Biden shifts strategy on infrastructure deal

  • : Coal, Crude oil, Electricity, Emissions, Metals, Natural gas, Oil products
  • 21/06/08

President Joe Biden today called off talks with top Republicans on an infrastructure bill, and is instead leaning on a bipartisan group of US senators to develop a compromise package that can pass.

Biden had spent weeks trying to reach an infrastructure deal with the US Senate Transportation and Infrastructure Committee's ranking member Shelley Moore Capito (R-West Virginia), but she said Biden called her today to end negotiations. The two sides had made limited progress on the two central issues for the bill: its overall size and how to pay for the new spending.

"After negotiating in good faith and making significant progress to move closer to what the president wanted, I am disappointed by his decision," Capito said.

The White House said on the call Biden expressed "disappointment" that while he cut the size of his infrastructure plan to $1 trillion from $2 trillion, Republicans only agreed to increase new investments by $150bn. Republicans for months refused to budge on their position that the bill should stick mostly to traditional infrastructure, such as roads and bridges, and not increase taxes.

The administration now hopes other US senators can make progress on a bipartisan deal, while Biden leaves town on a trip to Europe on 9-16 June. Biden has separately spoke with US senators Joe Manchin (D-West Virginia), Kyrsten Sinema (D-Arizona) and Bill Cassidy (R-Louisiana) to push them to continue infrastructure talks.

"He urged them to continue their work with other Democrats and Republicans to develop a bipartisan proposal that he hopes will be more responsive to the country's pressing infrastructure needs," the White House said.

Before talks with Capito ended, the White House had missed a self-imposed deadline to decide on a path forward around the Memorial Day holiday weekend. Senate Republicans in their latest offer on 4 June pledged to add $50bn onto a prior offer, a $310bn increase in baseline spending. But that was still well short of Biden's proposal for about $1 trillion in new spending.

Senate Democrats still have the option to pass large parts of their infrastructure plan through a maneuver named budget reconciliation, which would avoid a filibuster but needs unanimous support from Democrats because of their 50-50 majority in the chamber. But Manchin's push for a bipartisan plan has become a major obstacle to that strategy.

"I think we can come to that compromise to where we will find a bipartisan deal," Manchin said in a televised interview on 6 June. "I am very, very confident of that."

If the White House is still able to negotiate a bipartisan deal on infrastructure, Democrats worry it would likely have to exclude major climate change items, such as a national "clean energy standard" for the grid and the removal of tax preferences for oil and gas companies. Democrats could pass those items through a subsequent bill, but doing so could be a difficult political challenge.

"I am now officially very anxious about climate legislation," US senator Sheldon Whitehouse (D-Rhode Island) said on Twitter yesterday. "I do not see the preparatory work for a close Senate climate vote taking place in the administration."

Biden has proposed to pay for his infrastructure plan by raising taxes on corporations, which Senate Republicans say is a "red line" that would cost their support. Republicans have also raised concerns with US treasury secretary Janet Yellen's landmark deal on 5 June with G7 countries for a global minimum tax on corporations, which she says would stop a "race-to-the-bottom" in taxation.

"We continue to caution against moving forward in a way that could adversely affect US businesses and ultimately harm American workers and jobs at a critical time in our country's economic recovery," House of Representatives Ways and Means ranking member Kevin Brady (R-Texas) said.


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24/05/01

US gas industry pins hopes on AI power demand

US gas industry pins hopes on AI power demand

New York, 1 May (Argus) — US natural gas producers and pipelines have pivoted almost in unison this year to talking up what they see as one of the strongest bullish cases for gas this decade: surging electricity demand from yet-to-be-built data centers to power artificial intelligence software. EQT, the largest US gas producer by volume, in an investor presentation last week called growing data center demand the "cornerstone" to the "natural gas bull case." Combining its own research with data from the US Energy Information Administration, the gas giant forecast an increase in gas demand of 10 Bcf/d (283mn m3/d) by 2030 to generate electricity, mostly to run data centers. Its more aggressive data center build-out scenario envisions a whopping 18 Bcf/d increase in gas demand through 2030. Total US gas production is currently about 100 Bcf/d. Kinder Morgan, one of the largest US gas pipeline operators, this month forecast 20pc of US power being gobbled up by data centers in 2030, up from a 2.5pc share in 2022. Cobbling together projections from several consultancies and financial advisories, the company said the electricity needed to run artificial intelligence software alone will comprise 15pc of US power demand by 2030. If just 40pc of that demand is met by gas, that would represent an increase in gas demand of 7-10 Bcf/d, it said. This is roughly in line with the high end of US bank Tudor Pickering Holt's forecast for gas demand to power data centers through 2030 (1.3-8.5 Bcf/d) and well above Goldman Sachs' and consultancy Enverus' projections of 3.3 Bcf/d and 2 Bcf/d, respectively. New tech, old problems Separating the wide ranges of these projections is the highly speculative nature of forecasting demand years into the future for competing energy sources to power next-generation technology. But the major upside and downside risks, analysts say, concern the more humdrum challenges of permitting and building out energy infrastructure. Goldman Sachs expects 28GW, or 60pc, of the generation capacity needed to power new data centers through 2030 will come from natural gas — 9GW from combined cycle gas turbines and 19GW from gas peaker plants. But with an average lag of four years from the time a gas transmission project is announced to the time it enters service, to say nothing of the high probability of litigation being brought by environmentalists and landowners, construction and permitting timelines are "the most top of mind constraint for natural gas," the bank said. Indeed, litigation and opposition from state regulators have ultimately led developers to call off several interstate pipeline projects in the eastern US in recent years. The exception to the rule, Equitrans' 2 Bcf/d Mountain Valley Pipeline is moving forward only because congressional action allowed it to bypass federal permitting hurdles. This is a particular problem for the gas industry's hopes of exploiting the data center boom, as a large share of future data centers are slated to be built in the southeast US, far from the major US gas fields. New data centers representing 2 Bcf/d of gas demand in Georgia probably requires a new pipeline into the southeast, FactSet senior energy analyst Connor McLean said. Southeast premium A significant data-center buildout in the southeast without new pipelines could put upward pressure on regional gas prices, McLean said. This could exacerbate the effects of what has become perhaps the most prominent bullish case for US gas: a massive build-out of LNG export terminals along the US Gulf coast. With new export terminals pulling increasing volumes of gas south along the Transcontinental gas pipeline to super-chill and ship overseas in the coming years, the build-out in data centers will likely produce "an even bigger deficit in that southeast (gas) market," EQT chief financial officer Jeremy Knop told investors last week. "We think that market really, in time, becomes the most premium market in the country," he said. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Tankers can take TMX crude mid-May: Trans Mountain


24/05/01
24/05/01

Tankers can take TMX crude mid-May: Trans Mountain

Calgary, 1 May (Argus) — Commercial operations for the 590,000 b/d Trans Mountain Expansion (TMX) crude pipeline in western Canada have officially started today, but tankers will not be able to load crude from the line until later this month. Line fill activities, which began on 16 April, are still ongoing for the C$34bn ($25bn) project that stretches from Edmonton, Alberta, to the docks in Burnaby, British Columbia. About 70pc of the volumes needed are in the 1,181 kilometre (733 mile) line, Trans Mountain said on Wednesday. "As of today, all deliveries for shippers will be subject to the Expanded System tariff and tolls, and tankers will be able to receive oil from Line 2 by mid-May," Trans Mountain said. Aframax-size crude tankers started to take position on the west coast last month in anticipation of the new line. But the inability to deliver crude at Burnaby, while still having to pay full tolls, was a concern raised by several shippers on 23 April. "Trans Mountain must be able to receive, transport and deliver a shipper's contract volume," the shippers said in a letter to the CER. The ability to deliver the crude is "clearly central and fundamental qualities of firm service." The CER in November approved interim tolls for the system that will further connect Albertan oil sands producers to Pacific Rim markets. Shippers will, at least initially, pay C$11.46/bl to move crude from Edmonton, Alberta, to the Westridge terminal in Burnaby, British Columbia. The fixed portion accounts for C$10.88/bl of this and has nearly doubled from a C$5.76/bl estimate in 2017. The Canada Energy Regulator (CER) on 30 April gave Trans Mountain a green light to put TMX into service , ending years of uncertainty that the project would ever be completed. The expansion project, or Line 2, nearly triples the capacity of Canadian crude that can flow to the Pacific coast, complementing the original 300,000 b/d line, or Line 1, that has been operating since 1953. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

G7 coal exit goal puts focus on Germany, Japan and US


24/05/01
24/05/01

G7 coal exit goal puts focus on Germany, Japan and US

London, 1 May (Argus) — A G7 countries commitment to phase out "unabated coal power generation" by 2035 focuses attention on Germany, Japan and the US for charting a concrete coal-exit path, but provides some flexibility on timelines. The G7 commitment does not mark a departure from the previous course and provides a caveat by stating the unabated coal exit will take place by 2035 or "in a timeline consistent with keeping a limit of 1.5°C temperature rise within reach, in line with countries' net-zero pathways". The G7 countries are Italy — this year's host — Canada, France, Germany, Japan, the UK and the US. The EU is a non-enumerated member. The announcement calls for accelerating "efforts towards the phase-out of unabated coal power generation", but does not suggest policy action. It calls for reducing "as much as possible", providing room for manoeuvre to Germany, Japan and the US. Coal exports are not mentioned in the communique. Canada and the US are net coal exporters. France, which predominantly uses nuclear power in its generation mix is already scheduled to close its two remaining coal plants by the end of this year. The UK will shut its last coal-fired plant Ratcliffe in September . Italy has ended its emergency "coal maximisation plan" and has been less reliant on coal-fired generation, except in Sardinia . The country has 6GW of installed coal-fired power capacity, with state-controlled utility Enel operating 4.7GW of this. The operator said it wanted to shut all its coal-fired plants by 2027. Canada announced a coal exit by 2030 in 2016 and currently has 4.7GW of operational coal-fired capacity. In 2021-23, the country imported an average of 5.7mn t of coal each year, mainly from the US. Germany Germany has a legal obligation to shut down all its coal plants by 2038, but the country's nuclear fleet retirement in 2023, coupled with LNG shortages after Russia's invasion of Ukraine, led to an increase in coal use. Germany pushed for an informal target to phase out coal by 2030, but the grid regulator Bnetza's timeline still anticipates the last units going offline in 2038. The G7 agreement puts into questions how the country will treat its current reliance on coal as a backup fuel. The grid regulator requires "systematically relevant" coal plants to remain available as emergency power sources until the end of March 2031 . Germany generated 9.5TWh of electricity from hard-coal fired generation so far this year, according to European grid operator association Entso-E. Extending the current rate of generation, Germany's theoretical coal burn could reach about 8.8mn t. Japan Japan's operational coal capacity has increased since 2022, with over 3GW of new units connected to the grid, according to the latest analysis by Global Energy Monitor (GEM). Less than 5pc of Japan's operational coal fleet has a planned retirement year, and these comprise the oldest and least efficient plants. Coal capacity built in the last decade, following the Fukushima disaster, is unlikely to receive a retirement date without a country-wide policy that calls for a coal exit. Returning nuclear fleet capacity is curtailing any additional coal-fired generation in Japan , but it will have to build equivalent capacity to replace its 53GW of coal generation. And, according to IEA figures, Japan will only boost renewables up to 24pc until 2030. The US The US operates the third-largest coal-power generation fleet in the world, with 212GW operational capacity. Only 37pc of this capacity has a known retirement date before 2031. After 2031, the US will have to retire coal-fired capacity at a rate of 33GW/yr for four years to be able to meet the 2035 phase-out deadline. By Ashima Sharma Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Mitsui makes delayed exit from Paiton power project


24/05/01
24/05/01

Mitsui makes delayed exit from Paiton power project

Tokyo, 1 May (Argus) — Japanese trading house Mitsui completed on 30 April the ¥109bn ($690mn) sale of its stake in Indonesia's 2,045MW Paiton coal-fired power plant in east Java following multiple delays. Mitsui originally tried to complete its exit by the end of March 2022 . It said the procedures with Paiton's offtaker Indonesian state-owned power firm Persero took more time than expected without providing further details. Japanese thermal power producer Jera withdrew from Paiton by selling its 14pc share in 2021. Mitsui sold its 45.515pc share in Paiton Energy, as well as a 45.515pc stake in Netherlands-based subsidiary Minejesa Capital and a 65pc stake in Singapore-based IPM Asia that are related companies of the Paiton project. Mistui sold the stakes to RH International (RHIS), which is a Singapore-based subsidiary of Thai power producer Ratch, and Indonesian power company Medco Daya Abadi Lestari's subsidiary Medco Daya Energi Sentosa (MDES). Paiton Energy is now owned by RHIS, MDES and Qatar-based company Nebras Power. Mitsui did not disclose their ownership ratios. Paiton consists of the 615MW No.7, 615MW No.8 and the 815MW No.3 units, which sell electricity to Persero through an unspecified long-term contract. Mitsui now holds 9.6GW of power capacity assets globally, with 8pc being coal-fired projects. The exit from Paiton cut its coal-fired ratio by 8 percentage points, while raising its renewable ratio by 3 percentage points to 32pc. Growing global pressure against coal-fired power generation likely prompted Mitsui to exit Paiton. Energy ministers from G7 countries this week pledged to accelerate "efforts towards the phase-out of unabated coal power generation". By Nanami Oki Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Canada’s TMX pipeline ready to move crude: Update


24/04/30
24/04/30

Canada’s TMX pipeline ready to move crude: Update

Adds regulatory approvals received. Calgary, 30 April (Argus) — Canada's 590,000 b/d Trans Mountain Expansion (TMX) crude pipeline can now start moving volumes to the Pacific coast after receiving final regulatory approvals today, more than a decade after the project was first conceived. The Canada Energy Regulator (CER) approved Trans Mountain's final applications on Tuesday, giving the midstream company a green light to put its C$34bn ($25bn) project into service. Trans Mountain had recently maintained its commitment to being ready by 1 May. The expansion nearly triples the existing 300,000 b/d Trans Mountain line that runs from Edmonton, Alberta, to Burnaby, British Columbia. Also expanded was the Westridge Marine Terminal from one dock to three, all capable of loading Aframax-sized vessels. The line will provide Canadian oil sands producers with a significant export outlet without having to first go through the US. Much of the new volume to flow on TMX is expected to be heavy sour crude. Federally-owned Trans Mountain had submitted applications as recent as 15 April for the final section of the pipeline about 140 kilometers (87 miles) east of the line's terminus in Burnaby. The final applications concerned piping, valves and other components at two pipeline inspection device traps and the mainline pipe between the two traps. The traps were added for safety assurance when the operator was allowed by CER to use a smaller diameter pipe as part of the Mountain 3 deviation. Mountain 3 was the last segment of the pipeline to be constructed because of delays relating to difficult terrain while tunneling. The "golden weld" marking the end of construction occurred on 11 April, according to Trans Mountain. A group of shippers last week expressed concern that TMX would not be ready for commercial service by 1 May. The pipeline had been marred by legal challenges and cost over-runs since it was first proposed in 2013 by its then-owner US midstream firm Kinder Morgan. The Canadian government took ownership of it in 2018. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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