A Coordinated Electric System Interconnection Review—the utility’s deep-dive on technical and cost impacts of your project.

Challenge: Frequent false tripping using conventional electromechanical relays
Solution: SEL-487E integration with multi-terminal differential protection and dynamic inrush restraint
Result: 90% reduction in false trips, saving over $250,000 in downtime

The global energy transition is reshaping electricity systems at a speed and scale that has no historical precedent. Wind and solar now supply growing shares of generation across many regions, coal plants are retiring, and the concept of 'firm' baseload power is evolving. As the grid shifts, so does the nature of the reliability challenge.

At Keentel Engineering, we work at the intersection of power system planning, grid analysis, and energy transition strategy. In this brief, we draw on insights from a detailed technical webinar analyzing resource adequacy in Great Britain through the 2030s — a study particularly relevant for any power system undergoing deep decarbonization.

The questions raised are not unique to Britain. They are the same questions grid planners, utilities, regulators, and engineering firms are grappling with across North America, Europe, and beyond: How do you keep the lights on when weather drives your generation? What role does storage play during prolonged scarcity events? How do you model correlated risk across interconnected regions? And what does a reliable, decarbonized power system actually require?

Traditionally, power system stress meant one thing: peak demand on a cold winter evening with a generator unexpectedly offline. That single-axis framing is no longer sufficient.

In a highly renewable system, stress is multi-dimensional. The detailed modeling analysis we examined identified a vivid example: a stress event in mid-to-late February, driven simultaneously by:

High electricity demand during a cold spell
A collapse in wind and solar output — what German-speaking grid operators call 'Dunkelflaute' (dark, windless days)
Constrained imports from neighboring regions experiencing the same weather conditions

Within roughly 48 hours, available renewable generation dropped from around 60 gigawatts to near zero. At the same time, interconnector imports from continental Europe fell sharply because the cold spell extended across northwestern Europe simultaneously. The system was stressed from three directions at once.

Energy storage both short-duration batteries and longer-duration technologies such as pumped hydro and hydrogen — plays a critical role in managing these multi-day stress events. The modeling examined in the webinar revealed something important that is often overlooked in high-level storage discussions: the dispatch strategy matters as much as the installed capacity.

Three storage dispatch strategies were modeled and compared:

Immediate action — deploy maximum capacity as soon as stress is detected
Shortfall depth minimization — hold back reserves to smooth the depth of any shortfalls across the event
Mixed approaches — combinations of the above depending on foresight horizon

The striking finding: all three strategies produced the same total expected unserved energy across the year. But the hours of loss of load and the depth of individual shortfall events varied significantly depending on the strategy chosen. In other words, how you operate your storage fleet determines not whether customers experience outages, but how long those outages last and how severe they are.

This has direct implications for storage operations market design, and system operator protocols. It also reinforces that storage is not a passive resource it is an active, strategic tool that must be carefully integrated into grid operations frameworks.

The resource adequacy analysis covered in the webinar is built on a sophisticated hourly dispatch model. Understanding the methodology is important because it directly shapes the confidence one can have in the outputs.

Key methodological features:

Hourly time resolution: The model simulates dispatch on an hour-by-hour basis across a full modeled year, starting April 1 rather than January 1 — a deliberate choice to keep winter periods intact and avoid splitting the highest-stress season across two modeling years.

34 years of historical weather data: Rather than relying on synthetic peak events, the model runs across 34 years of observed weather patterns. This captures a realistic range of Dunkelflaute events, cold spells, and other stress drivers.

100 random outage patterns per weather year: Plant outages are modeled probabilistically. For each weather year, 100 different outage patterns are simulated, giving 3,400 total simulation runs per portfolio — a computationally intensive but statistically robust approach.

Imperfect foresight for storage: Unlike many models that assume perfect knowledge of future conditions, this model assigns storage a two-day perfect foresight window and a longer-term probabilistic outlook — more realistic and more conservative than full-foresight assumptions.

Simplified but detailed European import modeling: Rather than re-running a full pan-European model for every simulation, the team developed an upfront import availability time series that captures correlated continental weather risk. Europe is modeled as constrained to a Loss of Load Expectation (LOLE) of three hours — a conservative assumption that limits the import surplus available to GB during stress.

1. Decarbonization and adequacy are not in conflict

One of the most important findings from the analysis is that a highly decarbonized power system can be built to meet reliability targets. Across six portfolio scenarios — all featuring significantly increased renewable capacity, with offshore wind, onshore wind, and solar as the dominant generation sources — systems were designed to meet a LOLE target of 0.1 to 0.3 hours per year.

This directly challenges the assumption that decarbonization inherently degrades reliability. It is technically achievable to have both. The question is not whether to pursue decarbonization, but how to plan, design, and operate the resulting system.

2. Dispatchable capacity remains essential through 2040

Even in portfolios that aggressively add renewables, storage, and interconnection, dispatchable generation — capacity that can be called upon reliably regardless of weather — remained necessary through the 2040 modeling horizon.

In most scenarios, around 10 gigawatts of unabated gas generation remained on the system by 2040, operating at very low annual running hours but providing essential backup during stress events. This raises two important engineering and policy questions:

What is the economic viability of low-utilization gas plants? Market design and capacity remuneration mechanisms may need to be restructured.
What does the aging generation fleet look like? Much of the existing gas fleet was commissioned before 2000, meaning by the 2030s many units will be approaching end-of-life. Decisions about refurbishment, life extension, or new-build replacements are approaching.

Crucially, the analysis notes that this dispatchable requirement does not have to be met by gas. Long-duration energy storage — if it can maintain sufficient charge across a multi-day stress event — could serve the same function. This is an active area of exploration.

3. Weather is now the dominant driver of reliability risk

In the scenarios modeled, weather — specifically the occurrence of Dunkelflaute conditions emerged as the dominant driver of loss of load events. Just two or three historical weather years (out of 34 modeled) accounted for the vast majority of system stress.

A fascinating secondary finding: within a single stressed weather year, plant outage management had a significant impact on outcomes. Simulations with better outage coordination during the February 1986 stress event showed no loss of load at all — a powerful demonstration that operational excellence during stress periods matters enormously.

This also highlights a gap in current planning practice: if historical weather data from 30–40 years ago is used without adjustment, it may not capture the full range of stress events relevant under current and future climate conditions. Expanding weather datasets potentially to thousands of synthetic or climate-adjusted years — is a priority research direction.

Great Britain's interconnectors — DC links to France, Belgium, the Netherlands, Norway, Denmark, Germany, and Ireland — play a significant role in system adequacy. Sensitivity analysis removing all imports showed a substantial increase in loss of load hours, with the effect growing more pronounced toward 2040.

However, interconnection is a double-edged asset. The same cold weather that stresses the British system also stresses continental European systems. During the simulated February stress event, available imports fell sharply precisely when they were most needed. The correlated nature of weather risk across interconnected regions means that import availability cannot be assumed with confidence during system stress.

This has direct implications for grid planning:

Interconnection capacity should be counted conservatively in reliability assessments, with explicit weather-correlation adjustments
Stress testing should model worst-case import availability — not average availability — during peak scarcity
Bilateral and multilateral arrangements for emergency sharing must account for the possibility that all parties are under stress simultaneously

A specific sensitivity test fixed demand-side flexibility (DSF) capacity in one portfolio at 2030 levels and held it constant through 2040, rather than allowing it to grow. The results were nuanced:

Overall LOLE change was modest — DSF growth did not dramatically change the number of hours of loss of load
However, within stress events, expected unserved energy increased significantly when DSF was constrained

The practical interpretation: demand-side flexibility is most valuable not for preventing outages entirely, but for limiting the severity of outages that do occur. It reduces the depth of shortfall events — the total amount of energy not served during a crisis — rather than eliminating the events themselves.

For engineering teams designing demand response programs, this finding suggests that valuation frameworks focused purely on peak demand reduction may underestimate DSF's contribution to system resilience. Metrics that capture unserved energy depth, not just hours of outage, are needed.

The methodology described here represents current best practice, but the field is advancing rapidly.

Key areas being actively developed include:

Expanded weather datasets: Moving from 34 historical weather years to thousands of synthetic years, potentially using climate modeling outputs to better capture the tails of the weather distribution — where the most severe stress events live.
Probabilistic stress event framing: Beyond asking 'how much loss of load do we expect,' the field is moving toward 'what is the probability of a specific type of stress event?' This enables more precise risk communication to policymakers and regulators.
Transmission constraint integration: Current models often treat the system as a single copper plate. Modeling internal transmission constraints adds another layer of geographic risk — some areas may face more acute stress than system-level averages suggest.
Large load and electrification impacts: Data center loads, EV charging, heat pump adoption, and industrial electrification all add new demand patterns that may alter the timing and nature of stress events. Explicit modeling of these loads is becoming essential.
Long-duration storage operation: Hydrogen storage, compressed air, pumped hydro across seasons — modeling these technologies' behavior across multi-week or seasonal timescales requires new approaches to foresight and dispatch optimization.

At Keentel Engineering, we translate findings like these into practical guidance for clients in project development, system planning and policy support. The key engineering implications from this analysis include:

Storage sizing should account for multi-day stress durations, not just daily arbitrage — the storage envelope matters as much as the power rating
Portfolio design should include diverse resource types that perform differently under the same weather conditions — portfolio diversification reduces correlated risk
Reliability modeling for planning applications should move toward probabilistic, weather-conditional frameworks rather than deterministic single-point peak analysis
Aging thermal fleet decisions — retirement, refurbishment, replacement — need to account for the dispatchable reserve role these assets play in a future high-renewable system
Interconnection agreements and cross-border planning should be structured to account for simultaneous stress and not assume import availability during high-demand, low-renewable periods

In 1995, Sandip (Sonny) R. Patel earned his Electrical Engineering degree from the University of Illinois, specializing in Electrical Engineering . But degrees don’t build legacies—action does. For three decades, he’s been shaping the future of engineering, not just as a licensed Professional Engineer across multiple states (Florida, California, New York, West Virginia, and Minnesota), but as a doer. A builder. A leader. Not just an engineer. A Licensed Electrical Contractor in Florida with an Unlimited EC license. Not just an executive. The founder and CEO of KEENTEL LLC—where expertise meets execution. Three decades. Multiple states. Endless impact.