Probabilistic Resource Adequacy Assessment - Final Resourc… · Web viewThe 19 hours occur over 1 weeks’ time in late August with reliability reaching a low of 99.6% reliability

Probabilistic Resource Adequacy AssessmentWestern Interconnection 2017-2026

Matthew Elkins, Senior Economist[08/03/2017]

155 North 400 West, Suite 200

Salt Lake City, Utah 84103-1114

Probabilistic Resource Adequacy Assessment 1

Table of Contents

1. Introduction..................................................................................................................................1

2. Interconnection-Wide Summary...................................................................................................2

2.1. Normalized Reliability Threshold Margin....................................................................................3

2.1.1. Existing Resources Only.................................................................................................3

2.1.2. Future Resources Included............................................................................................4

2.2. Demand-At-Risk Hours................................................................................................................4

2.2.1. Existing Resources Only.................................................................................................4

2.2.2. Future Resources Included............................................................................................5

3. Northwest Power Pool – U.S. (NWPP-US)......................................................................................6

3.1. NERC Long-Term Reliability Assessment (LTRA) Results.............................................................7

3.2. Normalized Annual Threshold Margin – Existing Resources Only...............................................7

3.3. Normalized Annual Threshold Margin – Future Resources Included..........................................8

3.4. Pre-Import Demand-At-Risk Hours – Existing Resources Only....................................................9

3.5. Pre-Import Demand-At-Risk Hours – Future Resources Included...............................................9

3.6. Average Hourly Imports – Existing Resources Only..................................................................10

3.7. Average Hourly Imports – Future Resources Included..............................................................10

3.8. Post-Import Demand-At-Risk Hours – Existing Resources Only................................................11

3.9. Post-Import Demand-At-Risk Hours – Future Resources Included...........................................11

4. California/Mexico (CAMX)...........................................................................................................12

4.1. NERC Long-Term Reliability Assessment (LTRA) Results...........................................................13

4.2. Normalized Annual Threshold Margin – Existing Resources Only.............................................13

4.3. Normalized Annual Threshold Margin – Future Resources Included........................................14

4.4. Pre-Import Demand-At-Risk Hours – Existing Resources Only..................................................15

4.5. Pre-Import Demand-At-Risk Hours – Future Resources Included.............................................15




W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L



5. Southwest Reserve Sharing Group (SRSG)...................................................................................18










6. Rocky Mountain Reserve Group (RMRG).....................................................................................24










7. Canada........................................................................................................................................30












8. Conclusions.................................................................................................................................36



1. Introduction

The Western Electricity Coordinating Council (WECC) is responsible for coordinating and promoting Bulk Power System (BPS) reliability in the Western Interconnection. WECC’s 329 members, which include 38 Balancing Authorities (BA), represent a wide spectrum of organizations with an interest in the BPS. Serving an area of nearly 1.8 million square miles and approximately 82.2 million people, it is geographically the largest and most diverse of the North American Electric Reliability Corporation (NERC) Regional Reliability Organizations.

Each year, WECC is tasked with analyzing the resource adequacy of the Western Interconnection through the Long-Term Reliability Assessment (LTRA) report that is published by NERC. The LTRA focuses on the peak (highest demand) hours of both the winter and summer seasons. It compares the amount of available resources above the expected demand—a forecasted Planning Reserve Margin (PRM)—with a building block Reference Margin that WECC developed as a benchmark to maintain system reliability. This report follows up on the LTRA study that WECC provides to NERC and supplements the resource adequacy analysis by using probabilistic methods to analyze the reliability risk associated with forecast and operational uncertainty. This report produces a Threshold Margin (for convenience of comparison labeled “threshold” as the current methodology is labeled “reference”), to compare against the forecasted PRM. In contrast to the LTRA, the probabilistic calculations are conducted on every hour of the study horizon, including the peak hours, to determine where in the system there might be Demand-At-Risk (DAR) above a predetermined threshold margin of reliability acceptance.

The threshold margin used in this study is the amount of excess energy needed on an hourly basis to maintain a Loss-of-Load Probability (LOLP) of equal to or less than 0.02%. The inverse of this margin is, to maintain a level of reliability in the system equal to or greater than 99.98%. The amount of excess capacity in megawatts needed to maintain that level will vary each hour due to the level of expected demand. Therefore, the hourly threshold margins are weighted by each hour’s demand to produce a normalized annual threshold margin that can be referenced as a guide for maintaining reliability. As new resources are added to the system to meet growing demand, the threshold margin can change depending on the size of the new resources compared to the existing resources as well as the variability of the new resources.

For each of the subregions the report will look at the LTRA results, then compare the normalized annual threshold margin for existing resources only, and then with new resources included. The study will then focus on the number of DAR hours that may be present for each portfolio prior to importing from neighboring areas to satisfy the reliability threshold margin. The amount of imports that were calculated in the model will then be explored. Finally, the number of DAR hours after imports from neighboring areas will be analyzed to determine if the total system is expected to maintain 99.98% reliability.



2. Interconnection-Wide Summary

WECC’s service territory extends from Canada to Mexico. It includes the provinces of Alberta and British Columbia in Canada; the northern portion of Baja California, Mexico; and all or portions of the 14 Western states in between. The WECC assessment area is divided into five subregions: Rocky Mountain Reserve Group (RMRG), Southwest Reserve Sharing Group (SRSG), California/Mexico (CAMX), and the Northwest Power Pool (NWPP), which is further divided into Canada (CAN) and the U.S. portion (NWPP-US) areas. These subregional divisions are used for this study as they are structured around Reserve Sharing groups that have similar annual demand patterns and similar operating practices.

2.1. Normalized Reliability Threshold Margin

To calculate the normalized reliability threshold margin, compare the

hourly probability distributions

of supply and demand for

each BA against each other to

determine the amount of

overlap between the distributions.

The amount of the high end of the demand

distribution



that exceeds the low end of the supply distribution is the amount of DAR in megawatts for that given hour at that given reserve margin. The accumulative probability of the demand distribution that exceeds the supply distribution is multiplied by the accumulative amount of the supply distribution that is less than the demand distribution and determines the overall LOLP as a percentage for that hour. The margin needed to maintain an LOLP of less than or equal to 0.02% is calculated and becomes that hour’s reliability threshold margin. On an annual basis, each hour is multiplied by the expected demand for that hour, summed, and then divided by the total expected demand to produce a normalized reliability threshold margin.

2.1.1. Existing Resources Only

The normalized reliability threshold margin with existing resources only, ranges from ~10% to ~20% depending on the area and the variability of the overall generating portfolio. The overall Western Interconnection system threshold margin is 15.7% in 2017 falling to 14.6% by 2026.

Table 1 - Normalized Reliability Threshold Margin - Existing Resources Only - WI

Subregion

Year All NW CAMX SW RM CAN

2017 15.7% 20.4% 12.6% 15.3% 17.3% 11.4%

2018 15.5% 20.1% 12.7% 15.1% 17.0% 11.2%

2019 15.4% 19.9% 12.7% 14.9% 16.7% 10.9%

2020 15.2% 19.8% 12.7% 14.8% 16.4% 10.7%

2021 15.1% 19.5% 12.7% 14.6% 16.0% 10.5%

2022 14.9% 19.4% 12.7% 14.4% 15.9% 10.4%

2023 14.8% 19.3% 12.7% 14.2% 15.7% 10.3%

2024 14.8% 19.1% 12.7% 14.0% 15.5% 10.2%

2025 14.6% 19.0% 12.7% 13.9% 15.3% 10.1%

2026 14.6% 18.9% 12.7% 13.7% 15.1% 10.0%

2.1.2. Future Resources Included

With future resources included, the normalized reliability threshold margin for the Western Interconnection increases ~1.4% to an overall reliability threshold margin of 16.0% by 2026. The CAN subregion experiences the largest increase of ~2.9% while the RM subregion experiences a slight decrease in some years.



Table 2 - Normalized Reliability Threshold Margin - Future Resources Included - WI

Subregion


2017 15.8% 20.4% 12.7% 15.4% 17.3% 12.0%

2018 16.0% 20.1% 13.1% 15.9% 16.8% 13.1%

2019 16.3% 20.6% 13.4% 15.9% 16.5% 13.5%

2020 16.3% 20.5% 13.7% 15.9% 16.2% 13.3%

2021 16.2% 20.2% 13.8% 15.9% 16.1% 13.2%

2022 16.1% 20.0% 13.8% 15.9% 15.9% 13.0%

2023 16.0% 19.9% 13.8% 15.9% 15.7% 12.9%

2024 16.1% 20.1% 13.8% 15.8% 15.5% 13.0%

2025 16.1% 20.1% 13.8% 15.7% 15.3% 13.0%

2026 16.0% 20.0% 13.8% 15.6% 15.1% 12.9%

2.2. Demand-At-Risk Hours

Once a reliability threshold margin is calculated for each hour, a summation of the hours where the threshold cannot be met is needed to determine the frequency of a reliability shortfall for each BA. Demand-At-Risk hours represents the total number of hours where the amount of overlap between the supply and demand distributions produces an LOLP greater than 0.02%.

2.2.1. Existing Resources Only

There is one hour each year for 2017-19 in the CAMX subregion where there is DAR and the system is less than 99.98% reliable. The reliability for these hours is expected to be just slightly below the reliability threshold at 99.97%, 99.96%, and 99.97% for 2017, 2018, and 2019 respectively. This equates to approximately 1 MW of DAR for those hours. DAR hours begin to show up in 2022 and increase through 2026 with most of the hours located in the CAMX subregion.



Table 3 – Demand-At-Risk Hours - Existing Resources Only - WI

Subregion


201 1 - 1 - - -

201 1 - 1 - - -

201 1 - 1 - - -

202 - - - - - -

202 - - - - - -

202 3 - 3 - - -

202 20 1 18 - 2 -

202 53 6 49 - 4 -

202 103 8 93 - 10 2

202 200 9 198 6 7 3

2.2.2. Future Resources Included

With the addition of future resources, the Western Interconnection is expected to maintain a level of 99.98% reliability for all hours over the next ten years except for 19 hours in the CAMX subregion in 2026. The 19 hours occur over 1 weeks’ time in late August with reliability reaching a low of 99.6% reliability with approximately 12 MW of Demand-At-Risk in that specific area.

Table 4 – Demand-At-Risk Hours - Future Resources Included - WI

Subregion


201 - - - - - -

201 - - - - - -

201 - - - - - -

202 - - - - - -

202 - - - - - -

202 - - - - - -

202 - - - - - -

202 - - - - - -

202 - - - - - -

202 19 - 19 - - -



3. Northwest Power Pool – U.S. (NWPP-US)

The Northwest Power Pool (NWPP-US) subregion is made up of 38 BAs that are divided among seven major load areas: 1) BPAT—11 BAs in Oregon and Washington; 2) NWMT—four BAs in Montana; 3) IPFE—the IPCO BA in Idaho; 4) PAUT—the PACE BA in Utah, and parts of Idaho and Wyoming; 5) SPPC—Northern Nevada and 6) NEVP—Southern Nevada, both of which are part of the NEVP BA; and 7) BANC—two BAs representing a portion of East California.



3.1. NERC Long-Term Reliability Assessment (LTRA) Results

NWPP-US is a summer-peaking area with an expected peak demand forecast of roughly 48.7 GW in 2017 increasing to about 52.1 GW by 2026. Existing generating resources are approximately 56.8 GW decreasing to roughly 55.7 GW by 2026. Future resources are expected to add an additional 3.2 GW by 2026 for a total installed capacity of approximately 59 GW. For the summer-peak hours, the NWPP-US area imports approximately 4.6 GW in 2017 increasing to around 8.3 GW in 2026. The PRM in this subregion with existing resources and net imports is close to 26% in 2017 decreasing to just over 23% in 2026. Including future resources and imports, the expected future margin is as high as 32.7% in 2019 decreasing to just under 26% in 2026. The building block Reference Margin calculated for this subregion is 16.32%. Using probabilistic methods, the Threshold Margin for the peak hour is consistently between 17.2% and 17.9%.

Table 5 - LTRA Peak Hour Results for NWPP-US

Year 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Demand 48,794 49,252 49,655 50,124 50,498 50,926 51,266 51,680 52,252 52,101

Existing Resources 56,853 57,035 57,362 57,028 56,456 56,070 56,767 56,744 56,099 55,778

Future Resources 1,395 1,616 2,307 2,202 1,962 1,875 2,678 3,333 3,238 3,214

Net Imports 4,606 6,557 7,037 7,301 7,422 7,394 7,509 7,714 8,422 8,317

Existing + Net Imports

61,459 63,592 64,399 64,329 63,878 63,464 64,276 64,458 64,521 64,095

Future + Net Imports

62,854 65,209 66,706 66,532 65,841 65,339 66,954 67,791 67,759 67,309

Existing Margin 25.96%

29.12% 29.69%

28.34% 26.50%

24.62% 25.38% 24.72%

23.48% 23.02%

Future Margin 28.23%

31.80% 32.77%

31.30% 29.29%

27.28% 28.34% 27.68%

26.32% 25.84%

Reference Margin 16.32%

16.32% 16.32%

16.32% 16.32%

16.32% 16.32% 16.32%

16.32% 16.32%

Threshold Margin 17.26%

17.24%

17.97%

17.85%

17.65%

17.49%

17.45%

17.57%

17.46%

17.48%

3.2. Normalized Annual Threshold Margin – Existing Resources Only

Calculating the threshold margin for all hours of the year, the normalized annual threshold margin for all areas combined is as high as 20.4% in 2017, falling to 18.9% in 2026, with existing resources only. By individual area, the threshold margins deviate based on the variability of the generation portfolios and the demand distributions. NEVP has the least variability and calculates a threshold margin of 11.2% in 2017 to 10.2% in 2026. The decrease over the years is due to the increasing expected demand forecast. On a megawatt-hour basis, the numbers would remain about the same. IPFE has the most variability in the subregion leading to roughly a 30.2% threshold margin in 2017 falling to approximately 26.3% in 2026.



Table 6 - Normalized Annual Threshold Margin - Existing Resources Only - NWPP-US

Year All BPAT PAUT NEVP BANC IPFE SPPC NWMT

2017 20.4% 23.3% 14.6% 11.2% 17.9% 30.2% 12.9% 19.2%

2018 20.1% 23.0% 14.5% 10.8% 17.9% 29.8% 12.7% 19.0%

2019 19.9% 22.8% 14.4% 10.7% 17.9% 29.4% 12.3% 18.9%

2020 19.8% 22.7% 14.3% 10.7% 17.8% 29.3% 12.2% 18.8%

2021 19.5% 22.3% 14.2% 10.5% 17.7% 28.8% 12.1% 18.6%

2022 19.4% 22.2% 14.2% 10.6% 17.7% 28.0% 11.4% 18.5%

2023 19.3% 22.0% 14.1% 10.5% 17.6% 27.7% 11.4% 18.3%

2024 19.1% 21.9% 14.1% 10.4% 17.5% 27.4% 11.3% 18.3%

2025 19.0% 21.7% 14.0% 10.4% 17.4% 26.9% 10.6% 18.1%

2026 18.9% 21.6% 14.2% 10.2% 17.3% 26.3% 10.1% 18.0%

3.3. Normalized Annual Threshold Margin – Future Resources Included

Comparing the threshold margin for all hours of the year using future resources as well as existing resources, most areas experience an increase in the threshold margin as shown in Table 7 below. BPAT is expected to have an increase in the threshold margin of 1.1% by 2026. PAUT is expecting the largest increase of ~3.2% while the remaining areas experience small increases.

Table 7 - Normalized Annual Threshold Margin - Future Resources Included - NWPP-US


2017 20.4% 23.4% 14.7% 11.2% 17.9% 30.3% 13.1% 19.2%

2018 20.1% 23.0% 14.5% 10.8% 17.9% 29.9% 12.9% 19.0%

2019 20.6% 24.0% 14.5% 10.8% 17.9% 29.6% 12.1% 18.9%

2020 20.5% 23.8% 14.5% 10.7% 17.8% 29.7% 12.0% 18.8%

2021 20.2% 23.4% 14.4% 10.5% 17.8% 29.2% 11.9% 18.6%

2022 20.0% 23.2% 14.4% 10.6% 17.8% 28.4% 11.2% 18.5%

2023 19.9% 23.1% 14.6% 10.5% 17.7% 28.1% 11.2% 18.3%

2024 20.1% 23.0% 16.3% 10.5% 17.6% 27.8% 11.1% 18.3%

2025 20.1% 22.8% 17.0% 10.4% 17.5% 27.2% 10.4% 18.1%

2026 20.0% 22.7% 17.4% 10.3% 17.4% 26.6% 9.9% 18.0%



3.4. Pre-Import Demand-At-Risk Hours – Existing Resources Only

Analyzing all areas on an islanded basis (without imports), the number of hours each year where the threshold margin is not maintained can be represented as hours where there is DAR as shown in Table 8 below. With only existing resources, NWMT has the most hours where maintaining a 0.02% LOLP or less is not met. BPAT, PAUT, NEVP, and BANC all have some hours of DAR each year, where IPFE experiences some starting in 2018 while SPPC begins to experience hours of DAR beginning in 2022.

Table 8 – Pre-Import Demand-At-Risk Hours - Existing Resources Only - NWPP-US


2017 1,800 175 503 13 364 - - 1,5592018 2,046 233 560 109 346 3 - 1,8222019 2,264 282 580 126 349 5 - 2,0602020 2,377 332 632 148 378 15 - 2,1402021 2,910 692 664 220 388 32 - 2,5232022 3,227 806 637 228 382 98 58 2,8482023 3,452 956 711 278 401 133 74 3,0382024 3,475 1,068 781 315 414 179 92 3,004

2025 3,871 1,238 841 364 440 323 425 3,3102026 4,178 1,460 677 456 459 422 783 3,571

3.5. Pre-Import Demand-At-Risk Hours – Future Resources Included

Comparing all hours of the year using future resources as well as existing resources as represented in Table 9, BPAT and SPPC experience an increase in DAR hours. PAUT experiences a reduction in DAR hours going to zero hours beginning in 2024. NEVP, BANC, and IPFE experience reduction in hours, but still experience DAR hours all years, while NWMT remains unchanged.

Table 9 – Pre-Import Demand-At-Risk Hours - Future Resources Included - NWPP-US


2017 1,790 173 452 10 364 - - 1,559

2018 2,050 279 475 91 342 2 - 1,822

2019 2,266 332 473 111 345 4 - 2,060

2020 2,379 383 525 130 376 9 1 2,140

2021 2,919 803 538 197 382 22 1 2,523

2022 3,257 926 515 202 376 69 121 2,848

2023 3,481 1,085 257 257 392 104 147 3,038

2024 3,492 1,222 - 281 409 146 177 3,004

2025 3,879 1,392 - 331 434 280 580 3,310

2026 4,268 1,587 - 426 451 378 966 3,571



3.6. Average Hourly Imports – Existing Resources Only

As shown in Figure 1 below, only using existing resources throughout the entire Western Interconnection, the NWPP-US areas can import a significant amount of energy. The lighter shaded bars represent the “1st Order” imports (imports from immediate neighbors of which the area has direct ties with). The darker shaded bars represent the additional “2nd Order” imports (imports from the immediate neighbor’s immediate neighbors, relying on more than one area and multiple transmission transfers). As shown, BPAT relies on some 2nd Order imports beginning in 2021 while most of the areas experience 2nd Order imports in the last four years of the study.

Figure 1: Average Hourly Imports (in megawatts) - Existing Resources Only – NWPP-US

2017

2017

2017

2018

2018

2019

2019

2020

2020

2020

2021

2021

2022

2022

2023

2023

2023

2024

2024

2025

2025

2026

2026

2026 -

200 400 600 800

1,000 1,200 1,400 1,600 1,800 2,000

BPAT - 1st Order BPAT - 2nd Order PAUT - 1st Order PAUT - 2nd Order NEVP - 1st Order

NEVP - 2nd Order BANC - 1st Order BANC - 2nd Order IPFE - 1st Order IPFE - 2nd Order

SPPC - 1st Order SPPC - 2nd Order NWMT - 1st Order NWMT - 2nd Order

3.7. Average Hourly Imports – Future Resources Included

With future resources included as well as existing resources, almost all the 2nd Order transfers are no longer needed (see Figure 2). Reducing the 2nd Order transfers removes additional risk in the system that comes from transmission availability.

Figure 2: Average Hourly Imports (in megawatts) – Future Resources Included – NWPP-US

2017

2017

2017

2018

2018

2019

2019

2020

2020

2020

2021

2021

2022

2022

2023

2023

2023

2024

2024

2025

2025

2026

2026

2026 -

400 800

1,200 1,600 2,000

BPAT - 1st Order BPAT - 2nd Order PAUT - 1st Order PAUT - 2nd Order NEVP - 1st OrderNEVP - 2nd Order BANC - 1st Order BANC - 2nd Order IPFE - 1st Order IPFE - 2nd OrderSPPC - 1st Order SPPC - 2nd Order NWMT - 1st Order NWMT - 2nd Order



3.8. Post-Import Demand-At-Risk Hours – Existing Resources Only

Re-analyzing all areas but this time after imports, the number of hours each year where there is DAR (see Table 10) is significantly reduced from the Islanded analysis, Table 8 above. With only existing resources, only a few areas remain experiencing DAR hours in the last four years while NWMT and BANC experience no hours of DAR.

Table 10 – Post-Import Demand-At-Risk Hours - Existing Resources Only - NWPP-US


2017 - - - - - - - -

2018 - - - - - - - -

2019 - - - - - - - -

2020 - - - - - - - -

2021 - - - - - - - -

2022 - - - - - - - -

2023 1 1 - - - - - -

2024 6 2 4 1 - - 2 -

2025 8 3 7 3 - 1 6 -

2026 9 4 6 4 - 4 7 -

3.9. Post-Import Demand-At-Risk Hours – Future Resources Included

Comparing all hours of the year after imports using future resources as well as existing resources (see Table 11) all hours of DAR are removed from the subregion. This area can maintain a 99.98% reliability for all hours of the study horizon.

Table 11 – Post-Import Demand-At-Risk Hours - Future Resources Included - NWPP-US


2017 - - - - - - - -

2018 - - - - - - - -

2019 - - - - - - - -

2020 - - - - - - - -

2021 - - - - - - - -

2022 - - - - - - - -

2023 - - - - - - - -

2024 - - - - - - - -

2025 - - - - - - - -



2026 - - - - - - - -

4. California/Mexico (CAMX)

The California-Mexico (CAMX) subregion is made up of three BAs that represent five major load areas: 1) CIPV—Northern California, which is divided into CIPB and CIPV; 2) CISC—Southern California; 3) CISD—San Diego; 4) LDWP—Los Angeles area; and 5) CFE—a portion of Baja California, Mexico that is part of the Western Interconnection.




CAMX is a summer-peaking area with an expected peak demand forecast of roughly 53.0 GW in 2017 decreasing to about 52.2 GW by 2026 due to an expected increase in roof-top solar. Existing generating resources are around 55.5 GW decreasing to about 54.9 GW by 2026. Future resources are expected to add an additional 5.7 GW by 2026 for a total installed capacity of approximately 60.6 GW. For the summer-peak hours, the CAMX area imports approximately 6.9 GW in 2017 decreasing to around 1.4 GW in 2026. The PRM in this subregion with existing resources and net imports is close to 28% in 2017 decreasing to just under 8% in 2026. Including future resources and imports, the expected future margin is as high as 22.9% in 2019 decreasing to just under 19% in 2026. The building block Reference Margin calculated for this subregion is 16.16%. Using probabilistic methods, the Threshold Margin for the peak hour is approximately 16.3% in 2017 increasing to roughly 18.1% by 2026.

Table 12: LTRA Results for CAMX

Year 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Demand 53,027 52,848 52,628 52,514 52,455 52,580 52,594 52,553 52,422 52,298



Net Imports 6,925 5,450 4,184 3,228 3,370 3,535 3,163 2,928 1,874 1,439


62,508 61,178 60,310 59,219 58,833 58,767 58,569 57,830 57,254 56,389

Future + Net Imports 63,859 64,525 64,707 64,378 64,150 63,975 63,898 63,640 63,320 62,163

Existing Margin 17.88% 15.76% 14.60% 12.77% 12.16% 11.77% 11.36% 10.04% 9 . 2 7 . 8

Future Margin 20.43% 22.10% 22.95% 22.59% 22.30% 21.67% 21.49% 21.10% 20.79% 18.86

Reference Margin 16.16% 16.16% 16.16% 16.16% 16.16% 16.16% 16.16% 16.16% 16.16% 16.16

Threshold Margin 16.35% 16.77% 17.02% 18.01% 18.12% 18.09% 18.08% 18.08% 18.10% 18.13


Calculating the threshold margin for all hours of the year, as depicted in Table 13 below, the normalized annual threshold margin for all areas combined is consistently 12.7% with existing resources only. By individual area, the threshold margins deviate based on the variability of the generation portfolios and the demand distributions. CFE has the least variability and calculates a threshold margin of 9.3% in 2017 to 7.9% in 2026. The decrease over the years is due to the increasing expected demand forecast. On a megawatt-hour basis, the numbers would remain roughly the same. LDWP has the most variability in the subregion leading to a need of about 20.9% threshold margin in 2017 falling to around 19.4% in 2026.



Table 13: Normalized Annual Threshold Margin - Existing Resources Only - CAMX

Year All CISC CIPV LDWP CISD CFE

2017 12.6% 10.7% 12.7% 20.9% 13.2% 9.3%

2018 12.7% 10.8% 12.7% 20.9% 13.3% 9.1%

2019 12.7% 10.8% 12.8% 20.9% 13.4% 8.9%

2020 12.7% 10.9% 12.8% 20.9% 13.5% 8.8%

2021 12.7% 10.9% 12.8% 20.6% 13.5% 8.6%

2022 12.7% 10.9% 12.8% 20.4% 13.5% 8.4%

2023 12.7% 11.0% 12.8% 20.1% 13.5% 8.3%

2024 12.7% 11.0% 12.8% 19.8% 13.6% 8.2%

2025 12.7% 11.0% 12.8% 19.6% 13.6% 8.0%

2026 12.7% 11.1% 12.8% 19.4% 13.7% 7.9%


Comparing the threshold margin for all hours of the year using future resources as well as existing resources, all areas experience an increase in the threshold margin as shown in Table 14 below. CFE is expected to have an increase in the threshold margin beginning in 2019 when new resources are expected part-way through the year. Starting in 2020, the overall increase in the threshold margin is approximately 1.8% for the remaining years. CISC is expecting a full-year increase of ~1.4% while CIPV, LDWP, and CISD are expecting an overall increase of 0.9%, 0.6% and 0.7% respectively.

Table 14: Normalized Annual Threshold Margin - Future Resources Included - CAMX


2017 12.7% 10.8% 12.7% 20.9% 13.5% 9.3%

2018 13.1% 11.2% 13.2% 21.1% 14.0% 9.1%

2019 13.4% 11.5% 13.5% 21.4% 14.1% 9.4%

2020 13.7% 12.1% 13.5% 21.4% 14.2% 10.6%

2021 13.8% 12.3% 13.7% 21.2% 14.2% 10.5%

2022 13.8% 12.3% 13.7% 21.0% 14.2% 10.3%

2023 13.8% 12.3% 13.7% 20.7% 14.2% 10.1%

2024 13.8% 12.4% 13.7% 20.4% 14.3% 9.9%

2025 13.8% 12.4% 13.7% 20.2% 14.3% 9.7%

2026 13.8% 12.5% 13.7% 20.0% 14.4% 9.6%




Exploring all areas on an islanded basis (without imports), the number of hours each year where the threshold margin is not maintained can be represented as hours where there is DAR (see Table 15). With only existing resources, CFE has the most hours where maintaining a 0.02% LOLP or less is not met. CISC, LDWP, and CISD all have some hours of DAR. Where CISC experiences some hours every year, LDWP begins to experience hours of DAR beginning in 2023, and CISD experiences hours through 2019 but then none. CIPV experiences no hours of DAR.

Table 15: Pre-Import Demand-at-Risk Hours - Existing Resources Only - CAMX


2017 63 59 - - 8 9

2018 78 53 - - 3 39

2019 114 46 - - 2 84

2020 187 34 - - - 176

2021 308 24 - - - 303

2022 461 29 - - - 458

2023 598 30 - 2 - 597

2024 706 28 - 8 - 706

2025 903 20 - 14 - 903

2026 1,151 17 - 27 - 1,151


Comparing all hours of the year using future resources as well as existing resources and represented in Table 16, the overall number of DAR hours decreases. CFE experiences some DAR hours in 2017-18 but with the new resources, 2019 reflects no DAR hours. CISC still experiences some hours each year while LDWP is almost nil. CISD experiences no DAR hours as CIPV.

Table 16: Pre-Import Demand-at-Risk Hours - Future Resources Included - CAMX


2017 57 53 - - - 92018 64 33 - - - 382019 21 21 - - - -

2020 13 6 - - - 72021 29 3 - - - 262022 46 2 - - - 442023 98 2 - 2 - 952024 179 2 - 4 - 1762025 299 1 - 7 - 298

2026 440 1 - 19 - 439




As shown in Figure 3 below, only using existing resources throughout the entire Western Interconnection, the areas can import a significant amount of energy. The lighter shaded bars represent the “1st Order” imports (imports from immediate neighbors of which the area has direct ties with). The darker shaded bars represent the additional “2nd Order” imports (imports from the immediate neighbor’s immediate neighbors, relying on more than one area and multiple transmission transfers). As shown, CISC, CFE, and LDWP all rely on some 2nd Order imports.

Figure 3: Average Hourly Imports (in megawatts) - Existing Resources Only – CAMX

2017

2017

2017

2018

2018

2018

2019

2019

2019

2020

2020

2020

2021

2021

2021

2022

2022

2022

2023

2023

2023

2024

2024

2024

2025

2025

2025

2026

2026

2026 -

200

400

600

800

1,000

1,200

CISC - 1st Order CIPV - 1st Order LDWP - 1st Order CISD - 1st Order CFE - 1st OrderCISC - 2nd Order CIPV - 2nd Order LDWP - 2nd Order CISD - 2nd Order CFE - 2nd Order



Figure 4: Average Hourly Imports (in megawatts) – Future Resources Included – CAMX

2017

2017

2017

2018

2018

2018

2019

2019

2019

2020

2020

2020

2021

2021

2021

2022

2022

2022

2023

2023

2023

2024

2024

2024

2025

2025

2025

2026

2026

2026 -

200

400

600

800

1,000

1,200

CISC - 1st Order CIPV - 1st Order LDWP - 1st Order CISD - 1st Order CFE - 1st OrderCISC - 2nd Order CIPV - 2nd Order LDWP - 2nd Order CISD - 2nd Order CFE - 2nd Order




Re-analyzing all areas this time after imports, the number of hours each year where there is Demand-At-Risk (DAR) (see Table 17) is significantly reduced from the Islanded analysis. With only existing resources, CFE again has the most hours where maintaining a 0.02% LOLP or less is not met. CISC, LDWP, and CISD all have some hours of DAR, but they are limited. CIPV, as before, experiences no hours of DAR.

Table 17 – Post-Import Demand-At-Risk Hours - Existing Resources Only - CAMX


2017 1 - - - 1 -

2018 1 - - - 1 -

2019 1 - - - 1 -

2020 - - - - - -

2021 - - - - - -

2022 3 - - - - 3

2023 18 - - - - 18

2024 49 2 - 2 - 49

2025 93 3 - 3 - 93

2026 198 2 - 4 - 198


Comparing all hours of the year after imports using future resources as well as existing resources (see Table 18) all hours of DAR are removed from the subregion except for 19 hours in CFE in 2026.

Table 18 – Post-Import Demand-At-Risk Hours - Future Resources Included - CAMX


2017 - - - - - -

2018 - - - - - -

2019 - - - - - -

2020 - - - - - -

2021 - - - - - -

2022 - - - - - -

2023 - - - - - -

2024 - - - - - -

2025 - - - - - -

2026 19 - - - - 19



5. Southwest Reserve Sharing Group (SRSG)

The Southwest Reserve Sharing Group (SRSG) subregion is made up of 11 BAs that represent three major load areas: 1) PNM—New Mexico; 2) AZPS—Arizona; and 3) IID—a portion of southeastern California.




SRSG is a summer-peaking area with an expected peak demand forecast of roughly 22.7 GW in 2017 increasing to about 27.0 GW by 2026. Existing generating resources are about 32.0 GW decreasing to approximately 31.0 GW by 2026. Future resources are expected to add an additional 4.4 GW by 2026 for a total installed capacity of approximately 35.5 GW. For the summer-peak hours, the SRSG area exports approximately 3.1 GW in 2017 decreasing to around 0.7 GW in 2026. The PRM in this subregion with existing resources and net imports is close to 26.6% in 2017 decreasing to just under 12% in 2026. Including future resources and imports, the expected future margin is as high as 27.6% in 2017 decreasing to just under 18% in 2026. The building block Reference Margin calculated for this subregion is 15.82%. Using probabilistic methods, the Threshold Margin for the peak hour is consistently around 11%.

Table 19: LTRA Results for SRSG

Year 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Demand 22,787 23,175 23,660 24,124 24,623 24,964 25,411 25,856 26,516 27,069


Future Resources 334 246 788 1,816 2,187 2,883 3,464 4,224 4,415 4,486

Net Imports (3,168) (3,177) (3,177) (3,151) (3,177) (2,933) (2,548) (2,062) (1,380) (770)


28,863 28,603 28,557 28,510 28,462 28,749 28,979 29,138 29,761 30,302


Existing Margin 26.66 23.42 20.70 18.18 15.59 15.16 14.04 12.69 12.24 11.94%

Future Margin 27.68 22.99 20.26 21.85 19.18 19.92 18.69 18.29 18.04 17.95%

Reference Margin 15.82 15.82 15.82 15.82 15.82 15.82 15.82 15.82 15.82 15.82%

Threshold Margin 10.92% 11.2 11.03% 11.10% 11.02% 11.05% 11.03% 11.00% 10.84% 10.71%


Calculating the threshold margin for all hours of the year, as depicted in Table 20 below, the normalized annual threshold margin for all areas combined is about 15.3% in 2017 falling to approximately 13.7% in 2026 with existing resources only. By individual area, the threshold margins deviate based on the variability of the generation portfolios and the demand distributions. PNM has the least variability and calculates a threshold margin of 13.2% in 2017 to 11.9% in 2026. The decrease over the years is due to the increasing expected demand forecast. On a megawatt-hour basis, the numbers would remain about the same. AZPS has the most variability in the subregion leading to a need of about 16.0% threshold margin in 2017 falling to roughly 14.3% in 2026.



Table 20: Normalized Annual Threshold Margin - Existing Resources Only - SRSG

Year All AZPS PNM IID

2017 15.3% 16.0% 13.2% 13.7%

2018 15.1% 15.8% 13.2% 13.6%

2019 14.9% 15.5% 13.1% 13.4%

2020 14.8% 15.3% 13.1% 13.3%

2021 14.6% 15.1% 13.0% 13.1%

2022 14.4% 14.9% 12.8% 13.0%

2023 14.2% 14.7% 12.6% 12.9%

2024 14.0% 14.6% 12.3% 12.8%

2025 13.9% 14.4% 12.1% 12.6%

2026 13.7% 14.3% 11.9% 12.5%


Comparing the threshold margin for all hours of the year using future resources as well as existing resources, all areas experience an increase in the threshold margin as shown in Table 21 below. IID is expected to have an increase in the threshold margin beginning in 2019 when new resources are expected part-way through the year. Starting in 2020, the overall increase in the threshold margin is approximately 1.7% by 2026. PNM is expecting a full-year increase of ~1.4% while AZPS is expecting an overall increase of 2.0%.

Table 21: Normalized Annual Threshold Margin - Future Resources Included - SRSG


2017 15.4% 16.1% 13.2% 13.7%

2018 15.9% 17.0% 12.5% 13.6%

2019 15.9% 16.9% 12.5% 13.6%

2020 15.9% 16.9% 12.6% 13.7%

2021 15.9% 16.9% 12.6% 13.9%

2022 15.9% 16.8% 13.1% 13.8%

2023 15.9% 16.6% 13.4% 14.0%

2024 15.8% 16.6% 13.3% 14.2%

2025 15.7% 16.4% 13.3% 14.2%



2026 15.6% 16.3% 13.3% 14.2%


Exploring all areas on an islanded basis (without imports), the number of hours each year where the threshold margin is not maintained can be represented as hours where there is DAR (see Table 22). With only existing resources, PNM has the most hours where maintaining a 0.02% LOLP or less is not met. AZPS has some hours of DAR beginning in 2022, while IID experiences 1 DAR hour in 2026.

Table 22: Pre-Import Demand-at-Risk Hours - Existing Resources Only - SRSG


2017 5 - 5 -

2018 9 - 9 -

2019 20 - 20 -

2020 34 - 34 -

2021 66 - 66 -

2022 125 3 122 -

2023 224 11 220 -

2024 357 27 352 -

2025 481 52 472 -

2026 594 94 576 1


Comparing all hours of the year using future resources as well as existing resources (see Table 23) AZPS and IID DAR hours are reduced to none. PNM experiences a sharp increase in DAR hours in 2018-21 but then a decrease with new resources from 2022 to 2026.

Table 23: Pre-Import Demand-at-Risk Hours - Future Resources Included - SRSG


2017 5 - 5 -

2018 108 - 108 -

2019 126 - 126 -

2020 138 - 138 -

2021 182 - 182 -

2022 103 - 103 -

2023 103 - 103 -

2024 75 - 75 -

2025 100 - 100 -

2026 98 - 98 -




As shown in Figure 5 below, only using existing resources throughout the entire Western Interconnection, the areas can import a significant amount of energy. The lighter shaded bars represent the “1st Order” imports (imports from immediate neighbors of which the area has direct ties with). The darker shaded bars represent the additional “2nd Order” imports (imports from the immediate neighbor’s immediate neighbors, relying on more than one area and multiple transmission transfers). As shown, PNM relies on some 2nd Order imports in the latter years.

Figure 5: Average Hourly Imports (in megawatts) - Existing Resources Only - SRSG

2017

2017

2018

2018

2019

2019

2020

2020

2021

2021

2022

2022

2023

2023

2024

2024

2025

2025

2026

2026 -

100 200 300 400 500 600 700 800 900

AZPS - 1st Order AZPS - 2nd Order PNM - 1st OrderPNM - 2nd Order IID - 1st Order IID - 2nd Order



Figure 6: Average Hourly Imports (in megawatts) - Future Resources Included - SRSG

2017

2017

2018

2018

2019

2019

2020

2020

2021

2021

2022

2022

2023

2023

2024

2024

2025

2025

2026

2026 -

100 200 300 400 500 600 700 800 900

AZPS - 1st Order AZPS - 2nd Order PNM - 1st OrderPNM - 2nd Order IID - 1st Order IID - 2nd Order




Re-analyzing all areas this time after imports, the number of hours each year where there is Demand-At-Risk (DAR) (see Table 24) is significantly reduced from the Islanded analysis. With only existing resources, PNM and AZPS still show a few DAR hours in 2026. IID experiences no hours of DAR.

Table 24: Post-Import Demand-At-Risk Hours – Existing Resources Only - SRSG


2017 - - - -

2018 - - - -

2019 - - - -

2020 - - - -

2021 - - - -

2022 - - - -

2023 - - - -

2024 - - - -

2025 - - - -

2026 6 2 4 -



Table 25: Post-Import Demand-At-Risk Hours – Future Resources Included - SRSG


2017 - - - -

2018 - - - -

2019 - - - -

2020 - - - -

2021 - - - -

2022 - - - -

2023 - - - -

2024 - - - -

2025 - - - -

2026 - - - -



6. Rocky Mountain Reserve Group (RMRG)

The Rocky Mountain Reserve Group (RMRG) subregion is made up of 2 BAs and 2 major load areas: 1) WAWY—eastern Wyoming and parts of South Dakota and Nebraska; and 2) PSCO—all of Colorado.




RMRG is a summer-peaking area with an expected peak demand forecast of roughly 11.8 GW in 2017 increasing to approximately 13.4 GW by 2026. Existing generating resources are about 18.2 GW decreasing to around 17.5 GW by 2026. Future resources are expected to add an additional 0.4 GW by 2026 for a total installed capacity of approximately 18.0 GW. For the summer-peak hours, the RMRG area exports approximately 3.0 GW in 2017 decreasing to around 1.9 GW in 2026. The PRM in this subregion with existing resources and net imports is close to 28.5% in 2017 decreasing to just under 16% in 2026. Including future resources and imports, the expected future margin is as high as 29.6% in 2017 decreasing to just under 20% in 2026. The building block Reference Margin calculated for this subregion is 14.14%. Using probabilistic methods, the Threshold Margin for the peak hour is approximately 10.8% in 2017 decreasing to roughly 9.6% by 2026.

Table 26: NERC Long-Term Reliability Assessment (LTRA) Results - RMRG

Year 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Demand 11,847 11,968 12,178 12,344 12,585 12,760 12,932 13,113 13,279 13,459


Future Resources 152 458 416 434 429 445 450 440 444 443

Net Imports (3,047) (3,131) (3,131) (3,131) (2,723) (2,710) (2,511) (2,305) (2,184) (1,957)


15,224 14,528 14,538 14,532 14,742 14,846 15,047 15,221 15,389 15,594

Future + Net Imports

15,376 14,986 14,954 14,966 15,171 15,290 15,497 15,661 15,833 16,037

Existing Margin 28.50% 21.39% 19.38% 17.72% 17.14% 16.34% 16.35% 16.08% 15.89% 15.86%

Future Margin 29.68% 25.13% 22.72% 21.12% 20.45% 19.67% 19.64% 19.61% 19.58% 19.53%

Reference Margin 14.14% 14.14% 14.14% 14.14% 14.14% 14.14% 14.14% 14.14% 14.14% 14.14%

Threshold Margin 10.82% 10.56% 10.39% 10.25% 10.16% 10.02% 9.93% 9.85% 9.75% 9.64%


Calculating the threshold margin for all hours of the year, as depicted in Table 27 below, the normalized annual threshold margin for both load areas combined is roughly 17.3% in 2017 falling to approximately 15.1% in 2026 with existing resources only. By individual area, the threshold margins deviate based on the variability of the generation portfolios and the demand distributions. WAWY has the least variability and calculates a threshold margin of 10.9% in 2017 to 9.2% in 2026. The decrease over the years is due to the increasing expected demand forecast. On a megawatt-hour basis, the numbers would remain about the same. PSCO has the most variability in the subregion leading to a need of approximately 18.3% threshold margin in 2017 falling to roughly 16.1% in 2026.



Table 27: Normalized Annual Threshold Margin - Existing Resources Only - RMRG

Year All PSCO WAWY

2017 17.3% 18.3% 10.9%

2018 17.0% 18.0% 10.7%

2019 16.7% 17.7% 10.5%

2020 16.4% 17.5% 10.4%

2021 16.0% 17.0% 10.1%

2022 15.9% 16.9% 9.9%

2023 15.7% 16.7% 9.7%

2024 15.5% 16.5% 9.6%

2025 15.3% 16.3% 9.4%

2026 15.1% 16.1% 9.2%


Comparing the threshold margin for all hours of the year using future resources as well as existing resources, all areas reflect very small differences.

Table 28: Normalized Annual Threshold Margin - Future Resources Included - RMRG

Year All PSCO WAWY

2017 17.3% 18.4% 10.9%

2018 16.8% 17.8% 10.7%

2019 16.5% 17.5% 10.5%

2020 16.2% 17.2% 10.4%

2021 16.1% 17.1% 10.1%

2022 15.9% 16.9% 9.9%

2023 15.7% 16.7% 9.7%

2024 15.5% 16.5% 9.6%

2025 15.3% 16.3% 9.4%

2026 15.1% 16.1% 9.2%




Exploring all areas on an islanded basis (without imports), the number of hours each year where the threshold margin is not maintained can be represented as hours where there is DAR (see Table 29). With only existing resources, PSCO experiences hours where maintaining a 0.02% LOLP or less is not met, while WAWY experiences no hours of DAR.

Table 29: Pre-Import Demand-At-Risk Hours – Existing Resources Only - RMRG

Year All PSCO WAWY

2017 - - -

2018 5 5 -

2019 21 21 -

2020 51 51 -

2021 92 92 -

2022 136 136 -

2023 172 172 -

2024 189 189 -

2025 223 223 -

2026 290 290 -


Comparing all hours of the year using future resources as well as existing resources (see Table 30) the overall number of DAR hours increases. WAWY remains with no DAR hours.

Table 30: Pre-Import Demand-At-Risk Hours – Future Resources Included - RMRG

Year All PSCO WAWY

2017 - - -

2018 21 21 -

2019 44 44 -

2020 74 74 -

2021 128 128 -

2022 196 196 -

2023 237 237 -

2024 243 243 -

2025 281 281 -



2026 347 347 -


As shown in Figure 7 below, only using existing resources throughout the entire Western Interconnection, PSCO can import a significant amount of energy. The lighter shaded bars represent the “1st Order” imports (imports from immediate neighbors that the area has direct ties with). The darker shaded bars represent the additional “2nd Order” imports (imports from the immediate neighbor’s immediate neighbors, relying on more than one area and multiple transmission transfers). As shown, PSCO relies on 2nd Order imports in the outer years, WAWY does not need imports.

Figure 7: Annual Average Hourly Imports (in megawatts) - Existing Resources Only - RMRG

2017

2017

2018

2018

2019

2019

2020

2020

2021

2021

2022

2022

2023

2023

2024

2024

2025

2025

2026

2026 -

200

400

600

800

1,000

PSCO - 1st Order PSCO - 2nd Order WAWY - 1st Order WAWY - 2nd Order


With future resources included with existing resources, the 2nd Order transfers are significantly increased and begin in 2021 as compared to 2022 with existing resources (see Figure 8). Increasing the 2nd Order transfers adds additional risk in the system that comes from transmission availability.

Figure 8: Annual Average Hourly Imports (in megawatts) - Future Resources Included - RMRG

2017

2017

2018

2018

2019

2019

2020

2020

2021

2021

2022

2022

2023

2023

2024

2024

2025

2025

2026

2026 -

100 200 300 400 500 600 700 800 900

1,000

PSCO - 1st Order PSCO - 2nd Order WAWY - 1st Order WAWY - 2nd Order




Re-analyzing all areas, this time after imports, the number of hours each year where there is DAR is significantly reduced from the Islanded analysis (see Table 31). With only existing resources, PSCO only experiences a few hours in 2023 through 2026 where maintaining a 0.02% LOLP or less is not met. WAWY, as before, experiences no hours of DAR.

Table 31: Demand-At-Risk Hours - Existing Resources Only - RMRG

Year All PSCO WAWY

2017 - - -

2018 - - -

2019 - - -

2020 - - -

2021 - - -

2022 - - -

2023 2 2 -

2024 4 4 -

2025 10 10 -

2026 7 7 -



Table 32: Demand-At-Risk Hours - Future Resources Included - RMRG

Year All PSCO WAWY

2017 - - -

2018 - - -

2019 - - -

2020 - - -

2021 - - -

2022 - - -

2023 - - -

2024 - - -

2025 - - -

2026 - - -



7. Canada

The Canada (CAN) subregion is made up of two major load areas: BCHA—British Columbia; and AESO—Alberta.




CAN is a winter-peaking area with an expected peak demand forecast of roughly 23.7 GW in 2017-18 increasing to about 27.3 GW by 2026-27. Existing generating resources are approximately 27.6 GW increasing slightly to 27.7 GW by 2026-27. Future resources are expected to add an additional 10.7 GW by 2026-27 for a total installed capacity of approximately 38.4 GW. For the winter-peak hours, the CAN area imports approximately 0.7 GW in 2017-18 increasing to around 1.9 GW in 2026-27. The PRM in this subregion with existing resources and net imports is close to 19.3% in 2017-18 decreasing to just under 9% in 2026-27. Including future resources and imports, the expected future margin is as high as 50.8% in 2020-21 decreasing to just over 48% in 2026-27. The building block Reference Margin calculated for this subregion is 12.1%. Using probabilistic methods, the Threshold Margin for the peak hour is approximately 12.4% in 2017-18 increasing to roughly 13.3% by 2026-27.

Table 33: NERC Long-Term Reliability Assessment (LTRA) Results - Canada

Winter 2017-18 2018-19 2019-20

2020-21

2021-22

2022-23

2023-24

2024-25

2025-26

2026-27

Demand 23,785 24,001 24,600 25,082 25,440 25,861 26,229 26,600 26,967 27,344



Net Imports 715 881 1,084 1,248 1,391 1,625 1,756 1,900 1,950 1,950

Existing + Net Imports 28,386 28,505 28,792 28,902 29,176 29,296 29,301 29,524 29,604 29,721


Existing Margin 19.34% 18.76% 17.04% 15.23% 14.69% 13.28% 11.71% 10.99% 9.78% 8.69%

Future Margin 31.76% 46.62% 49.88% 50.83% 50.83% 48.78% 45.87% 48.79% 48.81% 48.03%

Reference Margin 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10%

Threshold Margin 12.44% 13.83% 14.15% 14.03% 13.87% 13.72% 13.57% 13.57% 13.49% 13.37%


Exploring the threshold margin for all hours of the year, as depicted in Table 34 below, the normalized annual threshold margin for both areas combined is roughly 11.4% in 2017 falling to approximately 10.0% in 2026 with existing resources only. By individual area, the threshold margins deviate based on the variability of the generation portfolios and the demand distributions. AESO has the least variability and calculates a threshold margin of 8.3% in 2017 to 7.2% in 2026. The decrease over the years is due to the increasing expected demand forecast. On a megawatt-hour basis, the numbers would remain about the same. BCHA has the most variability in the subregion leading to a need of approximately 15.7% threshold margin in 2017 falling to roughly 13.9% in 2026.



Table 34: Normalized Annual Threshold Margin - Existing Resources Only - Canada

Year All BCHA AESO

2017 11.4% 15.7% 8.3%

2018 11.2% 15.4% 8.1%

2019 10.9% 14.9% 8.0%

2020 10.7% 14.7% 7.8%

2021 10.5% 14.5% 7.7%

2022 10.4% 14.4% 7.6%

2023 10.3% 14.3% 7.5%

2024 10.2% 14.2% 7.4%

2025 10.1% 14.1% 7.3%

2026 10.0% 13.9% 7.2%


Comparing the threshold margin for all hours of the year using future resources as well as existing resources, all areas experience an increase in the threshold margin as shown in Table 35 below. AESO is expected to have an increase in the threshold margin of approximately 1.0% to 3.8%. BCHA is expecting an increase of roughly 1.8% by 2026.

Table 35: Normalized Annual Threshold Margin - Future Resources Included - Canada

Year All BCHA AESO

2017 12.0% 15.8% 9.3%

2018 13.1% 15.6% 11.3%

2019 13.5% 15.4% 12.1%

2020 13.3% 15.2% 11.9%

2021 13.2% 15.1% 11.7%

2022 13.0% 15.0% 11.6%

2023 12.9% 15.0% 11.4%

2024 13.0% 15.5% 11.3%

2025 13.0% 15.7% 11.1%

2026 12.9% 15.7% 11.0%




Exploring all areas on an islanded basis (without imports), the number of hours each year where the threshold margin is not maintained can be represented as hours where there is DAR (see Table 36). With only existing resources, BCHA experiences hours where maintaining a 0.02% LOLP or less is not met. AESO experiences no hours of DAR.

Table 36: Pre-Import Demand-At-Risk Hours - Existing Resources Only - Canada

Year All BCHA AESO

2017 314 314 -

2018 482 482 -

2019 737 737 -

2020 951 951 -

2021 1,156 1,156 -

2022 1,302 1,302 -

2023 1,453 1,453 -

2024 1,602 1,602 -

2025 1,858 1,858 -

2026 2,161 2,161 -


Comparing all hours of the year using future resources as well as existing resources (see Table 37) the overall number of DAR hours decreases. The hours that BCHA experiences DAR is decreased slightly in the beginning years and substantially in the outer years as new resources connect to the Interconnection. AESO remains with no DAR hours.

Table 37: Demand-At-Risk Hours - Future Resources Included - Canada

Year All BCHA AESO

2017 263 263 -

2018 358 358 -

2019 423 423 -

2020 546 546 -

2021 660 660 -

2022 608 608 -

2023 652 652 -

2024 343 343 -

2025 218 218 -

2026 271 271 -




As shown in Figure 9 below, only using existing resources throughout the entire Western Interconnection, BCHA can import a significant amount of energy. The lighter shaded bars represent the “1st Order” imports (imports from immediate neighbors of which the area has direct ties with). The darker shaded bars represent the additional “2nd Order” imports (imports from the immediate neighbor’s immediate neighbors, relying on more than one area and multiple transmission transfers). As shown, BCHA relies on some 2nd Order imports in all years.

Figure 9: Annual Average Hourly Imports (in megawatts) - Existing Resources Only - Canada

2017

2017

2018

2018

2019

2019

2020

2020

2021

2021

2022

2022

2023

2023

2024

2024

2025

2025

2026

2026 -

100 200 300 400 500 600 700 800 900

BCHA - 1st Order BCHA - 2nd Order AESO - 1st Order AESO - 2nd Order


With future resources included with existing resources, the 2nd Order transfers are significantly reduced but there are still significant imports in 2020-23 and again in 2026 (see Figure 10). Reducing the 2nd Order transfers removes additional risk in the system that comes from transmission availability.

Figure 10: Annual Average Hourly Imports (in megawatts) - Future Resources Included - Canada

2017

2017

2018

2018

2019

2019

2020

2020

2021

2021

2022

2022

2023

2023

2024

2024

2025

2025

2026

2026 -

100 200 300 400 500 600 700 800 900

BCHA - 1st Order BCHA - 2nd Order AESO - 1st Order AESO - 2nd Order




Re-analyzing all areas, this time after imports, the number of hours each year where there is DAR (see Table 38) is significantly reduced from the Islanded analysis. With only existing resources, BCHA only experiences a few hours in 2025 and 2026 where maintaining a 0.02% LOLP or less is not met. AESO, as before, experiences no hours of DAR.

Table 38: Demand-At-Risk Hours - Existing Resources Only - Canada

Year All BCHA AESO

2017 - - -

2018 - - -

2019 - - -

2020 - - -

2021 - - -

2022 - - -

2023 - - -

2024 - - -

2025 2 2 -

2026 3 3 -



Table 39: Demand-At-Risk Hours - Future Resources Included - Canada

Year All BCHA AESO

2017 - - -

2018 - - -

2019 - - -

2020 - - -

2021 - - -

2022 - - -

2023 - - -

2024 - - -

2025 - - -

2026 - - -



8. Conclusions

Overall, this report found that the Western Interconnection, with future planned resources and the ability to share excess energy among areas, is expected to maintain a reliability level of 99.98% for all hours over the next ten years except for 19 hours in 2026. As new resources are projected to be built in future resource plans and LTRA submittals, these hours will probably reach a higher level of reliability. Analyzing all areas on an individual basis without imports from other areas has shed light on where the system could experience high levels of unreliability if the transmission system were to fail and has also shown where there is high reliance on transfer capabilities to maintain a level of reliability of 99.98%.

This report has also shown that, as of the date of publication, there are small differences between using the building block approach to calculate a reference margin and using a probabilistic method to calculate a threshold margin. As the industry evolves, WECC should consider switching over to the probabilistic process to capture the dynamic nature of the evolving resource portfolio.

Finally, analyzing how the expected new resources impact the threshold margins as compared to the threshold margins with just existing resources, insight into how reliability risk is evolving as the resource portfolio evolves is now visible. Further analysis should be focused on larger portfolio changes to possibly determine at what levels of portfolio changes large movements in reliability risk occurs.


Documents

Probabilistic Resource Adequacy Assessment - Final Resourc… · Web viewThe 19 hours occur over 1 weeks’ time in late August with reliability reaching a low of 99.6% reliability