North Carolina budget blocks RGGI entry
North Carolina lawmakers have clinched a long-awaited budget agreement that includes language preventing state regulators from requiring power plants to join carbon trading programs, including the Regional Greenhouse Gas Initiative (RGGI).
The budget provision effectively targets the state Department of Environmental Quality, which had been looking at joining the RGGI power plant CO2 cap-and-trade program through rulemaking. North Carolina, with its multiple coal-fired power plants, would have been a major source of emissions and allowance demand in the multistate program.
The state government is unable to require electric utilities "to obtain allowances to offset their CO2 emissions" or to enter into "any agreement with other states" to do so, the final fiscal year 2023-25 budget says. The state House of Representatives voted 70-40 and the state Senate voted 26-17 to approve the budget late last week.
North Carolina governor Roy Cooper (D), while sharply critical of the months-late budget, indicated that he will let it become law without his signature. Republicans have large enough majorities in both chambers to override any veto, limiting Cooper's ability to request changes, and five Democratic members of the House voted in favor of the final budget.
"Make no mistake. Overall, this is a bad budget that seriously shortchanges our schools, prioritizes power grabs, keeps shady backroom deals secret and blatantly violates the constitution, and many of its provisions will face legal action," Cooper said.
The North Carolina Department of Environmental Quality, which did not respond to a request for comment, said last year that it was planning to launch a rulemaking that would allow the state to start participating in RGGI by the beginning of 2024.
But there have been few updates from state regulators since then.
RGGI executive director Andrew McKeon earlier this month said there were few obvious prospects for new states outside Pennsylvania to join and that prospects for North Carolina joining were grim.
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Chinese importers seek five LNG cargoes for Jun-Sep
Chinese importers seek five LNG cargoes for Jun-Sep
Shanghai, 15 May (Argus) — Five Chinese importers, mostly second-tier buyers, are each seeking one LNG cargo for June-September delivery, according to an official notice published by China's national pipeline operator PipeChina on 15 May. The five importers are PipeChina, Chinese independent ENN, Hong Kong-listed city gas firm China Resources Gas, Hong Kong-based Towngas and state-owned China Gas. PipeChina and ENN have indicated a target price of at most $9.50/mn Btu for their intended cargoes, both for delivery to PipeChina's 6mn t/yr Tianjin terminal. China Gas has indicated a target price of at most $9.30/mn Btu for delivery to PipeChina's 6mn t/yr Beihai termial. China Resources Gas and Towngas have both indicated a target price of at most $9/mn Btu for delivery to PipeChina's 2mn t/yr Yuedong and Tianjin terminals, respectively. This consolidated requirement came about because of a need for PipeChina to better leverage on its infrastructure advantages and, at the same time, meet the varying needs of gas importers and consumers in the country. But this requirement comes at a time when spot LNG prices are still somewhat higher than the importers' targeted prices. But the importers can choose not to buy if offers are not within their expectations. The front-half month of the ANEA, the Argus assessment for spot LNG deliveries to northeast Asia, was last assessed at $10.485/mn Btu on 15 May. Chinese importers mostly perceive spot prices below $9-9.50/mn Btu for June-September deliveries to be unattainable for now because there is strong buying interest from south and southeast Asia in particular. Indian state-controlled refiner IOC most recently bought LNG for delivery between 22 May and 15 June at around $10.60/mn Btu, through a tender that closed on 14 May. Thailand's state-controlled PTT most recently bought three deliveries for 9-10 July, 16-17 July and 22-23 July through a tender that closed on 13 May , at just slightly above $10.50/mn Btu. The most recent spot transaction was Japanese utility Tohoku Electric's purchase of a 10-30 June delivery at around $10.55/mn Btu through a tender that closed on 14 May . This is at least $1/mn Btu higher than Chinese importers' indications. Summer requirements have so far been muted but concerns among buyers about potential supply disruptions remain. Malaysia's 30mn t/yr Bintulu LNG export terminal suffered a power loss on 10 May, but this issue may have been resolved as of early on 15 May, according to offtakers. Some unspecified upstream issues may still be affecting production at the Bintulu facility, resulting in Malaysia's state-owned Petronas having to ask some of its buyers for cargo deferments, according to offtakers. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
US court upholds RFS blending targets for 2020-22
US court upholds RFS blending targets for 2020-22
Washington, 14 May (Argus) — A federal appeals court has affirmed biofuel blending requirements for 2020-22 under the Renewable Fuel Standard (RFS), rejecting lawsuits from refineries and renewable fuel producers challenging the standards. The US Environmental Protection Agency (EPA) acted within its authority in the rule when it revised the biofuel blending targets to account for small refinery exemptions it expected it would award in the future, the US Court of Appeals for the DC Circuit said today in a 2-1 ruling. The court rejected a complaint by refineries that argued EPA could only revise the annual biofuel blending targets based on exemptions it had already approved in the past. "The statute does not confine EPA to the Refiner Petitioners' preferred method of accounting for small refinery exemptions," DC Circuit judge Cornelia Pillard wrote on behalf of the majority. "EPA's choice to account for them both retrospectively and prospectively is not arbitrary or capricious." The ruling leaves intact a 2022 rule that required renewable fuel blending to increase to 20.63bn USG by 2022, up from 17.13bn USG in 2020. For the first time under the RFS, the rule used a new formula that tried to avoid a recurrent issue under which EPA failed to account for upcoming requests from small refineries for exemptions from the RFS. EPA has subsequently decided to start denying all small refinery exemptions, under a new argument that small refiners do not face a disproportionate hardship from complying with the RFS. But if the courts throw out that finding in a pending lawsuit , the formula at issue in today's court ruling could take on a greater relevance for how EPA accounts for small refinery exemptions when setting biofuel blending targets. The DC Circuit rejected a separate lawsuit by cellulosic ethanol producers that said EPA should have required increased blending of cellulosic ethanol, based in part on the availability of carryover compliance credits. The court found EPA had adequate authority to waive volumetric targets set by the US Congress in 2007 based on its finding there were inadequate domestic supplies of the fuel, which is produced from plant fibers. Judge Gregory Katsas, who dissented from the ruling, said he believed the biofuel blending requirements for 2022 were set "arbitrarily high." Katsas cited EPA's finding that those standards would impose an estimated $5.7bn in additional costs for fuel but only deliver $160mn in energy security benefits. Katsas also faulted EPA for increasing the biofuel blending targets by 250mn USG in 2022 to "cancel out a legal error" from biofuel blending targets in 2016. Katsas said there was no authority to transfer volume requirements from one year to another. By Chris Knight Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Q&A: Brazil adds Asian indexation for flexible gas
Q&A: Brazil adds Asian indexation for flexible gas
Sao Paulo, 13 May (Argus) — Three years after the natural gas market liberalization in Brazil, the number of consumers migrating from regulated supply has slowly increased and more flexible pricing mechanisms adopted. Argus spoke to Alessandro di Domenico , president of gas and power trader Delta Geração, about the current state of the market. Excerpts follow. Explain Delta's supply contract with Bolivia through 2026 despite Bolivia's gas production decline. The decline in production will happen because there is less investment [in Bolivia] than a few years back. But there are still some volumes that can supply the Brazilian market, especially in flexible contracts in the liberalized market. There is some gas that was being directed to Argentina and is now available. Even with the decline in Bolivia production, we will continue to have natural gas in the short-term. Besides that, the Rota 3 pipeline project [in Brazil's southeast] is close to being completed, which will bring more gas from pre-salt fields, leaving the market with more supply. This boosts the growth of the liberalized market. Delta is positioning itself to meet those demands and will sign other supply contracts soon. What types of contracts has Delta and others signed in the liberalized market? These are interruptible contracts. Their innovation relies on flexibility. Volume and duration are flexible. This allows us to meet clients almost back-to-back. How are these flexible contracts priced? They are competitive with the regulated market and are connected to international parity prices. Contracts are using Brent, Henry Hub and [Japan-Korea marker LNG spot prices]. How has the market progressed since 2021? This market was born rigid and is now gaining flexibility, in baby steps. In the beginning, there were only three consumers: Acelen, Brazilian steelmaker Gerdau and petrochemical group Unigel. Now we have companies in the cellulose business, metallurgy and automotive industry, which are all gas-intensive. So, in the future, there will be a big movement depending on state regulations, because that is an important axis of articulation for the mobility the liberalized market requires. State regulations play a very important role in allowing smaller entities to enter the market. By Rebecca Gompertz Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Sao Paulo state seeks biomethane boost
Sao Paulo state seeks biomethane boost
Sao Paulo, 13 May (Argus) — Brazil's Sao Paulo state is seeking to capitalize on growing demand for renewable energy, announcing a series of measures to increase biogas and biomethane production across various sectors, including sugarcane, waste management firms and waste agriculture. As Brazil's largest sugar and ethanol producing state, Sao Paulo has substantial potential to leverage existing infrastructure and resources — especially vinasse, a byproduct of ethanol production — to increase biomethane output. To boost output, the state government will streamline environmental licensing for new projects through new rules that should attract investment, according to the state's environment undersecretary for energy and mining, Marisa Barros. The focus will initially be on the sugar and ethanol industry, which can produce 30mn m³/d of biogas. Biogas contains 50pc methane, which can be processed into biomethane, a drop-in substitute for natural gas. The state is also seeking to attract investment in biogas production from animal waste, which can produce up to 5mn m³/d. The government estimates that roughly 190,000 farms in the state can install biodigestors to produce biogas, which would contribute to lower emissions in the state. The state agriculture secretary also approved the use of the Sao Paulo agribusiness expansion fund (Feap) for investments in biodigestors as well as new solar power installations. And earlier this year state regulatory agency Arsesp stipulated a discount on distribution fees for biomethane sold on the wholesale market. Brazil's energy research company EPE sees significant potential for the sugarcane industry to expand biomethane production, in part because it has the advantage of having many mills adjacent to existing gas distribution infrastructure. In addition to selling the renewable gas on the wholesale market, many mills are using biomethane in their own operations and to substitute diesel in their trucks and machinery, contributing to lower fuel costs and emissions. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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