Global liquefaction projects face uneven futures

The biggest single planned liquefaction project is Qatar Petroleum’s (QP) North Field East (NFE) expansion. North America leads in planned additions to regional capacity. The International Gas Union, however, cautions that most projects won’t get built given a diminished appetite for large capital investments in the face of the ongoing COVID-19 pandemic. Potential reductions in long-term demand for natural gas as the energy transition gains momentum are also playing a role in determining project viability.

This article updates progress on some of the larger or otherwise significant liquefaction projects around the world, be they advancing or foundering.

Middle East

QP in February 2021 took final investment decision (FID) on NFE and signed engineering, procurement, and construction (EPC) contracts for its onshore infrastructure, including LNG trains. NFE will raise Qatar’s LNG production capacity to 110 million tonnes/year (tpy) from 77 million tpy.

QP awarded the EPC contracts to Chiyoda Corp. and Technip Energies, with their main scope being construction of four 8-million tpy LNG trains. QP also awarded a lump-sum EPC contract to Samsung C&T Corp. for expansion of LNG storage and loading within Ras Laffan Industrial City as part of NFE. Contract scope includes three LNG tanks and three LNG loading berths, and options for two LNG tanks and one LNG berth for the future North Field South (NFS) project. NFS will increase Qatar’s LNG production to 126 million tpy.

The company said in June 2021 that it had received offtake commitments for double NFE’s planned 32-million tpy expansion.

North America

Tellurian Inc. in May-June 2021 signed 10-year sales agreements with both Gunvor Singapore Pte. Ltd. and Vitol Inc. for 3 million tpy of LNG indexed to a combination of the Japan Korea Marker (JKM) and the Dutch Title Transfer Facility (TTF), netted back for transportation charges. LNG would be delivered free on board (FOB) from Tellurian’s proposed 27.6-million tpy Driftwood LNG plant near Lake Charles, La. Then in July, Tellurian terminated its one previous non-binding LNG-purchase agreement, with TotalEnergies SE, related to Driftwood production. The LNG producer also pushed FID to first-quarter 2022 from late 2021.

Tellurian said it intends to market up to 10 million tpy of Driftwood’s 16.6-million tpy Phase 1 on a JKM, TTF, or blended-price basis. The company last year withdrew prefiling for the 2.3-bcfd Permian Global Access pipeline (OGJ Online, Dec. 14, 2021), and has since announced plans to produce its own natural gas.

NextDecade Corp. and Bechtel Oil, Gas, and Chemicals Inc. in March 2021 completed repricing their lump-sum turnkey EPC agreements for the first three trains at NextDecade’s 27-million tonne/year (tpy) Rio Grande LNG project in Brownsville, Tex.

The repricing had no impact on the overall cost of the project: $7 billion for two trains, $9.6 billion for three. The pricing is now valid until Dec. 31, 2021. NextDecade and Bechtel also agreed to extend the validity of the agreements to July 31, 2022.

NextDecade anticipates achieving FID on a minimum of two trains at Rio Grande LNG this year. The plant’s overall capacity is based on a planned five-train configuration (OGJ Online, July 15, 2020).

Venture Global LNG in April 2021 partnered with Zachry Group for development of its 21.6-million tpy Plaquemines LNG plant. Plaquemines will use 36 600,000-tpy trains arranged in 18 modules. Venture Global had previously chosen KBR as EPC contractor for the project. KBR and Zachry Group will work together, through a new joint venture as KZJV, under the EPC contract for Phase 1 (10 million tpy). KZJV will integrate the modularized, owner-furnished equipment for the plant.

Plaquemines LNG has contracted 3.5 million tpy of Phase-1 production under binding 20-year offtake agreements and received both US Department of Energy export authorization and final Federal Energy Regulatory Commission (FERC) approval. The company has yet to take FID on Plaquemines LNG.

Energy Transfer Partners LP likewise has not yet reached FID on its 16.45-million tpy Lake Charles LNG project, a redevelopment of its existing Lake Charles, La., regasification terminal. The project is fully permitted and FERC on Dec. 5, 2019, granted a 5-year extension to put the plant in service. Energy Transfer is considering reducing the plant’s size to two trains and 11 million tpy.

Woodside Energy in May 2021 decided to exit its 50% non-operated participating interest in the proposed 18-million tpy Kitimat LNG liquefaction plant in British Columbia, Canada, effectively killing the project pending a buyer or outside financing. The exit will include divestment or wind-up and restoration of assets, leases, and agreements covering the 471-km Pacific Trail pipeline route and the site of the proposed plant at Bish Cove.

QP and ExxonMobil’s 15.6-million tpy Golden Pass LNG joint venture, by contrast, is under construction at Golden Pass’ import terminal site in Sabine Pass, Tex. (Fig. 1). The companies expect the first of three trains at the plant to enter service in 2024. Liquefaction operations will use five existing 155,000-cu m full-containment storage tanks. The plant’s two marine berths can accommodate Q-Max class vessels (266,000 cu m) simultaneously.

Royal Dutch Shell PLC, Petronas, Mitsubishi Corp., PetroChina Canada Ltd. and Korea Gas Co.’s 14-million tpy LNG Canada project in June 2021 took delivery of the plant’s main cryogenic heat exchanger (MCHE) and two precoolers (Fig. 2). The MCHE is the first of two built by Linde PLC for the plant. The second is expected to arrive later this year, along with two more precoolers. Project completion is expected in 2025.

The Nisga’a Nation, Rockies LNG Partners LP, and Western LNG in July 2021 filed the initial project description for their floating 12-million tpy Ksi Lisims LNG plant with the Government of British Columbia and the Government of Canada. The plant will be stationed at Wil Milit on the northern tip of Pearse Island near the Nisga’a village of Gingolx, BC. Project partners expect commercial operations to begin late 2027 or early 2028. 

Two third-party natural gas pipeline projects are being evaluated to supply feed to Ksi Lisims LNG. Both have received regulatory approvals.

Venture Global’s 10-million tpy Calcasieu Pass LNG plant in Cameron Parish, La., was given permission in May 2021 to introduce hazardous fluids for commissioning of a gas turbine, with an eye toward bringing the full plant online by 2022. The plant’s modular design, however, using 18 small trains (similar to the approach used for Plaquemines LNG) could allow initial shipments before the end of this year.

The company has six binding, long-term agreements for sale of a total of 8 million tpy, as well as agreements for available quantities in excess of its 10-million tpy nameplate capacity. Agreements were made with Shell NA LNG LLC, Edison SPA, BP Gas Marketing Ltd., Galp Energia E&P BV, Repsol LNG Holding SA, Polskie Górnictwo Naftowe i Gazownictwo SA (PGNiG), and Venture Global Commodities LLC.

By contrast, Pieridae Energy Ltd. had expected to take FID on its 10-million tpy Goldboro LNG liquefaction plant in Nova Scotia, Canada, this year. As of July 2021, however, the company was evaluating strategic alternatives for the project while at the same time defending its fundamentals. “It became apparent that cost pressures and time constraints due to COVID-19 have made building the current version of the LNG project impractical,” said Pieridae chief executive officer Alfrend Sorensen in July 2021.

Pieridae had planned to begin a 5-year drilling schedule to fill the plant’s 5-million tpy Train 1. Production from the first train had been sold to German utility Uniper under a 20-year contract with a 10-year optional extension. 

Cheniere Energy Inc. put the third train at its 15-million tpy Corpus Christi LNG plant in commercial service in March 2021. The train had been operating for evaluation and testing since August 2020. Trains 1 and 2 entered service in 2019. 

Cheniere is also commercializing its Stage 3 expansion at Corpus Christi, which proposes up to seven ​midscale trains that would add 10 million tpy of production.

Sempra Energy had hoped to take FID on the two-train 11-million tpy first phase of its Port Arthur LNG plant in Port Arthur, Tex., in 2021 and begin construction Q1 2022 to meet a first-quarter 2026 in-service date for Train 1. In May 2021, however Sempra delayed FID into 2022. The company said it needs production from the plant to be fully contracted before taking FID.

Symbio Infrastructure LP and Siemens Energy in June 2021 agreed for Siemens to provide engineering services, comprehensive lifecycle equipment, and technology solutions for Symbio subsidiary GNL Quebec’s 10.5-million tonne/year Énergie Saguenay LNG plant in Quebec and subsidiary Gazoduq’s natural gas transmission pipeline between northeastern Ontario and Saguenay. The next month, however, Quebec’s government rejected the project on environmental concerns.

Freeport LNG is targeting 2022 FID for the 5-million tpy fourth train at its Quintana Island, Tex., liquefaction plant, pending sufficient offtake agreements. The company last year requested a 3-year extension from FERC to May 17, 2026, to put Train 4 in service.

Sempra Energy subsidiary ECA Liquefaction (ECA LNG), a joint venture between Sempra LNG and Infraestructura Energética Nova SAB de CV (IEnova), in November 2020 reached FID for development, construction, and operation of the 3.25-million tpy Energia Costa Azul LNG Phase 1 natural gas liquefaction-export project in Baja California, Mexico (Fig. 3). It was the only liquefaction FID taken in 2020 and followed two delays earlier that year. First production is expected late-2024.

Sempra LNG and IEnova will build and operate Phase 1 as a single-train liquefaction plant with initial offtake capacity of 2.5 million tpy. ECA LNG has secured definitive 20-year sale and purchase agreements with Mitsui & Co. Ltd. and an affiliate of TotalEnergies for the purchase of this production.

Pacific Oil & Gas Ltd.’s wholly-owned subsidiary, Woodfibre LNG, in May 2021 signed a second LNG sales agreement with BP Gas Marketing Ltd., a wholly-owned indirect subsidiary of BP PLC, for delivery from Woodfibre LNG’s planned 2.1-million tpy plant near Squamish, BC. BP will receive 0.75 million tpy over 15 years on an FOB basis. The deal increases BP’s total LNG offtake from Woodfibre to 1.5 million tpy.

Woodfibre last year received a 5-year extension from the British Columbia Environmental Assessment Office to begin construction of the plant. The new deadline is Oct. 26, 2025.

Asia Pacific

Rosneft and ExxonMobil’s 6.2-million tpy Far East LNG (Sakhalin-1) and Gazprom’s 5.4-million tpy Sakhalin-2 LNG Train 3 are both in pre-FID but struggling to secure feed gas. TechnipFMC is performing FEED work for Sakhalin-1. The project will include expansion of Chayvo onshore gas processing and construction of a 220-km gas pipeline, with the plant itself sited near De Kastri oil export terminal in Khabarovsk Krai. Rosneft plans to complete the project’s feasibility study in 2021 and then begin commercial marketing. Sakhalin-1 is not expected to enter service before 2028. The Sakhalin-2 expansion would grow total capacity at the plant at Prigorodnoye, Sakhalin Island, to 16.2-million tpy.

Inpex Corp. affirmed to the Indonesian Government in July 2021 that it will still develop the 9.5-million tpy Abadi LNG plant, to be supplied from Abadi gas and condensate field in the Masela production sharing contract (PSC). Local press reported that progress on the project’s environmental impact analysis had been slowed but was now targeted for August 2021 completion. Inpex’s affirmation came despite Indonesian regulators’ request that Shell complete its divestment from Masela PSC by end-2021. Shell and Inpex have been jointly developing Abadi field.

TotalEnergies in May 2021 remobilized teams for work on its 5.6-million tpy Papua LNG plant following meetings with the government of Papua New Guinea. Work had been paused for 1 year due to the COVID-19 pandemic. The company hopes to launch FEED early 2022 in preparation for a 2023 FID.

Papua LNG will liquefy gas from the onshore Elk and Antelope fields in Block PRL-15. Gas from these fields will be transported by a 320-km onshore-offshore pipeline to the plant’s Caution Bay site, north of Port Moresby.

Papua LNG’s two trains will be integrated with ExxonMobil’s existing 7.9-million tpy PNG LNG plant at the same site. Discussions regarding a 2.7-million tpy expansion of PNG LNG are ongoing, but have been hampered by a failure to come to terms with the Papua New Guinea government regarding the P’nyang gas development, one of the planned feed sources for the expansion.

Woodside Petroleum is interested in selling as much as 50% of its 4.5-million tpy Pluto LNG Train 2 on Burrup Peninsula near Dampier, and hopes to find a buyer before taking FID later this year. The train would be fed by gas from Scarborough field and start operations in 2025.

The Western Australia government in June 2021 imposed a net-zero emissions condition on both the proposed Pluto expansion and the existing train. Woodside agreed to the requirements and said it would need to cut overall emission from Pluto by 30% by 2030 to reach net-zero by 2050.

Santos Ltd. is likewise considering adding a second 3.7-million tpy train to its Darwin LNG liquefaction plant in northern Australia. The company took FID on development of the offshore Barossa field in March 2021, giving Darwin LNG a new potential feed source. But declining Australian production in general could force this gas to be used for existing operations instead.

Petronas loaded the first commercial cargo from its 1.5-million tpy PFLNG Dua onto MISC Bhd’s Seri Camar LNG carrier in March 2021 for shipment to Thailand. PFLNG Dua, Petronas’s second floating plant, is operating in 1,300-m water at Block H, Rotan gas field, 140 km offshore Sabah, Malaysia.

Energy World Corp.’s (EWC) 500,000-tpy Sengkang LNG Train 1 is expected to come online this year in South Sulawesi, Indonesia. EWC plans three additional trains for the plant, bringing its eventual capacity to 2 million tpy.

Europe

Russian media reported Yamal LNG’s 900,000-tpy fourth train reaching full capacity in June 2021, bringing total capacity to 17.4 million tpy. The plant’s 5.5-million tpy first train is scheduled for maintenance Aug. 1-19, 2021. Yamal LNG is a joint venture of PAO Novatek (50.1%), TotalEnergies SE (20%), China National Petroleum Corp. (CNPC, 20%), and Silk Road Fund (9.9%).

PAO Novatek wholly owned subsidiary, Novatek Gas & Power Asia Pte. Ltd., and Shenergy Group in March 2021 signed a 15-year agreement for LNG to be produced at Novatek’s planned 19.8 million tpy Arctic LNG 2 plant. The agreement stipulates shipment of 3 million tpy of Arctic LNG 2’s production to terminals in China on a delivered ex-ship basis.

Arctic LNG 2 will use three 6.6-million tpy liquefaction trains installed on gravity-based platforms on Gydan Peninsula across the Gulf of Ob from Yamal LNG. Novatek expects to complete the project in 2024. Arctic LNG 2 in April concluded 20-year LNG sales and purchase agreements with the project’s participants for all remaining anticipated production and expects sales from the plant’s first 6.6-million tpy train to begin in 2023. Project participants include Novatek (60%), TotalEnergies (10%), CNPC (10%), China National Offshore Oil Corp. Ltd. (10%), and the Japan Arctic LNG consortium of Mitsui & Co. Ltd. and Japan Oil, Gas and Metals National Corp. (10%).

Novatek also had been developing the 4.8-million tpy Ob LNG plant, intending to use the same proprietary Arctic Cascade liquefactions technology in place at Yamal and planned for Arctic LNG 2. But the site might now be used to produce ammonia, according to local press reports.

Gazprom’s RusKhimAlyans complex will have 13-million tpy of liquefaction (Baltic LNG) near Ust-Luga, receiving 45 bcmy of wet natural gas from the company’s Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula. Gas remaining after processing (including ethane extraction) and LNG production, about 18 bcmy, will go into Russia’s gas transmission system. The complex will produce as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG.

LNG and LPG produced at the Ust-Luga complex will be exported, while ethane from the site will feed nearby RusGazDobycha subsidiary Baltic Chemical Complex LLC’s proposed ethane cracking project, which will produce more than 3 million tpy of polymers.

Gazprom began construction on the two-train LNG plant in May 2021 and plans to put the first train in service by end-2023, with the second following 1 year later.

Africa

TotalEnergies in April 2021 declared force majeure on its 12-million tpy Mozambique LNG liquefaction project, citing the declining security situation in northern Cabo Delgado province and withdrawing all project personnel from the Afungi site. It had hoped to begin production in 2024.

The violent insurgencies in Cabo Delgado also threaten ExxonMobil’s yet-to-be sanctioned dual-train 15.2-million tpy Rovuma LNG plant, liquefying offshore Area 4 production.

“The ongoing insurgency in the Cabo Delgado region, while initially seeming manageable, appears to have dented Mozambique’s LNG dreams. We now expect Total’s Mozambique LNG to start production only in 2026, with construction unlikely to resume without demonstrably stronger security arrangements at the Afungi site. Rovuma LNG may be delayed enough to mean it is brought online only around 2029,” said Kaushal Ramesh, LNG analyst at Rystad Energy, in May 2021.

Coral South LNG, however, is using a 3.4-million tpy floating LNG (FLNG) plant linked to six subsea wells to develop gas resources in Area 4, Rovuma basin, off Mozambique’s coast. Coral South is being developed by Eni SPA, CNPC, Galp, Kogas, Mozambican-state ENH, and ExxonMobil. Output is contracted to bp PLC under a 20-year term with a 10-year optional extension. FLNG topsides installation was completed in November 2020 to meet planned 2022 startup. The vessel is expected to sail from Samsung Heavy Industries’ South Korea shipyard by yearend 2021.

Tanzania, having suspended development in late 2019, hopes to resolve outstanding issues regarding its Tanzania LNG plant (10 million tpy) in Lindi by October 2021, allowing 2022 FID. Construction would begin in 2023 to meet a planned 2028 startup. Equinor and Shell, however, have publicly stated that the time left to develop Tanzania’s gas resources is limited and Equinor wrote down its book value in the project at end 2020.

Djibouti LNG’s efforts to bring a 3-million tpy FLNG plant online offshore northeastern Africa stopped progressing in 2020 due to the COVID-19 pandemic.

Kosmos Energy in May 2021 reported that work on Tortue Ahmeyim field development, including the 2.5-million tpy Golar Gimi FLNG plant, was 58% complete as of the end of first-quarter 2021 and expect work to be 80% done by yearend. Golar and project-lead bp, however, have delayed delivery of the vessel to 2023. Golar Gimi will be stationed on the Mauritania and Senegal maritime border.

Brass LNG (10 million tpy) has been under development since 2003, but in June 2021 Nigerian National Petroleum Corp. (NNPC) declined to continue funding the project. The 12.6-million tpy OK LNG project, once a joint venture of NNPC, Shell, Chevron, and BG Group, but now with NNPC as its sole proponent, has also stalled.