Non-RTO/ISO Reporting Requirements

5

Docket No. AD12-8-000

Performance Metric		Specific Metric(s)
Reliability
A.	National or Regional Reliability Standards Compliance	1. References to which Electricity Reliability Organization (ERO) and Regional Reliability Organization (RRO) standards are applicable 2. Number of violations self-reported and made public by NERC/FERC 3. Number of violations identified and made public as RRO or ERO audit findings 4. Total number of violations made public by NERC/FERC 5. Severity level of each violation made public by NERC/FERC 6. Compliance with operating reserve standards 7. Unserved energy (or load shedding) caused by violations. Additional detail will be provided on (1) number of events; (2) duration of the events; (3) whether the events occurred during on/off-peak hours; (4) additional information on equipment types affected and kV of lines affected; and (5) number of events (and severity and duration of events) resulting in load shedding based on the utilization of TPL-002 Footnote b criteria. Items 2-7: Track the ISO/RTO definition: “This metric is a quantification of all NERC and RRO Reliability Standards violations that have been identified during an audit or as a result of an ISO/RTO self-report and have been published as part of that process.” Non –ISO/RTO utilities should limit reporting to the same eight functional areas used by the ISO/RTOs: 1. Balancing Authority 2. Interchange Authority 3. Planning Authority 4. Reliability Coordinator 5. Resource Planner 6. Transmission Operator 7. Transmission Planner 8. Transmission Service Provider
B.	Dispatch Reliability	1. Balance Authority Ace Limit (BAAL) OR// CPS1 and CPS2 2. Number of hours of transmission load reliefs (of severity level 3 or higher) called by the incumbent transmission provider or unscheduled flows WECC entities will report events under the WECC Unscheduled Flow Mitigation Procedure (equivalent to the NERC TLR Level three). 3. Energy Management System (EMS) availability
C.	Operational Planning – Load Forecast Accuracy	Actual peak load as a percentage variance from forecasted peak load as reported in OASIS.
D.	Wind Forecasting Accuracy	Actual wind availability compared to forecasted wind availability
E.	Unscheduled Flows	Difference between net actual interchange (actual measured power flow in real time) and the net scheduled interchange in megawatt hours Reported in Form 714
F.	Transmission Outage Coordination	1. Percentage of ≥ 200 kV planned outages of 5 days or more for which utility notified customers at least 1 month prior to the outage commencement date. 2. Percentage of ≥ 200kV outages cancelled by utility after having been previously approved. 3. Report information posted on OASIS (percentage of outages, planned and unplanned, with less than 2 days notice).
G.	Long-Term Reliability Planning – Transmission	Dollar amount and number of facilities approved to be constructed for reliability purposes 2. Percentage of approved construction on schedule and completed 3. Performance of planning process related to: a. Requests for and number of completed reliability studies b. Requests and number of completed economic studies Discussion of stakeholder process and identification of stakeholder groups participating
H.	Long-Term Reliability Planning – Resources	1. Processing time for generation interconnection requests 2. Actual reserve margins compared with planned reserve margins 3. Explanation of the nature and characteristics of demand response programs and how they are used in system planning. Discussion of programs to facilitate the integration of renewable resources and to mitigate any issues and uncertainty associated with scheduling renewable resources
I.	Infrastructure Investment – Interconnection and Transmission Process Metrics	1. Number of requests 2. Number of studies completed 3. Average age of incomplete studies 4. Average time for completed studies 5. Total cost and types of studies completed (e.g., feasibility study, system impact study and facility study) 6. Number of transmission access denials/transmission service requests (TSRs) denied
J.	Special Protection Systems	1. Number of special protection systems Percentage of special protection systems that responded as designed when activated Applicable pool of special protection systems should be based on how the reporting entity’s Regional Entity defines “special protection systems” 3. Number of unintended activations

System Operations Measures
A.	Demand Response	Comprehensive explanation of the nature of utility demand response programs implemented for load management as well as in compliance with state requirements.
B.	System Lambda	System Lambda (on marginal unit) Proposed System Lambda metric would not apply to utilities where the marginal price is typically set by hydro units System lambda data will be based on Form 714 information.
C.	Congestion Management	Congestion analysis per Order No. 890
D.	Resource Availability	1 - System forced outage rate as measured over 12 months
E.	Transmission System Availability	Interrupted load megawatt hours as a percentage of load served
F.	Fuel Diversity	Fuel diversity in terms of energy, installed capacity and actual production
G.	Clean Energy	1. Clean Energy megawatt hours, by resource type, as a percentage of total energy 2. Clean Energy megawatts, by resource type, as a percentage of total capacity
Organizational Effectiveness
	Not applicable to non-RTO entities