What Can Gas And LNG Expect In 2023

What Can Gas And LNG Expect In 2023
No commodity has faced the challenges that the global gas industry has faced in 2022. In this article, look at 6 things the gas market could expect in 2023.

No other commodity has faced the challenges that the global gas industry has faced in the last year. In this article, look at 6 things the gas market could expect in 2023.

Europe has grabbed the headlines last year. But 2022 has been much more – from record prices in North America to declining LNG demand in Asia, from momentum in LNG contracting to disappointment in LNG FIDs.

What does 2023 hold for the global gas and LNG industry? In this insight we discuss 6 things we will be watching closely – and offer our predictions.

Europe – better than feared but not out of the woods

Europe ended 2022 in a much better position than many feared only a few months ago. Gas demand has decreased by 50 bcm, equivalent to 10% vs 2021. LNG imports have increased by 60 bcm. Consequently, despite Russian pipeline imports reducing by 82 bcm, Europe has been able to end 2022 with storage levels at 83%. TTF has averaged $37.6/mmbtu in 2022 and has recently been trading up to $45/mmbtu, following a cold spell in early December. But prices have since reduced below $25/mmbtu, as temperatures turned unseasonably mild.

Europe will have to deal with lower Russian imports in the summer, up to 25 bcm less, compared to the same period of 2022, once the risk of further curtailments via Ukraine is also considered. However, continued weakness in demand and sustained LNG imports should help Europe get through winter with gas storage close to 40% of capacity. This is a much higher level than the 27% it reached in 2022, resulting in less storage injection required to hit the 90% storage capacity target set by the EU. That, combined with higher LNG imports (+9 bcm) and lower demand, will keep prices lower than in 2022.

Wood Mackenzie estimates a cold Q1 across Europe and Asia could result in European storage inventories reaching only 19% by the end of the winter, risking inventories to reach only 73% by November 2023. A strong rebound of Chinese LNG demand is another one. Further curtailments of Russian imports are a risk too. Any of these risks provide upside to Woodmac’s price view and the current forward curve, possibly testing the cap on TTF that the EU has imposed. Woodmac believes that European prices will be lower than in 2022 but still above $25/mmbtu to ensure strong LNG imports and subdued domestic demand.

LNG demand growth in China will be limited, but risk is to the upside

Covid restrictions and high LNG prices have resulted in Chinese LNG demand reducing by 16 mmtpa in 2020, equivalent to Asia’s overall net LNG demand reduction, helping ease market tightness as Europe has sought to maximize LNG imports. Domestic supply will continue to grow strongly (+12 bcm), following record production in 2022 as NOCs continue to invest. This, combined with further ramp up of Power of Siberia 1 (+7 bcm) means LNG will increase by 7 bcm, or 5.4 mmtpa. This is less than the increase in long term LNG contracts in 2023, meaning China will not have to rely on spot LNG imports on an aggregated national level and throughout the year. Instead, they could be again positioned to re-sell LNG in the market. Woodmac believes that LNG demand growth will be below 6 mmtpa.

Henry Hub price retreats in 2023 as supply and demand start to rebalance

Henry Hub price averaged near $6.65/mmbtu in 2022, a 14-year high. Strong gas demand growth, supported by increased LNG exports and limited coal to gas switching, has outpaced supply growth, resulting in storage levels consistently below the 5-year average. Woodmac predicts Henry Hub to average well below $5/mmbtu for 2023.

Domestic demand will be losing momentum in 2023, following an estimated 5.3% growth in 2022. Supply growth in Mexico and lack of additional new LNG supply projects will limit exports, despite the return of Freeport LNG. The analyst firm view is for 2023 domestic gas requirements, including exports, to increase by about 1.9 bcfd, or 1.8% vs 2022.

North America gas production has grown to record levels in 2022, some 4.7 bcfd more than in 2021. Similar growth will happen in 2023. Much will materialize in the Permian and Haynesville, while the Northeast will add limited incremental volumes amid on-going takeaway pipeline constraints. Canadian production too will contribute to growth in 2023. Overall, we anticipate production will grow by another 4.7 bcfd in 2023.

A bumper year for LNG FIDs, but some will struggle

With only 28 mmtpa of LNG sanctioned, 2022 was a disappointing year for FIDs. But with record LNG prices and the need to replace up to 140 bcm of Russian pipeline exports to Europe, there is more than 200 mmtpa of LNG supply targeting FID in 2023/2024. FID at Qatar’s 16 mmtpa North Field South development is expected in Q1 2023. Woodmac predicts more than 60 mmtpa to take FID in 2023

Two projects have emerged as clear front runners following recent contracting momentum: the second phase of Venture Global’s Plaquemines (6.7 mmtpa) and Sempra’s Port Arthur LNG (13.5 mmtpa). The latter is primed for an early 2023 FID announcement, having recently secured a revised EPC contract with Bechtel and a huge equity, offtake and gas supply deal with ConocoPhillips. Leading contenders for further development include Energy Transfer’s Lake Charles (16.5 mmtpa), Next Decade’s Rio Grande (16.5 mmtpa), Venture Global’s Calcasieu Pass Phase 2 (10 mmtpa), and Sempra’s Cameron Phase 2 (6.2 mmtpa). Some, but not all, will go ahead in 2023.

After a stuttering start, FLNG is hot again. Eni set the benchmark with Coral in Mozambique, delivering first gas on time and on budget, and making the large stalled onshore LNG plans for Area 1 and 4 look unreasonably risky by comparison. If commissioning goes well, we expect to see Eni and ExxonMobil abandon their onshore proposals in favor of multiple FLNG vessels in the country. Two new floating projects were sanctioned at the end of the year: Petronas’ third floating project in Malaysia, ZLNG (2 mmtpa); and the second phase of Eni’s Marine XII FLNG (2.4 mmtpa) in Congo. Looking forward to 2023, are BP may also sanction a second FLNG phase at Senegal-Mauritania’s Tortue and Chevron and NewMed Energy are due to decide on whether to go for FLNG at Leviathan Phase 2.

We’ll also be closely watching if New Fortress Energy’s Fast LNG platform concept proves successful. The company is aiming to radically reduce LNG execution and payback times, initially developing at least four 1.4 mmtpa units, with first LNG planned for 2023. If successful we expect further projects from New Fortress and other operators working out how to replicate the formula.

LNG contracting momentum will continue into 2023

More than 80 mmtpa contracts were signed in 2022, 75% from the US and over 50% with portfolio players and traders. Contracting momentum will continue, but less contracts will be signed compared to 2022.

More activity will come from Asian buyers, particularly in China, with other long-term contracts from Qatar likely, following the recently signed 4 mmtpa Qatar/Sinopec deal.

US independent upstream and mid-stream players will increase downstream activity in US LNG, following ConocoPhillip’s and Williams’s recent large-scale deals. European buyers are unlikely to enter the market in a big way. Some deals will happen, but not much more than 10 mmtpa, as buyers remain concerned about demand longevity and future pricing dynamics.

The fixed component on Henry Hub linked deals have ranged between $1.90/mmbtu and $2.40/mmbtu in 2022. These are expected to increase in 2023.

Gas needs CCS to ensure demand longevity

CCS is key for the longevity of gas demand in a world that is trying to achieve net zero carbon emissions by 2050. CCS is the only available option to reduce scope 3 emissions when burning gas to create electricity or in industrial processes, which accounts for 75-85% of CO2 emission across the gas value chain.

CCS is still a relatively nascent technology, with existing projects only capable of capturing and storing 50 Mtpa of CO2. However, momentum is growing rapidly with the pipeline of CCS capacity from planned projects now sitting above 1 Btpa, a 50% increase compared to the end of 2021.

It’s in Europe where projects are currently at a more advanced stage of development. Carbon prices are trading consistently close to $100/tCO2 and are expected to grow. Some projects are well placed to take FID in 2023, including HyNet North West and the East Coast Cluster in the UK, Porthos in the Netherlands, Greensand in Denmark, and Polaris in Norway.

Momentum has been building in the US following the approval of the Inflation Reduction Act, the new flagship legislation aimed at boosting investments in low carbon technologies. This has now increased the 12 years tax credit for CCS projects to $85/tCO2, from $50/tCO2, and has introduced direct payments for the first five years. This means CCS deployed to develop blue hydrogen and to capture CO2 in post-combustion industrial process are starting to be in the money, paving the way for new investment in what is already the most developed CCS market. Indeed, more than 50% of the newly announced CCS projects are in North America.

To contact the author, email bojan.lepic@rigzone.com



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