UN climate chief wants clear finance plan for Cop 29
Making the global financial system "fit for purpose" and producing a "clear plan" to fund the energy transition must be this year's goal, UN climate body UNFCCC executive secretary Simon Stiell said in Baku, Azerbaijan, as the country starts preparations to host the UN Cop 29 climate summit.
Stiell said that a new climate finance goal — moving on from the missed $100bn/yr commitment from developed countries by 2020 — must be agreed at Cop 29, and that developing countries must be confident that they will be able to rapidly access sufficient concessional support. Technical dialogues between developed and developing countries have started to set this new finance goal — the so-called NCQG — by 2025, but a lot of work remains to be done before parties shake hands on how much money should be set aside, and where it should be spent.
"Whether on slashing emissions or building climate resilience, it's already blazingly obvious that finance is the make or break factor in the world's climate fight — in quantity, quality, and innovation," Stiell said. Cop 29 host Azerbaijan has already promised to put reforming finance mechanisms at the top of the talks' agenda.
He noted that a total of $2.4 trillion per year is needed for renewable energy, adaptation, and other climate-related issues in developing countries, excluding China, according to the High-Level Expert Group on Climate Finance — a group tasked by the Cop 26 and Cop 27 presidencies to work on finance needs. The group released a report in November last year calling for an integrated climate finance framework to deliver on the Paris Agreement and boost all sources of finance — public, private, domestic and international. A five-fold increase in concessional finance is also needed by 2030, according to the group.
Stiell warned that "without far more finance, 2023's climate wins will quickly fizzle away into more empty promises", and that it must not be "quietly pilfered from aid budgets".
He also said clear progress is needed to address "the assessment of investment risk, the allocation of special drawing rights" — reserves of interest-bearing foreign currency that can provide liquidity to countries in need — but also innovative sources of financing and creative mechanisms to tackle debt burdens. Talking about multilateral development banks, he said that they should take innovative steps that would "double, if not triple" their financial capacity by 2030, especially grants and concessional finance. He highlighted their crucial role when it comes to leveraging their engagement with the private sector to double and triple the overall rate of private capital mobilisation.
He said that the Cop 28 agreement to transition away from fossil fuels would have been "unthinkable" a few years ago, and that it sent a "very strong signal about the inevitability of global decarbonisation". "But now is no time for victory laps. It's time to get on with the job," he said. "Hiding behind loopholes in decision texts, or dodging the hard work ahead through selective interpretation, would be entirely self-defeating for any government, as climate impacts hammer every country's economy and population."
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Japan’s J-Power steps up coal-fired power phase-out
Japan’s J-Power steps up coal-fired power phase-out
Osaka, 10 May (Argus) — Japanese power producer and wholesaler J-Power is stepping up efforts to halt operations of inefficient coal-fired power plants, while pushing ahead with decarbonisation of its existing plants by using clean fuels and technology. J-Power plans to scrap the 500MW Matsushima No.1 coal-fired unit by the end of March 2025 and the 250MW Takasago No.1 and No.2 coal-fired units by 2030, according to its 2024-26 business strategy announced on 9 May. It also aims to decommission or mothball the 700MW Takehara No.3 and the 1,000MW Matsuura No.1 coal-fired units in 2030. The combined capacity of the selected five coal-fired units accounts for 32pc of J-Power's total thermal capacity of 8,412MW, all fuelled by coal. While phasing out its ageing coal-fired capacity, J-Power is looking to co-fire with fuel ammonia at the 2,100MW Tachibanawan coal-fired plant sometime after 2030 and ensure it runs on 100pc ammonia subsequently. The company plans to increase the mixture of biomass at the 600MW Takehara No.1 unit, along with the installation of a carbon capture and storage (CCS) technology after 2030. The CCS technology will be also applied to the 1,000MW Matsuura No.2 unit, which is expected to co-fire ammonia, after 2030. J-Power plans to use hydrogen at the 1,200MW Isogo plant sometime after 2035. The company is also set to deploy integrated coal gasification combined-cycle and CCS technology at the 500MW Matsushima No.2 unit and the 150MW Ishikawa No.1 and No.2 units after 2035. The company aims to cut carbon dioxide emissions from its domestic power generation by 46pc by the April 2030-March 2031 fiscal year against 2013-14 levels before achieving a net zero emissions goal by 2050. This is in line with Tokyo's emissions reduction target. The company aims to expand domestic annual renewable output by 4TWh by 2030-31 compared with 2022-23, along with decarbonising thermal capacity. Its renewable generation totalled 10.4TWh in 2023-24. Tokyo has pledged to phase out existing inefficient coal-fired capacity by 2030, which could target units with less than 42pc efficiency. The country's large-scale power producers have reduced annual power output from their inefficient coal-fired fleet by 13TWh to 103TWh in 2022-23 against 2019-20, according to a document unveiled by the trade and industry ministry on 8 May. It expects such power generation will fall further by more than 60TWh to 39.700TWh in 2030-31. Global pressure against coal-fired power generation has been growing. Energy ministers from G7 countries in late April pledged to phase out "unabated coal power generation" by 2035 or "in a timeline consistent with keeping a limit of 1.5°C temperature rise within reach, in line with countries' net zero pathways". By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Australia’s ANZ bank to end new gas, oil lending
Australia’s ANZ bank to end new gas, oil lending
Sydney, 9 May (Argus) — Australia-based bank ANZ has updated its oil and gas policy, with it to no longer provide direct financing to new or expanding upstream oil and gas projects. The bank declared its new policy as part of its 2024 half-year results released on 7 May, saying it would also decline to integrate new customers primarily focused on upstream oil and gas. ANZ said that while it believes gas plays a "material and important part in meeting Australia's current energy needs and will do so for the foreseeable future", it will instead collaborate with energy customers to help finance their transition away from fossil fuels. The bank has a 26pc greenhouse gas (GHG) emissions reduction by 2030 goal and committed in 2020 to exit all lending to companies with exposure to thermal coal, either through extraction or power generation by 2030 as part of lending criteria to support the 2015 UN Paris climate agreement target of net zero GHG emissions by 2050. ANZ has however promised to consider exceptions on a case-by-case basis, if any national energy security issues arise. Australia's banks have been under sustained pressure by environmental groups to exit lending to fossil fuel projects, as upstream gas firms also face shareholder rebellions over climate action plans. But Australia's federal government has conceded gas will likely be needed post-2050 as a firming power source for renewables and industrial feedstock for some sectors. But investment in upstream exploration has been extremely low in recent years, with imports of LNG likely in southern Australia from about 2026 to meet demand for industrial users and power generation. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
LNG imports loom as Australia unveils gas strategy
LNG imports loom as Australia unveils gas strategy
Sydney, 9 May (Argus) — Australia's federal government will attempt to reverse the decline in new gas developments by expediting projects, although a report has found it is unlikely to reverse an anticipated shortfall in southern states' supplies later this decade. Canberra's long-awaited Future Gas Strategy will form its future policy on the resource, following two years of uncertainty for the industrial sector. This follows the Labor party-led government's election in May 2022 and its dumping of the previous Liberal-National coalition administration's gas-fed recovery from Covid-19 policy, which emphasised bringing new supplies on line to drive down rising prices. Six principles have been outlined by the government — driving down emissions reductions to reach net zero emissions by 2050, making gas affordable for users during the transition, bringing new supplies on line, supporting a shift to "higher-value and non-substitutable gas uses", ensuring gas and power markets remain fit for purpose during the energy transition and maintaining Australia's status as a reliable trading partner for energy, including LNG. The report found that gas-fired power generation will likely provide grid firming as renewables replace older coal-fired plants. Peak daily gas demand could rise by a factor of two to three by 2043, according to projections, with gas-powered peaking generation labelled a "core component of the National Electricity Market to 2050 and beyond". But by the 2040s more alternatives to gas for peaking and firming are expected to become available. Supplies are forecast to dip significantly in the latter years of the decade, especially in gas-dependent southeast Australia, driven by the 86pc depletion of the region's producing fields. This reduced supplies will outpace a fall in demand , while rising demand is forecast because of the retirement of Western Australia's coal-fired power plants . The report found the causes of Australia's low exploration investment are "multifaceted", blaming the Covid-19 pandemic, difficulties with approvals processes , legal challenges, market interventions and a perceived decline in social licence. It added that international companies may focus on lower cost and lower risk fields in other countries. New sources Stricter enforcement of petroleum retention leases and domestic gas reservation policies are also likely to increase supplies, the report found, with term swap arrangements beneficial in increasing their certainty. Upwards pressure in transport costs is likely to result from increased piping of Queensland coal-bed methane gas to southern markets such as Victoria state, which could influence industrial users to relocate closer to gas fields in the future. Options canvassed to meet demand include more pipelines and processing plants and LNG import terminals , which would provide the fastest option but must overcome regulatory and commercial pressures, given the pricing of LNG would be higher than current domestic prices. Longer term supplies depend on the commerciality from unsanctioned projects such as Narrabri and in the Beetaloo and Surat basins, the report said. More supplies are needed to support exports under foundational LNG contracts, with an impact on the domestic market if Surat basin developments such as Atlas does not continue, the report said. Forecasts show LNG exporters have sufficient production from existing and committed facilities to meet forecast exports until 2027 if expected investments proceed. But beyond this new investment is required, especially for the 8.5mn t/yr Shell-operated Queensland-Curtis LNG at Gladstone. The Australian Energy Producers lobby, which represents upstream oil and gas businesses, said the strategy should now provide clear direction on national energy policy. But the Greens party, the main federal parliamentary group aside from Labor and the Liberal-National coalition, said any plans to continue gas extraction beyond 2050 will negate state and federal net zero 2050 climate targets. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
EPA sets new oil and gas methane reporting rules
EPA sets new oil and gas methane reporting rules
Washington, 7 May (Argus) — Federal regulators have updated emissions reporting requirements for oil and gas facilities as they prepare to implement a methane "waste" fee for the industry. The US Environmental Protection Agency (EPA) on Monday finalized new rules it says will improve the accuracy of data from the oil and gas sector under the federal greenhouse gas emissions reporting program. Oil and gas facility owners and operators will be required to estimate emissions from additional types of equipment under the rule, and they can draw on newer technologies, like remote sensing, to help estimate emissions. "EPA is applying the latest tools, cutting edge technology, and expertise to track and measure methane emissions from the oil and gas industry," agency administrator Michael Regan said. "Together, a combination of strong standards, good monitoring and reporting, and historic investments to cut methane pollution will ensure the US leads in the global transition to a clean energy economy." Data to support new fee The revisions to the "Subpart W" reporting requirements will be used to determine the amount of methane that will be subject to a "waste emissions charge" created by the Inflation Reduction Act. Under the law, the charge will be calculated based on the annual data that about 8,000 oil and gas sources are now required to report. The charge will begin at $900/t for 2024 methane emissions above a minimum threshold using current measurement data. It will then rise to $1,200/t in 2025 and $1,500/t in subsequent years. Industry officials had raised "serious concerns" about several aspects of the original proposal , warning it could lead to inflated emissions data. "We are reviewing the final rule and will work with Congress and the administration as we continue to reduce GHG emissions while producing the energy the world needs," American Petroleum Institute vice president of corporate policy Aaron Padilla said. The industry group previously said it will ask Congress to repeal the fee, which is only likely to occur if Republicans win control of the White House. Data collected since 2010 Oil and gas facilities have reported emissions under Subpart W since 2010. To simplify reporting, operators often count the equipment they have deployed, and use industry-wide averages to estimate emissions, in addition to other direct and indirect measurements. The industry has argued the Subpart W data is not accurate enough to collect the methane charge, which is expected to cost operators more than $6bn over the next decade. Environmental groups have had their own criticisms of the data, which they say omits vast amounts of emissions such as those from "super-emitter" events and poorly maintained flares. The final rule seeks to respond to some of those concerns by relying on updated emission factors, incorporating additional empirical data on emission rates, collecting data at a more granular level and relying on remote sensing technologies to detect large emission events. EPA also revised Subpart W to include more types of sources, including produced water tanks, nitrogen removal units and crankcase venting. The final rule also sets a threshold of 100 kg/hr of methane for requiring the reporting of emissions from "other large release events." The new data rules will take effect on 1 January 2025 and will first apply to reports submitted in early 2026 for next year's emissions. EPA is allowing the use of the new methodologies for calculating 2024 emissions, but operators can still use the existing rules. By Michael Ball Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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