In Q1 2025, US LNG projects awaiting final investment decisions (pre-FID) failed to secure a single long-term contract, marking a first since 2021 despite favorable policies. Rising construction costs, higher Henry Hub prices, and concerns over a looming global supply glut have left buyers hesitant. Meanwhile, Qatar is capitalizing on low-cost, oil-linked deals to lock in market share. This episode dives into the reasons behind the US slowdown and examines whether this pause signals a shift in the global LNG market’s dynamics.

Could the United States, the world's top energy producer, ever join forces with OPEC? This episode unpacks the controversial, hypothetical scenario where the US aligns with oil-producing nations to manage global markets. We explore the potential "win-win" strategy: securing cheap energy domestically to fight inflation and boost industry, while maximizing profits from controlled exports at higher global prices. Discover the immense geopolitical implications, the potential for a similar US-Qatar LNG axis, and the monumental legal and political hurdles (like antitrust laws and NOPEC) that make this radical idea seem almost impossible... yet perhaps increasingly thinkable in a shifting global landscape focused on energy security.

What happens in the seemingly dry debates at the International Maritime Organization (IMO) has profound implications for the future of global shipping and the planet. We delve into the crucial decisions facing the IMO in regulating shipping's climate impact, exploring the potential for effective solutions and the risks of getting it wrong. From carbon levies to green fuel standards, we break down why these seemingly boring discussions are vital for a sustainable future.

China is making a significant leap in its renewable energy policy with the release of a new landmark directive focused on market-oriented reform of wind and solar electricity prices. This podcast episode dives into the details of the February 9th notice, titled 'Deepening the Market-oriented Reform of New Energy On-grid Electricity Prices' (新能源上网电价市场化改革的通知). For years, China's renewable sector thrived on subsidies and guaranteed purchase agreements tied to coal-fired power benchmarks. This new policy marks a pivotal shift towards market-based mechanisms, aiming for a more sustainable and efficient integration of renewables.  

We explore the novel concept of the 'Price Settlement Mechanism for Renewables Sustainable Development' (新能源可持续发展价格结算机制), a system drawing inspiration from the Contract for Difference (CfD) models used in the UK and Germany, but adapted with #ChineseCharacteristics. This mechanism intends to replace the traditional guarantee purchase, potentially offering revenue stability for wind and solar developers through a fixed "strike price" determined via competitive auctions. If market prices fall below this level, generators receive a top-up, and if prices rise above, they pay back the difference.

We'll discuss the directive's timeline, requiring all provinces to implement their own version of this RE Price Settlement Mechanism by the end of 2025. The crucial question remains: will these new price levels be higher or lower than the previous coal-benchmark tariffs?

In the short term, this policy is expected to accelerate the decline in electricity tariffs in China, allowing the nation to capitalize on the rapidly decreasing costs of renewable energy. We delve into how this rulebook will govern renewable energy participation in China's power market, covering aspects from mid-to-long-term contracts to spot market trading and the role of green power certificates and provincial RPS. The policy also thoughtfully differentiates between existing and new renewable energy projects (post-June 2025) to ensure a smooth transition.  

Ultimately, this market-oriented pricing strategy aims to drive greater renewable energy adoption and ensure grid stability. Interestingly, the policy makes no mention of carbon pricing, highlighting the current limitations of China's carbon market within its broader power sector deregulation efforts. Join us as we unpack this crucial development and its potential impact on China's energy landscape and the global renewable energy transition.

Q2 21: Support from LNG Supply outages in the Pacific Basin and nuclear outages in Japan and Korea

·South Korea had to shut its HanulNo.1 and 2 nuclear reactors (1.9 GW) this week after an influx of sea salps(marine organisms) clogged water systems used to cool the nuclear reactors. This is the second time in less than three weeks these units have had to be shut down and could lead to incremental demand for 1-2 spot LNG cargoes.

·Japan’s nuclear regulator has temporarily banned TEPCO from operating its nuclear plant in Niigata – due to safety concerns. TEPCO had originally planned to restart its two nuclear reactors (2.6 GW) over the May-June period and the latest ruling pushes out the chances of TEPCO operating the plant until at least H2 2022. Japanese LNG imports are expected to be up by 0.45 Mt y/y in Q2 21.

·Prelude and Sakhalin are back to full operation after undergoing maintenance in March, the next planned works will likely happen at Gorgon.

·Gorgon T3 will go offline for large-scale maintenance later this month—starting from 26 April according to Chevron’s schedule. If Chevron finds similar issues to those found at its first two trains last year – the total works could last ~14 weeks until early August (based on T1 work timeline).

·Large-scale maintenance works scheduled at Ichthys, GLNG and North West Shelf in May.

Planned maintenance at PNG LNG will reduce exports from Papua New Guinea in May, although the exact timing of these works has not been officially announced

Q3 21 gas balances to weaken relative to Q2 21 – on higher pipeline supplies

Bearish factors

·Strong pipeline imports from Russia and central Asia will limit Chinese LNG demand growth y/y to 1.0 Mt over the same period.

·Nuclear availability is set to improve in Japan - translating to a drop of 1.1 Mt y/y between July–September.

·11.4 Mt y/y growth of global LNG supply in Q3 21—primarily from the US and Egypt—will far outpace the call from Asia-Pacific markets.

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Constructive factors

•European gas inventories replenished.

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•Argentina expected to import 3 Mt (60-65 cargoes) this sumer of which only 1.7 Mt thus far tendered. They will have to secure another ~1.3 Mt of LNG (June-September). Through the Escobar terminal and Bahia Blanca FSRU terminal.

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•India and Pakistan. ~ 1 Mtpa incremental of imports due to FSRU (HoeghGiant) and ExcelerateSequoia)

This episode helps you understand the basics of California's carbon cap and trade programme. Its a primer that goes through the basic of the program, some history, the sectors included and some of the defining mechanisms of the programme like the maximum holding limit, minimum auction price.

The premium of Asian LNG spot prices (JKM) over the US Henry Hub benchmark has widened to the highest level in nearly two years (spread >US$5/mmbtu). This is partly a function of Pacific basin supply outages coinciding with congestion at the Panama Canal. As a result JKM contracts are pricing in the cost of securing US cargoes through longer transit routes around the Cape of Good Hope (costing an extra US$2.4/mmbtu at current freight rates). Wait times outside the Panama canal have been around nine days recently (Chart of the day), adding almost $0.40/mmbtu to using the route to Northeast Asia without waiting. 

Panama Canal congestion is causing delays to LNG deliveries from the US to Asia, driving up freight rates

• Higher than average arrivals, seasonal fog and      COVID-19 linked staffing reductions is causing congestion at the Panama      Canal.
• Waiting time for vessels with unbooked slots      is as long as 10-15 days and some US cargoes are now transiting through      the Cape of Good Hope.
• The extra shipping cost associated with a      97-day round trip for a US cargo to Northeast Asia via the COGH relative      to delivering to Europe is $2.40/mmbtu at prevailing freight rates and      boil-off costs.
• The Panama route costs $1.16/mmbtu extra at      current rates. The less time vessels spend holding position, the more      tonnage can be freed up and made available to the spot market, in turn      reducing spot freight rates.

Below factors could help ease strength in the JKM Feb-21 contract to reflect the cost of securing the marginal cargo through the Panama route, rather than pricing on more longer routes at present:

• A sequential increase in Pacific basin supply      equivalent to around 8-14 cargoes per month compared to today will help      cut Northeast Asia’s call on US cargoes.
• 3.6 Mtpa Prelude is expected to return by year-end,      followed by the return of Gorgon’s 15.6 Mtpa capacity at the end of Jan-21      (assuming no weld faults are found in trains one and three). The restart      of production at Qatargas’ 7.8 Mtpa train four at Ras Laffan next week      will also boost supply, as will the ramp-up of Egyptian      output—particularly from Idku, with some potentially from Damietta.
• Sequential declines in Northeast Asian demand      for LNG over the rest of winter is also likely. Japan and Korea are      expected to see improving availability in nuclear, and both countries will      be drawing down LNG terminal stocks. China will also be partly relying on      drawing down their undergrounds gas inventories – which have been boosted      y/y by heavy injections.

Per the below LHS chart, the JKM-TTF spread is incentivising transit through the Cape of Good Hope (green line). Costs of using the Panama canal have risen. With higher transit times through the Panama Canal – ships are using the route through the Cape

As rig counts continue to fall. Producers are high grading ie. Shifting to tight oil areas with higher well productivity.  High grading is more pronounced thus far in the current price downturn compared to 15/16.

• This has largely resulted in shale companies reporting higher efficiencies (charts below). Lower activity, concentrated on best assets with service cost reductions helping companies to guide for more efficiency gains.
• As of Friday’s data active oil rig counts are now at the lowest levels since before the shale revolution started, implying despite the efficiency gains being reported below – depletion rates will catch up.

As a result of high grading, well cost reductions expected in both Delaware and Midland Basins, more moderate reductions expected elsewhere.

• Producers across the Permian have realized or anticipate achieving ~20% reductions in normalized well costs relative to 2019 levels.
• While sharply lower activity levels and concomitant service price reductions are surely at play, durable process oriented drivers and “creative destruction” from an unprecedented (and virus-driven) downturn also appear to be contributing to this improvement.
• Above improvements partly linked with cyclical service cost reductions and impact from high grading.
• Beyond expected drivers of efficiency gains associated with downturns and through-cycle learning curve effects, more meaningful operational changes also appear to be occurring, with simultaneous hydraulic fracturing (Simul-Fracs) and increased automation/remote operations recently in focus.
• With respect to the former, multiple Midland basin producers have reported utilizing Simul-Fracs, which may be helping that side of the basin keep pace with the relatively less mature Delaware side this year.

Energy demand is 4% lower than it would have been without efficiency gains. Between 2015-2018 energy efficiency improvements helped reduce 3.5 Gt of Co2 – roughly equivalent to the energy-related emissions of Japan over the same period. 

Why has energy efficiency fallen:

• Consumers      preferring larger cars – vehicle occupancy rates have fallen
• Residential      buildings – increased device ownership and use, growth in per capita      residential floor area in all economies.
• China      and the US increased their share of industrial production - pushing up demand for primary energy      fuels
• Coal      power generation increased in 2017 (3%) and 2018 (2.5%)

But with COVID-19 oil intensity is likely to go higher - although overall consumption faces a cyclical headwind due to the economy. The per user oil intensity is likely to be higher. Especially with demand for PPE , Face Masks and more protection for packaging food.

Oil Market Outlook. Oil (Brent crude) has managed to stay above US$40/bbl over the second week of July, despite a choppy macro environment and looming risks. We explore the key reasons for this and highlight some of the key risks.