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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 O 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 O Page 1 of 2 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 O O Page 2 of 2 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. O Page 1 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 O Page 2 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 O Page 3 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 O Page 4 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 O Page 5 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 O Page 6 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 $1.10 billion. UPDATED ECONOMIC ANALYSIS 19.The Project's economic analysis was updated to reflect more current assumptions including:(1)cost estimates consistent with findings from technical review studies cost-and- performance assumptions described above;(2)current price-policy scenario assumptions, including more current natural gas and CO2 prices;and (3)recent changes in the federal tax rate for corporations. 20.In the updated analysis the Company applied PTC benefits on a nominal basis rather than on a levelized basis.This approach better reflects how the federal PTC benefits for the repowered assets will flow through to customers and aligns the treatment of federal PTC benefits O Page 7 in the system modeling results extending out through 2036 with the nominal revenue requirement results extendingout through 2050. 21.Table 1 summarizes the PVRR(d)results for each wind facilitywithin the scope of the wind repowering project when applying medium natural gas and medium CO2 price-policy assumptions.The PVRR(d)between cases with and without wind repowering are shown for each wind facility based on system modeling results from the SO model and for PaR,before accounting for the substantial increase in incremental energy beyond the 2036 time frame.When applying medium natural gas and medium CO2 price-policy assumptions,benefits from repowering the Leaning Juniper wind facility are equal to costs.All other wind facilities are projected to deliver net benefits. Table 1 -Project-by-ProjectSO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Medium Natural Gas And Medium CO2 Price-Policy i sssumptions ($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)($189) O Page 8 22.Table 2 summarizes the PVRR(d)results for each wind facility within the scope of the wind repowering project when applying low natural gas and zero CO2 price-policy assumptions. The PVRR(d)between cases with and without wind repowering are shown for each wind facility based on system modeling results from the SO model and for PaR.before accounting for the substantial increase in incremental energy beyond the 2036 time frame.When applying low natural gas and zero CO2 price-policy assumptions,costs from repowering the Leaning Juniper wind facility are slightlyhigher than the benefits.All other wind facilities are projected to deliver net benefits. Table 2 -Project-by-ProjectSO Model and PaR PVRR(d) (Benefit)/Cost of Wind Repowering with Low Natural Gas and Zero CO2 Price- Policy Assumptions ($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)($156) 23.Table 3 summarizes the PVRR(d)results for each wind facility calculated off of the change in annual nominal revenue requirement through 2050 for both price-policy scenarios. Page 9 Unlike the results summarized in Tables 1 and 2,these results account for the substantial increase in incremental energy beyond the 2036 time frame.Each of the wind facilities within the scope of the proposed repowering project show net benefits with repowering under the medium natural gas and medium CO2 price-policy scenario and all facilities show net benefits under the low natural gas and zero CO2 price-policy scenario,except for the Leaning Juniper wind facility,where the benefits are equal to the costs. Table 3 -Project-by-ProjectNominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind Repowering ($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 Page 10 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 $16/MWh 25.Table 5 summarizes the updated PVRR(d)results for each price-policy scenario for the full scope of the wind repowering project.The PVRR(d)between cases with and without the repowering project,are shown for the SO model and for PaR,which was used to calculate both the stochastic-mean PVRR(d)and the risk-adjusted PVRR(d). O Page 11 Table 5 -Updated SO Model and PaR PVRR(d) (Benefit)/Cost of the Wind Repowering Projects ($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$6 million Page 12 for every dollar assigned to the incremental RECs that will be generated from the repowered facilities through 2036.Quantifying the potential upside associated with incremental REC revenues is intended to simply communicate that the net benefits from the repowering project could improve if the incremental RECs can be monetized in the market. 28.The CO2 price assumptions used in the updated economic analysis were inadvertently modeled in 2012 real dollars instead of nominal dollars.Consequently,the PVRR(d)net benefits in the six price-policy scenariosthat use medium and high CO2 price assumptions are conservative. 29.Table 6 summarizes the updated PVRR(d)results for each price-policy scenario calculated using the change in annual nominal revenue requirement through 2050. Table 6 -Updated Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of he Wind Repowering Proj3ct ($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 Page 13 medium natural-gas prices and medium CO2 prices,the PVRR(d)benefits of the wind repowering project are $273 million.While changes in federal tax law have reduced net benefits relativeto the economic analysis from the Application,the wind repowering project continues to provide significant customer benefits in all price-policy scenarios.The updated economic analysis reconfirms that upside benefits outweigh downside risks. ESTIMATED RATE IMPACT 31.Provided as attachments to this compliance filing are updated Exhibit Nos.12-14 showing the estimated Idaho revenue requirement revised with the updated economic analysis incorporatingthe changes described above.The exhibits are in the same format as the Application, and calculate the monthly and annual revenue requirements and the overall impact of the wind repowering projects that would be reflected in rates,assuming operation of the RTM. 32.These exhibits include changes in Idaho's allocated share of the updated repoweringOprojects'wind construction cost,return,depreciation,PTCs,taxes,and operating costs and benefits.The updated net power cost changes associated with an updated load forecast,system dispatch and revised wind generation projections have been included in the Energy Cost Adjustment Mechanism ("ECAM")pass-through calculation.Table 7 summarizes the estimated repowering revenue requirement found in the updated exhibits.It shows that the repowering project now reflects rate benefits to customers beginning in 2022.As a result of the cap proposed for the RTM in this proceeding,customers would see no net change in rates for the repowering project for costs through 2021,absenta general rate case. O Page 14 Table 7 Repowering Estimated Revenue Requirement Cost (Benefit)$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 O Page 15 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 Page 16 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 O O O O Pa c i f i C o r p id a h o Win d Re p o w e r i n g - Ex a m p l e An n u a l 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 (a ) (b ) (c ) (d ) (e) (f) (g ) (h ) (i) (j) (k ) (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 e r i n q 40 2 1 Re p o w e r i n g 50 2 2 Re p o w e r i n g Re f e r e n c e Co pb a n y Fa c t o r Fa c t o r % Alld d Co an y Fa c t o r Fa c t o r % Alld d a t e d Co an y Fa c t o r Fa c t o r % All e ed Co an y Fa c t o r Fa c t o r % Al d 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 Fo o t n o t 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 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 . En e 16 O O O Pa c i f i C o r p id a h o Pa g e 3 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 1 20 2 1 20 2 1 20 2 1 20 2 1 20 2 1 20 2 1 20 2 1 20 2 1 20 2 1 20 2 1 20 2 1 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 l n v e s t m e n t 1,1 0 2 , 6 0 7 1,1 0 2 , 6 0 7 1, 1 0 2 , 6 0 7 1,1 0 2 , 6 0 7 1,1 0 2 , 6 0 7 1,1 0 2 , 6 0 7 1.1 0 5 , 0 3 3 1, 1 0 5 , 0 3 3 1, 1 0 5 , 0 3 3 1,1 0 5 , 0 3 3 1,1 0 5 , 0 3 3 1,1 0 5 , 0 3 3 2 De p r e c i a t i o n Re s e r v e (4 3 , 9 5 7 ) (4 7 , 0 2 0 ) (5 0 , 0 8 3 ) (5 3 , 1 4 6 ) (5 6 , 2 0 9 ) (5 9 . 2 7 2 ) (6 2 , 3 4 2 ) (6 5 , 4 1 3 ) (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 u l a t e d DIT Ba l a n c e (1 2 2 , 2 7 9 ) (1 2 2 , 2 7 9 ) (1 3 3 , 9 2 3 ) (1 3 3 , 9 2 3 ) (1 3 3 , 9 2 3 ) (1 4 5 , 5 6 7 ) (1 4 5 , 5 6 7 ) (1 4 5 , 5 6 7 ) (1 5 7 , 2 1 2 ) (1 5 7 , 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 91 8 , 8 0 1 91 5 , 5 3 8 91 2 , 4 7 5 89 7 , 7 6 7 89 7 , 1 2 3 89 4 , 0 5 3 87 9 , 3 3 8 87 6 , 2 6 8 87 3 , 1 9 8 85 8 , 4 8 3 5 Pr e - 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 ¾ 9. 2 3 4 % 9.2 3 4 % 9.2 3 4 % 6 Pr e - T a x Re t u m on Ra t e Ba s e Fo o t n o t e 1 7,2 2 9 7,2 0 5 7,1 8 2 7,0 6 9 7,0 4 5 7,0 2 1 6, 9 0 8 6,9 0 3 6.8 8 0 6,7 6 6 6,7 4 3 6,7 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 0p e r a t i o n & Ma i n t e n a n c e 1, 0 6 5 1,0 6 5 1,0 6 5 1,0 6 5 1,0 6 5 1, 0 6 5 1,0 6 5 1,0 6 5 1,0 6 5 1,0 6 5 1, 0 6 5 1,0 6 5 9 De p r e c i a t i o n Fo o t n o t e 5 3,0 6 3 3,0 6 3 3,0 6 3 3,0 6 3 3,0 6 3 3,0 6 3 3,0 7 0 3,0 7 0 3,0 7 0 3,0 7 0 3,0 7 0 3,0 7 0 10 Pro 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 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 a l P l a n t 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 s 6 - 1 1 12 , 0 7 7 12 , 0 5 4 12 , 0 3 0 11 . 9 1 7 11 , 8 9 4 11 , 8 7 0 11 , 7 6 4 11 , 7 5 9 11 . 7 3 5 11 , 6 2 2 11 , 5 9 9 11 , 5 7 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 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) 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 t 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 li n e 1 6 * ( l 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 l 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 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 ) (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 f t e r P a s s - t h r 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 ) (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 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 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (1 , 0 8 9 ) (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 GP 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 i r e m e n t $-T 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 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 1,1 0 5 , 0 3 3 1, 1 0 5 , 0 3 3 1,1 0 5 , 0 3 3 1,1 0 5 , 0 3 3 1,1 0 5 , 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 ) (8 3 , 8 3 4 ) (8 6 , 9 0 4 ) (8 9 , 9 7 4 ) (9 3 , 0 4 4 ) (9 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 i n g th e to t a l re p o w e r i n g pr o j e c t re v e n u e re q u i r e m e n t on li n e 19 , wh i c h is th e su m of To t a l Pla n t Re v e n u e Re q u i r e m e n t on li n e 12 , NP C In c r e m e n t a l Sa v i n g s on li n e 13 , an d 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 On e hu n d r e a d pe r c e n t EC A M pa s s - t h r o u g h on lin e 22 an d nin e t y pe r c e n t EC A M pa s s - t h r o u g h on lin e 25 ar e su b t r a c t e d to pr o v i d e th e Re v e n u e Re q u i r e m e n t af t e r EC A M Pa s s - t h r o u g h on lin e 26 . Id a h o ' s sh a r e of th e To t a l De f e r r a l is de p e n d e n t up o n th e am o u n t of re v e n u e re q u i r e m e n t co s t or be n e f i t th a t is de t e r m i n e d in a pa r t i c u l a r ye a r . If th e Re v e n u e Re q u i r e m e n t aft e r EC A M Pa s s - t h r o u g h fo r an y ye a r on li n e 26 is ne g a t i v e , wh i c h me a n s th a t th e re p o w e r i n g pr o j e c t pr o v i d e s a re v e n u e re q u i r e m e n t be n e f i t gr e a t e r th a n th e be n e f i t be i n g pa s s e d th r o u g h th e EC A M , th e n th a t ye a r ' s de f e r r a l is eq u a l to th e ad d i t i o n a l be n e f i t fo u n d on lin e 26 . If th e Re v e n u e Re q u i r e m e n t af t e r EC A M Pa s s - t h r o u g h fo r an y ye a r on li n e 26 is po s i t i v e , 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 , af t e r ta k i n g in t o ac c o u n t th e wi n d re p o w e r i n g be n e f i t s th a t wi l l flo w th r o u g h th e Co m p a n y ' s EC A M , it wi l 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 . T h e Ne t Cu s t o m e r Be n e f i t (li n e 28 ) is th e su m of th e EC A M Pa s s - t h r o u g h (l i n e 22 an d li n e 25 ) an d th e To t a l De f e r r a l - Id a h o Sh a r e (l i n e 27 ) . Th e ca r r y i n g ch a r g e , sh o w n on li n e 32 is ca l c u l a t e d us i n g th e Co m m i s s i o n - a u t h o r i z e d ra t e on lin e 36 an d is co n s i s t e n t wit h th e ca l c u l a t i o n s us e d in th e Co m p a n y ' s ot h e r me c h a n i s m s su c h as th e EC A M . As de s c r i b e d ea r l i e r , ea c h mo n t h th e to t a l - C o m p a n y RT M re v e n u e re q u i r e m e n t wi l l be ca l c u l a t e d as il l u s t r a t e d on Ex h i b i t 13 to al i g n wi t h th e re s o u r c e s in c l u d e d in th e EC A M . On c e pe r ye a r on a ca l e n d a r - y e a r ba s i s , th e Co m p a n y wi l l su m th e mo n t h l y RT M re v e n u e re q u i r e m e n t en t r i e s to pr e p a r e th e an n u a l RT M ap p l i c a t i o n fo r fi l i n g wit h th e Co m m i s s i o n on Ap r i l 1, wi t h an in t e r i m ra t e ef f e c t i v e da t e th a t co r r e s p o n d s wit h th e EC A M ap p l i c a t i o n , Ju n e 1. 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