Energy Investment

Solar + BESS under KUSUM 2.0! Strong intent, but outcomes will hugely depend on design discipline. If there is? The proposal to integrate battery storage with solar under KUSUM 2.0 is a structurally sound intervention. It directly addresses the temporal mismatch between solar generation (midday peak) and agricultural demand (morning–evening persistence, mostly non-peak solar hours), enabling firming, peak shaving, and improved feeder-level supply quality. However, deployment at the 33/11 kV level is inherently design-sensitive and CANNOT follow a template approach. First, the system context must anchor sizing. Feeder-level solutions must be aligned with upstream grid conditions, existing renewable penetration, and seasonal demand variability. The objective is not maximising solar injection, but optimising system balancing and cost. Second, marginal procurement cost is the decisive benchmark. Solar+BESS must be evaluated against the avoidable cost of power—typically short-term or high-cost purchases—not the average pooled cost. The discovered tariff should be compared with this marginal cost to determine both viability and optimal capacity sizing. Power during solar hours might be dirt cheap on the exchange in the near future, so utilities must be very mindful before entering into 25-year-long Solar+BESS PPAs. Third, the feeder load profile is a non-negotiable input. Hourly demand shape, irrigation patterns, and diversity of load will define storage duration and power rating. Misalignment here leads to either stranded storage or unmet peaks. Fourth, decisions must be lifecycle-based. Battery degradation curves, round-trip efficiency, augmentation/replacement cycles, and O&M costs must be internalised through LCOS/LCOE frameworks—not just upfront capex. Fifth, hybrid optimisation is often superior. A combination of solar (daytime), BESS (peak shifting), and grid supply (residual demand) typically minimises total system cost versus a fully standalone design. Sixth, portfolio impact is critical. Discoms already carry long-term PPAs. The key question: what cost is being displaced? If solar+BESS replaces cheaper contracted power, it erodes value despite being “green”. Seventh, structuring matters—capex vs opex. Asset ownership, risk allocation, and balance sheet constraints should guide whether utilities procure energy-as-a-service or invest directly. Finally, technical integration is non-trivial. Protection coordination under bidirectional flows, voltage/reactive power management, forecasting error handling, SCADA integration, and battery cycling strategy will determine operational success. In essence, solar+BESS under KUSUM 2.0 is not just a capacity addition—it is a system optimisation problem. The quality of techno-economic design will determine whether it reduces cost or merely adds assets. Bottom line: Each Solar+BESS plant will have to be designed as an individual entity based on how it adds/erodes value to the power system.

Not every C&I solar project is viable, I learnt this the hard way. It’s easy to jump at the show of a new C&I lead. Many developers and EPCs assume that every working factory, mart, farm, or hospital is a viable solar candidate. You scan industrial rooftops, chase meetings, and finally get invited to perform site assessments and energy audits. Excitement builds. You involve the engineering team, you design diligently, you push hard through your process. But then, weeks or months in, you hit a roadblock: the economics don’t stack, the client can’t commit, or the financier isn’t convinced. C&I projects aren’t about panels and batteries. They’re about business cases. And business cases need to make sense to two groups: The Offtakers → clients who must see real savings and operational value. The Financiers → investors who must see risk-adjusted returns. If you can’t defend both sides, then what you have is not a project, it’s just a lead. So, how do you qualify early? Start with three fundamental filters: 1️⃣ Load Profile: Does the client’s consumption pattern align with solar generation? A factory running 8 am–6 pm is viable. A hotel with peak load at midnight may not be, unless they’re ready to pay for storage. 2️⃣ Tariff Environment: What benchmark are you competing against? If grid tariffs are cheap and reliable, solar won’t make economic sense. But if diesel costs are spiraling, solar PPAs suddenly become compelling. 3️⃣ Client’s Energy Spend & Financial Strength: Is power a material cost for the business (e.g., power costs 20% of OPEX in agro-processing = urgent). And beyond these, you must run feasibility studies. They’re not paperwork. They’re the due diligence backbone: Technical → can the system physically work? Financial → do the numbers hold under stress tests? Legal/regulatory → are there barriers to connect or operate? Operational → will the client maintain and honor commitments? 🚩 Red flags you must not ignore: → Night-heavy loads with no storage appetite. → Clients with poor creditworthiness. → Subsidized tariff environments where solar can’t compete. → Weak roof structures or no space for panels. → Clients treating energy as a “nice to have” rather than a strategic priority. #SolarEnergy #RenewableEnergy #CISolar #EnergyTransition #PPAs #SolarProjects #EnergyFinance #CommercialSolar #IndustrialSolar #ProjectFinance #EnergyManagement #SolarDevelopment

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?

Your CFO just asked you to justify €850K in solar CAPEX to a board that's been burned by three "strategic investments" in the last 18 months. You have 15 minutes to prepare. Here's the framework that's working in 2025: The Zero-CAPEX Reframe 𝐃𝐨𝐧'𝐭 𝐩𝐫𝐞𝐬𝐞𝐧𝐭 𝐬𝐨𝐥𝐚𝐫 𝐚𝐬 𝐚 𝐜𝐚𝐩𝐢𝐭𝐚𝐥 𝐢𝐧𝐯𝐞𝐬𝐭𝐦𝐞𝐧𝐭. 𝐏𝐫𝐞𝐬𝐞𝐧𝐭 𝐢𝐭 𝐚𝐬 𝐚 𝐜𝐨𝐬𝐭-𝐞𝐥𝐢𝐦𝐢𝐧𝐚𝐭𝐢𝐨𝐧 𝐜𝐨𝐧𝐭𝐫𝐚𝐜𝐭. What the Board Hears: "We want €850K to install solar panels." Translation: Another balance sheet burden. Another 8-year payback nobody will be here to see. What They Should Hear: "We're signing a 15-year electricity contract at €0.11/kWh, locked. Zero upfront cost. Maintenance included. Immediate savings vs. our current €0.187/kWh grid rate." 𝐓𝐫𝐚𝐧𝐬𝐥𝐚𝐭𝐢𝐨𝐧: 𝐋𝐨𝐰𝐞𝐫 𝐎𝐏𝐄𝐗. 𝐏𝐫𝐞𝐝𝐢𝐜𝐭𝐚𝐛𝐥𝐞 𝐜𝐨𝐬𝐭𝐬. 𝐒𝐨𝐦𝐞𝐨𝐧𝐞 𝐞𝐥𝐬𝐞 𝐨𝐰𝐧𝐬 𝐭𝐡𝐞 𝐫𝐢𝐬𝐤. The Three-Scenario Comparison: Scenario A: Do Nothing → Current: €0.187/kWh (Belgium industrial average, Febeliec 2025) → 2027 with ETS2: €0.22-0.25/kWh → 10-year cost: €3.4M → Risk: Unhedged against volatility Scenario B: CAPEX Purchase (€850K upfront) → Balance sheet hit: €850K → Payback: 7-8 years → Maintenance: Your responsibility → CFO's unanswerable question: "What's salvage value in Year 10?" Scenario C: EaaS/PPA Model (€0 upfront) → Locked rate: €0.11/kWh for 15 years → Year 1 savings: €180K → 10-year savings: €1.8M → Balance sheet impact: €0 → Maintenance: Provider's responsibility Which scenario gets approved? In Helexia's 2024-2025 portfolio, most of corporate projects used EaaS/PPA models. Not because companies don't have capital—because CFOs prefer predictable OPEX over unpredictable CAPEX ROI. Healthcare Facility, Belgium: €670K solar investment rejected twice. Third presentation reframed as EaaS: → €0 upfront → Locked rate €0.105/kWh for 20 years → Monthly savings: €14,300 → Board approval time: 22 minutes Installation: 4 months. Savings: Day 1. The Pragmatic Rule: If your board keeps rejecting solar investments, stop presenting solar investments. Present energy cost reduction contracts that happen to use solar. Same outcome. Different risk profile. Different approval rate. The question nobody asks: If you can pay €0.187/kWh to the grid with zero price protection, why can't you pay €0.11/kWh to a solar provider with 15-year price lock? The only difference is who owns the panels. And in 2025, ownership is a liability—not an advantage. Sources: Febeliec 2025, Helexia ESCO/PPA portfolio analysis, European EaaS adoption trends Has your CFO rejected solar on CAPEX grounds, or on savings grounds? Because one is solvable. The other isn't real. #EnergyAsAService #CFO #SolarFinancing #ESCO #PPA #CostReduction #Helexia

📢 𝐀𝐟𝐫𝐢𝐜𝐚 𝐈𝐬𝐧’𝐭 𝐑𝐢𝐬𝐢𝐧𝐠. 𝐈𝐭’𝐬 𝐑𝐞𝐜𝐚𝐥𝐢𝐛𝐫𝐚𝐭𝐢𝐧𝐠 While headlines chase volatility, serious capital is already moving—quietly, strategically—into Africa’s key markets. This isn’t momentum. It’s realignment. And it’s time to act with precision. After a focused month of execution and strategic engagement, I return to this platform to reconnect, share insights from the field, and build partnerships where capital meets long-term value. 👣 𝐌𝐚𝐫𝐜𝐡 𝟐𝟎𝟐𝟓: 𝐀𝐟𝐫𝐢𝐜𝐚 𝐢𝐧 𝐌𝐨𝐭𝐢𝐨𝐧 Mozambique is reasserting global relevance. • The U.S. ExIm Bank unlocked $4.7B to restart TotalEnergies’ LNG megaproject. • ADNOC Group’s XRG division finalized its acquisition of a 10% stake in Mozambique’s Rovuma Basin Area 4—securing access to over 25 mtpa of LNG capacity and deepening UAE’s strategic footprint in global gas markets. • Mozambique & Zambia signed a $411.5M agreement to develop a 400kV cross-border transmission line—strengthening regional energy integration & boosting trade within the Southern African Power Pool. 🌍 𝐀𝐜𝐫𝐨𝐬𝐬 𝐭𝐡𝐞 𝐜𝐨𝐧𝐭𝐢𝐧𝐞𝐧𝐭, 𝐜𝐚𝐩𝐢𝐭𝐚𝐥 𝐢𝐬 𝐫𝐞𝐨𝐫𝐢𝐞𝐧𝐭𝐢𝐧𝐠. • Eni announced the $1.65B sale of its upstream assets in Côte d’Ivoire and the Republic of the Congo to Vitol—signaling a strategic reallocation of energy holdings across West and Central Africa. • Glencore’s Astron Energy (Pty) Ltd. committed $328M to upgrade its Cape Town refinery—aligning with South Africa’s Clean Fuels II regulations and reinforcing the country’s energy security amid a 75% reliance on fuel imports. 💣 𝐒𝐞𝐜𝐮𝐫𝐢𝐭𝐲 𝐚𝐧𝐝 𝐫𝐢𝐬𝐤 𝐫𝐞𝐦𝐚𝐢𝐧 𝐩𝐚𝐫𝐭 𝐨𝐟 𝐭𝐡𝐞 𝐞𝐪𝐮𝐚𝐭𝐢𝐨𝐧. • Nigeria declared emergency rule in Rivers State following pipeline attacks that disrupted key oil infrastructure—reinforcing the need for risk intelligence in investment strategies. 💰𝐌𝐞𝐚𝐧𝐰𝐡𝐢𝐥𝐞, 𝐧𝐞𝐰 𝐦𝐨𝐦𝐞𝐧𝐭𝐮𝐦 𝐛𝐮𝐢𝐥𝐝𝐬. • Mining, renewables, & industrial sectors are repositioning with stronger capital discipline and operational focus. 🔗 𝐖𝐡𝐞𝐫𝐞 𝐈 𝐒𝐭𝐚𝐧𝐝 These aren’t my projects. But this is the ecosystem I operate in. Africa is moving. Capital is shifting. Execution will define who leads. I work with global investors to: • Shape opportunities across Africa’s key markets; • Navigate complexity with clarity; • Partner locally—with aligned interests and results in mind. 🎯 𝐋𝐞𝐭’𝐬 𝐂𝐨𝐧𝐧𝐞𝐜𝐭 𝐖𝐢𝐭𝐡 𝐈𝐧𝐭𝐞𝐧𝐭𝐢𝐨𝐧 Africa is not a short-term trend. It’s a long-term transformation. Those who build early—and build well—will define the next cycle of growth. 📩 If you’re ready to partner with someone who works on the ground and alongside you, let’s talk. All updates referenced are based on March 2025 developments from Reuters, Financial Times, Bloomberg, #ADNOC & others.🚀🌍👌🏽 #AfricaMeansBusiness #StrategicCapital #ExecutionMatters #EmergingMarkets #AfricaOpportunities #LocalPartnerships #InvestmentLeadership #GrowthMarkets #InstitutionalInvestors #PrivateCapital

VPPs Are All the Rage – But They’re Not Just for Households! ⚡ Virtual Power Plants (#VPP) are once again a hot topic—and for good reason! The focus often falls on aggregating smaller players, like households or small producers, into a unified power source. However, the VPP model is just as relevant for large-scale producers managing a portfolio of Power Purchase Agreements (#PPA) from renewable assets like wind, solar, and storage. By treating renewable assets as an integrated portfolio, substantial value can be unlocked. Additionally, centralized portfolio management helps protect revenue against the volatile effects of renewable-dominated markets Turning Your PPA Bundle into a VPP  Managing a portfolio of PPAs from wind, solar, and storage assets mirrors the process of a “small” VPP. Through technology, these assets can be interconnected which then allows for the optimization across various energy markets, from ancillary services to bilateral PPAs. This portfolio approach maximizes the efficiency of diverse assets through centralized control, just like a VPP. How to Transform Your PPA Portfolio into a VPP 1. Digitally Connect Your Assets Gain the ability to operate your units as a single entity by connecting them through infrastructure and software, which are readily available and proven effective. 2. Build a Dedicated Commercial Team Start with a revenue management strategy that covers the full spectrum of PPA durations—from long-term contracts to day-ahead markets and ancillary services. This specialized team should structure, price, and execute PPA, hedging, and trading strategies. Most of the execution work can be outsourced as well, but oversight and control over partners remain essential 3. Enhance Data and Analytics Implement systems that offer deep insights into revenue streams, risk profiles, and market changes' impacts. Robust data and analytics are essential to managing a dynamic portfolio. The Benefits of Operating a Large-Scale VPP  A large-scale renewable portfolio managed as a VPP—even one based on long-term PPAs—can drive meaningful savings through reduced Route-to-Market and balancing costs while generating additional revenues. These gains arise from the flexibility to optimize production across all available energy markets. Most importantly, this approach allows producers to participate in future markets and innovative business models, such as offering fixed green shapes (see my recent post on 7/11 PPAs), selling power to smaller but higher-yielding industrial off-takers, and mitigating the impact of negative prices. Transforming a PPA portfolio into a VPP will require a dedicated effort, a clear commitment from top management, and an understanding that the journey will be a longer-term one. Embracing this approach positions renewable portfolios to thrive in the evolving energy landscape while unlocking new potential for sustained growth.

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.

There is a massive landscape of agencies, programs, and funding pathways that can accelerate a company, but most founders do not know where to start or how to engage. So I am starting a short series to spotlight key agencies, how they work, and how founders can actually use them for funding and partnerships. First up is ARPA-E. ARPA-E was created to fund high-risk, high-reward energy technologies that are too early for private capital but critical to national and economic security. This includes areas like long-duration energy storage, advanced materials, grid resilience, next generation nuclear, and carbon capture. What makes ARPA-E different is how it operates. It is program driven, meaning funding is released through focused initiatives led by program directors who are experts in specific technical areas. You are not pitching a broad idea. You are aligning to a defined problem set. Awards are milestone based, with active program management, which means teams are expected to show real technical progress over time, not just vision. Beyond funding, ARPA-E can open doors. It brings visibility, credibility with investors and strategic partners, and access to a broader network across government, labs, and industry. Many companies use it as a stepping stone into larger Department of Energy programs or commercial partnerships. The opportunity is non dilutive capital and validation. The challenge is that it is competitive, structured, and requires tight alignment with program goals and a clear path to impact. For the right company, ARPA-E can be a true catalyst. Learn more: https://arpa-e.energy.gov More to come in this series on where founders should actually be looking for capital and partners.