Macro Crude: Understanding Finance and The Global Economy (Oil, Stocks, Commodities, Currencies)

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.

The emergence of sovereign carbon credits from forest-rich nations under Article 6 of the Paris Agreement is poised to transform the carbon credit landscape. However, these large-scale issuances may have significant implications for voluntary carbon credits, potentially capping their prices. Here's an overview of how these sovereign credits could reshape the market and why price expectations might need a reality check. Concise Overview Sovereign Carbon Credits on the Rise: Suriname, Honduras, Belize, and the Democratic Republic of Congo (DRC) are gearing up to offer sovereign REDD+ units under Article 6 of the Paris Agreement. This trend signifies a major shift in climate finance. Voluntary Carbon Credits at Risk: The surge in sovereign carbon credits could impact the voluntary carbon market. Many entities buy voluntary credits to meet their net-zero targets. Sovereign issuances might fulfill a significant portion of this demand, potentially lowering prices for voluntary credits. Price Expectations vs. Market Reality: While nations like Suriname aim for a price of at least $30/tonne for their carbon credits, market dynamics might bring these prices down significantly. A more realistic price range could be in the vicinity of $10-$15/tonne. Detailed Read Sovereign Carbon Credits Alter the Landscape Sovereign carbon credits from rainforest nations are becoming a game-changer in the world of climate finance. These countries, including Suriname, Honduras, Belize, and the Democratic Republic of Congo (DRC), are preparing to issue sovereign REDD+ units under Article 6 of the Paris Agreement. These credits are set to be a critical component of global efforts to combat climate change. A Promising New Market Suriname, the first country to have its REDD+ issuances verified by the UN, is in discussions with corporate and national buyers. The targeted price for its 4.8 million verified units is at least $30 per tonne. The carbon credits will be sold on a new platform, supported by the Coalition for Rainforest Nations (CfRN). Implications for Voluntary Carbon Credits The growing issuance of sovereign carbon credits poses challenges for the voluntary carbon market. Many organizations and companies purchase voluntary credits to fulfill their net-zero commitments. These credits are typically sourced from projects that avoid emissions (like renewable energy projects) or remove carbon dioxide from the atmosphere (like reforestation efforts). However, sovereign issuances could provide an alternative supply source for meeting net-zero targets. This may reduce the demand for voluntary credits, potentially capping their prices. While voluntary credits are preferred for their removal attributes, the sheer scale of sovereign issuances could make them a viable substitute. Price Expectations Meet Market Realities One significant aspect to consider is the price expectations surrounding sovereign carbon credits. Nations like Suriname aim to secure a price of at least $30 per tonne for their carbon credits. However, market dynamics may not align with these expectations. It's likely that the market will dictate lower prices for sovereign credits. A more realistic price range could be in the vicinity of $10 to $15 per tonne. This gap between price aspirations and market realities underscores the need for a reassessment of price expectations. In summary, the rise of sovereign carbon credits is poised to reshape the carbon credit landscape. While these issuances could meet substantial demand for net-zero targets, they might also impact the prices of voluntary credits. To ensure a sustainable and effective carbon credit market, stakeholders must adapt to evolving market dynamics and adjust their price expectations accordingly.

Shipping will be incorporated into the EU ETS from 2023, but in its current form will only require shipowners to pay for emissions on a tank-to-wake, or combustion basis, rather than on a well-to-wake, or lifecycle basis

Japan is considering building new nuclear plants (a reversal from the decision made in the after math of the Fukushima incident). Likely to be bearish for hydrogen imports into Japan as the optionality with nuclear power plant for their utilities implies less willingness to sign long term offtake agreements with H2 exporters that are very reliant on them to take FID.

Improved tax incentives for CCUS/DAC in the US. We explore both the tax rebate and the potential for scaling up CCUS facilities and how they compare with the IEA NZE scenario expectation.

A trade deal that encompasses green hydrogen and critical minerals. At the heart of the energy transition and geopolitics that is bringing allies Germany and Canada together with this energy trade deal

Brief Analysis of the windfall tax introduced by the UK government.

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. · Constructive factors •European gas inventories replenished. • •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. • •India and Pakistan. ~ 1 Mtpa incremental of imports due to FSRU (HoeghGiant) and ExcelerateSequoia)

Update on China’s Emissions Trading Scheme: When trading starts in      June – prices for allowances are now expected to trade sub US$1.5/ton –      given the oversupply of allowances. Government officials and market      participants had previously expected trading to commence in the US$4.6 –      US$7.6/ton range. China’s ETS resembles      the first phase of the EU ETS where the program started with ample      allowances – with further regulatory reform needed to tighten the market. According to analysis by      Transitionzero, China has oversupplied its national emissions trading      scheme by as much as 1.56 billion allowances for 2019 and 2020. Regulators will have      issued around 10.51 billion allowances to coal-fired power plants for the      two years under the benchmark-based scheme, compared to an actual need of      some 8.94 billion. The surplus is bigger in 2020 (830 mln) than in 2019      (740 mln). For context: Cumulative      oversupply over its first two years of operation is on track to be the      equivalent of a year’s worth of EU ETS emissions. Replacing China’s coal      fleet with zero carbon alternatives could save $1.6 trillion or incur a      net-negative abatement cost of US$20/tCO2 according to analysis by      TransitionZero. China will have to halve      the carbon intensity of its power generation to 350 gCO2/kWh in 2030 from      672 g currently to be on track to meet its 2060 carbon neutral pledge.

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.

From Washington and New Delhi to Riyadh. How the voice of the oil consumer led Saudi Arabia and OPEC to bend and increase production

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

Henry Hub prices at the prompt have weakened in November. Four key drivers Warmer than expected weather in the US (Temperatures are 24% higher than normal this month). As Henry Hub prices increased above US$3/mmbtu level in October – this has incentivised more coal fired generation in the US (Exhibit 2 below) Reduced power demand due to COVID restrictions cutting load by 2.7 GW nationwide. Finally, US gas production has improved (chart of the day) – but they remain below pre-COVID levels of activity will be supportive for HH from re-visiting Q1 lows (at least until WTI remains below US$45/bbl). Prospects for US gas balances improving from here hinges on temperatures normalising for the rest of the winter and COVID lockdowns easing in Q1 21.

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.