Boardroom conversations are likely picking up among the owners of LNG Canada, the country’s giant liquefied natural gas export terminal project in British Columbia.
With its first phase more than 70% complete, the group that includes Shell PLC, Malaysia-based Petronas, PetroChina, Mitsubishi Corp. and South Korea’s Kogas must make a final investment decision to fund its second stage that could generate a total project cost of more than $31 billion, with gas extraction and transport included if both phases are built. Officials of the project, including its construction joint venture Fluor-JGC, have not commented on when the decision will be made, only indicating it will happen before first-phase operation starts in about 2025.
While LNG expansion in the past was seen as setting back climate change mitigation, many now wait to see how recent global events that have spurred more concern over "energy security" affect the second-phase decision.
Since work began at the remote British Columbia site in 2015, Canada’s largest private investment has been set to use natural gas-powered turbines—with approval from government regulators—in compressors that will cool fuel to -162° C to reduce the volume for export.
LNG Canada's first phase gas export terminal in Kitimat, B.C. is set to come on line in 2025. But an expansion faces gas emissions and power supply dilemmas.
Photo courtesy JGC-Fluor BC LNG JV
In the interim, the province launched its CleanBC initiative to lower emissions 40% by 2030 and reach net-zero by 2050—with the facility weighing climate change impact and project economics in switching to cleaner but more expensive hydroelectric power, which would require hundreds of kilometers of new transmission lines to reach the coastal site.
Now, climate urgency is colliding with global concerns, catapulted by Russian oil and gas cutoffs to Europe that followed its invasion of Ukraine one year ago, along with shifts in supply, demand and cost scenarios for renewable energy and fossil fuels in other global markets, such as Asia and Africa.
“With our five joint venture participants, we continue to evaluate the timeline and scope for a second phase expansion,” says Teresa Waddington, LNG Canada vice president. “A final investment decision will take into account several factors that include overall competitiveness, affordability, pace, future GHG emissions and stakeholder needs.”
The fuel supply and cost gyrations have forced some to rethink how quickly the renewables shift will realistically occur—despite pressure from government entities and climate change advocates—and fossil fuel’s role in future global energy supply. Some observers see natural gas as a needed player in the energy transition. Despite uncertainties, “we expect that U.S. natural gas production will establish new record highs in both 2023 and 2024, leading to lower domestic prices,” said Energy Information Administration chief Joe DeCarolis.
In its LNG outlook released Feb. 16, energy giant Shell said global trade in liquefied natural gas totaled 397 million tons last year, with S&P Global citing "industry forecasts" of demand rising to between 650 and more than 700 million tons per year by 2040. LNG imports by European countries, including the UK, totaled 121 million metric tons last year, up 60% compared with 2021, Shell said—adding that only a temperate 2022-2023 winter and reduced demand by China and South Asian nations enabled Europe to avoid dire shortages.
"The war in Ukraine has had far-reaching impacts on energy security around the world and caused structural shifts in the market that are likely to impact the global LNG industry over the long term," said Steve Hill, Shell executive vice president for energy marketing.
Image Uniper
Germany rushed work to build its first gas import infrastructure in two cities to meet needs after Russia supply cutoffs (above), and is planning larger onshore import and process hub facilities (right).
Photo by Sina Schuldt/Picture Alliance/AP Images
In the U.S., natural gas made up 32% of its energy consumption in 2022, says the U.S. Energy Dept. After a wind and solar energy building boom over recent years in Texas, state regulators approved in January a proposed plan to add more natural gas power to its grid as a needed resilience measure. The plan has critics, who cite costs, and faces approval by legislators.
Tennessee Valley Authority also said last month it will proceed with a plan to replace its large Cumberland coal-fired power plant in Tennessee with a $1.8-million gas-fired facility despite opposition from advocacy groups and EPA, which said the utility did not sufficiently analyze clean energy alternatives. The agency, however, has declined to further challenge the 1,450-MW combined cycle gas project, noting "there were practical and achievable actions TVA could do ... to improve environmental outcomes while meeting need" to close the coal plant, said a Feb. 15 Associated Press report.
At the same time, the trend tees up the continued clash between energy companies gaining big financial returns from a gas resurgence and a push for production, even with more emissions-cutting investments—and advocates who say the producers' clean energy shift is too slow to combat climate change urgency.
Market and price dynamics have led to recent record financial gains among major energy players. Shell last month reported adjusted earnings of $39.9 billion for 2022, double the amount for 2021. After posting a record $28-billion profit last year, BP now expects to reduce oil and gas production in 2030 to about 25% below its 2019 level, adjusted from its previous guidance of a 40% cut, said CEO Bernard Looney.
Critics of profiteering and the perceived slow push on renewables included President Joe Biden in his Feb. 7 State of the Union, but he also said, in a comment not in the official transcript, that “we are still going to need oil and gas for a while … at least another decade, and beyond that.” Energy Secretary Jennifer Granholm told a Jan. 23 press briefing that “we know that our liquefied natural gas exports have been a significant help to our allies,” even as her agency earmarks a large amount of the $369 billion in Inflation Reduction Act funding for clean energy-related investment and technology.
Hard Decisions in Europe
Germany has long relied on its Russia-supplied natural gas for heating and to run its industries, a key economic engine for Europe. Despite aggressive moves in recent years away from fossil fuels—an effort called Energiewende, or energy transition—Germany, and other European nations, scrambled this year to build new gas import infrastructure amid Russian supply cutoffs. “There may be investments that make sense, in this transition phase,” German Chancellor Olaf Scholz told reporters last June at the G-7 summit, as Germany scrambles to build a new energy infrastructure network.
Two floating storage and regasification terminals now operate in Wilhelmshaven and Lubmin, with a third unit elsewhere soon to start transferring U.S. gas imports to pipelines on the German grid. U.S. suppliers “have already started providing Germany with a diversity of supply,” says Giles Farrer, head of gas research at consultant Wood Mackenzie. Terminals will have a combined capacity of 17 billion cu m by year end, with three more also to operate by then.
New global energy security concerns will prompt continuing investment in fossil fuel capacity, experts say
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Germany’s supply boost also includes extending the life of some coal-fired plants, and keeping two nuclear reactors on standby through at least April, after they were set to close in 2022. Police last month removed protesters from an open-cast lignite mining site in western Germany.
“The government has a hard decision to make,” says Sascha Boden, energy and climate policy advisor at the nonprofit Environmental Action Germany. “Either build out even more fossil infrastructure and completely disregard climate protection targets, or actually step up their game in terms of the energy transition.”
While acknowledging the country's tough position, the group filed suit last September, seeking to cut by a decade the 2043 operating sunset of the planned gas pipeline from the Wilhelmshaven terminal. Groups also are concerned about plans to build permanent land-based LNG import terminals at coastal sites to replace floating platforms. “We’re still missing a holistic energy concept that includes how much liquefied natural gas you want to have, and from where,” Boden says.
The government says LNG terminals built today can be retrofitted in the future and converted to greener sources of energy, such as hydrogen. But after examining future potential for conversion to green hydrogen or emissions-free ammonia, the Fraunhofer Institute for Systems and Innovation Research concluded last year that future demand cannot be quantified. Analysts also noted lack of experience with larger scale components such as heat exchangers and storage tanks for designated hydrogen infrastructure, adding that conversion concepts must be built into construction. To boost demand, the European Parliament on Feb. 9 backed proposals to allow more renewable and low-carbon gas, including hydrogen, into the EU market.
As the Ukraine war enters its second year, European LNG imports continue to rise. Finland has a floating facility that started commercial operation in January. There are further plans for units in Greece, Holland, Italy, Ireland, Cyprus and Poland, according to S&P Global. It said EU nations imported 58% more LNG, with the U.S. by far the main exporter.
Protestors at German LNG import construction site seek faster action and more funding for renewable energy to address a fast-shrinking window for climate change mitigation.
Photo by Hauke Christian Dittrich/Pixture Alliance/AP Images
Energy Security
As such, the U.S. is set to more than double its LNG export capacity in the next five years, reaching 169 million tons by 2027, according to BloombergNEF data. Last year was the busiest for U.S. gas contracting since most exports started, the Center for LNG, a trade group, told Natural Gas Intelligence.
Also a factor in the ramp-up to build new U.S. capacity has been the shutdown since last June of major export site Freeport LNG in Texas following an explosion and fire, an event that has affected global gas prices. Exporting about 15 million tons per year, it has undergone major repairs and this month gained approval to begin limited commercial operation.
"The unexpected shutdown of the Freeport terminal ... demonstrated how significantly the US connection with global gas markets has grown," said a Feb. 23 S and P Global analysis. The site's return to operation "marked the end of the biggest outage in US LNG export history, which led to widespread market impacts and illustrated the importance of a US LNG terminal as a cog in the global energy system."
Energy market analyst Rystad Energy expects the world market for oil and gas contractors to reach $1 trillion in 2025 and remain high for several years. “Energy security was out of fashion for many years, but today the energy crisis has … put [it] back on the agenda worldwide,” says Joseph McMonigle, secretary general of International Energy Forum, a group of global energy ministers. Annual upstream oil and gas investment will need to reach $640 billion in 2030 to ensure adequate supply, he says.
Energy giant BP said it will slow planned cuts in oil and gas production, but touts emission reduction steps such as its $1.3-billion Grand Slam electrified processing network in the Texas Permian Basin.
Photo by Marc Morrison—Photography + Motion for BP
More than a dozen LNG projects have been approved by federal regulators but are not yet under construction, with most along the Gulf coast. These include Energy Transfer LP’s Lake Charles LNG, Venture Global LNG Inc.’s CP2 project, the first phase of Sempra Infrastructure’s estimated 10.5-billionn Port Arthur LNG, for which Bechtel signed an updated fixed-price EPC contract last year, and NextDecade Corp.’s Rio Grande LNG.
Cheniere Energy Inc.’s expansion of the Corpus Christi LNG site won corporate approval last year. “It’s a reminder that we don’t have the luxury of making a transition to an intermittent power system—which is, unfortunately, where we stand with renewables—until we have storage,” said Venture Global CEO Michael Sabel at a recent energy industry gathering.
U.S. projects face competition from fast developing LNG export infrastructure in Qatar, with China as a major customer, as well as completion impacts from a still unstable supply chain and workforce issues. With large export terminals taking up to five years to build, developers such as New Fortress Energy are constructing modular floating LNG export projects off the U.S. and Mexico Gulf coasts, using repurposed drilling jack-up rigs as their bases.
Many are watching the actions of the Federal Energy Regulatory Commission in project approval. Last month, it denied a Sierra Club push to delay the estimated $10-billion Rio Grande LNG terminal. The group contested the developer’s claim that carbon capture technology used during gas cooling in one of North America’s largest planned systems would make it the “greenest LNG project in the world.” The group and others say cooling only accounts for up to 7% of plant emissions, with upstream and downstream impacts not addressed.
FERC has been expediting proposed LNG environmental reviews, based on recent actions, but the eventual naming of a new chair to replace Richard Glick could reactivate a now stalled policy to make overall GHG emissions a bigger factor in project approval.
“Our members invest in cutting edge developments for new technologies like carbon capture and hydrogen, and developed technologies like enhanced drone monitoring for leak prevention and detection,” says a spokesman for the Natural Gas Supply Association and Center for LNG. “Natural gas certification programs also offer another good opportunity for further reductions in emissions.”
Joseph B. Powell, founding executive director of the University of Houston Energy Transition Institute and Shell former chief scientist, points to low-cost changes such as replacing or modifying pneumatic process equipment. S&P Global estimates that 25% of U.S. natural gas is sold with some certification of carbon content, up from none a few years ago.
'Healthy Skepticism'
But activists and developers are debating, in reports and in court, the veracity of certification. “There are lots of oil and gas companies making claims about the methane they produce,” says Dan Grossman, associate vice president for energy transition at advocacy group Environmental Defense Fund. “Some even call it ‘responsibly sourced gas’ or ‘low methane gas.’ Absent a standardized approach, based on empirical, measurement-based data, claims of certifiers and operators should be approached with healthy skepticism.”
Michael Clifford, associate vice president in Black & Veatch’s energy and process industries unit, notes that with natural gas considered the cleanest of fossil fuels, capturing fugitive emissions has not been a high priority. “But now that the greenhouse gas impact is really understood better, there are opportunities—really obligations—to reduce those emissions in the overall natural gas value chain.”
Adds Dary Burnett, LNG project manager at Burns & McDonnell: “LNG is used as a backup to maintain natural gas as dispatchable, but it is not clean enough for the future.”
The U.S. is set to more than double gas liquefaction export capacity over the next five years, as more developers commit to facility construction such as the estimated $10-billion Rio Grande LNG site in Texas (right). Rendering right, NextDecade
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Focus on Flaring
Methane emissions are set to be a particular focus, especially as the U.S. Environmental Protection Agency moves forward on new regulatory curbs, with the public comment period closed Feb. 13 on its proposal. “Methane will do the same amount of damage as CO2 over the next decade, even though it’s less abundant in the atmosphere,” says Desirée Plata, an MIT engineering professor. “The field of methane removal lags far behind.”
Grossman of EDF, which has done significant monitoring of methane flaring in the Texas Permian Basin, wants more study of methane leaks from the LNG supply chain, especially transport, as well as “comprehensive rules,” such as what EPA is finalizing.
Advocacy groups claim more than 400,000 comments were submitted by rule supporters. "The response to EPA during this public comment period leaves no question: the agency must strengthen and finalize the strongest possible methane rule as swiftly as possible," said Kelly Sheehan, Sierra Club senior director of energy campaigns."
But the American Petroleum Institute noted in its comments that despite EPA responses to regulation requirement issues it raised earlier, "we still have serious concerns regarding the cost-effectiveness, technical feasibility and legal soundness of many aspects" of the current proposal, including its effective date.
Vaseem Khan, senior vice president of operations for McDermott International, which has worked on engineering and construction for a number of LNG and other gas facilities, including the Freeport site, urges a “holistic approach” to regulation. “Some ambitions of the regulatory framework are actually impractical or unachievable, or just can’t be implemented in a short term,” he says.
BP has moved to curb flaring and other greenhouse gas emissions in Permian operations, building the $1.3-billion Grand Slam facility in 2020. The centralized network of tanks, pipes and equipment gathers, transports and processes oil, gas and byproducts for direct shipment to customers—with emission controls designed in at key connection points. Despite its higher flare rate than peers based on earlier EDF data, BP said that flaring was at 2% of its Permian production as of 2021. It also projects 95% of Permian wells to be electrified by year-end.
The oil giant also completed last month a $4-billion deal to buy Archaea, a firm that produces and sells landfill gas as renewable natural gas. Anja-Isabel Dotzenrath, BP executive vice president for gas & low carbon energy, notes its continued clean energy focus, including U.S. offshore wind investment. “Low carbon, that’s hydrogen and renewables, has been allocated $30 billion of [capacity expansion funding]until end of the decade,” she told publication Recharge.
Power Services firm We Energies contracted Burns & McDonnell to provide engineer-procure-construct (EPC) services for two peaking facilities in southeastern Wisconsin to store LNG and boost system reliability.
Photo: We Energies and Curtis Waltz/aerialscapes.com
Electrification is probably the most prevalent decarbonization strategy in the enlarging LNG sector, says Justin Ellrich, LNG solutions leader at Black & Veatch. While used for small plant refrigeration in the last few decades, “that’s now being applied to larger and larger sizes, and if you can that power from renewable sources, obviously that’s a big reduction.”
He notes his firm’s involvement in engineering for the smaller scale Cedar LNG terminal in British Columbia, which aims to tap the region’s available hydropower and use offsite modularized construction. Ellrich also sees electrification used in natural gas pipelines to replace gas-fired turbines “where compression is needed to keep the gas moving down the line as it loses pressure.”
Clifford of Black & Veatch also notes work on projects that have biomass as a feedstock to generate synthetic natural gas. These are in the planning stage and could start construction next year, he says. “Most of those projects have some element of a first-of-a-kind challenge around gas cleanup and need some improvement in efficiency to make them economical,” Clifford says.
On a smaller scale but with broad potential, Burns & McDonnell notes EPC work in building peaking plants, in lieu of pipeline expansion, for two utilities in southeastern Wisconsin, where natural gas will be stored in liquefied form to provide a reliable supply, even on short notice. “More R&D is happening in equipment for smaller scale peaking facilities,” says project manager Burnett.
Meanwhile, at the LNG Canada site, Fluor project chief Ian Swanbeck notes that not using hydroelectric power for compressors “was a design decision by LNG Canada,” but says current phase-one turbines and compressors “are a new generation, more fuel efficient and with less GHG produced.” He emphasizes that at the unique site, “no matter what we do we impact it, but we hope to minimize that.”
LNG Canada CEO Jason Klein was optimistic in comments to media last year of the project's energy transition durability. “The cleanest molecule is going to be the last molecule standing,” he said. “We are that clean molecule. When people start getting really picky, whether driven by carbon price or otherwise, the cleanest LNG will be the last LNG—which right now, in the world, that’s right here.”
At the Squamish, B.C., site of the $5-billion Woodfibre LNG export terminal just getting underway, McDermott International is managing preconstruction work for a project that will use only hydroelectric power.
“We’ve identified numerous pathways that can reduce emissions associated with building an LNG plant by 60% to 70%, some immediately applied, some maybe in five years and some that will take 10 years,” says its senior executive Khan. “There won’t be one solution. It will be a combination of different solutions. This is a whole-of-industry effort to get this done and it will be done.”
