US coal groups welcome CO2 rule change: Update

Spanish Market: Coal, Electricity, Emissions
21/08/18

Adds detail from EPA on expected coal capacity starting in the 10th paragraph

The US Environmental Protection Agency's (EPA) proposal today to replace the Clean Power Plan will help steady the coal industry, but more is needed, groups said.

The proposed rule would rely on on-site heat-rate improvements to cut CO2 emissions from coal-fired power plants, rather than the broader suite of measures, such as fuel switching and emissions trading, envisioned in the Clean Power Plan. It will give states up to three years to develop their own plans, quadruple the amount of time outlined in the previous rule, and modify standards for its New Source Review program to allow for an hourly emissions increase test.

The changes are largely in line with what members of the coal and electricity industries have identified as hurdles to upgrading aging, existing facilities. And they could protect a number of power plants from premature retirement once the rulemaking process is completed and litigation is resolved. This includes four of the five largest CO2 emitters in the US in 2016 according to EPA's database of facility level greenhouse gas emissions — the James H Miller, Scherer and Bowen plants, which Southern Company owns all or part of, as well as DTE's Monroe plant — none of which have near-term retirement plans.

"It certainly appears to be a step in the right direction," said Michelle Bloodworth, president of the American Coalition for Clean Coal Electricity. "But it is also insufficient."

The administration and regional transmission operators need to follow through on plans to restructure wholesale electricity markets to better support coal generation, Bloodworth and others said. "If those are not addressed we are going to see more retirements."

Energy secretary Rick Perry has repeatedly pushed for measures to support fuel secure facilities in wholesale markets, including a proposal to use the so-called "section 202(c)" emergency authority and a 1950s-era defense law to help the plants compete against low-cost natural gas and renewables. The PJM Interconnection already is considering restructuring its capacity auction and in April said it will start to evaluate fuel security within its grid. PJM has also been ordered by the Federal Energy Regulatory Commission to find a way by the end of this summer to prevent state subsidies for renewable energy and nuclear power plants from affecting prices in the grid's annual auction.

Bloodworth and others did not immediately have an estimate for how many more plants would retire if market changes are not enacted. US generators have 38.8GW of coal-fired capacity scheduled to retire between this year and 2030, according to a database kept by Argus.

Those plants will likely go off line as expected even if the new rule is implemented as currently written.

"The retirements are mostly market driven," said Josiah Neeley, energy policy director for the R Street Institute, a research group based in Washington, DC. "The market is not pricing CO2 so the retirements are going to be driven probably not by emissions but by competition from natural gas and things like that."

EPA expects 600 units at 300 coal-fired power plants to be covered by the new rule. That is roughly 60pc of the existing US coal fleet when including power plants scheduled for retirement before 2025.

The agency is estimating coal will make up as much as 13pc more of the total US generation mix than it would if the Clean Power Plan were in place. Even so, actual coal capacity will be, at most, 3pc higher than it would have been under the Obama administration's rule.

The agency's models of three proposed heat rate improvement and cost scenarios had coal capacity in 2035 at 171GW-177GW, compared with 173GW if the Clean Power Plan were in place. The coal sector had 266.6GW of net summer capacity in place in 2016, EPA said.

But the changes would be enough to make coal production for electric power sector use as much as 10pc higher than it would be under the Clean Power Plan, the agency said. It estimated output could be as much as 465mn short tons (421.8mn metric tonnes) in 2035 under its proposals, compared with 424mn st if the previous plan were in place.

The proposed rule is "a fulfillment to the president's promises" to end the "war on coal," the White House said today.

The rule will help the industry avoid as much as $6.4bn in compliance costs that would have been incurred had the Clean Power Plan gone into effect, the agency said.

"We recognize that markets have changed and will continue to change," said Kirk Johnson, senior vice president for government relations of the National Rural Electric Cooperative Association. "But there would have been for us electric coops significant assets that would have been placed in a really negative situation" had the Clean Power Plan been enforced.

The proposed rule is a "more achievable" plan for electric cooperatives that could help prevent premature power plant closings, the group said.

Others in the industry agree, but market conditions will continue to be the driving factor.

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27/12/24

Viewpoint: California-Quebec carbon faces murky 2025

Houston, 27 December (Argus) — The joint California-Quebec climate market, known as the Western Climate Initiative (WCI), is on tenterhooks going into 2025, stymied by rulemaking delays but on the cusp of a more mature phase. Both California and Quebec are eyeing more-stringent future programs and have floated a series of changes over the past year and a half designed to achieve those goals. The California Air Resources Board (CARB) is considering moving its program's mandate from the present 2030 target of a 40pc reduction in greenhouse gas (GHG) emissions, compared with 1990 levels, to a 48pc reduction to keep the state on target to meet its 2045 goal of net-zero emissions. In line with this increased ambition, CARB will need to remove at least 180mn metric tonnes (t) of allowances from the 2026-2030 auction and allocation annual budgets to start with, and up to 265mn t in total from the program budgets from 2026-2045. CARB has floated other changes , including toughening corporate relationship disclosure requirements, increasing the program's cost-containment allowance price tiers and updating a portion of the program's carbon offset protocols. Quebec has considered removing 17.5mn t of allowances, which correspond to carbon offset uses for compliance in the province over 2013-2020. The Quebec Environmental Ministry proposed to address this by removing these allowances from the province's 2025-2030 auction budgets in a November 2023 workshop. Quebec is also mulling changing the current three-year compliance period to align with statutory 2030 and 2050 GHG targets. But this a move that California, which had discussed similar compliance period changes in April , has not revisited since. Quebec is considering tapering the limit for carbon offset use for compliance in the province by 2030 and transitioning over to a provincial reduction purchase mechanism in 2031, although regulators have not gone in-depth on how a replacement system would function. The WCI rulemakings have been marked by a series of delays over this year, pushing past projections from the end of last year that it would finalize program changes by the second half of 2024. Quebec, which was set to deliver a draft of program amendments in September, rescheduled to early 2025, with implementation expected in spring 2025. While the regulation was nearly complete in late September, the Quebec Environmental Ministry chose to postpone, since it cannot publish before California, said Jean-Yves Benoit, the agency's director general of carbon regulation and emissions data. CARB has signaled it intends to publish its package of rulemaking amendments in early 2025. The agency on 19 December confirmed it expects to "complete and release the regulatory package for a 45-day public comment period" in early 2025 but did not explain the delay. The agency may be waiting for a formal extension of the cap-and-trade program when the legislature resumes on 6 January. California lawmakers have given CARB explicit authority to utilize a cap-and-trade system to reduce GHG emissions out to 2030. CARB maintains it has authority to operate a cap-and-trade program past 2030, but program participants have stressed the need for formal certainty around the program to aid future planning. CARB will begin invoking the post-2030 budgets starting in 2028 for the program's advance auctions. The various delays have compressed the timelines California and Quebec must achieve their statutory target ambitions, making 2025 a potentially pivotal year. By Denise Cathey Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Japanese firms to develop 1.07GW offshore wind power

27/12/24

Japanese firms to develop 1.07GW offshore wind power

Tokyo, 27 December (Argus) — Japanese firms will develop wind power farms with a total capacity of 1.07GW in Aomori and Yamagata prefectures, to raise domestic renewable power capacity as part of efforts to achieve the 2050 decarbonisation goal. Japan's largest power producer by capacity Jera, renewable energy firm Green Power Investment (GPI), and power utility Tohoku Electric Power will build a 615MW offshore wind farm off the coast of Aomori. The offshore wind farm will be the country's largest wind power project, according to Jera, and plans to start commercial operations in June 2030. Fellow utility Kansai Electric Power, trading house Marubeni, BP's subsidiary BP IOTA, Japanese gas distributor Tokyo Gas and local construction firm Marutaka separately plan to develop a 450MW offshore wind farm in Yuza city, Yamagata prefecture. The five companies set up a joint venture called Yamagata Yuza wind power ahead of the project. It plans to start commercial operations in June 2030, same as the other offshore wind project. The two projects are selected by the trade and industry ministry Meti's public offering which closed in July. The only way to build a large-scale offshore wind power plant is to apply for Meti's open call for proposals, Jera said. By Reina Maeda Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US gas market poised for more volatility

26/12/24

Viewpoint: US gas market poised for more volatility

New York, 26 December (Argus) — US natural gas markets may be subjected to more dramatic price swings in 2025 as growing LNG exports and increasingly price-sensitive producers place greater pressure on the US' stagnant gas storage capacity. Those price swings could pose challenges for consumers without ample access to gas supplies, as well as producers interested in keeping some output unhedged to capture potentially higher prices without taking on excessive financial risk. But volatility may also present opportunities for traders looking to exploit unstable price spreads, and for producers that can adapt their operations to fit a more unpredictable pricing environment. Calm before the storm High storage levels and low spot prices this year — averaging $2.11/mmBtu through November this year at the US benchmark Henry Hub — triggered by an unusually warm 2023-24 winter, may have obscured some of the structural factors pushing the US gas market into a more volatile future. But those structural factors remain and loom increasingly large for prices. The US has moved from a roughly 60 Bcf/d (1.7bn m³/d) market eight years ago to a more than 100 Bcf/d market today, "and we haven't grown our storage capacity at all", Rich Brockmeyer, head of North American gas and power at commodity trading house Gunvor, said earlier this year. As supply and demand for US gas grow, the country's roughly 4.7-Tcf storage capacity becomes ever less effective in stemming demand shocks, such as extreme winter weather events, which can more rapidly draw down inventories than in years past. Additionally, a growing share of US gas is being consumed by LNG export terminals being built and expanded on the US Gulf coast. When those facilities encounter unexpected problems and cease operations — as has happened numerous times at the 2 Bcf/d Freeport LNG terminal in Texas in recent years — volumes that were previously being liquefied and sent overseas were instead backed up into the domestic market, crushing prices. More LNG exports may mean more opportunities for such supply shocks. US LNG exports are expected to increase by 15pc to almost 14 Bcf/d in 2025 as operations begin at Venture Global's planned 27.2mn t/yr Plaquemines facility in Louisiana and Cheniere's 11.5mn t/yr Corpus Christi, Texas, stage 3 expansion, US Energy Information Administration data show. Spot price volatility will be most acutely felt in regions like New England that lack underground gas storage. "In areas like the Gulf coast, where you have a lot of storage, it won't be a problem," Alan Armstrong, chief executive of Williams, the largest US gas pipeline company, told Argus in an interview. Producers' trade-off Volatile gas markets are a mixed bag for producers, many of whom profit from volatility while also struggling to plan and budget based on uncertain revenues for unhedged volumes. Though insufficient gas storage deprives the market of stability, "from the standpoint of a marketing and trading guy that's trying to manage my gas supply to customers and my trading book, I love volatility",said Dennis Price, vice president of marketing and trading at Expand Energy, the largest US gas producer by volume. BP chief financial officer Sinead Gorman in November 2023 specifically named Freeport LNG's eight-month-long shutdown in 2022-23 from a fire as a driver of volatility in the global gas market. The supermajor was able to exploit the "incredibly fragile" gas market, she said, which was a key factor driving the success of its integrated gas business. "Those opportunities are what we typically seek and enjoy," Gorman said. Increasingly, producers have also been adapting to a more volatile market by switching production on and off in response to prices, but often without revealing the price at which a supply response will occur. Expand Energy, for instance, told investors in October that it was amassing drilled but uncompleted wells and wells that had yet to be brought on line, which it could activate relatively quickly when prices rise. It declined to name the price at which that would occur. Market participants, attempting to price in this phenomenon by anticipating producers' next moves may respond more dramatically to supply signals than in the past, when production was steadier. Producers' increased responsiveness to prices could help to balance the market somewhat, though more aggressive intervention into operations could take a toll on well performance and pipelines, FactSet senior energy analyst Connor McLean said. Producers are "treating the reservoir itself like a storage facility", Price said. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Unified CO2 market remains in distance

26/12/24

Viewpoint: Unified CO2 market remains in distance

Houston, 26 December (Argus) — Washington state's carbon market enters 2025 on steadier ground than it stood on for much of the past year, but still faces hurdles before it is part of a larger North American market. Washington's cap-and-invest program has weathered a year of highs and lows between advancing its ambitions to link with the Western Climate Initiative and operating through much of the year under threat of repeal in the November state elections. The state Department of Ecology director Laura Watson began the state's quest to link with the WCI last year , as regulators looked to the larger, more liquid market to potentially temper the higher-than-expected prices over the first year of the market in 2023. Washington Carbon Allowances (WCAs) for December 2023 delivery surged as high as $70/t last year, according to Argus assessments. But the state has clinched several wins for its program this year. State lawmakers were able to pass a bill to smooth out several areas of potential incompatibility with the WCI earlier this year, along with California and Quebec agreeing to move forward into formal linkage talks in March . But a repeal effort, initiative 2117, seeking to remove the state's cap-and-invest program dampened prices and forward movement on linkage since January. WCAs for December 2024 delivery fell to the lowest price to date for the program at $30.25/t on 4 March, according to Argus assessments, as uncertainty over the future of the program quieted market participation. State voters backed the cap-and-invest program in November with 62pc against the repeal effort, but months of uncertainty has cost the state time and linkage progress as the WCI awaited the November results. Additionally, while Washington started its own linkage rulemaking in April to align the program with changes planned for the WCI, finishing it requires the joint market first finalize its own changes. The linkage logjam has left market participants feeling that the state's momentum is stalled for the moment, even as perception of the state's eventual joining remains a question of "when" not "if." Ecology says it remains in communication with the WCI members and is evaluating the impact of California's new rulemaking timeline. California has indicated over this year that it does not intend to focus fully on linkage until its current rulemaking is complete. Ecology estimates it will adopt its new rules in fall 2025, with the earliest the state could expect a linkage agreement in late 2025. Washington must still complete further steps required by state law before any linkage agreement can proceed, including an environmental justice assessment and a final evaluation of a potential joint market under criteria set by its Climate Commitment Act, along with public comment. California and Quebec must also conduct their own evaluations to comply with respective state and provincial laws. If this timing works out, Ecology would be part of joint auctions starting in 2026. Compounding the process is the potential threat posed by incoming president-elect Donald Trump, who is likely to try to reverse major environmental regulations and commitments. Trump sought ultimately unsuccessful litigation in his first administration to sever the link between Quebec and California in 2019. The administration pursued the case on the grounds that California's participation violated federal authority to establish trade and other agreements with foreign entities under Article I of the US Constitution, which sets out the role of the federal and state powers in commerce and agreements with foreign powers. Both California and Washington have undergone preparations in recent months to gird themselves for a legal fight with the incoming administration, and that may add further scrutiny to linkage for both states going forward, said Justin Johnson, a market expert with the International Emissions Trading Association. "I think that it will require them to be more vigilant about the process they use and making sure they dot their i's and cross their t's because I think that there will be some folks in the federal administration who would like to see that not happen," Johnson said. By Denise Cathey Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: California dairy fight spills into 2025

24/12/24

Viewpoint: California dairy fight spills into 2025

Houston, 24 December (Argus) — California must begin crafting dairy methane limits next year as pressure grows for regulators to change course. The California Air Resources Board (CARB) has committed to begin crafting regulations that could mandate the reduction of dairy methane as it locked in incentives for harvesting gas to fuel vehicles in the state. The combination has frustrated environmental groups and other opponents of a methane capture strategy they accuse of collateral damage. Now, tough new targets pitched to help balance the program's incentives could become the fall-out in a new lawsuit. State regulators have repeatedly said that the Low Carbon Fuel Standard (LCFS) is ill-suited to consider mostly off-road emissions from a sector that could pack up and move to another state to escape regulation. California's LCFS requires yearly reductions of transportation fuel carbon intensity. Higher-carbon fuels that exceed the annual limits incur deficits that suppliers must offset with credits generated from the distribution to the state of approved, lower-carbon alternatives. Regulators extended participation in the program to dairy methane in 2017. Dairies may register to use manure digesters to capture methane that suppliers may process into pipeline-quality natural gas. This gas may then be attributed to compressed natural gas vehicles in California, so long as participants can show a path for approved supplies between the dairy and the customer. California only issues credits for methane cuts beyond other existing requirements. Regulators began mandating methane reductions from landfills more than a decade ago and in 2016 set similar requirements for wastewater treatment plants. But while lawmakers set a goal for in-state dairies to reduce methane emissions by 40pc from 2030 levels, regulators could not even consider rulemakings mandating such reductions until 2024. CARB made no move to directly regulate those emissions at their first opportunity, as staff grappled with amendments to the agency's LCFS and cap-and-trade programs. That has meant that dairies continue to receive credit for all of the methane they capture, generating deep, carbon-reducing scores under the LCFS and outsized credit production relative to the fuel they replace. Dairy methane harvesting generated 16pc of all new credits generated in 2023, compared with biodiesel's 6pc. Dairy methane replaced just 38pc of the diesel equivalent gallons that biodiesel did over the same period. The incentive has exasperated environmental and community groups, who see LCFS credits as encouraging larger operations with more consequences for local air and water quality. Dairies warn that costly methane capture systems could not be affordable otherwise. Adding to the expense of operating in California would cause more operations to leave the state. California dairies make up about two thirds of suppliers registered under the program. Dairy supporters successfully delayed proposed legislative requirements in 2023. CARB staff in May 2024 declined a petition seeking a faster approach to dairy regulation . Staff committed to take up a rulemaking considering the best way to address dairy methane reduction in 2025. Before that, final revisions to the LCFS approved in November included guarantees for dairy methane crediting. Projects that break ground by the end of this decade would remain eligible for up to 30 years of LCFS credit generation, compared with just 10 years for projects after 2029. Limits on the scope of book-and-claim participation for out-of-state projects would wait until well into the next decade. Staff said it was necessary to ensure continued investment in methane reduction. The inclusion immediately frustrated critics of the renewable natural gas policy, including board member Diane Tarkvarian, who sought to have the changes struck and was one of two votes ultimately against the LCFS revisions. Environmental groups have now sued , invoking violations that effectively froze the LCFS for years of court review. Regulators and lawmakers working to transition the state to cleaner air and lower-emissions vehicles will have to tread carefully in 2025. By Elliott Blackburn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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