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Australia’s 1H large-scale renewable approvals rise

  • Market: Electricity
  • 08/08/24

Australia's Clean Energy Regulator (CER) approved 24pc more large-scale renewable energy capacity in this year's first half compared with a year earlier, while large-scale generation certificates (LGCs) held in the local registry also increased.

The CER approved 1,175MW under the Large-scale Renewable Energy Target (LRET) scheme over January-June, up from 949MW in the same period of 2023 and the highest for a first half since 2020 when 2,146MW was accredited, CER data show.

Total approved capacity in 2023 reached 2,206MW, slightly above 2022 but almost half of the record highs of 4,110MW in 2019 and 4,070MW in 2020.

LRET-accredited plants can issue LGCs and sell them to liable entities under Australia's Renewable Energy Target, mainly electricity retailers that need to surrender the certificates to the CER on an annual basis. LGCs can also be sold to companies and individuals looking to support their emissions reduction claims.

Total LGCs in the local renewable energy certificate registry reached 28.45mn at the end of June this year, or the equivalent of 28.45TWh, with each certificate representing 1MWh of renewable power. This is up from 24.66TWh in the same period of 2023, according to CER data.

Accounts held by major utilities including Origin Energy, Alinta Energy, AGL and EnergyAustralia were among the largest LGC holders at the end of the first half of the year (see table).

Total operational accredited capacity under the LRET reached 20,971MW in June. The CER also reported 7,853MW of committed capacity from large-scale renewable projects that received all development approvals and reached a final investment decision by the end of the first half. There was also 4,391MW of "probable" projects, or those that have announced power purchase agreements with strong counterparties or provided other evidence of funding.

Australia top 10 LGC account holdings*
Origin Energy4,247,730
AquaSure1,772,066
Alinta Energy - GreenPower account970,732
AGL HP2 933,377
EnergyAustralia 916,174
Synergy843,747
Stanwell719,831
Alinta Energy652,988
Origin Energy - GreenPower account635,489
Snowy Hydro - GreenPower account628,376
* as of 30 June 2024

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06/08/24

Utah power plant takes Illinois basin coal

Utah power plant takes Illinois basin coal

New York, 6 August (Argus) — The Intermountain Power Project (IPP) in Utah further diversified its coal supply earlier this year to offset output declines from coal mines in the state. The plant took 12,315 short tons (11,351 metric tonnes) of coal from Alliance Resource Partners' Gibson mine in Indiana in April, operating data collected by the US Energy Information Administration (EIA) shows. It also has taken 270,824st of Powder River basin (PRB) coal from Arch Resources' Black Thunder mine in Wyoming, extending a trend started in 2023 as Utah coal supply was in earlier stages of dwindling. April's delivery of coal from the Gibson mine was the first time since at least 2008 that IPP has taken coal from the Illinois basin. Coal mined east of the Mississippi River typically does not travel west at least partly because of logistics challenges. It takes at least two railroads to take coal from the Illinois basin to Utah, and not all power plants can do that. According to EIA data, no other power plants in Utah and Colorado took any Indiana-sourced coal in at least ten years. IPP declined to comment on whether it will continue to take Illinois basin coal. Alliance Resource Partners did not respond to requests for comment. The coal received from the Gibson mine in April was part of a test burn. It is a higher heat content coal than the PRB supply and closer to what Utah producers produce, but also higher sulfur than coal from the PRB and Utah. Prior to last year, IPP only took coal from Wyoming, Colorado and Utah. IPP started receiving PRB coal in March 2023 as Utah coal producers struggled to meet contractual commitments. It also took coal from Colorado in 2023. Utah coal producers still are not supplying what they had previously agreed to, according to people familiar with the situation. This has forced IPP to idle one of its two generating units during non-peak seasons and to look further afield for fuel supply. Output from the Uinta basin dropped to a 38-year low in the second quarter partly because American Consolidated Natural Resources' Lila Canyon mine, which incurred a fire in September 2022, was closed in January. Wolverine Fuel's Skyline #3 - the largest active mine in Utah – decreased output by 71pc to 244,377st in the second quarter because of the longwall move. The delivery from the Gibson mine in April represents a fraction of that mine's output. In the first half of this year, the mine produced 2.89mn st, up from 2.67mn st a year earlier, MSHA data show. IPP's demand for PRB and Illinois basin coals may be short-lived. The power plant's owners expect to switch to natural gas in mid-2025, after operator Intermountain Power Agency (IPA) completes construction of an 840MW gas unit in 2025. IPP's largest customer, the Los Angeles Department of Water and Power, is required by the state law to stop using coal-fired generation by 2026. IPA declined to comment on fuel purchasing. In the first five months of 2024, IPP took 888,378st of coal from Colorado and Utah coal mines, according to EIA. That is up from 766,705st IPP has taken from the states' mines during the same five months last year. Shipments of PRB coal also increased compared with January-May 2023, when they had totaled 138,030st. By Elena Vasilyeva Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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China to set hard targets for curbing CO2 emissions


02/08/24
News
02/08/24

China to set hard targets for curbing CO2 emissions

San Francisco, 2 August (Argus) — China is planning a shift in the way it controls greenhouse gases, specifically carbon dioxide (CO2) emissions, in a move that could support progress in its national emissions trading scheme (ETS), although it is unclear what emissions levels will be targeted. The country currently measures CO2 against economic growth, or emissions per unit of GDP in what is known as carbon intensity. This allows it to tout progress despite rising emissions so long as these do not rise faster than GDP. But it plans to change this. Beijing aims to incorporate CO2 indicators and related requirements into national plans and establish and improve local carbon assessments in a goal to improve CO2 statistical accounting. This will affect sectors including the power, steel, building materials, non-ferrous metals, and petrochemicals sectors, according to a state council work plan issued on 2 August. It will evaluate CO2 emissions of fixed asset investments and conduct product carbon footprint assessments while local governments will implement provincial carbon budgets that could enter trials in 2025. The latter will involve a wide range of industries including oil, petrochemicals, coal-to-gas, steel, cement, aluminium, solar panels manufacturing and electric vehicles, among others. Beijing is hoping such measures will allow it to set hard targets for CO2 emissions from 2026-2030, although the government will still prioritise intensity control in the meantime in what it calls a ‘dual-control mechanism' — switching from controlling intensity to actual emissions of CO2. Provinces are expected to be allowed to further refine this dual control mechanism, suggesting it will may give localities some leeway to adjust. China's ETS currently includes only the power sector due in large part to challenges collating accurate CO2 emissions data from other sectors, although it is expected to include other sectors like aluminium into the scheme soon. China unveiled new regulations for its ETS earlier this year, aiming to crack down on falsification of data. It sees the ETS as a tool to help it meet a goal to peak carbon emissions before 2030 and reach carbon neutrality before 2060. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Japan’s Goi No.1 CCGT starts commercial operations


01/08/24
News
01/08/24

Japan’s Goi No.1 CCGT starts commercial operations

Osaka, 1 August (Argus) — Japanese joint venture Goi United Generation started commercial operations today of the 780MW No.1 combined-cycle gas turbine (CCGT) unit, with construction having begun in April 2021. The joint venture comprises Japan's largest power producer by capacity Jera, the power arm of refiner Eneos and regional utility Kyushu Electric Power with a shareholding ratio of 9:5:1 respectively. The new 1,650°C-class Goi CCGT unit can achieve around 64pc thermal efficiency on a lower calorific value basis, with the best available thermal technology helping cap carbon dioxide emissions. This is part of the development of the proposed 2,340MW Goi CCGT plant, which is to replace the 1,886MW conventional gas-fired power plant that was decommissioned in March 2018. The 780MW No.2 and No.3 CCGT units are scheduled to begin operations in November and March 2025 respectively. LNG use at Goi is expected to increase to 2.2mn t/yr from the previous 1.9mn t/yr following the plant's completion, according to the environmental impact assessment for the plant replacement. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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APLNG gas output rebounds in 2023-24: Origin


31/07/24
News
31/07/24

APLNG gas output rebounds in 2023-24: Origin

Sydney, 31 July (Argus) — The 9mn t/yr Australia Pacific LNG (APLNG) project in Queensland state produced and sold more LNG in the 2023-24 fiscal year to 30 June than the previous year, upstream operator Australian independent Origin Energy said in its April-June results. APLNG's 2023-24 output totalled 694PJ (18.53bn m³) or 3pc higher than a year earlier when it produced 674PJ, while sales of 665PJ were also 3pc up on 2022-23's 645PJ. APLNG's guidance for the year was 680-710PJ. The 2022-23 fiscal year was affected by cumulative wet weather that Origin said cut APLNG's output from 693PJ in 2021-22. This improved result was because of well and field optimisation Origin said, offset by the stranding of an LNG carrier at APLNG's wharf in Gladstone harbour last November that led to a temporary fall in gas production. APLNG exported 127PJ (2.29mn t) of LNG through 33 cargoes for April-June, 4pc down from 132PJ and 34 cargoes the previous quarter and 1pc down on the 128PJ and 33 cargoes shipped in April-June 2023. APLNG delivered 15 spot cargoes in 2023-24, up from seven the previous year. Total LNG sales for 2023-24 from APLNG were 503PJ, up from 495PJ a year earlier, with 130 cargoes up from 128 in 2022-23. The project's average realised LNG price for 2023-24 was $11.85/mn Btu, down by 17pc from $14.20/mn Btu a year earlier. APLNG provided Origin with A$1.367bn ($888mn) in cash distributions for 2023-24, net of Origin's oil hedging. The average National Electricity Market spot price for April-June was A$134/MWh, up by 14pc from A$118/MWh a year earlier, Origin said, with its 2,880MW Eraring coal-fired power station's output for 2023-24 up by 2.1TWh on 2022-23 to 14.3TWh. Eraring, which will now run at least two years longer than expected following a deal with the state government, benefited from the A$125/t coal price cap during 2023-24. Its weighted-average coal price is expected to be A$30/t higher in 2024-25, Origin said. By Tom Major Origin Energy results Apr-Jun '24 Jan-Mar '24 Apr-Jun '23 y-o-y % ± q-o-q % ± Production (PJ) 175 176 176 -1 -1 Sales (PJ) 177 168 165 7 5 Commodity revenue (A$mn) 2,602 2,303 2,471 5 2 Average realised LNG price ($/mn Btu) 11.70 12.17 12.24 -4 -4 Average realised domestic gas price (A$/GJ) 9.30 6.90 6.79 37 35 Source: Origin Energy Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Australia’s Mereenie JV signs gas supply deal with NT


29/07/24
News
29/07/24

Australia’s Mereenie JV signs gas supply deal with NT

Sydney, 29 July (Argus) — The joint venture (JV) partners at Mereenie, the Northern Territory's (NT's) largest onshore operating gas field, have entered a six-year deal to supply the NT government from 1 January 2025. The 40.5PJ (1.08bn m³) take-or-pay gas sales agreement (GSA) mitigates the risk incurred by closures to the 90 TJ/d (2.4mn m³/d) Northern gas pipeline (NGP). It does this by contracting all firm production capacity and expanding by up to 16 TJ/d on any day in 2025 when the NGP is unable to deliver to the east coast network, operator Australian independent Central Petroleum said on 29 July. The GSA underwrites the JV's potential investment in two new production wells at Mereenie, said Central, which holds a 25pc stake, by increasing firm sales to the NT by up to 6 TJ/d. The NT is dependent on gas-fired power supply but supply problems at Italian oil firm Eni's offshore Blacktip field led it to signing a GSA with Mereenie for 2024 supply earlier this year. The issues at Blacktip resulted in the NGP ceasing flows in early February, cutting Mereenie off from its customers. The NT this week also signed a GSA with Australian independent Empire Energy for supply from the proposed 25 TJ/d Carpentaria project in the onshore Beetaloo subbasin. A unit of Australia's Macquarie Bank owns 50pc of Mereenie, located in the Amadeus basin, with upstream firm New Zealand Oil and Gas holding 17.5pc and the remaining 7.5pc is owned by Australian independent Cue Energy. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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