Electric utility alliance to launch at Cop 28

Market: Electricity
09/11/23

A new international alliance focused on strengthening, modernizing and expanding power transmission and distribution lines is taking shape for launch at the UN's Cop 28 climate summit later this month.

"If we want to have more investment in renewables, we have to invest in modernizing and strengthening grid systems, in transmission and distribution lines," International Renewable Energy Agency (Irena) director-general Francesco La Camera told Argus. "This is crucial," he added on the sidelines of the regional energy summit of the Latin American Energy Organization (Olade) in Uruguay.

The new alliance is spearheaded by Irena, the World Economic Forum and Abu Dhabi's TAQA utility.

It currently includes 18 utilities in Africa, Europe and the Middle East, including major players like Denmark's Orsted, France's Engie, Saudi Arabia's Acwa Power and Spain's Iberdrola. The Chilean government could be the first in Latin America to sign on to the initiative.

Regional bottleneck

La Camera said the focus on transmission and distribution is the most critical issue in Latin America, which has abundant natural resources for renewables, but requires more robust transmission and distribution systems and new regulatory frameworks.

Government authorities from around the region agree that power lines are the bottleneck.

Edward Veras, executive director of the Dominican Republic's national energy commission, said distribution has been his country's most pressing issue in the energy sector. He said the government has improved generation and transmission capacity, but distribution remains a challenge.

The Argentinian government is working on new plans to "unclog" transmission lines in order to ramp up renewable participation in the country's grids, Florencia Teran, undersecretary for renewable energy, said. It has a plan for new public-private partnerships to build transmission lines and increase the use of distributed energy systems to take advantage of its bioenergy, solar and wind capacity.

In Guyana, the government is also focused on distributed energy, with plans for small solar and hydroelectric plants, including 0.75MW and 1.5MW hydroelectric plants currently out for tender.

Chief executive of the Guyana energy agency, Mahender Sharma, said the government was evaluating proposals for 33MW of solar power that it wants to bring on line in the next 12-18 months.

La Camera said private investment is critical, but international cooperation and funding from multilateral financial institutions will a;sp be needed.

"The private sector is financing generation projects, but it can't do both," he said. It "will require multilateral participation."

By Lucien Chauvin

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

News

31/12/24

Viewpoint: US coal supply may tighten

Houston, 31 December (Argus) — More US coal production cuts may be on the horizon, setting up thermal coal supply to potentially be lower than demand starting in late 2025. US coal producers have been scaling back mining operations since at least mid-2023 in response to lackluster demand. Market participants are continuing to contend with elevated power plant inventories following relatively mild winters and more competitive natural gas prices. Some producers are signaling more production cuts are coming in the next few months. As a result, the US Energy Information Administration (EIA) recently forecast the country's coal output in 2025 would fall by 7.2pc from this year to 472.3mn short tons (428.5mn metric tonnes), the lowest level in agency data going back to 1949. But US coal-fired generation and coal consumption is expected to grow modestly next year, to 643.7bn kWh and 409.4mn st, respectively, from 641.6bn kWh and 406mn st in 2024, because of greater electricity and industrial demand. Coal consumption for the electric power sector alone is expected to rise to 371.5mn st from an estimated 369.4mn st in 2024, EIA data show. Generators are expected to draw from their existing coal inventories for the majority of the year to meet the slightly higher electricity demand, potentially bringing power plant stockpiles down to more normal levels. Coal producers also are expected to have less inventory at mines and loadout facilities as volumes that had been deferred to 2025 are delivered. If the inventory withdrawals and expected slight increase in domestic consumption are coupled with higher export market prices and demand, "there could be an impetus for a slight ramp-up in domestic production, but currently, that prospect does not appear to be visibly on the horizon", EIA chief economist Jonathan Church said. For example, Argus assessments for calendar year 2025 API 2 coal swaps averaged $112.85/t from 1-24 December, compared with $104.19/t for all of December last year. The response from coal producers to any improvement in demand could be uneven, which could constrict competition and boost prices. While larger producers with longwall mining equipment, primarily in northern Appalachia and the Illinois basin, can somewhat efficiently resume or increase production, other companies may struggle to ramp up operations. Producers also may not have the financial support to increase coal output. A number of market participants expect smaller producers with higher-cost operations to be forced out of business as major banks continue to pull back on lending money to coal mining companies. In the nearer term, recent or planned coal mine closures could further limit supply. Alliance Resource Partners said in November that it intends to retire its central Appalachian coal-producing MC Mining complex in Kentucky, and the company has already cut operations to two of its four production units. Earlier in 2024, American Consolidated Natural Resources closed its Pride Mine in western Kentucky and Hallador Energy idled two small Indiana mines in February. Other producers have scaled back operations but kept mines open. Coal miners worked an average 45.5 hours/wk in October when not adjusted for seasonal factors, preliminary figures from the US Labor Department show. A year earlier, coal miners averaged 48.3 hours/wk. Producers also have to contend with an uncertain outlook beyond 2025, including an expected shift in environmental policies under president-elect Donald Trump, how new data centers will affect electricity demand, and timelines for installing new generation and transmission upgrades. Alliant Energy, Vistra Energy, Duke Energy and Louisville Gas & Electric and Kentucky Utilities are among utilities that recently announced plans to potentially delay retiring coal-fired generating units or plans to remodel coal units to co-fired natural gas and coal to try to meet load growth projections for the next few years. This could keep coal-fired generation and demand at least somewhat stable, but it may not provid long-term support. "To have increased coal demand, you would have to have load growth outpacing new supply," said Robert Godby, associate professor in the economics department at the University of Wyoming. He and others expect new renewable generation and transmission projects to eventually accommodate projected electricity demand growth. Increased load growth will be "at best just a reprieve from the ongoing downward trend in coal production and coal demand", Godby said. As such, producers may continue to try to limit output in 2025, which could partially raise domestic prices from current levels that straddle the line of profitability for many coal mining companies. But the increases will likely be modest as alternative energy sources are expected to continue to suppress demand for coal generation. By Anna Harmon Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Find out more

News

Viewpoint: Power demand could bolster RGGI allowances

31/12/24

News

31/12/24

Viewpoint: Power demand could bolster RGGI allowances

Houston, 31 December (Argus) — Regional Greenhouse Gas Initiative (RGGI) CO2 allowances in 2025 could get a boost from a projected increase in electricity demand, despite uncertainty over the RGGI states' ongoing program review. Allowance prices hit record highs this past year, particularly during the summer as high temperatures raised expectations for emissions, increasing compliance demand. The first three auctions of 2024 cleared at record levels, draining the cost containment reserve (CCR) — a mechanism where additional allowances are released to temper rising prices — during the March auction . Prices followed suit in the secondary market, reaching multiple all-time highs before peaking on 20 August, with Argus assessing December 2024 and prompt-month allowances at $27.82/short ton (st) and $27.31/st, respectively. The increases have been fueled by anticipated growth in electricity demand as states work to implement policies promoting electrification in the transportation, industrial and heating sectors. In New England alone, peak power demand is forecast to double from 27,000MW to 55,000MW by 2050, according to an Acadia Center report . But the biggest source of this demand — and the steady climb in RGGI allowance prices since late-2023 — is the rapid expansion of data centers, according to University of Virginia professor William Shobe, who studies emissions market and auction design. New CO2-emitting sources such as natural gas-fired plants must factor rising allowance prices into the future cost of electricity in the long-run, Shobe said. As prices rise, other cleaner sources of energy, such as offshore wind and small modular reactors, will become more competitive, he said. Review the review The member states of RGGI launched a review of the program in February 2021. As power demand creates a potential for a bullish RGGI market, the review remains a source of uncertainty for participants and volatility in the secondary market. The program review includes considerations for a more ambitious emissions cap plan beyond 2030. But it has faced a number of delays and was originally scheduled to wrap up last year . Member states have provided few updates on the status and timeline of the review, leaving participants and environmental groups alike on tenterhooks over how a finalized program review — and with it, an updated emissions cap plan — will affect the future supply of allowances. Participants "are always thinking about future scarcity", said Shobe. "The more information we can give them about the future path of scarcity (of allowances) now, the more efficient their own behavior can be." The latest updates were released in September. They included an emissions cap plan that combined two previously floated proposals where the allowance budget starts at about 70mn st, declining at a rate consistent with a zero-by-2035 goal from 2027-2033 and a lower rate consistent with a zero-by-2040 goal from 2033-2037. Member states are also considering adding a second CCR and eliminating the emissions containment reserve (ECR), a market mechanism designed to respond to falling prices by withholding allowances. The review is planned to end in early 2025. A draft rule with additional modeling was to be released in the fall, but there have been no updates regarding another change in timeline. RGGI has not responded to requests for comment. States in limbo The status of Virginia — which left RGGI in 2023 — and Pennsylvania as potential members is another point of uncertainty as those states' participation are under legal scrutiny in their respective courts. Virginia's Floyd County Circuit Court in November ruled that regulation enabling the state's exit from RGGI was unlawful since it was enacted without legislative approval. Governor Glen Youngkin's (R) administration intends to appeal to the Supreme Court of Virginia sometime in 2025, but has declined to specify when. While it is unlikely Virginia will rejoin RGGI in the interim, its participation would increase demand for allowances and put an "upward pressure on price", Shobe said. Much of this demand would be fueled by data center expansion, as northern Virginia is the largest market for data centers in the world, with 25pc of all reported data center operational capacity in the Americas and 13pc globally, according to a report by a state legislative commission. The Supreme Court of Pennsylvania is also reviewing a lower-court decision striking down CO2 trading regulation allowing the state to participate in RGGI. Governor Josh Shapiro (D) has reluctantly defended Pennsylvania's membership in the program as an issue of preserving executive authority, and Republican state lawmakers have been attempting to revive legislation that would cement the state's exit from RGGI. The state's high court could issue a decision sometime in 2025. But Governor Shapiro also proposed a state-specific power plant CO2 cap-and-trade program earlier this year — another development participants should keep an eye on. By Ida Balakrishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Viewpoint: Bearish year ahead for NOx markets

30/12/24

News

30/12/24

Viewpoint: Bearish year ahead for NOx markets

Houston, 30 December (Argus) — The Cross-State Air Pollution Rule (CSAPR) NOx allowance markets will likely face a bearish year in 2025, as the incoming administration of president-elect Donald Trump creates uncertainty over the fate of the latest federal regulation to curb emissions. The US Supreme Court halted implementation of the US Environmental Protection Agency's (EPA) "good neighbor" plan in June with a nationwide stay. This left an already stunted regulation to cut NOx emissions, a precursor to harmful ground-level ozone, obsolete for the foreseeable future. EPA finalized a plan in March 2023 to help downwind states meet the 2015 national air quality standards by setting tighter ozone season NOx caps on power plants covered by CSPAR as well as new limits for industrial facilities in more than 20 upwind states. But by the time the justices issued the stay, the number of covered states had already shrunk by more than half because of lower-court orders pausing implementation in 12 states. Prices for seasonal NOx allowances have flatlined and the market has been illiquid over much of 2024 because of uncertainty over how numerous legal challenges against the good neighbor plan would play out. Argus has assessed Group 2 allowances at $775/short ton (st) and Group 3 allowances at a record low $1,250/st since January. This could change, albeit at a slow pace, because EPA finalized an interim rule in November to comply with the nationwide stay. Power plants that had been covered by the good neighbor plan are now under less-stringent NOx budgets tied to older air quality standards, and the 10 states that had been participating in the Group 3 market prior to the stay are now reshuffled into Group 2 and a separate 12-state "expanded" Group 2 market. All that remains is… uncertainty In the new year, the market will wait to see how the Trump administration will deal with the good neighbor plan and the associated legal challenges in the US Court of Appeals for the DC Circuit and the US Supreme Court. Because of the stay, there is no hurry for the new administration to address the legal woes, and it is unlikely the DC Circuit will soon rule on the legality of EPA's rejection of state ozone reduction plans. The Trump EPA, following precedent of prior administrations, will likely ask the court to pause litigation until it decides whether to continue defending the plan, according to Jeff Holmstead, assistant administrator at the agency under former president George W Bush. The agency will likely revoke the plan at some point and replace it with a rule that is more "modest" and would not significantly affect allowance prices, he said. The EPA under Trump could ultimately decide that upwind states do not significantly contribute to interstate pollution, reversing a determination that has underpinned the good neighbor plan. That could lead to downwind states asking the agency to address specific sources that contribute to their air quality problems, said Carrie Jenks, executive director of Harvard Law School's Environmental and Energy Law Program. The Supreme Court is also hearing a case to decide the proper court venue for Clean Air Act disputes, which involves the good neighbor plan. The Trump administration likely will agree with various states and industry groups that say EPA's rejections of individual state plans are not a "nationally applicable" action and must be litigated in the regional circuit courts, but the Supreme Court is likely to continue the venue case, Jenks said. Oral arguments will likely be held early next year. It is also unclear how Lee Zeldin, Trump's pick to lead EPA will affect the regulation. Zeldin is a moderate, given his history, and will likely "not want to impose significant new burdens on fossil fuel power plants", Holmstead said. Trump's plans to downsize the federal bureaucracy could also affect future rulemakings, according to Jenks. "Nobody really knows what's going to happen," she said. As a result, market activity is likely to remain limited in the coming months as participants await legal and regulatory clarity. In addition, markets are likely to be oversupplied now that power plants are under lighter NOx caps. Most states in the seasonal NOx markets were well below their limits for the 2024 ozone season, despite a 9.2pc increase in cumulative emissions in the expanded Group 2. EPA will also allow some power plants to convert vintage 2021-23 Group 3 allowances to Group 2 or expanded Group 2 allowances, adding to supply. With low demand and a potential oversupply, seasonal NOx allowances could see prices fall . By Ida Balakrishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Japanese firms to develop 1.07GW offshore wind power

27/12/24

News

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.

News

Viewpoint: US gas market poised for more volatility

26/12/24

News

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.

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more