All articles in the Gas Monetization Section:

Italian major ENI has reported delivering a gas cargo of 3.1Billion cubic feet from Algeria to the SNAM regasification terminal in Piombino, Italy.

Unloading operations took place following the completion of the test phase and mark the beginning of the terminal’s commercial operation.

“The cargo was produced at the Sonatrach liquefaction plant in Betihoua, Algeria”, ENI says in a release. The partnership with Sonatrach and Algeria plays a central role in ENI’s strategy to diversify supplies and expand its gas portfolio, with investments in fast-track projects that will increase available volumes for the Italian and European markets”, it explains.

ENI is bullish on Algerian assets as evidenced by its recent $4.9Billion acquisition of a piece of Neptune Energy, which holds large gas properties in Algeria, including the Touat gas project, a joint venture with Sonatrach and ENGIE, considered an important source of supply for mainland Europe. Groupement Touat Gaz consists of Neptune Energy Touat (65%) and Sonatrach (35%).

“ENI targets growth in its LNG activities with contracted volumes expected to rise to over 18Million tonnes in 2026, more than double that of 2022. It is an important component of a reshaped global gas portfolio that will contribute to the security of supply and increasingly leverage equity production”.

Italian explorer ENI has submitted a formal proposal to the Mozambican government for the Coral North project, its second Floating LNG aimed at monetizing the Coral gas field in ultradeepwater Area 4 in the Indian Ocean.

The facility will be sited — around 10 kilometres north of the existing Coral South FLNG, 50 kilometres off the coast of Palma in Cabo Delgado Province.

Coral North will cost around $7Billion and ENI officials expect liquefaction and export to commence in 2027.

The company continues its environmental impact assessment process for the project and has announced two public consultation meetings: in Maputo on June 30 at the Radisson Blu Hotel, and in Pemba (in the Cabo Delgado Province) on July 4.

Coral North will have a production capacity of 3.5Million tonnes per year, like Coral Sul FLNG, which began exporting gas in November 2022. The molecules will be delivered from six subsea from the Coral offshore reservoir, located in Area 4 of the Rovuma Basin.

Onshore logistics operations for the project will be carried out from three designated bases: in the Port of Pemba, at a logistics base in Pemba, and at the Pemba Airport. ENI will run the project from its offices in Maputo and Pemba. Equipment requiring the use of a deepwater port will be unloaded at the Port of Nacala in Nampula province, south of Cabo Delgado.

ENI decided to move ahead with s the second floating gas production facility, as larger, onshore projects, planned by TOTAL led Mozambique LNG (13MMTPA) and ExxonMobil led Rovuma LNG, stall as a result of insecurity issues in

Coral South FLNG was built in South Korea by Samsung Heavy Industries; it was the first in deep water globally and the sixth FLNG platform set up anywhere in the world.

Justine Njoroge, in Nairobi

Orca Energy has reported a bolstering of the Compressed Natural Gas market in Tanzania, in the context of a global shift in gas supply and demand.

Russia’s invasion of Ukraine, and the subsequent and significant rise in Tanzanian domestic fuel prices, coupled with an increase in awareness of CNG as a vehicular fuel, has resulted in rapid growth of Natural Gas Vehicles (NGVs) and by extension a 400% increase in revenues generated from the CNG station over the past five years the company has noted in a report.

CNG business is a secondary opportunity for Orca, the operator of the 86.8Millon standard cubic feet per day (86.8MMscf/d) Songo Songo gas field, one of Tanzania’s two main natural gas projects.

But the company has continued its programne of preventative maintenance and improvement at its sole service station in Ubungo, (a district in Dar es Salam), which has included a 20,000 hour CNG compressor overhaul.

“Downstream CNG operations are rapidly becoming a critical service we provide to the citizens of Dar es Salaam”, company management says. “With an ever-increasing number of domestic and industrial transportation customers, as well as a number of off-network industries supported through virtual pipelines, the demand for CNG has increased considerably.

“System availability and increased demand also necessitated an increase in personnel to operate the facility 24/7, and the Company hired new CNG operators to ensure that the service for which we have become known is not impacted”, Orca explains in the statement.

Downstream demand continued to increase through 2022, driven primarily by increased power generation requirements and low hydropower production. Discussions and negotiations were held, and in some cases Gas Sales Agreements (GSAs) signed with several other customers seeking Piped Natural Gas (PNG) and CNG, and we expect to connect them in 2023.

“One of the GSAs entered into was with an Egypt based company called TAQA ARABIA for the supply of PNG for the generation of CNG for vehicles. This contract will increase the CNG to vehicle services in Tanzania by around 30%, further underpinning the value and availability of the service to customers, which in turn is expected to accelerate an already growing market”.

By Rachel Brasier, Andrea Pescatori, and Martin Stuermer-IMF

Natural gas might be the same commodity everywhere in the world, but prices can vary dramatically because of the complex network of infrastructure needed to transport it.

The result is a partially fragmented global market, mainly because most natural gas moves by pipeline—unlike the market for crude oil, which is more integrated and tends to trade at a single price in most places. Such fragmentation in the natural gas market means not only that prices differ across regions, but also that high prices in one part of the world don’t necessarily transmit to buyers in other places.

Russia’s invasion of Ukraine provided a stark illustration of the effects of segmentation. Pipeline flows to Europe from Russia dropped by 80 percent since mid-2021, sending the continent’s gas prices up 14-fold to a record level in August 2022.  Prices for globally traded liquefied natural gas saw a similar jump. But LNG prices in the United States merely tripled, remaining several times below Europe and Asia.

The disparity in prices, and the US insulation against global gas-market shocks, stems from the idiosyncrasies of gas extraction and transportation. Historically, the US market was linked to crude oil prices because gas was mostly a byproduct of oil drilling, but this relationship, sometimes called artificial integration, has been unwinding over the past decade, mainly because of rising shale gas production. And as gas production surged in the US, which surpassed Russia in 2012 as the world’s largest producer, and export terminals were built, it became easier to sell into markets beyond North America.

Another important factor for gas prices is the technology needed to liquefy and ship the fuel, which must be converted into a compact form—about 600 times smaller by volume than in its gas form—called liquefied natural gas before it can be loaded onto specially designed carriers for transport by sea or road.

LNG export capacity is fixed in the short-term. Facilities for the liquefaction, exporting, importing, and regasification require major investment, so a regional shock, such as Russia’s invasion of Ukraine, can send regional prices moving in different directions.

After the invasion last year, Europe turned to LNG to replace pipeline imports of Russian gas, and US shipments emerged as a key substitute. Why was that possible when US LNG export capacity is fixed? With gas in Europe commanding a temporary price premium during the spring and summer of 2022, Asian customers of US LNG decided to reroute their cargoes to sell in Europe.

There is another important quirk of the natural gas market at play. Pricing formulas for long-term delivery contracts with US companies usually use US prices. That meant Asian customers with long-term deals could buy more cheaply from the US, then reroute tanker ships at sea to sell cargo at the much higher European spot market price.

Despite an increasing reliance on LNG as a substitute for Russian pipeline gas, European LNG import capacity turned out not to be a binding constraint on market integration. European import terminals had plenty of spare capacity before Russia’s invasion of Ukraine, and with the addition of mobile floating storage regasification units, Europe has the necessary infrastructure to accommodate higher volumes of LNG imports.

On the other hand, the United States and other gas producers are exporting at the limits of their capacities, and expansions to global LNG export capacity are needed to bring European and Asian prices back to historically normal levels over the longer term. In the United States, these capacities are poised to keep growing, even after already rapid gains. The first LNG export terminal in the country opened in 2016, followed by many more.

Sizable expansion projects already under construction in the United States, Africa, the Middle East, and elsewhere are likely to increase global LNG export capacity by 14 percent by 2025. Other planned projects could bring export capacity to around 1Trillion cubic meters, roughly a quarter of last year’s global gas consumption.

Securing financing to build new terminals, however, can face major hurdles. Companies need 15- to 20-year contracts to obtain bank financing for construction. Terminals usually cost $10Billion to $15Billion and take two to four years to complete. Timelines are less certain for projects without long-term sales contracts, and some may never be built.

Ultimately, expanded LNG export capacity for the United States and other producers may prove crucial to creating truly global gas markets that are balanced across regions. As advanced economies increase reliance on weather-dependent renewable energy from wind and solar, they will likely see critical periods of increased demand for supplemental natural gas to meet power generation needs. Integrating global gas markets and building needed infrastructure allows prices to stimulate demand and supply reactions in larger, more integrated markets. This helps to buffer global energy markets against supply shocks

FIRST E&P is developing an open-access offshore gas gathering and processing hub around its operated OML 83 and 85 assets. The company is hoping the facility could have the capacity to process 1Billion standard cubic feet per day, from a mix of FIRST E&P’s gas as well as other third-party gas within a 60- to 80-kilometre radius.

First E&P thinks this is an opportunity because there is, in Nigeria, an absence of open-access gas gathering, processing and transportation infrastructure in the offshore terrain.This offshore gas hub will process wet gas to pipeline specifications as well as enhance value from our gas resources with extraction of the condensate and NGLs. Robust gas transportation options in addition to pipelines, such as LNG and CNG, will also be incorporated into the development concept to efficiently serve both local and international markets. The offshore gas hub plant FEED has been launched and is expected to be completed in mid-2023 when the formal project FID is scheduled to be taken to assure first gas is on stream in 2026.

There is no certainty, though, that the FID could be taken this year.

Such a project would fill a vast infrastructure gap, which has obstructed monetization of offshore gas resources in the country.

Unlike crude oil, raw gas must be processed and conditioned to pipeline-specification gas flow, which entails separating the gas liquids, condensates and related heavy ends before moving it onshore or commercialising demand points efficiently.