2020 LTRA Narrative Guide



2020 Long-Term Reliability AssessmentNarrative GuideGeneral InstructionsPlease adhere to the following guidelines when addressing the narrative questions below. Some questions will require specific actionable items or studies:Provide complete and accurate information in response to each question. Provide links to any documentation (e.g. studies, assessments) that will help explain your answers. If the study is non-public, please provide directly to NERC staff.Do not modify the questions.Example responses are provided for some questions. These examples are for additional clarity only and are not expected to be representative for responses in all assessment areas. Example responses may be deleted and are not needed for submission.The narrative summary to be used in the 2020 Long-Term Reliability Assessment will be produced by the assessment area after these answers have been reviewed in the peer review process and further reviewed by NERC and made consistent in style. Confidentiality – All responses will be posted to a secure site.Please contact NERC staff with any questions regarding this request.Assessment Area OverviewUse 2019 LTRA or modify if change has occurred since the prior year.Peak Season Data Summary Table (To be provided by NERC staff)Assessment ProcessAP-1: Briefly detail the reliability studies created by this assessment area. Include the periodicity, scope, and development process for each study or report. Planning Reserve MarginsPM1- If the Anticipated Reserve Margins fall below the Reference Margin Level(s) for first five years of the assessment period:Detail what contributed to the Anticipated Reserve Margins falling below the Reference Margin Level(s).Detail the potential contribution of Tier 2 resources if found below the Reference Margin Level(s).Describe any resource adequacy concerns and detail all actions that will be taken to address these concerns.Example: The Anticipated Reserve Margin falls below the ERCOT Target Reserve Margin in summer 2014. The depleting Reserve Margins in ERCOT is due to lack of generation resource additions that have not kept pace with the higher than normal load growth experienced in recent years. The generation market in ERCOT is unregulated and generators will make resource decisions based on market dynamics. Generation investors state that a combination of lack of long-term contracting with buyers, low market heat rates, and low gas prices are hindering decisions to build new generation. ERCOT’s energy-only market makes for a uniquely challenging investment environment. Market design proposals to enhance resource adequacy are being addressed at the Texas Public Utility Commission level (PUCT), with participation by ERCOT and other stakeholders. For its part, ERCOT is working through the stakeholder committee process to study, and facilitate revisions to, market protocols and pricing rules to bolster the reserve margin. Several proposed initiatives focus on demand responses resources, such as revising market rules to stimulate greater participation of weather-sensitive loads in the Emergency Response Service program.ERCOT expects tight reserves throughout the 10-year outlook. Based on current information regarding resource availability and anticipated demand levels, there is a significant chance that ERCOT will need to declare an Energy Emergency Alert (EEA) during a number of the future years and issue corresponding public appeals for conservation. The ERCOT system would likely have insufficient resources available to serve customer demand, if a higher‐than‐normal number of forced generation outages occur during a period of high demand or if record‐breaking weather conditions similar to the summer of 2011 lead to even higher‐than-expected peak demands. In these scenarios, the EEA declarations may be followed by a need to institute rotating outages to maintain the integrity of the system as a whole.PM2- Thoroughly explain the methods and assumptions used to calculate the Reference Margin Level(s).Explain if (and how) the Reference Margin Level relates to a 1-in-10 Loss of Load study. If necessary, provide a link to the latest related documentation and summarize the key methods and assumptions.Identify the states in the assessment area that have established a regulatory target of requirement for resource adequacy and describe the approach they use to establish it.Highlight any changes to these methods and assumptions since the prior LTRA. Example: ERCOT conducts a LOL study to determine a Target Reserve Margin (adopted as the NERC Reference Margin Level in this assessment) on a biennial basis. TRM is determined using a Monte Carlo Loss-of-Load Probability (LOLP) approach and the “one loss of load event in 10 years” criterion to determine the appropriate minimum ratio of resources to forecasted loads. This study reflects the availability of all resources within the ERCOT interconnection, including Existing Certain and Future Planned (i.e., generation with signed contracts for transmission service) generation and transmission-connected behind-the-meter generation. Switchable units have been allocated 100% to ERCOT in the study. Hydro generation, demand response, solar generation and import capacity of the DC ties are not included in the study. The study also includes assessment of generator outage data, load volatility due to weather variations, and output from variable generation to determine the minimum amount of resources required to achieve acceptable levels of system reliability. A description of the previously approved analysis of the Target Reserve Margin (TRM) for the ERCOT Region is provided in the report: 2010 ERCOT Target Reserve Margin Study (dated November 1, 2010). This report provides a description of the methodology and input assumptions for the analysis. An updated study of TRM requirements in the ERCOT Region is currently under review by the ERCOT stakeholders and the final approval by the ERCOT BOD is expected later this summer. ERCOT Protocols, Section 3 defines how loads and resources are included in the ERCOT internal system-wide reserve margin calculations. Existing-Certain (i.e., operational) and Future-Planned (i.e., with completed interconnection agreements and air permits) generation are considered as expected generation. Conceptual generation (resources in the interconnection process but without finalized interconnection agreements and air permits) are not considered expected. There are no energy-only or transmission limited resources included in the ERCOT area assessments. Future availabilities of demand-side resources and behind-the-meter generation are quantified based on statistical assessments of aggregate resource-specific availability during the most recent peak load period or based on the latest survey results. One of the demand-side programs are forecasted to increase by 10% of capacity on an annual basis. For ERCOT area assessments, one-half of asynchronous tie capacity is assumed to be available to serve internal load during scarcity conditions. The switchable units are assigned to ERCOT unless they have an “ERCOT Switchable Resource RFI” filing indicating otherwise.The Target Reserve Margin is reviewed by the ERCOT BOD based on the results of the LOLP studies conducted by ERCOT. The current TRM for the ERCOT Region, 13.75%, was established by the ERCOT BOD in November 2010.PM3 – Describe any off-peak demand periods (i.e., periods other than the peak hour for which the Planning Reserve Margins are determined) during which there is risk of resource shortage. Focusing on the first five year period, describe any periods of increased resource adequacy risk (either daily, monthly, and/or seasonally) that fall outside the expected peak demand hour. What are the main drivers and conditions that contribute to these additional periods of risk? Describe the assessment methodology, including additional metrics (probabilistic, if available and at the non peak hour), used to identify these risks. What actions have been taken during both planning and operational timeframes to address these risks? Please provide links to any studies performed to support this submittalPotential drivers could include:Low water conditionsFuel availability (e.g., gas pipelines and other interdependencies)Expansion of variable energy resources (including wind, solar, and distributed resources)Unseasonable weather (highly unexpected demand impacts)Resource outages Example: Some assessment areas are projecting risk away from the peak hour in day and some are projecting risk outside the peak hour month. This is sometimes referred to as “capacity to energy” or as a risk to energy assurance as it covers all potential hours of the year. This may include capacity contributions and actual demand at the non-peak hours, if available.Please provide links to any studies performed to support this submittal.DemandD1- Explain how the on-peak load forecast (Total Internal Demand) is developed. Include methods and assumptions for components and development process. Expand on the contributing factors (e.g., footprint changes, economic outlook, long-term weather outlook, demand-side management, distributed energy resources, behind-the-meter generation, changes to the load forecasting method, etc.).Identify differences between energy and peak demand forecasts and highlight notable trends (include changes in the load profile impacted by DERs, energy storage on distribution system, electric vehicles, etc.). Identify any studies performed (or ongoing or planned studies) that help identify any demand sensitivities regarding DERs, energy storage on distribution system, or electric vehicles, etc. Identify factors of these sensitives that are important to the demand forecast.Highlight any modifications made to these methods or assumptions since the prior LTRA.Example: Saskatchewan experiences peak‐season in the winter. The SaskPower Peak Forecast applies annual coincident peak load factors to annual sales forecasts by rate class and at the individual customer level for the largest industrial customers. The forecasted coincident peak factors represent historical average coincident peak load factors. The result is a forecasted coincident peak load for each of the categories. The category-level coincident peak factors are then aggregated across the classes to compute the System Peak Load Forecast. Within the Peak Forecast, there are econometric variables and weather normalization which both contribute to the system peak load forecast. The Econometric variables involve the construction of a regression model to generate the peak load forecast. The econometric models typically estimate peak loads as a function of seasonality, economic drivers, equipment stock drivers, prices, and peak producing weather conditions. It is also common to use weather normalized sales to drive peak loads, in certain cases the weather normalized sales are segmented into heating, cooling, and base load components. The peak weather normalization models estimate daily peaks as a function of weather variables, calendar conditions and a time trend. The variables used to estimate the weather impacts for daily peaks are the same as those that estimate the weather impacts for energy requirements. The maximum of the weather normalized daily peaks is computed on a monthly and annual basis to determine the weather normalized monthly and annual peaks. One of the primary economic assumptions is that Saskatchewan’s customer base will be maintained.High and low forecasts are developed for Saskatchewan to cover possible ranges in economic variations and other uncertainties, such as weather, using a Monte Carlo simulation model to reflect those uncertainties. This model considers each variable to be independent from other variables and assumes the distribution curve of a probability of occurrence of a given result to be normal. The probability of the load falling within the bounds created by the high and low forecasts is expected to be 90% (confidence interval). High and low demand cases are modeled separately as sensitivity cases. The load forecast also has a chronological 8760 load shape that is modeled based on historical load profiles.D2- Identify cases where projected demand growth in a localized area is significantly above or below the average for the whole assessment area. Explain the drivers and expected duration for the positive/negative load growth.Detail all reliability impacts attributed to this positive/negative load growth.Example: The High-Priority Incremental Load Study showed that the SPP Assessment Area is experiencing an increase in oil and gas drilling causing substantial load growth in northern Oklahoma, southwestern Kansas, Texas, and New Mexico. This localized growth has created the need for new transmission projects and generation in specific areas. SPP is working with Members to make sure that reliability needs are being addressed.Demand-Side ManagementDSM1- Explain how uniquely enrolled Controllable and Dispatchable Demand Response programs are accounted for. Further explain the approach for establishing how much capacity is considered available for peak. Also, highlight and differentiate between capacity, energy, regulation, and ancillary service types of Demand Response programs. Include considerations for:Pilot programsProgram use limitations Pending changes to program rulesPending changes to regulation or other policiesAny type of derating of registered MW based on past performanceDemand Response programs that exist or are being considered to address the need for flexibility and fast-start capability (e.g., frequency responsive load, regulation, etc.) and describe these programs.Any modifications made to these methods or assumptions since the 2019 LTRA.Example: Demand-Side Management (DSM) in the ISO-NE BPS includes both active and passive demand resources. Active demand resources consist of real-time Demand Response (DR) and Real-time Emergency Generation, which can be activated with the implementation of ISO-NE Operating Procedure No. 4 – Action during a Capacity Deficiency (OP-4). Some assets in the real-time DR programs are under direct load control by the load response providers (LRP). The LRP implements direct load control of these assets upon dispatch instructions from ISO-NE—for example, interruption of central air conditioning systems in residential and commercial facilities. Passive demand resources (i.e., Energy Efficiency and Conservation) include installed measures (e.g., products, equipment, systems, services, practices, and strategies) on end-use customer facilities that result in additional and verifiable reductions in the total amount of electrical energy used during on-peak hours. Active demand resources are based on the CSOs obtained through ISO-NE’s FCM three years in advance. The CSOs decrease slightly from 1,167 MW in 2015 to 944 MW in 2016 and then increase to 994 MW in 2017. Since there are no further auction results, the CSOs are assumed to remain at the same level through the end of the reporting period.DSM2- Briefly explain how Energy Efficiency and Conservation are measured and accounted for. Highlight changes and trends from prior years.ISO-NE has developed an Energy Efficiency forecasting methodology that takes into account the potential impact of growing Energy Efficiency and Conservation initiatives in the Region to project the amount of Energy Efficiency beyond the years when the FCM CSOs have already been procured. Energy Efficiency has generally been increasing and is projected to continue growing throughout the study period. The amount of Energy Efficiency in 2015 is 1,685 MW, and is projected to increase to nearly 3,500 MW by 2024.Distributed Energy Resources (DERs) Forecast and Impact on DemandDER1- What is the estimated penetration forecast for DER in the 5 Year horizon? 10 Year? Detail how DERs are accounted for and integrated into planning. Provide any references or applicable reports/documentation for how DERs are monitored and reported Highlight any modifications made to these methods or assumptions since the 2019 LTRA.Highlight any additional challenges highlighted by Planning Coordinators and Transmission Planners in the Assessment Area.The data requested in the LTRA data form is for embedded BTM solar PV (not all types of DER). Discuss trends and demand impacts (observed or anticipated) related to the BTM solar PV in the assessment area, and any other comments you believe are appropriate related to the BTM solar PV data you provided in the LTRA data form.Example response: This question is intended to provide information regarding the extent of DER penetration and its reporting. GenerationG1 - Detail any recent or projected capacity additions in the assessment area that are part of a planning strategy to mitigate resource adequacy issues. Example response: “The results from the assessment area’s reliability study showed a projected resource deficiency in the first five years of the assessment period. As detailed further in the study (hyperlink), there were multiple projects that could be advanced that would mitigate this resource adequacy concern. Additional details are…”G2 - Describe planning considerations and activities underway to address potential operational issues due to the changing resource mix.Discuss the impacts of renewable portfolio standards (RPS) or other similar state, and provincial mandates. Include whether these standards or mandates have been met. If not, estimate how much capacity, by state, is needed (in megawatts) and by when. Identify the specifics of the generation type (e.g. wind, solar, energy storage, additional natural gas capacity) associated with these potential operational issues. Example response: “Studies of (recently introduced regulation) have shown the assessment area will need to install an additional 5 GW of renewable generation by 2030; (hyperlink to study). Resource Planners have identified that a multi-phased approach of 0.5 GW projects over the next 10 years would be done to both meet the targets specified by the RPS and allow sufficient time to monitor any operational impacts. There have been no operational issues identified from performance data but there have been observable trends to decreasing system frequency response and steeper ramping during peak hours (additional details – link to study). Projected generation additions provided by resource planners will be coordinated with transmission planners through (joint effort/committee) to better evaluate the potential exacerbation of these observed trends…”G3 - Describe all methods and assumptions used to assign capacity contribution values for Variable Energy Resources (wind, solar, and hydro). Response should include: The methods used to calculate on-peak capacity contributions for Tier 1, Tier 2, and Tier 3. If they are not the same, expand on the differences between these calculations. Highlight any modifications made to these methods or assumptions since the 2019 LTRA.Example response: “The assessment area uses a 5 year rolling average of performance data to calculate the expected on-peak capacity contribution of all wind and utility-scale solar generation. These methods for calculating and the results are further explained in (intra-area study on variable energy resources)-(hyperlink). This methodology has not changed since the 2019 LTRA but the results have changed from 25% to 28% for wind and from 15% to 10% for solar.”G4 - How are any potential operational impacts of Distribute Energy Resources studied/monitored in the assessment area? Include considerations for non-peak ramping and/or effects of DERs on light-load conditionsProvide references or applicable reports/documentation on operating experiences/challenges related to DERs. How have these been incorporated into planning studies?Highlight any additional challenges highlighted by Reliability Coordinators and Balancing Authorities in the Assessment Area.Example response: “The assessment area monitors the current installed capacity of rooftop photovoltaic through (specific shared data program) with (relevant party). This data is received and reviewed annually. While there are a moderate capacity of DERs installed, they are evenly distributed across the assessment area’s footprint. A high-level screening analysis is performed to assess any potential impacts on ramping effects during light load conditions and across the system peak hour. The details and results of this high-level screening can be found at (hyperlink) and are summarized here…”G5 - Describe any studies conducted by your area to identify risks as a result of growth in inverter based resources. Have these studies identified any additional ancillary service or protection and control remedial action potential or actual needs for the first five-year period? Describe any actions taken to address these risks, if applicable. Coordinate with other groups as needed for a response (e.g., interconnection or multi-regional study group). Be clear on what aspect of reliability (e.g., resource adequacy versus network impact, ancillary services) is most challenged by inverter risks.G6 - Provide details on any severe retirement scenario(s) defined for resource adequacy or transmission adequacy studies conducted by the region or assessment area(s). Include considerations for:Any current or pending regulatory requirements.Requisite transmission additions or reinforcements.Impacts to reliability.Example response: “The most recent transmission adequacy study (optionally provided to NERC if non-public information and not to be distributed) indicated that under a specific generation retirement scenario that transmission in multiple zones would be insufficient to serve load. The publically available details of this scenario and impacts are… Mitigations strategies that would be necessary to guarantee resource deliverability would include…”G7 - Summarize changes to confirmed and unconfirmed retirements since the 2019 LTRA. Responses should include: How unit retirements are projected in the assessment area. Descriptions of all applicable generation types (e.g. Coal, Petroleum, Natural Gas, Nuclear).The main driver behind the retirement (e.g. end of lifespan, economic, environmental regulations).Explanation on any resulting adverse reliability impacts during the assessment period. G8 - List generating units that are returning from mothball to active status. Include additional detail if:The unit is returning to service as a plan to mitigate a resource adequacy concern or reliability risk.G9 - Provide details regarding known outages that may be extended through a peak season.Describe the generator including its size and reason for extended outage.Explain any resulting adverse reliability impacts or potential issues. Explain how these impacts will be managed by both Operations Planning and Long-Term Planning.G10 - How are natural gas limitations considered in long-term planning studies? Include considerations for: Normal load and extreme winter forecastsSeasonalityProjected gas-fired capacity additionsPotential derate of generation capacity to reflect potential limitationsG11- Provide information on how impacts to reliability from retirements are assessed and what actions are taken to mitigate reliability concerns (do not include specific operational plans, but rather explain how resource planning and operations will manage each specific occurrence).Highlight any modifications made to these methods or assumptions since the prior LTRA.Energy StorageES1- How are potential operational impacts of electricity storage (ES) studied/monitored in the assessment area? How much capacity is expected over the next five years? Next ten years?What are the prevalent uses for the expected electricity storage? (e.g., Economic vs reliability operation, peak shaving, frequency response)Detail how ESs are accounted for and integrated into planning. Load and/or generator?Provide references or applicable reports/documentation on operating experiences/challenges related to ES. How have these been incorporated into planning studies—both powerflow, dynamics, and resource adequacy?Highlight any additional challenges highlighted by Reliability Coordinators and Balancing Authorities in the Assessment Area.Highlight any modifications made to these methods or assumptions since the 2019 LTRA.Capacity Transfers CT1- Explain a severe scenario from planning studies whereby the capacity transfers would be limited and impact reliability. Also, list the actions or coordination that would be needed to mitigate the reliability impacts from this scenario.Example response: “The most recent resource adequacy study (optionally provided to NERC if non-public information and not to be distributed) indicated that under a specific scenario where import capability would be limited (provide additional details of scenario) and create a resource deficiency. The publically available details of this scenario and impacts are… Mitigations strategies that would be necessary to guarantee resource deliverability would include…”CT2- Based on projected changes to the resource mix, what are the expected impacts to capacity transfers (e.g. new directional flows, impacts of retirements or additions on firm or future contracts)?Example response: “The most recent resource adequacy study performed by the assessment area (hyperlink to study) includes resource projections outwards for 2, 4, and 6 years. The projected additions and retirements are expected to re-direct required on-peak capacity support from the northern tie-line to the southern tie-line by year 6. This is due to changes in (provided non-market sensitive information) and supported by the neighboring assessment areas own resource adequacy study (hyperlink)…”CT3- What coordinated efforts/studies/protocols have been developed for on-peak capacity transfers with neighboring assessment areas? Discuss assumptions on projections from short term commitments to the full ten year period.Outline the methods and assumptions for this coordination, especially to prevent double counting.Detail any future plans to enhance this coordination. Highlight any modifications made to these methods or assumptions since the 2019 LTRA.TransmissionT1- Summarize any major transmission projects that impact or are needed to maintain reliability, including:New transmission lines (including HVdc)Reconductor projectsPower electronic devices (SVC, FACTS controllers, synchrophasors, etc.)Delays of current projectsExample: There are several transmission projects projected to come on line during the assessment period that are important to the continuation of, or enhancement to, system or subarea reliability. These projects are the results of progress made by the ISO and regional stakeholders in analyzing the transmission system in New England and developing and implementing back-stop solutions to address existing and projected transmission system needs. The major projects under development in New England include the Maine Power Reliability Program (MPRP) and the New England East–West Solution (NEEWS). The new paths that are part of MPRP, many components of which are under construction, will provide the basic infrastructure necessary to increase the ability to move power from New Hampshire into Maine and improve the ability of Maine’s transmission system to move power into the local load pockets as necessary. NEEWS consists of a series of projects that will improve system reliability in areas including Springfield, Massachusetts, and Rhode Island, and increase total transfer capability across the New England east-to-west and west-to-east interfaces.T2- Describe transmission limitations or transmission constrained areas identified by transmission planning studies. Provide additional information for:Reliability impacts to planning and operations (including resource adequacy) within the assessment period.Summarize the plans to mitigate identified impacts to reliability.Are Tier 2 and Tier 2 capacity additions considered in the assessment area’s transmission plans? Briefly explain.Example: In 2013, an Operations Reliability Coordination Agreement (ORCA) was introduced to mitigate any potential reliability impacts associated with changing MISO market dispatch patterns on the neighboring systems. Starting the summer of 2014, MISO has implemented a MISO South to MISO North transfer limit of 1000 MW contract path until certain regulatory issues pending at FERC are addressed. This 1000 MW limit is below the 2000 limit in ORCA and for now should address the reliability concerns of neighboring systems. MISO and the neighboring systems continue to explore other reliability processes such as Congestion Management Process (CMP) and TLR to mitigate any adverse impacts on system reliability. MISO is also assessing options to expand the contract path capacity between MISO South and North through transmission enhancements. This could address all reliability concerns of neighboring systems.T3- Summarize the extent, findings, and conclusions of NERC TPL studies on “Steady State & Stability Performance Extreme Events” (Table 1 of NERC Reliability Standard TPL-001-4). Generally describe and assess the extreme events that were evaluated (steady state and stability), particularly: Loss of two generating stations resulting from conditions such as: Loss of a large gas pipeline into a region or multiple regions that have significant gas-fired generationLoss of the use of a large body of water as the cooling source for generationWildfiresSevere weather, e.g., hurricanes, tornadoes, etc. A successful cyber attackShutdown of a nuclear power plant(s) and related facilities for a day or more for common causes such as problems with similarly designed plants. Other events based upon operating experience that may result in wide area disturbances.If analyses concluded that there was a cascading outage caused by the occurrences of extreme events, what plans and coordination efforts were designed to mitigate the consequences or adverse impacts of the event?Note: NERC would not publically disclose transmission information. This question is to understand the impacts from the severe event and the coordination efforts to mitigate the impacts.T4- Describe any changes in the UVLS/UFLS protection schemes due to changes in resource mix since the prior LTRA. Example: There are plans to install additional UVLS equipment in the Nashville area in the near term planning time horizon. The amount of non-coincident peak load to be included in the scheme is still under study.SERC entities do not anticipate a need for UVLS programs necessary to maintain reliability during the long term planning horizon but do have UVLS procedures in place as a backup mechanism for maintaining reliability. SERC entities have not identified the need for additional UVLS equipment in the long term planning horizon.T5- Describe how reliability impacts are assessed for each of the following:Transmission limitationsTransmission constraintsDynamic and steady state reactive-power limited areasUnder voltage load shedding Under frequency load shedding Remedial Action SchemesShort-Circuit (include tie-line coordination efforts)T6- How are transmission-distribution links (interface) (sub-100 kV facilities) currently included within transmission planning studies?Are there future plans to include select links within these studies? Reliability IssuesRI1- Summarize the results and any identified reliability concerns of a recent extreme weather event planning study. Example: PJM has adopted a Loss of Load Expectation (LOLE) standard of one occurrence in ten years and performs an annual LOLE study to determine the reserve margin required to satisfy this criterion. The study recognizes, among other factors, load forecast uncertainty due to both economics and weather, generator unavailability, deliverability of resources to load, and the benefit of interconnection with neighboring systems. The weather assumptions and resulting load forecast includes the associated probability of extreme weather in its distribution. The methods and modeling assumptions used in this study are available in PJM Manual 20 at the following link: RI2- Describe any other reliability issues not addressed above that are unique to the assessment area. Include those that are in the initial stages of study and require additional attention. Include details regarding the drivers, likelihood of impact, and a timeframe for each issue. Include any impacts to resource adequacy during off-peak hours and shoulder periods.Describe the planning methods or assumptions in response to extreme weather events (drought, cold-snap, etc.).Example: The merger of Entergy and SMEPA into the MISO Balancing Authority Areas has created new unscheduled flows across the TVA system, AECI, and Southern Balancing Authority Area. An Operations Reliability Coordination Agreement (ORCA) has been put into place with MISO to mitigate any potential reliability impacts associated with these unscheduled flows thereby enhancing the reliability of the affected area. The topology of the MISO system creates a unique challenge to these coordination efforts and the unknown overall impact of these flows. Other reliability processes such as Congestion Management Process (CMP) and TLR will be utilized to mitigate any adverse impacts on system reliability. Another potential emerging issue is that very long HVDC lines are being considered by independent transmission developers in economic projects such as shipping wind to the southeast. The capacity of a single line is typically greater than the largest single contingency generation loss in a system. The capacity of two poles will probably be larger than that of the largest multi-unit generating plant. On very long lines, the risk of losing both poles may be appreciable, and that plus the high power level could impact reliability. An emerging issue may be the ability of present study criteria to adequately model the impact of these lines on a system.Also, due to the current tax subsidies in North Carolina, a large number of solar QFs have been requested in the transmission queue. These projects create uncertainty in planning for various reasons including the uncertainty of the projects actually coming to fruition (i.e. the Companies being able to rely on the capacity/generation from these facilities) and the intermittent nature of solar.RI3- Explain the long-term mitigation strategies for any adverse reliability impacts (e.g., resource adequacy, planning or operational impacts, etc.) resulting from fuel supply and/or fuel deliverability constraints.Highlight any modifications made to these methods or assumptions since the prior LTRA.Based on past performance, how sensitive are natural gas-fired resources to extreme winter weather events? The following should be considered and reported:The amount (MW) of natural gas-fired capacity that was simultaneously forced out of service during the last five years.The estimated amount of firm vs. non-firm gas capacity. Specify a range, when appropriate.The percentage of the assessment area’s natural gas-fired generation fleet, with dual-fuel capability and has maintained at least 1 day of oil/distillate inventory during the winter season.Narrative (to be included in the 2020 LTRA)Provide a brief narrative including appropriate information based on the responses above. ................
................

In order to avoid copyright disputes, this page is only a partial summary.

Google Online Preview   Download