Downstream Impacts and Considerations of FERC Order 881

ryanquint
May 4
4 min read

Authors:

Jiecheng Zhao, Senior Engineer

Nick Giffin, Lead Engineer

Kyle Thomas, VP of Engineering and Compliance Services

Power lines outside Palm Springs, CA [Source: Elijah Ekdahl]

FERC Order 881, with an implementation deadline of July 12, 2025, requires all transmission providers to implement ambient-adjusted ratings (AARs) and seasonal ratings. Unlike static ratings, AARs adjust transmission line ratings at least hourly based on forecasted ambient air temperature and day/night cycles. This dynamic rating approach is expected to increase system transfer capability and reduce operational costs under most conditions, while maintaining system safety and reliability, especially during extreme weather events when actual temperatures may exceed assumptions used in static or seasonal ratings. Order 881 mandates the use of AARs for both normal and emergency ratings in near-term transmission service evaluations and requires at least four seasonal ratings for long-term operational planning.

As these ratings transition from static or seasonal values to hourly updates, numerous downstream impacts on system procedures and tools must be considered. While updates of the transmission line ratings in EMS/SCADA are expected, several other critical areas require attention:

1. Transmission Protection

Remedial Action Schemes (RAS)

One often-overlooked area is Remedial Action Schemes (RAS), special protection schemes that automatically take corrective actions under predefined system conditions to maintain reliability. RAS may be used in both the transmission planning and generation interconnection processes to increase utilization of the existing grid.

With the implementation of AARs, any RAS originally designed using static or seasonal ratings could trigger unnecessary actions (e.g., generation curtailment, load adjustments, or reconfigurations) when power flow exceeds those outdated limits but remains within the AAR. This can reduce system efficiency and increase costs.

A RAS designed to protect a transmission line from overloading should not become the barrier of fully utilizing a transmission line’s transfer capability as determined by AAR. Conversely, the increased transfer capability enabled by AARs may introduce new system stability concerns, which could necessitate the design and implementation of new RAS.

To ensure reliability and efficiency, RAS configurations should be thoroughly re-evaluated and updated, as required under NERC PRC-012. Changes in transfer limits and power flow patterns resulting from AAR implementation may justify disabling outdated RAS or introducing new schemes tailored to AAR-based system behavior.

Relay Loadability

Similarly, transmission relay settings must be reassessed. NERC PRC-023 requires that transmission protective relays do not unnecessarily limit line loadability. When actual temperatures are lower than those assumed in static or seasonal calculations, enabling a higher AAR, relay settings may need to be re-evaluated to ensure they don’t restrict permissible power flow under AAR conditions.

2. Operational Modeling and Planning

Contingency Planning and Dynamic Choke Points

AAR implementation changes how equipment bottlenecks ("choke points") are identified. Since each component along a line (e.g., conductors, breakers, CTs) has its own temperature-rating curve, the limiting element can vary with ambient temperature. If a component fails (e.g., a breaker failure) and its function is executed by a lower-rated backup, this can cause dynamic derating that must be reflected in contingency models.

Operational studies and contingency files should be updated to evaluate AAR-based ratings for each element, including backup equipment. This will improve the accuracy of near-term operational transmission planning and help prevent unanticipated overloads.

Outage Coordination

Outage scheduling (including blackstart procedures) often assumes conservative, worst-case ratings. AARs provide flexibility to shift outage windows or approve additional outages, particularly during cooler periods. For example, using AARs may allow increased power transfer capability in the Fall versus Summer noon peaks, thus enabling more strategic outage timing. AARs may also provide more flexibility in scheduling urgent and emergency outages during cooler than normal periods.

Outage coordination tools should be upgraded to support variable ratings, and processes should reflect this adaptability. Tools should provide guidance on risk from AARs. This may include risks that an outage is canceled or identification of a reliability risk should an AAR be lower than anticipated.

3. Record Maintenance

Accurate facility rating records are essential and required by NERC FAC-008. Because line ratings depend on the lowest-rated component, including CTs and secondary devices like relays and meters, any equipment replacement must be followed by updates to:

As-built drawings
Facility rating databases
System models
Notifications to ISOs/RTOs and adjacent transmission owners (for tie-lines)

4. Forecasting and Uncertainty Management

AARs rely on forecasted ambient conditions and forecast inaccuracies can impact operation decisions and reliability. This is especially true for long transmission lines that span diverse climates.

Operators must understand and accommodate forecast error margins to avoid overloading facilities. Sensors that track equipment temperature and line sag in real time can help identify forecast deviations and trigger corrective actions.

Under conditions of high forecast uncertainty, such as extreme weather events, a fallback to more conservative ratings should be available to protect infrastructure and reduce the risk of extended outages.

5. Training and Awareness

Widespread AAR adoption introduces new operational complexities that require comprehensive training. System operators, planners, and external stakeholders must understand how AARs affect:

Real-time system operations
Planning and outage coordination
Protection schemes and contingency analysis

Training materials and certification modules should be updated to reflect FERC Order 881 compliance requirements and best engineering practices.

Conclusion

FERC Order 881 represents a paradigm shift in how transmission capacity is evaluated and utilized. While the direct benefits of AARs are clear—increased efficiency, reduced congestion, and better use of existing infrastructure – the indirect impacts span protection systems, planning tools, coordination procedures, and operator training. Thorough evaluation and adaptation of these downstream elements are essential to fully realize the potential of dynamic line ratings.

Let’s keep the conversation going...

As utilities, grid operators, and stakeholders prepare for FERC Order 881, it's critical to think beyond compliance and consider the downstream operational and planning impacts AAR may have. If you're navigating these challenges or exploring how to adapt your tools, procedures, or protection schemes, we’d welcome the opportunity to connect, exchange ideas, and lend support.

Feel free to reach out to our team of experts (info@elevate.energy) and check a little more about us here. We’re always interested in thoughtful conversations that move the industry forward!