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Home My WebLink About20231129Application.pdf 1407 W. North Temple, Suite 330 Salt Lake City, UT 84116 November 29, 2023 VIA ELECTRONIC DELIVERY Jan Noriyuki Commission Secretary Idaho Public Utilities Commission 11331 W. Chinden Blvd Building 8 Suite 201A Boise, ID 83714 RE: CASE NO. PAC-E-23-24 IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR AUTHORIZATION TO UPDATE THE WIND AND SOLAR INTEGRATION RATE FOR SMALL POWER GENERATION QUALIFYING FACILITIES Attention: Jan Noriyuki Please find for filing Rocky Mountain Power’s Application in the above-referenced matter which includes two attachments. Attachment No.1 is Appendix F, the Flexible Reserve Study from Volume II of the 2023 IRP and Attachment No. 2 is the non-levelized wind and solar integration rates in the format required by Order No. 34966. Workpapers also accompany this application. Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at (801) 220-2313. Very truly yours, Joelle Steward Senior Vice President, Regulation and Customer & Community Solutions RECEIVED 2023 NOVEMBER 29, 2023 2:02PM IDAHO PUBLIC UTILITIES COMMISSION Application of Rocky Mountain Power Page 1 Joe Dallas (ISB# 10330) 825 NE Multnomah St., Suite 2000 Portland, OR 97232 Telephone: (360) 560-1937 Email: joseph.dallas@pacificorp.com Attorney for Rocky Mountain Power BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR AUTHORIZATION TO UPDATE THE WIND INTEGRATION RATE FOR GENERATION UALIFYING FACILITIES ) ) ) ) ) ) CASE NO. PAC-E-23-24 APPLICATION Rocky Mountain Power, a division of PacifiCorp (“the Company”), in accordance with Idaho Code §61-502, §61-503, and RP 052, hereby respectfully submits this application (“Application”) to the Idaho Public Utilities Commission (“Commission”) requesting authorization to modify the wind and solar integration rates applicable to new power purchase agreements (“PPA”). Specifically, purchases by Rocky Mountain Power of electric power from wind-powered qualified facilities, (“QFs”), would drop from the current $1.25 per megawatt-hour (“MWh”) in 2024 dollars to a comparable real-levelized charge of $1.18/MWh, while the solar integration rate would rise from $0.96/MWh in 2024 dollars to a comparable real-levelized charge of $1.40/MWh, applicable to purchases by Rocky Mountain Power of electric power from solar- powered QFs. The charges applicable annually vary consistent with the results identified in the 2023 IRP. These amounts represent the integration costs of wind and solar power to be applied against published avoided cost rates except in those circumstances where the QF developer specifies in the PPA to deliver the QF output to Rocky Mountain Power on a firm hourly schedule. In support of this Application, Rocky Mountain Power states as follows: Application of Rocky Mountain Power Page 2 1. Rocky Mountain Power is a division of PacifiCorp, an Oregon corporation, which provides electric service to retail customers through its Rocky Mountain Power division in the states of Idaho, Utah, and Wyoming. Rocky Mountain Power is a public utility in the state of Idaho and is subject to the Commission’s jurisdiction with respect to its prices and terms of electric service to retail customers in Idaho pursuant to Idaho Code § 61-129. Rocky Mountain Power is authorized to do business in the state of Idaho and provides retail electric service to approximately 88,870 customers in the state. I. BACKGROUND 2. Commission Order No. 298391 stated: “we find that the unique supply characteristics of wind generation and the related integration costs provided a basis for adjustment to the published avoided cost rates, a calculated figure that may be different for each regulated utility.” 3. Pursuant to Order No. 29839 Rocky Mountain Power filed Case No. PAC-E-07-07 on April 23, 2007, requesting approval of a utility-specific wind integration adjustment to the published avoided costs rates. The Commission reviewed the facts and the stipulation entered into by the parties in that case and determined that a utility-specific wind integration cost adjustment to a utility’s published avoided costs, among other adjustments, was appropriate.2 The Commission also ordered the Company to file any changes to its wind integration charge as reflected in subsequent IRPs.3 Subsequently, in Case No. PAC-E-17-11, the Commission 1 In the Matter of the Petition of Idaho Power Company for an Order Temporarily Suspending Idaho Power’s PURPA Obligation to Enter into Contracts to Purchase Energy Generated by Wind-Powered Small Power Production Facilities. Case No. IPC-E-05-22, Order No. 29839 at 8 (August 4, 2005). 2 In the Matter of the Petition of Rocky Mountain Power for an Order Revising Certain Obligations to Enter into Contracts to Purchase Energy Generated by Wind-Powered Small Power Generation Qualified Facilities, Case No. PAC-E-7-07, Final Order No. 30497 at 12 (February 20, 2008). 3 Id. at 13. Application of Rocky Mountain Power Page 3 requested that any updates to the Company’s integration charges be filed after the IRP is acknowledged.4 4. On October 8, 2020, the Company filed, and the Commission later approved, an update to the wind and solar integration rates based on the results of the 2019 IRP Flexible Reserve Study.5 5. On October 31, 2023, the Commission acknowledged the Company’s 2023 Integrated Resource Plan (“IRP”).6 6. In compliance with Order No. 30497, Rocky Mountain Power hereby files this Application to update its wind and solar integration rates that can be deducted from the published avoided cost rates to determine a purchase and sale price established for the duration of the PPA with a QF. This modification to the published avoided cost rates is intended to reflect the cost of integrating wind and solar generation into the Company’s electrical system. These integration rates assure that QFs that deliver less than 100 KW have a predictable rate. In support of this Application the Company includes Attachment No. 1, Appendix F – Flexible Reserve Study from Volume II of the 2023 IRP, and Attachment No. 2. Attachment No. 1 explains in detail the methodology used and the results derived from PacifiCorp’s analysis of wind and solar integration costs. Attachment No. 2 includes the non-levelized wind and solar integration rates in the format required by Order No. 34966.7 4 In the Matter of the Application of Rocky Mountain Power to Revise the Wind Integration Rate and Implement a Solar Integration Rate for Small Power Generation Qualifying Facilities, Case No. PAC-E-17-11, Order No. 33937. 5 In the Matter of the Application of Rocky Mountain Power to Update the Wind and Solar Integration Rate for Small Power Generation Qualifying Facilities, Case No. PAC-E-20-14, Order No. 34966. 6 In the Matter of PacifiCorp’s Application for Acknowledgment of the 2023 Integrated Resource Plan, Case No. PAC-E-23-10, Order No. 35977 (October 31, 2023). 7 In the Matter of the Application of Rocky Mountain Power to Update the Wind and Solar Integration Rate for Small Power Generation Qualifying Facilities, Case No. PAC-E-20-14, Order No. 34966 at p.5. Application of Rocky Mountain Power Page 4 II. 2023 IRP – FLEXIBLE RESERVE STUDY 7. Appendix F of the 2023 IRP summarizes a Flexible Reserve Study (“FRS”) which estimates the regulation reserve required to maintain PacifiCorp’s system reliability and comply with North American Electric Reliability Corporation (“NERC”) reliability standards as well as the incremental cost of this regulation reserve. The FRS also compares PacifiCorp’s overall operating reserve requirements, including both regulation reserve and contingency reserve, to its flexible resource supply over the IRP study period. 8. The FRS is based on PacifiCorp’s actual operational data from January 2018 through December 2019 for load, wind, solar, and Non-Variable Energy Resources (“Non- VERs”). PacifiCorp’s primary analysis, focuses on the variability of load, wind, solar, and Non- VERs during this period. A supplemental analysis discusses how the total variability of PacifiCorp’s system changes with varying levels of load, wind and solar capacity. 9. The methodology in the FRS is similar to that employed in PacifiCorp’s previous regulation reserve requirement analysis in the 2019 IRP used in the current effective integration charges, but has been enhanced in some key ways. First, the historical period was enhanced to capture a larger sample of system conditions. Second, the methodology for extrapolating results for higher renewable resource penetration levels has been modified to better capture the diversity between growing wind and solar portfolios. 10. The estimated regulation reserve amounts determined in the FRS represent the incremental capacity needed in a particular operating hour to ensure compliance with NERC Standard BAL-001-2. The regulation reserve requirement for the combined portfolio is the sum of the individual requirements for load, wind, solar, and Non-VERs, less the reserve “savings” associated with diversity between the different classes, including diversity benefits realized as a Application of Rocky Mountain Power Page 5 result of PacifiCorp’s participation in the EIM operated by the California Independent System Operator Corporation. 11. The FRS produces an hourly forecast of the regulation reserve requirements for each of PacifiCorp’s Balancing Authority Areas that is sufficient to ensure the reliability of the transmission system and compliance with NERC and WECC standards. This regulation reserve forecast covers the combined deviations of the load, wind, solar and Non-VERs on PacifiCorp’s system and varies as a function of the wind and solar capacity on PacifiCorp’s system, as well as forecasted levels of wind, solar, and load. 12. The FRS first estimates the regulation reserve necessary to maintain compliance with NERC Standard BAL-001-2 given a specified portfolio of wind and solar resources. Next the FRS calculates the cost of holding regulation reserve for incremental wind and solar resources. Finally, the FRS compares PacifiCorp’s overall operating reserve requirements over the IRP study period, including both regulation reserve and contingency reserve, to its flexible resource supply. 13. In addition to estimating the regulation reserve based on the specific requirements of NERC Standard BAL-001-2, the FRS also incorporates the current timeline for EIM market processes, as well as EIM resource deviations and flexibility reserve benefits based on actual results. The FRS also includes adjustments to regulation reserve requirements to account for the changing portfolio of solar and wind resources on PacifiCorp’s system and for the diversity of using a single portfolio of regulation reserve resources to cover variations in load, wind, solar, and Non-VERs. Table F.1 summarizes the regulation reserve requirements for the various portfolios considered in this analysis, the 2019 IRP FRS are also included for reference. Application of Rocky Mountain Power Page 6 Table F.1 – Portfolio Regulation Reserve Requirements Wind Solar Regulation Diversity Requirement Case (MW) (MW) (MW) (%) (MW) CY2017 (2019 IRP) 2,750 1,021 994 47% 531 2018-2019 (2021 IRP) 2,745 1,080 1,057 49% 540 14. The integration costs determined from the FRS are summarized in Table F.2 which provides the wind and solar costs on a dollar per megawatt-hour ($/MWh) of generation basis. The results of the 2019 IRP FRS used to set the current integration charges are also included for comparison. Table F.2 – 2023 FRS Flexible Resource Costs as Compared to 2019 Costs, $/MWh 2025-2042 2025-2042 2018-2036 2018-2036 $1.38 $1.59 $1.11 $0.85 15. Based on the results of the FRS from the 2023 IRP, and after adjusting for inflation, the Company respectfully requests that the wind integration rate be decreased from $1.25 to $1.18 per MWh, in 2024 dollars, and the solar integration rate increased from $0.96 to $1.40 per MWh, in 2024 dollars, applicable to wind and solar QFs that qualify for the Company’s published QF rates. III. COMMUNICATIONS Communications regarding this filing should be addressed to: Mark Alder Idaho Regulatory Affairs Manager Rocky Mountain Power 1407 West North Temple, Suite 330 Salt Lake City, Utah 84116 Telephone: (801) 220-2313 Email: mark.alder@pacificorp.com Application of Rocky Mountain Power Page 7 Joe Dallas (ISB# 10330) Senior Attorney Rocky Mountain Power 825 NE Multnomah, Suite 2000 Portland, OR 97232 Telephone: (360) 560-1937 Email: joseph.dallas@pacificorp.com In addition, Rocky Mountain Power requests that all data requests regarding this Application be sent in Microsoft Word to the following: By email (preferred): datarequest@pacificorp.com By regular mail: Data Request Response Center PacifiCorp 825 NE Multnomah St., Suite 2000 Portland, Oregon 97232 Informal questions may be directed to Mark Alder, Idaho Regulatory Affairs Manager at (801) 220-2313. IV. MODIFIED PROCEDURE Rocky Mountain Power believes that a hearing is not necessary to consider the issues presented herein and respectfully requests that this Application be processed under Modified Procedure; i.e., by written submissions rather than by hearing, RP 201. If, however, the Commission determines that a technical hearing is required, the Company stands ready to prepare and present its testimony in such hearing. V. REQUEST FOR RELIEF WHEREFORE, Rocky Mountain Power respectfully requests that the Commission issue an Order: (1) authorizing this Application to be processed under Modified Procedure; (2) approving the wind integration rate of $1.18 per MWh for wind-powered QFs; and (3) approving the solar integration rate of $1.40 per MWh. These rates will be used by the Company for purchase of electric power from wind or solar-powered QFs, which amounts represents the integration costs Application of Rocky Mountain Power Page 8 of wind and solar power, to be applied against avoided cost rates in those circumstances, except where the QF developer agrees in the power purchase agreement with Rocky Mountain Power to schedule and deliver, via a transmission provider, the QF output to Rocky Mountain Power on a firm hourly basis. RESPECTFULLY SUBMITTED this 29th day of November 2023. Rocky Mountain Power By: Joe Dallas (ISB# 10330) 825 NE Multnomah St., Suite 2000 Portland, OR 97232 Telephone: (360) 560-1937 Email: joseph.dallas@pacificorp.com Attorney for Rocky Mountain Power Attachment No. 1 ! !" #"$%$&%'()*+,-./01,2.+34567895:5;<=48>?5@A5:598AB5A9<78?7?5AC;B4D5A>8A>?;68<98=895BE;A5B??E?B7FA;BE7BC77AB5F7B;9;6679B8A>8??7???H::5957AB45?B;<5986>8B8B48B5A9;HB=HBJ47<7:;<7G:;<B47 G895:5;<=5?9;AB5AH5A@B;H?7B47F7B5A5B? 67I5C677?7<K7BH>ELMGD4594<7657>H=;A45?B;<5986>8B8:<5?9H??7>C76;DJ67I5C677?7<K7BH>ELM7?B5F8B7>B47<7@H68B5;A<7?7<K7<7QH5<7>B;Z[[\[]^_X^`TRaT`T]\RbcSW_Y`\dT]eWX]e_^XTSRb`^S]XTS$^`TRaT`T]\VW658C565BE?B8A>8<>?J798H?7B47F7B4;>;6;@E899;HAB?:;<948A@7?5A895IGC;B4B47QH8AB5BE8A>9;?B;:<7?7<K7?48?C77AH=>8B7>:;<B47 G8;=7<8B7?BD;C868A95A@8HB4;<5BE8<78?L?M5AB4737?B7<A 679B<595BE;; M <7@5;AOO895:5;<= 8?BL M8A>895:5;<=37?BL3?8<75AB7<9;AA79B7>CE865F5B7>8F;HAB;:B<8A?F5??5;A89<;?F5??5;A?E?B7F8A>B47BD;?8<77894<7QH5<7>B;9;F=6ED5B4 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J=>:G^UU^S]Th^sg`\tkuvtwmVT[]e^cTUU^X^bS^a^]d^^bR#Z[[Se^cg`^cRbcRS]gR`5AB7<948A@78A><7<7A97C7BD77A7679B<5986@7A7<8B5;A8A>;8>D5B45AB48BJB8A>8<>O O3 OG4BB=?pqqDDDJA7<9J9;Fq=8qB8A>q7658C565BEr B8A>8<>?qO O3 4594C798F77::79B5K7iHA7 NG JO O3 O<7F;K7>B47<7QH5<7F7ABB48B8B678?Br;^bS\X^[^Xh^[a^e^`cR[l[YTbbTbfnX^[WgXS^[kR[]e5?D8?>77F7><7>HA>8ABD5B4:<7QH7A9E<7?=;A?7F7AB?HA>7<OO Jo 8<E;:7<F??7>5A 7658C565BEB8A>8<>?p Attachment No. 1 Page 1 of 34 !"#$%&'$(%)*!)!$%"&)+,&"-./"%!(*&01!(/0/2&$3456678&!# 9:;<=>?@AB=A;<?;-C%$%%!(*)'#/%#D%(!'%1!(/0/2&$34#!)!/"#/(!)%)*!))*%%E?FG?;H;I>?BEJ>I?FHBE@A>>H>G@AEH#/00%$%")$%K'L!)/&"$%%$M%D'$#%"&"1!(/0/2&$34N)%O<JHI?<:PPHBH;EH>:;IQHFAR;:IJ<H=PBHSJH;ET=A;<I:F:;R?PIQH:BUAB:AI:?;>PB?FP?BHEA>IH<@HUH@>VQH:>WA>H<?;AE:P:?BG?GHBAI:?;A@<AIABHE?B<H<PB?FXA;JABT YIQB?JRQ?A<=9:;<=>?@AB=A;<?;-71!(/0/2&$343$/O!$N!"!LN/P?EJ>H>?;?P@?A<=9:;<=>?@AB=A;<?;- ><JB:;R Y- 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ttachment No. 1 Page 16 of 34 !"#$%&'()*$&+,&-.$)+/0*1(+)"2345"#$%&'()*$&+,&-.$)+/0*1(+)4(7(1)0(1)* Attachment No. 1 Page 17 of 34 PACE W ind -Relationship between For-ecast and Er-r-or- 45% 40% 35% _;'.;' ,. ·;:; 30% ro . c._ ro : •' u 'b QJ 25% en ro +-' C: .. QJ ~ 20% QJ a.. ro V) ro ~ 1.5% g LU 1.0% 5% 0% 0% 1.0% 20% 30% 40% 50% 60% 70% 80% 90% Forecast as a Percentage of Capacity Reserves • Reserve Require ment PACW Wind -Relationsh ip between For-ecast and Err-or- 45% 40% 35% _;'.;' -~ 30% 0.. ro u 'b QJ 25% 01 2 C: QJ ~ 20% QJ a.. ro V) ro ~ 1.5% g LU 1.0% 5% 0% Reserves -·= 0% 1.0% 20% 30% 40% 50% 60% 70% 80% 90% Forecast as a Percentage of Capacity • Reserve Requi re m e nt ~ ..... j.:-; !"#$%&'%&($)'*+',-)(*./$0&*(1&2&0(/&0($"3415"#$%&'%&($)'*+',-)(*./$0&*(1&2&0(/&0($" Attachment No. 1 Page 18 of 34 PACE Solar -Re lationship between Forecast and Error 55% 50% 45% .;'.;' -~ 40% a. "' <..J 0 35% Q) en 2 c: 30% ~ Q) ';';j 25% V> "' g 20°/0 UJ 15% 10% 5% Reserves 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Forecast as a Percentage of Capacity • Reserve Requirement PACW Solar -Relationship between Forecast and Error 55% 50% 45% .;'.;' -~ 4 0% a. "' <..J 15 Q) en 2 C: Q) ~ Q) c.. "' V> "' ~ g UJ 35% 30% 25% 20% 15% 10% 5% 0% Reserves .. : 0% 1 0% 20% 30% 40% 50% 60% 70% 80% 90% Forecast as a Percentage of Capacity • Reserve Requirement !"#$%&'())*+,$%)-.)/0%,-123+4+5,2+5,$&673("#$%&'())*+,$%)-.)/0%,-123+4+5,2+5,$&67 Attachment No. 1 Page 19 of 34 PACE No n-VER -Relationsh ip between Forecast and Error ~ ·c; ro o._ ro LJ '15 "' c:n 24% 22% 20% 1 8% 1 6% 1 4% .; .. • ! • • .... _! :: .• :!··, z:. :-··. • --4 •' ·' ! -· .• ! _.-:· :. • ..::' _ .. - 2 C: ~ "' c.. 12% ro 10% V) ro ~ g 8% •• '•. -;JfCJ,\(j/jf~ilM· ; i' •. ·--;,~,·-~.:, -:_jt,; ----·.--.;:.!•'· -~ ...... _,__.-:. ; ..•. ii . ~. LJ.J •. -~..:-"'r., .. , r.· ;..·s" ... ,:•1••i•. , 6% _._·;._:, '_:._:"t:} .. y •• ,._., -· .•.:· • ·:\: •• •• '".s.· .. • 4 o/c I : : ,-~ 0 : : - 2% i-: -· 00/o t:-·- 20% 30% 40% 50% 60% 70% 80% 90% Forecast as a Percentage of Capacity Reserves • Reserve Requirement PACW Non-VER -Relationship between Forecast and Error 24% 22% 20% ~ 18% ·c; ro o._ 16% ro LJ '15 "' c:n 14% 2 C: "' 12% ~ "' c.. ro 10% V) ro ~ g 8% LJ.J 6% 4% 2% 0% 20% 30% 40% 50% 60% 70% 80% 90% Forecast as a Percentage of Capacity Reserves • Reserve Requireme nt !"#$%&'(%)*&+*%',)%$*&,-.,/0&$-(12346"#$%&'(%)*&+*%',)%$*&,-.,/0&$-(1237 Attachment No. 1 Page 20 of 34 PACE Load -Relationship between For-ecast and Er-r-or- 7.0% 6.5% 6.0% 5.5% -0 5.0% "' .3 .:,,:: 4.5% "' a, 0.. 4-0 4.0% a, en .B 3.5% C: a, ~ a, 3.0% 0.. "' V) 2.5% "' ~ g 2.0% LJ.J 1.5% 1 .0% 0.5% 0.0% 30% 40% Forecast as a Percentage of Peak Load Reserves • Reserve Req uire m e nt PACW Load -Relationship between For-ecast and Er-r-or- 7.0% -0 "' .3 .:,,:: "' a, 0.. 4-0 a, en .B C: a, ~ a, 0.. "' V) "' ~ g LJ.J 6.5% 6.0% 5.5% 5.0% 4 .5% 4.0% 3.5% 3.0% 2.5% 2.0% 1.5% 1 .0% 0.5% 0.0% Reserves 30% 40% • Reserve Req uire m e nt .. :- :~. :-: .... •:. .,::)--~-r- :·;-: .-. ·:_· ~ . ·-. . ·- 50% 60% 70% Forecast as a Percentage of Peak Load . :·· .· .. !"#!$%$ &'$"(%'%$) *) "(*+,-./01234566,789:4;,<=>,.9</?/@5.,;A9<?/B/7C/?/D5A7/6/<;B4;,<=>,.9</?/@5.,;A9<E,F,GA;84;,<=>,.9</?/@5.,;A94G/<,7A9097/G,B;H,IJKHIJK097/G,B;HLK"%M N O P* Q"$R OS *Q MT'%R U OU N*UQ M" $ S OP *PQ+9;,. 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Attachment No. 1 Page 31 of 34 !"#$ %&'()*+,-*../ )+,(0123+4567"89:; &4*+ !"<=>9?@AB9CCD;AE?C9DF@GH9C9:BGEIJ>GEG>KG>GLMA>GNIJE?A::A:=>GEG>KG>GEIM>BGEA:9BAJAI>?OPQRPSRTUVWPSXRYRTZ[T\R]S^_Yade^W\`Rb^PUWf_TPS`RSWS^RSgRZ[h[i_`bOPPaPSWf^RPP]hh[Z[WTS`WP_]`ZWPS_MA>GNG:FEF@>IM=@IMFF@G?C9::A:=?G>AI;jIFGF@9FkGG?A:=NA:ANMNEFI>9=GI>H>A:=A:=F@G>N9C?C9:FEI:CA:G9:;lI>>G;MBA:=F@GA>=G:G>9FAI:m@G9EGF@G9K9AC9HCG>GE?I:EGHGDI:;F@9FE@Im:A:F@GJA=M>GEn9:;9BBIM:FEJIGA:EM??CD9JFG> j:9;;AFAI:n9BAJAI>?BM>>G:FCDB9:F>9:EJG>9?I>F>GEG>KGE@GC;A:GAF@G>IJAFEH9C9:BA:=9MF@I>AFD9>G9EFI@GC?NGGFF@G>GLMA>C9:BA:=9MF@I>AFD9>G9nH9EG;I:F@G>GEG>KG:GG;9:;>GC9FAKGGBI:INABEIJF@G Attachment No. 1 Page 32 of 34 !"#$%&'()*&+&,- * . - / ' +0*)+1- *&2 *34)*05)6)+2+708&097 ):;<= !">$%&'()*&+&,- * . - / ' +0*)+1- *&2 *3< *057 ):;<= Attachment No. 1 Page 33 of 34 ............... .. ····•····· .......... . ···••·"·••"··· ····•······•·····+·· ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ - •... / - ........ ····•···•·+-·····•·····• ........ .+•····•·····•····· .~·····+·•···•······•····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`%(&%1),)%#& #%'%#2%#%9*#%"%&'!&-%#' '*/),+%#)\()'&#%%0.%-%2*%'')(&%10&-'-,& )10&-&-%1/1'%')/!#&-%#-)*#'()&%"&%1&-'%183 Attachment No. 1 Page 34 of 34 Attachment No. 2 Table 1. Wind Integration Charges Non‐Levelized Rates Levelized Rates Year $/MWh Contract Length 2024 2025 2026 2027 2028 2029 2024 2.03 1 $2.03 $5.64 $3.51 $2.26 $0.45 $0.36 2025 5.64 2 $3.76 $4.61 $2.91 $1.39 $0.41 $0.31 2026 3.51 3 $3.68 $3.89 $2.15 $1.07 $0.36 $0.30 2027 2.26 4 $3.37 $3.13 $1.76 $0.89 $0.34 $0.28 2028 0.45 5 $2.87 $2.66 $1.50 $0.79 $0.32 $0.26 2029 0.36 6 $2.53 $2.33 $1.33 $0.71 $0.30 $0.24 2030 0.27 7 $2.28 $2.10 $1.21 $0.64 $0.28 $0.24 2031 0.27 8 $2.09 $1.92 $1.11 $0.60 $0.28 $0.26 2032 0.21 9 $1.94 $1.78 $1.03 $0.57 $0.28 $0.25 2033 0.14 10 $1.81 $1.66 $0.98 $0.56 $0.28 $0.26 2034 0.14 11 $1.71 $1.58 $0.94 $0.54 $0.28 $0.26 2035 0.26 12 $1.63 $1.52 $0.90 $0.53 $0.29 $0.27 2036 0.39 13 $1.58 $1.46 $0.87 $0.52 $0.29 $0.29 2037 0.24 14 $1.52 $1.41 $0.85 $0.51 $0.30 $0.31 2038 0.29 15 $1.48 $1.37 $0.83 $0.52 $0.32 $0.33 2039 0.34 16 $1.44 $1.34 $0.83 $0.53 $0.34 $0.34 2040 0.36 17 $1.41 $1.32 $0.83 $0.54 $0.36 $0.36 2041 0.67 18 $1.39 $1.30 $0.83 $0.54 $0.37 $0.37 2042 0.81 19 $1.37 $1.29 $0.83 $0.55 $0.38 $0.39 2043 0.83 20 $1.36 $1.28 $0.83 $0.56 $0.39 $0.40 2044 0.84 21 2045 0.86 22 2046 0.88 23 2047 0.90 24 2048 0.91 25 Online Year Attachment No. 2 Page 1 of 2 Table 2. Solar Integration Charges Non‐Levelized Rates Levelized Rates Year $/MWh Contract Length 2024 2025 2026 2027 2028 2029 2024 1.92 1 $1.92 $3.85 $4.80 $3.48 $0.64 $0.67 2025 3.85 2 $2.85 $4.30 $4.17 $2.12 $0.65 $0.72 2026 4.80 3 $3.45 $4.05 $3.08 $1.67 $0.69 $0.71 2027 3.48 4 $3.46 $3.29 $2.54 $1.47 $0.69 $0.71 2028 0.64 5 $2.98 $2.85 $2.24 $1.34 $0.70 $0.67 2029 0.67 6 $2.66 $2.56 $2.03 $1.26 $0.67 $0.64 2030 0.77 7 $2.45 $2.35 $1.88 $1.17 $0.64 $0.63 2031 0.70 8 $2.28 $2.20 $1.75 $1.10 $0.63 $0.65 2032 0.72 9 $2.16 $2.06 $1.64 $1.06 $0.65 $0.63 2033 0.46 10 $2.04 $1.95 $1.57 $1.04 $0.63 $0.62 2034 0.43 11 $1.94 $1.87 $1.53 $1.00 $0.62 $0.62 2035 0.58 12 $1.87 $1.81 $1.47 $0.98 $0.62 $0.62 2036 0.81 13 $1.82 $1.75 $1.42 $0.96 $0.63 $0.65 2037 0.45 14 $1.77 $1.70 $1.39 $0.95 $0.65 $0.68 2038 0.49 15 $1.72 $1.65 $1.36 $0.96 $0.67 $0.70 2039 0.59 16 $1.68 $1.62 $1.36 $0.97 $0.69 $0.72 2040 0.70 17 $1.65 $1.61 $1.35 $0.98 $0.71 $0.74 2041 1.16 18 $1.64 $1.60 $1.35 $0.99 $0.73 $0.76 2042 1.30 19 $1.63 $1.59 $1.35 $1.00 $0.75 $0.78 2043 1.32 20 $1.62 $1.59 $1.35 $1.01 $0.76 $0.79 2044 1.35 21 2045 1.38 22 2046 1.40 23 2047 1.43 24 2048 1.46 25 Online Year Attachment No. 2 Page 2 of 2