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1407 W. North Temple, Suite 330 Salt Lake City, Utah 84116
February 7, 2018 VIA OVERNIGHT DELIVERY Diane Hanian Commission Secretary Idaho Public Utilities Commission 472 W. Washington Boise, ID 83702 Attention: Diane Hanian Commission Secretary RE: CASE NO. PAC-E-17-06
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR BINDING RATEMAKING TREATMENT FOR WIND REPOWERING
Rocky Mountain Power, in compliance with paragraph 16 of the Stipulation and Commission Order No. 33954 in the above referenced matter, is filing an original and seven (7) copies of the confidential and non-confidential Compliance filing summarizing the impact of the Tax Act on the Company’s Application, along with a CD containing the updated Exhibit Nos. 12 through 14 and the exhibit work papers. Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager, at (801) 220-2963. Very truly yours, Joelle R. Steward Vice President, Regulation Enclosures
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CERTIFICATE OF SERVICE
I hereby certify that on this 7th day of February, 2018, I caused to be served, via e-mail a true and correct copy of Rocky Mountain Power’s Compliance Filing in Case No. PAC-E-17-06 to the following:
Service List
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC. Eric L. Olsen ECHO HAWK & OLSEN, PLLC 505 Pershing Ave., Ste. 100 P.O. Box 6119 Pocatello, Idaho 83205 E-mail: [email protected]
Anthony Yankel 12700 Lake Avenue, Unit 2505 Lakewood, Ohio 44107 E-mail: [email protected]
MONSANTO COMPANY Randall C. Budge Racine, Olson, Nye & Budge, Chartered P.O. Box 1391; 201 E. Center Pocatello, Idaho 83204-1391 E-mail: [email protected]
Brubaker & Associates 16690 Swingley Ridge Rd., #140 Chesterfield, MO 63017 E-mail: [email protected] [email protected]
IDAHO INDUSTRIAL CONSUMERS Ronald L. Williams Williams Bradbury, P.C. P.O. Box 388 Boise ID, 83701 E-mail : [email protected]
Jim Duke Idahoan Foods E-mail: [email protected]
Kyle Williams BYU Idaho E-mail : [email protected]
Val Steiner Nu-West Industries, Inc. E-mail : [email protected]
Bradley Mullins 333 SW Taylor, Suite 400 Portland, OR 97204 E-mail: [email protected]
COMISSION STAFF Brandon Karpen Deputy Attorney General Idaho Public Utilities Commission 472 W. Washington (83702) PO Box 83720 Boise, ID 83720-0074 E-mail: [email protected]
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PACIFICORP, DBA ROCKY MOUNTAIN POWER Ted Weston PacifiCorp, dba Rocky Mountain Power 1407 West North Temple Suite 330 Salt Lake City, UT 84116 E-mail: [email protected]
Yvonne Hogle PacifiCorp, dba Rocky Mountain Power 1407 West North Temple Suite 320 Salt Lake City, UT 84116 E-mail: [email protected]
Data Request Response Center PacifiCorp 825 NE Multnomah, Suite 2000 Portland, OR 97232 E-mail: [email protected]
Dated this 7th day of February, 2018.
__________________________________ Katie Savarin Coordinator, Regulatory Operations
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R. Jeff Richards (#7294) Yvonne R. Hogle (#8930) 1407 West North Temple, Suite 320 Salt Lake City, Utah 84116 Telephone: (801) 220-4050 Facsimile: (801) 220-3299 Email: [email protected] [email protected]
Katherine McDowell (OR #890876) Adam Lowney (OR #053124) McDowell Rackner Gibson PC 419 SW 11th Avenue, Suite 400 Portland, OR 97205 Telephone: (503) 595-3924 Facsimile: (503) 595-3928 Email: [email protected] [email protected] Attorneys for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR BINDING RATEMAKING TREATMENT FOR
WIND REPOWERING
) CASE NO. PAC-E-17-06 ) ) COMPLIANCE FILING ) )
COMES NOW, Rocky Mountain Power, a division of PacifiCorp (“Rocky Mountain
Power” or “Company”), under Idaho Code § 61-541, and hereby respectfully makes this
compliance filing to show the impact of new federal tax law changes and other updated
assumptions, in accordance with the terms of the Stipulation between the parties to this case and
Commission Order No. 33954 approving the Stipulation. This updated economic analysis shows
the overall economics of the wind repowering project remain favorable and demonstrate a high
likelihood that repowering will provide significant customer benefits.
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BACKGROUND
1. On July 3, 2017, Rocky Mountain Power filed an Application for Binding Ratemaking
Treatment for Wind Repowering (“Application’) with the Commission. The Application requested
a Commission determination on the prudence of the Company’s plan to upgrade or “repower” most
of its wind resources, and Commission approval of the Company’s proposed ratemaking treatment
for new investment and continued rate recovery of and on the undepreciated balance of the
replaced assets associated with the wind repowering project (“Project”).
2. The Company’s original cost estimate for the Project was approximately $1.13 billion.
Because of the magnitude of this capital investment and the overall scope of the Project, the
Company requested Commission approval before the Company completed equipment orders and
began construction. The Application provided the Commission and interested parties a meaningful
opportunity to evaluate the prudence of the Project to ensure that it is reasonable, prudent, and in
the public interest.
3. To work toward resolving the issues raised in the Application, the Parties met on
October 19, 2017, under IDAPA 31.01.01.271 and .272, to engage in settlement discussions. Based
upon these settlement discussions, as a compromise of the Parties’ positions in this proceeding,
and for other good and valuable consideration, the Parties reached a comprehensive settlement
agreement. The Stipulation resolved all outstanding issues in the case, and the Parties believed the
Stipulation is in the public interest. On December 28, 2017, the Commission issued Order No.
33954 approving the Stipulation as filed.
4. Paragraph 16 of the Stipulation specified: “If there is a material change in circumstance,
such as changes to federal tax laws, change in the projected costs or benefits, or for some other
reason, the Parties agree that the Company will make a filing with the Commission to allow for
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additional review and a determination of whether the Company should proceed with the
implementation of the wind repowering project under the terms and conditions of this Stipulation."
5. In accordance with Paragraph 16 of the Stipulation and Order No. 33954, the Company
has prepared an updated economic analysis to account for changes in the federal corporate income
tax rate, updated market prices for natural gas and carbon dioxide, and update cost and
performance information. Each of these updates are described below.
TAX ACT
6. In December 2017, U.S. Congress passed, and the President signed, H.R. 1 (“Tax Act”),
which included significant federal income tax reforms. The passage of the Tax Act resolved any
uncertainty regarding risk that federal tax reform posed to the Project. The Tax Act set a new
corporate income tax rate of 21 percent. It also confirmed the continued availability of Production
Tax Credits (“PTCs”) for the Project, from which much of the economic benefit is derived. The
impacts of the Tax Act are now known and have been incorporated in the updated economic
analysis of the Project.
7. The reduction in the corporate income tax rate does not directly impact the value of the
PTCs. It does, however, impact the tax gross-up value of the PTCs to customers. There are two
other impacts associated with the reduction in the corporate income tax rate: (1) a reduction to the
corporate income tax rate reduces the tax gross-up, lowering the Company’s overall rate of return
on the Project, and; (2) the lower tax rate reduces the accumulated deferred income tax liability
related to the use of Modified Accelerated Cost Recovery System (“MACRS”) accelerated
depreciation for the five-year tax life of the repowered wind facilities, which will increase the net
rate-base balance. Bonus depreciation rules have also changed. Under prior income tax law,
repowered wind projects placed in service in 2019 by the Company would have received 30
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percent bonus depreciation. Repowered wind projects placed in service in 2020 would have
received no bonus depreciation. The Tax Act generally provides that regulated utilities such as the
Company will not be allowed to use bonus depreciation on projects placed in service after
September 27, 2017. The Project remains subject to the five-year MACRS accelerated
depreciation. The impacts of the reduction in the corporate income tax rate and the elimination of
bonus deprecation for regulated utilities has been fully reflected in the updated economic analysis.
PROJECT UPDATES
8. Since filing its Application July 3, 2017, the Company has continued to make progress
on the wind repowering project by completing technical studies and contracting. The Company
has: (1) updated its energy production estimates to reflect recent project-specific changes and
additional available data, with only a small net change in production; (2) confirmed the need and
scope of required facility retrofits, with project costs decreasing 1.6 percent from the Application;
and (3) completed significant permitting requirements for 11 of the 12 facilities. The Company
remains confident that it can qualify for the PTCs, and deliver the repowering project on-time at
or below the current cost estimates reflected in the updated economic analysis. The Company has
completed negotiations of a master retrofit contract with General Electric (“GE”) and a turbine
supply contract with Vestas. The negotiated contract provisions reduce the initial estimated cost of
the repowering project, increase the generation output, and reduce or eliminate various project
risks. In addition, the Company has now completed most of its siting and permitting work, clearing
this important project hurdle.
9. The Vestas turbine supply contract has fixed pricing with no adjustment mechanisms
for common price indexes for turbines ordered before . Generally, the turbine
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suppliers can only seek a change order for price relief as a result of changes in state and/or local
laws that impacts their costs.
10. The master retrofit contract commits GE to perform turn-key supply, delivery,
installation and commissioning of the repowering turbines at a fixed price. The negotiated contract
reduces the pricing for those wind facilities that will be repowered using GE turbines. The GE
retrofit contract also provides an off-ramp if the Company does not obtain regulatory approval for
the repowering project or any approval that includes conditions that present a material concern to
the Company in moving forward with the repowering project.
11. GE was developing a 91-meter rotor for repowering at wind facilities, like the
Company’s, that currently have GE 1.5-77 SLE turbines installed. GE finished developing this
rotor and has completed the engineering and design review on a turbine, which the
Company can use to repower its . The nameplate capacity of the generator
of this turbine is megawatts greater than the turbine previously specified. GE has
completed a mechanical loads analysis for the new turbine type at each of the Company’s
sites. The nacelles the Company acquired from GE in December 2016 can
be operated as a turbine. The mechanical loads analysis is an engineering study to assess
the site-specific climatic conditions and turbine loading to verify that the turbine is suitable for use
at the facility site with the existing towers. Black & Veatch reviewed the new foundation loading
at each facility site and determined that the existing foundations at the facilities can support the
new turbines.
12. The increase in rotor diameter allows the wind turbine to capture additional wind
energy, while the higher nameplate capacity allows the turbine to convert more of that available
wind energy into electrical energy at higher wind speeds. Previously the Company expected the
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generation output of the wind facilities to be fitted with GE wind turbines to increase by
13.3 percent. The new GE wind turbine results in an increase of 22.4 percent.
13. The repowering project is estimated to result in an additional 738 gigawatt-hours
(“GWh”) of energy annually, or an overall increase of 25.7 percent. This compares to the 551 GWh
and 19.2 percent increase in energy output estimated previously in the Company’s Application.
14. The Company has also negotiated a
.
15.
.
16. The Company’s updated economic analysis reflects higher operations and maintenance
costs for and reduced capital expenditures at the projects . Capital
expenditures are reduced for the
.
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All of the costs associated with these changes are reflected in the updated economic analysis
provided with this Compliance filing.
17. Site-specific turbine design and foundation analyses have now been completed for the
Goodnoe Hills and Leaning Juniper facilities. When the Company’s direct testimony was filed,
site-specific foundation load specifications for these facilities were not yet available and the
Company had not yet verified that the foundations at these facilities were suitable for the specified
repowering turbines. Black & Veatch, Inc., has now evaluated the foundations at the Leaning
Juniper and Goodnoe Hills facilities and determined that the foundations will be suitable for the
repowered turbines following a standard retrofit that will add strength to these foundations. This
strengthening will allow the foundations to resist the loads of the larger turbines for an additional
30-year service life following repowering, similar to all the other facilities previously evaluated.
18. Project capital costs have decreased by $27 million—or approximately 2.4 percent—
to $1.10 billion.
UPDATED ECONOMIC ANALYSIS
19. The Project’s economic analysis was updated to reflect more current assumptions
including: (1) cost estimates consistent with findings from technical review studies cost-and-
performance assumptions described above; (2) current price-policy scenario assumptions,
including more current natural gas and CO2 prices; and (3) recent changes in the federal tax rate
for corporations.
20. In the updated analysis the Company applied PTC benefits on a nominal basis rather
than on a levelized basis. This approach better reflects how the federal PTC benefits for the
repowered assets will flow through to customers and aligns the treatment of federal PTC benefits
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in the system modeling results extending out through 2036 with the nominal revenue requirement
results extending out through 2050.
21. Table 1 summarizes the PVRR(d) results for each wind facility within the scope of the
wind repowering project when applying medium natural gas and medium CO2 price-policy
assumptions. The PVRR(d) between cases with and without wind repowering are shown for each
wind facility based on system modeling results from the SO model and for PaR, before accounting
for the substantial increase in incremental energy beyond the 2036 time frame. When applying
medium natural gas and medium CO2 price-policy assumptions, benefits from repowering the
Leaning Juniper wind facility are equal to costs. All other wind facilities are projected to deliver
net benefits.
Table 1 - Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Medium Natural Gas
And Medium CO2 Price-Policy Assumptions ($ million)
Wind Facility SO Model PVRR(d)
PaR Stochastic-Mean PVRR(d)
PaR Risk-Adjusted 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) ($189)
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22. Table 2 summarizes the PVRR(d) results for each wind facility within the scope of the
wind repowering project when applying low natural gas and zero CO2 price-policy assumptions.
The PVRR(d) between cases with and without wind repowering are shown for each wind facility
based on system modeling results from the SO model and for PaR, before accounting for the
substantial increase in incremental energy beyond the 2036 time frame. When applying low natural
gas and zero CO2 price-policy assumptions, costs from repowering the Leaning Juniper wind
facility are slightly higher than the benefits. All other wind facilities are projected to deliver net
benefits.
Table 2 - Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Low Natural Gas and Zero CO2 Price-
Policy Assumptions ($ million)
Wind Facility SO Model PVRR(d)
PaR Stochastic-Mean PVRR(d)
PaR Risk-Adjusted 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) ($156)
23. Table 3 summarizes the PVRR(d) results for each wind facility calculated off of the
change in annual nominal revenue requirement through 2050 for both price-policy scenarios.
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Unlike the results summarized in Tables 1 and 2, these results account for the substantial increase
in incremental energy beyond the 2036 time frame. Each of the wind facilities within the scope of
the proposed repowering project show net benefits with repowering under the medium natural gas
and medium CO2 price-policy scenario and all facilities show net benefits under the low natural
gas and zero CO2 price-policy scenario, except for the Leaning Juniper wind facility, where the
benefits are equal to the costs.
Table 3 - Project-by-Project Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind Repowering ($ million)
Wind Facility Medium Natural Gas
and Medium CO2 Low Natural Gas
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 ($75) ($46)
Marengo 2 ($20) ($7)
Goodnoe Hills ($26) ($19)
Total ($306) ($194)
24. A reasonable metric to evaluate the relative benefits among the wind facilities that
captures the specific attributes of each facility is the nominal levelized net benefit per incremental
MWh expected after the facility is repowered. This metric captures the specific repowering cost
for each facility net of the specific benefits of each facility per incremental MWh of energy
expected after the facility is repowered. Table 4 shows the nominal levelized net benefit of
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repowering per MWh of expected incremental energy output after repowering for each wind
facility. When using medium natural gas and medium CO2 price-policy assumptions, the table
shows the Marengo I facility produces the largest net benefit per incremental MWh ($37/MWh),
and Leaning Juniper produces the smallest net benefit per incremental MWh ($7/MWh).
Table 4 - Nominal Levelized Net Benefit per MWh of Incremental Energy Output after Repowering ($/MWh)
Wind Facility Medium Natural Gas
and Medium CO2 Low Natural Gas
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 $37/MWh $23/MWh
Marengo 2 $21/MWh $8/MWh
Goodnoe Hills $26/MWh $18/MWh
Weighted Average $25/MWh $16/MWh
25. Table 5 summarizes the updated PVRR(d) results for each price-policy scenario for the
full scope of the wind repowering project. The PVRR(d) between cases with and without the
repowering project, are shown for the SO model and for PaR, which was used to calculate both
the stochastic-mean PVRR(d) and the risk-adjusted PVRR(d).
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Table 5 - Updated SO Model and PaR PVRR(d) (Benefit)/Cost of the Wind Repowering Projects ($ million)
Price-Policy Scenario SO Model PVRR(d)
PaR Stochastic-Mean PVRR(d)
PaR Risk-Adjusted 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)
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)
26. Over a 20-year period, the wind repowering project reduces customer costs in all nine
price-policy scenarios. This outcome is consistent in both the SO model and PaR results. Under
the central price-policy scenario, assuming medium natural-gas prices and medium CO2 prices,
the PVRR(d) net benefits range between $180 million, when derived from PaR stochastic-mean
results, and $204 million, when derived from SO model results. These benefits are higher than
those originally described in the Company’s Application (between $13 million to $22 million).
This change is influenced by the fact that the updated analysis reflects nominal federal PTC
benefits, whereas the analysis summarized in the Application reflects levelized federal PTC
benefits.
27. Consistent with the results in the Company’s Application, the PVRR(d) results
presented in Table 5 do not reflect the potential value of RECs generated by the incremental energy
output from the repowered facilities. Accounting for the updated performance estimates discussed
above, customer benefits for all price-policy scenarios would improve by approximately $6 million
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for every dollar assigned to the incremental RECs that will be generated from the repowered
facilities through 2036. Quantifying the potential upside associated with incremental REC
revenues is intended to simply communicate that the net benefits from the repowering project
could improve if the incremental RECs can be monetized in the market.
28. The CO2 price assumptions used in the updated economic analysis were inadvertently
modeled in 2012 real dollars instead of nominal dollars. Consequently, the PVRR(d) net benefits
in the six price-policy scenarios that use medium and high CO2 price assumptions are conservative.
29. Table 6 summarizes the updated PVRR(d) results for each price-policy scenario
calculated using the change in annual nominal revenue requirement through 2050.
Table 6 - Updated Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of the Wind Repowering Project ($ million)
Price-Policy Scenario Updated Annual Revenue
Requirement PVRR(d) Filed Annual Revenue
Requirement PVRR(d)
Low Gas, Zero CO2 ($127) ($41)
Low Gas, Medium CO2 ($121) ($245)
Low Gas, High CO2 ($223) ($344)
Medium Gas, Zero CO2 ($224) ($362)
Medium Gas, Medium CO2 ($273) ($359)
Medium Gas, High CO2 ($321) ($401)
High Gas, Zero CO2 ($389) ($400)
High Gas, Medium CO2 ($386) ($274)
High Gas, High CO2 ($466) ($589)
30. When system costs and benefits from the wind repowering project are extended
through 2050, covering the full depreciable life of the repowered wind facilities, the wind
repowering project customer benefits increase in all nine price-policy scenarios. Customer
benefits range from $121 million in the low natural gas and medium CO2 price-policy scenario to
$466 million in the high natural gas and high CO2 price-policy scenario, compared to a range of
$41 million to $589 million in the Application. Under the central price-policy scenario, assuming
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medium natural-gas prices and medium CO2 prices, the PVRR(d) benefits of the wind
repowering project are $273 million. While changes in federal tax law have reduced net benefits
relative to the economic analysis from the Application, the wind repowering project continues to
provide significant customer benefits in all price-policy scenarios. The updated economic
analysis reconfirms that upside benefits outweigh downside risks.
ESTIMATED RATE IMPACT
31. Provided as attachments to this compliance filing are updated Exhibit Nos. 12-14
showing the estimated Idaho revenue requirement revised with the updated economic analysis
incorporating the changes described above. The exhibits are in the same format as the Application,
and calculate the monthly and annual revenue requirements and the overall impact of the wind
repowering projects that would be reflected in rates, assuming operation of the RTM.
32. These exhibits include changes in Idaho’s allocated share of the updated repowering
projects’ wind construction cost, return, depreciation, PTCs, taxes, and operating costs and
benefits. The updated net power cost changes associated with an updated load forecast, system
dispatch and revised wind generation projections have been included in the Energy Cost
Adjustment Mechanism (“ECAM”) pass-through calculation. Table 7 summarizes the estimated
repowering revenue requirement found in the updated exhibits. It shows that the repowering
project now reflects rate benefits to customers beginning in 2022. As a result of the cap proposed
for the RTM in this proceeding, customers would see no net change in rates for the repowering
project for costs through 2021, absent a general rate case.
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Table 7
33. Due to the Tax Act the Company’s consolidated federal and state income tax rate has
changed from the 37.951 percent used in the Application to 24.587 percent and updated in Exhibit
No. 14 line 5. This changes the PTC tax gross-up factor which has been updated from 1.6116 to
1.3260 on line 6 of Exhibit No. 14. These changes are incorporated in the revenue requirement
results shown in Exhibit Nos. 12 and 13.
34. The updated rate impact estimate shows there would be no net rate change for
customers, absent a general rate case, with the RTM through 2021 as a result of the cap proposed
by the Company in its Application. Without the cap, the RTM would show a net increase to
customers of $0.1 million in 2019, $1.3 million in 2020, and $0.5 million in 2021, with a net
decrease thereafter.
35. The Company is not proposing changes to the RTM for the repowering project.
However, in light of the changes in the near-term rate impacts due to tax reform, the Company
proposes to separately defer the net costs in excess of the cap associated with the Tax Act changes,
and seek recovery through an offset to the deferral for the impacts from the Tax Act.
36. The Company believes this is reasonable because the impact of the Tax Act is beyond
the Company’s control and the economic analysis shows that the Project remains beneficial to
customers in all price-policy scenarios, even after taking into account the reduction in value in the
2019 2020 2021 20221 Total Company Rev. Req. 2,272$ 21,722$ 8,915$ (1,997)$ 2 Idaho Allocated 137$ 1,290$ 518$ (137)$ 3 Idaho ECAM (1,495)$ (6,628)$ (7,918)$ (7,966)$ 4 Idaho Deferral 1,495$ 6,628$ 7,918$ 7,829$ 5 Net Customer Benefit -$ -$ -$ (137)$
Repowering Estimated Revenue Requirement Cost (Benefit) $thousands
Page 16
PTCs due to Tax Act. The Company continues to be committed to smoothing rate impacts and
minimizing the number of general rate cases. The RTM and the cap proposed by the Company for
repowering remain an integral part of this effort. In light of the potential near-term impacts from
the reduction the PTC value it is reasonable to offset the costs in excess of the cap that are related
to tax law changes against the expected savings for overall Tax Act impacts. Customers would
continue to see no net rate change for the repowering project, and the Company would be able to
continue to align rate pressures into one general rate case without adverse consequences.
CONCLUSION
37. The updated economic analysis continues to show significant net customer benefits in
all of the scenarios analyzed. The repowering project will replace equipment at existing wind
facilities with modern technology to improve efficiency, increase energy production, extend the
operational life, reduce run-rate operating costs, reduce net power costs, and deliver substantial
federal PTC benefits that will be passed on to customers. The Company continues to believe that
proposed wind repowering project and the terms of the Stipulation, as approved, are in the public
interest.
Respectfully submitted this 7th day of February, 2018.
____________________________________ Jeff Richards Yvonne R. Hogle 1407 West North Temple, Suite 320 Salt Lake City, Utah 84116 Telephone: (801) 220-4050 Facsimile: (801) 220-3299 Email: [email protected] Attorneys for Rocky Mountain Power
Case No. PAC-E-17-06 Exhibit No. 12
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
____________________________________________
Updated Exhibit Accompanying Compliance Filing
February 2018
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5)
(2
3,03
9)
S
G6.
0136
%(1
,386
)
(57,
750)
S
G6.
0136
%(3
,473
)
(94,
590)
SG
6.01
36%
(5,6
88)
3
Acc
umul
ated
DIT
Bal
ance
Foo
tnot
e 1
(5,8
94)
S
G6.
0136
%(3
54)
(73,
468)
SG
6.01
36%
(4,4
18)
(1
39,7
45)
SG
6.01
36%
(8,4
04)
(1
78,0
68)
SG
6.01
36%
(10,
708)
4
Net
Rat
e B
ase
sum
of l
ines
1-3
160,
407
9,64
6
871,
206
52,3
91
906,
123
54,4
91
833,
587
50,1
29
5
Pre
-Tax
Rat
e of
Ret
urn
line
379.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%6
P
re-T
ax R
etur
n on
Rat
e B
ase
line
4 *
line
514
,812
89
1
80
,447
4,
838
83
,671
5,
032
76
,973
4,
629
7
Who
lesa
le W
heel
ing
Rev
enue
Foo
tnot
e 4
-
SG
6.01
36%
-
-
SG
6.01
36%
-
-
S
G6.
0136
%-
-
SG
6.01
36%
-
8
O
pera
tion
& M
aint
enan
ceF
ootn
ote
33,
876
SG
6.01
36%
233
12,1
37
SG
6.01
36%
730
12,7
79
SG
6.01
36%
768
9,61
5
S
G6.
0136
%57
8
9
D
epre
ciat
ion
Foo
tnot
e 3
& 6
8,26
0
S
G6.
0136
%49
7
32
,635
S
G6.
0136
%1,
963
36
,799
S
G6.
0136
%2,
213
36
,896
S
G6.
0136
%2,
219
10
P
rope
rty
Tax
esF
ootn
ote
3-
G
PS
5.79
78%
-
7,
431
G
PS
5.79
78%
431
8,22
9
G
PS
5.79
78%
477
7,96
3
G
PS
5.79
78%
462
11
Win
d T
axF
ootn
ote
398
S
G6.
0136
%6
33
8
S
G6.
0136
%20
41
9
SG
6.01
36%
25
419
SG
6.01
36%
25
12
To
tal P
lan
t R
even
ue
Req
uir
emen
tsu
m o
f lin
es 6
-11
27,0
4 5
1,
626
132,
987
7,
981
141,
896
8,51
5
13
1,86
5
7,91
3
Net
Po
wer
Co
st13
N
PC
Incr
emen
tal S
avin
gsF
ootn
ote
395
2
SG
6.01
36%
57
(10,
446)
SG
6.01
36%
(628
)
(1
3,06
2)
SG
6.01
36%
(786
)
(1
3,94
3)
S
G6.
0136
%(8
38)
PT
C B
enef
it14
P
TC
Ben
efit
Foo
tnot
e 3
(19,
400)
S
G6.
0136
%(1
,167
)
(76,
031)
SG
6.01
36%
(4,5
72)
(9
0,43
5)
SG
6.01
36%
(5,4
38)
(9
0,43
5)
S
G6.
0136
%(5
,438
)
15
P
TC
Ben
efit
in B
ase
Rat
esF
ootn
ote
3-
S
G6.
0136
%-
-
S
G6.
0136
%-
-
SG
6.01
36%
-
-
S
G6.
0136
%-
16
Net
PT
Csu
m o
f lin
es 1
4 an
d 15
(19,
400)
(1
,167
)
(76,
031)
(4,5
72)
(9
0,43
5)
(5,4
38)
(9
0,43
5)
(5
,438
)
17
G
ross
- up
for
taxe
slin
e 16
* (
line
35 -
1)
(6,3
25)
(3
80)
(24,
788)
(1,4
91)
(2
9,48
5)
(1,7
73)
(2
9,48
5)
(1
,773
)
18
P
TC
Rev
enue
Req
uire
men
t(2
5,72
5)
(1,5
47)
(1
00,8
19)
(6,0
63)
(1
19,9
19)
(7,2
11)
(1
19,9
19)
(7,2
11)
19R
ev. R
equ
irem
ent
sum
of l
ines
12,
13,
18
2,27
2
137
21
,722
1,29
0
8,
915
518
(1
,997
)
(1
37)
Ad
just
men
t fo
r E
CA
M P
ass-
thro
ug
h20
P
TC
Rev
enue
Req
uire
men
tlin
e 18
(1,5
47)
(6
,063
)
(7,2
11)
(7
,211
)
21
P
erce
ntag
e in
clud
ed in
EC
AM
(10
0%)
ID E
CA
M S
harin
g %
100%
100%
100%
100%
22
EC
AM
Pas
s-th
roug
hlin
e 20
* li
ne21
(1,5
47)
(6
,063
)
(7,2
11)
(7
,211
)
23
NP
C In
crem
enta
l Sav
ings
line
1357
(6
28)
(786
)
(8
38)
24
P
erce
ntag
e in
clud
ed in
EC
AM
(90
%)
ID E
CA
M S
harin
g %
90%
90%
90%
90%
25
EC
AM
Pas
s-th
roug
hlin
e 23
* li
ne 2
452
(5
65)
(707
)
(7
55)
26R
ev. R
eqt.
aft
er E
CA
M P
ass-
thro
ug
hlin
e 19
- li
ne 2
2 -
line
251,
632
7,91
8
8,
437
7,82
9
27T
ota
l Def
erra
l - ID
Sh
are
Foo
tnot
e 5
1,49
5
6,
628
7,91
8
7,
829
28N
et C
ust
om
er B
enef
i tsu
m o
f lin
es 2
2, 2
5, 2
7-
-
-
(1
37)
Def
erra
l Bal
ance
- ID
Sh
are
29
Beg
inni
ng D
efer
ral B
alan
celin
e 33
of p
revi
ous
year
-
1,
499
7,
298
10
,435
30
Mon
thly
Def
erra
lF
ootn
ote
51,
495
6,
628
7,
918
7,
829
31
D
efer
ral C
olle
ctio
nF
ootn
ote
3-
(874
)
(4
,882
)
(9,1
28)
32
Car
ryin
g C
harg
eF
ootn
ote
33
46
10
0
11
0
33
En
din
g D
efer
ral B
alan
cesu
m o
f lin
es 2
9-32
1,49
9
7,
298
10,4
35
9,
246
34F
eder
al/S
tate
Com
bine
d T
ax R
ate
Exh
ibit
14, l
ine
524
.587
%35
Net
to G
ross
Bum
p up
Fac
tor
= (
1/(1
-tax
rat
e))
Exh
ibit
14, l
ine
61.
3260
36D
efer
red
Bal
ance
Car
ryin
g C
harg
eF
ootn
ote
21.
00%
Cas
e N
umbe
r G
NR
-U-1
6-01
, Ord
er N
o. 3
3664
37P
reta
x R
etur
nE
xhib
it 14
, lin
e 4
9.23
4%P
AC
-E-1
5-09
Cap
ital S
truc
ture
& C
ost -
Ord
ered
38P
rope
rty
Tax
Rat
eE
xhib
it 14
, lin
e 14
0.78
%P
rope
rty
Tax
Exp
ense
as
a pe
rcen
t of N
et p
lant
from
PA
C-E
-15-
09
39Id
aho
SG
Fac
tor
Exh
ibit
14, l
ine
156.
0136
%40
Idah
o G
PS
Fac
tor
Exh
ibit
14, l
ine
165.
7978
%
Foo
tnot
es:
1) C
apita
l bal
ance
s eq
ual t
he a
vera
ge o
f the
mon
thly
bal
ance
s in
Exh
ibit
13 w
ith a
one
mon
th d
elay
2) C
arry
ing
Cha
rge
(line
32)
is a
pplie
d to
ave
rage
mon
thly
def
erra
l bal
ance
s3)
Equ
als
the
sum
of e
ach
year
's m
onth
ly v
alue
s in
Exh
ibit
134)
Not
App
licab
le fo
r R
epow
erin
g5)
The
Com
pany
is p
ropo
sing
to c
ap th
e R
TM
unt
il th
e ne
xt g
ener
al r
ate
case
so
that
, afte
r ta
king
into
acc
ount
the
win
d re
pow
erin
g be
nefit
s th
at w
ill fl
ow th
roug
h th
e C
ompa
ny's
EC
AM
, it w
ill n
ot o
pera
te to
sur
char
ge c
usto
mer
s6)
As
stat
ed in
test
imon
y, a
ctua
l dep
reci
atio
n ex
pens
e w
ill b
e ad
just
ed b
y th
e im
pact
of t
he r
etire
d as
sets
unt
il th
e ne
xt d
epre
ciat
ion
stud
y
2019
Rep
ow
erin
g
2020
Rep
ow
erin
g
2021
Rep
ow
erin
g
2022
Rep
ow
erin
g
Rocky Mountain Power Exhibit 12 Page 1 of 1
Case No. PAC-E-17-06
Case No. PAC-E-17-06 Exhibit No. 13
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
____________________________________________
Updated Exhibit Accompanying Compliance Filing
February 2018
Pac
ifiC
orp
Idah
oP
age
1 of
5W
ind
Rep
ower
ing
- E
xam
ple
Mon
thly
RT
M D
efer
ral C
alcu
latio
nR
even
ue R
equi
rem
ent
$-T
ho
usa
nd
s20
1920
1920
1920
1920
1920
1920
1920
1920
1920
1920
1920
19Li
ne
No.
Ref
eren
ceJa
nuar
yF
ebru
ary
Mar
chA
pril
May
June
July
Aug
ust
Sep
tem
ber
Oct
ober
Nov
embe
rD
ecem
ber
To
tal C
om
pan
yP
lan
t R
even
ue
Req
uir
emen
t1
C
apita
l Inv
estm
ent
-
-
-
-
-
-
145,
738
145,
738
145,
738
602,
278
967,
000
967,
000
2
Dep
reci
atio
n R
eser
ve-
-
-
-
-
-
(4
05)
(810
)
(1
,214
)
(2,8
87)
(5
,574
)
(8,2
60)
3
A
ccum
ulat
ed D
IT B
alan
ce-
-
-
-
-
-
(3
,480
)
(3,4
80)
(5
,220
)
(22,
320)
(3
6,22
3)
(48,
297)
4
N
et R
ate
Bas
esu
m o
f lin
es 1
-3-
-
-
-
-
-
14
1,85
3
14
1,44
8
13
9,30
3
57
7,07
1
92
5,20
4
91
0,44
4
5
Pre
-Tax
Rat
e of
Ret
urn
line
379.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%6
P
re-T
ax R
etur
n on
Rat
e B
ase
Foo
tnot
e 1
-
-
-
-
-
-
-
1,09
2
1,
088
1,07
2
4,
441
7,11
9
7
Who
lesa
le W
heel
ing
Rev
enue
Foo
tnot
e 2
-
-
-
-
-
-
-
-
-
-
-
-
8
Ope
ratio
n &
Mai
nten
ance
-
-
-
-
-
-
316
60
7
743
74
7
718
74
5
9
Dep
reci
atio
nF
ootn
ote
5-
-
-
-
-
-
40
5
405
40
5
1,67
3
2,
686
2,68
6
10
P
rope
rty
Tax
esP
rior
Dec
embe
r (li
ne 1
+ li
ne 2
) x
line
38-
-
-
-
-
-
-
-
-
-
-
-
11
W
ind
Tax
-
-
-
-
-
-
8
15
19
19
18
19
12
To
tal P
lan
t R
even
ue
Req
uir
emen
tsu
m o
f lin
es 6
-11
-
-
-
-
-
-
729
2,
118
2,25
5
3,
511
7,86
3
10
,569
Net
Po
wer
Co
st13
N
PC
Incr
emen
tal S
avin
gsS
ee E
xhib
it 14
-
-
-
-
-
-
78
149
18
2
184
17
6
183
PT
C B
enef
it14
P
TC
Ben
efit
-
-
-
-
-
-
(1,5
83)
(3
,037
)
(3,7
17)
(3
,741
)
(3,5
94)
(3
,728
)
15
PT
C B
enef
it in
Bas
e R
ates
-
-
-
-
-
-
-
-
-
-
-
-
16
Net
PT
Csu
m o
f lin
es 1
4 an
d 15
-
-
-
-
-
-
(1,5
83)
(3
,037
)
(3,7
17)
(3
,741
)
(3,5
94)
(3
,728
)
17
Gro
ss-
up fo
r ta
xes
line
16 *
(lin
e 35
- 1
)-
-
-
-
-
-
(5
16)
(990
)
(1
,212
)
(1,2
20)
(1
,172
)
(1,2
15)
18
P
TC
Rev
enue
Req
uire
men
tsu
m o
f lin
e 16
and
17
-
-
-
-
-
-
(2,0
99)
(4
,027
)
(4,9
29)
(4
,961
)
(4,7
66)
(4
,943
)
19R
ev. R
equ
irem
ent
sum
of l
ines
12,
13
and
18-
-
-
-
-
-
(1
,293
)
(1,7
60)
(2
,492
)
(1,2
66)
3,
273
5,80
9
Ad
just
men
t fo
r E
CA
M P
ass-
thro
ug
h20
P
TC
Rev
enue
Req
uire
men
tlin
e 18
-
-
-
-
-
-
(2,0
99)
(4
,027
)
(4,9
29)
(4
,961
)
(4,7
66)
(4
,943
)
21
Per
cent
age
incl
uded
in E
CA
M (
100%
)ID
EC
AM
Sha
ring
%10
0%10
0%10
0%10
0%10
0%10
0%10
0%10
0%10
0%10
0%10
0%10
0%22
N
et P
TC
Afte
r P
ass-
thro
ugh
line
20 *
line
21
-
-
-
-
-
-
(2,0
99)
(4
,027
)
(4,9
29)
(4
,961
)
(4,7
66)
(4
,943
)
23
NP
C In
crem
enta
l Sav
ings
line
13-
-
-
-
-
-
78
14
9
182
18
4
176
18
3
24
Per
cent
age
incl
uded
in E
CA
M (
90%
)ID
EC
AM
Sha
ring
%90
%90
%90
%90
%90
%90
%90
%90
%90
%90
%90
%90
%25
E
CA
M P
ass-
thro
ugh
line
23 *
line
24
-
-
-
-
-
-
70
134
16
4
165
15
9
165
26R
ev. R
eqt
afte
r E
CA
M P
ass-
thro
ug
hlin
e 19
- li
ne 2
2 -
line
25-
-
-
-
-
-
73
7
2,13
3
2,
273
3,53
0
7,
881
10,5
87
Idah
o A
lloca
ted
27T
ota
l Def
erra
l - ID
Sh
are
Foo
tnot
e 4
-
-
-
-
-
-
122
23
4
287
28
8
277
28
7
28N
et C
ust
om
er B
enef
i t(li
ne 2
2 +
line
25)
* li
ne 3
9 +
line
27
-
-
-
-
-
-
-
-
-
-
-
-
Def
erra
l Bal
ance
- ID
Sh
are
29
Beg
inni
ng D
efer
ral B
alan
celin
e 33
of p
revi
ous
mon
th-
-
-
-
-
-
-
12
2
356
64
3
932
1,
210
30
Mon
thly
Def
erra
llin
e 27
-
-
-
-
-
-
122
23
4
287
28
8
277
28
7
31
Def
erra
l Col
lect
ion
Foo
tnot
e 3
-
-
-
-
-
-
-
-
-
-
-
-
32
Car
ryin
g C
harg
e(ln
29
+ .5
* (
ln 3
0 -
ln 3
1))
* ln
36
-
-
-
-
-
-
0
0
0
1
1
1
33E
nd
ing
Def
erra
l Bal
ance
sum
of l
ines
29-
32-
-
-
-
-
-
12
2
356
64
3
932
1,
210
1,49
9
34F
eder
al/S
tate
Com
bine
d T
ax R
ate
Exh
ibit
14, l
ine
524
.587
%35
Net
to G
ross
Bum
p up
Fac
tor
= (
1/(1
-tax
rat
e))
Exh
ibit
14, l
ine
61.
3260
36D
efer
red
Bal
ance
Car
ryin
g C
harg
eE
xhib
it 12
line
35
1.00
%37
Pre
tax
Ret
urn
Exh
ibit
14, l
ine
49.
234%
38P
rope
rty
Tax
Rat
eE
xhib
it 14
, lin
e 14
0.78
%
39Id
aho
SG
Fac
tor
Exh
ibit
14, l
ine
156.
0136
%40
Idah
o G
PS
Fac
tor
Exh
ibit
14, l
ine
165.
7978
%
Foo
tnot
es:
1) P
re-t
ax R
etur
n, li
ne 6
, is
cal
cula
ted
as th
e ra
te o
f ret
urn
(line
5)
mul
tiplie
d by
the
endi
ng n
et r
ate
base
of t
he p
rior
mon
th (
line
4) d
ivid
ed b
y 12
2) N
ot A
pplic
able
for
Rep
ower
ing
3) F
or il
lust
rativ
e pu
rpos
es, c
olle
ctio
n of
Dec
embe
r's b
alan
ce is
ass
umed
to b
e co
llect
ed b
egin
ning
the
follo
win
g Ju
ne 1
4) T
he C
ompa
ny is
pro
posi
ng to
cap
the
RT
M u
ntil
the
next
gen
eral
rat
e ca
se s
o th
at, a
fter
taki
ng in
to a
ccou
nt th
ew
ind
repo
wer
ing
bene
fits
that
will
flow
thro
ugh
the
Com
pany
's E
CA
M, i
t will
not
ope
rate
to s
urch
arge
cus
tom
ers
5) A
s st
ated
in te
stim
ony,
act
ual d
epre
ciat
ion
expe
nse
will
be
adju
sted
by
the
impa
ct o
f the
ret
ired
asse
ts u
ntil
the
next
dep
reci
atio
n st
udy
Rocky Mountain Power Exhibit 13 Page 1 of 5
Case No. PAC-E-17-06
Pac
ifiC
orp
Idah
oW
ind
Rep
ower
ing
- E
xam
ple
Mon
thly
RT
M D
efer
ral C
alcu
latio
nR
even
ue R
equi
rem
ent
$-T
ho
usa
nd
sLi
ne
No.
Ref
eren
ce
To
tal C
om
pan
yP
lan
t R
even
ue
Req
uir
emen
t1
C
apita
l Inv
estm
ent
2
Dep
reci
atio
n R
eser
ve3
A
ccum
ulat
ed D
IT B
alan
ce4
N
et R
ate
Bas
esu
m o
f lin
es 1
-3
5
Pre
-Tax
Rat
e of
Ret
urn
line
376
P
re-T
ax R
etur
n on
Rat
e B
ase
Foo
tnot
e 1
7
Who
lesa
le W
heel
ing
Rev
enue
Foo
tnot
e 2
8
Ope
ratio
n &
Mai
nten
ance
9
Dep
reci
atio
nF
ootn
ote
510
P
rope
rty
Tax
esP
rior
Dec
embe
r (li
ne 1
+ li
ne 2
) x
line
3811
W
ind
Tax
12T
ota
l Pla
nt
Rev
enu
e R
equ
irem
ent
sum
of l
ines
6-1
1
Net
Po
wer
Co
st13
N
PC
Incr
emen
tal S
avin
gsS
ee E
xhib
it 14
PT
C B
enef
it14
P
TC
Ben
efit
15
PT
C B
enef
it in
Bas
e R
ates
16
Net
PT
Csu
m o
f lin
es 1
4 an
d 15
17
Gro
ss-
up fo
r ta
xes
line
16 *
(lin
e 35
- 1
)18
P
TC
Rev
enue
Req
uire
men
tsu
m o
f lin
e 16
and
17
19R
ev. R
equ
irem
ent
sum
of l
ines
12,
13
and
18
Ad
just
men
t fo
r E
CA
M P
ass-
thro
ug
h20
P
TC
Rev
enue
Req
uire
men
tlin
e 18
21
Per
cent
age
incl
uded
in E
CA
M (
100%
)ID
EC
AM
Sha
ring
%22
N
et P
TC
Afte
r P
ass-
thro
ugh
line
20 *
line
21
23
NP
C In
crem
enta
l Sav
ings
line
1324
P
erce
ntag
e in
clud
ed in
EC
AM
(90
%)
ID E
CA
M S
harin
g %
25
EC
AM
Pas
s-th
roug
hlin
e 23
* li
ne 2
4
26R
ev. R
eqt
afte
r E
CA
M P
ass-
thro
ug
hlin
e 19
- li
ne 2
2 -
line
25
Idah
o A
lloca
ted
27T
ota
l Def
erra
l - ID
Sh
are
Foo
tnot
e 4
28N
et C
ust
om
er B
enef
i t(li
ne 2
2 +
line
25)
* li
ne 3
9 +
line
27
Def
erra
l Bal
ance
- ID
Sh
are
29
Beg
inni
ng D
efer
ral B
alan
celin
e 33
of p
revi
ous
mon
th30
M
onth
ly D
efer
ral
line
2731
D
efer
ral C
olle
ctio
nF
ootn
ote
332
C
arry
ing
Cha
rge
(ln 2
9 +
.5 *
(ln
30
- ln
31)
) *
ln 3
633
En
din
g D
efer
ral B
alan
cesu
m o
f lin
es 2
9-32
34F
eder
al/S
tate
Com
bine
d T
ax R
ate
Exh
ibit
14, l
ine
535
Net
to G
ross
Bum
p up
Fac
tor
= (
1/(1
-tax
rat
e))
Exh
ibit
14, l
ine
636
Def
erre
d B
alan
ce C
arry
ing
Cha
rge
Exh
ibit
12 li
ne 3
537
Pre
tax
Ret
urn
Exh
ibit
14, l
ine
438
Pro
pert
y T
ax R
ate
Exh
ibit
14, l
ine
14
39Id
aho
SG
Fac
tor
Exh
ibit
14, l
ine
1540
Idah
o G
PS
Fac
tor
Exh
ibit
14, l
ine
16
Pag
e 2
of 5
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
Janu
ary
Feb
ruar
yM
arch
Apr
ilM
ayJu
neJu
lyA
ugus
tS
epte
mbe
rO
ctob
erN
ovem
ber
Dec
embe
r
967,
000
967,
000
967,
000
967,
000
967,
000
967,
000
968,
712
968,
712
968,
712
968,
712
968,
712
1,10
2,60
7
(10,
946)
(1
3,63
2)
(16,
318)
(1
9,00
4)
(21,
690)
(2
4,37
6)
(27,
067)
(2
9,75
8)
(32,
449)
(3
5,14
0)
(37,
832)
(4
0,89
4)
(48,
297)
(4
8,29
7)
(65,
078)
(6
5,07
8)
(65,
078)
(8
1,85
8)
(81,
858)
(8
1,85
8)
(98,
639)
(9
8,63
9)
(98,
639)
(1
22,2
79)
907,
758
905,
072
885,
605
882,
919
880,
233
860,
766
859,
786
857,
095
837,
624
834,
932
832,
241
939,
434
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
7,00
6
6,
985
6,96
4
6,
815
6,79
4
6,
773
6,62
4
6,
616
6,59
5
6,
445
6,42
5
6,
404
-
-
-
-
-
-
-
-
-
-
-
-
846
92
1
1,04
2
1,
076
1,04
7
98
8
1,01
7
91
6
1,03
7
1,
100
1,05
9
1,
088
2,68
6
2,
686
2,68
6
2,
686
2,68
6
2,
686
2,69
1
2,
691
2,69
1
2,
691
2,69
1
3,
063
619
61
9
619
61
9
619
61
9
619
61
9
619
61
9
619
61
9
24
26
29
30
29
28
28
26
29
31
30
30
11,1
80
11,2
37
11,3
41
11,2
26
11,1
76
11,0
94
10,9
80
10,8
68
10,9
72
10,8
86
10,8
23
11,2
04
(728
)
(7
93)
(897
)
(9
26)
(901
)
(8
50)
(876
)
(7
89)
(893
)
(9
46)
(911
)
(9
36)
(5,2
97)
(5
,768
)
(6,5
30)
(6
,743
)
(6,5
59)
(6
,188
)
(6,3
73)
(5
,741
)
(6,4
99)
(6
,888
)
(6,6
31)
(6
,814
)
-
-
-
-
-
-
-
-
-
-
-
-
(5,2
97)
(5
,768
)
(6,5
30)
(6
,743
)
(6,5
59)
(6
,188
)
(6,3
73)
(5
,741
)
(6,4
99)
(6
,888
)
(6,6
31)
(6
,814
)
(1,7
27)
(1
,881
)
(2,1
29)
(2
,198
)
(2,1
38)
(2
,017
)
(2,0
78)
(1
,872
)
(2,1
19)
(2
,246
)
(2,1
62)
(2
,222
)
(7,0
24)
(7
,649
)
(8,6
59)
(8
,941
)
(8,6
97)
(8
,206
)
(8,4
51)
(7
,612
)
(8,6
17)
(9
,134
)
(8,7
93)
(9
,035
)
3,42
9
2,
795
1,78
5
1,
359
1,57
7
2,
038
1,65
3
2,
467
1,46
2
80
5
1,11
9
1,
233
(7,0
24)
(7
,649
)
(8,6
59)
(8
,941
)
(8,6
97)
(8
,206
)
(8,4
51)
(7
,612
)
(8,6
17)
(9
,134
)
(8,7
93)
(9
,035
)
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
(7,0
24)
(7
,649
)
(8,6
59)
(8
,941
)
(8,6
97)
(8
,206
)
(8,4
51)
(7
,612
)
(8,6
17)
(9
,134
)
(8,7
93)
(9
,035
)
(728
)
(7
93)
(897
)
(9
26)
(901
)
(8
50)
(876
)
(7
89)
(893
)
(9
46)
(911
)
(9
36)
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
(655
)
(7
13)
(807
)
(8
34)
(811
)
(7
65)
(788
)
(7
10)
(804
)
(8
52)
(820
)
(8
43)
11,1
07
11,1
58
11,2
52
11,1
34
11,0
85
11,0
09
10,8
92
10,7
89
10,8
83
10,7
91
10,7
32
11,1
11
462
50
3
569
58
8
572
53
9
556
50
0
567
60
1
578
59
4
-
-
-
-
-
-
-
-
-
-
-
-
1,49
9
1,
962
2,46
7
3,
038
3,62
9
4,
204
4,62
2
5,
057
5,43
7
5,
884
6,36
4
6,
823
462
50
3
569
58
8
572
53
9
556
50
0
567
60
1
578
59
4
-
-
-
-
-
(125
)
(1
25)
(125
)
(1
25)
(125
)
(1
25)
(125
)
1
2
2
3
3
4
4
4
5
5
6
6
1,
962
2,46
7
3,
038
3,62
9
4,
204
4,62
2
5,
057
5,43
7
5,
884
6,36
4
6,
823
7,29
8
Rocky Mountain Power Exhibit 13 Page 2 of 5
Case No. PAC-E-17-06
Pac
ifiC
orp
Idah
oW
ind
Rep
ower
ing
- E
xam
ple
Mon
thly
RT
M D
efer
ral C
alcu
latio
nR
even
ue R
equi
rem
ent
$-T
ho
usa
nd
sLi
ne
No.
Ref
eren
ce
To
tal C
om
pan
yP
lan
t R
even
ue
Req
uir
emen
t1
C
apita
l Inv
estm
ent
2
Dep
reci
atio
n R
eser
ve3
A
ccum
ulat
ed D
IT B
alan
ce4
N
et R
ate
Bas
esu
m o
f lin
es 1
-3
5
Pre
-Tax
Rat
e of
Ret
urn
line
376
P
re-T
ax R
etur
n on
Rat
e B
ase
Foo
tnot
e 1
7
Who
lesa
le W
heel
ing
Rev
enue
Foo
tnot
e 2
8
Ope
ratio
n &
Mai
nten
ance
9
Dep
reci
atio
nF
ootn
ote
510
P
rope
rty
Tax
esP
rior
Dec
embe
r (li
ne 1
+ li
ne 2
) x
line
3811
W
ind
Tax
12T
ota
l Pla
nt
Rev
enu
e R
equ
irem
ent
sum
of l
ines
6-1
1
Net
Po
wer
Co
st13
N
PC
Incr
emen
tal S
avin
gsS
ee E
xhib
it 14
PT
C B
enef
it14
P
TC
Ben
efit
15
PT
C B
enef
it in
Bas
e R
ates
16
Net
PT
Csu
m o
f lin
es 1
4 an
d 15
17
Gro
ss-
up fo
r ta
xes
line
16 *
(lin
e 35
- 1
)18
P
TC
Rev
enue
Req
uire
men
tsu
m o
f lin
e 16
and
17
19R
ev. R
equ
irem
ent
sum
of l
ines
12,
13
and
18
Ad
just
men
t fo
r E
CA
M P
ass-
thro
ug
h20
P
TC
Rev
enue
Req
uire
men
tlin
e 18
21
Per
cent
age
incl
uded
in E
CA
M (
100%
)ID
EC
AM
Sha
ring
%22
N
et P
TC
Afte
r P
ass-
thro
ugh
line
20 *
line
21
23
NP
C In
crem
enta
l Sav
ings
line
1324
P
erce
ntag
e in
clud
ed in
EC
AM
(90
%)
ID E
CA
M S
harin
g %
25
EC
AM
Pas
s-th
roug
hlin
e 23
* li
ne 2
4
26R
ev. R
eqt
afte
r E
CA
M P
ass-
thro
ug
hlin
e 19
- li
ne 2
2 -
line
25
Idah
o A
lloca
ted
27T
ota
l Def
erra
l - ID
Sh
are
Foo
tnot
e 4
28N
et C
ust
om
er B
enef
i t(li
ne 2
2 +
line
25)
* li
ne 3
9 +
line
27
Def
erra
l Bal
ance
- ID
Sh
are
29
Beg
inni
ng D
efer
ral B
alan
celin
e 33
of p
revi
ous
mon
th30
M
onth
ly D
efer
ral
line
2731
D
efer
ral C
olle
ctio
nF
ootn
ote
332
C
arry
ing
Cha
rge
(ln 2
9 +
.5 *
(ln
30
- ln
31)
) *
ln 3
633
En
din
g D
efer
ral B
alan
cesu
m o
f lin
es 2
9-32
34F
eder
al/S
tate
Com
bine
d T
ax R
ate
Exh
ibit
14, l
ine
535
Net
to G
ross
Bum
p up
Fac
tor
= (
1/(1
-tax
rat
e))
Exh
ibit
14, l
ine
636
Def
erre
d B
alan
ce C
arry
ing
Cha
rge
Exh
ibit
12 li
ne 3
537
Pre
tax
Ret
urn
Exh
ibit
14, l
ine
438
Pro
pert
y T
ax R
ate
Exh
ibit
14, l
ine
14
39Id
aho
SG
Fac
tor
Exh
ibit
14, l
ine
1540
Idah
o G
PS
Fac
tor
Exh
ibit
14, l
ine
16
Pag
e 3
of 5
2021
2021
2021
2021
2021
2021
2021
2021
2021
2021
2021
2021
Janu
ary
Feb
ruar
yM
arch
Apr
ilM
ayJu
neJu
lyA
ugus
tS
epte
mbe
rO
ctob
erN
ovem
ber
Dec
embe
r
1,10
2,60
7
1,10
2,60
7
1,10
2,60
7
1,10
2,60
7
1,10
2,60
7
1,10
2,60
7
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
(43,
957)
(4
7,02
0)
(50,
083)
(5
3,14
6)
(56,
209)
(5
9,27
2)
(62,
342)
(6
5,41
3)
(68,
483)
(7
1,55
3)
(74,
623)
(7
7,69
3)
(122
,279
)
(1
22,2
79)
(133
,923
)
(1
33,9
23)
(133
,923
)
(1
45,5
67)
(145
,567
)
(1
45,5
67)
(157
,212
)
(1
57,2
12)
(157
,212
)
(1
68,8
56)
936,
371
933,
308
918,
601
915,
538
912,
475
897,
767
897,
123
894,
053
879,
338
876,
268
873,
198
858,
483
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
7,22
9
7,
205
7,18
2
7,
069
7,04
5
7,
021
6,90
8
6,
903
6,88
0
6,
766
6,74
3
6,
719
-
-
-
-
-
-
-
-
-
-
-
-
1,06
5
1,
065
1,06
5
1,
065
1,06
5
1,
065
1,06
5
1,
065
1,06
5
1,
065
1,06
5
1,
065
3,06
3
3,
063
3,06
3
3,
063
3,06
3
3,
063
3,07
0
3,
070
3,07
0
3,
070
3,07
0
3,
070
686
68
6
686
68
6
686
68
6
686
68
6
686
68
6
686
68
6
35
35
35
35
35
35
35
35
35
35
35
35
12,0
77
12,0
54
12,0
30
11,9
17
11,8
94
11,8
70
11,7
64
11,7
59
11,7
35
11,6
22
11,5
99
11,5
75
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
-
-
-
-
-
-
-
-
-
-
-
-
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
996
97
2
949
83
5
812
78
8
682
67
7
654
54
0
517
49
3
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
(1,0
89)
(1
,089
)
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
(980
)
(9
80)
(980
)
(9
80)
(980
)
(9
80)
(980
)
(9
80)
(980
)
(9
80)
(980
)
(9
80)
11,9
69
11,9
45
11,9
21
11,8
08
11,7
85
11,7
61
11,6
55
11,6
50
11,6
27
11,5
13
11,4
90
11,4
66
660
66
0
660
66
0
660
66
0
660
66
0
660
66
0
660
66
0
-
-
-
-
-
-
-
-
-
-
-
-
7,29
8
7,
840
8,38
2
8,
924
9,46
7
10
,010
10
,070
10
,131
10
,192
10
,252
10
,313
10
,374
66
0
660
66
0
660
66
0
660
66
0
660
66
0
660
66
0
660
(1
25)
(125
)
(1
25)
(125
)
(1
25)
(608
)
(6
08)
(608
)
(6
08)
(608
)
(6
08)
(608
)
6
7
7
8
8
9
9
9
9
9
9
9
7,
840
8,38
2
8,
924
9,46
7
10
,010
10
,070
10
,131
10
,192
10
,252
10
,313
10
,374
10
,435
Rocky Mountain Power Exhibit 13 Page 3 of 5
Case No. PAC-E-17-06
Pac
ifiC
orp
Idah
oW
ind
Rep
ower
ing
- E
xam
ple
Mon
thly
RT
M D
efer
ral C
alcu
latio
nR
even
ue R
equi
rem
ent
$-T
ho
usa
nd
sLi
ne
No.
Ref
eren
ce
To
tal C
om
pan
yP
lan
t R
even
ue
Req
uir
emen
t1
C
apita
l Inv
estm
ent
2
Dep
reci
atio
n R
eser
ve3
A
ccum
ulat
ed D
IT B
alan
ce4
N
et R
ate
Bas
esu
m o
f lin
es 1
-3
5
Pre
-Tax
Rat
e of
Ret
urn
line
376
P
re-T
ax R
etur
n on
Rat
e B
ase
Foo
tnot
e 1
7
Who
lesa
le W
heel
ing
Rev
enue
Foo
tnot
e 2
8
Ope
ratio
n &
Mai
nten
ance
9
Dep
reci
atio
nF
ootn
ote
510
P
rope
rty
Tax
esP
rior
Dec
embe
r (li
ne 1
+ li
ne 2
) x
line
3811
W
ind
Tax
12T
ota
l Pla
nt
Rev
enu
e R
equ
irem
ent
sum
of l
ines
6-1
1
Net
Po
wer
Co
st13
N
PC
Incr
emen
tal S
avin
gsS
ee E
xhib
it 14
PT
C B
enef
it14
P
TC
Ben
efit
15
PT
C B
enef
it in
Bas
e R
ates
16
Net
PT
Csu
m o
f lin
es 1
4 an
d 15
17
Gro
ss-
up fo
r ta
xes
line
16 *
(lin
e 35
- 1
)18
P
TC
Rev
enue
Req
uire
men
tsu
m o
f lin
e 16
and
17
19R
ev. R
equ
irem
ent
sum
of l
ines
12,
13
and
18
Ad
just
men
t fo
r E
CA
M P
ass-
thro
ug
h20
P
TC
Rev
enue
Req
uire
men
tlin
e 18
21
Per
cent
age
incl
uded
in E
CA
M (
100%
)ID
EC
AM
Sha
ring
%22
N
et P
TC
Afte
r P
ass-
thro
ugh
line
20 *
line
21
23
NP
C In
crem
enta
l Sav
ings
line
1324
P
erce
ntag
e in
clud
ed in
EC
AM
(90
%)
ID E
CA
M S
harin
g %
25
EC
AM
Pas
s-th
roug
hlin
e 23
* li
ne 2
4
26R
ev. R
eqt
afte
r E
CA
M P
ass-
thro
ug
hlin
e 19
- li
ne 2
2 -
line
25
Idah
o A
lloca
ted
27T
ota
l Def
erra
l - ID
Sh
are
Foo
tnot
e 4
28N
et C
ust
om
er B
enef
i t(li
ne 2
2 +
line
25)
* li
ne 3
9 +
line
27
Def
erra
l Bal
ance
- ID
Sh
are
29
Beg
inni
ng D
efer
ral B
alan
celin
e 33
of p
revi
ous
mon
th30
M
onth
ly D
efer
ral
line
2731
D
efer
ral C
olle
ctio
nF
ootn
ote
332
C
arry
ing
Cha
rge
(ln 2
9 +
.5 *
(ln
30
- ln
31)
) *
ln 3
633
En
din
g D
efer
ral B
alan
cesu
m o
f lin
es 2
9-32
34F
eder
al/S
tate
Com
bine
d T
ax R
ate
Exh
ibit
14, l
ine
535
Net
to G
ross
Bum
p up
Fac
tor
= (
1/(1
-tax
rat
e))
Exh
ibit
14, l
ine
636
Def
erre
d B
alan
ce C
arry
ing
Cha
rge
Exh
ibit
12 li
ne 3
537
Pre
tax
Ret
urn
Exh
ibit
14, l
ine
438
Pro
pert
y T
ax R
ate
Exh
ibit
14, l
ine
14
39Id
aho
SG
Fac
tor
Exh
ibit
14, l
ine
1540
Idah
o G
PS
Fac
tor
Exh
ibit
14, l
ine
16
Pag
e 4
of 5
2022
2022
2022
2022
2022
2022
2022
2022
2022
2022
2022
2022
Janu
ary
Feb
ruar
yM
arch
Apr
ilM
ayJu
neJu
lyA
ugus
tS
epte
mbe
rO
ctob
erN
ovem
ber
Dec
embe
r
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
1,10
5,03
3
1,10
7,94
4
1,10
7,94
4
1,10
7,94
4
1,10
7,94
4
1,10
7,94
4
1,10
7,94
4
(80,
763)
(8
3,83
4)
(86,
904)
(8
9,97
4)
(93,
044)
(9
6,11
4)
(99,
193)
(1
02,2
72)
(105
,352
)
(1
08,4
31)
(111
,510
)
(1
14,5
89)
(168
,856
)
(1
68,8
56)
(174
,998
)
(1
74,9
98)
(174
,998
)
(1
81,1
39)
(181
,139
)
(1
81,1
39)
(187
,281
)
(1
87,2
81)
(187
,281
)
(1
93,4
22)
855,
413
852,
343
843,
131
840,
061
836,
991
827,
779
827,
612
824,
533
815,
312
812,
233
809,
154
799,
933
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
9.23
4%9.
234%
6,60
6
6,
582
6,55
9
6,
488
6,46
4
6,
441
6,37
0
6,
368
6,34
5
6,
274
6,25
0
6,
226
-
-
-
-
-
-
-
-
-
-
-
-
801
80
1
801
80
1
801
80
1
801
80
1
801
80
1
801
80
1
3,07
0
3,
070
3,07
0
3,
070
3,07
0
3,
070
3,07
9
3,
079
3,07
9
3,
079
3,07
9
3,
079
664
66
4
664
66
4
664
66
4
664
66
4
664
66
4
664
66
4
35
35
35
35
35
35
35
35
35
35
35
35
11,1
76
11,1
52
11,1
29
11,0
58
11,0
34
11,0
10
10,9
49
10,9
47
10,9
24
10,8
53
10,8
29
10,8
05
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
-
-
-
-
-
-
-
-
-
-
-
-
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(7,5
36)
(7
,536
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(2,4
57)
(2
,457
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
21
(3)
(27)
(9
7)
(121
)
(1
45)
(207
)
(2
08)
(232
)
(3
03)
(326
)
(3
50)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(9,9
93)
(9
,993
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
(1,1
62)
(1
,162
)
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
90%
(1,0
46)
(1
,046
)
(1,0
46)
(1
,046
)
(1,0
46)
(1
,046
)
(1,0
46)
(1
,046
)
(1,0
46)
(1
,046
)
(1,0
46)
(1
,046
)
11,0
60
11,0
36
11,0
12
10,9
42
10,9
18
10,8
94
10,8
32
10,8
31
10,8
07
10,7
36
10,7
13
10,6
89
664
66
2
661
65
7
655
65
4
650
65
0
648
64
4
643
64
1
(0)
(2)
(3)
(7)
(9)
(10)
(1
4)
(14)
(1
5)
(20)
(2
1)
(22)
10,4
35
10,4
99
10,5
63
10,6
25
10,6
82
10,7
39
10,5
32
10,3
22
10,1
12
9,90
0
9,
683
9,46
5
66
4
662
66
1
657
65
5
654
65
0
650
64
8
644
64
3
641
(6
08)
(608
)
(6
08)
(608
)
(6
08)
(870
)
(8
70)
(870
)
(8
70)
(870
)
(8
70)
(870
)
9
9
9
9
9
10
9
9
9
9
9
9
10,4
99
10,5
63
10,6
25
10,6
82
10,7
39
10,5
32
10,3
22
10,1
12
9,90
0
9,
683
9,46
5
9,
246
Rocky Mountain Power Exhibit 13 Page 4 of 5
Case No. PAC-E-17-06
Pac
ifiC
orp
Idah
oP
age
5 of
5W
ind
Rep
ower
ing
- E
xam
ple
Mon
thly
RT
M D
efer
ral C
alcu
latio
nR
even
ue R
equi
rem
ent
To
tal P
lan
t R
even
ue
Req
uir
emen
t (L
ines
1 -
12, 3
7):
Exh
ibit
13 s
how
s th
e ca
lcul
atio
n of
the
RT
M r
even
ue r
equi
rem
ent d
efer
ral d
escr
ibed
in m
y te
stim
ony.
The
cal
cula
tion
star
ts w
ith to
tal C
ompa
ny a
mou
nts
on li
nes
1 -
26 to
ca
lcul
ate
the
Idah
o sp
ecifi
c am
ount
s on
line
s 27
-33
. T
o ca
lcul
ate
the
retu
rn o
n ra
te b
ase
asso
ciat
ed w
ith t
he w
ind
repo
wer
ing
inve
stm
ent,
net r
ate
base
ass
ocia
ted
with
the
re
pow
ered
win
d re
sour
ces
is c
alcu
late
d on
a m
onth
ly b
asis
. The
net
rat
e ba
se b
alan
ce o
n lin
e 4
incl
udes
the
inve
stm
ent i
n re
pow
ered
win
d re
sour
ces,
alo
ng w
ith th
e as
soci
ated
impa
cts
on th
e de
prec
iatio
n re
serv
e an
d ac
cum
ulat
ed D
IT B
alan
ce.
The
mon
thly
beg
inni
ng n
et r
ate
base
(th
e fin
al a
mou
nt fr
om th
e pr
ior
mon
th)
is th
en m
ultip
lied
by t
he p
re-t
ax W
eigh
ted
Ave
rage
Cos
t of C
apita
l (“W
AC
C”)
from
the
last
Idah
o ge
nera
l rat
e ca
se o
n lin
e 5
to d
eter
min
e th
e C
ompa
ny's
pre
-tax
ret
urn
on r
ate
base
on
line
6.
The
exa
mpl
e us
es th
e pr
e-ta
x W
AC
C fr
om C
ase
No.
PA
C-E
-15-
09 T
he to
tal p
lant
rev
enue
req
uire
men
t is
calc
ulat
ed b
y ta
king
the
retu
rn o
n ra
te b
ase
show
n on
line
6 a
nd
addi
ng th
e O
&M
exp
ense
, dep
reci
atio
n ex
pens
e, p
rope
rty
taxe
s an
d w
ind
tax
on li
nes
8 -
11 to
det
erm
ine
the
tota
l pla
nt r
even
ue r
equi
rem
ent o
n lin
e 12
. Who
lesa
le w
heel
ing
reve
nue
on li
ne 7
is n
ot u
sed
for
win
d re
pow
erin
g, b
ut is
nee
ded
for
a si
mila
r ca
lcul
atio
n fo
r th
e G
atew
ay t
rans
mis
sion
and
win
dex
pans
ion
proj
ect.
Net
Po
wer
Co
sts
(Lin
e 13
):T
he to
tal c
ompa
ny in
crem
enta
l NP
C s
avin
gs a
ssoc
iate
d w
ith r
epow
ered
win
d re
sour
ces
is s
how
n on
line
13.
The
incr
emen
tal N
PC
sav
ings
ass
ocia
ted
with
the
rep
ower
ed w
ind
proj
ects
are
mul
tiplie
d by
nin
ety
perc
ent o
n lin
e 24
to d
eter
min
e th
e am
ount
of t
he N
PC
sav
ings
that
will
be
retu
rned
to
cust
omer
s th
roug
h th
e sh
arin
g ba
nd o
f the
EC
AM
. The
R
TM
is d
esig
ned
to p
rovi
de t
he r
emai
ning
ten
perc
ent o
f the
NP
C s
avin
gs in
yea
rs th
at th
e re
venu
e re
quire
men
t ben
efits
are
suf
ficie
nt to
cov
er th
at a
mou
nt. A
bsen
t thi
s ad
just
men
t, cu
stom
ers
wou
ld n
ot g
et 1
00 p
erce
nt o
f the
NP
C a
ssoc
iate
d w
ith r
epow
erin
g. T
he c
alcu
latio
n of
NP
C s
avin
gs is
des
crib
ed in
Exh
ibit
14.
PT
C B
enef
its
(Lin
es 1
4-20
, 34,
35)
:Li
nes
14-1
8 sh
ow t
he c
alcu
latio
n of
the
PT
C b
enef
its a
ssoc
iate
d w
ith t
he r
epow
ered
win
d re
sour
ces.
The
act
ual P
TC
sal
es a
re g
ross
ed-u
p fo
r ta
xes
usin
g th
e ne
t-to
-gro
ss
bum
p-up
fact
or fr
om th
e C
ompa
ny’s
last
gen
eral
rat
e ca
se (
show
n on
line
35)
to d
eriv
e th
e P
TC
rev
enue
req
uire
men
t on
line
18. T
he ta
x gr
oss-
up is
nec
essa
ry fo
r cu
stom
ers
to g
et th
e fu
ll re
venu
e re
quire
men
t ben
efit
of th
e P
TC
s an
d is
cal
cula
ted
usin
g th
e fe
dera
l and
sta
te c
ombi
ned
tax
rate
sho
wn
onlin
e34
whi
ch w
as a
lso
incl
uded
in t
he la
st
gene
ral r
ate
case
.One
hun
dred
per
cent
of I
daho
's s
hare
of t
he P
TC
s ar
e re
turn
ed to
cus
tom
ers
thro
ugh
the
EC
AM
.
Def
erra
l Bal
ance
(L
ines
19
–33
):T
he Id
aho
shar
e of
the
net d
efer
ral b
egin
s by
cal
cula
ting
the
tota
l rep
ower
ing
proj
ect r
even
ue r
equi
rem
ent o
n lin
e 19
, whi
ch is
the
sum
of T
otal
Pla
nt R
even
ue R
equi
rem
ent o
n lin
e 12
, NP
C In
crem
enta
l Sav
ings
on
line
13, a
nd P
TC
Rev
enue
Req
uire
men
t on
line
18.
The
One
hun
drea
d pe
rcen
t EC
AM
pas
s-th
roug
hon
line
22 a
nd n
inet
y pe
rcen
t EC
AM
pa
ss-t
hrou
gh o
n lin
e25
are
subt
ract
ed to
pro
vide
the
Rev
enue
Req
uire
men
t aft
er E
CA
M P
ass-
thro
ugh
on li
ne 2
6. I
daho
's s
hare
of t
he T
otal
Def
erra
l is
depe
nden
t upo
n th
e am
ount
of r
even
ue r
equi
rem
ent c
ost o
r be
nefit
that
is d
eter
min
ed in
a p
artic
ular
yea
r. If
the
Rev
enue
Req
uire
men
t aft
er E
CA
M P
ass-
thro
ugh
for
any
year
on
line
26 is
neg
ativ
e,
whi
ch m
eans
that
the
repo
wer
ing
proj
ect p
rovi
des
a re
venu
e re
quire
men
t ben
efit
grea
ter
than
the
bene
fit b
eing
pas
sed
thro
ugh
the
EC
AM
, the
n th
at y
ear's
def
erra
l is
equa
l to
the
addi
tiona
l ben
efit
foun
d on
line
26.
If t
he R
even
ue R
equi
rem
ent a
fter
EC
AM
Pas
s-th
roug
h fo
r an
y ye
ar o
n lin
e 26
is p
ositi
ve, t
he C
ompa
ny is
pro
posi
ng to
cap
the
RT
M
until
the
next
gen
eral
rat
e ca
se s
o th
at, a
fter
taki
ng in
to a
ccou
nt th
e w
ind
repo
wer
ing
bene
fits
that
will
flo
w t
hrou
gh th
e C
ompa
ny's
EC
AM
, it w
ill n
ot o
pera
te to
sur
char
ge
cust
omer
s.T
he N
et C
usto
mer
Ben
efit
(line
28)
is th
e su
m o
f the
EC
AM
Pas
s-th
roug
h (li
ne 2
2an
d lin
e 25
) an
d th
e T
otal
Def
erra
l -Id
aho
Sha
re (
line
27).
The
car
ryin
g ch
arge
, sh
own
on li
ne 3
2is
cal
cula
ted
usin
g th
e C
omm
issi
on-a
utho
rized
rat
e on
line
36
and
is c
onsi
sten
t with
the
cal
cula
tions
use
d in
the
Com
pany
's o
ther
mec
hani
sms
such
as
the
EC
AM
. As
desc
ribed
ear
lier,
eac
h m
onth
the
tota
l-Com
pany
RT
M r
eve
nue
requ
irem
ent w
ill b
e ca
lcul
ated
as
illus
trat
ed o
n E
xhib
it 1
3to
alig
n w
ith th
e re
sour
ces
incl
uded
in th
e E
CA
M. O
nce
per
year
on
a ca
lend
ar-y
ear
basi
s, th
e C
ompa
ny w
ill s
um th
e m
onth
ly R
TM
rev
enue
req
uire
men
t ent
ries
to p
repa
re th
e an
nual
RT
M a
pplic
atio
n fo
r fil
ing
with
the
C
omm
issi
on o
n A
pril
1, w
ith a
n in
terim
rat
e ef
fect
ive
date
that
cor
resp
onds
with
the
EC
AM
app
licat
ion,
Jun
e 1.
Rocky Mountain Power Exhibit 13 Page 5 of 5
Case No. PAC-E-17-06
Case No. PAC-E-17-06 Exhibit No. 14
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
____________________________________________
Updated Exhibit Accompanying Compliance Filing
February 2018
PacifiCorpIdahoWind Repowering - Capital Structure, Property Tax and Net Power Cost DescriptionCapital Structure and Property Tax Rate
Capital Structure and Cost from Case Number PAC-E-15-09Updated with new consolidated tax rate consistent with the new tax lawEffective 1/1/2016
Line no. Capital Structure
Capital Structure
Capital Cost
Weighted Cost Pre-Tax Cost
1 Debt 48.810% 5.151% 2.514% 2.514%2 Preferred 0.010% 6.753% 0.001% 0.001%3 Common 51.180% 9.900% 5.067% 6.719%4 TOTAL 7.582% 9.234%
5 Consolidated Tax Rate 24.587%
6 Tax Gross-up factor for PTC = (1/(1 - tax rate)) 1.3260
Property Tax Calculation as filed in Case Number PAC-E-15-097 Total Company 139,158,574 8 Idaho GPS Factor 5.7978%9 Idaho Property Taxes 8,068,136
10 Idaho Gross EPIS 1,552,375,059 11 Idaho Accum. Depr. (479,609,578) 12 Idaho Accum. Amort. (31,808,156) 13 Idaho Net EPIS 1,040,957,325
14 Estimated Idaho Property Tax Rate 0.775%
15 Idaho SG Factor - Case No. PAC-E-15-09 6.0136%16 Idaho GPS Factor - Case No. PAC-E-15-09 5.7978%
Net Power Cost Incremental Savings Calculation and Definitions
IncrementalGeneration WindPlantGenerationMWh – BaseWindPlantGenerationMWh
BaseWindPlantGeneration WindPlantGenerationMWh/ 1 ProjectGenerationIncrease%
Where: IncrementalGeneration TheincreaseingenerationatthewindplantduetorepoweringProjectGenerationIncrease% Thepercentagechangeinenergyatthewindplantdueto
repowering SeeConfidentialExhibit3,page2of2 Theincreaseingenerationatthewindplantduetorepoweringduring
heavyloadhours Theincreaseingenerationatthewindplantduetorepoweringduringlight
loadhours Heavyloadhourmonthlymarketprice Lightloadhourmonthlymarketprice
IntegrationCosts WindintegrationcostsfromthemostrecentIRPRTMNPCBenefit TheNPCrepoweringbenefitabsorbedbytheCompanyintheECAMasaresult
ofthesharingband
Rocky Mountain Power Exhibit 14 Page 1 of 1
Case No. PAC-E-17-06