Energy Investment

📚 My Weekend Reading for Project Finance of Hydrogen projects The paper 'Bankability of Hydrogen Projects: Key Risks, Financing Challenges and Mitigation Solutions', published by the Oxford Institute for Energy Studies via this link: https://lnkd.in/dsiwEdVt This paper highlights the main lessons learned from successful hydrogen projects that have reached Final Investment Decision (FID), including the following points: 📌 Stable policy backing and long-term visibility NEOM in Saudi Arabia has benefited from clear national plans such as Vision 2030, strong government support, and consistent regulations. These factors helped the project secure billions of dollars in project funding. 📌 Securing bankable off-take agreements The 30-year fixed-price offtake agreement between NEOM Green Hydrogen Company and Air Products shifted the risk of changing market prices to a trusted partner, which made it easier to secure funding. In Europe, some projects have used contracts lasting 5-7 years instead of the usual 10 years or more. These shorter contracts often require investors to contribute about 50% more of their own money to cover the shorter period of stable income. Most funded projects have had reliable buyers or extra financial guarantees. 📌 Integrated infrastructure and value chain coordination The HySCALE project in Germany shows that placing hydrogen production close to factories in chemical parks can lower construction costs and reduce transportation risks. Projects that plan production, transport, and use of hydrogen together from the beginning are more likely to succeed because they reduce the risk of unused equipment. 📌 Effective risk mitigation instruments The Hydrogen Energy Supply Chain (HESC) project between Australia and Japan used major government grants and risk-sharing tools from both countries to handle early technology and market risks that commercial lenders would not have accepted on their own. Similarly, the European Investment Bank’s risk-sharing instruments have offered strong financial support, enabling projects to achieve bankable debt-to-equity ratios. 📌 Robust technical due diligence The REFHYNE project in Germany, which used a 10 MW PEM electrolyser at Shell’s Rheinland refinery, provided real-world data on performance, maintenance needs, and system integration. This information helped with the design and funding of larger projects later on. Careful checks of technology readiness, supply management, and system operation, supported by real-world testing, have made banks more confident in funding large project deployments.

Some investors in renewables made 3–5X returns. Others marked their investments to zero. The only difference? The type of bet they placed. In the last 9 years, renewable energy deals in India went from 134 to 230.  Total investment received - $62 billion But the money investors made when selling? Down 75%. But here's the strange part: some investors are losing money while others are making huge returns. The difference is simple. Two types of investors are playing completely different games: Type 1: Buying working renewable energy projects Think of this like buying a rental property that already has tenants paying rent. ↳ Brookfield paid $1.7 billion for solar and wind farms that are already operating.  ↳ Quebec pension fund paid $7 billion to buy a company that runs renewable energy plants. These farms have contracts to sell electricity at fixed prices for 20-25 years. Predictable money every month. Low excitement, but safe returns. Type 2: Betting on new renewable technology This is like investing in a startup before it makes any money. E-mobility jumped from 6% to 49% of deal volume by 2024. Battery storage grew from 1% to 9%. These sectors are projected to grow 12-35% annually. But they're not profitable yet. They need years to build, test, and scale. ↳ BlackRock marked down its Global Renewable Power Fund III to negative returns. ↳ Riverstone Holdings marked down at least seven investments, some to zero. What went wrong: 📍Startups bought at inflated prices didn't grow fast enough.  📍Government subsidies became uncertain.  📍High interest rates killed exit valuations. The lesson for investors managing significant capital: Mature renewables = lower returns but predictable income. Perfect for pension funds and family offices seeking stability. Emerging sectors = higher risk but 3-5X return potential. Only bet what you can afford to lose. Pick one strategy and stick to it. Which approach makes more sense for you?

What actually makes an energy project “bankable”? It’s rarely the technology. In practice, energy projects fail to reach financing not because the solution doesn’t work, but because the system around it isn’t ready. From experience across gas, clean cooking, and energy-efficiency projects, bankability usually comes down to five fundamentals: 1. Clear regulatory alignment: Financiers need certainty. Licensing, safety standards, tariffs, and approvals must be clearly mapped — not assumed. 2. Predictable revenue streams: Whether it’s LPG distribution, CNG supply, energy-efficiency services, or digital energy platforms, revenue must be structured, measurable, and resilient to shocks. 3. Strong operating model: Banks finance operations, not ideas. Logistics, maintenance, customer management, and risk controls matter as much as the technology itself. 4. Local content and partnerships: Projects with credible local partners move faster, face fewer disruptions, and build long-term trust with regulators and communities. 5. Risk allocation that makes sense: Successful projects don’t eliminate risk — they allocate it realistically across sponsors, operators, financiers, and customers. This is why energy bankability is not created in the boardroom alone. It’s built on the ground through pilots, regulatory engagement, and disciplined execution. As Tanzania accelerates its energy transition — across clean cooking, gas solutions, and energy efficiency — the real opportunity lies in designing projects for bankability from day one. That’s how good ideas become investable projects. #EnergyFinance #EnergyTransition #BankableProjects #CleanCooking #LPG #CNG #EnergyEfficiency #LocalContent #Tanzania #PublicPrivatePartnership

Most emerging energy projects are being priced as if the underlying technology behaves like a mature asset. Anyone who has worked inside an EPC team knows that is not the case. Hydrogen, Power to X, Carbon Capture, Battery Energy Storage, Small Modular Reactors, and Sustainable Aviation Fuel facilities are still early in their commercial life. The engineering packages may look complete, but the cost drivers behind them are not settled. Vendor information moves through several iterations. Installation methods are still evolving. Performance expectations are built on design intent rather than field data. This puts owners in a difficult position. They want predictable budgets and firm commitments. It puts contractors in an equally difficult position because they are expected to price and deliver against conditions that do not behave predictably in the field. The result is a maturity gap that affects cost accuracy, risk allocation, and contracting strategy. In this carousel I walk through how technology maturity shapes cost certainty, how first of a kind conditions show up even when the engineering appears stable, and why contract structure needs to match the real level of definition, not the perceived one. If you have worked on any of these projects, you will recognise the patterns. #Hydrogen #PtX #CCUS #BESS #SMR #SAF #EPC #CostEstimating #ProjectControls #ContractStrategy #RiskManagement #EnergyProjects #ConstructionEconomics #emeraldcost

The most valuable asset in the energy transition isn’t a new patent. It’s an old permit. There are 2,300 gigawatts sitting in U.S. interconnection queues right now. Only 13% of projects that applied since 2000 have ever reached commercial operation. Median wait from application to operation? Five years. In PJM territory? Eight. Meanwhile, Europe has 45 e-kerosene plants in development across 10 countries. Finland is converting stainless steel mill waste streams into jet fuel. Norway is producing e-SAF at existing industrial parks. Same physics. Different relationship with legacy infrastructure. If you’re building greenfield in North America today, you’re staring down years of permitting, years in the queue, and inflation eating your IRR every single month. So who’s actually skipping the line? Buyers who aren’t scouting cornfields. They’re scouting rust. Shuttered coal plants. Decommissioned refineries. Idle chemical facilities. To a traditional lender, these look like environmental liabilities. To strategic capital, they look like time machines: Active grid interconnection worth 4 to 8 years of queue time Grandfathered water rights irreplaceable in most jurisdictions Rail, pipe, and substation infrastructure that would cost a fortune to rebuild Homer City, Pennsylvania. The state’s largest coal plant shut down in 2023. By April 2025, announced as a $10 billion data center energy campus. Existing PJM and NYISO grid connections. Targeted power production by 2027. Four years from shutdown to new revenue. Phillips 66 Rodeo, California. Petroleum refinery converted to 800 million gallons per year of renewable fuels, including SAF. Repurposed existing hydrocracking units, marine terminals, and pipeline infrastructure. Full capacity reached in 2024. Two different end uses. Same playbook. Buy the bones. Now here’s where the math gets aggressive. The IRA made brownfields a triple play. These sites qualify as energy communities, unlocking a 10 percentage point bonus on clean energy investment tax credits. Stack that with remediation deductions and DOE loan guarantees, and you get the speed AND the subsidy. But the capital stack splits in an uncomfortable place. Traditional banks can’t underwrite cleanup. Too much binary environmental risk. Private credit fills exactly that gap. Wrapping the liability. Pricing the complexity. Funding the speed. While the greenfield developer fights for a grid study, the brownfield redeveloper is plugging into an existing substation and generating cash flow in 24 months. So here’s the question for asset owners still sitting on legacy industrial sites: Is the market valuing your property as a real estate play or an infrastructure play? Because the most valuable thing on the lot isn’t the land. It’s the grid connection underneath it.

Policy and private capital are finally aligning on nuclear. Recently, the U.S. Senate voted to appropriate $49 billion to the U.S. Department of Energy (DOE) including nearly $2 billion for the Office of Nuclear Energy and $3 billion for the Advanced Reactor Demonstration Program (ARDP). At the same time, Meta committed to 6.6 GW of nuclear capacity by 2035, working with Oklo Inc, TerraPower, Vistra Corp. and Constellation. Commonwealth Fusion Systems is also partnering with Nvidia and Siemens. Fusion companies TAE Technologies, Inc and General Fusion just went public – moving fusion into the public markets. ARDP funding supports projects with demonstrated capability. Loan programs help projects with clear commercial pathways. Private capital tries to make the best bets on commercial winners. Across all, the focus is on deployment - getting facilities built and operating. The nuclear environment is strengthening. Many companies are ready with different plans to scale. The best ideas should win – to the benefit of all. One way or another, new nuclear energy is coming!

A new national map Billy Roberts (National Laboratory of the Rockies) highlights where Enhanced Geothermal Systems (EGS) can be developed most effectively across the U.S. EGS is a technology that allows geothermal energy production without relying on naturally occurring hot water by drilling deep, enhancing rock permeability, and circulating fluid to extract heat. The result is 24/7 baseload power with long asset life and predictable output. What makes this map different is that it’s not theoretical. It evaluates where EGS development actually makes economic and operational sense, accounting for: ✅Required drilling depth to reach high temperatures ✅Power plant and development costs ✅Transmission and interconnection economics ✅Land-use and development constraints This shifts the conversation from “where geothermal exists” to where it can realistically be built and financed. Why this matters for real estate and infrastructure investing ✅Energy reliability influences land value Stable, local baseload power can materially affect long-term development feasibility. ✅Infrastructure tends to cluster around dependable power Industrial, data, and dense-use projects follow predictable energy supply. ✅Long-duration assets require long-duration energy EGS aligns structurally with infrastructure-style investments: long life, low volatility, and operational stability. ✅Underwriting is increasingly location-sensitive Power availability and transmission constraints are becoming core inputs, not afterthoughts. This map offers an early view into how subsurface energy economics may quietly shape future development patterns across U.S. markets, especially beyond traditional energy hubs. Worth paying attention. #Geothermal #EGS #InfrastructureInvesting #RealEstateDevelopment #EnergyTransition #LongTermCapital

Good News, Thursday. As electricity demand keeps rising across the U.S., we need power that can come online fast. A recent deal between HASI and Sunrun shows one way forward. The two companies just closed a $500 million joint venture to finance distributed energy assets, more than 300 megawatts of capacity across roughly 40,000 residential solar and battery systems. That's meaningful power, delivered not through a single large project, but through thousands of homes already connected to the grid. What caught my attention isn't just the size. It's what it signals. This is capital being structured around distributed energy assets like residential solar and battery systems installed on homes, bundled together and financed as infrastructure. Some of these systems are already producing power today, and others can be deployed quickly using standardized designs. Instead of waiting years for new power plants and transmission lines, this approach treats home energy systems as real grid assets that can support reliability and peak demand right now. It connects to a pattern we're seeing across the energy system. As AI, data centers, and electrification push demand higher, the biggest constraint isn't ideas, it's speed. Large centralized projects take time. Transmission takes longer. Distributed energy and repowering existing assets can add capacity faster and with fewer bottlenecks. This deal suggests investors are getting comfortable with that reality. Long-term residential energy assets are being financed like infrastructure now, with recurring cash flows, grid value, not just rooftop hardware. The same logic applies whether you're talking about home batteries, virtual power plants, or repowering aging solar projects. The common thread is making better use of what’s already built and scaling solutions that can move now, not a decade from now. At Do Good Energy, we see this shift playing out in real time. Capital is moving toward assets that already work, and the market is favoring quick and adaptable solutions rather than just focusing on large-scale operations. Good news doesn't always look like a single big power plant. Sometimes it's smarter capital, better structures, and thousands of small assets adding up to something that matters.

Most people think investing in EV infrastructure is all about volume: more charging stations means better returns, right? But the real game-changer is focusing on the details at each site. Instead of using broad averages, we're diving into the nitty gritty with address-level data. This means looking at specifics like local EV populations and nearby competition. It’s not just about plopping down chargers everywhere; it’s about placing them where they’ll actually get used. By using AI forecasting and hyper-local site selection, companies are seeing up to 20% better ROI. They avoid low-traffic sites and make sure they’re not overbuilding. It's a smarter, not harder, approach. Scenario analysis is another tool we're using. With so many unknowns—like EV adoption rates and energy prices—running different scenarios helps us understand when we'll break even. Investors now want to see scenario-based IRR and NPV outputs to prepare for policy shifts or market changes. Profitability isn’t just about utilization rates. We also look at pricing strategies, electricity costs, and capital costs. For instance, a fast-charge station in California showed losses at 15% utilization. But with either a slight increase in usage or a price bump, it could break even. It's about knowing which levers to pull. Public incentives are crucial too. With initiatives like the US NEVI fund, blending public grants into financing plans can significantly boost project returns. By incorporating these incentives, we can reduce net capital costs substantially. Partnerships are another strategic move. Collaborating with infrastructure investors can turn upfront capital expenditures into service agreements, improving returns on equity. These partnerships help spread risk and tap into lower-cost capital. Finally, long-term risks like tech obsolescence and downtime are factored into financial models. We’re looking at depreciation schedules and maintenance costs, ensuring we're prepared for any eventuality. In the end, it’s about being smart with where and how we allocate capital. Let’s keep the conversation going. How are you navigating these complexities in your investments?