FEATURE: Germany joins ranks of LNG importers in major diversification drive

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Germany is poised to begin commissioning work at its first floating LNG import terminal in a matter of days, enabling the EU powerhouse to receive direct LNG imports for the first time.

Germany has long held the ambition to install LNG terminals on its northern coast, but Russia's invasion of Ukraine and subsequent cuts in pipeline deliveries lent new momentum to German efforts to diversify supply through LNG.

In all, six import projects are under development -- five backed by the German state and one privately-funded terminal.

The first to start up will be Uniper's state-backed FSRU at Wilhelmshaven -- the Hoegh Esperanza -- which arrived in port on Dec. 15. "The first gas will flow on Dec. 22," a Uniper spokesperson told S&P Global Commodity Insights.

During the commissioning phase, gas send-outs of between 15 GWh/d and 155 GWh/d into the Open Grid Europe network are expected.

"Commercial operation of the FSRU is currently planned to commence mid-January with an expected maximum capacity of roughly 155 GWh/d," Uniper said in a market transparency note.

That is the equivalent of some 15 million cu m/d of gas flow, which on an annualized basis would mean total supply of some 5.5 Bcm/year.

That is a far cry from the 158 million cu m/d regularly supplied to Germany from Russia via the now damaged and idled Nord Stream pipeline system before June this year.

The loss of Russian gas has hit Germany hard, with record high prices putting significant pressure on German buyers of Russian gas forced to procure substitute gas on the open market.

Platts, part of S&P Global Commodity Insights, assessed the benchmark Dutch TTF month-ahead price at an all-time high of Eur319.98/MWh on Aug. 26.

Prices have weakened since on the back of healthy storage and demand curtailments, though prices remain historically high with Platts assessing the TTF month-ahead price Dec. 16 at Eur118.23/MWh.

Nonetheless, managing the deployment of an FSRU within such a short period of time is impressive, with construction work at Wilhelmshaven only having started in May after the project was revived in February.

The Hoegh Esperanza could also have an expanded capacity in the future, with Uniper having flagged a potential send-out capacity of 7.5 Bcm/year.

Other startups

As well as the FSRU at Wilhelmshaven, two other projects are due to begin operations shortly.

Private developer Deutsche ReGas is hoping to commission the Neptune FSRU at the port of Lubmin before the end of December. The FSRU arrived into the port on Dec. 16.

"Our goal is to be able to start supplying gas as soon as possible," Deutsche ReGas chairman Stephan Knabe said Dec. 16.

"But the commissioning can only take place when all the necessary permits have been obtained. We continue to assume December," he said.

Deutsche ReGas had said previously the terminal would be technically ready by Dec. 1, but a number of permits remain outstanding, while work on the FSRU at the nearby port of Mukran was also dependent on weather conditions.

RWE, meanwhile, plans to deploy a state-backed FSRU at Brunsbuttel in January, later than originally hoped.

"According to current planning, it is expected that the construction work for the operation of the FSRU in the port will be completed in January," an RWE spokesperson said Dec. 15.

The FSRU will then be able to dock and be connected to the newly constructed technical infrastructure, the spokesperson said.

The FSRU reported to be in line to serve Brunsbuttel is the Hoegh Gannet, which is currently in Brest, France, according to Platts cFlow ship and commodity tracking software from S&P Global Commodity Insights.

Earlier this year RWE had flagged that the first cargo to arrive at the port would be LNG it had contracted to buy from the UAE, which was originally intended to be delivered in December.

Both the FSRUs at Wilhelmshaven and Brunsbuttel are to be supplied with LNG by Uniper, RWE and EnBW unit VNG under a memorandum of understanding signed with the German economy ministry to guarantee their full use until March 2024.

Capacity bookings

Three other state-supported FSRUs are under development and are due online by the end of 2023 at: Stade (Hanseatic Energy Hub - HEH); Lubmin (RWE/Stena-Power); and Wilhelmshaven (TES/E.ON/Engie).

The German economy ministry said in September that the FSRUs at Brunsbuttel and Stade would be operated only until permanent onshore terminals go into operation in 2026.

Both permanent terminals have been buoyed in recent weeks by binding capacity bookings and related supply deals.

German utility EnBW said this month it had booked 3 Bcm/year of capacity at HEH's planned 13.3 Bcm/year capacity onshore terminal at Stade from the start of commissioning, expected in 2026.

As well as booking LNG import capacity at Stade, EnBW will also have the option to move to ammonia as a hydrogen-based energy source at a later date.

"This possibility is open to all Hanseatic Energy Hub customers with a long-term contract of more than 10 years," it said.

For the permanent 8 Bcm/year site at Brunsbuttel, the US' ConocoPhillips, chemicals giant Ineos and RWE have all booked long-term capacity.

ConocoPhillips said in late November it had agreed two long-term agreements with QatarEnergy for the supply of up to 2 million mt/year of LNG into Brunsbuttel for a period of at least 15 years.

The LNG will be supplied on a DES basis from Qatar's major North Field East and North Field South expansion projects, in which ConocoPhillips is a partner.

Ineos, meanwhile, said Dec. 1 it had signed a long-term agreement with Sempra Energy's infrastructure unit for the supply of LNG from the proposed Port Arthur export terminal in the US. First deliveries from Port Arthur are expected in 2027.

The agreement includes a 20-year commitment for 1.4 million mt/year from the first phase of the project, while the two companies also signed a non-binding deal for an additional 0.2 million mt/year from the project's second phase.

The permanent Brunsbuttel terminal is expected to begin operations in 2026, although efforts are underway to accelerate the startup, and its capacity could be expanded to at least 10 Bcm/year.


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  • Gas & Power

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Potential record-setting hurricane season is forecast and may weaken energy demand, prices

The National Oceanic and Atmospheric Administration on May 23 projected the most tropical cyclones ever in its early hurricane season forecast, and such storms could weaken energy demand and prices in landfall areas during what may be an otherwise warmer-than-normal summer. In particular, NOAA made the following forecast: 17-25 named storms, up from 14.7 for 1991-2023 Eight to 13 hurricanes, up from 7.2 for 1991-2023 Four to seven major hurricanes, up from 3.2 for 1991-2023 At the high end of the forecast, the season could equal 2020's record seven major hurricanes and approach 2020's record 30 named storms and 2005's record 15 hurricanes. "As one of the strongest El Nino ever observed nears its end, NOAA scientists predict a quick transition to La Nina conditions, which are conducive to Atlantic hurricane activity because La Nina tends to lessen wind shear in the tropics," NOAA said. "At the same time, abundant oceanic heat content in the tropical Atlantic Ocean and Caribbean Sea creates more energy to fuel storm development." Energy market impacts Tropical cyclones making landfall 2021 through 2023 cut peakloads at affected grids an average of 18%, power burns an average of 17%, and power prices -- excluding the Electric Reliability Council of Texas South Hub's extreme case in 2023 -- an average of 38%. ERCOT had one of its hottest summers on record in 2023, so day-ahead on-peak locational marginal prices at the South Hub averaged almost $795/MWh on Aug. 15, the Tuesday before Tropical Storm Harold hit South Texas on Tuesday, Aug. 22, when prices averaged less than $60/MWh. The change was drastic, inasmuch as ERCOT load fell just 1.5% on the week, and natural gas power burn actually increased 10.7%. South Texas has a large wind generation fleet, which may have been taken offline during the storm due to transmission constraints or grid reliability concerns. Grant Gunter, energy markets expert at PA Consulting, said hurricanes "can be a mixed bag for supply and demand" for natural gas. The production impact "used to be the typical thinking for hurricanes," as they would diminish offshore production as platforms shut down and evacuate, Gunter said in a May 23 email. "However, as offshore gas production has fallen and moved more onshore, these impacts have become more muted," Gunter said. "A mild hurricane likely won't impact onshore Gulf Coast production all that much." In contrast, hurricanes can have a big impact on power burn and shut-in LNG exports, Gunter said. The National Weather Service on May 16 forecast enhanced chances – 40% to 60% -- for above-normal temperatures for June, July and August across the US South Atlantic and Gulf Coast. CustomWeather on May 22 forecast temperatures to be zero to two degrees above normal across the region in June. "Power outages naturally reduce power burn demand, which is a significant source of demand in Texas and the Southeast," Gunter said. "LNG facilities, which are situated primarily along the Texas and Louisiana Gulf Coast, will usually halt exports during hurricanes due to rough seas and an inability to bring in tankers to load. These shut-ins can last 3-5 days or more depending on the severity of the storm, and a single LNG facility shutting in can result in 2+ Bcf/d of demand going offline. Ian Palao, vice president for strategic energy services at POWWR, an energy management service, advised considering ERCOT's likely heavy heat-driven power demand, despite the hurricane forecast. "Because of the random nature of hurricane landfall, I wouldn't expect an increased level of forecasted tropical activity to nullify the potential heat risk this far out in time," Palao said in a May 23 email. Hurricanes in the past have affected not only the demand side from reduced load due to system outages but also the supply side, due to reduced offshore production. "I would say hurricanes have more of a demand (gas burn for electricity generation) impact than a supply impact as significant swaths of cities can be off the grid for upwards of a week or more (thinking of Hurricanes Harvey and Ida)," Palao said. "Additionally, given that on-shore gas production far outpaces off-shore production, a temporary shutdown of offshore rigs will be but a blip in total supply." Risk management As of May 22, day-weighted average on-peak power forwards for the 2024 hurricane season, June 1 through Nov. 30, were less than day-ahead on-peak prices at relevant hub in ERCOT, but had premiums in comparison with day-ahead on-peak power in the Southeast and at the Midcontinent Independent System Operator's Louisiana Hub. 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"The forward markets, even at a near coastal hub months before the hurricane season begins, do not have any information or data that indicates the timing or severity of hurricane landfall, so the incorporation of a long-term forecast like this is interesting data to the market, but not likely a key component of forward price," Germeroth said in a May 23 email. Another risk to consider is the effect on solar installations, which have grown substantially over the past few years along the Gulf Coast, particularly in Florida and Texas. Tulane Energy Institute Associate Director Eric Smith said Florida's "new solar capabilities will be vulnerable to damage from wind-borne debris." "Texas is also vulnerable to wind damage to both solar and wind assets," Smith said May 23. 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The US exports about 13 billion cubic feet of LNG daily, mainly through Gulf Coast facilities. "Although LNG facilities generally have many layers of protection from direct impact, hurricanes can damage electrical and marine infrastructure and hamper ship movement," the EIA analysis said. Hurricane Laura in 2020 temporarily halted LNG exports from Louisiana's Sabine Pass and Cameron LNG facilities. All that said, OTC Global Holdings' Faulkner described forecasts for an abnormally active hurricane season are "borderline useless." "Last year was supposed to be horrible and ended up being rather benign," Faulkner said May 23. "Thus the prognosticating and fear mongering is an exercise designed to drive clicks and induce fear in the wider populace." But Faulkner acknowledged that if a hurricane does approach the Gulf Coast, its effect "could be serious, especially given the importance of LNG exports," causing gas prices to "plummet."


Global LNG markets finely balanced amid strong Asian demand: Shell Australia

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European LNG prices reach five-month high as global competition heats up

European LNG prices rose to a five-month high as ongoing geopolitical risk factors and tightness in European LNG supply intensified competition with other global demand hubs, market sources said. Platts, part of S&P Global Commodity Insights, assessed the DES Northwest Europe and Mediterranean markers for July at $10.445/MMBtu May 21, up 33.4 cents/MMBtu on the day, and at the highest levels seen since Dec. 27, when it was at $10.756/MMBtu. At the same time, Platts assessed the East Med marker at $10.645/MMBtu, also the highest seen since Dec. 27. LNG prices across Europe are under pressure, with market participants looking to compete for cargoes against Asia. Heat waves in Asia have sparked stronger seasonal demand, creating sturdy competition between the European and Asian LNG supply. In comparison, JKM also recently reached a price high of $11.498/MMBtu on May 20 -- the highest since Dec. 18 -- before falling slightly to $11.485/MMBtu May 21, Commodity Insights data showed. Although Europe is comfortable with high gas inventories, European LNG supply has constricted week on week. In both the NWE and Mediterranean, LNG traders saw sellers with the flexibility in taking cargoes toward Asia over Northwest Europe and suggested that prices in Europe need to increase further to attract selling interest. "No expectation [for demand] to pick up, people cannot pay, [Europe is] completely out of price," an LNG trader said. LNG dynamics While natural gas prices have strengthened recently amid continued geopolitical uncertainty and a tightening supply environment for both pipeline flows and LNG imports into the continent, European natural gas prices have yet to reach highs touched in mid-April. Despite an uptick in planned maintenance on the Norwegian Continental Shelf, which analysts at Commodity Insights expect will reduce flows from these assets by 11% month on month, Norwegian gas nominations have remained relatively strong averaging 300.5 million cu m/d in May so far basis data from offshore pipeline Gassco. Although most of the ongoing maintenances on the Atlantic side are planned, the market is still wary of any potential extensions which could put pressure on the market going into the third quarter, where injections are expected to be stronger. "There is a lot of maintenance in the North Sea...Just because [the maintenances] are planned doesn't reduce the potential impact if things go wrong," an Atlantic-based trader said. "With a relatively tight LNG market, this skews risk to the upside." Narrow spreads Historically as TTF prices increase, LNG-TTF spreads would widen. However, LNG-TTF spreads have remained persistently narrow due to increased global competition for LNG, sources said. Traders pointed to a "new normal" with expectations that the spreads will stay narrow as European bids remain relatively strong to attract cargoes. "I am bullish on LNG-TTF spreads, TTF seems to be lagging behind the [geopolitical] news," a second LNG trader said, adding that European prices were still falling behind those seen in Asia. Platts assessed NWE LNG prices at a 17.5 cents/MMBtu discount to the TTF Dutch gas hub price. The discount has averaged around 41 cents/MMBtu this year so far, compared with the 2023 average of $1.70/MMBtu. Similarly, East and West Med prices have been strong compared with TTF which has made it uneconomical to import LNG, pushing European and Med market participants to replenish supply on inland pipeline volumes. "PVB [the Spanish gas hub price] has been strengthening the past few days which is indicating a tightening [LNG] market and that is the same in the East Med too," the second LNG trader said. A Med-based trader said: "[The] market seems tight, and any news can push prices to spike." "Pipegas has great activity, we have this LNG freeze, but pipeline gas is a more hot environment, especially with the narrow LNG-TTF spreads it makes more sense to buy on gas," another Med-based trader said. However, the tight spreads were disincentivizing LNG flows into the continent as the prices, albeit high for European buyers, were unable to compete with the cargoes heading to Asia. "The only ones that are buying is because they have a firm commitment or they really need it," another trader said. "Everyone is cancelling." This is reflected in the low LNG imports into the continent accompanied with gas sendout levels from LNG facilities at multimonth lows.