2019 RRS Annual Report

2019 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.................................................................................................................... 17 SERC FL-Peninsula ...................................................................................................... 21 SERC MISO-Central ..................................................................................................... 25 SERC MISO-South ....................................................................................................... 28 SERC PJM.................................................................................................................... 31 SERC Southeast........................................................................................................... 34

Data Concepts and Assumptions ........................................................................... 37

Special Topics .................................................................................................... 41

Working Group Contributions ........................................................................................ 42 Long/Near-Term Transmission Summary...................................................................... 44 Seasonal Outlook.......................................................................................................... 45

Appendix A Glossary .......................................................................................... 46

Appendix B SERC Membership ............................................................................ 47

Appendix C SERC EC Reliability Review Subcommittee Membership ........................ 49

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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. On April 30, 2019, the Federal Energy Regulatory Commission issued an order formally approving the transfer of all registered entities in the Florida Reliability Coordinating Council (FRCC) Region to SERC by July 1, 2019. The integration of FRCC entities resulted in an additional SERC subregion and SERC Assessment Area for inclusion in NERC’s Reliability Assessments. The map showing the resulting SERC subregions is included in Figure 2.

Figure 1: 2018 Subregions

Figure 2: New 2019 Subregional Map with FL-Peninsula

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About This Assessment

This 2019 Reliability Review Subcommittee Annual Assessment (2019 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 2019 RRS Annual Report are not predictions of what will happen; they are based on information supplied by Registered Entities in February 2019 and updates incorporated prior to publication. The assessment period for the 2019 RRS Annual Report is from 2020 to 2029; however, some figures and tables examine data and information for year 2019. 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

 Approximately 4 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 PV projects totaling ~18.5 GW of nameplate capacity (~ 3.6 GW Tier 1, 5 GW Tier 2, and 9.9 GW Tier 3 ) are reported by Generator Owners over the next five years. 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.  As of July 1, 2019, there are 117,446 miles of transmission lines at 100 kV and above in the SERC Region.  Entities within the SERC Region anticipate adding approximately 2,000 miles of transmission during the ten-year reporting period.

Expected demand projections for the SERC Region are almost flat.

 The SERC Region’s 2020-2029 Compound Annual Growth Rate (CAGR) is 0.54%.  On the high end, FL-Peninsula subregion has a 1.08% CAGR.  On the low end, MISO-Central subregion has a -0.43% CAGR. Five of the seven SERC subregions expect the Anticipated Reserve Margins to be above 20% for the ten-year period.  Two of the seven subregions expect to maintain a ten-year reserve margin in the 18 – 30% range.  Three of the seven subregions expect to maintain a ten-year reserve margin in the 20-30% range. All subregions maintain ten-year reserve margins above SERC’s calculated Reference Reserve Margin, using the metric of 0.1 days per year loss of load expectation (LOLE), of 14.4%. Only slight changes in the Regional resource mix are projected for the ten-year planning horizon, with no significant change reported from 2018 to 2019. 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 5 GW of natural gas resources, 4 GW of utility scale solar (photovoltaic) resources, and 2 GW of nuclear resources are expected by 2024.

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Detailed Review of 2019 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). NERC does not require a certain level of planning reserves; instead, SERC—through the Resource Adequacy Working Group (RAWG)—conducts a loss of load expectation study to determine Planning Reserve Margins (PRM), or Reference Margin Levels. The SERC 2018 Probabilistic Assessment PRM analysis determined PRMs for each area with no transmission tie benefits (islanded) and a SERC-wide PRM that allowed for interconnection (tie benefits) for the study years of 2020 and 2022. Areas adopt the lesser of the two PRMs, and consequently, they all adopted the SERC-wide PRM of 13.15% and 14.41% for 2020 and 2022 respectively, which are below the NERC Reference Margin Level of 15%. For this assessment, interpolation determined the 2021 Reference Margin Level while other years equal to the 2020 or 2022 results. All margins are above the Reference Level over the next ten years. In addition to PRM analysis, the 2018 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 zero or near zero 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. The published SERC 2018 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

FL-Peninsula 1

Reference Margin Level

15.00

15.00 15.00 15.00 15.00 15.00 15.00 15.00 15.00 15.00

25.30%

24.31% 24.93% 26.18% 25.27% 24.72% 26.78% 24.58% 23.32% 23.39%

Anticipated Reserve Margin

All (Less FL-Peninsula) Reference Margin Level

13.15

13.15 13.78 14.41 14.41 14.41 14.41 14.41 14.41 14.41

31.56%

28.97% 27.78% 27.25% 24.73% 24.45% 24.69% 23.85% 23.40% 22.88%

Central

Anticipated Reserve Margin

21.28%

21.98% 22.75% 22.26% 21.58% 24.31% 23.23% 24.53% 23.44% 25.94%

East

Anticipated Reserve Margin

21.28%

22.21% 22.97% 19.68% 20.65% 21.06% 21.53% 22.01% 22.44% 22.44%

MISO-Central

Anticipated Reserve Margin

26.79%

29.47% 28.17% 26.13% 25.66% 23.58% 19.10% 18.60% 18.07% 18.07%

MISO-South

Anticipated Reserve Margin

SERC-PJM 2

57.03%

52.19% 50.43% 48.61% 47.40% 46.41% 45.89% 45.16% 44.00% 42.89%

Anticipated Reserve Margin

34.33%

33.87% 35.49% 37.26% 36.51% 35.81% 37.13% 39.90% 39.48% 38.03%

Southeast

Anticipated Reserve Margin

1 As filed for the NERC 2019 Long-term Reliability Assessment. The SERC 2018 Probabilistic Assessment did not include FL-Peninsula. 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.

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Capacity Resource Trends

Capacity resources in the SERC Region for 2019 total 310,881 MW. Net capacity resources in the Region are expected to increase for the first five years of the 2020-2029 planning horizon to 319,046 MW. Net capacity resources are projected to gradually increase over the planning horizon with natural gas-fired capacity additions being largely offset by coal-fired capacity retirements. Capacity resources in the SERC Region in 2029 are projected to total 322,901 MW. Primarily due to the integration of FRCC into the SERC Region, the SERC 2019 resource mix changed slightly from 2018, with an approximate 4 percentage point increase in natural gas resources and an approximate 3 percentage point decrease in coal resources. These slight trends in the Regional resource mix are projected for the ten-year planning horizon. Natural gas is the primary fuel source in the SERC Region, followed by coal, nuclear, and other types (which include pumped storage, oil-fired, solar, biomass, wind, and other). For the period 2020- 2029, natural gas-fired capacity is projected to increase from 47.4% to 48.7%. Through the same period, coal- fired capacity is projected to decrease from 26.5% to 23.7%. SERC members have announced approximately 4,000 MW of large-scale coal-fired capacity

retirements through the near-term planning horizon. Nuclear powered resources supply 13.1% of the SERC capacity in 2019. This share is projected to remain constant throughout the assessment period despite two 1,100 MW nuclear plant additions in 2022 and 2023. Existing solar (photo-voltaic) capacity resources in the SERC Region are reported at 4,000 MW, but planned solar additions of 4,500 MW are projected through 2024. With these additions, combined-type capacity resources would supply 10.7% of the SERC total by 2029, up from 9.4% in 2019. Hydro capacity resources are projected to remain essentially unchanged through the forecast period at approximately 3.6% of the Regional total. Biomass, wind, and other resources in the Region are small and do not contribute significantly to the SERC capacity totals or resource mix.

Figure 3: 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 ten-year compound annual growth rates to well below 1%. Some subregions report negative growth rates for the 10-year assessment period. With the exception of 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 0.9%, while coal drops about 2.0% 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, but remains very small compared to conventional generation. Solar installations, without energy storage, may not be able to cover the afternoon peak, making these plants less useful than conventional generation for reliability.

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

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 if 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, and may require further analysis to determine if fuel controls are required.

SERC East, SERC MISO-South

Natural Gas

All SERC subregions

Conventional Generation

Because of low penetration forecast of solar, no reliability concern exists.

SERC-E, SERC-SE, and SERC-PJM

Solar PV

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Demand Projections

The 2020-2029 demand forecast shows a 0.54% compound annual growth rate (CAGR), which is relatively flat compared to last year's ten-year growth rate of 0.77%. 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. The delta between the summer and winter season doubled from approximately 5 GW to 10 GW from last year’s projections with the addition of the summer peaking FL-Peninsula subregion.

Figure 4: Compound Annual Growth Rate

Figure 5: SERC Region Total Internal Demand (MW)

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Transmission Additions

As of July 1, 2019, there are approximately 117,500 miles of transmission lines operated at 100 kV and above in the SERC Region. Entities within the SERC Region anticipate adding approximately 2,000 miles during the ten-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 6: Bulk Electric System Transmission Mileage by Operating Voltage Class

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In addition to transmission lines, several new transformers are due to come into service during the next ten-years within the SERC Region. Of the 101 transformer projects, 92 have high-side voltages of 200 kV and above.

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 8: 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 7: 10-Year AC Circuit Project

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Subregional Dashboards/Summaries

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Highlights

 Anticipated Reserve Margins for SERC Central are expected to be above 20% for the next ten- years.

 Load growth is expected to be minimal across the subregion.

 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

40,761

41,104

41,380

41,533

41,609

41,690

41,636

41,761

41,903

42,072

Demand Response

2,076

2,054

1,979

1,927

1,894

1,888

1,885

1,882

1,879

1,877

Net Internal

38,685

39,050

39,401

39,606

39,715

39,802

39,751

39,879

40,024

40,195

Resources (MW)

Anticipated Prospective

50,893 54,593

50,362 54,017

50,345 54,406

50,400 54,460

49,535 53,590

49,535 53,590

49,565 53,620

49,390 53,445

49,390 53,445

49,390 53,445

Reserve Margins (%)

Anticipated Prospective

31.56% 41.12%

28.97% 38.33%

27.78% 38.08%

27.25% 37.51%

24.73% 34.94%

24.45% 34.64%

24.69% 34.89%

23.85% 34.02%

23.40% 33.53%

22.88% 32.97%

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)

Peak Capacity MW %

Generation Type

Biomass

0

0.00

Coal

16,793

33.25

Electric/Kentucky Utilities, and Tennessee Valley Authority.

Natural Gas

19,723

39.05

Hydro

3,478

6.89

Nuclear

8,422

16.68

Other

0

0.00

Petroleum

0

0.00

Pumped Storage Solar

1,748

3.46

8

0.02

Wind

334

0.66

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Distributed Energy Resources (DERs)

Planning Reserve Margins

For the majority of the SERC Central assessment area, larger wind plants (1,200 MW) and solar farms (400 MW) are monitored via Supervisory Control and Data Acquisition (SCADA) Energy Management Systems (EMS). The wind power is transported almost entirely into SERC Central via Pseudo Ties. Impacts from ramping and light load conditions are adjusted for by including forecasted Distributed Energy Resource (DER) output in unit commitment and scheduling models. Entities in SERC Central have not experienced any ramping or significant light loading issues from DERs. 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 50 projects (more than 6,000 MW) in the interconnection queue over the next five years. Many of these are solar projects that have potential to connect to the Bulk Electric System (BES). Generation With the exception of two confirmed resource retirements, one in the 2020-21 timeframe and another in the 2023-24 timeframe, anticipated generation resources in the SERC Central assessment area are reported to stay constant over the ten year planning horizon starting in 2020. Coal supplies about one third of the capacity in SERC Central in 2019, and its share is reported to decrease slightly during the next ten years. Natural gas and nuclear provide 39% and 17% of SERC Central’s capacity, respectively. Hydro and pumped storage provide 7% and 4%, respectively, for summer peak. Capacity Transfers The SERC Central assessment area expects firm imports of around 2,500 MW and firm exports of around 2,100 MW starting in 2020 through the ten year planning horizon.

Anticipated Reserve Margins for the SERC Central assessment area are expected to be above 20% for the next ten years. Entities in SERC Central use resource adequacy assessment tools (e.g., Strategic Energy Risk Valuation Model Monte Carlo simulations) to evaluate reserve margins. The assessment takes into account the impact of historical weather years, load uncertainty due to economic growth uncertainty, uncertainty due to generator forced outage rates, and other uncertainties. Some entities in SERC Central perform a second assessment that accounts for system costs, including customer outage costs that might happen under a combination of several uncertainties. The entities compare the normal reserve margin to this system costs calculation and its resulting reserve margin to compare risk neutral versus risk adjusted reserve margins to better reflect anticipated increases in intermittent resources and establish distinct summer and winter targets. Demand The SERC Central assessment area is now slightly winter peaking, with a forecast total internal demand of 41,076 MW in 2020. The total internal demand for winter exceeds the total internal demand for summer by 315 MW. The net internal demand for winter is expected to increase by approximately 1,700 MW over the ten year planning horizon. Demand-Side Management Entities in the SERC Central assessment area use flexible, responsive programs and resources to meet the demand. These programs include interruptible products, voltage optimization, and aggregated demand response, and can be dispatched up to 100 hours annually. Most are turnkey demand response programs that deliver economic load reduction by utilizing third party implementers. Entities in SERC Central do not expect a significant change to the programs and response through the forecasted period.

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Entities in SERC Central do not anticipate any transmission limitations/constraints with significant impacts to reliability. Limitations exist near multiple generation sites in SERC Central and along the seams due to line loading and transfers on the transmission system. Entities plan to mitigate all of the known transmission limitations/constraints through future transmission projects (new builds, reactors, etc.), generation adjustments, system reconfiguration, or system purchases.

Transmission

Approximately 163 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. A planned 500 kV substation will support system reliability for a confirmed resource retirement. In addition, a new Static VAR Compensator (SVC) is being planned for an existing 500 kV substation to support the stability of local generating units.

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Highlights

 Gas has overtaken Coal as the largest source of electric energy, supplying approximately 31% of the capacity in the subregion in 2019.

 The solar development project queue continues to increase significantly across the subregion.

 South Carolina Electric and Gas (SCE&G) was acquired recently by Dominion Energy and has changed its name to Dominion Energy South Carolina (DESC).

Projected Demands, Resources, and Reserve Margins (Summer)

Demand (MW)

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

Total Internal

43,852

43,991

44,205

44,460

44,733

45,063

45,478

45,838

46,318

46,771

Demand Response

1,068

1,071

1,075

1,075

1,075

1,076

1,077

1,078

1,080

1,081

Net Internal

42,784

42,920

43,130

43,385

43,658

43,987

44,401

44,760

45,238

45,690

Resources (MW)

Anticipated Prospective

51,887 51,929

52,353 52,395

52,942 52,984

53,041 53,083

53,081 53,123

54,680 54,722

54,716 54,758

55,738 55,780

55,840 55,882

57,544 57,586

Reserve Margins (%) Anticipated

21.28% 21.38%

21.98% 22.08%

22.75% 22.85%

22.26% 22.35%

21.58% 21.68%

24.31% 24.41%

23.23% 23.33%

24.53% 24.62%

23.44% 23.53%

25.94% 26.04%

SERC East

Prospective

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.

Existing On-Peak Generation (Summer)

Peak Capacity MW %

Generation Type

Biomass

B 164

0.32

i o m a o a l 15,794 15,959 H y d r o 3,044 N u c l 11,726 O 0 P 1,469 3,044 s s C P

Coal

30.56

Natural Gas

30.88

Hydro

5.89

Nuclear

22.69

Other

0.00

e a r t h e r e t r o l u m p e d S t o r o l a r 489 W i n d 0 e u m S

Petroleum

2.84

Pumped Storage

5.89

Solar

0.95

Wind

0.00

a g e

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Entities in SERC East expect normal demand growth to continue in the region. Statistical and economic models are used to develop peak demand forecasts based upon past load patterns and profiles. These models also take into consideration naturally occurring efficiency trends. Most of the distributed energy resource (DER) growth in the region has been solar, which has little to no projected impact on winter peak demand reduction, and only a small impact on summer peak demand. SERC East members will continue collecting data on the impact of solar DERs in the region, and will incorporate the results into the models. This methodology has not changed since the 2018 LTRA. Demand-Side Management Energy Efficiency and Conservation Programs are used for planning purposes and as a mechanism to reduce the peak load forecast. Some entities report using these programs in their Integrated Resource Plans to efficiently and cost effectively alter customer demands and reduce the long run supply costs for energy and peak demand. These programs can vary greatly in their dispatch characteristics, size, and duration of load response, certainty of load response, and level and frequency of customer participation. In general, entities offer the programs in two primary categories: Energy Efficiency (EE) programs that reduce energy consumption, and Demand Side Management (DSM) programs that reduce peak demand (demand side management or demand response programs and certain rate structure programs). Distributed Energy Resources (DERs) 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.

Planning Reserve Margins

Considering anticipated generation resources strictly within the SERC East subregion, the forecast planning reserve margin for 2020 exceeds 21%. The anticipated reserve margins continue to exceed 21.28%, reaching a 24.53% peak in 2027 and dropping to 23.44% in 2028 at the end of the forecast period. Considering prospective generation retirements and additions, prospective reserve margins are slightly higher, reaching a 24.62% peak in 2027 and dropping to 23.53% in 2028 at the end of the forecast period. Entities in the SERC East subregion also participate in a reserve sharing agreement among the VACAR companies. Reserve margin is defined as total resources minus peak demand, divided by peak demand. For peak seasons, resource adequacy studies are simulated regularly to determine the reserve margin required to satisfy the one day in ten years LOLE standard. Thus, summer and winter peak seasons included in the analysis incorporate the uncertainty of weather, economic load growth, unit availability, and the availability of transmission and generation capacity for emergency assistance. The calculations do not include uncommitted generation and non-firm resources. Demand-side management resources are modeled according to contract limits, and behind-the-meter generation is subtracted from the load. There are no changes from the 2018 LTRA. No parts of SERC East have Reserve Margin mandates (excluding North Carolina entities that are PJM members). Each utility determines its Reserve Margin and presents it in its Integrated Resource Plan (IRP). The North Carolina Utility Commission and the South Carolina Public Service Commission will either agree or disagree with the entities’ Reserve Margin percentages as part of the IRP proceeding. Demand The SERC East subregion is winter peaking with a forecast total internal demand for 2020 of 44,153 MW. The total internal demand for winter exceeds the total internal demand for summer by approximately 1300 MW or 3.0%. Both total and net internal demand within the SERC East subregion for winter are expected to increase by 6.6% over the 10-year planning horizon. 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.

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Entities report that the queued amount of DERs connected to the non- BES, sub-transmission system (rooftop solar, plug-in electric vehicles, etc.) is approximately 10% of the utility scale and transmission BES connected projects (~17,000+ MW) in the interconnection queue over the next five 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. Generation Anticipated generation resources in the SERC East subregion are reported to increase slightly by 10,100 MW (18.0%) over the 10-year planning horizon. No significant generation retirements in the subregion have been announced through 2028. Approximately 1500 MW of coal- fired generation and 464 MW of natural gas/oil-fired generation are slated for retirement by 2028. Gas supplies approximately 31% of the capacity in the subregion in 2019 and is the largest source of electric energy just ahead of coal. Natural gas and nuclear generation provide 31% and 23% of the subregion's capacity, respectively. Renewable resources (hydro, pumped storage, biomass, solar, and wind) provide approximately 13% of the capacity at the time of summer peak. Entities regularly analyze the existing and future demand and energy needs of their customers in order to ensure they have a plan that will serve customers in an economical and reliable manner. A mix of utility purchases of IPP generation facilities, adding new combined cycle/combustion turbine plants, energy storage, and short-term market purchases are utilized over the period available to meet demand. Planning assumptions for renewable resources assume that all NC Renewable Energy and Energy Efficiency Portfolio Standard (REPS) requirements and SC DERs goals are met fully, as well as additional solar resources procured in response to the newly signed NC House Bill, HB 589. The IRP assumes a robust mix of resources to meet customer demand. These resources include renewable energy, combustion turbines, combined cycle units, and nuclear units, as well as projected increases in both Energy Efficiency (EE) and Demand Response (DR). From a planning perspective, the move to winter planning and planning

reserve margin addresses the potential operational impacts of the changing resource mix. Additionally, the Capacity Value of Solar study allows the companies to apply the appropriate value of solar in the generation planning process as additional large amounts of solar are added to the systems. Various sensitivity studies using engineering judgment are performed to further investigate any potential impact of having changes in our available generation resource mix. Solar contribution to peak is defined as the hours between 2:00 p.m. and 7:00 p.m. in summer months of June-August and the hours between 7:00 a.m. and 8:00 a.m. in the winter months of December-February. For most entities, transmission-connected solar facilities’ output is set at 35-80% (of contractual committed MW) in summer and 0% in winter. These percentages are determined through a review of historical MW output during the peak hours. Run of river hydro MW output is determined by historical seasonal averages. Entities do not anticipate any specific environmental or regulatory restrictions or retrofits that may affect resource availability. Entities continue to manage lake levels, to the extent weather conditions and inflows permit, in order to mitigate hydro capacity limitations during seasonal peak load periods. Entities in the area report contracts for the firm natural gas needed for operations. Reliable fuel supplies are supported by fuel contracts that are in place months, and often years, into the future. Vendor performance is monitored closely and potential problems are addressed long before issues become critical; all large contracts are with very reputable and reliable vendors. Finally, proactive communications and cooperative relationships are invaluable toward meeting critical objectives. Planning studies assume all types of fuel are available on an economic basis Approximately 35% of gas-fired capacity has dual fuel capability and can run on fuel oil when necessary. Natural gas limitations are considered in the production costing model utilized in long-term planning studies as follows. Combined-cycle units have no gas limitations at all. Most simple cycle combustion turbines that are gas capable have no gas limitations except in January.

Capacity Transfers

No significant capacity transfers (imports or exports) have been reported for the SERC East subregion.

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planned lines. Ten new 230/100 or 230/115 kV transformers and one new 115/100 kV transformer are planned over the 10-year planning horizon. Reliability is the driver for all planned transmission additions.

Transmission

Seven 230 kV and ten 115 kV transmission lines are planned over the 10- year planning horizon. One new tie line from Dominion Energy South Carolina to South Carolina Public Service Authority is included in the

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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% throughout the ten-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

48,139

48,675

49,161

49,663

50,315

50,924

51,600

52,333

53,033

53,033

Demand Response

3,104

3,153

3,204

3,253

3,300

3,348

3,395

3,440

3,488

3,488

Net Internal

45,035

45,522

45,957

46,410

47,015

47,576

48,205

48,893

49,545

49,545

Resources (MW)

Anticipated Prospective

56,449 56,703

56,589 56,844

57,416 57,671

58,561 58,816

58,894 59,148

59,336 59,591

61,116 61,370

60,909 61,163

61,098 61,353

61,133 61,387

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.

Reserve Margins (%) Anticipated

25.30% 25.87%

24.31% 24.87%

24.93% 25.49%

26.18% 26.73%

25.27% 25.81%

24.72% 25.25%

26.78% 27.31%

24.58% 25.10%

23.32% 23.83%

23.39% 23.90%

Prospective

Existing On-Peak Generation (Summer)

Peak Capacity

Generation Type

MW

%

Biomass

B 117

0.22

i o m a o a l 6,743 N a t u r a l G a s 38,346 H y d r o 44 N u c l e a r 3,625 O t h e r 308 P e t r o l 2,438 P u m 0 S o l a r 611 W i n d 0 s s C

Coal

12.91

Natural Gas

73.41

Hydro

0.08

Nuclear

6.94

Other

0.59

Petroleum

4.67

Pumped Storage

0.00

Solar

1.17

Wind

0.00

e u m p e d S t o r

a g e

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Some of the larger utilities in the subregion account for load profile modifiers such as Distributed Energy Resources (DERs) and Electric Vehicles (EVs). The smaller utilities either (i) do not yet have enough data to account for such modifiers in their forecast, or (ii) have analyzed the estimated impacts of such trends and determined their impacts sufficiently small to include in an embedded manner. Load growth in the Miami-Dade and Broward Counties is significantly higher than load growth in the rest of the state. The effects of this load growth will require continued monitoring, as there are both limited transmission corridors into this area as well as limited generation siting availability in this area. Controllable Demand Response from interruptible and dispatchable load management programs within the FL-Peninsula is treated as a load-modifier, and is projected to be constant at approximately 6.3% of the summer and winter total peak demands for all years of the assessment period. Each individual reporting entity develops their own independent forecast of firm controllable and dispatchable Demand Response values to be available at system peak, based on their methodology. These individual reporting entities perform and develop independent analyses of the estimated impacts from their firm Demand Response and Load Management. The FRCC then aggregates those impacts for analytical purposes. Note that many of the utilities within the FL-Peninsula subregion are currently involved in a DSM docket that will set their proposed goals of demand response for the next ten years. The outcome of this docket may significantly change the projected amount of DSM in the FL- Peninsula subregion. Energy efficiency and conservation programs, along with the growth expectations for such initiatives, are embedded specifically in the individual entities’ load. The FRCC Load Forecast Working Group (LFWG) annually meets to discuss individual entities’ forecasting philosophy. In addition to the forecasts of utility-sponsored energy efficiencies (EE) described above, many of the FL-Peninsula utilities include forecasts of EE associated with the impact from governmental codes and Demand-Side Management

Planning Reserve Margins The SERC FL-Peninsula subregion uses the Florida Public Service Commission (FPSC) reliability criterion of a 15% reserve margin for non-Investor Owned Utilities (non-IOUs) as the minimum Regional Total Reserve Margin based on firm load. The Total Reserve Margin calculations include merchant plant capacity that is under firm contract to load-serving entities. The Florida Reliability Coordinating Council (FRCC) assesses the upcoming ten-year projected summer and winter peak hour loads, generating resources, and firm Demand Side Management (DSM) resources on an annual basis to ensure that the subregional Total Reserve Margin requirement is projected to be satisfied. Based on the forecasted load, firm generation capacity, and firm DSM, the projected Regional Total Reserve Margin is above 15% for the FL- Peninsula subregion. More specifically, the FL-Peninsula subregional Reserve Margins are projected to remain at or above 20% for all summer and winter seasons during the assessment period. Demand The individual entities within the FL-Peninsula develop their load forecasts and the FRCC then aggregates these forecasts to calculate a non-coincident seasonal peak for the Region. Each entity adjusts their forecasts annually to account for their actual peak demand, updated economic outlook, population growth, weather pattern, conservation and energy efficiency efforts, and electric appliances usage pattern. The Net Energy for Load (NEL) and summer peak demands are forecasted to remain steady when compared to previous forecasts. The current average annual growth rate for NEL is 0.8% per year. Firm summer peak demand growth is expected to decrease slightly to approximately 1.15% when compared to the previous forecasted growth rate of 1.2% per year. For firm winter peak load, the average growth rate is also expected to decrease to .99% when compared to the previous forecast of 1.1% per year. The higher growth rate for demand compared to energy implies a declining trend for regional load factor. (The growth rates for demand are higher than are the growth rates for NEL – average demand.)

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standards. These impacts are projected to be substantial over the next ten years. Distributed Energy Resources (DERs) Distributed Energy Resources are modeled with associated loads and netted out since the load forecasts of entities within the FL-Peninsula subregion account for these loads implicitly. Currently, the FL-Peninsula subregion has low penetration levels of DERs; however, penetration levels are expected to grow throughout the planning horizon. The FRCC standing committees and subcommittees continue to review recommendations developed by the FRCC Solar Task Force, which was tasked with examining and determining procedures and processes to address the projected growth of solar generation within FL-Peninsula. The FRCC Resource Subcommittee coordinated with the FRCC Load Forecast Working Group and developed a pilot data collection to amalgamate estimated statistics (historical and projected) for DERs within the FL-Peninsula subregion to better support the integration of DERs into infrastructure sufficiency studies for transmission and distribution systems. While this data will be aggregate in nature, the FRCC Resource Subcommittee is actively exploring geographical tracking processes to evaluate potential DER growth pockets, and continues to coordinate with the FRCC Planning Committee on tractable approaches to disaggregation in the near future (e.g., by substations, zip codes, counties, etc.). Generation No impacts because of generation retirements have been determined in the Planning Horizon. The FRCC Regional Transmission Planning Process (RTPP) incorporates planned (known) future generator retirements via the studies performed by the FRCC subcommittees. The FRCC Transmission Technical Subcommittee (TTS) and the FRCC Stability Analysis Subcommittee (SAS) perform their Annual Long Range Study (LRS) for the FRCC region in accordance with the FRCC Regional Transmission Planning Process. The LRS is performed by incorporating each individual planning authority’s 10-year load and resource plan (approved firm resources and planned retirements), along with transmission infrastructure, into a coordinated model of the region’s Bulk Electric System. This analysis is performed to ensure

long-term reliability of the FL-Peninsula subregion under a wide array of study scenarios. The SAS annually performs the FRCC Extreme Event (stability) Study for the FRCC region, which includes the expected 10-year resource plan at peak and light load conditions, as well as evaluating various generation import levels into the FL- Peninsula subregion. Capacity Transfers All firm capacity imports into the FL-Peninsula subregion have firm transmission service agreements in place to ensure deliverability into the subregion. These capacity resources are accounted for in the calculation of the subregion’s Anticipated Reserve Margin. In addition, the interface owners between the FL-Peninsula subregion and SERC- E subregion meet biennially to coordinate and perform joint studies to ensure the reliability and adequacy of the interface. Significant proposed gas pipeline projects (Sabal Trail Phases II and III) are expected to provide 0.245 Bcf of incremental gas transportation capacity to peninsular Florida and be fully in-service in 2021, increasing total delivery capacity to 1.075 Bcf. Completion of these projects will enhance fuel transportation reliability by increasing supply and delivery diversity for the FL-Peninsula. This capacity will also help the FRCC Region meet the increasing gas generation requirements driven from new gas-fired generators being constructed over the next 10 years. The FL-Peninsula subregion has not identified any scenarios that would affect transfers into the FL-Peninsula subregion or would result in reliability issues from reduced transfers. The FRCC’s TTS and SAS performed the annual Long-Range Study and Extreme Event Study, which includes all NERC contingency categories (P0 though P7) to determine any potential transmission limitations, transmission constraints, short-circuit analysis and dynamic and steady state reactive-power limited areas. The FL-Peninsula subregion has not identified any specific major projects that are needed to maintain reliability during the planning horizon. The FL-Peninsula subregion’ individual entities do have planned projects related primarily to system expansion in order to serve Transmission

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