Electric utilities have spent the last several years building out System Resiliency Plans, investing billions in grid hardening, vegetation management, and infrastructure modernization. The regulatory frameworks supporting those investments have been largely state-driven: Texas mandating SRPs through 2023 legislation, California requiring Wildfire Mitigation Plans, and a growing list of states following suit with their own filing requirements.
That landscape just shifted to the federal level.
In April 2026, NERC published its draft report, Reducing the Risk of Wildfire Ignition by the Bulk Power System, ahead of a May 1 FERC filing deadline. The report was mandated by FERC in September 2025, responding to Executive Order 14308, and it represents the most detailed federal roadmap yet for how utilities must manage, monitor, and document wildfire risk across their transmission networks.
For Investor-Owned Utilities already deep in SRP execution, this report does not introduce a fundamentally new concept. What it does is raise the bar—significantly—on what regulators, auditors, and insurers will expect in terms of documentation, transparency, and operational rigor. And for utilities still relying on fragmented, manual processes to build their compliance evidence, the window to modernize is narrowing fast.
But first, before I dive in: full disclosure. At Macedon Technologies, we help IOUs design and implement the kind of workflow orchestration that makes these documentation challenges manageable. Whether it is for rate case evidence, field compliance, or cost classification, our goal is to make your transition to automated, auditable planning fast and effective.
Here is a breakdown of what the NERC report actually means for your operations.
The headline recommendation in the NERC report is the proposed expansion of Reliability Standard FAC-003, the Transmission Vegetation Management standard, from its current applicability at 200 kV and above down to facilities rated 100 kV and above.
The data driving this recommendation is hard to argue with. According to the report, the 100–199 kV tier accounts for 43.5% of all wildfire-impacted transmission events and 86% of vegetation-contact outages. These are the lines most frequently causing problems, and they have been sitting outside the mandatory vegetation management framework since FAC-003 was created.
For many IOUs, this expansion could double or triple the circuit miles under formal vegetation management requirements. That is not a marginal compliance adjustment. It is a structural change in the scope of work that must be planned, executed, documented, and defended.
The realistic timeline for enforceable regulation is 2028 or 2029, given NERC’s standards development process and FERC’s approval cycle. But waiting for the rule to become mandatory would be a strategic mistake. Regulators are already watching what utilities do in the interim, and FERC has mandated biennial reporting through October 2034 to track progress. The utilities that move early will be the ones best positioned when the standard takes effect—and best positioned in the rate cases that precede it.
Beyond the FAC-003 expansion, the NERC report codifies a set of operational best practices that have been adopted by leading utilities but remain voluntary across the broader industry. These include disabling automatic reclosing on transmission lines in High Fire Risk Areas during elevated fire weather, prohibiting re-energization of tripped lines until field patrol is complete, conducting 72-hour advance Public Safety Power Shutoff assessments using wind speed and Fire Potential Index data, and performing vegetation removal at least twice per year in defined high-risk areas.
The report also explicitly endorses technology adoption as a best practice: LiDAR, satellite imagery, AI-driven vegetation proximity modeling, dynamic line rating sensors, and high-definition camera networks.
None of these are mandatory today. But the NERC report is clearly designed to inform future rulemaking. When these practices become the baseline expectation—whether through formal standards or through regulatory scrutiny during rate case proceedings—the question for every IOU will be the same: can you prove you were doing this, and can you prove it systematically?
Given NERC's standards development process and FERC's approval cycle, the realistic timeline for an enforceable federal regulation might be 2028 or 2029.
But waiting for that federal mandate would be a strategic mistake. State Public Utility Commissions (PUCs) and intervenors are reading the same data, and they are enforcing these standards today. The NERC report simply provides the federal validation for the scrutiny you are already facing in your local rate cases and WMP audits. The utilities that orchestrate their workflows now will be the ones positioned to secure their cost recovery tomorrow.
The NERC report explicitly endorses advanced technology: LiDAR, satellite imagery, and AI-driven vegetation proximity modeling.
But let’s be realistic about tech maturity: while some Tier 1 utilities are deploying AI satellite scans, many regional IOUs are still relying on human inspectors walking lines with iPads or flying helicopters.
This connects directly to the challenges I have been writing about in this series, such as in my earlier posts on BCR automation and byproduct documentation, where I argued that the real value of workflow orchestration is not just efficiency, it is the ability to generate compliance evidence as a natural byproduct of daily operations. When your field execution workflows are properly connected to your risk detection systems and your financial closeout processes, the documentation builds itself. Every work order captures the risk input that triggered it. Every dispatch records the contractor, scope, and timeline. Every completion is timestamped and verified.
The good news is that workflow orchestration is helpful regardless of your current technology level. Whether a high-risk span is flagged by a terabyte-sized LiDAR point cloud or an inspector's field note, the operational handoff is identical: the risk must automatically trigger a work order, route to a contractor, and lock in the compliance record without manual data entry.
When your field execution workflows are connected directly to your risk detection, the documentation builds itself. We call this "byproduct documentation." If your compliance process still relies on "reconstruction work" where your team scrambles after the fact to dig up contractor invoices and cross-reference outage logs, expanding your managed lines by thousands of miles will create a documentation crisis. If your operational workflows generate that evidence automatically as the work is completed, the expansion becomes a highly manageable scope increase.
The NERC report makes this approach not just strategically smart, but increasingly necessary. Consider what happens when the FAC-003 expansion takes effect: an IOU that previously managed formal vegetation documentation for a few hundred miles of 200 kV+ transmission lines now needs the same level of auditable evidence across potentially thousands of additional circuit miles at 100 kV and above.
If your documentation process relies on “reconstruction work”, where regulatory and compliance teams go back after the fact to dig up contractor invoices, cross-reference outage data, and stitch together a narrative, you are looking at a compliance burden that scales linearly with every additional mile brought under the standard. The cost and risk of that approach become untenable at the volumes the FAC-003 expansion implies.
If, on the other hand, your operational workflows generate that evidence automatically, the expansion is a manageable increase in scope rather than a documentation crisis.
In my first post in this series, I introduced the concept of moving from a “black box” to a “glass box” approach in BCR development—making the assumptions, data sources, and decision logic behind every investment fully transparent and auditable, rather than hiding them inside an opaque automated process.
The NERC report reinforces this principle at the federal level. Its endorsement of AI-assisted tools for vegetation risk scoring comes with an implicit expectation: these tools must be explainable. When an AI model flags a span as high-risk and triggers a work order, regulators will want to see the inputs, the logic, and the human review that validated the output.
This is the same “AI-assisted, human-approved” framework I described in the byproduct documentation post. The orchestration layer captures the context of every decision—ensuring that equity considerations, local ordinances, and engineering judgment are documented alongside the algorithmic outputs. In a post-NERC-report regulatory environment, this kind of transparency is not optional. It is what defensibility looks like.
One of the more forward-looking recommendations in the NERC report is the proposal for an industry organization modeled after the Institute of Nuclear Power Operations (INPO), complete with peer reviews, near-miss data collection, and—critically—insurance rate incentives tied to the maturity of a utility’s wildfire mitigation practices.
For IOUs, this creates a financial feedback loop that goes beyond rate case recovery. The insurance market for utilities has tightened dramatically since the L.A. wildfires, with premiums rising and coverage becoming harder to secure. If insurance costs become formally linked to documented mitigation maturity, then the investment in workflow orchestration and automated compliance evidence is not just a regulatory strategy—it is a direct driver of reduced operating costs.
Utilities that can demonstrate continuous, auditable vegetation management across their full network, with risk-based prioritization and verified field execution, will be the ones that benefit most as these insurance frameworks develop.
All of this plays out in real time when you look at CenterPoint Energy’s recent SRP experience in Texas. CenterPoint filed a $5.75 billion Systemwide Resiliency Plan in January 2025. Through settlement and PUCT review, the approved amount was trimmed to roughly $2.7 billion—less than half the original ask. Commissioners specifically questioned whether certain vegetation management spending constituted base maintenance or genuine above-and-beyond resiliency investment.
This is exactly the kind of scrutiny that the NERC report will intensify. When regulators are deciding what qualifies as recoverable resiliency investment versus routine O&M, the utility that can present risk-based targeting, transparent prioritization logic, and granular field execution evidence has a fundamentally different conversation than the one presenting reconstructed spreadsheets.
The distinction between “we spent this money on vegetation management” and “we can show you exactly which risk model identified this span, which contractor was dispatched, when the work was verified, and how it connects to our overall resiliency strategy” is the difference between a contested rate case and a defensible one.
The direction of travel is clear: more lines to manage, higher documentation standards, and direct financial consequences for utilities that fall behind. Here is how to prepare:
The IOUs that invest in the operational connective tissue between their risk data and their field crews are already ahead of the curve. The ones that haven't are looking at a rapidly narrowing window to catch up.
Want to continue the discussion? Schedule a chat with Tom.