HomeMy WebLinkAbout20180207Compliance Filing.pdfO ROCKY MOUNTAIN 1407 W.North Temple,Suite 330POWER-
-Salt Lake City,Utah 84116
A DIVISION OF PACIFICORP
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
O confidential and non-confidentialCompliance 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 (80 l)220-2963.
Very truly yours,
J ell R.Stewa d
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 atrueandcorrectcopyofRockyMountainPower's Compliance Filing in Case No.PAC-E-l7-06
to the following:
Service List
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.
Eric L.Olsen Anthony Yankel
ECHO HAWK &OLSEN,PLLC 12700 Lake Avenue,Unit 2505
505 Pershing Ave.,Ste.100 Lakewood,Ohio 44107
P.O.Box 6119 E-mail:tonv@vankel.net
Pocatello,Idaho 83205
E-mail:elo echohawk.com
MONSANTO COMPANY
Randall C.Budge Brubaker&Associates
Racine,Olson,Nye &Budge,Chartered 16690 Swingley Ridge Rd.,#140
P.O.Box 1391;201 E.Center Chesterfield,MO 63017
Pocatello,Idaho 83204-1391 E-mail:bcollins consultbai.com
E-mail:reb racinelaw.net kiverson consultbai.com
IDAHO INDUSTRIAL CONSUMERS
O Ronald L.Williams Jim Duke
Williams Bradbury,P.C.IdahoanFoods
P.O.Box 388 E-mail:jduke idahoan.com
Boise ID,83701
E-mail :ron@williamsbradbury.com
Kyle Williams Val Steiner
BYU Idaho Nu-West Industries,Inc.
E-mail :williamsk byui.edu E-mail :val.steiner@agrium.com
Bradley Mullins
333 SW Taylor,Suite 400
Portland,OR 97204
E-mail:brmullins@mwanalytics.com
COMISSION STAFF
BrandonKarpen
Deputy Attorney General
IdahoPublic Utilities Commission
472 W.Washington(83702)
PO Box 83720
Boise,ID 83720-0074
E-mail:brandon.karpen@puc.idaho.cov
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O PACIFICORP,DBA ROCKY MOUNTAIN POWER
Ted Weston Yvonne Hogle
PacifiCorp,dba Rocky Mountain Power PacifiCorp,dba Rocky Mountain Power
1407 West North Temple 1407 West North Temple
Suite 330 Suite 320
Salt Lake City,UT 84116 Salt Lake City,UT 84116
E-mail:ted.weston pacid E-mail:Yvonne.hoale oscificorp.com
Data Request Response Center
PacifiCorp
825 NE Multnomah,Suite 2000
Portland,OR 97232
E-mail:datarequest(alpa_cjjicágg.com
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:robert.richards@pacificorp.com
vvonne.houle@pacificorp.com
Katherine McDowell (OR #890876)
Adam Lowney (OR #053124)
McDowell Rackner Gibson PC
419 SW l l*Avenue,Suite 400
Portland,OR 97205
Telephone:(503)595-3924
Facsimile:(503)595-3928
Email:katherine@mre-law.com
adam@mre-law.com
Attorneys for Rocky Mountain Power
O BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )CASE NO.PAC-E-17-06
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR BINDING )COMPLIANCE FILING
RATEMAKING TREATMENT FOR )
WIND REPOWERING )
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 Stipulationbetween 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 providedthe Commission and interested parties a meaningful
opportunity to evaluate the prudence of the Project to ensure that it is reasonable,prudent,and inOthepublicinterest.
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 engagein 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 Stipulationresolved 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 Stipulationas filed.
4.Paragraph 16 of the Stipulationspecified:"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 Stipulationand 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.TheOimpactsoftheTaxActarenowknownandhavebeenincorporatedintheupdatedeconomic
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-yeartax 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
additionalavailable data,with only a small net change in production;(2)confirmed the need and
scope of required facilityretrofits,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 regulatoryapproval 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 g turbine,which the
Company can use to repower its .The nameplate capacity of the generator
of this turbine is |megawatts greater than the g 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 verifythat the turbine is suitable for use
at the facility site with the existing towers.Black &Veatch reviewed the new foundationloading
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 followinga 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 followingrepowering,similar to all the other facilities previously evaluated.
18.Project capital costs have decreased by $27 million-or approximately2.4 percent-O to $1.10 billion.
UPDATED ECONOMIC ANALYSIS
19.The Project's economic analysis was updated to reflect more current assumptions
including:(1)cost estimates consistent with findings from technical review studies cost-and-
performance assumptions described above;(2)current price-policy scenario assumptions,
including more current natural gas and CO2 prices;and (3)recent changes in the federal tax rate
for corporations.
20.In the updated analysis the Company applied PTC benefits on a nominal basis rather
than on a levelized basis.This approach better reflects how the federal PTC benefits for the
repowered assets will flow through to customers and aligns the treatment of federal PTC benefits
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in the system modeling results extending out through 2036 with the nominal revenue requirement
results extendingout through 2050.
21.Table 1 summarizes the PVRR(d)results for each wind facilitywithin the scope of the
wind repowering project when applying medium natural gas and medium CO2 price-policy
assumptions.The PVRR(d)between cases with and without wind repowering are shown for each
wind facility based on system modeling results from the SO model and for PaR,before accounting
for the substantial increase in incremental energy beyond the 2036 time frame.When applying
medium natural gas and medium CO2 price-policy assumptions,benefits from repowering the
Leaning Juniper wind facility are equal to costs.All other wind facilities are projected to deliver
net benefits.
Table 1 -Project-by-ProjectSO Model and PaR PVRR(d)
(Benefit)/Cost of Wind Repowering with Medium Natural Gas
And Medium CO2 Price-Policy i sssumptions ($mil ion)
SO Model PaR Stochastic-PaR Risk-Wind Facility PVRR(d)Mean PVRR(d)idjusted PVRR(d)
Glenrock I ($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)($189)
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22.Table 2 summarizes the PVRR(d)results for each wind facility within the scope of the
wind repowering project when applying low natural gas and zero CO2 price-policy assumptions.
The PVRR(d)between cases with and without wind repowering are shown for each wind facility
based on system modeling results from the SO model and for PaR.before accounting for the
substantial increase in incremental energy beyond the 2036 time frame.When applying low natural
gas and zero CO2 price-policy assumptions,costs from repowering the Leaning Juniper wind
facility are slightlyhigher than the benefits.All other wind facilities are projected to deliver net
benefits.
Table 2 -Project-by-ProjectSO Model and PaR PVRR(d)
(Benefit)/Cost of Wind Repowering with Low Natural Gas and Zero CO2 Price-
Policy Assumptions ($million)
SO Model PaR Stochastic-PaR Risk-Wind Facility PVRR(d)Mean PVRR(d)tdjusted 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)($156)
23.Table 3 summarizes the PVRR(d)results for each wind facility calculated off of the
change in annual nominal revenue requirement through 2050 for both price-policy scenarios.
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Unlike the results summarized in Tables 1 and 2,these results account for the substantial increase
in incremental energy beyond the 2036 time frame.Each of the wind facilities within the scope of
the proposed repowering project show net benefits with repowering under the medium natural gas
and medium CO2 price-policy scenario and all facilities show net benefits under the low natural
gas and zero CO2 price-policy scenario,except for the Leaning Juniper wind facility,where the
benefits are equal to the costs.
Table 3 -Project-by-ProjectNominal Revenue Requirement PVRR(d)
(Benefit)/Cost of Wind Repowering ($million)
Medium Natural Gas Low Natural GasWindFacilityandMediumCO2andZeroCO2
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 benefitper 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 ($7/MWh).
Table 4 -Nominal Levelized Net Benefit per MWh of Incremental
Energy Outputafter Repowering ($/MWh)
Medium Natural Gas Low Natural GasWindFacilityandMediumCO2andZeroCO2
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)
SO Model PaR Stochastic-Mean PaR Risk-AdjustedPrice-Policy Scenario PVRR(d)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)
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 potentialvalue 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 scenarioswould improve by approximately$6 million
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for every dollar assigned to the incremental RECs that will be generated from the repowered
facilities through 2036.Quantifying the potential upside associated with incremental REC
revenues is intended to simply communicate that the net benefits from the repowering project
could improve if the incremental RECs can be monetized in the market.
28.The CO2 price assumptions used in the updated economic analysis were inadvertently
modeled in 2012 real dollars instead of nominal dollars.Consequently,the PVRR(d)net benefits
in the six price-policy scenariosthat use medium and high CO2 price assumptions are conservative.
29.Table 6 summarizes the updated PVRR(d)results for each price-policy scenario
calculated using the change in annual nominal revenue requirement through 2050.
Table 6 -Updated Nominal Revenue Requirement PVRR(d)
(Benefit)/Cost of he Wind Repowering Proj3ct ($million)
Updated Annual Revenue Filed Annual RevenuePrice-Policy Scenario Requirement PVRR(d)Requirement PVRR(d)
Low Gas,Zero CO2 ($127)($41)
Low Gas,Medium CO2 ($121)($245)
Low Gas,High CO2 ($223)($344)
Medium Gas.Zero CO:($224)($362)
Medium Gas,Medium CO:($273)($359)
Medium Gas,High CO:($321)($401)
High Gas,Zero CO:($389)($400)
High Gas,Medium CO:($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 $273 million.While changes in federal tax law have reduced net benefits
relativeto the economic analysis from the Application,the wind repowering project continues to
provide significant customer benefits in all price-policy scenarios.The updated economic
analysis reconfirms that upside benefits outweigh downside risks.
ESTIMATED RATE IMPACT
31.Provided as attachments to this compliance filing are updated Exhibit Nos.12-14
showing the estimated Idaho revenue requirement revised with the updated economic analysis
incorporatingthe changes described above.The exhibits are in the same format as the Application,
and calculate the monthly and annual revenue requirements and the overall impact of the wind
repowering projects that would be reflected in rates,assuming operation of the RTM.
32.These exhibits include changes in Idaho's allocated share of the updated repoweringOprojects'wind construction cost,return,depreciation,PTCs,taxes,and operating costs and
benefits.The updated net power cost changes associated with an updated load forecast,system
dispatch and revised wind generation projections have been included in the Energy Cost
Adjustment Mechanism ("ECAM")pass-through calculation.Table 7 summarizes the estimated
repowering revenue requirement found in the updated exhibits.It shows that the repowering
project now reflects rate benefits to customers beginning in 2022.As a result of the cap proposed
for the RTM in this proceeding,customers would see no net change in rates for the repowering
project for costs through 2021,absenta general rate case.
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Table 7
Repowering Estimated Revenue Requirement Cost (Benefit)$thousands
2019 2020 2021 2022
1 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)
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
decreasethereafter.
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
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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 7*dayof February,2018.
Jeff Richar
Yvonne R.Hogle
1407 West North Temple,Suite 320
Salt Lake City,Utah 84116
Telephone:(801)220-4050
Facsimile:(801)220-3299
Email:robert.richards@pacificorp.com
Attorneys for Rocky Mountain Power
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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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(I)
(m
)
(n
)
(o
)
(p
)
$-
T
h
o
u
s
a
n
d
s
40
1
9
Re
p
o
w
e
r
i
n
g
20
2
0
Re
p
o
w
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r
i
n
q
40
2
1
Re
p
o
w
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r
i
n
g
50
2
2
Re
p
o
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e
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g
Re
f
e
r
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e
Co
pb
a
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y
Fa
c
t
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r
Fa
c
t
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r
%
Alld
d
Co
an
y
Fa
c
t
o
r
Fa
c
t
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r
%
Alld
d
a
t
e
d
Co
an
y
Fa
c
t
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r
Fa
c
t
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r
%
All
e
ed
Co
an
y
Fa
c
t
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r
Fa
c
t
o
r
%
Al
d
Pla
n
t
Re
v
e
n
u
e
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q
u
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t
1
Ca
p
i
t
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l
In
v
e
s
t
m
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t
Fo
o
t
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e
i
16
7
,
2
0
8
SG
6.0
1
3
6
%
10
,
0
5
5
96
7
,
7
1
4
SG
6.0
1
3
6
%
58
,
1
9
4
1,1
0
3
,
6
1
8
SG
6,0
1
3
6
%
66
,
3
6
7
1,1
0
6
,
2
4
6
SG
6.0
1
3
6
%
66
,
5
2
5
2
De
p
r
e
c
i
a
t
i
o
n
Re
s
e
r
v
e
Fo
o
t
n
o
t
e
1
(9
0
8
)
SG
6.0
1
3
6
%
(5
5
)
(2
3
,
0
3
9
)
SG
6.0
1
3
6
%
(1
,
3
8
6
)
(5
7
,
7
5
0
)
SG
6.0
1
3
6
%
(3
,
4
7
3
)
(9
4
59
0
)
SG
6.0
1
3
6
%
(5
,
6
8
8
)
3
Ac
c
u
m
u
l
a
t
e
d
DIT
Ba
l
a
n
c
e
Fo
o
t
n
o
t
e
1
SG
6.0
1
3
6
%
__
_
_
(
3
5
4
)
SG
6.0
1
3
6
%
(1
3
9
,
7
4
5
)
SG
6.0
1
3
6
%
SG
6,0
1
3
6
%
4
Ne
t
Ra
t
e
Ba
s
e
su
m
of
lin
e
s
1-3
16
0
40
7
9,6
4
6
87
1
20
6
52
,
3
9
1
90
6
,
1
2
3
54
49
1
83
3
58
7
50
,
1
2
9
te
r
o
tne
Ba
s
e
lin
e
5
7
Wh
o
l
e
s
a
l
e
W
h
e
e
l
i
n
g
R
e
v
e
n
u
e
Fo
o
t
n
o
t
e
4
-
SG
6.0
1
3
6
%
-
-
SG
6.0
1
3
6
%
-
-
SG
6.0
1
3
6
%
-
-
SG
6.0
1
3
6
%
8
Op
e
r
a
t
i
o
n
&
Ma
i
n
t
e
n
a
n
c
e
Fo
o
t
n
o
t
e
3
3,8
7
6
SG
6.0
1
3
6
%
23
3
12
,
1
3
7
SG
6.0
1
3
6
%
73
0
12
,
7
7
9
SG
6.0
1
3
6
%
76
8
9,6
1
5
SG
6.0
1
3
6
%
57
8
9
De
p
r
e
c
i
a
t
i
o
n
Fo
o
t
n
o
t
e
3
&
6
8,2
6
0
SG
6.0
1
3
6
%
49
7
32
,
6
3
5
SG
6.0
1
3
6
%
1,
9
6
3
36
,
7
9
9
SG
6.0
1
3
6
%
2,2
1
3
36
,
8
9
6
SG
6.0
1
3
6
%
2,2
1
9
10
Pro
p
e
r
t
y
T
a
x
e
s
Fo
o
t
n
o
t
e
3
-
GP
S
5.7
9
7
8
%
-
7,4
3
1
GP
S
5.7
9
7
8
%
43
1
8,2
2
9
GP
S
5.7
9
7
8
%
47
7
7,9
6
3
GP
S
57
9
7
8
%
46
2
11
Win
d
T
a
x
Fo
o
t
n
o
t
e
3
98
SG
6.0
1
3
6
%
6
33
8
SG
6.0
1
3
6
%
20
41
9
SG
6.0
1
3
6
%
25
41
9
SG
60
1
3
6
%
25
12
To
t
a
l
Pla
n
t
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
su
m
of
lin
e
s
6-1
1
27
,
0
4
5
1,6
2
6
13
2
,
9
8
7
7,9
8
1
14
1
,
8
9
6
8,5
1
5
13
1
,
8
6
5
7,9
1
3
No
t
Po
w
e
r
Co
s
t
13
NP
C
In
c
r
e
m
e
n
t
a
l
Sa
v
i
n
g
s
Fo
o
t
n
o
t
e
3
95
2
SG
6.0
1
3
6
%
57
(1
0
,
4
4
6
)
SG
6.0
1
3
6
%
(6
2
8
)
(1
3
,
0
6
2
)
SG
6.0
1
3
6
%
(7
8
6
)
(1
3
,
9
4
3
)
SG
6
01
3
6
%
(8
3
8
)
PT
C
Be
n
e
f
i
t
14
PT
C
Be
n
e
f
i
t
Fo
o
t
n
o
t
e
3
(1
9
,
4
0
0
)
SG
6.0
1
3
6
%
(1
,
1
6
7
)
(7
6
,
0
3
1
)
SG
6.0
1
3
6
%
(4
,
5
7
2
)
(9
0
,
4
3
5
)
SG
6.0
1
3
6
%
(5
,
4
3
8
)
(9
0
,
4
3
5
)
SG
6.0
1
3
6
%
(5
,
4
3
8
)
15
PT
C
Be
n
e
f
i
t
in
Ba
s
e
Ra
t
e
s
Fo
o
t
n
o
t
e
3
-
SG
6.0
1
3
6
%
-
-
SG
6.0
1
3
6
%
-
-
SG
6.0
1
3
6
%
-
-
SG
6.0
1
3
6
%
16
Ne
t
PT
C
su
m
of
lin
e
s
14
an
d
15
(1
9
,
4
0
0
)
(1
,
1
6
7
)
(7
6
,
0
3
1
)
(4
,
5
7
2
)
(9
0
,
4
3
5
)
(5
,
4
3
8
)
(9
0
,
4
3
5
)
(5
,
4
3
8
)
17
Gro
s
s
-
up
fo
r
ta
x
e
s
lin
e
16
*
(li
n
e
35
-
1)
(2
9
,
4
8
5
)
18
PT
C
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
(2
5
72
5
)
(1
54
7
)
(1
0
0
,
8
1
9
)
(6
,
0
6
3
)
(1
1
9
,
9
1
9
)
(7
,
2
1
1
)
(1
1
9
,
9
1
9
)
(7
21
1
)
19
Re
v
.
Re
q
u
i
r
e
m
e
n
t
su
m
of
lin
e
s
12
,
13
,
18
8.9
1
5
)
Ad
j
u
s
t
m
e
n
t
fo
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
20
PT
C
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
îln
e
18
(1
,
5
4
7
)
(6
,
0
6
3
)
(7
,
2
1
1
)
(7
,
2
1
1
)
21
Pe
r
c
e
n
t
a
g
e
in
c
l
u
d
e
d
in
EC
A
M
(1
0
0
%
)
ID
EC
A
M
Sh
a
r
i
n
g
%
10
0
%
10
0
%
10
0
%
10
0
%
22
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
lin
e
20
*
lin
e
2
1
(1
,
5
4
7
)
(6
,
0
6
3
)
(7
,
2
1
1
)
(7
,
2
1
1
)
23
NP
C
in
c
r
e
m
e
n
t
a
l
Sa
v
i
n
g
s
lin
e
13
57
(6
2
8
)
(7
8
6
)
(8
3
8
)
24
Pe
r
c
e
n
t
a
g
e
in
c
l
u
d
e
d
in
EC
A
M
(9
0
%
)
ID
EC
A
M
Sh
a
r
i
n
g
%
90
%
90
%
90
%
90
%
25
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
lin
e
23
*
lin
e
24
52
(5
6
5
)
(7
0
7
)
(7
5
5
)
26
Re
v
.
Re
q
t
.
aft
e
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
lin
e
19
-
tin
e
22
-li
n
e
25
27
To
t
a
l
De
f
e
r
r
a
l
-
ID
Sh
a
r
e
Fo
o
t
n
o
t
e
5
28
Ne
t
Cu
s
t
o
m
e
r
Be
n
e
f
i
t
su
m
of
lin
e
s
22
,
25
,
27
)
De
f
e
r
r
a
l
Ba
l
a
n
c
e
-
ID
Sh
a
r
e
29
Be
g
i
n
n
i
n
g
De
f
e
r
r
a
l
Ba
l
a
n
c
e
lin
e
33
of
pre
v
i
o
u
s
ye
a
r
1,4
9
9
7
29
8
10
43
5
30
Mo
n
t
h
l
y
De
f
e
r
r
a
l
Fo
o
t
n
o
t
e
5
1,4
9
5
6,
6
2
8
7,9
1
8
7
82
9
31
De
f
e
r
r
a
t
Co
l
l
e
c
t
i
o
n
Fo
o
t
n
o
t
e
3
(8
7
4
)
(4
,
8
8
2
)
(9
12
8
)
En
C
d
i
De
eh
eB
a
l
a
n
c
e
o
I
ns
29
-
3
2
34
Fe
d
e
r
a
l
/
S
t
a
t
e
Co
m
b
i
n
e
d
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
5
24
.
5
8
7
%
35
Ne
t
to
Gr
o
s
s
Bu
m
p
up
Fa
c
t
o
r
=
(1
/
(
1
-
t
a
x
ra
t
e
)
)
Ex
h
i
b
i
t
14
,
lin
e
6
1.
3
2
6
0
36
De
f
e
r
r
e
d
Ba
l
a
n
c
e
Ca
r
r
y
i
n
g
Ch
a
r
g
e
Fo
o
t
n
o
t
e
2
1.0
0
%
Ca
s
e
Nu
m
b
e
r
GN
R
-
U
16
01
,
Or
d
e
r
No
.
33
6
6
4
37
Pre
t
a
x
Re
t
u
r
n
Ex
h
i
b
i
t
14
,
lin
e
4
9.2
3
4
%
PA
C
-
E
-
1
5
-
0
9
Ca
p
i
t
a
l
Str
u
c
t
u
r
e
&
Co
s
t
-O
r
d
e
r
e
d
38
Pro
p
e
r
t
y
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
14
0.7
8
%
Pr
o
p
e
r
t
y
Ta
x
Ex
p
e
n
s
e
as
a
pe
r
c
e
n
t
of
Ne
t
pla
n
t
fro
m
PA
C
E-1
5
09
39
Id
a
h
o
SG
Fa
c
t
o
r
Ex
h
i
b
i
t
14
,
lin
e
15
6.0
1
3
6
%
40
Id
a
h
o
GP
S
Fa
c
t
o
r
Ex
h
i
b
i
t
14
,
lin
e
16
5.7
9
7
8
%
Fo
o
t
n
o
t
e
s
:
1)
Ca
p
i
t
a
l
ba
l
a
n
c
e
s
eq
u
a
l
th
e
av
e
r
a
g
e
of
th
e
mo
n
t
h
l
y
ba
l
a
n
c
e
s
in
Ex
h
i
b
i
t
13
wit
h
a
on
e
mo
n
t
h
de
l
a
y
2)
Ca
r
r
y
i
n
g
Ch
a
r
g
e
(li
n
e
32
)
is
ap
p
l
i
e
d
to
av
e
r
a
g
e
mo
n
t
h
l
y
de
f
e
r
r
a
l
ba
l
a
n
c
e
s
3)
Eq
u
a
l
s
th
e
su
m
of
ea
c
h
ye
a
r
'
s
mo
n
t
h
l
y
va
l
u
e
s
in
Ex
h
i
b
i
t
13
4)
No
t
Ap
p
l
í
c
a
b
l
e
fo
r
Re
p
o
w
e
r
i
n
g
5)
Th
e
Co
m
p
a
n
y
is
pr
o
p
o
s
i
n
g
to
ca
p
th
e
RT
M
un
t
i
l
th
e
ne
x
t
ge
n
e
r
a
l
ra
t
e
ca
s
e
so
th
a
t
,
aft
e
r
ta
k
i
n
g
in
t
o
ac
c
o
u
n
t
th
e
win
d
re
p
o
w
e
r
i
n
g
be
n
e
f
i
t
s
th
a
t
wil
l
flo
w
th
r
o
u
g
h
th
e
Co
m
p
a
n
y
'
s
EC
A
M
,
it
wil
l
no
t
op
e
r
a
t
e
to
su
r
c
h
a
r
g
e
cu
s
t
o
m
e
r
s
6)
As
sta
t
e
d
in
te
s
t
i
m
o
n
y
,
ac
t
u
a
l
de
p
r
e
c
i
a
t
i
o
n
ex
p
e
n
s
e
wil
l
be
ad
j
u
s
t
e
d
by
th
e
im
p
a
c
t
of
th
e
re
t
i
r
e
d
as
s
e
t
s
un
t
i
l
th
e
ne
x
t
de
p
r
e
c
i
a
t
i
o
n
stu
d
y
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
O
O
O
O
Pa
c
i
f
i
C
o
r
p
id
a
h
o
Pa
g
e
1
of
5
Win
d
Re
p
o
w
e
r
i
n
g
-
Ex
a
m
p
l
e
Mo
n
t
h
l
y
RT
M
De
f
e
r
r
a
l
Ca
l
c
u
l
a
t
i
o
n
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
$-
T
h
o
u
s
a
n
d
s
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
20
1
9
Lin
e
No
.
Re
f
e
r
e
n
c
e
Ja
n
u
a
r
y
Fe
b
r
u
a
r
y
Ma
r
c
h
Ap
r
i
l
Ma
y
Ju
n
e
Ju
l
y
Au
g
u
s
t
Se
p
t
e
m
b
e
r
Oc
t
o
b
e
r
No
v
e
m
b
e
r
De
c
e
m
b
e
r
To
t
a
l
Co
m
p
a
n
y
Pla
n
t
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
1
Ca
p
i
t
a
l
In
v
e
s
t
m
e
n
t
-
-
-
-
-
-
14
5
,
7
3
8
14
5
,
7
3
8
14
5
,
7
3
8
60
2
,
2
7
8
96
7
,
0
0
0
96
7
,
0
0
0
2
De
p
r
e
c
i
a
t
i
o
n
Re
s
e
r
v
e
-
-
-
-
-
-
(4
0
5
)
(8
1
0
)
(1
,
2
1
4
)
(2
,
8
8
7
)
(5
,
5
7
4
)
(8
,
2
6
0
)
3
Ac
c
u
m
u
l
a
t
e
d
DIT
Ba
l
a
n
c
e
-
-
-
-
-
-
(3
,
4
8
0
)
(3
,
4
8
0
)
(5
,
2
2
0
)
(2
2
,
3
2
0
)
(3
6
,
2
2
3
)
(4
8
,
2
9
7
)
4
Ne
t
R
a
t
e
B
a
s
e
su
m
o
f
l
i
n
e
s
1
-
3
-
-
-
-
-
-
14
1
,
8
5
3
14
1
,
4
4
8
13
9
,
3
0
3
57
7
,
0
7
1
92
5
,
2
0
4
91
0
,
4
4
4
5
Pre
-
T
a
x
Ra
t
e
of
Re
t
u
r
n
lin
e
37
9.2
3
4
%
9.2
3
4
%
9,2
3
4
%
9.2
3
4
%
9.
2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.
2
3
4
%
9.2
3
4
%
9.2
3
4
%
6
Pre
-
T
a
x
Re
t
u
m
on
Ra
t
e
Ba
s
e
Fo
o
t
n
o
t
e
1
-
1,0
9
2
1,0
8
8
1,0
7
2
4,4
4
1
7,1
1
9
7
Wh
o
l
e
s
a
l
e
Wh
e
e
l
i
n
g
Re
v
e
n
u
e
Fo
o
t
n
o
t
e
2
8
Op
e
r
a
t
i
o
n
&
Ma
i
n
t
e
n
a
n
c
e
-
31
6
60
7
74
3
74
7
71
8
74
5
9
De
p
r
e
c
i
a
t
i
o
n
Fo
o
t
n
o
t
e
5
-
40
5
40
5
40
5
1,6
7
3
2,6
8
6
2,6
8
6
10
Pr
o
p
e
r
t
y
Ta
x
e
s
Pri
o
r
De
c
e
m
b
e
r
(li
n
e
1
+
lin
e
2)
x
lin
e
38
11
Vin
d
T
a
x
8
15
19
19
18
19
12
To
t
a
l
Pla
n
t
Re
v
e
n
u
e
Re
q
u
î
t
e
m
e
n
t
su
m
of
lin
e
s
6-1
1
72
9
2,1
1
8
2,2
5
5
3,5
1
1
7,
8
6
3
10
,
5
6
9
Ne
t
Po
w
e
r
Co
s
t
13
N
P
C
i
n
c
r
e
m
e
n
t
a
l
S
a
v
i
n
g
s
Se
e
E
x
h
i
b
i
t
1
4
78
14
9
18
2
18
4
17
6
18
3
PT
C
Be
n
e
f
i
t
14
PT
C
Be
n
e
f
i
t
(1
,
5
8
3
)
(3
,
0
3
7
)
(3
,
7
1
7
)
{3
,
7
4
1
)
{3
,
5
9
4
)
(3
,
7
2
8
)
15
PT
C
Be
n
e
f
i
t
in
Ba
s
e
Ra
t
e
s
16
Ne
t
PT
C
su
m
of
lin
e
s
14
an
d
15
(1
,
5
8
3
)
(3
,
0
3
7
)
(3
,
7
1
7
)
(3
,
7
4
1
)
(3
,
5
9
4
)
(3
,
7
2
8
)
17
Gro
s
s
-
up
fo
r
ta
x
e
s
lin
e
16
*(
l
i
n
e
35
-
1)
(5
1
6
)
(9
9
0
)
(1
,
2
1
2
)
(1
,
2
2
0
)
(1
,
1
7
2
)
(1
,
2
1
5
)
18
PT
C
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
su
m
of
lin
e
16
an
d
17
(2
,
0
9
9
)
(4
,
0
2
7
)
(4
,
9
2
9
)
(4
,
9
6
1
)
(4
,
7
6
6
)
(4
,
9
4
3
)
19
Re
v
.
Re
q
u
i
r
e
m
e
n
t
su
m
of
lin
e
s
12
,
13
an
d
18
-
(1
29
3
)
(1
,
7
6
0
)
(2
,
4
9
2
)
(1
,
2
6
6
)
3,
2
7
3
5,8
0
9
Ad
j
u
s
t
m
e
n
t
fo
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
20
PT
C
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
lin
e
18
(2
,
0
9
9
)
(4
,
0
2
7
)
(4
,
9
2
9
)
(4
,
9
6
1
)
(4
,
7
6
6
)
(4
,
9
4
3
)
21
P
e
r
c
e
n
t
a
g
e
i
n
c
l
u
d
e
d
i
n
E
C
A
M
(
1
0
0
%
)
ID
E
C
A
M
S
h
a
r
i
n
g
%
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
Ne
t
PT
C
Aft
e
r
Pa
s
s
-
t
h
r
o
u
g
h
lin
e
20
*
lin
e
21
-
-
-
-
-
-
(2
,
0
9
9
)
(4
,
0
2
7
)
(4
,
9
2
9
)
(4
,
9
6
1
)
(4
,
7
6
6
)
(4
,
9
4
3
)
23
NP
C
In
c
r
e
m
e
n
t
a
l
Sa
v
i
n
g
s
lin
e
13
-
-
-
-
-
-
78
14
9
18
2
18
4
17
6
18
3
24
P
e
r
c
e
n
t
a
g
e
i
n
c
l
u
d
e
d
i
n
E
C
A
M
(
9
0
%
)
ID
E
C
A
M
S
h
a
r
i
n
g
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
25
EC
A
M
P
a
s
s
-
t
h
r
o
u
g
h
li
n
e
2
3
°
I
i
n
e
2
4
-
-
-
-
-
-
70
13
4
16
4
16
5
15
9
16
5
26
Re
v
.
Re
q
t
aft
e
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
lin
e
19
-
lin
e
22
-
lin
e
25
-
73
7
2,1
3
3
2,2
7
3
3,5
3
0
7,8
8
1
10
,
5
8
7
Id
a
h
o
All
o
c
a
t
e
d
27
T
o
t
a
l
D
e
f
e
r
r
a
l
-
I
D
S
h
a
r
e
Fo
o
t
n
o
t
e
4
-
12
2
23
4
28
7
28
6
27
7
28
7
28
Ne
t
Cu
s
t
o
m
e
r
Be
n
e
f
i
t
(li
n
e
22
+
lin
e
25
)
*li
n
e
39
+
lin
e
27
De
f
e
r
r
a
l
Ba
l
a
n
c
e
-
ID
Sh
a
r
e
29
Be
g
i
n
n
i
n
g
De
f
e
r
r
a
l
Ba
l
a
n
c
e
lin
e
33
of
pre
v
i
o
u
s
mo
n
t
h
-
-
12
2
35
6
64
3
93
2
1,
2
1
0
30
Mo
n
t
h
l
y
De
f
e
r
r
a
l
fin
e
27
-
-
-
-
-
-
12
2
23
4
28
7
28
8
27
7
28
7
31
De
f
e
r
r
a
l
Co
l
l
e
c
t
i
o
n
Fo
o
t
n
o
t
e
3
32
Ca
r
r
y
i
n
g
Ch
a
r
g
e
(In
29
+
.5
*
(in
30
-
In
31
)
)
*
In
36
-
-
-
-
0
0
0
1
1
1
33
En
d
i
n
g
De
f
e
r
r
a
l
Ba
l
a
n
c
e
su
m
of
lin
e
s
29
-
3
2
-
-
-
-
-
12
2
35
6
64
3
93
2
1,2
1
0
1,
4
9
9
FT
l
O
34
Fe
d
e
r
a
l
l
S
t
a
t
e
Co
m
b
i
n
e
d
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
5
24
,
5
8
7
%
35
Ne
t
to
Gro
s
s
Bu
m
p
up
Fa
c
t
o
r
=
(1
/
(
1
-
t
a
x
ra
t
e
)
)
Ex
h
î
b
i
t
14
.
lin
e
6
1
32
6
0
36
De
f
e
r
r
e
d
Ba
l
a
n
c
e
Ca
r
r
y
i
n
g
Ch
a
r
g
e
Ex
h
i
b
i
t
12
lin
e
35
1
00
%
37
Pre
t
a
x
Re
t
u
r
n
Ex
h
i
b
i
t
14
,
lin
e
4
9
23
4
%
38
Pro
p
e
r
t
y
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
14
0
78
%
39
Id
a
h
o
SG
Fa
c
t
o
r
Ex
h
i
b
i
t
14
,
lin
e
15
6
01
3
6
%
40
Id
a
h
o
GP
S
Fa
c
t
o
r
Ex
h
i
b
i
t
14
.
lin
e
16
5
79
7
8
%
Fo
o
t
n
o
t
e
s
:
1)
Pr
e
-
t
a
x
Re
t
u
m
,
lin
e
6,
is
ca
l
c
u
l
a
t
e
d
as
th
e
ra
t
e
of
re
t
u
m
(lin
e
5)
mu
l
t
i
p
i
l
e
d
by
th
e
en
d
i
n
g
ne
t
ra
t
e
ba
s
e
of
th
e
pri
o
r
mo
n
t
h
(li
n
e
4)
div
i
d
e
d
by
12
2)
No
t
Ap
p
l
i
c
a
b
l
e
fo
r
Re
p
o
w
e
r
i
n
g
3)
Fo
r
ill
u
s
t
r
a
t
i
v
e
pu
r
p
o
s
e
s
,
co
l
l
e
c
t
i
o
n
of
De
c
e
m
b
e
r
s
ba
l
a
n
c
e
is
as
s
u
m
e
d
to
be
co
l
l
e
c
t
e
d
be
g
i
n
n
i
n
g
th
e
fo
l
l
o
w
i
n
g
Ju
n
e
1
-h
4)
Th
e
Co
m
p
a
n
y
is
pro
p
o
s
i
n
g
to
ca
p
th
e
RT
M
un
t
i
l
th
e
ne
x
t
ge
n
e
r
a
l
ra
t
e
ca
s
e
so
th
a
t
,
aft
e
r
ta
k
i
n
g
in
t
o
ac
c
o
u
n
t
th
e
Q)
O1
win
d
re
p
o
w
e
r
i
n
g
be
n
e
f
i
t
s
th
a
t
wil
l
flo
w
th
r
o
u
g
h
th
e
Co
m
p
a
n
y
'
s
EC
A
M
,
it
wil
l
no
t
op
e
r
a
t
e
to
su
r
c
h
a
r
g
e
cu
s
t
o
m
e
r
s
5)
As
sta
t
e
d
in
te
s
t
i
m
o
n
y
,
ac
t
u
a
l
de
p
r
e
c
i
a
t
i
o
n
ex
p
e
n
s
e
will
be
ad
j
u
s
t
e
d
by
th
e
im
p
a
c
t
of
th
e
re
t
i
r
e
d
as
s
e
t
s
un
t
i
l
th
e
ne
x
t
de
p
r
e
c
i
a
t
i
o
n
stu
d
y
O
O
O
Pa
c
i
f
i
C
o
r
p
id
a
h
o
Pa
g
e
2
of
5
Win
d
Re
p
o
w
e
r
i
n
g
-
Ex
a
m
p
l
e
Mo
n
t
h
l
y
RT
M
De
f
e
r
r
a
l
Ca
l
c
u
l
a
t
i
o
n
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
$-T
h
o
u
s
a
n
d
s
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
20
2
0
Lin
e
No
.
Re
f
e
r
e
n
c
e
Ja
n
u
a
r
y
Fe
b
r
u
a
r
y
Ma
r
c
h
Ap
r
i
l
Ma
y
Ju
n
e
Ju
l
y
Au
g
u
s
t
Se
p
t
e
m
b
e
r
Oc
t
o
b
e
r
No
v
e
m
b
e
r
De
c
e
m
b
e
r
To
t
a
l
Co
m
p
a
n
y
Pla
n
t
Re
v
e
n
u
e
Re
q
u
î
r
e
m
e
n
t
1
Ca
p
i
t
a
l
i
n
v
e
s
t
m
e
n
t
96
7
,
0
0
0
96
7
,
0
0
0
96
7
,
0
0
0
96
7
,
0
0
0
96
7
,
0
0
0
96
7
,
0
0
0
96
8
,
7
1
2
96
8
,
7
1
2
96
8
,
7
1
2
96
8
,
7
1
2
96
8
,
7
1
2
1,1
0
2
,
6
0
7
2
De
p
r
e
c
i
a
t
i
o
n
Re
s
e
r
v
e
(1
0
,
9
4
6
)
(1
3
,
6
3
2
)
(1
6
,
3
1
8
)
(1
9
.
0
0
4
)
(2
1
,
6
9
0
)
(2
4
,
3
7
6
)
(2
7
,
0
6
7
)
(2
9
,
7
5
8
)
(3
2
,
4
4
9
)
(3
5
,
1
4
0
)
(3
7
,
8
3
2
)
(4
0
,
8
9
4
)
3
Ac
c
u
m
u
l
a
t
e
d
DIT
Ba
l
a
n
c
e
(4
8
,
2
9
7
)
(4
8
,
2
9
7
)
(6
5
,
0
7
8
}
(6
5
,
0
7
8
)
(6
5
,
0
7
8
)
(8
1
,
8
5
8
)
(8
1
,
8
5
8
)
(8
1
,
8
5
8
)
(9
8
,
6
3
9
)
(9
8
,
6
3
9
)
(9
8
,
6
3
9
)
(1
2
2
,
2
7
9
)
4
Ne
t
Ra
t
e
Ba
s
e
su
m
of
lin
e
s
1-3
90
7
,
7
5
8
90
5
,
0
7
2
88
5
,
6
0
5
88
2
,
9
1
9
88
0
,
2
3
3
86
0
,
7
6
6
85
9
,
7
8
6
85
7
,
0
9
5
83
7
,
6
2
4
83
4
,
9
3
2
83
2
,
2
4
1
93
9
,
4
3
4
5
Pre
-
T
a
x
Ra
t
e
of
Re
t
u
m
lin
e
37
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.
2
3
4
%
9,2
3
4
%
9.2
3
4
%
9.2
3
4
%
6
Pre
-
T
a
x
Re
t
u
m
on
Ra
t
e
Ba
s
e
Fo
o
t
n
o
t
e
1
7,0
0
6
6,9
8
5
6,9
6
4
6,8
1
5
6,7
9
4
6,
7
7
3
6,6
2
4
6,6
1
6
6,5
9
5
6,4
4
5
6,
4
2
5
6,4
0
4
7
Wh
o
l
e
s
a
l
e
Wh
e
e
l
i
n
g
Re
v
e
n
u
e
Fo
o
t
n
o
t
e
2
8
Op
e
r
a
t
i
o
n
&
Ma
i
n
t
e
n
a
n
c
e
84
6
92
1
1,
0
4
2
1,0
7
6
1,0
4
7
98
8
1,0
1
7
91
6
1,0
3
7
1,1
0
0
1,0
5
9
1,0
8
8
9
De
p
r
e
c
i
a
t
i
o
n
Fo
o
t
n
o
t
e
5
2,6
8
6
2,
6
8
6
2,6
8
6
2,6
8
6
2,6
8
6
2,
6
8
6
2,
6
9
1
2,6
9
1
2,6
9
1
2,6
9
1
2,6
9
1
3,0
6
3
10
Pro
p
e
r
t
y
Ta
x
e
s
Pri
o
r
De
c
e
m
b
e
r
(lin
e
1
+
lin
e
2)
x
lin
e
38
61
9
61
9
61
9
61
9
61
9
61
9
61
9
61
9
61
9
61
9
61
9
61
9
11
Win
d
Ta
x
24
26
29
30
29
28
28
26
29
31
30
30
12
To
t
a
l
Pla
n
t
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
su
m
of
lin
e
s
6-
1
1
11
,
1
8
0
11
,
2
3
7
11
,
3
4
1
11
,
2
2
6
11
,
1
7
6
11
,
0
9
4
10
,
9
8
0
10
,
8
6
8
10
,
9
7
2
10
,
8
8
6
10
,
8
2
3
11
,
2
0
4
Ne
t
Po
w
e
r
Co
s
t
13
NP
C
In
c
r
e
m
e
n
t
a
l
Sa
v
i
n
g
s
Se
e
Ex
h
i
b
i
t
14
(7
2
8
)
(7
9
3
)
(8
9
7
)
(9
2
6
)
(9
0
1
)
(8
5
0
)
(8
7
6
)
(7
8
9
)
(8
9
3
)
(9
4
6
)
(9
1
1
)
(9
3
6
)
PT
C
Be
n
e
f
i
t
14
PT
C
Be
n
e
f
i
t
(5
,
2
9
7
)
(5
,
7
6
8
)
(6
,
5
3
0
)
(6
,
7
4
3
)
(6
,
5
5
9
)
(6
,
1
8
8
)
(6
,
3
7
3
)
(5
,
7
4
1
)
(6
,
4
9
9
)
(6
,
8
8
8
)
(6
,
6
3
1
)
(6
,
8
1
4
)
15
PT
C
Be
n
e
f
i
t
in
Ba
s
e
Ra
t
e
s
16
N
e
t
P
T
C
su
m
o
f
l
i
n
e
s
1
4
a
n
d
1
5
(5
,
2
9
7
)
(5
,
7
6
8
)
(6
,
5
3
0
)
(6
,
7
4
3
)
(6
,
5
5
9
)
(6
,
1
8
8
)
(6
,
3
7
3
)
(5
,
7
4
1
)
(6
,
4
9
9
)
(6
,
8
8
8
)
(6
,
6
3
1
)
(6
,
8
1
4
)
17
G
r
o
s
s
-
u
p
f
o
r
t
a
x
e
s
lin
e
1
6
'
(
l
i
n
e
3
5
-
1
)
(1
,
7
2
7
)
(1
,
8
8
1
)
(2
,
1
2
9
)
(2
,
1
9
8
)
(2
,
1
3
8
)
(2
,
0
1
7
)
(2
,
0
7
8
)
(1
,
8
7
2
)
(2
,
1
1
9
)
(2
,
2
4
6
)
(2
,
1
6
2
)
(2
,
2
2
2
)
18
P
T
C
R
e
v
e
n
u
e
R
e
q
u
i
r
e
m
e
n
t
su
m
o
f
l
i
n
e
1
6
a
n
d
1
7
(7
,
0
2
4
)
(7
,
6
4
9
)
(8
,
6
5
9
)
(8
,
9
4
1
)
(8
,
6
9
7
)
(8
,
2
0
6
)
(8
,
4
5
1
)
(7
,
6
1
2
)
(8
,
6
1
7
)
(9
,
1
3
4
)
(8
,
7
9
3
)
(9
,
0
3
5
)
19
R
e
v
.
R
e
q
u
i
r
e
m
e
n
t
su
m
o
f
f
i
n
e
s
1
2
,
1
3
a
n
d
1
8
3,4
2
9
2,
7
9
5
1,
7
8
5
1,3
5
9
1,5
7
7
2,0
3
8
1,6
5
3
2,4
6
7
1,4
6
2
80
5
1,1
1
9
1,2
3
3
Ad
j
u
s
t
m
e
n
t
fo
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
20
PT
C
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
lin
e
18
(7
,
0
2
4
)
(7
,
6
4
9
)
(8
,
6
5
9
)
(8
,
9
4
1
)
(8
,
6
9
7
)
(8
,
2
0
6
)
(8
,
4
5
1
)
(7
,
6
1
2
)
(8
,
6
1
7
)
(9
,
1
3
4
)
(8
,
7
9
3
)
(9
,
0
3
5
)
21
P
e
r
c
e
n
t
a
g
e
i
n
c
l
u
d
e
d
i
n
E
C
A
M
(
1
0
0
%
)
ID
E
C
A
M
S
h
a
r
i
n
g
%
10
0
%
10
0
%
10
0
%
10
0
%
10
0
%
10
0
%
10
0
%
10
0
¾
10
0
%
10
0
%
10
0
%
10
0
%
22
N
e
t
P
T
C
A
f
t
e
r
P
a
s
s
-
t
h
r
o
u
g
h
lin
e
2
0
*
I
i
n
e
2
1
(7
,
0
2
4
)
(7
,
6
4
9
)
(8
,
6
5
9
)
(8
,
9
4
1
)
(8
,
6
9
7
)
(8
,
2
0
6
)
(8
,
4
5
1
)
(7
,
6
1
2
)
(8
,
6
1
7
)
(9
,
1
3
4
)
(8
,
7
9
3
)
(9
.
0
3
5
)
23
N
P
C
i
n
c
r
e
m
e
n
t
a
l
S
a
v
i
n
g
s
lin
e
1
3
(7
2
8
)
(7
9
3
)
(8
9
7
)
(9
2
6
)
(9
0
1
)
(8
5
0
)
(8
7
6
)
(7
8
9
)
(8
9
3
)
(9
4
6
)
(9
1
1
)
(9
3
6
)
24
Pe
r
c
e
n
t
a
g
e
in
c
l
u
d
e
d
in
EC
A
M
(9
0
%
)
ID
EC
A
M
Sh
a
r
i
n
g
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
25
E
C
A
M
P
a
s
s
t
h
r
o
u
g
h
lin
e
2
3
*
I
i
n
e
2
4
(6
5
5
)
(7
1
3
)
(8
0
7
)
(8
3
4
)
(8
1
1
)
(7
6
5
)
(7
8
8
)
(7
1
0
)
(8
0
4
)
(8
5
2
)
(8
2
0
)
(8
4
3
)
26
Re
v
.
Re
q
t
aft
e
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
lin
e
19
-
lin
e
22
-li
n
e
25
11
,
1
0
7
11
,
1
5
8
11
,
2
5
2
11
,
1
3
4
11
,
0
8
5
11
,
0
0
9
10
,
8
9
2
10
,
7
8
9
10
,
8
8
3
10
,
7
9
1
10
,
7
3
2
11
,
1
1
1
Id
a
h
o
Al
l
o
c
a
t
e
d
27
T
o
t
a
l
D
e
f
e
r
r
a
l
-
I
D
S
h
a
r
e
Fo
o
t
n
o
t
e
4
46
2
50
3
56
9
58
8
57
2
53
9
55
6
50
0
56
7
60
1
57
8
59
4
28
Ne
t
Cu
s
t
o
m
e
r
Be
n
e
f
i
t
(lin
e
22
+
lin
e
25
)
*
fin
e
39
+
lin
e
27
De
f
e
r
r
a
l
Ba
l
a
n
c
e
-
ID
Sh
a
r
e
29
Be
g
i
n
n
i
n
g
De
f
e
r
r
a
l
Ba
l
a
n
c
e
lin
e
33
of
pre
v
i
o
u
s
mo
n
t
h
1,4
9
9
1,9
6
2
2,4
6
7
3,0
3
8
3,6
2
9
4,2
0
4
4,6
2
2
5,
0
5
7
5,4
3
7
5,8
8
4
6,3
6
4
6,
8
2
3
30
Mo
n
t
h
l
y
De
f
e
r
r
a
l
lin
e
27
46
2
50
3
56
9
58
8
57
2
53
9
55
6
50
0
56
7
60
1
57
8
59
4
31
De
f
e
r
r
a
l
Co
N
e
c
t
i
o
n
Fo
o
t
n
o
t
e
3
-
-
-
-
-
(1
2
5
)
(1
2
5
)
(1
2
5
)
(1
2
5
)
(1
2
5
)
(1
2
5
)
(1
2
5
)
32
C
a
r
r
y
i
n
g
C
h
a
r
g
e
(In
2
9
+
.
5
'
(
I
n
3
0
-
i
n
3
1
)
)
*
l
n
3
6
1
2
2
3
3
4
4
4
5
5
6
6
33
En
d
i
n
g
De
f
e
r
r
a
l
Ba
l
a
n
c
e
su
m
of
lin
e
s
29
-
3
2
1,9
6
2
2,
4
6
7
3,
0
3
8
3,6
2
9
4,2
0
4
4,6
2
2
5,0
5
7
5,
4
3
7
5,8
8
4
6,3
6
4
6,8
2
3
7,
2
9
8
mo
34
Fe
d
e
r
a
W
S
t
a
t
e
Co
m
b
i
n
e
d
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
5
35
Ne
t
to
Gro
s
s
Su
m
p
up
Fa
c
t
o
r
=
(il
(
1
-
t
a
x
ra
t
e
)
)
Ex
h
i
b
i
t
14
,
lin
e
6
36
De
f
e
r
r
e
d
Ba
l
a
n
c
e
Ca
r
r
y
i
n
g
Ch
a
r
g
e
Ex
h
i
b
i
t
12
lin
e
35
37
Pr
e
t
a
x
Re
t
u
m
Ex
h
i
b
i
t
14
,
lin
e
4
38
Pr
o
p
e
r
t
y
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
.
lin
e
14
39
id
a
h
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Fa
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14
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lin
e
15
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En
e
16
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3
of
5
Win
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Ex
a
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M
De
f
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Ca
l
c
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t
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v
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q
u
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T
h
o
u
s
a
n
d
s
20
2
1
20
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1
20
2
1
20
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1
20
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1
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1
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1
20
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1
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Lin
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No
Re
f
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n
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Ca
p
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t
a
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m
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6
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6
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0
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3
2
De
p
r
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c
i
a
t
i
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n
Re
s
e
r
v
e
(4
3
,
9
5
7
)
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7
,
0
2
0
)
(5
0
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0
8
3
)
(5
3
,
1
4
6
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6
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0
9
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9
.
2
7
2
)
(6
2
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4
2
)
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5
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4
1
3
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(6
8
,
4
8
3
)
(7
1
,
5
5
3
)
(7
4
,
6
2
3
)
(7
7
,
6
9
3
)
3
Ac
c
u
m
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l
a
t
e
d
DIT
Ba
l
a
n
c
e
(1
2
2
,
2
7
9
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2
2
,
2
7
9
)
(1
3
3
,
9
2
3
)
(1
3
3
,
9
2
3
)
(1
3
3
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9
2
3
)
(1
4
5
,
5
6
7
)
(1
4
5
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5
6
7
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4
5
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5
6
7
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5
7
,
2
1
2
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5
7
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2
1
2
)
(1
5
7
,
2
1
2
)
(1
6
8
,
8
5
6
)
4
Ne
t
R
a
t
e
B
a
s
e
su
m
o
f
t
i
n
e
s
1
-
3
93
6
,
3
7
1
93
3
,
3
0
8
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8
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8
0
1
91
5
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5
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,
4
7
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7
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6
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9
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8
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4
8
3
5
Pr
e
-
T
a
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Ra
t
e
of
Re
t
u
m
lin
e
37
9.2
3
4
%
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4
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3
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3
4
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2
3
4
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4
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3
4
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9.2
3
4
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9.
2
3
4
%
9.2
3
4
%
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3
4
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6
Pr
e
-
T
a
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t
u
m
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Ra
t
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s
e
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o
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2
9
7,2
0
5
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4
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1
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9
0
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0
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6
6
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4
3
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1
9
7
Wh
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l
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s
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l
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Wh
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g
Re
v
e
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Fo
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2
8
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&
Ma
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n
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e
1,
0
6
5
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6
5
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6
5
1,0
6
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6
5
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0
6
5
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5
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6
5
1,0
6
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5
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0
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5
9
De
p
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5
3,0
6
3
3,0
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3
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6
3
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6
3
3,0
7
0
3,0
7
0
3,0
7
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3,0
7
0
3,0
7
0
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7
0
10
Pro
p
e
r
t
y
Ta
x
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s
Pri
o
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De
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b
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(li
n
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1
+
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x
lin
e
38
68
6
68
6
68
6
68
6
68
6
68
6
68
6
68
6
68
6
68
6
68
6
68
6
11
VW
n
d
T
a
x
35
35
35
35
35
35
35
35
35
35
35
35
12
To
t
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l
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R
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R
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6
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11
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9
1
7
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8
9
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8
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4
11
,
7
5
9
11
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7
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5
11
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6
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2
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5
9
9
11
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5
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t
Po
w
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r
Co
s
t
13
NP
C
In
c
r
e
m
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n
t
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l
Sa
v
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Ex
h
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b
i
t
14
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,
0
8
9
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0
8
9
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0
8
9
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0
8
9
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0
8
9
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,
0
8
9
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8
9
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0
8
9
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(1
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0
8
9
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(1
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0
8
9
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(1
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0
8
9
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(1
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0
8
9
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PT
C
Be
n
e
f
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t
14
PT
C
Be
n
e
f
i
t
(7
,
5
3
6
)
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5
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6
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(7
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5
3
6
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(7
,
5
3
6
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(7
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5
3
6
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(7
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5
3
6
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,
5
3
6
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5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
15
PT
C
Be
n
e
f
i
t
in
Ba
s
e
Ra
t
e
s
16
N
e
t
P
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m
o
f
f
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n
e
s
1
4
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n
d
t
5
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5
3
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5
3
6
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5
3
6
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,
5
3
6
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5
3
6
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5
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6
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5
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5
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6
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5
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6
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5
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6
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.
5
3
6
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(7
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5
3
6
)
17
G
r
o
s
s
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p
f
o
r
t
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x
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s
li
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1
6
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(
l
i
n
e
3
5
-
1
)
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,
4
5
7
)
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,
4
5
7
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,
4
5
7
)
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,
4
5
7
)
(2
,
4
5
7
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(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
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(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
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(2
,
4
5
7
)
18
P
T
C
R
e
v
e
n
u
e
R
e
q
u
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r
e
m
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n
t
su
m
o
f
l
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n
e
1
6
a
n
d
1
7
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
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(9
,
9
9
3
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(9
,
9
9
3
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,
9
9
3
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(9
,
9
9
3
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,
9
9
3
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9
9
3
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(9
,
9
9
3
)
19
R
e
v
.
R
e
q
u
i
r
e
m
e
n
t
su
m
o
f
l
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n
e
s
1
2
,
1
3
a
n
d
1
8
99
6
97
2
94
9
83
5
81
2
78
8
68
2
67
7
65
4
54
0
51
7
49
3
Ad
j
u
s
t
m
e
n
t
fo
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
20
PT
C
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
lin
e
18
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
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(9
,
9
9
3
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,
9
9
3
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(9
,
9
9
3
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(9
,
9
9
3
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(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
21
P
e
r
c
e
n
t
a
g
e
i
n
c
l
u
d
e
d
i
n
E
C
A
M
(
1
0
0
%
)
ID
E
C
A
M
S
h
a
r
i
n
g
%
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
e
t
P
T
C
A
f
t
e
r
P
a
s
s
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t
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o
u
g
h
li
n
e
2
0
*
l
i
n
e
2
1
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
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(9
,
9
9
3
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(9
,
9
9
3
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(9
,
9
9
3
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(9
,
9
9
3
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(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
23
NP
C
In
c
r
e
m
e
n
t
a
l
Sa
v
i
n
g
s
lin
e
13
(1
,
0
8
9
)
(1
,
0
8
9
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(1
,
0
8
9
)
(1
,
0
8
9
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(1
,
0
8
9
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(1
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0
8
9
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0
8
9
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0
8
9
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(1
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0
8
9
)
(1
,
0
8
9
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(1
,
0
8
9
)
(1
,
0
8
9
)
24
P
e
r
c
e
n
t
a
g
e
i
n
c
l
u
d
e
d
i
n
E
C
A
M
(
9
0
%
)
ID
E
C
A
M
S
h
a
r
i
n
g
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
25
E
C
A
M
P
a
s
s
-
t
h
r
o
u
g
h
li
n
e
2
3
*
I
i
n
e
2
4
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
(9
8
0
)
26
Re
v
.
R
e
g
t
a
f
t
e
r
E
C
A
M
P
a
s
s
-
1
h
r
o
u
g
h
li
n
e
1
9
-
l
i
n
e
2
2
-
l
i
n
e
2
5
11
,
9
6
9
11
,
9
4
5
11
,
9
2
1
11
,
8
0
8
11
,
7
8
5
11
,
7
6
1
11
,
6
5
5
11
,
6
5
0
11
,
6
2
7
11
,
5
1
3
11
,
4
9
0
11
,
4
6
6
id
a
h
o
All
o
c
a
t
e
d
27
T
o
t
a
l
D
e
f
e
r
r
a
l
-
I
D
S
h
a
r
e
Fo
o
t
n
o
t
e
4
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
28
Ne
t
Cu
s
t
o
m
e
r
Be
n
e
f
i
t
(li
n
e
22
+
lin
e
25
)
*li
n
e
39
+
fin
e
27
De
f
e
r
r
a
l
Ba
l
a
n
c
e
-ID
Sh
a
r
e
29
Be
g
i
n
n
i
n
g
De
f
e
r
r
a
l
Ba
l
a
n
c
e
lin
e
33
of
pre
v
i
o
u
s
mo
n
t
h
7,
2
9
8
7,8
4
0
8,3
8
2
8,9
2
4
9,4
6
7
10
,
0
1
0
10
,
0
7
0
10
,
1
3
1
10
,
1
9
2
10
,
2
5
2
10
,
3
1
3
10
,
3
7
4
30
Mo
n
t
h
l
y
De
f
e
r
r
a
l
lin
e
27
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
66
0
31
De
f
e
r
r
a
l
Co
l
l
e
c
t
i
o
n
Fo
o
t
n
o
t
e
3
(1
2
5
)
(1
2
5
)
(1
2
5
)
(1
2
5
)
(1
2
5
)
(6
0
8
)
(6
0
8
)
(6
0
8
)
(6
0
8
)
(6
0
8
)
(6
0
8
)
(6
0
8
)
32
Ca
r
r
y
i
n
g
Ch
a
r
g
e
(in
29
+
,5
·
(In
30
-
In
31
)
)
*
In
36
6
7
7
8
8
9
9
9
9
9
9
9
33
E
n
d
i
n
g
D
e
f
e
r
r
a
l
B
a
l
a
n
c
e
su
m
o
f
f
i
n
e
s
2
9
-
3
2
7,8
4
0
8,3
8
2
8,9
2
4
9,4
6
7
10
,
0
1
0
10
,
0
7
0
10
,
1
3
1
10
,
1
9
2
10
.
2
5
2
10
,
3
1
3
10
,
3
7
4
10
,
4
3
5
FT
1
e
34
Fe
d
e
r
a
l
/
S
t
a
t
e
Co
m
b
i
n
e
d
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
5
35
Ne
t
to
Gro
s
s
Bu
m
p
up
Fa
c
t
o
r
=
(1
/
(
1
-
t
a
x
ra
t
e
)
)
Ex
h
i
b
i
t
14
,
lin
e
6
36
De
f
e
r
r
e
d
Ba
l
a
n
c
e
Ca
r
r
y
i
n
g
Ch
a
r
g
e
Ex
h
i
b
i
t
12
lin
e
35
37
Pr
e
t
a
x
Re
t
u
r
n
Ex
h
i
b
i
t
14
,
lin
e
4
38
Pr
o
p
e
r
t
y
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
14
39
Id
a
h
o
SG
Fa
c
t
o
r
Ex
h
i
b
i
t
14
,
lin
e
15
40
Id
a
h
o
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S
Fa
c
t
o
r
Ex
h
i
b
i
t
14
,
lin
e
16
O
O
O
Pa
c
i
f
i
C
o
r
p
Id
a
h
o
Pa
g
e
4
of
5
Win
d
Re
p
o
w
e
r
i
n
g
-
Ex
a
m
p
l
e
Mo
n
t
h
l
y
RT
M
De
f
e
r
r
a
l
Ca
l
c
u
l
a
t
i
o
n
Re
v
e
n
u
e
Re
q
u
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m
e
n
t
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h
o
u
s
a
n
d
s
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
20
2
2
Lin
e
No
.
Re
f
e
r
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n
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e
Ja
n
u
a
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Fe
b
r
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a
r
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Ma
r
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h
Ap
r
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y
Ju
n
e
Ju
l
y
Au
g
u
s
t
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p
t
e
m
b
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r
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t
o
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r
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v
e
m
b
e
r
De
c
e
m
b
e
r
To
t
a
l
Co
m
p
a
n
y
Pla
n
t
Re
v
e
n
u
e
Re
q
u
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e
m
e
n
t
1
Ca
p
i
t
a
l
In
v
e
s
t
m
e
n
t
1,1
0
5
,
0
3
3
1,
1
0
5
,
0
3
3
1,1
0
5
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0
3
3
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0
5
,
0
3
3
1,1
0
5
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0
3
3
1,1
0
5
,
0
3
3
1,
1
0
7
,
9
4
4
1,1
0
7
,
9
4
4
1,1
0
7
,
9
4
4
1,1
0
7
,
9
4
4
1,1
0
7
,
9
4
4
1,
1
0
7
,
9
4
4
2
De
p
r
e
c
i
a
t
i
o
n
Re
s
e
r
v
e
(8
0
,
7
6
3
)
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3
,
8
3
4
)
(8
6
,
9
0
4
)
(8
9
,
9
7
4
)
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3
,
0
4
4
)
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6
,
1
1
4
)
(9
9
,
1
9
3
)
(1
0
2
,
2
7
2
)
(1
0
5
,
3
5
2
)
(1
0
8
,
4
3
1
)
(1
1
1
,
5
1
0
)
(1
1
4
,
5
8
9
)
3
Ac
c
u
m
u
l
a
t
e
d
DIT
Ba
l
a
n
c
e
(1
6
8
,
8
5
6
)
(1
6
8
,
8
5
6
)
(1
7
4
,
9
9
8
)
(1
7
4
,
9
9
8
)
(1
7
4
,
9
9
8
)
(1
8
1
,
1
3
9
)
(1
8
1
,
1
3
9
)
(1
8
1
,
1
3
9
)
(1
8
7
,
2
8
1
)
(1
8
7
,
2
8
1
)
(1
8
7
,
2
8
1
)
(1
9
3
,
4
2
2
)
4
Ne
t
Ra
t
e
Ba
s
e
su
m
of
lin
e
s
1-3
85
5
,
4
1
3
85
2
,
3
4
3
84
3
,
1
3
1
84
0
,
0
6
1
83
6
,
9
9
1
82
7
,
7
7
9
82
7
,
6
1
2
82
4
,
5
3
3
81
5
,
3
1
2
81
2
,
2
3
3
80
9
,
1
5
4
79
9
,
9
3
3
5
Pre
-
T
a
x
Ra
t
e
of
Re
t
u
m
lin
e
37
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
9
23
4
%
9.2
3
4
%
9.2
3
4
%
9.
2
3
4
%
9.2
3
4
%
9.2
3
4
%
9.2
3
4
%
6
Pre
-
T
a
x
Re
t
u
m
on
Ra
t
e
Ba
s
e
Fo
o
t
n
o
t
e
1
6,
6
0
6
6,5
8
2
6,5
5
9
6,4
8
8
6,4
6
4
6,4
4
1
6,3
7
0
6,3
6
8
6,3
4
5
6,2
7
4
6,2
5
0
6,2
2
6
7
Wh
o
l
e
s
a
l
e
Wh
e
e
l
i
n
g
Re
v
e
n
u
e
Fo
o
t
n
o
t
e
2
8
Op
e
r
a
t
i
o
n
&
Ma
i
n
t
e
n
a
n
c
e
80
1
80
1
80
1
801
80
1
80
1
80
1
80
1
80
1
80
1
80
1
80
1
9
De
p
r
e
c
i
a
t
i
o
n
Fo
o
t
n
o
t
e
5
3,0
7
0
3,0
7
0
3,0
7
0
3,0
7
0
3,0
7
0
3,0
7
0
3,0
7
9
3,0
7
9
3,0
7
9
3,0
7
9
3,0
7
9
3,0
7
9
10
P
r
o
p
e
r
t
y
T
a
x
e
s
Pr
i
o
r
D
e
c
e
m
b
e
r
(
l
i
n
e
1
+
I
i
n
e
2
)
x
l
i
n
e
3
8
66
4
66
4
66
4
66
4
66
4
66
4
66
4
66
4
66
4
66
4
66
4
66
4
11
VW
a
d
T
a
x
35
35
35
35
35
35
35
35
35
35
35
35
12
To
t
a
l
Pla
n
t
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
su
m
of
lin
e
s
6-1
1
11
,
1
7
6
11
,
1
5
2
11
,
1
2
9
11
,
0
5
8
11
,
0
3
4
11
,
0
1
0
10
,
9
4
9
10
,
9
4
7
10
,
9
2
4
10
,
8
5
3
10
,
8
2
9
10
,
8
0
5
Ne
t
Po
w
e
r
Co
s
t
13
NP
C
In
c
r
e
m
e
n
t
a
l
Sa
v
i
n
g
s
Se
e
Ex
h
i
b
i
t
14
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
PT
C
Be
n
e
f
i
t
14
PT
C
Be
n
e
f
i
t
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
15
PT
C
Be
n
e
f
i
t
in
Ba
s
e
Ra
t
e
s
16
N
e
t
P
T
C
su
m
o
f
f
i
n
e
s
1
4
a
n
d
1
5
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
(7
,
5
3
6
)
17
G
r
o
s
s
-
u
p
f
o
r
t
a
x
e
s
lin
e
1
6
*
(
t
i
n
e
3
5
-
1
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
(2
,
4
5
7
)
18
P
T
C
R
e
v
e
n
u
e
R
e
q
u
i
r
e
m
e
n
t
su
m
o
f
f
i
n
e
1
6
a
n
d
1
7
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
19
R
e
v
.
R
e
q
u
i
r
e
m
e
n
t
su
m
o
f
l
i
n
e
s
1
2
,
1
3
a
n
d
1
8
21
(3
)
(2
7
)
(9
7
)
(1
2
1
)
(1
4
5
)
(2
0
7
)
(2
0
8
)
(2
3
2
)
(3
0
3
)
(3
2
6
)
(3
5
0
)
Ad
j
u
s
t
m
e
n
t
fo
r
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
20
PT
C
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
lin
e
18
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
21
P
e
r
c
e
n
t
a
g
e
i
n
c
l
u
d
e
d
i
n
E
C
A
M
(
1
0
0
%
)
ID
E
C
A
M
S
h
a
r
i
n
g
%
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
e
t
P
T
C
A
l
t
e
r
P
a
s
s
-
t
h
r
o
u
g
h
lin
e
2
0
*
i
i
n
e
2
1
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
.
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
(9
,
9
9
3
)
23
NP
C
la
c
r
e
m
e
n
t
a
l
Sa
v
i
n
g
s
fin
e
13
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
.
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
(1
,
1
6
2
)
24
Pe
r
c
e
n
t
a
g
e
in
c
l
u
d
e
d
in
EC
A
M
(9
0
%
)
ID
EC
A
M
Sh
a
r
i
n
g
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
90
%
25
EC
A
M
Pa
s
s
-
t
h
r
o
u
g
h
lin
e
23
*
lin
e
24
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
(1
,
0
4
6
)
26
Re
v
.
Re
g
t
aft
e
r
EC
A
M
Pa
s
s
4
h
r
o
u
g
h
lin
e
19
-
lin
e
22
-
lin
e
25
11
,
0
6
0
11
,
0
3
6
11
,
0
1
2
10
,
9
4
2
10
,
9
1
8
10
,
8
9
4
10
,
8
3
2
10
,
8
3
1
10
,
8
0
7
10
,
7
3
6
10
,
7
1
3
10
,
6
8
9
Id
a
h
o
All
o
c
a
t
e
d
27
T
o
t
a
l
D
e
f
e
r
r
a
l
-
I
D
S
h
a
r
e
Fo
o
t
n
o
t
e
4
66
4
66
2
66
1
65
7
65
5
65
4
65
0
65
0
64
8
64
4
64
3
64
1
28
Ne
t
Cu
s
t
o
m
e
r
Be
n
e
f
i
t
(li
n
e
22
+
lin
e
25
)
*
lin
e
39
+
lin
e
27
(0
)
(2
)
(3
)
(7
)
(9
)
(1
0
)
(1
4
)
(1
4
)
(1
5
)
(2
0
)
(2
1
)
(2
2
)
De
f
e
r
r
a
l
Ba
l
a
n
c
e
-
ID
Sh
a
r
e
29
Be
g
i
n
n
i
n
g
De
f
e
r
r
a
l
Ba
l
a
n
c
e
lin
e
33
of
pre
v
i
o
u
s
mo
n
t
h
10
,
4
3
5
10
,
4
9
9
10
,
5
6
3
10
,
6
2
5
10
,
6
8
2
10
,
7
3
9
10
,
5
3
2
10
,
3
2
2
10
,
1
1
2
9,
9
0
0
9,6
8
3
9,4
6
5
30
M
o
n
t
h
l
y
D
e
f
e
r
r
a
l
fin
e
2
7
66
4
66
2
66
1
65
7
65
5
65
4
65
0
65
0
64
8
64
4
64
3
64
1
31
De
f
e
r
r
a
l
Co
l
l
e
c
t
i
o
n
Fo
o
t
n
o
t
e
3
(6
0
8
)
(6
0
8
)
(6
0
8
)
(6
0
8
)
(6
0
8
)
(8
7
0
)
(8
7
0
)
(8
7
0
)
(8
7
0
)
(8
7
0
)
(8
7
0
)
(8
7
0
)
32
Ca
r
r
y
i
n
g
Ch
a
r
g
e
(in
29
+
.5
*
(In
30
-
in
31
)
)
*
In
36
9
9
9
9
9
10
9
9
9
9
9
9
33
E
n
d
i
n
g
D
e
f
e
r
r
a
l
B
a
l
a
n
c
e
su
m
o
f
l
i
n
e
s
2
9
-
3
2
10
,
4
9
9
10
,
5
6
3
10
,
6
2
5
10
,
6
8
2
10
,
7
3
9
10
,
5
3
2
10
,
3
2
2
10
,
1
1
2
9,9
0
0
9,
6
8
3
9,4
6
5
9,2
4
6
IT
l
O
34
Fe
d
e
r
a
l
/
S
t
a
t
e
Co
m
b
i
n
e
d
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
lin
e
5
35
Ne
t
to
Gro
s
s
Su
m
p
up
Fa
c
t
o
r
=
(1
/
(
1
-
t
a
x
ra
t
e
)
)
Ex
h
i
b
i
t
14
,
lin
e
6
36
De
f
e
r
r
e
d
Ba
l
a
n
c
e
Ca
r
r
y
i
n
g
Ch
a
r
g
e
Ex
h
i
b
i
t
12
lin
e
35
37
Pr
e
t
a
x
Re
t
u
m
Ex
h
i
b
i
t
14
,
tin
e
4
38
Pr
o
p
e
r
t
y
Ta
x
Ra
t
e
Ex
h
i
b
i
t
14
,
tin
e
14
39
Id
a
h
o
SG
Fa
c
t
o
r
Ex
h
i
b
i
t
14
,
lin
e
15
40
id
a
h
o
GP
S
Fa
c
t
o
r
Ex
h
i
b
i
t
14
,
lin
e
16
o
O
O
O
Pa
c
i
f
i
C
o
r
p
Id
a
h
o
Pa
g
e
5
of
5
Win
d
Re
p
o
w
e
n
n
g
-
Ex
a
m
p
l
e
Mo
n
t
h
l
y
RT
M
De
f
e
r
r
a
l
Ca
l
c
u
l
a
t
i
o
n
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
To
t
a
l
Pl
a
n
t
Re
v
e
n
u
e
Re
q
u
i
r
e
m
e
n
t
(L
i
n
e
s
1
-
12
,
37
)
:
Ex
h
i
b
i
t
13
sh
o
w
s
th
e
ca
l
c
u
l
a
t
i
o
n
of
th
e
RT
M
re
v
e
n
u
e
re
q
u
i
r
e
m
e
n
t
de
f
e
r
r
a
l
de
s
c
r
i
b
e
d
in
my
te
s
t
i
m
o
n
y
.
Th
e
ca
l
c
u
l
a
t
i
o
n
st
a
r
t
s
wi
t
h
to
t
a
l
Co
m
p
a
n
y
am
o
u
n
t
s
on
li
n
e
s
1
-
26
to
ca
l
c
u
l
a
t
e
th
e
Id
a
h
o
sp
e
c
i
f
i
c
am
o
u
n
t
s
on
lin
e
s
27
-
33
.
To
ca
l
c
u
l
a
t
e
th
e
re
t
u
r
n
on
ra
t
e
ba
s
e
as
s
o
c
i
a
t
e
d
wit
h
th
e
wi
n
d
re
p
o
w
e
r
i
n
g
in
v
e
s
t
m
e
n
t
,
ne
t
ra
t
e
ba
s
e
as
s
o
c
i
a
t
e
d
wi
t
h
th
e
re
p
o
w
e
r
e
d
wi
n
d
re
s
o
u
r
c
e
s
is
ca
l
c
u
l
a
t
e
d
on
a
mo
n
t
h
l
y
ba
s
i
s
.
Th
e
ne
t
ra
t
e
ba
s
e
ba
l
a
n
c
e
on
lin
e
4
in
c
l
u
d
e
s
th
e
in
v
e
s
t
m
e
n
t
in
re
p
o
w
e
r
e
d
win
d
re
s
o
u
r
c
e
s
,
alo
n
g
wit
h
th
e
as
s
o
c
i
a
t
e
d
im
p
a
c
t
s
on
th
e
de
p
r
e
c
i
a
t
i
o
n
re
s
e
r
v
e
an
d
ac
c
u
m
u
l
a
t
e
d
DI
T
Ba
l
a
n
c
e
.
Th
e
mo
n
t
h
l
y
be
g
i
n
n
i
n
g
ne
t
ra
t
e
ba
s
e
(t
h
e
fin
a
l
am
o
u
n
t
fr
o
m
th
e
pr
i
o
r
mo
n
t
h
)
is
th
e
n
mu
l
t
i
p
l
i
e
d
by
th
e
pr
e
-
t
a
x
We
i
g
h
t
e
d
Av
e
r
a
g
e
Co
s
t
of
Ca
p
i
t
a
l
("
W
A
C
C
"
)
fr
o
m
th
e
la
s
t
Id
a
h
o
ge
n
e
r
a
l
ra
t
e
ca
s
e
on
li
n
e
5
to
de
t
e
r
m
i
n
e
th
e
Co
m
p
a
n
y
'
s
pr
e
-
t
a
x
re
t
u
r
n
on
ra
t
e
ba
s
e
on
li
n
e
6.
Th
e
ex
a
m
p
l
e
us
e
s
th
e
pr
e
-
t
a
x
WA
C
C
fr
o
m
Ca
s
e
No
.
PA
C
-
E
-
1
5
-
0
9
Th
e
to
t
a
l
pl
a
n
t
re
v
e
n
u
e
re
q
u
i
r
e
m
e
n
t
is
ca
l
c
u
l
a
t
e
d
by
ta
k
i
n
g
th
e
re
t
u
r
n
on
ra
t
e
ba
s
e
sh
o
w
n
on
li
n
e
6
an
d
ad
d
i
n
g
th
e
O&
M
ex
p
e
n
s
e
,
de
p
r
e
c
i
a
t
i
o
n
ex
p
e
n
s
e
,
pr
o
p
e
r
t
y
ta
x
e
s
an
d
wi
n
d
ta
x
on
li
n
e
s
8
-
11
to
de
t
e
r
m
i
n
e
th
e
to
t
a
l
pl
a
n
t
re
v
e
n
u
e
re
q
u
i
r
e
m
e
n
t
on
lin
e
12
.
Wh
o
l
e
s
a
l
e
wh
e
e
l
i
n
g
re
v
e
n
u
e
on
lin
e
7
is
no
t
us
e
d
fo
r
wi
n
d
re
p
o
w
e
r
i
n
g
,
bu
t
is
ne
e
d
e
d
fo
r
a
si
m
i
l
a
r
ca
l
c
u
l
a
t
i
o
n
fo
r
th
e
Ga
t
e
w
a
y
tr
a
n
s
m
i
s
s
i
o
n
an
d
wi
n
d
ex
p
a
n
s
i
o
n
pr
o
j
e
c
t
.
Ne
t
Po
w
e
r
Co
s
t
s
(L
i
n
e
13
)
:
Th
e
to
t
a
l
co
m
p
a
n
y
in
c
r
e
m
e
n
t
a
l
NP
C
sa
v
i
n
g
s
as
s
o
c
i
a
t
e
d
wi
t
h
re
p
o
w
e
r
e
d
wi
n
d
re
s
o
u
r
c
e
s
is
sh
o
w
n
on
li
n
e
13
.
Th
e
in
c
r
e
m
e
n
t
a
l
NP
C
sa
v
i
n
g
s
as
s
o
c
i
a
t
e
d
wit
h
th
e
re
p
o
w
e
r
e
d
wi
n
d
pr
o
j
e
c
t
s
ar
e
mu
l
t
i
p
l
i
e
d
by
ni
n
e
t
y
pe
r
c
e
n
t
on
lin
e
24
to
de
t
e
r
m
i
n
e
th
e
am
o
u
n
t
of
th
e
NP
C
sa
v
i
n
g
s
th
a
t
wi
l
l
be
re
t
u
r
n
e
d
to
cu
s
t
o
m
e
r
s
th
r
o
u
g
h
th
e
sh
a
r
i
n
g
ba
n
d
of
th
e
EC
A
M
.
Th
e
RT
M
is
de
s
i
g
n
e
d
to
pr
o
v
i
d
e
th
e
re
m
a
i
n
i
n
g
te
n
pe
r
c
e
n
t
of
th
e
NP
C
sa
v
i
n
g
s
in
ye
a
r
s
th
a
t
th
e
re
v
e
n
u
e
re
q
u
i
r
e
m
e
n
t
be
n
e
f
i
t
s
ar
e
su
f
f
i
c
i
e
n
t
to
co
v
e
r
th
a
t
am
o
u
n
t
.
Ab
s
e
n
t
th
i
s
ad
j
u
s
t
m
e
n
t
,
cu
s
t
o
m
e
r
s
wo
u
l
d
no
t
ge
t
10
0
pe
r
c
e
n
t
of
th
e
NP
C
as
s
o
c
i
a
t
e
d
wit
h
re
p
o
w
e
r
i
n
g
.
Th
e
ca
l
c
u
l
a
t
i
o
n
of
NP
C
sa
v
i
n
g
s
is
de
s
c
r
i
b
e
d
in
Ex
h
i
b
i
t
14
.
PT
C
Be
n
e
f
i
t
s
(L
i
n
e
s
14
-
2
0
,
34
,
35
)
:
Lin
e
s
14
-
1
8
sh
o
w
th
e
ca
l
c
u
l
a
t
i
o
n
of
th
e
PT
C
be
n
e
f
i
t
s
as
s
o
c
i
a
t
e
d
wit
h
th
e
re
p
o
w
e
r
e
d
win
d
re
s
o
u
r
c
e
s
.
Th
e
ac
t
u
a
l
PT
C
sa
l
e
s
ar
e
gr
o
s
s
e
d
-
u
p
fo
r
ta
x
e
s
us
i
n
g
th
e
ne
t
-
t
o
-
g
r
o
s
s
bu
m
p
-
u
p
fa
c
t
o
r
fr
o
m
th
e
Co
m
p
a
n
y
'
s
la
s
t
ge
n
e
r
a
l
ra
t
e
ca
s
e
(s
h
o
w
n
on
li
n
e
35
)
to
de
r
i
v
e
th
e
PT
C
re
v
e
n
u
e
re
q
u
i
r
e
m
e
n
t
on
li
n
e
18
.
Th
e
ta
x
gr
o
s
s
-
u
p
is
ne
c
e
s
s
a
r
y
fo
r
cu
s
t
o
m
e
r
s
to
ge
t
th
e
fu
l
l
re
v
e
n
u
e
re
q
u
i
r
e
m
e
n
t
be
n
e
f
i
t
of
th
e
PT
C
s
an
d
is
ca
l
c
u
l
a
t
e
d
us
i
n
g
th
e
fe
d
e
r
a
l
an
d
st
a
t
e
co
m
b
i
n
e
d
ta
x
ra
t
e
sh
o
w
n
on
lin
e
34
wh
i
c
h
wa
s
al
s
o
in
c
l
u
d
e
d
in
th
e
la
s
t
ge
n
e
r
a
l
ra
t
e
ca
s
e
.
On
e
hu
n
d
r
e
d
pe
r
c
e
n
t
of
Id
a
h
o
'
s
sh
a
r
e
of
th
e
PT
C
s
ar
e
re
t
u
r
n
e
d
to
cu
s
t
o
m
e
r
s
th
r
o
u
g
h
th
e
EC
A
M
.
De
f
e
r
r
a
l
Ba
l
a
n
c
e
(L
i
n
e
s
19
-
33
)
:
Th
e
Id
a
h
o
sh
a
r
e
of
th
e
ne
t
de
f
e
r
r
a
l
be
g
i
n
s
by
ca
l
c
u
l
a
t
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m
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n
t
on
li
n
e
19
,
wh
i
c
h
is
th
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m
of
To
t
a
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Pla
n
t
Re
v
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q
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i
r
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m
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n
t
on
li
n
e
12
,
NP
C
In
c
r
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m
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n
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a
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Sa
v
i
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g
s
on
li
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13
,
an
d
PT
C
Re
v
e
n
u
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Re
q
u
i
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m
e
n
t
on
li
n
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18
.
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On
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n
d
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d
pe
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EC
A
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pa
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-
t
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on
lin
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22
an
d
nin
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pe
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EC
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pa
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-
t
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on
lin
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25
ar
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on
lin
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26
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a
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'
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a
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of
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To
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De
f
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r
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p
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up
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m
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th
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Re
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li
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26
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be
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f
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fo
u
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d
on
lin
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26
.
If
th
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Re
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q
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m
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li
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26
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(li
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28
)
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(l
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(l
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r
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sh
o
w
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on
li
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32
is
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ra
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lin
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36
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Ex
h
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to
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ap
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ap
p
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mm
o
-a
o
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
O
Rocky Mountain Power
Exhibit 14 Page 1 of 1
Case No.PAC-E-17-06PacifiCorp
O Idaho
Wind Repowering -Capital Structure,Property Tax and Net Power Cost Description
Capital Structure and Property Tax Rate
Capital Structure and Cost from Case Number PAC-E-15-09
Updated with new consolidated tax rate consistent with the new tax law
Effective 1/1/2016
Line Capital Capital Weighted
no.Capital Structure Structure Cost 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-15-09
7 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
Incremental Generation =Wind Plant Generation MWh -Base Wind Plant Generation MWh
Base Wind Plant Generation =Wind Plant Generation MWh/(1 +Project Generation Increase %)
NPC Incremental Savings
=[IncrementalGenHLH × (Monthly Market PriC€HLH -Integration Costs)]
+[IncrementalGenLLH × (Monthly Market PriceLLH -Inf€gTGCÌORÛOSCS)
RTM NPC Benefit =NPC Incremental Savings × ECAM SharingBand
Where:
Incremental Generation =The increase in generation at the windplant due to repoweringProjectGenerationIncrease%=Thepercentage change in energyat the wind plant due torepowering(See Confidential Exhibit 3,page 2 of2)
Incremental GenHLH =The increase in generation at the wind plantdue to repoweringduringheavyloadhoursIncrementalGenLLH=The increase in generation at the windplantdue to repoweringduringhght
load hoursMonthlyMarket PTÍC€HLH =Heavy/oadhourmonthlymarketpriœMonthlyMarketPriC€LLH =Lightloadhourmonthlymarketpriœ
Integration Costs =Wind integration costs from the most recent IRP
RTMNPC Beneßt =The NPCrepoweringbenefit absorbed by the Company in the ECAM as a resultofthesharingband
O