20200702Rate Plan Application.pdf

ROCKY MOUNTAIN
FIOWER
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1407 W North Temple, Suite 330
Salt Lake City, Utah 84116
July 2,2020
VIA ELECTRONIC DELIVERY
Diane Hanian
Commission Secretary
Idaho Fublic Utilities Commission
11331 W Chinden Blvd.
Building 8 Suite 20lA
Boise,lD 83714
Re:Case No. PAC-E-20-03
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
F'OR AUTHORITY TO INCREASE ITS RATES AND CHARGES IN IDAHO
AI\D APPROVAL OF PROPOSED ELECTRIC SERVICE SCHEDULES AI\D
REGT'LATIONS
Dear Ms. Hanian:
Please find enclosed for electronic filing Rocky Mountain Power's Application in the above-
referenced matter along with a Stipulation provided as Attachment I to postpone the general
rate case and request Commission authorization for: l) an accounting order authorizing the
Company to create a regulatory asset to transfer the decommissioning and plant closure costs
of Cholla Unit No. 4 ("Unit 4") when it is retired; 2) approval of modifications to Phase II of
the settlement stipulation to implement tax reform ("the Tax Stipulation");' a16 3) approval of
ratemaking treafrnent for Pryor Mountain and Foote Creek I wind resources to match costs
with benefits, with cost recovery capped at the level of benefits until the prudence of the
resources can be determined in the next general rate case. Work papers supporting the Excess
Deferred Income Tax balances are also included.
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
I In the Matter of the Investigation into the Impact of Federal Tax Code Revisions on Utility Costs and
Ratemaking, Case No. GNR-U-18-01, Final Order No. 34431 (May 3, 2019).
Idaho Public Utilities Commission
Jaly 2,2020
Page2
Very tnrly yous,
Enclosures
CC:
Terri Carlock- Commission Staff
Randy Budge - Bayer
Ben Otto - Idaho Conservation League
Eric Olsen- Idaho Irrigation Pump€r Association
Ron Williams - PacifiCorp Idaho Indusfiial Customers
Adam Lowney (ISB#1 0456)
McDowell Rackner Gibson PC
419 SW 116 Avenue, Suite 400
Portland, OR 97205
Telephone: [phone]
Fax: [phone]
Email: [e-mail]
Emily Wegener (Pro Hac Vice)
Rocky Mountain Power
1407 W. North Temple Suite 320
salt Lake city, utah 84113
Telephone: [phone]
Cell: [phone]
emily. weeener@f acifi corp. com
Attorneysfor Rocly Mountain Power
IN THE MATTER OF THE APPLICATION
OF ROCKY MOIINTAIN POWER FOR
AUTHORITY TO INCREASE ITS RATESAND CHARGES IN IDAHO AND
APPROVAL OF PROPOSED ELECTRICSERVICE SCHEDULES AND
REGULATIONS
BEFORE THE IDAIIO PUBLIC UTILITIES COMMISSION
CASE NO. PAC.E-20-03
APPLICATION OF
ROCKY MOI]NTIAN POWER
Rocky Mountain Power, a division of PacifiCorp, ("Rocky Mountain Power" or the
"Company"), hereby applies to the Idaho Public Utilities Commission ("Commission") for:
1) an accounting order authorizing the Company to create a regulatory asset to transfer the
decommissioning and plant closure costs of Cholla Unit No. 4 ("Unit 4") when it is retired;
2) approval of modifications to Phase II of the settlement stipulation to implement tax reform
("the Tax Stipulation");l and 3) approval of ratemaking treatment for Pryor Mountain and
I In the Matter of the Investigation into the Impact of Federal Tax Code Revisions on Utility Costs and
Ratemaking, Case No. GNR-U-18-01, Final Order No. 34431 (May 3, 2019).
Page I - APPLICATION FOR ACCOUNTING ORDER
Foote Creek I wind resources to match costs with benefits, with cost recovery capped at the
level of benefits until the prudence of the resources can be determined in the next general rate
case.
ln support of this Application, Rocky Mountain Power states as follows:
I. INTRODUCTION
1. Rocky Mountain Power is authorized to do and is doing business in the state of
Idaho. The Company provides retail electric service to approximately 84,000 customers in the
state of Idaho and is subject to the jurisdiction of the Commission.
2. Rocky Mountain Power files this application pursuant to Idaho Code $61-524
and RP 52, which authorizes the Commission to prescribe the accounting to be used by public
utilities subject to its jurisdiction.
II. COMMT]NICATIONS
3. Communications regarding this Application should be addressed to:
Ted Weston
Idaho Regulatory Affairs Manager
Rocky Mountain Power
1407 WNorth Temple Suite 330
Salt Lake City, Utah 841l6
E-mail: [e-mail]
Emily Wegener
Senior Attorney
Rocky Mountain Power
1407 W North Temple, Suite 320
Salt Lake City, Utah 84116
E-mail: emily.wesener(Epacificom.com
In addition, Rocky Mountain Power requests that all data requests regarding
this application be addressed to:
Page 2 APPLICATION FOR ACCOUNTTNG ORDER
By email (preferred) datarequest(@pacificorp.com
By regular mail Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR97232
Informal inquiries related to this application may be directed to Ted Weston, [phone].
III. CASE NO. PAC.E.2O.O3 SETTLEMENT TERMS
4. On March 26, 2020, pursuant to Idaho Fublic Utilities Commission Rule of
Procedure 122, the Company filed a Notice of Intent to file a General Rate Case with the
Commission. Recognizing the impact that the COVID-I9 pandemic has on its customers and
knowing a rate increase at this time in particular would be challenging for customers, the
Company developed a rate plan that would allow it to delay filing a general rate case.
5. The Company, Commission staff, Bayer, Idaho Conservation League, Idaho
Irrigation Pumper Association, and PacifiCorp Idaho Industrial Customers, the ("Parties")
were able to reach an agreement to delay a general rate case so no change to general rates
would be effective prior to January 1,2022.In return for the Company agreeing to delay the
rate case, the Parties agreed to support the Company's application to request Commission
authorization for:
o A regulatory asset to transfer Cholla Unit 4 net book balance upon closure
of the plant in December 2020. The regulatory asset will also include other
closure-related and decommissioning costs.
o Modifications to the Phase II Settlement Stipulation in Case No. GNR-U-
18-01, on the ratemaking treatment for the 2017 Tax Cut and Jobs Act
("TCJA"). The Company may propose that the remaining balance from
Page 3 APPLICATION FOR ACCOUNTING ORDER
excess deferred income tax savings from the TCJA be retained to buy-down
the Cholla Unit 4 and be deferred to offset the January 1,2022 rate increase.
o Ratemaking treatnent for the Pryor Mountain and Foote Creek I wind
resource to match costs and benefits with a cost cap amount each year at the
benefit level. The Company may propose to include these resources in the
Resource Tracking Mechanism/Energy Cost Adjustment Mechanism
(*RTM/ECAM"), consistent with the terms agreed to in Case No. PAC-E-
17-07. Prudency will be determined during the next General Rate Case.
o There will be no change to the ECAM baseline NPC of $26.90/IvIWh (on
a sales-basis) established in PAC-E-16-12, until the base is reset in the
next general rate case.
o The Company will make its results of operations and cost of service
models developed in anticipation of filing a rate case on June 1,2020,
available to parties and the Company will respond to the parties'
reasonable data requests regarding the same.
6. The Company will provide the annual Results of Operations report and a Cost
of Service study separately to the Parties. The Results of Operations will fulfil the requirements
of Commission Order 29708 that requires the Company to file an Annual Earnings Report. On
Apil7,2020, the Company notified the Commission of its intent to utilize the Results of
Operations report from the rate case to meet this requirement. The agreement signed by the
Parties is provided as Attachment I to the Application.
Page 4 APPLICATION FOR ACCOUNTING ORDER
IV. CLOSURE OF CHOLLA UNIT NO.4
7 . The Cholla power plant consists of four units located near Joseph City, Arizona,
with a combined generating capability of 995 megawatts ("MW"). Aizona Public Service
Company ("APS") owns Cholla Units I and 3 (Unit 2 was retired in October 2015) and
operates the entire Cholla facility. PacifiCorp owns approximately 37 percent of Cholla's
common facilities and 100 percent of Unit 4, which was commissioned in 1981 with a
generating capability of 395 MW.
8. In February 2011, the Arizona Department of Environmental Quality
("ADEQ") submitted a regional haze state implementation plan ("SIP") to the Environmental
Protection Agency ("EPA"). The SIP submittal included a best available retrofit technology
("BART") analysis and determination for the need to install nitrogen oxides ("NOx") emission
controls on Cholla Unit 4. In December 2012, EPA rejected the state's BART determination
for NOx controls on the Cholla units and issued a federal implementation plan ("FIP") in place
of the SIP. The EPA's FIP required installation of low-NOx burners ("LNB"), separated over-
fire air ("SOFA"), and selective catalytic reduction ("SCR") systems for NOx control on the
Cholla units by December 5,2017.
9. In January of 2015, APS and PacifiCorp prepared and submitted a BART
reassessment for the Cholla Units to ADEQ and requested that ADEQ revise its BART analysis
due to the substantial costs associated with the compliance requirements of EPA's FIP. As part
of the reassessment, APS and PacifiCorp committed to operate LNB and SOFA on Unit 4, and
permanently cease burning coal in the Unit by April 30,2025 (with an option to convert to
natural gas combustion by July 31, 2025).In October 2015, ADEQ submitted a SIP revision
Page 5 - APPLICATION FOR ACCOUNTING ORDER
to EPA adopting the requirements of the BART reassessment, including the cease operations
or convert requirement. EPA proposed approval of the SIP revision in July of 2016, and issued
final approval in March of 2017.
10. Due to these environmental compliance rulings, PacifiCorp is required to cease
operations at Cholla Unit 4 or convert it to natural gas by April 30, 2025. However, the
Company's most recent IRPs have indicated that it was economic to pursue earlier retirement.
On December 21,2019, the Company announced its decision to retire Unit 4 by December 31,
2020. The Company's decision to initiate the process of retiring Unit 4 is supported by the
economic analysis it conducted.
I 1. PacifiCorp's 2019 IRP preferred portfolio reflects customer benefits associated
with Cholla Unit 4's retirement as early as2020. Given the unique ownership structure at the
Cholla plant, PacifiCorp's action plan committed to initiating the process of retiring Cholla
Unit 4 and removing it from service no later than January 2023 and earlier if possible.
12. PacifiCorp has initiated the process of retiring Unit 4 and anticipates being able
to achieve retirement by year-end 2020, earlier than the January 2023 timefuame initially set
forth in the 2019 IRP action plan. Further economic analysis building on the IRP studies
confirmed that early closure at the end of 2020 is expected to generate more present-value
customer benefits relative to Unit 4 continuing operation through Apil2025.
13. The IRP economic analysis relies on an assessment of system value which
compares the outcomes of the Planning and Risk model ("PaR") scenarios with a simulation
period covering the 2019 through 2025 timeframes. Consistent with the 2019 IRP preferred
portfolio, the simulations utilize a range of natural gas price and carbon policy scenarios which
Page 6 - APPLICATION FOR ACCOUNTING ORDER
incorporate aCOzprice beginningin2025 (medium natural gas price and medium COz price
assumptions (the '6MM" price-policy scenario); low natural gas price and no COz price
assumptions (the "LN" price-policy scenario), and high natural gas price and no COz price
assumptions (the "HN" price-policy scenario)). 2
14. Each price-policy scenario was run twice: once to update the 2019 preferred
portfolio where Cholla Unit 4 is assumed to retire at the end of December 2020, and the other
assuming Unit 4 continues operation through the April 2025 timeframe. Each price-policy
scenario showed an increase in net system costs when it was assumed that Unit 4 operated as
a coal-fired facility through April 30, 2025.
15. The updated economic analysis confirmed PacifiCorp's ongoing IRP analyses
and demonstrated that retirement of Unit 4 by year-end 2020 will produce net customer
benefits relative to a case where Unit 4 continues operating through April2025. This outcome
is consistent across a rarlrge of price-policy scenarios. This holds true even with incremental
costs, such as the closure-related costs, in part because PacifiCorp will no longer incur the
operating costs associated with running Unit 4.
16. Early closure at the end of 2020 is expected to generate between $96 million
and $123 million in present-value customer benefits relative to an alternative where Unit 4
continues to operate through Apnl2025. All three price-policy scenarios report an increase in
2 For both PaR runs produced under the MM price-policy scenario, price assumptions were developed from
PacifiCorp's September 2019 official forward price curve. LN and HN price-policy scenarios are derived from
third-party sources. Natural gas prices in the LN price-policy scenario do not drop below prices in the MM
scenario until 2026-beyond the early retirement study period. Consequently, the primary difference between the
MM and LN price-policy scenario is the absence of a COu price in 2025 inthe LN scenario.
Page 7 - APPLICATION FOR ACCOUNTING ORDER
net system costs when it is assumed that Unit 4 operates as a coal-fired facility through
April 30, 2025,relative to the case where it is assumed to retire at the end of 2020. Attachment
2 to this application summarizes the results of each of these price-policy scenarios.
17. Early retirement of Cholla Unit 4 will increase costs n 2020, followed by
decreased costs between}02l and2025.The2020 cost increases are primarily associated with
early termination payments of a safe harbor lease. PacifiCorp is the legal owner of Cholla Unit
4, but for income tax purposes only, PacifiCorp is treated as leasing portions of Unit 4 that are
subject to a safe harbor lease. With the early retirement, certain payments may be required to
be made by PacifiCorp to the tax lessor. The Company has estimated the high range of a
potential payment at approximately $3.3 million.
18. When PacifiCorp acquired Cholla Unit 4, the Company paid APS prepaid
availability and transmission charges in April 1994 and April 1996. The charges are related to
the construction of transmission facilities that enable an additional 150 MW of northbound
firm transmission capability on the Phoenix-Mead ffansmission line. The prepaid transmission
service cost began amortization over a fifty-year life in May 1997, and PacifiCorp began
receiving transmission credits on its bill from APS. Under the early retirement case, it is
assumed the unamortized balance would be written off.
19. Early retirement of Unit 4 by December 2020 will reduce net system costs
through the assumed April2025 retirement date. Over this period, projected generation from
Unit 4 declines, and the value of energy net of fuel costs is insufficient to offset annual fixed
operating costs.
20. As of December 3I, 2020, Unit 4's net book value is expected to be
Page 8 APPLICATION FOR ACCOUNTTNG ORDER
approximately $284 million. Because the Company anticipated filing a general rate case with
rates effective January 1,2020, Cholla Unit 4 was removed from the 2018 Depreciation study.
If the Commission approves the 2018 Depreciation stipulation depreciation of Cholla will end
December 31,2020. However, current rates include approximately $0.9 million in annual
depreciation expense. The Company provided an offset to the regulatory asset balance by that
amount to account for one additional year during 202I of Cholla depreciation expense in Idaho
rates.
21. The Company anticipates retiring Unit 4 by December 31, 2020, and requests
Commission approval to use tax benefits to buy-down the net plant balance as explained below
and transfer the remaining balances for Cholla Unit 4 from the respective FERC accounts and
record a regulatory asset in FERC account 182.3 (Other Regulatory Assets) on the date the
plant is removed from service. ldaho's share of the regulatory asset will be established based
on the system generation (*SG") allocation factor for the calendar year 2019. Table I
summarizes the estimated plant balances as of December 31,2020.
TABLE 1
Cholla Unit #4 Retirement - December3l,2020 Estimated Balances
Total Company Idaho AllocatedDescription
Gross EPIS
Accunuhted Deprec iation
CWtP
M&S
Liquitlated danrages
GE safe harbor lease terminatbn paynrnt
Savings due to O&M Eryense
Savinp due to Depreciation E:rpense
Estimated Deconrnissioning Costs
Estimated Decembe r 31, 2020 Balances
$
$
$
$
$
$
$
$
$
ss2.7 $
(268.4) $
1.8 $
6.1 $
t9.6 $
3.3 $
(27.3) $
(1s.2) $
47.3 S
319.9 $
32.7
(ls.e)
0.1
0.4
1.2
0.2
(1.6)
(0.e)
2.8
18.9$
Page 9 APPLICATION FOR ACCOUNTING ORDER
22. Since Cholla Unit 4 was not included in the 2018 depreciation rates not only
will plant balances stop being depreciated, recovery of estimated decommissioning costs will
also stop. The Company currently estimates the cost of decommissioning Cholla Unit 4 and
remediating the site to be approximately $47 million. The Cholla plant is operated by APS so
the Company isn't certain when the plant will be retired and decommissioned.
23. As further discussed below the Company recommends using some of the
available Excess Deferred Income Tax ("EDIT") benefits to buy-down or offset the Cholla
Unit No. 4 unrecovered plant balances and closure costs to mitigate future rate impact to Idaho
customers.
V. MODIFICATION OF FEDERAL TAX REFORM ACT SETTLEMENT
24. On March 5, 2019, the Company filed an all-party stipulation with the
Commission resolving how the tax savings from the federal "act to provide for reconciliation
pursuant to titles II and V of the concurrent resolution of the budget for fiscal year 2018" (the
"Tax Reform Act") for the period of 2018 through 2020 would be returned to customers.3
25. Parties to the Tax Stipulation agreed to the ratemaking treatment for the
deferred balances associated with the tax savings arising from the Tax Reform Act, which
included refunding certain tax savings through the ECAM and offsetting the 2013 incremental
depreciation expense with some of those tax savings. The Order approved the $1,141,000
deferred balance of current tax savings for the period of January l, 2018, through
May 31, 2019, that had not been returned to customers through Schedule 197. This balance
was tracked and amortized over two years ($570,500 per yeil), beginning June l, 2019,
3 In the Matter of the Investigation into the impact of Federal Tax Code Revisions on Utility Costs and
Ratemaking, Case No. GNR-U-I8-01, Order No. 34331 (May 3, 2019).
Page 10 - APPLICATION FORACCOUNTING ORDER
through the ECAM.
26. The Tax Reform Act resulted in ldaho-allocated EDIT composed of the
following amounts, grossed-up for taxes: l) Protected property-related EDIT of
$105,924,6044, with estimated arurual amortizations through the average rate assumption
method (ooAItAM") of $2,564,410 in 2018, $2,352,309 in2019, and $2,306,632 rn2020; and
Non-protected property and non-property EDIT of $14,883,505.5
27. During 2019 the Company determined that it was necessary to use a different
method to amortize the protected EDIT balances. The Tax Stipulation was based on the
ARAM, but on further review the Company determined that it didn't have the necessary
records to support that accounting method and had to switch to the Reverse South Georgia
Method ("RSGM"). The RSGM did not change the balances available but it did modifu the
annual amortization of those balances as compared to the ARAM.
28. The Tax Stipulation included an estimate of the annual protected property EDIT
in the amount of $2,564,364 for 2018, $2,352,309 for 2019 and $2,306,632 for 2020,less the
associated rate base offset, that would be refunded to retail customers through a cents per
kilowatt-hour credit netted against the ECAM rate.
29. Lastly, the Tax Stipulation provided that the non-protected and non-property
EDIT, arising from the Tax Reform Act would be amortized over seven years, approximately
$2,126,215 annually less the rate base offset, and used to offset the 2013 incremental
depreciation expense through the ECAM, not subject to the sharing band and until the rate
4 The protected property EDIT is $79,881,345, or $105,924,604 grossed up for taxes.
5 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.
Page I I - APPLICATION FOR ACCOUNTING ORDER
effective date in the next general rate case.
30. In the Tax Stipulation the parties agreed they could propose to change the
seven-year amortization period for the unamortized portion of the non-protected property and
non-property EDIT balance in the next Idaho general rate case. In the agreement with parties
to not file a general rate case n2020, parties agreed the Company could propose modifications
to the Tax Stipulation outside of a general rate case.6
31. Under the RSGM protected-property EDIT was $4,571,790 for 2018 and
$4,602,855 for 2019, increasing the Tax Savings amortization of protected-property EDIT by
$4,257 ,972 over the two-year period. The Company also identified the need to reclassiff EDIT
between protected property and non-protected and transfened$2,964,471 from the protected
property to the non-protected EDIT balance which increased the unamortized balance to
$17,847,973 for non-protected EDIT benefits.
32. Combining the increased amortization of protected property under the RSGM
for 2018 and 2019 with the 2020 EDIT amortization that hasn't been returned to customers
and the unamortized non-protected EDIT balance produces a total EDIT balance available to
customers of $24,305,381. Table 2 is a summary of the EDIT savings available to customers.
Work papers supporting these amounts are provided with the Application.
6 See Attachment I
Page 12 - APPLICATION FORACCOUNTING ORDER
Table 2
Tax Reform Act Benefits 2018 2019 2020 Total
Protected EDIT Deferral - RSGM
Protected EDIT Deftrral - ARAM
$ (4,571,790) $ (4,602,855) $ (6,451,861) $(15,626,506)$ 2.564.364 $ 2.3s2.309 $ 4.916,673
$ (2,007,426) $ (2,250,546) $ (6,451,861) $(10,709,833)
NonProtected EDIT - Estimate
Amortization $2,126,215$2,126,215
NonProtected EDIT - Reclassification
Balance December 31, 2O2O
$(14,883,504)
$ 4,252,430
$ (2,964,474)
$ (13,595,548)
Tax Reform Act Benefits Available December3l,2O2O $ (24,305,381)
33. The Company requests authorization to use approximately $15.9 million of the
$24.3 million EDIT Tax Reform Act benefits to pay off the Cholla Unit No. 4 unrecovered
balances. The Cholla regulatory asset will be used to transfer the GE Safe Harbor lease
payment and track actual decommissioning costs. The Company also requests authorization to
cease the refund of tax savings in the ECAM filing in 2021 inorder to use any remaining EDIT
savings as of December 31, 2021 to mitigate the rate impact from the 2021 general rate case.
As of December 31,2020 this results in approximately $8.4 million in deferred Tax Reform
Act benefits available to use to offset the next general rate case increase. The current refund
of $7.6 million in current tax savings on Schedule 197 would continue until new rates are
effective from the next general rate case.
34. The Company's decision to retire Cholla Unit 4 and use EDIT Tax Reform Act
benefits to buy-down the remaining plant balance accelerates the availability of Idaho-
allocated Cholla EDIT benefits as reflected in the 2020 Protected EDIT Deferral amount. Table
3 summarizes the items the Tax Benefit buy-down would be used for and the items tracked in
the regulatory asset.
Page 13 - APPLICATIONFORACCOUNTINGORDER
TABLE 3
VI. RATEMAKING FOR PRYOR MOUNTAIN AND FOOTE CREEK I
35. The Company requests the Pryor Mountain and Foote Creek I wind resources
be included in the RTM authorized by the Commission for other Company wind projects in
Order No. 34104 to match the costs with the benefits these resources produce for customers.T
Consistent with the stipulation8 for ratemaking treatment approved in that proceeding, the costs
would be capped at the benefit levels passed back through the ECAM so customers would not
see a net cost for these projects through the RTM or ECAM. Net costs, if any, would be
deferred for later recovery to be determined in the next general rate case when a full prudence
7 In the Matter of the Application of Roclg, Mountain Powerfor a Certificate of Public Convenience and Necessity
and Binding Ratemaking Treatment for new Wind and Transmission Facilities. Case No. PAC-E-17-07, Order
No. 34104 (July 20, 2018).
8 The Stipulating Parties agree that the Company will maintain a cap on the annual total cost of the Stipulated
Projects not to exceed the annual project benefits in the ECAM and RIM. Costs that are passed on to customers
through the RIM, before the next general rate case, will be capped at the level of benefits that will flow through
the ECAM, as such, on a combined basis, the ECAM and the RTM will not result in a net cost to customers
associated with the Stipulated Projects. Any costs above this cap will be deferred as a regulatory asset for
recovery to be set in the next general rate case. Case No. PAC-E-17-07, paragraph l4 ofthe Stipulation.
Cholla Unit #4 Tax Brry-Down / Regulatory Asset
I)escription Total Companv Idaho Allocated
Gross EPIS
Acc tnnulated Depre c iation
CWIP
M&S
Litluilated danrages
Savings dtre to O&M E>perse
Savings due to Depreciation Eryense
Estimated Tax Benefrt Buy-Doum
Transfenrcd to Regulatory Asset
GE saft harbor lease termination payment
Estimated Decornrnissioning Costs
Estimated Regulatory Asset Balance
$
$
$
$
$
S
$
ss2.7 s
(268.4) $
1.8 $
6.1 s
19.6 $
(27.3) $
(1s.2) $
32.7
(r s.e)
0.1
o.4
1.2
(1.6)
(0.9)
$
3.0$
269.3 $
3.3 $
47.3 $
50.6 $
15.9
$
$
0.2
2.8
Page 14 - APPLICATION FORACCOUNTING ORDER
review for these resources is expected to occur.
36. The Pryor Mountain Wind Project will have a nameplate capacity of 240 MW
and is located in Carbon County, Montana, approximately 60 miles south of Billings, Montana.
The project consists of 57 Vestas Model Vl10-2.0 MW safe harbor, 2l Vestas Model Vl10-
2.2lvIW safe harbor, four General Electric Model 2.3-116 MW safe harbor, and.32 Vestas
model Yll0-2.2 MW follow-on wind turbine generators ("WTGs").
37. The Pryor Mountain Wind Project is similar to the new wind facilities included
in the Energy Vision 2020 Project. The time-sensitive nature of the Pryor Mountain Wind
Project is primarily driven by the pending phase-out of the federal Production Tax Credits
("PTCs") for new wind resources. With an in-service date before the end of 2021, the Pryor
Mountain Wind Project will be eligible for the full 100 percent PTCs rate. The Company's
acquisition and implementation plan for the Pryor Mountain Wind Project is designed to meet
the year-end2020 in-service schedule and provide customers the fulI economic benefit of the
project.
38. Through its wind repowering efforts, PacifiCorp is leveraging past investments
in its wind fleet and enhancing the future value of these resources for the benefit of its
customers. The Company's repowering efforts now include all of its owned wind resources,
including the Foote Creek I facility that was not subject to the Commission's prior ordere
related to repowering. By taking advantage of the unique opportunity to repower this facility,
the Company is able to provide efficiency and reliability improvements in wind generation
e In the Matter of the Application of RoclE Mountain Powerfor Binding Ratemaking Treatmentfor Wind
Repowering, Case No. PAC-E- I 7-06, Order No. 33954 @ec. 28, 2017).
Page 15 - APPLICATION FORACCOLINTING ORDER
technology to its customers, and return the entirety of its wind fleet to like-new condition, all
while enhancing performance, reducing ongoing maintenance expenditures, and reducing
customer costs.
39. Foote Creek I, the Company's oldest wind facility, began commercial operation
in April 1999. The facility served as a demonstration project to evaluate the feasibility of
utility-scale wind energy. The facility was developed in parfirership with the Eugene Water &
Electric Board ("EWEB") and the Bonneville Power Administration ("BPA"). As developed,
Foote Creek I was co-owned by EWEB's21,.21percent ownership and PacifiCorp's 78.79
percent ownership, with BPA taking 37 percent of the facility's output through a 25-year cost-
based Purchase Power Agreement ("PPA"). As the first utility-scale wind energy project in
Wyoming, Foote Creek I was sited at one of the most favorable wind sites in the United States
and enjoys the highest wind speeds of any of the Company's wind projects. Unlike the
remainder of the facilities the Company is repowering, the Foote Creek I project is unique in
that it was co-owned and also had a third-party PPA associated with the resource.
40. The Foote Creek I facility currently consists of 68 turbines, each with a 600-
kilowatt generating capacity, a rotor diameter of 42 meters, and towers that support a 40 meter
hub height. Although employing the latest technology when originally installed, the existing
turbines are costly to operate and maintain relative to the Company's more modem turbines
that have a much higher nameplate capacity, larger rotor diameters, and taller towers. Since
the maintenance requirernents for these smaller turbines are similar to those of larger turbines,
the operation and maintenance costs of the Foote Creek I facility are the highest of all of the
Company-owned wind resources on a per-MW basis.
Page 16 - APPLICATION FOR ACCOUNTING ORDER
41. The costs associated with continued operation of the existing turbines at Foote
Creek I for both the Company and EWEB would have increased after the expiration of the
BPA PPA in April 2024 srnce 37 percent of these costs would no longer be covered through
the cost-based PPA. Similarly, BPA was required to take higher cost energy from the project
until the PPA expired. For these reasons, PacifiCorp, EWEB, and BPA were all motivated to
explore whether the existing Foote Creek I contract could be unwound in order to achieve an
outcome more favorable to customers as compared to continuing to operate the facility through
its planned 30-year asset life. Repowering the facility presented the opportunity to realize this
outcome for all customers.
42. Repowering Foote Creek I re-qualifies it for PTCs, which are benefits that are
passed through to customers. Additionally, repowering increases the amount of zero-fuel-cost
energy produced from the repowered facilities given the much larger energy production
capability of the new turbines. Further, by replacing older WTG equipment, which is subject
to more failure and maintenance issues than newer equipment, repowering will reduce
PacifiCorp's ongoing operating costs. Finally, repowering the wind facilities with new WTG
equipment will extend the useful lives of the facilities by up to 21 years, creating substantial
energy and capacity benefits for customers in the future when this wind facility would
otherwise have been retired from service.
43. Repowering Foote Creek I will lower the ongoing capital costs of operating the
facility. PacifiCorp's turbine-supply contract for repowering, consistent with wind industry
standards for new equipment, includes a two-year warranty on the new equipment. This will
reduce capital costs associated with replacing or refurbishing turbine components currently in
Page 17 - APPLICATION FOR ACCOUNTING ORDER
servrce.
44. Repowering will also result in more certainty related to ongoing O&M costs of
the facility. PacifiCorp will operate the repowered facility under a full service agreement with
the turbine equipment supplier who will be responsible for operating and maintaining the new
turbines for a fixed cost while guaranteeing availability of the turbines. Under this agreement,
failure to meet the guaranteed availability, if not the result of an excusable event defined in the
contract, will result in the payment of liquidated damages to the Company. Customers will
benefit by having operation and maintenance costs fixed for the term of the agreement. Thus,
there is greater cost certainty related to the run-rate capital expenditures and operation and
maintenance costs as compared to continued operation of older turbines that are near the end
of their useful life.
45. The Company's wind repowering efforts leverage past investments in
PacifiCorp's wind fleet to enhance the future value of these resources for the benefit of its
customers. By taking advantage of the unique opportunity to repower this facility, the
Company is able to deliver its customers efficiency and reliability improvements in wind
generation technology, extend its life by returning the wind fleet to like-new condition, all
while enhancing performance, reducing ongoing maintenance expenditures, and re-qualiffing
the facility for PTCs - all of which reduces customers' rates.
VIL MODIFIED PROCEDURE
46. Rocky Mountain Power believes that a hearing is not necessary to consider the
issues presented herein and respectfully requests that this Application be processed under
Modified Procedure, i.e., by written submissions rather than by hearing, in accordance with
Page 18 - APPLICATION FOR ACCOUNTING ORDER
Idaho Public Utilities Commission Rules of Procedure20l - 204.
vlu. REQUEST FOR RELTEF
WHEREFORE, Rocky Mountain Power respectfully requests that the Commission
issue an order authoizng the Company to: 1) establish a regulatory asset to transfer and
recover the decommissioning and closure costs of Cholla Unit 4 when it is retired; 2) approve
modifications to Phase II of the Tax Reform Stipulation authorizing the Company to use those
funds to buy-down the Cholla net plant balances and offset the 2021 rate increase; and 3)
approve RTM ratemaking treatment for Pryor Mountain and Foote Creek I wind resources to
match costs with benefits.
DATED: Ju1y2,2020
Respectfully submitted by,
ROCKY MOUNTATN POWER
Emily L. Wegener Qtro hac vice)
1407 West North Temple, Suite 320
Salt Lake City, Utah 841l6
Telephone No. [phone]
Mobile No. (385) 227 -247 6
Email: [e-mail]
Attorneyfor Roclqt Mountain Power
Page 19 - APPLICATION FOR ACCOUNTING ORDER
Attachment 1
Rocky Mountain Power - Sefflement Terms
Rocky Mountain Power
Case No. PAC-E-20-03 Settlement Terms
May28,2020
Sefrlement Terms in lieu of Idaho General Rate Cose
The Company re*ognizes the impact that the COVID-I9 pandemic has on its customers
and is ready to face the challenges it presents with its Idaho customers and communities. The
Companyhas suspended residential disconnections fornon-payments and is helping accommodate
all customers with payment plans. Recognizing any rate increase at this time in particular can be
challenging for customers in light of the economic impact of the COVID-I9 public health
emergency, the Company is proposing two ratemaking measures to delay a general rate increase.
In consideration of COVID-l9 and the financial impact to customers the Parties agree to
the following approach in lieu of the Company filing a general rate case June l, 2020:
l. Case No. PAC-E-1&08 - 2018 Deoreciation Studr':
o The Parties will support adding language in the pending Depreciation stipulation
recommending that the Commission authoizethe Company to create a regulatory
asset to defer the incremental annual depreciation expense of $13,940,303.
o The deferral would be $1,161,692 per month ($13,940,303 / 12) beginning January
2021 until the incrernental depreciation expense is included in base rates.
o No carrying charge will apply to the regulatory asset until the next general rate case.
A carrying charge or rate base treatment and period for amortization of the balance
will be determined in the next general rate case and begin at the rate effective date.
o The depreciation expense tacked in the RTM will be calculated using the
depreciation rates approved in Case No. PAC-E-13-02, Order No. 32926, to
eliminate any double countingwith the $13,940,303.
o The Company will stop deferring incremental depreciation expense from PAC-E-
13-02 currently recovered in the ECAM effective December 31,2020, because this
incremental depreciation expense is included in the $13,940,303 referenced above.
o Parties agree to support establishment of Phase 2 in Case No. PAC-E-18-08 to
evaluate the incremental Decommissioning costs filed with the Commission on
January 17,2020 and March 16,2020. The Idaho Parties will make all reasonable
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Settlement Document
efforts to complete Phase 2 in time to allow the Commission to issue a final order
before December 3 l, 2020.
o Ratemaking treatment for the incremental decommissioning costs will be
determined in Phase 2, including potentially incorporating any approved
inqemental expense into depreciation rates and the depreciation deferral for 2021.
2. Case No PAC-E-20-03 RMP NOI to File a General Rate 9=g_sg:.
o The Company agrees not to file a general rate case for rates to be effective prior to
January 1,2022.
o The Parties agree that in lieu ofa general rate case with rates to be effective January
1,2021, the Company will file for an accounting order to authorize:
o A regulatory asset to transfer Cholla Unit 4 net book balance upon closure
of the plant in December 2020. The regulatory asset will include other
closure-related and decommissioning costs.
o Modifications to the Phase II Settlement Stipulation in Case No. GNR-U-
18-01, on the ratemaking treatnent for the 2017 Tax Cut and Jobs Act
(TCJA). The Company may propose that the remaining balance firom
excess defened income tax savihgs from the TCJA be retained to buy-down
the Cholla Unit 4 and be deferred to ofhet the January 1,2022 rate increase.
o Ratemaking treatment for the Pryor Mountain wind resource and the
repowering of Foote Creek I to match costs and benefits with a cost cap
amount each year at the benefit level. The Company may propose to include
these resources in the RTM/ECAM, consistent with the terms agreed to in
Case No. PAC-E-17-07. Prudency will be determined during the next
General Rate Case.
o There will be no change to the ECAM baseline NPC of $26.9044Wh (on a sales-
basis) established in PAC-E-16-12, until the base is reset in the next general rate
case.
o The Company will make its results of operations and cost of seruice models
developed in anticipation of filing a rate case on June 1,2020, available to parties
and the Company will respond to the parties' reasonable data requests regarding
the same.
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