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Australian new environment agency to speed up approvals

  • Spanish Market: Coal, Crude oil, Metals, Natural gas
  • 16/04/24

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.


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08/10/24

Hurricane Milton set for late Wednesday landfall

Hurricane Milton set for late Wednesday landfall

New York, 8 October (Argus) — Hurricane Milton is expected to come ashore on Florida's Gulf coast near Tampa Bay late Wednesday, bringing life-threatening storm surge and destructive winds that have already spurred widespread evacuation orders. US president Joe Biden warned Milton could be one of the worst storms to hit Florida in 100 years, as he urged residents under evacuation orders to act without delay. "It's a matter of life and death," he said today. The storm was located about 520 miles southwest of Tampa at 2pm ET today, with maximum sustained winds of 155mph, according to the National Hurricane Center. Storm surge is expected to range from 10-15 feet along the Florida coast from north of Tampa to Englewood. The fall-out for offshore oil and gas production in the US Gulf of Mexico appears limited given the forecast track takes Milton far south of most platforms. Mexican state oil company Pemex said its ports in the Gulf of Mexico stopped operations over the last 24 hours as Milton passed north of the Yucatan Peninsula, but the company did not report on the status of offshore production. Milton is expected to pick up speed as it turns toward the northeast later today, with the center forecast to move across the eastern Gulf of Mexico and approach the west-central coast of Florida through Wednesday. Landfall is expected on Wednesday night before Milton sweeps across central Florida. "While fluctuations in intensity are expected, Milton is forecast to remain an extremely dangerous hurricane through landfall in Florida," the center said. Florida officials are dispatching previously stockpiled fuel to retail stations throughout the state as hundreds of thousands of residents flee the western coast. Ports and terminals on Florida's Gulf coast from Tampa to Fort Myers Beach closed at 8am ET today as a precaution. Chevron previously evacuated and shut in its Blind Faith oil and gas production platform in the Gulf of Mexico. The 65,000 b/d platform is located around 160 miles southeast of New Orleans. Crude production from Blind Faith feeds into South Louisiana Intermediate crude slate, which is not actively traded in the spot market but is typically priced using Heavy Louisiana Sweet. Shell, BP and ExxonMobil all said there has been no impact to their drilling or production in the Gulf of Mexico, although the companies continue to monitor the hurricane. By Stephen Cunningham Hurricane Milton projected path Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Asia LNG premium to Europe falls to six-month low


08/10/24
08/10/24

Asia LNG premium to Europe falls to six-month low

London, 8 October (Argus) — The premium offered by northeast Asian delivered LNG markets over those in northwest Europe for prompt Atlantic loadings has this week slipped to its smallest since early May, as very low winter charter rates force European firms to bid higher compared to Asian buyers in order to secure cargoes. The Argus Northeast Asia (ANEA) des price for December offered just a 39¢/mn Btu premium to the northwest Europe November des price on 7 October. The spread dropped to 33¢/mn Btu on 4 October — the smallest since 2 May — having been as much as $2.36/mn Btu on 19 September ( see ANEA premium graph ). At least four LNG carriers loaded from US liquefaction terminals have diverted away from heading to Asia via the Cape of Good Hope to Europe instead over the last week, judging by shiptracking data from Kpler, likely stemming from the narrowing premium offered by Asian markets compared to Europe. The inter-basin spread has tightened since mid-September largely because a rally in European delivered markets has not been matched by Asia. The northwest Europe November des price increased by $1.85/mn Btu over 19 September-7 October, largely as a result of extensions to Norwegian pipeline maintenance, incremental downward revisions in minimum temperature forecasts, and geopolitical concerns surrounding conflict in the Middle East. The corresponding ANEA price, on the other hand, was little changed over the same period, as warmer weather than the seasonal average curbed early heating gas demand. Prompt shipping rates holding lower on the year has also forced European buyers to bid higher in order to compete with their Asian counterparts and ensure uncommitted Atlantic cargoes head for Europe. The prompt Argus Round Voyage rate (ARV2) for tri-fuel diesel-electric (TFDE) carriers in the Atlantic basin stood at $40,000/d today, compared to $130,000/d a year earlier ( see ARV2 spot charter graph ), with some firms even viewing additional shipping capacity as a sunk cost given the number of available vessels at present and difficulties subletting spare shipping capacity. The quick delivery of newbuild LNG carriers this year, coupled with the lack of floating storage in Europe, has contributed to a very shallow contango in forward freight prices. Forward winter rates for two-stroke vessels delivering US LNG to northwest Europe (ARV5) peak at $81,000/d in December, having been revised lower from over $100,000/d at the start of September ( see ARV2 winter rates graph ). Weak charter rates mean European buyers will likely continue to have to bid higher relative Asian bids over the winter than in previous winters, when the freight market was tighter, particularly in instances of cold snaps or other events which would tighten the global LNG balance. Europe's demand for LNG was consistently lower on the year over the second and third quarter of 2024, as Asian demand held the inter-basin arbitrage for US LNG mostly open. But imports to Europe are likely to step higher in the fourth quarter, with the arbitrage firmly shut. Minimum temperatures across the northwest — where much of the region's heating demand emanates from — are forecast to hold below the seasonal average from mid-October onwards, which may spur gas consumption. And the EU's underground gas storages are less full than a year earlier. Aggregate gas stocks stood at 1,083TWh on 1 October 2024, marginally lower than last year's 1091TWh, though both are above the EU-mandated 90pc target. A lack of floating storage this year could limit deliveries later in the year however, with European receipts over the period in the past two years supported by the unwinding of floating storage, mainly in November and December, boosting supply as colder weather boosts heating demand. By Cerys Edwards ARV2 spot charter costs 2022-2024 ARV2 winter rates assessed over Jan-Sept 2024 ANEA premium to NWE August-October Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Dutch TTF gas rises through coal-to-gas switching range


08/10/24
08/10/24

Dutch TTF gas rises through coal-to-gas switching range

London, 8 October (Argus) — A rally in recent weeks has pushed gas prices up to a range at which even older coal-fired power stations would be more profitable to run than some of the most efficient gas-fired power stations. European gas benchmark price the Dutch TTF front-month has risen strongly over the past two weeks, having closed at €40.57/MWh on 7 October, up from a recent low of €32.80/MWh on 19 September. The higher gas prices have outstripped similar price increases of other energy-related commodities such as coal, with the TTF front-month contract approaching the top of the gas-to-coal fuel-switching range ( see TTF front-month graph ). In assessments on 3 and 4 October, even older coal-fired power stations with an efficiency of 42pc would would be more profitable to run than the newest gas-fired turbines with an efficiency of 60pc, for the first time since early December last year. Geopolitical tensions in the Middle East have contributed to gas' price increase. But with muted LNG deliveries to the continent so far this shoulder season and colder weather than last year, European gas storage sites are less full than they were a year earlier. European stocks were filled to about 94.5pc of capacity on the morning of 7 October, according to GIE transparency platform data, down from 96.7pc a year earlier. Demand has already stepped up strongly in some countries, pushing the continent to some days of net withdrawals from storage earlier in the autumn than in most recent years. While coal prices have also stepped up slightly in turn, partly in reaction to the expectations of higher coal burn, their slower upwards momentum has brought coal largely ahead of gas in the merit order. Many coal trading firms have banked on a strong coal burn this winter, with low trading activity in the shoulder season so far, which incentivises trading companies to keep coal prices close to the fuel-switching level, market participants have told Argus . And prompt prices for European CO2 emissions allowances in September and October so far have been about 20pc lower on the year, closing at an average of €64.24/t, compared with €81.60/t over the same period in 2023. Lower emissions prices benefit higher coal burn as coal is more CO2-intensive than gas, requiring operators to purchase and surrender more CO2 emissions certificates. A similar price movement happened last autumn, when a rally in early October pushed the TTF front-month price to the top of the fuel-switching range. But from early December, when a mild winter reduced the remaining risks for gas security of supply, prices fell through the fuel-switching ranges sharply , to the bottom of the range. Impact probably highest in Germany Germany is one of the last remaining markets with large numbers of both coal- and gas-fired power stations in Europe, leaving the market able to react to price movements in either market more flexibly. The power sector can still provide considerable demand-side flexibility in the German gas market, while coal phase-out plans in the rest of Europe mean the scope for alternating between the thermal generation fuels has narrowed. Gas prices can provide the signal that the market has spare gas for the power sector to burn by falling into coal-to-gas switching territory, while gas prices climb above the fuel-switching range to discourage gas-fired generation when the gas market is tighter. Last winter, gas prices at the very bottom of the fuel-switching range encouraged the highest gas-fired generation in Germany in at least a decade , according to data from European system operators' association Entso-E. While many German coal and gas-fired plants are combined-heat-and-power plants, which do not respond to price incentives as flexibly as pure power plants, the impact of the fuel switch on gas' share in the thermal generation mix was still visible last winter in Germany. In October and November, with prices at the top of the range, gas-fired generation at 6GW met 55pc of the combined call on coal and gas. But when prices dropped through the switching range, gas' share increased to 63pc in December-March, with about 7.3GW of gas-fired generation ( see generation percentage graph ). In addition, the German storage levy of €2.50/MWh, which power producers must pay, pushes gas prices up further in the fuel-switching range. The levy, which is likely to rise further from next year , thus further decreases gas' profitability compared with coal, which could be detrimental for Germany's own coal phase-out plans. By Till Stehr TTF front-month vs fuel-switching range €/MWh German gas- and coal-fired generation and fuel-switching price pc, €/MWh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Serbia, N Macedonia sign agreement on gas link


08/10/24
08/10/24

Serbia, N Macedonia sign agreement on gas link

London, 8 October (Argus) — The governments of Serbia and North Macedonia on 7 October signed an agreement on the construction of a 70km gas interconnector, although no timeline for the project was given. The agreement was signed in Skopje by the Serbian and North Macedonian prime ministers. Serbian prime minister Milos Vucevic said that with the new interconnection, Serbia aims to create another supply route from Greece's new Alexandroupolis LNG terminal, where Serbia's dominant supplier, Srbijagas, holds capacity . It is unclear why another route is needed given the recent commissioning of the Interconnector Bulgaria-Serbia, although flows through the link have been low since its commissioning at the beginning of this year, with Azerbaijan's Socar having been the only user under its so far underutilised 365mn m³/yr contract with Srbijagas. The 70km pipeline will have a capacity of about 1.2bn m³/yr, Vucevic said according to state news agency Tanjug, but no timeline was given for its construction. Serbia wants to "expand the number of partners interested in co-operating with us in the energy sector and that will definitely lead, or contribute, to our state's energy stability", Vucevic said, adding that the North Macedonian side also expressed interest in building an oil or oil products pipeline simultaneously with the gas pipeline. North Macedonia is also "finalising a tender procedure that will finally start the construction of the interconnector with our southern neighbour [Greece], to provide an additional option for gas supply to central Europe", Vucevic's North Macedonian counterpart, Hristijan Mickoski, said. Greek grid operator Desfa has already started construction of the 1.5bn m³/yr interconnector, which is scheduled to begin commercial operations at the start of 2026, according to Desfa's latest plans . By Brendan A'Hearn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

German 3Q hard coal output falls on reduced fleet


08/10/24
08/10/24

German 3Q hard coal output falls on reduced fleet

London, 8 October (Argus) — Hard coal-fired output from German utilities dropped by 23pc on the year in July-September, largely driven by a smaller generation capacity following a series of plant retirements or returning to grid reserve in the first half of 2024. German hard coal-fired generation averaged 2.1GW in the third quarter, according to European grid operator Entso-E. Compared with a year ago this was equivalent to around 505,000t of NAR 6,000 kcal/kg coal consumption, assuming 40pc efficiency plants. September output reached a seven-month high of 2.9GW, but it was down by 15pc from a year earlier. Germany's overall available hard coal-fired capacity was 6.5GW in September, cut by 1.6GW on the year, based on European Energy Exchange (EEX) data. The German hard coal fleet's implied load factor was 45pc in September, slightly higher than 41pc from a year ago. Trianel was the German utility with the highest hard coal-fired generation in July-September, as it raised the output from its sole 750MW hard coal plant Lunen 1 in northwest Germany by 28pc on the year to 380MW. Oynx meanwhile produced the second-highest hard coal output in the third quarter, averaging 352MW, as it was the generator with the sharpest rise in coal burn from a year earlier at 53pc. This was despite the company closing its 350MW Farge plant in March. Phase-out weigh on coal burn Uniper was Germany's largest hard coal-fired operator in the third quarter of last year, but its hard coal output halved on the year to just 316MW in July-September because the utility took off the bulk of its fleet from the market. Only the 1.05GW Datteln 4 plant was running in the third quarter, given Uniper placed its four other hard coal-fired units — the 345MW Scholven B, 345MW Scholven C, 522MW Staudinger 5 and 875MW Heyden 4 — into the grid reserve earlier this year. The company could no longer run hard coal plants within Germany in the near future as it seeks to sell Datteln 4 plant . Similarly, fellow utility EnBW transferred its 517MW Karlsruhe RDK 7 into the reserve in late May, which contributed to a 35pc on-year fall in its total hard coal-fired generation to 248MW in July-September. Steag took off a larger capacity of hard coal assets — around 2GW from three sites in Saarland — from the market in the first half, resulting in a 32pc drop on the year to 99MW in the third quarter. Smaller operators likewise exited coal this year, with Bremen-based SWB shutting down its 119MW Hastedt 15 hard coal-fired unit in the end of April. The municipal utility has already replaced Hastedt 15 with a 104MW gas-fired combined heat and power plant . In addition, Czech utility EPH retired the 690MW Mehrum 3 plant in late March, having returned to the market in August 2022. Elsewhere, Wolfsburg-based industrial user Volkswagen decommissioned its two 138MW coal-fired units in March as the company opted for coal-to-gas fuel switching. Firm renewables supress thermal generation Wind and solar output rose on the year in the third quarter, crowding out not only hard coal but also gas and lignite within the German power mix. Combined wind and solar generation averaged 23.3GW during July-September, up by 12pc on the year. Solar output alone picked up by 2.1GW, owing to a higher load factor and increased installed capacity. Considering hydro and biomass generation also incrementally rose on the year in the third quarter, the overall strength in renewables meant Germany had to cut down thermal power output and cross-border imports in a bid to balance out with the demand, which only rose by 3pc on the year to 54.8GW in the same period. Consequently, thermal generation from hard coal, gas and lignite all fell on the year in the third quarter, but lignite dropped to 7.4GW at a slower rate of just 4pc compared with other fuels because of its low fuel procurement cost. German lignite-fired plants typically source their fuel from nearby mines. German gas-fired output was down by 26pc on the year to 7.1GW in July-September, in part owing to theoretical spark spreads deteriorating from a year earlier. In the beginning of the third quarter, a typical 55pc-efficient gas-fired plant using German VTP supplies was ahead of a 40pc-efficient German hard coal-fired unit on a month-ahead basis, but in the end of the quarter, such coal-gas fuel switching dynamics flipped (see chart). Ronald Kim DE month ahead fuel switching € MWh €/MWh DE coal output by operator GW GW DE hard coal-fired output GW GW Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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