2018 SERC RRS Annual Assessment

2018 Annual Assessment Reliability Review Subcommittee

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Contents

Preface...........................................................................................................................................................................................................3 About This Assessment .................................................................................................................................................................................4 Executive Summary .......................................................................................................................................................................................5 Detailed Review of 2018 Findings ............................................................................................................................................. 6 Subregion Reserve Margins ..........................................................................................................................................................................7 Capacity Resource Trends ............................................................................................................................................................................8 Capacity Resource Issues .............................................................................................................................................................................9 Demand Projections.....................................................................................................................................................................................10 Transmission Additions................................................................................................................................................................................11 Subregion Dashboards/Summaries ......................................................................................................................................... 13 SERC Central ..............................................................................................................................................................................................14 SERC East...................................................................................................................................................................................................17 SERC MISO-Central ....................................................................................................................................................................................21 SERC MISO-South ......................................................................................................................................................................................24 SERC PJM...................................................................................................................................................................................................27 SERC Southeast..........................................................................................................................................................................................30 Data Concepts and Assumptions ............................................................................................................................................ 33 Special Topics ...................................................................................................................................................................... 37 Working Group Contributions.......................................................................................................................................................................38 Long/Near-Term Transmission Non-Public Summary .................................................................................................................................42 SERC Special Analysis: RISTF Report........................................................................................................................................................43 Appendix A Glossary ........................................................................................................................................................... 44

Appendix B SERC Membership ............................................................................................................................................. 45

Appendix C SERC EC Reliability Review Subcommittee Membership ......................................................................................... 47

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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 seven 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. In 2017, SERC redefined the five subregions in Figure 1 to the six subregions shown in Figure 2. This change aligns studies, assessments, and reporting with the existing boundaries of the Planning Coordinators in the SERC footprint. The SERC Region covers an area of approximately 560,000 square miles and serves more than 53 million customers. On July 1, 2018, the FERC approved requests made by NERC to transfer 13 Registered Entities from the dissolved SPP RE to SERC. Figure 2 below shows the new subregional boundaries and includes the SPP entities located in MISO-South, MISO Central and SPP RTO. Onboarding and coordination activities are underway with the new Registered Entities to assist with the transition into SERC’s programs and processes.

Figure 1: Initial 2006-2017 Subregions

Figure 2: New 2018 Subregions

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About This Assessment This 2018 Reliability Review Subcommittee Annual Assessment (2018 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 instructs the Regions to conduct periodic assessments of the Regional BPS. In response to industry trends and comments received, the 2018 Annual Report is presented in a more succinct format to highlight data and information that is especially important to the long-term outlook of the SERC BPS. This transition to a shorter format was executed without affecting the comprehensive assessment development process described in the Data Concepts and Assumptions section. Interested parties should contact SERC Staff with any questions. 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 2018 RRS Annual Report are not predictions of what will happen; they are based on information supplied by Registered Entities in February 2018 and updates incorporated prior to publication. The assessment period for the 2018 RRS Annual Report is from 2019 to 2028; however, some figures and tables examine data and information for year 2018. 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. Due to the SPP RE transition, this report does not include information for two entities within the SPP RTO footprint. However, these entities are included in the Region’s and individual entity planning studies. The remaining entities located in MISO-South in Figure 2 above were included in this year’s report.

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Executive Summary The RRS assembled and reviewed many sources of data to verify the future reliability of the Region from a resource adequacy and transmission system performance vantage point. This report is an assessment of 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 Adequacy Working 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:

SERC is proactively addressing the impacts of increased renewable resources within the SERC footprint and identifying its risks through various forums. • The RAWG is currently identifying resource adequacy impacts due to increased renewables. • The Variable Energy Resource Working Group (VERWG) explores the reliability considerations related to variable energy resource integration in the SERC Region. • The EC’s Renewables Impact Study Task Force (RISTF) is currently considering the RAWG’s resource mix scenarios, analyzing transmission impacts, and proposing next steps for the changing resource mix. Across the SERC Region, member companies continue to build transmission, especially in the first 5 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 December 31, 2017, there are 103,069 miles of bulk transmission lines at 100 kV and above in the SERC Region. • Entities within the SERC Region anticipate adding approximately 2,136 miles of transmission during the ten-year reporting period.

Key Findings Expected demand projections for the SERC Region are almost flat. • The SERC Region’s 2019-2028 Compound Annual Growth Rate (CAGR) is 0.77%. • On the high end, MISO-South subregion has a 1.98% CAGR. • On the low end, MISO-Central subregion has a 0.22% CAGR. The six SERC subregions expect the Anticipated Reserve Margins to be above 20% for the ten-year period. • Four of the six subregions expect to maintain a ten-year reserve margin in the 20-28% range. • Two of the six subregions expect to maintain a ten-year reserve margin in excess of 30%. • Going forward, the Resource Adequacy Working Group (RAWG) will calculate SERC’s Reference Reserve Margin using metrics of 0.1 days per year loss of load expectation (LOLE). Only slight changes in the Regional resource mix are projected for the ten-year planning horizon, with no significant change reported from 2017 to 2018. Net capacity resources in the Region are expected to increase for the first five years of the ten-year planning horizon and level out in the last five years, with natural gas-fired capacity additions largely offset by coal-fired capacity retirements.

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Detailed Review of 2018 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. SERC anticipates the publication of the 2018 Probabilistic Assessment to be September 2018. 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 2019 2020 2021 2022 2023 2024 2025 2026 2027 All Reference Margin Level 13.15 13.15 13.78 14.41 14.41 14.41 14.41 14.41 14.41 Central Anticipated Reserve Margin 25.7 25.71 25.56 25.21 24.58 24.4 24.02 23.2 22.98 East Anticipated Reserve Margin 23.28 21.05 20.93 22.29 21.48 20.36 21.94 23.35 21.78 MISO-Central Anticipated Reserve Margin 23.97 26.48 26.77 26.22 22.59 22.66 21.76 20.82 19.85 MISO-South Anticipated Reserve Margin 21.63 23.96 27.99 26.65 25.9 25.33 23.17 22.54 21.85 SERC-PJM 1 Anticipated Reserve Margin 33.12 35.46 35.66 35.20 34.53 34.00 33.40 32.73 31.98 Southeast Anticipated Reserve Margin 32.56 32.09 31.33 32.6 33.83 33.1 32.51 30.65 33.15

1 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 2018 total 256,400 MW. Net capacity resources in the Region are expected to increase for the first five years of the 2019-2028 planning horizon to 266,900 MW. Net capacity resources are projected to level out in the last five years of the planning horizon with natural gas-fired capacity additions being largely offset by coal-fired capacity retirements. Capacity resources in the SERC Region in 2028 are projected to total 267,600 MW. No significant change in the SERC resource mix was reported for 2018 compared to 2017. Only slight changes 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 combined types (which includes pumped storage, oil-fired, solar, biomass, wind, and other). For the period 2018-2028, natural gas-fired capacity is projected to increase from 42.6% to 44.1%. Through the same period, coal- fired capacity is projected to decrease from 31.2% to 29.1%. SERC members have not announced any large-scale coal- fired capacity retirements through the near-term planning horizon.

Nuclear powered resources supply 14.3% of the SERC capacity in 2018. This share is projected to increase to 14.6% in 2028 due to two 1,100 MW nuclear plant additions in 2022 and 2023. Existing solar (photo-voltaic) capacity resources in the SERC Region are reported at 1,700 MW, but planned solar additions of over 2,400 MW are projected through 2023. With these additions, combined-type capacity resources would supply 7.9% of the SERC total by 2028, up from 7.3% in 2018. Hydro capacity resources are projected to remain essentially unchanged through the forecast period at approximately 4.5% 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 4: Capacity Resource Trends

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Capacity Resource Issues

Table 2: Capacity Resource Issues 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%. MISO-South is seeing a recent increase in growth close to 2%. Gas growth in SERC is lower than most of NERC areas. Gas growth through the assessment period is about 1.5%, while coal drops about 2%. Coal, nuclear, and hydro remain fairly constant through the assessment period, noting a one percentage point drop in coal. Two new nuclear units are planned in SERC Southeast during the assessment period. Solar generation doubles by the end of the assessment period, but remains very small compared with other generation. Solar’s limitations make it less useful than conventional and gas 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. 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 duel-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 may require further analysis to determine if fuel controls are required.

All subregions, with the exception of SERC MISO-South

Demand

SERC East, SERC MISO-South

Natural Gas

All subregions

Conventional Generation

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

SERC-PJM

Solar PV

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Demand Projections The 2018-2027 demand forecast shows a 0.77% compound annual growth rate (CAGR), which is relatively flat compared to last year's 2017-2026 growth rate of 0.70%. Figure 5 shows a breakdown of the forecasted growth in internal demand by subregion. The ten-year projected growth rate is 6.71% for summer and 4.55% for winter. Figure 6 shows the forecasted growth in total internal demand by year. The actual total internal demand in 2017 winter was above forecast due to below normal system temperatures, but does exceed the 2018-2027 forecast.

Figure 5: Compound Annual Growth Rate

Figure 6: SERC Region Total Internal Demand (MW)

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Transmission Additions As of December 31, 2017, there are 103,069 miles of bulk transmission lines operated at 100 kV and above in the SERC Region. Entities within the SERC Region anticipate adding approximately 2,136 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 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

In addition to transmission lines, several new transformers are due to come in service during the next ten-years within the SERC Region. Of the 85 transformer projects, 73 have high-side voltages of 200 kV and above.

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

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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.

Demand (MW) Total Internal

2019

2020

2021

2022

2023

2024

2025

2026

2027

41,526

41,730

41,784

41,851

42,001

42,025

42,143

42,414

42,486

Demand Response

1,795

1,795

1,802

1,759

1,705

1,671

1,666

1,666

1,666

Net Internal

39,731

39,935

39,982

40,092

40,296

40,354

40,477

40,748

40,820

Resources (MW) Anticipated

49,943 52,136

50,201 52,394

50,201 52,394

50,201 52,394

50,201 52,394

50,201 52,394

50,201 52,394

50,201 52,394

50,201 52,394

SERC Central The SERC Central subregion consists of the following Planning Coordinators: Associated Electric Cooperative Inc., Alcoa Power Generating Inc.-Tapoco Division, Electric Energy Inc., Louisville Gas & Electric/Kentucky Utilities, Tennessee Valley Authority

Prospective

Reserve Margins Anticipated

25.70 31.22

25.71 31.20

25.56 31.04

25.21 30.68

24.58 30.02

24.40 29.84

24.02 29.44

23.20 28.58

22.98 28.35

Prospective

Existing On-Peak Generation (Summer) Generation Type

Peak Season Capacity MW Percent

Biomass

0

0.00

Coal Gas

17,097 19,833

33.76 39.17

Hydro

3,566 8,121

7.04

Nuclear

16.04

Oil

0 0

0.00 0.00 3.32 0.02 0.66

Other

Pumped Storage

1,680

Sun

8

Wind

333

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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 within the region 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 DERs (> 5 MW) that are not behind the wholesale meter are modeled explicitly. These would also have the dynamic characteristics included. Currently, there are 55 projects (~5,540 MW) in the interconnection queue over the next five years. These are solar projects that have potential to connect to the BES. Generation Anticipated generation resources in the SERC-Central subregion are reported to stay constant over the ten-year planning horizon despite the confirmed resource retirements starting in 2019. Coal supplies approximately a third of the capacity in the subregion in 2018 and will remain constant across the ten-year period. Natural gas and nuclear provide 39 and 16% of the subregion’s capacity, respectively. Hydro and pumped storage provide 7 and 3% for summer peak. Capacity Transfers This subregion expects firm imports of 1221 starting in summer 2019 through the ten-year period. It expects firm exports around 2,200 MWs through the ten-year period. Transmission Approximately 204 miles of transmission lines 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. In

Planning Reserve Margins Anticipated Reserve Margins for the SERC Central subregion 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 the subregion do 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 neutralversus risk adjusted reserve margins to better reflect anticipated increases in intermittent resources and establish distinct summer and winter targets. Demand The SERC-Central subregion is slightly summer peaking with a forecast total internal demand for 2019 of 39,731 MWs. The total internal demand for summer exceeds the total internal demand for winter by approximately 59 MW. The net internal demand for summer is expected to increase by approximately 1,200 MW over the ten-year planning horizon. Demand-Side Management Companies within SERC Central use flexible, responsive programs and resources to meet the demand. These programs range from 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. SERC Central entities do not expect a significant change to the programs and response through the forecasted period. Distributed Energy Resources (DERs) For the majority of the SERC Central region, 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 is transported almost entirely into the subregion via Pseudo

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addition, a 500 kV substation is currently being constructed to alleviate decreasing voltages and higher flows on lines caused by increased loads in the area. In addition, a Static VAR Compensator (SVC) is planned for a 500 kV substation to support the stability of local units. Entities 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. All of the transmission limitations/constraints will be mitigated through future transmission projects (new builds, reactors, etc.), generation adjustments, system reconfiguration, or system purchase.

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Highlights • With the additional ~3,700 MW of gas generation serving as replacement generation for the cancelation of the VC Summer nuclear plant (~2,200 MW), reserve margins in SERC East consistently trend above 20%. • Entities report hundreds of utility-scale transmission BES connected projects (~17,000+ MW) in the interconnection queue over the next five years.

Demand (MW) Total Internal

2019

2020

2021

2022

2023

2024

2025

2026

2027 45,876 1,098 44,778 54,529 54,571

42,684 1,090 41,594 51,278 51,320

43,162 1,091 42,071 50,925 50,967

43,523 1,093 42,430 51,312 51,354

43,902 1,093 42,809 52,351 52,393

44,227 1,093 43,134 52,397 52,439

44,632 1,094 43,538 52,401 52,443

45,010 1,095 43,915 53,552 53,594

45,445 1,096 44,349 54,705 54,747

Demand Response

Net Internal

Resources (MW) Anticipated Reserve Margins Anticipated Prospective

SERC East The SERC East subregion consists of the following Planning Coordinators: Cube Hydro Carolinas, Duke Energy Carolinas, Duke Energy Progress, South Carolina Electric & Gas Company, South Carolina Public Service Authority

23.28 23.38

21.05 21.14

20.93 21.03

22.29 22.39

21.48 21.57

20.36 20.45

21.94 22.04

23.35 23.45

21.78 21.87

Prospective

Existing On-Peak Generation (Summer)

Peak Season Capacity MW Percent

Generation Type

Biomass

164

0.32

Coal Gas

15,794 15,363

30.95 30.11

Hydro

3,006

5.89

Nuclear

11,694

22.92

Oil

1,475

2.89 0.00 5.97 0.96 0.00

Other

0

Pumped Storage

3,044

Sun

490

Wind

0

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ten-year planning horizon. DER to date have not caused a noticeable change to the net internal demand, but the solar development project queue continues to significantly increase across the subregion. 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 DER growth in the region has been solar; it is projected to have little to no 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 2016 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, programs are offered 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. Transmission-connected DER is modeled in the energy management system and transmission planning models, whereas sub transmission DERs (roof-top solar, plug-in electric vehicles, etc.) are netted against load. Future DER utility scale solar (i.e. non-roof top solar) output projections are considered with historical load shapes to assess the future operational impacts on ramping, as well as the magnitude of projected excess energy issues from increasing DER solar penetration scenarios, above the already occurring, high penetration. In the operating horizon, utility scale solar output is forecasted to support

Planning Reserve Margins Considering anticipated generation resources strictly within the SERC East subregion, the forecast planning reserve margin for 2019 exceeds 22%. The forecast reserve margins are expected to decline starting in 2020, but resources would still exceed net internal demand by at least 18.43% at the end of the forecast period. Reserve margins could be higher and exceed 18.43% considering prospective generation retirements and additions. The SERC East subregion also has a reserve sharing agreement among the VACAR companies. Resources planned and added within the assessment period will assist in maintaining the minimum planning reserve margin. With the additional ~3,700 MW of gas generation serving as replacement generation for the cancelation of the VC Summer nuclear plant (~2,200 MW), reserve margins in SERC East consistently trend above 20%. 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 are included in the analysis and incorporate the uncertainty of weather, economic load growth, unit availability, and the availability of transmission and generation capacity for emergency assistance. Uncommitted generation and non-firm resources are not included in the calculations. 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 NERC 2016 Long-Term Reliability Assessment (LTRA). No parts of SERC East have Reserve Margin mandates (excludes North Carolina entities that are PJM members). Each utility determines its Reserve Margin and presents it in their IRP (Integrated Resource Plan). 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 2019 of 42,684 MW. The total internal demand for winter exceeds the total internal demand for summer by approximately 900 MW or 2.1%. Both Total and Net Internal Demand within the SERC East subregion for winter are expected to increase by 9.7%) over the

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seven-day operational planning, and to assess the potential for ramping challenges and over supply situations during light load conditions. 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. Entities report there are hundreds of utility scale, transmission BES connected projects (~17,000+ MW) in the interconnection queue over the next five years. Transmission Planners account for BES connected DERs by explicitly modeling those connected at transmission voltage levels in accordance with data provided through the generation interconnection process. For most entities, transmission connected solar facilities’ output is based on historical MW output on peak or if no data is available, at 35-80% of contractual committed MW in summer and 0% in winter. These in front of the meter DERs (existing, under construction, and expected renewable additions) are included as generation resources in resource planning and mid-term planning models. Modeling data includes the manufacturer’s control scheme for dynamic studies. The queued amount of DERs connected to the non- BES, sub-transmission system (roof-top solar, plug-in electric vehicles, etc.) is approximately 10% of the utility scale, transmission BES connected projects. 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 3,100 MW (6.2%) over the ten-year planning horizon. No significant generation retirements in the subregion have been announced through 2028. There are plans to retire approximately 1700 MW of coal-fired generation and 430 MW of natural gas-fired generation by 2028. Coal supplies approximately 31% of the capacity in the subregion in 2018 and is the largest source of electric energy just ahead of Gas. Natural gas and nuclear generation provide 30% and 23% of the

subregion's capacity, respectively. Renewable resources (hydro, pumped storage, biomass, solar, and wind) provide approximately 14% of the capacity at 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. On July 31, 2017, the Santee Cooper Board of Directors voted to suspend construction of Units 2 and 3 at V.C. Summer Nuclear Station in Jenkinsville, S.C. The vote followed a comprehensive analysis of the project’s cost to complete following the bankruptcy and stated plan to reject Santee Cooper’s fixed price contract by Westinghouse, the contractor building the new units. Even without construction of Summer Units 2 and 3, Santee Cooper projects its existing/remaining portfolio to be capable of meeting its energy and capacity needs through 2035. In addition, the subregion reports to have an additional ~3,700 MW of gas additions over the period to meet demand. Entity planning assumptions for renewable resources incorporate North Carolina Renewable Energy and Energy Efficiency Portfolio Standards (REPS) requirements and South Carolina DERS goals, as well as additional solar resources procured in response to the newly signed NC House Bill, HB 589. Entity IRPs assume 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 EE and DSM. From a planning perspective, the move to winter planning and planning reserve margin addresses the potential operational impacts of the changing resource mix. Entities select various sensitivity studies using engineering judgment to investigate further any potential impact of having changes in available generation resource mix. No operational issues are anticipated over the period. 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.

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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 that purported Adverse Governmental Actions will delay the in service date of the previously planned Atlantic Coast Pipeline (ACP) and impose additional costs. Although a one-year ACP delay will require companies in the subregion to continue to rely on Transco as the single interstate pipeline for its growing gas generation needs, entities do not anticipate that the projected ACP delay will affect how entities utilize gas fired generation. In the planning horizon, entities have secured additional capacity for future years, and reflect it in long-term planning studies, accordingly. As far as firm gas contracts, on a MW basis, ~40-82% of the contracts in the subregion are firm transport contracts; on a gas-fired baseload generation basis, ~16-66% of the contracts are firm.

Capacity Transfers No significant capacity transfers (imports or exports) have been reported for the SERC East subregion. Transmission Nine 230 kV and three 115 kV transmission lines are planned over the ten-year planning horizon. Two new tie lines from South Carolina Electric and Gas to South Carolina Public Service Authority and Southern Company are included in the planned lines. Twelve new 230/100 or 230/115 kV transformers are planned over the ten-year planning horizon. All planned transmission additions are driven by reliability.

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Highlights • Anticipated resources are stable but slightly decreasing through the ten-year planning horizon. • Extra High Voltage (EHV) transmission development continues with approximately 340 miles planned in the next 5 years.

Demand (MW) Total Internal

2019

2020

2021

2022

2023

2024

2025

2026

2027

19,064

19,067

19,025

19,105

19,065

19,054

19,189

19,333

19,484

Demand Response

719

718

718

718

718

718

718

718

718

Net Internal

18,345

18,349

18,307

18,387

18,347

18,336

18,471

18,615

18,766

Resources (MW) Anticipated

22,743 22,892

23,208 23,357

23,208 23,357

23,208 23,357

22,491 22,640

22,491 22,640

22,491 22,640

22,491 22,640

22,491 22,640

Prospective

SERC MISO-Central The SERC MISO-Central subregion consists of the following Planning Coordinators: Midcontinent Independent System Operator, Inc.

Reserve Margins Anticipated

23.97 24.78

26.48 27.29

26.77 27.58

26.22 27.03

22.59 23.40

22.66 23.47

21.76 22.57

20.82 21.62

19.85 20.64

Prospective

Existing On-Peak Generation (Summer) Generation Type Peak Season Capacity MW Percent Biomass 6 0.03 Coal 13,224 58.27 Gas 6,013 26.49 Hydro 415 1.83 Nuclear 2,255 9.94 Oil 266 1.17 Other 0 0.00 Pumped Storage 440 1.94 Sun 0 0.00 Wind 76 0.33

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SERC MISO-Central subregion. Connections of large DERs in the subregion have been limited to wind farms. Interest in DERs is continuing but has not caused a noticeable change to the net internal demand in the subregion. Both transmission and distribution planning engineers in many areas of the subregion are preparing for increased PV and inverter-based resource development. Generation Anticipated generation resources in the SERC MISO-Central subregion are expected to exceed 23,000 MW through the ten-year planning horizon, but are expected to decline slightly by 252 MW (1.4%) over this period. No significant generation retirements in the subregion have been announced through 2022. Approximately 600 MW of coal-fired generation and 120 MW of natural gas-fired generation is planned to be retired in 2023. Coal supplies approximately 57% of the capacity in the subregion in 2018 and is by far the largest source of electric energy. Natural gas and nuclear generation provide 28% and 10% of the subregion's capacity, respectively. Renewable resources (hydro, pumped storage, biomass, solar, and wind) provide approximately 4.1% of the capacity at time of summer peak. Capacity Transfers No capacity transfers (imports or exports) have been reported for the subregion. All SERC MISO-Central members are participants in the MISO energy market. Transmission Existing EHV transmission mileage in the SERC MISO-Central subregion exceeds 2300 miles. Lower voltage transmission > 100 kV but < 200 kV exceeds 6300 miles. Planned EHV transmission line additions in the next 5 years is approximately 340 miles, while planned lower voltage transmission lines are less than 90 miles. Approximately 40 miles of lower voltage transmission is planned for the second five years in the subregion. EHV development continues across the SERC MISO-Central subregion. The 50-mile Faraday-Kansas and 35-mile Fargo-Sandburg 345 kV lines were recently completed as part of the MISO MVP transmission development to collect and deliver wind energy

Planning Reserve Margins Considering anticipated generation resources strictly within the SERC MISO-Central subregion, the forecast planning reserve margin for 2019 exceeds 27%. The forecast reserve margins are expected to decline starting in 2023, but resources would still exceed net internal demand by at least 22.8% at the end of the forecast period. Reserve margins could be higher and exceed 23.6% at the end of the planning horizon considering prospective generation retirements and additions. The SERC MISO-Central subregion also has access to all of the deliverable resources within the MISO footprint. Although not shown here, MISO’s forecasts sufficient capacity resources to meet expected demand and reserves for the next five years, above the Planning Reserve Margin Requirement (PRMR) of 17.1%. Beginning in 2023 however, MISO capacity is projected to fall below the PRMR and remain there for the rest of the assessment period. Falling below the PRMR signifies that the MISO region is projected to operate at a reliability level lower than the one-day-in-10 standard in 2023 and beyond. Demand The SERC MISO-Central subregion is summer peaking with a forecast total internal demand for 2019 of 19,064 MW. The Total Internal Demand for summer exceeds the Total Internal Demand for winter by more than 3,600 MW. Both Total and Net Internal Demand within the SERC MISO-Central for summer are expected to increase slightly (by 2.2-2.3%) over the ten-year planning horizon. Distributed Energy Resources to date have not caused a noticeable change to the net internal demand. Demand-Side Management Reported demand-side management response in the SERC MISO- Central subregion exceeds 700 MW or 3.8% of the Total Internal Demand for 2019. This level of demand response is expected to continue through the forecast period. Distributed Energy Resources (DERs) At this time, no significant photo-voltaic (PV) developments have been connected to either the transmission or distribution systems in the

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throughout the MISO-Central footprint. Two additional projects, the 71- mile Ottumwa (IA)-Zachary (MO) and 58-mile Zachary-Maywood 345 kV lines, are also part of that MISO MVP development and are planned for completion in 2019. Planned/committed EHV transmission development in the planning horizon also includes a 26-mile Albion South-Norris City North 345 kV line, an 11-mile Gateway-Roxford 345 kV line, and the conversion of the existing Cahokia-North Coulterville 230 kV line to a Gateway-Prairie State 345 kV line and a Prairie State- North Coulterville 345 kV line. These projects are needed to eliminate

congestion, address aging infrastructure concerns, and meet local planning criteria. The second Neoga South 345/138 kV transformer was installed earlier this year. Planned EHV transformer additions for the subregion for the next 5 years include 345/161 kV transformers for Zachary and Massac (IL) and 345/138 kV transformers for Beehive, Fargo, Jarvis, Gateway, Jordan, and Miles to provide additional capacity and enhance local area voltages.

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Highlights • The anticipated reserve margin for the SERC MISO-South subregion is projected to increase by 5% in the near term as new resources are brought online, and then return to approximately the same level in 2027 as its 2019 starting point. • The SERC MISO-South subregion contains a mix of traditional generation resources with gas fired generation as the predominant type. Additional gas generation is planned for the near term in the subregion along the coastal areas of the region. Interest in potential non-traditional resources such as solar is increasing. • The SERC MISO-South subregion continues to focus on transmission investments to address both reliability and address potential market congestion.

Demand (MW) Total Internal

2019

2020

2021

2022

2023

2024

2025

2026

2027

SERC MISO-South The SERC MISO-South subregion consists of the following Planning Coordinators: Midcontinent Independent System Operator, Inc.

33,767 1,160 32,607 39,661 40,604

33,954 1,164 32,790 40,645 41,588

34,101 1,164 32,937 42,157 43,100

34,240 1,122 33,118 41,945 42,888

34,439 1,122 33,317 41,945 42,888

34,585 1,116 33,469 41,945 42,888

34,750 1,116 33,634 41,426 42,368

34,922 1,116 33,806 41,426 42,368

35,114 1,116 33,998 41,426 42,368

Demand Response

Net Internal

Resources (MW) Anticipated Reserve Margins Anticipated Prospective

21.63 24.53

23.96 26.83

27.99 30.85

26.65 29.50

25.90 28.73

25.33 28.14

23.17 25.97

22.54 25.33

21.85 24.62

Prospective

Existing On-Peak Generation (Summer)

Peak Season Capacity MW Percent

Generation Type

Biomass

0

0.00

Coal Gas

7,162

18.41 64.17

24,964

Hydro

430

1.10

Nuclear

5,229 1,116

13.44

Oil

2.87 0.00 0.00 0.00 0.00

Other

0 0 1 0

Pumped Storage

Sun

Wind

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