2020 RRS Annual Assessment

2020 Annual Assessment Reliability Review Subcommittee

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Contents

Preface ...........................................................................................................................3 About This Assessment ..................................................................................................4 Executive Summary ........................................................................................................5 Detailed Review of 2019 Findings ............................................................................ 6 Subregion Reserve Margins............................................................................................7 Capacity Resource Trends..............................................................................................8 Capacity Resource Topics ..............................................................................................9 Demand Projections......................................................................................................10 Transmission Additions .................................................................................................11 Subregional Dashboards/Summaries ..................................................................... 13 SERC Central ...............................................................................................................14 SERC East....................................................................................................................16 SERC FL-Peninsula ......................................................................................................18 SERC MISO-Central .....................................................................................................20 SERC MISO-South .......................................................................................................23 SERC PJM....................................................................................................................25 SERC Southeast ...........................................................................................................27 Special Topics .................................................................................................... 29 Working Group Contributions ........................................................................................30 Long/Near-Term Transmission Summary...................................................................... 32 Seasonal Outlook..........................................................................................................33 Data Concepts and Assumptions ........................................................................... 34 Appendix A Glossary ........................................................................................ 388 Appendix B SERC Membership ............................................................................ 39

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Preface SERC Reliability Corporation (SERC), located in Charlotte, North Carolina, is a nonprofit regulatory authority that promotes effective and efficient administration of bulk power system (BPS) reliability in all or parts of 16 central and southeastern states. SERC’s jurisdiction includes users, owners, and operators of the BPS within the SERC footprint, known as the SERC Region. On July 20, 2006, the North American Electric Reliability Corporation (NERC) was certified as the Electric Reliability Organization (ERO) in the United States, pursuant to Section 215 of the Federal Power Act. As the ERO, NERC may delegate authority to Regional Entities (REs) to monitor and enforce NERC Reliability Standards. NERC and the REs work to safeguard BPS reliability throughout North America. As one of six REs, SERC is delegated to perform certain functions from the ERO and is subject to oversight from the Federal Energy Regulatory Commission (FERC). SERC promotes and monitors compliance with mandatory Reliability Standards, assesses seasonal and long-term reliability, monitors the BPS through system awareness, and educates and trains industry personnel.

Figure 1: 2020 Subregions

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About This Assessment This 2020 Reliability Review Subcommittee Annual Assessment (2020 Annual Report) was developed by the SERC Reliability Review Subcommittee (RRS) in accordance with the Energy Policy Act of 2005 (Title 18, § 39.111 of the Code of Federal Regulations). This assessment also fulfils the ERO’s Rules of Procedure, which instruct the Regions to conduct periodic assessments of the Regional BPS. Development Process This assessment was developed based on data and narrative information collected by SERC from its Registered Entities to independently assess the long-term reliability of the SERC BPS while identifying trends, emerging issues, and potential risks during the ten- year assessment period. The Reliability Review Subcommittee (RRS), at the direction of SERC’s Engineering Committee, supported the development of this assessment through a review process that leveraged the knowledge and experience of system planners, RRS members, SERC staff, and other subject matter experts. This review

process ensures the accuracy and completeness of all data and information. The SERC Engineering Committee reviewed and

approved this assessment. Data Considerations

Forecasts in the 2020 RRS Annual Report are not predictions of what will happen; they are based on information supplied by Registered Entities in February 2020 and updates incorporated prior to publication. The assessment period for the 2020 RRS Annual Report is from 2020 to 2029. The assessment was developed using a consistent approach for projecting future resource adequacy through the application of SERC’s assumptions and assessment methods. SERC’s standardized data reporting and instructions were developed through stakeholder processes to promote data consistency across all the reporting entities. Reliability impacts related to physical and cybersecurity risks are not addressed in this assessment, which is primarily focused on resource adequacy.

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Executive Summary The RRS assembled and reviewed many sources of data to assess the future reliability of the Region from a resource adequacy and transmission system performance vantage point. This report considers four focus areas: Demand and Energy, Capacity Resources, Reserve Margins, and Transmission. The RRS leverages studies and reports from other SERC committees such as the Dynamics Working Group (DWG), Resource AdequacyWorking Group (RAWG), Near-TermWorking Group (NTWG), and Long-TermWorking Group (LTWG) to assess transmission and resource adequacy impacts from different perspectives. The main body of this report provides additional detail to support the following: Key Findings

Expected demand projections for the SERC Region are almost flat. • The SERC Region’s 2020-2029 Compound Annual Growth Rate (CAGR) is 0.62 percent, slightly higher than that reported last year. • On the high end, the SERC PJM subregion has a 1.27 percent CAGR. • On the low end, the SERC Southeast subregion has a -0.10 percent CAGR. Five of the seven SERC subregions expect the Anticipated Reserve Margins to be above twenty percent for the ten-year period. • Two of the seven subregions expect to maintain a ten-year reserve margin in the eighteen to thirty percent range. • MISO South and MISO Central have access to additional firm deliverable resources between the two subregions up to the Regional Directional Transfer Limit of 1,000 MW; however, combined both subregions begin to fall below the reserve margin level beginning in 2026. • SERC and the RRS will monitor the resource additions for the later years for the MISO foot print. Only slight changes in the Regional resource mix are projected for the 10-year planning horizon, with no significant change reported from 2019 to 2020. The only exception is higher long term forecasted growth in variable energy resources

Net capacity resources in the Region are expected to increase for the first five years of the ten-year planning horizon and gradually level out in the last five years, with natural gas-fired capacity additions largely offset by coal-fired capacity retirements. • Approximately 1.1 GW of natural gas resources, 6.5 GW of utility scale solar (photovoltaic) resources, and 2 GW of nuclear resources are expected by 2024. • Approximately 2.2 GW of coal resource retirements are expected by 2024. SERC is proactively addressing the impacts of increased renewable resources within the SERC footprint and identifying its risks through various forums. • The Variable Energy Resource Working Group (VERWG) explores the reliability considerations related to variable energy resource integration in the SERC Region. • Hundreds of future utility scale transmission connected photovoltaic (PV) projects totaling ~28.8 GW of nameplate capacity (~7.1 GW Tier 1, 10 GW Tier 2, and 12 GW Tier 3; see Resource Categories on page 35 for definitions of tier resources) are reported by Generator Owners over the next 5 years.

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• As of August, 2020 there are 123,950 miles of transmission lines at 100 kV and above in the SERC Region. • Entities within the SERC Region anticipate adding approximately 2,500 miles of transmission during the 10-year reporting period.

Across the SERC Region, member companies continue to build transmission, especially in the first five years of the assessment period, to ensure a reliable interconnected power system. • Transmission is added to ensure compliance with national and local standards, improve intraregional and interregional transfer capabilities, relieve congestion, and ensure generation deliverability.

Detailed Review of 2020 Findings

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Subregion Reserve Margins Reference Margin Levels are established to allow NERC to assess the level of planning reserves, recognizing factors of uncertainty involved in long- term planning (e.g., forced generator outages, extreme weather impacts on demand, fuel availability, and intermittency of variable generation). SERC utilized the NERC Reference Margin Level of 15 percent. All margins are above the Reference Level over the next 10 years. In addition to Planning Reserve Margin analysis, the 2020 Probabilistic Assessment determines four resource adequacy metrics, which are loss-of- load hours (LOLH), loss-of-load expectation (LOLE), loss-of-load frequency (LOLF), and expected unserved energy (MWh and MPM). At the Anticipated Reserve Margins below, all areas have minimal risk to resource adequacy. In addition to the base case analysis, the RAWG conducts several sensitivity/scenario cases to assess the resource adequacy impact of reducing the Anticipated Reserve Margins and Increased Maintenance Rates. The published SERC 2020 Probabilistic Assessment is available on SERC’s website. For more information regarding this analysis, please read the RAWG subsection under Working Group Contributions of this document. Table 1: Calculated Reserve Margins by Subregion SERC Subregion Margin 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 All Reference Margin Level 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% SERC Central Anticipated Reserve Margin 21.8% 22.2% 22.8% 22.9% 19.4% 17.3% 17.6% 17.2% 16.4% 15.8% SERC East Anticipated Reserve Margin 19.5% 21.2% 21.6% 21.1% 20.4% 23.4% 23.5% 25.1% 25.3% 27.9% SERC MISO- Central 1 Anticipated Reserve Margin 9.5% 12.2% 10.7% 6.8% 6.6% 6.6% 6.5% 6.3% 6.0% 9.8% MISO-South Anticipated Reserve Margin 28.3% 31.3% 29.1% 26.8% 25.8% 23.3% 18.8% 18.3% 17.8% 12.5% SERC-PJM 2 Anticipated Reserve Margin 51.5% 48.7% 45.5% 44.6% 42.1% 40.6% 39.4% 38.2% 36.8% 35.6% SERC Southeast Anticipated Reserve Margin 34.7% 34.5% 37.9% 39.5% 41.4% 40.9% 42.7% 41.8% 45.8% 44.6% SERC Florida Peninsula Anticipated Reserve Margin 22.0% 22.3% 20.9% 23.6% 22.0% 22.1% 24.6% 21.6% 20.1% 20.1%

1 MISO-Central and MISO-South is one Balancing Authority and has access to reserves in both subregions up to the Regional Directional Transfer Limit. 2 Reserve Margins in SERC PJM are calculated for the entire PJM footprint since power flows around PJM without regard to Regional boundaries. No specific reserve margin requirement exists in the regional portions of PJM.

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Capacity Resource Trends

period, with two 1,100 MW nuclear plant additions in 2021 and 2022. Hydro capacity resources are projected to remain essentially unchanged through the forecast period at approximately 7% of the Regional total. Existing solar (photovoltaic) capacity resources in the SERC Region are reported at 5,587 MW, but planned solar additions of around 6,000 MW are projected through 2025. For the period 2020-2029, solar capacity is projected to grow steeply from 1.8 percent to almost 4 percent of the overall resource mix. Biomass, wind, and other resources in the Region are small and do not contribute significantly to the SERC capacity totals or resource mix.

Capacity resources in the SERC Region for 2020 total 308,310 MW. Net capacity resources in the Region are expected to increase for the first 5 years of the 2021- 2029 planning horizon to 317,331 MW. Net capacity resources are projected to gradually increase over the planning horizon with many coal-fired capacity retirements being offset by the additions of natural gas fired generation and variable energy generation. Capacity resources in the planning horizon are projected to increase, reaching 320,305 MW in 2029. Natural gas is the primary fuel source in the SERC Region, followed by coal, nuclear, pumped storage, and other types (which include oil-fired, solar, biomass, wind, and other). For the period 2020- 2029, coal-fired capacity is projected to decrease from 24 percent to 22 percent. SERC members have announced approximately 1,233 MW of large-scale coal-fired capacity retirements through the near-term planning horizon. Nuclear powered resources supply 13 percent of the SERC capacity in 2020. Nuclear is projected to increase slightly to 15 percent through the assessment

Figure 2: Capacity Resource Trends

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Capacity Resource Topics

Table 2: Capacity Resource Topics by Fuel Type Current State

Potential Reliability Issues

Impacted Subregions

Most SERC subregions have recently seen the shrinking of 10-year compound annual growth rates to well below 1%. SERC- South East subregion is reporting a negative growth rate for the 10-year assessment period. With the exception of SERC Florida Peninsula (FL-Peninsula), growth of gas- fired generation in SERC subregions is lower than in most of the NERC Regions. Gas growth, as a percentage of the total fuel mix, is about 1.8%, while coal drops about 4.0% through the assessment period. The use of coal and oil-fired generation is declining. Hydro, pumped storage, and nuclear generation are increasing slightly, with two new nuclear units planned in SERC Southeast during the assessment period. Solar generation is expected to nearly double by the end of the assessment period with the potential of adding upwards of 35 GW by 2029 (51 GW nameplate).

SERC foresees no potential reliability issues relating to demand. However, this lull in growth rates may affect the ability to respond to possible future higher growth.

All SERC subregions, with the exception of SERC FL Peninsula and SERC PJM

Demand

Fuel delivery for gas units is a concern in the unlikely event that a gas pipeline is lost. Development of utility sized natural gas storage or dual-fuel capability may alleviate some concerns. Accelerated natural gas development in the future may require further analysis to determine whether fuel controls are required. Since conventional generation values remain relatively constant, little reliability concern exists. Accelerated natural gas development in the future, coupled with widespread coal plant retirements may require further analysis to determine whether fuel controls are required. Integration of variable energy resources (VERs) raises the risk of voltage regulation, dynamic response, and sudden change in dispatch patterns. The changing characteristic of the grid with the growth of VERs will affect how the grid is operated in the future.

SERC East, SERC MISO-South

Natural Gas

All SERC subregions

Conventional Generation

SERC-East, SERC-Southeast, SERC-FL Peninsula and SERC-PJM

Solar PV

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Demand Projections The 2021-2030 demand forecast shows a 0.62% compound annual growth rate (CAGR), which is slightly higher compared to last year's ten-year growth rate of 0.54%. Figure 4 shows a breakdown of the forecasted growth in total internal demand by subregion. Figure 5 shows the forecasted total internal demand by year.

Figure 3: Compound Annual Growth Rate

Figure 4: SERC Region Total Internal Demand (MW)

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Transmission Additions As of August, 2020, there are approximately 124,000 miles of transmission lines operated at 100 kV and above in the SERC Region. Entities within the SERC Region anticipate adding approximately 2,500 miles during the 10-year reporting period. SERC entities coordinate transmission expansion plans in the Region annually through joint model-building efforts that include the plans of all SERC entities. The coordination of transmission expansion plans with entities outside the Region is achieved through annual participation in joint modeling efforts with the Eastern Interconnection Reliability Assessment Group (ERAG) Multi-regional Modeling Working Group (MMWG). Transmission expansion plans by most SERC entities are dependent on regulatory support at the federal, state, and local levels since the regulatory entities can influence the siting, permitting, and cost recovery of new transmission facilities.

Figure 5: Bulk Electric System Transmission Mileage by Operating Voltage Class

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Transmission Projects Projects to maintain or improve transfer capabilities between Regions or subregions are not necessarily obvious in maps or in lists of planned transmission additions. Tie lines themselves infrequently limit transactions. Rather, the limiting elements are most often internal to the entities’ systems. Projects to improve transfer capabilities can include reconductoring lines, replacing transformers, and upgrading terminal equipment.

Figure 7: Transformer Additions Conclusion

NERC Registered Entities in the SERC Region are committed to planning for a reliable delivery system. Transmission upgrades and the installation of new facilities will be necessary to ensure compliance with national and local standards, improve both intraregional and interregional transfer capabilities, relieve congestion, and ensure generation deliverability. The RRS will continue to assess transmission development in the SERC Region and will monitor the implications to current and future reliability.

Figure 6: 10-Year AC Circuit Project In addition to transmission lines, several new transformers are due to come into service during the next 10 years within the SERC Region. Of the 85 transformer projects, 71 have high-side voltages of 200 kV and above.

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Subregional Dashboards/Summaries

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Highlights • Anticipated Reserve Margins for SERC Central are expected to be sufficient for the next ten-years; however, the Anticipated Reserve Margin starts approaching the reserve margin level in the later years. • Load growth is expected to be minimal across the subregion at approximately 0.38 percent. • Annual peak demand shifted slightly for the subregion from the summer season to the winter season. Projected Demands, Resources, and Reserve Margins (Summer) Demand (MW) 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Total Internal 40,799 40,952 41,159 41,431 41,571 41,600 41,518 41,657 41,759 41,974 Demand Response 1,970 1,958 1,883 1,830 1,795 1,792 1,790 1,789 1,788 1,787 Net Internal 38,829 38,994 39,276 39,601 39,776 39,808 39,728 39,868 39,971 40,187 Resources (MW) Anticipated 47,306 47,633 48,237 48,658 47,474 46,704 46,704 46,704 46,529 46,529 Prospective 51,621 51,898 52,410 52,428 52,240 51,920 51,920 51,920 51,745 51,745 Reserve Margins (%) Anticipated 21.83% 22.15% 22.81% 22.87% 19.35% 17.32% 17.56% 17.15% 16.41% 15.78% Prospective 32.94% 33.09% 33.44% 32.39% 31.33% 30.42% 30.69% 30.23% 29.46% 28.76%

SERC Central The SERC Central subregion is a winter peaking system, which consists of the following Planning Coordinators: Associated Electric Cooperative Inc., Electric Energy Inc., Louisville Gas &

Existing On-Peak Generation (Summer) Generation Type Peak Capacity MW % Biomass 0 0.0% Coal 15,200 31.5% Natural Gas 18,857 39.1% Hydro 3,566 7.4% Nuclear 8,421 17.4% Other 0 0.0% Petroleum 0 0.0% Pumped 1,759 3.6% Solar 8 0.0% Wind 456 0.9%

Electric/Kentucky Utilities, and Tennessee Valley Authority.

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projects that have potential to connect to the Bulk Electric System (BES). A much lower projection is expected for solar DER over this same 5 year period. SERC Central expects to add approximately 4,000 MW of new generation over the 10-year planning horizon, predominantly with variable energy resources. Additionally, SERC Central is planning to retire approximately 2,250 MW of coal and gas generators. Coal supplies about 1/3 of the capacity in SERC Central in 2020. Natural gas and nuclear provide 39 percent and 17 percent of SERC Central’s capacity, respectively. Hydro and pumped storage provide 7 percent and 4 percent, respectively, for summer peak. Approximately 197 miles of new transmission lines in the SERC Central assessment area are in the design/construction phase, and are projected to enhance system reliability by supporting voltage and relieving challenging flows. Other projects include adding new extra high voltage transformers, reconductoring existing transmission lines, and other system reconfigurations/additions to support transmission system reliability. Entities in SERC Central do not anticipate any transmission limitations/constraints with significant impacts to reliability.

State of Reliability of SERC Central

Anticipated Reserve Margins for the SERC Central subregion are expected to remain above the Reference Reserve Margin for the next 10 years. The SERC Central assessment area is now slightly winter peaking, with a forecast total internal demand of 41,170 MW in 2020. The total internal demand for winter exceeds the total internal demand for summer by 371 MW. The net internal demand for winter is expected to remain relatively flat, increasing by approximately .32 percent over the 10-year planning horizon. As with many of the SERC subregions, Distributed Energy Resources (DERs) are accounted for both in the load forecast behind the meter and through programs that are in front of the meter and evaluated like a resource. Entities continue to work with the local distribution power companies to account for the magnitude and characteristics of the DER. Generally, smaller (< 5 MW) DERs that are behind the wholesale meter are accounted for in the load forecast. Larger (> 5 MW) DERs that are not behind the wholesale meter are modeled explicitly. These would also have the dynamic characteristics included. Currently, there are over 100 projects (and more than 15,000 MW) in the interconnection queue over the next 5 years. Many of these are solar

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Highlights • Gas has continued to overtake Coal as the largest source of electric energy, supplying approximately 31 percent of the capacity in the subregion in 2020. • The solar development project interconnection queue continues to increase significantly across the subregion.

Projected Demands, Resources, and Reserve Margins (Summer)

Demand (MW)

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

Total Internal

43,702

43,624

43,976

44,258

44,544

44,793

45,141

45,458

45,817

46,256

Demand Response

947

955

964

973

976

976

977

978

979

980

Net Internal

42,755

42,669

43,012

43,285

43,568

43,817

44,164

44,480

44,838

45,276

Resources (MW)

Anticipated Prospective

51,822 51,864 21.21% 21.30%

52,459 52,501 22.94% 23.04%

53,042 53,084 23.32% 23.42%

53,141 53,183 22.77% 22.87%

53,177 53,219 22.05% 22.15%

54,819 54,861 25.11% 25.20%

55,281 55,323 25.17% 25.27%

56,366 56,408 26.72% 26.82%

56,935 56,977 26.98% 27.07%

58,645 58,687 29.53% 29.62%

Reserve Margins (%) Anticipated

SERC East The SERC East subregion is a winter peaking system, which consists of the following Planning Coordinators: Cube Hydro Carolinas, Duke Energy Carolinas, Duke Energy Progress, Dominion Energy South Carolina, and South Carolina Public Service Authority.

Prospective

Existing On-Peak Generation (Summer)

Peak Capacity MW %

Generation Type

Biomass

B 164

0.3%

Coal

C 15,416 16,307

29.9% 31.6%

Natural Gas

Hydro

H 3,032

5.9%

Nuclear

N 11,744

22.8%

Other

O 0

0.0% 2.4% 6.0% 1.1% 0.0%

Petroleum

P 1,237 P 3,109

Pumped Storage

Solar Wind

S 546

W 0

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SERC East expects to add approximate 7,500 MW of new generation over the 10-year planning horizon, predominantly Gas fired resources. Additionally, SERC East is planning to retire approximately 2,000 MW of coal, nuclear, oil and gas generators. Distributed Energy Resources to date have not caused a noticeable change to the net internal demand, but the solar development project queue continues to increase significantly across the subregion. Entities continue to monitor DER penetration levels, assess the impacts from DER, and incorporate these impacts in system studies. Unlike directly modeled transmission-connected solar, sub-transmission DERs (i.e., rooftop solar) are netted against load in the energy management system and transmission planning models. Future DER output projections are considered to assess the future operational impacts, as well as the magnitude of projected excess energy issues from increasing DER penetration scenarios. Entities continue to plan for these resources and support deploying increased regulation, balancing reserves, essential reliability services allowances, and solar curtailments in the operations planning and real time operating horizons to mitigate potential operational impacts in the near term.

State of Reliability of SERC East Anticipated Reserve Margins for the SERC East subregion are expected to remain above the Reference Reserve Margin for the next 10 years. The forecast planning reserve margin for 2020 exceeds 21 percent. The Anticipated Reserve Margins continue to grow, reaching a 29.62 percent peak by 2029. Additionally, entities in the SERC East subregion also participate in a reserve sharing agreement among the VACAR companies. The SERC East subregion is winter peaking with a forecast total internal demand for 2020 of 43,702 MW. The total internal demand for winter exceeds the total internal demand for summer by approximately 1800 MW. The net internal demand for winter is expected to increase slightly by approximately 0.63 percent over the 10-year planning horizon. Entities report that the queued amount of Distributed Energy Resources (DERs) connected to the non-BES, sub-transmission system (rooftop solar, plug-in electric vehicles, etc.) is the driver for approximately 10 percent of the utility scale and transmission BES connected projects (~17,000+ MW) in the interconnection queue over the next 5 years. These non-BES connected DERs are not explicitly modeled as generators, but are instead modeled as a reduction in bus load, netting the actual bus load and the on-line DER generation. Entities are trying to put processes in place to use available data to explicitly model the bus load and DER generation independently to better represent these DERs in our planning models.

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Highlights • Based on the forecasted load, firm generation capacity, and firm DSM, the projected subregional reserve margin remains well above 15 percent throughout the 10-year planning horizon. In addition, no adverse impacts to the reserve margins have been identified due to generation retirements. • Significant proposed gas pipeline projects (Sabal Trail Phases II and III) are expected to provide increased gas transportation capacity to peninsular Florida and be fully in-service in 2021. These projects will enhance fuel transportation reliability by increasing supply and delivery diversity for the FL-Peninsula subregion. Projected Demands, Resources, and Reserve Margins (Summer) Demand (MW) 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Total Internal 49,286 49,026 49,778 50,073 50,726 51,107 51,742 52,474 53,175 53,175 Demand Response 2,906 2,951 3,008 3,053 3,099 3,146 3,193 3,238 3,285 3,285 Net Internal 46,380 46,075 46,770 47,020 47,627 47,961 48,549 49,236 49,890 49,890 Resources (MW) Anticipated 56,584 56,350 56,656 58,144 58,257 58,594 60,523 59,864 59,906 59,949 Prospective 57,115 56,881 57,187 58,675 58,788 59,115 61,044 60,384 60,427 60,470 Reserve Margins (%) Anticipated 22.00% 22.30% 21.14% 23.66% 22.32% 22.17% 24.66% 21.59% 20.08% 20.16% Prospective 23.15% 23.45% 22.27% 24.79% 23.43% 23.26% 25.74% 22.64% 21.12% 21.21%

SERC FL-Peninsula The SERC FL-Peninsula subregion is a summer peaking system that consists of the following Planning Coordinators: Duke Energy Florida, Florida Municipal Power Agency, Florida Power & Light Company, Florida Reliability Coordinating Council, Gainesville Regional Utilities, City of Homestead, JEA, Lakeland Electric, Orlando Utilities Commission, Seminole Electric Cooperative, City of Tallahassee, and Tampa Electric Company.

Existing On-Peak Generation (Summer)

Peak Capacity

Generation Type

MW

%

Biomass

117

0.22

Coal

6,743

12.91 73.41

Natural Gas

38,346

Hydro

44

0.08 6.94 0.59 4.67 0.00 1.17 0.00

Nuclear

3,625

Other

308

Petroleum

2,438

Pumped Storage

0

Solar Wind

611

0

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load-modifier, and is projected to be constant at approximately 6.3 percent of the summer and winter total peak demands for all years of the assessment period. SERC FL-Peninsula expects to add approximately 9,000 MW of new generation over the 10-year planning horizon, predominantly natural gas, variable energy resources, and battery storage. Additionally, SERC FL-Peninsula is planning to retire approximately 4,798 MW of coal and gas generators. Natural gas supplies about 2/3 of the capacity in the SERC FL-Peninsula in 2020. Coal and nuclear provide 11 percent and 6 percent of SERC FL-Peninsula capacity, respectively. Petroleum and solar each provide 3 percent for summer peak. Approximately 111 miles of new transmission lines in the SERC FL- Peninsula are in the design/construction phase and are projected to enhance system reliability, interconnect new generators, and meet the growing load demand. Other projects include reconductoring existing transmission lines and other system reconfigurations/additions to support transmission system reliability. The coordinated reliability studies performed by the SERC FL- Peninsula entities through the FRCC have shown that the performance of the transmission system within the FL-Peninsula subregion is reliable, adequate, and secure for the near-term and long-term planning horizon.

State of Reliability of SERC Florida Peninsula Anticipated Reserve Margins for the SERC Florida Peninsula (FL- Peninsula) are expected to remain above 20 percent for the 10-year planning horizon. The SERC FL-Peninsula is summer peaking, with a forecast total internal demand of 49,286 MW in 2020. The total internal demand forecast for winter 2020/2021 is 44,625 MW. The SERC FL- Peninsula’s net internal demand is the fastest growing of all subregions within SERC, increasing by approximately 1 percent over the 10-year planning horizon. Entities within the SERC FL-Peninsula subregion model Distributed Energy Resources (DERs) with their associated loads and netted out since the load forecasts of entities within the SERC FL-Peninsula subregion account for these loads implicitly. Currently, the SERC FL-Peninsula subregion has low penetration levels of DERs; however, penetration levels are expected to grow throughout the planning horizon. The SERC FL-Peninsula entities work through the FRCC standing committees and subcommittees to monitor jointly the projected growth within the subregion. Currently the SERC FL-Peninsula subregion has a large number of solar projects requested in the interconnected queue over the next 5 years that are being studied collaboratively between the Florida entities and the Florida Reliability Coordinating Council. Controllable Demand Response from interruptible and dispatchable load management programs within the FL-Peninsula is treated as a

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Highlights • Anticipated resources are considerably lower than past assessments and are decreasing through the ten-year planning horizon. • Approximately 950 miles of new transmission lines will be constructed through the 10-year planning horizon. These transmission conditions will provide additional capacity and enhance local area voltage support.

Projected Demands, Resources, and Reserve Margins (Summer)

Demand (MW)

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

Total Internal

18,792

18,750

19,001

18,994

19,029

19,038

19,056

19,089

19,131

19,075

Demand Response

1,026

1,022

1,022

1,022

1,022

1,022

1,022

1,022

1,022

1,022

Net Internal

17,766

17,728

17,979

17,972

18,007

18,016

18,034

18,067

18,109

18,053

Resources (MW)

Anticipated Prospective

19,454 20,689

19,897 20,689

19,897 20,689

19,201 19,993

19,201 19,993

19,201 19,993

19,201 19,993

19,201 19,993

19,201 19,993

19,822 19,993

SERC MISO-Central The SERC MISO-Central subregion is a summer peaking system that consists of the following Planning Coordinators: Midcontinent Independent System Operator, Inc.

Reserve Margins (%) Anticipated

9.50%

12.23% 16.70%

10.67% 15.07%

6.84%

6.63%

6.58%

6.47%

6.28%

6.03%

9.80%

Prospective

16.45%

11.25%

11.03%

10.97%

10.86%

10.66%

10.40%

10.75%

Existing On-Peak Generation (Summer) Generation Type Peak Capacity MW % Biomass 3 0.02 Coal 11,11 55.81 Gas 5,307 26.64 Hydro 363 1.82 Nuclear 2,255 11.32 Other 0 0.00 Petroleum 266 1.33 Pumped Storage 440 2.21 Solar 0 0.00 Wind 169 0.85

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To address the potential generation deficit, MISO is currently evaluating 42.8 GW of generation active in the MISO-Central generation queue. Additional transmission projects will be necessary to allow interconnection to the BES, to relieve constraints and increase transfer capability between MISO-Central and MISO-South. The SERC MISO-Central assessment area is summer peaking, with a forecast total internal demand of 18,792 MW in 2020. The total internal demand for summer exceeds the total internal demand for winter by approximately 3,000 MW. The net internal demand for summer is expected to remain relatively flat, increasing by approximately .18 percent over the 10-year planning horizon. Reported demand-side management response in the SERC MISO- Central subregion exceeds 1,000 MW, or 5.4 percent of the Total Internal Demand for 2020. This level of demand response is expected to continue through the forecast period. At this time, no significant photovoltaic (PV) developments have been connected to either the transmission or distribution systems in the SERC MISO-Central subregion. Connections of large Distributed Energy Resources (DERs) in the subregion have been limited to wind farms. Interest in DERs is continuing but to date, DERs have not caused a substantial change to the net internal demand in the subregion. Both transmission and distribution planning engineers in many areas of the subregion are experiencing increased interest from customers regarding possible connection of PV and inverter-based resources. SERC MISO-Central does not expect to add any new baseline generation over the 10-year planning horizon. Additionally, SERC MISO-Central is planning to retire approximately 700 MW of coal and gas generators. Coal supplies about 1/2 of the capacity in SERC MISO- Central in 2020. Natural gas and nuclear provide 27 percent and 11 percent of SERC MISO-Central’s capacity, respectively. Hydro and pumped storage provide an additional 2 percent and 2.2 percent, respectively, for summer peak. Approximately 950 miles of new transmission lines in the SERC MISO-Central assessment area are in the design/construction phase. These lines are projected to enhance system reliability and to provide additional capacity and enhance local area voltages. Of the 950 miles of new transmission lines, the vast majority (822 miles) will be

State of Reliability of SERC MISO-Central MISO is one Balancing Authority (BA); however, to better evaluate the reliability, SERC breaks the MISO footprint into MISO-Central and MISO-South. Considering anticipated generation resources strictly within the SERC MISO-Central subregion, the forecasted planning Anticipated Reserve Margin is below the reserve margin benchmark of 15 percent. The Anticipated Reserve Margin is considerably lower than reported in last year’s annual assessment. The forecasted reserve margins are expected to decline further starting in 2023. However, resources would exceed net internal demand by at least 15.07 percent through 2022 considering prospective generation retirements and additions. The SERC MISO-Central subregion also has access to additional firm deliverable resources within the MISO footprint up to the Regional Directional Transfer Limit of 1,000 MW.

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constructed in the first 5 years of the planning horizon. Other projects include adding new extra high voltage transformers, reconductoring existing transmission lines, and other system reconfigurations/additions to support transmission system reliability.

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Highlights • The SERC MISO-South subregion contains a mix of traditional generation resources with gas- fired generation as the predominant type. The Anticipated Reserve Margin is well above the reference margin for the first five years. • The SERC MISO-South subregion continues to focus on transmission investments in the near- term to address both reliability and potential market congestion.

Projected Demands, Resources, and Reserve Margins (Summer)

Demand (MW)

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

Total Internal

33,582 1,081 32,501 41,703 43,517 28.31% 33.90%

33,950 1,076 32,874 43,167 44,981 31.31% 36.83%

34,338 1,075 33,263 42,958 44,772 29.15% 34.60%

34,540 1,075 33,465 42,438 44,252 26.81% 32.23%

34,813 1,075 33,738 42,438 44,252 25.79% 31.16%

35,064 1,075 33,989 41,916 43,730 23.32% 28.66%

35,211 1,075 34,136 40,562 42,376 18.82% 24.14%

35,356 1,076 34,280 40,562 42,376 18.32% 23.62%

35,511 1,075 34,436 40,562 42,376 17.79% 23.06%

35,684 1,075 34,609 38,928 40,742 12.48% 17.72%

Demand Response

Net Internal

Resources (MW) Anticipated

SERC MISO-South The SERC MISO-South subregion is a summer peaking system that consists of the following Planning Coordinators: Midcontinent Independent System Operator, Inc.

Prospective

Reserve Margins (%) Anticipated

Prospective

Existing On-Peak Generation (Summer)

Peak Season Capacity MW Percent

Generation Type

Biomass

94

0.23

Coal

7,170

17.43 66.00

Natural Gas

27,145

Hydro

385

0.94

Nuclear

5,197

12.64

Other

47

0.11 2.64 0.00 0.00 0.00

Petroleum

1,088

Pumped Storage

0 1 0

Solar Wind

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State of Reliability of SERC MISO-South Anticipated Reserve Margins within the SERC MISO-South subregion indicate an increasing trend in the first two years, from 28.31 percent to 31.31 percent by 2021. This reflects a net increase in new resources along the coastal areas of SERC MISO-South. After 2021, the forecasted reserve margins are projected to decline to 12.48 percent, below the Reference Reserve Margin of 15 percent. When considering prospective resources in the region, the Reserve Margin follows the same trend, but indicates resource adequacy over the planning horizon. The SERC MISO-South subregion also has access to all of the deliverable resources within the MISO footprint per the Settlement agreement between MISO and the Joint parties. The SERC MISO-South assessment area is summer peaking, with a forecast total internal demand of 33,582 MW in 2020. The total internal demand for summer exceeds the total internal demand for winter by approximately 3,450 MW. The net internal demand for summer is expected to increase by approximately .70 percent over the 10-year planning horizon. Reported demand-side management response in the SERC MISO-South subregion is approximately 1,100 MW, or 3.3 percent of the Total Internal Demand for 2020. This level of demand response is expected to remain steady through the forecast period. As in SERC MISO-Central, few significant photovoltaic (PV) developments have been connected to either the transmission or distribution systems in the SERC MISO-South subregion. Interest in developing solar resources in the subregion is increasing and beginning to emerge from the MISO Definitive Planning Phase (DPP) processes, but has not caused a noticeable change to the net internal demand or anticipated capacity additions in the subregion so far. Both transmission and distribution planning engineers in the subregion are preparing for increased PV and inverter-based resource development. SERC MISO-South expects to add approximate 2,500 MW of new generation over the 10-year planning horizon, predominantly gas generation. Additionally, SERC MISO-South is planning on approximately 4,300 MW of future derates/deactivations of coal and gas generators. Natural gas supplies about 2/3 of the capacity in SERC MISO-South in 2020. Coal and nuclear provide 18 percent and 13 percent of SERC MISO-South’s capacity, respectively. While hydro, pumped storage,

biomass, and variable energy sources contribute approximately 1 percent for summer peak. Approximately 525 miles of new transmission lines in the SERC MISO-South assessment area are in the design/construction phase, and are projected to enhance system reliability. Of the 525 miles of new transmission lines, the majority (466 miles) will be constructed in the first 5 years of the planning horizon. The SERC MISO-South subregion continues to make the necessary investments in transmission to ensure that reliability needs are met over the 10-year horizon.

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Highlights • Anticipated Reserve Margins do not fall below the Reference Margin Level for any year of the assessment period in SERC PJM. • Reduced load growth, energy efficiency, generation shifts, and aging infrastructure drivers, among others, continue to shift transmission need away from large-scale, cross-system backbone projects toward projects focusing on transmission owner criteria. Projected Demands, Resources, and Reserve Margins (Summer) Demand (MW) 1 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Total Internal 21,817 22,163 22,572 22,914 23,322 23,570 23,770 23,978 24,218 24,438 Demand Response 919 933 951 965 982 993 1,002 1,011 1,021 1,030 Net Internal 20,898 21,230 21,621 21,949 22,340 22,577 22,768 22,967 23,197 23,408 Resources (MW) Anticipated 31,654 31,565 31,456 31,736 31,736 31,736 31,736 31,736 31,736 31,736 Prospective 32,046 34,135 36,972 42,544 44,243 44,970 45,397 45,664 45,827 45,827 Reserve Margins (%) 2 Anticipated 51.47% 48.68% 45.49% 44.59% 42.06% 40.57% 39.39% 38.18% 36.81% 35.58% Prospective 53.34% 60.79% 71.00% 93.83% 98.04% 99.19% 99.39% 98.83% 97.56% 95.78% 1 Demand and resource reflected in this table are for PJM member companies located within SERC. 2 Reserve Margins in PJM are calculated for the entire PJM footprint since power flows around PJM without regard to Regional boundaries. No specific reserve margin requirement exists in the regional portions of PJM.

SERC PJM The SERC PJM subregion is a winter peaking system that consists of the following Planning Coordinators: PJM Interconnection, LLC. Natural gas-fired generation capacity now exceeds coal, and natural gas plants totaling over 50 GW comprise 80 percent of the generation capacity interconnection rights in PJM’s new services queue.

Existing On-Peak Generation (Summer) Generation Type Peak Capacity MW % Biomass 320 0.99 Coal 6,281 19.46 Gas 14,201 44.00 Hydro 766 2.37 Nuclear 3,576 11.08 Other 0 0 Petroleum 1,848 5.73 Pumped Storage 3,015 9.34 Solar 2,195 6.80 Wind W 75 0.23

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• New generating plants powered by Marcellus and Utica shale natural gas • New wind and solar units driven by federal and state renewable incentives • Generating plant deactivations • Market impacts introduced by demand resources and energy efficiency programs PJM expects to add approximate 1,370 MW of new generation over the 10-year planning horizon, predominantly variable energy resources. Additionally, PJM is planning to retire approximately 770 MW of coal- fired generators. Gas-fired generation supplies about 44 percent of the capacity in PJM in 2020. Coal and nuclear provide 20 percent and 11 percent of PJM capacity, respectively. Hydro and pumped storage provide 3 percent and 10 percent, respectively, for summer peak. Solar is beginning to become an increase capacity source for PJM at approximately 7 percent. Reduced load growth, energy efficiency, generation shifts, and aging infrastructure drivers, among others, continue to shift transmission need away from large-scale, cross-system backbone projects toward projects focusing on transmission owner criteria. Approximately 187 miles of new transmission lines in the SERC PJM assessment area are in the design/construction phase, and are projected to enhance system reliability, economics or congestion and VER integration.

State of Reliability of SERC PJM The Anticipated Reserve Margins do not fall below the Reference Margin Level for any year of the assessment period in the SERC PJM subregion. The reserve margin values shown are for the entire PJM area, not just the area of PJM that is within the SERC footprint. The SERC PJM assessment area is slightly winter peaking, with a forecast total internal demand of 20,898 MW in 2020. The total internal demand for winter exceeds the total internal demand for summer by 1,690 MW. The net internal demand for winter is expected to increase by approximately 1.27 percent over the 10-year planning horizon, making SERC PJM the highest growing subregion within SERC. SERC PJM differs from other subregions in SERC in that Demand Response resources can participate in all PJM Markets—Capacity, Energy, and Ancillary Services. PJM requires that PJM member Third Party Suppliers (Curtailment Service Providers - CSPs) bring these resources to PJM Markets; it is the responsibility of these CSPs to act as Market Operating Centers, relaying PJM instructions for load reductions (in any of the markets) to these resources. As with many of the SERC subregions, Distributed Energy Resources (DERs) are accounted for in the load forecast. For the purposes of the long-term load forecast, PJM defines distributed solar generation as any solar resource that is not interconnected to the PJM markets. These resources do not go through the full interconnection queue process and do not offer as capacity or as energy resources. Furthermore, the output of these resources is netted directly with the load. PJM does not receive metered production data from any of these resources. There have been no current or anticipated operational impacts of DERs noted in PJM. PJM’s Regional Transmission Expansion Process (RTEP) continues to manage an unprecedented capacity shift driven by federal and state public policy and broader fuel economics:

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Highlights • Progress continues on Georgia Power’s Vogtle nuclear expansion project (~2,200 MW), which will be the first nuclear units in the United States to use the Westinghouse AP1000 advanced pressurized water reactor technology. The current in-service date is early 2021. • Entities in SERC SE do not anticipate any transmission limitations/constraints with significant impacts to reliability or generation shortfalls throughout the planning horizon. Projected Demands, Resources, and Reserve Margins (Summer) Demand (MW) 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Total Internal 47,311 47,748 47,882 48,057 48,289 48,450 47,923 48,208 46,970 47,342 Demand Response 2,145 2,354 2,565 2,557 2,542 2,556 2,555 2,562 2,568 2,576 Net Internal 45,166 45,394 45,317 45,500 45,747 45,894 45,368 45,646 44,402 44,766 Resources (MW) Anticipated 60,626 60,900 62,470 63,488 64,674 64,685 64,747 64,749 64,752 64,754 Prospective 60,915 61,739 64,233 65,331 66,597 66,608 66,670 66,672 66,675 66,677 Reserve Margins (%) Anticipated 34.23% 34.16% 37.85% 39.53% 41.37% 40.94% 42.71% 41.85% 45.83% 44.65% Prospective 34.87% 36.01% 41.74% 43.58% 45.58% 45.13% 46.95% 46.06% 50.16% 48.95%

SERC Southeast The SERC Southeast (SERC SE) subregion is a summer peaking system that consists of the following Planning Coordinators: Georgia Transmission Corporation, Municipal Electric Authority of Georgia, PowerSouth Energy Cooperative, and Southern Company.

Existing On-Peak Generation (Summer) Generation Type Peak Capacity MW Percent Biomass B 361 0.6% Coal C 16,935 27.5% Gas N 30,240 49.1% Hydro H 3,288 5.3% Nuclear N 5,818 9.5% Other O 315 0.5% Petroleum P 961 1.6% Pumped Storage P 1,632 2.7% Solar S 2,003 3.3% Wind W 0 0.0%

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