An increasing number of construction-related issues at major LNG projects this year has kept a demand-hungry natural gas market wary of delays, but analysts say price and production forecasts remain mostly intact – so far.
Nine North American liquefied natural gas export projects are inching along on varying construction schedules at the same time. Two major projects, Golden Pass LNG and Plaquemines LNG, expect to initiate start-up activities as early as the end of this year, creating a critical question mark in production and price forecasts.
“Golden Pass and Plaquemines should add either side of 5 Bcf/d of natural gas feed gas demand when both facilities are fully functional,” NGI’s Pat Rau, senior vice president of Research & Analysis, said. “That's roughly 5% of current Lower 48 dry gas production.”
Six Months Or 12?
Golden Pass and Plaquemines are expected to have phased commissioning processes. Each train – or for Plaquemines, block of trains – would add natural gas demand in incremental stages. Each of the three trains at Golden Pass in Southeast Texas could add around 700 MMcf/d in feed gas demand, Rau said. Each of the two phases at Plaquemines in Louisiana could add roughly double that amount.
Speculation that years of labor market constraints and inflationary pressure from the Covid-19 pandemic coming to a head in the form of delays has made the market hone in on any hint of lags in commissioning.
That speculation broke in May, when one of the engineering, procurement and construction (EPC) partners working on Golden Pass, Zachry Industrial Inc., filed for bankruptcy. Project partners ExxonMobil and QatarEnergy had months earlier changed their guidance for a potential start-up of Train 1 from December to early 2025.
Since then, Zachry has laid off more than 4,400 people assigned to the project. Golden Pass has warned the bankruptcy could push the timeline back further.
Earlier in the month, EPC partner Chiyoda Corp. advised shareholders that the bankruptcy court had approved a path for the Japanese firm and McDermott to continue paying contractors and using some equipment on site while Zachary evaluated whether it could continue to be a part of the project.
However, in an emergency motion, Golden Pass lawyers told the bankruptcy court handling Zachry’s restructuring that the firm's refusal to drop its interest in the EPC contract was blocking the partnership's ability to ramp up construction.
As of Tuesday (June 18), Golden Pass estimated Train 1 was 83% complete and could be ready by next June if the project partners were able to sustain a full workforce. At peak construction, more than 7,000 people are expected to be working on the project.
“Moreover, the time to completion will be delayed further if Zachry continues to impede progress,” Golden Pass counsel wrote in the motion. “Because of Zachry’s actions, workers and vendors are already leaving –or have left– the project and will be difficult to replace.”
East Daley’s Jack Weixel, senior director of energy analysis, said the firm has taken a “hedged” approach to anticipating the start of production on Train 1 at Golden Pass, pushing an estimated ramp to mid-2025. Even with a possible six-month delay, though, the next year’s forecast is largely on course.
“We don't see a major change in the production rate for next year, because price ultimately is going to dictate that,” Weixel told NGI. “Our forecast is only going down 15 cents for calendar year 2025, which still puts us roughly 17 cents above the current forward curve.”
In May, East Daley projected Henry Hub could average $3.75/MMBtu in 2025. Gains in prices through the upcoming winter could be driven by roughly 4.2 Bcf/d in feed gas demand on the Gulf Coast and in Mexico from export projects other than Golden Pass.
As long as delays in major projects remain under a year, Weixel said, large-scale producers in the Haynesville Shale, like Chesapeake Energy Corp. and Comstock Resources Inc., should be able to start reversing curtailments they instituted this year.
Rau said producers, especially in the Haynesville, have added around 2-3 Bcf/d of “virtual storage” through curtailed production and deferring completions, which could be turned in line within several weeks after demand arises.
On the other hand, Rau added, the risk of extended delays for Golden Pass or Plaquemines also being pushed back could lead to production lags leading to tight supply and demand balances in Winter 2025/2026. That’s when feed gas demand combines with incremental growth.
“Keep an eye on the March/April 2025 spread, the so-called Widow Maker, for more clues,” Rau said. “The longer these facilities are delayed, the more that spread may blow out.”
Forward Momentum
On the upside, Plaquemines has appeared to skirt major construction and timing issues, according to energy analytics firm Arbo. However, there still may be some gray area around initial feed gas demand.
Plaquemines developer Venture Global LNG Inc. previously targeted first LNG this summer. It had told federal regulators that construction is ahead of schedule. Arbo’s Responsive Analytics Manager Reilly Meinert told NGI “it is not likely they will be in commercial operation this year, based on their saying commissioning is expected to be 24 months.”
EPC contractor Zachry is also working on Plaquemines LNG. It formed a joint venture with engineering firm KBR Inc. in 2021 to construct the initial 13 million metric tons/year (mmty) phase of the facility.
A Venture spokesperson told NGI the company does not “anticipate any material impacts on execution at Plaquemines” from Zachry’s bankruptcy proceedings.
A small amount of gas was introduced to the facility southeast of New Orleans in May to pressurize parts of a pipeline system. At that time, the Federal Energy Regulatory Commission granted permission to flow gas to the facility’s gas gate and the Gator Express pipeline.
Timing for major commissioning activities for the first blocks at Plaquemines, however, could be largely contingent on the delivery of imported LNG. The Virginia-based company asked the U.S. Department of Energy for permission to import up to 600 MMcf over a two-year period to use in the cooling equipment. The company also asked for imports to begin in mid-June, and expects all LNG cargoes to be received later this year.
An earlier than expected startup to Cheniere Energy Inc.’s Corpus Christi Stage 3 expansion project is also offering some potential cushion for the demand outlook. In guidance earlier in the year, management told investors the first train of the 10 mmty project could start production by the end of the year.
In April, Cheniere asked FERC for permission to connect the first train of the expansion to power. The company has to file separate requests for approval before introducing gas to the Texas project. However, connecting the power facilities is typically a sign that systems may be ready for broader testing.
More Demand North And South
Further south in Mexico, progress on the first phase of Sempra Infrastructure’s Energía Costa Azul (ECA) is on track for a start up by mid-2025. The 3 mmty project was previously expected to be the first in a chain of terminals in Mexico boosting the draw of Permian Basin gas south of the border.
However, New Fortress Energy Inc.’s (NFE) Altamira LNG, also in Mexico, has added a wild card to the outlook. The market has been watching for cargoes to depart the offshore installation on Mexico’s east coast since March. Delays with installation and a late April malfunction with the cold box pushed the schedule back several months.
On June 14, NFE confirmed it had made progress on pre-commissioning activities and expected first production within two weeks. The first exported cargo is slated for July. The first phase consists of two trains, each with 1.4 mmty of capacity, hoisted on jack-up rigs.
The floating LNG units, and successive phases planned onshore, are to be supplied feed gas by the marketing arm of Mexico’s Comisión Federal de Electricidad (CFE), CFEnergía, from the Agua Dulce Hub in South Texas via the Valley Crossing pipeline. CFE transports volumes on the Sur de Texas-Tuxpan pipeline.
Also adding to the upside are reports that start-up activities at LNG Canada in British Columbia may start by the end of the year. The 2 Bcf/d capacity facility was previously expected to come online in mid-2025, but commissioning may begin later this year, according to joint venture partner Shell plc.
LNG Canada’s output, which could account for 11% of Canada’s current gas production at full capacity, has the potential to spike prices in the western United States. Large gas utilities including Northern California’s Pacific Gas & Electric Corp. (PG&E), could lose Canadian supply to LNG exports.
PG&E may “look to source more gas from the Rockies, given the favorable spreads to PG&E Citygate from Opal versus the SoCal Border,” Rau noted recently. “Perhaps this would help breathe some new life into Ruby Pipeline LLC, which Tallgrass Energy Partners bought out of bankruptcy in January 2023.”
