LNG plant developers face added CCS cost challenge

LNG project costs have shown volatility over time and industry is seeking to overcome new challenges in efforts to reduce them. These challenges encompass not just rising raw material, labour and financial costs, but the LNG sector’s embrace of low-carbon initiatives to reduce the industry’s environmental footprint.

LNG plant costs rose in the period 2010-2014, driven in large part by the expansion and high project construction demand in Australia. Subsequently, there was a significant fall in both upstream and liquefaction plant unit costs, as the focus of LNG plant construction moved to the US.

In addition to innovation with small-to-mid-scale liquefaction trains, US LNG benefited from very different upstream conditions as a result of the country’s extensive shale gas development. Projects in some cases could simply plug into the extensive US gas network, a huge difference from Australia’s often remote offshore gas resources or its foray into coal seam gas. However, liquefaction plant unit costs also saw a fairly consistent decline, aided by another US-specific factor –the existence of brownfield sites housing idle regasification terminals. Much of the infrastructure for new US LNG plants was already in place.

As charted by the Oxford Institute for Energy Studies report LNG Plant Cost Reduction 2014-2018, the combined upstream and liquefaction unit cost of US LNG projects fell with the construction of Sabine Pass Trains 1-4 to under $600/TPA, vastly cheaper than the earlier Australian LNG plants, where costs ranged from $2,400/TPA to more than $4,000/TPA.

Floating LNG also entered the scene, offering a competitive option for remote offshore fields, which would otherwise have incurred large costs in bringing gas to shore.

Disease and war

Step forward another five years and the picture has changed yet again. The coronavirus pandemic wrought havoc with supply chains worldwide, and Russia’s war with Ukraine has added inflationary pressures, as well as sending European demand for LNG through the roof.

This has created the expectation that LNG spot prices will remain elevated, supporting the business case for the construction of new LNG supply capacity. The question now is whether developers can keep their cost base under control.

Even before emissions control is considered, the situation can be challenging:

• The cost of capital has been on an upward trend. Central banks worldwide have been raising interest rates in an attempt to contain inflation. The US Federal Reserve’s federal funds rate had jumped from near zero in March 2022 to a range of 4.755.00% in April 2023.

• Steel prices have been very volatile, rising close to $2,000/T in September 2021 for US hot-rolled coil. They are currently just over $1,000/T, leaving them 30% higher than in the 2015-2020 period. Cement prices in March this year were 36% higher than at the end of 2018.

• Labour costs have also been rising. In the US, wage inflation has not kept pace with consumer prices, but has nonetheless been increasing by a rate in excess of 6% in the period from May 2022 to January 2023.

All-electric drive trains – a no regrets option?

LNG developers are adding a focus to reduce their greenhouse gas emissions. The two principal means of addressing carbon emissions are all-electric drive trains and CCS.

Electric drive trains have a higher initial investment cost than traditional gas turbines used to drive compressors directly, but the advantages can soon roll in. Savings potentially result from more reliable operation, lower maintenance costs, increased shaft power efficiency, better emissions control and lower gas consumption, which allows more gas to be exported as LNG.

The key determining factor for the emissions outcomes from using electric drive trains at LNG facilities is the source of the electricity. For example, if the electricity can be sourced from renewable sources, then the emissions reductions can really start to mount.

This is the route LNG Canada has taken in its first phase of construction, sourcing renewable power from utility B.C. Hydro. However, a second-phase expansion is expected to use gas-fired generation as there is insufficient electricity transmission capacity to the remote project location.

As LNG Canada CEO Jason Klein said, “If the power was there today, it would be a pretty straightforward decision.”

The same problem is faced by all developers – is sufficient renewable electricity available at or near the site? And, even if it is, this doesn’t mean it will be allocated to LNG.

Norway’s state oil and gas company Equinor has run into problems with its plan to electrify the Hammerfest LNG plant at Melkøya. It wants to use power from Norway’s national grid to replace the use of gas. Norway’s power system is dominated by hydro generation, with an increasing component now supplied by wind power. Thermal generation makes up as little as 2% of the country’s electricity generation, making it one of the world’s lowest carbon power systems.

However, Norway’s parliament in April ordered the company to reassess the options for CCS as an alternative. Opposition to the electrification plan stems from concerns that the plant’s electricity consumption will drive power prices higher and reduce the availability of low carbon power for other industrial developments related to the energy transition. The impact of new power line construction on indigenous Sami reindeer herding was also a concern.

CCS is the pricier option

Equinor says CCS is the more expensive option although not for reasons which apply generically to all LNG plants. The problem is not the cost of the carbon capture, but integrating the capture unit with the plant, which will require a 170-day shutdown and deferred gas exports. Equinor’s assessment also suggests the need for a new CO2 pipeline, well and CO2 reservoir.

It estimates that adding CCS at the Hammerfest LNG plant would cost 37bn kroner ($3.5bn), of which the capture plant would account for 30%, plant integration including offshore compression 53%, and transport and storage costs 17%.

It also estimates that raw material and supply chain inflation mean the cost would be some 30% higher today than when the initial assessment was made in 2019.

CCS is gaining favour, but costs need to fall

The main sources of carbon emissions from LNG projects are upstream reservoir CO2, emissions from compression and emissions from on-site power generation.

A 5 MTPA LNG plant requires around 185 MW of power capacity for mechanical drive and about 45 MW for power generation. This implies a carbon capture plant with capacity to capture about 1 MTPA CO2, – a size similar to the Boundary Dam coal-fired CCS project in Canada, which cost around C$1.5bn ($1.1bn) and has not been extended to the sites’ other coal units.

While CCS costs are expected to fall, there is little question that pioneering projects, such as Boundary Dam, are expensive. The cost of Chevron’s CCS project at its Gorgon LNG project in Australia has increased to more than A$3.1bn ($2.0bn) and has so far been struggling to meet its storage targets.

As a result, CCS has been thought of as an expensive, often too expensive, option. However, International Energy Agency (IEA) analysis highlights that there is no single cost for CCS, and that CCS can be effectively retrofitted to existing industrial facilities, such as LNG plants, with costs lower for newbuild construction, where CCS can be part of the initial design.

In some cases, storing CO2 captured from the feed gas is the best option, while in others it may be postcombustion capture, or both. Almost all LNG projects remove CO2 from the feed-in gas source before use. Capturing carbon post-combustion from flue stream gas is more expensive.

Multiple factors will affect individual project costs, for example the proximity of an injection site. The concentration of the CO2 stream is a significant factor and the CO2 streams from LNG plants and natural gas processing are relatively pure, putting CCS for these applications at the lowest end of the cost scale. The IEA puts the cost range for capture at $15-25/T CO2 for concentrated CO2 streams, compared with $40-120/T for more dilute carbon streams.

Policy also plays a big role and US LNG developers have welcomed the recent passage of the Inflation Reduction Act, which increased the 45Q tax credit for capturing and storing carbon. This looks set to spur a range of CCS projects in US gas producing regions, notably the US Gulf Coast. A number of US companies have announced plans for CCS operations at their LNG plants, including Cheniere Energy, NextDecade, Sempra Energy and Venture Global.

It is also notable that all of these companies are active in searching for improved CCS technologies. CCS costs are expected to fall with wider development and greater experience. They need to.

The bottom line is that LNG developers are willing to shoulder an increase in cost in order to put effective carbon emissions controls in place, but not at any price. They are betting that just as they managed to reduce upstream and LNG plant unit costs in the 2014-2018 period, similarly cost containment can be achieved for CCS in the period up to 2030.