20210527Link Direct-Redacted.pdf

BEFORE TIM IDAHO PT]BLIC UTILITIES COMNISSION
IN THE MATTER OF THE )
APPLTCATTON OF ROCKY )
MOUNTATN POWERFOR )
AUTHORTTY TO INCREASE ITS )
RATES AND CHARGES IN IDAHO )
AI\D APPROVAL OF PROPOSED )
ELECTRTC SERVICE SCTmDULES )
AND REGULATIONS )
ROCKY MOUNTAIN POWER
CASE NO. PAC.E.2I-07
Direct Testimony of Rick T.Link
REDACTEI)
CASE NO. PAC.E-2I-07
I0day 2O2l
TABLE OT'CONIENTS
INTRODUCTION AlrD QUALTTCATTONS .....
PIIRPOSE AI.ID SIJMMARY OF TESTMONY
REPOWERING OF FOOTE CREEK I................
NEW WIND AND TRANSMISSION.....
PRYOR MOI.JNTAIN WIND PROJECT
NAUGHTON I.JNIT 3 NATI.JRAL GAS CONVERSION..........
vII. CONCLUSION...............
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L INTRODUCTION AND QUALIFICATIONS
Please state your name, business address, and position with PacifrCorp.
My name is fuckT. Link. My business address is 825 NE Multnomah Street, Suite 600,
Portland, Oregon 97232- My position is Vice President, Resource Planning and
Acquisitions. I am testifying on behalf of PacifiCorp dlbla Rocky Mountain Power
("PacifiCorp" or the "Company").
Please describe the responsibilities of your current position.
I am responsible for PacifiCorp's integrated resource plan ("IIU"';, structured
commercial business and valuation activities, and long-term load forecasts. Most
relevant to this docket, I am responsible for the economic analysis used to screen
system resource investments and for conducting competitive request for proposal
("RFP"; processes consistent with applicable state procurement rules and guidelines.
Please describe your professional experience and education.
I joined PacifiCorp in December 2003 and assumed the responsibilities of my current
position in September 2016. Over this time period, I held several analytical and
leadership positions responsible for developing long-tern commodity price forecasts,
pricing structured commercial contract opportunities and developing financial models
to evaluate resource investment opportunities, negotiating commercial contract terms,
and overseeing development of PacifiCorp's resource plans. I was responsible for
delivering PacifiCorp's 2013, 2015,2017 , and2019IRPs; have been directly involved
in several resource RFP processes; and performed economic analysis supporting a
range of resource investment opporhmities. Before joining PacifiCorp,I was an energy
and environmental economics consultant with ICF Consulting (now ICF International)
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from 1999 to 2003, where I performed electric-sector financial modeling of
environmental policies and resource investment opportunities for utility clients.
I received a Bachelor of Science degree in Environmental Science from the Ohio State
University in 1996 and a Masters of Environmental Management from Duke University
in 1999.
Have you testified in previous regulatory proceedings?
Yes. I have testified in proceedings before the Idaho Public Utilities Commission
("Commission"), the Utah Public Service Commission, the Wyoming Public Service
Commission, the Public Utility Commission of Oregon, the Washington Utilities and
Transportation Commission, and the California Public Utilities Commission.
U. PURPOSE AI\D SUMMARY OF TESTIMOI{Y
What is the purpose of your testimony?
I provide the economic analyses that support the resource decisions for several plant
investments included in the case for recovery in base rates. First, I demonstrate that the
Company's decision to repower the Foote Creek I wind facility will provide benefits to
customers. Second, I explain that the Energy Vision 2O2O ("EV 2020") project, which
includes new wind and transmission, helps meet the Company's need for new
resources. Furtheq I show that EV 2O2O wlll deliver significant customer net benefits
despite a slight increase in capital costs relative to those assumed when the Company
decided to move forward with the project. Third, PacifiCorp has acquired another wind
resource, the Pryor Mountain Wnd Project in Montana, which achieved commercial
operation inApril 2O2l.I present and explain the economic analysis that demonstrates
that this investment is reasonable and prudent. Fourth, I present economic analysis
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supporting the conversion ofNaughton Unit 3 to natural gas in 2020.
How have you organized your testimony?
I have divided my testimony into seven sections, including the introduction in Section
I and this Section II. Section III ofmy testimony addresses repowering the Foote Creek
I wind facility. I address EV 2020 in Section IV of my testimony. Section V of my
testimony addresses PacifiCorp's new Pryor Mountain Wind Project. Section VI
presents PacifiCorp's resource decisions involving Naughton Unit 3. Finally, my
conclusion is provided in Section VII.
III. REPOWERING OF FOOTE CREEK I
Please describe the scope of PacifiCorp's full repowering project.
The full wind repowering project includes l3 wind facilities, representing
approximately 1,040 megawatts ("MW") of installed wind capacity. In Case No. PAC-
E-17-06 ("Repowering Proceeding"), the Company presented the economic analysis
and received approval for 12 of the 13 wind facilities, totaling approximately
999.1 MW. The facilities approved in the Repowering Proceeding were Glenrock I,
Glenrock III, Rolling Hills, Seven Mile Hill I, Seven Mile Hill II, High Plains,
McFadden Ridge, and Dunlap in Wyomingi the Marengo I, Marengo II and Goodnoe
Hills in Washington; and the Leaning Juniper facility in Oregon.r This filing includes
the l3m facility, Foote Creek I in Wyoming, which presents similar economic benefits,
I In the Matter of the Application of Rocky Mountatn Power for Binding Rote Making Treatment for Wind
Repoweing, Case No. PAC-E-I7-06 Order No. 33954 @ec. 28,2017). The wind facilities approved for
repowering from this case are Glenrock I, Glenrock III, Rolling Hills, Seven Mile Hill I, Seven Mile Hill II,
High Plains, McFadden Ridge, Dunlap I, Marengo I, Marengo II, Goodnoe Hills and Leaning Juniper. The
Company is demonstrating that the benefits to repower the Foote Creek I facility are prudent and in the public
interest within this rate case'
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as described further below.
Is PaciliCorp seeking recovery in base rates for all 13 facilities in the repowering
project in this general rate case?
Yes. All the facilities will be in service by the rate effective date for this proceeding so
the Company is seeking to include the costs in base rates for all 13 of the repowering
facilities.
Generally, what are the benefits of the repowering project?
Repowering upgrades increase output of the wind facilities by 27 percent, extend the
operating lives of the facilities, and allow the facilities to requalify for federal
production tax credits ("PTCs") for l0 additional years.
Please describe the repowering of the Foote Creek I facitity.
As discussed in Mr. Timothy J. Hemstreet's testimony, the Foote Creek I wind facility
was originally developed more than 20 years ago. Because of its age and design,
repowering of Foote Creek I involves the removal of all existing wind turbine
equipment, including towers, foundations, and energy collection system, and
replacement with new equipment and energy collector circuits appropriately sized for
the new equipment. This is different from repowering the rest of PacifiCorp's wind
fleet, where the existing towers, foundations, and energy collection systems remained
in place and were able to accommodate more modem wind-turbine-generator
equipment.
Repowering at the Foote Creek I facility involved the replacement of 68
existing small-capacity wind turbines with 13 modern wind turbines, representing
approximately 46 MW of wind resource nameplate capacity.
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Why was Foote Creek I not included in the Repowering Proceeding and your
February 2018 economic analysis?
As discussed above, the scope of repowering the Foote Creek I facility is notably
different than the other wind facilities. Moreover, unlike the other 12 wind facilities
within the scope of the wind repowering project, PacifiCorp shared ownership of Foote
Creek I with Eugene Water & Electric Board ("EWEB"). Further differentiating Foote
Creek I from the other 12 wind facilities within the scope of the wind repowering
project, Bonneville PowerAdministration ("BPA") was purchasing 37 percent of the
output from Foote Creek I via a power-purchase agreement ("PPA") that was to
terminate inApril 2024.Takentogether, it took additional time to engage in discussions
with EWEB and BPA to determine whether the ownership structure and PPA could be
modified to facilitate repowering the Foote Creek I wind facility. Ultimately, as
Mr. Hemstreet describes in his testimony, PacifrCorp was able to clear the way for
repowering by acquiring EWEB's ownership interest, terminating the PPA with BPA,
and acquiring the master wind energy lease rights associated with the Foote Creek I
site.
When did PacifiCorp make the decision to repower Foote Creek I?
PacifiCorp made the decision to repower Foote Creek I in June 2019.
Please summarize the economic analysis that supports the prudence of this
decision.
PacifiCorp originally decided to repower Foote Creek I based on a June LL,2019,
economic analysis, indicating that repowering would produce present-value net
customer benefits ranging between $3 million and $46 million. This analysis included
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acquisition of EWEB's 21.21 percent ownership interest and termination of the PPA
with BPA. This analysis did not include acquisition of the master wind energy lease
rights associated with the Foote Creek I site.
The economic analysis was updated July 16,2019, to reflect the acquisition of
the master wind energy lease rights associated with the Foote Creek I site. This analysis
used two price-policy scenarios, representing low and medium natural gas prices and
zero and medium COz price scenarios. The price-policy scenario that pairs medium
natural gas prices with medium COz prices is referred to as the '(MM" scenario and the
price-policy scenario that pairs low natural gas prices with a zero COzprice is referred
to as the "LN" scenario. The natural gas and COz price assumptions are sufirmarized in
Figure l.
Figure 1. Price-Policy Assumptions used in the
Economic Analysis of Foote Creek I Repowering
Natural Gas Prices (S/MMBtu)CO2 Prices (S/Ton)
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My analysis shows that Foote Creek I will deliver net customer benefits in both pnce-
policy scenarios through 2050, producing present-value net customer benefits ranglng
between $6 million and $48 million.
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Please explain how you conducted your analysis.
The methodology is consistent with the approach used to perform the economic
analysis of the other 12 facilities within the scope of the wind repowering project in
Case No. PAC-E-17-06. The system value of incremental wind energy in eastern
Wyoming is calculated from trvo planning and risk ("PaR") simulations for a given
price-policy sc€ftrrio-one simulation with incremental wind energy and one
simulation without incremental wind energy. I then converted the system value of
incremental wind energy to a dollar-per-megawatt-hour value by dividing the change
in annual system costs by the change in incremental wind energy for both price-policy
scenarios through 2038. The value of wind energy is extended out through 2050 by
extrapolating the system values calculated from modeled data over the 2030-2038
timeframe. The assumed system value, expressed in dollars per megawatt-hour, is
applied to the incremental energy output associated with Foote Creek I wind
repowering.
Please provide the results of your analysis.
Foote CreekI repowering is forecasted to provide significant net benefits for customers.
Table I summarizes the present-value revenue requirement differential ("PVRR(d)")
between cases, with and without Foote Creek I repowering. A negative value indicates
the project is expected to benefit customers. This table also presents the same
information on a levelized dollar-per-megawatt-hour basis. Under the medium and low
price-policy scenarios, nominal levelized net benefits are $29lmegawatt-hour
("MWh") and $3/IrrIWh, respectively. These results are consistent with the range of the
net benefits associated with other wind repowering facilities presented in my direct
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testimony in the Repowering Proceeding.
Table 1. Net Benefits from Foote Creek I Repowering
PVRR(d) Net
@enefit)/Cost
Nom. Lev. Net
Benefit ($/NIWh of
Medium Natural Gas- Medium ($48.20)$29A4Wh
Low Natural Gas No COr ($s.60)$3A4Wh
Have you demonstrated the estimated change in nominal annual revenue
requirement from Foote Creek I repowering for the medium price-policy
scenario?
Yes. Figure 2 reflects the change in nominal revenue requirement associated with
project costs, including capital revenue requirement (i.e., depreciation, return, income
taxes, and property taxes), operations and maintenance expenses, the Wyoming wind-
production tax, and production tax credits. The project costs are netted against system
benefits as described above. Foote Creek I repowering reduces nominal revenue
requirement in all but the first three years of its depreciable life.
Figure 2. (Reduction)/Increase in Total-System Annual
Revenue Requirement from Foote Creek I Repowering
lncrease/(Dereese) ln Annual Revenue Requirement
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REDACTED
ry. NEW WTND AI\D TRANSMISSION
Please describe the new wind and transmission projects the Company is
developing as part of its EV 2020 project.
The EV 2020 project includes 1,150 MW of new wind facilities-Ekola Flats (250
MW), TB Flats I and II (500 MW), and Cedar Springs (400 MW). Ekola Flats and TB
Flats I and II were benchmarks from the 2017R RFP. The Cedar Springs facility was
offered into the 2017R RFP by a third party and is one-half build-transfer agreement
and one-half power-purchase agreement. The EV 2020 project also includes the
Aeolus-to-Bridger/Anticline line and transmission network upgrades needed to
interconnect the wind facilities. All of the wind and transmission assets have either
already come online or are expected to come online l.rl.2021.
Are you familiar with the overall cost cap established by the Commission in its
review of the CPCN for these projects?
Yes. It is my understanding that the Company was able to reach a stipulation with the
Commission's staff("Staff') regarding the CPCN, but the issue of the cost cap was left
for the Commission to determine. The Company advocated for a "soft cap," whereas
Staffwere in favor of a "hard cap." Both parties to the stipulation agreed that whatever
form of cap the Commission determined appropriate that it was a cap set to the
estimated total capital costs of the projects, or f million. In OrderNo. 34104 the
Commission found in favor of Staff and established a hard cap on costs for the new
wind and transmission projects. In Ms. Joelle R. Steward's testimony, she describes the
Commission's reasoning on finding for a hard cap in greater detail. For the purposes of
my testimony, the key element of the Commission's finding for a hard cap was that the
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Company's 'Justification [for the new wind and transmission projects] is economic m
nature, as opposed to purely reliable and safe service."2
Was the justification for the new wind and transmission projects purely economic
in nature?
No. In the CPCN proceeding, the Company showed that its 2017 IRP identified a need
for new resources. The 2Ol7 IRP included a load and resource balance that showed
PacifiCorp's summer coincident surlmer peak capacity position was short by
1,023 MW in2O2l, the first full year that the EV 2020 wind resources were projected
to be online. This short capacity position was projected to increase over the 2O-year
planning period. The capacity contribution of the proxy windresources in the 2017 IRP
preferred portfolio totaled 174 MW. As such, even after accounting for the capacity
associated with new wind resources projected to come online by the end of 2020 in the
2017 IRP preferred portfolio, the Company's 2O2l capacity position was projected to
remain shortby 849 MW.
In my supplemental rebuttal testimony from the CPCN proceeding, I described
how an updated load forecast that was finalized after the 2017 IRP was completed did
not alter the fact that the Company continued to show a need for new resources. After
accounting for that more recent and lower load forecast, PacifiCorp's summer
coincident peak position remained short by 595 MW in2O2l. This capacity deficit was
still considerably greater than the capacity contribution of the new wind facilities from
2 In the Matter of the Application of Rocky Mountain Power lbr a Certiticate of Public Convenience and
Necessity and Binding Ratemaking Treatment for New Wind and Transmission Facilities, Case No. PAC-E-17-
07, Order No. 34104, at p. l3 (Jul. 20, 2018).
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I the EV 2020 project.
After accounting for new resources procured after the 2017 IRP was filed,
including the EY2O20 wind resources, the 2019 IRP continues to show that the
Company's summer coincident peak capacity position is short by 614 MW in 2021. As
in the 2017 IRP, this short position grows over the 2019 IRP 2D-year planning period.
a. Have some of the projects exceeded the capital cost estimates that were combined
to establish the cost cap approved by the Commission in the CPCN proceeding?
A. Yes. Mr. Hemstreet discusses how the wind project costs compared to those assumed
in my economic analysis of the EY 2020 project in the CPCN proceeding and Mr. Rick
Vail discusses how the ffansmission and network upgrade costs compare to those
assumed in the CPCN proceeding. In aggregate the capital costs of EV 2020 were
within 2.2 percent of the cost estimates provided in the CPCN proceeding.
a. Despite the relatively small increase in current cost forecasts relative to the
assumed costs from the CPCN proceeding, do these projects continue to show
substantial customer benefits?
A. Yes. I applied the percent change in capital costs for the wind facilities and the
transmission and network upgrades to capture how the change in costs for those specific
line items affect the PVRR(d) presented in my supplemental rebuttal testimony from
the CPCN proceeding. Table 2 shows how the PVRR(d) results are impacted for the
low natural gas with no COz and the medium natural gas with medium COz price-policy
scenarios used in the CPCN proceeding. These results are shown for the Z0-year
stochastic mean results through 2036 and, the nominal results through 2050. No other
changes were made.
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1 Table 2. Estimated Impact of Current D,Y 2020 Capital Cost Forecasts
These results show that, while the updated capital costs reduce customer benefits by
$27 million in the stochastic mean results through 2036,the projected customer benefits
remain significant in both price-policy scenarios. In the nominal results through 2O5O,
customer benefits are reduced by $36 million. While the EV 2020 project continues to
showpotential costs in the most conservative low gas and no COz price-policy scenario,
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PaR Stochastic Mean PVRR(d) (Benefit)/Cost ($ million) through 2036
Price.Policy Scenario
PyRR(d)
CPCN
Supplemental
Rebuttal
PvRR(d)
Most Current
Forecasted
Capital Costs
Variance from
CPCN
Supplemental
Rebuttal
Low Gas, Zero COz ($143)($l l6)$27
Medium Gas, Medium
COz
($338)($3 I I)$27
Nominal PVRR(d) (Benefit/Cost ($ million) through 2050
Price.Policy Scenario
PVRR(d)
CPCN
Supplemental
Rebuttal
PYRR(d)
Most Current
Forecasted
Capital Costs
Variance from
CPCN
Supplemental
Rebuttal
Low Gas, Zero COz $ls4 $190 s36
Medium Gas, Medium
COz
(s174)($ I 38)$36
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the medium gas and medium COz price-policy scenario continues to show significant
customer benefits.
Please describe how these projects contribute to the Company's duty to provide
customers affordable and reliable service?
These assets are included in the Company's 2019IRP, and as discussed above, the EV
2020 project is important to meeting PacifiCorp's projected capacity needs for many
years to come. The EV 2020 project will generate federal PTCs, produce zero-fuel-cost
energy that will lower net power costs, generate renewable energy credits which can be
sold in the market to create additional revenues that would lower customer costs, and
help decarbonize PacifiCorp's resource portfolio, which mitigates risk associated with
potential future policies targeting greenhouse gas emissions reductions.
Is it your opinion that, despite the minor cost overruns, these projects are
necessary for the Company to continue to provide affordable and reliable service
to customers?
Yes.
Should the Commission approve the full costs of these projects, including the
amounts in excess of its previously approved cap because these projects are
necessary for the Company to provide safe and low-cost service to its customers?
Yes.
V. PRYOR MOI'NTAIN WIND PROJECT
Did you conduct the economic analysis supporting acquisition of the Pryor
Mountain Wind Project?
Yes. I prepared the economic analysis for the 240 NflW Pryor Mountain Wind Project,
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which supports PacifiCorp's decision to move forward with the project as a resource
decision that is least-cost and least-risk for customers. I completed this analysis in
September 20L9.
Please provide background on the Pryor Mountain Wind Project
In May 2019, PacifiCorp executed an agreement for the development rights associated
with the Pryor Mountain Wind Project, located in Montana. In June 2019, PacifiCorp
and Vitesse, LLC ("Vitesse") (a wholly-owned subsidiary of Facebook, Inc.) executed
an agreement for the purchase of all renewable energy credits ("RECs") generated by
Pryor Mountain over a Zl-year period under PacifiCorp's Oregon Schedule 272 -
Renewable Energy Rider Optional Bulk Purchase Option. The opportunity evolved
over a very compressed timeline, beginning in October 2018, with final terms on all
material agreements completed before September 30, 2019. In September 2019,
PacifiCorp executed the Engineering, Procurement, and Consffuction Contractor and
wind turbine supplier agreements for the project. Mr. Robert Van Engelenhoven
provides additional information about this project in his testimony.
Please describe your economic analysis of the Pryor Mountain Wind Project
I used the same methodology to perform the economic analysis of the Pryor Mountain
Wind Project as I used to perform the economic analysis of the other resources
addressed in my testimony. I relied on PaR runs with a simulation period covering the
2019-2038 timeframe. System benefits from the development of the Pryor Mountain
Wind Project, which includes sale of the associated RECs in accordance with the
Oregon Schedule 272 Agreement, are based on two PaR simulations-one with
incremental generation from the project and one without incremental generation from
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the project.
What price.policy scenarios did you use in your economic analysis?
I used the same trvo price-policy scenarios as in PacifiCorp's wind repowering analysis
for Foote Creek I-one assuming medium natural gas price and medium COz price
assumptions (the "MM" price-policy scenario) and one assuming low natural gas price
and no CO2 price assumptions (the "LN" price-policy scenario). These assumptions
are summarized in Figure l, which is presented earlier in my testimony.
Over what period did you analyze the costs and benelits of the Pryor Mountain
Wind Project?
My analysis covers the 30-year life of the asset-from 2020 through 2050.
Please explain how you developed a forecast ofthe project's benefits beyond the
2038 timeframe.
As with my economic analysis of Foote Creek I, the system value of incremental energy
is converted to a dollar-per-megawatt-hour value by dividing the reduction in annual
system costs associated with the Pryor Mountain Wind Project by the change in
incremental energy from the Pryor Mountain Wind Project. This analysis was
performed for the MM and LN price-policy scenarios through 2038. The value of
energy is extended out through 2050 by extrapolating the system values calculated from
modeled data over two different time frames-2028-2038, and, 2034-2038. The
assumed system value, expressed in dollars-per-megawatt-hour, is applied to the
incremental energy output from Pryor Mountain Wind Project. The system value of the
Pryor Mountain Wind Project is summarized for both price-policy scenarios in Figure
3.
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Figure 3. System Value Used in the Economic
Analysis of Pryor Mountain Wind Project
System Value (S/MWh)
Medium Gas/Medium CO2
System value (S/Mwh)
Low Gas/No CO2
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Please provide the results of your economic analysis.
The Pryor Mountain Wind Project is expected to provide significant net benefits for
customers. Table 3 summarizes the PVRR(d) benefits calculated from changes in
system costs through 2050. This table also presents the same information on a levelized
dollar-per-megawatt-hour basis. Under the MM price-policy scenario, net benefits
range between $69 million and $82 million. Under the LN price-policy scenario, the
PVRR(d) benefits range between a $7 million benefit and a $l million cost, depending
upon the period used to extrapolate benefi* beyond 2038. The execution of the
Schedule 272 agreement with Vitesse was a necessary milestone to ensure the Pryor
Mountain Wind Project could move forward and mitigates the risk of deteriorating
value under a variety of price and policy scenarios, including the most conservative LN
price policy scenario. Ms. Steward's testimony describes how Idaho's share of the
benefits from the Schedule 272 agreement will flow to customers. Additionally, while
not explicitly aralyzed, customer benefits would increase siguificantly with high
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natural-gas price and/or high COz price assumptions.
Table 3. Net Benelits from the Pryor Mountain Wind Project
Have you analyzed the change in annual revenue requirement associated with the
Pryor Mountain Wind Project?
Yes. Figtre 4 shows the estimated change in nominal annual revenue requirement due
to the Pryor Mountain Wnd Project for the MM and LN price-policy scenarios with
extrapolated benefits derived from modeled results over the period 2034-2038. This
figure reflects the change in nominal revenue requirement associated with Pryor
Mountain Wind Project netted against system benefits, which were calculated as
described above. Considering both the MM and LN cases illustrated below, the Pryor
Mountain Wind Project reduces nominal revenue requirement during a majority of its
depreciable life.
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Price-Policy Scenario PVRR(d) Net Nom. Lev. Benefit
MM ('28-'38 Extraoolation)s(69)so 22\
MM ('34-'38 Extraoolation)$(82)$(8.s6)
LN ('28-'38 Extrapolation)$1 s0.r2
LN ('34-' 38 Extraoolation)$(7)$(0.72)
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Revenue Requirement from the Pryor Mountain Wind Project
VI. NAUGHTON UNIT 3 NATURAL GAS CONIVERSION
Have you prepared economic analysis supporting major resource management
decisions for coal generation units included in this case?
Yes. I present economic analysis supporting the conversion of Naughton Unit 3 to
natural gas in 2020.
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Please provide background on Naughton Unit 3.
The Naughton plant is located near Kemmerer, Wyoming. For several years PacifiCorp
has been considering the conversion of Naughton Unit 3, a 280 MW coal-fired
resource, to a natural gas facility for environmental compliance purposes. The most
recent perrnit from the Wyoming Air Quality Division requires Naughton Unit 3 to
cease coal firing by January 30,2019, and that gils conversion be completed by June 24,
2021.
Did PacifiCorp end coal generation at Naughton Unit 3 in 2019?
Yes. Coal generation from Naughton Unit 3 ended on January 30,2019.
Does the 2019 IRP's preferred portfolio reflect the conversion of Naughton Unit 3
to a natural gas facility in2O2O?
Yes. In the 2019 IRP prefened portfolio, Naughton Unit 3 is converted to natural gas
in 2020, providing a low-cost reliable resource for meeting load and reliability
requirements. The 2019 tRP action plan provides that PacifiCorp will complete the gas
conversion ofNaughton Unit 3, including completion of all required regulatory notices
and filings, in2o20. The conversion will reffofit the unit to a natural gas fueled, slow
start peaking unit at 75 percent maximum continuous rating, with expected generation
of 247 MW. In his testimony, Mr. Van Engelenhoven describes the history and status
of this conversion project, which was completed by mid-2020.
In the 2019 IRP, how long does PacifiCorp assume Naughton Unit 3 will operate
as a natural gas facility?
The 2019IRP assumes Naughton 3 will operate as a natural gas facility through 2029.
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Does the conversion of Naughton 3 to natural gas benefit customers over other
alternatives?
Yes. The cost of natural gas conversion equates to approximately $12lkilowatt ("kW").
A new frame simple cycle combustion turbine located near the Naughton facility is
estimated to cost $745lkw (2018 dollars). While the assumed design life of a new gas
peaking asset is longer than the assumed life of Naughton Unit 3 once it is converted
to a gas-fueled generating unit, the upfront capital required to convert natural gas is
significantly less than the initial capital of new gas-fired generating unit. The gas
conversion of Naughton Unit 3 represents an opportunity to maintain system capacity
at a very low cost over a period in time where there are resource adequacy concems in
the region. PacifiCorp's analysis in the 2019 tRP demonstrates that, compared to early
retirement ofNaughton Unit 3, natural gas conversion has a PVRR(d) customer benefit
ranging between $62 million and $ l2 I million. The range of benefits is dependent upon
the timing and magnitude of early coal unit retirement assumptions.
Please explain the methods and assumptions used for the economic analysis in the
2019IRP.
Portfolio development cases from the 2019 IRP explored, among other things,
alternative coal unit retirement assumptions. These cases also evaluated how system
costs would be impacted if Naughton Unit 3 were converted to natural gas in 2020.
Case P-09 from the 2019 IRP is a variant of case P-03 that isolates the impact
of converting Naughton Unit 3 to a 247 MW gas-fred facility in 2020. Both cases
assume less accelerated coal retirements relative to the 2019 IRP prefened portfolio.
Through the end of 2024, the total coal capacity assumed to retire in cases P-09 and P-
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03 is 280 MW, which represents Naughton Unit 3 ending coal-fired operations in 2019.
Through the end of 2027, the total coal capacity assumed to retire in cases P-09 and P-
03 is 1,734 MW The PVRR of system costs in case P-09, where Naughton Unit 3 is
assumed to convert to a247 MW gas-fired facility in202O, is $62 million lower than
in case P-03.
Similarly, Case P-10 from the 2019 IRP is a variant of case P-04 that isolates
the impact of converting Naughton Unit 3 to a247 MW gas-fired facility inZO2O. Cases
P-10 and P-04 assume more accelerated coal retirements relative to the 2019 IRP
preferred portfolio. Through the end of 2024, the total coal capacity assumed to retire
in cases P- l0 and P-04 is I ,730 MW. Through the end of 2027 , the total coal capacity
assumed to retire in these cases is 2,568 MW. The PVRR of total system costs in case
P-10, where Naughton Unit 3 is assumed to convert to a247 MW gas-fired facility in
2020, is $121 million. As compared to the PVRR(d) between cases P-09 and P-03,
customer benefie are higher with the increase in accelerated coal retirements assumed
in cases P-10 and P-04.
As noted above, cases developed in the initial portfolio development phase of
the 2019 IRP were developed on the basis of outcomes of modeled results and
stakeholder feedback. Subsequent cases produced during the initial portfolio
development phase of the 2019 IRP were designed to evaluate cost and risk impacts of
other variables (i.e., further analysis of coal unit retirement timing and price-policy
assumptions). Based on the findings described above, subsequent cases produced in the
2019 IRP-including the case that was ultimately identified as the preferred portfolio-
retained the assumption that Naughton Unit 3 is converted to a 247 MW gas-fired
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VII. CONCLUSION
Based on your testimony, what do you recommend to the Commission?
I recommend that the Commission conclude that PacifiCorp's repowering of the Foote
Creek I wind facility and the acquisition of the Pryor Mountain Wind Project are
reasonable and prudent. I recommend that the full cost of the EV 2020 projects be
included in rates. I also recommend that the Commission approve the costs of the
resource decisions PacifiCorp has made with respect to Naughton Unit 3.
Does this conclude your direct testimony?
Yes.
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