To establish common criteria, based on “one day in ten year” loss of Load expectation principles, for the analysis, assessment and documentation of Resource Adequacy for Load in the ReliabilityFirst Corporation (RFC) region
Upon RFC Board approval
R1.1 Calculate a planning reserve margin that will result in the sum of the probabilities for loss of Load for the integrated peak hour for all days of each planning year1 analyzed (per R1.2) being equal to 0.1. (This is comparable to a “one day in 10 year” criterion).
R1.2 Be performed or verified separately for each of the following planning years:
R1.2.1 Perform an analysis for Year One.
R1.2.2 Perform an analysis or verification at a minimum for one year in the 2 through 5 year period and at a minimum one year in the 6 though 10 year period.
R18.104.22.168 If the analysis is verified, the verification must be supported by current or past studies for the same planning year.
R1.3 Include the following subject matter and documentation of its use:
R1.3.1 Load forecast characteristics:
- Median (50:50) forecast peak Load.
- Load forecast uncertainty (reflects variability in the Load forecast due to weather and regional economic forecasts).
- Load diversity.
- Seasonal Load variations.
- Daily demand modeling assumptions (firm, interruptible).
- Contractual arrangements concerning curtailable/Interruptible Demand.
R1.3.2 Resource characteristics:
- Historic resource performance and any projected changes
- Seasonal resource ratings
- Modeling assumptions of firm capacity purchases from and sales to entities outside the Planning Coordinator area.
- Resource planned outage schedules, deratings, and retirements.
- Modeling assumptions of intermittent and energy limited resource such as wind and cogeneration.
- Criteria for including planned resource additions in the analysis
R1.3.3 Transmission limitations that prevent the delivery of generation reserves
R1.3.4 Assistance from other interconnected systems including multi-area assessment considering Transmission limitations into the study area.
R1.4 Consider the following resource availability characteristics and document how and why they were included in the analysis or why they were not included:
- Availability and deliverability of fuel.
- Common mode outages that affect resource availability
- Environmental or regulatory restrictions of resource availability.
- Any other demand (Load) response programs not included in R1.3.1.
- Sensitivity to resource outage rates.
- Impacts of extreme weather/drought conditions that affect unit availability.
- Modeling assumptions for emergency operation procedures used to make reserves available.
- Market resources not committed to serving Load (uncommitted resources) within the Planning Coordinator area.
R1.6 Document that capacity resources are appropriately accounted for in its Resource Adequacy analysis
R2 The Planning Coordinator shall annually document the projected Load and resource capability, for each area or Transmission constrained sub-area identified in the Resource Adequacy analysis [Violation Risk Factor: Lower].
R2.1 This documentation shall cover each of the years in Year One through ten.
R2.2 This documentation shall include the planning reserve margin calculated per requirement R1.1 for each of the three years in the analysis.
R2.3 The documentation as specified per requirement R2.1 and R2.2 shall be publicly posted no later than 30 calendar days prior to the beginning of Year One.
M2 Each Planning Coordinator shall possess the documentation of its projected Load and resource capability, for each area or Transmission constrained sub-area identified in the Resource Adequacy analysis on an annual basis in accordance with R2.
- Resource Adequacy – the ability of supply-side and demand-side resources to meet the aggregate electrical demand (including losses).
- Net Internal Demand – Total of all end-use customer demand and electric system losses within specified metered boundaries, less Direct Control Load Management and Interruptible Demand.
- Peak Period – A period consisting of two (2) or more calendar months but less than seven (7) calendar months, which includes the period during which the responsible entity’s annual peak demand is expected to occur
- Year One – The planning year that begins with the upcoming annual Peak Period.
The following definitions were extracted from the February 12th, 2008 NERC Glossary of Terms:
- Direct Control Load Management – Demand-Side Management that is under the direct control of the system operator. DCLM may control the electric supply to individual appliances or equipment on customer premises. DCLM as defined here does not include Interruptible Demand.
- Facility – A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)
- Interruptible Demand – Demand that the end-use customer makes available to its Load-Serving Entity via contract or agreement for curtailment.
- Load – An end-use device or customer that receives power from the electric system.
- Transmission – An interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems.