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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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18/02/25

India's domestic coal supply to utilities rises in Jan

India's domestic coal supply to utilities rises in Jan

Singapore, 18 February (Argus) — Domestic thermal coal supplies to Indian utilities rose in January as power plants continued to boost inventories. Combined coal supplies to utilities from domestic sources such as state-controlled Coal India (CIL), Singareni Collieries (SCCL) and captive blocks stood at 76.41mn t, up by 5.8pc from a year earlier, provisional data from India's coal ministry show. Supply was also up from 76.04mn t in December. Indian utilities continued to restock, although coal consumption at utilities was weaker than initially anticipated, as temperatures in most parts of the country were higher last month compared to historical averages, curbing power demand. India's coal-fired generation — which meets most of its power requirements — stood at 109.68TWh during January, down from 111.72TWh a year earlier, but up from 104.30TWh in December, Central Electricity Authority (CEA) data show. Higher domestic coal supplies and weaker coal burn supported stock positions at utilities. Combined coal inventories at Indian power plants stood at around 50.5mn t on 31 January, up from 45.2mn t on 31 December and higher from 38.59mn t as of 31 January 2024, according to CEA data. The inventory as of the end of January would last for over 17 days at the current daily coal consumption rate at utilities. Higher stocks and a steady uptick in domestic supplies might have pressured utility demand for imported coal and India's overall seaborne receipts last month. India imported 11.63mn t of thermal coal last month, down from 13.34mn t a year earlier, according to data from analytics firm Kpler. Imports reached 163mn t in 2024, down from 168.2mn t in 2023, Kpler data show. Indian power sector imports, which account for more than 40pc of the country's overall imports, dropped on the year for the fourth straight month in December , and might have eased in January. Combined thermal coal imports by Indian utilities, excluding captive power plants, stood at 3.25mn t in December, down by 2.17mn t or 49pc from a year earlier, CEA data show. Imports could come under pressure if the government does not extend its directive to imported coal-fired plants, which have a combined capacity of 17.7GW, to boost generation under Section 11 of the Indian electricity law, which also gives some flexibility to such generators to sell excess production in the power market. The directive is due to expire on 28 February. Production, supply mix The increased supplies to utilities were supported by higher overall thermal production. India's coal output rose by 4.4pc in January from a year earlier to 104.49mn t. The country's supplies to all sectors stood at 93.21mn t last month, up by 6.7pc on the year. CIL produced 77.79mn t in January, down from around 78.41mn t a year earlier, while it supplied 69.26mn t, rising from 67.52mn t last year, ministry data show. Of this, 55.01mn t of coal was supplied to the power sector in January, easing from 55.15mn t a year earlier. Meanwhile, output at coal producer SCCL rose by 5pc from a year earlier to 6.97mn t in January. But its overall supplies in January fell by about 1.5pc on the year to 6.12mn t, while dispatches to the power sector rose by 2.2pc on the year to 5.6mn t. Captive coal block producers and other small government mining entities comprised the remainder of the supplies to utilities in January. Output from captive coal blocks and other mining companies rose by over 31pc on the year to 19.72mn t in January, while supplies rose by nearly 30.7pc to 17.83mn t. Data on domestic coal supplies to Indian utilities do not include dispatches to captive power plants set up by industries. Supplies to such captive utilities — from sources such as CIL, SCCL and captive coal blocks — reached 6.29mn t in January, up by almost 9pc from a year earlier. Domestic supplies to steel and cement sector in January rose by 4.5pc and 31pc from a year earlier to 860,000t and 900,000t respectively, the ministry data show. By Saurabh Chaturvedi Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Philippines to review shutdown of 232MW coal plant


17/02/25
17/02/25

Philippines to review shutdown of 232MW coal plant

Manila, 17 February (Argus) — The Philippines will review plans to retire the 232MW Mindanao coal-fired power plant in Misamis Oriental province because the rehabilitation of a major regional power complex could cause an electricity supply shortage. The country could put on hold plans to accelerate the retirement of the Mindanao coal plant to 2026 from 2031, the Department of Energy (DoE) said. The plant, majority owned by private-sector Aboitiz Power, started operations in 2006 under a build-operate-transfer (BOT) agreement with the National Power and Power Sector Assets and Liabilities Management. The plant was originally scheduled to be retired in 2031 once the BOT agreement had run its course and plant ownership transferred to the national government, but authorities later decided to shut it down by 2026. The plant consumes over 1mn t/yr of coal. Authorities might review the retirement plans to offset the loss of power supply from the 1,000MW Agus-Pulangi hydropower complex, which will be rehabilitated next year. The complex comprises seven hydropower plants and serves as a key source of baseload power in the Mindanao grid. It is currently capable of producing only 600-700MW of power because of siltation and ageing infrastructure. Parts of the power complex are over 50 years old and its oldest dam, Agus 6, started commercial operations in April 1971. The rehabilitation involves repairing, replacing and upgrading the components of an existing hydroelectric power plant to restore its functionality, improve efficiency and extend its lifespan. The complex will run at a derated capacity during rehabilitation works, which could take several years. This comes as power demand in the Mindanao grid continued to increase last year. Demand averaged 2.248GW in 2024, a 10.2pc increase from 2.040GW a year earlier. The Mindanao plant could supply enough power to keep the grid stable at its full capacity, by covering for the loss in generating capacity and meeting the increase in power demand, DoE added. By Antonio Delos Reyes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Upper Mississippi River ice tops 5-year average


13/02/25
13/02/25

Upper Mississippi River ice tops 5-year average

Houston, 13 February (Argus) — Ice measurements taken Wednesday to gauge when barges can transit the upper Mississippi River exceeded the five-year average, according to the US Army Corps of Engineers (Corps). The annual Lake Pepin ice reports — taken by the Corps in February and March at Lake Pepin south of Minneapolis — are a bellwether for when barge transit can resume on the upper Mississippi River. This year's first report found ice at the lake was 19in thick on 12 February, 8in thicker than last year's measurement and 3in above the five-year average. The Corps' initial report last year found only 11in of ice at the lake, thin enough for waterborne traffic to break through. Subsequent reports were cancelled after the Corps said it would be too hazardous for crews and equipment to take additional measurements. Locks along the upper Mississippi River are anticipated to remain closed through 3 March, the Rock Island Corps district in Illinois said on 5 February. By Meghan Yoyotte Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

ACBL sets release dates for Illinois River lock


13/02/25
13/02/25

ACBL sets release dates for Illinois River lock

Houston, 13 February (Argus) — Major barge carrier American Commercial Barge Line (ACBL) has issued its earliest release dates for Illinois River barges planning to transit the Lockport Lock, which closed for maintenance last month. Release dates will be from 23 February through 19 March for barges expecting to pass through the Lockport Lock over the spring season, ACBL said Wednesday. The US Army Corps of Engineers (Corps) expects to reopen the Lockport Lock on 25 March, the Corps said when it announced the closure . The Corps closed the lock on 28 January to install new vertical lift gates and make repairs. The closure has cut off major trade hubs such as Chicago, Illinois, and Burns Harbor, Indiana, from Illinois River barge transportation. Lock 27 and the Mel Price Lock above St Louis will remain partially closed through 1 April, as they are also undergoing maintenance by the Corps, ACBL said. The barge line acknowledged higher demurrage rates were likely for those who loaded barges prior to the released dates. Initial transit on the Illinois River is also anticipated to have a significant backlog in the spring months. By Meghan Yoyotte ACBL's Illinois River release dates Origin Port Barges destined above Lockport Lock, on IL River Mobile, AL 25 Feb Houston, TX 23 Feb Weeks Island, LA 26 Feb New Orleans, LA 3 Mar Pittsburgh, PA 2 Mar Cincinnati, OH 5 Mar Decatur, AL 10 Mar Memphis, TN 10 Mar Evanscille, IN 12 Mar Cairo, IL 16 Mar St Louis, MO 19 Mar — ACBL Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US wholesale inflation holds near 2-year high in Jan


13/02/25
13/02/25

US wholesale inflation holds near 2-year high in Jan

Houston, 13 February (Argus) — Prices paid to US producers in January held at nearly a two-year high, another sign of mounting inflation pressures that may keep the Federal Reserve from lowering rates for longer. Prices paid to producers (PPI) rose by 3.5pc in January from a year earlier, matching the prior month's gain, the Bureau of Labor Statistics said today. Analysts surveyed by Trading Economics had forecast a gain of 3.2pc. The PPI number follows a higher-than-expected consumer price reading Wednesday which together reinforce the message that the Federal Reserve may hold off longer on rate cuts, especially in the face of potentially inflationary trade conflicts and migrant roundups under the new US administration. PPI excluding food, energy and trade services rose by 3.4pc in January following a 3.5pc gain in December. PPI for services rose by 4.1pc in January following a 4pc gain in December. Wholesale prices for energy were flat following a 2pc annual decline the prior month. PPI for goods rose by 2.3pc in January following a 1.8pc gain in December On a monthly basis, headline PPI rose by a seasonally adjusted 0.4pc, compared with a 0.5pc gain in December and a 0.2pc increase in November. Services PPI rose by 0.3pc in December, following a monthly gain of 0.5pc in December and a 0.1pc gain in November. By Bob Willis Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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