Genesis secures more gas to curb New Zealand shortages
New Zealand upstream firm and utility Genesis Energy has secured emergency gas supplies for its dual gas- and coal-fired Huntly power station on the North Island.
Genesis has secured 3.2PJ (86mn m³) of gas to allow the 400MW No.5 unit at Huntly to reach full capacity for the first time this winter, it said on 13 August, describing the electricity grid as facing "unprecedented pressure".
An agreement has been reached with Canadian methanol manufacturer Methanex, which will shut its Motunui plants in the North Island's Taranaki province until the end of October to allow for more gas-fired power generation, Genesis said.
The commercial arrangements regarding the gas transfer are structured to provide Methanex with a base price for each unit of gas delivered, with further incremental value shared between the parties depending on electricity pricing over the period, it said on 12 August. Methanex's 1.72mn t/yr plant in Motunui has paused production in the past, also diverting feedstock natural gas to support electricity generation in the winter of 2021.
The 953MW Huntly — New Zealand's largest power station by capacity and the country's only coal-fired unit, has been under significant strain as dry, cold conditions have led to increased demand during winter as hydroelectricity inflows remain low. New Zealand has also experienced light winds cutting expected wind-powered generation this winter, with Genesis planning coal imports for the first time since 2022 in response to lower domestic gas output and rapidly falling coal stocks.
LNG imports investigated
New Zealand energy minister Simeon Brown told parliament on 7 August his administration was investigating two separate options to ease the gas shortfall in the short to medium term.
Industry body the Gas Industry Company (GIC) is studying the feasibility of importing LNG, while also considering policies to increase investment in flexible gas-fired generation, Brown said. Data from upstream firms released earlier this year show a significant drop in proven plus probable reserves, falling from 1,635PJ to 1,300PJ, he added.
Gas production into open access pipelines was 58.8PJ during January-June, GIC said in its April-June quarterly report, 20pc down on 73.7PJ a year earlier, while gas-fired power demand grew by 10pc against April-June 2023.
New Zealand's National Party-led government is aiming to overturn a 2018 ban on new oil and gas exploration with legislation to be introduced to parliament later this year.
Related news posts
About 42pc of US Gulf oil output still shut on Francine
About 42pc of US Gulf oil output still shut on Francine
New York, 13 September (Argus) — About 42pc of oil output in the Gulf of Mexico was still shut-in on Friday, just days after Hurricane Francine passed through the region. Around 732,316 b/d of offshore oil output was off line as of 12:30pm ET Friday, according to the Bureau of Safety and Environmental Enforcement (BSEE), while 973.20mn cf/d of natural gas production, or 52pc of the region's output, was also off line. The volume of crude production shut in rose slightly from yesterday, by about 2,000 b/d, while curtailed gas output fell. Operators evacuated workers from 144 platforms this week ahead of the storm. Shell said today it is ramping up production at its Appomattox, Mars, Vito, Ursa and Olympus platforms after resolving downstream issues. However, the company's Perdido, Auger and Enchilada/Salsa assets remain shut-in due to other downstream issues. And drilling remains on hold at its Whale asset, which is scheduled to begin operations later this year. The port of New Orleans resumed all normal operations Thursday evening. Preliminary damage assessments showed no significant damage to facilities or infrastructure, port officials said, while onshore refinery operational issues appear to be minor . By Stephen Cunningham and Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
India’s higher LNG regas rates receive customer flak
India’s higher LNG regas rates receive customer flak
Mumbai, 13 September (Argus) — Indian LNG terminal developers led by state-run Petronet LNG and Shell are charging some of the highest rates among the world to regasify LNG, prompting consumers to complain, raising concerns over the government's plan to more than double the share of gas in the country's energy mix to 15pc by 2030. Petronet is charging as much as Rs62.91/mn Btu ($0.75/mn Btu) to regasify the fuel received at the 17.5mn t/yr Dahej terminal on the west coast, the country's largest such facility, according to consumers using the import facility. Coupled with the annual escalation in charges, the rates are "unsustainable in the longer-run," a person who did not wish to be identified said. "Going by the 5pc increase in regas rates every year, by 2030, regas rates could become Rs84/mn Btu ($1/mn Btu), which is not justified," the source added. State-run Petronet has lifted regasification rates by 5pc in recent years. "The 5pc hike in regas rates every year may eventually have to stop in the coming years before it reaches a dollar," an equity analyst at a foreign investment bank said. Shell is also charging similar rates at its 5.2mn t/yr Hazira LNG import facility on the west coast at $0.75/mn Btu, industry sources said. Both Dahej and Hazira are well connected to consumption centres by pipelines and operate year-round, unlike many of India's other terminals which suffer from lack of a breakwater facility or weak pipeline connectivity. Higher regas prices account for the lower usage levels in other terminals, because the country's overall LNG imports are lower than major importers like China or Japan, market participants say. India's regasification rates are much higher compared to terminals in the Europe. The 9.2mn t/yr Gate terminal in Netherland charges around $0.35/mn Btu for unloading and regasification, while Spain is much lower. Regasification rates in Japan LNG terminals are around $0.5/mn Btu, while rates at terminals operated by Jera, like the 22.9mn t/yr Futtsu LNG facility, are much lower, according to market participants. Regasification rates in China, however, are also higher, on a par with India as PipeChina's eight LNG terminals, including the largest 12mn t/yr Tianjin terminal in north China, and 6mn t/yr Dalian terminal in Liaoning. These are charging $0.7-1.3/mn Btu for unloading and regasification, sources say. Regas rates across the world are mostly determined by market forces based on demand fundamentals compared with fixed prices charged by Indian terminal operators. But record regasification rates have not stopped city gas utilities and industries from using Petronet and Shell's terminals to import the fuel, enabling Petronet to operate Dahej at around 109pc in April-June, a record for the facility, according to oil ministry data. Hazira, which in the past has operated at over 80pc, operated at 46.5pc in the second quarter. Capacity usage at LNG terminals in Europe, China and Japan are mostly in the range of 30-50pc, and the rest of India's five terminals with a combined 25mn tons a year in capacity operate at 20-40pc of that. Judging by deliveries in January-July this year, India's LNG imports stood at 16mn t, compared to an annual installed import capacity of 47.7mn t. Strategic location Importers in the country have little option of switching to other facilities because of the strategic location of Dahej and Hazira, which are well connected by major pipelines to the country's western region — where consumption is strong. The cost structure breakdown for a customer comes to $11.62/mn Btu at the Dahej terminal, which is calculated based on a delivered LNG price at $10/mn Btu, custom duty of 2.75pc at $0.275/mn Btu, regas price at $0.76/mn Btu, system used gas at $0.07/mn Btu and zone 1 pipeline tariff at $0.51. Tariffs under zone 2 are $0.95/mn btu and zone 3 is at $1.27/mn Btu. The zone 1 tariff is application for pipelines defined as up to 300km from the terminal, followed by between 300-1,200km for zone 2 and zone 3 more than 1,200km. Regulatory scrutiny Weak capacity utilisation levels in India's LNG terminals have attracted the attention of India's Petroleum and Natural Gas Regulatory Board (PNGRB), as it issued a draft proposal for enhanced regulatory control earlier this year. The draft regulations state the PNGRB must approve new facilities or capacity additions, review regasification fees and approve setting up pipeline infrastructure for regasified LNG. Terminal operators are reluctant to share information with the regulator. Total Adani, operator of the 5mn t/yr Dhamra LNG terminal on the east coast, said "requirement to share commercially sensitive information" such as project costs, regasification tariffs and capacity allocation are "not consistent" with the PNGRB Act. "An authorisation regime for LNG terminals may indeed negatively impact healthy competition and create monopolistic behaviour by the existing terminals." Each project would require a certification of registration by PNGRB, and may even face penalties if there are any start-up delays. Developers will also need to publicly disclose their regasification tariffs and other charges for transparency. By Rituparna Ghosh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Colombia advances moves to end coal production
Colombia advances moves to end coal production
Bogota, 13 September (Argus) — The Colombian government has identified areas in thermal coal rich parts of the Cesar and La Guajira provinces as special mining districts where coal production may eventually be replaced with operations meant to aid the transition to cleaner energy sources, deputy minister of mines Johana Rocha said on 12 September. The country has selected five areas in Cesar and three areas in La Guajira to be subject to Colombian president Gustavo Petro's decree issued on 2 August to create 16 special mining districts for diversifying production. The districts that have been selected include areas where Drummond, Cerrejon and CNR have coal mining operations and where Glencore subsidiary Prodeco used to mine. Anticipating the downturn in international coal demand, the Petro administration is looking at how to convert mining areas to other uses. Cesar and La Guajira also have the ability to be used for producing renewable energy, tourism and production of other minerals in high need such as silicon and agriculture, Rocha said. The Ministry of Mines will soon declare some of the areas as strategic mining areas that will be auctioned before the end of Petro's term in August 2026, Rocha said. The areas contain high grades of ferro silicon and polysilicon needed for production of solar panels and microchips. The ministry has held 20 separate meetings with local people in Cesar province. But Colombia will not convert the special mining districts until existing lease agreements with producers expire, Rocha said. "We want these coal licenses to continue operating under the contractual terms that they have. In the meantime, we will look at how we can supplement other income for those territories that have a high dependence on coal," Rocha said. Colombia's policy also could change under future presidential administrations. Drummond's El Descanso coal concessions expire in 2032. The company's La Loma lease ends in 2039. Drummond Colombia president Jose Miguel Linares told Argus two weeks ago that the company is interested in extending the El Descanso coal project for an additional 30 years. The company's three mines in Colombia have measured coal reserves that exceed 2bn metric tonnes. On the other hand, Glencore has laid out plans to progressively close Cerrejon by the time current mining concessions expire in 2034. Colombia's coal production could end by 2040 under a scenario of a gradual energy transition, Alvaro Pardo, the director of the Colombian mining agency, ANM recently said. By Diana Delgado Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Argentina's big energy hopes face reality
Argentina's big energy hopes face reality
Houston, 13 September (Argus) — Argentina has the reserves, investor interest and now most of the regulatory framework to potentially triple its oil and natural gas output by the early 2030s, but ensuring success will require much more, producers in the country said today. "Argentina has tremendous production potential," said Chevron's general manager of its Argentina upstream unit Jim Navratil, speaking at the 4th Shale in Argentina conference in Houston, Texas. But the country needs to give more assurances that contracts and investment regimes will be honored, and make it easier to move capital, he added. Chevron produces more than 100,000 b/d in Argentina. The South American country is banking mostly on its Vaca Muerta unconventional oil and gas deposit that holds an estimated 308 trillion cf in natural gas and 16bn bl of oil reserves. Output from Vaca Muerta alone could rise to more than 1mn b/d from about 390,000 b/d now by 2030, the government and outside forecasts estimate. This comes after Argentina's overall oil output hit a 20-year high in July of 682,000 b/d and 151.7mn m³/d of gas, a 21-year high. To further that increase, Argentina's government under President Javier Milei has passed massive changes to its financial and energy regulatory framework. The changes are aimed at ending the costly policy of energy sovereignty that "has hurt us" and instead making the system financially self-sustaining and open for investment, Argentina's energy minister Eduardo Rodriguez Chirillo said at the same event. Not quite there Optimism has grown, but more work is pending, producers say. "We are supporting [the government's changes] and cheering, but we are still not quite there yet", Equinor's Vaca Muerta asset manager Max Medina said. Equinor has interest in one exploration license and one producing block in Vaca Muerta, with about 59,000 b/d of production. Argentina should add more incentives for producers and those companies must place more attention on safety, emissions reductions and compliance as the basin expands, Medina said. Workforce development is also a challenge in Neuquen, the province where Vaca Muerta is centered, which has a population of about 700,000. "The challenge to get to 1mn b/d [in Vaca Muerta] is going to be much more difficult, especially on the human resources side," Medina said. Technological and cost constraints also present difficulties, said Pan American Energy's upstream managing director Fausto Caretta. The company hopes to triple its oil production in the Neuquina basin asset and in the Neuquen province in coming years, from 6,000 b/d of oil now. But restrictions in Argentina on importing needed technology have also delayed needed improvements, Caretta said, although rules are easing. This has contributed to well drilling costs in the Vaca Muerta region being about 20pc higher than in the Permian basin in Texas, to which it is often compared, and completion times remain about 30pc more. Financing multiple proposed infrastructure projects will also be key. "The challenge is how to get that oil to markets," said Julian Escuder, country manager for Pluspetrol, which produces about 21,000 b/d of oil in Argentina. "We need infrastructure." Despite the hurdles, Argentinian officials are assuring investors that changes are here to stay, unlike recent abrupt shifts in energy policy in Colombia and Mexico to focus on state-centered models. Neuquen governor Roland Figuero assured attendees that energy policy is stable in his province. "That has been the same for years," he said, adding that Vaca Muerta "is the last big opportunity that Argentinians have to do things well" in energy. By Carla Bass 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