Q1. Could you start by giving us a brief overview of your professional background, particularly focusing on your expertise in the industry?

I am a utility technology and grid modernization consultant with deep experience across electric distribution operations, GIS, ADMS, EMS, SCADA, OMS, DERMS, and operational technology program management. My background includes more than two decades at Duke Energy, where I worked in distribution operations, grid analysis, switching, storm restoration, and enterprise GIS modernization. I later supported Exelon/ComEd on ADMS and EMS implementation work across multiple utilities, and I now support Madison Gas and Electric as a program manager over operational technology initiatives, including EMS upgrades, ADMS integration, SCADA readiness, GIS modernization, field device coordination, and data integration.

My expertise sits at the intersection of utility operations, technology implementation, and capital project execution. I have worked with control room users, engineers, IT/OT teams, vendors, and leadership to translate operational needs into practical system requirements. That includes work involving GE Vernova EMS/ADMS, Schneider ADMS, ESRI GIS, ArcFM, OMS, SCADA, DERMS, and related integration layers.

I also bring a practical field-informed perspective. I understand not only how these systems are designed and procured, but how they actually affect operators, reliability, outage restoration, customer service, and long-term grid investment decisions.

 

Q2. With hyperscale data center demand reaching record highs, what is the average 'Time-to-Grid' for a 100MW+ connection? Are companies utilizing Automated GIS-to-SCADA mapping to accelerate these studies?

For a 100MW+ load, I would generally expect the practical “time-to-grid” to fall in the 3-to-7-year range, depending heavily on location, available substation capacity, transmission constraints, permitting, protection studies, and whether new transmission or major distribution upgrades are required. Recent market commentary points to interconnection timelines of roughly 36 to 84 months, which lines up with what utilities are seeing as large load requests accelerate faster than traditional planning cycles.  

Automated GIS-to-SCADA mapping can help, but it does not eliminate the core bottleneck. It can speed up model validation, asset mapping, connectivity checks, protection coordination, and ADMS/SCADA readiness. However, the larger delays usually come from engineering studies, transformer availability, transmission upgrades, permitting, land, construction sequencing, and regulatory approval.

In my view, automation is becoming more important, especially where GIS is the system of record and feeds ADMS, OMS, SCADA, and planning models. But for 100MW+ data center loads, the deciding factor is still whether the utility has physical grid capacity available at the right voltage level and location.

 

Q3. As Virtual Power Plants (VPPs) are projected to reach a $3.3B market size in 2026, in your view, what percentage of companies are positioned to act as the central 'Platform Operator'?

The VPP market is growing quickly, but I would estimate that only 10% to 20% of companies are truly positioned to act as the central platform operator today. Many companies can participate in a VPP ecosystem, but far fewer can orchestrate DERs, customer programs, market dispatch, utility constraints, telemetry, cybersecurity, and settlement at scale.

Utilities are natural candidates because they understand grid constraints, reliability obligations, and customer impact. However, many utilities are still early in DERMS maturity, customer device integration, and real-time operational control. Aggregators and technology vendors often move faster on software and customer acquisition, but they may lack direct visibility into grid topology, switching conditions, feeder constraints, and outage operations.

That creates a split market. Some companies will own the customer relationship, some will own the software platform, and some will control grid operations. The true platform operator will need all three, or at least tight integration across all three.

The companies best positioned are those already investing in DERMS, ADMS integration, advanced metering infrastructure, customer enrollment programs, and utility-grade cybersecurity. VPPs are not just software products. They are operational grid assets.

 

Q4. In your point of view, what percentage of OT budget needs to be dedicated to 'Active Resilience' (automated circuit isolation and anomaly detection) versus traditional 'Passive' firewalls?

In my view, utilities should be moving toward dedicating roughly 30% to 40% of the OT cybersecurity and resilience budget to active resilience, while still maintaining strong passive defenses such as firewalls, segmentation, access control, and monitoring. Passive controls remain essential, but they are no longer enough by themselves.

Traditional firewalls help keep bad actors out. Active resilience is about detecting abnormal behavior, isolating affected circuits or systems, maintaining operations during an event, and recovering quickly. That matters more as ADMS, EMS, SCADA, DERMS, AMI, GIS, field devices, and cloud-connected tools become more integrated.

The budget split will vary by utility maturity. A smaller utility may still need to invest heavily in foundational controls. A larger or more digitally mature utility should be shifting more dollars toward anomaly detection, automated isolation, backup control paths, incident response automation, and operational recovery drills.

The key is not replacing passive defenses. It is building a layered OT strategy where the utility assumes something will eventually fail or be compromised and designs the system to contain the damage quickly.

 

Q5. As cloud-based OT (Operational Technology) becomes the standard, what specific regulatory mechanisms are you using to ensure software-as-a-service (SaaS) and digital integration costs are treated as capitalizable assets?

For SaaS and cloud-based OT costs, the most important mechanism is to separate subscription expense from implementation and integration costs. The subscription itself is typically treated as operating expense, but configuration, integration, testing, data migration, internal-use software work, and certain implementation activities may be capitalizable depending on the accounting treatment and regulatory approval.

FERC has recognized cloud computing implementation cost treatment tied to accounting guidance for internal-use software, including guidance that certain implementation costs in a cloud service arrangement may be capitalized. NARUC has also discussed cloud computing and SaaS cost recovery as a utility regulatory issue, especially because traditional rate-base models were built around owned physical assets.  

Practically, I would document these costs by project phase: planning, configuration, integration, testing, cybersecurity controls, data conversion, training, and ongoing subscription. The utility then needs clear regulatory support showing that the cloud or SaaS investment provides long-term operational value, supports reliability, improves resiliency, and replaces or extends traditional capital infrastructure.

For OT systems, this is especially important because SaaS is not just back-office software. It can support grid reliability, outage response, DER integration, and operational visibility.

 

Q6. With infrastructure spend at record highs, what is your projected 'Rate Impact' for the 2026-2028 cycle?

For the 2026-2028 cycle, I would expect customer rate pressure to remain elevated, with many utilities likely seeing cumulative rate impacts in the mid-to-high single digits annually depending on jurisdiction, capital plan size, fuel costs, storm recovery, generation investment, and grid modernization needs.

The biggest drivers are transmission expansion, distribution hardening, data center load growth, renewable integration, battery storage, aging infrastructure replacement, cybersecurity, and operational technology modernization. Large load growth from data centers is especially important because it can require major upstream investment before the load is fully online. If not structured carefully, those costs can create concern about cross-subsidization between large customers and residential or small commercial customers.

I would expect regulators to push harder on cost allocation, contribution-in-aid-of-construction, minimum demand commitments, special tariffs, and large-load contract structures. Utilities will need to prove that new infrastructure benefits the broader system and that speculative data center requests are not driving unnecessary capital spend.

My practical estimate would be that rate impacts land around 5% to 9% annually in higher-growth service territories, with lower-growth areas closer to 3% to 5%. The utilities that manage this best will be the ones that pair capital investment with transparent planning, strong load validation, and disciplined customer cost allocation.

 

Q7. If you were an investor looking at companies within the space, what critical question would you pose to their senior management?

If I were an investor, my critical question would be:

How much of your projected growth is backed by firm, funded, and operationally realistic load commitments versus speculative interconnection requests?

That question matters because the utility sector is entering a period where growth forecasts can look very attractive on paper, especially with data centers, electrification, DERs, and industrial load expansion. But not all load requests are equal. Some are real, funded, and tied to specific construction timelines. Others are exploratory, duplicated across multiple utilities, or dependent on uncertain customer financing.

I would want management to explain how they validate large-load requests, how much upfront financial commitment they require, how they allocate infrastructure costs, and how they protect existing customers from paying for speculative growth. I would also ask whether their OT, EMS, ADMS, SCADA, GIS, and cybersecurity systems are mature enough to support the growth they are forecasting.

The best utility investments will not simply be the companies with the biggest load queue. They will be the companies that can convert load growth into reliable earnings without overbuilding, under-recovering costs, or creating political and regulatory backlash.