N Dakota CO2 bills challenge to oil producers

Spanish Market: Crude oil, Emissions
27/01/23

Several proposed North Dakota laws set for debate today could bolster rights for property owners but challenge the state oil industry's plans to use carbon dioxide (CO2) to boost future production.

Companies building pipelines to carry CO2 in North Dakota would need consent from as much as 85pc of landowners on the pipeline right of way to proceed under a draft of Senate Bill 2209 (SB2209) that will be discussed in the state senate's energy and natural resources committee hearing today. The right of eminent domain would also be stripped from CO2 projects — but not oil and gas projects — even if they are considered common carrier pipelines, under another bill, SB2212.

The catalyst for the legislative efforts in a traditionally energy industry-friendly state is the Midwest Carbon Express pipeline, a $4.5bn project proposed by Summit Carbon Solutions and backed by oil and gas producer Continental Resources. The project would carry CO2 from ethanol plants in North Dakota, South Dakota, Nebraska, Minnesota and Iowa for sequestration north of Bismarck, North Dakota.

The project has attracted the ire of environmental groups throughout the states who label it an attempt at greenwashing biofuel production and the oil and gas business as a whole. Indigenous groups and other landowners along the planned pipeline route have also joined in on the opposition in many states, suggestion measures similar to the ones in North Dakota.

While the Midwest Carbon Express pipeline project is aimed at eventual carbon sequestration, injecting CO2 into oil wells to mobilize otherwise stranded oil volumes is one form of enhanced oil recovery (EOR) being pursued in North Dakota, the US' third-largest oil producing state. The technique has been used for years in other fields, including the Permian basin in Texas and New Mexico, which is served by several pipelines that carry CO2. But sourcing enough CO2 for new projects in North Dakota could be a challenge, making pipelines critical for future projects.

The proposed legislation aimed at CO2 projects "would really tie the hands of the oil and gas industry," according to Lynn Helms, the head of North Dakota's Department of Mineral Resources (DMR), as operators explore other methods to sustain production in the mature but prolific Bakken field. "[Bills 2209 and 2212] would both make it extremely difficult, if not impossible, to build carbon dioxide pipelines in the state."

North Dakota would likely "sacrifice many billions of barrels of oil" that would otherwise be unreachable without CO2 injections, said Helms.

State senator Jeffrey Magrum (R), who introduced the bills, told Argus the bills are not aimed at the oil and gas industry but are focused on protecting property rights and the "misuse" of eminent domain. Another bill put forward by Magrum, SB2313, would also increase the compensation for landowners by 33pc if eminent domain is used.

About 3pc of North Dakota's CO2 needs can be sourced from within the state, but the balance must be imported from elsewhere, DMR said. North Dakota's first and only crude project using CO2 injection is in Bowman County, which brings in CO2 from Wyoming via pipeline.

The DMR estimates 30-60pc of the Bakken's oil could be extracted using enhanced oil recovery, compared to just 1-15pc without this technology. The regulator did not specify how much CO2 injection would contribute to this gain compared to other EOR methods, such as water injection.

By Brett Holmes

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02/04/25

Article 6 credits 'could provide CBAM cost flexibility'

Lisbon, 2 April (Argus) — Allowing the use of credits issued under Article 6 of the Paris climate agreement for compliance with the EU's carbon border adjustment mechanism (CBAM) could provide flexibility for developing countries that lack the capacity to set up their own carbon pricing systems in response to the measure, delegates at a conference in Lisbon, Portugal, heard today. The CBAM regulation provides for a carbon price already paid on a product in its country of origin to be deducted from CBAM costs, providing an incentive for countries importing products covered by the measure to the EU to introduce equivalent carbon pricing systems. But developing countries often lack the capacity to enact such policies, the chief sustainability and innovation officer at ACT Group, Federico di Credico, told delegates, and allowing the use of Article 6 credits for compliance could provide an alternative. This could in one form take place implicitly, di Credico said, if CBAM liabilities are adjusted down in relation to pricing systems that themselves allow some compliance using Article 6 credits. An example of this is Singapore, where 5pc of the country's carbon tax can be offset through the purchase of Article 6 internationally traded mitigation outcomes (Itmos). A more direct inclusion of Article 6 credits for compliance could entail a calculation on a euro-for-euro basis, di Credico suggested, for example reducing a CBAM liability of €100 to €50 if the importer has purchased €50-worth of Article 6 credits. Using a tonne-for-tonne basis would not work because the CBAM is not volume based, he said. But the uncertainty surrounding Article 6 credits means that their inclusion would bring an added layer of complexity to the CBAM, Cedric de Meeus of cement producer Holcim said. Article 6 credits are not usable in the EU emissions trading system (ETS), which forms the reference price for the CBAM, he pointed out, while not all activities producing Article 6 credits would be equivalent to the deep decarbonisation being carried out by European industry. It remains unclear how the EU will take into account carbon prices in other jurisdictions for the purposes of the CBAM. The CBAM regulation includes the ability to credit a "carbon price… effectively paid in the country of origin" but does not define what falls within this term, and the implementing regulation that will provide further detail on the matter has not yet been tabled. Article 6 of the Paris deal provides for two carbon pricing mechanisms allowing countries to collaborate voluntarily to reduce their emissions. Article 6.2, which is already fully operational, produces Itmos through bilateral agreements on emissions reduction or removal projects, while Article 6.4 establishes the soon-to-be-implemented Paris Agreement Crediting Mechanism (Pacm), a UN-regulated global carbon crediting system. By Victoria Hatherick Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Transition technology draws energy R&D spend: IEA

02/04/25

Transition technology draws energy R&D spend: IEA

London, 2 April (Argus) — Public and corporate spending on energy research and development (R&D) is "trending upwards", with a focus on "low-emissions" technology, but venture capital investment in energy start-ups dropped last year, energy watchdog the IEA found. Government and corporate energy R&D spending increased to $50bn and over $160bn, respectively, in 2023 — the latest year for which full data are available, the IEA said. There are "early indications of continued growth in 2024", although the pace of growth has "slowed slightly" since 2022, it added. But "the momentum of investing in low-emissions energy technologies has been maintained", partly on the back of climate policy goals, the IEA noted. The share of "low-emissions" energy R&D spending has held at "roughly four-fifths of the global total" in recent years, the IEA said. It defines low-emissions energy as renewable power, grids and storage, energy efficiency, nuclear and "low-emissions fuels". Venture capital investments in energy start-ups totalled around $27bn in 2024, 23pc lower on the year, the IEA found. This reflects the "cyclical nature" of venture capital, as well as a drop in funding owed to inflation, but the trend "could have long-term negative impacts as innovators struggle to scale up high-potential technologies without access to affordable capital", the watchdog noted. The IEA also suggested that "the situation is compounded by uncertainties about political commitments to the climate policies that many start-ups depend on to drive demand". But venture capital financing rose in 2024 for start-ups focused on nuclear, synthetic fuels and carbon capture, use and storage (CCUS), it found. CCUS and "novel CDR" — carbon removal — technologies have drawn more venture capital funding in recent years, and sector R&D "is being spurred on by private capital mobilised by carbon credits", the IEA said. There are multiple ways to capture and store CO2, but many are at very early stages, while most funding goes towards just two approaches — direct air capture and bioenergy with CCS, its report found. By Georgia Gratton Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Australia’s gas leaders hit out at market intervention

02/04/25

Australia’s gas leaders hit out at market intervention

Sydney, 2 April (Argus) — Senior figures in Australia's upstream gas sector have hit out at plans for intervention in the heavily regulated industry, as debate continues on how to best address domestic supply shortfalls later this decade. The federal Coalition in March announced National Gas Plan including a 50-100 PJ/yr (1.34bn-2.68bn m³/yr) domestic reservation system aimed at forcing the three LNG exporters based in Queensland's Gladstone to direct more supply to the eastern states' market. But oversupplying the market to drive down prices would destroy the viability of smaller gas projects, Australian independent Beach Energy's chief executive Brett Woods said at a conference in Sydney on 1 April. The domestic-focused firm, which will export some LNG volumes via its Waitsia project in 2025, warns that such a move by the Peter Dutton-led opposition would reduce export incomes while harming Australia's international reputation. The volumes impacted by the policy could reach around 900,000-1.8mn t/yr. Expropriation of developed reserves is equivalent to breaking contracts with LNG buyers and with the foreign and local investors that the country needs for ongoing economic security, Woods said on 1 April. Domestic gas reservation systems put in place by the state governments of Western Australia (WA) and Queensland, designed to keep local markets well supplied, were "clearly supportable", Woods said, but only future supply should be subject to the regulations. LNG terminals, which represent about 70pc of eastern Australia's total gas consumption and shipped 24mn t in 2024 , should not be blamed for the failure of governments to expedite new supply and plan for Australia's gas future, head of Shell Australia Cecile Wake said in response to the Coalition's proposal. Shell's QGC business supplied 15pc of its volumes to the local grid, with the remainder shipped from its 8.5mn t/yr Queensland Curtis LNG project, Wake added. Canberra has moved to promote gas use as a transition fuel to firm renewable energy in line with its 2030 emissions reduction targets, but progress has been slow as reforming laws appear to be hampering development . The state governments, particularly in gas-poor Victoria and New South Wales (NSW), must recognise the need for locally-produced supply and streamline the approvals processes, especially environmental permits, executives said. But despite pleas for an end to years of interventionist policy — including the governing Labor party's measures to cap the price of domestic gas at A$12/GJ , Australia's fractured political environment and rising cost of living has sparked largely populist responses from its leaders. A so-called "hung" parliament is likely to result from the 3 May poll , with a variety of mainly left-leaning independents representing an anti-fossil fuel agenda expected to control the balance of power in Australia's parliament. LNG debate sharpens Debate on the causes of southern Australia's gas deficit has persisted, and the ironic outcome of underinvestment in gas supply could be LNG re-imports from Gladstone to NSW, Victoria and South Australia, making fracked coal-bed methane — liquefied in Queensland and regasified — a likely higher-emissions alternative to pipeline supply. Several developers are readying for this possibility , which is considered inevitable without action to increase supply in Victoria or NSW, increase winter storages or raise north-south pipeline capacity. Australian pipeline operator APA appears to have the most to lose out of the active firms in the gas sector. APA chief executive Adam Watson this week criticised plans for imports, because relying on LNG will set the price of domestic gas at a detrimental level, raise emissions and decrease reliability of supply, Watson said. The firm is planning to increase its eastern pipeline capacity by 25pc to bring new supplies from the Bass, Surat and Beetaloo basins to market. But investment certainty is needed or Australia will risk needing to subsidise coal-fired power for longer if sufficient gas is unavailable to back up wind and solar generators with peaking power, Watson said. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Brazil’s Bauna oilfield restarts after maintenance

02/04/25

Brazil’s Bauna oilfield restarts after maintenance

Sydney, 2 April (Argus) — Brazil-focused Australian oil and gas company Karoon Energy has brought its Bauna oilfield in the offshore Santos basin back on line after the completion of intervention works at its SPS-88 well in February. Production resumed on 27 March after the project was shut down for maintenance on 7 March, Karoon said. The field's output has since reached about 26,500 b/d, above pre-shutdown levels because of the return of SPS-88 well production on 28 March. The well is pumping 2,000 b/d of oil on a restricted choke and is gradually being opened further, with rates in line with expectations. The intervention was originally planned for October-December 2024 after being taken off line in November 2023 because of a mechanical blockage in the gas lift valve. Karoon's plans to acquire the Cidade de Itajai floating production, storage and offloading (FPSO) unit at its Bauna oilfield have progressed, with the transaction on track to close as forecast in April. Selection of a new operations and maintenance contractor for the FPSO will be announced in mid-2025, with an updated cost guidance to be provided once terms are agreed. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Canada oil producers get 6pc 1Q lift on weaker currency

01/04/25

Canada oil producers get 6pc 1Q lift on weaker currency

Calgary, 1 April (Argus) — A depreciating Canadian dollar is giving oil sands producers an extra lift and complementing relatively strong domestic crude prices to help weather tariff concerns. The Canadian dollar, on average, was worth C$1.44 to one US dollar in January-March 2025, weakening from C$1.35 to the greenback in the same quarter 2024, according to the Bank of Canada. That represents a more than 6pc advantage to Canadian producers selling crude in US dollars who then turn those earnings around to pay workers and suppliers in local currency. The outright price for heavy sour Western Canadian Select (WCS) at Hardisty, Alberta, settled at $58.67/bl in the first quarter this year, according to Argus data. This is only $1/bl higher than the same period last year, but with the now weaker Canadian dollar, that converts to over C$84/bl for producers who would have seen that under C$78/bl in the first quarter 2024. The Canadian dollar, on average, was worth C$1.37 to the US dollar in 2024, weakening from C$1.35 to the greenback in 2023 and the weakest annual average since 2003. The Bank of Canada largely attributes the sliding Canadian dollar to a rising foreign exchange rate risk premium, which relates to holding currencies other than the US dollar. This premium rises with uncertainty that has been amplified by US president Donald Trump's tariff actions in recent months, and that has also weighed on currencies from other economies, hitting developing countries' currencies harder than those of advanced economies. Also keeping the US dollar elevated is the US Federal Reserve's recent caution about resuming its cycle of cutting interest rates, thus attracting relatively more investors to US Treasury bills and boosting demand for US dollars. Canada meanwhile has brought its target rate lower to try to get ahead of an anticipated economic slowdown. The Fed's Federal Open Market Committee (FOMC) on 19 March held the federal funds rate unchanged at 4.25-4.50pc for a second consecutive meeting after cutting at the last three meetings of 2024. The Bank of Canada a week earlier lowered its overnight rate for the seventh consecutive time to 2.75pc. Giving a more obvious boost to Canadian producers in the first quarter this year compared with a year earlier have been the appreciating domestic crude prices relative to the US light sweet benchmark, which has weakened across the same period. WCS trades at a discount to the Nymex WTI calendar month average (CMA) and that gap has narrowed on the back of new export pipeline capacity out of Canada, added in May 2024. WCS traded at about $12.75/bl under the WTI CMA across the first quarter this year, compared with a $19.25/bl discount a year earlier. More recent trade activity shows WCS for April-delivery narrowing further yet to within $10/bl under the basis — the tightest since April 2021 — with oil sands producers temporarily shutting in some production to embark on major maintenance . By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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