Dutch regulator urges caution on H2 transport
Dutch energy regulator ACM recommended that investors should target the scaling up of hydrogen production as well as waiting for higher hydrogen consumption prior to developing transportation infrastructure, including repurposing existing gas pipelines.
Investors should focus on bringing sufficient hydrogen production capacity on line before developing transportation routes in order to avoid excess costs from underutilisation, ACM said.
And consumption of hydrogen — which is "virtually absent" at present — must become widespread in order to justify investments in pipelines, it added. Hydrogen can be used for chemical products, heat-intensive industrial processes, heavy transport and electricity generation, as well as a form of energy storage, but is not widely used for these purposes today.
Fossil-fuel derived blue and grey hydrogen must be scaled up before sustainable green hydrogen, as the electrolysis process used to produce hydrogen from renewables-generated electricity is still "too expensive", the regulator said.
But ACM suggested that appropriately pricing CO2 emissions into the cost of grey and blue hydrogen could make green hydrogen more competitive.
Governments should offer subsidies to improve the technological performance of electrolysers used in the production of green hydrogen, the regulator said.
Once hydrogen production and consumption have reached a certain threshold, ACM recommends that operators take a "step-by-step approach" to developing transport infrastructure.
Firms should only gradually convert gas pipelines for hydrogen use in order to limit the possibility of stranding assets following the transition, it said. And investors should focus on first developing pipeline projects at industrial sites, which are largely positioned along the coast near seaports in the Netherlands.
Industrial sites can utilise hydrogen most easily, and offshore wind sites could provide an opportunity for green electrolysis moving forward, ACM said.
Hydrogen could also be transported in liquid form or as ammonia by ship to the seaports.
Government rules regulating hydrogen markets and related infrastructure should be implemented incrementally as needed rather than in advance, ACM said. This will allow for "innovation" while also preventing the "abuse of market power", it said.
A number of Europe's gas system operators have proposed building a continent-wide hydrogen network by combining repurposed gas pipelines and new infrastructure, called the European Hydrogen Backbone (EHB). Rotterdam's port authority — where the country's lone LNG import terminal Gate is located — is working with transmission operator GTS and German utility Uniper to build hydrogen infrastructure that could connect to such a network if developed.
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Canada furthers investment in GHG reductions
Canada furthers investment in GHG reductions
Houston, 18 April (Argus) — The Canadian government plans to have C$93bn ($67.5bn) in federal incentives up and running by the end of the year to spur developments in clean energy technology, hydrogen production, carbon capture utilization and storage (CCUS) along with a new tax credit for electric vehicle (EV) supply chains. The Canada Department of Finance, in its 2024 budget released on 16 April, said it expects to have the first planned investment tax credits (ITCs), for CCUS and renewable energy investments, in law before 1 June. The ITCs would be available for investments made generally within or before 2023 depending on the credit. The anticipated clean hydrogen ITC is also moving forward. It could provide 15-40pc of related eligible costs, with projects that produce the cleanest hydrogen set to receive the higher levels of support, along with other credits for equipment purchases and power-purchase agreements. The government is pursuing a new ITC for EV supply chains, meant to bolster in-country manufacturing and consumer adoption of EVs with a 10pc return on the cost of buildings used in vehicle assembly, battery production and related materials. The credit would build on the clean technology manufacturing ITC, which allows businesses to claim 30pc of the cost of new machinery and equipment. To bolster reductions in transportation-related greenhouse gas (GHG) emissions, the government will also direct up to C$500mn ($363mn) in funding from the country's low-carbon fuel standard to support domestic biofuel production . Transportation is the second largest source of GHG emissions for the country, at 28pc, or 188mn metric tonnes of CO2 equivalent, in 2021. But the province of Alberta expressed disappointment at the pace of development of ITC support that could help companies affected by the country's move away from fossil fuels. "There was nothing around ammonia or hydrogen, and no updates on the CCUS ITCs that would actually spur on investment," Alberta finance minister Nate Horner said. The incentives are intended to help Canada achieve a 40-45pc reduction in GHG emissions by 2030, relative to 2005 levels. This would require a reduction in GHG emissions to about 439mn t/yr, while Canada's emissions totaled 670mn in 2021, according to the government's most recent inventory. The budget also details additional plans for the Canada Growth Fund's carbon contracts for a difference, which help decarbonize hard-to-abate industries. The government plans to add off-the-shelf contracts to its current offering of bespoke one-off contracts tailored to a specific enterprise to broaden the reach and GHG reductions of the program. These contracts incentivize businesses to invest in emissions reducing program or technology, such as CCUS, through the government providing a financial backstop to a project developer. The government and developer establish a "strike price" that carbon allowances would need to reach for a return on the investment, with the government paying the difference if the market price fails to increase. CGF signed its first contract under this program last year , with Calgary-based carbon capture and sequestration company Entropy and has around $6bn remaining to issue agreements. To stretch this funding further, the Canadian government intends for Environment and Climate Change Canada to work with provincial and territorial carbon markets to improve performance and potentially send stronger price signals to spur decarbonization. By Denise Cathey Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
NSTA fines Neo Energy for North Sea methane venting
NSTA fines Neo Energy for North Sea methane venting
London, 18 April (Argus) — UK offshore regulator the North Sea Transition Authority (NSTA) has fined UK upstream firm Neo Energy £100,000 for breaching its methane venting permit at North Sea fields. The company emitted 1,200t of methane in excess of its permit from the Donan, Lochranza and Balloch fields in the first nine months of 2022. Neo had permission to vent 378t of methane from installations at these fields in that year, but incorrectly assigned volumes vented through unlit flares to its flaring consent, the NSTA found. Neo showed a "lack of oversight" by failing to detect the licence breach for seven months, NSTA said. The company reached its annual limit by 21 March 2022, but continued venting without authorisation until October 2022. The company said it did not update its flare and vent allocation process to reflect NSTA guidance updated in 2021, and as such was still assigning its flaring and venting according to previous guidance. Neo becomes the fourth company to be fined by the NSTA over breaches relating to flaring and venting consents. The regulator in 2022 sanctioned Equinor and EnQuest and last year fined Spanish utility Repsol for consent breaches. The four companies have been fined a total of £475,000 for the breaches. And the regulator in February had four more investigations under way for breaches of vent consents. Neo Energy's fine is equivalent to £2.98/t of CO2e emitted, assuming a global warming potential of methane that is 28 times that of CO2 on a 100-year time scale, compared with a UK emissions trading system price of £34.40/t of CO2e on 17 April. The UK offshore industry targets a 50pc reduction in production emissions of greenhouse gases by 2030, from a 2018 baseline. And it intends to end all routine venting and flaring by that year. The regulator last year warned that "further, sustained action" would be needed to reach the 2030 emissions reduction goal. Methane emissions from offshore gas fell in recent years, to 1mn t in 2022 from 1.6mn t in 2018, according to NSTA data. Roughly half of methane emissions in the sector in recent years has been produced by venting, while flaring makes up about a quarter of the emissions. The UK government is a member of the Global Methane Pledge group of countries that aims to reduce methane emissions by 30pc by 2030 from a 2020 baseline. By Rhys Talbot Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
US LNG growth seen stoking price volatility
US LNG growth seen stoking price volatility
Ponte Vedra Beach, 17 April (Argus) — Natural gas prices in the US and globally will face greater volatility because of LNG export expansions along the US Gulf Coast, according to speakers at the Southeast LDC Gas Forum in Ponte Vedra Beach, Florida. LNG export capacity from the US, already the largest provider of LNG into the global market, is set to expand in the coming years, putting an important source of global supply in the path of hurricanes and exposed to pipeline disruptions from key supply areas such as the Permian basin in west Texas and southeastern New Mexico. US baseload LNG export capacity was forecast to increase by the end of 2025 to about 16.7 Bcf/d (473mn m³/d), up by 46pc from the 11.4 Bcf/d of capacity at the end of 2023, according to the US Energy Information Administration (EIA). US LNG production by 2030 will meet about 5pc of global gas demand and 30pc of global LNG demand, Jill Davies, general manager of North America LNG Trading at Shell Energy, told attendees today at the conference. Most of those supplies will depart the US from the Gulf coast. That means a disruption in US exports could cause global prices to rise or domestic prices to crater. More pipelines and storage would allow LNG export terminals to access supply from different regions, defraying some of the price risk, according to speakers at the conference. The potential price volatility highlights the need for greater US political support for new gas infrastructure, Davies said on the sidelines of the conference. Pipeline projects aiming to connect key producing areas to growing demand centers have failed to clear regulatory hurdles in recent years, raising concerns about the potential for supply growth from prolific fields such as the Marcellus and Utica shales. Prices in the US market can also soar on supply disruptions or plunge on downtime at LNG export terminals. Prices have faced downward pressure this spring from ongoing maintenance at the 2.1 Bcf/d Freeport LNG export terminal in Texas. An extended, eight-month-long shutdown of that terminal that began in the summer of 2022 caused prices to fall by backing up supply into the US market. Producers that gain more exposure to exports and, in turn, the global market could "face a tenuous situation when a hurricane stirs up in the Gulf," Zach Inman, vice president of origination for BP said during a panel discussion Wednesday. By Jason Womack Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Permian gas pipes will shift lower prices east: Panel
Permian gas pipes will shift lower prices east: Panel
Ponte Vedra Beach, 17 April (Argus) — Additional pipelines will be needed to remedy negative natural gas prices at Waha in west Texas, but that new takeaway capacity will only shift lower prices further east, according to panelists today at Southeast LDC Gas Forum in Ponte Vedra Beach, Florida. Spot natural gas prices at Waha have mostly traded at negative levels since 11 March as robust gas production outstrips the pipeline capacity needed to ferry those supplies to market. The pipeline constraints have been exacerbated in recent weeks by seasonal pipeline maintenance and the usual drop in demand that accompanies spring. Spot prices at Waha, a key indicator for the price of gas output from the Permian basin in west Texas and southeastern New Mexico, has averaged -$1.45/mmBtu so far in April, meaning that producers were paying buyers to take gas. Waha prices are waiting on Matterhorn, a 2.5 Bcf/d (71mn m3) gas pipeline that will connect the Permian basin to southeast Texas, Jack Weixel, senior director of East Daley Analytics, told attendees at the conference. Matterhorn was scheduled to begin service later this year and will probably begin taking initial gas supplies this summer. Most of the gas produced in the Permian basin comes from oil wells, so as long as oil prices are high enough to encourage drilling, gas production will remain stout. Oil producers in the Permian "are well in the money to drill," Zach Inman, vice president of origination for BP, said. The additional gas supplies traveling to the Texas coast will push prices at key markets such as the Katy storage hub and the Houston Ship Channel to deeper discounts against the Henry Hub. Those additional supplies will also bottle up production that would usually flow to those markets from east Texas and parts of Louisiana, Weixel said. The resulting gas supplies may even push prices in east Texas low enough to inhibit drilling in the Haynesville shale, a prolific gas field in east Texas and northern Louisiana. Still, prices could receive a boost next year as new LNG export projects start service along the US Gulf coast, offering an outlet for those robust supplies, the panelists said. By Jason Womack Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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