US, Japan, Germany miss G7 fossil fuel goal: Report

: Coal, Crude oil, Emissions, Natural gas
23/04/13

G7 countries the US, Japan — which is hosting the group's summit this year — Italy and Germany are still lagging behind their commitment to end new direct international public finance for unabated fossil fuels, according to civil society organisations (CSOs) Oil Change International and E3G.

G7 climate and environment ministers reiterated in May 2022 a pledge made by 39 countries at the UN Cop 26 climate conference in 2021, committing to end public financing of unabated coal, oil and gas projects by the end of 2022. The G7 nations are Canada, France, Germany, Italy, Japan, the UK and the US.

Progress has been made in shifting billions in international public finance away from fossil fuels and into clean energy, the organisations said, adding that Canada, the UK and France's new and existing policies "largely meet" the Glasgow and G7 promises.

But Japan and Germany have yet to release policies to meet their commitment, while Italy's policy does not meet the pledge, they added. The three countries, as well as the US, have all missed the 2022 deadline. The US has adopted some guidelines but has not made them public, the two CSOs said.

The G7 has the opportunity to accelerate the energy transition by delivering on their commitment, the CSOs said, adding that the group's climate and energy ministers meeting this weekend in Japan "must reiterate and strengthen" their public financing goal and steer clear of language supporting investments in upstream gas and LNG.

The G7 economies last year added a caveat to the commitment, saying "publicly supported investment in the gas sector can be appropriate" in order to reduce dependency on Russian gas.

Japan is "actively pushing" for investments in LNG this year, although this has been "met with resistance" from the EU, Canada, the UK and the US, the organisations said.

Oil Change International and E3G found that the G7's international public finance for fossil fuels reached at least $73bn in 2020-22, compared with $28.6bn for clean energy over the same period. The brunt of the funding for fossil fuel projects — 82pc — came from export credit agencies (ECAs). The organisations also found that, in 2022-22, 28pc of all G7 energy finance went to gas — $10bn/yr — "more than any other energy sub-sector", with the majority of gas finance going into LNG.

Japan and the US were the top supporters of LNG, providing 47pc and 20pc, respectively, of all of the G7's LNG finance, they said.

A further $8.6bn/yr went to oil and gas projects, they said, while clean energy finance reached $9.5bn in the 2020-22 period.

"Canada, Japan, and Italy provided the most international public finance for fossil fuels between 2020 and 2022, giving an annual average of at least $10.5bn, $6.9bn and $2.9bn, respectively," Oil Change International and E3G said.

By Caroline Varin

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24/12/27

Viewpoint: California-Quebec carbon faces murky 2025

Houston, 27 December (Argus) — The joint California-Quebec climate market, known as the Western Climate Initiative (WCI), is on tenterhooks going into 2025, stymied by rulemaking delays but on the cusp of a more mature phase. Both California and Quebec are eyeing more-stringent future programs and have floated a series of changes over the past year and a half designed to achieve those goals. The California Air Resources Board (CARB) is considering moving its program's mandate from the present 2030 target of a 40pc reduction in greenhouse gas (GHG) emissions, compared with 1990 levels, to a 48pc reduction to keep the state on target to meet its 2045 goal of net-zero emissions. In line with this increased ambition, CARB will need to remove at least 180mn metric tonnes (t) of allowances from the 2026-2030 auction and allocation annual budgets to start with, and up to 265mn t in total from the program budgets from 2026-2045. CARB has floated other changes , including toughening corporate relationship disclosure requirements, increasing the program's cost-containment allowance price tiers and updating a portion of the program's carbon offset protocols. Quebec has considered removing 17.5mn t of allowances, which correspond to carbon offset uses for compliance in the province over 2013-2020. The Quebec Environmental Ministry proposed to address this by removing these allowances from the province's 2025-2030 auction budgets in a November 2023 workshop. Quebec is also mulling changing the current three-year compliance period to align with statutory 2030 and 2050 GHG targets. But this a move that California, which had discussed similar compliance period changes in April , has not revisited since. Quebec is considering tapering the limit for carbon offset use for compliance in the province by 2030 and transitioning over to a provincial reduction purchase mechanism in 2031, although regulators have not gone in-depth on how a replacement system would function. The WCI rulemakings have been marked by a series of delays over this year, pushing past projections from the end of last year that it would finalize program changes by the second half of 2024. Quebec, which was set to deliver a draft of program amendments in September, rescheduled to early 2025, with implementation expected in spring 2025. While the regulation was nearly complete in late September, the Quebec Environmental Ministry chose to postpone, since it cannot publish before California, said Jean-Yves Benoit, the agency's director general of carbon regulation and emissions data. CARB has signaled it intends to publish its package of rulemaking amendments in early 2025. The agency on 19 December confirmed it expects to "complete and release the regulatory package for a 45-day public comment period" in early 2025 but did not explain the delay. The agency may be waiting for a formal extension of the cap-and-trade program when the legislature resumes on 6 January. California lawmakers have given CARB explicit authority to utilize a cap-and-trade system to reduce GHG emissions out to 2030. CARB maintains it has authority to operate a cap-and-trade program past 2030, but program participants have stressed the need for formal certainty around the program to aid future planning. CARB will begin invoking the post-2030 budgets starting in 2028 for the program's advance auctions. The various delays have compressed the timelines California and Quebec must achieve their statutory target ambitions, making 2025 a potentially pivotal year. By Denise Cathey Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Mild weather may pressure gas prices in 2025

24/12/27

Viewpoint: Mild weather may pressure gas prices in 2025

Houston, 27 December (Argus) — The US natural gas market has worked to lower inventories and bring prices up this year, but a warm 2024-25 winter may once again keep storage levels elevated in the new year. US natural gas inventories at the end of the 2023-24 winter season were well above average due to minimal heating demand caused by mild winter weather and robust US production. Storage levels ended the season on 29 March at 2.259 Tcf (64bn m³) — 39pc higher than the five-year average and 23pc higher than a year earlier. The higher inventories pushed down gas prices by minimizing concerns about supply shortfalls and disincentivized production this year, as large natural gas producers such as Chesapeake Energy and EQT reduced output on low prices and minimal expected demand. These interventions helped reduce the supply glut. Total US gas inventories for the week ending 1 November were 3.932 Tcf, entering the 2024-25 winter season only 6pc higher than the five-year average and 4pc higher than a year earlier. In addition, the US Energy Information Administration (EIA) predicted in its November Short Term Energy Outlook (STEO) that production in 2025 would be up 1pc from 2024 as lower inventories push up prices and once again incentivize production. EIA estimates that demand this winter will exceed last year's levels and keep inventories only just above average. According to December's STEO, inventories are expected to be 1.92 Tcf at the end of March 2025, only 2pc higher than the five-year average . However, the mild weather that has covered much of the country this November and December risks once again sharply cutting into heating demand, leaving inventories at the start of 2025's spring injection season high enough to again put downward pressure on gas prices. Heating demand in November was 12pc below the seasonal average, according to the National Weather Service (NWS). The mild weather caused prices at the Henry Hub, the US benchmark, to average roughly $2/mmBtu in November. However, EIA's December STEO predicted that prices at the Henry Hub would average just under $3/mmBtu for the rest of the winter heating season on expectations for cold weather. That cold weather has yet to fully materialize. While demand in the first week of December was 20pc higher than average on cold snap, temperatures since then have been above seasonal norms, with heating demand in the week ending 20 December landing at 22pc below average and demand in the week ending 28 December expected to be 26pc below average. If below-average demand continues into 2025, it is unlikely that inventories will drop as much as forecast. Prices this winter would be close to $3/mmBtu if withdrawals this season are close to 2.1 Tcf , East Daley Analytics senior director Jack Weixel said in September. US inventories had that level of withdrawal in winter from 2020-22. However, if temperatures this winter are once again well above average, Weixel said inventories could end the season more than 530 Bcf above average, cutting average prices to $2.50/mmBtu and undoing price from the smaller-than-average injection season. Prices may be especially pressured by rising production in the Permian basin of west Texas and southeastern New Mexico. Since most of the gas output from the Permian comes from oil wells, low gas prices may not affect production, as drilling decisions there are influenced by oil production rather than gas production. Prices may still rally this winter if temperatures dip low enough in January and February, offsetting the mild weather of November and December. In addition, the rise of LNG exports next year may boost demand and subsequently raise prices. Several LNG projects or expansions are currently underway in the US with the Golden Pass export terminal, the Plaquemines export terminal and the stage 3 expansion at Cheniere's Corpus Christi liquefaction terminal all expected to start up in 2025. By Anna Muthalaly Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US gas market poised for more volatility

24/12/26

Viewpoint: US gas market poised for more volatility

New York, 26 December (Argus) — US natural gas markets may be subjected to more dramatic price swings in 2025 as growing LNG exports and increasingly price-sensitive producers place greater pressure on the US' stagnant gas storage capacity. Those price swings could pose challenges for consumers without ample access to gas supplies, as well as producers interested in keeping some output unhedged to capture potentially higher prices without taking on excessive financial risk. But volatility may also present opportunities for traders looking to exploit unstable price spreads, and for producers that can adapt their operations to fit a more unpredictable pricing environment. Calm before the storm High storage levels and low spot prices this year — averaging $2.11/mmBtu through November this year at the US benchmark Henry Hub — triggered by an unusually warm 2023-24 winter, may have obscured some of the structural factors pushing the US gas market into a more volatile future. But those structural factors remain and loom increasingly large for prices. The US has moved from a roughly 60 Bcf/d (1.7bn m³/d) market eight years ago to a more than 100 Bcf/d market today, "and we haven't grown our storage capacity at all", Rich Brockmeyer, head of North American gas and power at commodity trading house Gunvor, said earlier this year. As supply and demand for US gas grow, the country's roughly 4.7-Tcf storage capacity becomes ever less effective in stemming demand shocks, such as extreme winter weather events, which can more rapidly draw down inventories than in years past. Additionally, a growing share of US gas is being consumed by LNG export terminals being built and expanded on the US Gulf coast. When those facilities encounter unexpected problems and cease operations — as has happened numerous times at the 2 Bcf/d Freeport LNG terminal in Texas in recent years — volumes that were previously being liquefied and sent overseas were instead backed up into the domestic market, crushing prices. More LNG exports may mean more opportunities for such supply shocks. US LNG exports are expected to increase by 15pc to almost 14 Bcf/d in 2025 as operations begin at Venture Global's planned 27.2mn t/yr Plaquemines facility in Louisiana and Cheniere's 11.5mn t/yr Corpus Christi, Texas, stage 3 expansion, US Energy Information Administration data show. Spot price volatility will be most acutely felt in regions like New England that lack underground gas storage. "In areas like the Gulf coast, where you have a lot of storage, it won't be a problem," Alan Armstrong, chief executive of Williams, the largest US gas pipeline company, told Argus in an interview. Producers' trade-off Volatile gas markets are a mixed bag for producers, many of whom profit from volatility while also struggling to plan and budget based on uncertain revenues for unhedged volumes. Though insufficient gas storage deprives the market of stability, "from the standpoint of a marketing and trading guy that's trying to manage my gas supply to customers and my trading book, I love volatility",said Dennis Price, vice president of marketing and trading at Expand Energy, the largest US gas producer by volume. BP chief financial officer Sinead Gorman in November 2023 specifically named Freeport LNG's eight-month-long shutdown in 2022-23 from a fire as a driver of volatility in the global gas market. The supermajor was able to exploit the "incredibly fragile" gas market, she said, which was a key factor driving the success of its integrated gas business. "Those opportunities are what we typically seek and enjoy," Gorman said. Increasingly, producers have also been adapting to a more volatile market by switching production on and off in response to prices, but often without revealing the price at which a supply response will occur. Expand Energy, for instance, told investors in October that it was amassing drilled but uncompleted wells and wells that had yet to be brought on line, which it could activate relatively quickly when prices rise. It declined to name the price at which that would occur. Market participants, attempting to price in this phenomenon by anticipating producers' next moves may respond more dramatically to supply signals than in the past, when production was steadier. Producers' increased responsiveness to prices could help to balance the market somewhat, though more aggressive intervention into operations could take a toll on well performance and pipelines, FactSet senior energy analyst Connor McLean said. Producers are "treating the reservoir itself like a storage facility", Price said. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Unified CO2 market remains in distance

24/12/26

Viewpoint: Unified CO2 market remains in distance

Houston, 26 December (Argus) — Washington state's carbon market enters 2025 on steadier ground than it stood on for much of the past year, but still faces hurdles before it is part of a larger North American market. Washington's cap-and-invest program has weathered a year of highs and lows between advancing its ambitions to link with the Western Climate Initiative and operating through much of the year under threat of repeal in the November state elections. The state Department of Ecology director Laura Watson began the state's quest to link with the WCI last year , as regulators looked to the larger, more liquid market to potentially temper the higher-than-expected prices over the first year of the market in 2023. Washington Carbon Allowances (WCAs) for December 2023 delivery surged as high as $70/t last year, according to Argus assessments. But the state has clinched several wins for its program this year. State lawmakers were able to pass a bill to smooth out several areas of potential incompatibility with the WCI earlier this year, along with California and Quebec agreeing to move forward into formal linkage talks in March . But a repeal effort, initiative 2117, seeking to remove the state's cap-and-invest program dampened prices and forward movement on linkage since January. WCAs for December 2024 delivery fell to the lowest price to date for the program at $30.25/t on 4 March, according to Argus assessments, as uncertainty over the future of the program quieted market participation. State voters backed the cap-and-invest program in November with 62pc against the repeal effort, but months of uncertainty has cost the state time and linkage progress as the WCI awaited the November results. Additionally, while Washington started its own linkage rulemaking in April to align the program with changes planned for the WCI, finishing it requires the joint market first finalize its own changes. The linkage logjam has left market participants feeling that the state's momentum is stalled for the moment, even as perception of the state's eventual joining remains a question of "when" not "if." Ecology says it remains in communication with the WCI members and is evaluating the impact of California's new rulemaking timeline. California has indicated over this year that it does not intend to focus fully on linkage until its current rulemaking is complete. Ecology estimates it will adopt its new rules in fall 2025, with the earliest the state could expect a linkage agreement in late 2025. Washington must still complete further steps required by state law before any linkage agreement can proceed, including an environmental justice assessment and a final evaluation of a potential joint market under criteria set by its Climate Commitment Act, along with public comment. California and Quebec must also conduct their own evaluations to comply with respective state and provincial laws. If this timing works out, Ecology would be part of joint auctions starting in 2026. Compounding the process is the potential threat posed by incoming president-elect Donald Trump, who is likely to try to reverse major environmental regulations and commitments. Trump sought ultimately unsuccessful litigation in his first administration to sever the link between Quebec and California in 2019. The administration pursued the case on the grounds that California's participation violated federal authority to establish trade and other agreements with foreign entities under Article I of the US Constitution, which sets out the role of the federal and state powers in commerce and agreements with foreign powers. Both California and Washington have undergone preparations in recent months to gird themselves for a legal fight with the incoming administration, and that may add further scrutiny to linkage for both states going forward, said Justin Johnson, a market expert with the International Emissions Trading Association. "I think that it will require them to be more vigilant about the process they use and making sure they dot their i's and cross their t's because I think that there will be some folks in the federal administration who would like to see that not happen," Johnson said. By Denise Cathey Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: MEH-Midland spread to remain wider in 2025

24/12/26

Viewpoint: MEH-Midland spread to remain wider in 2025

Houston, 26 December (Argus) — WTI Houston's premium to WTI in Midland, Texas, is set to hold at 50¢/bl or wider in 2025, boosted by swelling volumes headed toward the Gulf coast as Houston grows in importance as a center for price discovery. The locational spread between WTI Houston and Midland rose steadily throughout 2024, averaging 49¢/bl year-to-date and widening as high as $1.41/bl during the June trade month as the 1.5mn b/d Wink-to-Webster pipeline was taken offline for repairs. In 2023, the spread averaged 21¢/bl. Trading activity for WTI at Oneok's Magellan East Houston (MEH) terminal — both in the physical and financial markets — climbed to all-time highs in 2024. Reported trade month volumes for WTI Houston swelled to 1.26mn b/d during the December trade cycle, a high for the year, and just 0.8pc below its previous record. On 16 December, WTI Houston trade closed the day at 153,000 b/d for the January trade cycle, the highest single-day trade volume in the history of Argus assessments of the grade. In financial markets, WTI Houston trade activity broke records in 2024, with open interest on CME's WTI Houston futures contract climbing to an all-time high of 412,519 lots — each 1,000 bl — on 21 November. MEH demand up despite export slowdown Trading activity broke records even as US crude exports slowed in the latter half of 2024 on Chinese economic woes that dampened Asian demand. New Chinese stimulus initiatives, namely relaxed fiscal and monetary policy , are meant to reverse that trend, but it remains to be seen if the efforts will work. Further challenges weighing on the US export market are a strengthening dollar combined with a high degree of uncertainty surrounding president-elect Donald Trump's proposed tariff plans, which feature ratcheting-up trade tensions with China even more. Multiple projects to add Permian takeaway capacity at the Texas Gulf coast are in various stages of planning, which could eventually open the window for ever-larger WTI export volumes, and further support WTI Houston against Midland. But industry participants have grown skeptical of the need for new export terminals or other projects. Midstream companies showed little enthusiasm for pitching new coast-bound pipelines from the Permian basin in their end-of-year investor reports . Key firms previously sought more takeaway capacity before the Covid-19 pandemic, when WTI Houston premiums to WTI in Midland consistently topped $1/bl, which would help recoup pipeline construction costs. As it stands, the roughly 3mn b/d total available pipeline capacity from the Permian basin to the Houston area is likely to remain static in coming years. This status quo for onshore infrastructure will help prop open the Houston-Midland WTI premium for the coming year, even if export demand fails to picks up in 2025. By Gordon Pollock WTI Houston-WTI Midland spread Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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