Utah Compressed Air Energy Storage (CAES) Project Phase 1 Economic Evaluation using PLEXOS

Transcription

1 Utah Compressed Air Energy Storage () Project Phase 1 Economic Evaluation using PLEXOS Tao Guo, Ph.D., Regional Director, WEST Coast - USA Guangjuan Liu, Ph.D., Senior Consultant Xiaolong Wang, Consultant Yannick Degeilh, Ph.D., Consultant Energy Exemplar, LLC 3013 Douglas Blvd, Suite 120 Roseville, CA U.S.A. Prepared for City of Burbank Water and Power 164 W. Magnolia Blvd. Burbank, CA Schulte Associates LLC 2236 Coley Forest Place Raleigh, NC P a g e

2 List of Acronyms ANL Argonne National Laboratory AS PSH Adjustable Speed Pumped-storage Hydro Generator AS Ancillary Services BA Balancing Area BAA Balancing Authority Area BPA Bonneville Power Administration BWP City of Burbank Water and Power Compressed Air Energy Storage CAISO California Independent System Operator COI California-Oregon Interface DA Day-Ahead DOE US Department of Energy FS PSH Fixed Speed Pumped-storage Hydro Generator GWh Gigawatt-hours HA Hour-Ahead LTPP Long Term Procurement Plan NREL National Renewable Energy Laboratory OPF Optimal Power Flow PACW Pacific Corps West PNNL Pacific Northwest National Laboratory PSH Pumped-storage Hydro Generator RPS Renewable Portfolio Standards RT Real Time SCED Security Constrained Economic Dispatch SCUC Security Constrained Unit Commitment TEPPC Transmission Expansion Planning and Policy Committee WI Western Interconnection WECC Western Electricity Coordinating Council WWSIS Western Wind and Solar Integration Study 2 P a g e

3 Executive Summary Energy Exemplar was engaged by Schulte Associates LLC, consultant for the City of Burbank Water and Power (BWP), for the economic evaluation of the Utah Project using PLEXOS, an integrated power market simulation software suite. The Utah Project Phase 1 is proposed to be a 300 MW generation facility located at Delta, Utah and connected to the Intermountain Power Project (IPP) substation. This project has transmission access to Southern California through the DC-Tie from the Intermountain substation to the Adelanto substation close to the Los Angeles Basin. Phase I is an initial effort leading to a larger, 1200 MW /renewable energy combination project to follow. In order to capture the benefit of this Utah project in detail, a WECC database with the nodal transmission representation was prepared and configured to be as close to reality as possible. The WECC system is simulated for years 2020 to Assumptions The database prepared for this study was originally from the WECC TEPPC 2024 Common Case database version [1]. It has been converted to a PLEXOS database and further updated with California-specific assumptions, and renewable generation profiles and flexibility reserve requirements. The TEPPC 2024 database covers the entire footprint of the Western Interconnection (WI), including the provinces of British Columbia and Alberta in Canada, and Comision Federal de Electricidad (CFE) in northern Mexico. The additional assumption updates include California low frequency modeling. In the California transmission operation, certain low frequency reliability requirements are modeled for BANC, TID, SCE, SDGE, and IID. 25% of the area loads are covered by the local generations with moving mass such as thermal or hydro generators. Renewable Generation Profiles. The simulations are performed at the hourly interval. The hour-ahead wind and solar generation profile forecasts are derivated from the 5-minute actual wind and solar generation profiles. The 5- minute actual wind and solar generation profiles in year 2024 were received from NREL [6] based on year 2006 for the entire WECC footprint. The one-hour persistency forecast technique is used to generate the hour-ahead wind and solar generation profiles. The solar generators include the solar generators with and without the tracking system. Regional loads. The Hour-Ahead (HA) regional load profiles in year 2020 were received from Pacific Northwest National Laboratory (PNNL) for the WECC VGS 1 There was no release note published for TEPPC 2024 Common Case version P a g e

4 study [5]. The load profiles in year 2020 were updated for year 2024 for the given annual peaks and load energies using the PLEXOS time series build function. Contingency, Flexibility and Regulation Reserves. The contingency, flexibility and regulation reserve requirements were generated based on the 5-minute actual net loads and the HA net loads in BAAs (a BAA net load is the BAA load less the solar and wind generation in the BAA). Modeling Approach and Scope The study is performed using the PLEXOS Energy-Ancillary Service-DC-OPF cooptimization capability. The simulations are performed for each of the years 2022 to 2025 for the cases without and with the Utah project. All cases included the existing, 1900 MW IPP coal plant in operation. Results and Findings The findings of this study are summarized below. All the results mentioned here are based on the annual measurement from the simulations for years 2020 to The cost and revenue values are measured based on real, 2014 US dollars including real escalation to the year shown, but excluding general inflation. WECC Production Cost The WECC total production cost saving by year due to the Utah project, including the reserve provision shortfall cost reductions (i.e., ancillary services ), are listed in the following chart. In addition to reserve provisions, production costs include fuel, variable operating and maintenance (O&M) costs, startup costs, and carbon emissions (CO2) costs for resources in and serving California. 35,000 30,000 25,000 20,000 15,000 10,000 5,000 WECC Total Production Cost Savings in 000$ due to Utah Project (Including Reserve Shortfall Cost Reduction) - 4 P a g e Production Cost Savings

5 It is noticed that, when the renewable energies reach 20% in WECC and 37% in California (including the OOS renewables) in year 2023, the WECC production cost savings due to the Utah project sharply increase to nearly 20 million dollars. This step change is not due to a year-to-year discontinuity in Plexos model input assumptions. Instead, it appears to represent a tipping point inflection in the WECC system s needs for storage as the California RPS approaches 38% to 40%. Utah Project Operation Performance Utah Project earns energy arbitrage revenue and AS revenues. The following charts display the Utah project operation, operating costs, energy and AS revenues, and net operating revenues. 1,400 1,200 1, Generation and Total Reserve Provisions (GWh) by Year Generation Reserve Provision 5 P a g e

6 Operating Cost (000$) by Year 25,000 20,000 15,000 10,000 5, Generation Cost Pumping Cost Operating Revenue (000$) by Year 25,000 20,000 15,000 10,000 5, Energy Revenue AS Revenue 6 P a g e

7 Net Operating Revenue (000$) by Year 12,000 10,000 8,000 6,000 4,000 2, Net Revenue The Utah project net operating revenue is calculated as Net Revenue = Energy Revenue (LMP x Generation) + Reserve Revenue (Reserve Shadow Price x Reserve Provision) Fuel and VO&M Cost Pumping Cost (LMP x Pumping Load) Usually, the net revenue represents the profit of the project that is operated as an Independent Power Producer (IPP) in a power market. One can notice that the net revenue increases from 3 million dollars in year 2020 to 11 million dollars in year Size of the Storage Cavern Thourgh the storage size of the Utah Project is defined as 7.2 GWh, the max compressing energy is 0.54 GWh the represents nearly 2 consecutive hours full capacity (300 MW) compressing; the max discharging energy is 1.22GWh that represents nearly 4 consecutive hours full capacity (300 MW) discharging. Impact on Other Generators The following table shows the generation changes in WECC by generator type due to the Utah project. The following can be observed. 1. With the Utah project, the Coal generation ( COAL in the table) in WECC is reduced with the Utah project in years 2020 and 2021, but increased from year 2022 to year P a g e

8 2. With the Utah Project, the CC and CT generation 2 ( CC and CT in the table) in WECC is increased in years 2020 and 2021, but reduced from year 2022 to year From the observation point 1, the CO2 production in WECC is reduced in years 2020 and 2021 but increased in years 2022 to With the renewable generation increase from year 2020 to year 2025 and due to the Utah project, the activities of the pumped storage generators ( PSH in the table) and the energy storage generators ( ES in the table) are increased. The Utah project shares the reserve provisions from the PSH and ES facilities so that the PSH and ES facilities can generate more energy. 2 In the WECC TEPPC database, the CT generator category includes co-generation facilities. 8 P a g e

9 WECC Generation in GWh by Generator Type Generator Type (- ) (- ) (- ) (- ) (- ) (- ) - 84 (84) (109) (124) (172) (208) (233) Coal 234, , , , , ,159 (276) 232, ,360 (364) 232, ,552 (93) 231, ,208 (542) Hydro 239, ,605 (31) 239, ,591 (2) 239, , , , , ,563 (32) 239, ,580 2 Nuclear 56,561 56,561-56,561 56,561-56,561 56,561 (0) 56,561 56,561 (0) 56,561 56,561 (0) 56,561 56,561 (0) Others 5,328 5,381 (52) 5,307 5,358 (51) 5,267 5,310 (42) 5,296 5,313 (17) 5,311 5,332 (22) 5,354 5,379 (25) ST 2,266 2,317 (51) 2,343 2, ,330 2,351 (22) 2,359 2, ,426 2,466 (40) 2,478 2,502 (23) Bio 18,351 18,414 (63) 18,300 18,349 (49) 18,197 18,236 (38) 18,120 18,166 (46) 18,018 18,083 (65) 17,961 18,000 (39) CC 253, , , ,505 (403) 253, , , , , , , , CT 35,663 35,756 (93) 36,937 36, ,563 37,807 (244) 39,104 39, ,412 40, ,698 41, DR-EE 3,099 3,099-3,409 3,409-3,750 3,750-4,125 4,125-4,537 4,537-4,990 4,990 - ES 1,387 1,449 (62) 1,449 1,502 (53) 1,504 1,552 (48) 1,542 1,589 (47) 1,587 1,616 (29) 1,603 1,645 (42) Geo 27,222 27,222 (0) 27,211 27, ,199 27,200 (1) 27,187 27,188 (2) 27,183 27,183 (0) 27,172 27,179 (7) Small Hydro 4,278 4,278-4,278 4,278-4,278 4,278-4,278 4,278-4,278 4,278-4,278 4,278 - PSH 3,846 4,003 (158) 3,972 4,108 (136) 3,983 4,137 (155) 4,056 4,214 (157) 4,122 4,256 (134) 4,196 4,347 (151) PV-BTM 15,677 15,677-17,145 17,145-18,613 18,613-20,081 20,081-21,549 21,549-23,017 23,017 - Solar 40,031 40,031-43,780 43,780 (0) 47,527 47,527 (0) 51,268 51, ,001 55,002 (0) 58,722 58,723 (1) Wind 60,083 60,083-65,709 65,709-71,336 71,336-76,962 76,962-82,583 82,588 (5) 88,208 88,213 (4) Total 1,001,362 1,001,699 (337) 1,013,456 1,013,779 (323) 1,025,550 1,025,898 (347) 1,037,842 1,038,236 (394) 1,050,292 1,050,661 (369) 1,062,860 1,063,282 (422) The following table shows the generation changes in California by generator type due to the Utah project. The followings can be observed. 1. With the Utah project, the Coal generation ( COAL in the table) in California is increased slightly in years 2020 and 2025; 9 P a g e

10 2. With the Utah Project, the CC and CT generation 3 ( CC and CT in the table) in California is increased in years 2020 and 2021, but reduced from year 2022 to year California Net Import reduced gradually from year 2020 to year 2025 due to the renewable generation increases in California. However, with the Utah Project, the California net import is reduced in year 2020 and 2021 but increased in years 2022 to 2025 as opposed to the cases without the Utah Project. 4. With the renewable generation increase from year 2020 to year 2025 and due to the Utah project, the activities of the pumped storage generators ( PSH in the table) and the energy storage generators ( ES in the table) are increased. The Utah project shares the reserve provisions from the PSH and ES facilities so that the PSH and ES facilities can generate more energy. Combining the observations of points 2 and 3, the CO2 production in California is increased in year 2020 and 2021 and is reduced in years 2022 to That is opposite to the trend of the CO2 production in WECC. These trends go in opposite directions over time because as load increases gradually and renewables increase over the study period, higher-cost natural gas-fired generation in California (compared to elselwhere in WECC) is at the margin more often later in the planning period. As a result, natural gas-fired generation in California is more likely to be offset by generation during the latter part of the study period. 3 In the WECC TEPPC database, the CT generator category includes co-generation facilities. 10 P a g e

11 California Generation in GWh by Generator Type Generator Type (- ) (- ) (- ) (- ) (- ) (- ) - 84 (84) (109) (124) (172) (208) (233) Coal 11,198 11,265 (68) 11,094 11,147 (53) 10,971 11,005 (34) 10,816 10,849 (33) 10,702 10,730 (29) 10,586 10,622 (35) Hydro 35,016 34, ,993 34,996 (3) 34,973 34,991 (17) 34,928 34,934 (6) 34,927 34, ,928 34,929 (1) Nuclear 17,114 17,114-17,114 17,114-17,114 17,114 (0) 17,114 17,114 (0) 17,114 17,114 (0) 17,113 17,113 (0) Others (18) (22) (16) (5) (8) (8) ST 1,580 1,627 (47) 1,642 1, ,607 1,627 (20) 1,596 1,611 (14) 1,594 1,640 (46) 1,598 1,611 (13) Bio 9,891 9,909 (18) 9,798 9,815 (17) 9,667 9,699 (32) 9,553 9,577 (23) 9,414 9,434 (20) 9,283 9,317 (34) CC 83,535 83,569 (34) 82,211 82,386 (176) 81,109 80, ,392 80, ,509 79, ,032 77, CT 9,462 9,480 (18) 9,593 9, ,631 9, ,689 9,722 (33) 9,768 9, ,829 9, DR-EE 3,099 3, ,409 3,409-3,750 3,750-4,124 4,124-4,537 4,537-4,990 4,990 0 ES 1,387 1,449 (62) 1,449 1,502 (53) 1,504 1,552 (48) 1,542 1,589 (47) 1,587 1,616 (29) 1,603 1,645 (42) Geo 14,476 14, ,466 14, ,455 14, ,443 14,443 (0) 14,441 14, ,431 14,436 (5) Small Hydro 4,206 4, ,206 4, ,206 4, ,206 4, ,206 4, ,206 4,206 0 PSH 3,393 3,551 (159) 3,531 3,660 (129) 3,556 3,705 (149) 3,644 3,789 (145) 3,711 3,836 (126) 3,769 3,913 (143) PV-BTM 12,022 12,022-13,147 13,147-14,273 14,273-15,399 15,399-16,524 16,524-17,650 17,650 - Solar 34,361 34, ,579 37,579 (0) 40,794 40,795 (0) 44,005 44, ,207 47,207 (0) 50,397 50,398 (1) Wind 16,203 16,203 (0) 17,721 17,721-19,238 19,238-20,756 20,756 (0) 22,273 22, ,790 23,790 - CA Total Gen 257, ,698 (486) 262, ,715 (485) 267, ,397 (268) 272, ,626 (123) 277, ,917 (92) 282, , Net Import 63,018 62, ,962 61, ,933 61,003 (70) 59,524 59,774 (250) 58,203 58,470 (266) 57,496 58,060 (564) Total 320, ,566 (336) 324, ,505 (313) 328, ,399 (338) 332, ,400 (373) 336, ,386 (358) 340, ,437 (411) 11 P a g e

12 Contributions to emission reductions With the Utah Project, due to the Coal generation reduction in WECC in years 2020 and 2021 but increase in years 2022 to 2025, the CO2 production in WECC is reduced in years 2020 and 2021 but increased in years 2022 to With the Utah Project, the coal generation in California is increased slightly for all years. This happens in part because the IPP Coal facility, whose generation increases with, is included in the California totals. However, due to the CC and CT generation increase in California in years 2020 and 2021 but reduction in years 2022 to 2025, the CO2 production in California is increased in years 2020 and 2021 but reduced in years 2022 to Year WECC CO 2 Production (1000 ton) CO 2 Reduct ion CO 2 Reducti on (%) CO 2 Cost ($000) only in CA CO2 Cost Reduct ion CO2 Cost Reducti on (%) , , % 1,286,122 1,288,657 (2,535) -0.20% , , % 1,273,065 1,275,707 (2,642) -0.21% , ,750 (185) -0.05% 1,261,043 1,260, % , ,156 (178) -0.05% 1,252,827 1,250,945 1, % , ,723 (21) -0.01% 1,244,758 1,242,042 2, % , ,634 (287) -0.08% 1,229,569 1,224,093 5, % Contribution to Renewable Generation Integration The pumping mode of the Utah project operation can absorb over-generation from the solar and wind generation. The Utah Project helps reduce solar and wind generation curtailment from 0 GWh in year 2020 to 5.11 GWh (0.61 GWh Solar generation curtailment reduction and 4.5 GWh wind generation curtailment reduction) in year P a g e

13 WECC Solar and Wind Generation Curtailment (GWh) without and with Utah Project Solar Curtailment in Wind Curtailment in Solar Curtailment in Wind Curtailment in Changes in STS Transmission Line Constraints Though the flow in STS transmission line (IPPDC-Tie) is always from North (Utah) to South (Southern California), one can observe that, at the hourly level, In most compressing hours, the flow from North to South is decreased as opposed to the flow in the Case. This indicates that some generation flows from Southern California to Utah to provide compressing energy for the Utah project. In most generating hours, the flow from North to South is increased as opposed to the flow in the Case. This indicates that some generation from the Utah flows to Southern California. 13 P a g e

14 Table of Contents 1 Introduction Database Preparation and Assumption Revisions Database Preparation Assumptions Updates California Low Frequency Modeling Renewable Generation Profiles Regional Loads Renewable Portfolio Standard Contingency, Flexibility and Regulation Reserves Utah Project Representation Gas Forecast Emission Market Modeling for California CAISO Export Transmission Charge Modeling Approaches PLEXOS SCUC/ED Algorithm Simulation Results Total WECC System Production Cost Utah Project Performance as Independent Power Producer (IPP) Total Generation and Generation Cost Changes by Generator Type Solar and Wind Generation Curtailment Emissions Production Intermountain Power Plant Production Intermountain Power Plant DC-Tie Findings WECC Production Cost Utah Project Operation Performance Impact on Other Generators Contributions to Emission Reductions Contribution to Renewable Generation Integration Storage Cavern Capacity References P a g e

15 List of Figures Figure 1-1 Utah Project Site Figure 2-1 Diagram of WECC Load Regions (Source: WECC) Figure 2-2 Illustration of a operation Figure 2-3 Compressing Mode Representation Figure 2-4 Generating Mode Representation Figure 3-1 PLEXOS Security Constrained Unit Commitment and Economic Dispatch Algorithm 45 Figure 4-1 STS Flow versus Utah Project Operation in a Typical Day of May, Figure 5-1 WECC Retail Loads and Renewable Generation Figure 5-2 WECC RPS % Figure 5-3 California Retail Load and Renewable Generation Figure 5-4 California RPS in % Figure 5-5 WECC Total Production Cost Saving due to Utah Project Figure 5-6 Utah Project Generation and Total Reserve Provision (GWh) Figure 5-7 Utah Operating Costs Figure 5-8 Utah Energy and AS Revenues Figure 5-9 Utah Project Net Operating Revenue Figure 5-10 WECC Renewable Generation Curtailment without and with Utah Project P a g e

16 List of Tables Table 2-1 Total Annual Energy Demand for BAAs in WECC for Year 2024 (GWh) Table 2-2 RPS by Technology and BAA for Year Table 2-3 RPS by Technology and BAA for Year Table 2-4 RPS by Technology and BAA for Year Table 2-5 RPS by Technology and BAA for Year Table 2-6 RPS by Technology and BAA for Year Table 2-7 RPS by Technology and BAA for Year Table 2-8 Mapping of Load Regions and Contingency Reserve Sharing Groups Table 2-9 Characteristics of Utah Project Representation in PLEXOS Table 2-10 Gas Price Forecast for Year 2024 by Month Table 2-11 Thresholds for Tiered CO2 Allowance Charge for Energy Import from NW into California Table 4-1 Penalty Prices for Reserve Provision Shortfall Table 4-2 WECC Production Cost Savings due to Utah Project Table 4-3 Utah Project Value as an Independent Power Producer Table 4-4 WECC Generation and Generation Cost Changes Due to Utah Project Table 4-6 California Generation and Generation Cost Changes Due to Utah Project Table 4-7 WECC Renewable Curtailment Reduction Due to Utah Project Table 4-8 WECC CO2 Reduction and CA CO2 Cost Reduction Due to Utah Project Table 4-9 Intermountain Power Plant Generation and AS Service Table 4-10 IPP DC-Tie flows with and without Utah Project Table 5-1 WECC Generation Changes by Generator Type due Utah Project Table 5-2 California Generation Changes by Generator Type Due to Utah Project Table 5-3 WECC CO2 Reduction and CA CO2 Cost Reduction Due to Utah Project P a g e

17 1 Introduction Energy Exemplar was engaged by Schulte Associates LLC for the Utah Compressed Air Energy Storage () project economic evaluation on behalf of the City of Burbank Water and Power, using PLEXOS, the Integrated Energy Model 4. This report presents the study assumptions, simulation solutions and analysis. As shown in Figure 1-1, the Utah Project Phase 1 is proposed to be a 300 MW generation, 300 MW compression facility located at Delta, Utah and connected to the Intermountain Power Project (IPP) substation. This project has transmission access to Southern California through the DC-Tie from the IPP substation to the Adelanto substation close to the Los Angeles Basin. In order to capture the benefit of the Utah project in detail, a WECC database with the nodal transmission representation was prepared and configured to be as realistic as possible. In this study, Energy Exemplar performed a Case study from year 2020 to year 2025 to better understand the Utah project s value for those years. The Case for these years and the case with the Utah project for these years are simulated to quantify the Utah project benefit to the WECC system. Figure 1-1 Utah Project Site 4 For more information about PLEXOS, visit 17 P a g e

18 For the rest of the report, Section 2 describes Database Preparation and Assumption Revisions; Section 0 describes Emission Market Modeling for California The California CO2 Market is modeled in this study. The CO2 price is $/lb (or about $25/ton) and the commitment and dispatch price of the thermal generators in California includes the CO2 cost component. The import energy from outside of California is charged with the GHG allowance as well. The energy imported from Northwest is charged at the tiered rate: at $0.523/MWh below the thresholds and $11.97/MWh above the thresholds. The thresholds follow the following patterns. Thresholds for the Tiered CO 2 Allowance Charge for Energy Import from NW into California Threshold (MW) Time Period 1120 M M M M04,D M04,D M M M M08,D M08,D M09 1 M10 97 M11 1 M12 Table 2-11 Thresholds for Tiered CO2 Allowance Charge for Energy Import from NW into California The GHG allowance charge for the energy import from Southwest to California is constant of $11.97/MWh CAISO Export Transmission Charge Any energy export from CAISO is charged at $10.83/MWh for the transmission usage. 18 P a g e

19 Modeling Approaches; Section 4 presents Simulation Results; Section 5 summarizes Findings. 19 P a g e

20 2 Database Preparation and Assumption Revisions 2.1 Database Preparation The database prepared for this study was originally from the WECC TEPPC 2024 Common Case database version [1]. It has been converted to a PLEXOS database and further updated with California-specific assumptions, and renewable generation profiles and contingency, flexibility and regulation reserve requirements. The TEPPC 2024 database covers the entire footprint of the Western Interconnection (WI). As shown in Figure 2-1, there are total of 43 load regions in this footprint, representing the Balance Authority Areas (BAAs), trading hubs, and/or the BAA s sub-regions in the United States, plus the provinces of British Columbia and Alberta in Canada, and Comision Federal de Electricidad (CFE) in northern Mexico. Figure 2-1 Diagram of WECC Load Regions (Source: WECC) 5 There was no release note published for TEPPC 2024 Common Case version P a g e

21 The entire WI network consists of over 19,000 buses, over 25,000 transmission lines and over 5,300 generators (including the renewables). For the detailed descriptions of the TEPPC 2024 Common Case database, please refer to reference [1]. 2.2 Assumptions Updates There are further assumption updates in the areas of California low frequency reliability requirements, WECC renewable generation profiles, and flexibility reserve requirements. This section provides some highlights of the major assumption updates California Low Frequency Modeling In the California transmission operation, certain low frequency reliability requirements are modeled for BANC, TID, SCE, SDGE, and IID. 25% of these area loads are covered by the local generation with moving mass such as thermal or hydro generators Renewable Generation Profiles The 5-minute actual wind and solar generation profiles in year 2024 were received from NREL [6] based on year 2006 for the entire WECC footprint. The one-hour persistency forecast technique is used to generate the hour-ahead wind and solar generation profiles. The solar generators include solar generators with and without tracking systems Regional Loads The Day-Ahead (DA) and Hour-Ahead (HA) load forecasts and 5-minute Real Time (RT) actual loads in year 2020 were received from Pacific Northwest National Laboratory (PNNL) for the WECC VGS study [5]. d on the three sets of loads in year 2020, the three sets of loads are built for year 2024 for the given annual peaks and load energies using the PLEXOS time series build function. The BAA s annual peak and load energies are from [1]. A summary of the total annual energy demand for the BAAs in WECC are listed in the following table 6. 6 Please refer to Figure 2-1 for the load area acronyms 21 P a g e

22 Demand Energy by BAAs in Year 2024 Gross Load in GWh (Including Transmission Load Regions and Distribution losses) Retail Load in GWh AESO 113, ,631 AZPS 36,149 32,751 AVA 14,592 13,220 BCHA 68,475 62,038 BPAT 60,903 55,178 CFE 14,475 13,114 CHPD 4,231 3,833 DOPD 1,829 1,657 EPE 10,814 9,798 IPFE 2,815 2,551 GCPD 5,253 4,759 IID 4,756 4,309 LDWP 35,296 31,978 IPMV 5,461 4,948 NEVP 29,213 26,467 NWMT 12,004 10,876 PAID 7,138 6,467 PAUT 32,078 29,063 PAWY 11,152 10,104 PACW 23,826 21,586 CIPB 52,500 47,565 CIPV 65,779 59,596 PGE 24,946 22,601 PNM 16,248 14,721 PSCO 43,025 38,980 PSEI 27,001 24,463 CISC 115, ,633 SCL 10,528 9,538 CISD 25,953 22,756 BANC 18,321 16,599 SPPC 15,336 13,895 SRP 40,145 36,371 TEPC 15,498 14,041 TIDC 3,045 2,759 TPWR 5,427 4,916 IPTV 11,865 10,750 WACM 32,164 29,141 WALC 5,380 4,874 WAUW P a g e

23 Demand Energy by BAAs in Year 2024 Gross Load in GWh (Including Transmission Load Regions and Distribution losses) Retail Load in GWh VEA WECC Total 1,023, ,694 CA Total 321, ,695 CAISO Total 260, ,050 Table 2-1 Total Annual Energy Demand for BAAs in WECC for Year 2024 (GWh) When generating the BAA loads for other years, the load growth rate is assumed 1.231% as stated in [9] in the State of California. The same load growth rate is assumed for other BAAs as an approximation Renewable Portfolio Standard The Renewable Portfolio Standard (RPS) in each BAA is obtained from variety of sources [1], [7], and [8]. The RPS percentage of a BAA is calculated as follows RPS% = RPS(GWh) PV_BTM(GWh) Load(GWh) PV_BTM(GWh) Where PV_BTM is the solar and distributed generation behind the meter. The RPS percentage in California is growing from 33% in year 2020 to 42% in year 2025, assuming 3% to 4% of RPS from Out Of State (OOS). In years 2020 to 2025, only the wind and solar generation are assumed to grow in the WECC. The renewable energy and load energy for years 2020 to 2025 by BAA and by technology are listed in the following tables. 23 P a g e

24 RPS in GWh by Technology and BAA in Year 2020 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% AESO 2, ,371 8,139 8,139 97,799 97,799 8% AVA 1, ,761 1,748 12,598 12,585 14% AZPS ,410 3,884 3,168 31,209 30,493 10% BANC , ,850 1,521 15,817 15,488 10% BCHA 2, ,429 4,351 4,351 59,117 59,117 7% BPAT 3, ,724 16,689 16,584 52,580 52,475 32% CFE - 5, ,679 5,679 12,497 12,497 45% CHPD ,653 3,650 0% CIPB ,226 1, ,607 2,381 45,326 43,100 6% CIPV 6,064 8,080 2,639 2,791 9, ,348 32,479 29,688 56,790 53,999 55% CISC 2,938 2, ,227 12,251 2,782 9,563 35,769 30,542 95,895 90,667 34% CISD ,158 4, ,376 7,452 6,294 21,685 20,527 31% DOPD ,579 1,578 0% EPE ,336 9,315 2% GCPD ,535 4,532 0% IID 860 3, , ,461 5,366 4,106 4, % IPFE ,431 2,421 6% IPMV ,715 4,706 18% IPTV ,244 10,231 8% LDWP ,523-1,137 5,085 4,463 30,472 29,851 15% NEVP ,221 25,040 3% NWMT ,277 1,343 1,320 10,364 10,341 13% 24 P a g e

25 RPS in GWh by Technology and BAA in Year 2020 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% PACW ,417 1,355 20,570 20,508 7% PAID ,163 6,155 8% PAUT ,756 1,650 27,694 27,589 6% PAWY ,905 2,925 2,905 9,628 9,609 30% PGE , ,537 21,479 5% PNM ,939 2,258 2,105 14,028 13,875 15% PSCO ,038 5,692 5,188 37,145 36,640 14% PSEI ,289 1,537 1,520 23,311 23,295 7% SCL ,089 9,083 0% SPPC 26 6, ,471 8,519 8,426 13,240 13,147 64% SRP , ,659 33,878 2% TEPC ,380 13,058 3% TH_Mea d % TH_PV % TIDC ,629 2,573 1% TPWR ,685 4,681 4% WACM ,769 27,526 2% WALC , ,645 4,423 20% WAUW % VEA % WECC Total 22,930 27,535 4,296 16,199 35,795 5,430 56, , , , ,051 18% CA 10,496 14,079 4,224 12,503 32,460 3,054 15,966 92,782 80, , ,693 31% 25 P a g e

26 RPS in GWh by Technology and BAA in Year 2020 Small Hydro PV-BTM Solar Solar Thermal Total RPS Total RPS w/o PV-BTM Retail Load Retail load after PV-BTM Region Bio Geo Wind RPS% Total CAISO Total 9,526 10,842 3,186 11,402 27,540 3,038 14,774 80,307 68, , ,769 33% Table 2-2 RPS by Technology and BAA for Year 2020 RPS in GWh by Technology and BAA in Year 2021 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% AESO 2, ,874 8,642 8,642 98,985 98,985 9% AVA 1, ,790 1,776 12,750 12,736 14% AZPS ,636 4,243 3,460 31,588 30,804 11% BANC , ,991 1,631 16,009 15,649 10% BCHA 2, ,563 4,485 4,485 59,834 59,834 7% BPAT 3, ,916 17,894 17,780 53,218 53,103 33% CFE - 5, ,681 5,681 12,649 12,649 45% CHPD ,697 3,694 0% CIPB ,434 1, ,010 2,575 45,876 43,441 6% CIPV 6,064 8,080 2,639 3,052 10, ,662 33,949 30,896 57,479 54,426 57% CISC 2,938 2, ,717 13,398 3,043 10,459 38,562 32,845 97,058 91,341 36% CISD ,266 4, ,505 8,102 6,835 21,948 20,682 33% DOPD ,598 1,597 0% EPE ,450 9,426 3% 26 P a g e

27 RPS in GWh by Technology and BAA in Year 2021 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% GCPD ,590 4,587 0% IID 860 3, , ,591 5,487 4,156 4, % IPFE ,460 2,450 6% IPMV ,772 4,762 20% IPTV ,368 10,354 8% LDWP ,759-1,243 5,486 4,806 30,842 30,162 16% NEVP ,527 25,329 3% NWMT ,397 1,465 1,440 10,490 10,465 14% PACW ,067 1,514 1,447 20,819 20,752 7% PAID ,237 6,229 8% PAUT ,841 1,725 28,030 27,915 6% PAWY ,177 3,199 3,177 9,745 9,724 33% PGE ,122 1,058 21,798 21,735 5% PNM ,120 2,469 2,302 14,198 14,031 16% PSCO ,510 6,223 5,670 37,596 37,044 15% PSEI ,410 1,659 1,641 23,594 23,576 7% SCL ,199 9,192 0% SPPC 26 6, ,609 8,699 8,597 13,401 13,299 65% SRP , ,079 34,226 2% TEPC ,543 13,190 3% TH_Mea d % TH_PV % TIDC ,661 2,600 1% 27 P a g e

28 RPS in GWh by Technology and BAA in Year 2021 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% TPWR ,742 4,738 3% WACM ,105 27,840 2% WALC , ,701 4,458 22% WAUW % VEA % WECC Total 22,930 27,535 4,296 17,716 39,147 5,939 61, , , , ,200 19% CA Total 10,496 14,079 4,224 13,674 35,500 3,340 17,461 98,773 85, , ,836 32% CAISO Total 9,526 10,842 3,186 12,470 30,119 3,322 16,158 85,622 73, , ,372 35% Table 2-3 RPS by Technology and BAA for Year 2021 RPS in GWh by Technology and BAA in Year 2022 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% AESO 2, ,377 9,145 9, , ,186 9% AVA 1, ,819 1,803 12,905 12,890 14% AZPS ,862 4,602 3,752 31,971 31,120 12% BANC , ,132 1,741 16,204 15,813 11% BCHA 2, ,697 4,619 4,619 60,560 60,560 8% BPAT 3, ,107 19,100 18,976 53,863 53,739 35% CFE - 5, ,684 5,684 12,802 12,802 44% 28 P a g e

29 RPS in GWh by Technology and BAA in Year 2022 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% CHPD ,742 3,739 0% CIPB ,643 1, ,412 2,769 46,432 43,789 6% CIPV 6,064 8,080 2,639 3,314 11, ,975 35,419 32,105 58,176 54,862 59% CISC 2,938 2, ,206 14,546 3,303 11,354 41,355 35,149 98,235 92,029 38% CISD ,375 4, ,633 8,751 7,377 22,214 20,839 35% DOPD ,618 1,616 0% EPE ,564 9,539 3% GCPD ,646 4,642 0% IID 860 3, , ,721 5,608 4,206 4, % IPFE ,490 2,479 7% IPMV ,014 1,004 4,830 4,819 21% IPTV ,494 10,479 8% LDWP ,996-1,350 5,887 5,149 31,216 30,478 17% NEVP ,836 25,621 3% NWMT ,516 1,586 1,559 10,617 10,590 15% PACW ,158 1,611 1,538 21,072 20,999 7% PAID ,313 6,304 9% PAUT ,926 1,801 28,370 28,245 6% PAWY ,449 3,472 3,449 9,863 9,840 35% PGE ,029 1,209 1,140 22,063 21,994 5% PNM ,302 2,680 2,499 14,370 14,189 18% PSCO ,982 6,753 6,153 38,052 37,452 16% PSEI ,530 1,781 1,762 23,880 23,861 7% SCL ,311 9,303 0% 29 P a g e

30 RPS in GWh by Technology and BAA in Year 2022 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% SPPC 26 6, ,747 8,878 8,768 13,564 13,453 65% SRP , ,505 34,578 2% TEPC ,707 13,324 3% TH_Mea d % TH_PV % TIDC ,693 2,627 1% TPWR ,799 4,795 3% WACM ,446 28,158 2% WALC ,049-1,313 1,049 4,758 4,494 23% WAUW % VEA % WECC Total 22,930 27,535 4,296 19,233 42,499 6,447 66, , , , ,477 19% CA Total 10,496 14,079 4,224 14,845 38,539 3,626 18, ,765 89, , ,019 34% CAISO Total 9,526 10,842 3,186 13,537 32,698 3,606 17,541 90,937 77, , ,007 37% Table 2-4 RPS by Technology and BAA for Year 2022 RPS in GWh by Technology and BAA in Year 2023 Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Total RPS w/o PV-BTM Retail Load Retail load after PV-BTM RPS% 30 P a g e

31 RPS in GWh by Technology and BAA in Year 2023 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% AESO 2, ,880 9,648 9, , ,401 10% AVA 1, ,847 1,831 13,062 13,045 14% AZPS ,088 4,961 4,044 32,359 31,441 13% BANC , ,272 1,851 16,400 15,979 12% BCHA 2, ,830 4,753 4,753 61,294 61,294 8% BPAT 3, ,299 20,306 20,171 54,517 54,382 37% CFE - 5, ,686 5,686 12,957 12,957 44% CHPD ,787 3,784 0% CIPB ,851 2, ,814 2,963 46,995 44,144 7% CIPV 6,064 8,080 2,639 3,575 12, ,289 36,888 33,313 58,881 55,306 60% CISC 2,938 2, ,696 15,693 3,564 12,250 44,148 37,452 99,427 92,731 40% CISD ,483 5, ,762 9,401 7,918 22,484 21,000 38% DOPD ,637 1,636 0% EPE ,680 9,653 3% GCPD ,702 4,698 0% IID 860 3, , ,851 5,730 4,257 4, % IPFE ,520 2,508 7% IPMV ,084 1,072 4,888 4,877 22% IPTV ,621 10,605 8% LDWP ,232-1,456 6,288 5,492 31,595 30,798 18% NEVP , ,150 25,918 3% NWMT ,636 1,708 1,679 10,746 10,717 16% PACW ,249 1,708 1,629 21,327 21,249 8% PAID ,390 6,380 10% 31 P a g e

32 RPS in GWh by Technology and BAA in Year 2023 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% PAUT , ,011 1,876 28,714 28,579 7% PAWY ,721 3,746 3,721 9,983 9,958 37% PGE ,110 1,296 1,221 22,331 22,256 5% PNM ,483 2,892 2,696 14,545 14,349 19% PSCO ,454 7,283 6,636 38,513 37,867 18% PSEI ,651 1,903 1,883 24,170 24,149 8% SCL ,424 9,415 0% SPPC 26 6, ,885 9,058 8,939 13,728 13,609 66% SRP , , ,935 34,936 2% TEPC ,873 13,460 3% TH_Mea d % TH_PV % TIDC ,726 2,655 1% TPWR ,858 4,853 3% WACM ,791 28,481 2% WALC ,132-1,417 1,132 4,816 4,531 25% WAUW % VEA % WECC Total 22,930 27,535 4,296 20,750 45,851 6,956 72, , , , ,886 20% CA Total 10,496 14,079 4,224 16,016 41,579 3,912 20, ,757 94, , ,243 35% CAISO 9,526 10,842 3,186 14,605 35,277 3,891 18,925 96,251 81, , ,675 38% 32 P a g e

33 RPS in GWh by Technology and BAA in Year 2023 Region Bio Geo Total Table 2-5 RPS by Technology and BAA for Year 2023 Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Total RPS w/o PV-BTM Retail Load Retail load after PV-BTM RPS% RPS in GWh by Technology and BAA in Year 2024 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% AESO 2, ,383 10,151 10, , ,631 10% AVA 1, ,876 1,858 13,220 13,202 14% AZPS ,313 5,320 4,336 32,751 31,767 14% BANC , ,413 1,961 16,599 16,147 12% BCHA 2, ,964 4,886 4,886 62,038 62,038 8% BPAT 3, ,490 21,511 21,367 55,178 55,034 39% CFE - 5, ,689 5,689 13,114 13,114 43% CHPD ,833 3,830 0% CIPB ,060 2, ,217 3,157 47,565 44,506 7% CIPV 6,064 8,080 2,639 3,836 13, ,602 38,358 34,522 59,596 55,759 62% CISC 2,938 2, ,185 16,840 3,824 13,145 46,940 39, ,633 93,448 43% CISD ,592 5, ,891 10,051 8,459 22,756 21,165 40% DOPD ,657 1,655 0% EPE ,798 9,768 3% GCPD ,759 4,755 0% IID 860 3, , ,981 5,851 4,309 4, % 33 P a g e

34 RPS in GWh by Technology and BAA in Year 2024 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% IPFE ,551 2,538 8% IPMV ,005 1,153 1,141 4,948 4,935 23% IPTV ,750 10,732 9% LDWP ,468-1,563 6,689 5,834 31,978 31,123 19% NEVP , ,467 26,218 3% NWMT ,756 1,830 1,799 10,876 10,845 17% PACW ,341 1,805 1,721 21,586 21,502 8% PAID ,467 6,457 10% PAUT , ,096 1,951 29,063 28,918 7% PAWY ,993 4,020 3,993 10,104 10,077 40% PGE ,191 1,383 1,303 22,601 22,521 6% PNM ,665 3,103 2,893 14,721 14,511 20% PSCO ,926 7,813 7,119 38,980 38,286 19% PSEI ,772 2,026 2,003 24,463 24,441 8% SCL ,538 9,529 0% SPPC 26 6, ,023 9,237 9,110 13,895 13,767 66% SRP , , ,371 35,298 2% TEPC ,041 13,598 3% TH_Mea d % TH_PV , ,069 1, % TIDC ,759 2,682 1% TPWR ,916 4,912 3% WACM ,141 28,807 2% 34 P a g e

35 RPS in GWh by Technology and BAA in Year 2024 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% WALC ,215-1,520 1,215 4,874 4,569 27% WAUW % VEA % WECC Total 22,930 27,535 4,296 22,267 49,203 7,464 77, , , , ,928 21% CA Total 10,496 14,079 4,224 17,187 44,619 4,198 21, ,748 99, , ,008 37% CAISO Total 9,526 10,842 3,186 15,673 37,856 4,175 20, ,566 85, , ,877 40% Table 2-6 RPS by Technology and BAA for Year 2024 RPS in GWh by Technology and BAA in Year 2025 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% AESO 2, ,886 10,654 10, , ,876 10% AVA 1, ,905 1,885 13,380 13,361 14% AZPS ,052-1,038 3,539 5,679 4,627 33,148 32,097 14% BANC , ,554 2,071 16,800 16,317 13% BCHA 2, ,098 5,020 5,020 62,791 62,791 8% BPAT 3, ,682 22,717 22,563 55,847 55,693 41% CFE - 5, ,691 5,691 13,274 13,274 43% 35 P a g e

36 RPS in GWh by Technology and BAA in Year 2025 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% CHPD ,880 3,876 0% CIPB ,268 2, ,619 3,351 48,142 44,874 7% CIPV 6,064 8,080 2,639 4,098 14, ,916 39,828 35,730 60,319 56,221 64% CISC 2,938 2, ,675 17,987 4,085 14,041 49,733 42, ,853 94,179 45% CISD ,700 6, ,020 10,700 9,000 23,032 21,332 42% DOPD ,677 1,675 0% EPE ,917 9,885 3% GCPD ,817 4,812 0% IID 860 3, , ,110 5,972 4,361 4, % IPFE ,582 2,568 8% IPMV ,074 1,222 1,209 5,008 4,994 24% IPTV ,880 10,862 9% LDWP ,705-1,669 7,090 6,177 32,366 31,453 20% NEVP , ,788 26,522 4% NWMT ,875 1,951 1,918 11,008 10,975 17% PACW ,432 1,902 1,812 21,848 21,758 8% PAID ,545 6,534 11% PAUT , ,182 2,027 29,415 29,260 7% PAWY ,265 4,294 4,265 10,226 10,198 42% PGE ,273 1,469 1,384 22,876 22,790 6% PNM ,846 3,315 3,090 14,900 14,675 21% PSCO ,397 8,343 7,602 39,453 38,712 20% PSEI ,892 2,148 2,124 24,760 24,736 9% SCL ,654 9,644 0% 36 P a g e

37 RPS in GWh by Technology and BAA in Year 2025 Total RPS w/o PV-BTM Retail load after PV-BTM Region Bio Geo Small Hydro PV-BTM Solar Solar Thermal Wind Total RPS Retail Load RPS% SPPC 26 6, ,160 9,417 9,281 14,063 13,927 67% SRP , , ,812 35,666 3% TEPC ,212 13,738 4% TH_Mea d % TH_PV , ,141 1, % TIDC ,793 2,711 1% TPWR ,976 4,971 3% WACM ,494 29,138 2% WALC ,298-1,624 1,298 4,934 4,607 28% WAUW % VEA % WECC Total 22,930 27,535 4,296 23,784 52,555 7,973 82, , , , ,103 22% CA Total 10,496 14,079 4,224 18,358 47,658 4,484 23, , , , ,815 38% CAISO Total 9,526 10,842 3,186 16,741 40,434 4,460 21, ,880 90, , ,112 42% Table 2-7 RPS by Technology and BAA for Year P a g e

38 2.2.5 Contingency, Flexibility and Regulation Reserves 38 P a g e Contingency Reserves The requirements for contingency reserves, i.e. spinning and non-spinning reserves, are defined for 28 reserve regions. The mapping between the reserve regions and the load regions is specified in the following table. Reserve Region AESO APS AVA BCTC BPA Burbank CAISO CFE EPE Glendale IID IPC LDWP NVE NWMT PAC PGN PNM PSC PSE Load Region AESO AZPS AVA BCHA BPAT CHPD DOPD GCPD SCL TPWR Burbank CIPB CIPV CISC CISD VEA CFE EPE Glendale IID IPFE IPMV IPTV LDWP NEVP SPPC NWMT PAID PAUT PAWY PACW PGE PNM PSCO PSEI

39 Reserve Region SMUD SRP TEP TIDC WACM WALC WAUW Load Region BANC SRP TEPC TIDC WACM WALC WAUW Table 2-8 Mapping of Load Regions and Contingency Reserve Sharing Groups The spinning reserve requirement of a reserve region is 3% of the loads of the load regions in the reserve region. The spinning reserve is provided by the eligible on-line generators in the regions. The non-spinning reserve requirement of a reserve region is 3% of the loads of the load regions in the reserve region. The non-spinning reserve is provided by the eligible on-line generators and the off-line quick startup generators in the region [3] Regulation up and Regulation Down Reserves The requirements of the regulation up and regulation down reserves are defined as 1% of the loads of the load regions in the reserve region. The regulation up and regulation down reserves are provided by the eligible on-line generators in the regions Flexibility Up and Flexibility Down Reserves The requirements of the hourly flexibility up and flexibility down reserve for a reserve region are calculated based on the distribution of the 5-minute net load (load less solar and wind generation) less the hourly net load forecast in the reserve region [6]. The flexibility up and down reserve requirements are determined at 95 percent of the distribution Utah Project Representation A Compressed Air Energy System () operation can be illustrated in the following diagram. 39 P a g e

40 Figure 2-2 Illustration of a operation In the Utah Project Phase 1, two trains of equipment will be built with each train including 150 MW of both compressing and generating capacity. The storage cavern size for each train is 7.2 GWh (representing 48 hours of storage at full 150 MW generation output). A is modeled in PLEXOS as a pumped storage generator with 80% cycle efficiency and a CT generator. For purposes of the Plexos modeling, the compressing mode and generating mode are illustrated in the following diagrams. in Compressing Mode Gen=120 MWh Gen=150 MWh Storage Fuel=0 Btu ~ Gen=150 MWh 40 P a g e ~ Gen=0 MWh

41 Figure 2-3 Compressing Mode Representation in Generating Mode Gen=100 MWh Gen=100 MWh Storage Fuel= mm Btu ~ Gen=150 MWh Figure 2-4 Generating Mode Representation The following table summarizes the characteristics of the project. 41 P a g e ~ Gen=50 MWh Heat Rate=13,125 Btu/kWh Utah Properties Value Trains 2 Max Cap per Train (MW) 150 Min Cap per Train (MW) 20 Max Ramp Rate per Train (MW/min) 30 Fuel Burned at Max Capacity per Train(mmBtu) Heat Rate at CT Max Capacity of 50 MW per Train (Btu/kWh) 13,125 Heat Rate at Max Capacity of 150 MW per Train (Btu/kWh) 4,375 Max Compressing Load per Train (MW) 150 Min Compressing Load per Train (MW) 90 Storage (GWh) 7.2 Cycle Efficiency 80% Table 2-9 Characteristics of Utah Project Representation in PLEXOS The generation heat rate of 13,125 Btu/kWh shown in the above figure is based on the assumption that natural gas input to the facility provides about one-third of the

42 energy for generation (the rest coming from the stored energy). For Plexos modeling purposes, the 13,125 Btu/kWh figure is calculated by taking three times the actual heat rate of a facility (i.e., 4,375 Btu/kWh applicable to 100% of the generation ouput energy 7 ). The Plexos model then uses the 13,125 Btu/kWh figure for one-third of the generation output energy to determine fuel costs. The project is capable of providing contingency reserves, regulation up and down reserves, and flex up and down reserves, in both compressing mode and generating mode. Each 150 MW train was assumed to be capable of compressing at the same time that the other train was generating, and vice versa. The Plexos results showed this would happen only occasionally and typically during ramping events when the needs for compression or generation would toggle from one to the other. Energy Exemplar also initially tested the results of allowing the compressor mode and the generation mode of an individual train to operate at the same time. The Plexos results in this test showed this approach of operating significantly decreased the economic benefits of the facility. As a result, for the balance of of the study it was assumed that each train would either be in compression mode or generation mode in a particular time period but not both at the same time Gas Forecast The gas price assumption was originally from CEC IEPR 2013 [2]. The following table lists the Gas Price Forecast by Month for the year 2024 in real 2014 dollars. 7 Lessons from Iowa: Development of a 270 Megawatt Compressed Air Energy Storage Projecy in Midwest Independent System Operator A Study for the DOE Energy Storage Systems Program, Robert H. Schulte, Nicholas Critelli, Hr., Kent Holst, and Georgianne Huff. Sandia Report, SAND , January P a g e

43 2024 Gas Price Forecast ($/mmbtu in Real 2014 dollars) BAA or Region M01 M02 M03 M04 M05 M06 M07 M08 M09 M10 M11 M12 AESO Arizona North Arizona South Baja Baja California BC Hydro California Blythe California Kern River California Mojave California PG&E BB California PG&E LT California San Juan Valley California SDGE California SoCal Gas California SoCal Gas B California SoCal Gas B Other Colorado Gas to Idaho North Idaho South Montana Nevada North Nevada South Nevada South California P a g e

44 2024 Gas Price Forecast ($/mmbtu in Real 2014 dollars) BAA or Region M01 M02 M03 M04 M05 M06 M07 M08 M09 M10 M11 M12 New Mexico North New Mexico South Oregon Oregon Malin Synthetic Gas Texas West Utah Washington Wyoming Table 2-10 Gas Price Forecast for Year 2024 by Month 44 P a g e

45 2.2.8 Emission Market Modeling for California The California CO2 Market is modeled in this study. The CO2 price is $/lb (or about $25/ton) and the commitment and dispatch price of the thermal generators in California includes the CO2 cost component. The import energy from outside of California is charged with the GHG allowance as well. The energy imported from Northwest is charged at the tiered rate: at $0.523/MWh below the thresholds and $11.97/MWh above the thresholds. The thresholds follow the following patterns. Thresholds for the Tiered CO 2 Allowance Charge for Energy Import from NW into California Threshold (MW) Time Period 1120 M M M M04,D M04,D M M M M08,D M08,D M09 1 M10 97 M11 1 M12 Table 2-11 Thresholds for Tiered CO2 Allowance Charge for Energy Import from NW into California The GHG allowance charge for the energy import from Southwest to California is constant of $11.97/MWh CAISO Export Transmission Charge Any energy export from CAISO is charged at $10.83/MWh for the transmission usage. 45 P a g e

46 3 Modeling Approaches 3.1 PLEXOS SCUC/ED Algorithm PLEXOS Security Constrained Unit Commitment (SCUC) algorithm consists of two major logics: Unit Commitment using Mixed Integer Programming and Network Applications. The SCUC/ED simulation algorithm is illustrated in the following figure. Figure 3-1 PLEXOS Security Constrained Unit Commitment and Economic Dispatch Algorithm The unit commitment and economic dispatch (UC/ED) logic performs the Energy-AS cooptimization using Mixed Integer Programming enforcing all resource and operation constraints. The UC/ED logic commits and dispatches resources to balance the system energy demand and meet the system reserve requirements. The resource schedules from the UC/ED are passed to the Network Applications logic. The Network Applications logic solves the DC-OPF to enforce the power flow limits and nomograms. The Network Applications logic also performs the contingency analysis if the contingencies are defined. If there are any transmission limit violations, these transmission limits are passed to the UC/ED logic for the re-run of UC/ED. The iteration continues until all transmission limit violations are resolved. Thus the co-optimization solution of Energy-AS-DC-OPF is reached. The same algorithm for the SCUC/ED is used by many ISO market scheduling software (some ISO market scheduling software may use AC-OPF in the Network Applications). 46 P a g e