I-REC January-August demand surpasses whole of 2023

: Electricity
24/09/04

International renewable energy certificate (I-REC) demand in January-August surpassed consumption in all of 2023, with 20pc more I-RECs redeemed in August compared with the same month last year.

Higher redemptions in Colombia, Malaysia and India last month outpaced lower demand from key buyers Brazil and China.

Global I-REC redemptions totalled 9.9TWh in August, higher than 8.2TWh in August 2023 and broadly steady on the month, according to data from UK-based global registry Evident. A total of around 182TWh was redeemed in January-August this year, surpassing the 176TWh redeemed in all of 2023.

There were 14.2TWh of I-RECs issued in August, up from 12.7TWh in July but below the 14.9TWh a year earlier. The 12-month rolling average of issuances is 25.8TWh.

Latin America

I-REC redemptions in Latin American countries totalled 4.1TWh in August, up from 3.1TWh a year earlier. Colombia accounted for around 65pc of redemptions with 2.65TWh — the highest in at least three years — surpassing Brazil, which accounted for almost 20pc.

Brazilian I-REC demand was around two-thirds lower last month compared with August 2023, with 762GWh redeemed compared with 2.4TWh a year earlier. But the country is still the largest I-REC consumer in 2024 so far, with 41.3TWh redeemed over January-August.

Issuances in Brazil more than halved on the year to 532GWh in August, the lowest since June 2022.

Brazilian 2024 hydropower and wind/solar I-RECs were last assessed at $0.17/MWh and $0.19/MWh, respectively, on 28 August, both steady since the end of July.

I-REC demand was nearly 10 times higher on the year in Chile, where redemptions were at 266GWh last month compared with 29GWh in August 2023. But they declined from both June and July, with almost 700GWh redeemed in each month.

Asia-Pacific

Redemptions in the Asia-Pacific region edged up to 3.6TWh in August from 3.1TWh a year earlier, as a slight decline in Chinese demand was offset by a surge in redemptions in Malaysia.

Redemptions in China were at 2.2TWh last month compared with 2.3TWh in August 2023, although they still accounted for the biggest share in the region at 61pc. Chinese I-REC issuances also declined last month and were at 5TWh, down by 2TWh year-on-year.

There were 1.1TWh of I-RECs redeemed in Malaysia in August, the highest since February and nearly 12 times higher than August 2023. Approximately 8.4TWh have been redeemed in the country so far this year, compared with 9.1TWh in all of 2023. Hydropower comprises the biggest share of redemptions so far in 2024 at 7.1TWh, followed by solar with 1TWh.

The volume of I-REC issued in Malaysia edged down to 623GWh last month from 672GWh in August 2023.

Malaysian current-year hydro I-RECs were assessed at $1.30/MWh throughout August, broadly steady since Argus assessments began in February. Solar I-RECs with 2024 vintage were at $5.60/MWh at the end of last month, up from $5.25/MWh when assessments first launched on 15 February.

South Asia

Redemptions in India continued to rise last month to 854GWh, up from 813GWh in July and 550GWh in August 2023.

I-REC issuances were at 1.1TWh in August, down from 1.17TWh in July but nearly two times above the 576GWh issued in August last year. Earlier this week, the International Tracking Standard Foundation announced that ICX, a wholly-owned subsidiary of Indian Energy Exchange (IEX), has been approved as the country's first local issuer of I-RECs for renewable electricity.

The latest Argus assessments for 2024 Indian hydro and wind/solar I-RECs were $0.50/MWh and $0.65/MWh, respectively, on 29 August, both down by $0.05/MWh on the week after holding steady since the end of July.

By Giulio Bajona

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24/10/08

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.

German 3Q hard coal output falls on reduced fleet

24/10/08

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.

Fossil fuel cars phase-out comes up again in Brussels

24/10/07

Fossil fuel cars phase-out comes up again in Brussels

Brussels, 7 October (Argus) — The European parliament will this week debate a "crisis" facing the EU's automotive industry which could lead to "potential" plant closures, putting discussions on already-decided CO2 standards for vehicles on the forefront. Members have faced increased efforts by industry arguing for or against speedy review of the EU's regulation on CO2 emission standards for cars and vans. The regulation sets a 2035 phase-out target for new fossil fuel cars. The European commission is expected to give a statement to parliament, but a spokesperson told Argus that any change to the EU CO2 standards for cars and light vehicles would require a legal proposal by the commission to both parliament and EU member states. The priority, the spokesperson said, is on meeting 2025 targets for fleet CO2 reductions, agreed in 2019, but the commission is aware of "different opinions" in industry. Automakers association Acea has been calling for a "substantive and holistic" review of the CO2 regulation. The transition to zero-emission vehicles must be made "more manageable", assessing real-world progress against the ambition level. On the other hand, European power industry association Eurelectric today told members of parliament that bringing forward a review of the EU's regulation on CO2 standards for cars and vans to the start of 2025 would only encourage carmakers to hold off on making lower-priced and smaller electric vehicles (EV). The next CO2 target for car fleets is set to take effect in 2025. It requires a 15pc cut in emissions for newly registered cars. Some member states view the CO2 target cuts, and phase-out of the internal combustion engine (ICE) by 2035, as contentious. The regulation was only approved after a delay to normally formal approval. And parliament's largest centre-right EPP group is calling for a revision of CO2 standards for new cars to allow for alternative zero-emission fuels beyond 2035. As a counterweight to such pressure, Austrian, Belgian, Dutch and Irish ministers today called on commission president Ursula von der Leyen to step up EU action to push decarbonisation of company vehicles, notably light duty vehicles. "We need to consider action on the demand side in order to push zero-emission vehicles sales. Corporate fleets are the EU's most important market segment," the four ministers told von der Leyen. By Dafydd ab Iago Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Sheinbaum targets $40bn energy transition plan

24/10/04

Sheinbaum targets $40bn energy transition plan

New York, 4 October (Argus) — The ambition of Mexico's new President Claudia Sheunbaum to reach 45pc of renewable generation in the electricity mix by 2030 will include an investment plan of $35bn-40bn, sources familiar with the matter said. Sheinbaum announced a more ambitious goal for renewables and promised to launch an energy transition plan in coming days during her inaugural address on 1 October. The awaited document will include specific strategies and projects to be developed in the first days of her term, Alonso Romero, deputy director of commercial strategy at state utility CFE and one of Sheinbaum's energy advisors during her campaign, told Argus . There will be around $6bn/yr in new investments under Sheinbaum's six-year term to develop a pipeline of 60GW in new capacity, mostly renewable, he added. The new administration will propose several types of contracts to developers that guarantee CFE holds the largest participation in the sector, said Romero. There have been meetings between Sheinbaum's representatives and banks to show the plan's potential, said a source familiar with the topic. But potential investors are still waiting to see if congress passes the bill to reform the energy sector sent by former president Andres Manuel Lopez Obrador. That energy bill is crucial in Sheinbaum's plan, as it will lay the groundwork for further legal modifications, said Romero. It will be easier to attract the private sector into investing in projects if a long-term contract with CFE provides support as the final source of payment in case of a default, said Romero. Under current law, CFE cannot directly buy electricity from a new power plant unless it comes from a long-term auction. Congress would need to approve the bill and then modify the electricity law to lift that prohibition, so lenders would have certainty that CFE can sign long-term contracts with new renewable or thermal power plants without holding a tender, said Romero. The Sheinbaum administration is considering signing Build, Lease and Transfer (BLT) contracts for some projects, said Romero. This way, CFE will have the opportunity to acquire the asset after 10-15 years of being operated by another company. Hopes and fears Sheinbaum's bet on the energy transition could be seen as a hopeful message for the renewables sector, but investors still need clarity on the rules in the electricity market. Market players have been worried that Sheinbaum will continue her predecessor's energy policy that for years openly attacked private-sector renewable companies. "It is clear that Sheinbaum is trying to make the energy transition her own mark," said Jesus Carrillo, energy expert at Mexican think tank Instituto Mexicano para la Competitividad. "However, it is risking her credibility by setting such ambitious goals." In 2023, Mexico generated just 24.3pc of its electricity from clean sources, despite that category holding 32pc of installed capacity, according to energy ministry (Sener) data. Reaching the new target could be possible if Sheinbaum's administration pulled off a clear path to speed up investments in renewable generation, the sector said. "The energy transition path goes much faster when the government leads it," said Romero. Private-sector renewable companies are willing to finally put an end to the impasse during Lopez Obrador's term. But the legislative electricity proposal along with modifications that will overhaul the judicial power in upcoming months create a worrisome business environment in Mexico, sources said. The Sheinbaum administration needs to provide not only a clear but also attractive legal framework so the private sector can provide the funds and capabilities to aid in this energy transition plan, sources said. Mexico's electricity system requires around $130bn in new investments to meet the country's growing demand from 2024-2030, according to a recent analysis from business trade group Coparmex. By Edgar Sigler Mexico’s share of clean electricity % Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

France's wind sector weighs impact of new government

24/10/04

France's wind sector weighs impact of new government

London, 4 October (Argus) — Doubts over government policy on onshore wind competed with optimism over offshore wind at the French wind sector's annual conference in Paris on Wednesday. The event took place a day after the first policy announcements of prime minister Michel Barnier , in which he said his government would "better handle the impacts" of wind energy. No more detail is available on what this will mean exactly, although far-right party Rassemblement National (RN), which props up Barnier's minority government, is strongly opposed to wind energy. And of two of the parties in his coalition, president Emmanuel Macron's EPR and Barnier's own Les Republicans (LR), the former is supportive of wind, while the latter is more sceptical without being downright opposed, one developer told Argus . While junior energy minister Olga Givernet told the conference of her intention to reduce the delays developers face, participants Argus spoke to feared Barnier's evocation of "impacts" could mean an expansion of barriers to building new capacity. "We already take the impacts into account," one developer said, noting that firms perform extensive studies and undertake environmental impact assessments (EIAs). And legal challenges are one of the main obstacles slowing down capacity increases, with one developer calling for better-trained judges to reduce the number of "arbitrary" decisions made in these cases. Delays in receiving grid connection and EIAs were other factors developers cited. But the conference was more upbeat on offshore wind. The government will in the coming weeks announce priority zones for offshore wind, which will allow it to launch tenders for 8-10GW of capacity by the end of the year. These will contribute to the country's goal of reaching 18GW of installed capacity by 2035. At the same time, the increasing occurrence of negative price hours threatens the sector, according to industry body France Renouvelables. Negative prices can pose a threat to grid stability, according to grid operator RTE. Large quantities of renewables can be shut down suddenly at the beginning of negative price hours, leading to a sharp output slope, which the grid operator has little visibility of, RTE said. Negative prices are a problem for operators too, even those under contracts for difference (CfDs) which are not directly exposed, according to Jean-Francois Petit of renewables operator Boralex. Operators typically shut down during negative pricing hours, but receive only partial compensation for lost output, he said, while the requirement that production be completely halted can be difficult operationally. And slow progress on repowering could represent another brake to capacity increases. Repowering is not underpinned by primary legislation, but only by ministerial circulars, one developer said, which offers little certainty to firms that want to undertake it. Meanwhile, height limits imposed for aviation constraints and landscape protection reduce the potential to add taller, more powerful turbines. French turbines are typically much smaller than those in neighbouring countries because of these height limits, which reduces access to higher-quality wind resource. And an open question remains over potential local content requirements in future tenders for CfDs. These requirements, enabled by the European Net Zero industry Act (NZIA) and supported by energy regulator the CRE, could prove a fillip for manufacturers of energy-transition materiel such as wind turbines, hobbled by competition from Chinese manufacturers. But incorporation of these requirements would push up costs, requiring higher strike prices at CfDs and more public subsidy. Energy minister Givernet did not appear to give the conference any hints on which way the government would lean, saying that control over both energy prices and security of supply were absolute priorities. Reaching France's goals by 2028 of 33.2-34.7GW of onshore capacity would require an installation rate of 2.3-2.7 GW/yr, roughly twice rates reached in recent years ( see graph ). By Rhys Talbot France onshore capacity and 2028 goals Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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