Managing Seasonal Demand Fluctuations

"One of the key ways to make energy systems more reliable is by maximizing flexibility — improving how well the system can adapt in real time to changes in supply and demand. The more flexible the system, the better it can handle sudden demand spikes in the event of extreme weather, such as cold snaps or heat waves, or respond to supply disruptions such as plant outages. Improving flexibility includes upgrading aging infrastructure. Much of the U.S. grid was built decades ago under different demand patterns. Modernizing the grid — by updating substations and transmission equipment, deploying advanced sensors and incorporating advanced transmission technologies (ATTs), for example — can reduce failure rates during extreme heat and cold. These technologies help operators detect problems quicker, reroute power if equipment is damaged and restore service fast. Modernization not only improves reliability but also reduces expensive emergency interventions and lowers long-term maintenance costs. Increasing grid capacity, both through deployment of ATTs and building regional and interregional transmission lines, can reduce the risk of a local weather event turning into a widespread outage. Creating a more interconnected grid allows regions to share power during shortages. Having this greater transmission capacity also help keep prices down by allowing lower-cost electricity to reach areas facing higher demand. Demand-side management options can help ease pressure on the system during extreme weather events. These include encouraging customers and large users to reduce or shift electricity use during peak periods in exchange for lower bills or leveraging distributed energy resources to help prevent shortages. Systems that rely too much on a single fuel are more vulnerable to disruption. Diversification across energy sources and technologies helps reduce the risk of issues related to fuel shortages, infrastructure failures and localized weather impacts. Finally, policy is also critical. It’s vital that incentives are properly aligned with modern needs for flexibility and preparedness. This can help utilities make system investments that really work in extreme weather and minimize costs to consumers in both the short and the long run." Kelly Lefler World Resources Institute https://lnkd.in/e5syqXQp

Some of us keep talking about DERs and better grid utilization to help solve the power demand problem. Excited to see things are starting to move in that direction. For years, when utilities needed to meet peak demand, the answer was almost automatic: build a gas peaker plant. That assumption is starting to crack. Not because of ideology—but because the math is changing. Take Consolidated Edison’s Brooklyn-Queens Demand Management program. Instead of building a new gas peaker and substation upgrade, they deployed a portfolio of distributed energy resources—efficiency, rooftop solar, and behind-the-meter batteries. It delivered the same reliability outcome at a fraction of the cost. Or look at what’s happening more broadly with virtual power plants—aggregations of home batteries, smart thermostats, EVs, and flexible loads. In places like California and Texas, these systems are now being treated as real capacity resources—able to shave peaks and reduce the need for fossil peakers. What’s emerging is not a one-off workaround. It’s a pattern. Distributed energy resources are increasingly taking over the role that gas peakers used to play: meeting short-duration spikes in demand, cheaply and quickly. And now there’s a new twist: Large loads—especially data centers—are beginning to join that stack. Through demand flexibility and workload shifting, they can act less like passive demand and more like dispatchable capacity. If this continues, the implications are significant: • Less need to build new gas peakers • Lower system costs (because DERs are modular and faster to deploy) • A grid that’s more flexible—and more participatory To be clear: DERs aren’t replacing all firm capacity. We still need solutions for multi-day reliability and extreme events. But they don’t have to. If DERs can cover even 10–20% of peak demand by 2030—as several analyses suggest—that’s enough to avoid a large share of new peaker builds. The “default” is shifting from one big plant solving the problem to a portfolio of smaller, smarter resources working together. That’s not just a technology story. It’s a different way of thinking about the grid. Keep watching this trend ….

Battery Energy Storage Systems (BESS) help Malaysian homes and businesses cut bills after the tariff hike by shifting usage from expensive peak hours (e.g., 2–10 pm weekdays) to off-peak periods, shaving maximum demand/capacity charges, and maximizing self-consumption of rooftop solar. For residences (best for higher-usage or solar homes), 5–15 kWh LFP batteries store midday solar or cheap night power for evening use and provide seamless backup. For commercial users, 30–500 kWh (scalable to MWh) batteries flatten daily peaks, arbitrage ToU price gaps, and smooth HVAC/chiller loads—often delivering 6–7%+ total energy-cost reduction, faster if paired with PV. Industrial sites deploy MW/MWh-scale systems to trim costly MD spikes (saving tens of thousands monthly), ride through disturbances, improve power quality, and comply with 2025 rules that require storage for >72 kWp self-consumption PV, while enabling deeper PV usage. Economics are boosted by GITA (100% capex tax allowance for BESS) and green financing, making solar+storage paybacks commonly ~3–6 years in C&I (longer for typical homes, shorter for large users). Key actions: right-size battery to your peak window, enroll in ToU where suitable, integrate with PV for >80% self-use, prioritize critical-load backup, and use smart controls to target the exact 30-minute peaks that set charges. Overall, BESS turns tariff volatility into savings and resilience across residential, commercial, and industrial sectors.

When the duck curve turns into an all-day plateau, industrial consumers need either fuel-switching options or long-duration storage to stay competitive. Today’s day-ahead prices in the DE-LU bidding zone look very different from the usual pattern. The typical midday dip is missing; instead, prices stay high from early morning until late evening. With an average of 220.5 €/MWh, 25 November now ranks as the third most expensive trading day of 2025, surpassed only by two extreme days in January. And the situation is not easing: the forecast for 26 November remains only marginally lower. 𝐖𝐡𝐲 𝐩𝐫𝐢𝐜𝐞𝐬 𝐫𝐞𝐦𝐚𝐢𝐧 𝐞𝐥𝐞𝐯𝐚𝐭𝐞𝐝 𝐟𝐨𝐫 𝐯𝐢𝐫𝐭𝐮𝐚𝐥𝐥𝐲 𝐭𝐡𝐞 𝐞𝐧𝐭𝐢𝐫𝐞 𝐝𝐚𝐲 A set of reinforcing factors compresses the price curve upward: ➤ Weak wind and solar generation limit supply across all hours. ➤ Low temperatures keep the residual load above 65 GW, even during midday. ➤ Structural scarcity in dispatchable capacity, as recently highlighted by Andri Busch. On top of that: once short-duration storage is exhausted, demand becomes largely inflexible, reducing the system’s ability to respond to price spikes. ➤ Additional contributors may be at play, potentially including local market power effects. The outcome is a remarkable spread between electricity and natural gas: for several consecutive hours, power prices exceed ten times the gas spot price (~32 €/MWh). 𝐖𝐡𝐚𝐭 𝐭𝐡𝐢𝐬 𝐦𝐞𝐚𝐧𝐬 𝐟𝐨𝐫 𝐢𝐧𝐝𝐮𝐬𝐭𝐫𝐢𝐚𝐥 𝐞𝐧𝐞𝐫𝐠𝐲 𝐮𝐬𝐞𝐫𝐬 Industries with substantial process-heat requirements face a simple fact: without a non-electric heat source or a high-temperature, long-duration storage asset, they are forced into producing heat at highly unfavorable electricity prices. Both strategies, fuel-switching or long-duration storage, are becoming critical elements of cost resilience. 𝐖𝐡𝐲 𝐬𝐭𝐨𝐫𝐚𝐠𝐞 𝐝𝐮𝐫𝐚𝐭𝐢𝐨𝐧 𝐦𝐚𝐭𝐭𝐞𝐫𝐬 In a renewables-driven system, short-duration storage smooths volatility but does not compensate for system-wide generation deficits spanning an entire working day. When price plateaus persist for eight hours or more, only technologies capable of shifting energy across multi-hour to multi-day intervals can stabilise operations and costs. These include: ➤ Long-duration thermal storage ➤ Hydrogen-ready or hybrid plants ➤ Other forms of long-duration energy storage (LDES) Days like today make one point unambiguously clear: flexibility is not solely about rapid response. It is about endurance. A renewables-based system requires assets that can maintain supply through extended scarcity periods without defaulting back to additional fossil capacity. Brenmiller Energy ENERGYNEST KRAFTBLOCK Kyoto Group AS Rondo Energy et al.

Reflecting on recent reports of peak demand shortages that the #IndianGrid is tackling, I was trying to make sense of energy storage arbitrage opportunities—particularly for 2-hour and 4-hour systems. India’s electricity demand surged to ~240 GW in April 2025, a 10% YoY growth driven by summer heat, industrial recovery, and rural electrification. Per capita consumption hit 1,500 kWh, echoing urban and economic momentum. Yet, evening peak demand (6–9 PM) consistently outstripped supply, with ~5–10 GW deficits in northern states. On the supply side, India’s 450 GW capacity (175 GW solar, 50 GW wind) saw renewables contribute 42% of generation. But midday solar surplus (10 AM–3 PM) led to grid congestion, and coal—still 60% of non-solar generation—faced 15–20% outages. This imbalance makes a compelling case for flexible storage. IEX price signals add weight. A short IEX data scan and some back-of-the-envelope math reveal this: day-ahead (G-DAM) prices during solar hours hover around ₹4.00–₹4.20/unit, while RTM/G-TAM evening peaks spike to ₹7.50–₹8.50/unit. That ₹3.50–₹4.50/unit gap opens a solid arbitrage window. A 1 MW/4 MWh lithium-ion BESS charging at ~₹4.00/unit and discharging at ~₹8.00/unit (90% efficiency) nets ~₹12,250/day post O&M. On strategy: 2-hour systems (₹25 lakh/MWh, 95% efficiency) suit sharp evening peaks (6–8 PM). A 1 MW/2 MWh setup earns ~₹6,100/day, ideal for C&I demand charge management. 4-hour systems suit 6–10 PM peaks and morning ramps—earning ~₹12,250/day, with ~2.2-year payback (validated by SECI’s ₹3.52 lakh/MW/month BESS tender). Grid challenges persist—17% AT&C losses, $11.38Bn DISCOM debt—but BESS enables peak shaving, coal displacement, and supports the 500 GW RE goal. With VGF and evolving real-time markets, storage economics are shifting. Still, let’s be clear: arbitrage won’t last forever. As BESS scales up, price differentials may shrink. Grid modernization, smart dispatch, and reforms like Time-of-Day tariffs will compress margins. Arbitrage is a bridge—not the destination. Storage, especially lithium-ion, remains central to grid integration. With AI-driven IEX bidding, profit margins can rise 10–15%. Winter peaks (Nov–Jan) offer more windows. India’s grid is evolving. Storage is no longer a tool—it’s the backbone of resilience. Let’s seize today’s arbitrage, while preparing for tomorrow’s smarter, stacked models. #IndianEnergy #GridOperations #EnergyStorage #BESS #IEX #Arbitrage #Renewables #NetZero2030 #StorageEconomics #PeakDemand

On 24 June 2026, the Belgian day-ahead spot price reached a daily average of €257/MWh, with a peak close to €933/MWh at 9 p.m. This type of situation illustrates the new reality of European power systems: more interconnected, more renewable, but also more exposed to extreme events. During a heatwave, demand rises sharply: air conditioning, chillers, ventilation, industrial processes, cold chain logistics. During the day, solar power can help cushion the system. But in the evening, solar generation drops rapidly while demand remains high. If wind generation is low, the system loses a second source of natural flexibility. In Belgium, this is compounded by the heavy maintenance of extended nuclear reactors, notably Doel 4 and Tihange 3, as part of their lifetime extension programme. This temporary unavailability significantly reduces the low-carbon dispatchable baseload available during the summer. Belgium then has to rely more heavily on imports, gas-fired power plants and available flexible capacity. However, during a European heatwave, neighbouring countries are also under pressure. The price is therefore no longer set by the average cost of generation, but by the last capacity called upon: often gas, constrained imports or scarce flexibility. For industrial players, the conclusion is clear: a strategy that is too dependent on the spot market creates direct exposure to these extreme episodes. Energy performance can no longer be limited to buying cheaper electricity. It must integrate resilience, flexibility and the ability to manage consumption dynamically. This means combining long-term contracts, PPAs, solar self-consumption, cogeneration, storage, demand response and intelligent load management. Industrial companies that are able to shift, smooth or secure their consumption will gain a competitive advantage. Conversely, those that remain passive in the face of the market will be increasingly exposed to volatility. One of John Cockerill’s missions is precisely to help industrial customers limit the impact of these peaks: through energy audits, transformation plans, local generation solutions, energy recovery, flexibility, storage and intelligent control. Data source: ENTSO-E – Belgium, 24/06/2026. #EnergyTransition #ElectricityMarket #EnergyEfficiency #IndustrialDecarbonization #EnergyResilience #JohnCockerill

From Problem to Opportunity Some might see it as a problem whereas some might see an opportunity. Now putting in context of Pakistan Power System this is the average hourly load demand based on the actual recorded load demand of ISMO for Year 2024/25. We can see two distinct features huge drop in demand during solar hours thanks to DER penetration and large peak demand in evening hours. So can we turn this problem into an opportunity. Based on my understanding of CTBCM, current market participants would be => Generators => Suppliers/Traders => Bulk Power Consumers (BPCs) What if we extent this category to include two new participants say =>Virtual Power Plants (VPPs). Aggregators of distributed generation, storage, and flexible demand. Allowing them to sell aggregated energy or capacity to suppliers, traders, or even BPCs through bilateral contracts. =>Demand Response Aggregators (DRAs). Entities that pool flexible consumer loads and sell negative watts (reduced demand) as capacity or energy resources. Allowing then to turn consumption flexibility into a tradable resource. These new participants can allow reduction in steep net demand fall caused by solar generation from rooftops and embedded PV. Instead of curtailing solar or running thermal units inefficiently, VPPs can export surplus to nearby industrial loads through local trading arrangements. On the other hand, as solar output fades, demand spikes DRAs can activate flexible loads (HVAC, pumping, industrial processes) to temporarily reduce demand. Together, VPPs and DRAs flatten the load curve, transforming an operational challenge into a market opportunity. CTBCM already provides the institutional and contractual foundation. What’s missing is the regulatory recognition of flexibility as a market product. Introducing VPPs and DR Aggregators can provide a structured way to monetize flexibility, help reduce ISMO balancing costs and empowering consumers to become active market participants. #CTBCM #VirtualPowerPlant #DemandResponse #GridFlexibility #PakistanPowerSector #EnergyTransitionPakistan #learning

𝐔𝐧𝐝𝐞𝐫𝐬𝐭𝐚𝐧𝐝𝐢𝐧𝐠 𝐌𝐚𝐱𝐢𝐦𝐮𝐦 𝐃𝐞𝐦𝐚𝐧𝐝: 𝐀 𝐊𝐞𝐲 𝐭𝐨 𝐑𝐞𝐝𝐮𝐜𝐢𝐧𝐠 𝐄𝐥𝐞𝐜𝐭𝐫𝐢𝐜𝐢𝐭𝐲 𝐂𝐨𝐬𝐭𝐬💰 For commercial and industrial consumers, electricity bills include an important component "𝐃𝐞𝐦𝐚𝐧𝐝 𝐂𝐡𝐚𝐫𝐠𝐞𝐬" which directly influence monthly electricity costs. With recent regulatory changes in Maharashtra, including an increase in Minimum Billing Demand (from 50% to 75%) and demand charges, it has become even more critical to understand and manage demand efficiently. 𝐖𝐡𝐚𝐭 𝐢𝐬 𝐌𝐚𝐱𝐢𝐦𝐮𝐦 𝐃𝐞𝐦𝐚𝐧𝐝 ? 🔍 Maximum Demand (MD) is the highest electrical load (kVA) drawn during any 15- or 30-minute interval in the billing cycle. In #Maharashtra, MD is calculated based on IS 14697, using the sliding window method, which identifies the highest average power over a continuous 30-minute interval. Since utilities must maintain infrastructure capable of serving this peak load, demand charges are applied to recover these costs. 𝐌𝐢𝐧𝐢𝐦𝐮𝐦 𝐁𝐢𝐥𝐥𝐢𝐧𝐠 𝐃𝐞𝐦𝐚𝐧𝐝 📌 Minimum Billing Demand is the minimum demand a consumer will be billed for, irrespective of actual usage. This means even if your actual MD is low, the utility will still bill you for at least minimum billed demand (currently 75% of your Contract Demand). 𝐇𝐨𝐰 𝐭𝐨 𝐌𝐚𝐧𝐚𝐠𝐞 𝐨𝐫 𝐑𝐞𝐝𝐮𝐜𝐞 𝐌𝐚𝐱𝐢𝐦𝐮𝐦 𝐃𝐞𝐦𝐚𝐧𝐝 📉 ■ Shift loads to off-peak hours ■ Implement energy efficiency upgrades ■ Improve operational planning and stagger equipment start-up ■ Use automatic demand controllers ■ Deploy Battery Energy Storage Systems – the most effective modern solution 𝐇𝐨𝐰 𝐁𝐄𝐒𝐒 𝐇𝐞𝐥𝐩𝐬 𝐑𝐞𝐝𝐮𝐜𝐞 𝐌𝐚𝐱𝐢𝐦𝐮𝐦 𝐃𝐞𝐦𝐚𝐧𝐝🔋 Battery Energy Storage Systems charge during off-peak periods and discharge during peak load events, shaving the peak and keeping MD well within limits. Benefits: ✓ Reduce Maximum Demand charges ✓ Avoid Maximum Demand penalties ✓ Right-size Contract Demand to avoid unnecessary Minimum Build Demand charges ✓ Improve utilization of renewable energy (Solar PV + BESS) ✓ Enhance power quality and reliability By keeping MD lower #BESS helps optimize and potentially reduce Contract Demand, resulting in lower fixed monthly demand charges and reduced electricity bills. 𝘞𝘪𝘵𝘩 𝘪𝘯𝘤𝘳𝘦𝘢𝘴𝘪𝘯𝘨 𝘥𝘦𝘮𝘢𝘯𝘥 𝘤𝘩𝘢𝘳𝘨𝘦𝘴 𝘺𝘦𝘢𝘳-𝘰𝘯-𝘺𝘦𝘢𝘳 𝘢𝘯𝘥 𝘳𝘢𝘪𝘴𝘪𝘯𝘨 𝘵𝘩𝘦 𝘮𝘪𝘯𝘪𝘮𝘶𝘮 𝘣𝘪𝘭𝘭𝘦𝘥 𝘥𝘦𝘮𝘢𝘯𝘥 𝘵𝘩𝘳𝘦𝘴𝘩𝘰𝘭𝘥, 𝘱𝘳𝘰𝘢𝘤𝘵𝘪𝘷𝘦 𝘔𝘋 𝘤𝘰𝘯𝘵𝘳𝘰𝘭 𝘢𝘯𝘥 𝘊𝘰𝘯𝘵𝘳𝘢𝘤𝘵 𝘋𝘦𝘮𝘢𝘯𝘥 𝘰𝘱𝘵𝘪𝘮𝘪𝘻𝘢𝘵𝘪𝘰𝘯 𝘩𝘢𝘷𝘦 𝘣𝘦𝘤𝘰𝘮𝘦 𝘦𝘴𝘴𝘦𝘯𝘵𝘪𝘢𝘭. 𝘉𝘌𝘚𝘚-𝘣𝘢𝘴𝘦𝘥 𝘱𝘦𝘢𝘬 𝘴𝘩𝘢𝘷𝘪𝘯𝘨 𝘱𝘳𝘰𝘷𝘪𝘥𝘦𝘴 𝘢 𝘴𝘮𝘢𝘳𝘵, 𝘳𝘦𝘭𝘪𝘢𝘣𝘭𝘦, 𝘢𝘯𝘥 𝘴𝘶𝘴𝘵𝘢𝘪𝘯𝘢𝘣𝘭𝘦 𝘱𝘢𝘵𝘩𝘸𝘢𝘺 𝘧𝘰𝘳 𝘤𝘰𝘴𝘵 𝘳𝘦𝘥𝘶𝘤𝘵𝘪𝘰𝘯 𝘢𝘯𝘥 𝘤𝘢𝘳𝘣𝘰𝘯 𝘳𝘦𝘥𝘶𝘤𝘵𝘪𝘰𝘯.🌍 Let’s build awareness and empower industries to move toward a greener, more efficient energy future.🌱 Shared here MSEDCL's FAQ for Maximum Demand Calculation !!! #Sustainability #RenewableEnergy #SolarEnergy #MaximumDemand

Are you tired of paying for MDI? It can be reduced significantly and even avoided! Many industrial facilities invest heavily in solar to reduce their electricity bills, yet their Maximum Demand Indicator (MDI) charges remain frustratingly high. The reason is simple. Utilities don't only charge for the energy you consume (kWh). They also charge for the highest power demand (kW) your facility draws from the grid during a billing period. Imagine a factory operating at an average load of 2 MW. For a few minutes, multiple motors, compressors, or production lines start simultaneously, causing demand to spike to 3 MW. Even if that peak lasts only a short time, it can significantly impact monthly demand charges. This is where BESS creates value. Instead of allowing the facility to draw the full 3 MW from the grid, the battery instantly discharges and supplies the additional 1 MW required during the peak event. As a result: • Grid demand remains capped at 2 MW • MDI charges are reduced • Power quality improves • Existing electrical infrastructure experiences less stress This application is known as PEAK SHAVING. Unlike backup power applications where batteries may remain idle for weeks, peak-shaving BESS systems can generate value every day by reducing demand charges and optimizing energy consumption. A common misconception is that BESS is only for power outages. In reality, for many industrial facilities, the strongest business case is often not backup power but reducing recurring demand charges through intelligent peak management.

It’s 16:30 on a Tuesday. Your facility manager just received September’s electricity bill. €47,300. 8% higher than August. Same kWh consumption. He can’t explain why. Neither can you. Here’s why this happens (and how to fix it in under 30 days): The structural problem: European electricity bills have two cost components most companies overlook: Energy cost: €/kWh × consumption Peak demand charges: penalty for maximum consumption during specific windows That second component can reach 30–40% of your bill. And it’s optimizable without reducing production. The Temporal Optimization Framework (implementation: 30 days): Week 1: Temporal Consumption Mapping You don’t need expensive tech—just data you already have. Tools: bills from the last 12 months + monitoring software. Objective: identify three things: Which equipment consumes most? When does it operate? Does it coincide with premium price windows? Output: visual map of hourly consumption vs rates. Week 2: Quick Win Identification Ask operations: “Which of these processes MUST run at these hours for technical reasons?” Answer: “None. We’ve always done it this way.” Quick wins: → Battery charging (forklifts, equipment): move to 02:00–06:00 → Cleaning cycles: shift off-peak → HVAC pre-heating: adjust timing → Batch processes: reschedule off-peak Week 3: Pilot Test Don’t change everything at once. Pick one high-consumption process and move it off-peak for two weeks. Measure: Operational impact (usually none) Bill reduction (typically 12–18% for that line item) Example (logistics company, Belgium): shifted EV charging from 18:00–20:00 to 23:00–05:00. Savings: €28K annually. Implementation: 4 days. Week 4: Rollout & Monitoring Extend changes to all identified processes. Add alerts if peak use exceeds thresholds. The maturity model: Level 1 (70% of companies): Monitor monthly consumption. Level 2 (30-day goal): Monitor hourly consumption. Optimize timing. Level 3 (6-month goal): Automate load shifting on real-time prices. Typical investment: Monitoring software: €2–5K Facility manager time: 20 h over 4 weeks Operational changes: €0 (reprogramming) Typical return: Cost reduction: 15–25% Payback: 2–4 months Year 1 savings: €50K–250K depending on facility size The metric that matters: Your timing Power Factor — ratio between peak and off-peak consumption. Ideal: 0.6 (40% less in peak). European average: 1.4 (40% more). If you don’t know your ratio, you’re overpaying. Immediate action: Ask your supplier for hourly consumption data from the last three months. With that and a few hours of analysis, you have your savings roadmap. Timing isn’t sustainability. It’s operational intelligence. Are you going to keep paying premium for convenience? Sources: Helexia Belgium operational efficiency projects, European tariff structures, Industrial Energy Management best practices. #LoadShifting #SmartEnergy #FacilityOptimization #EnergyManagement #IndustrialIoT #OperationalEfficiency #Helexia