20240531Direct R. Link.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-24-04
OF ROCKY MOUNTAIN POWER FOR )
AUTHORITY TO INCREASE ITS RATES ) DIRECT TESTIMONY OF
AND CHARGES IN IDAHO AND ) Rick T. Link
APPROVAL OF PROPOSED )
ELECTRIC SERVICE SCHEDULES AND )
REGULATIONS )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-24-04
May 2024

1 I . INTRODUCTION AND QUALIFICATIONS
2 Q. Please state your name, business address, and present
3 position with PacifiCorp d/b/a Rocky Mountain Power (the
4 "Company") .
5 A. My name is Rick T . Link. My business address is 825 NE
6 Multnomah Street, Suite 600, Portland, Oregon 97232 . My
7 position is Senior Vice President, Resource Planning and
8 Procurement .
9 Q. Please describe the responsibilities of your current
10 position.
11 A. I am responsible for PacifiCorp' s resource planning and
12 procurement functions, which includes the integrated
13 resource plan ("IRP") and structured commercial business
14 and valuation activities . Most relevant to this docket,
15 I am responsible for the economic analysis used to screen
16 system resource investments and conducting competitive
17 request for proposal ("RFP") processes, consistent with
18 applicable state procurement rules and guidelines .
19 Q. Briefly describe your education and professional
20 experience.
21 A. I joined PacifiCorp in December 2003 and assumed the
22 responsibilities of my current position in September
23 2021 . I have held several analytical and leadership
24 positions responsible for developing long-term commodity
25 price forecasts, pricing structured commercial contract
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1 opportunities and developing financial models to
2 evaluate resource investment opportunities, negotiating
3 commercial contract terms, and overseeing development of
4 PacifiCorp' s resource plans . I have been heavily
5 involved in developing PacifiCorp' s IRPs since 2013;
6 have been directly involved in several resource RFP
7 processes; and performed economic analysis supporting a
8 range of resource and transmission investment
9 opportunities . Before joining PacifiCorp, I was an
10 energy and environmental economics consultant with ICF
11 Consulting (now ICF International) from 1999 to 2003,
12 where I performed electric-sector financial modeling of
13 environmental policies and resource investment
14 opportunities for utility clients . I received a Bachelor
15 of Science degree in Environmental Science from the Ohio
16 State University in 1996 and a Master of Environmental
17 Management from Duke University in 1999 .
18 Q. Have you testified in previous regulatory proceedings?
19 A. Yes . I have testified in proceedings before the Idaho
20 Public Utilities Commission ("Commission") , the Public
21 Service Commission of Utah ("Utah Commission") , the
22 California Public Utilities Commission, the Public
23 Utility Commission of Oregon ("Oregon Commission") , the
24 Washington Utilities and Transportation Commission, and
25 the Wyoming Public Service Commission.
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1 II . PURPOSE OF TESTIMONY
2 Q. What is the purpose of your direct testimony?
3 A. I provide economic analysis that supports PacifiCorp' s
4 decision to build two transmission projects, including:
5 (1) Gateway South, a 414-mile, 500-kilovolt ("kV")
6 overhead transmission line between the Aeolus
7 Substation, near Medicine Bow, Wyoming, to the Clover
8 substation near Mona, Utah; and (2) Gateway West Segment
9 D. 1, a 59-mile, 230-kV transmission line from the
10 Shirley Basin substation in southeastern Wyoming to the
11 Windstar substation near Glenrock, Wyoming and the
12 accompanying ancillary facilities (collectively, the
13 "Transmission Projects") .
14 I also summarize PacifiCorp' s assessment of the
15 projects from the 2021 IRP and 2021 IRP update, provide
16 background on PacifiCorp' s 2020 All-Source Request for
17 Proposal ("2020AS RFP") to solicit new resources,
18 including those enabled by the Transmission Projects,
19 and discuss customer benefits that result from the
20 projects .
21 For details regarding Gateway South and Gateway
22 West, please refer to the direct testimony of Company
23 witness Richard A. Vail .
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1 Q. Please summarize your testimony for the Transmission
2 Projects .
3 A. The 2021 IRP confirmed that the Transmission Projects
4 remain a key transmission investment that will enable
5 the procurement of low-cost wind facilities to reliably
6 meet the Company' s need for additional resources . These
7 resources are expected to produce significant customer
8 benefits . This includes ensuring that all new wind
9 resources from the 2020AS RFP that depend on the
10 Transmission Projects : (1) qualify for 110 percent of
11 available federal production tax credits ("PTC") ,
12 further reducing the cost of these resources (that
13 already have no fuel costs or emissions) relative to
14 other resource options; and (2) generate renewable-
15 energy certificates ("RECs") that can be used to offset
16 revenue requirements where appropriate.
17 As discussed by Company witness Vail, the
18 Transmission Projects will also provide critical voltage
19 support to the Wyoming transmission network, improve
20 overall reliability of the transmission system, and
21 enhance PacifiCorp' s ability to comply with mandated
22 reliability and performance standards . Most importantly,
23 the Transmission Projects ensure the Company will meet
24 its obligations to reliably accommodate nearly 2, 500
25 megawatts ("MW") of interconnection and transmission
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1 service requests, including 13 executed interconnection
2 service and transmission service agreements for over
3 1, 600 MW of new wind resources . This includes 500 MW of
4 firm point-to-point ("PTP") transmission service to a
5 third-party transmission customer under the Federal
6 Energy Regulatory Commission' s ("FERC") jurisdiction.
7 Moreover, the Transmission Projects create additional
8 opportunity to increase transfer capability with the
9 construction of additional segments of the Energy
10 Gateway project.
11 Q. Please summarize your economic analysis of the
12 Transmission Projects .
13 A. My economic analysis demonstrates that the Transmission
14 Projects are necessary and in the public interest. In my
15 analyses, I reviewed the change in revenue requirement
16 due to the Transmission Projects, and associated
17 resources that are dependent upon the Transmission
18 Projects, using the Company' s IRP modeling tool across
19 five different scenarios that pair varying natural gas
20 price assumptions with varying carbon dioxide ("CO2")
21 policy assumptions (price-policy scenarios) .
22 For each price-policy scenario, I calculated the
23 change in system revenue requirement between cases with
24 and without the Transmission Projects through 2040,
25 where capital revenue requirement is levelized. These
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1 price-policy scenarios include :
2 • Medium natural gas prices paired with medium CO2
3 prices ("MM") ;
4 • Medium natural gas prices without a CO2 price
5 ("MN") ;
6 • High natural gas prices paired with high CO2 prices
V ("HH") ;
8 • Low natural gas prices without a CO2 price ("LN") ;
9 and
10 • The Social Cost of Greenhouse Gas ("SCGHG") .
11 These analyses confirm that the Transmission
12 Projects are expected to generate customer benefits .
13 Under the MM price-policy scenario, the present-value
14 revenue requirement differential ("PVRR (d) ") customer
15 benefit when using the most conservative assumptions for
16 unavoidable transmission is $128 million, while the
17 risk-adjusted PVRR (d) benefits are $260 million .
18 When assuming the cost of the Transmission Projects
19 are unavoidable, the PVRR (d) under the MM price-policy
20 scenario yields a $610 million customer benefit and a
21 risk-adjusted benefit of $742 million. Conservatively,
22 these benefits do not assign any value to the RECs that
23 will be generated by new resources made available due to
24 the Transmission Projects . The risk-adjusted results
25 indicate that the Transmission Projects add significant
26 risk mitigation benefits associated with volatility in
27 market prices, loads, hydroelectric generation, and
28 unplanned outages .
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1 Q. Did you develop an additional calculation to measure how
2 changes in cost might influence customer benefits?
3 A. Yes . I calculated how changes in resource and
4 transmission cost assumptions would impact customer
5 benefits . My review of resource costs show that assumed
6 initial capital costs would need to increase by 32
7 percent to erode the customer benefits from the MM price-
8 policy scenario. Similarly, the cost of the Transmission
9 Projects would need to increase by 50 percent to erode
10 the benefits from the MM price-policy scenario. These
11 results show that the projected customer benefits are
12 robust, and that they persist even if the resource costs
13 and transmission costs far exceed the estimates that
14 were available when we committed to move forward with
15 the Transmission Projects .
16 Q. Did you continue to review the economic analysis after
17 the Company began construction of the Transmission
18 Projects?
19 A. Yes . I revisited the economic analysis as we were
20 finalizing contracts for the wind resources dependent
21 upon the Transmission Projects . This update accounted
22 for, among other things, higher costs, higher PTC values
23 associated with the passage of the Inflation Reduction
24 Act ("IRA") , and the potential impacts of the Ozone
25 Transport Rule ("OTR") . This review showed risk-adjusted
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1 customer benefits totaling $247 million in the MM price-
2 policy scenario .
3 Q. Do you believe your testimony supports the prudency of
4 the Company' s investments for both Transmission
5 Projects?
6 A. Yes .
7 III . GATEWAY SOUTH AND GATEWAY WEST SEGMENT D. 1
8 Q. Can you please provide an overview of this section of
9 your testimony?
10 A. Yes . I provide an overview of the Company' s resource
11 needs from the 2021 IRP and procurement efforts in 2020AS
12 RFP, detail the Company' s price-policy assumptions and
13 modeling methodologies that were used to analyze the
14 Transmission Projects, discuss results from these
15 analyses, and provide additional post-construction
16 economic review.
17 A. Resource Need
18 Q. Did the 2021 IRP identify the need for additional
19 resources to serve PacifiCorp' s customers?
20 A. Yes . The primary focus of the 2021 IRP is to forecast
21 the need for resources and then evaluate different ways
22 to meet that need over time . In the 2021 IRP, the
23 assessment of resource need is presented in Volume I,
24 Chapter 6 . The load-and-resource balance shows that
25 PacifiCorp has a capacity deficit in all years of the
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1 planning horizon—starting at 1, 071 MW in 2021 and
2 increasing to over 6, 600 MW by 2040 . 1 In 2025, the first
3 full year that the Transmission Projects will be online,
4 the resource need is 1, 627 MW. Consistent with prior
5 IRPs, all resource portfolios produced in the 2021 IRP
6 that were considered as candidates for the preferred
7 portfolio contain new supply-side, demand-side, and
8 market resources to fill this need.
9 This need has continued to increase due to
10 increases in forecasted load. The 2021 IRP Update shows
11 a resource need in all years of the planning horizon-
12 starting at 1, 584 MW in 2022 and increasing to 6, 755 MW
13 in 2040 .2 In 2025, the first full year that the
14 Transmission Projects will be online, the resource need
15 is 1, 867 MW, an increase of 240 MW or approximately 15
16 percent from the 2021 IRP. The higher load reflected in
17 the 2021 IRP Update approaches the level analyzed in the
18 high-load sensitivity conducted in the 2021 IRP. 3
19 Since the Company initiated construction of the
20 Transmission Projects, national tariff policies, global
21 supply-chain issues, and inflationary pressures
22 eliminated some bids on the 2020AS RFP final shortlist.
23 Consequently, PacifiCorp' s procurement was reduced by
1 PacifiCorp 2021 Integrated Resource Plan, Vol. I, Table 6.12.
z Id. at Table 4.2.
s Id. at 2.
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1 902 MW of solar resources and 497 MW of battery storage
2 resources . Additional resources are needed to reduce
3 PacifiCorp' s reliance on the market .
4 Q. Why is it important to reduce PacifiCorp' s reliance on
5 market purchases?
6 A. There is a strong consensus that the western United
7 States will face an increasing capacity deficit in the
8 near future .4 For example, in December 2020, the Western
9 Electricity Coordinating Council ("WECC") issued its
10 Western Assessment of Resource Adequacy Report
11 ("WARA") .5 The WARA was developed based on data collected
12 from balancing authorities describing their own demand
13 and supply projections over the next 10 years . The WARA
14 evaluated resource adequacy among six subregions under
15 two scenarios—one with and without imports to the
16 subregion. PacifiCorp serves load in three of these
17 subregions—Northwest Power Pool Northwest ("NWPP-NW") ,
18 Northwest Power Pool Northeast ("NWPP-NE") , and
19 Northwest Power Pool Central ("NWPP-C") . For each of
20 these scenarios, the WARA considered variations of
21 supply. The most conservative assumes availability of
22 only existing resources, and the most liberal includes
4 Id. at Vol. I, Ch. 5.
5 The Western Assessment of Resource Adequacy Report, Western
Electricity Coordinating Council (Dec. 18, 2020)
(https://www.wecc.org/Administrative/Western%20Assessment%20of%2OResour
ce%20Adequacy%2OReport%2020201218.pdf) .
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1 availability of new resources under construction, those
2 expected to come online, and those under development.
3 The study found that for each of the three subregions in
4 which PacifiCorp serves load, imports are needed to meet
5 a one-day in 10-year planning threshold. The WARA shows
6 that the NWPP-NW subregion would fall short of the
7 planning threshold in 194 hours (under the most liberal
8 supply case) to 208 hours (assuming availability of only
9 existing resources) without imports . In the NWPP-NE and
10 NWPP-C subregions, the study found that planning
11 threshold is not met in 4, 200 hours without imports .
12 These findings highlight that there are real
13 reliability risks associated with relying on supply
14 being available in the market to meet projected load
15 obligations . In addition, WECC' s 2021 WARA issued
16 December 2021 further concludes that not only are
17 resource adequacy risks to reliability likely to
18 increase over the next 10 years, it recommends entities
19 take immediate action to mitigate near-term risks and
20 prevent long-term risks . The 2021 WARA projects that "by
21 2025, each subregion, and the interconnection, will be
22 unable to meet the 99 . 98o-one-day-in-ten-year-
23 reliability threshold. "6
6 2021 Western Assessment of Resource Adequacy Report, Western
Electricity Coordinating Council (Dec. 17, 2021)
(https://www.wecc.org/Administrative/WARAo202021.pdf) .
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1 Q. Are there any other third-party studies confirming the
2 resource adequacy concerns in the west?
3 A. Yes . In December 2020, the North American Electric
4 Reliability Corporation ("NERC") issued its Long-Term
5 Resource Adequacy ("LTRA") study that included its 10-
6 year WECC region reliability assessment. ' The NERC LTRA
7 calculates an anticipated resource-based reserve margin
8 to a reference reserve margin to establish one of three
9 risk determinations—adequate (anticipated margin
10 exceeds the reference margin) , marginal (anticipated
11 margin is below the reference margin, but new resources
12 under development could cover the shortfall) , and
13 inadequate (anticipated reserve margin is below the
14 reference margin and load interruption is likely) .
15 The NERC LTRA shows that the Northwest Power Pool
16 region and Rocky Mountain Reserve Group regions are
17 projected to be inadequate beginning in 2028 even if
18 resources under development come online. Again, these
19 findings highlight the risk of relying on other entities
20 in the region to have excess supply available for the
21 market when PacifiCorp may be required to buy power to
22 serve its customers .
2020 Long-Term Reliability Assessment, North American Electric
Reliability Corporation (Dec. 2020)
(https://www.nerc.com/pa/RAPA/ra/Reliabilityo20Assessmentso20DL/NERC LT
RA 2020.pdf) .
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1 Q. How did the 2021 IRP preferred portfolio address the
2 need for new resources?
3 A. The 2021 IRP preferred portfolio represented
4 PacifiCorp' s least-cost, least-risk plan to reliably
5 meet customer demand over a 20-year planning period,
6 based on the information available at the time the plan
7 was developed. Using a range of cost and risk metrics to
8 evaluate numerous resource portfolios, PacifiCorp
9 selected a preferred portfolio that reflected a cost-
10 conscious plan with near-term investments in renewable
11 resources that capture tax credits before they expire or
12 decrease, and new transmission infrastructure to
13 facilitate the interconnection and delivery of these
14 resources . These new resources and transmission
15 investments are lower cost than other resource and
16 transmission alternatives and are necessary to reliably
17 serve our customers .
18 Q. Were the Transmission Projects part of the 2021 IRP
19 preferred portfolio?
20 A. Yes . As described in Volume I, Chapter 4 of the 2021
21 IRP, the preferred portfolio includes both Gateway South
22 and Gateway West Segment D. 1 . In the 2021 IRP, the
23 Transmission Projects are assumed to be placed in
24 service by the end of 2024, consistent with current
25 construction timelines discussed by Company witness
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1 Vail . The Transmission Projects will enable the addition
2 of new wind facilities that contribute to meeting 1, 627
3 MW of projected resource need beginning 2025 .
4 Q. Were the Transmission Projects part of the 2021 IRP
5 Update?
6 A. Yes . $
7 Q. What new transfer capabilities and interconnection
8 capacity do the Transmission Projects add to
9 PacifiCorp' s system?
10 A. The Transmission Projects will increase the transfer
11 capability between the Aeolus substation in eastern
12 Wyoming and the Clover substation located near Mona,
13 Utah by 1, 700 MW, and enable the interconnection of 2, 030
14 MW of new resources in eastern Wyoming.
15 Q. Please describe key factors supporting the inclusion of
16 the Transmission Projects as prudent investments in this
17 case.
18 A. The Transmission Projects allow PacifiCorp to implement
19 system improvements, support the full capacity rating of
20 Gateway South and West, and enable the addition of
21 incremental Wyoming renewable resources to support
22 customer needs and deliver value for customers in the
$ PacifiCorp's 2021 Integrated Resource Plan Update, Ch. 7, Action Plan
Item 3a-3b, at 103-104 (Mar. 31, 2022)
(https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/e
nergy/integrated-resource-plan/2021 IRP Update.pdf) .
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1 most cost-effective way. As discussed by Company witness
2 Vail, the Transmission Projects will also improve
3 overall reliability of the transmission system and
4 enhance PacifiCorp' s ability to comply with mandated
5 reliability and performance standards . Importantly, at
6 the time PacifiCorp committed to move forward with
7 building these new transmission assets, the Transmission
8 Projects would ensure the Company could meet its
9 obligations to reliably accommodate nearly 2, 500 MW of
10 interconnection and transmission service requests,
11 including 13 executed interconnection service and
12 transmission service agreements for over 1, 600 MW of new
13 wind resources . This included 500 MW of firm PTP
14 transmission service to a third-party transmission
15 customer under the FERC' s jurisdiction .
16 Q. Please describe the reliability benefits of the
17 Transmission Projects .
18 A. The Transmission Projects directly connect eastern
19 Wyoming to central Utah while enhancing reliability
20 throughout PacifiCorp-served regions . Connecting to the
21 Mona/Clover market hub provides additional flexibility
22 in the use of least-cost resources from eastern Wyoming
23 or southern Utah.
24 Moreover, allowing additional generation resources
25 to interconnect and serve load will lessen PacifiCorp' s
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1 reliance on volatile and potentially diminishing market
2 transactions to serve load. Given concerns over regional
3 resource adequacy, reducing reliance on the market
4 ensures a stable and reliable supply of capacity and
5 energy going forward.
6 In addition, Gateway South improves reliability by
7 relieving the stress on the transmission system in
8 eastern Wyoming and central Utah. Gateway South relieves
9 stress on the underlying 230-kV transmission system in
10 Wyoming, and it unloads the underlying 345-kV
11 transmission system in central Utah, improving
12 reliability in both regions . Essentially, the 500-kV
13 line brings two distant areas closer to each other in a
14 way that improves regional reliability.
15 Gateway West Segment D. 1 creates a new transmission
16 path that allows for additional resource development in
17 the area. The addition of this line improves the
18 reliability of the transmission system during certain
19 identified outage conditions (Dave Johnston to Amasa
20 230-kV outage or Amasa - Shirley Basin 230-kV outage) .
21 Gateway West Segment D. 1 is also a prerequisite for
22 interconnecting new resources, including those selected
23 in the 2020AS RFP. Company witness Vail' s testimony
24 addresses transmission system reliability and
25 interconnection issues in greater detail .
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1 B. The 2020AS RFP
2 Q. Please provide an overview of the 2020AS RFP.
3 A. The 2020AS RFP was issued to identify resources that
4 could meet the Company' s projected resource need
5 identified in the 2019 IRP. Based on the cost-and-
6 performance assumptions for proxy resources in the 2019
7 IRP, the Company expected that new wind, solar and
8 battery energy storage systems ("BESS") were likely to
9 be the most cost-competitive types of resources offered
10 into the 2020AS RFP. However, bidders could offer
11 proposals for other types of resources (i . e. , natural
12 gas, pumped storage, etc. ) .
13 Q. When was the 2020AS RFP issued?
14 A. After receiving approval from the Utah Commission
15 (Docket No. 20-035-05) and Oregon Commission (Docket No.
16 UM 2059) , PacifiCorp issued the 2020AS RFP on July 7,
17 2020 . 9
18 Q. What was the market response to the 2020AS RFP?
19 A. There was a robust market response that resulted in over
20 28, 000 MW of conforming bids, with an additional 12, 500
9 Utah's Energy Resource Procurement Act requires a competitive
solicitation process before the acquisition of renewable resources
greater than 300 MW. Utah Code Ann. § 54-17-201 et. seq. In addition, the
Oregon Commission has established competitive bidding requirements for
certain resource acquisitions by Oregon's investor-owned utilities. In
the Matter of the Rulemaking Regarding Allowances for Diverse Ownership
of Renewable Energy Resources, Docket No. AR 600, Order No. 18-324,
Appendix A (Aug. 30, 2018)
(https://apps.puc.state.or.us/orders/2018ords/18-324.pdf) (codified at
Or. Admin. R. 860-89-0010, et seq. ) .
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1 MW of non-confirming bids . Bids for 24 projects totaling
2 over 9, 000 MW of resource capacity located in eastern
3 Wyoming were submitted.
4 Q. How did the Company evaluate submitted bids?
5 A. The Company created an initial shortlist that was made
6 public on October 29, 2020 . This shortlist included
7 5, 453 MW of renewable resource capacity: 2, 974 MW of
8 solar or solar with storage (1, 130 MW of battery
9 storage) , 2, 479 MW of wind, and 200 MW of standalone
10 BESS . PacifiCorp then initiated a capacity factor
11 evaluation process (performed by third-party expert WSP
12 Global) . The initial shortlist contained a mix of
13 various ownership structures, including proposals for
14 power-purchase agreements ("PPAs") , build-transfer
15 agreements ("BTAs") , and battery storage agreements
16 ("BSAs") .
17 Q. What resources were selected to the final shortlist?
18 A. After evaluating a range of potential bid portfolios,
19 and accounting for bid updates from interconnection
20 study results, the final shortlist included: 1, 792 MW of
21 new wind capacity (590 MW as BTAs and 1, 202 as PPAs) ;
22 1, 302 MW of solar capacity as PPAs; and 697 MW of BESS
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1 (497 MW of BESS capacity paired with solar bids, and
2 200 MW as standalone BESS capacity as a BSA) . 10
3 Q. Which final shortlist resources depend on the
4 Transmission Projects for interconnection?
5 A. Six final shortlist resources, representing over 1, 600
6 MW of wind generation, require the Transmission Projects
7 to interconnect to PacifiCorp' s transmission system.
8 Table 1 summarizes the wind resources that require the
9 Transmission Projects to achieve interconnection.
Table 1 . 2020AS RFP Wind Bids Dependent on the Transmission
Projects for Interconnection
Project Bidder Structure Capacity
(MW)
Cedar NextEra PPA 350
Springs IV
Boswell Innergex PPA 320
Springs
BlueEarth
Two Rivers Renewables LLC PPA 280
and Clearway
Renew LLC
Anticline NextEra PPA 101
Rock Creek Invenergy BTA 190
I
Rock Creek Invenergy BTA 400
II
10 Q. Was the 2020AS RFP overseen by independent evaluators?
11 A. Yes . Consistent with Utah and Oregon Commissions'
12 requirements, the solicitation process was overseen by
io The final shortlist originally included an additional solar bid
collocated with BESS. Shortly after the bidder was notified its project
was on the final shortlist, it withdrew the bid from the 2020AS RFP. This
bid is not included in the total capacity.
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1 two independent evaluators—one retained by the Utah
2 Commission (Merrimack Energy Group) , and one retained by
3 PacifiCorp and appointed by the Oregon Commission (PA
4 Consulting Group, Inc . ) .
5 Q. What were the independent evaluators' conclusions
6 regarding the 2020AS RFP?
7 A. Both independent evaluators concluded that the process
8 was fair and transparent, and that the bids selected for
9 the final shortlist were reasonable.
10 Q. Please describe the Utah independent evaluator' s
11 conclusions regarding the 2020AS RFP.
12 A. In its Shortlist Report, the Utah independent evaluator
13 concluded that the RFP was fair, reasonable, and in the
14 public interest.11 The Utah independent evaluator
15 concluded:
16 • The market response to the RFP was robust and,
17 "Based on the unbelievable response from the market
18 it is safe to say that the solicitation process
19 resulted in a very competitive process with many
20 more proposals generally submitted than the
21 expected requirements by bubble identified by
22 PacifiCorp. "12
23 • PacifiCorp engaged the bidders throughout the
24 process in a timely manner to ensure that all
25 bidders were treated fairly.
26 • All bidders were treated the same, had access to
27 the same information at the same time, and had an
28 equal opportunity to compete.
11 In re Rocky Mountain Power 2020AS RFP Application, Docket No. 20-035-
05 (Sept. 2, 2021) (https://psc.utah.gov/2020/01/24/docket-no-20-035-
05/) .
12 Utah Independent Evaluator Shortlist Report at 74.
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1 • PacifiCorp implemented its evaluation and selection
2 process consistent with its proposed evaluation and
3 selection process as outlined in the RFP in a
4 structured and consistent manner designed to result
5 in the selection of a portfolio of projects that
6 would result in a least cost solution.
7 • PacifiCorp subjected all bidders to the same
8 information requirements and conducted a consistent
9 evaluation process with all proposals treated
10 equally in terms of the evaluation methodology and
11 information required of each bidder.
12 • The selection process was unbiased with respect to
13 ownership structures, i .e. , the process did not
14 unreasonably favor bids that resulted in a utility-
15 owned resource.
16 • The selected bids resulted in lower system cost
17 than a case where no bids were selected and
18 maximized customer benefits while managing risk.
19 Q. Please describe the Oregon independent evaluator' s
20 conclusions regarding the 2020AS RFP.
21 A. In its Closing Report, the Oregon independent evaluator
22 concluded that the final shortlist reflected a diverse
23 portfolio of competitive resources that achieves the
24 resource adequacy and least cost goals set forth in
25 PacifiCorp' s IRP.13 This was based on the following
26 conclusions :
27 • PacifiCorp' s procurement process, scoring
28 methodology and results were fair and free of bias
29 across all bids and bidders .
30 • PacifiCorp applied the rules of the 2020AS RFP in
31 an unbiased manner, communicated transparently with
32 the independent evaluators regarding their
13 In re PacifiCorp's 2020AS RFP Application, Docket No. UM 2059 (Oregon
Commission; Jun. 15, 2021)
(https://apps.puc.state.or.us/edockets/DocketNoLayout.asp?DocketID=2232
0) .
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1 modelling processes and with stakeholders regarding
2 their decisions .
3 • PacifiCorp' s bid price scores were on average
4 consistent with the independent evaluator' s
5 independent scoring methodology.
6 • PacifiCorp' s utilization of an outside consultant,
7 WSP Global, to evaluate wind, solar, and battery
8 storage benefitted stakeholders .
9 • The final shortlist was reasonably aligned with the
10 2019 IRP preferred portfolio.
11 Q. Did the Oregon Commission acknowledge the shortlist?
12 A. Yes .14 Acknowledgement means that the Oregon Commission
13 found that the "final shortlist appears reasonable at
14 the time of acknowledgment and was determined in a manner
15 consistent with [Oregon' s] competitive bidding rules . "ls
16 The Oregon Commission noted that the final shortlist "is
17 a reasonable capacity and energy blend, with diversity
18 in contract structures (and therefore rate impact
19 profiles) , technology types, and geography. 1116
20 C. Price-Policy Assumptions
21 Q. Please summarize the natural gas and CO2 price
22 assumptions used in the economic analysis .
23 A. The economic analysis of the Transmission Projects
24 includes five price-policy scenarios—MM, MN, HH, LN, and
25 SCGHG. These assumptions influence the value of system
14 Docket No. UM 2059, Order No. 21-437 (Nov. 24, 2021)
(https://apps.puc.state.or.us/orders/2021ords/21-437.pdf) .
is Id. at 12.
i6 Id. at 13.
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1 energy, the dispatch of system resources, and
2 PacifiCorp' s resource mix. Consequently, wholesale-
3 power prices and CO2policy assumptions affect net-power
4 cost ("NPC") benefits, non-NPC variable-cost benefits,
5 and system fixed-cost benefits associated with the
6 Transmission Projects . Because wholesale power prices
7 and CO2policy outcomes are both uncertain and important
8 drivers to the economic analysis, it is important to
9 evaluate a range of assumptions for these variables .
10 Table 2 summarizes the price-policy scenarios used to
11 analyze the Transmission Projects .
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Table 2 . Price-Policy Scenario Assumption Overview
Henry Hub
Price- Natural Gas
CO2 Price Description
Policy Price
Scenario (Levelized
$/MMBtu)
$9 . 93/ton starting
MM $4 . 44 2025 rising to
$57 . 94/ton in 2040
MN $4 . 44 None
$22 . 57/ton starting
HH $5 . 64 2025 rising to
$102 . 48/ton in 2040
LN $2 . 94 None
$74 . 10/ton starting
SCGHG $4 . 44 2021 rising to
$150 . 38/ton in 2040
*Nominal levelized Henry Hub natural gas price from
2025 through 2040 .
1 Q. Please describe the natural-gas price assumptions used
2 in the price-policy scenarios.
3 A. The medium natural gas price assumptions are from
4 PacifiCorp' s official forward price curve ("OFPC") dated
5 March 31, 2021, which was the most current OFPC available
6 when PacifiCorp prepared its modeling inputs for the
7 2021 IRP. The first 36 months of the OFPC reflect market
8 forwards at the close of a given trading day (March 31,
9 2021, in this case) . As such, these 36 months are market
10 forwards as of March 2021 . The blending period (months
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1 37 through 48) is calculated by averaging the month-on-
2 month market forwards from the prior year with the month-
3 on-month fundamentals-based price from the subsequent
4 year. The fundamentals portion of the natural gas OFPC
5 reflects an expert third-party, multi-client "off-the-
6 shelf" price forecast. The fundamentals portion of the
7 electricity OFPC reflects prices as forecast by
8 AURORAXMP4 ("Aurora") , a WECC-wide market model . Aurora
9 uses the expert third-party natural gas price forecast
10 to produce a consistent electricity price forecast for
11 market hubs in which PacifiCorp participates . Figure 1
12 shows Henry Hub natural-gas price assumptions for the
13 medium, high, and low natural gas price scenarios .
Figure 1 . Natural Gas Price Assumptions
Wholesale Electricity Prices Natural Gas Prices
Average of Palo Verde and Mid-C(Flat) Henry Hub
$120 $9
$100 $8
$80 $7
$6 on
$60 $5
$40 $3
$20 $2
$_ $1
N N N N N N N N N M M M M M M M M M M V $-
O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M OV
O O O O O O O O O O O O O O O O O O O
—Mgas_00O2 tMgas_MCO2 —0—Hgas_HCO2 N N N N N N N N N N N N N N N N N N N N
--O--Lgas_00O2 —0—Mgas_SCO2 —Medium tLow —m—High
14 Q. Please describe the CO2 price assumptions used in the
15 price-policy scenarios .
16 A. PacifiCorp used four different CO2 price scenarios in
17 the 2021 IRP—zero, medium, high, and a price forecast
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1 that aligns with the social cost of greenhouse gases .
2 The medium and high scenario are derived from expert
3 third-party, multi-client "off-the-shelf" subscription
4 services . Both scenarios apply a CO2 price beginning
5 2025 . PacifiCorp also incorporated the social cost of
6 greenhouse gas, which is assumed to start in 2021 . The
7 social cost of greenhouse gases is applied such that the
8 price for the social cost of greenhouse gas is reflected
9 in market prices and dispatch costs for the purposes of
10 developing each portfolio (i . e. , incorporated into
11 capacity expansion optimization modeling) . Figure 2
12 shows the three non-zero CO2 price assumptions used to
13 analyze the Transmission Projects .
Figure 2 . CO2 Price Assumptions
$160
$150 —
$140
$130
$120
$110
$100
$90
$80
$70
$60
$50
$40
$30
$20 -
$10
$0
- N M \O r- o0 C1 O - N M � kn � r- 00 C1 O
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
}Medium High Societal Cost
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1 Q. How did PacifiCorp pair the natural gas and CO2 price
2 assumptions for purposes of its analysis of the
3 Transmission Projects?
4 A. Scenarios pairing medium gas prices with alternative CO2
5 price assumptions reflect OFPC forwards through April
6 2024 before transitioning to a fundamentals forecast.
7 Scenarios using high or low gas prices, regardless of
8 CO2 price assumptions, do not incorporate any market
9 forwards because these scenarios are designed to reflect
10 an alternative view to that of the market. As such, the
11 low and high natural gas price scenarios are purely
12 fundamental forecasts . Low and high natural gas price
13 scenarios are also derived from expert third-party,
14 multi-client "off-the-shelf" subscription services .
15 Q. Does including potential future CO2 costs reflect prudent
16 utility planning?
17 A. Yes . The Company' s price-policy scenarios include
18 varying levels of assumed CO2 costs to reflect the fact
19 it is more likely than not that some policy will exist
20 that will drive reduced emissions over the life of the
21 Transmission Projects . When determining CO2 costs used
22 for planning purposes, the Company strives to ensure
23 that it is not an outlier as discussed above, and the
24 medium price is within a reasonable range used by the
25 industry to assess risk and conduct prudent resource
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1 planning.
2 Q. Are the modeled CO2 costs intended to represent a literal
3 carbon tax?
4 A. No . The modeled CO2 costs are not intended to explicitly
5 account for a future tax on CO2 emissions . Rather, these
6 costs capture the effect of policies incentivizing
7 reduced emissions through benefits or imposing costs
8 through penalties or other costs resulting from market
9 dynamics driving the need for zero-emission resources or
10 customer preferences .
11 D. Modeling Methodology
12 Q. Please describe the modeling methodology PacifiCorp used
13 in its analysis of the Transmission Projects .
14 A. PacifiCorp calculated a system PURR by identifying
15 least-cost resource portfolios and dispatching system
16 resources through 2040, which aligns with the 20-year
17 forecast period used in the 2021 IRP. Net customer
18 benefits are calculated as the PVRR (d) between two
19 simulations of PacifiCorp' s system. One simulation
20 includes the Transmission Projects, and the other
21 simulation excludes them. In addition, because wind bids
22 selected from the 2020AS RFP located in eastern Wyoming
23 cannot interconnect without the Transmission Projects,
24 these wind resources are also eliminated from the
25 simulation without the Transmission Projects . When the
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1 two simulations are compared, changes to system costs
2 are attributable to the Transmission Projects and
3 associated wind resources from the 2020AS RFP final
4 shortlist .
5 Customers are expected to realize benefits when the
6 system PVRR from the simulation with the Transmission
7 Projects is lower than the system PVRR without the
8 Transmission Projects . Conversely, customers would
9 experience increased costs if the system PURR with the
10 Transmission Projects were higher than the system PVRR
11 without the Transmission Projects .
12 Q. Are there any other costs that differ between the
13 simulations with and without the Transmission Projects?
14 A. Yes . The simulation that excludes the Transmission
15 Projects includes the cost of transmission upgrades
16 necessary to accommodate PacifiCorp' s obligation to
17 provide 500 MW of firm PTP transmission service to a
18 third-party customer. As explained in more detail by
19 Company witness Vail, these transmission upgrade costs
20 were included because, even conservatively ignoring all
21 the executed interconnection service and transmission
22 service contracts listing the Transmission Projects as
23 prerequisites and focusing solely on the upgrades
24 required to provide service under one transmission
25 service contract, PacifiCorp assumed it would need to
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1 construct a 230-kV line by the end of 2024 at an
2 estimated cost of approximately $1 . 4 billion .
3 Further, this $1 . 4 billion cost is the minimum cost
4 for the alternative considering that it includes only
5 the upgrades required to provide service under a single
6 transmission service contract. Additional costs would be
7 incurred to provide service under all interconnection
8 service contracts listing the Transmission Projects as
9 prerequisites . To provide service under all these
10 contracts, it is likely the alternative would be to
11 construct the Transmission Projects, which means that
12 construction of these transmission investments are
13 unavoidable given PacifiCorp' s federal open access
14 transmission tariff obligations to grant interconnection
15 and transmission service requests .
16 Q. Please describe the modeling tool used to create the
17 economic analysis of the Transmission Projects .
18 A. PacifiCorp uses the PLEXOS modeling system. The PLEXOS
19 modeling system provides three platforms of the PLEXOS
20 tool (referred to as Long-term ("LT") , Medium-term
21 ("MT") and Short-term ("ST") ) , which work on an
22 integrated basis to inform the optimal combination of
23 resources by type, timing, size, and location over
24 PacifiCorp' s 20-year planning horizon. The PLEXOS tool
25 also allows for improved endogenous modeling of resource
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1 options simultaneously, greatly reducing the volume of
2 individual portfolios needed to evaluate impacts of
3 varying resource decisions .
4 Q. Please describe how PacifiCorp used the LT model.
5 A. PacifiCorp used the LT model to produce unique resource
6 portfolios across a range of different planning cases .
7 Informed by the public-input process, PacifiCorp
8 identified case assumptions that were used to produce
9 optimized resource portfolios, each one unique regarding
10 the type, timing, location, and amount of new resources
11 that could be pursued to serve customers over the next
12 20 years . Portfolios from the LT model are informed by
13 an hourly review of reliability based on ST model
14 simulations (described below) . This ensures that each
15 portfolio meets minimum reliability criteria in all
16 hours .
17 Q. Please describe how PacifiCorp used the MT model .
18 A. PacifiCorp used the MT model to perform stochastic risk
19 analysis of the portfolios . Each portfolio was evaluated
20 for cost and risk among five price-policy scenarios (MM,
21 MN, HH, LN, and SCGHG) . A primary function of the MT
22 model is to calculate an optimized risk-adjustment,
23 representing the relative risk of a portfolio under
24 unfavorable stochastic conditions for that portfolio .
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1 Q. Please describe how PacifiCorp used the ST model .
2 A. PacifiCorp used to ST model to evaluate each portfolio
3 to establish system costs over the entire 20-year
4 planning period. The ST model accounts for resource
5 availability and system requirements at an hourly level,
6 producing reliability and resource value outcomes as
7 well as a PURR, which serves as the basis for selecting
8 least-cost, least-risk portfolios . As noted above, ST
9 model simulations were also used to identify the
10 potential need for resources in the portfolio to
11 maintain system reliability.
12 Q. How did each of the three PLEXOS models work together to
13 inform the economic analysis presented here?
14 A. In the first step, resource portfolios (with and without
15 the Transmission Projects and associated wind resources)
16 were developed using the LT model . The LT model operates
17 by minimizing operating costs for existing and
18 prospective new resources, subject to system load
19 balance, reliability, and other constraints . Over the
20 20-year planning horizon, the model optimizes resource
21 additions subject to resource costs and load
22 constraints . These constraints include seasonal loads,
23 operating reserves and regulation reserves plus a
24 minimum capacity reserve margin for each load area
25 represented in the model .
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1 To accomplish these optimization objectives, the LT
2 model performs a least-cost dispatch for existing and
3 potential planned generation, while considering cost and
4 performance of existing contracts and new demand-side
5 management ("DSM") alternatives within PacifiCorp' s
6 transmission system. Resource dispatch is based on
7 representative data blocks for each of the 12 months of
8 every year. Dispatch also determines optimal electricity
9 flows between zones and includes spot market
10 transactions for system balancing. The model minimizes
11 the system PURR, which includes the net present value
12 cost of existing contracts, market purchase costs,
13 market sale revenues, generation costs (fuel, fixed and
14 variable operation and maintenance, decommissioning,
15 emissions, unserved energy, and unmet capacity) , costs
16 of DSM resources, amortized capital costs for existing
17 coal resources and potential new resources, and costs
18 for potential transmission upgrades .
19 Each portfolio developed by the LT model must have
20 sufficient capacity to be reliable over the IRP' s 20-
21 year planning horizon. The resource portfolios reflect
22 a combination of planning assumptions such as resource
23 retirements, CO2 prices, wholesale power and natural gas
24 prices, load growth net of assumed private generation
25 penetration levels, cost and performance attributes of
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1 potential transmission upgrades, and new and existing
2 resource cost and performance data, including
3 assumptions for new supply-side resources and
4 incremental DSM resources .
5 Q. What is the next step in the modeling process?
6 A. In the second step, the Company conducted a reliability
7 assessment using the ST model . The ST model begins with
8 a portfolio from the LT model that has not yet benefited
9 from a reliability assessment conducted at an hourly
10 level . The ST model is first run at an hourly level for
11 20 years to retrieve two critical pieces of data: (1)
12 shortfalls by hour; and (2) the value of every potential
13 resource to the system. This information is then used to
14 determine the most cost-effective resource additions
15 needed to meet reliability shortfalls, leading to a
16 reliability-modified portfolio. The ST model is then run
17 again with the modified portfolio to calculate an
18 initial PURR, which is risk-adjusted by outcomes of MT
19 model stochastics that occurs in the third step of the
20 process .
21 Q. Please describe how the MT model is used to conduct cost
22 and risk analysis .
23 A. In the third step, the resource portfolios developed by
24 the LT model and adjusted for reliability by the ST model
25 are simulated in the MT model to produce metrics that
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1 support comparative cost and risk analysis among the
2 different resource portfolio alternatives . The
3 stochastic simulation in the MT model produces a
4 dispatch solution that accounts for chronological
5 commitment and dispatch constraints . The MT simulation
6 incorporates stochastic risk in its production cost
7 estimates by using the Monte Carlo sampling of
8 stochastic variables, which include load, wholesale
9 electricity and natural gas prices, hydro generation,
10 and thermal unit outages . The MT results are used to
11 calculate a risk adjustment, which is combined with ST
12 model system costs to achieve a final risk-adjusted
13 PVRR.
14 Q. Is the PLEXOS model appropriate for analyzing the
15 customer benefits of the Transmission Projects?
16 A. Yes . The PLEXOS model is the appropriate modeling tool
17 when evaluating significant capital investments that
18 influence PacifiCorp' s resource mix and affect least-
19 cost dispatch of system resources . The LT model
20 simultaneously and endogenously evaluates capacity and
21 energy trade-offs associated with resource and
22 transmission capital projects and is needed to
23 understand how the type, timing, and location of future
24 resources might be affected by the Transmission
25 Projects . The ST and MT models provide additional
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1 granularity on how the Transmission Projects are
2 projected to affect system operations while assessing
3 stochastic risks . Together, the LT, MT, and ST models
4 are best suited to perform a benefit analysis for the
5 Transmission Projects that is consistent with long-
6 standing least-cost, least-risk planning principles
7 applied in PacifiCorp' s IRP and resource procurement
8 activities .
9 Q. When developing resource portfolios with the PLEXOS
10 model, did you perform a reliability assessment?
11 A. Yes . As described above, the ST model was used to
12 establish system costs for each portfolio over the
13 entire 20-year planning period. The ST model accounts
14 for resource availability and system requirements at an
15 hourly level, producing reliability and resource value
16 outcomes that will reveal whether an initially reliable
17 portfolio selected by the LT model leaves shortfalls at
18 an hourly level, which can then be addressed.
19 Q. Did PacifiCorp analyze how other assumptions affect its
20 economic analysis of the Transmission Projects?
21 A. Yes . The economic analysis also included one sensitivity
22 that quantified how changes in new resource capital
23 costs for the two BTA wind projects and capital cost
24 assumptions for the Transmission Projects influenced
25 projected customer benefits .
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1 Q. Company witness Vail' s testimony indicates that the
2 Transmission Projects will enable up to 2 , 030 MW of new
3 resources to interconnect in eastern Wyoming. Why does
4 your analysis only account for 1 , 640 MW?
5 A. The economic analysis reasonably accounted for only
6 those wind resources that were selected to the 2020AS
7 RFP final shortlist .
8 Q. Does PacifiCorp assume that all the up-front capital
9 costs of the Transmission Projects will be paid by its
10 retail customers?
11 A. No . The cost of the Transmission Projects will be shared
12 between PacifiCorp' s retail and wholesale transmission
13 customers . In my analyses, I assumed retail customers
14 would pay 80 percent of the revenue requirement from the
15 up-front capital cost for the Transmission Projects,
16 after accounting for an assumed 20 percent revenue
17 credit from the Company' s transmission customers .
18 E. Price-Policy Scenario Results
19 Q. Please summarize the PVRR(d) results calculated from the
20 PLEXOS model .
21 A. Table 3 summarizes the PVRR (d) results for each price-
22 policy scenario . 17
17 Exhibit No. 31 - Transmission Projects Analysis.
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Table 3 . PVRR(d) (Benefit) /Cost of the Transmission
Projects ($ million)
Price-Policy PVRR(d) Risk-Adjusted
Scenario PVRR(d)
MM ($128) ($260)
LN $755 $670
MN $393 $289
HH ($932) ($1, 100)
SCGHG ($2, 568) ($2, 819)
1 As shown above, system costs increase when the
2 Transmission Projects are removed from the portfolio in
3 the MM, HH, and SCGHG price-policy scenarios .
4 Conversely, costs decrease in the LN and MN price-policy
5 scenarios . Without the Transmission Projects, emissions
6 from PacifiCorp' s generation resources increase
7 considerably—ranging from 8 . 4 percent in the MN price-
8 policy scenario to 17 . 8 percent in the SCGHG price-
9 policy scenario. The LN and MN scenarios unrealistically
10 fail to account for the risk that there will be some
11 form of policy action taken to impute a cost or penalty
12 on greenhouse gas emissions over the planning period. It
13 is also unlikely gas prices will be suppressed for many
14 decades to come, as assumed in the LN price-policy
15 scenario . Further, cost-and-risk results indicate that
16 there is a tremendous opportunity cost of not building
17 the Transmission Projects should policies develop that
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1 impose costs on greenhouse gas emissions . This is seen
2 with the disproportionate increase in costs under the HH
3 and SCGHG price-policy scenarios relative to the size of
4 cost reductions in the unlikely LN and MN price-policy
5 scenarios .
6 Considering that the removal of the Transmission
7 Projects increases system costs among the MM, HH, and
8 SCGHG price-policy scenarios, significantly increases
9 emissions and associated costs and risks, and
10 significantly increases market-reliance risk (discussed
11 further below) , this analysis supports the necessity of
12 the Transmission Projects and indicates that they are
13 likely to result in robust customer benefits .
14 Q. Did you calculate how the PVRR(d) results presented
15 above would change if you assumed the Transmission
16 Projects would be required to provide service under all
17 these interconnection and transmission service
18 contracts?
19 A. Yes . This would increase the cost of the "alternative"
20 to equal the cost of the Transmission Projects, which
21 represents a $971 million increase in unavoidable
22 capital relative to what is shown in the table above.
23 This translates into $482 million on a PVRR basis . Table
24 4 shows the PVRR(d) results with this level of
25 unavoidable capital . When this higher cost is applied to
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1 the results, the MN price-policy scenario now shows
2 there are significant customer benefits from the
3 Transmission Projects .
Table 4 . PVRR(d) (Benefit) /Cost of the Transmission
Projects Assuming the Transmission Projects are Unavoidable
($ million)
Price-Policy PVRR(d) Risk-Adjusted
Scenario PVRR(d)
MM ($610) ($742)
LN $273 $188
MN ($90) ($194)
HH ($1, 414) ($1, 582)
SCGHG ($3, 050) ($3, 301)
4 Q. Please describe the impact of removing the Transmission
5 Projects and associated wind resources from the 2021
6 IRP' s preferred portfolio.
7 A. Figure 3 shows the cumulative (at left) and incremental
8 (at right) portfolio changes when the Transmission
9 Projects are eliminated under the MM price-policy
10 scenario . A positive value indicates an increase in
11 resources and a negative value indicates a decrease in
12 resources when the Transmission Projects are eliminated.
13 Without the Transmission Projects, the 1, 640 MW of wind
14 resources selected in the 2020AS RFP are removed from
15 the portfolio in 2024 (shown as a reduction in 2025, the
16 first full year these resources would be online) . An
17 additional 289 MW of wind is eliminated in 2030 . In 2034,
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1 the absence of the new wind resources triggers the
2 addition of an advanced nuclear plant that displaces
3 solar co-located with storage resources .
Figure 3 . Changes in the Resource Portfolio without
the Transmission Projects
ctmluimive PoMolio chmga h.—.td Portfolio chmga
1000
100
W
-500
•300
•1000
-I300 �•1000
-2000
-I51f0
-2500
A R4 41� 1 'P5^'f 't'iA "i 4 h �f'7 'C �P�' /^Q�'y r� 'P 'P� ^ci'' .Pi^ '� ,
-Md— oSda,+ M. Arod =�,MyPBd®ry oN.d.. •gW_S". •Wind •Enalq Ef6d..y
4 Q. Does the removal of the Transmission Projects and
5 associated wind resources increase the Company' s
6 reliance on market purchases?
7 A. Yes . Figure 4 shows how market purchases change when the
8 Transmission Projects are removed from the portfolio
9 under the MM price-policy scenario. With fewer
10 resources, market purchases increase by nearly 20
11 percent on an annual basis . This creates higher risk as
12 the Company is forced to rely on market purchases at a
13 time when there are increasing resource adequacy
14 concerns throughout the western interconnect. This
15 increased market and reliability risk is not reflected
16 in the PVRR (d) results .
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Figure 4 . Changes in Market Purchases without the
Transmission Projects
1,200
1,000
800 ---_-��-
600
400 --
200
0
N m Q n n 00 m o N m Q vi t, 00 m o
N N N N N N N N N M m M m M M M m m m Q
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
———P02-MPo1 —P02c-No GWS
1 Q. How do system costs change with and without the
2 Transmission Projects?
3 A. Figure 5 summarizes changes in system costs
4 (conservatively assuming the cost for a 230-kV
5 alternative is unavoidable) , based on ST model results
6 using MM price-policy assumptions, when the Transmission
7 Projects are eliminated from the portfolio . The graph on
8 the left shows annual changes in cost by category and
9 the graph on right shows annual net changes in total
10 costs (the solid black line) and the cumulative PVRR (d)
11 of changes to net system costs over time (the dashed
12 black line) . Through 2040, the PVRR(d) shows that the
13 portfolio without the Transmission Projects is $128
14 million higher cost than the portfolio with the
15 Transmission Projects . On a risk-adjusted basis, which
16 factors in the risk associated with low-probability,
17 high-cost events through stochastic simulations, the
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1 portfolio without the Transmission Projects is $260
2 million higher cost than the portfolio with the
3 Transmission Projects . The risk-adjusted results
4 indicate that the Transmission Projects add significant
5 risk mitigation benefits associated with volatility in
6 market prices, loads, hydro generation, and unplanned
7 outages .
Figure 5 . Increase/ (Decrease) in System Costs when the
Transmission Projects are Removed from the Portfolio
Annual Change in Cost by Line Item Net Difference In Total System Cost
$400 $a0
$300 $20
$2�$100 _'�� 1 1 1111 $0 - --"
($20)
$0 ($40)
($100)
($200) ' 1 1 1" isS80 ($128)
($300) - _. (5180) —
($400) ($120)
($s00) ($140) —
n n ao m n n ao m
so($1 )
ry n ry ry n n ry ry ry ry ry ry ry n ry ry n ry ry ry n m n m
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
■Coal&Gas Fixed ■Coal&Gas Variable ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry
■Proxy Resource Costs ■Emissions
■Net Market Transactions■Transmission Net Cost/(Benefit) ———Cumulative PVRR(d)
8 Q. Is there incremental customer upside to the PVRR(d)
9 results?
10 A. Yes . The PVRR (d) results presented in Table 4 do not
11 reflect the potential value of RECs generated by the
12 incremental energy output from the renewable projects
13 enabled by the Transmission Projects . Customer benefits
14 for all price-policy scenarios would improve by
15 approximately $42 million for every dollar assigned to
16 the incremental RECs that will be generated through
17 2040 . Beyond potential REC-revenue benefits, the
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1 economic analysis of the Transmission Projects does not
2 reflect the reliability benefits that these investments
3 will provide to the transmission system, which are
4 described by Company witness Vail .
5 Q. How do the risk-adjusted PVRR(d) results compare to the
6 stochastic-mean PVRR(d) results?
7 A. The risk-adjusted PVRR(d) results show an increase in
8 the benefits of the Transmission Projects when compared
9 to the reported ST-model PVRR (d) results . This indicates
10 that the Transmission Projects provide stochastic risk
11 benefits by making the system less susceptible to low-
12 probability combinations of load, market price, hydro
13 generation, and thermal outage volatility that can
14 increase system costs .
15 Q. Have you calculated how changes in the capital cost for
16 the Transmission Projects might affect customer
17 benefits?
18 A. Yes . A one percent increase in the initial capital costs
19 associated with the Transmission Projects would reduce
20 PVRR benefits by $4 . 8 million . This estimate
21 conservatively assumes that there is no change in
22 transmission costs that will be avoided with the
23 construction of the Transmission Projects . In the MM
24 price-policy scenario, capital costs for the
25 Transmission Projects would need to increase by
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1 54 percent to eliminate customer benefits on a risk-
2 adjusted basis . This demonstrates that the projected
3 customer benefits are robust to potential variations in
4 capital costs for the Transmission Projects,
5 particularly when considering that the cost estimates
6 used in the economic analysis of the Transmission
7 Projects reflect PacifiCorp' s experience with the recent
8 construction of Gateway West Segment D. 2 and the
9 associated 230-kV network upgrades reflecting current
10 market conditions .
11 F. Post-Construction Economic Review
12 Q. Did you continue to revisit your economic analysis of
13 the Transmission Projects after initiating construction?
14 A. Yes .
15 Q. Why did you continue to revisit your economic analysis?
16 A. After PacifiCorp provided its notice to proceed to begin
17 constructing the Transmission Projects, the Company
18 continued to negotiate contracts for the wind resources
19 that are dependent on the Transmission Projects . During
20 the pendency of those negotiations, there were two
21 significant developments that affected the cost of the
22 wind resources . Considering that the cost of the wind
23 resources affects the economic analysis of the
24 Transmission Projects, I continued to check that changes
25 to costs did not erode customer benefits .
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1 Q. Please describe the two developments that affected the
2 cost of the wind resources dependent upon the
3 Transmission Projects .
4 A. First, as the Company finalized contracts with resources
5 selected to the 2020AS RFP final shortlist, national
6 tariff policies, global supply-chain challenges, and
7 inflationary pressures required that bidders secure
8 higher prices than originally offered into the 2020AS
9 RFP. Second, Congress passed the IRA that, among other
10 things, provided an opportunity for the wind projects
11 dependent upon the Transmission Projects to qualify for
12 a 110 percent PTC, which is substantially higher than
13 the 60 percent PTC assumed in my economic analysis that
14 supported the Company' s decision to begin constructing
15 the Transmission Projects .
16 Q. How did you evaluate the impact of these developments on
17 the economic analysis of the Transmission Projects?
18 A. As the Company finalized the wind resource contracts to
19 capture price changes and new provisions related to the
20 IRA, MM price-policy results were revisited so that we
21 could understand how the economic analysis was being
22 impacted. The updated analysis captured price changes in
23 the contracts and incorporated updated energy values for
24 projected wind energy using more current market price
25 assumptions (i . e. , June 2022) .
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1 Q. Did your post-construction economic review capture other
2 updates?
3 A. Yes . Due to the price pressures I discussed above, some
4 of the 2020AS RFP final shortlist bidders were unwilling
5 to offer any form of price update. These projects were
6 removed from consideration. While this did not include
7 any of the wind projects dependent on the Transmission
8 Projects, the removal of bids increases the overall need
9 for new resources . The updated analysis also included
10 any new contracts that were executed outside of the
11 2020AS RFP process and incorporated the most current
12 load forecast, which was developed in May 2022 . The
13 updated analysis also accounted for the potential impact
14 of the OTR.
15 Q. What did you find when you prepared this post-
16 construction economic review of the Transmission
17 Projects?
18 A. This on-going review continued to show that the
19 Transmission Projects are expected to generate customer
20 benefits . The last of these reviews, prepared in
21 September 2022, reflected updated pricing for all wind
22 resource PPAs dependent upon the Transmission Projects
23 and showed risk-adjusted customer benefits totaling
24 $247 million in the MM price-policy scenario. This is
25 similar to the comparable risk-adjusted customer
Link, Di 47
Rocky Mountain Power

1 benefits totaling $260 million from the economic
2 analysis in place when the Company initiated
3 construction of the Transmission Projects .
4 IV. CONCLUSION
5 Q. Please summarize the conclusions of your Gateway South
6 and Gateway West testimony.
7 A. PacifiCorp' s analysis shows that the Transmission
8 Projects are necessary and in the public interest. Under
9 the MM price-policy scenario, the Transmission Projects
10 produce significantly lower total system costs—ranging
11 from $128 to $260 million when using the most
12 conservating assumptions for avoided transmission and
13 ranging from $610 million to $742 million when assuming
14 the Transmission Projects are unavoidable. The
15 Transmission Projects are also lower risk than
16 alternative scenarios without the resources . Most
17 notably, without the Transmission Projects and
18 accompanying wind resources, the Company is forced to
19 rely heavily on market purchases to serve load, which
20 increases risk related to market volatility and creates
21 reliability concerns given the region' s well established
22 resource adequacy concerns .
23 By proactively constructing the Transmission
24 Projects the Company can not only save customers money
25 (as evidenced by the savings in the MM price-policy
Link, Di 48
Rocky Mountain Power

1 scenario) but also reduce customer risk, which is a non-
2 quantifiable benefit that strongly favors the
3 Transmission Projects . The updated economic analysis of
4 the Transmission Projects demonstrates that net benefits
5 more than outweigh net project costs .
6 Q. What do you recommend?
7 A. As supported by PacifiCorp' s economic analysis, I
8 recommend that the Commission determine that Company' s
9 decisions to invest in the Transmission Projects are
10 prudent and reasonable.
11 Q. Does this conclude your direct testimony?
12 A. Yes .
Link, Di 49
Rocky Mountain Power

Case No. PAC-E-24-04
Exhibit No. 31
Witness : Rick T. Link
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Rick T. Link
Transmission Projects Analysis
May 2024

Rocky Mountain Power
Exhibit No.31 Page 1 of 3
Case No. PAC-E-24-04
Witness:Rick T.Link
ST Results($million)
Medium Gas,Medium CO2
(Benefit)/Cost I PVRR(d) 2021 1 2022 1 2023 1 2024 1 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 1 2034 1 2035 1 2036 1 2037 1 2038 1 2039 2040
Cost of Project $1,837 $0 $0 $0 $0 $193 $194 $199 $214 $217 $225 $231 $234 $240 $238 $298 $301 $298 $300 $304 S309
New Wind Capital Cost $397 $0 $0 $0 $0 $33 $34 $34 $40 $40 $42 $45 $45 $47 $51 $93 $94 $94 $95 $97 $99
Wind Run-Rate Fixed Costs $327 $0 $0 $0 $0 $51 $51 $54 $53 $55 $56 $57 $59 $59 $56 $16 $17 $17 $17 $17 $17
PPA $1,332 $0 $0 $0 ($0) $180 $181 $188 $197 $202 $208 $215 $220 $224 $220 $130 $132 $129 $129 $132 $134
PTC Credits ($748) $0 $0 $0 $0 ($130) ($130) ($135) ($134) ($139) ($140) ($143) ($148) ($148) ($148) $0 $0 $0 $0 $0 $0
Wind Tax $14 $0 $0 $0 $0 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2
Transmission GWS $1,261 $0 $0 $0 $0 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138
Transmission D.1 $185 $0 $0 $0 $0 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20
Avoided Transmission-Base 230 kV ($843) $0 $0 $0 $0 ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92)
Transmisison Network Wind $41 $0 $0 $0 $0 $5 $5 $5 $5 $4 $4 $4 $4 $4 $4 $5 $4 $4 $4 $4 $4
Transmission OATT Credit ($129) $0 $0 $0 ($0) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14)
Change inNPC ($1,345) ($0) $0 ($1) ($2) ($170) ($158) ($166) ($175) ($175) ($189) ($198) ($193) ($163) ($169) ($171) ($171) ($212) ($211) ($222) ($306)
Change in Emissions ($488) $0 $0 $0 $0 ($25) ($32) ($36) ($41) ($49) ($82) ($80) ($99) ($71) ($76) ($87) ($107) ($95) ($105) ($120) ($91)
Change in VOM&Driver Adjustments ($40) (SO) $0 $0 (SO) ($5) ($5) ($5) ($3) ($3) ($3) ($3) ($3) $34 ($16) ($16) ($16) ($16) ($16) ($16) ($17)
Change in DSM ($41) $0 ($1) ($2) ($3) ($3) ($3) ($4) ($5) ($5) ($5) ($5) ($6) ($5) ($5) ($5) ($6) ($6) ($6) ($6) ($6)
Change in Deficiency ($4) (SO) $0 $0 ($1) ($3) $0 ($1) ($2) ($O) $0 $0 $0 $0 $0 $0 $1 ($0) $0 $0 $0
Change in System Fixed Cost ($48) (SO) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) $48 $49 $49 ($40) ($41) ($42) ($43) ($45) ($46) ($48) ($49)
Net(Benefit)/Cost ($128) (SO) ($1) ($2) ($6) ($12) ($4) ($12) ($12) ($16) ($5) ($6) ($17) ($5) ($70) ($24) ($42) ($76) ($85) ($107) ($160)
Risk Adjustment ($132)
Net(Benefit)/Cost with Risk Adjustment ($260)
�2
(Benefit)/Cost PVRR(d) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 1 2034 1 2035 2036 2037 2038 2039 2A40
Cost of Project $1,811 $0 $0 $0 $0 $194 $195 $201 $215 $217 $225 $231 $234 $240 $167 $297 $301 $298 $300 $304 $309
New Wind Capital Cost $398 $0 $0 $0 $0 $34 $35 $34 $40 $40 $42 $45 $45 $47 $51 $93 $94 $94 $95 $97 $99
Wind Run-Rate Fixed Costs $326 $0 $0 $0 $0 $50 $50 $54 $52 $55 $56 $57 $59 $59 $56 $16 $17 $17 $17 $17 $17
PPA $1,304 $0 $0 $0 ($0) $180 $181 $188 $197 $202 $208 $215 $220 $224 $149 $130 $132 $129 $129 $132 $134
PTC Credits ($746) $0 $0 $0 $0 ($129) ($129) ($134) ($134) ($139) ($140) ($143) ($148) ($148) ($148) $0 $0 $0 $0 $0 $0
Wind Tax $14 $0 $0 $0 $0 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2
Transmission GWS $1,261 $0 $0 $0 $0 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138
Transmission D.1 $185 $0 $0 $0 $0 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20
Avoided Transmission-Base 230 kV ($843) $0 $0 $0 $0 ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92)
Transmisison Network Wind[1] $41 $0 $0 $0 $0 $5 $5 $5 $5 $4 $4 $4 $4 $4 $4 $5 $4 $4 $4 $4 $4
Transmission OATT Credit ($129) $0 $0 $0 ($0) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14)
Change inNPC ($1,305) $1 $0 ($1) ($1) ($163) ($163) ($168) ($171) ($172) ($202) ($197) ($203) ($150) ($152) ($153) ($167) ($190) ($202) ($215) ($251)
Change in Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Change in VOM&Driver Adjustments ($49) ($O) ($0) $0 ($0) ($7) ($8) ($8) ($4) ($4) ($4) ($4) ($4) $34 ($16) ($17) ($17) ($17) ($17) ($17) ($16)
Change inDSM ($41) $0 ($1) ($2) ($3) ($3) ($3) ($4) ($5) ($5) ($5) ($5) ($6) ($5) ($5) ($5) ($6) ($6) ($6) ($6) ($6)
Change in Deficiency ($4) (SO) $0 $0 ($1) ($3) ($O) ($1) ($1) $0 ($0) $0 $0 ($0) $0 $0 ($1) $0 $0 $0 $0
Change in System Fixed Cast ($20) (SO) ($0) ($0) ($0) ($0) ($O) ($0) ($0) ($0) $48 $49 $49 ($40) $30 ($42) ($43) ($45) ($46) ($48) ($49)
Net(Bencfit)/Cost $393 $0 ($1) ($2) ($5) $18 $21 $19 $33 $36 $62 $74 $70 $80 $23 $80 $68 $39 $28 $20 ($12)
Risk Adjustment ($104)
Net(Benefit)/Cost with Risk Adjustment $289

Rocky Mountain Power
Exhibit No.31 Page 2 of 3
Case No. PAC-E-24-04
Witness:Rick T.Link
High Gas,Iligh CO2
(Benefit)/Cos[ I PVRR(d) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Cost of Project $1,808 $0 $0 $0 $0 $193 $194 $199 $214 $217 $225 $231 $234 $240 $167 $298 $301 $298 $300 $304 $309
New Wind Capital Cost $396 $0 $0 $0 $0 $33 $34 $34 $40 $40 $42 $45 $45 $47 $51 $93 $94 $94 $95 $97 $99
Wind Run-Rate Fixed Costs $327 $0 $0 $0 $0 $51 $51 $54 $53 $55 $56 $57 $59 $59 $56 $16 $17 $17 $17 $17 $17
PPA $1,304 $0 $0 $0 ($0) $180 $181 $188 $197 $202 $208 $215 $220 $224 $149 $130 $132 $129 $129 $132 $134
PTC Credits ($749) $0 $0 $0 $0 ($131) ($131) ($135) ($134) ($139) ($140) ($143) ($148) ($148) ($148) $0 $0 $0 $0 $0 $0
Wind Tax $14 $0 $0 $0 $0 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2
Transmission GWS $1,261 $0 $0 $0 $0 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138
Transmission D.1 $185 $0 $0 $0 $0 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20
Avoided Transmission-Base 230 kV ($843) $0 $0 $0 $0 ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92)
Transmission Network Wind $41 $0 $0 $0 $0 $5 $5 $5 $5 $4 $4 $4 $4 $4 $4 $5 $4 $4 $4 $4 $4
Transmission OATT Credit ($129) $0 $0 $0 ($0) ($14) ($14) ($14) 14) 14 14 14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14)
Change in NPC ($1,697) $0 $1 $1 ($4) ($185) ($183) ($199) ($217) ($206) ($232) ($241) ($259) ($217) ($211) ($237) ($233) ($269) ($346) ($349) ($339)
Change in Emissions ($936) $0 $0 $0 $0 ($71) ($79) ($86) ($84) ($109) ($160) ($161) ($169) ($125) ($153) ($150) ($186) ($188) ($130) ($170) ($203)
Change in VOM&Driver Adjustments ($37) ($0) $0 $0 $0 ($3) ($3) ($3) ($3) ($3) ($2) ($2) ($3) $34 ($16) ($16) ($16) ($17) ($17) ($19) ($18)
Change in DSM ($41) $0 ($1) ($2) ($3) ($3) ($3) ($4) ($5) ($5) ($5) ($5) ($6) ($5) ($5) ($5) ($6) ($6) ($6) ($6) ($6)
Change in Deficiency ($8) ($3) $0 $0 ($1) ($3) $0 ($1) ($3) $0 ($0) ($0) ($2) ($0) ($0) $0 $0 $0 $0 $0 $0
Change in System Fixed Cost ($20) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) $48 $49 $49 ($40) $30 ($42) ($43) ($45) ($46) ($48) ($49)
Net(Benefit)/Cost ($932) ($3) ($1) ($1) ($8) ($72) ($75) ($95) ($98) ($106) ($125) ($130) ($154) ($113) ($189) ($154) ($183) ($227) ($246) ($287) ($306)
Risk Adjustment ($168)
Net(Benefit)/Cost with Risk Adjustment ($1,100)
(Benefit)/Cost PVRR(d) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Cost ofProiect $1,838 $0 $0 $0 $0 $194 $195 $200 $214 $217 $225 $231 $234 $240 $238 $298 $301 $298 $300 $304 $309
New Wind Capital Cost $397 $0 $0 $0 $0 $34 $34 $34 $40 $40 $42 $45 $45 $47 $51 $93 $94 $94 $95 $97 $99
Wind Run-Rate Fixed Costs $326 $0 $0 $0 $0 $51 $51 $54 $53 $55 $56 $57 $59 $59 $56 $16 $17 $17 $17 $17 $17
PPA $1,332 $0 $0 $0 ($0) $180 $181 $188 $197 $202 $208 $215 $220 $224 $220 $130 $132 $129 $129 $132 $134
PTC Credits ($748) $0 $0 $0 $0 ($130) ($130) ($134) ($134) ($139) ($140) ($143) ($148) ($148) ($148) $0 $0 $0 $0 $0 $0
Wind Tax $14 $0 $0 $0 $0 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2
Transmission GWS $1,261 $0 $0 $0 $0 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138
Transmission D.1 $185 $0 $0 $0 $0 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20
Avoided Transmission-Base 230 kV ($843) $0 $0 $0 $0 ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92)
Transmisison Network Wind[1] $41 $0 $0 $0 $0 $5 $5 $5 $5 $4 $4 $4 $4 $4 $4 $5 $4 $4 $4 $4 $4
Transmission OATT Credit ($128.78) $0.00 $0.00 $0.00 ($0.07) ($14.19) ($14.17) ($14.14) ($14.13) ($14.11) ($14.10) ($14.08) ($14.06) ($14.05) ($14.04) ($14.14 ( 1a.1z) ( 1a.1o) ( 1a.o8) ( 1a.o7) ( 14.06)
Change in NPC ($948) ($0) $0 $0 ($2) ($105) ($109) ($115) ($120) ($119) ($141) ($141) ($147) ($118) ($123) ($122) ($130) ($151) ($159) ($165) ($200)
Change in Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Change inVOM&Driver Adjustments ($40) $0 $0 $0 $0 ($4) ($5) ($6) ($3) ($2) ($2) ($3) ($3) $34 ($17) ($17) ($17) ($17) ($17) ($17) ($17)
Change inDSM ($41) $0 ($1) ($2) ($3) ($3) ($3) ($4) ($5) ($5) ($5) ($5) ($6) ($5) ($5) ($5) ($6) ($6) ($6) ($6) ($6)
Change in Deficiency ($5) ($0) $0 $0 ($2) ($3) ($0) ($1) ($2) ($0) ($0) $0 $0 ($0) $0 ($0) ($0) $0 $0 $0 $0
Change in System Fixed Cost ($48) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) $48 $49 $49 ($40) ($41) ($42) ($43) ($45) ($46) ($48) ($49)
Net(Benefit)/Cost $755 ($0) ($1) ($2) ($6) $79 $77 $74 $84 $90 $125 $132 $128 Sill $52 Sill $105 $79 $72 $69 $38
Risk Adjustment ($85)
Net(Benefit)/Cost with Risk Adjustment $670

Rocky Mountain Power
Exhibit No.31 Page 3 of 3
Case No. PAC-E-24-04
Witness:Rick T.Link
(Benefit)/Cost I PFRR(d) 2021 2022 2023 2024 1 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 1 2034 1 2035 2036 2037 1 2038 1 2039 2040
Cost of Project $1,836 $0 $0 $0 $0 $192 $194 $199 $214 $217 $225 $231 $234 $240 $238 $298 $301 $298 $300 $304 $309
New Wind Capital Cost $396 $0 $0 $0 $0 $33 $34 $34 $40 $40 $42 $45 $45 $47 $51 $93 $94 $94 $95 $97 $99
Wind Run-Rate Fixed Costs $328 $0 $0 $0 $0 $51 $52 $54 $53 $55 $56 $57 $59 $59 $56 $16 $17 $17 $17 $17 $17
PPA $1,332 $0 $0 $0 (s0) $180 $181 $188 $197 $202 $208 $215 $220 $224 $220 $130 $132 $129 $129 $132 $134
PTC Credits ($750) $0 $0 $0 $0 ($131) ($131) ($135) ($134) ($139) ($140) ($143) ($148) ($148) ($148) $0 $0 $0 $0 $0 $0
Wind Tax $14 $0 $0 $0 $0 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2 $2
Transmission GWS $1,261 $0 $0 $0 $0 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138 $138
Transmission D.1 $185 $0 $0 $0 $0 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20 $20
Avoided Transmission-Base 230 kV ($843) $0 $0 $0 $0 ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92) ($92)
Transmission Network Wind $41 $0 $0 $0 $0 $5 $5 $5 $5 $4 $4 $4 $4 $4 $4 $5 $4 $4 $4 $4 $4
Transmission OATT Credit ($129) $0 $0 $0 ($0) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14) ($14)
Change in NPC ($2,129) $0 ($1) ($6) ($4) ($217) ($230) ($243) ($260) ($296) ($363) ($350) ($357) ($286) ($288) ($292) ($304) ($380) ($270) ($291) (359)
Change in Emissions ($1,919) ($0) $3 $5 ($3) ($317) ($264) ($266) ($245) ($246) ($286) ($286) ($296) ($198) ($218) ($229) ($260) ($257) ($274) ($274) ($260)
Change in VOM ($30) $0 ($0) $0 $0 ($1) ($1) ($2) ($2) ($2) ($1) ($2) ($2) $35 ($16) ($16) ($15) ($22) ($15) ($14) ($17)
Change in DSM ($41) $0 ($1) ($2) ($3) ($3) ($3) ($4) ($5) ($5) ($5) ($5) ($6) ($5) ($5) ($5) ($6) ($6) ($6) ($6) ($6)
Change in Deficiency ($236) ($0) $0 ($15) ($3) ($67) ($38) ($16) ($25) ($4) ($126) $0 $0 $0 ($0) $0 ($0 233) 0 0 69
Change in System Fixed Cost ($48) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) $48 $49 $49 ($40) ($41) ($42) ($43) ($45) ($46) ($48) ($49)
Net(Benefit)/Cost ($2,568) (SO $1 ($18) ($13) ($412) ($343) ($331) ($322) ($336) ($508) ($363) ($377) ($254 (331) (287) (328) (646) (312) (328) (312)
Risk Adjustment ($251)
Net(Benefit)/Cost with Risk Adjustment ($2,819)