Redefining Energy - TECH

• 57. Deepwater Minerals, Shallow Promises (1/2)

  In this episode of Redefining Energy Tech Michael Barnard sat down with Lyle Trytten, who many in the industry know as the nickel nerd. He has spent decades working in mining and mineral processing and has become a trusted voice for organizations like Natural Resources Canada and the International Energy Agency. Our conversation turned to the techno-economic realities of seabed mining, a topic made timely by American executive orders on resource leasing and the ongoing debates around the Clarion Clipperton Zone in the Pacific.Lyle laid out the three categories of undersea mineralization that matter: manganese-rich crusts closer to shore, sulfide deposits around black smokers, and the polymetallic nodules that dominate the abyssal plains. It is those nodules that attract the most attention, given their mix of manganese, nickel, copper, cobalt and iron. The percentages matter here. Manganese makes up 20 to 30% of nodules, feeding a steel market of about 20 million tons annually. Copper mirrors manganese in demand at similar volumes. Nickel sits above copper in value, with nodules carrying over 1% grades. Cobalt is the prize, worth two and a half times nickel and largely controlled today by the Democratic Republic of Congo with annual output of 250,000 to 300,000 tons. Compared to terrestrial deposits, those grades are very competitive, often better than what current copper and nickel mines deliver onshore.Of course, the challenge is not what lies within the nodules but where they are. Four kilometers down is a different game than an open pit in Chile. Lyle framed it with a simple multiplier: one times for onshore, ten times for offshore, a hundred times underwater, and a thousand times when you hit the seabed. The Clarion Clipperton Zone lies thousands of kilometers from shore, making costs and logistics daunting. Even compared to offshore oil, with rigs like Deepwater Horizon working at 1.5 kilometers depth, this is an order of magnitude harder. That reality explains why seabed mining remains more a promise than a practice.We also dug into the credibility problem the sector faces. The history of mining is littered with scams, from Bre-X to pump-and-dump juniors, which is why Canada now requires transparent disclosures under NI 43-101. Without strict governance and independent validation, seabed mining risks repeating those mistakes. The resource base is not the issue. Just as with oil, the minerals are there. The question is whether reserves—economically viable, technically accessible deposits—will come online in time to meet surging demand, especially for copper, which looks tight in the next 15 years.Substitutability plays a role too. Aluminum can stand in for copper in transmission lines. Stainless steel has shifted chemistries in response to nickel price spikes. Battery makers tweak their chemistries—NMC ratios change with market conditions, and lithium iron phosphate has taken half the electric vehicle market without using nickel, manganese, or cobalt at all. Recycling will matter increasingly, but with service lives of decades for stainless and 20 years for batteries, secondary supply will not relieve near-term shortages. Companies like Redwood Materials and Moment Energy are building the bridge to a circular system, but the lag time is real.The conversation left me with a clear takeaway. Seabed mining is not an easy fix. The minerals are there in attractive grades, but the depth, cost, and governance challenges are immense. At the same time, demand for copper, nickel, and cobalt will keep rising, and prices will eventually force new sources to market. The industry has opportunities in recycling, substitution, and responsible development, but the old habits of hype and over-promising will have to be broken if it is to have a role in the critical minerals future.

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• 56. Planning the future of an energy system: case study Netherlands (2/2)

  In this second part of the podcast, Michael Barnard pursues his conversation Paul Martin and Emiel van Druten with explores emerging insights into the Netherlands' energy transition, addressing core assumptions around efficiency, hydrogen usage, and electrification.Building efficiency upgrades yield disappointing returns, with gas consumption often rebounding within 2-4 years post-renovation, limiting achievable reductions to about 50%. The recommended solution is a clear shift toward electrification-first strategies, emphasizing cost-effective insulation to properly size heat pumps, a strategy supported by Heat Geeks' methodology and monitored at heatmonitor.org.Tata Steel's ambitious hydrogen-based direct reduction of iron (DRI) plans illustrate the industrial challenge. The strategy begins with natural gas DRI combined with carbon capture by 2025, transitioning fully to green hydrogen by 2040. However, declining global steel demand, driven by China's reduced infrastructure spending and a shift to scrap-based electric arc furnace production, calls into question the economic viability of domestic hydrogen-based steelmaking. A preferred interim solution involves biogenic methane with CCS, progressing eventually to importing green iron pellets for local processing.Contrary to broader industry forecasts, Dutch hydrogen demand may collapse by as much as 80% by 2050, drastically reducing electrolysis capacity requirements from over 30 GW to around 3 GW, reserved primarily for refineries and biorefineries. This scenario eliminates hydrogen from previously expected uses, such as ammonia production, transportation, steelmaking, and electricity backup generation.Methanol emerges surprisingly as a preferred shipping fuel, surpassing ammonia due to safety advantages and ease of biological sourcing. In aviation, hydrotreated vegetable oil (HVO) derived from waste oils becomes the preferred fuel, driven by its simpler conversion process, though competition for limited feedstocks will favor aviation, pushing shipping toward methanol. Electrification projections for short-sea shipping and inland waterways see significant upward revisions, with long-haul shipping partially electrified due to soaring alternative fuel costs.Transportation electrification accelerates, with full truck electrification anticipated by 2035, eliminating earlier expectations for hydrogen trucks. Industry expert Johnny Ninehuis predicts no diesel trucks sold beyond that point, emphasizing battery technology overcoming heavy transport challenges.The chemical industry faces transformation, with methanol production pathways favoring gasification of waste plastics and biomass, particularly for chemical feedstocks and fuel applications. A smaller, cleaner petrochemical sector will remain viable, shifting to low-sulfur crude and significantly cutting hydrogen demand.System-wide rebalancing adjusts electricity demand growth forecasts downward from a previously projected fivefold increase to approximately 3.5 to 4 times current consumption. This adjustment significantly reduces offshore wind expansion targets, eliminating expensive distant and deep-water installations. Nuclear power is also excluded as non-economic, positioning the Netherlands as a future electricity exporter to neighboring markets, notably southern Germany. Direct air capture and synthetic fuel production are considered economically impractical within the Netherlands, and the fertilizer sector is projected to shift towards ammonia imports as local production becomes increasingly uneconomic. Highlighting broader electrification trends, Fortescue’s recent $3 billion investment in electrified mining equipment illustrates a growing momentum towards electrification even in challenging, heavy industrial sectors.    

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• 55. Planning the future of an energy system: case study Netherlands (1/2)

  Michael Barnard hosts Paul Martin and Emiel van Druten in an insightful podcast episode exploring the Netherlands’ evolving energy transition scenarios, specifically focusing on strategic planning for 2030 and 2050. Emil van Druten, leading the scenario development at Tennet, collaborates closely with Dutch network operators, leveraging his engineering background to advance pragmatic electrification pathways.Central to the discussion is a recent workshop where Canadian experts provided critical economic validation of the proposed high-electrification strategies. This validation helps anchor ambitious scenarios in realistic economic contexts, highlighting where adjustments might enhance feasibility and efficacy. Complementing these strategic insights was a site visit to the Netherlands' largest operating land-based wind farm—200 MW of wind generation complemented by solar and upcoming battery storage. Detailed discussion covered turbine specifications, operational efficiencies, and the integration potential of such multi-technology sites.The historical context provided by Flevoland's infrastructure evolution underscores the Netherlands' capacity for resilience, particularly with regard to the Afsluitdijk closure dam and sophisticated pumping station operations. Strategically scheduling these pumping stations based on fluctuating energy prices has already achieved substantial operational cost savings, with significant further potential identified through increased automation.The conversation also highlighted acute challenges facing industrial sectors historically dependent on Groningen gas, as the scheduled closure of this major gas field threatens competitiveness. Transition urgency grows, prompting industrial sectors, including major refineries, to rethink energy sourcing strategies and economic positioning within European markets.Biomethane emerges as a notable strategic element, with significant domestic capacity aimed at enhancing industrial processes and providing backup power generation. The strategy prioritizes biomethane for industrial feedstock rather than residential use, capitalizing on its benefits for CO2 enrichment in greenhouse agriculture and nutrient cycling back to farmlands. Maintaining existing methane plants is crucial for ensuring generation reliability, particularly during renewable generation shortfalls anticipated in capacity planning for the early 2030s.Emil and Paul also explore the technological merits of aquifer thermal energy storage (ATES), particularly effective for seasonal heat storage and cooling applications in conjunction with greenhouse operations. Geological advantages and deep drilling expertise have made the Netherlands a leader in this technology, complementing the shift toward optimized heat pump solutions for residential heating. They advocate moving decisively toward all-electric heat pumps over hybrid systems, recommending regulatory adaptations to streamline adoption without imposing expensive building fabric upgrades.Finally, the episode outlines critical regulatory and operational actions needed: automating pumping stations for additional energy savings, revising regulations to facilitate practical heat pump adoption in residential sectors, and addressing persistent regulatory delays hindering district heating initiatives. The insights provided offer a comprehensive blueprint for navigating the complexities and opportunities of the Dutch energy transition.

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• 54. Decarbonizing the High Seas - IMO’s Billion-Dollar Bet (2/2)

  In this episode (2/2), Michael Barnard concludes his conversation with Tristan Smith, a leading voice in maritime decarbonization and professor at the UCL Energy Institute, to unpack the tangled web of choices, regulations, and constraints facing the shipping industry as it attempts to cut emissions. From dual-fuel ships and synthetic fuels to compliance markets and long-term infrastructure investment, our conversation covered the broad terrain that policymakers, shippers, and fuel producers are all trying to navigate—with varying degrees of alignment and clarity.The core challenge, as Tristan makes clear, is the uncertainty. Despite rhetoric about decarbonization, the shipping industry remains paralyzed by confusion over which fuel pathways will ultimately dominate. LNG got a big early lead, with over half of dual-fuel ships opting for it before the IMO's revised climate strategy took hold. But now? Stakeholders are stuck in a feedback loop: shipbuilders hesitate to commit without clarity on fuel availability, and fuel suppliers can’t scale up without clear demand signals. Hydrogen and synthetic fuels are still expensive and energy-intensive. Methanol offers potential but with its own limitations. Even advanced biofuels are subject to competing demands, especially from aviation. The result? Fleet choices made today could lock in constraints that ripple out for decades.We dove into the IMO’s recent regulatory shift, a surprisingly muscular move for a UN body. The new rules focus not just on emissions, but on the carbon intensity of the fuels ships burn. GHG Fuel Intensity (GFI) targets are now baked in, with meaningful penalties: ships that fail to comply will pay fines starting at $100 per ton of CO₂, with funds used to accelerate zero- and near-zero-emission fuel development and assist lower-income countries with energy transitions. It's not a symbolic gesture. Modeling suggests the system could generate $11–12 billion annually in the first three years alone, creating a $33–36 billion fund for global maritime decarbonization. For once, there’s a stick and a pot of carrots.Tristan stressed the importance of early action. Ships being built now will still be in service by 2050, and port infrastructure decisions last even longer. Regulatory clarity today means the excuses are drying up. Planning needs to happen now to avoid locking in fossil dependency for another generation. The regulation also means that even if the industry’s fuel mix is uncertain, the cost of carbon is not. That changes investment calculus across the board, from ship design to bunker fuel contracts.We also touched on the equity angle. If global shipping decarbonization happens only in the wealthiest ports, it undermines the whole effort. The transition must include support for infrastructure, workforce training, and technology deployment in lower-income nations. Otherwise, we're just pushing emissions and economic pain offshore—literally.This conversation reinforced what I’ve argued for years: while aviation drags its feet and road transport electrifies at speed, shipping sits in the middle—finally regulated, still confused, and facing real opportunity. The IMO’s climate strategy isn’t perfect, but it’s real, binding, and globally coordinated. It’s a serious signal to a sector long stuck in the waiting room of decarbonization. Now the countdown has started.      

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• 53. Decarbonizing the High Seas - IMO’s Billion-Dollar Bet (1/2)

  In Episode 53 of Redefining Energy TECH, Host Michael Barnard speaks with Tristan Smith, a prominent expert in maritime decarbonization and professor at the University College London Energy Institute. Tristan shares his insights, beginning with an overview of maritime shipping, which accounts for approximately 1 gigaton of CO₂ equivalent annually, making it responsible for about 2-3% of global emissions. Crucially, the regulatory oversight for these emissions sits largely with the International Maritime Organization (IMO) due to the nature of international shipping occurring beyond national jurisdictions.Our conversation moves through the historical context of the IMO, tracing its evolution from a safety standards body established post-Titanic disaster to an organization now deeply involved in global climate policy. Historically, the IMO faced significant challenges in progressing climate regulations due to entrenched disagreements between developed and developing countries around responsibilities. The Paris Agreement in 2015, alongside persistent advocacy from smaller nations like the Marshall Islands, notably shifted this dynamic, leading to the adoption of the IMO’s initial climate strategy in 2018.We delve into recent regulatory developments, including the unprecedented IMO vote initiated by Saudi Arabia, resulting in a decisive 63-to-16 vote (with around 29 abstentions) mandating progressive reductions in greenhouse gas intensity for ships over the next 25 years. The regulation sets clear fines for non-compliance—$380 per ton for exceeding the highest threshold and $100 per ton for mid-level breaches—ultimately requiring ships to achieve a 65% reduction in emissions intensity by 2040.The discussion highlights the role of Emissions Control Areas (ECAs), established initially to curb SOx and NOx emissions in sensitive regions like the Baltic Sea, North Sea, and North America, effectively serving as early tests for broader international regulations. Additionally, we critically examine LNG’s journey from a touted solution for reducing SOx and NOx emissions to its complicated position as a potential climate liability due to significant methane emissions both onboard and upstream. Norway’s influential promotion of LNG and subsequent studies, such as those by the International Council on Clean Transportation, underline these complexities. Finally, Tristan emphasizes the future challenges facing maritime decarbonization, notably the risk of technological lock-in with LNG and the powerful role of the oil and gas industry within the maritime sector. We also explore the shifting political landscape as global fossil fuel transportation—currently 40% of maritime tonnage along with another declining 15% for raw iron ore—faces inevitable structural declines, promising profound implications for industry dynamics and global decarbonization efforts.

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