Key Assumptions in Renewable Energy Market Analysis

In the next 5 years, the US will be facing resource adequacy challenges due to a combination of high demand growth, thermal generator retirements, not enough energy storage, and generator interconnection delays. The “not enough energy storage” issue appears because the energy transition is replacing base load generation (high-capacity credit) with variable #renewableenergy (VRE) resources (low-capacity credit). Solar and #windenergy assets need to be combined with energy storage to approach the capacity credit (CC) of the thermal resources being replaced. Capacity credits capture what fraction of a resource’s nameplate capacity can be expected to contribute to meeting demand during peak periods. In November 2024, NREL published a report on CC values of #renewableenergy and #energystorage. The 1st figure below shows average CC’s across technologies from 2026 to 2050. Between regions and scenarios, CC’s differ widely, but still, this is instructive. #Solar CC’s are low and decline as penetration rates increase, which drives a gradual shift of peak net load hours to hours with little solar generation. The wind CCs over time are explained by a combination of project development cycles and penetration levels. Energy storage CC’s are high, and 4-hour #battery capacity credits range between 66% and 100%. The 2nd figure is from FERC’s 2023 Market Report and shows the nameplate capacity net additions & retirements from 2013 to 2023 by resource type. Zooming in on MISO, note that resource additions will only cover retirements if they have similar capacity credit (they don’t), and negligible #energystorage was added. A back of the envelope calculation demonstrates why NERC’s Reliability Assessment (Dec 2024) has characterized MISO as “High Risk” to fall below established resource adequacy criteria. Assumptions were made to simplify this math (MISO’s accreditation for resources is highly seasonal, controversial, and in flux). Remove 26 GW of coal (85% CC) and 2 GW of nuclear (95% CC) means MISO was down 24 GW over the period. Add 17 GW of wind (22% CC), 8 GW solar (25% CC), and 2 GW Nat Gas (80% CC), and this adds back 7.3 GW. This is a net loss of over 16.5 GW of “real” capacity. Obviously, this is not sustainable, especially considering the 9 GW of load growth expected in MISO by 2029 (Grid Strategies). Similar scenarios are playing out across other markets in the US. Delaying thermal retirements is the current answer, but retirements typically happen when assets are no longer economically running. If they suddenly become economic, it probably means they are getting paid more (i.e. electricity prices will rise). This also means #sustainability progress goes in reverse. A better solution is to fix IX processes, carefully plan for load growth, and add more energy storage along with VRE’s. Indeed, the NREL report shows the average CC of 4-hour #energy storage stays above 70% at penetration levels past 50% of peak load. References in comments.

"Low-cost energy ≠ low-cost electricity." The future of energy is clearly renewable, nevertheless, thinking that countries with a bigger installed base of renewables are having cheaper electricity prices is one of the most misunderstood dynamics in today’s energy transition. Countries with higher shares of installed renewables (like wind and solar) often see higher electricity prices for several key technical, economic, and policy-related reasons: ⚡ 1. Intermittency Requires Backup and Balancing Renewables like wind and solar are variable — they don’t produce energy 24/7. ✅ You need backup systems (like gas turbines or batteries) to keep the grid stable when renewables underperform. ✅ This requires redundant infrastructure — which raises system-level costs, even if solar/wind are cheap on a per-kWh basis. 🛠️ 2. Grid Upgrades & Storage Infrastructure To handle renewables, grids need: ▪️ More transmission lines (to move power from remote wind/solar farms) ▪️ Advanced grid management systems ▪️ Energy storage (batteries, pumped hydro, etc.) 🔧 These investments are expensive, and costs are often passed to consumers. 📈 3. Subsidies and Tariff Structures In many countries: ▪️ Renewables were subsidized early on with feed-in tariffs (FITs) that guaranteed high returns to investors. ▪️ These long-term contracts are still being paid via electricity bills — even if newer projects are cheaper today. So paradoxically, more renewables can mean higher retail prices, especially in countries that adopted them early and aggressively. 🏭 4. Merit Order Effect + Capacity Market Distortions While renewables can push wholesale prices down in the short term (because they have zero marginal cost), this creates problems: ▪️ It undermines profitability for flexible backup plants (like gas), which are still needed. ▪️ So governments add capacity payments to keep them around — another cost that lands on the consumer. 🌍 5. Policy Design > Technology Cost Cheap renewables ≠ cheap electricity — unless: ▪️ Policies are well-designed ▪️ Grids are resilient ▪️ Markets are flexible enough to integrate renewables without inefficiencies Compare: ▪️ 🇩🇪 Germany: >50% renewables, high prices due to early subsidies and costly grid balancing. ▪️ 🇸🇪 Sweden or 🇫🇮 Finland: lots of nuclear + hydro = low emissions and more stable prices. The key to affordable green energy is not just more renewables — but smart system design, baseload reliability, flexibility, and balanced investments in storage, nuclear, and grid modernization. #EnergyTransition #CleanEnergy #Decarbonization #SustainableEnergy #ElectricityPrices #EnergyMarkets #GridModernization #EnergyPolicy #RenewableEnergy #SmartGrid #TechForGood #EnergyEconomics

Current market designs assume perfect information and risk-neutral investors. But real-world conditions create coordination failures that undermine the energy transition. New research modeling California's 2025-45 pathway shows stark deviations from optimal outcomes: system costs rise 3-14% under risk aversion, wholesale prices jump from $85/MWh to $108-136/MWh, and carbon emissions increase substantially. Loss of load expectation soars from 0.4 to 10 hours/year. Investment in renewables and storage gets delayed while fossil plant retirements stall, creating a vicious cycle that slows decarbonization. This suggests pure price signals aren't enough. Market design reforms need complementary mechanisms to coordinate low-carbon investment with fossil phaseout. Research by Alexis Lebeau, Marie P., Simon Quemin, and Marcelo Saguan.

𝐒𝐨𝐥𝐚𝐫 𝐏𝐕 𝐯𝐬 𝐒𝐨𝐥𝐚𝐫 𝐏𝐕 + 𝐁𝐄𝐒𝐒: 𝐀 2025 𝐅𝐢𝐧𝐚𝐧𝐜𝐢𝐚𝐥 & 𝐏𝐞𝐫𝐟𝐨𝐫𝐦𝐚𝐧𝐜𝐞 𝐂𝐨𝐦𝐩𝐚𝐫𝐢𝐬𝐨𝐧 (𝐔𝐒 𝐌𝐚𝐫𝐤𝐞𝐭) This post summarizes a 𝐟𝐢𝐧𝐚𝐧𝐜𝐢𝐚𝐥 𝐚𝐧𝐝 𝐨𝐩𝐞𝐫𝐚𝐭𝐢𝐨𝐧𝐚𝐥 comparison between: 🔹 100 MW Solar PV (standalone) 🔹 100 MW Solar PV + 200 MWh BESS (2-hour, C-0.5) 📌 𝐀𝐬𝐬𝐮𝐦𝐩𝐭𝐢𝐨𝐧𝐬: US utility-scale market CAPEX, OPEX, and PPA rates benchmarked from recent 2024–2025 projects CUF ~21–22% Annual degradation ~0.25% Debt 70% (12 yrs @ 9%), Equity 30% 👉 Actual results will vary by location, interconnection, market design, incentives, and project structure — but this gives a realistic project-level outline. 🔍 𝐊𝐞𝐲 𝐏𝐫𝐨𝐣𝐞𝐜𝐭 𝐇𝐢𝐠𝐡𝐥𝐢𝐠𝐡𝐭𝐬 100 𝐌𝐖 𝐒𝐨𝐥𝐚𝐫 𝐏𝐕 (𝐒𝐭𝐚𝐧𝐝𝐚𝐥𝐨𝐧𝐞) CAPEX: ~USD 100M (≈ USD 1.0M/MW) PPA: ~USD 45/MWh Annual Generation: ~188 GWh Annual Revenue (Yr-1): ~USD 8.5M Equity IRR: ~13–16% Payback: ~7–9 years Strength: Lowest cost clean energy Limitation: Daytime-only generation, price cannibalization risk 100 𝐌𝐖 𝐒𝐨𝐥𝐚𝐫 𝐏𝐕 + 200 𝐌𝐖𝐡 𝐁𝐄𝐒𝐒 Total CAPEX: ~USD 127M BESS cost assumed: USD 125/kWh PPA with storage: ~USD 55/MWh Same solar generation, but dispatchable & firmed Annual Revenue (Yr-1): ~USD 10.3M Equity IRR: ~15.5–19% Payback: ~6.5–8.5 years Strength: Peak shaving, energy arbitrage, grid flexibility Trade-off: Higher CAPEX & operational complexity 📊 𝐖𝐡𝐲 𝐇𝐲𝐛𝐫𝐢𝐝 𝐏𝐫𝐨𝐣𝐞𝐜𝐭𝐬 𝐀𝐫𝐞 𝐆𝐚𝐢𝐧𝐢𝐧𝐠 𝐌𝐨𝐦𝐞𝐧𝐭𝐮𝐦 🔋 Peak-hour value > energy-only value ⚡ Reduced curtailment & improved grid reliability 💰 Higher monetization per MWh 🌱 Strong fit for IRA tax credits & ESG capital Key takeaway: PV maximizes cost efficiency. PV + BESS maximizes value. At current US prices, hybrid projects are increasingly outperforming standalone PV on equity returns, especially where peak pricing or capacity value exists. Visit👉https://alendei.energy/ for 𝐒𝐨𝐥𝐚𝐫, 𝐁𝐄𝐒𝐒 𝐄𝐏𝐂𝐬, 𝐈𝐧𝐯𝐞𝐬𝐭𝐦𝐞𝐧𝐭, 𝐂𝐨𝐧𝐬𝐮𝐥𝐭𝐚𝐭𝐢𝐨𝐧 Alendei from Bharat Alendei Green RE Pvt. Ltd. #RenewableEnergy #SolarEnergy #WindEnergy #EnergyTransition #NetZero #IPP #UtilityScaleSolar #OnshoreWind #SolarEPC #WindEPC #ReNewPower #AdaniGreen #TataPowerRenewables #Suzlon #InoxWind #JSWEnergy #NTPC #SECI #SterlingAndWilson #LarsenAndToubro #ACWAPower #Masdar #DEWA #EWEC #NEOM #AmeaPower #AlFanar #CEPCO #SaudiEnergy #UAEEnergy #LekelaPower #Globeleq #Azuri #AfreximBank #KenGen #Eskom #ZESCO #AfricaIPP #NextEraEnergy #Invenergy #PatternEnergy #AESCorporation #NRG #DukeEnergy #Exelon #DominionEnergy #Enbridge #BrookfieldRenewables #AlgonquinPower #HydroOne #OntarioPowerGeneration #EDFrenewables #EDPRenewables #BPAlternativeEnergy #ClearwayEnergy #ApexCleanEnergy #FirstSolar #TrinaSolar #CanadianSolar #JinkoSolar #BechtelEPC #BlackAndVeatch #BurnsAndMcDonnell #RESAmericas #Vestas #VestasAmericas #GErenewables #SiemensGamesa #Nordex #NordexAcciona #TeslaEnergy #EatonEnergy #ABBPowerGrids #AtlasRenewableEnergy #EnelGreenPower #Neoenergia #Energisa

Many of the assumptions that shape climate & energy policy today were formed >20 years ago. They no longer describe the world we live in. In the early 2000s, clean technologies were expected to remain expensive. Storage was assumed to be niche. Industrial processes were treated as rigid. Energy demand was considered fixed. And decarbonization was framed as an economic trade-off: higher costs for climate benefits. The overall perceptions have stuck, shaping our systems -- as we have BLOWN past those expectations: • Utility-scale solar is now among the most competitive sources of new power in many markets. • Battery, heat-pump, and other electrification technologies are cost-competitive in many contexts. • Digital tools now enable real-time forecasting, optimization, and coordination at scales unimaginable 20 years ago. And now, we are seeing that operational flexibility is feasible and viable across nearly every major demand category: buildings, water pumping and desalination, EVs and charging networks, commercial refrigeration, data centers, etc... Today, Maria de Miguel, Jessika Trancik, Caroline Narich, and Christine Gschwendtner add imp't new findings on industrial flexibility: https://lnkd.in/emFi6Zz5 Their work shows that large industrial facilities -- previously assumed to have rigid demand -- can offer meaningful, predictable demand flexibility. Industrial clusters can also act like a large-scale storage, supporting renewable integration and reducing system strain. Our old models did not anticipate this. As the researchers explain, industrial flexibility can: • lower system costs and reduce the need for peakers, transmission, and storage; • increase reliability and resilience; • and create strategic and economic value for industry and the broader economy. Flexibility has become central to modern energy systems. We have the technologies and the economics are favorable. What's most often missing is the coordination across industry, utilities, grid operators, regulators, policymakers, and finance. The lack of coordination is perpetuated by the continued use of outdated models which consistently over-estimate costs and under-estimate how dynamic energy systems have become, and how much value comes from that flexibility. These outdated models consistently under-value efficiency, flexibility and other low-cost solutions, and either lead to over-investment in excess capacity or result in delayed transitions because of inflated estimates of financing needs. We need new models that reflect today's system realities and how far technology has come, and that center the role flexibility can play in our modern energy systems. AND we need to double down on the coordination (among utilities, regulators, industry, policy, finance) that is decisive to making these transitions financeable.