Solar Curtailment and AGC for Utility-Scale Solar Plants

May 16, 2026REIG Solar Technical Team

Key Takeaways

CAISO curtailed 3.4 million megawatt-hours of wind and solar in 2024, a 29 percent jump from 2023, with solar making up 93 percent of the total per the U.S. Energy Information Administration.
Solar curtailment shows up as a four-second AGC setpoint at the point of interconnection, and the plant controller has to ramp linearly between targets without exceeding interconnection-defined ramp limits.
NERC PRC-029-1 takes effect in 2026 and requires inverter-based resources to ride through 56 to 64 hertz for six seconds with a 5 hertz per second Rate of Change of Frequency (ROCOF) tolerance per NERC.
IEEE 2800-2022 defines uniform transmission-connected IBR requirements for active power, reactive power, and fast voltage support that curtailment logic must respect, per IEEE Standards.
The seven AGC failure modes most often missed during commissioning are setpoint scaling errors, missing loss-of-comms failsafe, reactive coordination drift, ramp-rate divergence between PPC and inverters, dead-time exceeding the audit window, telemetry latency assumed instead of measured, and curtailment vs ride-through events confused in alarm logic.

Solar curtailment never comes with an explanation. The ISO sends a setpoint, and the plant has four seconds to respond. So the response is what the audit reads twelve months later when settlement disputes show up.

Most utility-scale solar teams already know that solar curtailment is rising. In fact, CAISO crossed 3.4 terawatt-hours of wind and solar curtailment in 2024, with solar at 93 percent of the total, per the U.S. Energy Information Administration. ERCOT is climbing the same curve from a smaller base, with utility-scale solar curtailment projected to reach 19 percent by 2035 against 9 percent in 2022, per EIA Today in Energy. The macro story is well covered. The story we want to focus on here is the part that lands inside the plant: how a solar curtailment instruction travels from ISO to inverter, what gets logged, what gets audited, and which failure modes show up at the Factory Acceptance Test (FAT) and Site Acceptance Test (SAT).

This post is for project managers, commissioning leads, SCADA engineers, and O&M teams who need their AGC participation to be defensible from day one.

How Solar Curtailment and AGC Connect at the Plant Level

Solar curtailment is an instructed reduction in active power output. The plant could deliver more. Yet it is being told not to. Automatic Generation Control, or AGC, is the mechanism that delivers that instruction in real time, four seconds at a time, over the same telemetry channel the plant uses to report its actual output back.

The two are not the same thing. Solar curtailment is the policy decision: economic dispatch, transmission congestion, voltage stability, ride-through. AGC is the transport. So a plant can be curtailed without AGC if the operator schedules a manual setpoint at a market interval. A plant can also be on AGC and never receive a solar curtailment instruction, because the setpoint always tracks available output.

The reason this distinction matters during commissioning is that the alarm logic, the historian schema, and the witness pack are different for each case. A scheduled solar curtailment is a slow event with audit trails measured in minutes. An AGC-driven solar curtailment is a tight loop measured in seconds. As a result, conflating them in the alarm rationalization spreadsheet is one of the most common reasons a plant ships with "online but wrong" dispatch behavior.

Setpoint Path: How a 4-Second AGC Signal Reaches the Inverter

CAISO sends a direct megawatt setpoint to participating units every four seconds, per the CAISO AGC Requirements and Telemetry document. The setpoint increments linearly from the starting value to the target across one or more four-second intervals, governed by an agreed ramp rate. ERCOT runs Security-Constrained Economic Dispatch on a five-minute cadence with AGC overlaying for frequency response. The transport protocol is typically ICCP for the ISO link, with DNP3 or Modbus TCP carrying the same signal from the plant gateway down to the Power Plant Controller.

The chain looks straightforward on a diagram. In the field it has six places to fail.

First is the ISO-side mapping. The setpoint is a number with a unit, and the unit can be megawatts, per-unit normalized to plant nameplate, or a percentage of available output depending on the Balancing Authority (BA). In practice, every commissioning team that has worked across more than two ISOs has at least one project where the setpoint was scaled wrong by a factor of ten on the first FAT day.

Second is the plant gateway. ICCP-to-DNP3 conversion at the substation gateway introduces between 0.5 and 2 seconds of latency in well-tuned systems, more in legacy installations. So if the gateway timestamps the message at receipt instead of at the ISO emit time, the historian record looks compliant when the actual response was late.

Third is the PPC. The Power Plant Controller has to translate the setpoint into per-block targets, applying the active ramp limit, reactive priority, and any voltage-droop trim. As a result, mis-tuned PPC ramp rates that disagree with the inverters' own ramp settings show up as oscillation around the setpoint instead of clean linear tracking.

Fourth is the inverter. Inverter-level response is fast, milliseconds rather than seconds. The constraint is rarely the silicon. Instead, it is the configuration: enabled modes, override flags, power factor coordination, reactive priority that fights active priority during a solar curtailment.

Fifth is the telemetry return. Real-time MW, MVAR, voltage, and frequency at the point of interconnection have to land back at the ISO with timestamps that align to the same four-second clock. Still, NTP drift on the gateway clock turns a clean response into a phantom violation in the audit log.

Sixth is the historian. Sampling rates below one sample per second alias the response. For example, a plant that ramped cleanly across a four-second AGC tick can look like it overshot or undershot when the historian compresses the response into a thirty-second average. Therefore, that sampling decision is made on day one of system design and is expensive to change after commercial operation date (COD).

Solar Curtailment by ISO: 2024 Numbers and What Drives Them

The macro picture in 2024 was the largest annual solar curtailment increase CAISO has ever recorded. The drivers are not symmetric across regions, which matters when an EPC is designing a plant for one ISO and signing PPAs that route across another.

In CAISO, oversupply during spring midday hours dominates. Solar output peaks while load is moderate, demand-side reduction is limited, and the grid hits a soft ceiling on what neighboring balancing authorities will accept through the Western Energy Imbalance Market (WEIM, now operating alongside the Extended Day-Ahead Market under the 2024 EDAM expansion). In fact, the market took 274,000 MWh of would-be curtailment off the table in 2024, about 8 percent of the year's total, per EIA Today in Energy. Meanwhile, battery capacity in CAISO grew 45 percent in 2024 to 11.6 gigawatts. As a result, the batteries soak up shoulder-hour solar curtailment that used to spill.

ERCOT's primary driver is transmission congestion on coastal export interfaces. The system met 36 percent of demand with wind and solar combined in the first nine months of 2025, with solar generation up 50 percent year over year, per EIA. Also, the 2024 ERCOT Constraints and Needs report flags coastal wind curtailment as a transmission-driven event tied to the South Texas export interface, with similar exposure rising for solar in the lower Rio Grande Valley.

Solar accounted for 93 percent of the 2024 curtailment total in CAISO.

The pattern is consistent across regions: solar curtailment grows roughly twice as fast as the underlying capacity. That is the gap between deliverable hours and bid hours, and it is the operating metric that asset managers track against PPA economics. The curtailment-aware KPI framework we use during monitoring setup separates economic from reliability events on the same dashboard so the operator does not have to chase the cause through three different historians.

The Power Plant Controller's Role in AGC Execution

The PPC is the layer that turns ISO instructions into plant behavior. On a pure PV plant it tracks four setpoint priority modes: active power (P), reactive power (Q), voltage (V), and power factor (PF). Frequency response (F) is layered on as an autonomous primary response in jurisdictions that require it. Most plants run in P-priority during normal AGC dispatch, with Q-priority enforced during voltage events at the point of interconnection.

The arbitration logic between modes is where field surprises live. A reactive power command from the ISO that demands more MVAR than the inverters can deliver while holding active power at setpoint forces the PPC to choose. The choice has to be configured, witnessed, and logged. Default vendor logic that derates active power to satisfy reactive setpoint without telling SCADA is one of the most common reasons a plant misses its commercial obligations during the first month of post-COD operation.

For hybrid plants the layer underneath the PPC, the hybrid plant controller, has to split a single setpoint between PV inverter blocks and a battery bank with completely different response characteristics. The PV array responds in seconds with no memory. The BESS has to track state of charge, cycle count, and thermal limits across hours. The curtailment-specific behavior on a hybrid plant is a strict subset of that arbitration logic, and the witness pack treats hybrid setpoint splits as a separate test scope on top of the AGC tests below.

What ends up in the witness pack is a documented test of every priority mode under realistic field conditions, not benchtop simulation. That includes loss-of-comms behavior, ramp-rate divergence between PPC and inverters, and reactive coordination during a voltage transient. The point list for an AGC FAT typically runs 80 to 120 testable points on a 200 megawatt plant, and the SAT extends those tests against the live ISO link.

Solar Curtailment Causes: Economic, Reliability, Voltage, Export-Limit

The categories are not interchangeable. They have different audit windows, different settlement implications, and different SCADA logging requirements. The table below is the version we use during alarm rationalization on AGC-participating plants.

Category	Trigger	Cadence	Settlement implication
Economic	Oversupply, low LMP, negative pricing window	Real-time market, 5 to 15 min	Plant typically delivers, paid cleared price (often near zero or negative)
Reliability	Transmission overload, contingency analysis result	4-second AGC override	Typically uncompensated under tariff; may trigger PPA force-majeure language
Voltage stability	Voltage out of band at POI, reactive-power exhaustion upstream	Continuous, V-priority mode	Often unmetered; logged as derate, not curtailment
Export-limit	Interconnection agreement cap (e.g., 200 MW on a 240 MW plant)	Continuous, hard limit at PPC	Pre-negotiated; appears as flat-top, not as event
Ride-through residual	Frequency or voltage excursion forces inverter mode change	Subsecond, autonomous	NERC-reportable under PRC-029-1; six-second window

Voltage-driven solar curtailment in particular is where IEEE 1547-2018 smart inverter modes earn their keep. For example, Volt-VAR, Volt-Watt, and Frequency-Watt curves let the inverter trim active or reactive output autonomously to support voltage at the local terminal, per NREL's Highlights of IEEE 1547-2018 Implementation Considerations. Those curves are configured at commissioning, yet they are not visible to the SCADA operator unless the engineer who configured them also exposed the curve parameters as historian tags. In practice, that second step is forgotten on roughly a third of the projects we audit. The result: the curve fires correctly during a voltage event, the plant data acquisition system records the resulting active-power dip, and nobody can tell the operator whether the dip was a solar curtailment, a derate, or a fault response.

This is a Measurement, Meaning, Control problem. Measurement is the active-power tag at the inverter. Meaning is the categorical label (economic, reliability, voltage, export-limit, ride-through). Control is the response that produced the dip. Without all three, the post-event review collapses into guessing.

NERC PRC-029-1, IEEE 2800-2022, and FERC Order 901: Compliance Stakes

The regulatory layer hardened in 2024 and continues hardening through 2030. Three documents define the compliance envelope for AGC participation and curtailment behavior on transmission-connected solar plants today.

NERC PRC-029-1 replaces the older PRC-024-3 with an IBR-specific ride-through standard. Frequency: 56 to 64 hertz for 6 seconds of continuous operation, 5 hertz per second ROCOF. Voltage envelopes are tightened against the older standard. Tripping inside this window is a violation. The cutover is 2026, and the implementation plan is documented at NERC. SCADA implication: ride-through events have to be timestamped at one-second resolution or finer, and the alarm logic has to distinguish a ride-through from a curtailment.

IEEE 2800-2022 is the transmission-side bookend. It defines uniform technical minimum requirements for IBR active power control, reactive power control, fast voltage support, negative-sequence current injection, and protection coordination, per IEEE Standards Association. It does not change AGC mechanics directly. It sets the floor below which inverter and PPC behavior cannot fall regardless of regional rules.

FERC Order 901, issued October 2023, tasked NERC with a multi-year reliability standards program covering IBR data sharing, model validation, planning studies, and performance requirements. Milestone 1 standards filed November 4, 2024. Milestone 3 deadline November 4, 2025, full implementation by January 1, 2030, per FERC. Bulk Power System-connected IBRs that did not meet the prior BES definition register no later than May 2026 under the IBR Registration proceeding. Plants that already participate in AGC will have their model data and performance behavior re-evaluated under the new framework.

The practical effect on an AGC commissioning team is that the witness pack expands. The same FAT and SAT scope that was acceptable in 2022 needs additional ride-through verification, model validation evidence, and telemetry quality proof to satisfy the 2026 standards. None of that is impossible. All of it has to be planned at FAT scope-of-work signing, not discovered after SAT.

Solar Curtailment Failure Modes During AGC Commissioning

Seven failure modes account for most of the AGC findings we close out during witness testing. Each one has a fix. The fix is cheap before COD and expensive after.

A 1.5-second response lag turns clean linear tracking into an audit-flagged event.

1. Setpoint scaling errors. First, the setpoint comes in as megawatts in one ISO and as per-unit normalized to nameplate in another. A scaling factor configured for the wrong ISO results in a plant that responds at one-tenth or ten-times the intended level. Caught early in FAT with a known-good test signal, missed when the FAT plan assumes the scaling.

2. Loss-of-comms failsafe missing. Second, when the ISO link drops, the PPC has to default to a known state. Some plants default to last-good-setpoint, which holds active power at whatever was commanded right before the drop. Others default to available-output, which can spike production into a constraint that triggered the solar curtailment. Still others default to zero. In practice, the right default depends on the interconnection agreement, and the wrong default is a settlements problem.

3. Reactive power coordination drift. Third, reactive setpoints from the ISO have to play nicely with active setpoints. When they do not, the PPC arbitrates. Vendor defaults vary. For example, we have seen plants that derate active power by 8 percent during a sustained reactive demand without flagging the derate to the operator.

4. Ramp-rate divergence between PPC and inverters. Next, the PPC ramp limit is configured at the plant level. Inverters have their own ramp limits, often factory-set. When the two disagree, the response oscillates around the setpoint. So the oscillation looks like a control-loop instability in the historian, but the root cause is two configurations both trying to be authoritative.

5. Dead-time exceeding the audit window. Then every step in the chain (ISO emit, gateway receive, PPC process, inverter execute, telemetry return) has a dead time. Tariffs and ISO performance metrics define a maximum acceptable end-to-end response time. As a result, if the dead times sum past that limit, the plant is technically non-compliant during every dispatch event, and nobody noticed until the first quarterly review.

6. Telemetry latency assumed instead of measured. Also, most field teams know the round-trip latency of their ICCP link is around 200 to 800 milliseconds. Yet few have measured it on their actual plant during commissioning. In practice, a latency that drifts past one second under load shows up as setpoint follow-up violations that do not match the local PPC log.

7. Solar curtailment vs ride-through events confused in alarm logic. Finally, a ride-through event under PRC-029-1 looks superficially like a solar curtailment in the active-power signal. They are different categories with different settlement implications. Alarm logic that treats both as "low output event" loses the regulatory distinction. The first time it matters is when the Reliability Coordinator asks for a six-second timestamp envelope and the historian only resolves to thirty-second averages.

Where REIG Fits: Commissioning AGC for Curtailment-Ready Plants

REIG commissions AGC participation as part of the broader SCADA and DAS scope. The framework is the same one we apply to every utility-scale plant: Measurement, Meaning, Control. Measurement is the telemetry stack at the point of interconnection, validated end-to-end from device to historian against the ISO's expected performance envelope. Meaning is the alarm and event categorization that lets the operator distinguish economic curtailment from a ride-through residual without reading three logs in parallel. Control is the verified PPC behavior across every priority mode, witness-tested with utility presence where the interconnection agreement requires it.

The deliverable is a testable point list for AGC performance, a witness pack that maps every priority mode to a documented test case, and a historian schema that resolves the four-second AGC tick without aliasing. RenergyWare is the field-proven hardware platform we configure into the plant alongside the SCADA and DAS scope, sized for the AGC throughput the project requires from control-signal layer outward.

The objective is not just compliance. It is a plant whose AGC behavior is defensible from day one, with no rework after COD when settlement disputes or PRC-029-1 evidence requests land on the asset manager's desk. Commissioning-ready, end-to-end, on the day the plant goes live.

What Defensible Solar Curtailment Looks Like at COD

Solar curtailment is no longer a side effect to discuss in PPA renegotiations. It is a real-time control loop with a four-second cadence, a regulatory floor that hardens through 2030, and an audit trail that has to survive five years of settlement scrutiny. The plants that ship with clean AGC behavior do so because the witness pack assumed every failure mode listed above and tested against each one before COD. The plants that do not, pay the difference in unrecovered megawatt-hours and disputed performance metrics for the life of the asset.

Frequently Asked Questions

What is solar curtailment, and how is it different from a planned outage?

Solar curtailment is an instructed reduction in active power output from a utility-scale plant that is otherwise capable of generating more, issued by the system operator or balancing authority through an automated dispatch signal. A planned outage takes the plant offline for maintenance, with the asset class flagged unavailable in the market. Curtailment keeps the plant online, responsive, and metered, which means every curtailed megawatt-hour still has to be timestamped, reconciled with the dispatch instruction, and submitted for settlement. The control loop and the audit trail are different problems.

How fast does an Automatic Generation Control setpoint reach a solar plant?

CAISO and most North American balancing authorities send a direct megawatt setpoint to participating units every four seconds over an ICCP or DNP3 link, and the plant is expected to begin ramping within that interval. The setpoint increments linearly between the starting value and the target, with each successive update arriving on the same four-second tick. Inverter-level response is faster than the AGC signal cadence, so the binding constraint is rarely the inverters themselves. It is usually the round-trip path between the ISO, the plant controller, and the telemetry return.

What is the most common cause of solar curtailment in 2024 and 2025?

Economic curtailment from oversupply during low-load hours has been the dominant cause in CAISO and is rising fast in ERCOT. CAISO curtailed 3.4 million megawatt-hours of wind and solar combined in 2024, a 29 percent jump from 2023, with solar accounting for 93 percent of the total per the U.S. Energy Information Administration. Spring midday hours produce the bulk of the curtailment because demand is moderate and solar output is at its annual peak. Transmission congestion and voltage-driven curtailment are growing on coastal export interfaces in Texas.

Do solar plant owners get paid for curtailed energy?

It depends on the contract and the cause. Reliability-driven solar curtailment under a tariff or NERC standard is typically uncompensated. Economic curtailment in a real-time market often results in zero or negative locational marginal prices, which means the plant is paid the cleared price (sometimes negative) for any megawatt it actually delivers. Solar curtailment-payment provisions exist in some power purchase agreements and queued projects with deliverability rights. In practice, the dispute that lands on a SCADA team's desk is usually about whether the dispatch instruction was followed and at what timestamp resolution.

What does the Power Plant Controller do during an AGC curtailment instruction?

The Power Plant Controller, or PPC, takes the setpoint from the ISO and translates it into device-level commands. For a pure PV plant the PPC distributes active power across inverter blocks while respecting reactive power coordination, voltage at the point of interconnection, and any export limit imposed by the interconnection agreement. For a hybrid plant with battery storage, the PPC also arbitrates between curtailing the PV array and charging the battery. The witness pack for AGC commissioning has to verify each priority mode (P, Q, V, F, PF) under field conditions, not just on a benchtop simulator.

How do NERC PRC-029-1 and IEEE 2800-2022 affect curtailment behavior?

NERC PRC-029-1 requires inverter-based resources to ride through frequency excursions between 56 and 64 hertz for six seconds and to tolerate a Rate of Change of Frequency up to 5 hertz per second, with a 2026 cutover from PRC-024-3. IEEE 2800-2022 sets transmission-side performance requirements for active and reactive power control, fast voltage support, and negative-sequence current injection during faults. Curtailment logic that trips an inverter inside the ride-through envelope is a violation, not a safe shutdown. Settings, alarm masks, and historian sampling rates have to align with both documents before the witness pack closes.

Note: ISO market rules, ramp-rate limits, and ride-through envelopes vary by region. Confirm requirements against the most recent interconnection agreement and the applicable NERC standard before finalizing any AGC commissioning plan.

If you are scoping AGC participation for a new plant or auditing the dispatch behavior of an existing one, talk to the REIG team. We bring the testable point list, the witness pack, and the field-proven RenergyWare hardware that turns a four-second AGC tick into a defensible record. Explore RenergyWare or contact us to schedule a working session on your AGC scope.

References

U.S. Energy Information Administration. Solar and wind power curtailments are increasing in California. 2025. https://www.eia.gov/todayinenergy/detail.php?id=65364
NERC. PRC-029-1 Frequency and Voltage Ride-through Requirements for Inverter-Based Resources. 2024. https://www.nerc.com/standards/reliability-standards/prc/prc-029-1
IEEE Standards Association. IEEE 2800-2022: Standard for Interconnection and Interoperability of Inverter-Based Resources Interconnecting with Associated Transmission Electric Power Systems. 2022. https://standards.ieee.org/ieee/2800/10453/
FERC. FERC Approves Grid Reliability Standards Applicable to Inverter-Based Generators. 2024. https://www.ferc.gov/news-events/news/ferc-approves-grid-reliability-standards-applicable-inverter-based-generators
California Independent System Operator. AGC Requirements and Telemetry. https://www.caiso.com/Documents/AGCRequirements_Telemetry.pdf
NREL. Highlights of IEEE Standard 1547-2018 Implementation Considerations. 2021. https://docs.nrel.gov/docs/fy21osti/81028.pdf