Confidential per WAC 480-07-160 Exh. RTL-1CT Docket UE-19____ Witness: Rick T. Link
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Docket UE-19____ Complainant, v.
PACIFICORP dba PACIFIC POWER & LIGHT COMPANY
Respondent.
PACIFICORP
REDACTED DIRECT TESTIMONY OF RICK T. LINK
December 2019 TABLE OF CONTENTS
PURPOSE AND SUMMARY OF TESTIMONY ...... 2 I. WIND REPOWERING ...... 3 2017 INTEGRATED RESOURCE PLAN ...... 5 MODELING SCOPE, METHODOLOGIES, AND ASSUMPTIONS...... 10 Modeling Methodology ...... 10 Annual Revenue Requirement Methodology...... 18 Price-Policy Scenarios ...... 23 February 2018 Price-Policy Assumptions ...... 24 August 2018 Price-Policy Assumptions ...... 27 Other Assumption Updates in the August 2018 Analysis ...... 29 FEBRUARY 2018 WIND REPOWERING ANALYSIS ...... 30 Project-by-Project Results ...... 30 Project-by-Project Annual Revenue Requirement Price-Policy Results ...... 33 Project-wide SO and PaR Price-Policy Results ...... 36 Project-Wide Annual Revenue Requirement Price-Policy Results ...... 40 New Wind and Transmission Sensitivity ...... 46 AUGUST 2018 WIND REPOWERING ANALYSIS ...... 48 Project-by-Project SO and PaR Model Price-Policy Results ...... 48 Project-by-Project Annual Revenue Requirement Price-Policy Results ...... 52 FOOTE CREEK I ...... 57 II. NEW WIND AND TRANSMISSION ...... 62 2017 INTEGRATED RESOURCE PLAN ...... 64 2017R RFP ...... 71 ENERGY VISION 2020 CPCN/PRE-APPROVAL FILINGS ...... 77 MODELING METHODOLOGY ...... 78 System Modeling Methodology ...... 79 Annual Revenue Requirement Modeling Methodology ...... 85 SYSTEM MODELING PRICE-POLICY RESULTS ...... 87 REVENUE REQUIREMENT MODELING PRICE-POLICY RESULTS ...... 90 SOLAR SENSITIVITY ...... 94 Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page i
WIND-REPOWERING SENSITIVITY ...... 97 ADJUSTED ECONOMIC ANALYSIS WITHOUT UINTA FACILITY ...... 98 III. PRYOR MOUNTAIN WIND PROJECT ...... 105 IV. SALES AND LOAD FORECAST ...... 111 CONCLUSION ...... 114
ATTACHED EXHIBITS
Confidential Exhibit No. RTL-2C—Cost-and-Performance Assumptions for Wind Facilities
Confidential Exhibit No. RTL-3C—Nominal Henry Hub Natural Gas Price Forecasts
Exhibit No. RTL-4—Project-Wide Wind Repowering SO and PaR PVRR(d) (Benefit)/Cost, February 2018
Exhibit No. RTL-5—Project-Wide Wind Repowering Nominal Revenue Requirement PVRR(d) (Benefit)/Cost, February 2018
Exhibit No. RTL-6—Combined Projects SO and PaR PVRR(d) (Benefit)/Cost, February 2018
Exhibit No. RTL-7—Combined Projects Nominal Revenue Requirement PVRR(d) (Benefit)/Cost, February 2018
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page ii
1 Q. Please state your name, business address, and position with PacifiCorp.
2 A. My name is Rick T. Link. My business address is 825 NE Multnomah Street, Suite
3 600, Portland, Oregon 97232. My position is Vice President, Resource Planning and
4 Acquisitions. I am testifying on behalf of PacifiCorp dba Pacific Power & Light
5 Company (PacifiCorp or the Company).
6 Q. Please describe the responsibilities of your current position.
7 A. I am responsible for PacifiCorp’s integrated resource plan (IRP), structured
8 commercial business and valuation activities, and long-term commodity price
9 forecasts. Most relevant to this docket, I am responsible for the economic analysis
10 used to screen system resource investments and for conducting competitive request
11 for proposal (RFP) processes consistent with applicable state procurement rules and
12 guidelines.
13 Q. Please describe your professional experience and education.
14 A. I joined PacifiCorp in December 2003 and assumed the responsibilities of my current
15 position in September 2016. Over this time period, I held several analytical and
16 leadership positions responsible for developing long-term commodity price forecasts,
17 pricing structured commercial contract opportunities and developing financial models
18 to evaluate resource investment opportunities, negotiating commercial contract terms,
19 and overseeing development of PacifiCorp’s resource plans. I was responsible for
20 delivering PacifiCorp’s 2013, 2015, 2017, and 2019 IRPs; have been directly
21 involved in several resource RFP processes; and performed economic analysis
22 supporting a range of resource investment opportunities. Before joining PacifiCorp, I
23 was an energy and environmental economics consultant with ICF Consulting (now
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1 ICF International) from 1999 to 2003, where I performed electric-sector financial
2 modeling of environmental policies and resource investment opportunities for utility
3 clients. I received a Bachelor of Science degree in Environmental Science from the
4 Ohio State University in 1996 and a Masters of Environmental Management from
5 Duke University in 1999.
6 Q. Have you testified in previous regulatory proceedings?
7 A. Yes. I have testified in proceedings before the Washington Utilities and
8 Transportation Commission (Commission), the Utah Public Service Commission
9 (Utah Commission), the Wyoming Public Service Commission (Wyoming
10 Commission), the Public Utility Commission of Oregon (Oregon Commission), the
11 Idaho Public Utilities Commission (Idaho Commission), and the California Public
12 Utilities Commission.
13 PURPOSE AND SUMMARY OF TESTIMONY
14 Q. What is the purpose of your testimony?
15 A. PacifiCorp’s Energy Vision 2020 uses opportunities presented by the extension of the
16 federal production tax credit (PTC) to make renewable energy and infrastructure
17 investments that produce net benefits to customers. Energy Vision 2020 consists of
18 two major components, both of which are included in this case: (1) wind repowering;
19 and (2) investments in new wind and transmission. In my testimony, I present and
20 explain the economic analysis that demonstrates that these investments are prudent,
21 used and useful, and further the public interest.
22 In addition to Energy Vision 2020, PacifiCorp has acquired another wind
23 resource, the Pryor Mountain Wind Project in Montana, which will achieve
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1 commercial operation in 2020. I present and explain the economic analysis that
2 demonstrates that this investment is prudent, used and useful as of the rate effective
3 date, and furthers the public interest. I also present the Company’s load forecast upon
4 which this rate case filing was based.
5 Q. How have you organized your testimony?
6 A. I have divided my testimony into four sections. I address PacifiCorp’s wind
7 repowering project in Section I of my testimony. I address PacifiCorp’s new wind
8 and transmission investments, collectively referred to as the “Combined Projects” in
9 Section II of my testimony. Section III of my testimony addresses PacifiCorp’s new
10 Pryor Mountain Wind Project, and Section IV presents PacifiCorp’s load forecast.
11 I. WIND REPOWERING
12 Q. Please summarize Section I of your testimony.
13 A. PacifiCorp’s economic analysis that shows that its decision to “repower” its wind
14 fleet is prudent, in the public interest, and provides significant customer benefits. The
15 wind repowering project includes 13 wind facilities, representing 1,039.9 megawatts
16 (MW) of installed wind capacity. PacifiCorp’s underlying economic analysis covers
17 12 of the 13 wind facilities, totaling approximately 999.1 MW—Glenrock I, Glenrock
18 III, Rolling Hills, Seven Mile Hill I, Seven Mile Hill II, High Plains, McFadden
19 Ridge, and Dunlap in Wyoming; Marengo I, Marengo II and Goodnoe Hills in
20 Washington; and Leaning Juniper in Oregon. This filing includes the 13th facility,
21 Foote Creek I in Wyoming, which presents similar economic benefits.
22 The repowered wind facilities will qualify for an additional 10 years of federal
23 PTCs, produce more energy, reset the 30-year depreciable life of the assets, and
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1 reduce run-rate operating costs. PacifiCorp’s economic analysis of the wind
2 repowering project demonstrates that net benefits, which include federal PTC
3 benefits, net power cost (NPC) benefits, other system variable-cost benefits, and
4 system fixed-cost benefits, more than outweigh net project costs.
5 Based on an economic analysis completed in February 2018 covering all
6 facilities except Foote Creek I, my testimony shows that:
7 The wind repowering project will deliver net customer benefits in 8 all price-policy scenarios studied.
9 The wind repowering project will produce present-value net 10 customer benefits, based on analysis covering the remaining life of 11 the repowered wind facilities, ranging between $121 million to 12 $466 million (total system).
13 Present-value gross customer benefits calculated over the 14 remaining life of the repowered wind facilities range between 15 $1.14 billion and $1.48 billion, which compares to present-value 16 project costs totaling $1.01 billion.
17 These net and gross customer benefits are conservative, as they do 18 not account for potential incremental benefits from renewable 19 energy credits (RECs), understate the potential benefits from 20 reduced carbon-dioxide (CO2) emissions, and assign no 21 incremental capacity value associated with extending the life of the 22 repowered wind facilities by 10–13 years.
23 When measured over a 20-year period, the present value of net 24 customer benefits from wind repowering range between $139 25 million and $273 million, which accounts for the nominal value of 26 federal PTCs, but does not account for the value of incremental 27 energy output that will increase significantly beyond 2036.
28 PacifiCorp performed updated analysis in August 2018 to understand how
29 more recent changes in other modeling assumptions affect project-by-project results
30 relative to those included in the February 2018 analysis. Based on this updated
31 economic analysis, my testimony shows that projected net customer benefits remain
32 similar to those calculated previously. This targeted reassessment confirms that the
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1 repowering project is prudent. As with the February 2018 results, the net customer
2 benefits projected in the August 2018 analyses are conservative, as they do not
3 account for potential incremental benefits from RECs and assign no incremental
4 capacity value associated with extending the life of the repowered wind facilities by
5 10-13 years.
6 2017 INTEGRATED RESOURCE PLAN
7 Q. Did PacifiCorp analyze wind repowering in its 2017 IRP?
8 A. Yes. The preferred portfolio in the 2017 IRP, representing PacifiCorp’s risk-adjusted,
9 least-cost plan to reliably meet customer demand over a 20-year planning period,
10 includes repowering 905 MW of existing wind resource capacity located in
11 Wyoming, Washington, and Oregon. PacifiCorp later expanded the wind repowering
12 scope to include its Goodnoe Hills and Foote Creek I wind facilities, increasing the
13 project to approximately 1,040 MW of existing wind capacity.
14 Q. What led PacifiCorp to evaluate the wind repowering opportunity in its 2017
15 IRP?
16 A. As explained in Mr. Timothy J. Hemstreet’s testimony, PacifiCorp purchased safe-
17 harbor equipment from General Electric International, Inc., and Vestas American
18 Wind Technology, Inc. in December 2016. Consistent with Internal Revenue Service
19 (IRS) guidance, these equipment purchases, totaling $77.8 million, secured an option
20 for PacifiCorp to repower its fleet of owned wind resources, thereby qualifying them
21 for the full value of federal PTCs.
22 Wind repowering presents an opportunity to deliver several different types of
23 benefits for customers. First, federal PTCs will apply to 10 additional years of
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1 generation from each repowered wind resource. The current PTC equates to a
2 $33.15/MWh reduction in revenue requirement that can be passed through to
3 customers.
4 Second, existing wind resources will be upgraded with modern technology,
5 which improves efficiency and increases energy output. The additional energy output
6 from these zero-fuel-cost assets provides incremental NPC benefits for customers.
7 Third, repowering a wind resource, which replaces the mechanical equipment
8 of an existing wind facility, resets the usable life of the asset (currently 30 years),
9 thereby extending and increasing NPC benefits over the period in which the
10 repowered wind resource would have otherwise been retired from service.
11 Finally, PacifiCorp will operate the repowered wind turbines under full
12 service agreements (FSAs) with the original equipment manufacturer for 10 years to
13 perform all routine operations and maintenance (O&M) and capital replacements
14 during the contract, which will avoid capital expenditures that would otherwise be
15 needed to replace or refurbish existing equipment. Moreover, PacifiCorp anticipates
16 that new, modern equipment will reduce failure rates for certain wind turbine
17 components within the wind fleet that were experiencing high failure rates.
18 After executing its safe-harbor equipment purchase in December 2016,
19 PacifiCorp developed a wind repowering sensitivity in the first quarter of 2017, for
20 consideration in its 2017 IRP, to evaluate potential net customer benefits.
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1 Q. What wind resources did PacifiCorp include in the wind repowering sensitivity
2 presented in its 2017 IRP?
3 A. Of the 905 MW of existing wind resource capacity in the 2017 IRP, approximately
4 594 MW of this capacity are located in Wyoming (Glenrock, Rolling Hills, Seven
5 Mile Hill, High Plains, McFadden Ridge, and Dunlap), approximately 101 MW are
6 located in Oregon (Leaning Juniper), and approximately 210 MW are located in
7 Washington (Marengo). PacifiCorp has since expanded the scope of the wind
8 repowering project to include Goodnoe Hills, located in Washington and Foote Creek
9 I, located in Wyoming.
10 Q. What were the results of the wind repowering sensitivity presented in
11 PacifiCorp’s 2017 IRP?
12 A. The 2017 IRP wind repowering sensitivity showed significant customer benefits
13 across a range of assumptions related to forward market prices and possible federal
14 CO2 policy.
15 Q. Did the wind repowering sensitivity influence selection of the preferred portfolio
16 in the 2017 IRP?
17 A. Yes. The wind repowering sensitivity showed significant net customer benefits by
18 lowering the projected system present-value revenue requirement (PVRR) relative to
19 other resource portfolio options. Consequently, wind repowering was included in the
20 2017 IRP preferred portfolio, which represents PacifiCorp’s plan to deliver reliable
21 and reasonably priced service with manageable risk for customers through specific
22 actions.
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1 Q. Did PacifiCorp include a wind repowering action item in its 2017 IRP action
2 plan?
3 A. Yes. The 2017 IRP action plan, which lists specific steps PacifiCorp will take over
4 the next two to four years to deliver resources in the preferred portfolio, includes the
5 following action item:
6 PacifiCorp will implement the wind repowering project, taking 7 advantage of safe-harbor wind-turbine-generator equipment purchase 8 agreements executed in December 2016.
9 Continue to refine and update economic analysis of plant- 10 specific wind repowering opportunities that maximize 11 customer benefits before issuing the notice to proceed.
12 By September 2017, complete technical and economic analysis 13 of other potential repowering opportunities at PacifiCorp wind 14 plants not studied in the 2017 IRP (i.e., Foote Creek I and 15 Goodnoe Hills).
16 Pursue regulatory review and approval as necessary.
17 By May 2018, issue engineering, procurement and construction 18 notice to proceed to begin implementing wind repowering for 19 specific projects consistent with updated financial analysis.
20 By December 31, 2020, complete installation of wind 21 repowering equipment on all identified projects.
22 Q. Did the Commission acknowledge the 2017 IRP?
23 A. Yes. In Docket UE-160353, the Commission acknowledged the 2017 IRP in a letter
24 dated May 7, 2018.
25 Q. Did PacifiCorp update its economic analysis of wind repowering in the 2017 IRP
26 Update to account for federal income tax changes?
27 A. Yes. PacifiCorp developed its February 2018 analysis and included it in the 2017
28 IRP Update. This analysis confirmed that wind repowering continues to provide
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1 significant net benefits to customers after accounting for changes in the federal
2 income tax law.
3 Q. How did PacifiCorp address its wind repowering analysis in the 2019 IRP?
4 A. The 2019 IRP incorporates repowering approximately 999.1 MW of existing wind
5 resource capacity for 12 wind facilities. The repowering of these 12 wind facilities
6 was not evaluated in the 2019 IRP; however, new resource acquisitions were
7 evaluated assuming repowering.
8 Q. In the 2017 IRP analysis, PacifiCorp assumed the turbine-supply contracts
9 would include a two-year warranty on the new equipment. What is the updated
10 assumption?
11 A. PacifiCorp plans to operate the repowered facilities under 10-year FSAs with the
12 original equipment manufacturers to perform all routine O&M and capital
13 replacements during the contract term. After the expiration of the FSAs PacifiCorp
14 expects to perform all maintenance and capital replacements.
15 The annual cost of the FSAs will be classified to capital or expense based on
16 the nature of the work performed. This allocation will vary from year to year and
17 from plant to plant. However, based on its experience with similar contracts,
18 PacifiCorp expects that approximately 55 percent of the total cost of the FSAs will be
19 classified as capital.
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1 MODELING SCOPE, METHODOLOGIES, AND ASSUMPTIONS
2 Q. What wind resources did PacifiCorp include in its economic analysis of the wind
3 repowering project, and how do those resources relate to this filing?
4 A. As noted above, PacifiCorp prepared its main economic analysis of the wind
5 repowering project in February 2018. The economic analysis covers 12 wind
6 facilities (all except Foote Creek I), and estimates customer benefits from repowering
7 these facilities comprising approximately 999.1 MW of existing wind resource
8 capacity located in Wyoming, Oregon, and Washington in 2019 and 2020. The
9 economic analysis informed PacifiCorp’s decision to move forward with the project.
10 Modeling Methodology
11 Q. Please summarize the methodology PacifiCorp used in its economic analysis of
12 the wind repowering project.
13 A. PacifiCorp relied on the same modeling tools used to develop and analyze resource
14 portfolios in its 2017 IRP to refine and update its analysis of the wind repowering
15 project. These modeling tools calculate a system PVRR by identifying least-cost
16 resource portfolios and dispatching system resources over a 20-year forecast period
17 (2017–2036). Net customer benefits are calculated as the present-value revenue
18 requirement differential (PVRR(d)) between two simulations of PacifiCorp’s system.
19 One simulation includes the wind repowering project and the other simulation
20 excludes the wind repowering project. Customers are expected to realize net benefits
21 when the system PVRR with wind repowering is lower than the system PVRR
22 without wind repowering. Conversely, customers would experience increased costs if
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1 the system PVRR with wind repowering were higher than the system PVRR without
2 wind repowering.
3 Q. What modeling tools did PacifiCorp use to perform its economic analysis of the
4 wind repowering project?
5 A. PacifiCorp used the System Optimizer (SO) model and the Planning and Risk model
6 (PaR) to develop resource portfolios and to forecast dispatch of system resources in
7 simulations with and without wind repowering.
8 Q. Please describe the SO model and PaR.
9 A. The SO model is used to develop resource portfolios with sufficient capacity to
10 achieve a target planning-reserve margin. The SO model selects a portfolio of
11 resources from a broad range of resource alternatives by minimizing the system
12 PVRR. In selecting the least-cost resource portfolio for a given set of input
13 assumptions, the SO model performs time-of-day, least-cost dispatch for existing
14 resources and prospective new resource alternatives, while considering the cost-and-
15 performance characteristics of existing contracts and prospective demand-side
16 management (DSM) resources—all within or connected to PacifiCorp’s system. The
17 system PVRR from the SO model reflects the cost of existing contracts, wholesale-
18 market purchases and sales, the cost of new and existing generating resources (fuel,
19 fixed and variable O&M, and emissions, as applicable), the cost of new DSM
20 resources, and levelized revenue requirement of capital additions for existing coal
21 resources and potential new generating resources.
22 PaR is used to develop a chronological unit commitment and dispatch forecast
23 of the resource portfolio generated by the SO model, accounting for operating
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1 reserves, volatility and uncertainty in key system variables. PaR captures volatility
2 and uncertainty in its unit commitment and dispatch forecast by using Monte Carlo
3 sampling of stochastic variables, which include load, wholesale electricity and
4 natural-gas prices, hydro generation, and thermal unit outages. PaR uses the same
5 common input assumptions that are used in the SO model, with resource-portfolio
6 data provided by the SO model results. The PVRR from PaR reflects a distribution of
7 system variable costs, including variable costs associated with existing contracts,
8 wholesale-market purchases and sales, fuel costs, variable O&M costs, emissions
9 costs, as applicable, and costs associated with energy or reserve deficiencies. Fixed
10 costs that do not change with system dispatch, including the cost of DSM resources,
11 fixed O&M costs, and the levelized revenue requirement of capital additions for
12 existing coal resources and potential new generating resources, are based on the fixed
13 costs from the SO model, which are combined with the distribution of PaR variable
14 costs to establish a distribution of system PVRR for each simulation.
15 Q. How has PacifiCorp historically used the SO model and PaR?
16 A. PacifiCorp uses the SO model and PaR to produce and evaluate resource portfolios in
17 its IRP. PacifiCorp also uses these models to analyze resource-acquisition
18 opportunities, resource retirements, resource capital investments, and system
19 transmission projects. For example, the models were used to support the successful
20 acquisition of the Chehalis combined-cycle plant. These models were also used to
21 evaluate bids in PacifiCorp’s recent 2017R RFP, issued to solicit bids for new wind
22 resources, and in PacifiCorp’s recent 2017S RFP, issued to solicit bids for new solar
23 resources, both of which are discussed below.
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1 Q. Are the SO model and PaR the appropriate tools for analyzing the wind
2 repowering opportunity?
3 A. Yes. The SO model and PaR are the appropriate modeling tools when evaluating
4 significant capital investments that influence PacifiCorp’s resource mix and affect
5 least-cost dispatch of system resources. The SO model simultaneously and
6 endogenously evaluates capacity and energy trade-offs associated with resource
7 capital projects and is needed to understand how the type, timing, and location of
8 future resources might be affected by the wind repowering project. PaR provides
9 additional granularity on how wind repowering is projected to affect system
10 operations, recognizing that key system conditions are volatile and uncertain.
11 Together, the SO model and PaR are best suited to perform a net-benefit analysis for
12 the wind repowering opportunity that is consistent with long-standing risk-adjusted,
13 least-cost planning principles applied in PacifiCorp’s IRP.
14 Q. How did PacifiCorp use PaR to assess stochastic system cost risk associated with
15 wind repowering?
16 A. Just as it evaluates resource-portfolio alternatives in the IRP, PacifiCorp uses the
17 stochastic-mean PVRR and risk-adjusted PVRR, calculated from PaR study results, to
18 assess the stochastic system-cost risk of repowering. With Monte Carlo sampling of
19 stochastic variables, PaR produces a distribution of system variable costs. The
20 stochastic-mean PVRR is the average of net variable operating costs from the
21 distribution of system variable costs, combined with system fixed costs from the SO
22 model. PacifiCorp uses a risk-adjusted PVRR to evaluate stochastic system cost risk.
23 The risk-adjusted PVRR incorporates the expected value of low-probability, high-cost
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1 outcomes. The risk-adjusted PVRR is calculated by adding five percent of system
2 variable costs, from the 95th percentile of the distribution of system variable costs, to
3 the stochastic-mean PVRR.
4 When applied to the wind repowering analysis, the stochastic-mean PVRR
5 represents the expected level of system costs from cases with and without
6 repowering. The risk-adjusted PVRR is used to assess whether wind repowering
7 causes a disproportionate increase to system variable costs under low-probability,
8 high-cost system conditions.
9 Q. Please describe how the effective combined federal and state income tax rate
10 assumption is applied in the SO model and the PaR in the economic analysis.
11 A. The effective combined federal and state income tax rate affects PacifiCorp’s post-tax
12 weighted average cost of capital, which is used as the discount rate in the SO model
13 and PaR. Accounting for recent changes in tax law, the discount rate used in the
14 economic analysis is 6.91 percent.
15 The income tax rate also affects the capital revenue requirement for all new
16 resource options available for selection in the SO model. Capital revenue
17 requirement is levelized in the SO and PaR models to avoid potential distortions in
18 the economic analysis of capital-intensive assets that have different lives and in-
19 service dates. This is achieved through annual capital recovery factors, which are
20 expressed as a percentage of the initial capital investment for any given resource
21 alternative in any given year. Capital recovery factors, which are based on the
22 revenue requirement for specific types of assets, are differentiated by each asset’s
23 assumed life, book-depreciation rates, and tax-depreciation rates. Because capital
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1 revenue requirement accounts for the impact of income taxes on rate-based assets, the
2 capital recovery factors applied to new resource costs in the SO model were reflected
3 for each system simulation.
4 Finally, the income tax rate affects the tax gross-up of all PTC-eligible
5 resources. At the time, federal PTCs were $24/MWh, which equates to a
6 $31.82/MWh reduction in revenue requirement assuming an effective combined
7 federal and state income tax rate of 24.587 percent. The impact of the income tax rate
8 assumptions were applied to all PTC-eligible resource alternatives available in the SO
9 model.
10 Q. Did PacifiCorp analyze how other assumptions affect its economic analysis of the
11 wind repowering project?
12 A. Yes. In addition to assessing stochastic system cost risk, PacifiCorp analyzed the
13 wind-repowering project under a range of assumptions regarding wholesale market
14 prices and CO2 policy assumptions. These price-policy assumptions drive NPC-
15 related benefits, and so it is important to understand how the net-benefit analysis is
16 affected under a range of potential outcomes. PacifiCorp developed low, medium,
17 and high scenarios for the market price of electricity and natural gas and zero,
18 medium, and high CO2 price scenarios. Each pair of model simulations—with and
19 without repowering, in both the SO model and PaR—was analyzed under each
20 combination of these price-policy assumptions. I summarize the assumptions for
21 each price-policy scenario later in my testimony.
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1 Q. How did PacifiCorp assess which wind facilities to include in the scope of the
2 wind repowering project?
3 A. PacifiCorp completed a series of SO model and PaR studies to determine how the
4 system PVRR changes when a specific wind facility is added or removed from the
5 scope of the wind repowering project. This project-by-project analysis was
6 performed by running one SO model simulation that included the full scope of the
7 wind repowering project and then 12 separate SO model simulations where one of the
8 repowered wind facilities is assumed to be excluded from the scope of the wind
9 repowering project. The total system cost from the SO model simulation where all
10 facilities are repowered and from the SO model simulation where one facility is
11 removed from scope is used to calculate the marginal PVRR(d) for each wind facility.
12 Using the resource portfolio from the SO model simulations, this same approach was
13 used to calculate the PVRR(d) for each wind facility using projected system costs
14 from PaR.
15 Q. What key assumptions did PacifiCorp update since analyzing the wind
16 repowering project in its 2017 IRP?
17 A. Beyond the price-policy assumptions used to analyze a range of NPC-related benefits,
18 the updated wind repowering analysis reflects updated assumptions for up-front
19 capital costs, run-rate operating costs, and energy output for both the existing and
20 repowered wind facilities. PacifiCorp’s analysis assumes an up-front capital
21 investment totaling approximately $1.101 billion with a 25.7 percent average increase
22 in annual energy output (738 gigawatt-hours (GWh) per year). Subsequent to this
23 economic analysis the cost of the Leaning Juniper project was reduced and its
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1 performance increased resulting in a decrease in total capital project costs and an
2 increase in annual energy output. Additionally, repowering Foote Creek I was later
3 added by the Company, so its costs and energy benefits are not accounted in these
4 numbers.
5 The cost-and-performance assumptions for the wind facilities studied in this
6 updated economic analysis are summarized in Confidential Exhibit No. RTL-2C. In
7 addition, as described further below, several other assumptions were updated in the
8 August 2018 analysis to align with updates included in the 2017 IRP Update, which
9 was filed after the February 2018 analysis was completed.
10 Q. Did PacifiCorp analyze potential energy imbalance market (EIM) benefits in its
11 wind repowering analysis?
12 A. Yes. In its final 2017 IRP resource-portfolio screening process, PacifiCorp described
13 how the EIM can provide potential benefits when incremental energy is added to
14 transmission-constrained areas of Wyoming. Unscheduled or unused transmission
15 from participating EIM entities enables more efficient power flows within the hour.
16 With increasing participation in the EIM, there will be increasing opportunities to
17 move incremental energy from Wyoming to offset higher-priced generation in the
18 PacifiCorp system or other EIM participants’ systems. The more efficient use of
19 transmission that is expected with growing participation in the EIM was captured in
20 the wind repowering analysis by increasing the transfer capability between the east
21 and west sides of PacifiCorp’s system by 300 MW (from the Jim Bridger plant to
22 south-central Oregon). The ability to more efficiently use intra-hour transmission
23 from a growing list of EIM participants is not driven by the wind repowering project;
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1 however, this increased connectivity provides the opportunity to move low-cost
2 incremental energy out of transmission-constrained areas of Wyoming.
3 Q. How did PacifiCorp account for the unrecovered investments in the original
4 equipment that will be replaced with new equipment?
5 A. The economic analysis assumes that PacifiCorp will fully recover the unrecovered
6 investment in the original equipment and earn its authorized rate of return on the
7 unrecovered balance over the 30-year depreciable life of each repowered facility.
8 Q. Did PacifiCorp assume any salvage value for the equipment that will be replaced
9 with repowering?
10 A. No. But any salvage value for the existing equipment would decrease the
11 unrecovered investment and increase customer benefits.
12 Annual Revenue Requirement Methodology
13 Q. In addition to the system modeling used to calculate present-value net benefits
14 over a 20-year planning period, has PacifiCorp forecasted the change in
15 nominal-annual revenue requirement due to the wind repowering project?
16 A. Yes. The system PVRR from the SO model and PaR is calculated from an annual
17 stream of forecasted revenue requirement over a 20-year time frame, consistent with
18 the planning period in the IRP. The annual stream of forecasted revenue requirement
19 captures nominal revenue requirement for non-capital items (e.g., NPC, fixed O&M)
20 and levelized revenue requirement for capital expenditures. To estimate the annual
21 revenue-requirement impacts of repowering, project capital costs need to be
22 considered in nominal terms (i.e., not levelized).
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 18
1 Q. Why is the capital revenue requirement used in the calculation of the system
2 PVRR from the SO model and PaR levelized?
3 A. Levelization of capital revenue requirement is necessary in these models to avoid
4 potential distortions in the economic analysis of capital-intensive assets that have
5 different lives and in-service dates. Without levelization, this potential distortion is
6 driven by how capital costs are included in rate base over time. Capital revenue
7 requirement is generally highest in the first year an asset is placed in service and
8 declines over time as the asset depreciates.
9 Consider the potential implications of modeling nominal capital revenue
10 requirement for a future generating resource needed in 2036, the last year of the 2017
11 IRP planning period. If nominal capital revenue requirement were assumed, the
12 model would capture in its economic assessment of resource alternatives the highest,
13 first-year revenue requirement capital cost without having any foresight on the
14 potential benefits that resource would provide beyond 2036. If nominal capital costs
15 were applied, the model’s economic assessment of resource alternatives for the 2036
16 resource need would inappropriately favor less capital-intensive projects or projects
17 having longer asset lives, even if those alternatives would increase system costs over
18 their remaining life. Levelized capital costs for assets that have different lives and in-
19 service dates is an established way to address these types of distortions in the
20 comparative economic analysis of resource alternatives.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 19
1 Q. How did PacifiCorp forecast the annual revenue-requirement impacts of the
2 wind repowering project?
3 A. In the models that exclude repowered wind, the annual stream of costs for wind
4 facilities that are within the wind repowering scope, including levelized capital, are
5 removed from the annual stream of costs used to calculate the stochastic-mean system
6 PVRR. Similarly, in the simulation that includes repowered wind, the annual stream
7 of costs for repowered wind facilities, including levelized capital and PTCs, are
8 temporarily removed from the annual stream of costs used to calculate the stochastic-
9 mean PVRR. The differential in the remaining stream of annual costs, which
10 includes all system costs except for those associated with the wind facilities that are
11 within the wind repowering scope, represents the net system benefit caused by the
12 wind repowering project.
13 These data are disaggregated to isolate the estimated annual NPC benefits,
14 other non-NPC variable-cost benefits (i.e., variable O&M and emissions costs for
15 those scenarios that include a CO2 price assumption), and fixed-cost benefits. To
16 complete the annual revenue-requirement forecast, the change in fixed costs for those
17 wind facilities included in the wind repowering scope, including nominal capital
18 revenue requirement and PTCs, are added back in with the annual system net benefits
19 caused by wind repowering.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 20
1 Q. Over what time frame did PacifiCorp estimate the change in annual revenue
2 requirement due to the wind repowering project?
3 A. The change in annual revenue requirement was estimated through 2050. This
4 captures the full 30-year life of the new equipment installed on repowered wind
5 facilities.
6 Q. How did PacifiCorp calculate the net annual benefits caused by wind repowering
7 beyond the 20-year forecast period used in PaR?
8 A. The PaR forecast period runs from 2017 through 2036. The change in net system
9 benefits caused by wind repowering over the 2028-through-2036 time frame,
10 expressed in dollars-per-MWh of incremental energy output from wind repowering,
11 were used to estimate the change in system net benefits from 2037 through 2050.
12 This calculation was performed in several steps.
13 First, the net system benefits caused by wind repowering were divided by the
14 change in incremental energy expected from the wind repowering project, as modeled
15 in PaR over the 2028-through-2036 time frame. Next, the net system benefits per
16 MWh of incremental energy from the repowered wind projects over the 2028-
17 through-2036 time frame were levelized. These levelized results were extended out
18 through 2050 at inflation. The levelized net system benefits per MWh of incremental
19 energy output from the repowered wind projects over the 2037-through-2050 time
20 frame were then multiplied by the change in incremental energy output from
21 repowered wind projects over the same period.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 21
1 Q. Why did PacifiCorp use PaR results from the 2028-through-2036 time frame to
2 extend system cost impacts out through 2050?
3 A. Consistent with the 2017 IRP, PacifiCorp’s wind repowering analysis assumes the
4 Dave Johnston coal plant, located in eastern Wyoming, retires at the end of 2027.
5 When this plant is assumed to retire, transmission congestion affecting energy output
6 from resources in eastern Wyoming, where many repowered wind resources are
7 located, is reduced. The incremental energy output from repowered wind resources
8 provides more system benefits when not constrained by transmission limitations.
9 Consequently, the net system benefits caused by wind repowering over the 2028-
10 through-2036 time frame, after Dave Johnston is assumed to retire, is representative
11 of net system benefits that could be expected beyond 2036.
12 Q. Did PacifiCorp calculate a PVRR(d) for the wind repowering project using its
13 estimate of annual revenue-requirement impacts projected out through 2050?
14 A. Yes.
15 Q. Does the PVRR(d) calculated from estimated annual revenue requirement
16 through 2050 capture wind repowering benefits not included in the PVRR(d)
17 calculated from the 20-year forecast coming out of the SO model and PaR?
18 A. Yes. The PVRR(d) calculated from estimated annual revenue requirement extended
19 out through 2050 captures the significant increase in projected wind energy output
20 beyond the 20-year forecast period.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 22
1 Q. Why is there a significant increase in projected wind energy output beyond the
2 20-year forecast period ending 2036?
3 A. The change in wind energy output between cases with and without repowering
4 experiences a step change in the 2036-through-2040 time frame, when the wind
5 facilities, originally placed in-service during the 2006-through-2010 time frame,
6 would otherwise have hit the end of their depreciable life. Before the 2036-through-
7 2040 time frame, the change in wind energy output reflects the incremental energy
8 production that results from installing modern equipment on repowered wind assets.
9 Beyond the 2036-through-2040 time frame, the change in wind energy output
10 between a case with and without repowering reflects the full energy output from the
11 repowered wind facilities that would otherwise be retired.
12 Price-Policy Scenarios
13 Q. Please explain why price-policy scenarios are important when analyzing the
14 wind repowering project.
15 A. Wholesale-power prices, often set by natural-gas prices, and the system cost impacts
16 of potential CO2 policies influence the forecast of net system benefits from wind
17 repowering. Wholesale-power prices and CO2 policy outcomes affect the value of
18 system energy, the dispatch of system resources, and PacifiCorp’s resource mix.
19 Consequently, wholesale-power prices and CO2 policy assumptions affect NPC
20 benefits, non-NPC variable cost benefits, and system fixed-cost benefits of wind
21 repowering. Because wholesale-power prices and CO2 policy outcomes are both
22 uncertain and important drivers to the wind repowering analysis, PacifiCorp studied
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 23
1 the economics of the wind repowering project under a range of different price-policy
2 scenarios.
3 Q. What price-policy scenarios did PacifiCorp use in its wind repowering analysis?
4 A. I present two vintages of the wind repowering economic analysis—a complete set of
5 studies was prepared in February 2018 and a more targeted set of studies was
6 prepared in August 2018 as validation. The February 2018 analysis represents the
7 final set of studies used to support PacifiCorp’s pre-approval proceedings in Idaho,
8 Utah, and Wyoming. The August 2018 analysis was prepared to understand how
9 updates to certain modeling assumptions, which I describe later in my testimony,
10 affect the economic analysis that was prepared in February 2018. The specific price-
11 policy scenarios used in each of these studies are described further below.
12 February 2018 Price-Policy Assumptions
13 Q. What price-policy assumptions did PacifiCorp use in its February 2018 wind
14 repowering analysis?
15 A. PacifiCorp developed three wholesale-power price scenarios (low, medium, and
16 high), and similarly developed three CO2 policy scenarios (zero, medium, and high).
17 The nine price-policy scenarios developed for the wind repowering analysis reflect
18 different combinations of these scenario assumptions.
19 Considering that there is a high level of correlation between wholesale-power
20 prices and natural-gas prices, the wholesale-power price scenarios were based on a
21 range of natural-gas price assumptions. This ensures consistency between power
22 price and natural-gas price assumptions for each scenario. PacifiCorp implemented
23 its CO2 policy assumptions through a CO2 price, expressed in dollars-per-ton
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 24 REDACTED
1 recognizing that it is possible that future CO2 policies targeting electric-sector
2 emissions could be adopted and impose incremental costs to drive emission
3 reductions. CO2 price assumptions used in the price-policy scenarios are not intended
4 to mimic a specific type of policy mechanism (i.e., a tax or an allowance price under
5 a cap-and-trade program), but are intended to recognize that there might be future
6 CO2 policies that impose a cost to reduce emissions.
7 Q. Please describe the natural-gas price assumptions used in the February 2018
8 price-policy scenarios.
9 A. The medium-natural-gas price assumptions that are paired with zero CO2 prices
10 reflect natural-gas prices from PacifiCorp’s official forward price curve (OFPC) dated
11 December 29, 2017. This OFPC uses observed forward market prices as of
12 December 29, 2017, for 72 months, followed by a 12-month transition to natural-gas
13 prices based on a forecast developed by third-party forecasting service. The
14 medium-, low-, and high-natural-gas price assumptions used for all other scenarios
15 were chosen after reviewing a range of credible third-party forecasts. Confidential
16 Exhibit No. RTL-3C shows the range in natural-gas price assumptions from these
17 third-party forecasts relative to those adopted for the price-policy scenarios to
18 evaluate the wind repowering project.
19 The low-natural-gas price assumption was also derived from a low-price
20 scenario developed by a third-party forecasting service. The medium-natural-gas
21 price assumption, which is used beyond month 84 in the December 2017 OFPC, and
22 in all months when medium-natural-gas prices are paired with medium or low CO2
23 price assumptions, is based on a base-case forecast from that is reasonably
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 25 REDACTED
1 aligned with other base-case forecasts. The high-natural-gas price assumption was
2 based on a high-price scenario from that is characterized by exaggerated
3 boom-bust cycles (cyclical periods of high prices and low prices). PacifiCorp
4 smoothed the boom-bust cycle in this third party’s high-price scenario because the
5 specific timing of these cycles is extremely difficult to project with reasonable
6 accuracy.
7 Figure 1 shows Henry Hub natural-gas price assumptions from the December
8 2017 OFPC, low-, and high-natural-gas price scenarios.
Figure 1. Nominal Natural-Gas Price Scenarios in the February 2018 Analysis
$10 $9 $8 $7 $6 $5 $4 $/MMBtu $3 $2 $1 $0 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Low Med Gas (Dec 2017 OFPC) High
9 Q. Please describe the CO2 price assumptions used in the February 2018 price-
10 policy scenarios.
11 A. As with natural-gas prices, the medium and high CO2 price assumptions are based on
12 third-party projections from . To bracket the low end of
13 potential policy outcomes, PacifiCorp assumes there are no future policies adopted
14 that would require incremental costs to achieve emissions reductions in the electric
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 26
1 sector. In this scenario, the assumed CO2 price is zero. Figure 2 shows the CO2 price
2 assumptions used to analyze the wind repowering project.
Figure 2. Nominal CO2 Price Assumptions in the February 2018 Analysis
$25
$20
$15
$/Ton $10
$5
$0 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Medium High Zero
3 August 2018 Price-Policy Assumptions
4 Q. What price-policy assumptions did PacifiCorp use in its August 2018 wind
5 repowering analysis?
6 A. In August 2018, PacifiCorp conducted a more targeted wind repowering analysis to
7 understand how the results were impacted by certain assumption updates, which I
8 describe later in my testimony. For this study, therefore, PacifiCorp only updated its
9 medium natural-gas price and CO2 price assumptions.
10 Q. Please describe the natural-gas price assumption used in the August 2018 price-
11 policy scenario.
12 A. The medium-natural-gas price assumption that is paired with medium CO2 prices
13 reflect natural-gas prices from PacifiCorp’s OFPC dated June 29, 2018. This OFPC
14 uses observed forward market prices as of June 29, 2018, for 72 months, followed by
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 27 REDACTED
1 a 12-month transition to natural-gas prices based on an updated forecast developed by
2 .
3 Figure 3 shows Henry Hub natural-gas price assumptions used in the August
4 2018 wind repowering analysis alongside the medium-natural-gas price assumptions
5 used in the February 2018 wind repowering analysis. The nominal levelized price
6 over the period 2019 through 2036 from the August 2018 analysis is $3.97/MMBtu,
7 which is down just two percent relative to the $4.05/MMBtu levelized price from the
8 February 2018 analysis.
Figure 3. Nominal Natural-Gas Price Assumptions in the August 2018 Analysis Relative to Medium Price Assumptions from the February 2018 Analysis
$8 $7 $6 $5 $4
$/MMBtu $3 $2 $1 $0 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Med Gas (Feb 2018 Analysis) Med Gas (Aug 2018 Analysis)
9 Q. Please describe the CO2 price assumption used in the August 2018 price-policy
10 scenario.
11 A. As with natural-gas prices, the medium CO2 price assumption is based on a forecast
12 from . Figure 4 shows how the CO2 price assumptions used in the
13 August 2018 wind repowering analysis compares to the medium assumption used in
14 the February 2018 wind repowering analysis. In both instances, the CO2 price is
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 28
1 applied beginning 2030, and while the CO2 price used in the August 2018 analysis is
2 higher, this is driven by the fact that CO2 price assumptions used in the February
3 2018 analysis were inadvertently modeled in 2012 real dollars instead of nominal
4 dollars. As noted below, this was corrected in the August 2018 analysis, which was
5 modeled in nominal dollars. The CO2 price assumptions used in the August 2018
6 analysis applies inflation to determine the prices in nominal dollars.
Figure 4. CO2 Price Assumptions in the August 2018 Analysis Relative to Medium Price Assumptions from the February 2018 Analysis
$25
$20
$15
$/Ton $10
$5
$0 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Med CO2 (Feb 2018 Analysis) Med CO2 (Aug 2018 Analysis)
7 Other Assumption Updates in the August 2018 Analysis
8 Q. Beyond the price-policy assumptions discussed earlier in your testimony, what
9 other assumptions did you update in the August 2018 wind repowering analysis?
10 A. The August 2018 analysis includes updated hourly market price profiles, updated firm
11 resources, which includes 1,150 MW of new Wyoming wind resource capacity
12 consistent with the final shortlist from the 2017R RFP and inclusion of the Aeolus-to-
13 Bridger/Anticline transmission line, updated proxy resource costs for new wind and
14 solar resources, and updated inflation rate assumptions. The August 2018 analysis
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 29
1 also reflects an updated load forecast, which was refreshed after PacifiCorp filed its
2 2017 IRP Update.
Table 1. Updated Assumptions in the August 2018 Analysis Relative to Assumptions from the February 2018 Analysis Description February 2018 Analysis August 2018 Analysis
Load Forecast August 2017 June 2018
CAISO Day-Ahead Hourly Price Profile PowerDex Scalar Method Method 1,150 MW of Wyoming No New Wind and wind and the Aeolus-to- Energy Vision 2020 Transmission Bridger/Anticline Transmission Line 2017 IRP Update plus Other Resources 2017 IRP Executed and Planned Solar PPAs
Annual Inflation Rate 2.22% 2.27%
Proxy Resource Costs 2017 IRP 2017 IRP Update
3 FEBRUARY 2018 WIND REPOWERING ANALYSIS
4 Project-by-Project Results
5 Q. What price-policy scenarios were used in the project-by-project analysis?
6 A. PacifiCorp used two price-policy scenarios—the low natural-gas and zero CO2 price-
7 policy scenario and the medium natural-gas and medium CO2 price-policy scenario.
8 Based on the results of these two price-policy scenarios, PacifiCorp determined which
9 individual projects are expected to provide net customer benefits, and then these
10 projects were analyzed under all price-policy scenarios.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 30
1 Q. Please summarize the project-by-project PVRR(d) results calculated from the
2 SO model and PaR through 2036 when assuming medium natural-gas and
3 medium CO2 price-policy assumptions.
4 A. Table 2 summarizes the PVRR(d) results for each wind facility. The PVRR(d)
5 between cases with and without wind repowering are shown for each wind facility
6 based on system modeling results from the SO model and PaR, before accounting for
7 the substantial increase in incremental energy beyond the 2036 time frame. When
8 applying medium natural-gas and medium CO2 price-policy assumptions, benefits
9 from repowering the Leaning Juniper wind facility are equal to costs. All other wind
10 facilities are projected to deliver net benefits.
Table 2. Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Medium Natural-Gas and Medium CO2 Price- Policy Assumptions (2017$ million), February 2018 PaR Risk- SO Model PaR Stochastic- Wind Facility Adjusted PVRR(d) Mean PVRR(d) PVRR(d) Glenrock 1 ($25) ($21) ($23) Glenrock 3 ($8) ($7) ($7) Seven Mile Hill 1 ($33) ($28) ($29) Seven Mile Hill 2 ($7) ($7) ($7) High Plains ($17) ($13) ($13) McFadden Ridge ($5) ($4) ($4) Dunlap Ranch ($30) ($26) ($27) Rolling Hills ($12) ($9) ($10) Leaning Juniper ($0) ($0) ($0) Marengo 1 ($35) ($33) ($34) Marengo 2 ($15) ($14) ($15) Goodnoe Hills ($18) ($18) ($19) Total ($205) ($180) ($189)
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 31
1 Q. Please summarize the project-by-project PVRR(d) results calculated from the
2 SO model and PaR through 2036 when assuming low natural-gas and zero CO2
3 price-policy assumptions.
4 A. Table 3 summarizes the PVRR(d) results for each wind facility. The PVRR(d)
5 between cases with and without wind repowering are shown for each wind facility
6 based on system modeling results from the SO model and PaR, before accounting for
7 the substantial increase in incremental energy beyond the 2036 time frame. When
8 applying low natural-gas and zero CO2 price-policy assumptions, costs from
9 repowering the Leaning Juniper wind facility are slightly higher than the benefits. All
10 other wind facilities are projected to deliver net benefits.
Table 3. Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Low Natural-Gas and Zero CO2 Price-Policy Assumptions (2017$ million), February 2018 PaR Risk- SO Model PaR Stochastic- Wind Facility Adjusted PVRR(d) Mean PVRR(d) PVRR(d) Glenrock 1 ($21) ($21) ($22) Glenrock 3 ($7) ($6) ($6) Seven Mile Hill 1 ($28) ($28) ($29) Seven Mile Hill 2 ($6) ($6) ($6) High Plains ($12) ($9) ($10) McFadden Ridge ($4) ($3) ($3) Dunlap Ranch ($25) ($22) ($24) Rolling Hills ($9) ($7) ($7) Leaning Juniper $6 $3 $4 Marengo 1 ($27) ($25) ($26) Marengo 2 ($11) ($10) ($11) Goodnoe Hills ($13) ($15) ($15) Total ($157) ($149) ($156)
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 32
1 Project-by-Project Annual Revenue Requirement Price-Policy Results
2 Q. Please summarize the project-by-project PVRR(d) results calculated from the
3 change in annual revenue requirement through 2050.
4 A. Table 4 summarizes the PVRR(d) results for each wind facility calculated from the
5 change in annual nominal revenue requirement through 2050 for both price-policy
6 scenarios. Unlike the results summarized in Tables 2 and 3, these results account for
7 the substantial increase in incremental energy beyond the 2036 time frame. Each of
8 the wind facilities within the scope of the proposed repowering project show net
9 benefits with repowering under the medium natural-gas and medium CO2 price-policy
10 scenario and all facilities show net benefits under the low-natural-gas and zero CO2
11 price-policy scenario, except for the Leaning Juniper wind facility, where the benefits
12 are equal to the costs.
Table 4. Project-by-Project Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind Repowering (2017$ million), February 2018 Medium Natural-Gas Low Natural-Gas Wind Facility and Medium CO2 and Zero CO2 Glenrock 1 ($33) ($33) Glenrock 3 ($11) ($6) Seven Mile Hill 1 ($41) ($40) Seven Mile Hill 2 ($10) ($6) High Plains ($22) ($6) McFadden Ridge ($7) ($2) Dunlap Ranch ($39) ($23) Rolling Hills ($15) ($5) Leaning Juniper ($8) ($0) Marengo 1 ($50) ($22) Marengo 2 ($20) ($7) Goodnoe Hills ($26) ($19) Total ($282) ($170)
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 33
1 Q. The project-by-project results vary by wind facility, and some wind facilities
2 appear to show relatively small PVRR(d) benefits. Have you calculated the net
3 benefits of the wind repowering project accounting for the size of each wind
4 facility?
5 A. Yes. The magnitude of the PVRR(d) results must be considered in relation to the
6 specific attributes of the repowered wind facility, including the size of the facility, the
7 expected cost to repower the facility, and the level of annual energy output expected
8 after the new equipment is installed. For example, the PVRR(d) for McFadden Ridge
9 shows a $7 million benefit when repowered (using medium natural-gas and medium
10 CO2 price-policy assumptions)—the lowest PVRR(d) among all the project-by-
11 project results. The PVRR(d) benefit for McFadden Ridge is approximately
12 14 percent of the $50 million benefit for Marengo I, which yields the highest
13 PVRR(d) among all the project-by-project results. However, the capacity of
14 McFadden Ridge (28.5 MW) is approximately 20 percent of the capacity of Marengo
15 I (140.4 MW). Similarly, the expected energy output after repowering McFadden
16 Ridge (approximately 117 GWh per year) is approximately 24 percent of the expected
17 energy output after repowering Marengo I (approximately 488 GWh per year).
18 A reasonable metric to evaluate the relative benefits among the wind facilities
19 that captures the specific attributes of each facility is the nominal levelized net benefit
20 per incremental MWh expected after the facility is repowered. This metric captures
21 the specific repowering cost for each facility net of the specific benefits of each
22 facility per incremental MWh of energy expected after the facility is repowered.
23 Table 5 shows the nominal levelized net benefit of repowering per MWh of expected
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 34
1 incremental energy output after repowering for each wind facility. When using
2 medium natural-gas and medium CO2 price-policy assumptions, Table 5 shows the
3 Seven Mile Hill II facility produces the largest net benefit per incremental MWh
4 ($36/MWh), and Leaning Juniper produces the smallest net benefit per incremental
5 MWh ($7/MWh).
Table 5. Nominal Levelized Net Benefit per MWh of Incremental Energy Output after Repowering (2017$/MWh), February 2018 Medium Natural-Gas Low Natural-Gas Wind Facility and Medium CO2 and Zero CO2 Glenrock 1 $29/MWh $29/MWh Glenrock 3 $28/MWh $16/MWh Seven Mile Hill 1 $30/MWh $29/MWh Seven Mile Hill 2 $36/MWh $23/MWh High Plains $17/MWh $5/MWh McFadden Ridge $17/MWh $5/MWh Dunlap Ranch $28/MWh $17/MWh Rolling Hills $19/MWh $7/MWh Leaning Juniper $7/MWh $0/MWh Marengo 1 $25/MWh $11/MWh Marengo 2 $21/MWh $8/MWh Goodnoe Hills $26/MWh $18/MWh Weighted Average $23/MWh $14/MWh
6 Q. Is there an upside to the project-by-project PVRR(d) results?
7 A. Yes. The project-by-project results do not reflect the potential value of RECs that
8 will be generated by the incremental energy output from each facility. For instance,
9 as applied to the Leaning Juniper project discussed above, present-value net customer
10 benefits would increase by approximately $1.1 million (approximately 14 percent of
11 the PVRR(d) benefits under the medium natural-gas and medium CO2 price-policy
12 scenario as shown in Table 4) for every dollar assigned to the incremental RECs that
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 35
1 will be generated from this facility. Moreover, as noted earlier in my testimony, the
2 CO2 price assumptions used in the economic analysis were inadvertently modeled in
3 2012 real dollars instead of nominal dollars. Consequently, the PVRR(d) net benefits
4 in the medium natural-gas and medium CO2 price-policy scenario are conservative.
5 Project-wide SO and PaR Price-Policy Results
6 Q. Please summarize the PVRR(d) results for the full scope of the wind repowering
7 project as calculated from the SO model and PaR through 2036 among all nine
8 price-policy scenarios.
9 A. Table 6 summarizes the PVRR(d) results for each price-policy scenario for the full
10 scope of the wind repowering project. The PVRR(d) between cases with and without
11 the repowering project are shown for the SO model and for PaR. The data used to
12 calculate the SO Model PVRR(d) and PaR Stochastic Mean PVRR(d) results shown
13 in Table 6 are provided as Exhibit No. RTL-4.
Table 6. Project-Wide SO Model and PaR PVRR(d) (Benefit)/Cost of the Wind Repowering Projects (2017$ million), February 2018 PaR Risk- SO Model PaR Stochastic- Price-Policy Scenario Adjusted PVRR(d) Mean PVRR(d) PVRR(d)
Low Gas, Zero CO2 ($159) ($141) ($148)
Low Gas, Medium CO2 ($158) ($139) ($146)
Low Gas, High CO2 ($183) ($165) ($173)
Medium Gas, Zero CO2 ($201) ($171) ($180) Medium Gas, Medium ($204) ($180) ($189) CO Medium Gas, High CO2 ($215) ($193) ($203)
High Gas, Zero CO2 ($257) ($234) ($246)
High Gas, Medium CO2 ($260) ($248) ($260)
High Gas, High CO2 ($273) ($240) ($252)
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 36
1 Over a 20-year period, the wind repowering project reduces customer costs in
2 all nine price-policy scenarios. This outcome is consistent in both the SO model and
3 PaR results. Under the central price-policy scenario, assuming medium natural-gas
4 prices and medium CO2 prices, the PVRR(d) net benefits range between
5 $180 million, when derived from PaR stochastic-mean results, and $204 million,
6 when derived from SO model results.
7 Q. What trends do you observe in the modeling results across the different price-
8 policy scenarios?
9 A. Projected project-wide net benefits increase with higher natural-gas price
10 assumptions, and similarly, generally increase with higher CO2 price assumptions.
11 Conversely, project-wide net benefits generally decline when low natural-gas prices
12 and low CO2 prices are assumed. This trend holds true when looking at the results
13 from the two simulations used to calculate the PVRR(d) for all nine of the price-
14 policy scenarios. Importantly, both models show that the net benefits from the wind
15 repowering project are robust across a range of price-policy assumptions.
16 Q. Is there incremental customer upside to the PVRR(d) results calculated from the
17 SO model and PaR through 2036?
18 A. Yes. The PVRR(d) results presented in Table 6 do not reflect the potential value of
19 RECs generated by the incremental energy output from the repowered facilities.
20 Customer benefits for all price-policy scenarios would improve by approximately
21 $6 million for every dollar assigned to the incremental RECs that will be generated
22 from the repowered facilities through 2036. Quantifying the potential upside
23 associated with incremental REC revenues is intended simply to communicate that
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 37
1 the net benefits from the repowering project would improve if the incremental RECs
2 can be monetized in the market or if those RECs are used to reduce incremental costs
3 associated with meeting state renewable portfolio standard targets, such as those
4 PacifiCorp is subject to in Washington. Moreover, as noted earlier in my testimony,
5 the CO2 price assumptions used in the economic analysis were inadvertently modeled
6 in 2012 real dollars instead of nominal dollars. Consequently, the PVRR(d) net
7 benefits in the six price-policy scenarios that use medium and high CO2 price
8 assumptions are conservative.
9 Q. Why do the PaR results tend to show a different level of benefits from the wind
10 repowering project when compared to the results from the SO model?
11 A. The two models assess the system impacts of the wind repowering project in different
12 ways. The SO model is designed to dynamically assess system dispatch, with less
13 granularity than PaR, while optimizing the selection of resources to the portfolio over
14 time. PaR is able to dynamically assess system dispatch, with more granularity than
15 the SO model and with consideration of stochastic risk variables; however, PaR does
16 not modify the type, timing, size, and location of resources in the portfolio in
17 response to its more detailed assessment of system dispatch. In evaluating differences
18 in annual system costs between the two models, PaR’s ability to better simulate
19 system dispatch relative to the SO model results in lower benefits from repowering
20 being reported from PaR.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 38
1 Q. Does one of these two models provide a better assessment of the wind repowering
2 project relative to the other?
3 A. No. The two models are simply different, and both are useful in establishing a range
4 of wind repowering benefits through the 20-year forecast period. Importantly, the
5 PVRR(d) results from both models show customer benefits across the same set of
6 price-policy scenarios with consistent trends in the difference in PVRR(d) results
7 between price-policy scenarios. The consistency in the trend of forecasted benefits
8 between the two models, each having its own strengths, shows that the wind
9 repowering benefits are robust across a range of price-policy assumptions and when
10 analyzed using different modeling tools.
11 Q. How do the risk-adjusted PVRR(d) results compare to the stochastic-mean
12 PVRR(d) results?
13 A. The risk-adjusted PVRR(d) results show slightly greater net benefits than those
14 calculated from the stochastic-mean PVRR(d) results. This indicates that the wind
15 repowering project, which provides incremental zero-fuel-cost energy, provides
16 incremental benefits in reducing the impact of high-cost, low-probability outcomes
17 that can occur due to volatility in stochastic variables like load, wholesale-market
18 prices, hydro generation, and thermal-unit outages.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 39
1 Project-Wide Annual Revenue Requirement Price-Policy Results
2 Q. Please summarize the PVRR(d) results for the full scope of the wind repowering
3 project as calculated from the change in annual revenue requirement through
4 2050.
5 A. Table 7 summarizes the PVRR(d) results for the full scope of the wind repowering
6 project for each price-policy scenario calculated from the change in annual nominal
7 revenue requirement through 2050. The annual data over the period 2017 through
8 2050 that were used to calculate the PVRR(d) results shown in Table 7 are provided
9 as Exhibit No. RTL-5.
Table 7. Project-Wide Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind Repowering (2017$ million), February 2018 Annual Revenue Requirement Price-Policy Scenario PVRR(d)
Low Gas, Zero CO2 ($127)
Low Gas, Medium CO2 ($121)
Low Gas, High CO2 ($223)
Medium Gas, Zero CO2 ($224)
Medium Gas, Medium CO2 ($273)
Medium Gas, High CO2 ($321)
High Gas, Zero CO2 ($389)
High Gas, Medium CO2 ($386)
High Gas, High CO2 ($466)
10 When calculated through 2050, which covers the remaining life of the
11 repowered facilities, the wind repowering project reduces customer costs in all nine
12 price-policy scenarios, with PVRR(d) benefits ranging from $121 million in the low
13 natural-gas and medium CO2 price-policy scenario to $466 million in the high
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 40
1 natural-gas and high CO2 price-policy scenario. Under the central price-policy
2 scenario, assuming medium natural-gas prices and medium CO2 prices, the PVRR(d)
3 benefits are $273 million.
4 Q. What are the gross customer benefits of the repowering project and how do
5 those gross benefits compare to project costs?
6 A. Present-value gross customer benefits calculated over the remaining life of the
7 repowered wind facilities range between $1.14 billion and $1.48 billion, which
8 compares to present-value project costs totaling $1.01 billion.
9 Q. What causes the increase in PVRR(d) benefits for many of the price-policy
10 scenarios when calculated from nominal revenue requirement through 2050
11 relative to the PVRR(d) results calculated from the SO model and PaR results
12 through 2036?
13 A. The PVRR(d) calculated from estimated annual revenue requirement through 2050
14 picks up the sizable increase in incremental wind energy output beyond the 20-year
15 forecast period analyzed with the SO model and PaR. As discussed earlier in my
16 testimony, the change in wind energy output between cases with and without wind
17 repowering experiences a step change beyond this 20-year period, when the existing
18 wind facilities would otherwise have hit the end of their depreciable life. Beyond the
19 20-year forecast period, the change in wind energy output between cases with and
20 without repowering reflects the full energy output from the repowered wind facilities.
21 Figure 5 shows the incremental change in wind energy output resulting from
22 the repowering project. Incremental energy output associated with wind repowering
23 progressively increases over the 2036-through-2040 period, as wind facilities
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 41
1 originally placed in service in the 2006-through-2010 time frame would have
2 otherwise hit the end of their lives. Before 2036, and once all the wind resources
3 within the project scope are repowered, the average annual incremental increase in
4 wind energy output is approximately 738 GWh. Beyond 2040, and before the new
5 equipment hits the end of its depreciable life, the average annual incremental increase
6 in wind-energy output is approximately 3,478 GWh.
Figure 5. Change in Incremental Wind Energy Output Due to Wind Repowering (GWh), February 2018 4,000 3,500 3,000 2,500 2,000
GWh 1,500 1,000 500 0 (500)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050
7 Q. Is there additional potential upside to the PVRR(d) results calculated from the
8 change in estimated annual revenue requirement through 2050?
9 A. Yes. As in the case with the PVRR(d) results calculated from the SO model and PaR
10 results through 2036, the PVRR(d) results presented in Table 7 do not reflect the
11 potential value of RECs produced by the repowered facilities. Customer benefits for
12 all price-policy scenarios would improve by approximately $12 million for every
13 dollar assigned to the incremental RECs that will be generated from the wind
14 repowering project through 2050. Moreover, as noted earlier, the CO2 price
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 42
1 assumptions used in the February 2018 economic analysis were inadvertently
2 modeled in 2012 real dollars instead of nominal dollars. Consequently, the PVRR(d)
3 net benefits in the six price-policy scenarios that use medium and high CO2 price
4 assumptions are conservative.
5 Q. Please describe the change in annual nominal revenue requirement from the
6 wind repowering project.
7 A. Figure 6 shows the change in nominal revenue requirement due to the wind
8 repowering project for the medium natural-gas and medium CO2 price-policy
9 scenario on a total-system basis. The change in nominal revenue requirement shown
10 in the figure reflects project costs, including capital revenue requirement (i.e.,
11 depreciation, return, income taxes, and property taxes), O&M expenses, the Wyoming
12 wind-production tax, and PTCs. The project costs are netted against system impacts
13 from the wind repowering project, reflecting the change in NPC, emissions, non-NPC
14 variable costs, and system fixed costs that are affected by, but not directly associated
15 with, the wind repowering project.
Figure 6. Total-System Annual Revenue Requirement With the Wind Repowering Project (Benefit)/Cost (2017$ million), February 2018
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 43
1 As this chart shows, the wind repowering project generates substantial near-
2 term customer benefits and continues to contribute to customer benefits over the long
3 term. Before repowering, the reduction in wind energy output due to component
4 failures on the existing wind resource equipment is assumed to reduce wind energy
5 output for specific wind turbines until the time new equipment is installed. This
6 contributes to an increase in revenue requirement in 2017 and 2018 ($1 million to
7 $4 million, total system). In the February 2018 analysis, all the facilities were
8 assumed to be repowered in 2019, except the Dunlap facility, which was assumed to
9 be repowered toward the end of 2020. Over the 2019-to-2020 time frame, project
10 costs reflecting partial-year capital revenue requirement net of PTCs and system cost
11 impacts cause slight changes to revenue requirement.
12 The wind repowering project reduces revenue requirement soon after the new
13 equipment is placed in service, and from 2021 through 2028, annual revenue
14 requirement is reduced as PTC benefits increase with inflation and the new equipment
15 continues to depreciate. The reduction in annual revenue requirement is $76 million
16 by 2028. Revenue requirement increases once the PTCs expire toward the end of
17 2030. Annual revenue requirement is reduced over the 2037-through-2050 time
18 frame when, as discussed earlier in my testimony, the incremental wind energy output
19 associated with wind repowering increases substantially.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 44
1 Q. Did you evaluate how wind repowering benefits assumed beyond 2036 affect the
2 PVRR(d) results calculated from the change in annual nominal revenue
3 requirement through 2050?
4 A. Yes. The point of extrapolating results beyond 2036 is to capture the benefits from
5 the significant increase in the expected annual energy output from the repowered
6 wind facilities beyond the period in which the existing wind facilities would have
7 otherwise reached the end of their lives. While the methodology used in my analysis
8 is valid, the value of this incremental energy can be evaluated in different ways.
9 Table 8 summarizes how the PVRR(d) results through 2050 would change if
10 flat market prices at the Palo Verde (PV) market from the December 29, 2017 OFPC
11 were used as the basis to evaluate the value of incremental energy from wind
12 repowering over the 2037-through-2050 time frame. Recognizing there is both
13 upside and downside price risk to the value of this energy, I assume different levels of
14 PV prices—70 percent of the PV forward curve, 100 percent of the PV forward curve,
15 and 130 percent of the PV forward curve. PacifiCorp’s December 29, 2017 OFPC
16 includes forward prices through 2042. Conservatively, I assume no escalation in PV
17 prices beyond 2042 for each of these scenarios. Each of these scenarios is shown
18 alongside the $273 million PVRR(d) net benefit when incremental energy from
19 repowering beyond 2036 is calculated from system modeling results over the 2028
20 through 2036 time frame.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 45
Table 8. Long-Term Benefit Sensitivity, February 2018 Annual Revenue Nominal Levelized Source of 2037-2050 Requirement PVRR(d) Benefit from 2037-2050 Benefits (Benefit)/Cost ($/MWh) ($ million) 2027-2036 System $59.08 ($273) 70%Mdli of PV $49.49 ($213) 100% of PV $70.70 ($351) 130% of PV $91.92 ($489)
1 This analysis demonstrates that regardless of the methodology used to extend
2 wind repowering benefits to 2050, the PVRR(d) result shows significant customer
3 savings. If the incremental energy is valued at the PV forward curve, the PVRR(d)
4 benefits of the wind repowering project are $351 million, which is $78 million higher
5 than the methodology used in my analysis.
6 New Wind and Transmission Sensitivity
7 Q. Did PacifiCorp produce any sensitivities on its economic analysis of the wind
8 repowering project?
9 A. Yes. In the February 2018 analysis, PacifiCorp developed a sensitivity to quantify
10 how the net benefits of wind repowering are affected when combined with 1,170 MW
11 of new Wyoming wind resources and the Aeolus-to-Bridger/Anticline transmission
12 project included in the Company’s 2017 IRP. As discussed in Section II of my
13 testimony, the 2017 IRP assumed 1,100 MW of new Wyoming wind by the end of
14 2020. After filing the 2017 IRP, PacifiCorp issued its 2017R RFP and initially
15 identified 1,170 MW of new Wyoming wind to the final shortlist, which served as the
16 basis for this sensitivity. PacifiCorp later updated its 2017R RFP final shortlist to
17 include 1,150 MW of new Wyoming wind. This sensitivity was based on the
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 46
1 assumption that the new wind and transmission would be operational by the end of
2 2020.
3 Q. Please summarize the results of the sensitivity that includes new Wyoming wind
4 resources and the planned Aeolus-to-Bridger/Anticline transmission project.
5 A. Table 9 summarizes the PVRR(d) results for the new wind sensitivity that assumes
6 wind repowering is implemented in combination with adding 1,170 MW of new
7 Wyoming wind and the Aeolus-to-Bridger/Anticline transmission project. This
8 sensitivity was developed using SO model and PaR simulations through 2036 for the
9 medium natural-gas, medium CO2 and the low natural-gas, zero CO2 price-policy
10 scenarios. The results are shown alongside the base repowering study presented
11 above in which wind repowering was evaluated without the new wind and
12 transmission
Table 9. New Wind and Aeolus-to-Bridger/Anticline Sensitivity (Benefit)/Cost of Wind Repowering (2017$ million), February 2018 Sensitivity Base Study (Repowering + New Change in (Repowering) Wind & Trans.) PVRR(d) PVRR(d) PVRR(d)
Medium Gas, Medium CO2 SO Model ($532) ($204) ($328) PaR Stochastic ($466) ($180) ($286) PaR RiskM Adjusted ($489) ($189) ($300)
Low Gas, Zero CO2 SO Model ($301) ($159) ($142) PaR Stochastic ($300) ($141) ($159) PaR Risk Adjusted ($315) ($148) ($167)
13 Customer benefits increase significantly when the wind repowering project is
14 implemented with the new wind and transmission in both the medium natural-gas,
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 47
1 medium CO2 and the low natural-gas, zero CO2 price-policy scenarios. These results
2 demonstrate that customer benefits not only persist, but increase, if both the wind
3 repowering project and the new wind and transmission projects are completed.
4 AUGUST 2018 WIND REPOWERING ANALYSIS
5 Project-by-Project SO and PaR Model Price-Policy Results
6 Q. Please summarize the scope of the approach taken in the August 2018 analysis,
7 relative to the February 2018 analysis, including the price-policy scenarios used.
8 A. For the August 2018 analysis, PacifiCorp performed a project-by-project economic
9 analysis that was updated to account for more current modeling assumptions, using
10 the same basic methodology used in the February 2018 analysis: SO model and PaR
11 studies through 2036 (levelized capital and nominal treatment of PTCs); and nominal
12 revenue requirement analysis through 2050 (nominal capital and nominal treatment of
13 PTCs). PacifiCorp performed the updated analysis in August 2018 for each facility
14 using medium natural gas and medium CO2 price-policy assumptions.
15 For Leaning Juniper, PacifiCorp also performed an updated analysis in August
16 2018 using the most conservative low natural gas and zero CO2 price-policy
17 assumptions. This additional price-policy scenario was analyzed for the Leaning
18 Juniper facility because its cost-and-performance assumptions had improved relative
19 to the February 2018 analysis where Leaning Juniper presented the lowest customer
20 net benefits relative to other wind facilities.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 48 REDACTED
1 Q. How did the cost-and-performance assumptions change for Leaning Juniper in
2 the August 2018 analysis relative to the February 2018 analysis?
3 A. After evaluating alternative equipment suppliers, the capital cost required to repower
4 Leaning Juniper was reduced by approximately from to
5 and the expected increase in annual energy output increased from
6 percent to percent.
7 Q. Please summarize the project-by-project PVRR(d) results calculated from the
8 SO model and PaR through 2036 when assuming medium natural-gas and
9 medium CO2 price-policy assumptions.
10 A. Table 10 summarizes the PVRR(d) results for each wind facility. With the passage of
11 time between the February 2018 and August 2018 analyses, PVRR(d) results from the
12 August 2018 analysis are discounted back to 2018 dollars. Results from the
13 February 2018 analysis are discounted back to 2017 dollars. The PVRR(d) between
14 cases with and without wind repowering are shown for each wind facility based on
15 system modeling results from the SO model and PaR, before accounting for the
16 substantial increase in incremental energy beyond the 2036 time frame. When
17 applying medium natural-gas and medium CO2 price-policy assumptions, all wind
18 facilities are projected to deliver net benefits.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 49
Table 10. Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Medium Natural-Gas and Medium CO2 Price- Policy Assumptions (2018$ million); August 2018 PaR Risk- SO Model PaR Stochastic- Wind Facility Adjusted PVRR(d) Mean PVRR(d) PVRR(d) Glenrock 1 ($29) ($24) ($31) Glenrock 3 ($10) ($8) ($11) Seven Mile Hill 1 ($40) ($31) ($39) Seven Mile Hill 2 ($9) ($8) ($9) High Plains ($23) ($14) ($21) McFadden Ridge ($7) ($5) ($7) Dunlap Ranch ($37) ($28) ($37) Rolling Hills ($16) ($11) ($16) Leaning Juniper ($10) ($10) ($10) Marengo 1 ($44) ($33) ($43) Marengo 2 ($20) ($15) ($20) Goodnoe Hills ($24) ($20) ($26)
1 Q. How do the August 2018 results in Table 10 compare with February 2018 results
2 assuming medium natural-gas and medium CO2 price-policy assumptions?
3 A. Using the medium natural-gas and medium CO2 price-policy assumptions, the
4 August 2018 project-by-project PVRR(d) results calculated from the SO model and
5 PaR through 2036 are similar to, and generally improve upon, projected customer
6 benefits relative to the February 2018 project-by-project PVRR(d) results. As
7 discussed further below, a particularly notable change is evident for Leaning Juniper.
8 This facility was projected in February 2018 to provide net zero customer benefits,
9 but with improved cost-and-performance assumptions applied in the August 2018
10 analysis is projected to provide $10 million in net positive customer benefits.
11 Table 11 displays the two sets of analyses side by side. These results confirm
12 that with updated assumptions, the conclusions from the February 2018 study—
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 50
1 implementing the repowering project will provide substantial customer benefits—
2 remain valid.
Table 11. Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Medium Natural-Gas and Medium CO2 Price- Policy Assumptions ($ million); February and August 2018
PaR Risk-Adjusted Wind Facility SO Model PaR Stochastic-Mean PVRR(d) PVRR(d) PVRR(d)
February August February August February August 2018 2018 2018 2018 2018 2018 (2017$) (2018$) (2017$) (2018$) (2017$) (2018$) Glenrock 1 ($25) ($29) ($21) ($24) ($23) ($31) Glenrock 3 ($8) ($10) ($7) ($8) ($7) ($11) Seven Mile Hill ($33) ($40) ($28) ($31) ($29) ($39) Seven Mile1 Hill ($7) ($9) ($7) ($8) ($7) ($9) High Plains ($17) ($23) ($13) ($14) ($13) ($21) McFadden Ridge ($5) ($7) ($4) ($5) ($4) ($7) Dunlap Ranch ($30) ($37) ($26) ($28) ($27) ($37) Rolling Hills ($12) ($16) ($9) ($11) ($10) ($16) Leaning Juniper ($0) ($10) ($0) ($10) ($0) ($10) Marengo 1 ($35) ($44) ($33) ($33) ($34) ($43) Marengo 2 ($15) ($20) ($14) ($15) ($15) ($20) Goodnoe Hills ($18) ($24) ($18) ($20) ($19) ($26)
3 Q. Please summarize the PVRR(d) results for the Leaning Juniper facility
4 calculated from the SO model and PaR through 2036 when assuming low
5 natural-gas and zero CO2 price-policy assumptions.
6 A. Table 12 summarizes the PVRR(d) results for the Leaning Juniper facility when
7 applying low natural-gas and zero CO2 price-policy assumptions. Results, which
8 represent the PVRR(d) between cases with and without repowering the Leaning
9 Juniper facility, are shown alongside those reported from the February 2018 analysis.
10 The PVRR(d) results in Table 12 are from the SO model and PaR, before accounting
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 51
1 for the substantial increase in incremental energy beyond the 2036 time frame. Under
2 this most conservative price-policy scenario, the Leaning Juniper facility is still
3 projected to deliver net benefits, and driven by improved cost-and-performance
4 assumptions, these net benefits improve relative to the February 2018 PVRR(d)
5 results. These results confirm that with updated assumptions, implementing the entire
6 repowering project, including at the Leaning Juniper facility, will provide customer
7 benefits and is therefore prudent.
Table 12. Leaning Juniper SO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Low Natural-Gas and Zero CO2 Price-Policy Assumptions ($ million); February and August 2018
PaR Risk-Adjusted Wind Facility SO Model PaR Stochastic-Mean PVRR(d) PVRR(d) PVRR(d)
February August February August February August 2018 2018 2018 2018 2018 2018 $ $ $ $ $ $ Leaning Juniper $6 ($5) $3 ($4) $4 ($4)
8 Q. Is there incremental customer upside to the PVRR(d) results calculated from the
9 SO model and PaR through 2036?
10 A. Yes. As is the case for the February 2018 analysis, the PVRR(d) results presented in
11 Tables 10 and 12 do not reflect the potential value of RECs generated by the
12 incremental energy output from the repowered facilities.
13 Project-by-Project Annual Revenue Requirement Price-Policy Results
14 Q. Please summarize the project-by-project PVRR(d) results calculated from the
15 change in annual revenue requirement through 2050.
16 A. Table 13 summarizes the PVRR(d) results for each wind facility calculated from the
17 change in annual nominal revenue requirement through 2050 for the medium natural-
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 52
1 gas and medium CO2 price-policy scenario. Unlike the results summarized in Table
2 10, these results account for the substantial increase in incremental energy beyond the
3 2036 time frame. Each of the wind facilities within the scope of the proposed
4 repowering project show net benefits with repowering under the medium natural-gas
5 and medium CO2 price-policy scenario.
Table 13. Project-by-Project Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind Repowering (2018$ million), with Medium Natural-Gas and Medium CO2 Price-Policy Assumptions; August 2018 Nom. Rev. Req. PVRR(d) Wind Facility (Benefit)/Cost Glenrock 1 ($35) Glenrock 3 ($10) Seven Mile Hill 1 ($43) Seven Mile Hill 2 ($9) High Plains ($19) McFadden Ridge ($5) Dunlap Ranch ($39) Rolling Hills ($15) Leaning Juniper ($21) Marengo 1 ($46) Marengo 2 ($17) Goodnoe Hills ($25)
6 Q. How do the August 2018 results in Table 13 compare with the February 2018
7 analysis assuming medium natural-gas and medium CO2 price-policy
8 assumptions?
9 A. Using the medium natural-gas and medium CO2 price-policy assumptions, the
10 August 2018 project-by-project PVRR(d) results calculated from change in annual
11 nominal revenue requirement through 2050 are similar to the February 2018 results.
12 Table 14 displays the two sets of analyses side by side. These results confirm that
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 53
1 with updated assumptions, the conclusions from the February 2018 study—
2 implementing the repowering project will provide substantial customer benefits—
3 remain valid.
Table 14. Project-by-Project Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind Repowering ($ million), with Medium Natural-Gas and Medium CO2 Price-Policy Assumptions; February and August 2018 Wind Facility Nom.Rev.Req. PVRR(d) (Benefit)/Cost February 2018 August 2018
(2017$) (2018$) Glenrock 1 ($33) ($35) Glenrock 3 ($11) ($10) Seven Mile Hill 1 ($41) ($43) Seven Mile Hill 2 ($10) ($9) High Plains ($22) ($19) McFadden Ridge ($7) ($5) Dunlap Ranch ($39) ($39) Rolling Hills ($15) ($15) Leaning Juniper ($8) ($21) Marengo 1 ($50) ($46) Marengo 2 ($20) ($17) Goodnoe Hills ($26) ($25)
4 Q. Please summarize the PVRR(d) results for the Leaning Juniper facility
5 calculated from the change in annual revenue requirement through 2050 when
6 assuming low natural-gas and zero CO2 price-policy assumptions.
7 A. Table 15 summarizes the PVRR(d) results for the Leaning Juniper facility when
8 applying low natural-gas and zero CO2 price-policy assumptions. Results, which
9 represent the PVRR(d) between cases with and without repowering the Leaning
10 Juniper facility, are shown alongside those reported from the February 2018 analysis.
11 The PVRR(d) results in Table 15 are based on system modeling results from the
12 change in annual revenue requirement through 2050. Under this most conservative
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 54
1 price-policy scenario, the Leaning Juniper facility is still projected to deliver net
2 benefits, and driven by improved cost-and-performance assumptions, these net
3 benefits improve relative to the February 2018 PVRR(d) results. These results
4 confirm that with updated assumptions, implementing the entire repowering project,
5 including at the Leaning Juniper facility, will provide customer benefits and is
6 therefore prudent.
Table 15. Leaning Juniper Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind Repowering ($ million), with Low Natural-Gas and Zero CO2 Price-Policy Assumptions; February and August 2018 Wind Facility Nom. Rev. Req. PVRR(d) (Benefit)/Cost February 2018 August 2018
(2017$) (2018$) Leaning Juniper ($0) ($4)
7 Q. Have you calculated the net benefits of the wind repowering project considering
8 the size of each wind facility?
9 A. Yes. As discussed above, the metric of nominal levelized net benefit per incremental
10 MWh expected after the facility is repowered captures the specific repowering cost
11 for each facility net of the specific benefits of each facility per incremental MWh of
12 energy expected after the facility is repowered. Table 16 shows the nominal levelized
13 net benefit of repowering per MWh of expected incremental energy output after
14 repowering each wind facility. When using medium natural-gas and medium CO2
15 price-policy assumptions, Table 16 shows the Glenrock 1, Seven Mile Hill 1, and
16 Seven Mile Hill 2 facilities produce the largest net benefit per incremental MWh
17 ($29/MWh), and McFadden Ridge produces the smallest net benefit per incremental
18 MWh ($12/MWh).
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 55
Table 16. Project-by-Project Nominal Levelized Net Benefit per MWh of Incremental Energy Output after Repowering (2018$/MWh), with Medium Natural-Gas and Medium CO2 Price-Policy Assumptions; August 2018 Wind Facility Nom. Lev. $/MWh Glenrock 1 $29/MWh Glenrock 3 $25/MWh Seven Mile Hill 1 $29/MWh Seven Mile Hill 2 $29/MWh High Plains $14/MWh McFadden Ridge $12/MWh Dunlap Ranch $27/MWh Rolling Hills $17/MWh Leaning Juniper $17/MWh Marengo 1 $21/MWh Marengo 2 $17/MWh Goodnoe Hills $23/MWh
1 Q. How do the August 2018 results in Table 16 compare with the previous analysis
2 in February 2018 assuming medium natural-gas and medium CO2 price-policy
3 assumptions?
4 A. Using the medium natural-gas and medium CO2 price-policy assumptions, the
5 August 2018 project-by-project metrics for nominal levelized net benefit per
6 incremental MWh expected after the facility is repowered are similar to the February
7 2018 results under the same price-policy scenario. Table 17 displays the two sets of
8 analyses side by side. These results confirm that with updated assumptions, the
9 conclusions from the February 2018 study—implementing the repowering project
10 will provide substantial customer benefits—remain valid.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 56
Table 17. Project-by-Project Nominal Levelized Net Benefit per MWh of Incremental Energy Output after Repowering ($/MWh), with Medium Natural-Gas and Medium CO2 Price-Policy Assumptions; February and August 2018 Wind Facility Nom. Lev. $/MWh February 2018 August 2018 Glenrock 1 $29/MWh $29/MWh Glenrock 3 $28/MWh $25/MWh Seven Mile Hill 1 $30/MWh $29/MWh Seven Mile Hill 2 $36/MWh $29/MWh High Plains $17/MWh $14/MWh McFadden Ridge $17/MWh $12/MWh Dunlap Ranch $28/MWh $27/MWh Rolling Hills $19/MWh $17/MWh Leaning Juniper $7/MWh $17/MWh Marengo 1 $25/MWh $21/MWh Marengo 2 $21/MWh $17/MWh Goodnoe Hills $26/MWh $23/MWh
1 Q. Is there an upside to the project-by-project PVRR(d) results?
2 A. Yes. As is the case for the February 2018 analysis, these project-by-project results do
3 not reflect the potential value of RECs that will be generated by the incremental
4 energy output from each facility.
5 FOOTE CREEK I
6 Q. Please describe the repowering of the Foote Creek I facility.
7 A. As discussed in the testimony of Mr. Hemstreet, the Foote Creek I wind facility was
8 originally developed more than 20 years ago. Because of its age and design,
9 repowering of Foote Creek I involves the removal of all existing wind turbine
10 equipment, including towers, foundations, and energy collection system, and
11 replacement with new equipment and energy collector circuits appropriately sized for
12 the new equipment. Repowering at the Foote Creek I facility will result in the
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 57
1 replacement of 68 existing small-capacity wind turbines with 13 modern wind
2 turbines, representing approximately 46 MW of wind resource nameplate capacity.
3 Q. Why wasn’t Foote Creek I included in your main economic analysis?
4 A. As discussed above, the scope of repowering the Foote Creek I facility is notably
5 different than the other wind facilities. Moreover, unlike the other 12 wind facilities
6 within the scope of the wind repowering project, PacifiCorp shared ownership of
7 Foote Creek I with Eugene Water & Electric Board (EWEB). Further differentiating
8 Foote Creek I from the other 12 wind facilities within the scope of the wind
9 repowering project, Bonneville Power Administration (BPA) was purchasing
10 37 percent of the output from Foote Creek I via a power-purchase agreement (PPA)
11 that was to terminate in April 2024. Taken together, it took additional time to engage
12 in discussions with EWEB and BPA to determine whether the ownership structure
13 and PPA could be modified to facilitate repowering the Foote Creek I wind facility.
14 Ultimately, as Mr. Hemstreet describes in his testimony, PacifiCorp was able to clear
15 the way for repowering by acquiring EWEB’s ownership interest, terminating the
16 PPA with BPA, and acquiring the master wind energy lease rights associated with the
17 Foote Creek I site.
18 Q. When did PacifiCorp make the decision to repower Foote Creek I?
19 A. PacifiCorp made the decision to repower Foote Creek I in June 2019.
20 Q. Please summarize the economic analysis that supports the prudence of this
21 decision.
22 A. PacifiCorp originally approved repowering Foote Creek I based on a June 11, 2019
23 economic analysis indicating that repowering would produce present-value net
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1 customer benefits ranging between $3 million to $46 million. This analysis included
2 acquisition of EWEB’s 21.21 percent ownership interest and termination of the PPA
3 with BPA. This analysis did not include acquisition of the master wind energy lease
4 rights associated with the Foote Creek I site.
5 The economic analysis was updated July 16, 2019, to reflect the acquisition of
6 the master wind energy lease rights associated with the Foote Creek I site. This
7 analysis used two price-policy scenarios, representing low and medium natural gas
8 prices and zero and medium CO2 price scenarios. The price-policy scenario that pairs
9 medium natural gas prices with medium CO2 prices is referred to as the “MM”
10 scenario and the price-policy scenario that pairs low natural gas prices with a zero
11 CO2 price is referred to as the “LN” scenario. The natural gas and CO2 price
12 assumptions are summarized in Figure 7.
Figure 7. Price-Policy Assumptions used in the Economic Analysis of Foote Creek I Repowering.
13 My analysis shows that Foote Creek I will deliver net customer benefits in
14 both price-policy scenarios through 2050, producing present-value net customer
15 benefits ranging between $6 million to $48 million.
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1 Q. Please explain how you conducted your analysis.
2 A. The methodology is consistent with the approach used to perform the economic
3 analysis of the other 12 facilities within the scope of the wind repowering project.
4 The system value of incremental wind energy in eastern Wyoming is calculated from
5 two PaR simulations for a given price-policy scenario—one simulation with
6 incremental wind energy and one simulation without incremental wind energy. I then
7 converted the system value of incremental wind energy to a dollar-per-megawatt-hour
8 value by dividing the change in annual system costs by the change in incremental
9 wind energy for both price-policy scenarios through 2038. The value of wind energy
10 is extended out through 2050 by extrapolating the system values calculated from
11 modeled data over the 2030-2038 time frame. The assumed system value, expressed
12 in dollars per megawatt-hour, is applied to the incremental energy output associated
13 with Foote Creek I wind repowering.
14 Q. Please provide the results of your analysis.
15 A. Foote Creek I repowering is forecasted to provide significant net benefits for
16 customers. Table 18 summarizes PVRR(d) benefits calculated from changes in
17 system costs through 2050, inclusive of the cost of repowering. This table also
18 presents the same information on a levelized dollar-per-megawatt-hour basis. Under
19 the medium and low price-policy scenarios, nominal levelized net benefits are
20 $29/MWh and $3/MWh, respectively. These results are consistent with the range of
21 the net benefits associated with other wind repowering facilities, shown above in
22 Tables 5 and 16.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 60
Table 18. Net Benefits from Foote Creek I Repowering PVRR(d) Net Nom. Lev. Net Benefit (Benefit)/Cost ($/MWh of Incremental ($ million) Energy) Medium Natural Gas, ($48.2) $29/MWh Medium CO2 Low Natural Gas, No CO2 ($5.6) $3/MWh
1 Q. Have you demonstrated the estimated change in nominal annual revenue
2 requirement from Foote Creek I repowering for the medium price-policy
3 scenario?
4 A. Yes. Figure 8 reflects the change in nominal revenue requirement associated with
5 project costs, including capital revenue requirement (i.e., depreciation, return, income
6 taxes, and property taxes), O&M expenses, the Wyoming wind-production tax, and
7 production tax credits. The project costs are netted against system benefits as
8 described above. Foote Creek I repowering reduces nominal revenue requirement in
9 all but the first three years of its depreciable life.
Figure 8. (Reduction)/Increase in Total-System Annual Revenue Requirement from Foote Creek I Repowering
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 61
1 II. NEW WIND AND TRANSMISSION
2 Q. Please describe the new wind and transmission elements of Energy Vision 2020
3 included in this case.
4 A. By the end of 2020, PacifiCorp will add 1,150 MW of new wind resources in
5 Wyoming. These resources are comprised of three facilities built by PacifiCorp, the
6 500 MW TB Flats I and II facilities and the 250 MW Ekola Flats project, and one
7 facility that is a combined build-transfer agreement (BTA) and PPA, the 400 MW
8 Cedar Springs facility (collectively, the Energy Vision 2020 Wind Projects). These
9 facilities were carefully selected to maximize value to customers in the 2017R RFP,
10 which was monitored by independent evaluators from both Oregon and Utah.
11 Because PacifiCorp’s current transmission system in eastern Wyoming is
12 operating at capacity, PacifiCorp is also building a new, 140-mile Gateway West
13 transmission sub-segment—the 500 kV Aeolus-to-Bridger/Anticline transmission
14 line, plus network upgrades—in Wyoming to enable this generation (collectively,
15 Transmission Projects). As explained by Mr. Richard A. Vail, the line allows
16 PacifiCorp to interconnect up to 1,510 MW of new capacity, relieving existing
17 transmission constraints in southeastern Wyoming. The new line increases transfer
18 capability westbound by approximately 950 MW.
19 Q. Please summarize your testimony in Section II.
20 A. PacifiCorp’s economic analysis shows that the investments in the Combined Projects
21 are prudent, useful, and in the public interest. The Energy Vision 2020 Wind
22 Projects, which are enabled by the Transmission Projects, will generate PTCs for 10
23 years; produce zero-fuel-cost energy that will lower NPC; generate RECs, which can
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 62
1 be sold in the market to create additional revenues that would lower net customer
2 costs or be used to comply with state renewable portfolio standard targets; and help
3 decarbonize PacifiCorp’s resource portfolio, which will mitigate long-term risk
4 associated with potential future state and federal policies targeting CO2 emissions
5 reductions from the electric sector.
6 The Transmission Projects will relieve congestion on the current transmission
7 system in eastern Wyoming, enable new wind resource interconnections, provide
8 critical voltage support to the Wyoming transmission network, improve overall
9 reliability of the transmission system, enhance PacifiCorp’s ability to comply with
10 mandated reliability and performance standards, and reduce line losses. Moreover,
11 the proposed transmission-system investments create an opportunity for further
12 increases to the transfer capability across the Aeolus-to-Bridger/Anticline line with
13 the construction of additional segments of Energy Gateway.
14 The Combined Projects will produce customer benefits that significantly
15 outweigh costs. The change in revenue requirement due to the Combined Projects
16 was analyzed using two different IRP modeling tools across nine different scenarios,
17 each with varying natural-gas and CO2 price assumptions. For each of these
18 scenarios, the PVRR(d) was calculated from system revenue requirement forecasts
19 through 2050 (through the 30-year life of the Wind Projects), reflecting nominal
20 capital revenue requirement from the Combined Projects, and from system revenue
21 requirement forecasts over a 20-year period, where capital revenue requirement is
22 levelized. This approach is the same basic methodology that was used to evaluate the
23 wind repowering project discussed earlier in my testimony.
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1 The Combined Projects show net PVRR(d) benefits of $174 million in the
2 medium case through 2050, and benefits of $338 million in the medium case through
3 2036. In the 18 scenarios studied (nine each for the 2050 and 2036 analyses), 16 of
4 18 cases show net customer benefits.
5 The customer benefits from the Combined Projects increase substantially with
6 higher natural-gas price assumptions and higher CO2 price assumptions. These
7 benefits conservatively do not assign any value to the RECs that will be generated by
8 the Energy Vision 2020 Wind Projects. For every dollar assigned to the incremental
9 RECs that will be generated by the Wind Projects, present-value benefits would
10 improve for all scenarios by an additional $38 million when calculated from the
11 change in system revenue requirement through 2050. When calculated from the
12 change in system revenue requirement over a 20-year period, each dollar assigned to
13 the incremental RECs from the Energy Vision 2020 Wind Projects would increase
14 PVRR(d) benefits by $31 million.
15 Sensitivity analysis shows that substantial benefits of the Combined Projects
16 persist when paired with PacifiCorp’s plans to repower certain wind resources, which
17 is the subject of Section I of my testimony.
18 2017 INTEGRATED RESOURCE PLAN
19 Q. Did PacifiCorp analyze new Wyoming wind resources and the Aeolus-to-
20 Bridger/Anticline Line in its 2017 IRP?
21 A. Yes. The 2017 IRP preferred portfolio included 1,100 MW of new wind resources
22 located in Wyoming. This wind capacity is enabled by the Aeolus-to-
23 Bridger/Anticline line, which is also included in the 2017 IRP preferred portfolio.
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1 The new wind and Aeolus-to-Bridger/Anticline line are assumed to be placed in
2 service by the end of 2020 so that the new wind resources can qualify for the full
3 value of PTCs.
4 Q. What led PacifiCorp to include 1,100 MW of new Wyoming wind resources and
5 the Aeolus-to-Bridger Anticline Line in its 2017 IRP preferred portfolio?
6 A. All of the resource portfolios produced during the initial stages of the portfolio-
7 development phase of the 2017 IRP contained new Wyoming wind resources in 2021,
8 which for modeling purposes was used as a proxy on-line date for PTC-eligible wind
9 achieving commercial operation by the end of 2020. At the same time, the load-and-
10 resource balance developed for the 2017 IRP shows that PacifiCorp would not require
11 incremental system capacity to meet its 13-percent planning-reserve margin until
12 2028, accounting for assumed coal unit retirements, incremental energy efficiency
13 savings, and available wholesale-power market purchase opportunities. These results
14 indicated that PTC-eligible wind resources located in wind-rich areas like Wyoming
15 provide customer benefits.
16 During the initial stages of portfolio development for the 2017 IRP, the
17 amount of Wyoming wind capacity that routinely appeared in 2021 was limited by
18 transmission congestion on PacifiCorp’s existing 230 kV transmission system. This
19 congestion affects energy output from resources in eastern Wyoming where there is
20 substantial potential to develop high-quality, low-cost wind resources. Wyoming
21 resource selections at or near the limitation on Wyoming wind capacity caused by
22 transmission constraints indicated clear potential for incremental customer benefits if
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1 incremental transmission is added to accommodate more PTC-eligible wind resources
2 located in Wyoming.
3 To assess these potential incremental benefits, PacifiCorp reviewed
4 components of its Energy Gateway transmission project to identify specific sub-
5 segments that could access additional new Wyoming wind resources. In performing
6 this review, PacifiCorp looked at the transmission interconnection queue and
7 determined that sub-segment D.2 (the Aeolus-to-Bridger/Anticline Line) of the
8 Energy Gateway transmission project could access a sizable volume of new wind
9 projects being developed in the Aeolus area. PacifiCorp then developed an initial,
10 high-level cost estimate for the Aeolus-to-Bridger/Anticline Line that was used for an
11 initial Aeolus-to-Bridger/Anticline sensitivity assuming 650 MW of incremental
12 transfer capability and 900 MW of new Wyoming wind resources.
13 Q. Why did PacifiCorp assume new wind resource capacity in excess of the
14 assumed incremental transfer capability of the Aeolus-to-Bridger/Anticline Line
15 in this initial sensitivity?
16 A. The Aeolus-to-Bridger/Anticline Line can enable new resource interconnections in
17 excess of the transfer capability of the line. PacifiCorp’s preliminary sensitivity in
18 the 2017 IRP assumed the Aeolus-to-Bridger/Anticline Line would support at least
19 900 MW of new resource interconnections. The assumed level of new wind
20 resources is higher than the assumed incremental transfer capability of the
21 transmission line because wind resources do not generate at their full capability in all
22 hours of the year. At times when wind resources in southeastern Wyoming are
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1 operating near full output, other resources in the area can be re-dispatched to
2 accommodate PTC-producing wind generation.
3 Q. What were the results of this initial Aeolus-to-Bridger/Anticline sensitivity?
4 A. The initial sensitivity indicated that there could be economic benefits from aligning
5 development of the Aeolus-to-Bridger/Anticline Line with new, PTC-eligible
6 Wyoming wind resources. Based on the promising results from this initial sensitivity,
7 PacifiCorp reviewed its initial, high-level assumptions to determine how refined
8 inputs would affect potential benefits from the incremental new Wyoming wind
9 resources and the Aeolus-to-Bridger/Anticline Line.
10 PacifiCorp completed power flow and dynamic-stability studies to refine its
11 Aeolus-to-Bridger/Anticline Line assumptions. These studies supported increasing
12 the assumed incremental transfer capability of the new transmission line from 650
13 MW to 750 MW and suggested that it could enable up to 1,270 MW of new resource
14 interconnections. PacifiCorp also refined its initial, high-level cost assumptions,
15 reducing the estimated capital cost of the project by over $100 million.
16 In addition, PacifiCorp reviewed its new wind resource cost-and-performance
17 assumptions, initially developed to represent proxy Wyoming wind resources, to
18 focus on specific projects that could be developed in the Aeolus area. Based on this
19 review, PacifiCorp determined that the estimated capital cost for new wind resources
20 could be lowered by 10.7 percent from its initial proxy cost assumptions and that its
21 wind capacity factor assumptions should be reduced from 43 percent to 41.2 percent.
22 PacifiCorp also reviewed whether additional benefits from the wind enabled
23 by the Aeolus-to-Bridger/Anticline Line could be quantified. PacifiCorp identified
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1 and quantified three additional value streams associated with its participation in the
2 EIM, improved transmission reliability, and reduced transmission line losses. The
3 results from this additional review and analysis were applied in the final 2017 IRP
4 resource-portfolio screening process, where PacifiCorp conducted additional studies
5 that considered analysis performed in earlier resource-portfolio screening stages.
6 Q. What type of analysis did PacifiCorp consider from earlier resource-portfolio
7 screening stages?
8 A. In earlier stages of its resource-portfolio screening process, PacifiCorp developed a
9 wind repowering sensitivity, where certain existing wind resources qualify for an
10 additional 10 years of PTCs after they are upgraded with modern equipment. The
11 wind repowering project, discussed in Section I of my testimony, showed significant
12 net customer benefits across a range of assumptions related to forward market prices
13 and federal CO2 policy based on the Clean Power Plan. Considering the significant
14 customer benefits associated with the wind repowering project, PacifiCorp combined
15 its refined assumptions for incremental new Wyoming wind and the Aeolus-to-
16 Bridger/Anticline Line in a study that included wind repowering.
17 Q. What were the results of PacifiCorp’s final 2017 IRP resource-portfolio
18 screening process that incorporated refined and expanded input assumptions for
19 incremental new Wyoming wind resources and the Aeolus-to-Bridger/Anticline
20 Line?
21 A. Studies developed for the final 2017 IRP resource-portfolio screening process showed
22 significant net customer benefits relative to other resource-portfolio alternatives.
23 Based on these results, the Aeolus-to-Bridger/Anticline Line and the 1,100 MW of
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 68
1 new Wyoming wind resources, both assumed to be placed in service by the end of
2 2020, were included in the 2017 IRP preferred portfolio.
3 Q. Did PacifiCorp include an action item for new Wyoming wind resources in its
4 2017 IRP action plan?
5 A. Yes. The 2017 IRP action plan, which lists the specific steps PacifiCorp will take
6 over the next two to four years to deliver resources in the preferred portfolio, includes
7 the following action item associated with the new Wyoming wind resources:
8 PacifiCorp will issue a wind resource request for proposals (RFP) for 9 at least 1,100 MW of Wyoming wind resources that will qualify for 10 federal wind production tax credits and achieve commercial operation 11 by December 31, 2020.
12 April 2017, notify the Utah Public Service Commission of 13 intent to issue the Wyoming wind resource RFP.
14 May-June, 2017, file a draft Wyoming wind RFP with the Utah 15 Public Service Commission and the Washington Utilities and 16 Transportation Commission.
17 May-June, 2017, file to open a Wyoming wind RFP docket 18 with the Public Utility Commission of Oregon and initiate the 19 Independent Evaluator RFP.
20 June-July, 2017, file a draft Wyoming wind RFP with the 21 Public Utility Commission of Oregon and file a Public 22 Convenience and Necessity (CPCN) application with the 23 Public Service Commission of Wyoming.
24 By August 2017, obtain approval of the Wyoming wind 25 resource RFP from the Public Utility Commission of Oregon, 26 the Utah Public Service Commission and the Washington 27 Utilities and Transportation Commission.
28 By August 2017, issue the Wyoming wind RFP to the market.
29 By October 2017, Wyoming wind RFP bids are due.
30 November-December, 2017, complete initial shortlist bid 31 evaluation.
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1 By January 2018, complete final shortlist bid evaluation, seek 2 acknowledgment of the final shortlist from the Public Utility 3 Commission of Oregon, and seek approval of winning bids 4 from the Utah Public Service Commission.
5 By March 2018, receive CPCN approval from the Wyoming 6 Public Service Commission.
7 Complete construction of new wind projects by December 31, 8 2020.
9 Q. Did PacifiCorp also include an action item for the Aeolus-to-Bridger/Anticline
10 Line in its 2017 IRP action plan?
11 A. Yes. The 2017 IRP action plan includes the following action item associated with the
12 Aeolus-to-Bridger/Anticline line:
13 By December 31, 2020, PacifiCorp will build the 140-mile, 500 kV 14 transmission line running from the Aeolus substation near Medicine 15 Bow, Wyoming, to the Jim Bridger power plant (a sub-segment of the 16 Energy Gateway West transmission project). This includes pursuing 17 regulatory review and approval as necessary.
18 June-July 2017, file a CPCN application with the Wyoming 19 Public Service Commission.
20 By March 2018, receive conditional CPCN approval from the 21 Wyoming Public Service Commission pending acquisition of 22 rights of way.
23 By December 2018, obtain Wyoming Industrial Siting permit 24 and issue EPC limited notice to proceed.
25 Complete construction of the transmission line by December 26 31, 2020.
27 Q. Did PacifiCorp address the Combined Projects in its 2019 IRP?
28 A. All resource portfolios developed for the 2019 IRP include the Combined Projects,
29 which are under construction. New resource acquisitions were evaluated assuming
30 the Combined Projects will be placed in service by the end of 2020.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 70
1 2017R RFP
2 Q. When did PacifiCorp issue the 2017R RFP called for in the 2017 IRP?
3 A. PacifiCorp is subject to resource procurement requirements in Oregon under
4 Competitive Bidding Guidelines established by Oregon Commission Order No. 06-
5 446 in Docket No. UM 1182, and in Utah under Utah Code Ann. § 54-17-201 et. seq.
6 PacifiCorp issued the 2017R RFP on September 27, 2017, after it was approved by
7 the Utah Commission on September 22, 2017, and the Oregon Commission on
8 September 27, 2017.
9 Q. Was the scope of the 2017R RFP modified before it was issued to include non-
10 Wyoming wind projects?
11 A. Yes. PacifiCorp’s original RFP was limited to Wyoming wind resources. In response
12 to feedback from the Utah independent evaluator and other stakeholders, the
13 Company expanded the 2017R RFP to allow bids from non-Wyoming wind projects.
14 Q. In response to the Utah Commission’s approval order, did the Company decide
15 to issue a solar RFP to run concurrently with the 2017R RFP?
16 A. Yes. In its order approving the 2017R RFP, the Utah Commission suggested, but did
17 not require, a modification to expand the 2017R RFP to solicit solar resource bids. To
18 maintain the 2017R RFP schedule while addressing the Utah Commission’s
19 suggestion, the Company issued a separate solicitation process for solar resources, the
20 2017S RFP, on November 15, 2017. The 2017S RFP allowed the Company to:
21 (1) evaluate how solar resource bids might impact the economic analysis of bids
22 selected to the final shortlist in the 2017R RFP without delaying the schedule for the
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 71
1 2017R RFP; and (2) explore whether new solar resource opportunities might provide
2 all-in economic benefits for customers.
3 Q. Please describe the key milestones in the 2017R RFP.
4 A. First, PacifiCorp received initial bids in October 2017. The 2017R RFP was well
5 received by the market, with 5,219 MW of new wind resource capacity bid into the
6 2017R RFP (4,624 MW of Wyoming wind and 595 MW of non-Wyoming wind).
7 Second, PacifiCorp evaluated bids and selected the initial shortlist in
8 November 2017. The establishment of the final shortlist was delayed by the need for
9 refreshed bids to account for the enactment of the Tax Cuts and Jobs Act (TCJA) in
10 December 2017.
11 Third, PacifiCorp announced its final shortlist in January 2018. The final
12 shortlist consisted of four new wind projects located in Wyoming with a total capacity
13 of 1,170 MW including three of the Company’s benchmark facilities (TB Flats I and
14 II, now combined as a single 500 MW project, and the 109 MW McFadden Ridge II
15 project), and two new facilities: Uinta, a BTA totaling 161 MW, and Cedar Springs,
16 one-half BTA and one-half PPA, for a total of 400 MW.
17 Fourth, PacifiCorp updated the final shortlist in February 2018 after
18 completing its interconnection-restudy process. PacifiCorp initially developed the
19 final shortlist based on economic analysis of the bids without consideration of
20 interconnection queue position. Based on the results of the interconnection restudies,
21 PacifiCorp removed the McFadden Ridge II benchmark because it could not be
22 interconnected with just the addition of the Aeolus-to-Bridger/Anticline transmission
23 line. The updated final shortlist added the Ekola Flats benchmark bid and increased
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 72
1 the total capacity in the updated final shortlist to 1,311 MW. In its restudy process,
2 PacifiCorp confirmed the Aeolus-to-Bridger/Anticline Line will enable
3 interconnection of up to 1,510 MW of new wind capacity within the constrained area
4 of PacifiCorp’s transmission.
5 Q. Please summarize the role of the independent evaluators who monitored the
6 2017R RFP.
7 A. The 2017R RFP was overseen by two independent evaluators—one appointed and
8 retained by the Utah Commission, and one appointed by the Oregon Commission and
9 retained by PacifiCorp. In accordance with the statutes, rules, and policies in Utah
10 and Oregon, the independent evaluator is an independent expert appointed and
11 managed by the Utah Commission (not PacifiCorp) to ensure that the RFP process
12 was conducted in a fair and unbiased manner and the final shortlist projects are
13 reasonable and consistent with the modeling results used to evaluate bids.
14 In the 2017R RFP, both independent evaluators were involved from the
15 beginning—providing feedback and recommendations regarding the design and
16 content of the 2017R RFP and actively participating in every stage of the RFP. For
17 its part, PacifiCorp ensured that the independent evaluators had complete and
18 unrestricted access to all information related to the 2017R RFP and kept both
19 independent evaluators informed of developments as they occurred.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 73
1 Q. Did the independent evaluators provide an assessment of PacifiCorp’s
2 benchmark resources bid into the 2017R RFP (i.e., TB Flats I and II, Ekola
3 Flats, and McFadden Ridge II)?
4 A. Yes. Because the 2017R RFP included benchmark resources, both independent
5 evaluators provided detailed assessments of the benchmark bids to ensure that they
6 were reasonable and would not bias the solicitation in favor of utility-owned
7 resources.1 The benchmark review process occurred before any other bids were
8 received to provide additional assurance that the benchmarks were not provided an
9 unfair advantage.
10 Q. Did the independent evaluators confirm the reasonableness of the benchmark
11 bids?
12 A. Yes. The Utah independent evaluator concluded that: (1) PacifiCorp provided
13 detailed information related to the benchmarks that exceeded industry standards; (2)
14 cost estimates were reasonable; and (3) the review, assessment, and scoring of the
15 benchmark resources was conducted in a fair and equitable manner with no outward
16 perception of bias.2
17 The Oregon independent evaluator also conducted a thorough assessment of
18 the benchmarks, noting that when “assessing a utility’s own bids in response to the
19 RFP, our greatest concern is that the utility will incorporate cost estimates that have
20 been aggressively estimated and do not characterize the costs of the project
1 Oregon’s final independent evaluator report, issued in February 2018 (Oregon IE Report), is available at: https://edocs.puc.state.or.us/efdocs/HAH/um1845hah16913.pdf; Utah’s final independent evaluator report, also issued in February 2018 (Utah IE Report), is available at: https://pscdocs.utah.gov/electric/17docs/1703523/300621IERedacFinRep2-27-2018.pdf. 2 Utah IE Report at 44-45. Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 74
1 accurately.”3 To make its assessment, the Oregon independent evaluator “looked at a
2 detailed breakdown of each of the benchmarks costs to determine if any items have
3 been improperly omitted from the cost calculation, and at overall capital cost levels
4 by comparing them to publicly-available data on recent wind generation capital
5 costs.”4 This “comparison provided a measure of the overall reasonableness of the
6 Benchmark capital costs and capacity factors.”5 The Oregon independent evaluator
7 ultimately found that the benchmarks were acceptable based on three items:
8 • First, the benchmarks were not deliberately underpriced through omission of 9 any capital cost components.
10 • Second, the benchmark capital and operating costs appeared reasonable when 11 compared with public data on U.S. wind projects.
12 • Third, the capacity factors of the benchmarks were reasonable when compared 13 with public data and were supported by credible third-party analysis.6
14 Q. Did the independent evaluators provide any overall conclusions related to the
15 2017R RFP?
16 A. Yes. The Utah independent evaluator supported the final shortlist projects based on
17 the following conclusions:
18 The 2017R RFP was fair, reasonable, and generally in the public 19 interest.7
20 The bid evaluation and selection processes were designed to lead 21 to the acquisition of wind-generated electricity at the lowest 22 reasonable cost based on the detailed state-of-the-art portfolio 23 evaluation methodology used, the steps taken to achieve 24 comparability between utility cost-of-service resources and third- 25 party firm priced bids, the flexibility afforded bidders via a range
3 Oregon IE Report at 10. 4 Id. 5 Id. 6 Id. at 10–11. 7 Utah IE Report at 70. Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 75
1 of eligible resource alternatives, and the attempt to allow for equal 2 terms for PPA and BTA resources.8
3 PacifiCorp’s modeling demonstrates that the Combined Projects 4 “should result in significant savings for customers.” Further, 5 because PTCs will flow through to customers in the first 10 years, 6 the “near-term benefits to customers should be significant.”9
7 The Oregon independent evaluator also recommended that the Oregon
8 Commission approve PacifiCorp’s final shortlist based on the following conclusions:
9 The selected bids represent the top offers that are viable under 10 current transmission planning assumptions and provide the greatest 11 benefits to ratepayers.
12 The selected bids represent the best viable options from a 13 competitive perspective, based on the 59 bid options presented.
14 The IE’s analysis confirmed that the selected bids were reasonably 15 priced and, while not the lowest-cost offers, were the lowest-cost 16 offers that were viable under current transmission planning 17 assumptions. The independent evaluator’s analysis included its 18 own cost models for each bid option and a review of PacifiCorp’s 19 models.
20 The IE took special care to confirm the selection of PacifiCorp’s 21 benchmark resources. The independent evaluator confirmed the 22 accuracy of the benchmark costs and scoring. The independent 23 evaluator noted that the benchmark bids were disciplined by the 24 fact that a third-party bidder submitted a competing offer for a 25 BTA for benchmark projects.
26 The IE confirmed that the 2017R RFP aligns with the 2017 IRP.10
8 Utah IE Report at 71. 9 Utah IE Report at 83. 10 Oregon IE Report at 2-3. Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 76
1 ENERGY VISION 2020 CPCN/PRE-APPROVAL FILINGS
2 Q. Did PacifiCorp seek a certificate of public convenience (CPCN) for the
3 Combined Projects from the Wyoming Commission?
4 A. Yes. Because the Combined Projects are being constructed in Wyoming, PacifiCorp
5 filed an application for a CPCN at the Wyoming Commission in June 2017.
6 Q. Did the Wyoming Commission approve PacifiCorp’s CPCN application?
7 A. Yes, in April 2018, the Wyoming Commission approved the CPCN based on a
8 stipulation among several parties. In the stipulation, PacifiCorp agreed to remove the
9 161 MW Uinta facility from the final shortlist. This reduced the total capacity of the
10 Wind Projects from 1,311 MW to 1,150 MW. PacifiCorp updated its February 2018
11 economic analysis to reflect this change.
12 Q. Did PacifiCorp request and receive approval for the Combined Projects in other
13 states?
14 A. Yes. PacifiCorp filed for a CPCN in Idaho. In Utah, PacifiCorp requested approval
15 under Utah Code Ann. § 54-17-302 for the Company’s “significant energy resource
16 decision” to acquire the Wind Projects; it also requested approval under Utah Code
17 Ann. § 54-17-402 for its “resource decision” to construct the Transmission Projects.
18 The Company updated both applications to remove the Uinta facility based on the
19 stipulation in Wyoming. The Utah and Idaho Commissions granted the applications
20 in June and July 2018, respectively.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 77
1 MODELING METHODOLOGY
2 Q. Please describe the chronology of PacifiCorp’s analyses of the Combined
3 Projects.
4 A. PacifiCorp’s initial economic analysis of the Combined Projects was in the 2017 IRP.
5 The Company updated this analysis in June 2017 when it filed for CPCNs and pre-
6 approval in Wyoming, Utah and Idaho. After the initial final shortlist was selected,
7 PacifiCorp updated its analysis in January 2018 to reflect the winning bids, which at
8 the time included McFadden Ridge II. Following the completion of the
9 interconnection restudies, in February 2018, PacifiCorp updated its economic analysis
10 to replace McFadden Ridge II with Ekola Flats. After the stipulation removing Uinta
11 from the Combined Projects, PacifiCorp adjusted its February 2018 analysis to reflect
12 this change.
13 Q. What economic analysis did the Company rely upon in deciding to move
14 forward with its investment in the Combined Projects?
15 A. PacifiCorp relied upon its economic analysis from February 2018, adjusted to remove
16 the Uinta facility, to make its decision to move forward with the Combined Projects.
17 Q. In Section I of your testimony, you present an August 2018 update to the wind
18 repowering analysis. Why is there not an August 2018 update to the analysis of
19 the Combined Projects?
20 A. The August 2018 wind repowering analysis was primarily produced to capture
21 updated cost-and-performance estimates for the Leaning Juniper wind facility, which
22 could be implemented at a lower cost and with higher incremental energy output
23 relative to what was originally assumed. To ensure the updated economics of
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 78
1 Leaning Juniper repowering could be compared with other repowering projects, the
2 economic analysis for each facility was updated. This analysis confirmed that the
3 updated cost-and-performance assumptions for Leaning Juniper would improve
4 expected customer benefits and the economics of the other wind facilities within the
5 scope of the wind repowering project did not materially change. In contrast, there
6 were no comparable changes to the expected cost-and-performance assumptions for
7 any of the Energy Vision 2020 Wind Projects that would necessitate triggering an
8 updated analysis.
9 System Modeling Methodology
10 Q. Please summarize the methodology PacifiCorp used in its system analysis of the
11 Combined Projects.
12 A. As with the wind repowering project, PacifiCorp relied upon the modeling tools used
13 to develop resource portfolios in its 2017 IRP to refine its analysis of the Combined
14 Projects. These IRP modeling tools, described in Section I of my testimony, calculate
15 system PVRR by identifying least-cost resource portfolios and dispatching system
16 resources over a 20-year forecast period (2017–2036). Net customer benefits are
17 calculated as the PVRR(d) between two simulations of PacifiCorp’s system. One
18 simulation includes the Combined Projects, and the other simulation excludes the
19 Combined Projects.
20 Q. Did PacifiCorp analyze how other assumptions affect its economic analysis of the
21 Combined Projects?
22 A. Yes. As with the wind repowering project, PacifiCorp analyzed the Combined
23 Projects under a range of price-policy assumptions regarding wholesale market prices
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 79
1 and CO2 policy. Each pair of model simulations—with and without the Combined
2 Projects, in both the SO model and PaR—was analyzed under each combination of
3 these price-policy assumptions.
4 PacifiCorp also completed sensitivity studies to assess how certain factors
5 affect the net benefits of the Combined Projects. The first sensitivity compares the
6 Combined Projects to potential solar resources, based on bids received in the 2017S
7 RFP. The second sensitivity quantifies how the net benefits of the Combined Projects
8 are affected when paired with the wind repowering project.
9 Q. What assumptions did PacifiCorp use in its economic analysis of the Combined
10 Projects in February 2018?
11 A. The models reflect: (1) cost-and-performance assumptions for the Wind Projects
12 consistent with the winning bids selected to the 2017R RFP final shortlist; (2) the
13 latest load-forecast projections; (3) the latest price-policy scenario assumptions; and
14 (4) changes in federal tax rate for corporations under the TCJA.
15 Q. Please describe the cost-and-performance estimates for the Energy Vision 2020
16 Wind Projects in the February 2018 economic analysis.
17 A. The February 2018 economic analysis includes the capital costs associated with the
18 winning bids, the costs associated with the Cedar Springs PPA, and updated net
19 capacity factors. This economic analysis also captures terminal-value benefits from
20 BTA and EPC-benchmark bids, where the Company retains control of the site at the
21 end of the asset life. These benefits were considered in the 2017R RFP bid-selection
22 process, consistent with the bid-evaluation methodology described in the RFP, and
23 therefore, they are applied in the economic analysis.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 80
1 Q. Please describe the load forecast and price-policy assumptions included in the
2 February 2018 economic analysis.
3 A. The economic analysis uses PacifiCorp’s load forecast completed in the summer of
4 2017. PacifiCorp used the same price-policy assumptions for the February 2018
5 analysis of the Combined Projects that it used for the February 2018 analysis of the
6 wind repowering project. These assumptions are described in Section I of my
7 testimony.
8 Q. Please describe the updated federal tax rate for corporations included in the
9 updated economic analysis.
10 A. PacifiCorp’s analysis assumes a 21-percent federal income tax rate. Based on an
11 assumed net state income tax rate of 4.54 percent, the effective combined federal and
12 state income tax rate used in the updated analysis is 24.587 percent.
13 Q. How did PacifiCorp apply federal PTC benefits in its system modeling using the
14 SO model and PaR configured to forecast system costs through 2036?
15 A. When establishing the 2017R RFP final shortlist, PacifiCorp applied PTC benefits for
16 applicable bids (BTAs and benchmark-EPC bids) on a nominal basis rather than on a
17 levelized basis. This approach better reflects how the federal PTC benefits for these
18 bids will flow through to customers and aligns the treatment of federal PTC benefits
19 in the system modeling results extending out through 2036 with the nominal revenue
20 requirement results extending out through 2050. It also ensures the 2017R RFP bid
21 selections from the SO model more accurately reflect the difference in how BTA and
22 benchmark-EPC bids are expected to impact customer rates.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 81
1 Q. Did PacifiCorp apply revenue requirement associated with capital costs on a
2 levelized basis in its system modeling using the SO model and PaR configured to
3 forecast system costs through 2036?
4 A. Yes. As discussed below, when setting rates, revenue requirement from capital costs
5 is depreciated over the book life of the asset, effectively spreading the cost of capital
6 investments over the life of the asset. Because revenue requirement from capital
7 projects is spread over the life of the asset in rates, these costs continue to be treated
8 as a levelized cost in the SO model and PaR simulations.
9 Q. Does PacifiCorp assume that all of the up-front capital costs of the Transmission
10 Projects will be paid by its retail customers?
11 A. No. While the up-front capital cost of the Transmission Projects will contribute to
12 retail-customer rate base, the revenue requirement for these investments will be
13 partially offset by incremental revenue from other transmission customers. The up-
14 front transmission costs will flow into PacifiCorp’s formula transmission rate under
15 its Open Access Transmission Tariff (OATT) and generate revenue credits that offset
16 costs for retail customers.
17 PacifiCorp’s merchant function, which uses PacifiCorp’s transmission system
18 to serve retail-customer load and to manage retail-customer NPC through off-system
19 market sales and purchases, is the largest user of PacifiCorp’s transmission system.
20 However, other transmission customers pay OATT-based transmission rates that
21 generate revenue credits and offset the cost of PacifiCorp’s transmission revenue
22 requirement. As discussed in Mr. Vail’s testimony, the Transmission Projects are
23 considered network transmission assets under PacifiCorp’s OATT and therefore will
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 82
1 be given rolled-in treatment under PacifiCorp’s transmission formula rate. Based on
2 recent history, PacifiCorp assumed that these revenue credits will account for
3 approximately 12 percent of PacifiCorp’s transmission revenue requirement.
4 Consequently, PacifiCorp’s analysis assumes its retail customers pay 88 percent of
5 the revenue requirement from the up-front capital cost for the Transmission Projects
6 after accounting for an assumed 12 percent revenue credit from other transmission
7 customers.
8 Q. How did PacifiCorp model de-rates to its Wyoming 230 kV transmission system
9 when evaluating the Combined Projects?
10 A. In its final 2017 IRP resource-portfolio screening process, PacifiCorp identified and
11 quantified reliability benefits associated with the Aeolus-to-Bridger/Anticline Line.
12 This new transmission project will eliminate de-rates caused by outages on 230 kV
13 transmission-system elements. Historical outages on this part of PacifiCorp’s
14 transmission system indicate an average de-rate of 146 MW over approximately
15 88 outage days per year, which equates to approximately one 146-MW, twenty-four
16 hour outage every four days. Without knowing when these events might occur, de-
17 rates on the existing 230 kV transmission system were captured in the SO model and
18 PaR as a 36.5 MW reduction in the transfer capability from eastern Wyoming to the
19 Aeolus area. In simulations that include the Combined Projects, this de-rate
20 assumption was eliminated when the new transmission assets are placed in service at
21 the end of October 2020.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 83
1 Q. How did PacifiCorp model line-loss benefits associated with the Transmission
2 Projects when performing its economic analysis of the Combined Projects?
3 A. Line-loss benefits are only applicable in those simulations where the Transmission
4 Projects are built and therefore were only considered in the simulations that include
5 the Combined Projects. When the Aeolus-to-Bridger/Anticline Line is added in
6 parallel to the existing transmission lines, resistance is reduced, which lowers line
7 losses. With reduced line losses, an incremental 11.6 average MW (aMW) of energy,
8 which equates to approximately 102 gigawatt hours (GWh), will be able to flow out
9 of eastern Wyoming each year. The line-loss benefit was reflected in the SO model
10 and PaR by reducing northeast Wyoming load by approximately 11.6 aMW each year.
11 Q. Did PacifiCorp analyze potential EIM benefits in its economic analysis of the
12 Combined Projects?
13 A. Yes. As with the wind repowering project, the more efficient use of transmission that
14 is expected with growing participation in the EIM was captured in the economic
15 analysis of the Combined Projects by increasing the transfer capability between the
16 east and west sides of PacifiCorp’s system by 300 MW (from the Jim Bridger plant to
17 south-central Oregon). The ability to more efficiently use intra-hour transmission
18 from a growing list of EIM participants is not driven by the Combined Projects;
19 however, this increased connectivity provides the opportunity to move low-cost
20 incremental energy out of transmission-constrained areas of Wyoming.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 84
1 Annual Revenue Requirement Modeling Methodology
2 Q. In addition to the system modeling used to calculate present-value net benefits
3 over a 20-year planning period, has PacifiCorp forecasted the change in nominal
4 revenue requirement due to the Combined Projects?
5 A. Yes. The system PVRR from the SO model and PaR was calculated from an annual
6 stream of forecasted revenue requirement over a 20-year time frame, consistent with
7 the planning period in the IRP. The annual stream of forecasted revenue requirement
8 captures nominal revenue requirement for non-capital items (i.e., NPC, fixed
9 operations and maintenance, etc.) and levelized revenue requirement for capital
10 expenditures. To estimate the annual revenue-requirement impacts of the Combined
11 Projects, capital costs for the Wind Projects and the Transmission Projects need to be
12 considered in nominal terms (i.e., not levelized).
13 Q. Why is the capital revenue requirement used in the calculation of the 2036
14 system PVRR from the SO model and PaR levelized?
15 A. Levelization of capital revenue requirement is necessary in these models to avoid
16 potential distortions in the economic analysis of capital-intensive assets that have
17 different lives and in-service dates. Without levelization, this potential distortion is
18 driven by how capital costs are included in rate base over time. Capital revenue
19 requirement is generally highest in the first year an asset is placed in service and
20 declines over time as the asset depreciates.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 85
1 Q. How did PacifiCorp forecast the annual revenue-requirement impacts of the
2 Combined Projects?
3 A. In the simulations that include the Combined Projects, the annual stream of costs for
4 the Wind Projects, including levelized capital and PTCs, and the Transmission
5 Projects are temporarily removed from the annual stream of costs used to calculate
6 the stochastic-mean PVRR. The differential in the remaining stream of annual costs,
7 which includes all system costs except for those associated with the Combined
8 Projects, represents the net system benefit caused by the Combined Projects.
9 These data are disaggregated to isolate the estimated annual NPC benefits,
10 other non-NPC variable-cost benefits (i.e., variable O&M and emissions costs for
11 those scenarios that include a CO2 price assumption), and fixed-cost benefits. To
12 complete the annual revenue-requirement forecast, the change in costs for the
13 Combined Projects, including nominal capital revenue requirement and PTCs, are
14 added back in with the annual system net benefits caused by the Combined Projects.
15 Q. Over what time frame did PacifiCorp estimate the change in annual revenue
16 requirement due to the Combined Projects?
17 A. The change in annual revenue requirement was estimated through 2050. This
18 captures the full 30-year life of the Wind Projects.
19 Q. What is the assumed life of the Transmission Projects?
20 A. PacifiCorp assumed a 62-year life for the Transmission Projects. The Transmission
21 Projects will continue to provide system benefits well beyond 2050 when the Wind
22 Projects are fully depreciated. These additional benefits are not reflected in
23 PacifiCorp’s economic analysis.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 86
1 Q. How did PacifiCorp calculate the annual net benefits caused by the Combined
2 Projects beyond the 20-year forecast period used in PaR?
3 A. PacifiCorp followed the same approach it used to assess the wind repowering projects
4 through 2050, described in Section I of my testimony.
5 Q. Did PacifiCorp calculate a PVRR(d) for the Combined Projects using its
6 estimate of annual revenue requirement impacts projected out through 2050?
7 A. Yes.
8 SYSTEM MODELING PRICE-POLICY RESULTS
9 Q. Please summarize the PVRR(d) results calculated in February 2018 from the SO
10 model and PaR through 2036.
11 A. Table 19 summarizes the PVRR(d) results for each price-policy scenario. The
12 PVRR(d) between cases with and without the Combined Projects, reflecting the
13 updated final shortlist from the 2017R RFP, are shown for the SO model and for PaR,
14 which was used to calculate both the stochastic-mean PVRR(d) and the risk-adjusted
15 PVRR(d). The data used to calculate the updated SO Model PVRR(d) and PaR
16 Stochastic Mean PVRR(d) results shown in the table are provided as Exhibit No.
17 RTL-6.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 87
Table 19. February 2018 SO Model and PaR PVRR(d) (Benefit)/Cost of the Combined Projects ($ million) Updated Final Shortlist
PaR PaR Risk- Price-Policy Scenario SO Model Stochastic Adjusted PVRR(d) Mean PVRR(d) PVRR(d)
Low Gas, Zero CO2 ($185) ($150) ($156)
Low Gas, Medium CO2 ($208) ($179) ($188)
Low Gas, High CO2 ($370) ($337) ($355)
Medium Gas, Zero CO2 ($377) ($319) ($334)
Medium Gas, Medium CO2 ($405) ($357) ($386)
Medium Gas, High CO2 ($489) $(448) ($469)
High Gas, Zero CO2 ($699) ($568) ($596)
High Gas, Medium CO2 ($716) ($603) ($633)
High Gas, High CO2 ($781) ($694) ($728)
1 Over a 20-year period, the Combined Projects reduce customer costs in all
2 nine price-policy scenarios. This outcome is consistent in both the SO model and
3 PaR results. Under the central price-policy scenario, when applying medium natural
4 gas, medium CO2 price-policy assumptions, the PVRR(d) net benefits range between
5 $357 million, when derived from PaR stochastic-mean results, and $405 million,
6 when derived from SO model results.
7 Q. What is the potential upside to these PVRR(d) results associated with REC
8 revenues?
9 A. The PVRR(d) results presented in Table 19 do not reflect the potential value of RECs
10 generated by the incremental energy output from the updated final shortlist projects.
11 Accounting for the performance estimates from the updated final shortlist projects,
12 customer benefits for all price-policy scenarios would improve by approximately Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 88
1 $34 million for every dollar assigned to the incremental RECs that will be generated
2 from the winning bids through 2036. Quantifying the potential upside associated
3 with incremental REC revenues is simply intended to communicate that the net
4 benefits from the winning bids could improve if the incremental RECs can be
5 monetized in the market or otherwise used to offset higher cost purchases required to
6 meet state renewable portfolio standard targets.
7 Q. Did you calculate the potential upside to these PVRR(d) results associated with
8 reduced O&M costs?
9 A. Yes. Projects with large wind turbines are expected to require less O&M costs
10 because there are fewer turbines on a given site. The default O&M assumptions
11 applied to BTA and benchmark-EPC bids in the economic analysis are based on the
12 Company’s experience in operating and maintaining the existing fleet of owned-wind
13 facilities, and do not reflect expected cost savings associated with operating and
14 maintaining wind facilities proposing to use larger wind turbines. If the O&M cost
15 elements applicable to the larger-turbine equipment are reduced by 42 percent, which
16 is equivalent to an approximately 18-percent reduction in total O&M costs, beyond
17 the proposed O&M agreement period, customer benefits calculated through 2036 for
18 all price-policy scenarios would improve by approximately $19 million.
19 Q. Is there additional upside to the net benefits shown in Table 19?
20 A. Yes. The Company’s analysis conservatively calculates net benefits by comparing a
21 case with the Combined Projects against a case without the Combined Projects. As
22 discussed by Mr. Vail, the Aeolus-to-Bridger/Anticline Line has been an integral
23 component of PacifiCorp’s long-term transmission plan for some time and it is
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 89
1 unlikely that this investment would never be needed. The economic benefits would
2 increase substantially if the case with the Combined Projects were compared to a case
3 where the Aeolus-to-Bridger/Anticline line were added to the system at a later date.
4 Further, the CO2 price assumptions used in the updated economic analysis were
5 inadvertently modeled in 2012 real dollars instead of nominal dollars. Consequently,
6 the PVRR(d) net benefits in the six price-policy scenarios that use medium and high
7 CO2 price assumptions are conservative.
8 REVENUE REQUIREMENT MODELING PRICE-POLICY RESULTS
9 Q. Please summarize the February 2018 PVRR(d) results calculated from the
10 change in annual revenue requirement through 2050.
11 A. Table 20 summarizes the updated PVRR(d) results for each price-policy scenario
12 calculated from the change in annual nominal revenue requirement through 2050.
13 The annual data over the period 2017 through 2050 that was used to calculate the
14 updated PVRR(d) results shown in the table are provided as Exhibit No. RTL-7.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 90
Table 20. February 2018 Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of the Combined Projects ($ million) Updated Final Price-Policy Scenario Shortlist
Low Gas, Zero CO2 $184
Low Gas, Medium CO2 $127
Low Gas, High CO2 ($147)
Medium Gas, Zero CO2 ($92)
Medium Gas, Medium CO2 ($167)
Medium Gas, High CO2 ($304)
High Gas, Zero CO2 ($448)
High Gas, Medium CO2 ($499)
High Gas, High CO2 ($635)
1 When system costs and benefits from the Combined Projects are extended out
2 through 2050, covering the full depreciable life of the owned-wind projects included
3 in the updated 2017R RFP final shortlist, the Combined Projects reduce customer
4 costs in seven out of nine price-policy scenarios. Customer net benefits range from
5 $92 million in the medium natural-gas, zero CO2 price-policy scenario to $635
6 million in the high natural gas, high CO2 price-policy scenario. Under the central
7 price-policy scenario, when applying medium natural gas, medium CO2 price-policy
8 assumptions, the PVRR(d) benefits of the Combined Projects are $167 million. The
9 Combined Projects provide significant customer benefits in all price-policy scenarios,
10 and the net benefits are unfavorable only when low natural-gas prices are paired with
11 zero or medium CO2 prices. These results show that upside benefits far outweigh
12 downside risks.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 91
1 Q. Is there additional potential upside to these PVRR(d) results associated with
2 REC revenues?
3 A. Yes. The PVRR(d) results presented in Table 20 do not reflect the potential value of
4 RECs generated by the incremental energy output from the Energy Vision 2020 Wind
5 Projects. Accounting for the performance estimates from the updated final shortlist
6 projects, customer benefits for all price-policy scenarios would improve by
7 approximately $43 million for every dollar assigned to the incremental RECs that will
8 be generated from the winning bids through 2050.
9 Q. Is there additional potential upside to these PVRR(d) results associated with
10 reduced O&M costs?
11 A. Yes. As discussed above, the Company anticipates O&M costs for those projects that
12 will install larger-turbine equipment to be lower than what has been reflected in the
13 updated economic analysis. Accounting for these cost savings, customer benefits for
14 all price-policy scenarios would improve by approximately $31 million when
15 calculated from projected operating costs through 2050.
16 Q. Is there additional potential upside to these PVRR(d) results shown in Table 20?
17 A. Yes. As noted earlier, the economic benefits would increase substantially if the case
18 with the Combined Projects were compared to a case where the Aeolus-to-
19 Bridger/Anticline line were added to the system at a later date. Moreover, the
20 updated CO2 price assumptions used in the updated economic analysis were
21 inadvertently modeled in 2012 real dollars instead of nominal dollars. Consequently,
22 the PVRR(d) net benefits in the six price-policy scenarios that use medium and high
23 CO2 price assumptions are conservative.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 92
1 Q. Please describe the change in annual nominal revenue requirement from the
2 Combined Projects.
3 A. Figure 9 shows the change in nominal revenue requirement due to the Combined
4 Projects for the medium natural gas, medium CO2 price-policy scenario on a total-
5 system basis. The change in nominal revenue requirement shown in the figure
6 reflects February 2018 costs, including capital revenue requirement (i.e., depreciation,
7 return, income taxes, and property taxes), O&M expenses, the Wyoming wind-
8 production tax, and PTCs. The project costs are netted against system impacts from
9 the Combined Projects, reflecting the change in NPC, emissions, non-NPC variable
10 costs, and system fixed costs that are affected by, but not directly associated with, the
11 Combined Projects.
Figure 9. February 2018 Total-System Annual Revenue Requirement With the Combined Projects (Benefit)/Cost ($ million)
12 The Combined Projects produce net benefits in 23 years out of the 30 years
13 that the proposed owned-wind resources selected to the 2017R RFP final shortlist are
14 assumed to operate. The year-on-year reduction in net benefits from 2036 to 2037 is
15 driven by the Company’s conservative approach to extrapolate benefits from 2037
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 93
1 through 2050 based on modeled results from the 2028-through-2036 time frame.
2 This leads to an abrupt reduction in the benefits in 2037, and a subsequent year-on-
3 year reduction to net benefits, which breaks from the trend observed in the model
4 results over the 2035-to-2036 time frame. This extrapolation methodology is
5 conservative because it results in project benefits not matching the levels observed in
6 the model results for 2036 until 2047.
7 SOLAR SENSITIVITY
8 Q. Did PacifiCorp include a solar sensitivity in its February 2018 analysis?
9 A. Yes. The solar sensitivity analysis reflects the updated final shortlist from the 2017R
10 RFP and best-and-final pricing supplied by bidders participating in the 2017S RFP on
11 February 1, 2018.
12 Q. Please describe the sensitivity studies that analyzed the impact of the solar bids
13 received in the 2017S RFP on the economics of the Combined Projects.
14 A. The Company’s solar sensitivity analysis used the SO model and PaR simulations to
15 determine the PVRR(d) based on two model runs—one with solar PPA bids and the
16 Combined Projects and one with solar PPA bids but without the Combined Projects.
17 Q. What were the results of the solar sensitivity where solar PPA bids are assumed
18 to be pursued in lieu of the Combined Projects?
19 A. Table 21 summarizes PVRR(d) results for the solar sensitivity where solar PPA bids
20 are assumed to be pursued without any investments in the Combined Projects. This
21 sensitivity was developed using SO model and PaR simulations through 2036 for the
22 medium natural gas, medium CO2 and the low natural gas, zero CO2 price-policy
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 94
1 scenarios. The results are shown alongside the benchmark study in which the
2 Combined Projects were evaluated without solar PPA bids.
Table 21. February 2018 Solar Sensitivity with Solar PPAs Included in lieu of the Combined Projects (Benefit)/Cost ($ million) Sensitivity Benchmark Change in PVRR(d) PVRR(d) PVRR(d)
Medium Gas, Medium CO2 SO Model ($343) ($405) $61 PaR Stochastic Mean ($228) ($357) $129 PaR Risk Adjusted ($237) ($386) $149
Low Gas, Zero CO2 SO Model ($196) ($185) ($11) PaR Stochastic Mean ($139) ($150) $11 PaR Risk Adjusted ($145) ($156) $11
3 In this sensitivity, the SO model selects 1,122 MW of solar PPA bids in the
4 low natural gas, zero CO2 price-policy scenario and 1,419 MW of solar PPA bids in
5 the medium natural gas, medium CO2 price-policy scenario. All the selected solar
6 PPA bids are for projects located in Utah.
7 In the medium natural gas, medium CO2 price-policy scenario, a portfolio
8 with the Combined Projects delivers greater customer benefits relative to a portfolio
9 that adds solar PPA bids without the Combined Projects. Customer benefits are
10 greater when the resource portfolio includes the Combined Projects without solar PPA
11 bids by $149 million in the medium natural gas, medium CO2 price-policy scenario
12 based on the risk-adjusted PaR results. In the low natural gas, zero CO2 price-policy
13 scenario, the portfolio with the Combined Projects delivers slightly greater customer
14 benefits relative to a portfolio that adds solar PPA bids without the Combined Projects
15 when modeled in PaR, and slightly lower customer benefits when analyzed with the
16 SO model. The decrease in net benefits in the solar PPA portfolio is $11 million
17 based on the risk-adjusted PaR results. Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 95
1 When analyzed without the Combined Projects, the solar PPA bids produce
2 net customer benefits that are lower than the benefits expected from the Combined
3 Projects in the medium natural gas, medium CO2 price-policy scenario. While the
4 sensitivity with a portfolio containing solar PPAs without the Combined Projects
5 produces PVRR(d) results that are similar to the PVRR(d) results with only the
6 Combined Projects in the low natural-gas, zero CO2 price-policy scenario, both
7 portfolios deliver customer benefits. This sensitivity did not support an alternative
8 resource procurement strategy to pursue solar PPA bids in lieu of the Combined
9 Projects. This would leave the significant benefits from the Combined Projects,
10 which include building a much-needed transmission line, on the table.
11 Q. What were the results of the solar sensitivity where solar PPA bids are pursued
12 with the Combined Projects?
13 A. Table 22 summarizes PVRR(d) results for the solar sensitivity where solar PPA bids
14 are assumed to be pursued along with the proposed investments in the Combined
15 Projects. This sensitivity was developed using SO model and PaR simulations
16 through 2036 for the medium natural gas, medium CO2 and the low natural gas, zero
17 CO2 price-policy scenarios. The results are shown alongside the benchmark study in
18 which the Combined Projects were evaluated without solar PPA bids.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 96
Table 22. February 2018 Solar Sensitivity with Solar PPAs Included With the Combined Projects (Benefit)/Cost ($ million) Sensitivity Benchmark Change in PVRR(d) PVRR(d) PVRR(d)
Medium Gas, Medium CO2 SO Model ($647) ($405) ($242) PaR Stochastic Mean ($519) ($357) ($163) PaR Risk Adjusted ($543) ($386) ($157)
Low Gas, Zero CO2 SO Model ($312) ($185) ($127) PaR Stochastic Mean ($250) ($150) ($100) PaR Risk Adjusted ($259) ($156) ($103)
1 In this sensitivity, the SO model continues to choose the winning bids
2 included in the updated 2017R RFP final shortlist as part of the least-cost bid
3 portfolio. In addition to these wind resource selections, the SO model selects 1,042
4 MW of solar PPA bids in the low natural gas, zero CO2 price-policy scenario and
5 1,419 MW of solar PPA bids in the medium natural gas, medium CO2 price-policy
6 scenario. Again, all the selected solar PPA bids are for projects located in Utah.
7 When the solar PPAs are assumed to be pursued in addition to the Combined
8 Projects, total net customer benefits increase. This result is consistent with
9 PacifiCorp’s expectation that cost-effective solar opportunities would not displace the
10 Combined Projects but would only potentially add to incremental resource
11 procurement opportunities that might provide net customer benefits.
12 WIND-REPOWERING SENSITIVITY
13 Q. Please explain PacifiCorp’s February 2018 sensitivity analysis related to the
14 wind repowering project.
15 A. The wind repowering sensitivity reflects the updated final shortlist and cost-and
16 performance estimates for the wind repowering project as of February 2018. Table 23
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 97 REDACTED
1 summarizes PVRR(d) results for this wind-repowering sensitivity. This sensitivity
2 was developed using SO model and PaR simulations through 2036 for the medium
3 natural-gas, medium CO2 and the low natural-gas, zero CO2 price-policy scenarios.
4 The results are shown alongside the benchmark study in which the Combined Projects
5 were evaluated without wind repowering.
Table 23. Wind-Repowering Sensitivity (Benefit)/Cost ($ million) Sensitivity Benchmark Change in PVRR(d) PVRR(d) PVRR(d) Medium Gas, Medium CO2 SO Model ($608) ($405) ($204) PaR Stochastic Mean ($541) ($357) ($184) PaR Risk Adjusted ($567) ($386) ($181) Low Gas, Zero CO2 SO Model ($334) ($185) ($149) PaR Stochastic Mean ($281) ($150) ($131) PaR Risk Adjusted ($295) ($156) ($138)
6 In the February 2018 wind-repowering sensitivity, customer benefits increase
7 significantly when the wind repowering project is implemented with the Combined
8 Projects in both the medium natural-gas, medium CO2, and the low natural-gas, zero
9 CO2 price-policy scenarios. These results demonstrate that customer benefits not
10 only persist, but also increase, if both the wind-repowering project and the Combined
11 Projects are completed.
12 ADJUSTED ECONOMIC ANALYSIS WITHOUT UINTA FACILITY
13 Q. Please summarize the cost-and-performance attributes of the Wind Projects
14 without Uinta.
15 A. With removal of the Uinta project, the total in-service capital cost for the remaining
16 Energy Vision 2020 Wind Projects is approximately $ billion, with a per-unit
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 98 REDACTED
1 capital cost of $ /kW. In aggregate, the Energy Vision 2020 Wind Projects are
2 expected to operate at a capacity-weighted average annual capacity factor of
3 percent.
4 Q. What is the nominal value of PTCs relative to the in-service capital cost of the
5 Energy Vision 2020 Wind Projects without Uinta?
6 A. Over the first 10 years of operation, the Energy Vision 2020 Wind Projects that will
7 be owned by PacifiCorp will generate over $1.2 billion in PTC benefits, which is
8 nearly 103 percent of the in-service capital for these wind facilities.
9 Q. Did PacifiCorp update the February 2018 economic analysis of the Combined
10 Projects based on the removal of the Uinta project?
11 A. Yes. First, PacifiCorp performed a spreadsheet analysis to estimate the high-level
12 economic impact of removing the Uinta project. This spreadsheet analysis was
13 performed for all nine price-policy scenarios previously described in my testimony.
14 Consistent with the Company’s previous economic analysis, these results are based
15 on the methodology used in the Company’s IRP through 2036 and using nominal
16 revenue requirement projections through 2050.
17 Q. Please describe how you performed the high-level spreadsheet analysis.
18 A. Using data from the February 2018 economic analysis, I calculated the system
19 benefits, including the Uinta Project, on a dollar-per-MWh basis for each price-policy
20 scenario. I then multiplied these results by the expected generation from the Uinta
21 project to estimate the annual system benefits associated with the Uinta project in
22 total dollars. These system-benefit estimates were then netted against the same
23 project-specific costs for the Uinta facility that were used in the February 2018
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 99
1 economic analysis. This calculation results in an estimate of the marginal net benefit
2 or cost of removing the Uinta project for each price-policy scenario.
3 Q. Did you also update the February 2018 economic analysis using PacifiCorp’s
4 models?
5 A. Yes. I also re-ran PacifiCorp’s IRP models to remove Uinta under the medium
6 natural gas, medium CO2 and low natural gas, zero CO2 price-policy scenarios.
7 Q. Did you update any of the other inputs used in the analysis?
8 A. No. Other than removing Uinta, all the other inputs used in the economic analysis are
9 the same as the inputs used in the February 2018 analysis.
10 Q. What is the high-level estimate of the economic impact of removing Uinta based
11 on results through 2036?
12 A. Table 24 reports the high-level estimate of the economic impact of removing Uinta
13 based on the results through 2036. These PVRR(d) results are shown alongside the
14 results summarized in my February 2018 economic analysis. The difference between
15 the original results that include Uinta and the high-level estimates without Uinta are
16 an indicator of the marginal net benefit or cost of the Uinta project.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 100
Table 24. Estimated Impact of Removing Uinta PaR Stochastic Mean PVRR(d) (Benefit)/Cost ($ million) through 2036 High-Level Marginal February 2018 Price-Policy Scenario Estimate (Benefit)/Cost (With Uinta) (Without Uinta) of Uinta
Low Gas, Zero CO2 ($150) ($146) ($4)
Low Gas, Medium CO2 ($179) ($172) ($7)
Low Gas, High CO2 ($337) ($312) ($25)
Medium Gas, Zero CO2 ($319) ($296) ($23)
Medium Gas, Medium CO2 ($357) ($330) ($27)
Medium Gas, High CO2 ($448) ($410) ($38)
High Gas, Zero CO2 ($568) ($517) ($51)
High Gas, Medium CO2 ($603) ($548) ($55)
High Gas, High CO2 ($694) ($629) ($66)
1 Q. What conclusions can you draw from the results provided in Table 24?
2 A. The high-level estimate based on results through 2036 shows that net benefits of the
3 Combined Projects (without Uinta) are reduced by between $4 million and
4 $66 million. In the medium natural gas, medium CO2 price-policy scenario, net
5 benefits are reduced by $27 million. Considering that results from the IRP models
6 were used to select winning bids in the 2017R RFP, these findings confirm that it was
7 reasonable to include Uinta in the 2017R RFP final shortlist. Importantly, these
8 results also show that the Combined Projects will continue to deliver substantial net
9 customer benefits with removal of the Uinta project. With Uinta removed, the net
10 benefits from the Combined Projects range between $146 million and $629 million.
11 In the medium natural gas, medium CO2 price-policy scenario, the net benefits are
12 estimated to be $330 million.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 101
1 Q. What is the high-level estimate of the economic impact of removing Uinta based
2 on nominal revenue requirement results through 2050?
3 A. Table 25 reports the high-level estimate of the economic impact of removing Uinta
4 based on the nominal revenue requirement results through 2050. These PVRR(d)
5 results are shown alongside the February 2018 economic analysis. Like Table 24
6 above, the difference between the original results that include Uinta and the high-
7 level estimates without Uinta are an indicator of the marginal net benefit or cost of the
8 Uinta project.
Table 25. Estimated Impact of Removing Uinta Nominal PVRR(d) (Benefit)/Cost ($ million) through 2050 High-Level Marginal February 2018 Price-Policy Scenario Estimate (Benefit)/Cost (With Uinta) (Without Uinta) of Uinta
Low Gas, Zero CO2 $184 $146 $38
Low Gas, Medium CO2 $127 $97 $31
Low Gas, High CO2 ($147) ($145) ($2)
Medium Gas, Zero CO2 ($92) ($97) $5
Medium Gas, Medium CO2 ($167) ($162) ($4)
Medium Gas, High CO2 ($304) ($283) ($20)
High Gas, Zero CO2 ($448) ($411) ($37)
High Gas, Medium CO2 ($499) ($456) ($43)
High Gas, High CO2 ($635) ($576) ($59)
9 Q. What conclusions can you draw from Table 25?
10 A. The high-level estimate based on nominal revenue requirement results through 2050
11 shows that removal of Uinta reduces the net cost of the Combined Projects in three of
12 the nine price-policy scenarios, and that the net benefits of the Combined Projects are
13 reduced in six of the nine price-policy scenarios. In the medium natural gas, medium
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 102
1 CO2 price-policy scenario, net benefits are reduced by $4 million. Importantly, when
2 the impact of net benefits are based on nominal revenue requirement results through
3 2050, these results show that the Combined Projects will continue to deliver
4 substantial net customer benefits with removal of the Uinta project. With Uinta
5 removed, the net benefits from the Combined Projects in the scenarios where they
6 occur range between $97 million and $576 million. In the medium natural gas,
7 medium CO2 price-policy scenario, the net benefits are estimated to be $162 million.
8 Q. What is the economic impact of removing Uinta based on updated results from
9 the IRP model runs?
10 A. Table 26 reports the high-level estimate of the economic impact of removing Uinta
11 alongside the updated modeled results using the 2036 and 2050 calculation
12 methodologies. These results are presented for both the low natural gas, zero CO2
13 and the medium natural gas, medium CO2 price-policy scenarios. The table also
14 shows the difference between the high-level estimate and the modeled results.
Table 26. Estimated Impact of Removing Uinta Nominal PVRR(d) (Benefit)/Cost ($ million) through 2050 PaR Stochastic Mean PVRR(d) (Benefit)/Cost ($ million) through 2036 High-Level Modeled Result Variance from Price-Policy Scenario Estimate (Without Uinta) Modeled Result (Without Uinta)
Low Gas, Zero CO2 ($146) ($143) ($3)
Medium Gas, Medium CO2 ($330) ($338) $8 Nominal PVRR(d) (Benefit)/Cost ($ million) through 2050 High-Level Modeled Result Variance from Price-Policy Scenario Estimate (Without Uinta) Modeled Result (Without Uinta)
Low Gas, Zero CO2 $146 $154 ($8)
Medium Gas, Medium CO2 ($162) ($174) $12
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 103 REDACTED
1 Q. What conclusions can you draw from Table 26?
2 A. First, the modeled results are similar to the high-level estimates described above, and
3 consequently, the high-level estimates provide a reasonable representation of the
4 impact of removing Uinta.
5 Second, under the medium natural gas, medium CO2 price-policy scenario, the
6 Combined Projects still provide net customer benefits when Uinta is removed. When
7 calculated from IRP model results through 2036, customer net benefits are
8 $338 million (down by $19 million from $357 million in the February 2018 analysis).
9 When calculated from the nominal revenue requirement results through 2050,
10 customer net benefits are $174 million (up by $7 million from the $167 million in the
11 February 2018 analysis).
12 Third, under the low natural gas, zero CO2 price-policy scenario, the
13 Combined Projects still provide net customer benefits with Uinta removed when the
14 PVRR(d) is calculated from IRP model results through 2036. Based on this
15 methodology, customer net benefits are $143 million (down by $7 million from the
16 $150 million benefit in the February 2018 analysis). When calculated from the
17 nominal revenue requirement results through 2050, net costs are $154 million (down
18 by $30 million from the $184 million in the February 2018 economic analysis).
19 Q. Have you calculated the change in capital costs that would have to occur to
20 eliminate net benefits in the medium natural gas, medium CO2 price-policy
21 scenario?
22 A. Yes. Removal of the Uinta project reduces capital costs for the Combined Projects to
23 $ billion. In-service capital costs would have to increase by approximately
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 104 REDACTED
1 11.1 percent (or $ million) to eliminate net benefits in the medium natural gas,
2 medium CO2 price-policy scenario.
3 Q. Do the Combined Projects without Uinta still provide overall customer net
4 benefits?
5 A. Yes. As set forth above, when using the IRP modeling, the Combined Projects still
6 provide robust customer net benefits under all nine price-policy scenarios. Although
7 the benefits have decreased slightly, they remain substantial. In addition, under the
8 nominal revenue requirement view, the net benefits remained fairly consistent,
9 increasing in some price-policy scenarios and decreasing in others. Although neither
10 view is dispositive, each of these views provides important insight into how the
11 Combined Projects are expected to impact the Company’s revenue requirement.
12 Taken together, each of these views indicate that the removal of Uinta does not
13 adversely impact the customer benefits, and the acquisition of the Combined Projects
14 remains in the public interest.
15 III. PRYOR MOUNTAIN WIND PROJECT
16 Q. Did you conduct the economic analysis supporting acquisition of the Pryor
17 Mountain Wind Project?
18 A. Yes. I prepared the economic analysis for the 240 MW Pryor Mountain Wind Project,
19 which supports PacifiCorp’s decision to move forward with the project. I completed
20 this analysis in September 2019.
21 Q. Please provide background on the Pryor Mountain Wind Project.
22 A. In May 2019, PacifiCorp executed an agreement for the development rights
23 associated with the Pryor Mountain Wind Project, located in Montana. In June 2019,
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 105
1 PacifiCorp and Vitesse, LLC (Vitesse) (a wholly-owned subsidiary of Facebook, Inc.)
2 executed an agreement for the purchase of all RECs generated by Pryor Mountain
3 over a 25-year period under PacifiCorp’s Oregon Schedule 272 – Renewable Energy
4 Rider Optional Bulk Purchase Option. In September 2019, PacifiCorp executed the
5 Engineering, Procurement, and Construction Contractor (EPC) and wind turbine
6 supplier agreements for the project. Mr. Chad A. Teply provides additional
7 information about this project in his testimony.
8 Q. Was the Pryor Mountain Wind Project the result of an RFP issued by
9 PacifiCorp?
10 A. No. PacifiCorp pursued the Pryor Mountain Wind Project outside of an RFP because
11 it was a unique, time sensitive opportunity to provide significant value to customers.
12 The opportunity evolved over a very compressed timeline, beginning in October
13 2018, with final terms on all material agreements completed before September 30,
14 2019. Under Oregon Commission rules, PacifiCorp filed a notice of an exception to
15 the RFP guidelines on this basis on September 27, 2019.
16 Q. Is the Pryor Mountain Wind Project eligible for the full PTC?
17 A. Yes. As Mr. Teply describes, the project will be in service by December 31, 2020,
18 and it meets all other PTC requirements.
19 Q. Did you consider the Schedule 272 agreement for REC sales in your economic
20 analysis?
21 A. Yes. The Schedule 272 Agreement represents a unique opportunity to leverage
22 Vitesse’s desire to purchase RECs from a specified resource while providing a cost-
23 effective energy resource to serve PacifiCorp’s customers. The Company estimates
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 106 REDACTED
1 that the present-value cost reduction resulting from Vitesse’s purchase of all RECs
2 generated by the project is $ , which will mitigate risks under the various
3 price-policy assumptions.
4 Q. Please describe your economic analysis of the Pryor Mountain Wind Project.
5 A. The methodology I used to perform the economic analysis of the Pryor Mountain
6 Wind Project is the same I used to perform the economic analysis of the other
7 resources addressed in my testimony. I relied on PaR runs with a simulation period
8 covering the 2019-2038 time frame. System benefits from the development of the
9 Pryor Mountain Wind Project, which includes sale of the associated RECs in
10 accordance with the Schedule 272 Agreement, are based on two PaR simulations—
11 one with incremental generation from the project and one without incremental
12 generation from the project.
13 Q. What price-policy scenarios did you use in your economic analysis?
14 A. I used the same two price-policy scenarios as in PacifiCorp’s project-by-project wind
15 repowering analysis and for Foote Creek I—one assuming medium natural gas price
16 and medium CO2 price assumptions (the “MM” price-policy scenario) and one
17 assuming low natural gas price and no CO2 price assumptions (the “LN” price-policy
18 scenario). These assumptions are summarized in Figure 10.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 107
Figure 10. Price-Policy Assumptions in the Economic Analysis of the Pryor Mountain Wind Project
Natural Gas Prices ($/MMBtu) CO2 Prices ($/Ton)
$7 $50 $6 $40 $5 $30 $4 $3 $20 $2 $10 $1 $0 $0 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
MM Avg. Sumas/Opal LN Avg. Sumas/Opal MM
1 Q. Over what period did you analyze the costs and benefits of the Pryor Mountain
2 Wind Project?
3 A. My analysis covers the 30-year life of the asset—from 2020 through 2050.
4 Q. Please explain how you developed a forecast of the project’s benefits beyond the
5 2038 time frame?
6 A. As with the wind repowering projects and Combined Projects, the system value of
7 incremental energy is converted to a dollar-per-megawatt-hour value by dividing the
8 reduction in annual system costs associated with the Pryor Mountain Wind Project by
9 the change in incremental energy from the Pryor Mountain Wind Project. This
10 analysis was performed for the MM and LN price-policy scenarios through 2038.
11 The value of energy is extended out through 2050 by extrapolating the system values
12 calculated from modeled data over two different time frames—2028–2038, and 2034–
13 2038. The assumed system value, expressed in dollars-per-megawatt-hour, is applied
14 to the incremental energy output from Pryor Mountain Wind Project. The system
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 108
1 value of the Pryor Mountain Wind Project is summarized for both price-policy
2 scenarios in Figure 11.
Figure 11. System Value Used in the Economic Analysis of Pryor Mountain Wind Project
3 Q. Please provide the results of your economic analysis.
4 A. The Pryor Mountain Wind Project is expected to provide significant net benefits for
5 customers. Table 27 summarizes the PVRR(d) benefits calculated from changes in
6 system costs through 2050. This table also presents the same information on a
7 levelized dollar-per-megawatt-hour basis. Under the MM price-policy scenario, net
8 benefits range between $69 million and $82 million. Under the LN price-policy
9 scenario, the PVRR(d) ranges between a $7 million benefit and a $1 million cost,
10 depending upon the period used to extrapolate benefits beyond 2038. The execution
11 of the Schedule 272 agreement with Vitesse was a necessary milestone to ensure the
12 Pryor Mountain Wind Project could move forward and mitigates the risk of
13 deteriorating value under a variety of price and policy scenarios, including the most
14 conservative LN price policy scenario. Additionally, while not explicitly analyzed,
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 109
1 customer benefits would increase significantly with high natural-gas price and/or high
2 CO2 price assumptions.
Table 27. Net Benefits from the Pryor Mountain Wind Project PVRR(d) Net Nom. Lev. Benefit Price-Policy Scenario (Benefit)/Cost ($/MWh (Extrapolation Method) ($ million) of Incremental Energy) MM ('28-'38 Extrapolation) ($69) ($7.22) MM ('34-'38 Extrapolation) ($82) ($8.56) LN ('28-'38 Extrapolation) $1 $0.12 LN ('34-'38 Extrapolation) ($7) ($0.72)
3 Q. Have you analyzed the change in annual revenue requirement associated with
4 the Pryor Mountain Wind Project?
5 A. Yes. Figure 12 shows the estimated change in nominal annual revenue requirement
6 due to the Pryor Mountain Wind Project for the MM and LN price-policy scenarios
7 with extrapolated benefits derived from modeled results over the period 2034–2038.
8 This figure reflects the change in nominal revenue requirement associated with Pryor
9 Mountain Wind Project netted against system benefits, which were calculated as
10 described above. Considering both the MM and LN cases illustrated below, the Pryor
11 Mountain Wind Project reduces nominal revenue requirement during a majority of its
12 depreciable life.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 110
Figure 12. (Reduction)/Increase in Total-System Annual Revenue Requirement from the Pryor Mountain Wind Project
1 IV. SALES AND LOAD FORECAST
2 Q. Please summarize the changes in Washington sales in the current filing as
3 compared to the Washington sales included in the Company’s 2014 general rate
4 case, docket UE-140762 (2014 Rate Case).
5 A. As shown in Table 28 below, PacifiCorp’s Washington sales in the test period are
6 20,972 MWh, or 0.5 percent higher than the sales included in the 2014 Rate Case.
7 The increase in sales is driven by increased sales to the commercial and irrigation
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 111
1 classes and is offset in part by a decrease in sales to the residential, industrial and
2 lighting classes.
Table 28. Washington Sales Comparison* (MWh) 2020 2014 Rate Case Rate Case Percentage 12 ME Jun-19 12 ME Dec-13 Difference Change Residential 1,547,792 1,580,882 (33,090) -2.1% Commercial 1,559,609 1,481,385 78,225 5.3% Industrial 749,767 790,071 (40,304) -5.1% Irrigation 164,796 148,533 16,262 10.9% Lighting 9,169 9,290 (121) -1.3% Total 4,031,134 4,010,161 20,972 0.5% * At meter
3 Q. How are the temperature normalized sales and load for the test period used in
4 the preparation of this case?
5 A. The temperature normalized retail sales for the test period are used by
6 Mr. Robert M. Meredith to develop present revenues and proposed rates, and
7 Ms. Shelley E. McCoy uses the test period temperature normalized loads to calculate
8 inter-jurisdictional allocation factors.
9 Q. Please summarize the changes in forecasted load compared to the 2014 Rate
10 Case.
11 A. As shown in Table 29, the forecasted load for NPC in this case (the rate effective
12 period of 12 months ending December 2021) are higher than forecasted loads for the
13 2014 rate case (12 months ending March 2016) for both the state of Washington and
14 the system as a whole.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 112
Table 29. Comparison of System Loads* in NPC. 2020 Rate Case 2014 Rate Case 12 months ending 12 months ending Dec-21 Mar-16 Percentage State (MWh) (MWh) Difference Difference Washington 4,558,260 4,421,740 136,520 3.1% Oregon 15,219,850 14,714,670 505,180 3.4% California 881,850 883,290 -1,440 -0.2% Utah 26,586,297 25,588,543 997,754 3.9% Idaho 3,976,120 3,720,890 255,230 6.9% Wyoming 9,689,150 10,558,050 -868,900 -8.2% System Load 60,911,527 59,887,183 1,024,344 1.7% *At system input (includes losses)
1 The increase in the load forecast for Washington is driven by an increase in
2 the commercial class offset in part by a decrease in forecasted sales to the residential
3 class.
4 Q. How are the forecasted loads for the PacifiCorp system used in preparing this
5 case?
6 A. The forecasted loads for PacifiCorp’s system are used by Mr. Michael G. Wilding to
7 calculate NPC.
8 Q. Please list the assumptions and updates to the current load forecast.
9 A. The Company updated the following information in the current load forecast:
10 Actual sales January 2000 through January 2019.
11 Updated weather splines to use load research data over the October 2013 12 through September 2018 timeframe.
13 The Company’s load forecast is based on normal weather defined by the 20- 14 year time period of 1999–2018.
15 Economic data is based on the October 2018 release from IHS Markit, which 16 includes households, population, and employment figures.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 113
1 Q. Are there any changes in the load forecast methodology since the 2014 Rate
2 Case?
3 A. Yes. PacifiCorp updated its residential customer forecasting methodology by
4 adopting a differenced model approach. Rather than directly forecasting the number
5 of customers as was conducted for the 2014 Rate Case, the differenced model predicts
6 the monthly change in number of customers. PacifiCorp performed a historical
7 comparison of the forecasted results using both methods against actual customer
8 counts and determined the differenced model produced a more accurate customer
9 forecast.
10 CONCLUSION
11 Q. Based on your testimony, what do you recommend to the Commission?
12 A. I recommend that the Commission conclude that PacifiCorp’s repowered wind
13 facilities, EV 2020 Wind Projects and Transmission Projects, and Pryor Mountain
14 Wind Project are prudent and in the public interest.
15 Q. Does this conclude your direct testimony?
16 A. Yes.
Direct Testimony of Rick T. Link Exhibit No. RTL-1CT Page 114 Confidential per WAC 480-07-160 Exh. RTL-2C Docket UE-19____ Witness: Rick T. Link
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Docket UE-19____ Complainant, v.
PACIFICORP dba PACIFIC POWER & LIGHT COMPANY
Respondent.
PACIFICORP
REDACTED EXHIBIT OF RICK T. LINK
Cost-and-Performance Assumptions for Wind Facilities
December 2019 Wind-Facility Data
Existing Wind Prior to Repowering Repower LGIA Limited Capital Capacity Capacity Energy Capacity Investment Date PTC End-of-Life (MW) (MW) (MWh) Factor ($m) Ends Date Repower Date Glenrock 1 99.0 99.0 303,723 35.0% n/a 12/30/2018 12/31/2038 n/a Glenrock 3 39.0 39.0 113,438 33.2% n/a 1/16/2019 12/31/2038 n/a Seven Mile Hill 1 99.0 99.0 339,195 39.1% n/a 12/30/2018 12/31/2038 n/a Seven Mile Hill 2 19.5 19.5 71,224 41.7% n/a 12/30/2018 12/31/2038 n/a High Plains 99.0 99.0 306,145 35.3% n/a 9/12/2019 12/31/2038 n/a McFadden Ridge 28.5 28.5 93,101 37.3% n/a 9/28/2019 12/31/2038 n/a Dunlap Ranch 111.0 111.0 389,045 40.0% n/a 9/30/2020 10/1/2040 n/a Rolling Hills 99.0 99.0 271,635 31.3% n/a 1/16/2019 12/31/2038 n/a Leaning Juniper 100.5 100.5 233,592 26.5% n/a 9/13/2016 9/14/2036 n/a Marengo 1 140.4 140.4 360,279 29.3% n/a 8/2/2017 8/1/2037 n/a Marengo 2 70.2 70.2 166,742 27.1% n/a 6/25/2018 6/1/2038 n/a Goodnoe Hills 94.0 94.0 220,898 26.8% n/a 5/31/2018 12/31/2038 n/a
Total 999.1 999.1 2,869,016 32.8%
Repowered Wind Repower LGIA Limited LGIA Limited LGIA Limited Capital Capacity Capacity1 Energy Capacity Investment Date PTC End-of-Life (MW) (MW) (MWh) Factor ($m) Ends Date Repower Date Glenrock 1 112.0 99.0 369,723 42.6% 9/30/2029 10/1/2049 10/1/2019 Glenrock 3 44.3 39.0 136,864 40.1% 9/30/2029 10/1/2049 10/1/2019
Seven Mile Hill 1 110.9 99.0 417,258 48.1% 6/30/2029 7/1/2049 7/1/2019 REDACTED Seven Mile Hill 2 22.8 19.5 87,480 51.2% 6/30/2029 7/1/2049 7/1/2019 High Plains 115.5 99.0 382,400 44.1% 10/31/2029 11/1/2049 11/1/2019 McFadden Ridge 33.3 28.5 116,644 46.7% 10/31/2029 11/1/2049 11/1/2019 Dunlap Ranch 129.5 111.0 476,749 49.0% 11/30/2030 12/1/2050 12/1/2020 Rolling Hills 107.5 99.0 319,022 36.8% 9/30/2029 10/1/2049 10/1/2019 Leaning Juniper 110.6 100.5 296,590 33.7% 9/30/2029 10/1/2049 10/1/2019 Marengo 1 156.0 156.0 488,207 35.7% 10/31/2029 11/1/2049 11/1/2019 Marengo 2 78.0 78.0 232,424 34.0% 10/31/2029 11/1/2049 11/1/2019 Goodnoe Hills 103.4 94.0 283,696 34.5% 9/30/2029 10/1/2049 10/1/2019
Total 1,123.6 1,022.5 3,607,057 40.3% $1,101 1 Marengo 1 and 2 include increased interconnection capability based on the completion of recent transmission studies.
Increase/(Decrease) in Run-Rate Operating Costs Due to Repowering ($m)
Run-Rate Capital
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 All Repowered Projects ($9.8) ($14.7) ($19.6) ($20.5) ($19.8) ($18.0) ($17.9) ($15.2) ($13.2) ($11.4) ($9.6) ($9.9)
2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 All Repowered Projects ($8.7) ($4.4) ($2.3) ($1.8) ($1.8) ($1.8) ($1.9) ($1.0) $1.0 $9.2 $16.5 $17.0
2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 All Repowered Projects $18.6 $19.0 $19.4 $19.9 $20.3 $20.8 $21.3 $21.8 $12.5 $1.4
Run-Rate Operations and Maintenance Expense Exhibit RTL-2C
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Page1of All Repowered Projects $0.0 $0.0 $3.9 $12.1 $12.8 $9.6 $9.5 $9.4 $9.2 $9.1 $9.0 $8.8
2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 All Repowered Projects $5.9 $2.2 $1.2 $1.2 $1.2 $1.2 $1.3 $2.1 $5.5 $13.7 $28.2 $29.5
2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 All Repowered Projects $32.3 $33.1 $33.8 $34.6 $35.4 $36.2 $37.1 $37.9 $29.9 $2.6 Confidential per WAC 480-07-160 Exh. RTL-3C Docket UE-19____ Witness: Rick T. Link
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Docket UE-19____ Complainant, v.
PACIFICORP dba PACIFIC POWER & LIGHT COMPANY
Respondent.
PACIFICORP
REDACTED EXHIBIT OF RICK T. LINK
Nominal Henry Hub Natural Gas Price Forecasts
December 2019 Confidential Exhibit No. RTL-3C
Nominal Henry Hub Natural Gas Price Forecasts ($/MMBtu)
Dec 29, 2017 Year OFPC Lowest Price Highest Price Range 2018 $2.85 $2.85 $3.89 $2.74 $3.31 $3.89 $3.31 $3.24 $3.83 $2.56 $2.56 $3.89 $1.33 2019 $2.81 $3.18 $4.33 $2.60 $3.43 $4.63 $3.39 $3.75 $4.71 $2.73 $2.60 $4.71 $2.10 2020 $2.82 $3.13 $4.26 $2.47 $3.46 $4.65 $4.39 $3.86 $5.90 $2.87 $2.47 $5.90 $3.43 2021 $2.85 $3.12 $4.25 $2.33 $3.44 $4.49 $5.01 $3.62 $6.44 $2.97 $2.33 $6.44 $4.11 2022 $2.89 $3.31 $4.51 $2.32 $3.57 $5.12 $6.48 $3.56 $7.24 $2.92 $2.32 $7.24 $4.92 2023 $2.93 $3.58 $4.88 $2.54 $3.71 $5.42 $7.57 $3.71 $7.74 $3.11 $2.54 $7.74 $5.20 2024 $3.49 $4.00 $5.45 $2.71 $3.80 $5.91 $7.64 $3.94 $8.19 $3.11 $2.71 $8.19 $5.48 2025 $4.09 $4.14 $5.64 $2.87 $4.07 $6.35 $7.00 $4.14 $8.76 $3.16 $2.87 $8.76 $5.89 2026 $4.15 $4.15 $5.65 $3.03 $4.41 $6.74 $4.29 $4.37 $9.41 $3.28 $3.03 $9.41 $6.38 2027 $4.29 $4.29 $5.85 $3.04 $4.64 $6.97 $4.10 $4.63 $9.86 $3.43 $3.04 $9.86 $6.82 2028 $4.49 $4.49 $6.11 $3.20 $4.87 $7.12 $4.15 $4.96 $10.30 $3.55 $3.20 $10.30 $7.09 2029 $4.80 $4.80 $6.54 $3.36 $5.11 $7.26 $5.37 $5.08 $10.72 $3.80 $3.36 $10.72 $7.36 2030 $5.10 $5.10 $6.95 $3.49 $5.31 $7.52 $6.94 $5.03 $11.02 $3.88 $3.49 $11.02 $7.53 2031 $5.35 $5.35 $7.29 $3.61 $5.50 $7.77 $8.34 $4.89 $11.89 $3.95 $3.61 $11.89 $8.28 2032 $5.51 $5.51 $7.51 $3.72 $5.60 $7.95 $8.84 $4.90 $12.45 $3.92 $3.72 $12.45 $8.73 2033 $5.79 $5.79 $7.88 $3.75 $5.76 $8.08 $9.08 $4.97 $12.71 $4.03 $3.75 $12.71 $8.96 2034 $6.08 $6.08 $8.28 $3.84 $5.90 $8.33 $8.58 $5.07 $12.96 $4.29 $3.84 $12.96 $9.12
2035 $6.30 $6.30 $8.58 $3.93 $6.05 $8.64 $6.68 $5.15 $13.24 $4.41 $3.93 $13.24 $9.32 REDACTED 2036 $6.70 $6.70 $9.12 $4.01 $6.21 $9.10 $7.21 $5.21 $14.06 $4.29 $4.01 $14.06 $10.05
Henry Hub Natural Gas Price Forecasts $16
$14
$12
$10
$8
$6
Nominal $/ MMBtu $/ Nominal $4
$2 Exhibit RTL-3C $0 Page1of 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Dec 29, 2017 OFPC Exh. RTL-4 Docket UE-19____ Witness: Rick T. Link
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Docket UE-19____ Complainant, v.
PACIFICORP dba PACIFIC POWER & LIGHT COMPANY
Respondent.
PACIFICORP
EXHIBIT OF RICK T. LINK
Project-Wide Wind Repowering SO and PaR PVRR(d) (Benefit)/Cost, February 2018
December 2019 Exhibit RTL-4 Page 1 of 2
Exhibit No. RTL-4
SO Model Annual Results ($ million)
Low Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($155) $1 $3 $1 ($13) ($16) ($16) ($17) ($18) ($18) ($19) ($20) ($22) ($23) ($25) ($25) ($25) ($26) ($27) ($28) ($28) 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 DSM ($5) $0 $0 ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) Change in System Fixed Cost $0 ($0) ($0) $0 $0 ($0) ($0) ($0) ($0) ($0) $0 ($0) ($0) ($0) ($0) $0 $0 ($0) $0 $0$0 Net (Benefit)/Cost ($159) $58 $62 $37 ($51) ($73) ($72) ($76) ($75) ($79) ($78) ($82) ($83) ($56) $34 $53 $54 $55 $56 $57 $59
Low Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($145) $1 $3 $1 ($13) ($16) ($16) ($17) ($18) ($19) ($19) ($20) ($23) ($23) ($26) ($25) ($26) ($26) ($28) ($5) $3 Change in Emissions ($1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($2) ($2) ($2) ($1) $2 $2 Change in DSM ($1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($2) ($3) Change in System Fixed Cost ($12) ($0) ($0) $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($15) ($28) Net (Benefit)/Cost ($158) $58 $62 $37 ($51) ($73) ($72) ($76) ($75) ($79) ($78) ($82) ($83) ($56) $32 $52 $53 $53 $54 $66 $62
Low Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($166) $1 $3 $1 ($13) ($16) ($16) ($17) ($17) ($18) ($19) ($20) ($24) ($27) ($28) ($29) ($28) ($29) ($31) ($31) ($30) Change in Emissions ($17) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($2) ($3) ($2) ($3) ($4) ($5) ($6) ($5) ($4) ($5) ($8) Change in DSM ($9) $0 $0 $0 ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($2) ($2) ($2) Change in System Fixed Cost $7 ($0) ($0) $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 ($0) $3 $3 $3 $3 $2 $2 $2 $4 Net (Benefit)/Cost ($183) $58 $62 $37 ($51) ($73) ($72) ($76) ($76) ($80) ($81) ($86) ($88) ($61) $27 $46 $47 $48 $49 $50 $52
OFPC Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($210) $1 $3 $1 ($13) ($17) ($18) ($18) ($20) ($22) ($22) ($23) ($26) ($29) ($32) ($34) ($42) ($46) ($48) ($50) ($60) 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 DSM ($12) $0 $0 ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) Change in System Fixed Cost $20 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) $0 ($0) ($0) $0 $0 $0 $0 $13 $10 $11 $11 $20 Net (Benefit)/Cost ($201) $58 $62 $37 ($52) ($75) ($75) ($78) ($79) ($84) ($83) ($87) ($88) ($63) $26 $43 $49 $45 $44 $45 $45
Medium Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($185) $1 $3 $1 ($14) ($18) ($18) ($19) ($21) ($23) ($23) ($24) ($26) ($30) ($34) ($36) ($48) ($36) ($24) ($14) ($15) 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 DSM ($6) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) Change in System Fixed Cost ($14) ($0) ($0) $0 ($0) ($0) ($0) ($0) $0 ($0) $0 $0 $0 $1 $1 $1 $16 ($2) ($16) ($28) ($28) Net (Benefit)/Cost ($204) $58 $62 $37 ($52) ($75) ($74) ($78) ($78) ($84) ($82) ($87) ($88) ($63) $24 $42 $46 $43 $43 $43 $43
Medium Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($215) $1 $3 $1 ($13) ($17) ($18) ($19) ($20) ($23) ($23) ($26) ($28) ($39) ($49) ($53) ($56) ($36) ($35) ($29) ($29) Change in Emissions ($11) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($2) ($2) ($3) ($7) ($4) ($2) ($2) ($0) ($3) ($2) ($2) Change in DSM ($8) $0 $0 ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($2) ($1) ($2) ($1) ($1) Change in System Fixed Cost $19 ($0) ($0) $0 ($0) $0 ($0) ($0) ($0) ($0) $0 ($0) ($0) $18 $19 $20 $22 ($4) ($3) ($15) ($18) Net (Benefit)/Cost ($215) $58 $62 $37 ($52) ($75) ($74) ($78) ($78) ($84) ($84) ($91) ($93) ($62) $23 $42 $42 $40 $41 $38 $37
High Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($141) $1 $4 $1 ($19) ($21) ($23) ($8) ($9) ($10) ($10) ($11) ($11) ($12) ($16) ($15) ($17) ($41) ($41) ($42) ($39) 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 DSM $2 $0 $0 $0 $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 $0 $0 $1 $1 $1 $1 $1 $1 Change in System Fixed Cost ($119) ($0) ($0) $0 ($0) ($0) $0 ($23) ($24) ($24) ($25) ($25) ($26) ($25) ($23) ($25) ($24) ($1) ($3) ($3) ($8) Net (Benefit)/Cost ($257) $58 $63 $37 ($57) ($78) ($79) ($90) ($90) ($94) ($93) ($97) ($97) ($69) $20 $39 $40 $41 $41 $41 $41
High Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($46) $1 $4 $1 ($19) ($21) ($23) $9 $10 $11 $10 $11 $12 $12 $3 $3 $1 ($30) ($41) ($42) ($51) Change in Emissions ($1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($1) ($1) ($1) Change in DSM ($14) $0 $0 $0 $0 $0 ($0) ($1) ($1) ($1) ($1) ($2) ($2) ($2) ($2) ($3) ($3) ($4) ($4) ($5) ($6) Change in System Fixed Cost ($200) ($0) ($0) $0 ($0) ($0) $0 ($44) ($45) ($46) ($47) ($48) ($49) ($44) ($35) ($35) ($33) ($3) $5 $5 $11 Net (Benefit)/Cost ($260) $58 $63 $37 ($57) ($78) ($79) ($95) ($94) ($97) ($97) ($101) ($99) ($66) $24 $44 $46 $44 $43 $42 $40
High Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($230) $1 $4 $1 ($19) ($20) ($22) ($21) ($23) ($25) ($26) ($27) ($30) ($33) ($34) ($43) ($31) ($16) ($58) ($64) ($63) Change in Emissions ($8) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($1) ($2) ($2) ($3) ($1) ($2) ($1) ($5) ($2) ($2) Change in DSM ($3) $0 $0 $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($1) ($1) Change in System Fixed Cost ($34) ($0) ($0) $0 ($0) ($1) ($1) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($6) ($6) ($12) ($27) ($11) $13 $8 Net (Benefit)/Cost ($273) $58 $63 $37 ($57) ($78) ($79) ($85) ($85) ($91) ($90) ($96) ($98) ($74) $15 $28 $34 $36 $9 $31 $30
PaR Stochastic-Mean Results ($ million)
Low Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($134) $1 $2 $1 ($10) ($12) ($13) ($13) ($14) ($14) ($15) ($15) ($21) ($22) ($23) ($23) ($24) ($24) ($25) ($26) ($26) 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 ($1) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) Change in DSM ($5) $0 $0 ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) Change in Deficiency ($2) $0 $0 ($0) ($0) $0 ($0) $0 $0 ($0) ($0) $0 ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($0) ($1) Change in PTC losses (dumped energy $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Change in System Fixed Cost $0 ($0) ($0) $0 $0 ($0) ($0) ($0) ($0) ($0) $0 ($0) ($0) ($0) ($0) $0 $0 ($0) $0 $0$0 Net (Benefit)/Cost ($141) $58 $61 $36 ($49) ($70) ($69) ($73) ($72) ($76) ($75) ($78) ($82) ($55) $35 $54 $55 $56 $57 $58 $59
Low Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($122) $1 $2 $1 ($10) ($12) ($13) ($14) ($14) ($15) ($15) ($16) ($21) ($22) ($23) ($23) ($24) ($24) ($24) ($4) $4 Change in Emissions ($2) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($1) ($2) ($2) ($2) $1 $2 Change in VOM ($1) $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($1) $0 $1 Change in DSM ($1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($3) ($3) Change in Deficiency ($1) $0 $0 ($0) ($0) $0 ($0) ($0) $0 ($0) $0 $0 ($0) ($0) ($1) ($0) ($1) ($1) $3 ($0) ($4) Change in PTC losses (dumped energy $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Change in System Fixed Cost ($12) ($0) ($0) $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($15) ($28) Net (Benefit)/Cost ($139) $58 $61 $37 ($49) ($69) ($69) ($73) ($72) ($75) ($74) ($78) ($82) ($55) $34 $53 $53 $54 $59 $66 $59
Low Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Exhibit RTL-4 Page 2 of 2
Exhibit No. RTL-4 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($145) $1 $2 $1 ($10) ($12) ($12) ($13) ($14) ($14) ($15) ($16) ($23) ($25) ($27) ($27) ($27) ($27) ($28) ($29) ($30) Change in Emissions ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($2) ($3) ($3) ($4) ($5) ($5) ($6) ($6) ($6) ($6) ($6) Change in VOM ($1) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) Change in DSM ($9) $0 $0 $0 ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($2) ($2) ($2) ($2) Change in Deficiency ($0) $0 $0 ($0) ($0) ($0) $0 $0 $0 ($0) $0 ($0) ($0) ($0) ($0) ($2) ($1) ($1) $5 $0 ($1) Change in PTC losses (dumped energy $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Change in System Fixed Cost $7 ($0) ($0) $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 ($0) $3 $3 $3 $3 $2 $2 $2 $4 Net (Benefit)/Cost ($165) $58 $61 $37 ($49) ($69) ($69) ($73) ($72) ($76) ($77) ($83) ($88) ($61) $27 $45 $48 $49 $55 $51 $52
OFPC Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($174) $1 $2 $1 ($11) ($13) ($14) ($14) ($16) ($17) ($17) ($18) ($25) ($27) ($27) ($29) ($37) ($38) ($40) ($43) ($50) 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 ($2) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($1) ($1) Change in DSM ($13) $0 $0 ($1) ($1) ($1) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) Change in Deficiency ($2) ($0) $0 $0 ($0) ($0) $0 ($0) $0 ($0) $0 ($0) $0 ($0) ($0) ($1) ($2) ($0) ($3) $0 ($1) Change in PTC losses (dumped energy $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Change in System Fixed Cost $20 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) $0 ($0) ($0) $0 $0 $0 $0 $13 $10 $11 $11 $20 Net (Benefit)/Cost ($171) $58 $62 $36 ($50) ($71) ($71) ($75) ($74) ($79) ($78) ($82) ($87) ($62) $29 $47 $51 $51 $48 $51 $54
Medium Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($159) $1 $2 $1 ($11) ($14) ($14) ($15) ($16) ($18) ($18) ($18) ($26) ($28) ($31) ($33) ($43) ($33) ($22) ($15) ($15) Change in Emissions ($1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($1) ($1) ($1) ($0) $0 $0 Change in VOM ($1) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) Change in DSM ($6) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) Change in Deficiency $1 ($0) $0 $0 ($0) $0 $0 ($0) $0 ($0) $0 $0 ($0) ($0) ($1) ($1) ($2) $3 $2 ($0) $1 Change in PTC losses (dumped energy $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Change in System Fixed Cost ($14) ($0) ($0) $0 ($0) ($0) ($0) ($0) $0 ($0) $0 $0 $0 $1 $1 $1 $16 ($2) ($16) ($28) ($28) Net (Benefit)/Cost ($180) $58 $62 $37 ($49) ($71) ($70) ($74) ($74) ($79) ($77) ($82) ($88) ($62) $25 $43 $48 $48 $46 $41 $44
Medium Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $1 $57 $59 $36 ($38) ($57) ($56) ($59) ($57) ($60) ($59) ($62) ($60) ($33) $59 $78 $80 $82 $84 $86 $88 Change in NPC ($186) $1 $2 $1 ($11) ($13) ($14) ($15) ($16) ($18) ($18) ($19) ($27) ($39) ($45) ($47) ($49) ($32) ($33) ($28) ($27) Change in Emissions ($16) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($2) ($3) ($3) ($6) ($6) ($5) ($6) ($4) ($4) ($3) ($3) Change in VOM ($1) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) Change in DSM ($8) $0 $0 ($1) ($1) ($0) ($0) ($0) ($1) ($1) ($1) ($1) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) Change in Deficiency ($2) ($0) $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 $0 $0 ($0) ($0) ($0) ($1) ($1) ($1) ($0) ($1) Change in PTC losses (dumped energy $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Change in System Fixed Cost $19 ($0) ($0) $0 ($0) $0 ($0) ($0) ($0) ($0) $0 ($0) ($0) $18 $19 $20 $22 ($4) ($3) ($15) ($18) Net (Benefit)/Cost ($193) $58 $61 $36 ($50) ($71) ($70) ($74) ($74) ($79) ($79) ($85) ($92) ($61) $25 $44 $44 $40 $40 $37 $37 Exh. RTL-5 Docket UE-19____ Witness: Rick T. Link
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Docket UE-19____ Complainant, v.
PACIFICORP dba PACIFIC POWER & LIGHT COMPANY
Respondent.
PACIFICORP
EXHIBIT OF RICK T. LINK
Project-Wide Wind Repowering Nominal Revenue Requirement PVRR(d) (Benefit)/Cost, February 2018
December 2019 Exhibit No. RTL-5
Estimated Annual Revenue Requirement Results ($ million)
9 Low Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($394) $1 $2 $1 ($10) ($12) ($13) ($13) ($14) ($14) ($15) ($15) ($21) ($22) ($23) ($23) ($24) ($24) ($25) ($26) ($26) ($46) ($64) ($116) ($121) ($135) ($138) ($141) ($144) ($147) ($150) ($154) ($144) ($97) ($15) Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Variable Costs ($24) $0 $0 ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($2) ($2) ($2) ($2) ($1) ($2) ($3) ($4) ($7) ($7) ($8) ($8) ($9) ($9) ($9) ($9) ($9) ($9) ($6) ($1) System Fixed Costs $0 ($0) ($0) $0 $0 ($0) ($0) ($0) ($0) ($0) $0 ($0) ($0) ($0) ($0) $0 $0 ($0) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net System Impacts ($418) $1 $2 $1 ($11) ($13) ($13) ($14) ($15) ($15) ($16) ($16) ($22) ($22) ($24) ($25) ($26) ($26) ($27) ($27) ($28) ($49) ($68) ($123) ($128) ($143) ($146) ($149) ($153) ($156) ($159) ($163) ($152) ($103) ($16)
2050 Net (Benefit)/Cost ($127) $0 $1 $3 $16 ($1) ($15) ($29) ($37) ($47) ($52) ($61) ($70) ($53) $27 $41 $37 $33 $28 $21 $18 $10 $18 ($6) ($8) ($17) ($19) ($22) ($24) ($25) ($26) ($23) ($7) ($17) ($12)
7 Low Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($334) $1 $2 $1 ($10) ($12) ($13) ($14) ($14) ($15) ($15) ($16) ($21) ($22) ($23) ($23) ($24) ($24) ($24) ($4) $4 ($38) ($52) ($94) ($98) ($110) ($112) ($114) ($117) ($120) ($122) ($125) ($117) ($79) ($13) Emissions ($9) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($1) ($2) ($2) ($2) $1 $2 ($1) ($2) ($3) ($3) ($4) ($4) ($4) ($4) ($4) ($4) ($4) ($4) ($3) ($0) Other Variable Costs ($15) $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($2) ($1) $3 ($3) ($6) ($2) ($3) ($5) ($5) ($6) ($6) ($6) ($6) ($7) ($7) ($7) ($6) ($4) ($1) System Fixed Costs ($55) ($0) ($0) $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 ($0) ($0) ($0) ($0) ($0) ($1) ($1) ($15) ($28) ($8) ($11) ($19) ($20) ($22) ($23) ($23) ($24) ($24) ($25) ($25) ($24) ($16) ($3) Net System Impacts ($413) $1 $2 $1 ($10) ($12) ($13) ($14) ($14) ($15) ($15) ($16) ($21) ($22) ($25) ($26) ($27) ($28) ($25) ($20) ($29) ($49) ($67) ($122) ($127) ($141) ($145) ($148) ($151) ($154) ($158) ($161) ($151) ($102) ($16)
2050 Net (Benefit)/Cost ($121) $0 $1 $3 $16 ($1) ($15) ($28) ($36) ($47) ($52) ($61) ($70) ($53) $27 $40 $35 $30 $30 $29 $18 $10 $19 ($4) ($7) ($15) ($18) ($20) ($22) ($24) ($25) ($21) ($5) ($16) ($11)
8 Low Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($443) $1 $2 $1 ($10) ($12) ($12) ($13) ($14) ($14) ($15) ($16) ($23) ($25) ($27) ($27) ($27) ($27) ($28) ($29) ($30) ($53) ($74) ($133) ($138) ($154) ($158) ($161) ($165) ($168) ($172) ($176) ($164) ($111) ($18) Emissions ($73) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($2) ($3) ($3) ($4) ($5) ($5) ($6) ($6) ($6) ($6) ($6) ($10) ($14) ($24) ($25) ($28) ($29) ($30) ($30) ($31) ($32) ($32) ($30) ($20) ($3) Other Variable Costs ($31) $0 $0 ($0) ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($2) ($2) ($3) ($2) ($3) $2 ($2) ($4) ($4) ($5) ($9) ($10) ($11) ($11) ($11) ($11) ($12) ($12) ($12) ($11) ($8) ($1) System Fixed Costs $33 ($0) ($0) $0 $0 ($0) ($0) $0 ($0) ($0) $0 $0 ($0) $3 $3 $3 $3 $2 $2 $2 $4 $5 $6 $11 $12 $13 $14 $14 $14 $14 $15 $15 $14 $10 $2 Net System Impacts ($514) $1 $2 $1 ($10) ($12) ($14) ($15) ($15) ($16) ($18) ($21) ($27) ($28) ($31) ($33) ($32) ($33) ($29) ($34) ($36) ($62) ($86) ($155) ($161) ($180) ($184) ($188) ($192) ($197) ($201) ($206) ($192) ($130) ($21)
2050 Net (Benefit)/Cost ($223) $0 $1 $3 $16 ($1) ($15) ($29) ($37) ($48) ($55) ($66) ($76) ($59) $20 $32 $30 $25 $26 $14 $11 ($3) $0 ($38) ($42) ($54) ($58) ($61) ($64) ($66) ($68) ($66) ($46) ($44) ($16)
3 OFPC Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($552) $1 $2 $1 ($11) ($13) ($14) ($14) ($16) ($17) ($17) ($18) ($25) ($27) ($27) ($29) ($37) ($38) ($40) ($43) ($50) ($67) ($93) ($168) ($175) ($195) ($200) ($204) ($209) ($213) ($218) ($223) ($208) ($140) ($22) Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Variable Costs ($55) $0 $0 ($0) ($1) ($1) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($3) ($4) ($5) ($3) ($6) ($3) ($4) ($7) ($9) ($17) ($17) ($19) ($20) ($20) ($21) ($21) ($22) ($22) ($21) ($14) ($2) System Fixed Costs $91 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($0) $0 ($0) ($0) $0 $0 $0 $0 $13 $10 $11 $11 $20 $13 $18 $32 $33 $37 $38 $38 $39 $40 $41 $42 $39 $26 $4 Net System Impacts ($516) $1 $2 $1 ($11) ($14) ($15) ($16) ($17) ($19) ($19) ($20) ($27) ($29) ($30) ($32) ($29) ($30) ($35) ($35) ($34) ($61) ($85) ($153) ($159) ($178) ($182) ($186) ($190) ($194) ($198) ($203) ($189) ($128) ($20)
2050 Net (Benefit)/Cost ($224) $0 $1 $3 $15 ($3) ($17) ($31) ($39) ($51) ($56) ($65) ($76) ($60) $22 $34 $34 $28 $19 $13 $12 ($2) $2 ($36) ($40) ($52) ($55) ($58) ($61) ($63) ($65) ($63) ($44) ($42) ($16)
1 Medium Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($470) $1 $2 $1 ($11) ($14) ($14) ($15) ($16) ($18) ($18) ($18) ($26) ($28) ($31) ($33) ($43) ($33) ($22) ($15) ($15) ($55) ($77) ($139) ($144) ($161) ($165) ($168) ($172) ($176) ($180) ($184) ($171) ($116) ($18) Emissions ($6) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($1) ($1) ($1) ($0) $0 $0 ($1) ($1) ($2) ($2) ($3) ($3) ($3) ($3) ($3) ($3) ($3) ($3) ($2) ($0) Other Variable Costs ($24) $0 $0 $0 ($0) ($0) ($0) ($0) ($0) ($0) ($0) ($2) ($2) ($2) ($2) ($2) ($4) $2 ($0) ($2) ($0) ($3) ($4) ($8) ($8) ($9) ($9) ($9) ($9) ($10) ($10) ($10) ($9) ($6) ($1) System Fixed Costs ($65) ($0) ($0) $0 ($0) ($0) ($0) ($0) $0 ($0) $0 $0 $0 $1 $1 $1 $16 ($2) ($16) ($28) ($28) ($9) ($12) ($23) ($23) ($26) ($27) ($27) ($28) ($29) ($29) ($30) ($28) ($19) ($3) Exhibit Net System Impacts ($565) $1 $2 $1 ($11) ($14) ($15) ($15) ($17) ($19) ($19) ($20) ($27) ($29) ($33) ($36) ($32) ($34) ($38) ($44) ($44) ($68) ($95) ($171) ($178) ($198) ($203) ($207) ($212) ($217) ($221) ($226) ($211) ($143) ($23) Page
2050 Net (Benefit)/Cost ($273) $0 $1 $4 $16 ($2) ($16) ($30) ($39) ($51) ($55) ($65) ($76) ($60) $18 $30 $30 $25 $17 $4 $2 ($9) ($8) ($53) ($58) ($72) ($76) ($80) ($83) ($86) ($88) ($86) ($66) ($57) ($18)
2 Medium Natural Gas, High CO2 Price-Policy Scenario RTL-5 1
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 of Project Net Costs
Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 3 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5 Exhibit No. RTL-5
Estimated Annual Revenue Requirement Results ($ million)
System Impacts NPC ($596) $1 $2 $1 ($11) ($13) ($14) ($15) ($16) ($18) ($18) ($19) ($27) ($39) ($45) ($47) ($49) ($32) ($33) ($28) ($27) ($73) ($101) ($183) ($190) ($212) ($217) ($222) ($227) ($232) ($237) ($242) ($226) ($153) ($24) Emissions ($64) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($2) ($3) ($3) ($6) ($6) ($5) ($6) ($4) ($4) ($3) ($3) ($9) ($12) ($22) ($22) ($25) ($26) ($26) ($27) ($27) ($28) ($29) ($27) ($18) ($3) Other Variable Costs ($37) $0 $0 ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($2) ($2) ($2) ($2) ($2) ($3) ($3) ($2) ($3) ($5) ($6) ($12) ($12) ($13) ($14) ($14) ($14) ($15) ($15) ($15) ($14) ($10) ($2) System Fixed Costs $85 ($0) ($0) $0 ($0) $0 ($0) ($0) ($0) ($0) $0 ($0) ($0) $18 $19 $20 $22 ($4) ($3) ($15) ($18) $12 $16 $29 $31 $34 $35 $36 $37 $37 $38 $39 $36 $25 $4 Net System Impacts ($612) $1 $2 $1 ($11) ($14) ($15) ($16) ($17) ($19) ($21) ($23) ($32) ($29) ($33) ($34) ($36) ($42) ($43) ($48) ($51) ($74) ($103) ($186) ($194) ($216) ($221) ($226) ($231) ($236) ($241) ($247) ($231) ($156) ($25)
2050 Net (Benefit)/Cost ($321) $0 $1 $3 $15 ($3) ($17) ($30) ($39) ($51) ($57) ($68) ($81) ($59) $18 $31 $27 $17 $11 $0 ($5) ($16) ($17) ($69) ($74) ($90) ($95) ($99) ($102) ($105) ($108) ($107) ($85) ($70) ($20) Exhibit Page RTL-5 2 of 3 Exhibit No. RTL-5
Estimated Annual Revenue Requirement Results ($ million)
6 High Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($374) $1 $3 $1 ($14) ($16) ($18) ($4) ($5) ($5) ($5) ($6) ($12) ($13) ($17) ($16) ($17) ($38) ($36) ($39) ($36) ($46) ($64) ($115) ($120) ($133) ($136) ($139) ($142) ($146) ($149) ($152) ($142) ($96) ($15) Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Variable Costs ($1) $0 $0 $0 ($0) ($0) ($0) ($0) $0 $0 $0 $1 $1 $1 $1 $1 $1 ($2) ($3) ($1) ($1) ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($0) ($0) System Fixed Costs ($306) ($0) ($0) $0 ($0) ($0) $0 ($23) ($24) ($24) ($25) ($25) ($26) ($25) ($23) ($25) ($24) ($1) ($3) ($3) ($8) ($33) ($46) ($83) ($87) ($97) ($99) ($101) ($103) ($106) ($108) ($110) ($103) ($70) ($11) Net System Impacts ($681) $1 $3 $1 ($14) ($17) ($18) ($27) ($28) ($29) ($30) ($30) ($37) ($37) ($38) ($40) ($40) ($41) ($42) ($43) ($46) ($79) ($110) ($199) ($207) ($231) ($236) ($241) ($246) ($252) ($257) ($263) ($246) ($166) ($26)
2050 Net (Benefit)/Cost ($389) $0 $1 $4 $12 ($5) ($19) ($42) ($50) ($61) ($66) ($76) ($86) ($68) $13 $26 $22 $18 $13 $6 $1 ($21) ($24) ($81) ($87) ($105) ($109) ($114) ($118) ($121) ($124) ($123) ($100) ($80) ($22)
4 High Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($157) $1 $3 $1 ($14) ($16) ($18) $11 $12 $12 $12 $12 $8 $8 $1 $0 ($1) ($28) ($36) ($38) ($44) ($22) ($31) ($55) ($58) ($64) ($66) ($67) ($69) ($70) ($72) ($73) ($69) ($46) ($7) Emissions ($3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $1 $1 $1 ($1) ($1) ($1) ($2) ($0) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($1) ($0) Other Variable Costs ($56) $0 $0 $0 ($0) ($0) ($0) ($1) ($1) ($1) ($1) ($2) ($2) ($2) ($1) ($1) ($3) ($6) ($7) ($8) ($7) ($7) ($10) ($18) ($19) ($21) ($22) ($22) ($23) ($23) ($24) ($24) ($23) ($15) ($2) System Fixed Costs ($461) ($0) ($0) $0 ($0) ($0) $0 ($44) ($45) ($46) ($47) ($48) ($49) ($44) ($35) ($35) ($33) ($3) $5 $5 $11 ($46) ($64) ($116) ($121) ($135) ($138) ($141) ($144) ($148) ($151) ($154) ($144) ($97) ($16) Net System Impacts ($677) $1 $3 $1 ($14) ($17) ($18) ($34) ($34) ($35) ($36) ($38) ($42) ($37) ($36) ($36) ($36) ($38) ($39) ($41) ($42) ($76) ($106) ($191) ($199) ($222) ($227) ($232) ($237) ($242) ($248) ($253) ($237) ($160) ($25)
2050 Net (Benefit)/Cost ($386) $0 $1 $4 $12 ($5) ($19) ($49) ($56) ($67) ($73) ($83) ($91) ($68) $16 $30 $26 $21 $15 $7 $4 ($18) ($20) ($74) ($79) ($96) ($100) ($105) ($109) ($112) ($115) ($113) ($91) ($74) ($21)
5 High Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Capital Recovery $873 ($1) ($2) $22 $114 $118 $108 $100 $92 $87 $83 $79 $75 $70 $66 $63 $60 $56 $52 $46 $43 $51 $70 $84 $85 $88 $88 $88 $88 $89 $91 $97 $102 $52 $2 O&M $125 $0 $0 $4 $12 $13 $10 $9 $9 $9 $9 $9 $9 $6 $2 $1 $1 $1 $1 $1 $2 $6 $14 $28 $30 $32 $33 $34 $35 $35 $36 $37 $38 $30 $3 Wind Tax $18 $0 ($0) $0 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $1 $2 $2 $5 $5 $6 $6 $6 $6 $6 $6 $6 $6 $4 $1 PTCs ($725) $0 $1 ($24) ($100) ($120) ($120) ($125) ($125) ($129) ($129) ($134) ($134) ($108) ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $291 ($1) ($1) $3 $27 $11 ($2) ($15) ($22) ($32) ($37) ($45) ($49) ($31) $52 $65 $62 $59 $55 $48 $46 $59 $86 $117 $120 $126 $127 $127 $129 $131 $133 $140 $146 $86 $5
System Impacts NPC ($594) $1 $3 $1 ($14) ($16) ($17) ($16) ($17) ($18) ($19) ($19) ($28) ($30) ($32) ($43) ($29) ($22) ($49) ($52) ($51) ($72) ($99) ($180) ($187) ($209) ($213) ($218) ($223) ($228) ($233) ($238) ($222) ($150) ($24) Emissions ($43) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($2) ($2) ($3) ($3) ($1) ($2) ($2) ($6) ($4) ($4) ($6) ($8) ($14) ($15) ($17) ($17) ($17) ($18) ($18) ($19) ($19) ($18) ($12) ($2) Other Variable Costs ($16) $0 $0 $0 ($0) ($0) ($0) ($1) ($0) ($0) ($0) ($0) ($1) ($1) ($1) ($1) ($1) ($4) $7 ($4) ($5) ($2) ($3) ($5) ($5) ($6) ($6) ($6) ($6) ($6) ($7) ($7) ($6) ($4) ($1) System Fixed Costs ($105) ($0) ($0) $0 ($0) ($1) ($1) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($6) ($6) ($12) ($27) ($11) $13 $8 ($13) ($17) ($31) ($33) ($36) ($37) ($38) ($39) ($40) ($41) ($42) ($39) ($26) ($4) Net System Impacts ($758) $1 $3 $1 ($14) ($17) ($18) ($21) ($22) ($23) ($25) ($27) ($36) ($39) ($42) ($51) ($45) ($55) ($59) ($47) ($52) ($92) ($128) ($230) ($240) ($268) ($274) ($280) ($286) ($292) ($299) ($305) ($285) ($192) ($31)
2050 Net (Benefit)/Cost ($466) $0 $1 $4 $12 ($6) ($20) ($36) ($44) ($55) ($61) ($72) ($84) ($70) $9 $14 $17 $4 ($5) $1 ($5) ($33) ($41) ($113) ($120) ($142) ($147) ($152) ($157) ($161) ($166) ($165) ($139) ($107) ($26) Exhibit Page RTL-5 3 of 3 Exh. RTL-6 Docket UE-19____ Witness: Rick T. Link
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Docket UE-19____ Complainant, v.
PACIFICORP dba PACIFIC POWER & LIGHT COMPANY
Respondent.
PACIFICORP
EXHIBIT OF RICK T. LINK
Combined Projects SO and PaR PVRR(d) (Benefit)/Cost, February 2018
December 2019 Exhibit RTL-6 Page 1 of 2
Exhibit No. RTL-6
SO Model Annual Results ($ million)
Low Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($857) ($0) $0 $1 ($13) ($99) ($100) ($103) ($102) ($106) ($106) ($109) ($122) ($122) ($136) ($132) ($132) ($144) ($158) ($138) ($136) 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 DSM ($92) $0 ($0) ($1) ($3) ($4) ($5) ($6) ($9) ($11) ($12) ($14) ($15) ($15) ($15) ($15) ($16) ($17) ($19) ($23) ($25) Change in System Fixed Cost ($100) $0 $0 $0 ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($19) ($19) ($19) ($35) ($22) ($11) ($55) ($57) Net (Benefit)/Cost ($185) ($0) ($0) ($0) ($15) ($46) ($44) ($49) ($51) ($52) ($54) ($54) ($69) ($76) ($61) $74 $63 $69 $69 $47 $51
Low Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($838) ($0) ($0) $1 ($13) ($99) ($100) ($104) ($103) ($107) ($107) ($110) ($124) ($124) ($137) ($126) ($126) ($129) ($130) ($129) ($113) Change in Emissions ($40) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($9) ($17) ($21) ($19) ($19) ($17) ($25) Change in DSM ($84) $0 $0 ($1) ($3) ($3) ($4) ($5) ($7) ($9) ($10) ($12) ($12) ($14) ($14) ($16) ($18) ($20) ($21) ($21) ($22) Change in System Fixed Cost ($109) $0 ($0) ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($19) ($19) ($19) ($13) ($26) ($64) ($49) ($63) Net (Benefit)/Cost ($208) ($0) $0 ($0) ($15) ($45) ($43) ($49) ($51) ($52) ($53) ($53) ($68) ($76) ($70) $63 $68 $57 $23 $48 $47
Low Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($909) ($0) $1 $1 ($13) ($100) ($101) ($104) ($104) ($109) ($111) ($119) ($143) ($151) ($152) ($138) ($136) ($156) ($157) ($156) ($143) Change in Emissions ($145) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($11) ($20) ($17) ($22) ($37) ($55) ($60) ($45) ($42) ($49) ($63) Change in DSM ($69) $0 ($2) ($2) ($3) ($3) ($4) ($6) ($7) ($7) ($8) ($8) ($9) ($10) ($11) ($12) ($13) ($14) ($15) ($16) ($16) Change in System Fixed Cost ($110) $0 $0 ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($21) ($21) ($21) ($21) ($21) ($57) ($55) ($56) Net (Benefit)/Cost ($370) ($0) ($1) ($1) ($15) ($45) ($44) ($49) ($51) ($51) ($66) ($78) ($102) ($124) ($112) $15 $16 $16 ($15) ($12) ($10)
OFPC Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($1,060) ($0) $1 $2 ($13) ($104) ($107) ($109) ($112) ($125) ($124) ($128) ($143) ($159) ($178) ($195) ($196) ($204) ($230) ($208) ($173) 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 DSM ($68) $0 ($2) ($3) ($3) ($4) ($5) ($7) ($7) ($7) ($8) ($8) ($10) ($10) ($11) ($11) ($12) ($12) ($12) ($12) ($13) Change in System Fixed Cost ($113) $0 $0 ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($21) ($21) ($21) ($19) ($24) ($7) ($63) ($115) Net (Benefit)/Cost ($377) ($0) ($1) ($1) ($15) ($51) ($51) ($55) ($60) ($67) ($68) ($68) ($85) ($110) ($100) $14 $19 $12 $7 ($20) ($33)
Medium Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($989) ($0) $0 $1 ($14) ($105) ($109) ($111) ($116) ($128) ($126) ($130) ($145) ($161) ($183) ($203) ($204) ($199) ($203) ($81) ($1) Change in Emissions ($12) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($7) ($4) ($5) ($7) ($8) ($5) ($2) Change in DSM ($48) $0 ($0) ($1) ($2) ($2) ($3) ($3) ($4) ($4) ($5) ($7) ($8) ($9) ($9) ($10) ($10) ($10) ($10) ($10) ($10) Change in System Fixed Cost ($219) $0 $0 $0 ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($22) ($22) ($22) ($22) ($39) ($45) ($202) ($299) Net (Benefit)/Cost ($405) ($0) ($0) ($0) ($15) ($50) ($51) ($54) ($60) ($67) ($67) ($68) ($85) ($111) ($111) $2 $5 ($3) ($9) ($35) ($45)
Medium Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($910) ($0) $0 $1 ($14) ($94) ($97) ($99) ($103) ($113) ($111) ($122) ($126) ($125) ($172) ($193) ($207) ($86) ($90) ($171) ($177) Change in Emissions ($103) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($14) ($18) ($37) ($50) ($32) ($14) ($21) ($22) ($23) ($21) ($23) Change in DSM ($53) $0 ($1) ($1) ($2) ($3) ($3) ($4) ($4) ($5) ($7) ($7) ($8) ($9) ($11) ($11) ($11) ($11) ($11) ($11) ($11) Change in System Fixed Cost ($287) $0 $0 $0 ($0) ($19) ($19) ($20) ($24) ($24) ($25) ($25) ($26) ($38) ($38) ($39) ($21) ($147) ($148) ($73) ($76) Net (Benefit)/Cost ($489) ($0) ($0) ($0) ($15) ($55) ($55) ($58) ($64) ($71) ($85) ($96) ($122) ($142) ($143) ($15) ($13) ($14) ($14) ($13) ($19)
High Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($1,213) ($0) $0 $1 ($21) ($127) ($137) ($130) ($141) ($149) ($149) ($154) ($172) ($188) ($204) ($180) ($125) ($214) ($189) ($279) ($264) 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 DSM ($48) $0 ($1) ($1) ($2) ($2) ($2) ($3) ($6) ($6) ($6) ($6) ($8) ($8) ($8) ($8) ($9) ($9) ($10) ($10) ($11) Change in System Fixed Cost ($303) $0 $0 ($0) ($0) ($3) ($3) ($27) ($30) ($31) ($32) ($32) ($33) ($41) ($55) ($92) ($147) ($57) ($99) ($41) ($67) Net (Benefit)/Cost ($699) ($0) ($0) ($0) ($22) ($72) ($78) ($96) ($110) ($115) ($116) ($117) ($138) ($157) ($158) ($39) ($35) ($29) ($40) ($68) ($73)
High Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($1,130) ($0) $0 $1 ($21) ($127) ($137) ($114) ($118) ($130) ($130) ($134) ($150) ($163) ($181) ($128) ($142) ($206) ($198) ($289) ($305) Change in Emissions ($15) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($5) ($4) ($5) ($7) ($8) ($10) ($12) Change in DSM ($51) $0 ($1) ($1) ($2) ($2) ($2) ($3) ($6) ($6) ($6) ($7) ($8) ($8) ($9) ($9) ($10) ($10) ($11) ($12) ($12) Change in System Fixed Cost ($383) $0 $0 ($0) ($0) ($3) ($3) ($48) ($52) ($53) ($54) ($55) ($56) ($63) ($76) ($138) ($129) ($62) ($83) ($27) ($25) Net (Benefit)/Cost ($716) ($0) ($0) ($0) ($22) ($72) ($78) ($100) ($110) ($117) ($119) ($120) ($139) ($155) ($160) ($39) ($39) ($34) ($43) ($76) ($86)
High Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Projects $864 $0 $0 $0 $2 $60 $64 $64 $66 $71 $71 $76 $75 $80 $109 $241 $246 $251 $257 $263 $268 Change in NPC ($1,131) ($0) $0 $1 ($22) ($125) ($134) ($84) ($87) ($96) ($96) ($99) ($113) ($145) ($177) ($225) ($243) ($224) ($260) ($337) ($348) Change in Emissions ($67) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($4) ($8) ($11) ($16) ($15) ($8) ($24) ($22) ($29) ($30) ($31) Change in DSM ($41) $0 ($1) ($1) ($1) ($1) ($1) ($3) ($4) ($5) ($5) ($5) ($6) ($7) ($7) ($7) ($8) ($8) ($9) ($10) ($11) Change in System Fixed Cost ($406) $0 $0 ($0) ($0) ($7) ($7) ($84) ($89) ($91) ($93) ($95) ($97) ($77) ($74) ($44) ($23) ($49) ($41) $17 $13 Net (Benefit)/Cost ($781) ($0) ($0) ($0) ($22) ($73) ($78) ($107) ($114) ($120) ($127) ($131) ($151) ($165) ($163) ($44) ($52) ($52) ($82) ($97) ($109)
PaR Stochastic-Mean Results ($ million)
Low Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($757) $0 $0 $1 ($12) ($89) ($90) ($92) ($90) ($94) ($92) ($92) ($105) ($109) ($116) ($119) ($121) ($127) ($137) ($124) ($121) 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 ($18) $0 $0 $0 ($0) ($2) ($2) ($2) ($2) ($2) ($3) ($3) ($3) ($2) ($2) ($2) ($2) ($3) ($4) ($3) ($3) Change in DSM ($108) $0 ($1) ($2) ($3) ($5) ($6) ($8) ($10) ($13) ($15) ($16) ($17) ($18) ($18) ($18) ($18) ($19) ($20) ($25) ($27) Change in Deficiency ($8) $0 ($0) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($3) ($4) ($3) ($2) ($6) ($2) ($4) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($100) $0 $0 $0 ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($19) ($19) ($19) ($35) ($22) ($11) ($55) ($57) Net (Benefit)/Cost ($150) $0 ($0) ($1) ($15) ($41) ($39) ($44) ($47) ($48) ($49) ($45) ($60) ($72) ($53) $74 $63 $76 $75 $50 $52
Low Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($756) $0 $0 $1 ($13) ($90) ($90) ($93) ($92) ($96) ($94) ($94) ($107) ($111) ($118) ($120) ($121) ($121) ($119) ($119) ($110) Change in Emissions ($36) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($12) ($14) ($16) ($17) ($19) ($17) ($19) Change in VOM ($17) $0 $0 $0 ($0) ($2) ($2) ($2) ($2) ($2) ($3) ($3) ($3) ($2) ($2) ($2) ($2) ($2) ($3) ($2) ($2) Change in DSM ($93) $0 $0 ($1) ($3) ($4) ($5) ($6) ($8) ($10) ($12) ($13) ($13) ($15) ($16) ($18) ($20) ($21) ($22) ($22) ($24) Change in Deficiency ($7) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($3) ($3) ($4) ($2) ($7) ($1) ($4) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($109) $0 ($0) ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($19) ($19) ($19) ($13) ($26) ($64) ($49) ($63) Net (Benefit)/Cost ($179) $0 ($0) ($1) ($15) ($41) ($39) ($44) ($46) ($47) ($47) ($44) ($58) ($71) ($65) $62 $66 $58 $19 $48 $43
Low Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Exhibit RTL-6 Page 2 of 2
Exhibit No. RTL-6 Change in NPC ($807) $0 $1 $1 ($13) ($90) ($90) ($93) ($92) ($97) ($99) ($102) ($120) ($125) ($131) ($133) ($133) ($134) ($131) ($136) ($137) Change in Emissions ($159) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($11) ($22) ($30) ($37) ($46) ($48) ($51) ($52) ($54) ($52) ($52) Change in VOM ($16) $0 $0 $0 ($0) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($3) ($3) ($3) Change in DSM ($76) $0 ($2) ($3) ($3) ($3) ($5) ($7) ($7) ($7) ($8) ($9) ($10) ($11) ($12) ($13) ($14) ($16) ($16) ($17) ($18) Change in Deficiency ($8) $0 ($0) $0 $0 ($0) $0 $0 $0 $0 $0 $0 $0 ($1) ($4) ($4) ($3) ($4) ($5) ($2) ($5) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($110) $0 $0 ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($21) ($21) ($21) ($21) ($21) ($57) ($55) ($56) Net (Benefit)/Cost ($337) $0 ($1) ($1) ($15) ($41) ($39) ($44) ($45) ($45) ($60) ($69) ($97) ($119) ($111) $17 $18 $19 ($13) ($6) ($6)
OFPC Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($941) $0 $1 $2 ($12) ($94) ($96) ($97) ($101) ($114) ($112) ($114) ($133) ($143) ($156) ($166) ($169) ($178) ($200) ($184) ($149) 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 ($23) $0 $0 $0 ($0) ($2) ($3) ($3) ($3) ($3) ($3) ($3) ($2) ($3) ($3) ($3) ($3) ($5) ($6) ($4) ($4) Change in DSM ($76) $0 ($2) ($3) ($4) ($4) ($6) ($7) ($8) ($8) ($9) ($9) ($11) ($11) ($12) ($12) ($13) ($13) ($13) ($13) ($15) Change in Deficiency ($6) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($1) ($2) ($4) ($5) ($1) ($5) ($1) ($4) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($113) $0 $0 ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($21) ($21) ($21) ($19) ($24) ($7) ($63) ($115) Net (Benefit)/Cost ($319) $0 ($1) ($1) ($16) ($46) ($45) ($49) ($55) ($63) ($63) ($61) ($81) ($101) ($88) $31 $34 $26 $23 ($6) ($22)
Medium Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($882) $0 $0 $1 ($13) ($95) ($97) ($99) ($104) ($117) ($114) ($115) ($135) ($144) ($162) ($171) ($175) ($176) ($177) ($74) ($3) Change in Emissions ($18) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($9) ($8) ($9) ($10) ($11) ($5) ($2) Change in VOM ($21) $0 $0 $0 ($0) ($2) ($3) ($3) ($3) ($3) ($3) ($3) ($2) ($3) ($3) ($3) ($3) ($4) ($5) ($2) ($1) Change in DSM ($53) $0 ($1) ($1) ($2) ($2) ($4) ($4) ($4) ($5) ($6) ($7) ($9) ($9) ($9) ($11) ($11) ($11) ($11) ($11) ($11) Change in Deficiency ($4) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($0) ($2) ($3) ($5) $1 ($2) ($1) ($0) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($219) $0 $0 $0 ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($22) ($22) ($22) ($22) ($39) ($45) ($202) ($299) Net (Benefit)/Cost ($357) $0 ($0) ($1) ($15) ($45) ($45) ($47) ($55) ($63) ($62) ($60) ($81) ($102) ($101) $19 $17 $10 $3 ($36) ($52)
Medium Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($804) $0 $0 $1 ($13) ($85) ($86) ($88) ($92) ($104) ($101) ($101) ($119) ($129) ($144) ($154) ($169) ($80) ($82) ($147) ($148) Change in Emissions ($116) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($10) ($20) ($29) ($35) ($38) ($36) ($42) ($21) ($22) ($32) ($34) Change in VOM ($17) $0 $0 $0 ($0) ($2) ($2) ($2) ($3) ($3) ($3) ($3) ($2) ($2) ($2) ($2) ($3) ($1) ($2) ($2) ($3) Change in DSM ($57) $0 ($1) ($1) ($2) ($3) ($4) ($4) ($4) ($6) ($7) ($7) ($9) ($10) ($11) ($12) ($12) ($11) ($11) ($12) ($12) Change in Deficiency ($7) $0 $0 ($0) $0 $0 ($0) $0 $0 $0 $1 $0 $0 ($1) ($2) ($2) ($2) ($3) ($3) ($4) ($9) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($287) $0 $0 $0 ($0) ($19) ($19) ($20) ($24) ($24) ($25) ($25) ($26) ($38) ($38) ($39) ($21) ($147) ($148) ($73) ($76) Net (Benefit)/Cost ($448) $0 ($0) ($1) ($15) ($51) ($50) ($53) ($59) ($68) ($76) ($84) ($113) ($137) ($130) ($7) ($5) ($16) ($16) ($12) ($19)
High Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($1,021) $0 $0 $1 ($19) ($115) ($122) ($113) ($118) ($123) ($122) ($122) ($143) ($159) ($173) ($154) ($109) ($176) ($152) ($227) ($214) 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 ($19) $0 $0 $0 ($0) ($3) ($3) ($3) ($2) ($2) ($3) ($3) ($2) ($2) ($2) ($2) ($2) ($3) ($3) ($4) ($4) Change in DSM ($52) $0 ($1) ($1) ($2) ($2) ($2) ($3) ($6) ($7) ($7) ($7) ($8) ($9) ($9) ($9) ($10) ($10) ($10) ($11) ($11) Change in Deficiency ($13) $0 $0 $0 $0 $1 $0 $0 $1 $0 $0 $0 $1 ($0) ($2) ($4) ($3) ($14) ($20) ($2) ($5) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($303) $0 $0 ($0) ($0) ($3) ($3) ($27) ($30) ($31) ($32) ($32) ($33) ($41) ($55) ($92) ($147) ($57) ($99) ($41) ($67) Net (Benefit)/Cost ($568) $0 ($0) ($1) ($20) ($65) ($68) ($85) ($93) ($95) ($94) ($92) ($114) ($134) ($135) ($23) ($28) ($12) ($30) ($26) ($36)
High Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($954) $0 $0 $1 ($19) ($115) ($122) ($99) ($101) ($107) ($105) ($106) ($125) ($138) ($153) ($110) ($120) ($171) ($165) ($237) ($249) Change in Emissions ($21) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($6) ($4) ($6) ($10) ($10) ($14) ($17) Change in VOM ($18) $0 $0 $0 ($0) ($3) ($3) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($3) ($3) ($4) ($4) Change in DSM ($55) $0 ($1) ($1) ($2) ($2) ($2) ($3) ($6) ($7) ($7) ($8) ($9) ($9) ($10) ($10) ($10) ($11) ($12) ($13) ($14) Change in Deficiency ($13) $0 $0 $0 $0 $1 $0 $0 $1 $0 $0 $0 $1 $0 ($1) ($3) ($2) ($15) ($19) ($3) ($5) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($383) $0 $0 ($0) ($0) ($3) ($3) ($48) ($52) ($53) ($54) ($55) ($56) ($63) ($76) ($138) ($129) ($62) ($83) ($27) ($25) Net (Benefit)/Cost ($603) $0 ($0) ($1) ($20) ($65) ($68) ($91) ($97) ($100) ($100) ($98) ($119) ($135) ($142) ($30) ($26) ($23) ($38) ($38) ($50)
High Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 Cost of Project $840 $0 $0 $0 $1 $57 $61 $61 $63 $68 $68 $72 $72 $77 $106 $237 $243 $248 $253 $259 $264 Change in NPC ($955) $0 $0 $1 ($19) ($112) ($119) ($75) ($75) ($79) ($77) ($76) ($93) ($121) ($151) ($208) ($202) ($183) ($211) ($275) ($279) Change in Emissions ($101) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($7) ($14) ($18) ($23) ($23) ($17) ($34) ($35) ($40) ($43) ($44) Change in VOM ($19) $0 $0 $0 ($0) ($3) ($3) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($2) ($4) ($4) ($3) ($4) ($5) ($5) Change in DSM ($44) $0 ($1) ($1) ($1) ($1) ($1) ($4) ($5) ($5) ($5) ($6) ($7) ($7) ($7) ($8) ($8) ($9) ($10) ($10) ($12) Change in Deficiency ($9) $0 $0 $0 $0 $1 $0 ($0) $1 $0 ($0) ($0) $0 $0 ($0) ($2) ($2) ($16) ($4) ($3) ($7) Change in PTC losses (dumped energy) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0$0$0$0$0$0$0 Change in System Fixed Cost ($406) $0 $0 ($0) ($0) ($7) ($7) ($84) ($89) ($91) ($93) ($95) ($97) ($77) ($74) ($44) ($23) ($49) ($41) $17 $13 Net (Benefit)/Cost ($694) $0 ($0) ($1) ($20) ($66) ($68) ($103) ($107) ($109) ($116) ($120) ($143) ($153) ($152) ($46) ($30) ($47) ($56) ($59) ($70) Exh. RTL-7 Docket UE-19____ Witness: Rick T. Link
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Docket UE-19____ Complainant, v.
PACIFICORP dba PACIFIC POWER & LIGHT COMPANY
Respondent.
PACIFICORP
EXHIBIT OF RICK T. LINK
Combined Projects Nominal Revenue Requirement PVRR(d) (Benefit)/Cost, February 2018
December 2019 Exhibit No. RTL-7
Estimated Annual Revenue Requirement Results ($ million)
Low Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245) $0
System Impacts NPC ($1,069) $0 $0 $1 ($12) ($89) ($90) ($92) ($90) ($94) ($92) ($92) ($105) ($109) ($116) ($119) ($121) ($127) ($137) ($124) ($121) ($133) ($136) ($139) ($143) ($121) ($124) ($127) ($130) ($133) ($136) ($139) ($142) ($145) ($148) Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Variable Costs ($198) $0 ($1) ($2) ($3) ($7) ($8) ($10) ($13) ($15) ($18) ($19) ($20) ($21) ($23) ($25) ($24) ($24) ($30) ($30) ($34) ($28) ($28) ($29) ($30) ($25) ($26) ($27) ($27) ($28) ($28) ($29) ($30) ($30) ($31) System Fixed Costs ($166) $0 $0 $0 ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($19) ($19) ($19) ($35) ($22) ($11) ($55) ($57) ($28) ($29) ($29) ($30) ($26) ($26) ($27) ($28) ($28) ($29) ($29) ($30) ($31) ($31) Net System Impacts ($1,432) $0 ($0) ($1) ($16) ($99) ($101) ($106) ($110) ($116) ($116) ($118) ($132) ($149) ($159) ($163) ($180) ($172) ($178) ($209) ($212) ($189) ($194) ($198) ($203) ($173) ($176) ($180) ($185) ($188) ($193) ($197) ($202) ($206) ($210)
Net (Benefit)/Cost $184 $0 ($0) ($1) $6 $71 $54 $33 $16 $4 ($7) ($12) ($35) ($55) ($43) $78 $59 $65 $56 $24 $20 $41 $36 $31 $25 $43 $39 $36 $32 $30 $28 $29 $32 $28 ($455)
Low Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245)
System Impacts NPC ($1,061) $0 $0 $1 ($13) ($90) ($90) ($93) ($92) ($96) ($94) ($94) ($107) ($111) ($118) ($120) ($121) ($121) ($119) ($119) ($110) ($130) ($133) ($136) ($140) ($119) ($122) ($124) ($128) ($130) ($133) ($136) ($139) ($142) ($145) Emissions ($66) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($12) ($14) ($16) ($17) ($19) ($17) ($19) ($13) ($13) ($13) ($14) ($12) ($12) ($12) ($13) ($13) ($13) ($13) ($14) ($14) ($14) Other Variable Costs ($178) $0 $0 ($1) ($3) ($6) ($7) ($8) ($11) ($12) ($14) ($15) ($15) ($18) ($21) ($23) ($26) ($25) ($32) ($26) ($30) ($26) ($27) ($27) ($28) ($24) ($24) ($25) ($25) ($26) ($27) ($27) ($28) ($28) ($29) System Fixed Costs ($183) $0 ($0) ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($19) ($19) ($19) ($13) ($26) ($64) ($49) ($63) ($32) ($32) ($33) ($34) ($29) ($29) ($30) ($31) ($31) ($32) ($33) ($34) ($34) ($35) Net System Impacts ($1,488) $0 ($0) ($1) ($16) ($98) ($100) ($105) ($109) ($115) ($115) ($116) ($130) ($148) ($171) ($176) ($176) ($190) ($234) ($211) ($222) ($201) ($206) ($210) ($215) ($183) ($187) ($191) ($196) ($200) ($204) ($209) ($215) ($218) ($223)
Net (Benefit)/Cost $127 $0 ($0) ($1) $6 $71 $54 $34 $17 $5 ($6) ($10) ($33) ($54) ($55) $66 $63 $47 $0 $22 $10 $29 $24 $18 $13 $32 $28 $24 $20 $18 $16 $16 $20 $16 ($468)
Low Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245)
System Impacts NPC ($1,149) $0 $1 $1 ($13) ($90) ($90) ($93) ($92) ($97) ($99) ($102) ($120) ($125) ($131) ($133) ($133) ($134) ($131) ($136) ($137) ($147) ($150) ($153) ($157) ($134) ($137) ($140) ($143) ($146) ($149) ($152) ($156) ($159) ($163) Emissions ($279) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($11) ($22) ($30) ($37) ($46) ($48) ($51) ($52) ($54) ($52) ($52) ($51) ($52) ($54) ($55) ($47) ($48) ($49) ($50) ($51) ($52) ($53) ($55) ($56) ($57) Other Variable Costs ($149) $0 ($2) ($3) ($3) ($5) ($7) ($9) ($10) ($10) ($11) ($11) ($12) ($14) ($18) ($19) ($19) ($22) ($24) ($21) ($25) ($21) ($22) ($22) ($23) ($19) ($20) ($20) ($21) ($21) ($21) ($22) ($22) ($23) ($23) System Fixed Costs ($185) $0 $0 ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($21) ($21) ($21) ($21) ($21) ($57) ($55) ($56) ($32) ($33) ($33) ($34) ($29) ($30) ($30) ($31) ($32) ($33) ($33) ($34) ($35) ($36) Net System Impacts ($1,762) $0 ($1) ($1) ($16) ($98) ($100) ($106) ($109) ($114) ($128) ($141) ($168) ($197) ($217) ($221) ($224) ($229) ($267) ($264) ($271) ($251) ($256) ($262) ($269) ($229) ($234) ($239) ($245) ($250) ($255) ($261) ($268) ($272) ($279)
Net (Benefit)/Cost ($147) $0 ($1) ($1) $6 $71 $54 $33 $18 $6 ($18) ($35) ($72) ($103) ($101) $21 $15 $8 ($32) ($32) ($39) ($21) ($27) ($34) ($41) ($13) ($18) ($23) ($29) ($31) ($34) ($35) ($33) ($38) ($523)
OFPC Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245)
System Impacts NPC ($1,366) $0 $1 $2 ($12) ($94) ($96) ($97) ($101) ($114) ($112) ($114) ($133) ($143) ($156) ($166) ($169) ($178) ($200) ($184) ($149) ($182) ($186) ($190) ($195) ($166) ($169) ($173) ($178) ($181) ($185) ($189) ($194) ($198) ($202) Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Variable Costs ($152) $0 ($2) ($3) ($4) ($6) ($8) ($10) ($11) ($11) ($12) ($12) ($13) ($15) ($17) ($19) ($21) ($19) ($24) ($18) ($22) ($20) ($21) ($21) ($22) ($19) ($19) ($19) ($20) ($20) ($21) ($21) ($22) ($22) ($23)
System Fixed Costs ($190) $0 $0 ($0) ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($21) ($21) ($21) ($19) ($24) ($7) ($63) ($115) ($33) ($34) ($34) ($35) ($30) ($31) ($31) ($32) ($33) ($33) ($34) ($35) ($36) ($37) Exhibit Net System Impacts ($1,708) $0 ($1) ($1) ($17) ($103) ($107) ($110) ($119) ($132) ($131) ($133) ($153) ($178) ($194) ($206) ($209) ($221) ($231) ($264) ($286) ($235) ($241) ($246) ($252) ($214) ($219) ($224) ($230) ($234) ($239) ($245) ($251) ($256) ($261) Page
Net (Benefit)/Cost ($92) $0 ($1) ($1) $5 $66 $48 $29 $8 ($12) ($21) ($27) ($56) ($84) ($78) $35 $30 $15 $4 ($32) ($55) ($5) ($11) ($17) ($24) $1 ($4) ($8) ($13) ($16) ($18) ($19) ($17) ($22) ($506)
Medium Natural Gas, Medium CO2 Price-Policy Scenario RTL-7 1 (Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs of Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) 3 Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) Exhibit No. RTL-7
Estimated Annual Revenue Requirement Results ($ million) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245)
System Impacts NPC ($1,249) $0 $0 $1 ($13) ($95) ($97) ($99) ($104) ($117) ($114) ($115) ($135) ($144) ($162) ($171) ($175) ($176) ($177) ($74) ($3) ($157) ($161) ($164) ($168) ($143) ($146) ($150) ($154) ($156) ($160) ($163) ($168) ($171) ($175) Emissions ($33) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($9) ($8) ($9) ($10) ($11) ($5) ($2) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($7) ($7) ($7) ($7) ($7) Other Variable Costs ($115) $0 ($1) ($1) ($2) ($4) ($6) ($6) ($7) ($7) ($9) ($10) ($11) ($13) ($15) ($17) ($19) ($14) ($17) ($14) ($12) ($16) ($17) ($17) ($17) ($15) ($15) ($15) ($16) ($16) ($16) ($17) ($17) ($18) ($18) System Fixed Costs ($385) $0 $0 $0 ($0) ($3) ($3) ($4) ($7) ($7) ($7) ($7) ($7) ($22) ($22) ($22) ($22) ($39) ($45) ($202) ($299) ($71) ($72) ($74) ($76) ($65) ($66) ($67) ($69) ($71) ($72) ($74) ($76) ($77) ($79) Net System Impacts ($1,782) $0 ($0) ($1) ($16) ($103) ($106) ($109) ($118) ($132) ($130) ($133) ($153) ($179) ($207) ($218) ($226) ($238) ($250) ($295) ($316) ($251) ($256) ($262) ($269) ($229) ($234) ($239) ($245) ($249) ($255) ($261) ($268) ($272) ($278)
Net (Benefit)/Cost ($167) $0 ($0) ($1) $6 $67 $48 $30 $8 ($12) ($20) ($27) ($56) ($85) ($91) $23 $13 ($1) ($16) ($63) ($85) ($20) ($27) ($33) ($41) ($13) ($18) ($23) ($28) ($31) ($34) ($35) ($33) ($38) ($523) Exhibit Page RTL-7 2 of 3 Exhibit No. RTL-7
Estimated Annual Revenue Requirement Results ($ million)
Medium Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
System Impacts NPC ($1,146) $0 $0 $1 ($13) ($85) ($86) ($88) ($92) ($104) ($101) ($101) ($119) ($129) ($144) ($154) ($169) ($80) ($82) ($147) ($148) ($147) ($150) ($153) ($157) ($134) ($137) ($140) ($143) ($146) ($149) ($153) ($157) ($159) ($163) Emissions ($200) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($10) ($20) ($29) ($35) ($38) ($36) ($42) ($21) ($22) ($32) ($34) ($36) ($37) ($38) ($39) ($33) ($34) ($35) ($35) ($36) ($37) ($38) ($39) ($39) ($40) Other Variable Costs ($122) $0 ($1) ($1) ($2) ($5) ($6) ($6) ($7) ($8) ($9) ($10) ($10) ($13) ($16) ($16) ($16) ($16) ($17) ($18) ($24) ($17) ($18) ($18) ($19) ($16) ($16) ($17) ($17) ($17) ($18) ($18) ($19) ($19) ($19) System Fixed Costs ($451) $0 $0 $0 ($0) ($19) ($19) ($20) ($24) ($24) ($25) ($25) ($26) ($38) ($38) ($39) ($21) ($147) ($148) ($73) ($76) ($70) ($72) ($73) ($75) ($64) ($65) ($67) ($69) ($70) ($71) ($73) ($75) ($76) ($78) Net System Impacts ($1,920) $0 ($0) ($1) ($16) ($108) ($112) ($114) ($123) ($136) ($144) ($156) ($184) ($214) ($236) ($244) ($248) ($264) ($269) ($270) ($283) ($271) ($277) ($283) ($290) ($247) ($252) ($258) ($265) ($269) ($275) ($281) ($289) ($294) ($301)
Net (Benefit)/Cost ($304) $0 ($0) ($1) $6 $61 $43 $25 $4 ($17) ($35) ($50) ($88) ($120) ($120) ($3) ($9) ($27) ($35) ($38) ($51) ($40) ($47) ($54) ($62) ($31) ($37) ($42) ($48) ($51) ($54) ($56) ($55) ($60) ($545)
High Natural Gas, Zero CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245)
System Impacts NPC ($1,452) $0 $0 $1 ($19) ($115) ($122) ($113) ($118) ($123) ($122) ($122) ($143) ($159) ($173) ($154) ($109) ($176) ($152) ($227) ($214) ($184) ($189) ($193) ($198) ($168) ($172) ($176) ($180) ($184) ($188) ($192) ($197) ($200) ($205) Emissions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Variable Costs ($129) $0 ($1) ($1) ($2) ($4) ($4) ($6) ($8) ($9) ($9) ($9) ($10) ($11) ($13) ($15) ($15) ($27) ($33) ($16) ($20) ($19) ($19) ($20) ($20) ($17) ($18) ($18) ($19) ($19) ($19) ($20) ($20) ($21) ($21) System Fixed Costs ($483) $0 $0 ($0) ($0) ($3) ($3) ($27) ($30) ($31) ($32) ($32) ($33) ($41) ($55) ($92) ($147) ($57) ($99) ($41) ($67) ($77) ($79) ($80) ($83) ($70) ($72) ($73) ($75) ($77) ($78) ($80) ($82) ($84) ($86) Net System Impacts ($2,063) $0 ($0) ($1) ($22) ($122) ($129) ($146) ($157) ($163) ($162) ($164) ($186) ($211) ($241) ($261) ($271) ($260) ($284) ($284) ($300) ($281) ($287) ($293) ($301) ($256) ($261) ($267) ($274) ($279) ($285) ($292) ($299) ($305) ($311)
Net (Benefit)/Cost ($448) $0 ($0) ($1) $0 $47 $25 ($7) ($31) ($43) ($52) ($58) ($90) ($117) ($125) ($19) ($32) ($23) ($49) ($52) ($69) ($50) ($57) ($65) ($73) ($40) ($46) ($51) ($58) ($61) ($64) ($66) ($65) ($71) ($556) $0
High Natural Gas, Medium CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245)
System Impacts NPC ($1,365) $0 $0 $1 ($19) ($115) ($122) ($99) ($101) ($107) ($105) ($106) ($125) ($138) ($153) ($110) ($120) ($171) ($165) ($237) ($249) ($176) ($180) ($184) ($189) ($161) ($164) ($168) ($172) ($175) ($179) ($183) ($188) ($191) ($196) Emissions ($38) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($6) ($4) ($6) ($10) ($10) ($14) ($17) ($7) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($8) ($8) ($8) ($8) ($8) Other Variable Costs ($132) $0 ($1) ($1) ($2) ($4) ($4) ($5) ($8) ($9) ($9) ($10) ($10) ($11) ($13) ($14) ($14) ($29) ($33) ($19) ($22) ($20) ($20) ($20) ($21) ($18) ($18) ($19) ($19) ($19) ($20) ($20) ($21) ($21) ($22) System Fixed Costs ($580) $0 $0 ($0) ($0) ($3) ($3) ($48) ($52) ($53) ($54) ($55) ($56) ($63) ($76) ($138) ($129) ($62) ($83) ($27) ($25) ($84) ($86) ($88) ($90) ($77) ($79) ($80) ($83) ($84) ($86) ($88) ($90) ($92) ($94) Net System Impacts ($2,115) $0 ($0) ($1) ($22) ($122) ($129) ($152) ($160) ($168) ($168) ($170) ($191) ($213) ($248) ($267) ($269) ($271) ($291) ($297) ($314) ($288) ($294) ($301) ($308) ($262) ($268) ($274) ($281) ($286) ($293) ($299) ($307) ($312) ($319)
Net (Benefit)/Cost ($499) $0 ($0) ($1) $0 $47 $25 ($13) ($34) ($49) ($58) ($65) ($94) ($119) ($132) ($26) ($30) ($35) ($57) ($64) ($83) ($57) ($65) ($72) ($80) ($46) ($52) ($58) ($65) ($68) ($72) ($74) ($73) ($78) ($564)
High Natural Gas, High CO2 Price-Policy Scenario
(Benefit)/Cost PVRR(d) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Project Net Costs Transmission Project Capital Recovery $602 $0 $0 $0 $12 $79 $77 $75 $73 $71 $69 $67 $65 $63 $62 $60 $58 $56 $54 $53 $51 $50 $50 $49 $48 $47 $46 $45 $44 $43 $42 $41 $40 $39 $38 Incremental Transmission Revenues ($72) $0 $0 $0 ($1) ($9) ($9) ($9) ($9) ($8) ($8) ($8) ($8) ($8) ($7) ($7) ($7) ($7) ($7) ($6) ($6) ($6) ($6) ($6) ($6) ($6) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) ($5) Capital Recovery - Wind $1,220 $0 $0 $0 $28 $182 $169 $160 $152 $145 $140 $136 $132 $128 $125 $121 $117 $113 $109 $105 $101 $97 $94 $90 $86 $82 $78 $74 $71 $67 $63 $59 $55 $51 $44 Network - Wind $83 $0 $0 $0 $2 $11 $11 $10 $10 $10 $10 $9 $9 $9 $9 $8 $8 $8 $7 $7 $7 $7 $7 $7 $6 $6 $6 $6 $6 $6 $6 $5 $5 $5 $5 O&M - Wind $492 $0 $0 $0 $5 $24 $25 $26 $29 $30 $32 $34 $36 $39 $43 $48 $51 $54 $58 $62 $66 $69 $73 $77 $82 $86 $91 $96 $102 $108 $115 $125 $138 $143 $84 Terminal Wind ($42) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ($411) PTCs - Wind ($767) $0 $0 $0 ($23) ($130) ($130) ($135) ($141) ($140) ($145) ($145) ($151) ($150) ($126) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 PPA Cost $99 $0 $0 $0 $0 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Net Project Cost $1,616 $0 $0 $0 $22 $169 $154 $139 $126 $119 $110 $106 $97 $94 $116 $241 $239 $237 $234 $232 $231 $230 $229 $229 $228 $216 $216 $216 $217 $218 $221 $226 $234 $234 ($245)
System Impacts NPC ($1,432) $0 $0 $1 ($19) ($112) ($119) ($75) ($75) ($79) ($77) ($76) ($93) ($121) ($151) ($208) ($202) ($183) ($211) ($275) ($279) ($204) ($209) ($213) ($219) ($186) ($190) ($194) ($200) ($203) ($208) ($212) ($218) ($222) ($227) Emissions ($178) $0 $0 $0 $0 $0 $0 $0 $0 $0 ($7) ($14) ($18) ($23) ($23) ($17) ($34) ($35) ($40) ($43) ($44) ($33) ($33) ($34) ($35) ($30) ($30) ($31) ($32) ($33) ($33) ($34) ($35) ($36) ($36) Other Variable Costs ($112) $0 ($1) ($1) ($2) ($4) ($4) ($5) ($6) ($7) ($7) ($8) ($8) ($9) ($10) ($14) ($14) ($27) ($18) ($18) ($24) ($17) ($17) ($17) ($18) ($15) ($16) ($16) ($16) ($17) ($17) ($17) ($18) ($18) ($19) System Fixed Costs ($530) $0 $0 ($0) ($0) ($7) ($7) ($84) ($89) ($91) ($93) ($95) ($97) ($77) ($74) ($44) ($23) ($49) ($41) $17 $13 ($53) ($54) ($56) ($57) ($48) ($50) ($51) ($52) ($53) ($54) ($55) ($57) ($58) ($59)
Net System Impacts ($2,251) $0 ($0) ($1) ($21) ($123) ($130) ($165) ($170) ($177) ($184) ($193) ($215) ($230) ($258) ($283) ($273) ($294) ($309) ($318) ($334) ($307) ($314) ($321) ($329) ($280) ($286) ($292) ($300) ($305) ($312) ($319) ($327) ($333) ($341) Exhibit Page Net (Benefit)/Cost ($635) $0 ($0) ($1) $0 $46 $25 ($25) ($44) ($57) ($74) ($87) ($118) ($136) ($142) ($42) ($34) ($58) ($75) ($86) ($103) ($77) ($84) ($92) ($101) ($64) ($70) ($76) ($83) ($87) ($91) ($93) ($93) ($99) ($586) RTL-7 3 of 3