20240531Direct T. Burns - Redacted.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 ) THOMAS R. BURNS
APPROVAL OF PROPOSED ) REDACTED
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 current
3 position with PacifiCorp d/b/a Rocky Mountain Power (the
4 "Company") .
5 A. My name is Thomas R. Burns, my business address is 825
6 NE Multnomah Street, Suite 600, Portland, Oregon 97232 .
7 I am currently employed as Vice President of Resource
8 Planning and Acquisitions for PacifiCorp.
9 Q. Please describe your education and professional
10 experience.
11 A. I graduated from Illinois State University with a
12 Bachelor of Science degree in Economics . I joined
13 PacifiCorp in 2007 and assumed the responsibilities of
14 my current position in September 2022 . Over this period,
15 I held several operational, analytical and leadership
16 positions within the Company. My previous role with
17 PacifiCorp was Director of Energy Supply Management,
18 Operations, and Reliability. In that role I was
19 instrumental in the design and implementation of the
20 Western Energy Imbalance Market .
21 Q. Briefly describe the responsibilities of your current
22 position.
23 A. I am responsible for PacifiCorp' s resource planning and
24 procurement functions, which include the integrated
25 resource plan ("IRP") , structured commercial business
Burns, Di 1
Rocky Mountain Power

1 and valuation activities, and long-term load forecasts .
2 Most relevant to this general rate case, I oversee the
3 planning, analysis, and outreach processes that are used
4 to develop PacifiCorp' s IRP, and the economic analysis
5 that helps guide the Company' s resource acquisitions .
6 II . PURPOSE OF TESTIMONY
7 Q. What is the purpose of your testimony in this case?
8 A. I provide economic analysis that supports PacifiCorp' s
9 decisions to: acquire the 190-megawatt ("MW") Rock Creek
10 I wind facility; and acquire and repower the 43 MW Foote
11 Creek II-IV and 50 MW Rock River I wind facilities in
12 Wyoming.
13 I also summarize PacifiCorp' s assessment of the
14 projects from the 2021 IRP and IRP Update, 2020 All-
15 Source Request for Proposals ("2020AS RFP") , and
16 customer benefits that result from these projects .
17 Q. Please provide an overview of your testimony for Rock
18 Creek I .
19 A. My economic analyses show that the project is in the
20 public interest and will generate significant benefits
21 for Idaho customers across all scenarios . Analysis
22 prepared before passage of the Inflation Reduction Act
23 ("IRA") showed risk-adjusted benefits ranging from a
24 present-value revenue requirement differential
25 ("PVRR (d) ") $2 million benefit to customers in the low
Burns, Di 2
Rocky Mountain Power

1 natural gas, no carbon scenario, to a $20 million benefit
2 in the medium natural gas, medium carbon scenario.
3 The post-IRA analysis of both Rock Creek I and Rock
4 Creek II (a co-located sister facility that the Company
5 analyzed together with Rock Creek I after passage of the
6 IRA) yields customer benefits totaling $298 million,
7 that rise to $318 million on a risk-adjusted basis under
8 an MM price-policy scenario. Conservatively, these
9 benefits do not assign any value to the renewable energy
10 certificates ("RECs") that will be generated by Rock
11 Creek I and Rock Creek II, which can provide additional
12 customer benefits if sold, transferred, or used to
13 comply with relevant state requirements .
14 Q. Please provide an overview of your testimony for Foote
15 Creek II-IV and Rock River I repowering projects .
16 A. My economic analyses indicate that these projects are in
17 the public interest and will generate benefits for Idaho
18 customers .
19 Benefits for Foote Creek II-IV range from $53 . 07
20 million when using medium natural gas and medium carbon
21 dioxide ("CO2") assumptions to $142 . 77 million for high
22 natural gas and the social cost of greenhouse gases
23 assumptions prior to adjusting for benefits from the
24 IRA. This is compared to a $17 . 09 million customer cost
25 in the LN scenario. These benefits increase to $76 . 49
Burns, Di 3
Rocky Mountain Power

1 million when using medium natural gas and medium CO2
2 assumptions and $104 . 23 million for high natural gas and
3 high CO2 assumptions when factoring in the IRA.
4 Importantly, the only scenario where Foote Creek II-IV
5 was expected to generate customer costs prior to passage
6 of the IRA—the LN scenario ($17 . 09 million)—has
7 transformed to a $6 . 33 million customer benefit. These
8 benefits only increase under the highest cost of carbon
9 scenario (MM-SCGHG) .
10 Similarly, benefits for Rock River I range from
11 $30 . 15 million when using medium natural gas and medium
12 CO2 assumptions to $67 . 76 million for high natural gas
13 and high CO2 assumptions before adjusting for the IRA.
14 When factoring in the IRA, these benefits increased to
15 $54 . 09 million when using medium natural gas and medium
16 CO2 assumptions and $91 . 69 million for high natural gas
17 and high CO2 assumptions .
18 Like Rock Creek I, the analyses of both facilities
19 does not assign any value to the RECs that will be
20 generated by either Foote Creek II-IV or Rock River I,
21 which will provide additional customer benefits if sold,
22 transferred, or used to comply with relevant state
23 requirements .
Burns, Di 4
Rocky Mountain Power

1 III . ROCK CREEK I
2 Q. Please generally describe the Rock Creek I.
3 A. As described in the confidential testimony of Company
4 witness Jeffrey M. Wagner, PacifiCorp is acquiring the
5 190 MW Rock Creek I project under a build-transfer
6 agreement ("BTA") from Invenergy, and will be
7 transferred to the Company after construction is
8 complete . My testimony provides the economic
9 justification for the Company' s decision to acquire this
10 project .
11 A. Resource Need
12 Q. Please provide an overview of the Company' s IRP process .
13 A. PacifiCorp' s IRP process uses thorough analysis and
14 modeling that measures cost and risk to develop the
15 Company' s plans to provide reliable and reasonably
16 priced service for its customers . The primary objective
17 of the IRP is to identify the least-cost, least-risk
18 portfolio of resources that can serve customers in the
19 future with manageable risks .
20 The Company completes an IRP cycle every two years
21 (odd-numbered years) , which includes preparing a full
22 IRP every two years and an update to the full IRP in the
23 off years (even-numbered years) . The Company submits
24 both its IRP and IRP Update to each of the six regulatory
25 commissions in the states where the Company provides
Burns, Di 5
Rocky Mountain Power

1 retail service . Each IRP is developed through an open
2 and public process, with input from an active and diverse
3 group of stakeholders, including state regulatory
4 commissions, state consumer-advocacy departments,
5 customer-sponsored advocacy groups, environmental-
6 advocacy groups, resource-advocacy groups, independent-
7 power producers, project developers, other utilities,
8 and customers . During the public-input process, which
9 typically spans at least a full year before the release
10 of a full IRP, PacifiCorp holds regular meetings with
11 stakeholders to solicit feedback on the Company' s
12 planning assumptions, methodologies, and model results .
13 Q. Did the Company' s 2021 IRP identify a need for additional
14 resources to serve PacifiCorp' s customers?
15 A. Yes . The primary focus of any IRP is to forecast the
16 need for resources and evaluate different strategies to
17 meet that need over time. The Company' s 2021 IRP
18 indicated that PacifiCorp has a capacity deficit in all
19 years of the planning horizon—starting at 1, 071 MW in
20 2021 and increasing to over 6, 600 MW by 2040 . In 2025,
21 the resource need in the 2021 IRP is 1, 627 MW. As
22 described further below, this need has increased since
23 the 2021 IRP was released.
Burns, Di 6
Rocky Mountain Power

1 Q. How does the 2021 IRP preferred portfolio address the
2 need for new resources?
3 A. The 2021 IRP preferred portfolio represents PacifiCorp' s
4 least-cost, least-risk plan to reliably meet customer
5 demand over a 20-year planning period. Using a range of
6 cost and risk metrics to evaluate numerous resource
7 portfolios, PacifiCorp selected a preferred portfolio
8 that reflects a cost-conscious plan that includes near-
9 term investments in renewable resources that can capture
10 tax credits before they expire or decrease, and new
11 transmission infrastructure to facilitate the
12 interconnection and delivery of these resources . These
13 new resources and transmission investments are lower
14 cost than other resource and transmission alternatives
15 and are necessary to reliably serve our customers .
16 Q. Can you describe the methodology that PacifiCorp used in
17 the 2021 IRP to analyze the economics of the preferred
18 portfolio?
19 A. Yes . PacifiCorp incorporated a new and more advanced
20 optimization modeling system called PLEXOS . The PLEXOS
21 modeling system provides three platforms (referred to as
22 Long-term ("LT") , Medium-term ("MT") and Short-term
23 ("ST") ) , which work on an integrated basis to inform the
24 optimal combination of resources by type, timing, size,
25 and location over PacifiCorp' s 20-year planning horizon.
Burns, Di 7
Rocky Mountain Power

1 Please refer to Company witness Rick T. Link' s testimony
2 for additional detail regarding PLEXOS and the LT, MT,
3 and ST platforms .
4 Q. Does PacifiCorp have a need for Rock Creek I?
5 A. Yes . As discussed above, the 2021 IRP preferred
6 portfolio indicated a demonstrated need for new
7 resources . The Company proposed to begin addressing this
8 need through 1, 792 MW of new wind generation resulting
9 from the 2020AS RFP, which included Rock Creek I . '
10 Q. Please describe key factors that support including Rock
11 Creek I in PacifiCorp' s 2021 IRP preferred portfolio.
12 A. The project is expected to meet the Company' s near-term
13 resource need and provide significant customer benefits
14 by providing zero-fuel cost generation and substantial
15 production tax credit ("PTC") benefits, while mitigating
16 risks associated with future regulation of carbon-
17 emitting resources .
18 Q. Please describe the reliability benefits of projects
19 like Rock Creek I .
20 A. Rock Creek I reduces the Company' s exposure to price and
21 volume volatility by reducing the need for market
22 purchases . Increased reliance on the market exposes
23 customers to price volatility and price spikes that
24 occur when the region experiences severe weather events
1 2021 IRP, Vol. I, Ch. 9.
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Rocky Mountain Power

1 or system disruptions . Such events increase net power
2 costs, and the magnitude of increase is directly
3 proportional to the volume of purchases needed. In
4 short, there is no guarantee that there will be a seller
5 when PacifiCorp needs to make a short-term purchase to
6 serve its load. This risk also exists for firm forward
7 market purchases, where the seller could cut scheduled
8 deliveries and accept liquidated damages if they do not
9 have sufficient supply to meet their contractual
10 obligations of the sale. As discussed in Company witness
11 Link' s testimony, Western Electricity Coordinating
12 Counsel and North American Electric Reliability
13 Corporation ("NERC") reliability studies highlight the
14 risks of resource shortfalls across the region in the
15 coming years .
16 Q. How do these studies relate to Rock Creek I?
17 A. Each of these studies confirm the generally accepted
18 understanding that the west is facing increasing
19 resource adequacy risks in the near term. More recently,
20 NERC further confirmed these findings and warned in its
21 2022 Summer Reliability Assessment that several regions
22 in North America were at high or elevated risk of power
23 outages this past summer due to above-normal
Burns, Di 9
Rocky Mountain Power

1 temperatures and drought conditions, particularly in the
2 western half of Canada and the United States .2
3 Rock Creek I will help mitigate the risk that there
4 may be inadequate supply to support market purchases and
5 reduce exposure to price spikes in periods where demand
6 threatens to exceed supply for market purchases .
7 Q. Was Rock Creek I selected in the 2020AS RFP?
8 A. Yes . As discussed in Company witness Link' s testimony,
9 the 2020AS RFP final shortlist included six final
10 shortlist bids representing over 1, 600 MW of wind
11 generation that seek to interconnect to PacifiCorp' s
12 transmission system. These bids include Rock Creek I
13 which, with Rock Creek II, were the only two bids that
14 were not power purchase agreements .
15 Q. Following its selection in the 2020AS RFP final
16 shortlist, did the Company begin negotiating a BTA for
17 Rock Creek I?
18 A. Yes . As discussed by Company witness Wagner, the Company
19 engaged in BTA negotiations with Invenergy for the
20 project .
z 2022 Summer Reliability Assessment, North American Electric
Reliability Corporation (May 2022)
(https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC SR
A 2022.pdf) .
Burns, Di 10
Rocky Mountain Power

1 Q. Were negotiations impacted by current economic
2 conditions?
3 A. Yes . Bidder development efforts were challenged by
4 importation restrictions related to China, COVID-19
5 international impacts, and hostilities in Ukraine that
6 created significant logistics and supply chain
7 challenges associated with solar panels, wind turbines,
8 lithium batteries, transformers, and many balance-of-
9 plant materials . As a result, many developers have been
10 forced to abandon established supply chains and revert
11 to new suppliers (if available) , which has materially
12 impacted overall renewable power plant pricing and
13 commitments toward project in-service dates .
14 Given PacifiCorp' s need for generation resources,
15 PacifiCorp allowed pricing adjustments from all final
16 shortlist projects from the 2020AS RFP, as well as
17 limited extensions to commercial operations dates .
18 Despite this additional flexibility, some of the bids
19 from the final shortlist were unable to provide firm
20 prices and were not available for selection. This
21 contributed to an under procurement of 902 MW of solar
22 capacity and 497 MW of battery capacity.
23 Q. Have current economic conditions impacted costs for Rock
24 Creek I compared to the costs from initial bids?
25 A. Yes . Given the market dynamics discussed above, the
Burns, Di 11
Rocky Mountain Power

1 overall costs for Rock Creek I has increased from its
2 initial bid in the 2020AS RFP. My economic analysis below
3 is based on updated project costs .
4 Q. Were there any additional benefits associated with Rock
5 Creek I that offset these increased costs?
6 A. Yes . PacifiCorp' s original economic analysis in the
7 2020AS RFP assumed that Rock Creek I qualified for a 60
8 percent PTC through the first 10 years of operation. As
9 a result of the IRA, the economic analysis in this case
10 reflects the value of the 110 percent PTC, in addition
11 to the updated project costs . These updates cause a
12 significant and positive change in the economic benefits
13 of the project.
14 Q. Have current economic drivers also impacted the
15 Company' s resource needs?
16 A. Yes . While the costs of 2020AS RFP bids have increased,
17 the Company' s resource needs have also increased. It is
18 also important to consider the broader regional capacity
19 need that aligns with the Company' s need and expected
20 in-service date for Rock Creek I . The 2020AS RFP included
21 virtually every potential non-market resource in the
22 region capable of achieving commercial operation by
23 2025 . Meeting this near-term need with physical assets
24 that will provide incremental generation capacity
Burns, Di 12
Rocky Mountain Power

1 effectively limits the Company' s options to bidders in
2 the 2020AS RFP.
3 Therefore, the 2020AS RFP bids and Rock Creek I
4 remain necessary to reliably serve Idaho customers, and
5 Rock Creek I selection in the RFP confirms it is part of
6 the least-cost, least-risk resources available to meet
7 the Company' s need.
8 Q. Did the Company prepare an update to the 2021 IRP?
9 A. Yes . On March 31, 2022, the Company issued its 2021 IRP
10 Update .3
11 Q. What is the purpose of the 2021 IRP Update?
12 A. The IRP update is a checkpoint on the 2021 IRP action
13 plan and ensures that changes in the planning
14 environment are considered between the two-year IRP
15 planning cycle. The 2021 IRP Update assessed whether
16 evolving trends and events impact customers and required
17 changes to the action plan to deliver resources and
18 transmission investments . Relevant here, the 2021 IRP
19 Update reflects resource planning and procurement
20 activities that occurred since the 2021 IRP, and present
21 an updated load-and-resource balance and an updated
22 resource portfolio .
3 PacifiCorp 2021 Integrated Resource Plan Update (Mar. 31, 2022)
(https://www.pacificorp.com/energy/integrated-resource-plan.html) .
Burns, Di 13
Rocky Mountain Power

1 Q. Was Rock Creek I included in the Company' s 2021 IRP
2 Update preferred portfolio?
3 A. Yes . 4
4 Q. Where there any important modeling updates in the 2021
5 IRP Update?
6 A. As discussed in Chapter 5 of the 2021 IRP Update, key
7 updates in addition to the load-and-resource balance
8 include the resource changes due to 2020AS RFP activity,
9 which is discussed further below. Importantly, the EPA' s
10 pre-publication version of the OTR, released on March
11 11, 2022, was not modeled in the 2021 IRP Update.
12 Q. Did the 2021 IRP Update continue to show a need for
13 additional generation resources?
14 A. Yes . As discussed in Company witness Link' s testimony,
15 the need increased due to an increase in forecast load.
16 The 2021 IRP Update shows a resource need in all years
17 of the planning horizon—starting at 1, 584 MW in 2022 and
18 increasing to 6, 755 MW in 2040 . In 2025, the resource
19 need is 1, 867 MW, an increase of 240 MW, or approximately
20 15 percent, relative to the resource need identified in
21 the 2021 IRP. The higher load reflected in the 2021 IRP
22 Update approaches the level analyzed in the high-load
23 sensitivity conducted in the 2021 IRP. The most recent
n Id.at Ch. 7, Action Item 2e, at 103 (Mar. 31, 2022) .
Burns, Di 14
Rocky Mountain Power

1 load forecast is even higher than that assumed in the
2 2021 IRP Update.
3 Moreover, now that the 2020AS RFP has ended,
4 PacifiCorp was unable to execute firm contracts with all
5 projects on the final shortlist. Due to national tariff
6 policies, global supply-chain issues, and inflationary
7 pressures, some projects on the 2020AS RFP final
8 shortlist were unable to move forward. Consequently,
9 PacifiCorp' s procurement was reduced by 902 MW of solar
10 resources and 497 MW of battery storage resources . This
11 under-procurement adds to our need for new resources .
12 Q. Does the 2021 IRP Update consider the reliability issues
13 related to reliance on market purchases?
14 A. Yes . Given near-term concerns over resource adequacy,
15 and because of the acquisition of additional resources
16 including Rock Creek I, the 2021 IRP Update' s preferred
17 portfolio shows generally lower market purchases in the
18 first five years relative to the 2021 IRP preferred
19 portfolio .5
20 B. Modeling Assumptions and Methods
21 Q. Did the Company analyze Rock Creek I and Rock Creek II
22 together?
23 A. Yes, for the most part. As stated above, there were two
24 BTA wind facilities in the Company' s final shortlist of
5 Id. at Figure 1.11.
Burns, Di 15
Rocky Mountain Power

1 projects : Rock Creek I and Rock Creek II . The second
2 facility is a larger wind facility, at 400 MW compared
3 to Rock Creek I at 190 MW. In previous regulatory
4 proceedings, the Company analyzed the wind projects
5 together to determine whether acquiring the projects
6 would provide net benefits to customers . This was
7 reasonable, because the projects are co-located with
8 each other and share the same modeling assumptions .
9 In this proceeding the Company is only requesting
10 rate recovery of Rock Creek I, because Rock Creek II has
11 an in-service date that falls outside the test period of
12 this rate case. Nonetheless, several of the analyses
13 below include combined results from both wind projects,
14 as well as Rock Creek I specific analyses . This allows
15 the Commission to examine both the additive benefits
16 that will occur when wind projects are interconnected to
17 PacifiCorp' s system, but also the Rock Creek I specific
18 customer benefits that inform the Company' s revenue
19 requirement in this proceeding.
20 Q. Please summarize the natural gas and CO2 price
21 assumptions used in the economic analysis of Rock
22 Creek I .
23 A. The economic analysis of Rock Creek I included three
24 price-policy scenarios—medium natural gas paired with
25 medium CO2 prices ("MM") , medium natural gas prices
Burns, Di 16
Rocky Mountain Power

1 without a CO2 price ("MN") , and low natural gas without
2 a CO2 price ("LN") price-policy scenarios . While the MM
3 price-policy scenario represents the Company' s "expected
4 case" describing likely future conditions, the
5 additional scenarios provide additional helpful
6 analyses .
7 These assumptions influence the value of system
8 energy, the dispatch of system resources, and
9 PacifiCorp' s resource mix. Consequently, wholesale-
10 power prices and CO2 policy assumptions affect NPC
11 benefits, non-NPC variable-cost benefits, and system
12 fixed-cost benefits associated with Rock Creek I .
13 Because wholesale power prices and CO2 policy outcomes
14 are both uncertain and important drivers to the economic
15 analysis, it is important to evaluate a range of
16 assumptions for these variables . Table 1 summarizes the
17 price-policy scenarios .
Burns, Di 17
Rocky Mountain Power

Table 1 . Price-Policy Scenario Assumption Overview
Henry Hub
Price- Natural Gas CO2 Price
Policy Price Description
Scenario (Levelized
$/MMBtu) *
$12 . 10/ton
MM $4 . 52 starting 2025
rising to
MN $4 . 52 None
LN $2 . 92 None
*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 June 30, 2022, which was the most current OFPC available
6 when PacifiCorp prepared its modeling inputs for the
7 2020AS RFP. The first 36 months of the OFPC reflect
8 market forwards at the close of a given trading day (June
9 30, 2022 in this case) . As such, these 36 months are
10 market forwards as of June 2022 . The blending period
11 (months 37 through 48) is calculated by averaging the
12 month-on-month market forwards from the prior year with
13 the month-on-month fundamentals-based price from the
14 subsequent year. The fundamentals portion of the natural
15 gas OFPC reflects Aurora-forecast prices .
Burns, Di 18
Rocky Mountain Power

1 Q. Please describe the CO2 price assumptions used in the
2 price-policy scenarios .
3 A. PacifiCorp used two different CO2 price scenarios—zero
4 and medium. The medium scenario is derived from a survey
5 of third-party industry experts, including IHS CERA, and
6 Wood Mackenzie and the Energy Information Administration
7 as well as CO2 price assumptions used by peer utilities .
8 The resulting CO2 price is applied as a tax beginning in
9 2025 .
10 Q. Does including potential future CO2 costs reflect prudent
11 utility planning?
12 A. Yes . The Company' s price-policy scenarios include
13 varying levels of assumed CO2 costs to reflect the fact
14 it is more likely than not that some policy will exist
15 that will reduce emissions for carbon emitting
16 resources . When determining CO2 costs used for planning
17 purposes, the Company strives to ensure that it is not
18 an outlier, and the medium price is within a reasonable
19 range used by the industry to assess risk and conduct
20 prudent resource planning. The most recent example of
21 this trend is the Environmental Protection Agency' s
22 ("EPA") proposed Ozone Transport Rule ("OTR")
23 restricting nitrogen oxide ("NOX") emissions from power
24 plants and other industrial sources . At the time the
25 Company conducted its economic analyses, this rule would
Burns, Di 19
Rocky Mountain Power

1 have imposed new environmental compliance obligations
2 beginning in 2023 and 2024 on coal units in Utah and
3 Wyoming, respectively, with more severe limitations
4 applicable in both states by 2026 . 6
5 Q. Are the modeled CO2 costs intended to represent a literal
6 carbon tax?
7 A. No . The modeled CO2 costs are not intended to explicitly
8 account for a future tax on CO2 emissions . Rather, these
9 costs capture the effect of policies incentivizing
10 reduced emissions through benefits or imposing costs
11 through penalties or other costs resulting from market
12 dynamics driving the need for zero-emission resources or
13 customer preferences .
14 Q. Did PacifiCorp update its load forecast in its analysis
15 of Rock Creek I?
16 A. Yes . The Company used a sales and load forecast that was
17 completed in May 2022 .
18 Q. How does the May 2022 forecast compare to the load
19 forecast used in the 2021 IRP?
20 A. Figures 1 and 2 show PacifiCorp' s May 2022 load and peak
21 forecast relative to the 2021 IRP before incremental
6 While these requirements are now subject to further federal litigation
and agency review (see, e.g. , Wyoming, et al. , v. United States
Environmental Protection Agency, et al. , 78 F4th 1171 (loth Cir. 2023)
(OTR vacated and remanded in part) ; Utah, et al. , v. United States
Environmental Protection Agency, et al. , No. 23-9509 (Jul. 27, 2023)
(staying OTR until final resolution for Utah) ) , the Company's economic
analyses reflects then-current assumptions that the OTR would be in
effect.
Burns, Di 20
Rocky Mountain Power

1 energy efficiency savings . A higher load forecast is
2 being driven by new industrial and commercial customer
3 growth, increased air conditioning saturations and
4 miscellaneous devices and electric vehicle adoption
5 expectations . The updated load forecast also accounts
6 for updates to weather, temperature, and line losses to
7 account for the progression of historical data since the
8 load forecast that informed the 2021 IRP.
9 On average, over the 2023 through 2040 timeframe,
10 forecast system load is up 13 . 6 percent per year and
11 forecast coincident system peak is up 14 . 1 percent per
12 year when compared to the 2021 IRP. Over that same
13 timeframe, the average annual growth rate for the May
14 2022 forecast, before accounting for incremental energy
15 efficiency improvements, is 2 . 04 percent for load and
16 1 . 66 percent for peak.
Burns, Di 21
Rocky Mountain Power

Figure 1 . Forecast Annual System Load
100,000
90,000
3 80,000
C7 70,000
o _ T _
60,000
a�
50,000
40,000
30,000
c 20,000
Q 10,000 }2021 IRP May 2022
0
M IV Vi 1O [-- 00 Q� O N M IV to �O [-- 00 ON O
N N N N N N N tri M t*i M M N'i M M lri M �
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
Figure 2 . Forecast Annual System Coincident Peak
16,000
3
14,000
12,000
a
10,000
3
8,000
o
6,000
U
4,000
+2021 IRP +May 2022
2,000
a
Q 0
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
Burns, Di 22
Rocky Mountain Power

1 Q. Has PacifiCorp incorporated the EPA' s proposed OTR in
2 its analysis of Rock Creek I?
3 A. Yes . PacifiCorp modeled two primary components to
4 reflect the OTR: NOX allowance requirements for each of
5 its units including penalties for units with high
6 emissions rates, and a dispatch target or shadow price
7 for NOX allowances, which is used to avoid producing NOX
8 emissions during periods when the economic benefits are
9 relatively low. After running the model, PacifiCorp
10 compared the results to forecasts of its annual
11 allocation of NOX allowances for Utah and Wyoming.
12 Q. Please describe how the annual allocation of NOx
13 allowances would work under the proposed rule.
14 A. The proposed rule calls for dynamic budgeting of NOX
15 allowances in 2025 and beyond, with available allowances
16 allocated among resources within a state based on the
17 recent historical heat input and emissions rates of each
18 resource . Under the EPA' s proposed rule, the forecast
19 allocation of NOX allowances drops significantly in 2026,
20 as the EPA assumed that selective catalytic reduction
21 ("SCR") installations at eligible facilities would
22 significantly reduce emissions by that year.
23 PacifiCorp' s thermal facilities in Utah would be covered
24 by the rule beginning 2023 and thermal facilities in
25 Wyoming could be covered by the rule beginning 2024 .
Burns, Di 23
Rocky Mountain Power

1 While trading of NOx allowances among participating
2 states is allowed, the proposed OTR includes significant
3 penalties if a state' s emissions exceed 121 percent of
4 its annual allocation. Limited banking of NOx allowances
5 is also allowed, but emissions met via banked allowances
6 may also be subject to penalties if a state' s emissions
7 exceed 121 percent of its annual allocation. To avoid
8 such penalties, PacifiCorp' s NOx emissions during the
9 ozone season (May-September) in each state cannot exceed
10 121 percent of PacifiCorp' s forecast allocation of NOx
11 allowances for that state .
12 Q. Please describe how PacifiCorp developed NOx allowance
13 requirements for each of its units .
14 A. In general, an allowance for one ton of NOx emissions
15 would allow the holder of the allowance to emit one ton
16 of NOx. However, starting in 2027, 7 the proposed OTR also
17 imposes a daily NOx emissions rate limit of 0 . 14 pounds-
18 per-million British thermal units ("lb/MMBtu") for each
19 coal-fired facility, and requires emitters to provide an
20 equivalent of triple allowances for any emissions that
21 exceed that rate . For example, a resource with an
22 emissions rate of 0 . 20 lb/MMBtu would have an effective
' Coal units that currently have SCR installed must meet the daily backstop
limit in 2024. Coal units that do not currently have SCR installed must
meet the daily backstop limit in 2027.
Burns, Di 24
Rocky Mountain Power

1 allowance requirement of 0 . 32 lb/MMBtu. 8 To calculate
2 PacifiCorp' s NOx allowance requirements under the OTR,
3 starting in 2027 the modeled emission rates for coal
4 resources whose emissions exceed 0 . 14 lb/MMBTU were
5 grossed up to account for the additional surrender of
6 allowances .
7 Q. Please describe how PacifiCorp developed a dispatch
8 target to manage its NOx allowance requirements .
9 A. While trading is allowed under the EPA' s proposed OTR,
10 the restrictions on inter-state transfers limit the
11 number of potential counterparties . PacifiCorp' s
12 generation fleet is an appreciable portion of the
13 electric generating units in both Utah and Wyoming, so
14 the potential counterparties that could have allowances
15 available for sale within those states is quite limited.
16 With that in mind, PacifiCorp' s current planning assumes
17 that it will comply with the OTR using only its own
18 combined allocation of NOx allowances and is meant to
19 ensure that its annual allowance requirements do not
20 exceed 100 percent of the sum of its Utah and Wyoming
21 allowance allocations . When combined with state-specific
22 limits previously described, while either PacifiCorp' s
23 Utah or Wyoming NOx allowance requirements could be up
$ Effective allowance requirement for resource with emissions rate of 0.20
lb/MMBTU: 100% * 0.20 lb/MMBtu + 200% * (0.20 - 0.14) lb/MMBtu = 100%
*0.20 + 200% * 0.06 = 0.32 lb/MMBtu.
Burns, Di 25
Rocky Mountain Power

REDACTED
1 to 121 percent of that state' s allocation, any increase
2 in one state would have to be accompanied by a reduction
3 in emissions allowance requirements from PacifiCorp
4 resources in the other state.
5 PacifiCorp' s primary production cost analysis
6 relies upon PLEXOS ST modeling that identifies system
7 costs for a single deterministic set of expected or
8 normal input conditions . In reality, and in stochastic
9 modeling the Company performs using the PLEXOS MT model,
10 significant variations in inputs such as load, hydro
11 generation, and thermal availability are a normal course
12 of operations . Each of these inputs can unexpectedly
13 increase PacifiCorp' s need for NOX emission allowances .
14 Because banking and trading are limited under the OTR,
15 variations in NOX emissions that might otherwise average
16 out over time must comply in every year and under every
17 set of conditions . As a result, the NOX allowances used
18 under "normal" input conditions will likely need to be
19 somewhat below the forecast limit to ensure sufficient
20 allowances are available to meet unexpected input
21 conditions .
22 PacifiCorp' s analysis indicated that using a NOX
23 allowance dispatch target of in the ST model
24 would result in NOX allowance requirements that were
25 under PacifiCorp' s forecast allocation and would leave
Burns, Di 26
Rocky Mountain Power

REDACTED
1 sufficient allowances to meet a range of potential
2 "above-normal" conditions . Whenever the incremental
3 value of using a high NOX emitting resources exceeds the
4 dispatch target price, the model will deploy the high
5 NOX resource, rather than lower NOX alternatives, which
6 are typically gas-fired resources or market
7 transactions . For a coal-fired resource with a NOX
8 emissions rate of 0 . 20 lb/MMBtu, the NOX dispatch target
9 price means that the resource would not be dispatched
10 unless it provides at least in incremental
11 value relative to no NOX alternatives, or a proportional
12 amount of incremental value relative to lower NOX
13 alternatives . 9
14 The dispatch target price is used to direct the
15 model to avoid emissions, and is not a direct cost, as
16 the Company would receive its allowance allocation free
17 of charge under the proposed rule . While the Company
18 could potentially sell allowances, there is little
19 indication what market prices may prevail, and market
20 prices may be below this target. As a result, no direct
21 costs or revenues for allowances are included in the
22 analysis . The allowance requirements resulting from this
9 A 0.20 lb/MMBTU coal-fired resource would have a NOx credit
requirement of 0.32 lb/MMBTU in 2027 and beyond, as detailed in
footnote 22. A typical average heat rate for a coal-fired resource is
11 MMBtu/MWh. - 2, 000 lb/ton * 0.32 lb/MMBtu * 11 MMBtu/MWh
Burns, Di 27
Rocky Mountain Power

1 dispatch target price vary over time as the OTR
2 requirements take full effect and as the Company' s
3 portfolio evolves . The Company' s load forecast and other
4 modeling inputs also play a role in the resulting
5 volumes . A comparison of the allowance requirements for
6 the scenarios relative and forecast allowance
7 allocations is discussed in the Price-Policy Scenario
8 Results section later in my testimony.
9 Q. Please describe the modeling methodology PacifiCorp used
10 in its analysis of Rock Creek I.
11 A. Consistent with IRP modeling practices, the Company
12 calculated a system PURR by identifying least-cost
13 resource portfolios and dispatching system resources
14 through 2040, which aligns with the 20-year forecast
15 period used in the 2021 IRP and 2021 IRP Update. Net
16 customer benefits are calculated as the PVRR (d) between
17 different simulations of PacifiCorp' s system. One
18 simulation includes Rock Creek I (and in the combined
19 studies, both Rock Creek I and II) , and the other
20 simulation excludes them. The simulation that includes
21 Rock Creek includes transmission interconnection costs .
22 When the two simulations are compared, changes to system
23 costs are attributable to Rock Creek. These studies also
24 include simulations before and after passage of the IRA,
25 to reflect the value of increased PTCs .
Burns, Di 28
Rocky Mountain Power

1 PacifiCorp also calculated a PVRR (d) based on one
2 simulation that includes only Rock Creek I and compares
3 it to a simulation that excludes both Rock Creek
4 projects, and one simulation that includes only Rock
5 Creek II and compares it to a simulation that excludes
6 both Rock Creek projects . In all studies, the Gateway
7 West and Gateway South transmission projects discussed
8 in Company witness Link' s testimony were assumed to be
9 in-service, and beyond 2025 proxy resource options from
10 the 2021 IRP are available to meet system needs .
11 Customers are expected to realize benefits when the
12 system PVRR from the simulation with the projects is
13 lower than the system PVRR without. Conversely,
14 customers would experience increased costs if the system
15 PVRR with the projects is higher than the system PVRR
16 without .
Burns, Di 29
Rocky Mountain Power

1 Q. What portfolios did you analyze using the PLEXOS model
2 in this case?
3 A. Portfolios were analyzed with and without both projects,
4 with and without Rock Creek I, and with and without Rock
5 Creek II, including certain results pre-IRA and post-
6 IRA.
7 Q. Did PacifiCorp analyze how other assumptions affect its
8 economic analysis of the wind projects?
9 A. Yes . PacifiCorp analyzed sensitivities that quantify how
10 changes in capital costs and PTC values influence
11 projected customer benefits .
12 C. Price-Policy Scenario Results
13 Q. Please summarize the pre-IRA results for the simulations
14 that focused on each Rock Creek project individually.
15 A. Tables 2 and 3 summarize the PVRR (d) results for each
16 price-policy scenario for the scenarios that examined
17 each of the Rock Creek projects prior to passage of the
18 IRA. 10
o See also Confidential Exhibit No. 32
Burns, Di 30
Rocky Mountain Power

Table 2 . Pre-IRA (Benefit) /Cost of Rock Creek I ($ million)
Price-Policy Risk-Adjusted
Scenario PVRR(d) PVRR(d)
MM (15) (20)
MN (9) (15)
LN 3 (2)
Table 3 . Pre-IRA (Benefit) /Cost of Rock Creek II ($
million)
Price-Policy Risk-Adjusted
Scenario PVRR(d) PVRR(d)
MM (24) (33)
MN (14) (24)
LN 8 (3)
1 Rock Creek II generally provides a larger benefit,
2 because it is approximately twice the size of Rock Creek
3 I . All the same, under the MM price-policy scenario,
4 Rock Creek I lowers total-system costs by $15 million,
5 and adjusted for risk these benefits increase to a $20
6 million reduction in system costs . System benefits
7 generally mirror the results seen in Table 4 when both
8 projects were considered together, with a slight cost
9 for Rock Creek I and Rock Creek II in the LN scenario
10 prior to adjusting for risk and benefits in each of the
11 other scenarios . Both projects, when evaluated
12 individually, yield benefits on a risk-adjusted basis
13 among all three price-policy scenarios .
Burns, Di 31
Rocky Mountain Power

1 Q. Why did PacifiCorp decide to update its economic
2 analysis after passage of the IRA?
3 A. Based on existing law, PacifiCorp' s economic analysis
4 assumed that Rock Creek I and II qualified for 60 percent
5 of available PTCs through the first 10 years of
6 operation. After passage of the IRA, the Company
7 understands that both Rock Creek projects qualify for
8 110 percent of available PTCs . This provides a
9 significant increase to the economic benefits from the
10 projects, and the Company' s updated analysis reflects
11 those benefits . The Company also updated its analysis to
12 reflect current project costs .
13 Q. Please summarize the PVRR(d) results post-IRA.
14 A. Table 4 summarizes the PVRR (d) results for each price-
15 policy scenario from the combined projects after passage
16 of the IRA.11
11See also Confidential Exhibit No. 33.
Burns, Di 32
Rocky Mountain Power

Table 4 . Post-IRA (Benefit) /Cost of Rock Creek I and II ($
million)
(e) _ (f) _ (g) _
(a) (b) (c) (d) (c) + (a) + (b) +
(d) (e) (e)
Price- Risk- 110% Proje Updated
Policy PVRR(d Adjust PTC ct Total Updated Risk-
Scenar ed Cost Adjuste
PVRR(d Updat Updat Update PVRR(d) d
io ) e e PVRR(d)
MM (143) (163) (197) 42 (155) (298) (318)
MN (33) (51) (194) 42 (151) (185) (202)
LN 16 2 (195) 42 (153) (137) (151)
1 Before adjusting for risk (Column (f) ) , system costs are
2 lower when the wind projects are included in the
3 portfolio in all scenarios : ranging from a $137 million
4 customer benefit under the LN scenario to $298 million
5 in the MM scenario . When adjusting for risk (Column (g) ) ,
6 the benefits from the wind projects increase : ranging
7 from $151 million in the LN scenario to $318 million in
8 the MM scenario . The increase in customer benefits from
9 the 110 percent PTC is substantial, even when accounting
10 for the increase in project costs . This updated analysis
11 supports the necessity of Rock Creek I and indicates it
12 will produce robust customer benefits . As discussed
13 earlier, these benefits only increase under a high gas
14 or a high CO2 price-policy scenario .
Burns, Di 33
Rocky Mountain Power

1 Q. How do system costs change post-IRA with and without
2 both projects?
3 A. Figure 3 summarizes changes in system costs, based on ST
4 model results using MM price-policy assumptions, when
5 both projects are eliminated from the portfolio . The
6 graph on the left shows annual changes in cost by
7 category and the graph on right shows annual net changes
8 in total costs (the solid black line) and the cumulative
9 PVRR (d) of changes to net system costs over time (the
10 dashed black line) . Through 2040, the PVRR (d) shows that
11 the portfolio that includes both projects is
12 $298 million lower cost than the portfolio without both.
Figure 3 . Increase/ (Decrease) in System Costs when both
Projects are Removed from the Portfolio ($ millions) Medium
Gas/Medium CO2
Annual Change in Cost by line Item Net Difference In Total System Cost
$zoo $50
$150
$100 ■ so
$so ■��so ■���� (550)
_����
Isso) ——� — _ ������� (slop)
($100)
(sisa) ($150)
($zoo) ($zoo) `%
I$3o30o) (szw) --
(1
350) ($300) -
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (s350)
•Coal&Gas FF.ed Coal&Gas Variable N N N N N N H M N M M H M rw H N M N N 3
■P—y Res ourm Costs Emiss Ions
•Net Markct Tram &m IN Trors k,ion Net Cost/(B*xfltl ---Cumulstrve PVRR(d)
Burns, Di 34
Rocky Mountain Power

1 Q. How do the risk-adjusted PVRR(d) results compare to the
2 stochastic-mean PVRR(d) results?
3 A. For both projects, the risk-adjusted medium gas medium
4 CO2 PVRR (d) results show a benefit of $318 million, which
5 is higher than the reported ST-model PVRR (d) results of
6 $298 million prior to the risk adjustment. This
7 indicates that the wind projects provide stochastic risk
8 benefits by making the system less susceptible to
9 low-probability combinations of load, market price,
10 hydro generation, and thermal outage volatility that can
11 increase system costs .
12 Q. How do the modeled OTR allowance requirements compare to
13 PacifiCorp' s forecast allowance allocation?
14 A. The annual allowance requirements in the ST-model
15 results are generally slightly below a high estimate of
16 PacifiCorp' s allowance allocation. Based on the
17 allocation methodology identified in the proposed rule,
18 this high allowance allocation would likely require
19 installation of SCR equipment at most of PacifiCorp' s
20 coal-fired generating units that are not equipped with
21 that technology. In the absence of additional emission
22 control equipment, PacifiCorp' s allocation would be
23 significantly lower, and well below the allowance
24 requirements from the ST-model results . The high and low
25 allocation forecasts and the ST-model results for the MM
Burns, Di 35
Rocky Mountain Power

REDACTED
1 and MN price-policy scenarios are shown in Confidential
2 Figure 4 . As shown, allowance allocations could be
3 significantly lower than what is assumed to be available
4 in the current ST-model results, which would further
5 increase the value of generation from resources without
6 emissions, such as Rock Creek I and II .
Confidential Figure 4 . Forecast OTR Allocation and Modeled
Requirements
7 Q. Would Rock Creek I provide customer benefits even if
8 construction costs are higher than expected?
9 A. Yes . For both projects, a one percent increase in the
10 initial capital costs would reduce PVRR benefits through
11 2040 by $9 . 1 million . To negate the $318 million in
Burns, Di 36
Rocky Mountain Power

1 risk-adjusted, post-IRA benefits under the MM price-
2 policy scenario, project costs would need to increase by
3 35 percent . To negate the $202 million in risk-adjusted,
4 post-IRA benefits under the MN price-policy scenario,
5 project costs would need to increase by 22 percent .
6 Q. Are the Company' s economic analyses of the expected
7 customer benefits from Rock Creek I conservative?
8 A. Yes . The PVRR(d) results for Rock Creek I does not
9 reflect the potential value of RECs generated by the
10 incremental energy output from the renewable project.
11 Customer benefits for all price-policy scenarios would
12 improve by approximately $14 million for every dollar
13 assigned to the incremental RECs that will be generated
14 through 2040 .
15 Similarly, the Company' s analyses understate
16 forecast coal costs for certain system resources,
17 including the Dave Johnston plant. If corrected to
18 include the full costs of fuel supply for all plants,
19 the Company' s economic analysis would demonstrate even
20 higher benefits for Rock Creek I . Additionally, the
21 natural gas and electricity prices in the Company' s
22 September 2022 OFPC are higher than the values assumed
23 in the June 2022 OFPC used in the Company' s analysis,
24 which would similarly result in higher benefits for Rock
25 Creek I .
Burns, Di 37
Rocky Mountain Power

1 IV. FOOTE CREEK II-IV AND ROCK RIVER I
2 Q. Please describe the acquisition and repowering of the
3 Foote Creek II-IV and Rock River I wind facilities .
4 A. As described in the confidential testimony of Company
5 witness Timothy J. Hemstreet, PacifiCorp is acquiring
6 and repowering the 43 MW Foote Creek II-IV and 50 MW
7 Rock River I wind facilities . This involves installing
8 approximately 11 modern wind turbine generators ("WTGs")
9 at the Foote Creek facilities, and 19 wind turbine
10 generators at the Rock River I facility. These new
11 turbines will increase the power generation from the
12 previous capability, and extend the service life of the
13 facility, and allow customers to benefit from this
14 favorable wind site . My testimony provides the economic
15 justification for the Company' s decision to acquire and
16 repower these facilities .
17 A. Resource Need
18 Q. Did PacifiCorp' s preferred portfolio of resources
19 developed in the Company' s 2021 IRP include Foote Creek
20 II-IV and Rock River I?
21 A. Yes . 12
12 2021 IRP, Ch. 1 Action Plan, Action Item 2b, at 25.
Burns, Di 38
Rocky Mountain Power

1 Q. Please describe the key factors for including Foote
2 Creek II-IV and Rock River I in the 2021 IRP preferred
3 portfolio.
4 A. The projects are anticipated to be fully online and
5 serving customers before 2025 . This timing enables both
6 projects to deliver needed energy and capacity for
7 customers before the availability of either new proxy
8 resources, or final shortlist project generation
9 expected to be enabled by the Gateway South transmission
10 line, as identified in the Company' s 2020AS RFP. Without
11 these projects, the risk of shortfalls is increased as
12 is the Company' s reliance on energy markets . In their
13 current states, the existing Rock River I facility is
14 not operating as turbines have been removed pending the
15 repowering of the sites . Repowering will allow the
16 facility to once again provide energy and capacity to
17 serve load and reduce market reliance, while allowing
18 the newly installed turbines to qualify for substantial
19 federal PTCs .
20 Q. Were each of these facilities included in the Company' s
21 2021 IRP Update?
22 A. Yes .13
is PacifiCorp 2021 IRP Update (Mar. 31, 2022) .
Burns, Di 39
Rocky Mountain Power

1 B. Assumptions and Results
2 Q. Has the Company performed updated analyses of the
3 projects after filing the 2021 IRP?
4 A. Yes . The Company performed a 30-year analysis of each
5 project' s economics through end-of-life using its PLEXOS
6 modeling system, the same modeling system used for the
7 2021 IRP.
8 Q. Please summarize the natural gas and CO2 price
9 assumptions used in the economic analyses for each
10 project.
11 A. The economic analysis for each of the projects included
12 four price-policy scenarios—representing low, medium,
13 and high natural gas prices, and zero, medium, high, and
14 the SCGHG CO2 prices . The price-policy scenario that
15 pairs medium natural gas prices with medium CO2 prices
16 is referred to as the "MM" scenario, the price-policy
17 scenario that pairs low natural gas prices with a zero
18 CO2 price is referred to as the "LN" scenario, the price-
19 policy scenario that pairs high natural gas prices with
20 a high CO2 price is referred to as the "HH" scenario,
21 and the scenario that pairs medium natural gas prices
22 with the SCGHG is referred to as the MM-SCGHG scenario.
23 While the MM price-policy scenario represents the
24 Company' s "expected case" describing likely future
Burns, Di 40
Rocky Mountain Power

1 conditions, the LN, HH, and MM-SCGHG scenarios provide
2 informative analytical bookends scenarios .
3 Similar to the Company' s other analyses, these
4 assumptions can influence the value of system energy,
5 the dispatch of system resources, and PacifiCorp' s
6 resource mix. Consequently, wholesale-power prices and
7 CO2 policy assumptions affect NPC, non-NPC variable-cost
8 benefits, and system fixed-cost benefits associated with
9 Foote Creek II-Iv and Rock River I . Because wholesale
10 power prices and CO2 policy outcomes are both uncertain
11 and important drivers to the economic analysis, it is
12 important to evaluate a range of assumptions for these
13 variables . The natural gas and CO2 price assumptions are
14 summarized in Table 5 .
Table 5 . Price-Policy Assumptions
Henry Hub
Price-Policy
Natural Gas CO2 Price
Scenario Price Description
(Levelized
$/MMBtu) *
22 .57/ton starting
HH $5. 64 2025 rising to
102 . 48/ton in 2040
$9. 93/ton starting
MM $4 .44 in 2025 rising to
$57 . 94/ton in 2040
LN $2 . 94 None
$74 . 10/ton starting
MM-SCGHG $4 .44 2021 rising to
$150 .38/ton in 2040
*Nominal levelized Henry Hub natural gas price from
2025 through 2040 .
Burns, Di 41
Rocky Mountain Power

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 OFPC dated March 31, 2021, which was the
5 most recent OFPC available when the modeling inputs were
6 developed. The first 36 months of the OFPC reflect market
7 forwards at the close of a given trading day, May 2021
8 is the prompt month in this case. As such, these 36
9 months are market forwards as of May 2021 . The blending
10 period (months 37 through 48) is calculated by averaging
11 the month-on-month market forwards from the prior year
12 with the month-on-month fundamentals-based price from
13 the subsequent year. The fundamentals portion of the
14 natural gas OFPC reflects Aurora-forecast prices .
15 Q. Please describe the CO2 price assumptions used in the
16 price-policy scenarios .
17 A. PacifiCorp used four different CO2 price scenarios—zero,
18 medium, high, and the SCGHG. The medium scenario is
19 derived from a survey of third-party industry experts,
20 including I CERA, and Wood Mackenzie and the Energy
21 Information Administration as well as CO2 price
22 assumptions used by peer utilities . Both the medium and
23 high scenarios apply a CO2 price as a tax beginning 2025 .
24 PacifiCorp also incorporated the SCGHG that is assumed
25 to start in 2021 for Washington, and is applied such
Burns, Di 42
Rocky Mountain Power

1 that the SCGHG is reflected in market prices and dispatch
2 costs for the purposes of developing each portfolio
3 (i .e . , incorporated into capacity expansion optimization
4 modeling) .
5 Q. How did PacifiCorp pair the natural gas and CO2 price
6 assumptions for purposes of analyzing Foote Creek II-IV
7 and Rock River I?
8 A. Scenarios pairing medium gas prices with alternative CO2
9 price assumptions reflect OFPC forwards through April
10 2024 before transitioning to a fundamentals forecast.
11 Scenarios using high or low gas prices, regardless of
12 CO2 price assumptions, do not incorporate any market
13 forwards because these scenarios are designed to reflect
14 an alternative view to that of the market. As such, the
15 low and high natural gas price scenarios are purely
16 fundamental forecasts . Low and high natural gas price
17 scenarios are also derived from expert third-party,
18 multi-client, "off-the-shelf" subscription services .
19 Q. Please explain how you conducted your analyses.
20 A. The methodologies are consistent with the approach used
21 to perform the economic analysis of portfolios in the
22 2021 IRP. The system value of incremental wind energy
23 from Foote Creek II-IV and Rock River I are each
24 calculated from two PLEXOS ST model simulations for a
25 given price-policy scenario—one simulation with
Burns, Di 43
Rocky Mountain Power

1 incremental wind energy and one simulation without
2 incremental wind energy. The system value of incremental
3 wind energy is then converted to a dollar-per-$/MWh
4 value by dividing the change in annual system cost by
5 the change in incremental wind energy for both price-
6 policy scenarios through 2040 . The value of wind energy
7 is extended out through 2050 by extrapolating the system
8 values calculated from modeled data over the 2038-2040
9 timeframe . The assumed system value, expressed in
10 dollars per$/MWh, is applied to the incremental energy
11 output associated with each of the wind repowering
12 projects .
13 Q. Were your initial economic analyses conducted before
14 passage of the IRA?
15 A. Yes .
16 Q. How does the IRA impact your analyses?
17 A. Based on existing law, PacifiCorp' s initial economic
18 analyses assumed that both Foote Creek II-IV and Rock
19 River I qualified for 60 percent of available PTCs . After
20 passage of the IRA, the Company understands that each
21 facility now qualifies for 110 percent of available
22 PTCs . The Company has updated its economic analyses to
23 reflect the new PTC value for both projects, and the
24 results are reflected in Tables 6 and 7 below.
Burns, Di 44
Rocky Mountain Power

1 Q. What are the results of your economic analyses for Foote
2 Creek II-IV?
3 A. Table 6 summarizes the PVRR(d) customer benefits (or
4 costs) of Foote Creek II-IV both before and after passage
5 of the IRA.14 This table also presents the same
6 information on a levelized dollar-per-MWh basis .
Table 6. Foote Creek II-IV (Benefits) /Costs
Price- Pre-IRA Pre-IRA Net Post-IRA Post-IRA
Policy PVRR(d) Benefit PVRR(d) Net Benefit
Scenario ($ million) ($/MWh) ($ million) ($/MWh)
HH ($80 . 80) ($38/MWh) ($104 . 23) ($49/MWh)
MM ($53 . 07) ($25/MWh) ($76 . 49) ($36/MWh)
LN $17 . 09 $8/MWh ($6 . 33) ($3/MWh)
r4M-SCGHGI ($142 . 77) ($67/MWh) ($166 . 19) ($78/MWh)
7 Prior to passage of the IRA, Foote Creek II-IV was
8 expected to deliver $53 . 07 million in present-value net
9 customer benefits in the MM scenario, and $80 . 8 million
10 in the HH scenario. This is contrasted with $17 . 09
11 million cost in the LN scenario . Under the MM and HH
12 scenarios, nominal levelized net benefits are $25/MWh
13 and $38/MWh, respectively. Under the LN scenario there
14 is a nominal levelized net cost of $8/MWh.
15 After passage of the IRA, customer benefits
16 increased substantially: Foote Creek II-IV will now
17 deliver $76 . 49 million in present-value net customer
i4 See also Confidential Exhibit No. 34.
Burns, Di 45
Rocky Mountain Power

1 benefits in the MM scenario and $104 . 23 million in the
2 HH scenario .
3 Importantly, the only scenario where Foote Creek
4 II-IV was expected to generate customer costs prior to
5 passage of the IRA—the LN scenario ($17 . 09 million)—has
6 transformed to a $6 . 33 million customer benefit. These
7 benefits only increase under the highest cost of carbon
8 scenario (MM-SCGHG) . While the Company decided to move
9 forward with Foote Creek II-IV prior to passage of the
10 IRA, the substantial post-IRA benefits continue to
11 support the Company' s decision to acquire and repower
12 the facilities .
13 Q. What are the results of your economic analyses for Rock
14 River I?
15 A. Table 7 summarizes the PVRR(d) customer benefits (or
16 costs) of Rock River I both before and after passage of
17 the IRA. 15 This table also presents the same information
18 on a levelized dollar-per-MWh basis .
Table 7 . Rock River I (Benefits) /Costs
Pre-IRA Post-IRA Post-IRA
Price- PVRR(d) Pre-IRA Net PVRR(d) Net
Policy Benefit
Scenario ($ ($/MWh) ($ Benefit
million) million) ($/MWh)
HH ($67 . 76) ($31/MWh) ($91 . 69) ($43/MWh)
MM ($30 . 15) ($14/MWh) ($54 . 09) ($25/MWh)
LN $23 . 12 $11/MWh ($15 . 12) ($7/MWh)
MM-SCGHG ($143 . 42) ($67/MWh) ($167 . 35) ($78/MWh)
is See also Confidential Exhibit No. 35.
Burns, Di 46
Rocky Mountain Power

1 Before passage of the IRA, Rock River I was expected
2 to deliver $30 . 15 million in present-value net customer
3 benefits in the MM scenario, $67 . 76 million in the HH
4 scenario, and $143 . 42 million in the MM-SCGHG scenario.
5 This is contrasted with $23 . 12 million cost in the LN
6 scenario . Under the MM-SCGHG, MM and HH scenarios,
7 nominal levelized net benefits are $67/MWh, $14/MWh and
8 $31/MWh, respectively. Under the LN scenario there is a
9 nominal levelized net cost of $11/MWh.
10 After passage of the IRA, customer benefits
11 increased substantially: Rock River I will now deliver
12 $54 . 09 million in present-value net customer benefits in
13 the MM scenario and $91 . 69 million in the HH scenario.
14 Importantly, the only scenario where Rock River I was
15 expected to generate customer costs before passage of
16 the IRA—the LN scenario ($23 . 12 million)—has transformed
17 to a $15 . 12 million customer benefit . These benefits
18 only increase under higher gas or CO2 scenarios .
19 Q. Are the Company' s economic analyses of the expected
20 customer benefits from Foote Creek II-IV and Rock
21 River I conservative?
22 A. Yes . The PVRR (d) results do not reflect the potential
23 value of RECs generated by the incremental energy output
24 from each of the wind facilities . Customer benefits for
25 all price-policy scenarios would improve significantly
Burns, Di 47
Rocky Mountain Power

1 for every dollar assigned to the incremental RECs that
2 will be generated through 2040, and these RECs can also
3 be sold to reduce the revenue requirement impact of this
4 resource .
5 V. CONCLUSION
6 Q. Please summarize the conclusions of your testimony.
7 A. PacifiCorp' s economic analysis shows that the Company' s
8 decision to procure these resources are necessary, and
9 each will provide substantial customer benefits compared
10 to anticipated project costs .
11 Q. What is your recommendation?
12 A. I recommend that the Commission determine that the
13 Company' s decisions to acquire Rock Creek I, and acquire
14 and repower Foote Creek II-IV and Rock River I were
15 prudent .
16 Q. Does this conclude your direct testimony?
17 A. Yes .
Burns, Di 48
Rocky Mountain Power

REDACTED
Case No. PAC-E-24-04
Exhibit No. 32
Witness : Thomas R. Burns
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Thomas R. Burns
Rock Creek I and II Pre-IRA Combined Analysis
May 2024

THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER
SEPARATE COVER

REDACTED
Case No. PAC-E-24-04
Exhibit No. 33
Witness : Thomas R. Burns
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Thomas R. Burns
Rock Creek I and II Post-IRA Combined Analysis
May 2024

THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER
SEPARATE COVER

REDACTED
Case No. PAC-E-24-04
Exhibit No. 34
Witness : Thomas R. Burns
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Thomas R. Burns
Foote Creek II-IV Analysis
May 2024

THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER
SEPARATE COVER

REDACTED
Case No. PAC-E-24-04
Exhibit No. 35
Witness : Thomas R. Burns
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Thomas R. Burns
Rock River Analysis
May 2024

THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER
SEPARATE COVER