Key Drivers of Energy Pricing Changes

Picture of the Week: European power prices are now lower than pre-Ukrainian times! The significant reduction in #European wholesale power prices in 2024 compared to 2021, especially in countries like #Spain and #Portugal, can be attributed to several key factors: 1. Expansion of Renewable Energy: Spain and Portugal have made substantial investments in #renewable energy, particularly #solar and #wind power. Since the onset of the Ukrainian crisis, these two countries have added nearly 20 GW of solar and wind capacity, which now represents about 15% of their total installed electricity capacity. This massive build-out of renewables has played a crucial role in reducing reliance on fossil fuels and lowering electricity prices. As a result, Spain has seen a dramatic increase in the share of #electricity generated from #renewables, rising from 51% in 2021 to 65% in 2024. This shift has significantly contributed to reducing wholesale power prices by half compared to 2021 levels. 2. Diversification Away from Russian Gas: The European Union, along with individual countries, has made concerted efforts to reduce dependence on #Russian #naturalgas, which was a major factor driving high energy prices during the 2022/2023 period. These efforts included securing alternative gas supplies, increasing LNG imports, and enhancing gas storage capacities. The shift away from Russian gas, coupled with a mild winter and lower overall demand for gas, has eased pressure on gas prices, which in turn has lowered electricity prices across much of Europe. 3. Energy Efficiency Measures: Governments across Europe have implemented #energyefficiency programs aimed at reducing overall energy consumption. These measures, along with public campaigns promoting energy savings, have contributed to reducing electricity demand, helping to stabilize or lower prices. 4. Government and Industry Cooperation: There has been close cooperation between governments and energy companies to stabilize the energy market.

I read a headline this morning suggesting that policies from the prior administration are to blame for higher power prices. Let’s be clear-eyed: electricity prices today are being driven by supply and demand. On the demand side, electricity needs are surging after decades of flat growth—driven by AI and new U.S. manufacturing. These are positive forces for long-term economic strength in the U.S., but they require generation that takes years to build. On the supply side, new generation faces headwinds: — Supply chain constraints (equipment such as turbines, labor, permitting cycles). — Policy uncertainty (federal incentives, permitting, interconnection). Both matter. Federal policy clarity is within the administration’s control, while fixing supply bottlenecks requires broad, coordinated effort. Until then, customers will see higher prices. For example, higher turbine costs and constrained labor mean gas plants coming online in the 2030s may cost $2,500–$3,000/kW, up from less than $1,000/kW just a few years ago. There are bright spots—particularly promising announcements around advanced nuclear and small modular reactors—but the real solution is diversity of supply options and investments in our grid, paired with stable, durable policies. Without all of this, customers will continue to face higher prices.

Electricity rates across the US reached their highest levels in 2024, rising an average of 4%. In the EIA’s January Short-Term Energy Outlook, they forecast wholesale prices will rise by 7% in 2025 (see figure below). The main driver: higher natural gas prices. The 2 markets projected to see lower rates are Texas and the Northwest, courtesy of increased solar deployment and more hydro production, respectively. In just 10 years, the US will need 50% more annual electricity generation than it does today (Brattle, figure below). Unless something changes, supply won’t keep up thanks to slow interconnection (IX), T&D constraints, and other factors. With electricity prices escalating for the foreseeable future, how do we keep #electricity prices low? An exercise useful for narrowing down solutions is called “The Opposite.” Seinfeld fans may remember this concept: “If every instinct you have is wrong, then the opposite would have to be right.” So ask this question: “What won’t bring down electricity prices?” Then do the opposite. Answer: Repealing or diminishing the Inflation Reduction Act (IRA) tax credits won’t bring prices down. Indeed, a recent study shows that by 2035, the loss of the PTC & ITC would increase generation system costs for consumers by 14% (NERA, figure below). Why? Because less of the lowest cost generation would be deployed (i.e., less #solar, #energystorage, and #windenergy). We have Texas as a real-world testbed. It’s a deregulated, competitive market with huge growth expected, and an IX process that works (build/manage). The data shows that Texas increased its #energy supply by 35% over the last 4 years and 92% (!) of that new supply came from solar, wind and #battery storage. In 2023 the Texas Legislature created a $5 billion Texas Energy Fund (TEF) for providing low-cost capital to spur 10 GW of #naturalgas plants, running counter to Texas free-market ideals. At first, the program was oversubscribed, but in February, Engie pulled out a 930 MW peaker plant citing “equipment procurement constraints, among other factors.” This won’t be the last project to drop out, because “other factors” include the inability of natural gas to compete with low-cost renewables plus storage. Consider: during the first week of March, ERCOT set records for wind (28.4 GW), solar (24.8 GW), and greatest #battery discharge (4.8 GW) (Canary). If TEF funds went toward more BESS capacity, my math shows it could support >10 GW of 4-hour storage. We are passed the point where low electricity prices and slowing climate change are mutually exclusive. The reality is that #cleanenergy assets have a faster path to commercial operation and better economics than nuclear and natural gas plants in many markets. One report shows #renewableenergy resources saved Texas #power consumers around $11 billion in the last 2 years (IdeaSmiths). To keep electricity prices low, we need the IRA in place. References in comments.

𝐄𝐮𝐫𝐨𝐩𝐞’𝐬 𝐄𝐧𝐞𝐫𝐠𝐲 𝐏𝐫𝐢𝐜𝐞𝐬 𝐢𝐧 𝟐𝟎𝟐𝟓: 𝐀 𝐘𝐞𝐚𝐫 𝐨𝐟 𝐃𝐢𝐯𝐞𝐫𝐠𝐞𝐧𝐜𝐞 2025 has been a fascinating year for European energy markets. After a volatile first half driven by geopolitics, fundamentals and strong market positioning took centre stage in the second half, reshaping the forward curves. 🔻 𝐍𝐚𝐭𝐮𝐫𝐚𝐥 𝐆𝐚𝐬: The biggest mover, with 𝐓𝐓𝐅 𝐂𝐚𝐥+𝟏 𝐝𝐨𝐰𝐧 𝐦𝐨𝐫𝐞 𝐭𝐡𝐚𝐧 𝟑𝟎% 𝐘𝐓𝐃. Key drivers? Strong correlation with weak Brent prices (in EUR/b) until Q4, then surging LNG imports into Europe thanks to soft Asian demand and the ramp-up of North American LNG exports + strong short positioning from investment funds. ⚫ 𝐓𝐡𝐞𝐫𝐦𝐚𝐥 𝐂𝐨𝐚𝐥: More resilient than gas. Global demand held steady (even rising in the US), while export cuts from Indonesia and Colombia supported prices. ⚡ 𝐄𝐥𝐞𝐜𝐭𝐫𝐢𝐜𝐢𝐭𝐲: Fragmentation deepened. France and Spain decoupled from Western Europe, supported by abundant low-carbon supply, muted demand growth, and cross-border constraints: 𝐅𝐫𝐚𝐧𝐜𝐞 𝐛𝐚𝐬𝐞𝐥𝐨𝐚𝐝 𝐂𝐚𝐥+𝟏 𝐩𝐫𝐢𝐜𝐞𝐬 𝐚𝐫𝐞 𝐝𝐨𝐰𝐧 𝟑𝟎% 𝐘𝐓𝐃. Germany and neighbours saw declines too, but less pronounced—higher carbon intensity and soaring EUA prices kept pressure on. 🔺 𝐂𝐚𝐫𝐛𝐨𝐧 (𝐄𝐔𝐀): The planned structural tightening for the coming years has been progressively priced in over the past months and the trend is continuing with 𝐭𝐡𝐞 𝐟𝐢𝐫𝐬𝐭 𝐄𝐔𝐀 𝐃𝐞𝐜𝐞𝐦𝐛𝐞𝐫 𝐜𝐨𝐧𝐭𝐫𝐚𝐜𝐭 𝐮𝐩 𝟏𝟓% 𝐘𝐓𝐃, supported by record long positions held by investment funds (as explained in a previous post). 👉 What’s next? Will this divergence persist in 2026? Which fundamentals will dominate? #EnergyMarkets #NaturalGas #Electricity #Commodities #EuropeEnergy #EnergyTransition #LNG #Carbon

Electricity prices aren’t rising for the same reasons everywhere (nor are they rising everywhere). As part of LBNL’s recent work, we explored what’s driving prices across the U.S. Our six case studies show just how diverse the drivers can be: ⚡Florida: Storm recovery and grid hardening pushed nominal prices up, while natural gas volatility added price variability 🔥California: Wildfire mitigation and liability costs, distribution upgrades, and net metering all contributed to higher prices in 2024 vs. 2019 ❄️Maine: Storm recovery, net billing, RPS requirements, and distribution costs drove recent increases; natural gas price fluctuations caused tremendous price variability 🌱Virginia: RPS requirements and gas costs pushed prices up, but demand growth helped offset some of those increases through 2024 📈North Dakota: A case where load growth + abundant energy = lower prices ⬆️Mid-Atlantic: PJM capacity prices caused significant recent price spikes in 2025 IMPORTANT: Price increases hurt the pocketbook but ideally offer longer-term value. I doubt anyone would argue that we should leave millions of households without power after a major hurricane because rebuilding will increase prices. Balancing price increases with value received is one of the most important tasks of policymaker and regulators.   A slide on the Florida case is shown below; for all six, see the PPTs at this link: https://lnkd.in/g6xN7EYT #ElectricityMarkets #EnergyPolicy #GridModernization #ElectricityPrices #RenewableEnergy #PowerSector #EnergyInsights

US gas is now a material driver of European price formation. Recent data puts US LNG at roughly a quarter of the EU’s total natural gas imports, reinforcing how North American weather and LNG flows increasingly transmit into European benchmarks. In January 2026, European natural gas prices surged by ~40% amid a “perfect storm” of cold weather, lower storage levels, and stronger demand, pushing benchmark futures above €40/MWh. The US market moved in parallel, with prices at their highest since 2022 as freezing temperatures constrained supply and tightened the global LNG balance. What is driving the spike - cold weather and higher-than-normal demand across Europe and North America, - lower European storage levels, reducing resilience to shocks - tight LNG availability and cargo competition, including diversions to Asia - added volatility from geopolitics, speculative positioning, and weaker wind output increasing gas-fired generation This is below the extreme price levels of 2022, but it is a rapid repricing that immediately pressures heating costs and energy-intensive industry. The strategic implication is clear: resilience comes from reduction of demand, diversification, flexibility, and credible demand-side measures. #Energy #NaturalGas #LNG #Europe #EnergySecurity

Remember when natural gas was supposed to be the "bridge fuel" that would gradually phase out? Well, Canadian producers just got a wake-up call that might flip that timeline. Deloitte's year-end report dropped some numbers that should have every clean energy professional taking notes. Canadian natural gas prices are projected to nearly double in 2025—jumping from the rock-bottom levels we saw throughout 2024 to around $2.15 per Alberta benchmark pricing. The catalyst? LNG Canada's export terminal comes online mid-2025. For the first time, Canada can export liquefied natural gas directly from its west coast. That fundamentally changes supply-demand dynamics across North America. What was an oversupplied, price-depressed market suddenly has a new outlet to global buyers willing to pay premium rates. Here's what this means for our sector: Corporate procurement teams are already recalculating their energy strategies. When natural gas price volatility increases, renewable power purchase agreements start looking like stability, not just sustainability. We're seeing this pattern play out in real-time across industrial customers—particularly in energy-intensive manufacturing and data centers. The timing couldn't be more strategic. Just as AI-driven electricity demand surges, traditional power generation costs are becoming less predictable. Energy security conversations are shifting from "How much renewable can we handle?" to "how fast can we scale renewable baseload alternatives?" But there's a complexity here that's worth acknowledging. Higher natural gas prices don't automatically equal renewable wins. They also mean higher peak power costs, potentially challenging grid operators managing intermittency. Clean energy companies are already positioning around storage solutions and demand response technologies that can capitalize on this price volatility. Regional nuance matters too. Western Canada has been producing record natural gas volumes while prices sat at historic lows. Now those same producers have an economic incentive to maintain high output levels—but for export markets, not domestic supply. That creates interesting arbitrage opportunities for renewable developers who understand regional grid dynamics. Looking ahead, this price shift accelerates conversations we've been having about energy independence. Companies that locked in renewable contracts over the past two years are going to look prescient. Those still weighing options just got a compelling data point about price risk in traditional energy portfolios. The question isn't whether this drives more renewable adoption—it's how quickly we can scale infrastructure to meet demand that's about to get more urgent. And for those working across the US-Canada energy corridor, how do you see this LNG export capacity affecting cross-border renewable project development?

𝗪𝗵𝘆 𝗔𝗿𝗲 𝗘𝗹𝗲𝗰𝘁𝗿𝗶𝗰𝗶𝘁𝘆 𝗥𝗮𝘁𝗲𝘀 𝗦𝗸𝘆𝗿𝗼𝗰𝗸𝗲𝘁𝗶𝗻𝗴? Before we argue about policy, renewables, or data centers, it helps to zoom out and look at what the data is actually doing. 𝗪𝗵𝗮𝘁 𝘁𝗵𝗲 𝗴𝗿𝗮𝗽𝗵𝘀 𝗮𝗿𝗲 𝘀𝗮𝘆𝗶𝗻𝗴 1️⃣ The CPI for electricity is up about 41% since January 2020. Customers feel this directly. 2️⃣ Utility scale electricity generation is not collapsing. It is rising and is now pushing new highs. So we have a situation where we are generating more power, yet the delivered price keeps climbing. 𝗧𝗵𝗿𝗲𝗲 𝗯𝗮𝘀𝗶𝗰 𝘄𝗮𝘆𝘀 𝘁𝗵𝗶𝘀 𝗰𝗮𝗻 𝗵𝗮𝗽𝗽𝗲𝗻 1️⃣ 𝗔𝗱𝗱𝗶𝘁𝗶𝗼𝗻𝘀 𝘁𝗼 𝗿𝗮𝘁𝗲 𝗯𝗮𝘀𝗲 𝗮𝗻𝗱 𝘁𝗵𝗲 𝗰𝗼𝘀𝘁 𝗼𝗳 𝘀𝗲𝗿𝘃𝗶𝗰𝗲 𝗺𝗼𝗱𝗲𝗹 When utilities can use securitization to keep retired coal plant costs inside the rate structure, that legacy cost does not just disappear. Then you stack new renewables and battery storage into rate base on top of it. The customer ends up paying for the past and the future at the same time, and rates can move up fast. 2️⃣ 𝗜𝘀 𝗶𝘁 𝗻𝗮𝘁𝘂𝗿𝗮𝗹 𝗴𝗮𝘀 𝗮𝗳𝘁𝗲𝗿 𝗖𝗢𝗩𝗜𝗗 Fuel and wholesale power costs spiked after COVID, and many customers see those costs flow through riders and adjustments. Even when fuel prices cool off, the recovery and lag in rate mechanisms can keep bills elevated. 3️⃣ 𝗜𝘀 𝗶𝘁 𝗱𝗮𝘁𝗮 𝗰𝗲𝗻𝘁𝗲𝗿 𝗱𝗲𝗺𝗮𝗻𝗱 𝗽𝘂𝗹𝗹𝗲𝗱 𝗺𝗮𝗶𝗻𝗹𝘆 𝗳𝗿𝗼𝗺 𝗴𝗿𝗶𝗱 𝗽𝗼𝘄𝗲𝗿 Load growth changes everything. Even if annual generation rises, the system is built for peaks, congestion, and local constraints. Big new loads can drive new infrastructure, capacity needs, and higher marginal costs in the places where the grid is already tight. 𝗪𝗵𝗮𝘁 𝗱𝗼 𝘆𝗼𝘂 𝘁𝗵𝗶𝗻𝗸 𝗶𝘀 𝗱𝗿𝗶𝘃𝗶𝗻𝗴 𝗲𝗹𝗲𝗰𝘁𝗿𝗶𝗰𝗶𝘁𝘆 𝗽𝗿𝗶𝗰𝗲𝘀 𝘁𝗵𝗲 𝗺𝗼𝘀𝘁?

The U.S. electricity market is highly fragmented, with regional variations shaped by different regulatory models, market structures, and policy environments. This comparison outlines key factors across major electricity markets and utility territories, including retail choice, capacity and ancillary services markets, price volatility, ISO/RTO participation, interconnection transparency, grid congestion, policy influence, DER support, and investment stability. These parameters are essential for developers, investors, and stakeholders aiming to navigate market complexity and deploy successful energy strategies. Discussion The table highlights major contrasts in market design and behavior: Retail Choice and Market Structure: ERCOT offers full retail choice with no capacity market, while ISO/RTOs like PJM and CAISO provide varying degrees of market access and regulatory oversight. Vertically integrated utilities like TVA and Southern Co lack retail choice and rely on internal resource planning, limiting competition. Price Signals and Market Access: ERCOT allows real-time price spikes up to $5,000/MWh, providing strong incentives for BESS and peaker participation. Other ISO/RTOs have price caps around $1,000–$2,000/MWh, while utility-run markets keep prices low and regulated. ISO Participation and Transparency: ISO/RTO markets maintain open interconnection queues, increasing visibility and investor confidence. In contrast, non-ISO regions often lack transparency, making project planning riskier. Congestion and Policy Influence: ERCOT and CAISO face high grid congestion, partly due to fast DER growth. CAISO also reflects significant policy-driven initiatives. Other markets like SPP or MISO have moderate congestion and lower policy volatility. DER Friendliness and Volatility: Markets such as ERCOT and PJM support DER growth, making them appealing to innovative technologies. Meanwhile, regulated utilities offer predictable investment conditions but limited opportunity for DER developers. Conclusion Each U.S. market offers distinct advantages and risks. ERCOT supports innovation and real-time pricing but comes with volatility. ISO/RTO regions offer a mix of structure and opportunity. Utility-dominated markets provide stability but reduced flexibility for third-party players. Success in these markets depends on deep knowledge of local rules, pricing dynamics, and development risks. Cordia Energy can help you navigate these challenges by developing, financing, and operating on-site energy systems that de-risk your project and free you to focus on your core business. Reach out to explore how we can support your energy goals. #cordia #energy #ercot #caiso