Record carbon prices fail to stifle German coal margins

  • Spanish Market: Coal
  • 07/09/21

Record carbon prices in Europe are failing to price coal out of Germany's base-load merit order this winter, as a shortage of natural gas means there is limited scope for utilities to switch to cleaner alternatives at short notice.

The supply of EU emissions trading system (ETS) allowances, natural gas and coal have all tightened in Europe this year, creating a intense positive feedback loop in the power sector.

Rising carbon prices, all things being equal, provide an incentive to burn gas instead of coal for power, but a shortage of gas this year has supported gas prices at levels that fully offset the positive impact of rising carbon prices on gas' competitiveness against coal. This has created upward pressure for power prices, which have increased to cover the rising carbon costs that cannot be mitigated or lessened by coal-to-gas switching, supporting margins for coal-fired power plants this winter and boosting the demand outlook for power-sector coal burn.

The potential for firm and so relatively more carbon-intensive coal-fired power generation this winter is in turn creating additional support for carbon prices, closing the loop of an upward cycle that has characterised European generation fuels markets this year.

Carbon prices

Carbon prices exist to correct a market failure — they allocate a financial cost to a negative externality that was previously unaccounted for — in this case, the environmental cost of emitting CO2 from generating electricity.

But setting a financial cost that is equal to the environmental cost of the externality is difficult. Rather than setting this price directly itself, the EU indirectly sets the price through a cap-and-trade market-based system, with the supply of emissions allowances (EUAs) gradually reduced over time.

This reduction in EUA supply — and the likelihood of further reductions in the future as part of the bloc's "Fit for 55" plan to cut emissions by at least 55pc by 2030 from 1990 levels — has supported carbon prices this year, with allowances exceeding €60/t of CO2 equivalent for the first time at the end of August.

At current prices, the cost of carbon accounts for around €50/MWh, or 51pc of the marginal generation cost of a 42pc efficient coal-fired power plant in Germany. In early 2018, the carbon component was around €27/MWh, or 20pc of the marginal generation cost (see chart).

Wholesale power prices are a function of the generation costs for the marginal power plants needed to meet electricity demand, which are usually coal or gas-fired plants, and so power prices have risen this year in tandem with firming carbon and fuel costs.

This means carbon is increasingly being priced into the wholesale electricity market, going some way towards correcting the market failure that uncosted emissions represent. The previously unaccounted environmental cost of carbon is now being at least partly covered through a financial cost incurred by generators.

While the main goal of carbon prices is to ensure that the negative externality of emissions bears a financial cost, the mechanism can have other consequences that may be desirable or undesirable.

An implicit goal of carbon pricing is to encourage a shift towards cleaner sources of generation, since it is assumed that market participants will act to reduce the negative externality that they are responsible for in order to avoid the financial cost it now incurs.

In this sense, high carbon prices are a signal to accelerate investment in carbon-free generation capacity such as a solar and wind — although this may take some time to bear fruit — and to switch from more carbon-intensive fuels such as coal and lignite to cleaner fuels such as gas. Fuel switching like this could be more immediate if there is already spare gas-fired capacity to use and natural gas supply to consume, as there was in Europe last year.

The existence of a carbon price, and any strength in the carbon market, serves to lift the fuel-switching price for natural gas, which is the theoretical gas price at which generation costs for coal and gas-fired plants of specific efficiencies would be at parity. When the real market price for gas is above or below this level, the fuel is, respectively, uncompetitive or competitive with coal for power generation, based on prevailing coal and carbon prices at the time.

Since coal-fired generation is more carbon-intensive than gas-fired generation, the carbon price always represents a positive component of the fuel-switching price for natural gas. Rising carbon prices lift fuel-switching prices for natural gas and — assuming that gas and coal prices remain unchanged — make gas-fired generation relatively more competitive than coal.

In early 2018, the carbon component of the fuel-switching price of gas for a 55pc efficient gas-fired plant competing with a 42pc coal-fired unit was around €2/MWh, or 12pc of the total. This rose to €8.20/MWh, or 44pc, by the start of this year, and so far this month is €14.90/MWh, or 36pc, of the fuel-switching price (see chart).

Coal prices — the second component of the price for switching to gas — are also trading at more than a decade-high, resulting in an unprecedented fuel-switching price for gas of more than €41/MWh so far this month. But despite such a high fuel-switching price, the actual price of gas is even higher still, at around €51/MWh.

This is because of a shortage of gas in Europe, driven by unusually low inventories and relatively weak pipeline gas and LNG imports, which has significantly reduced availability for the power sector and kept prices supported at a level that makes it uncompetitive with coal.

German gas-fired generation fell by 5.9GW in August from a year earlier to 2.4GW, while coal-fired generation climbed by 690MW to 3.3GW. Coal-fired generation has averaged 7.2GW so far in September.

If rising carbon costs fail to trigger a shift towards less-emissions intensive generation, the carbon cost that is borne by the final consumer will be greater than it otherwise would be. This shows up another potential consequence of carbon pricing, namely that higher carbon costs could, when passed through to the consumer in higher prices, cut overall power demand.

To the extent that this may drive more efficient power demand — consumers insulating their homes for example — the consequence may be considered desirable. But if surging carbon prices make electricity prohibitively expensive for households and businesses and cut demand altogether, their impact may be significantly less palatable, since lower power demand could dent household living standards and economic output more generally.

The current situation marked by supply tightness across the carbon, gas and coal markets is creating a tension between two separate priorities — effectively pricing the environmental cost of unabated carbon emissions and ensuring affordable energy to support the wider economy.

What does this mean for coal?

Surging coal and carbon prices this year have failed to damage implied margins for winter coal-fired generation, which have continued to rise. The fourth-quarter 2021 and first-quarter 2022 clean dark spreads for 42pc efficient coal-fired base-load generation in Germany reached highs of €17.80/MWh and €25.60/MWh, respectively, last week.

The front fourth-quarter clean dark spread has not been higher at any point for at least the past six years (see chart).

The increasing profitability of coal-fired generation this winter suggests that the fuel remains an important backstop in the European power sector that may still be called upon when cleaner alternatives such as gas are not available, no matter what the carbon price.

But forward margins beyond the winter remain under pressure, with summer clean dark spreads for 42pc efficient coal-fired plants negative and spreads for even the highest efficiency coal-fired units negative for calendar 2024 and beyond because of the recent surge in carbon prices. This is a signal to retire existing capacity, meaning less coal-fired power is likely to be available in the future in the event of similar supply crunches, creating the potential for further power price volatility, depending on the speed at which renewable capacity is scaled up.

Some 8.4GW of German coal-fired capacity has already been awarded in phase-out tenders, 4.8GW of which had a 1 July deadline to stop burning coal, with a further 1.5GW to stop from 8 December. Availability is currently scheduled to climb from around 12GW in October to a peak of 14.7GW over November-February this winter.

German daily generation from coal peaked at 13.7GW last winter and averaged 6.6GW over November-February.

4Q 42% clean dark spreads €/MWh

42% efficient coal-fired costs €/MWh

42% coal vs 55% gas coal-switching price €/MWh

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Coal sales at Australia’s Whitehaven fall in Jan-Mar


Coal sales at Australia’s Whitehaven fall in Jan-Mar

Sydney, 19 April (Argus) — Australian coal miner Whitehaven reported higher production but lower sales in January-March, with the firm increasing its percentage of high-grade thermal coal sales from the previous quarter. Saleable coal volumes rose by 8pc on the year to 3.9mn t but managed coal sales fell by 7pc to 3.8mn t compared to a year earlier. Sales were 83pc high-grade thermal, higher than 72pc in October-December and 68pc a year earlier. Whitehaven said run-of-mine production at Narrabri was below expectations because of the current panel's geological challenges, leading to reliability and maintenance problems with equipment. Whitehaven's overall sales guidance for the 2023-24 fiscal year remains unchanged at 16mn-17.5mn t for 2023-24 with a unit cost guidance, excluding royalties, of A$103-113/t ($66-$72/t) which the firm said is tracking at the top end. This is because of lower output from Narrabri, which is tracking below its output guidance of 5.1mn-5.7mn t for the fiscal year to 30 June. Whitehaven finalised takeovers of Australian-Japanese joint venture BHP Mitsubishi Alliance's (BMA) 12mn t/yr Blackwater and 4mn t/yr Daunia coking and thermal coal mine in Queensland on 2 April, with initial sales and production data to be reported in its April-June production report. The two mines are anticipated to deliver 4.5mn-5mn t run-of-mine output in April-June, with Whitehaven's revenue breakdown to be 70pc metallurgical and 30pc thermal on an annual basis post-acquisition as it seeks to pivot toward coking coal. Blackwater and Daunia contributed 10.11mn t and 4mn t respectively to BMA's total output in 2023. Whitehaven plans to sell down a 20pc stake in Blackwater to global steel producers, with a process presently underway. Whitehaven views the high calorific value (CV) thermal coal market as well supported in its key Asian markets, and said tightening of sanctions on Russian exporters is containing global supply. India's continuing growth is driving demand and underpinning price sentiment, Whitehaven said, despite a softening in metallurgical coal prices during the quarter . The Argus high-grade 6,000 kcal/kg NAR price averaged $126.74/t fob Newcastle and the 5,500 kcal/kg NAR coal price $93.85/t during January-March, compared with $134.23/t and $96.80/t respectively for October-December. By Tom Major Whitehaven quarterly results Jan-Mar '24 Oct-Dec '23 Jan-Mar '23 Volumes (mn t) Managed coal production 3.9 4.2 3.6 Managed coal sales 3.8 4.7 4.1 Managed coal stocks at period end 1 1.5 1.5 Coal sales mix (%) High-grade thermal coal 83 72 68 Other thermal coal 8 19 26 Metallurgical coal 9 9 6 Prices achieved ($/t) 136 142 280 Thermal coal 136 142 280 Metallurgical coal 213 166 234 Source: Whitehaven Australian coal price comparisons ($/t) Send comments and request more information at Copyright © 2024. Argus Media group . All rights reserved.

Australia’s Queensland legislates emissions targets


Australia’s Queensland legislates emissions targets

Sydney, 18 April (Argus) — Australia's Queensland state today approved two separate laws setting renewable energy and emissions reduction targets over the next decade, as it transitions away from a coal-fired dependent power generation system. Queensland set net greenhouse gas (GHG) emissions reduction targets of 30pc below 2005 levels by 2030, 75pc by 2035 and zero by 2050 under the Clean Economy Jobs Act, while theEnergy (Renewable Transformation and Jobs) Act sets renewable energy targets of 50pc by 2030, 70pc by 2032 and 80pc by 2035. The state is on track to surpass the 2030 emissions target, latest data show, as it achieved a 29pc reduction in 2021. Even though the share of renewables in the power mix last year was the lowest across Australia at 26.9pc, it has been increasing consistently since 2015 when it was 4.5pc, according to data from the National Electricity Market's OpenNem website. Coal-fired generation has been steadily falling, down to 42.9TWh or a 65.7pc share in 2023 from 52.9TWh or 83pc in 2018. Most of Queensland's coal-fired plants belong to state-owned utilities, which the previous Labor party-led government of Annastacia Palaszczuk indicated would stop burning coal by 2035 . The new Labor party premier Steven Miles disclosed the 75pc emissions reduction target by 2035 in his first speech as leader last December. The Energy Act locks in public ownership of electricity assets, ensuring that at least 54pc of power generation assets above 30MW remain under state control, as well as 100pc of all transmission and distribution assets and 100pc of so-called "deep storage" assets — pumped hydro plants with at least 1.5GW of capacity. The government will need to prepare and publish a public ownership strategy for the July 2025-June 2030 and July 2030-June 2035 periods. A fund totalling A$150mn ($97mn) will also be set up to ensure workers at existing state-owned coal-fired power plants and associated coal mines have access to new jobs and training or financial assistance during the transition. The Clean Economy Jobs Act sees the government receiving advice from an expert panel on the measures needed to reduce emissions. The government will need to develop and publish sector plans by the end of 2025 with annual progress reports to Queensland's parliament. By Juan Weik Send comments and request more information at Copyright © 2024. Argus Media group . All rights reserved.

Q&A: Ramaco adding production, sees market growth


Q&A: Ramaco adding production, sees market growth

New York, 16 April (Argus) — Randall Atkins is a founder and chief executive of metallurgical coal producer Ramaco Resources. He also has been involved in energy-related investment and financing activity for over 40 years. In this Q&A, edited for length and clarity, he discusses effects from the Francis Scott Key bridge collapse, his outlook for coal and the company's research projects. What effect has the Key bridge collapse and Port of Baltimore closing had on Ramaco and the US coal industry in general? Like most things of that tragic nature, it is going to take longer than everyone expects to actually solve the problem. I think where it is going to impact producers probably more is on the rails. There will be a need for...producers to rearrange stockpiles and to rearrange where they are going to try and ship, even at reduced levels. Particularly, CSX is going to have an immense logistical complexity to deal with over the near-term. We do not ship from Baltimore. We have not seen any problems, knock on wood, with our rail shipments post the incident. What are your long-term projections for metallurgical coal given expectations that low-volatile coal reserves will shrink in coming decades and the steel industry could be in oversupply? Low vol coal has traditionally been the highest priced coal and the dearest, if you will. High vol A coal has over the last few years grown in importance, and to the extent that there is any new increase in production in the US, it's high vol. What we perceive is that there is going to be a crowding in the high vol space. As a result, our increase in production is primarily in low vol. As far as the demand side is concerned, we do not believe that blast furnace steel demand is going to decline anytime soon. There's a lot of noise from the green community that hydrogen is going to replace coal in blast furnaces. We took some advice on that from the IEA…and when that question was posed (to IEA), the answer that was given was it would take about $1.5 trillion to build a pilot plant using hydrogen by 2035 and probably about another equal or greater sum to build a commercial facility by 2040. So, I don't lose a lot of sleep on the demand for coal for blast furnaces. What I do see shifting, however, is the US has held relatively steady at about 20mn short tons (18.1mn metric tonnes) of met coal demand over the last 10 to 15 years. The growth is clearly overseas, and the growth is clearly at the moment in Asia. When we started back in 2017, and 2018 was really our first year of production, we predominantly sold coal domestically; I think 80pc of our coal went to US steel mills. Now that is almost reversed. We're going to sell probably this year, 70pc overseas, and about a third or less domestically. With Europe moving towards electric arc furnace technology and significant new blast furnace capacity coming online in Asia, what kind of role will the US play as a coal supplier over the coming years? It is cheaper to use a blast furnace than electric arc. And the steel that they (Asian companies) mostly require is the heavier steel for cars and buildings and things of that nature. So, they have a bias towards blast furnace capacity. The US and Europe are very developed economies that are trying to go and wean away from coal, (while) the rest of the world is aggressively moving further into coal. People will shake their heads at the cost that European and American consumers will start to have to pay for that privilege. We see market growth is still there, but it's a different kind of growth. It will be more in the Asian markets, predominantly some in Europe, some in South America and Africa. The low vol coal demand in Asia is extremely strong because while they are able to buy high vol product from Australia very inexpensively, they do not have the low vol production. They need that to blend up to get the proper mix in their blast furnaces. There is a very good future for low vol, and that is the direction we are positioning ourselves. How confident is Ramaco about securing its investments in the longer run given the emphasis on ESG? What I see is sort of a dichotomy. In the thermal coal business, there's not a lot of investment in new mining there for the obvious reason that their customer base is declining. On the met side, it is a bit shortsighted from an investment standpoint because of the composition of the ownership of met coal companies. Virtually every major metallurgical coal producer except for us went through bankruptcy and post-bankruptcy proceedings. Their board composition became essentially distressed debt investors...Their interest was not developing a long-term coal company. Strategically their vision was: "How can we most quickly get money back out of that coal company?" We are certainly the only coal company that is doubling in size. We produced a little under 4mn st last year. We will be at about 4.5mn st this year. We can maybe go higher, depending upon the market. The market is not strong right now. The other issue (for coal producers) even when they weren't doing special dividends, is they've now shifted to doing large-scale share buybacks. You are starting to see the cost curve increase for most domestic coal producers. What you haven't seen, but I think you will probably find over the next probably 18 to 24 months, is you will begin to see depletion kick in. The amount of coal that they are able to produce from their existing operation will begin to decline. And that is strictly a result of not investing in new mine production. My approach was to kind of be a little bit of an outlier and then approach coal to products as an alternative use, certainly for thermal coal. And that, of course, brought us to rare earth (mineral extraction). Do you have funding for Ramaco's rare earth materials projects? Let me step back one step. We introduced the idea that we actually had rare earth (deposits) in May 2023….When we sent the samples to be tested, they tested them as if they were hard minerals. In other words, they did not combust off the organic material. What we have done since then, is we went back and we had samples that were probably 200-300 parts per million. From a commercial standpoint, we have kind of crossed the Rubicon that this is indeed sufficiently concentrated that it makes commercial sense. Now what we are doing is we are going through a process of further chemical analysis and testing to determine what is the best extraction and refinement technique. And the last point you raised was financing. We have a very nice growing mining metallurgical business, which can provide the funding to do whatever we want to do on rare earth. I am not too concerned about our financing capability. Any updates on your coal-to-carbon product projects ? We have looked at a number of different things with the national labs. We started looking at carbon fiber, which could be made from coal and we have got some patents around some very interesting processes. The areas that we are now focusing on...are using coal to make synthetic graphite. The other thing we are working on is using coal for direct air capture. We are considering going into a pilot phase sometime starting later this year with Oak Ridge National Laboratory on a synthetic graphite plant. As far as direct air capture, we probably have more work to do. We are also working on that with Oak Ridge. But I would hope that sometime by 2025, certainly 2026, we would perhaps have our first product, quote unquote, to be able to offer into the market. And it would be delightful if it was synthetic graphite. By Elena Vasilyeva Send comments and request more information at Copyright © 2024. Argus Media group . All rights reserved.

Australian new environment agency to speed up approvals


Australian new environment agency to speed up approvals

Sydney, 16 April (Argus) — The Australian federal government announced today it will introduce new legislation in the coming weeks to implement the second stage of its Nature Positive Plan, which includes setting up a national environment protection agency to speed up approval decisions. The planned Environment Protection Australia (EPA) will initially operate within the Department of Climate Change, Energy, Environment and Water until it transitions to become an independent statutory agency, with "strong new powers and penalties" to better enforce federal laws, the government said on 16 April. The EPA chief will be an independent statutory appointment, similar to the Australian federal police commissioner, so that "no government can interfere" with the new agency's enforcement work. The agency will be able to audit businesses to ensure they are compliant with environment approval conditions and issue environment protection orders to anyone breaking the law. Penalties will be increased, with courts able to impose fines of up to A$780mn ($504mn) or jail terms for up to seven years in cases of extremely serious intentional breaches of federal environment law. EPA will also be tasked with speeding up development decisions, including project assessments in areas such as renewable energy and critical minerals. Almost A$100mn will be allocated to optimise the approval processes, with its budget directed to support staff to assess project proposals and help businesses comply with the law. A new independent body Environment Information Australia (EIA) will also be created to provide environmental data to the government and the public through a public website. EIA will need to develop an online database giving businesses quicker access to data and helping EPA to make faster decisions. It will also need to publish state of environment reports every two years. The government said that an audit ordered by environment minister Tanya Plibersek last year found that around one in seven developments could be in breach of their offset conditions, when a business had not properly compensated for the impact a development was having on the environment, highlighting "the need to urgently strengthen enforcement". The planned new legislation is part of the federal government's reform of Australia's environmental laws including the Environment Protection and Biodiversity Conservation Act. Resource project decisions are currently made by the environment minister, with the move to an independent agency will removing any perception of political interference in such decisions, the government said when it first announced the reforms in late 2022. The first stage of the reform was completed late last year with new laws passed to create the Nature Repair Market, with further stages expected to be implemented in the future, the government said. Tight timing Resources industry body the Chamber of Minerals and Energy of Western Australia (CMEWA) welcomed the announcement that the federal government will take a "staged approach" to the implementation of the reforms but noted the timing of EPA's implementation was "tight". "We continue to hold reservations about the proposed decision-making model and will continue to advocate for a model that balances ecologically sustainable development considerations and includes the [environment] minister as the decision maker," CMEWA chief executive Rebecca Tomkinson said. The Minerals Council of Australia (MCA) said that it had been advocating for the creation of EIA, whose future collated data "will provide greater certainty and reduced costs for both government and project proponents", which "may shave years off project development". But it was cautious about potential "unintended consequences" stemming from more bureaucracy. "Australia has one of the most comprehensive environmental approvals processes in the world and the MCA has been clear about the significant risks of duplicative, complex and uncertain approvals processes pose to the minerals sector, the broader economy and the environment if we do not get this right," it warned. By Juan Weik Send comments and request more information at Copyright © 2024. Argus Media group . All rights reserved.

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