Power Plays

About Power Plays

Join us - Dr Charlotte Kirk and Lucy Shaw - as we dive into the tech, finance and politics powering the energy transition each week. We'll unpack what happened, why it matters, and what you need to know. With deep industry insights and unique insider knowledge, we'll keep you up to date with all the Power Plays.

Publisher

Dr Charlotte Kirk and Lucy Shaw

Category

news

Language

en

Explicit

No

First episode

19 Feb 2026

Latest episode

1 Sept 2026

Latest episodes

26 episodes in the feed.

1. 

   1 Sept 2026

   Can America secure its renewable energy future without making it more expensive? With Oliver Badenhorst, VP at Solar Landscape

   Recorded 25 August 2026. This week, we’re joined by Oliver Badenhorst, Vice President of Strategy and Business Operations at Solar Landscape. Drawing on his experience in commercial rooftop solar, energy strategy and US offshore wind, Ollie joins us in his personal capacity to discuss three major stories shaping the US energy sector: new solar import measures, restrictions on foreign-made inverters and the federal government’s offshore-wind lease refunds. 1 - New tariffs and minimum prices could raise US solar costs From December 2026, imported solar products will face a 15% tariff alongside minimum prices covering polysilicon, wafers, cells and modules. The $0.38/W module price floor could increase module costs for a 100 MW project from approximately $25 million to $38 million, adding around 12–13% to total project costs. The impact will vary by business model: community-solar developers may have more flexibility than utility-scale projects operating under long-term, fixed-price power contracts. The measures could support US manufacturing and reduce reliance on concentrated overseas supply chains, while raising energy costs and placing some marginal projects at risk. Developers may find administrative complexity, tax-credit eligibility rules and supply interruptions more disruptive than a clearly defined increase in equipment prices. 2 - Restrictions on foreign inverters address a growing cybersecurity risk The FCC has blocked new models of foreign-made, internet-connected power inverters from receiving US authorization, unless they qualify for an exemption or are linked to domestic production plans. Previously approved models can continue to be manufactured, imported, sold and installed, delaying the immediate impact on developers with existing inventories. Inverters connect solar panels, batteries and EV chargers to the grid and increasingly enable remote monitoring, bidirectional power flows and distributed-energy coordination. Large fleets managed through shared cloud platforms can expand the grid’s cyberattack surface, strengthening the case for secure firmware, controlled software updates and clear remote-access rights. The restrictions could encourage domestic power-electronics manufacturing, while reducing equipment choice and potentially slowing access to newer inverter technology. 3 - US offshore wind has been hit by financial, operational and political pressures The US government has agreed to return approximately $4 billion in offshore-wind lease payments, securing the cancellation of projects whose developers may otherwise have continued or challenged federal action. Many projects committed to fixed electricity prices before inflation, interest rates and supply-chain costs rose, weakening their economics. Offshore wind requires long development timelines, highly specialized equipment and complex construction at sea; the Jones Act adds further logistical constraints in the US. Turbine reliability problems, steel-price increases, constrained installation capacity and federal opposition have compounded the sector’s challenges. Falling solar and battery costs have strengthened a competing source of modular, rapidly deployable capacity, particularly as batteries allow solar generation to serve demand across more hours of the day.

2. 

   25 Aug 2026

   Can Microreactors Deliver on the Nuclear Hype? With Guy Cohen from Currence

   Recorded on 21 August 2026 with this week’s co-host, Guy Cohen, who leads clean-firm-power analysis at Currence. There have been 2 recent news stories in the micro-reactors: Valar Atomics raised a $1 billion Series B, while Antares announced a $370 million Series C. We examine why investors are backing microreactors, what commercial progress looks like and the parallel opportunity in the infrastructure needed to deploy the reactors. 1. Why microreactors are attracting capital Microreactors produce 1–20 MW, are factory-built and transportable. Early markets include military bases, mines, remote communities and industrial sites dependent on diesel. They may suit smaller distributed computing facilities rather than gigawatt-scale AI campuses. Their advantage may be speed rather than cost: data centres could pay more for earlier power. US regulatory changes could enable fleet licensing, remote operation and smaller security footprints. 2. What would justify the valuations? Neither Valar nor Antares has a commercially licensed reactor in operation. Reaching criticality matters, but does not prove commercial viability. Stronger indicators would include customer contracts, financing and long-lead equipment orders. Developers must demonstrate licensing progress, fuel access, manufacturing capacity and delivery experience. Economics depend on factory production, standardisation and repeated deployment. 3. The opportunity extends beyond reactors Does nuclear really need more reactor designs, or stronger supply chains and delivery capabilities? Many advanced reactors require HALEU and specialised TRISO fuel. Announced non-Russian and non-Chinese HALEU production may support only around 5 GW by 2035. Projects also require fuel fabrication, heavy forgings, pressure vessels, turbines and skilled workers. Currence found reactor-developer funding fell 64% relative to H2 2025, while non-reactor funding rose 384%. In H1 2026, non-reactor startups raised as much as reactor developers. 4. How microreactors differ from SMRs The Valar and Antares deals follow years of slower-than-expected Western SMR deployment. But leading SMRs are moving from early-stage equity towards government support and project finance. Gen III+ designs benefit from established supply chains; Gen IV reactors face greater first-of-a-kind risks. Microreactors are attracting early-stage capital because their regulatory and commercial pathways are only now emerging. 5. Are existing reactors the faster opportunity? Restarts, uprates and life extensions can add capacity sooner and more cheaply. Microsoft is backing the 835 MW Three Mile Island restart. Palisades could return 800 MW to the grid. Meta’s 20-year Vistra agreement supports 433 MW of uprates. These projects matter this decade but cannot deliver the additional 100–300 GW contemplated by US targets. 6. Where nuclear fits in the power mix Can microreactors and SMRs compete with other clean-power sources? Enhanced geothermal targets 8–10¢/kWh, while DOE aims for 4.5¢/kWh by 2035. Solar delivers around 3–5¢/kWh; adding four-hour storage brings to 9–10¢/kWh. Nuclear offers higher capacity factors; geothermal may be cheaper and faster where resources exist. Falling battery costs could reduce future baseload requirements. Public markets could finance established nuclear companies.

3. 

   17 Aug 2026

   What Australia can Teach Europe and the US about the Energy Transition, with Hamish Mackenzie, Director of Energy at the Grattan Institute

   Recorded on 13 August in California / 14 August in Australia. Excited to have Hamish Mackenzie as our co-host this week. He is Deputy Director of Climate and Energy at the Grattan Institute, and has previously worked across the private sector and Australian energy policy. This week we focus on 3 stories shaping Australia’s energy transition, and what they tell us about similar challenges playing out in the US and UK: 1. Australia’s proposed “bring your own power” rules for data centres: Australia already has 160 data centres, with over 90 in the pipeline, as investment and electricity demand grow rapidly. We discuss the government’s proposed framework requiring new data centres to procure 100% renewable electricity from additional generation, secure firming capacity, provide grid flexibility and respond to locational incentives. We look at how renewable matching could work, including proposals to divide procurement into different periods of the day rather than relying on annual matching. We explore the tension between data centres that can be developed in ~2 years and renewable projects that can take over 7, and what this could mean for wind, offshore wind, batteries and gas firming. 2. Australia’s 82% renewable-electricity target and electricity-market reform: Australia’s National Electricity Market is approaching 50% renewable generation, but project development is slowing as the country works towards its 82% renewables target by 2030. We discuss delays to wind and transmission, community opposition, differing state policies and concerns that projects awarded support through the Capacity Investment Scheme may not all reach construction. We explain the tenor gap, developers need long-term revenue certainty to finance projects, while buyers are often reluctant to sign contracts beyond a few years. We examine the proposed contract-recycling mechanism intended to bridge that gap, and the challenges of implementing market reform across Australia’s federal and state governments. We discuss the changing generation mix: solar and batteries are growing rapidly, wind is struggling, batteries are increasingly displacing gas from intraday firming, and wholesale prices have fallen sharply over the past year. 3. Australia’s domestic gas policy during the Iran war: Australia is one of the world’s largest LNG exporters, while remaining heavily dependent on imported liquid fuels and exposed to international energy-market volatility. We discuss how east-coast LNG exports connected domestic gas consumers to global markets and contributed to higher and more volatile prices, particularly during the 2022 energy crisis. The government’s proposed domestic gas-reservation policy would require LNG exporters to make gas equivalent to 20% of exports available to the domestic market. We consider whether lower domestic gas prices could slow electrification, while improving energy security and limiting exposure to extreme global price spikes. We also look at batteries increasingly replacing gas for short-duration firming, while gas retains a role during longer periods of low renewable generation. We finish with Australia’s wider transition: renewables have risen from around 8% of electricity in 2010 to close to 50% today, rooftop solar and household batteries have scaled rapidly, and policymakers are now looking to commercial and industrial solar as another source of quickly deployable capacity.

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