Top Products
The transmission planning sector is facing a critical challenge. With over 2,600 GW of generation projects waiting for interconnection, more than 2x the entire current U.S. generation capacity, it’s no surprise that utilities are overwhelmed with analysis tasks. But the issue isn't just the volume. The nature of grid analysis itself has radically changed, and many utilities are realizing that their 40+ year old software strategies weren't built for this new environment.
Most current transmission planning tools were created in the 1970s. They addressed the main issue of that time: steady-state and dynamic analysis of large, interconnected power systems mostly made up of synchronous generators. Utilities could conduct their yearly planning studies, verify system stability, and then move forward. The grid changed slowly, and planning cycles spanned years.
That world is gone.
Today's transmission planner arrives at work to find three new solar interconnection requests, two battery storage projects, and a data center load that appeared seemingly overnight. Each project triggers a cascade of required studies: power flow, short-circuit, protection coordination, arc-flash, harmonic analysis, transient stability, voltage stability, and, increasingly, electromagnetic transient (EMT) studies for inverter-based resources.
The problem? Power system simulation for engineering (PSS/E ) does power flow and dynamics exceptionally well, but that's only the beginning of what's needed. For everything else, engineers export data to separate point solutions, one tool for power flow, another for short-circuit and protection analysis, yet another for EMT studies, and various other tools for harmonics and power quality. This archipelago of disconnected software creates a cascade of inefficiencies:
Data translation hell. Every tool has its own data format, conventions, and quirks. Engineers spend hours to days translating network models between platforms, manually verifying for example that Bus 47 in one tool correctly maps to Node 47-138KV in the protection coordination tool. The substation is modeled as equivalent in one tool, but needs to be a complete substation with a breaker-and-a-half scheme in another.
Version control nightmares. When the network model changes (which now happens weekly rather than annually), every downstream tool needs to be updated. Miss one, and your protection study is analyzing yesterday's grid while your power flow represents today's reality. These models are shared with an ecosystem of consulting engineers who need the latest information to ensure their work is accurate.
Domain expertise silos. Different teams favor different tools. The power flow specialists use one tool. Protection engineers use another tool. Power quality experts have their own specialized software. SCADA/EMS has its own model. Coordinating across these silos turns every interconnection study into a project management challenge.
Slow iteration cycles. Let's say you discover a protection problem that requires moving a circuit breaker. That triggers new fault calculations to evaluate the breaker short-circuit capacity, which requires updating the short-circuit model, which might reveal new arc-flash hazards, which change equipment specifications, which affects the cost estimate. Each iteration loops through multiple tools, multiple engineers, and sometimes multiple companies.
A transmission interconnection study today consists of a collection of separate analyses. But actually, it's a tightly coupled multi-physics problem. For example, when a 200 MW solar farm connects, then:
These aren't independent problems you can solve sequentially. They're coupled. The harmonic resonance you discover might require a filter or capacitor that changes the grounding scheme, which affects fault currents that invalidate your protection coordination, which changes your arc flash analysis.
The issue is that point solutions force you to iterate manually across tools. Instead, integrated platforms let you iterate within a unified model where changes propagate automatically.
This is where the architecture of ETAP shows its fundamental advantage. When you modify the network in ETAP - add a transformer, change a cable, or reconfigure a bus - every analysis module instantly sees the change. Your short-circuit calculations, protection coordination, arc-flash studies, harmonic analysis, and transient stability models all reference the same single-line diagram, the same equipment database, and the same network topology. In other words, ETAP uses the exact electrical digital twin that stores the past, present, and future states of the system. And further, the ETAP project management platform, NetPM™, enables real-time collaboration between the grid planners and integrated SCADA/EMS, which allows for the Design Digital Twin and Operations Digital Twin to remain synchronized for the As Built / As Operated system.
I invite you to learn more about the ETAP Utility Transmission solution https://etap.com/sectors/transmission and the ETAP GridCode™ Grid Interconnection solution https://etap.com/solutions/gridcode.
The economic case for integrated platforms becomes even more compelling when you consider the total cost of ownership:
Engineering time. How much of your transmission planning engineers' time should be spent translating data between software tools versus actually analyzing the grid?
Training and expertise. Each additional software tool requires training, certification, and ongoing skill maintenance. An integrated platform means your planning engineers become deeper experts in grid analysis rather than diverting their energy learning software interfaces.
Quality and accuracy. Every manual data translation is an opportunity for error. Single-platform analysis eliminates entire categories of mistakes.
Agility. Here's an example: When FERC Order 2023 required cluster studies instead of individual project analysis, utilities with integrated platforms adapted in weeks. Those stitching together point solutions are still figuring out their workflows. Vendors providing cloud solutions are trying to help, but they can only model workflows, not run the analyses themselves.
There's another dimension where platform architecture matters: the emerging world of real-time, automated grid management.
Current transmission tools were designed for batch processing, where engineers run cases, generate reports, and make decisions. They usually have a command-line interface (CLI) and a Fortran core that are brilliant for what they do, but they're not built for modern software integration patterns.
Today's utilities need analysis engines that can be called from control systems, queried by optimization algorithms, integrated into SCADA, and provided through APIs for third-party applications. They need software that plays nicely with cloud infrastructure, scales horizontally, and integrates into DevOps workflows.
When energy companies like Con Edison want to build a digital twin that continuously validates grid state, when independent system operators like CAISO need to run thousands of contingency scenarios in parallel to optimize dispatch, and when utilities like Duke Energy want to expose grid hosting capacity through a developer portal, they need platforms built for the API economy, not command-line tools from the mainframe era.
None of this means the current tools should be immediately replaced. Transmission planning has enormous momentum, with massive investments in existing models and workflows and rightfully conservative engineering practices. Current tools will remain relevant for utilities whose primary need is bulk power system stability analysis.
But the question every transmission utility should ask is: "What percentage of our engineering time is spent doing the analysis our current tools excel at, versus all the other studies that interconnection and modern grid management require?"
For many utilities, an honest assessment reveals that traditional power flow and stability analysis now accounts for less than 30% of the engineering workload. The other 70% is protection coordination, power quality, equipment ratings, grounding, and HV arc-flash - all happening in disconnected tools or spreadsheets.
That's not a sustainable strategy when interconnection queues are growing exponentially, and regulatory pressure demands faster study turnaround times.
The transmission grid is entering an unprecedented period of transformation since electrification itself: inverter-based resources, bidirectional power flows, distributed energy resources affecting transmission-level stability, and electrification loads appearing at the utility scale. These aren't incremental changes, but a phase transition.
The tools we use to analyze, plan, and operate this grid need to evolve accordingly. Point solutions optimized for yesterday's challenges will increasingly become bottlenecks. Integrated platforms that unify multi-domain analysis, automate iteration cycles, and expose modern interfaces will define the utilities that successfully navigate this transition.
The interconnection queue won't shrink. The complexity isn't going to decrease. The only variable that utilities can control is whether their engineering tools accelerate analysis or impede it.
The platform vs. point solution decision isn't really about software preferences. It's about whether your engineering organization is architected for the grid you have today, or the grid you had forty years ago.
What's your utility's experience with integrated vs. point solution workflows? I'm particularly interested in hearing from transmission planners dealing with high penetrations of inverter-based resources. How are your analysis workflows adapting?
CEO, ETAP
Follow
Tanuj began his career with ETAP over 21 years ago, and his contribution has proven instrumental in achieving and advancing ETAP’s growth strategy goals. In his previous role as Chief Technology Officer and Global VP of Business Development, Tanuj successfully orchestrated and managed teams, driving ETAP as the leading solution for power system design and operation.