Here’s some background:

1. The team was constituted based on a good Standards Authorization Request (SAR) that was developed by two NERC entities and approved by the Standards Committee in December 2023.

2. When they first met in - I believe - July 2024, the team decided they wanted to re-draft their SAR. They spent the next six months doing that; it was approved a year after the first one. I didn’t think the second SAR was hugely different from the first one, but I was willing to concede that it had been worthwhile to take so much time to draft it.

3. The second SAR (on page 3) listed two “deliverables” for the project. The first reads, “The (S)DT will strive to minimize impacts to existing requirements for on-premises systems and assets under the existing CIP-002 through CIP-015 suite of standards.” Have they achieved this goal? No, just the opposite: They’re developing a completely new set of CIP standards and definitions called the “100 series” (CIP-102, CIP-103, etc.).

Any NERC entity that wants to make any use of the cloud in a medium or high impact BES environment will need to adopt these standards and definitions wholesale. Moreover, they need to adopt them for both cloud-based and on premises systems. This means those entities must toss their existing CIP programs altogether and start over literally from scratch. I don’t think this meets the definition of “minimizing impact”, do you?

4. Of course, if the SDT is willing to force NERC entities to adopt the new standards for both on premises and cloud-based systems, at least those standards need to be superior to the current ones. Are they? Here’s the problem: The SDT has yet to finalize the first draft of a single standard (and I suppose the same applies to the definitions), let alone all twelve new standards. So, there’s currently no way to be sure what the new standards will look like.

In July, the SDT released “straw man” versions of five standards and nine definitions, which are quite convoluted and raise more questions than they answer (plus, releasing just five of a planned 12 standards is close to useless, since CIP standards tend to depend heavily on each other; that’s certainly true in the case of the 100 series).

Since the July release, inadequate as it was, is the best we have so far, here is the definition of “Cyber Security Zone”, the concept that will replace “Electronic Security Perimeter” for both on premises and cloud based systems: “A defined logical trust boundary that groups applicable systems based on common security requirements, impact levels, or operational security objectives and enforces controls for access, communication, and monitoring. The boundary of a Cyber Security Zone is established through logical security controls, including security policies, identity and access management controls, authenticated communication pathways, and monitoring capabilities, and is independent of physical location or underlying network topology.”

Got it? You’d better get it, since if this definition isn’t improved and the 100 series standards are approved by the NERC ballot body and FERC, you will have to apply it to every on premises medium or high impact BES Cyber System. Moreover, you will have to apply it equally to systems in the cloud, if they meet the definition of “BES Cyber Systems or Services” (BCSS).

5. And what, pray tell, is a BCSS? That definition (the one provided in July, of course) in essence consists of the current BES Cyber Asset definition, with the words “A Cyber Asset” replaced with “One or more cyber services or systems…” This would be OK if there were NERC glossary definitions of both “service” and “system”; but there aren’t any. Of course, NERC entities all have long experience identifying on premises BES Cyber Systems, so it’s safe to assume that if they continue to identify those in the same way, they won’t be found in violation when BCSS replaces BCS.

However, how will you identify your BCSS in the cloud? With on-premises BCS, you have an easy rule to follow: You need to identify every Cyber Asset (i.e., “programmable electronic device”), then decide which of those meet the definition of BES Cyber Asset, including a sub-15-minute impact on the BES if compromised, lost, etc. Then you need to include each BCA in one or more BES Cyber Systems. But I know of no such simple rule for the cloud. Of course, this will lead to problems.

For example, let’s say a NERC entity takes a narrow view of what constitutes a BCSS in the cloud, so they end up identifying very few BCSS. However, an auditor strongly disagrees with them and says they should have identified many more. How can either the entity or the auditor win this argument, absent rigorous definitions of system and service? One way to settle the argument would be if the SDT prepared Implementation Guidance for each standard, as is often (but unfortunately not always) done by SDTs dealing with CIP, and if the document provided guidance on identifying BCSS in the cloud.

However, this SDT has decided they don’t have “enough time” to develop Implementation Guidance, even though they’ve been meeting for 2 ½ years. This means it will be up to each NERC entity to develop their own definitions. In theory, if they apply those definitions consistently in asset identification, the auditors can’t complain, since the problem is that there’s no definition available.

I remember when NERC entities were preparing for implementation of CIP version 5 (the last time the CIP standards and definitions were totally rewritten, although the 100 series will entail much more thoroughgoing changes). Then, multiple auditors weighed in to endorse the idea of NERC entities “rolling their own” definitions. However, since the auditors haven’t been part of discussions of the 100 series so far (probably because they’re under greater restrictions on providing compliance advice than they were more than ten years ago), I doubt that will happen now. The NERC entities will have to decide for themselves how they will comply with ambiguous wording in requirements and missing definitions, and hope their auditor likes what they did when audit time rolls around.

6. Getting back to the SDT’s 2024 Standards Authorization Request, the second deliverable (of two) reads, “The Drafting Team will consider risks related to cloud services for CIP applicable systems, including but not limited to:…” This is followed by twelve risks like “Reliance on indirect services”, “Data sovereignty”, “Key management”, and “Multi-tenancy”. I was pleased to see this deliverable, since I initially thought (and still think) the SDT should focus on “cloud” risks like these. But I was disappointed to hear a few months ago that the SDT has decided these “cloud-only” risks aren’t in their scope, so they’re not addressing them at all in the new standards.

Instead, all the requirements the SDT is now developing are based on the existing CIP requirements for patch management, background checks, configuration management, vulnerability assessments, etc. While all of these are good things, is there really reason to fear that any major cloud provider isn’t regularly applying patches or conducting background checks on their employees? More importantly, since everything in the current CIP standards is required by certifications like ISO27001 and authorizations like FedRAMP, and since the major cloud providers have all of these, why is it necessary to ask them again whether they do these things, since they will be glad to show you their audit reports that demonstrate they’re completely compliant with those standards? Wouldn’t it be better to ask about their key management options or what they can do about the multi-tenancy problem in SaaS? When you’re talking about the cloud, those are the real risks.

Therefore, the SDT is ignoring both of the deliverables they committed to in their SAR. Instead, they’ve decided to rewrite the current CIP standards, even though that goal was nowhere mentioned in the SAR. While I’ve been pointing out inadequacies in the current CIP standards for more than a decade, I believe the only way to rewrite them - and get acceptance from the CIP community for the new standards - is for NERC entities to draft a new SAR requesting this, and for the drafting team to solicit copious comments and ideas from the community before putting (digital) pen to (digital) paper. I say this because I doubt there’s anyone who’s worked with the CIP standards for a while that doesn’t have strong opinions (some unprintable, to be sure) about them.

What should never have happened – but which has happened – is for a drafting team that was formed to address a very different task to decide that it would be more interesting to rewrite the existing CIP standards, then develop new standards that reflect their own idiosyncratic ideas about what the standards should look like – all without soliciting any feedback from the CIP community until the standards are balloted. At that point, the NERC entity’s only choice will be to reject the standards altogether or to swallow their objections and approve them.

7. Probably the worst part of all this is that the SDT, again because they’re in such a hurry, is clearly not planning to post the standards and definitions they’re drafting for the NERC entities before the first ballot. What it seems they’re planning to do is share them with certain selected NERC entities that ask to see them. Given that there are over a thousand NERC entities that will be affected by this, that seems a little odd, don’t you agree? I don’t know of any time that’s been done before. It’s certainly against the spirit of NERC standards development, if not the Rules of Procedure themselves. Every NERC entity that will have to comply with the new standards should have the opportunity to comment on them before the SDT finalizes them.

Folks, I remember the big confusion – and sometimes fierce arguments, although I don’t believe anybody was killed – that accompanied the CIP v5 rollout, due to the ambiguities in those standards and their definitions. Even though there were only a small number of significant ambiguities in CIP v5, including the meanings of “affect the BES”, “programmable” and “routable” – those alone were enough to create a lot of trouble.

If what this SDT released in July is any indication (and it’s unfortunately the only indication that most NERC entities are likely to have before the first ballot in early 2027), there will be far more significant ambiguities in the 100 series, with even more arguments, etc. And as I’ve already said, there will be no guidance documents to settle arguments between auditors and entities.

Why should the NERC CIP community have to suffer through this? In my opinion, two things need to be done:

1.      When the SDT finishes their first draft of the 100 series standards and definitions – even if it’s at 11:59 PM on December 31 – they need to post them for comment by all NERC entities. There should be at least a three-week comment period, hopefully followed by a webinar so entities can get their questions answered and perhaps make further suggestions. The SDT should then make their best effort to incorporate each suggested change into the 100 series standards (when the change has merit, of course). At that point, they should submit the standards to the quality review process and make any changes required by the QR team. Once they’ve done that, they can be posted for the first ballot.

2.      The SDT needs to develop implementation guidance for each of the 100 series standards. Of course, that will take a significant amount of time and will delay approval, since the guidance itself will need to be approved by the ballot body. However, that’s the whole point: NERC entities should not be forced to throw out their current CIP compliance program and adopt a brand new one, if there are going to be significant questions about what “compliance” means and no reliable way to resolve them.

I’ve already made suggestions like this to one SDT member, who immediately pointed out that they must finish drafting the standards by the end of the year. I asked why that’s the case, although I already knew the answer: the Modernization of Standards Processes and Procedures (MSPP) changes come into effect on January 1. These are a set of badly needed changes to the NERC standards development process.

I’ve skimmed through the document I just linked, and I think these changes are quite good. My favorite is that NERC entities will only need to vote once on each new or changed standard, as opposed to having to vote usually four times, with the standards revised to reflect comments received with the ballots. In the new procedure, there will be multiple comment periods, in which the entities will submit comments and the SDT will make changes based on those comments; but there will only need to be one vote, after the NERC entities have gone through multiple comment rounds, and the standards are to their liking. This should greatly expedite the approval process and make it much less stressful.

I asked the SDT member why the MSPP was something to be feared. He didn’t have an answer, but I already knew it: The MSPP replaces the Standards Authorization Request process – which has always been quite cumbersome – with a more streamlined Standards Initiation Request (SIR) process. Of course, that’s good, but that means the SAR that the drafting team spent six months developing will need to be thrown away and they’ll need to start over with a SIR.

However, I consider that to be a feature, not a bug, since the SDT hasn’t followed their SAR anyway. They need to rethink what they’re doing and only require deliverables that they can actually…you know, deliver. And if they insist that they need to rewrite the current CIP standards, they need to explain why that’s necessary, so the replacement for the Standards Committee (which goes away on January 1) can decide whether this is in fact needed. Even more importantly, they need to provide the one “deliverable” that was urgently requested in both SARs: They should focus first on solving the problem of NERC entities not being able to utilize SIEM services that move to the cloud.

In my last post, I described (in the second-to-last paragraph) the three small changes that I think are needed to make it possible to use cloud-based SIEM services; I honestly think those changes could be drafted in a matter of weeks, not 2 ½ years and counting. Let’s get this done first and then think about whatever else is needed. But whatever we do, let’s not saddle NERC entities with a Rube Goldberg machine that seems designed to provide maximum confusion with minimum benefits.

P.S. It’s ironic that the SDT is in such a hurry to finish this year, since it will be more than two years before the 100 series can be implemented, even if the standards are quickly approved by the NERC ballot body and by FERC. This is because the SDT wants to make some changes to CIP-002 (i.e., the current version for on-premises systems, not CIP-102, the 100 series version). Those changes will go into a new version CIP-002-9.

However, there are now two previous versions of CIP-002 that are scheduled to become enforceable on July 1, 2028: CIP-002-7 and CIP-002-8. Since one version of a NERC standard, no matter how important, isn’t allowed to “jump ahead” of an earlier version, this means the 100 series can’t be enforced before October 1, 2028, but most likely will need to wait until sometime in 2029.

By the way, the simple proposal to fix the SIEM-in-the-cloud problem that I discussed earlier shouldn’t require any change to CIP-002 or any of the other current CIP standards. Thus, it can be implemented as soon as it is approved by FERC, although how soon will depend on the implementation plan.

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https://www.controlglobal.com/blogs/unfettered/blog/55416557/the-plc-says-the-valve-is-open-the-hmi-agrees-but-what-if-neither-is-telling-the-truth

How GIS-powered enterprise mobility drives safety, reliability, and resilience, with new Energy Central audience data on what's behind field safety incidents.

A crew swaps out a pole on Tuesday. Two weeks later a planner pulls up the map, and the old pole is still there. When we asked utility pros how long it takes for a field change to show up in their records, only 16% said the same day, and more than 25% said a month or longer.

That lag has real costs. Crews end up working from outdated or incorrect info, planners budget around a network that has already changed, and many safety incidents and near-misses trace back to information or communication breakdowns.

This report, produced with Esri, shows how utilities are closing the field-to-office gap with GIS and mobile tools, and what changed when they did:

• Puget Sound Energy went from 120 days to 24 hours for new gas assets to show up in its maps.

• Great River Energy saved 450 hours of work after linking its maps to its work-order system.

• Denmark's N1 kept power on for 99.6% of customers through a historic storm surge.

Get the free report →

Electricity demand is growing, experienced workers are retiring, and utilities are competing with big tech for talent. How can the energy industry attract, and keep, the people needed to power its future?

Paige Knutsen, executive director of the Midwest Energy Efficiency Alliance, unpacks findings from Energy Central’s State of the Utility Workforce survey.

She discusses with Energy Central's Molly Glick why recruitment alone won’t solve the workforce challenge, how employers can support their existing teams, and the range of energy careers available even without a four-year engineering degree.

Despite all the challenges, Paige says she remains optimistic about the industry’s future.

Watch the full episode on YouTube

Listen on Spotify

Listen on Apple

Most of the adequacy debate in ERCOT runs through reserve margins and effective load-carrying capability. Both blend resources together by their expected contribution. I wanted a narrower, structural number. How much of the summer peak rests on capacity that can be dispatched on command, whatever the weather?

I call it the Thermal Coverage Ratio: net summer capacity of gas and coal units in the ERCOT balancing authority, divided by the annual summer peak. It is not a reserve margin, and nobody argues thermal should cover 100% of the peak. It measures dependence, not adequacy.

The result. In 2019, ERCOT’s summer peak was 74,820 MW and dispatchable thermal capacity was 73,487 MW. Coverage was 98%. At the July 2026 record of 91,134 MW, thermal capacity stood at 75,775 MW. Coverage was 83%. The gap between peak and thermal capacity grew from 1.3 GW to 15.4 GW.

What was built. Combined cycle capacity has been essentially flat since 2019, at about 39.6 GW. Net thermal growth came from combustion turbines (+3.6 GW) and reciprocating engines (+0.6 GW), offset by coal and gas steam retirements of about 2.1 GW. Texas built peaking capacity, not baseload.

What filled the gap. Batteries, mainly. ERCOT now has 19.2 GW of battery storage, more than the entire gap. But the fleet holds 31.7 GWh, an average duration of 1.65 hours, and only about 0.5 GW is rated four hours or longer. At a 6 pm peak with solar still producing, the gap is covered. On a long evening shoulder, duration becomes the binding constraint.

Method notes for planners. Capacity is from EIA Form 860M, with the Operating and Retired tabs combined to rebuild the fleet as of each year’s peak month. Nuclear (4,980 MW) is excluded because it doesn’t follow load. Including it adds about 5.5 points. Imports, demand response and storage are excluded by design. Removing units now listed as out of service lowers 2026 to 81.3%. The 2025 uptick to 89% reflects a milder summer, not new capacity.

This is the first market in a series. PJM follows. I’d value challenge from anyone who plans these systems. Is the 1.65-hour duration profile already reflected in how you think about evening adequacy, or is the megawatt figure still doing too much of the work?

Full analysis, method and a downloadable data pack listing every unit behind every number: https://alexmarshallenergy.com/perspectives/ercot-thermal-coverage-ratio

For the last months I talked and wrote a lot about AI-native Power Grid, Agentic Grid Operations, Deep Grid Data, Grid Ground Truth or Trusted State. During the weekend, I noticed something quite embarrassing: I never said what I mean with the AI-native Power Grid. I never wrote down my definition. My vision. My thoughts.

AI-native seems everywhere now. And everything seems to be AI-native, too. Quite often it simply means: we put some AI into or onto something that already existed (and worked). For me that is AI-enabled. AI-enhanced.

When I think about AI-enabled, I think about a system or workflow that works exactly the old way, but got some AI tools helping a human here and there with some tasks. Take the AI out, the system or workflow still works, but maybe less effective for the operators than with AI in it.

AI-native on the other hand, in my mind, means the system and workflow is designed around AI. AI is the execution layer. Take the AI out, and the system or workflow stops working as defined and falls back to the operators.

My Definition of the AI-Native Power Grid

The AI-Native Power grid is a power grid with AI being the execution layer of grid operations, instead of a tool bolted on top. The grid runs like a living system: within the limits, policies, and strategies set by human operators, it monitors, operates, balances, optimises and restores supply by itself. The role of the human operators changes from reacting to every event and approving every action, to defining and governing these limits. And the Human operators take over whenever the situations is outside the defined limits.

Or in short: AI does the work. Human operators set the rules. Govern it. And step in when the rules do not fit.

A new Name for the Smart Grid

No. It is not a smart grid with a new or more fancy name. Self-healing is not new. FLISR has done it for years. Rules based self-healing. Rules written by engineers. An AI-native grid also handles the situations. where no rules are written in advance.

It is not a grid with out people. It is not a dark control room. It is not fully autonomous operating in all known or unknown conditions. Human operators are reacting on events anymore. Human operators are not managing the grid anymore. Human operators are not approving every single step or action. Human operators define the policies, strategies, and limits. Monitor those. Govern those. It is not a smaller job. Not at all. It is a different job..

It is distribute, but not fragmented. Decisions can be distributed. Decisions should be distributed. To many agents. Close to where things happen. But all them must act on the same picture of the grid: the Trusted State. Or at least all agents must know exactly on which version / snapshot it can act on.

And it is not a Big Bang. The AI-native Power Grid develops over times. Step by step, task by task, as trust grows. It is a Journey of Trust.

My Definition of the Agentic Grid

When the AI-Native Power Grid describes where we want to go, then the Agentic Grid tells us how to build it. I think about the Agentic Grid being the architecture backbone for the AI-Native Power Grid:

The Agentic Grid is the architecture for the AI-Native Power Grid. Many AI agents, from different vendors, third parties, and from the utility. Each egent with a defined role, tasks, and authority. All agents act on one Trusted State. None of them acts on the grid except through the cognition/control boundary.

Instead of describing it as an architecture stack with different layers, I like to think like a system of systems. A living system.

The grid is measured. The data get snapshotted and certified to a Trusted State. All agents reason on it, within the limits the human operators set. Every action goes through the cognition/control boundary into deterministic control. Control changes the grid, And the grid is measured again. A loop. A living system. AI-native.

How to get started

The AI-Native Power Grid is a journey. We are not jumping from advice to autonomy. It is not a big bang. It is a journey of trust. Task by task. Step by step. But every step needs three things in place:

• The one Trusted State of the grid that all agents share and reason on.

• A clear cognition / control boundary between where AI may advise and where AI may act.

• People who can check, definie the limits and strategies and understand when the AI goes wrong. We have to train the people who will check the machines.

These three are not technology problem. Utilities should start working on them. Today.

Your Points

For now, that is what I mean when I talk / write about the AI-Native Power Grid. My definition. Or vision. Or thinking. For now.

I guess, it will change as we and I all learn more. But would love to get your thoughts and inputs !

Disclaimer: The post was originally published on the AI-native Power Grid Channel on Substack, but adapted for the Energy Central Community.

Quick note on the use of AI: All articles are written by me. All ideas, thoughts, concepts, and opinions are mine. But yes, I am using AI. To challenge my thinking, to validate and fact-check some of the content. To create the banner pictures or diagrams. And occassionally, as I am a non-native speaker, to check my spelling and grammar.

In a bid to save their controversial $67 billion merger, Virginia-based Dominion Energy, the seller, and Florida’s NextEra Energy, the buyer, have agreed to accept many of the conditions the staff of the Virginia State Corporation Commission laid out last month as needed to protect consumers. The merger would create a mammoth company, serving some 10 million customer accounts.

The two companies also rejected a demand from Virginia governor Abigail Spanberger that the merged company freeze rates for six years.

The two Fortune 500 companies Tuesday (Nov. 3) announced that they have “have filed rebuttal testimony with the Virginia State Corporation Commission strengthening their proposed combination with additional customer and financial protections.”

The SCC’s staff on Oct. 19 opposed the merger in a 201-page filing, concluding that “the Petitioners have not met their burden to prove that ‘adequate service to the public at just and reasonable rates will not be impaired or jeopardized.’” In an 11-page appendix that is part of the total filing, the staff detailed 57 conditions the SCC should impose, which encompass many specific action items.

In their joint news release, the two utilities said, “Of the 117 conditions proposed by the Commission Staff and the Consumer Counsel, the companies have accepted 101 conditions as proposed and another 13 conditions with enhancements or modifications.”

The utilities’ decision to accept major portions of the SCC staff’s objections came as both companies were unveiling their third quarter 2026 earnings.

NextEra reported a strong third quarter: $2.592 billion in earnings, or $1.24 per share, compared to $2.348 billion, or $1.13 per share, in the third quarter of 2025. John Ketchum, NextEra chairman, president and chief executive officer, said, “NextEra Energy delivered strong third-quarter results, with adjusted earnings per share increasing 9.7% year-over year, reflecting continued strong financial and operational performance at both FPL and NextEra Energy Resources.”

FPL is Florida Power and Light, NextEra’s conventional monopoly generation, transmission, and distribution electric company. In terms of residential customers, FPL is the largest electric utility in the U.S. with about 5.34 million customers. It is the original and most significant business element of NextEra.

In 1984, FPL created a holding company named FPL Group, which began acquiring utility generating assets outside of The Sunshine State but in the South. In 1998, FPL created another holding company, FPL Energy, to reach assets outside the South, beginning with the Seabrook Nuclear Power Plant in New Hampshire in 2002. In 2010, FPL Group and FPL Energy rebranded themselves into NextEra Energy and NextEra Resources.

Dominion also reported strong third-quarter 2026 earnings: $1.2 billion ($1.30 per share) compared with net income of $1.0 billion ($1.16 per share) for the same period in 2025. The company said it is on target to hit the top half of it estimates for full 2026 earnings of $3.45 to $3.69 per share. 24/7 Wall Street noted that Dominion’s earnings beat “expectations for the seventh consecutive quarter. Revenue grew about 24% from a year earlier.”

In an online conversation with financial analysts, Dominion chair, president, and CEO Bob Blue raised the issue of the merger. “Looking ahead,” he said, “we believe we can accomplish far more on behalf of our customers together than we can apart.”

Dominion describes itself as providing “regulated electricity service to 3.6 million homes and businesses in Virginia, North Carolina, and South Carolina, and regulated natural gas service to 500,000 customers in South Carolina. The company is one of the nation’s leading developers and operators of regulated offshore wind and solar power and the largest producer of carbon-free electricity in New England.”

Dominion Energy’s roots go back to 1909 when Frank Jay Gould (1877-1956), son of the 19th Century railroad baron Jay Gould, bought Virginia Railway & Power Company and Virginia Passenger & Power, changing the name in 1925 to Virginia Electric and Power Co., or VEPCO, a regulated monopoly, which remains the legal name of the Virginia utility operations.

In 1980, the company stopped calling itself VEPCO, instead preferring Virginia Power for its Virginia business and North Carolina Power for its Carolina line. Three years later, it became Dominion Resources and Dominion Energy in 1987.

While the deal did not require approval in Florida, the Virginia case is the main state event in a three-ring regulatory circus. Dominion owns regulated utilities in North and South Carolina. South Carolina testimony is due Nov. 18, hearings are set for Dec. 8, with a decision due Jan. 29. In North Carolina, hearings begin on Feb. 23.

The deal also faces scrutiny from the U.S. Nuclear Regulatory Commission and the Federal Energy Regulatory Commission, but those reviews are not likely to be controversial

The Quad Report, covering energy policy and politics

Worse still is the lack of any clear, official signals ensuring that established rules are upheld.

A recent case involves a major power trader that was stripped of its accreditation by the CCEE precisely for failing to meet its obligations—yet was subsequently authorized by the "upper" courts to continue its operations.

This has created a state of confusion. The market suffers as a result, losing credibility and facing rising costs driven by this institutional disarray.

What should a client do if they have contracted with a power trader in such a position? What is the "official" recommendation?

The electricity sector is in a state of disarray, and this unacceptable situation is driving up additional costs.

So, what are potential solutions to the quandary presented in the above paragraph:

1.     Back-up on-site generation

2.     An uninterruptible power system (UPS)

3.     Full-time on-site generation

4.     Both 1 and 2 above

5.     Both 2 and 3 above