NGS’ NG/LNG SNAPSHOT – Aug 16-31, 2023
City Gas Distribution & Auto LPG
Gruner to set up 100 bio-CNG plant in FY24 across country
NEW DELHI: Gruner Renewable Energy (GRE), a start-up in the renewable sector, will set up 100 bio CNG plants across India, with a target turnover of Rs 1,000 crore by the end of this fiscal. The company recently collaborated with BioEnergy Germany, a German company that provides technology and engineering design for biomass-based gas plants, and so far it has received 42 project orders to establish biogas plants in the country.
“We have so far secured 42 firm contracts for building biogas plants and many more are in the offing,” said Utkarsh Gupta, founder and CEO of Gruner Renewable. India aims to build 5,000 commercial units and create 15 MMT of CBG (Compressed Biogas) by 2024–2025.
At the Global Conference on Compressed Biogas (CBG) held in April, petroleum minister Hardeep Singh Puri said India has set a target to increase the share of gas in the energy mix up to 15% by 2030 to transform India into a gas-based. Currently, it imports nearly half the natural gas used in India.
Recently, the company announced the first Napier grass bio CNG plant in the country.
AG&P inaugurates CNG station at Ooruttambalam
In a notable development, AG&P Pratham has inaugurated its tenth compressed natural gas (CNG) station in Thiruvananthapuram district at Ooruttambalam. With this, there are 29 CNG stations in the Alappuzha-Kollam-Thiruvananthapuram geographical area (GA).
AG&P Pratham holds 25-year exclusive rights from the Petroleum and Natural Gas Regulatory Board to develop city gas distribution infrastructure and supply gas in more than 278,000 square km area across Rajasthan, Kerala, Andhra Pradesh, Karnataka and Tamil Nadu. This involves setting up more than 1,500 compressed natural gas stations and 17,000 inch-km of pipelines.
CNG Sales Volume Grows 51% in 6 Months to March
New Delhi : City gas companies have grown their super-profitable CNG sales volume at a faster rate in the past two years than the less profitable segment of gas supplies meantforhomes.
City gas distributors sold 19.4 million metric standard cubic meters a day (mmscmd) of CNG in six months to March 2023, up 51% from October 2020 to March 2021 period, oil ministry data showed. In the same period, the sale of piped natural gas (PNG) meant for cooking at home rose 11% to 2.9 mmscmd.
Sales to commercial customers that includes hotels and malls, dropped 25% to 0.7 mmscmd, while those to industries fell 38% to 10.3 mmscmd as high imported gas prices forced them to switch to alternative fuels.
As a result, the share of CNG in city gas distributors’ overall sales sharply increased to 58% in two years from 39% in the six months to March 2021. The share of sales to industrial customers fell from 50% to 30%. The share of sales to households, or domestic PNG, rose marginally to 8.7% from 8%.
City gas companies get price-controlled domestic natural gas, which they can sell at market rates as CNG and domestic PNG. They are mostly monopolies in their licensed areas, giving them pricing power and fat margins. CNG and domestic PNG prices are mainly influenced by the rates of alternative fuels such as petrol and LPG cylinders. Petrol is heavily taxed and mostly moves in line with international prices, while CNG and domestic PNG are very lightly taxed.
At March-end, the number of CNG stations in the country was 5,665, up 83% in two years. Domestic PNG customers expanded by 41% to 1.1 crore in the same period. Delhi is the largest market for CNG, while Gujarat is the largest market for domestic, commercial, and industrial customers of natural gas.
City gas distributors mostly import liquefied natural gas (LNG) to supply commercial and industrial customers. Extraordinarily high prices of natural gas in international markets in the past two years forced industrial and commercial customers to switch to alternative liquid fuels such as LPG and fuel oil.
India’s LNG imports fell to 19.9 million metric tonnes (mmt) in the last fiscal year, down 22% from 25.6 mmt in 2019-20.
Expansion of CNG stations across the country, increased availability of CNG cars, and high petrol prices have combined to boost CNG sales in the country, an industry executive said.
Dharmendra Pradhan inaugurates Odisha’s first natural gas based crematorium
Union minister Dharmendra Pradhan on Friday inaugurated Odisha’s first natural gas-based crematorium in Bhubaneswar. The project, undertaken by the GAIL (India) Limited under its Corporate Social Responsibility (CSR) initiative, is aimed at reducing air pollution.
Policy Matters/ Gas Pricing/ Others
PNGRB re-evaluating performance bank guarantee rule
New Delhi : The Petroleum and Natural Gas Regulatory Board (PNGRB) is re-evaluating a rule on performance bank guarantees for city gas companies that has benefited the likes of Adani Gas, Indian Oil and GAIL.
The current rule allows the downstream regulator to reduce the performance bank guarantees (PBG) required of city gas licensees to 40% of the initial amount after they have completed their minimum work programme (MWP). Recently, PNGRB allowed a reduction in the PBG by GAIL Gas Ltd and Indian Oil Adani Gas Pvt Ltd after the two entities completed their MWP in their respec tive licensed areas of Bengaluru and Daman.
After having allowed some city gas companies to benefit from this rule, the regulator is now having a rethink as several companies, which have completed MWP, have queued up with their requests for PBG reduction, according to people familiar with the matter. “A differentiated approach is needed,” a source close to PNGRB said. Companies that have submitted high-value performance bonds need some relief as their increased financial cost could escalate cost for gas consumers, he said, adding that the companies that have submitted small amounts of PBG do not have a strong case for relief. “How will PNGRB enforce the licensing rules for the rest of the contract period if their PBG is reduced to a very small amount?” he added. The regulator can encash PBG if city gas companies fail to lay infrastructure or provide quality service to customers during the license period.
In a few past bidding rounds, city gas licences were awarded to companies that offered the highest
amount of PBG. In many of those cases, winners offered hundreds of crores worth of PBG. But as they started rolling out infrastructure and services, the high PBG added to their cost and affected their profitability.
In many other licensing rounds, PBG was not the criteria for winning licences and so the amounts of PBG offered were small, something around Rs 15-20 crore. Now the winners in these rounds too want to benefit from the PNGRB rule of PBG reduction following the completion of MWP. This has prompted the regulator to relook at the rule. The government wants to increase the share of natural gas in the country’s primary energy mix to 15% by 2030 from the current 6%. The rapid expansion of city gas distribution is a key government strategy to increase gas penetration in the economy.
Govt. unveils Green hydrogen standards, sets emission thresholds for production
With this notification, India becomes one of the first few countries in the world to announce a definition of Green hydrogen
The government on Saturday unveiled Green hydrogen standards and included electrolysis and biomass-based methods in its definition.
In a significant move for the progress of the National Green Hydrogen Mission, the government has notified the Green Hydrogen Standard for India, the New and Renewable Energy Ministry said in a statement.
The standards issued by the Ministry outline the emission thresholds that must be met in order for hydrogen produced to be classified as ‘Green’, i.e., from renewable sources.
The scope of the definition encompasses both electrolysis-based and biomass-based hydrogen production methods, it stated.
After discussions with multiple stakeholders, the Ministry of New & Renewable Energy has decided to define Green Hydrogen as having a well-to-gate emission (i.e., including water treatment, electrolysis, gas purification, drying and compression of hydrogen) of not more than 2 kg CO2 equivalent / kg H2.
The notification specifies that a detailed methodology for measurement, reporting, monitoring, on-site verification, and certification of green hydrogen and its derivatives shall be specified by the Ministry of New & Renewable Energy.
The notification also specifies that the Bureau of Energy Efficiency (BEE) under the Ministry of Power shall be the Nodal Authority for accreditation of agencies for the monitoring, verification and certification for Green Hydrogen production projects.
The notification of the Green Hydrogen Standard brings a lot of clarity to the Green Hydrogen community in India and was widely awaited, it stated.
With this notification, India becomes one of the first few countries in the world to announce a definition of Green Hydrogen.
UP bioenergy policy promotes bio-CNG and CBG units to curb pollution
The Yogi government in Uttar Pradesh is taking proactive steps to address the environmental impacts of stubble burning through sustainable agricultural practices. With a focus on reducing pollution caused by burning crop residues, the government plans to provide 17 lakh farmers with bio-decomposers, facilitating the conversion of paddy straw into bio-compost. Chief Minister Yogi Adityanath’s comprehensive approach includes penalties, awareness campaigns, and innovative strategies.
The Uttar Pradesh State Bioenergy Policy 2022 outlines incentives for agriculture residue-based bio-CNG and bio-CBG units. These efforts align with the government’s push for agricultural sustainability and involve setting up these units in every district. Indian Oil is set to launch a Rs 1.6 billion plant in Gorakhpur, which will use various materials including crop residues, rice husk, and cow dung to produce compost manure. This initiative not only adds value to crop residues but also generates local employment opportunities.
Educational programs for farmers aim to raise awareness about the negative consequences of stubble burning, while research highlights the nutrient-rich potential of crop residues. Composting residues in the field enhances soil health, reduces fertiliser costs, and combats global warming effects. The Gorakhpur Environmental Action Group highlights the loss of valuable nutrients and carbon due to stubble burning.Dr. BK Singh underscores the economic value of crop residues, emphasising the need to avoid their wasteful burning. Retaining crop residues has multiple benefits, including moderating soil temperature, enhancing water retention, and conserving water resources. The alternative of deep ploughing and composting aids in decomposition and improves soil health, providing a sustainable solution to stubble burning.
Haryana to roll out ‘right of use and right of way’ policy for natural gas infrastructure
The decision was announced after a meeting held to expedite the deployment of CNG and PNG infrastructure across the state. Haryana is set to launch a “right of use and right of way” policy aimed at facilitating the smooth establishment of compressed natural gas and piped natural gas distribution networks across the state.
Presiding over a review meeting convened by the Department of Industries and Commerce on Monday, Chief Secretary Sanjeev Kaushal directed officials to inspect the industrial units not using approved fuel and to take strict action against the erring ones.
As many as 632 industrial units in Haryana have adopted gas as their fuel choice and 257 of them are operating within the industrial zone. Additionally, 403 units in the industrial sector are operating with approved alternative fuels.
“State-Level Apex Monitoring Committees shall be constituted to oversee the strategic implementation of CNG/PNG infrastructure projects. This committee will include representatives from the departments of industries and commerce, urban development, and local bodies. Elevating operational efficiency, officers shall launch an online service module designed for Right of Way and Right of Use processes in CNG and PNG pipeline installation within a fixed timeline. This digital innovation aims to infuse convenience into procedural intricacies,” Kaushal said in a press statement.
A draft standard operating procedure is being developed and feedback has been sought from 10 departments to ensure its refinement, the chief secretary said. “Focus of these inputs is directed towards seven specific aspects: forms, document checklist, applicable processing fees for Right of Way (RoW), applicable fee for Right of Use (RoU) – leasehold right, proposed timeline for both approval and Deemed approval, process flow diagram, certificate template for online auto-generation, and the tracking, monitoring, and MIS dashboard,” he added.
Status of work in various cities across Haryana
Faridabad: Pipeline-laying and connection provisions are underway in numerous industrial areas such as Gurukul, DLF Industrial Sectors and NIT Industrial Area, among others.
Gurugram: Actively progressing with connection provision for multiple industrial clusters including Sector 33/34, Behrampur, IMT Manesar, Udyog Vihar, and others. Hisar shows advancement in sectors including Sec 9-11 (IDC), Sec 27-28 and Delhi Road
Rohtak: Pipeline-laying and connection provision for diverse industrial clusters, including IMT Rohtak, Kheri Sadh, IDC and Kutana have been completed.
Yamunanagar: Work is ongoing across industrial areas like Sector 33/34, Behrampur, IMT Manesar and Udyog Vihar.
Sonipat: Pipeline-laying and connection provision have been completed for industrial clusters such as Rai, Kundali, Bhalgarh, Nathupur, Murthal, Piyu Maniary, Saboli and Sonipat city.
Fatehabad and Sirsa: Effectively completed pipeline-laying and connection provision for various industrial clusters.
Ambala: In the process of connection provision for crucial industrial zones including the SAHA Industrial Area and the HSIIDC Industrial Area
Kurukshetra: Connection provision for various sectors and industrial zones in progress.
Kaithal: Connection provision complete.
Karnal: Pipeline-laying and connection provision have been completed for multiple industrial clusters.
Rewari: Work is steadily progressing in industrial clusters in Rewari, Bawal and Dharuhera.
Govt hikes ethanol prices for second time in 15 days, raises it by ₹3.71/litre
In a span of 15 days, distilleries have got a second hike in rates of ethanol purchased by oil marketing companies (OMCs) as the government does not want the target of achieving 12 per cent blending to be disrupted in any way after the Food Corporation of India (FCI) halted supply of subsidised rice.
In a notification, the government has raised prices of ethanol made from damaged/broken rice and maize by ₹3.71/litre with immediate effect to help distilleries continue production, official sources said.
Ethanol made from damaged/broken rice was increased by ₹4.75/litre from August 7 and from maize by ₹6.01/litre. After Tuesday’s upward revision as “additional incentives”, ethanol prices stand at ₹64/litre (from damaged rice) and ₹66.07/litre (from maize), up by 15-17 per cent from the rates fixed for the season. Until July 31, the OMCs had achieved 11.77 per cent blending since the ethanol season started in December 2022, industry sources said. The government has shortened the current ethanol season to 11 months and from the 2023-24 season, it has been changed to run from November to October.
Out of 21.25 crore litres contracted by OMCs in current season to buy from grain-based plants and to be produced from damaged rice, distilleries have supplied only 9.52 crore litres whereas the season will end in October 31. The current decision to hike rates may help the distilleries to speed up manufacturing and supply the whatever possible out of remaining 11.73 crore litres during August-October, sources said.
Many distilleries stopped operation in July after the FCI stopped issuing rice and if they do not operate during August-October, there is a chance of fall in blending rate from current level, industry earlier informed the government demanding the mid-season price revision.
Acting on the industry’s apprehension, an inter-ministerial group was constituted to recommend revised ethanol prices for next season in view of the expected higher availability of sugarcane that may increase diversion towards ethanol. The panel was also tasked to recommend if any incentive in prices of ethanol is required mid season.
In terms of sugar, the Food Ministry expects about 5.5 million tonnes (mt) may be diverted towards ethanol against about 4 mt last season. The sugar industry is more conservative and has pegged the diversion at 4.5 mt. Actually, sugar is not diverted to produce ethanol, which is made out of molasses (a by-product of sugar) or sugarcane juice/syrup. The diversion estimate is based on how much quantity of sugar could have been produced from the same quantity of sugarcane that gets diverted towards ethanol.
From mid-July, FCI has stopped supplying ₹20/kg rice supplied to produce ethanol, which is attributed to the political controversy created due its withdrawal of approval within 24 hours with regard to supply of rice to Karnataka for human consumption at ₹31/kg, citing insufficient availability in the Central pool.
Electric Mobility/ Hydrogen/Bio-Methane
Many bumps on the road to green hydrogen
Today, the refiners and fertiliser manufacturers get grey hydrogen at around $ 2.5 a kg, if not cheaper. L&T, the Indian engineering and construction major, said it would invest $ four billion in the green-hydrogen sector. Many other companies, such as ACME and JSW have made similar announcements. So, a big hype around is building up in the country.
So far, 49 projects totalling 3.5 million tonnes of green hydrogen and 19 projects for electrolyser manufacture have been announced.
It is time for a reality check. The big question to all these companies is, where will you sell the green hydrogen?
The world can be divided (only) into two markets – domestic and international.
The domestic market consumers are mainly refineries and fertiliser companies, steel and other sectors may come in as consumers later. Today, the refiners and fertiliser manufacturers get grey hydrogen at around $ 2.5 a kg, if not cheaper. What is the incentive for them to buy green hydrogen that costs not less than $ 4 a kg today? The government initially said that it would bring in a ‘green hydrogen purchase obligation’. Such a purchase obligation is there for renewable energy and the RPO mechanism has worked well for the sector, helping to build demand.
Now it is clear that the government is not going to bring in any such mandatory purchase obligation for green hydrogen. In the absence of a mandatory obligation, it is hard to see refiners and fertiliser units voluntarily coming forward to buy the expensive green hydrogen. Even if you assume that they may, it is hard to believe that a green hydrogen producer would take such a huge leap of faith as to invest billions of dollars just trusting the good intentions of the consumers.
Nor is there a prospect of green hydrogen prices coming down, because the prices of renewable energy – a key input for green hydrogen—are slated to go up, rather than come down, thanks to the change of method of capacity auctions from ‘reverse bidding’ to ‘closed bidding’ for wind, and the drive to procurement of India-made cells and modules, for solar. Today, renewable energy is available to electricity utilities around ₹2.80 a kWhr; this is set to rise to ₹3.20 or 3.30. So, don’t expect green hydrogen prices to come down.
In conversations with journalists, green hydrogen companies say that they would set up manufacturing facilities that would cater to the international market and turn their sights to the domestic market as and when it develops.
So, that brings us to the international market.
There are only two major consumption centers globally – the US and Europe. The US market is practically closed to green hydrogen produced outside the country, because the Inflation Reduction Act makes local production so cheap as to ward off any competition from abroad. Here is an insightful quote from Kapil Bansal, EY India Energy Transition and Decarbonization Partner: “ After introduction of IRA, US is positioned to be one of the lowest green hydrogen production cost regions in the world, at $0.5 to $1.5 per kg of green hydrogen, which is going to substantially boost the demand in the US, potentially growing to about 30 MTPA by 2030 to 35, setting a precedent for other countries to follow.”
Now look at Europe, which has adopted very liberal standards for green hydrogen. The big debate in the world today is about what exactly “green” hydrogen is. Ideally, ‘green’ should be defined as so-many kg of associated carbon dioxide emissions per kg of hydrogen produced, but there is no such global definition. The Green Hydrogen Organisation, a Switzerland-based not-for-profit body that wants to promote green hydrogen, gives its recommendation as “not exceeding one kg of CO2 per kg of hydrogen produced”. Against this, the European Union has adopted a standard that translates to 3.2 kg of CO2. The Indian government has not prescribed a number for associated emissions for green hydrogen but has made it clear that the electricity would have to come from wind, solar or nuclear energy.
This makes Indian producers uncompetitive against those in, say, the Middle East, where natural gas is available and a little of gas-based power could be used to produce green hydrogen. Indian green hydrogen companies themselves want to put up production facilities in the Middle East to take advantage of this situation. A good example is that of ACME, which is putting up a large green hydrogen plant in Oman and has recently secured REC funding for it.
Furthermore, countries like Australia, that already have LNG linkage to Europe, are better positioned to supply green hydrogen than India. Australia has both renewable energy and natural gas in abundance and well-established supply chains to cater to Europe.
With all this, breaking into the European market is also not easy for Indian companies.
The Indian green hydrogen campaign is therefore born-jinxed. The only way to break the jinx is for the government to create assured demand by prescribing, as it once promised, a green hydrogen purchase obligation. But the government is in no mood to do so.
Swedish firm to double capacity in India as EV demand grows
Swedish industrial manufacturing company, Atlas Copco, is doubling its capacity in India and having nearly exhausted capacity at its two existing plants in Pune, in Dapodi and Chakan, has started construction on a third manufacturing facility in Talegaon.
Atlas manufactures compressors, vacuum solutions, generators, pumps, power tools and assembly systems, products used by EV battery assembly lines, semiconductor makers and alternative fuel systems, including CNG, hydrogen, methane and the solar industry.
It is stepping up production to meet growing demand from the EV mobility, hydrogen and semiconductor industry. The company is also planning two acquisitions to further expand its business in the country.
Philippe Ernens, president, Oil-free Air division, Atlas Copco, said they are already supplying to all major semiconductor makers across the world and are engaging with these for the Indian market foray. “The company is a leading supplier of CNG pumps in the country and this technology base would be the same for adopting the hydrogen and methane segment,” Ernens said.
Compressors account for around 70% of Atlas’s business in India.
The new facility in Talegaon, expected to be completed by the second quarter of 2024, would increase Atlas’ capacity by 170% and grow its R&D test facility capacity by 700%.
The Rs 140 crore plant will make high-end air and gas compressor systems for both the Indian market and for export purposes. The Chakan plant will be focused on high-volume products. This expansion would take care of the company till 2030 and they would then focus on the next phase of expansion.
The company is also planning to grow inorganically. Frans Van Neikerk, managing director, Atlas Copco India said last year, they acquired HHV Pumps, a Bengaluru-based company that designed and manufactured vacuum pumps and systems in India. Neikerk said they have two more acquisitions lined up in the vacuum pumps space.
These vacuum pumps are used for chemical and pharmaceutical industries, electrical power equipment, general industry, and rotary-vane pumps are used for manufacturing, refrigeration and air-conditioning. The acquired business has been integrated into the Industrial Vacuum Division within the Vacuum Technique Business Area.
Atlas Copco had a turnover of Rs 4,000 crore in India FY23 and 20% of the invoicing was exports. The company said it was reporting double-digit growth in the last three years and would be continuing this growth momentum for the next three years.
Indian Oil, L&T, ReNew form JV for green hydrogen projects
A joint venture of Indian Oil Corporation, L&T and ReNew to focus on green hydrogen projects has been incorporated with the three partners investing ₹1 crore each in its authorised capital.
The JV company GH4India Private Ltd., incorporated on August 25, has been formed for the purpose of development of green hydrogen and its derivatives, including green ammonia and methanol, besides production assets and associated renewable assets through any model of ownership and operatorship, IOC and L&T said in separate filings on Saturday.
In April 2022, the three companies had signed a binding term sheet for formation of the JV company to develop the nascent green hydrogen sector in the country by tapping into the expertise of L&T in designing, executing and delivering EPC projects, that of Indian Oil in petroleum refining and ReNew’s expertise in offering and developing utility-scale renewable energy solutions.
Natural Gas / Transnational Pipelines/ Others
Iran: Iran inaugurates last phase of mega-gas field
TEHRAN: Iranian President Ebrahim Raisi inaugurated on Monday the last phase of the South Pars gas field, one of the world´s largest natural gas condensate field and the country´s biggest. Iran shares the gas field with energy giant Qatar and there are 24 platforms on the side of the Islamic republic which has been developing it in the Gulf since the 1990s.
Oil Minister Javad Owji said around 50 million cubic meters of gas will be extracted daily from phase 11 of the project “after the completion of the wells”, during a ceremony in the southern port city of Asalouyeh broadcast live on state television.
Raisi meanwhile complained that foreign companies, including French energy giant Total, “had not fulfilled their obligations to complete the 11th phase of South Pars”, leaving Iranian experts to do the job.
Total was due to develop phase 11 of South Pars along with China´s National Petroleum Corporation (CNPC) and an Iranian firm, under a 2017 deal worth $4.8 billion.
A year later Total withdrew from the project after then US president Donald Trump unilaterally pulled out from the landmark 2015 nuclear agreement and reimposed sanctions on Iran. In 2019, Tehran announced that China had also abandoned the project. Iran has the world´s second largest gas reserves, after Russia, and the world´s fourth largest oil reserves.
Malaysia: Shell launches Timi gas production
A unit of LNG giant Shell has started gas production at its Timi platform in Malaysia under the SK318 production sharing contract. Sarawak Shell Berhad operates the SK318 PSC with a 75 percent stake, while other partners include Petronas and Brunei Energy Exploration that have 15 percent and 10 percent participating interests, respectively.
In August 2021, Shell took a final investment decision on its Timi gas development located 200 kilometers off the coast of Sarawak, Malaysia.
Timi sweet gas field is located at about 252 km north-west of Bintulu, Sarawak, the home of the Petronas-operated LNG complex.
Moreover, Timi features Shell’s first wellhead platform in Malaysia that is powered by a solar and wind hybrid power system.
This unmanned platform is also more cost efficient, as a result of it being around 60 percent lighter in weight, than a conventional tender-assisted drilling wellhead platform that relies on oil and gas for power, Shell said.
Timi is designed to produce up to 50,000 barrels of oil equivalent per day of gas at peak production and will evacuate its gas through a new 80 km pipeline to the F23 production hub.
The project supports the future growth in the central Luconia area, off the coast of Sarawak, Shell said.
Prior to Timi, Shell Malaysia’s first fully solar powered wellhead platform, the Gorek field, located 145 km offshore Malaysia, achieved first gas production on May 24, 2020.
In 2022, Shell Malaysia took a final investment decision on the Rosmari-Marjoram gas project, the largest integrated offshore and onshore project in Sarawak, which will be primarily powered by renewable energy.
This project will feed the Bintulu LNG export plant in Sarawak.
Israel: Israel to increase natural gas output by 60 pc
TEL AVIV: Israel’s Ministry of Energy and Infrastructure is working to promote a plan to expand the supply of natural gas from Israel’s Tamar offshore reservoir by approximately 6 BCM per year starting in 2026, which represents an increase of approximately 60 per cent in the production capacity of the reservoir compared to the output rate today.
The government said the step is being taken in order to strengthen the energy security of the State of Israel and to encourage competition in the natural gas industry.The expansion, which is currently awaiting a final investment decision by the partnership in the reservoir, will be carried out by adding a third transmission line from the Tamar wells to the production rig, as well as upgrading the equipment in the production system.
The decision regarding the promotion of production expansion was made at the end of professional and comprehensive staff work conducted in recent months at the Ministry of Energy and Infrastructure, which included an examination of natural gas supply and demand forecasts for the next 25 years – on an annual, monthly and daily level.About a third of the increase in production capacity is intended for the local market and is expected to supply about 15-25 per cent of the existing consumption of natural gas in the Israeli economy. In emergency cases, it will be possible to divert all of the additional production to the use of the local economy, in accordance with the provisions of the permit.
Global LNG Development
Russia: Russia’s largest independent gas producer delivers first train to flagship Arctic LNG 2 project
The successful end of sea journey from Murmansk underpins global LNG ambitions of Russian gas producer Novatek despite the burden of international sanctions against the country’s LNG projects
Russia’s largest independent gas producer Novatek has successfully delivered the first train of its flagship Arctic LNG 2 project on the western shore of the Gydan Peninsula in West Siberia, which is slated to start producing liquefied natural gas before the end of this year.
The 640,000-tonne structure that sits on a concrete gravity based structure (GBS), has been transported from a Novatek-run specialist shipyard near Russia’s northern port of Murmansk, known as Belokamenka.
The train that arrived this weekend is being positioned for permanent installation on the seabed and then will be connected to onshore infrastructure to enter into the final commissioning phase, a company spokesperson said.
Most of the units at the first train, which has an annual capacity of 6.6 million tonnes per annum of LNG, were pre-commissioned in the Belokamenka yard ahead of the journey.
The onshore supporting infrastructure includes connecting pipelines, an administrative and office module, power generation and gas feeding facilities that are 99% complete.
The train’s operations also will be supported by an onshore gas processing and treatment plant.
The plant will process up to 18 billion cubic metres of natural gas that will arrive from the onshore Utrenneye field on the Gydan Peninsula, where 70 production wells have been drilled.
Novatek still plans to install the second and third trains of Arctic LNG 2 before the end of 2026, despite a need to reconfigure the project’s power supply after international sanctions made it impossible to use gas-fired turbines and other equipment supplied by the West.
Speaking to Russian-state television channel Vesti, Deputy Prime Minister Alexander Novak said that once Arctic LNG 2’s three trains are commissioned and reach full capacity, Russia hopes to grow its share in global LNG deliveries to 12% from the estimated 9% today.
Arctic LNG 2 deputy director Dmitry Kadulin said the operator expects to be ready to produce first LNG at the train before the end of this year, according to Vesti.
The project’s shareholders are Novatek with a 60% interest, France’s TotalEnergies with 10%, China National Petroleum Corporation with 10%, China National Offshore Oil Corporation with 10%, and Japan Arctic LNG, a consortium of Japan’s Mitsui Group and Jogmec, with the remaining 10% interest.(Copyright)
Canada: Titan completes conversion of LNG carriers to bunker vessels
Titan completed the conversion of two recently acquired small-scale LNG carriers into bunkering vessels. In addition to providing a quicker means to expand the LNG bunkering infrastructure, the company reports the conversion of vessels designed to transport gas into bunker vessels provides enhanced capabilities.
The vessels which were built in 2011, were acquired from Seapeak, the Canadian gas transportation company formerly known as Teekay LNG Partners. The company was rebranded in 2022 and was realigning its fleet with the order of new vessels and the acquisition of Evergas, which it completed late in 2022. The Seapeak Unikum was delivered to Titan on March 24 in Gibraltar and the Seapeak Vision was due to be handed over in April.
Titan said at the time that it would retrofit the carriers to improve LNG bunkering capabilities. The work was designed to ensure that they would be able to load at all major LNG terminals and perform ship-to-ship bunkering and loading operations. In addition, the company noted due to their cargo conditioning capabilities, the vessel would also be capable of “doing more complex projects, including gas-up cool-down operations and commissioning parcels.”
Each of the ships has a cargo capacity of 12,000 cbm. Built as carriers, they have the advantage of stainless steel cargo tanks, which makes them compatible with propylene, ethylene, and ammonia. In addition to bunkering LNG and bio-LNG, in the future, the company looks to use the vessel to bunker hydrogen-derived e-methane.
“Retrofitting these ships so that they can trade and bunker LNG, LBM, and in the longer-term hydrogen derived e-methane, offers Titan even more flexibility in its clean fuel operations,” said Douwe de Jong, fleet development director at Titan when the acquisition was announced.
The conversion of the Titan Unikum was undertaken at Metalships & Docks S.A.U. shipyard in Spain while the work on the Titan Vision took place at the PaxOcean shipyard in Indonesia. The upgrading work was recently completed and both vessels are entering service as versatile LNG Bunker Vessels (LNGBVs).
Titan notes that it was able to introduce this added capacity in just four months from delivery. The vessels will be used to cater to the increasing demand for LNG and bio-LNG in Europe. They previously reported that the plan was to deploy the vessels in the Mediterranean and northwest Europe.
South Africa: Kinetiko to form JV for LNG Production
Kinetiko Energy Ltd. subsidiary Afro Energy Pty. Ltd. has executed a non-binding term sheet with South Africa’s Industrial Development Corp. (IDC) to co-develop a new joint venture (JV) for the appraisal and production of liquefied natural gas (LNG) in South Africa.
The project’s first stage targets 50 megawatts (MW) of gas-equivalent energy, Kinetiko said in a news release. The first stage is estimated to cost approximately AUD 138 million ($88.4 million), of which IDC will fund AUD 52 million ($33.3 million) in equity for a 30 percent interest in the JV and Afro Energy will fund AUD 38 million ($24.3 million) for a 70 percent interest in the JV. Afro Energy “has the right to introduce third-party investors to the JV for part or all of its 70 percent interest and can stage payment”, Kinetiko said in the release.
The second stage of the project would see the JV expand production to 500 MW of gas-equivalent energy, which would be the largest onshore LNG project in South Africa, according to the release. The IDC plans to fund 30 percent of the second stage of development.
The parties aim for the first block of 50 MW of equivalent LNG to be completed in two to three years, with further blocks targeted to be developed in nine to 10 years, the release said.
The term sheet also grants the IDC the option to participate in the co-development of 1,000 MW of gas-equivalent energy in other LNG, the release said.
“This is a step change in the scale of the Company’s development and represents a national project to support South Africa’s transition to cleaner, reliable, affordable energy”, Kinetiko CEO Nick de Blocq said. “I cannot overstate the importance of this massive step we have taken in collaboration with our IDC joint venture partners, as it represents a level of confidence in our project from high layers of Government. The project has been registered under the Strategic Infrastructural Projects management mechanism that operates from the Office of the President. This is expected to expedite all State and Government-related processes in terms of permitting and licensing and minimizing of tape. We are beyond delighted to be able to say that our journey towards a large-scale project commercialization and production has now begun.”
Australia’s Kinetiko is focused on commercializing advanced shallow conventional gas and coal bed methane projects in South Africa. The company said the term sheet underpins its objectives to unlock over two trillion cubic feet in gas reserves in the country.
The IDC has been granted a 60-day exclusivity period during which the parties aim to complete the formal legal documentation and obtain necessary internal approvals for binding agreements. The IDC internal approvals include the execution of finance documents comprising joint venture agreements, shareholder agreements, and loan agreements that must be approved by the IDC investment committee and board, according to the release.
Kinetiko currently holds a 49 percent economic interest in Afro Energy, which holds the exploration permits for the project. Kinetiko said it has recently obtained the necessary shareholder approvals allowing it to acquire a 100 percent economic interest in Afro Energy, and expects to complete the transaction shortly. Once the acquisition is complete, Kinetiko will be the sole shareholder of Afro Energy and therefore all the obligations noted for Afro Energy under the term sheet will then be assumed 100 percent by Kinetiko, the company said.
Senegal: FLNG unit for BP’s Tortue Ahmeyim Project nearing completion
The Golar Gimi FLNG unit, being built for BP’s Tortue Ahmeyim project in Senegal/Mauritania offshore area, is set to sail away next month.
According to Golar LNG, tasked with delivering the unit, the FLNG Gimi conversion works 97% complete. Golar LNG said that FLNG Gimi was scheduled to leave the yard in September 2023.
„Final checks, storing up and sea trials will then take place in Singapore ahead of her voyage to Mauritania and Senegal, expected to commence around the end of September/early October,“ Golar LNG said.
Golar LNG also said that a contract interpretation dispute between Golar and BP regarding parts of the pre-commissioning contractual cash flows remains, and arbitration proceedings have been initiated.
“This does not impact the wider execution of the 20-year project that is expected to unlock around $3 billion of Adjusted EBITDA Backlog to Golar, equivalent to Annual Adjusted EBITDA of around $151 million,” Golar LNG said.
Golar and BP in February 2019 signed a 20-year deal for the charter of a floating liquefied natural gas (FLNG) unit, Gimi, and Golar then tasked Keppel with the conversion of the LNG carrier Gimi into an FLNG unit. Golar at the time said that the construction of FLNG Gimi was expected to cost approximately $1.3 billion.
Once delivered, the Gimi FLNG will be used for the development of the Mauritania and Senegal cross-border offshore gas development Tortue/Ahmeyim, one of Africa’s deepest offshore projects at 2,000 meters below the sea’s surface.
The project will produce gas from an ultra-deepwater subsea system and mid-water floating production, storage, and offloading (FPSO) vessel, which will process the gas, removing heavier hydrocarbon components.
Gas will then be transferred to the GIMI FLNG at a nearshore hub located on the Mauritania and Senegal maritime border. The FLNG facility is designed to provide circa 2.5 million metric tons of LNG per annum on average. Total gas resources in the field are estimated to be around 15 trillion cubic feet.
Kosmos Energy discovered the Greater Tortue Ahmeyim field in 2015, and BP signed onto the project through an agreement with Kosmos in 2016.
BP is the project operator. The partners sanctioned the first phase of the project development in December 2018. The vessel had been scheduled for delivery in 2022, but an agreement was reached in October 2020 to delay the delivery due to the coronavirus outbreak.
Oman LNG seals supply deal with Germany’s SEFE
State-owned producer Oman LNG has signed a deal to supply liquefied natural gas to German gas importer Securing Energy for Europe (SEFE). Under the binding term sheet, Oman LNG will supply about 400,000 million tonnes of LNG to SEFE, starting in 2026, according to Oman’s energy ministry.
This is Oman LNG’s first deal with a German firm and the contract is for a period of four years.
SEFE boosting LNG volumes
SEFE said in a statement later on Monday that the signing of the four-year deal for 0.58 bcm of LNG per year marks a “remarkable milestone” as SEFE becomes the first German firm to receive Omani LNG in the ever-growing partnership between Oman LNG and international energy firms.
“The partnership with Oman LNG diversifies SEFE’s portfolio and reinforces our efforts to continue to reliably provide Europe with energy,” SEFE’s CEO Egbert Laege, said.
Earlier this year, SEFE signed a 20-year deal to buy 2.25 million tonnes per annum of LNG from US exporter Venture Global LNG.
State-owned SEFE previously booked long-term capacity at Hanseatic Energy Hub’s planned Stade LNG import terminal in Germany.
Starting in 2027, SEFE, previously known as Gazprom Germania, plans to import at least 4 bcm per year of LNG via the terminal.
SEFE booked the capacity for 20 years and with future flexibility to switch to ammonia.
The firm also reportedly booked 3.5 bcm of regasification capacity at the Dunkirk LNG terminal in France.
In addition, commodity trader Trafigura said in December it would supply US LNG to SEFE.
9th supply deal for Oman LNG
This deal with SEFE is the 9th contract Oman LNG signed since December last year and follows the deal with China’s Unipec, a unit of state-owned energy giant Sinopec.
Oman LNG, in which the government of Oman holds 51 percent, also signed term sheets with Turkey’s Botas and its shareholders TotalEnergies, PTT, and Shell.
Also, Oman LNG signed key term sheets in December to supply LNG to Japan’s Jera, Mitsui, and Itochu.
The firm operates three LNG trains in Qalhat with a nameplate capacity of 10.4 mtpa sourcing gas from the central Oman gas field complex.
Due to debottlenecking, the company’s complex now has a production capacity of around 11.4 mtpa.
UK: Golar LNG and NNPCL agree on joint gas development for FLNG project
In its interim results for the period that ended in June 2023, Golar LNG said it signed heads of terms with Nigeria National Petroleum Corporation for the joint development of gas fields using floating liquefied natural gas (FLNG), expanding on the Memorandum of Understanding signed in April 2023.
A part of Golar LNG’s statement read thus:
“Strong progress with the potential deployment of Golar’s FLNG vessels to various gas fields in Nigeria has been made since signing the MOU with NNPC in April. Under a further head of terms signed with NNPC on August 1, 2023, Golar and NNPC have agreed on an integrated contractual framework for the joint development of specific gas fields toward potential FLNG projects.”
In April 2023, Nairametrics reported that NNPC Limited signed an MoU with Golar LNG to build a floating liquefied natural gas plant in Nigeria to increase the country’s domestic gas utilization and enhance gas export.
Before the signing, the NNPC Limited said it is committed to improving Nigeria’s energy security through the enhancement of the country’s natural gas resources.
At the time, the NNPCL statement on the signing read thus;
“In furtherance of its efforts to deepen Nigeria’s domestic gas utilization and enhance gas export, Nigerian National Petroleum Company Limited has signed a Memorandum of Understanding (MoU) with a Norwegian company, Golar LNG (GLNG), to build a Floating Liquified Natural Gas (LNG) plant in Nigeria.
“Group CEO, of NNPCL and CEO of Golar LNG, Mr. Karl Fredrik Staubo, signed the agreement on behalf of their respective companies during a brief ceremony held at the NNPC Towers in Abuja.
“Golar LNG is one of the world’s largest independent owners and operators of marine-based LNG midstream infrastructure active in the liquefaction, transportation, and regasification of natural gas.”
Golar LNG is a reputable company with over 50 years of experience in developing marine LNG infrastructure and has a strong balance sheet position, low leverage, and strong cash flow from operations to expand the FLNG business.
What you should know:
According to Golar LNG, material-technical and commercial progress has been made on the deal with NNPCL. Note that the memorandum has a 5-year duration.
In its results statement, Golar LNG said that as of March 31, 2023, its total cash was $1 billion, comprising $889 million of cash and cash equivalents and $113 million of restricted cash.
South Korea: South Korea’s SK Gas seals Ulsan LNG bunkering pact
SK Gas, a unit of South Korean conglomerate SK Group, is joining forces with compatriot shipping firm H-Line and the Ulsan Port Authority to develop a liquefied natural gas (LNG) bunkering project.
In that regard, the trio signed a memorandum of understanding for a public-private joint project, according to a statement by SK Gas.
SK Gas, H-Line Shipping, and UPA will now work to create a joint venture for the project in the first half of 2024.
Following the formation of the new firm, the partners plan to build a new LNG bunkering vessel, the statement said.
With this move, SK Gas will enter the LNG bunkering business.
SK Gas is a partner in Korea Energy Terminal (KET) along Korea National Oil Corporation.
Back in 2020, Daewoo E&C won a contract for the first phase of this project in the port of Ulsan which includes the construction of a 215,000-cbm LNG tank and additional regas facilities with about 1 mtpa capacity. It also won a contract for the second phase with the same scope the same year.
Last year, a consortium led by Daewoo E&C also won the contract for the third phase as well and the full project will have three LNG tanks with a total capacity of 645,000 cbm.
The terminal also includes a berth for LNG bunkering vessels.
KET plans to launch commercial operations of the first and second phase in 2024.
Technological Development for Cleaner and Greener Environment Hydrogen & Bio-Methane
Hydrogen Policy: Enabling a Hydrogen Economy
The transition toward net-zero has propelled the meteoric rise of hydrogen as an energy vector. The development of a hydrogen economy is however no mean endeavour, requiring nimble policies and robust regulatory frameworks to foster a competitive hydrogen industry.
What are the most compelling focal points for regulators to enable hydrogen against the backdrop of the need for clean, reliable and affordable power and the race to achieve Net Zero?
Growing a hydrogen economy requires a paradigm shift from the way energy is traditionally regulated.
A hydrogen economy is one that uses hydrogen as a regular fuel source for electricity production, energy storage and common modes of transportation. The aspiration would be to eliminate emissions whilst also enhancing economic development in a fully sustainable manner. Unlike for instance, in the use of renewables like solar power to supplement grid power, or the import of LNG as a secondary feedstock to piped natural gas, the transition to a hydrogen economy requires significant policy support to spur the development of systems and structures, including production facilities, transportation media, storage, refuelling stations and possibly hydrogen highways. Regulators cannot do it alone. Governments, industry players, R&D institutions, international trade associations, investors and consumers will need to be part of the conversation to carve out an optimal role of hydrogen.
Identifying the best use of hydrogen is key to understanding how hydrogen can viably displace or co-exist with other energy sources.
With the plethora of hydrogen applications being developed, policymakers are still urgently trying to understand where hydrogen may be the most useful in their respective energy systems. An incredible amount of real time industry knowledge and a close watch on the technological breakthroughs in this sector are required to understand the entire value chain, and to identify the means to match demand and supply cost-effectively. Most countries have assigned a role to hydrogen in sectors where emissions are hard to abate and where electrification or other mitigation measures may not be available or would be difficult to implement, namely heavy industry, long-distance transport, shipping and aviation. A useful way to identify the best use of hydrogen includes grant calls to test bed innovations and applications to identify suitable uses cases which will differ between jurisdictions. Regulatory sandboxes or regulation free zones can also be set up to commercialise applications whilst providing useful inputs on how hydrogen laws can be improved or implemented.
Regulatory tools are needed to boost hydrogen demand without a downward spiral into the perennial chicken and egg conundrum of supply and demand.
Just like how progressive policies support have spurred the exponential growth of renewable energy, nimble policies and regulations are essential to give hydrogen a leg up if hydrogen is going mainstream. Renewable energy tax credits and subsidies, feed-in tariffs and competitive tenders for large-scale public projects have all helped to cut costs and speed up deployment for renewables like solar and wind. In the same vein, carbon pricing, emissions control standards or clean energy regulations can likely also drive the demand for hydrogen. A number of countries are well ahead in the hydrogen race, having devised a dedicated hydrogen strategy and followed through with clear timelines for hydrogen deployment in specific sectors. Singapore’s national hydrogen strategy for instance, has stipulated that depending on technological developments and the development of other energy sources, hydrogen could supply up to 50% of Singapore power needs by 2050.
Enabling policies can encourage much needed investment in hydrogen infrastructure which in turn drives down costs and increases uptake.
A reliable and stable policy framework is essential to give investors the confidence to invest in the hydrogen supply chain network (equipment manufacturers, infrastructure providers, and vehicle manufacturers, etc.) and to develop hydrogen infrastructure (refuelling stations, pipelines, hydrogen highways, etc.) Policies and regulations may also help to propel the repurposing of existing infrastructure (e.g., converting natural gas to dedicated hydrogen pipelines) or to secure land availability and public acceptance for the development of infrastructure for hydrogen production, transportation or storage. In some cases, subsidies for green H2 projects may also help to incentivise investments in hydrogen infrastructure or technology. Public-private partnerships (PPP) foster cooperation between governments (public institutions), businesses (private institutions) and the public (users) and is a tested means to accelerate infrastructure development and eliminate the risks in the early stage.
Innovation policies create a stimulating environment for hydrogen innovation to be realized and for the exchange of information and knowledge to grow the industry.
A genuine intention to grow the hydrogen industry requires an in-depth examination of how a country can produce, store, transport and consume hydrogen. Each country differs in its approach to enable hydrogen within its existing energy system and there is also the need to avoid stranded assets in any switch to hydrogen. For instance, the US Inflation Reduction Act seeks to overcome the cost barrier for hydrogen production with lucrative tax credits, including by differentiating hydrogen production based on their carbon intensity and rewarding tax credits of USD0.60/kgH2 if lifecycle emissions are 2.5-0.4 kgCO2e/kgH2 up to USD3.00/kgH2 if lifecycle emissions are 0-0.45kgCO2e/kgH2. Other useful tools to foster innovation include giving tax incentives for R&D, supporting manpower upskilling and providing direct grants for hydrogen projects. Over time, monitoring the relative success of the different approaches will help to identify the best practices for policy and regulation to enable hydrogen in differing contexts.
US: Hydrogen brings both opportunities and challenges to West Virginia
CHARLESTON — Hydrogen is the new buzzword in clean energy, with several projects either underway in West Virginia or proposed. But what does it mean? Is there potential for West Virginia as a leader in producing this clean fuel, or will promises of a hydrogen future go the way of cracker plants and natural gas storage hubs?
The Pleasants Power Plant near St. Marys is being converted from a coal-fired plant to run on hydrogen. A new project near Point Pleasant wants to produce hydrogen from natural gas and pump the greenhouse gas emissions underground. And politicians still talk about a possible regional hydrogen hub, one of which must be built somewhere in Appalachia.
There is nothing new about hydrogen in and of itself. It’s one of the most comment elements in the universe. Two hydrogen atoms combine with one oxygen atom to create water. On the flipside, hydrogen is highly flammable. Ignition of hydrogen gas is what brought down the infamous Hindenburg airship in 1937.
But hydrogen is back in the news, seen as a possible clean-burning fuel for manufacturing and vehicles. Hydrogen burns clean with no greenhouse gas emissions and only water as its byproduct. But producing hydrogen gas in large-scale quantities is expensive, and the ways of producing hydrogen to scale still involve the use of fossil fuels, such as natural gas.
LIGHT IT UP
President Joe Biden set a goal at the beginning of his term in 2021 of cutting greenhouse emissions in the U.S. in half by the end of the decade. Biden wants to cut U.S. greenhouse gas emissions by between 50% and 52% of 2005 levels by 2030, a carbon-neutral electric grid by 2035, and zero-emissions by 2050.
One way the Biden administration hopes to meet those goals is with hydrogen, with the U.S. Department of Energy leading the way on research. This includes work by the National Energy Technology Laboratory, with one facility in Morgantown.
“Ensuring America is the global leader in the next generation of clean energy technologies requires all of us – government and industry — coming together to confront shared challenges, particularly lack of market certainty for clean hydrogen that too often delays progress,” said U.S. Secretary of Energy Jennifer M. Granholm in a July press release.
The $1.2 trillion Infrastructure investment and Jobs Act — negotiated in 2021 by U.S. Senators Joe Manchin, D-W.Va., and Shelley Moore Capito, R-W.Va., — included $9.5 billion in funding for hydrogen research. One program included $1.5 billion to support hydrogen electrolysis, using electricity to separate the hydrogen gas from water molecules. Another $8 billion was set aside to fund a broad Regional Clean Hydrogen Hubs program.
The West Virginia Hydrogen Hub Working Group — made up of state and federal elected leaders — applied to the Department of Energy last year to land a regional hydrogen hub. Each hub is required to demonstrate the production of clean hydrogen and demonstrate the use of clean hydrogen.
As many as 10 regional hubs could be built, but Manchin and Capito inserted specific language in the law requiring a hub in Appalachia. The DOE is expected to announce the locations for regional hydrogen hubs by the end of the year.
In July, the Biden administration launched the Demand-Side Initiative to invest more than $1 billion towards supporting the regional hydrogen hubs and helping provide market certainty for both producers of hydrogen and potential industrial and commercial end-users.
“… DOE is setting up a new initiative to help our private sector partners address bottlenecks and other project impediments – helping industry unlock the full potential of this incredibly versatile energy resource and supporting the long-term success of the H2hubs,” Granholm said.
The DOE set a goal – called the Hydrogen Shot – of being able to produce hydrogen at $1 per one kilogram by the end of 2032. If the Hydrogen Shot objectives can be achieved, the DOE believes greenhouse gas emissions can be reduced by 16% by 2050, create $140 million in revenues, and create more than 700,000 new jobs by 2030.
The $737 billion Inflation Reduction Act passed last summer after negotiations between Democratic leaders and Manchin, also includes several tax credits to incentivize the production and commercial use of hydrogen. This includes the 45V hydrogen tax credit, with provides up to $3 per kilogram of hydrogen produced for projects that begin prior to 2033.
BLINDED BY SCIENCE
The National Energy Technology Laboratory (NETL) is conducting wide-ranging research into hydrogen storage – from fuel cells for vehicles and industry, to large-scale storage. In Morgantown and other facilities, NETL engineers are working on developing new kinds of turbine engines that can use hydrogen for fuel, using microwaves to extract hydrogen and other petrochemical feedstocks, and storing large quantities of hydrogen underground.
“As we work to mitigate the impact of climate change, it’s crucial that we identify how we can best interact to unlock the potential of hydrogen by developing carbon-negative hydrogen technologies and systems,” said NETL researcher Jonathan Lekse in a statement following a July conference in Colorado.
“These and other projects are especially important to establish a hydrogen economy and reap the many benefits it will provide,” said Nathan Weiland, a senior fellow at NETL.
But others doubt the ability of hydrogen to vitalize the regional economy. The Ohio River Valley Institute, a left-of-center public policy advocacy organization, released a report last week, titled “Frackalachia Update: Peak Natural Gas and the Economic Implications for Appalachia.”
In that report, senior researcher Sean O’Leary argued that much like the boom predicted for natural gas in the last decade – such as the building of cracker plants to extract petrochemical feedstocks from natural gas or underground natural gas storage hubs – that promises of hydrogen production are overhyped.
“This report, its predecessors, and struggling downtowns in communities throughout Frackalachia provide overwhelming evidence that the predictions weren’t only wrong, they were the products of deeply flawed and biased analyses … Sadly, the same is likely to be true of the most recent shiny object being dangled in front of the region’s policymakers — the promised creation of an Appalachian hydrogen hub,” O’Leary wrote.
O’Leary said that any hydrogen hub is likely to be smaller than what supporters say it would be, that the potential market for hydrogen will grow but still be far smaller to support the projected jobs the DOE expects to create, that private markets may never be able to support a hub, and that hydrogen manufacturing plants could still be too expensive and capital-intensive to build and still be highly polluting.
“That isn’t to say that the region doesn’t need new industry, including some that might be part of a hydrogen hub,” O’Leary wrote. “It’s to say that policymakers should be realistic about what these industries do and do not offer in the way of economic development as well as the costs they may inflict and the quality of life trade-offs they may require.”
“If policymakers are realistic about these things, they will recognize the need for a more effective and sustainable approach to economic development regardless of whether or not the natural gas industry stagnates or continues to grow, regardless of whether the hydrogen hub is realized, and regardless of whether some small amount of petrochemical development manages to find a foothold,” O’Leary continued.
BENEATH THE SURFACE
One way to extract hydrogen is by using natural gas – a process called blue hydrogen. Houston-based Fidelis New Energy was approved for up to $62.5 million in forgivable loans from the state Economic Development Authority last week for a hydrogen production project and biomass power plant in north Point Pleasant.
The Mountaineer GigaSystem project will produce hydrogen for use in powering data centers and other potential projects by using natural gas. The greenhouse gas emission produced by the hydrogen manufacturing process would be captured, transported by pipeline, and pumped underground in pore spaces underground state-owned wildlife lands nearby.
Legislation passed during the 2023 session earlier this year allows the state Division of Natural Resources to sell, lease, or dispose of property under its control, including leasing state-owned pore spaces beneath state forests, wildlife management areas, and other lands under DNR’s jurisdiction for use in carbon capture and sequestration.
Environmental advocates are not pleased with the Fidelis project, both for its use of natural gas and its plans for pumping carbon emissions underground. Morgan King, a climate campaign coordinator for the West Virginia Rivers Coalition, accused Fidelis and the state of “experimenting” on nearby communities
“We’ve not been able to see projects achieve the 95% capture rate that is established by the Department of Energy as the recommended standard for capturing pollution,” King said. “On top of that, there are life cycle concerns. Even imagining a perfect world where we can produce blue hydrogen in an economic and safe way and we can capture the carbon at 95% or more, there is still concerns of storage.
“When we look at taking our protected state forests and our protected wildlife areas and injecting carbon into those pore spaces, that’s extremely experimental and dangerous,” King continued. “This hasn’t happened here before, and I don’t think West Virginia communities and West Virginia public lands should be the experiment to figure out if it works safely.”
King raised concerns about the potential for earthquake activities in the areas where the greenhouse gas emissions would be stored and the possibility of groundwater contamination. She also raised issues about lack of community engagement, the economic viability of hydrogen, and the continued use of fossil fuels to produce it.
“If we’re continuing to frack and extract gas, there’s going to be environmental and public health impacts for that,” King said. “If we really want to store carbon and protect our communities, we would just leave that gas in the ground.”
Jessica Pierson Moore is director and state geologist for the West Virginia Geological and Economic Survey, a division of the state Department of Commerce. Speaking by phone, Moore said GES has conducted several studies of underground geology in the state. The areas being looked at for underground storage of carbon emissions are thousands of feet below groundwater and in much harder geologic formations, mitigating the risks of earthquake activities.
“We have a long track record of storing gases in the Appalachian Basin, most notably natural gas and methane storage which has been done here safely for probably about 80 years,” Moore said. “We know that we can do that kind of gas storage. We also know we can dispose of waste directly in the basin.”
Moore explained that Ohio has dealt with earthquake activities due to the underground storage of fracking wastewater, but those quakes are caused by the combination of its sedimentary rocks and older crystalline basin rocks.
“When you move into West Virginia, the section of sedimentary rock is thicker,” Moore said. “The section we’re looking at in West Virginia is not in proximity to that crystalline basin interface … it’s that history of development in the basin that has enabled us to understand the deep subsurface. It is really deep.”
The deepness is what will protect the state’s groundwater, Moore said. Projects like Fidelis are required to apply for a class six carbon dioxide injection well permit. Underground saltwater reservoirs in the area being considered sit at around 1,500 feet below the surface. The geologic pore spaces for greenhouse gas storage will have to be deeper than 2,500 feet to be viable.
“The target that we are looking at for this project is several thousand feet even deeper than that,” Moore said. It’s 7,000-feet-to-8,000-feet in the subsurface … for this project, we’re not really looking at the shallowest reservoirs that have been targets of oil and natural has exploration for 150 years.”
Moore said there has been exploration of this deeper reservoir target since the 1940s, but since most natural gas and oil reservoirs are far shallower, it was overlooked for drilling. With the opening up of the Marcellus and Utica shale deposits, state researchers have worked to map out these larger, deeper pore spaces.
Despite complaints from environmental groups about lack of community engagement, Moore said none of the groups that have lodged complaints have reached out to GES. She encouraged anyone with questions to contact her office.
“I can tell you from meeting the folks at Fidelis that they are engaged in the community. They really see something special in West Virginia,” Moore said. “As far as the technical information, my office is here for the people of West Virginia. We’re taxpayer supported. We pride ourselves in meeting you with your questions.”
US: California may pay up to $300M for Hydrogen car fuel stations. Why?
Electric cars are rolling off production lines, and one in five new cars sold in California this year is battery-powered. “California is showing the world what’s possible,” said Gov. Gavin Newsom, whose plan to phase out fossil fuels and gasoline-powered cars is key to his ambitions of tackling climate change.
But as California steers away from the internal combustion engine, the rapid transition is fueling a fight in the Capitol over how large a role hydrogen fuel cells will play in powering the clean cars of the future.
Democrats in the state Legislature are debating how much money to give companies to build hydrogen fueling stations. A lobbying group for hydrogen supporters and suppliers, including Chevron, Shell and Toyota, is seeking a designated 30% share of money from the state Clean Transportation Program, amounting to $300 million over the next decade.
The program is funded by annual fees paid by California drivers—$2 car registration fees and $4 smog abatement fees. Over the last decade, hydrogen has been earmarked for 20% of its funds.
So far, the California Energy Commission has spent $202 million for hydrogen fueling stations. Yet there is still low demand for the cars, with sluggish sales: Only two hydrogen models are available, the Toyota Mirai and Hyundai Nexo, and only 1,767 have been sold in California this year. Last year’s sales declined 20% although sales are up this summer.
In all, Californians own only about 12,000 hydrogen-powered cars, compared with more than 760,000 powered by batteries.
Like battery-powered cars, hydrogen cars produce no emissions. But the electricity to run their motors uses compressed hydrogen gas, which is mostly derived from natural gas, a fossil fuel.
The state’s funding has helped create a network of just 65 hydrogen fueling stations, 20 of them in Los Angeles County. Driving a hydrogen car outside of California is virtually impossible: One other public hydrogen fueling station exists in the U.S., and it’s in Hawaii.
The Energy Commission staff has warned lawmakers that there won’t be enough hydrogen cars on the roads to use new stations already allocated state funds. Stations will triple by 2027—resulting in four times more than the amount needed to support even the “vehicle manufacturers’ best-case expected volume,” the commission said. They also warned that they haven’t received enough bids from hydrogen station developers to spend all the money the Legislature already has allocated.
“Ten years ago, there was a reasonable argument that hydrogen could make up a pretty significant percentage of our zero-emission transportation needs,” said Ethan Elkind, director of the climate program at the Center for Law, Energy & the Environment at UC Berkeley Law. “But at this point, battery electric has completely dominated the light-duty sector and is looking to dominate on heavy-duty, as well.”
In the Legislature, the debate among Democrats is whether hydrogen suppliers should continue to get a substantial amount of money from the Clean Transportation Program—and if so, how much and for how long.
Assembly Bill 241 by Eloise Gomez Reyes, a Democrat from San Bernardino, would designate 10% of the program’s funds—$10 million a year through July 1, 2030—to pay for hydrogen fueling stations.
Reyes and Sen. Lena Gonzalez, a Democrat from Long Beach, initially tried bills that would have completely eliminated a hydrogen carveout. But they failed to get enough support from fellow Democrats so Reyes amended her bill in June to seek the 10%.
Reyes has not brought the proposal to a vote because some assemblymembers want more money for hydrogen, while others think that’s too much, so she wants “more conversations with concerned members.”
Gonzalez said she opposes more than the $10 million a year because hydrogen car technology remains unpopular, inefficient and dependent on burning fossil fuels.
“It’s a waste of money,” she said. “They say they’re hydrogen businesses, but they’re really fossil fuel industry businesses.”
Sen. Josh Newman, a Democrat from Fullerton, said hydrogen cars are not competitive yet because they haven’t received the state money they need for fueling stations. “The reason it’s behind is because we haven’t made the appropriate investments,” he said during an April hearing.
The success of the funding bill could come down to the votes of several Democrats in the Assembly who expressed concerns to Reyes. Four told CalMatters that they want money explicitly set aside for hydrogen, calling it a valuable, zero-emission technology for cars. But they didn’t include specifics on how much. They are Cecilia Aguiar-Curry of Davis, Jacqui Irwin of Thousand Oaks, Blanca Rubio of West Covina and Carlos Villapudua of Stockton.
Without their votes, a funding bill for the Clean Transportation Program likely won’t pass.
Other legislators say electric cars have left hydrogen vehicles in the dust, so they would be misspending the fees paid by California drivers for fueling stations that few drivers will use.
The conflict in the Legislature could jeopardize the future of the program, which is a key source of money for building new charging stations as more people buy electric cars. The program will expire next year if the Legislature can’t agree on a spending plan.
The Clean Transportation Program, created in 2007, has used fees paid by California drivers to invest nearly $1.6 billion in alternative fuels, charging stations and other clean vehicle technologies through March of this year. It’s an essential source of funding for California’s clean car transition given that it’s more consistent than California’s volatile budget.
“The Clean Transportation Program is—not to be too dorky about it—a beautiful market signal,” said Hannon Rasool, director of the Energy Commission’s fuels and transportation division. “It tells folks we’re committed, we’re in it for the long run and here’s a steady amount of funding.”
The program has explicitly set aside money for hydrogen fueling stations since 2013, when former Assemblymember Henry Perea, who now leads West Coast government affairs for Chevron, authored a 20% annual carveout for hydrogen. The goal was to build a network of 100 hydrogen-fueling stations. Gov. Jerry Brown increased that target to 200 by 2025. California Energy Commission staff told lawmakers in presentations that it will meet the 200-station goal by 2027.
The Battle Among Democrats in the Legislature
Reyes’ original bill would have forced hydrogen developers to compete for program funds directly with those who build electric charging stations, a proposal she called “technology neutral.”
“The truth is hydrogen has made less than an ideal progress in making this market competitive compared to other zero-emission technologies,” Reyes said. She added, “I am not anti-hydrogen, especially not in the heavy-duty space,” and that she was taking all of her colleagues’ concerns seriously.
Since the program raises money through vehicle registration and other fees, the bill needs two-thirds of lawmakers’ votes to be reauthorized. It needs 54 votes out of 80 lawmakers in the Assembly and 27 out of 40 in the Senate.
“If we’re not able to reach an agreement, and it lapses or sunsets, it’ll be almost impossible to get a new bill through,” Reyes said. “So having it reauthorized is extremely important.”
Reyes said the legislators who oppose her proposal include “both individuals who want more dedicated funding for hydrogen, and those who feel that the 10% carve-out for hydrogen in the legislation has already gone too far.”
Reyes declined to identify the legislators who want more hydrogen funding or those who want less.
But Melissa Romero, senior legislative manager for the environmental group California Environmental Voters, said at least seven Assemblymembers opposed reauthorization of the program even after the bill included 10% for hydrogen.
Romero’s environmental group supports candidates who seek to reduce California’s dependence on fossil fuels. She worries the clean transportation program might expire, leaving California in jeopardy of not funding the charging stations it needs for electric cars.
The state estimates it will need nearly 1.2 million chargers for battery-powered cars by 2030. Only about 88,000 are now installed.
“How is it that we could have a supermajority of Democrats … and not be able to extend a program that provides funding for zero-emission vehicle infrastructure?” Romero asked. “That is totally crazy to me.”
Automakers opposed the bill because fees paid by car owners would be used in part to fund fueling stations for trucks.
“The state is nowhere near having the amount of necessary” electric car charging stations, so “it is unfair to place the burden” on car owners for paying for both truck and car stations, the Alliance for Automotive Innovation wrote to legislators in April.
Most large automakers have set goals to convert all of their fleets to battery-powered cars—not hydrogen—but they did not take a stance on the funding for hydrogen stations. Two of their members, Hyundai and Toyota, sell hydrogen cars.
The Link Between Hydrogen Cars and Fossil Fuels
Romero said the influence of the oil and gas industry, which is hoping to transition to hydrogen technology, is a major reason that the Legislature is debating whether to pay for hydrogen fuel stations.
Major oil and gas companies see hydrogen as a potential way for their industry to remain viable in a decarbonized future. Most hydrogen is now produced using natural gas. Some companies are exploring ways of making hydrogen a green energy source by splitting water using renewable-energy electrolyzers. But that technology remains much more costly than today’s process using fossil fuels.
Energy companies are also experimenting with capturing emissions from the natural gas process and then storing those emissions underground. But those carbon-capture techniques are not yet widespread.
While electric cars are also reliant on energy from carbon-emitting power plants, California is greening its grid. Under a state mandate, 100% of electricity must be renewable and carbon-free by 2045, with most coming from solar and wind.
Teresa Cooke, executive director of the California Hydrogen Coalition, said she is disappointed that so few hydrogen fueling stations have been built over the last decade. She attributed the slow progress to the Energy Commission delaying approvals and difficulty with getting the stations permitted.
Cooke said only about 3.5% of all state funding for clean cars has been spent on hydrogen vehicle infrastructure, while battery electric cars have been overwhelmingly favored by state agencies and lawmakers.
She said oil and gas companies deserve the chance to make the shift away from carbon-heavy fuels.
“It blows my mind that there is such resistance to (supporting) the possibility of oil and gas companies transitioning into hydrogen,” Cooke said. “They should be able to transition into a vehicle fuel that can be produced domestically, can be produced renewably and put into a zero-emission vehicle and maintain all of the good labor jobs that come with it—full stop.”
Hydrogen support in the Legislature
Among legislators who support a carve-out for hydrogen, some have been major recipients of oil and gas industry contributions, while others have not been.
For instance, one hydrogen supporter, Rubio, a Democrat from West Covina, took more campaign money from oil and gas than any Assemblymember other than Republican Vince Fong, who represents oil-rich Kern County, according to a CalMatters analysis of campaign contributions data from the National Institute on Money in Politics.
Rubio has taken $218,399 from the oil and gas industry since 2016, including contributions from Chevron, Valero and ExxonMobil, among others, the data shows.
In a statement to CalMatters, Rubio reiterated a widely cited industry finding that the U.S. hydrogen industry has the potential to create $140 billion per year in revenue and support 700,000 jobs by 2030.
Rubio said in her district—a swath of communities east of Los Angeles—people who drive long distances will likely need more options than electric cars.
“We have a great number of ‘super commuters’ that drive hours a day to their jobs,” Rubio said. “They can’t afford to wait for their vehicles to get charged or gamble on whether they make it to their destination because of limited battery range.”
Irwin, the Assemblymember from Thousand Oaks, said she wants something closer to the 20% share that hydrogen got in past years. She has not taken much money from the oil and gas industry—around $3,100, with most coming from companies representing gas stations, not oil and gas companies.
Irwin said she believes hydrogen has a role to play in transportation, particularly for trucking, and so it makes sense to build hydrogen infrastructure for cars, too.
“We know that hydrogen has to be part of the future for medium-duty vehicles,” Irwin said. “So why not continue to invest in hydrogen stations that can accommodate both medium and light-duty? I think that’s a really smart investment that hedges our bets.”
When the proposal was heard in the Senate’s Transportation Committee on April 11, several Democratic senators spoke in favor of maintaining a carveout for hydrogen.
Sen. Bob Archuleta of Norwalk said the technology was important for meeting the state’s climate goals. “We will need more zero-emission vehicle options than plug-in alone,” he said. “We’ve got to combine everything. Hydrogen fuel-cell vehicles are complementary.”
Archuleta has accepted $63,186 in campaign contributions from the oil and gas industry. Newman, the senator from Fullerton, has taken $4,000.
Experts say that hydrogen can play other roles in clean energy, including potentially replacing diesel for large trucks and aviation fuels. Hydrogen’s storage potential also is likely to be important as grids rely more on renewable energy.
California is competing to be named a regional clean hydrogen hub by the Biden administration, part of an $8 billion program. “California is all in on clean, renewable hydrogen—an essential aspect of how we’ll power our future and cut pollution,” Newsom said earlier this month, announcing plans for a statewide hydrogen energy strategy.
But a spokesman for the governor, Alex Stack, declined to say whether Newsom supports a carve-out for hydrogen vehicle fueling stations in the Clean Transportation program.
Orville Thomas of Calstart, a sustainable energy nonprofit, said the state money for hydrogen stations should be used for not just cars, but also medium- and heavy-duty trucks.
“Let’s make sure that we’re being good stewards of that money, ” Thomas said. “Every million dollars is important to make sure California gets to its goals.”