 20
provide the following: 21
• A summary of the ECAM calculation, including changes made to comply with 22
Commission orders; 23

Webb, Di-2
Rocky Mountain Power
• Details supporting the addition of approximately $21.6 million to the deferral 1
balance, including $11.5 million customers’ share of excess ECAM-related 2
costs, $4.5 million Lake Side 2 Resource Adder, a $4.7 million reduction in 3
renewable energy production tax credits (“PTCs”), $0.5 million resource 4
tracking mechanism (“RTM”) deferral, $32 thousand renewable energy credit 5
(“REC”) revenue differential, and $0.5 million interest accrued; 6
• Discussion of the main differences between adjusted actual net power costs 7
(“Actual NPC”) and net power costs in rates (“Base NPC”); and, 8
• Discussion about the Company’s participation in the energy imbalance market 9
(“EIM”) with the California Independent System Operator (“CAISO”) and the 10
benefits from EIM that are passed through to customers. 11
Q. What other witnesses present testimony for the ECAM and Tariff Schedule 94 in 12
this case? 13
A. Mr. Robert M. Meredith, Director, Pricing and Cost of Service, provides testimony on 14
the proposed rates in Electric Service Schedule No. 94, Energy Cost Adjustment 15
(“Schedule 94”) and Mr. Steven R. McDougal, Director, Revenue Requirement, 16
provides testimony on wind repowering costs as calculated and deferred through the 17
approved RTM. 18
SUMMARY OF THE ECAM DEFERRAL CALCULATION 19
Q. Please briefly describe the Company’s ECAM authorized by the Commission. 20
A. In general, the ECAM tracks deviations between Actual NPC and Base NPC and defers 21
90 percent of the difference for later recovery.1 Other items, described in detail later in 22

1 See Order No. 30904 in Case No. PAC-E-08-08 and Order No. 33440 in Case No. PAC-E-15-09.

Webb, Di-3
Rocky Mountain Power
my testimony, are also tracked in the ECAM to true-up the amount in base rates to 1
actuals. These items include a resource adder for the Lake Side 2 gas generation plant, 2
PTCs, RTM deferral, and revenues from the sale of RECs.2 The balance that 3
accumulates over a deferral period is then passed on to customers as a rate surcharge 4
or credit. The Schedule 94 rate, described in Mr. Meredith’s testimony appears as a 5
separate line item on customer bills, collects from or credits to customers the balance 6
of deferred costs. Schedule 94 is adjusted as needed in the Company’s annual ECAM 7
filings. 8
The Company is required to file an application with the Commission annually 9
by April 1st to seek approval of the deferral amount and the new Schedule 94 rate, which 10
becomes effective June 1st. 11
Q. How is the ECAM deferral calculation presented in your testimony? 12
A. The calculation of the ECAM deferral is contained in Exhibit No. 1, discussed later in 13
my testimony. Table 1 is a summary of the major components. 14
Q. Are there any changes to the ECAM calculation? 15
A. Yes. As discussed in Mr. McDougal’s testimony, the Company and intervening parties 16
reached a stipulated agreement approved in Order No. 33954, that authorized the 17
Company to use the ECAM to recover the replacement of certain assets, new 18
investment, incremental energy production, and wind repowering project PTCs through 19
the RTM. The RTM and ECAM will capture the costs and benefits of the repowered 20
wind facilities until they are recovered in base rates through a general rate case. 21
Exhibit No. 1 has been modified from previous years to include the RTM deferral. 22

2 See Order No. 33440 in Case No. PAC-E-15-09 pages 5–6.

Webb, Di-4
Rocky Mountain Power
ECAM DEFERRAL CALCULATION 1
Q. Please describe the calculation of the ECAM deferral included in this filing. 2
A. Table 1 provides a summary of the total ECAM deferral and a breakdown of the 3
individual components of the ECAM. Additionally, Exhibit No. 1 presents the detailed 4
calculation of the ECAM deferral on a monthly basis. 5
Table 1 6
Annual ECAM Calculation

Table 1 summarizes the components of the ECAM balance. The first section 7
summarizes the Idaho-allocated share of those items for which Idaho customers and 8
the Company share responsibility, including: NPC differential, EITF 04-6 adjustment, 9
and load change adjustment revenue (“LCAR”) costs. The next section calculates the 10
90 percent customers’ share of the items above and adds the following items which are 11
refunded or collected in full (i.e., 100 percent): the Lake Side 2 resource adder, PTCs, 12
RTM deferral and REC revenues. The total of these items equal the ECAM deferral. 13

Calendar Year 2019 ECAM Deferral
NPC Differential 13,470,193$
EITF 04-6 Adjustment 115,324
LCAR (829,632)
Total Deferral Before Sharing 12,755,886$
Sharing Band 90%
Customer Reponsibility 11,480,297$
Lake Side 2 Resource Adder 4,540,985$
Production Tax Credits 4,717,273
RTM Adjustment 452,488
REC Deferral (31,947)
Interest on Deferral 462,786
Annual Deferral (Jan - Dec 2019)21,621,882$

Webb, Di-5
Rocky Mountain Power
Q. Please explain how the depreciation regulatory asset has been included in the 1
ECAM calculation. 2
A. In Case No. PAC-E-18-01, the Commission ordered the Company to include the 3
depreciation regulatory asset created in Case No. PAC-E-13-02 in future Idaho ECAM 4
filings. As seen in Exhibit No. 1, the beginning balance, monthly deferral, and monthly 5
amortization are included as part of the ECAM deferral balance. 6
Q. Based on your calculations, what is the balance expected to be in the ECAM 7
deferral account as of June 1, 2020? 8
A. The projected balance in the ECAM deferral account as of June 1, 2020 is 9
approximately $22.3 million. Table 2 summarizes the ECAM balancing account 10
activity starting with the calendar year 2018 ECAM deferral balance of $17.4 million 11
approved in Case No. PAC-E-19-04. Approximately $21.6 million is added to the 12
balance from the annual deferral and interest during the Deferral Period, offset by $11.7 13
million of ECAM revenue collections. Table 2 then summarizes the depreciation 14
regulatory asset balance activity; the sum of the two is the balance for collection as of 15
December 31, 2019. 16

Webb, Di-6
Rocky Mountain Power
Table 2 1
Balancing Account Activity

Q. Please describe the ECAM calculations in Exhibit No. 1. 2
A. The ECAM deferral is calculated by comparing Idaho-allocated Actual NPC to the 3
NPC collected in rates on a monthly basis and deferring the differences into an ECAM 4
balancing account. Exhibit No. 1 includes details of the ECAM calculation. I have also 5
provided confidential work papers supporting this exhibit. 6
Q. How are the Base NPC and Actual NPC calculated? 7
A. The monthly Base NPC collected in rates, as set forth in Exhibit No. 1 line 6, is 8
calculated by taking the dollar-per-megawatt-hour Base NPC rate multiplied by the 9
actual Idaho retail sales. The Actual Idaho NPC, as set forth in Exhibit No. 1 line 15, is 10
calculated by dividing the monthly total Company Actual NPC in the Deferral Period 11
by the actual monthly system megawatt-hours (“MWh”) in the Deferral Period. The 12
total Company Actual NPC dollar-per-megawatt-hour basis is then multiplied by Idaho 13
actual monthly MWh to calculate Actual Idaho NPC. 14

ECAM Deferral Balance
Prior Deferral 17,365,652$
Annual Deferral (Jan - Dec 2019) 21,159,096
Interest 462,786
ECAM Revenue Collection - Schedule 94 (11,701,152)
Activity Through December 31, 2019 27,286,382$
Depreciation Regulatory Asset Balance
Beginning Balance (86,905)$
Annual Deferral (Jan - Dec 2019) 1,914,765
ECAM Revenue Collection - Schedule 94 (1,904,737)
Activity Through December 31, 2019 (76,878)$
December 31, 2019 Balance For Collection 27,209,505$
Schedule 94 Collection - Jan - May 2020 (5,100,346)$
Interest 206,406
Expected Balance as of June 1, 2020 22,315,564$

Webb, Di-7
Rocky Mountain Power
Q. Please describe how the NPC deferral is calculated. 1
A. The deferral is calculated on a monthly basis by subtracting the Base NPC collected in 2
rates from the Actual Idaho NPC. For the Deferral Period, the NPC differential was 3
$13.5 million before applying the 90 / 10 percent sharing. 4
Q. What costs are included in the NPC differential for deferral? 5
A. The NPC differential for deferral captures all components of NPC as defined in the 6
Company’s general rate case proceedings and modeled by the Company’s production 7
dispatch model the Generation and Regulation Initiative Decision Tool (“GRID”). 8
Specifically, Base NPC and Actual NPC include amounts booked to the following 9
FERC accounts: 10
Account 447 – Sales for resale; excluding on-system wholesale sales and other 11
revenues that are not modeled in GRID 12
Account 501 – Fuel, steam generation; excluding fuel handling, start-up fuel 13
(gas and diesel fuel, residual disposal), and other costs that are 14
not modeled in GRID 15
Account 503 – Steam from other sources 16
Account 547 – Fuel, other generation 17
Account 555 – Purchased power; excluding the Bonneville Power 18
Administration (“BPA”) residential exchange credit pass-19
through if applicable 20
Account 565 – Transmission of electricity by others 21
Q. Are adjustments made to the Actual NPC before comparing them to Base NPC? 22
A. Yes. The Company adjusts Actual NPC to reflect the ratemaking treatment of several 23

Webb, Di-8
Rocky Mountain Power
items, including: 1
• out of period accounting entries booked in the Deferral Period that relate to 2
operations before implementation of the ECAM on July 1, 2009; 3
• buy-through of economic curtailment by interruptible industrial customers; 4
• revenue from a contract related to the Leaning Juniper wind resource; 5
• situs assignment of the generation from Oregon solar resources procured to 6
satisfy Oregon Revised Statute (“ORS”) 757.370 solar capacity standard; 7
• situs assignment of Oregon allocated excess amortization related to a 8
prepaid wheeling expense; 9
• situs assignment of certain Utah solar resources and Schedule 32 contract 10
costs; 11
• coal inventory adjustments to reflect coal costs in the correct period; 12
• legal fees related to fines and citations included in the cost of coal; and, 13
• adjustments related to liquidated damages that occurred outside the Deferral 14
Period (all liquidated damage fees per a coal supply agreement are booked 15
in accordance with generally accepted accounting principles). 16
Q. Why is the July 1, 2009 cutoff used to determine out of period entries? 17
A. Since the ECAM took effect, customers’ rates have been adjusted to recover essentially 18
all of the Company’s actual net power costs, excluding any differences due to the 90 / 19
10 percent sharing band. Consequently, any accounting entries made during the current 20
Deferral Period that relate to any operating period since the ECAM took effect, should 21
also be reflected in customer rates, whether they increase or decrease Actual NPC. 22
Accounting entries related to operating periods before the inception of the ECAM 23

Webb, Di-9
Rocky Mountain Power
should not impact the ECAM deferral. 1
Q. In addition to comparing Actual NPC to Base NPC, what other components are 2
included in the ECAM? 3
A. Six additional components are included in the ECAM calculations: (i) an adjustment 4
for deferred costs associated with coal mine stripping activities recorded under the 5
Financial Accounting Standards Board (“FASB”) EITF 04-6; (ii) the LCAR 6
adjustment; (iii) a resource adder to collect the investment in the Lake Side 2 natural 7
gas generation facility; (iv) a true-up of PTCs; (v) the resource tracking mechanism 8
deferral; and (vi) a true-up of REC revenues as authorized in Order No. 32196. 9
Q. How is the adjustment for accounting pronouncement EITF 04-6 included in the 10
ECAM? 11
A. The calculation of coal stripping costs on Line 17 of Exhibit No. 1 reflects Idaho’s 12
allocated differences between the coal stripping costs incurred by the Company during 13
excavation and recorded on the Company’s books pursuant to the guidance of the 14
accounting pronouncement EITF 04-6, and the amortization of the coal stripping costs 15
as approved by the Commission in Case No. PAC-E-09-08, Order No. 30987. For the 16
Deferral Period, the total EITF 04-6 coal stripping deferral adjustment is a $0.1 million 17
increase to the ECAM deferral balance before the 90 / 10 percent sharing. 18
Q. Please describe the LCAR adjustment. 19
A. The calculation of the LCAR adjustment is a symmetrical adjustment for over- or 20
under-collection of the energy-related portion of the Company’s embedded revenue 21
requirement for production facilities as specified in Case No. GNR-E-10-03, Order No. 22
32206. The LCAR accounts for variances in Idaho load that cause the Company to 23

Webb, Di-10
Rocky Mountain Power
collect more or less of these production-related costs. The LCAR rate of $5.54 per 1
MWh is used for the Deferral Period. 2
Q. How is the LCAR adjustment calculated and what impact does it have on the 3
Deferral Period? 4
A. The LCAR adjustment assumes that the actual production-related costs of the LCAR 5
are equal to base, Exhibit No. 1 line 18. The actual production-related costs are then 6
compared to the LCAR revenue collection in rates, calculated by multiplying the LCAR 7
rate by the actual Idaho retail sales, Exhibit No. 1 line 21. The LCAR adjustment is the 8
difference between the actual production-related costs and the LCAR revenue, line 22 9
of Exhibit No. 1, and is a $0.8 million decrease to the ECAM deferral balance before 10
the 90 / 10 percent sharing. 11
Q. Please explain the sharing ratio between the Company and customers in the 12
ECAM. 13
A. The ECAM includes a symmetrical sharing ratio in which customers either pay or 14
receive 90 percent of the ECAM deferral balance, and the Company is responsible for 15
the remaining 10 percent. Line 24 of Exhibit No. 1 represents the customers’ 90 percent 16
share of the monthly deferral shown on line 23 of Exhibit No. 1. For the Deferral 17
Period, the customers’ share of the deferred balance is $11.5 million. The remaining 18
balance of $1.3 million associated with the Company’s 10 percent share is not included 19
in the deferral balance as it is not recoverable from customers. 20
Q. What is the amount of the Lake Side 2 resource adder in the current filing? 21
A. Pursuant to the stipulation in Case No. PAC-E-13-04, approved by the Commission in 22
Order No. 32910, the Company included a resource adder to recover the investment in 23

Webb, Di-11
Rocky Mountain Power
the Lake Side 2 generation plant which is not yet included in base rates. The resource 1
adder amounts to $1.99/MWh of the Lake Side 2 generation capped at 2,729,500 MWh 2
or $5.4 million for the calendar year. The total Lake Side 2 resource adder for the 3
Deferral Period was $4.5 million based on 2,281,902 MWh of generation, line 27 of 4
Exhibit No. 1. 5
Q. What is the amount of the PTC true-up in the current filing? 6
A. The PTC Deferral, on line 32 of Exhibit No. 1, is calculated by comparing the actual 7
Idaho-allocated PTC to the PTC customers receive through base rates. The PTC credit 8
in base rates is calculated by multiplying the approved PTC rate of $1.99/MWh by 9
Idaho retail sales. The difference is a $4.7 million increase to the ECAM deferral. 10
Q. Please explain the RTM deferral. 11
A. The RTM deferral, on line 33 of Exhibit No. 1, is calculated per Exhibit No. 4 described 12
in Mr. McDougal’s testimony. The RTM deferral during calendar year 2019 is $0.5 13
million. 14
Q. What is the amount of REC revenue adjustment in the current filing? 15
A. The REC revenue adjustment, on line 38 of Exhibit No. 1, is calculated by comparing 16
the actual Idaho-allocated REC revenue to the REC revenue credit customers receive 17
through base rates. The REC revenue credit in base rates is calculated by multiplying 18
the approved REC revenue rate of $0.09/MWh by Idaho retail sales. The difference is 19
a $32 thousand decrease to the ECAM deferral. 20
Q. What is the total ECAM deferred balance calculated in Exhibit No. 1? 21
A. The total ECAM deferred balance as of December 31, 2019 is $21.2 million, shown on 22
line 39 plus $463 thousand of interest on line 48 of Exhibit No. 1, for a total deferral 23

Webb, Di-12
Rocky Mountain Power
of $21.6 million. 1
Q. Does the calculation of the ECAM deferral in this application comply with the 2
parameters of the Idaho ECAM as approved by the Commission? 3
A. Yes. Therefore, the Company recommends the Commission approve the ECAM 4
application for recovery of the $21.6 million prudently incurred ECAM costs. 5
DIFFERENCES IN NPC 6
Q. On a total-Company basis, what was the difference between Actual NPC and Base 7
NPC for the Deferral Period? 8
A. On a total-Company basis, Actual NPC for the Deferral Period were $1,653 million, 9
exceeding Base NPC for the Deferral Period by $167 million. Table 3 provides a high 10
level summary of the difference between Base NPC and Actual NPC by category on a 11
total-Company basis. 12
Table 3 13
Net Power Cost Reconciliation ($ millions)

TOTAL
Base NPC 1,485$
Increase/(Decrease) to NPC:
Wholesale Sales Revenue 157
Purchased Power Expense 91
Coal Fuel Expense (83)
Natural Gas Expense 2
Wheeling and Other Expense 0
Total Increase/(Decrease)167$
Adjusted Actual NPC 1,653$

Webb, Di-13
Rocky Mountain Power
Q. Please describe the Base NPC the Company used to calculate the NPC component 1
of the ECAM deferral. 2
A. The Base NPC were set in Case No. PAC-E-16-12 and became effective January 1, 3
2017. Base NPC used the 12 month test period of January 2016 through 4
December 2016 and set total-Company Base NPC at $1,485 million. 5
Q. Please describe the primary differences between Actual NPC and Base NPC. 6
A. From an accounting perspective, and as shown in Table 3, Actual NPC were higher than 7
Base NPC due to a $157 million reduction in wholesale sales, a $91 million increase in 8
purchased power expense, a $2 million increase in natural gas expense, and a 9
$0.2 million increase in wheeling and other expenses. The items were partially offset 10
by an $83 million reduction in coal fuel expense. 11
Q. Please explain the changes in wholesale sales revenue. 12
A. Wholesale sales revenue declined relative to Base NPC due to higher market prices and 13
a reduction in the wholesale sales volume of market transactions (represented in GRID 14
as short-term firm and system balancing sales). 15
Revenue from market transactions is $141 million lower than Base NPC due to 16
higher market prices and lower volume of market sales transactions. The average price 17
of actual market sales transactions was $9.94/MWh, or 42 percent, higher than the 18
average price in Base NPC. Actual wholesale market volumes were 8,148 GWh, or 19
62 percent, lower than the Base NPC. In addition, an expired contract accounted for 20
$9 million of the decrease in wholesale sales revenue. 21
Q. Please explain the changes in purchased power expense. 22
A. Purchased power expense increased due to a $104 million increase (49 percent) in 23

Webb, Di-14
Rocky Mountain Power
qualifying facility (“QF”) transactions, partially offset by the expiration of a long-term 1
purchase power contract. Actual QF transaction volumes were 1,690 GWh (47 percent) 2
higher than Base NPC. The expiration of the Hermiston purchase power agreement 3
(“PPA”) resulted in lower purchased power costs of $31.3 million. 4
Additionally, expenses from market transactions (represented in GRID as short-5
term firm and system balancing purchases) increased by $37.0 million compared to 6
Base NPC. Actual market purchases were 2,714 GWh (38 percent) lower than Base 7
NPC, but the average price of actual market purchases transactions was $23.51/MWh 8
(94 percent) higher than Base NPC. 9
Q. Please explain the changes in wheeling expenses. 10
A. Actual long-term wheeling expenses decreased by $1.4 million when compared to Base 11
NPC due to expired wheeling contracts. This was offset by an increase of $6.8 million 12
of short-term wheeling expenses. 13
Q. Please explain the changes in coal fuel expense. 14
A. Coal fuel expense decreased because coal generation volume decreased 4,587 GWh 15
(12 percent) compared to Base NPC. The average cost of coal generation increased 16
from $19.96/MWh in Base NPC to $20.22/MWh in the Deferral Period, but the lower 17
generation volume results in an overall decrease of $83 million in coal fuel expense. 18
Q. Please explain the changes in natural gas fuel expense. 19
A. The total natural gas fuel expense in Actual NPC increased by $2 million compared to 20
Base NPC mainly due to an increase in average cost of natural gas generation from 21
$23.06/MWh in Base NPC to $23.79/MWh in the Deferral Period. This was partially 22
offset by a decrease in gas generation volumes of 291 GWh (2 percent). 23

Webb, Di-15
Rocky Mountain Power
Q. Please provide an update of the Enbridge natural gas pipeline rupture and its 1
impact on Company operations and costs. 2
A. On October 9, 2018, the Enbridge natural gas pipeline that transports natural gas 3
produced in the Western Canadian Sedimentary Basin to consumers in British 4
Columbia (“B.C.”) and, through interconnecting pipelines, the Northwestern United 5
States (“U.S.”), experienced a massive rupture. The pipeline was brought back into 6
service in late October 2018, however, at a reduced capacity until testing of the many 7
segments of the pipeline were completed. Spot natural gas prices at the Sumas B.C.-8
U.S. border trading point traded as high as $159 per million British thermal units on 9
days of intense demand due to cold weather and reduced natural gas supply in the first 10
quarter of 2019. 11
The pipeline rupture and reduced operating capacity impacted electricity prices 12
primarily at the Mid-Columbia power market hub, but also increased electricity prices 13
at other trading points where PacifiCorp transacts. Because of PacifiCorp’s 14
geographical and resource diversity, the impact to the Company was not as severe as 15
other utilities and power producers that have a high reliance on Sumas natural gas 16
supplies. PacifiCorp has one natural gas-fired generator—the Chehalis plant—that is 17
sourced from the Sumas natural gas hub. Due to the pipeline rupture, there were times 18
of limited availability of natural gas flowing to the Sumas gas hub and limited ability 19
to withdraw out of storage facilities at Jackson Prairie. With the inability to run 20
Chehalis due to limited gas availability and supplies, plus the impact of uneconomical 21
market conditions, the result contributed to higher prices at Mid-Columbia ultimately 22
increasing net power costs. 23

Webb, Di-16
Rocky Mountain Power
IMPACT OF PARTICIPATING IN THE EIM 1
Q. Are the actual benefits from participating in the EIM with CAISO included in the 2
ECAM deferral? 3
A. Yes. Participation in the EIM provides benefits to customers in the form of reduced 4
Actual NPC. The EIM benefits are embedded in Actual NPC through lower fuel and 5
purchased power costs. The Company is able to calculate the margin realized on its 6
EIM imports and exports, the inter-regional benefit. The Company’s EIM inter-regional 7
benefit for the deferral period was $57.2 million. 8
Q. How does the Company calculate its actual EIM benefits? 9
A. Using actual information from the EIM, including five- and 15-minute pricing, the 10
Company identifies the incremental resource that could have facilitated the transfer to 11
an adjacent EIM area or the CAISO in each five-minute interval. The benefit is then 12
calculated as the difference between the revenue received less the expense of generation 13
assumed to supply the transfer. In the event of an import, the benefit is equal to the cost 14
of the import minus the avoided expense of the generation that would have otherwise 15
been dispatched. 16
Q. Please summarize your testimony. 17
A. The ECAM deferral of $21.6 million, including interest, for the Deferral Period, was 18
accurately calculated in compliance with previous Commission orders and 19
Exhibit No. 1 was updated to include the RTM deferral. Therefore, I respectfully 20
request that the Commission approve this application as filed with rates effective 21
June 1, 2020. 22

Webb, Di-17
Rocky Mountain Power
Q. Does this conclude your direct testimony? 1
A. Yes. 2

Case No. PAC-E-20-02
Exhibit No. 1
Witness: David G. Webb

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of David G. Webb

April 2020

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Rocky Mountain Power
Exhibit No. 1 Page 1 of 1 Case No. PAC-E-20-02 Witness: David G. Webb

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $21.2
MILLON NET POWER COST DEFERRAL
) CASE NO. PAC-E-20-02
)
) DIRECT TESTIMONY OF
) ROBERT M. MEREDITH

ROCKY MOUNTAIN POWER

CASE NO. PAC-E-20-02

April 2020

Meredith, Di-1
Rocky Mountain Power
Q. Please state your name, business address and present position with PacifiCorp, 1
dba Rocky Mountain Power (“the Company”). 2
A. My name is Robert M. Meredith. My business address is 825 NE Multnomah Street, 3
Suite 2000, Portland, Oregon 97232. My present position is Director, Pricing and Cost 4
of Service. 5
QUALIFICATIONS 6
Q. Briefly describe your educational and professional background. 7
A. I graduated from Oregon State University in 2004 with a Bachelor of Science degree 8
in Business Administration and a minor in Economics. In addition to my formal 9
education, I have attended various industry-related seminars. I have worked for the 10
Company for 15 years in various roles of increasing responsibility in the Customer 11
Service, Regulation, and Integrated Resource Planning departments. I have over nine 12
years of experience preparing cost of service and pricing related analyses for all of the 13
six states that PacifiCorp serves. In March 2016, I became Manager, Pricing and Cost 14
of Service. In June 2019, I was promoted to my current position. 15
Q. Have you testified in previous regulatory proceedings? 16
A. Yes. I have previously filed testimony on behalf of the Company in regulatory 17
proceedings in Idaho, Utah, Wyoming, Oregon, Washington, and California. 18
Q. What is the purpose of your testimony in this proceeding? 19
A. My testimony presents and supports the Company’s proposed rates to recover the 2019 20
Energy Cost Adjustment Mechanism (“ECAM”) deferral balances through Electric 21
Service Schedule No. 94, Energy Cost Adjustment (“Schedule 94”). 22

Meredith, Di-2
Rocky Mountain Power
BACKGROUND 1
Q. What level of revenues is Schedule 94 currently designed to collect? 2
A. Schedule 94 is currently designed to collect approximately $10.6 million—$4.2 million 3
for Tariff Contract 400, $0.3 million for Tariff Contract 401, and $6.1 million for the 4
standard tariff customers—based on Idaho loads from Case No. PAC-E-15-09. 5
PROPOSED RATE CHANGE FOR SCHEDULE 94 6
Q. Please describe the Company’s proposed rate change in this case. 7
A. The 2020 ECAM application proposes to increase Schedule 94 rates to recover 8
approximately $22.3 million from June 1, 2020 to May 31, 2021. The $22.3 million 9
includes $21.6 million for the 2019 ECAM Deferral, plus approximately $5.7 million 10
remaining from the 2018 ECAM balance, for a total balance of $27.3 million as of 11
December 31, 2019. This is offset by a net credit of $76,878 in the depreciation 12
regulatory asset balance and $4.9 million Schedule 94 forecasted revenue collection 13
from January 1, 2020 through May 31, 2020, as shown in Table 2 of Mr. David G. 14
Webb’s testimony. Mr. Webb explains in his testimony the components of the 15
2019 ECAM deferred balance. The $22.3 million balance summarized in Table 2 is 16
also partially offset by a $3.1 million amortization of the amount representing the 17
savings from federal tax reform resulting from the Tax Cuts and Jobs Act, enacted in 18
December 2017 (“ECAM Tax Reform Credit”), as further discussed in the testimony 19
of Mr. Steven R. McDougal. 20
Q. Please explain the proposed rate change for Tariff Contracts 400 and 401. 21
A. The proposed rate for Tariff Contracts 400 and 401 is the same as for standard tariff 22
customers with transmission delivery service voltage. 23

Meredith, Di-3
Rocky Mountain Power
Q. What is the impact of the proposed ECAM rates? 1
A. As summarized in my Exhibit No. 2, these rate change proposals result in an increase 2
of 3.8 percent for Tariff Contract 400, and an increase of 3.9 percent for Tariff Contract 3
401. Standard tariff customers will also see an average increase of 2.6 percent, or 4
$4.9 million. 5
CALCULATION OF PROPOSED RATES FOR SCHEDULE 94 6
Q. How were the proposed Schedule 94 rates developed for all customers? 7
A. The proposed rates for all customers were developed in four steps. First, I developed 8
their kilowatt-hour (“kWh”) consumption at the generation level by multiplying their 9
retail loads at the delivery service voltage level with the corresponding line loss factors. 10
Next, an overall average rate at the generation level was developed by dividing their 11
total collection target identified above with their kWh consumption at the generation 12
level. Finally, rates by delivery voltage level were developed by multiplying the above 13
overall average rate at the generation level with the corresponding line loss factors. As 14
a result, the Company proposes Schedule 94 rates of 0.571, 0.549 and 0.532 cents per 15
kWh for secondary, primary and transmission delivery service voltages, respectively, 16
for all customers. 17
Q. Please describe Exhibit No. 2. 18
A. Exhibit No. 2 shows the 2014 loads used to develop rates, the line loss adjusted loads, 19
the allocation of the ECAM price change including the ECAM Tax Reform Credit, and 20
the percentage change by rate schedule. 21
Q. Please describe Exhibit No. 3. 22
A. Exhibit No. 3 contains clean and legislative copies of the proposed Electric Service 23

Meredith, Di-4
Rocky Mountain Power
Schedule No. 94, Energy Cost Adjustment. The Company requests that the proposed 1
Schedule 94 rates become effective on June 1, 2020. 2
Q. Does this conclude your direct testimony? 3
A. Yes. 4

Case No. PAC-E-20-02
Exhibit No. 2
Witness: Robert M. Meredith

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Robert M. Meredith

April 2020

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Case No. PAC-E-20-02
Exhibit No. 3
Witness: Robert M. Meredith

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Robert M. Meredith

April 2020

Ninth Tenth Revision of Sheet No. 94.1 I.P.U.C. No. 1 Canceling Eighth Ninth Revision of Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 94 STATE OF IDAHO
______________ Energy Cost Adjustment ______________
AVAILABILITY: At any point on the Company’s interconnected system. APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service under the Company’s electric service schedules.
ENERGY COST ADJUSTMENT: The Energy Cost Adjustment is calculated to collect the accumulated difference between total Company Base Net Power Cost and total Company Actual Net Power Cost calculated on a cents per kWh basis. MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable schedule, all monthly bills shall have applied the following cents per kilowatt-hour rate by delivery voltage.

Submitted Under Case No. PAC-E-20-0219-04 ISSUED: April 13, 202019 EFFECTIVE: June 1, 202019
Rocky Mountain Power
Exhibit No. 3 Page 1 of 2 Case No. PAC-E-20-02 Witness: Robert M. Meredith
Tenth Revision of Sheet No. 94.1 I.P.U.C. No. 1 Canceling Ninth Revision of Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 94 STATE OF IDAHO
______________ Energy Cost Adjustment ______________
AVAILABILITY: At any point on the Company’s interconnected system. APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service under the Company’s electric service schedules.
ENERGY COST ADJUSTMENT: The Energy Cost Adjustment is calculated to collect the accumulated difference between total Company Base Net Power Cost and total Company Actual Net Power Cost calculated on a cents per kWh basis. MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable schedule, all monthly bills shall have applied the following cents per kilowatt-hour rate by delivery voltage.

Submitted Under Case No. PAC-E-20-02 ISSUED: April 1, 2020 EFFECTIVE: June 1, 2020
Rocky Mountain Power
Exhibit No. 3 Page 2 of 2 Case No. PAC-E-20-02 Witness: Robert M. Meredith

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $21.2
MILLON NET POWER COST DEFERRAL
) CASE NO. PAC-E-20-02
)
) DIRECT TESTIMONY OF
) STEVEN R. MCDOUGAL

ROCKY MOUNTAIN POWER

CASE NO. PAC-E-20-02

April 2020

McDougal, Di-1
Rocky Mountain Power
Q. Please state your name and business address with PacifiCorp dba Rocky 1
Mountain Power (“Company”). 2
A. My name is Steven R. McDougal, and my business address is 1407 W. North Temple, 3
Suite 330, Salt Lake City, Utah 84116. 4
QUALIFICATIONS 5
Q. Please describe your education and professional background. 6
A. I received a Master of Accountancy from Brigham Young University with an emphasis 7
in Management Advisory Services and a Bachelor of Science degree in Accounting 8
from Brigham Young University. In addition to my formal education, I have also 9
attended various educational, professional, and electric industry-related seminars. I 10
have been employed with PacifiCorp and its predecessor, Utah Power and Light 11
Company (the “Company”), since 1983. My experience includes various positions with 12
regulation, finance, resource planning, and internal audit. My current position is the 13
Director of Revenue Requirements. 14
Q. What are your current responsibilities with the Company? 15
A. My primary responsibilities include overseeing the calculation and reporting of the 16
Company’s regulated earnings and revenue requirement, assuring that the 17
interjurisdictional cost allocation methodology is correctly applied, and explaining 18
those calculations to regulators in the jurisdictions in which the Company operates. 19
Q. Have you testified in previous proceedings? 20
A. Yes. I have provided testimony in regulatory proceedings in California, Idaho, Oregon, 21
Utah, Washington, and Wyoming. 22

McDougal, Di-2
Rocky Mountain Power
PURPOSE OF TESTIMONY 1
Q. What is the purpose of your testimony? 2
A. I explain and support the Company’s request, through this Energy Cost Adjustment 3
Mechanism (ECAM), for recovery of $452 thousand, before carrying charge, 4
associated with the wind repowering costs as calculated and deferred through the 5
approved Resource Tracking Mechanism (RTM). This amount is included the ECAM 6
as shown in Mr. Dave Webb’s Testimony, Exhibit No. 1, line 33. I also summarize the 7
2017 Tax Reform Credit and modifications to the accounting treatment of the excess 8
deferred income tax, (“EDIT”), balances. 9
RESOURCE TRACKING MECHANISM 10
Q. Please briefly describe the background and purpose of the resource tracking 11
mechanism, (“RTM”). 12
A. In Case No. PAC-E-17-06, filed on July 3, 2017, the Company applied for approval of 13
the plan to upgrade (or “repower”) its existing wind resources and approval of 14
associated ratemaking treatment. On November 21, 2017, the Company and 15
intervening parties reached a stipulated agreement that allows the Company to use the 16
ECAM to recover the replacement of certain assets, new investment, incremental 17
energy production, and wind repowering project PTCs through the RTM. The RTM and 18
ECAM will capture the costs and benefits of the repowered wind facilities until they 19
are recovered in base rates through a general rate case. The Stipulation between the 20
parties was approved by Commission Order No. 33954, dated December 28, 2017. 21
Q. Which repowering projects are included in the RTM and this ECAM? 22
A. Nine repowering projects were completed and placed in service during 2019 that 23

McDougal, Di-3
Rocky Mountain Power
produced an Idaho-allocated net incremental benefit of $529,156. These include 1
Leaning Juniper, Glenrock I, Glenrock III, Rolling Hills, Seven Mile Hill I, Seven Mile 2
Hill II, High Plains, McFadden Ridge and Goodnoe Hills wind facilities. Other future 3
repowered wind projects, as they are completed and placed in service, will be included 4
in future RTM deferrals. 5
Q. Has the Company calculated the wind repowering deferral under the RTM 6
guidelines that were agreed to in the Stipulation and approved by the 7
Commission? 8
A. Yes. The deferral calculations follow the design and operation of the RTM as submitted 9
in the Direct Testimony of Mr. Jeffrey K. Larsen pages 6-16 and Exhibit 12 that was 10
referenced and approved in the Stipulation and Final Order of Case No. PAC-E-17-06. 11
The RTM, along with the ECAM, will capture and match all the costs and benefits of 12
the repowered wind facilities until such time as they are recovered in base rates. 13
Q. What are the costs and benefits associated with repowering that the Company has 14
included in the RTM deferral? 15
A. The Company has included the following items in the RTM on a monthly basis 16
beginning when a repowered wind project is placed into service: 17
• The pre-tax return on investment; 18
• Operation and maintenance expense; 19
• Depreciation expense; 20
• Property taxes; 21
• Wind taxes, if assessed; 22
• NPC benefits; and 23

McDougal, Di-4
Rocky Mountain Power
• PTC benefits. 1
Q. Has the Company prepared an exhibit showing the calculated amount of the wind 2
repowering deferral under the approved RTM guidelines? 3
A. Yes. Exhibit No. 4 shows the calculation of the December 31, 2019 RTM deferral 4
balance which results in a $452 thousand charge to be collected from customers through 5
the ECAM. This exhibit is structured similar to Exhibit 12 of Mr. Larsen’s Direct 6
Testimony referenced above. 7
Q. Line 18 of Exhibit No. 4 shows that the repowered wind projects produced a net 8
revenue requirement benefit of $(529) thousand. Why is the Company seeking 9
recovery of $452 thousand through the ECAM? 10
A. The RTM was approved to match all of the costs and benefits associated with the 11
repowered wind projects and pass those onto customers. Absent the RTM the ECAM 12
only captures some of the benefits and does not included any of the costs incurred to 13
produce those benefits. The ECAM will return to customers 100 percent of the 14
Production Tax Credits (PTC) of $882 thousand, and 90 percent of Net Power Cost 15
(NPC) benefit of $100 thousand, shown on lines 21 and 24, respectively. Combined, 16
the ECAM would return to customers $982 thousand, absent the RTM. Due to the 17
sharing band in the ECAM 10 percent of the NPC benefits wouldn’t be passed onto 18
customers. However the ECAM does not capture any of the costs incurred by the 19
Company to repower the wind facilities. The purposes of the RTM is to capture those 20
costs and match them with the benefits. The $529 thousand, on line 18, represents 21
Idaho’s share of the net benefit produced by the repowered wind facilities. The 22

McDougal, Di-5
Rocky Mountain Power
$452 thousand RTM deferral allows the Company to recover the net costs that are not 1
reflected in the ECAM. 2
Q. Has the Company included a carrying charge on the RTM deferral balance in 3
Exhibit No. 4? 4
A. No. Although the RTM deferral balance is subject to a carrying charge, the monthly 5
RTM deferral balance is summed with the other ECAM components and receives a 6
carrying charge as part of the overall carrying charge calculation. 7
TAX REFORM CREDIT 8
Q. Was the Federal Tax Act Adjustment credit netted against the ECAM? 9
A. Yes. The savings from federal tax reform, resulting from the Tax Cuts and Jobs Act, 10
enacted in December 2017, as prescribed in the tax stipulation among the Company 11
and parties filed with the Commission March 5, 2019 in Case No. GNR-U-18-01 12
(“ECAM Tax Reform Credit”) were netted against the ECAM deferral as described in 13
Mr. Robert M. Meredith’s testimony. 14
Q. Please summarize the ECAM Tax Reform Credit approved in Order No. 34331. 15
A. The Order approved the $1,141,000 deferred balance of current tax savings for the 16
period of January 1, 2018, through May 31, 2019, that had not been returned to 17
customers through Schedule 197. This balance was tracked and amortized over two 18
years ($570,500 per year), beginning June 1, 2019, through the Energy Cost 19
Adjustment Mechanism (“ECAM”). The Tax Reform Act resulted in Idaho-allocated 20
Excess Deferred Income Taxes (“EDIT”), composed of the following amounts, 21
grossed-up for taxes: 22

McDougal, Di-6
Rocky Mountain Power
 Protected property-related EDIT of $105,924,6041, with estimated annual 1
amortizations through the average rate assumption method (“ARAM”) of 2
$2,564,410 in 2018, $2,352,309 in 2019, and $2,306,632 in 2020; and 3
 Non-protected property and non-property EDIT of $14,883,505.2 4
The Order also specified that as the EDIT balances amortize in rates, the amounts will 5
include a rate base carrying charge offset to account for the corresponding increase in 6
rate base associated with the amortized EDIT until the next Idaho general rate case. 7
Q. What was the amount of Tax Reform Credit included in this Application? 8
A. Table 1 summarizes the Tax Reform Credit Mr. Meredith netted against the ECAM 9
deferral to calculate the net ECAM rates. 10
Table 1 
ECAM Tax Benefits   2020 
Amortization Of Current Tax Savings   $     (570,500) 
2019 Protected EDIT    $  (2,352,309) 
2019 Non‐Protected EDIT (7yr Amort)   $  (2,126,215) 
2013 Depreciation Offset   $    1,889,100  
EDIT Rate Base Offset   $        137,173  
2019 ECAM Net Tax Savings   $  (3,022,751) 
Amount Over/(Under) Refunded   $        (70,120) 
2020 ECAM Tax Offset   $  (3,092,871) 

Q. Did the Company determine a change to the accounting treatment for the EDIT 11
amortization was needed? 12
A. Yes. During December 2019, the Company determined that it was necessary to use a 13
different method of amortizing protected EDIT balances. While the tax filing was based 14

1 The protected property EDIT is $79,881,345, or $105,924,604 grossed up for taxes.
2 The non-protected property EDIT is $10,009,386, or $13,272,689 grossed up for taxes, and non-protected non-
property total EDIT is $1,214,771, or $1,610,816 grossed up for taxes.

McDougal, Di-7
Rocky Mountain Power
on the ARAM the Company determined that it didn’t have the necessary records to 1
support that method and had to switch to the Reverse South Georgia Method, 2
(“RSGM”). 3
Q. Does the RSGM change the EDIT balances? 4
A. No, but it does modify the amortization of those balances. The RSGM method uses a 5
shorter amortization period which increases the protected EDIT amortization in the 6
front-end. 7
Q. Did the Company incorporate the RSGM amortization in the 2020 ECAM? 8
A. No. The Company used the Tax Reform Credits approved in Order 34331. The 9
Company intends to propose treatment for the unamortized portion of the protected 10
property, non-protected property and non-property EDIT balances in the Idaho general 11
rate case in June 2020. 12
Q. Does this conclude your direct testimony? 13
A. Yes. 14
Case No. PAC-E-20-02
Exhibit No. 4
Witness: Steven R. McDougal

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Steven R. McDougal

April 2020

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-

(4
7
4
,
1
6
6
)

SG

6
.
0
1
3
6
%

(
2
8
,
5
1
4
)

3

A
c
c
u
m
u
l
a
t
e
d

D
I
T

B
a
l
a
n
c
e
Fo
o
t
n
o
t
e

1
(1
1
,
8
4
3
,
7
9
4
)

SG

6
.
0
1
3
6
%

(
7
1
2
,
2
3
8
)

-

S
G

6
.
0
1
3
6
%

-

(1
2
,
7
5
9
,
1
4
4
)

SG

6
.
0
1
3
6
%

(
7
6
7
,
2
8
4
)

4

N
e
t

R
a
t
e

B
a
s
e

(
p
r
e
v
i
o
u
s

m
o
n
t
h
)
su
m

o
f

l
i
n
e
s

1
-
3
29
9
,
6
0
6
,
9
9
0

18
,
0
1
7
,
1
6
6

-

-

33
1
,
3
3
3
,
4
1
3

19
,
9
2
5
,
0
6
6

5

P
r
e
-
T
a
x

R
a
t
e

o
f

R
e
t
u
r
n
lin
e

3
6
9.2
3
4
%
9.2
3
4
%
9.
2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
6

P
r
e
-
T
a
x

R
e
t
u
r
n

o
n

R
a
t
e

B
a
s
e
lin
e

4

*

l
i
n
e

5
9,
2
2
1
,
8
0
5

55
4
,
5
6
2

-

-

2,5
4
9
,
5
8
3

15
3
,
3
2
2

7

W
h
o
l
e
s
a
l
e

W
h
e
e
l
i
n
g

R
e
v
e
n
u
e
Fo
o
t
n
o
t
e

4
-

S
G

6
.
0
1
3
6
%
-

-

S
G

6
.
0
1
3
6
%

-

-

S
G

6
.
0
1
3
6
%
-

8

O
p
e
r
a
t
i
o
n

&

M
a
i
n
t
e
n
a
n
c
e
Fo
o
t
n
o
t
e

3
(9
0
2
,
1
8
5
)

SG

6
.
0
1
3
6
%

(
5
4
,
2
5
4
)

(1
6
9
,
4
6
6
)

SG

6
.
0
1
3
6
%

(
1
0
,
1
9
1
)

75
,
5
4
4

S
G

6
.
0
1
3
6
%

4
,
5
4
3

9

D
e
p
r
e
c
i
a
t
i
o
n
Fo
o
t
n
o
t
e
s

3

&

6
4,
4
3
0
,
7
4
0

SG

6
.
0
1
3
6
%

2
6
6
,
4
4
7

47
4
,
1
6
6

SG

6
.
0
1
3
6
%

2
8
,
5
1
4

1,
0
5
3
,
8
6
2

SG

6
.
0
1
3
6
%

6
3
,
3
7
5

10

P
r
o
p
e
r
t
y

T
a
x
e
s
Fo
o
t
n
o
t
e

3
-

G
P
S

5
.
7
9
7
8
%
-

-

G
P
S

5
.
7
9
7
8
%

-

-

G
P
S

5
.
7
9
7
8
%
-

11

W
i
n
d

T
a
x
Fo
o
t
n
o
t
e

3
49
,
7
2
2

S
G

6
.
0
1
3
6
%

2
,
9
9
0

2,3
0
5

S
G

6
.
0
1
3
6
%

1
3
9

12
,
5
0
0

S
G

6
.
0
1
3
6
%
75
2

12
To
t
a
l

P
l
a
n
t

R
e
v
e
n
u
e

R
e
q
u
i
r
e
m
e
n
t
su
m

o
f

l
i
n
e
s

6
-
1
1
12
,
8
0
0
,
0
8
1

76
9
,
7
4
6

30
7
,
0
0
5

18
,
4
6
2

3,
6
9
1
,
4
8
9

22
1
,
9
9
1

Ne
t

P
o
w
e
r

C
o
s
t
13

N
P
C

I
n
c
r
e
m
e
n
t
a
l

S
a
v
i
n
g
s
Fo
o
t
n
o
t
e

3
(1
,
8
3
9
,
5
8
6
)

SG

6
.
0
1
3
6
%

(
1
1
0
,
6
2
5
)

(1
6
6
,
6
9
6
)

SG

6
.
0
1
3
6
%

(
1
0
,
0
2
4
)

(4
5
8
,
5
3
6
)

SG

6
.
0
1
3
6
%

(
2
7
,
5
7
5
)

PT
C

B
e
n
e
f
i
t
14

PT
C

B
e
n
e
f
i
t
Fo
o
t
n
o
t
e

3
(1
1
,
0
6
1
,
7
2
4
)

SG

6
.
0
1
3
6
%

(
6
6
5
,
2
0
8
)

(7
2
0
,
2
1
1
)

SG

6
.
0
1
3
6
%

(
4
3
,
3
1
1
)

(2
,
9
4
4
,
6
5
9
)

SG

6
.
0
1
3
6
%

(
1
7
7
,
0
8
0
)

15

G
r
o
s
s
-

u
p

f
o
r

t
a
x
e
s
lin
e

1
4

*

(
l
i
n
e

3
4

-

1
)
(3
,
6
0
6
,
3
9
1
)

(2
1
6
,
8
7
4
)

(2
3
4
,
8
0
6
)

(1
4
,
1
2
0
)

(9
6
0
,
0
3
0
)

(5
7
,
7
3
2
)

16

P
T
C

R
e
v
e
n
u
e

R
e
q
u
i
r
e
m
e
n
t
su
m

o
f

l
i
n
e
s

1
4

a
n
d

1
5
(1
4
,
6
6
8
,
1
1
4
)

(8
8
2
,
0
8
2
)

(9
5
5
,
0
1
8
)

(5
7
,
4
3
1
)

(3
,
9
0
4
,
6
8
9
)

(2
3
4
,
8
1
2
)

17

D
e
p
r
e
c
i
a
t
i
o
n

E
x
p
e
n
s
e

A
d
j
u
s
t
m
e
n
t
Fo
o
t
n
o
t
e
s

6

&

7
(5
,
0
9
1
,
7
0
5
)

SG

6
.
0
1
3
6
%

(
3
0
6
,
1
9
5
)

(5
3
3
,
2
7
9
)

SG

6
.
0
1
3
6
%

(
3
2
,
0
6
9
)

(1
,
1
9
3
,
0
5
1
)

SG

6
.
0
1
3
6
%

(
7
1
,
7
4
5
)

18
Re
v
.

R
e
q
u
i
r
e
m
e
n
t
su
m

o
f

l
i
n
e
s

1
2
,

1
3
,

1
6
,

1
7
(8
,
7
9
9
,
3
2
4
)

(5
2
9
,
1
5
6
)

(1
,
3
4
7
,
9
8
8
)

(8
1
,
0
6
3
)

(1
,
8
6
4
,
7
8
8
)

(1
1
2
,
1
4
1
)

Ad
j
u
s
t
m
e
n
t

f
o
r

E
C
A
M

P
a
s
s
-
t
h
r
o
u
g
h
19

P
T
C

R
e
v
e
n
u
e

R
e
q
u
i
r
e
m
e
n
t
lin
e

1
6
(8
8
2
,
0
8
2
)

(5
7
,
4
3
1
)

(2
3
4
,
8
1
2
)

20

P
e
r
c
e
n
t
a
g
e

i
n
c
l
u
d
e
d

i
n

E
C
A
M

(
1
0
0
%
)

I
D

E
C
A
M

S
h
a
r
i
n
g

%
10
0
%
10
0
%
10
0
%
21

E
C
A
M

P
a
s
s
-
t
h
r
o
u
g
h
lin
e

1
9

*

l
i
n
e
2
0
(8
8
2
,
0
8
2
)

(5
7
,
4
3
1
)

(2
3
4
,
8
1
2
)

22

N
P
C

I
n
c
r
e
m
e
n
t
a
l

S
a
v
i
n
g
s
lin
e

1
3
(1
1
0
,
6
2
5
)

(1
0
,
0
2
4
)

(2
7
,
5
7
5
)

23

P
e
r
c
e
n
t
a
g
e

i
n
c
l
u
d
e
d

i
n

E
C
A
M

(
9
0
%
)
ID

E
C
A
M

S
h
a
r
i
n
g

%
90
%
90
%
90
%
24

E
C
A
M

P
a
s
s
-
t
h
r
o
u
g
h
lin
e

2
2

*

l
i
n
e

2
3
(9
9
,
5
6
3
)

(9
,
0
2
2
)

(2
4
,
8
1
7
)

25
Re
v
.

R
e
q
t
.

a
f
t
e
r

E
C
A
M

P
a
s
s
-
t
h
r
o
u
g
h
lin
e

1
8

-

l
i
n
e

2
1

-

l
i
n
e

2
4
45
2
,
4
8
8

(1
4
,
6
1
0
)

14
7
,
4
8
9

25
.
5
Au
t
h
o
r
i
z
e
d

C
a
p
p
e
d

R
e
c
o
v
e
r
y
lin
e

2
6

-

l
i
n
e

2
5
-

-

-

26
To
t
a
l

D
e
f
e
r
r
a
l

-

I
D

S
h
a
r
e
Fo
o
t
n
o
t
e

5
45
2
,
4
8
8

(1
4
,
6
1
0
)

14
7
,
4
8
9

27
Ne
t

C
u
s
t
o
m
e
r

(
B
e
n
e
f
i
t
)
su
m

o
f

l
i
n
e
s

2
1
,

2
4
,

2
6
(5
2
9
,
1
5
6
)

(8
1
,
0
6
3
)

(1
1
2
,
1
4
1
)

De
f
e
r
r
a
l

B
a
l
a
n
c
e

-

I
D

S
h
a
r
e
28

B
e
g
i
n
n
i
n
g

D
e
f
e
r
r
a
l

B
a
l
a
n
c
e
lin
e

3
2

o
f

p
r
e
v
i
o
u
s

y
e
a
r
-

-

(1
4
,
6
1
0
)

29

M
o
n
t
h
l
y

D
e
f
e
r
r
a
l
Fo
o
t
n
o
t
e

5
45
2
,
4
8
8

(1
4
,
6
1
0
)

14
7
,
4
8
9

30

D
e
f
e
r
r
a
l

C
o
l
l
e
c
t
i
o
n
Fo
o
t
n
o
t
e

3
-

-

-

31

C
a
r
r
y
i
n
g

C
h
a
r
g
e
Fo
o
t
n
o
t
e

2
-

-

-

32
En
d
i
n
g

D
e
f
e
r
r
a
l

B
a
l
a
n
c
e
su
m

o
f

l
i
n
e
s

2
8
-
3
1
45
2
,
4
8
8

(1
4
,
6
1
0
)

13
2
,
8
7
9

33

F
e
d
e
r
a
l
/
S
t
a
t
e

C
o
m
b
i
n
e
d

T
a
x

R
a
t
e
24
.
5
8
6
6
%
34

N
e
t

t
o

G
r
o
s
s

B
u
m
p

u
p

F
a
c
t
o
r
(1
/
(
1
-
t
a
x

r
a
t
e
)
)
1.3
2
6
0
35

D
e
f
e
r
r
e
d

B
a
l
a
n
c
e

C
a
r
r
y
i
n
g

C
h
a
r
g
e
Fo
o
t
n
o
t
e

2
2.0
0
%
36

P
r
e
t
a
x

R
e
t
u
r
n
Ca
s
e

N
o
.

P
A
C
-
E
-
1
5
-
0
9
9.2
3
4
%
37

P
r
o
p
e
r
t
y

T
a
x

R
a
t
e
Ra
t
e

a
s

p
e
r
c
e
n
t

o
f

n
e
t
0.7
8
%
pla
n
t

i
n

P
A
C
-
E
-
1
5
-
0
9
38

I
d
a
h
o

S
G

F
a
c
t
o
r
Ca
s
e

N
o
.

P
A
C
-
E
-
1
5
-
0
9
6.
0
1
3
6
%
39

I
d
a
h
o

G
P
S

F
a
c
t
o
r
Ca
s
e

N
o
.

P
A
C
-
E
-
1
5
-
0
9
5.
7
9
7
8
%
Fo
o
t
n
o
t
e
s
:
1)

E
n
d
i
n
g

m
o
n
t
h
l
y

c
a
p
i
t
a
l

b
a
l
a
n
c
e

o
f

t
h
e

p
r
e
v
i
o
u
s

m
o
n
t
h
.
2)

T
h
e

R
T
M

d
e
f
e
r
r
a
l

b
a
l
a
n
c
e

i
s

i
n
c
l
u
d
e
d

i
n

t
h
e

E
C
A
M

c
a
r
r
y
i
n
g

c
h
a
r
g
e
c
a
l
c
u
l
a
t
i
o
n

a
n
d

i
s

t
h
e
r
e
f
o
r
e

z
e
r
o

h
e
r
e
.
3)

E
q
u
a
l
s

t
h
e

m
o
n
t
h
l
y

s
u
m

o
f

a
l
l

p
r
o
j
e
c
t
s
4)

N
o
t

A
p
p
l
i
c
a
b
l
e

f
o
r

R
e
p
o
w
e
r
i
n
g
5)

T
h
e

R
T
M

i
s

c
a
p
p
e
d

u
n
t
i
l

t
h
e

n
e
x
t

g
e
n
e
r
a
l

r
a
t
e

c
a
s
e

s
o

t
h
a
t
,

a
f
t
e
r

t
a
k
i
n
g

i
n
t
o

a
c
c
o
u
n
t

t
h
e
win
d

r
e
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2
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p
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1
9
Rocky Mountain Power
Exhibit No. 4 Page 1 of 2 Case No. PAC-E-20-02 Witness: Steven R. McDougal
Pa
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37

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p
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38

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r

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Fo
o
t
n
o
t
e
s
:
1)

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n
d
i
n
g

m
o
n
t
h
l
y

c
a
p
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a
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a
l
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s

m
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t
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.
2)

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h
e

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d
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a
l

b
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n

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c
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c
h
a
r
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e
c
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c
u
l
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t
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a
n
d

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e
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3)

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q
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a
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s

t
h
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m
o
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t
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s
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4)

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o
t

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p
p
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c
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b
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f
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p
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5)

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h
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s

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p
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u
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t
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n
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x
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g
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c
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t
h
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win
d

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)

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7

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2
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8
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(
1
9
,
0
7
8
,
6
0
2
)

S
G

6
.
0
1
3
6
%

(
1
,
1
4
7
,
3
1
1
)

40
2
,
5
4
2
,
2
1
9

2
4
,
2
0
7
,
2
7
9

4
6
4
,
5
5
2
,
3
2
9

2
7
,
9
3
6
,
3
1
9

9.
2
3
4
%

9
.
2
3
4
%

9
.
2
3
4
%

9
.
2
3
4
%
3,0
9
7
,
5
2
9

1
8
6
,
2
7
3

3
,
5
7
4
,
6
9
2

2
1
4
,
9
6
8

-

S
G

6
.
0
1
3
6
%

-

-

S
G

6
.
0
1
3
6
%

-

(4
9
9
,
4
5
3
)

S
G

6
.
0
1
3
6
%

(
3
0
,
0
3
5
)

(
3
0
8
,
8
1
1
)

S
G

6
.
0
1
3
6
%

(
1
8
,
5
7
1
)

1,2
5
2
,
4
9
3

S
G

6
.
0
1
3
6
%

7
5
,
3
2
0

1
,
6
5
0
,
2
1
9

S
G

6
.
0
1
3
6
%

9
9
,
2
3
8

-

G
P
S

5
.
7
9
7
8
%

-

-

G
P
S

5
.
7
9
7
8
%

-

13
,
9
9
5

S
G

6
.
0
1
3
6
%

8
4
2

2
0
,
9
2
2

S
G

6
.
0
1
3
6
%

1
,
2
5
8

3,8
6
4
,
5
6
4

2
3
2
,
3
9
9

4
,
9
3
7
,
0
2
2

2
9
6
,
8
9
3

(5
1
8
,
3
7
5
)

S
G

6
.
0
1
3
6
%

(
3
1
,
1
7
3
)

(
6
9
5
,
9
7
9
)

S
G

6
.
0
1
3
6
%

(
4
1
,
8
5
3
)

(3
,
0
3
8
,
5
7
7
)

S
G

6
.
0
1
3
6
%

(
1
8
2
,
7
2
8
)

(
4
,
3
5
8
,
2
7
7
)

S
G

6
.
0
1
3
6
%

(
2
6
2
,
0
8
9
)

(9
9
0
,
6
5
0
)

(
5
9
,
5
7
4
)

(
1
,
4
2
0
,
9
0
4
)

(
8
5
,
4
4
7
)

(4
,
0
2
9
,
2
2
6
)

(
2
4
2
,
3
0
2
)

(
5
,
7
7
9
,
1
8
1
)

(
3
4
7
,
5
3
7
)

(1
,
4
3
0
,
7
3
7
)

SG

6
.
0
1
3
6
%

(
8
6
,
0
3
9
)

(1
,
9
3
4
,
6
3
8
)

SG

6
.
0
1
3
6
%

(
1
1
6
,
3
4
1
)

(2
,
1
1
3
,
7
7
4
)

(1
2
7
,
1
1
4
)

(3
,
4
7
2
,
7
7
5
)

(2
0
8
,
8
3
9
)

(2
4
2
,
3
0
2
)

(3
4
7
,
5
3
7
)

10
0
%
10
0
%
(2
4
2
,
3
0
2
)

(3
4
7
,
5
3
7
)

(3
1
,
1
7
3
)

(4
1
,
8
5
3
)

90
%
90
%
(2
8
,
0
5
6
)

(3
7
,
6
6
8
)

14
3
,
2
4
3

17
6
,
3
6
6

-

-

14
3
,
2
4
3

17
6
,
3
6
6

(1
2
7
,
1
1
4
)

(2
0
8
,
8
3
9
)

13
2
,
8
7
9

27
6
,
1
2
2

14
3
,
2
4
3

17
6
,
3
6
6

-

-

-

-

27
6
,
1
2
2

45
2
,
4
8
8

No
v
-
1
9
De
c
-
1
9
Rocky Mountain Power
Exhibit No. 4 Page 2 of 2 Case No. PAC-E-20-02 Witness: Steven R. McDougal