石炭
概要
欧州では、制裁措置により石炭の輸入先がロシアから他の供給国にシフトしています。電力ミックスにおける石炭の役割はピーク負荷用へとさらにシフトしており、今後のプランニングはより困難になっています。
アジア太平洋地域では、一般炭が電力・産業部門の柱であり続けています。世界の石炭貿易のフローと価格スプレッドは変化しており、主要供給国であるロシア、インドネシア、オーストラリア、南アフリカ、コロンビア、米国からのフローは、価格ダイナミクスと貿易障壁に対応して新しい市場に浸透しつつあります。
価格と市場動向を常に注視し、石炭市場が他のエネルギーやコモディティのベンチマークとどのように交差しているかを把握することが、今後数年間はより一層重要になってきます。
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Viewpoint: Coal plant extensions not always easy
Viewpoint: Coal plant extensions not always easy
Houston, 14 January (Argus) — US generators are starting this year with more coal-fired power plants open than previously planned, following a series of US Department of Energy (DOE) emergency orders, but maintaining generation from these facilities might not be easy. Since late May, US energy secretary Chris Wright has signed orders to keep at least parts of five coal plants running beyond their planned 2025 retirement dates. These facilities have a combined generating capacity of 2,128MW. Wright also has indicated he may continue issuing such orders to address near-term reliability issues and potential energy supply shortages in the next few years. While some power plant operators may welcome the orders, others are more reticent. "I think the executive orders make for lots of questions in our current environment," one market participant said. "As with anything, there are lots of legal challenges that will arise, and it all could change again in a few years" under a new administration. The nature of the orders also raises logistical concerns that some power plant operators warned could affect their ability to comply. Last year, Wright issued the orders shortly before the facilities were scheduled to close. That kind of timetable can be challenging for plant operators who typically have spent months winding down fuel orders and making other preparations to permanently close a facility. The orders also have 90-day limits that can be extended, and Wright has not shied away from renewing directives to keep plants operating. Several coal plants that were either scheduled to close recently or are slated to be retired in the near future have not received adequate maintenance and upgrades in the last few years that would allow them to keep running sustainably long-term, one operator told Argus . That suggests operators could face higher rates of unexpected coal unit outages this year or more frequent planned outages as companies catch up on maintenance. For example, unit 1 of the Craig Station coal plant in Colorado, the most recent unit ordered to stay on line for another 90 days, has been out of service since 19 December, following a mechanical failure of a valve. The plant will need repairs and additional investments to continue running into 2026, Tri-State Generation & Transmission — one of the co-owners of the plant — said on 31 December. Some of the utilities that have received emergency orders to keep coal plants open also warned that delaying the facilities' closures could interfere with previous energy transition plans and investments. But Indiana utility NiSource, which received an order to keep its RM Schahfer coal plant on line until at least 23 March 2026, said "our long-term plan to transition to a more sustainable energy future remains unchanged". Other utilities also remain committed to transitioning from coal-fired generation. One operator said the recent emergency orders have merely put the coal industry on "life-support", rather than providing a substantial lifeline beyond the next few years. Many other coal market participants asserted that DOE's orders only require the plants to remain available during their extension periods and, at least so far, have not specified a minimum capacity factor at which they must run. Most of the plants operating in compliance with the emergency orders may just run as peaker plants, only operating at maximum capacity during extreme periods of generation demand. Still, the prospect of keeping the facilities open for an unknown period of time can be a challenge for planning fuel purchases. While some plants that received a DOE order still have a small quantity of coal stockpiled on site, those volumes will only sustain a few more weeks of coal burn, necessitating additional shipments. Other utilities are faced with buying more coal and deciding whether to purchase enough for just the extent of existing orders or to enter into longer-term agreements. Some operators have already opted into multi-year deals because they expect DOE's emergency orders on their plants will keep getting renewed well into the back half of this decade. Many utilities, especially by the end of 2025, found pricing in longer-term purchases to be more stable and economical because constrained supply in most US basins had prompted producers to offer spot coal at higher prices. Tight US coal supply also has led producers to be less willing to agree to options in newer coal contracts that would allow buyers to opt out of taking all of their volume commitments. Because of this, some utilities that have received orders from DOE have limited their additional coal purchases to deliveries only in 2026. Some utilities also said that they can not justify issuing longer-term requests for proposals to state regulators and ratepayers, since the DOE orders are only issued for 90 days. The US House of Representatives in mid-December passed a bill that aims to address some utility concerns. The Power Plant Reliability Act of 2025 would authorize the US Federal Energy Regulatory Commission (FERC) to require an owner or operator to continue running a power plant for up to five more years if the commission finds that its closure could threaten grid reliability. The bill would protect plant operators from penalties for potentially violating state or federal environmental laws while FERC's order is in place. And it would authorize FERC to renew an order by another five years if requested by a transmission organizer, state commission or public utility. The US Senate has not yet scheduled any action on the bill. And even if the measure is enacted, it will only address some of the uncertainties power plant operators face. By Anna Harmon Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Japan’s Shimane reactor to shut for Feb-Aug turnaround
Japan’s Shimane reactor to shut for Feb-Aug turnaround
Osaka, 9 January (Argus) — Japanese utility Chugoku Electric Power plans to shut its 820MW Shimane No.2 nuclear reactor from February-August to carry out maintenance works. Chugoku will close the No.2 reactor at Shimane in western Japan on 9 February, the company said on 8 January. Test generation is expected to resume on 6 August in the final phase of the turnaround, according to a power plant operational status notice by the Japan Electric Power Exchange. Full maintenance completion is targeted for 4 September. This will be the first maintenance check for the Shimane reactor since it returned to service in December 2024 after nearly 13 years off line for enhanced nuclear safety inspections following the 2011 Fukushima disaster. The Shimane No.2 reactor is Chugoku's sole nuclear unit in operation. The shutdown would require the utility to boost replacement thermal generation units to meet peak demand in the remainder of winter and in early summer. Chugoku consumed 2.72mn t of coal in April-September 2025, up by 16pc from the same period a year earlier, while its oil use rose by 25pc to 1,719 b/d. But LNG consumption fell by 11pc to 500,000t during the period. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Indonesian coal output, exports decline in 2025
Indonesian coal output, exports decline in 2025
Singapore, 8 January (Argus) — Indonesia's coal production and exports declined for the first time in five years in 2025 on weak demand from key markets China and India. The world's largest coal exporter produced 790mn t of coal last year, out of which about 514mn t was exported, according to latest government data compiled by Indonesian Coal Mining Association (ICMA). The production volume was down 5.5pc from a year earlier, while exports fell by 7.9pc on the year. But the 2025 output exceeded Indonesia's target of about 740mn t. This marks the first decline in production and exports since 2020, when Covid-19 pandemic affected demand as well as the coal supply chain. The drop comes as demand from two of the largest coal importing nations, China and India, decreased in 2025 on an increase in domestic coal availability and fall in coal consumption, indicating a broad weakness in the economy and decline of coal-fired generation in the power mix. Indonesian suppliers recalibrated output in response to weak demand and lower prices. Argus assessed the widely traded GAR 4,200 kcal/kg coal for Supramax vessels at $44.99/t fob Kalimantan on 24 December 2025, down by 71pc from its all-time high of $154.21/t on 21 October 2021. Prices hit a more than four-year lows of $39.40/t in June 2025 and have since hovered in a narrow range that some producers said barely covers costs. Coal supply may remain under pressure because Jakarta is weighing production cuts and policy changes including the introduction of an export duty on coal, moves that could fuel fresh uncertainty in the global seaborne market . The country is considering setting coal production target under 700mn t for 2026, although energy minister Bahlil Lahadalia said on 8 January that the final figure would be firmed up after assessing the domestic coal requirements. Indonesian miners need to adhere to regulations to sell at least a quarter of their production locally under the so-called domestic market obligation (DMO). DMO sales reached 254mn t in 2025, while stocks at the end of the year were at 22mn t, according to the government data compiled by ICMA. The government will prioritise coal mining quotas for DMO before it can determine production levels for exports, Lahadalia said. The Indonesian government also took other measures in 2025 to tighten supply because the ongoing surplus has kept prices under pressure, it said. Some of these steps include withholding export sales proceeds in onshore bank accounts, tweaking domestic coal reference prices — the HBA — rolling out mandatory biofuel blending norms, banning coal hauling in parts of South Sumatra, imposing export tax on coal and reverting to annual RKAB appraisals with increased compliance on mine reclamation. This comes as the seaborne market appears to be well-supplied, with domestic supply potentially capping the import outlook of China and India, on top of broad weakness in the economy and changing generation patterns. Economic growth in China — the world's biggest coal importer — is expected to slow to 4.4pc in 2026 from an estimated 4.9pc in 2025, according to World Bank projections. China is also gradually increasing the share of renewable energy in its power generation mix, putting further pressure on overall coal demand. Similarly, coal burn in India has largely remained lacklustre on the back of an extended monsoon spell in 2025 and increase in renewable power generation. The sharp depreciation of the Indian rupee in 2025 has also weighed on imports. By Saurabh Chaturvedi and Nadhir Mokhtar Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Viewpoint: Tighter supply may lift PRB coal prices
Viewpoint: Tighter supply may lift PRB coal prices
New York, 6 January (Argus) — Powder River Basin (PRB) coal prices could rise further in 2026 as producers face constraints on boosting output and demand holds steady. The year is starting with some US coal-fired units running longer than anticipated — some by utility choice, others under Department of Energy (DOE) emergency orders aimed at preserving grid reliability. A number of these plants consume PRB coal. TransAlta's Centralia plant in Washington consumed 1.83mn short tons (st) (1.66mn metric tonnes) of PRB coal in January-October 2025, US Energy Information Administration (EIA) data show. Consumers Energy's JH Campbell plant in Michigan used 3.7mn st over the same period, while Xcel Energy's Comanche unit 2 consumed 877,391st. All three facilities were scheduled to be retired in 2025, but will remain in operation through at least early 2026. However, the response from coal producers to any improvement in demand could be uneven, which could in turn constrict competition and boost prices. The EIA projected in December that western US coal production would decrease to 274mn st in 2026 from an estimated 284mn st in 2025. More than 80pc of western US coal output comes from the PRB. PRB coal production rose in most of 2025 after two years of declines, but annual output may still have been below 2023 levels. EIA estimated mines in Montana and Wyoming, which primarily yield PRB coal, produced 228.2mn st from 1 January through 27 December 2025, up by 5.9pc from the same period in 2024. In comparison, mines in those states produced 266.3mn st in all of 2023. While larger producers in the basin appear optimistic about market conditions for this year, the two biggest PRB producers — Peabody Energy and Core Natural Resources — said in October they had nearly all of their expected 2026 production already under contract to sell. "Are we confident about running at max capacity for the next couple of years?" asked Malcolm Roberts, Peabody's chief commercial officer, on 30 October. "The answer is definitely yes in the PRB." However, "adding on capacity is not something you do for one year; it is going to need customer commitments, and then we'll be looking for the price signals," Peabody chief executive officer Jim Grech said. "We'll see what the market does in terms of price signals to bring those additional tons on. I think that's the best way to look at it." Producers are uncertain that 2025's uptick in coal-fired generation and coal demand as well as delays in power plant retirements will continue beyond the next few years. Some market participants expect smaller producers with higher-cost operations to eventually be forced out of business as major banks continue to pull back on lending to coal mining companies. In the near term, PRB coal producers are diversifying their client portfolios, which may leave some larger utilities unable to secure all the coal they have requested. This supply tightness has already lifted prices for additional tons sought for prompt quarter deliveries. PRB 8,800 Btu/lb coal prompt quarter shipments were assessed at $14.95/st in the week ended 2 January, well above the $13.10/st and $13.95/st in the same weeks of 2025 and 2024, respectively. Additionally, some sellers are adding extra charges — or ‘adders' — to contracts for coal shipments that might be postponed from 2026 to 2027. PRB mine employment and operating hours continued on a downward trend for most of 2025. The basin's mines employed an average 4,226 people in the first nine months of the year, according to the US Mine Safety and Health Administration (MSHA), the fewest employees since January-September 2004. The number of hours each miner worked in January-September 2025 was the lowest since the first nine months of 2005. Average employment at PRB mines in January-September decreased by 6.9pc from the same nine months of 2024, with miners' hours down by 3.7pc in the same period, MSHA data show. The declines in employment and hours worked took place even as coal-fired generation in PRB-consuming regions of the US such as the Midcontinent Independent System Operator (MISO) and Electric Reliability Council of Texas (ERCOT) topped year-earlier levels. EIA projected in December that coal power in MISO, ERCOT and the Southwest Power Pool would slip in 2026. Some of its forecast likely was based on power plant retirements, including the closures of some facilities that have since been postponed or are likely to be postponed. For example, the agency's generator inventory data for November had unit 2 of Xcel Energy's Comanche coal plant in Colorado retiring by the end of 2025, but Colorado regulators in December approved a plan to keep the Comanche unit 2 open for another year. Most US generators that have spoken with Argus anticipate coal burn in 2026 will remain largely in line with 2025 levels, while some project a slight uptick. Even utilities considering coal unit retirements are negotiating additional tons, asking PRB producers to accommodate incremental needs if their units are required to run longer. Rising demand pushed PRB mine productivity for January-September 2025 to a three-year high of 25.9 st/hour, Argus calculations of MSHA data show. More recent information from the US Labor Department and EIA suggest employment and production may have lagged behind year-earlier levels in the final months of 2025. That further sets the PRB up for tight supply in 2026. By Elena Vasilyeva Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
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