Technological, Operational and Energy
Pathways for Maritime Transport to Reduce
Emissions Towards 2050
Final report___________________________________________________
Report for OGCI/Concawe

ED 13389 | Issue Number 6 | Date 31/01/2022

Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

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Authors:
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ShakeelApproved By:
Tim ScarbroughDate:
31 January 2022
Ricardo reference:
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Executive summary
Introduction
This is the final report from a study for OGCI and Concawe on the “Technological, Operational andEnergy Pathways for Maritime Transport to Reduce Emissions Towards 2050”. The context for thisstudy is the International Maritime Organization’s level of ambition to reduce the total carbon emissions
from international shipping by 50% in 2050 compared to 2008 levels, as well as reducing the carbon
intensity of international shipping by at least 40% by 2030 and 70% by 2050 (again compared to a 2008base year)1. Given the commitments at a country level for the reduction of GHG emissions under theParis Agreement, and that global GHG emissions from shipping if ranked among countries would be
the sixth largest in the world, it is important that work is done to reduce GHG emissions from international
shipping that will otherwise not be addressed at a country level.
The IMO’s fourth greenhouse gas study, published in 2020, gave their forecasts for the future
development of emissions from international maritime transport, under wider global economic scenarios
consistent with limiting global temperature rise to less than 2°C.

These projections emphasised the considerable challenges that the industry faces to meet the 2050
ambition.
Context – historic and future trends
Historically, seaborne trade has been closely correlated with world GDP, at least since 1990. World
seaborne trade grows approximately in line with world GDP and has more than doubled over the last
20 to 25 years. Therefore with anticipated growth in global GDP, there is a need to decouple
international shipping emissions from economic growth.
Population, economic growth and energy access are the key drivers of demand for transport in allmodes. Higher economic activity, triggered by an increase in consumption, production, intensification of
trade, or a combination of several factors, usually implies an increase in demand for transport. With1

It should be noted that the IMO has started to discuss potential tightening of the ambition level, including a possible revision of the ambition in
2023.

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continued economic growth, it is expected that there will continue to be strong growth in the demand forthe international transport of freight, although different levels of growth in different global regions arelikely to lead to changes in the distribution of demand. Overall, the OECD expects global freight demand(measured in tonne-miles) to triple by 2050, relative to 2015 (OECD, 2019). If this is realised, seaborne
trade will exceed 120,000 billion tonne-miles by 2050 (double that of today).
There will be changes to the nature of the goods to be transported. Continued global efforts todecarbonise all sectors is expected to lead to a significant reduction in the demand to transport wet anddry bulk fossil fuels (oil and coal); this may be accompanied by an increase in demand for the transportof other goods, including raw materials and finished goods. Economic growth and regionalisation add
uncertainty to the projections as they act as opposite forces. Geopolitics is shaping the trade routes; thedevelopment of trade is highly dependent on international agreements.
In 2020, the growth in trade has been halted, and even reversed, by the effects of the COVID-19
pandemic. This adds considerable uncertainty to the future, particularly in the short to medium term. In
the long term, it is likely that the world will return to a more stable growth pattern, but whether it will
recover the previous economic (and hence transport demand) trajectory is far from certain.
Other changes in society will also affect demand: the continued digitalisation of our economies, as well
as novel technologies such as 3-D printing, could disrupt the “Asia-production for US and EU
consumers” model that emerged over the last decades and promote a shift to regionalisation and/or an
overall reduction in demand. The increasing emphasis (particularly in Europe) to try to shift to a morecircular economy – where virgin resource use is decreased, and waste streams are re-purposed as
products for other industries – could lead to structural changes in the maritime industry, as well as
potentially demand for new routes.
The rapid growth in demand over the past 20 years has led to significant changes in the structure of the
fleet, with increases in the size of new ships to leverage economies of scale. This has been largely
driven by the requirements to reduce fuel costs, as such costs are one of the strongest incentives for
operators. This has been particularly evident in the container sector, which has also been supported bya trend of increased containerisation of goods for transport, a trend that is expected to continue.
Continued pressure to increase efficiency could lead to changes in transport practices with, for example,
better use being made of empty containers returning from western economies to Asia, thus displacing
capacity of other vessels such as dry bulk.
To address the challenges of climate change, all sectors of the economy, including all modes oftransport, are under pressure to decarbonise. In aviation (the most comparable mode to maritime
shipping in terms of the distances covered per vessel), there are strong commercial incentives foraircraft manufacturers and airlines to continuously improve the fuel efficiency of their aircraft. The
International Civil Aviation Organisation has also introduced a CO2 standard that new aircraft types needto meet from 2020 (and all newly built aircraft will need to meet from 2028). Aircraft have long operating
lifetimes (similar to the maritime sector), but the strong economic pressures lead, in many cases, toairlines replacing their fleet more frequently, leading to a more rapid penetration of the latest technology
into the operating fleet than is, perhaps, evident in the maritime sector.
The light-duty road transport sector is easier to decarbonise as demands for vehicle range are lower,
and vehicles have much shorter lifetimes leading to a more rapid fleet turnover. Heavy duty vehicles,
particularly goods vehicles, also have challenges in decarbonising due to the high energy requirementsof transporting payloads for the long distances travelled.
There is also pressure on the rail sector to decarbonise. In this case, a significant part of the sector isalready electrified, using electricity supplied through the rail infrastructure (e.g. overhead line or thirdrail), rather than rechargeable batteries. This provides an option that can be extended more widely,although at considerable infrastructure cost, to achieve a greater decarbonisation (depending on the

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source of the electricity used). Other technologies, such as hydrogen, are also considered by the rail
sector to lower its GHG emissions.
Because of the structure of the shipping sector, it is more susceptible to a specific potential barrier tothe introduction of new technologies, known as the “split incentive” problem, than other transport
sectors. This is because responsibilities such as fuel charges, operational measures, technologicalinvestments and cargo loading can be allocated to either ship owners or ship charterers. Whether there
is an incentive for a Ship Owner to implement energy efficiency measures is often highly dependent on
the charter rate that the charterer pays to the ship owner. If the benefit of the energy efficiency measure
is not accrued by the party paying for its implementation, this can act as a barrier to the adoption of themeasure when ordering a new ship.
Analyses of different sources of data have shown that global CO 2 emissions from international shipping
were about 860 million tonnes in 2019, with a growth rate of over 2% per annum from 2013 to 2018.
The three main ship categories for CO2 emissions were bulk carriers, container ships and tankers.
Projections of future demand growth from different sources show considerable variations, ranging from
34% to 185% growth by 2050 (relative to 2018). The different future growth scenarios analysed for thisstudy, are shown in the figure below2.

Total demand for maritime freight (10^9 Tonne-miles)

250,000

200,000

ITF 2019
IMO GHG4 SSP1 RCP1.9
IMO GHG4 SSP1 RCP4.5
IMO GHG4 SSP1 RCP6.0
IMO GHG4 SSP2 RCP2.6

150,000

IMO GHG4 SSP2 RCP4.5
IMO GHG4 SSP2 RCP6.0
IMO GHG4 SSP3 RCP3.4
IMO GHG4 SSP3 RCP4.5
100,000

IMO GHG4 SSP3 RCP6.0
IMO GHG4 SSP4 RCP2.6
IMO GHG4 SSP4 RCP4.5
IMO GHG4 SSP4 RCP6.0
IMO GHG4 SSP5 RCP3.4

50,000

0
2000

IMO GHG4 SSP5 RCP6.0

2005

2010

2015

2020

2025

2030

2035

2040

2045

2050

If the average carbon intensity of the fleet remains constant over time, these scenarios would lead toemissions in 2050 being between 1.3 and 2.8 times those in 2018 (between 1.2 and 2.5 billion tonnes
CO2 in 2050).
Data published from the EU monitoring, reporting and verification (MRV) programme for 2019 show thatthe carbon intensity3 of newly built ships has been reducing by approximately 4.2% per year on average
since 1990. This is a higher rate of improvement than is generally considered appropriate for other2

The three scenarios were selected as being representative of the lower and upper bounds of those identified (and approximately in the middle),
having eliminated those that assume high continued growth in the demand for transporting fossils fuels, as not being consistent with the global focus
on climate change.
3

Carbon intensity defined as CO2 emissions per unit of work, measured in g/tonne-mile

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transport modes (usually closer to 1% to 1.5%) and may reflect a growth in the average size of newly
delivered ships over time as well as the introduction of the International Maritime Organization’s Energy
Efficiency Design Index (EEDI) Phase 1 (2015) and Phase 2 (2020) regulations. However, the literature
reviewed and stakeholders interviewed during the course of this study have indicated that the EEDI may
not be as effective as previously, with many ships already meeting the Phase 2 regulations; theagreement reached in 2019 to bring Phase 3 of the regulations forward from 2025 to 2022 will further
increase the fleet energy efficiency, recognising that improvements to date have been achieved quicker
than anticipated. Concerns have been expressed, however, that the unequal targeting of the regulation
by different sectors (vessel types) will still limit its effectiveness.
Nonetheless, the improvements in ship efficiency that have been achieved are significant and, if
maintained, should enable the IMO’s ambition on carbon intensity to be achieved in 2050. However,given the potential for future growth in demand, that would still be insufficient to achieve the IMO’s
ambition on total CO2 emissions for 2050.
Stakeholders interviewed for this study have indicated that regulatory intervention or guidance,
particularly regarding the adoption of alternative fuels, may be needed to achieve decarbonisation inline with the IMO ambition, unless price parity with conventional fuels can be achieved.
Fuel costs are a key component of vessel operating costs, despite the tendency for the maritime industry
to use the lowest cost (fossil) fuel. The COVID-19 pandemic initially led to further price reductions(average prices in May 2020 were nearly 50% lower than the average over the last five years). As aresult, the price differential to alternative fuels is further increasing the challenge of achieving
competitiveness for alternative fuels. Fuel prices have since rebounded to 2019 levels.
Many operators have implemented reduced vessel speeds to reduce fuel consumption, emissions andcosts. Speed reductions are especially effective in reducing fuel consumption when waiting times at
ports are converted to a slower cruising speed (just in time arrival) and the cargo carrying capacity ofvessels is maximised. Speed reductions of up to 30% have been used, though not for time-sensitive
cargos. The use of reduced vessel speeds also requires more ships to be at sea to achieve the samedelivery rates, reducing the overall effectiveness of the measure. Nonetheless, it is seen as having
overall benefits, which will increase further as new ships are delivered with lower design speeds.
Analyses of ship demolition ages show that for most categories the average retirement age is about 25
years, while for Roll-on-Roll-off (Ro-Ro) ships it is about 35 years. These long lifetimes limit the rate ofpenetration of new technologies into the operating fleet, so developments such as lower design speeds
will take several years to have an effect on the overall fleet efficiency. Some technologies, such aswaste heat recovery (WHR) have the potential to be retrofitted to the in-service fleet, thus accelerating
the penetration of such technologies. However, these technologies tend to have a smaller impact on
the overall fuel efficiency than other technologies that need to be incorporated at the design stage.
Meeting the IMO’s 2050 decarbonisation ambition will need significant change in the shipping industry
The IMO’s fourth greenhouse gas study, published in 2020, indicated that significant progress has been
made, with global emissions in 2018 being almost the same as those in 2008. However, their future
projections4 of emissions from the sector in 2050, of between 90% and 130% of 2008 levels, miss the2050 ambition by a considerable margin. To achieve the IMO ambition will require the introduction andlarge scale deployment of new technologies and/or alternative low-carbon fuels across international
shipping.
Traditionally, demand for maritime transport is well correlated to global gross domestic product.
Although projections for the future development show changes in the nature of goods transported –largely due to decarbonisation efforts in other sectors leading to a reduction in demand for transporting
4

Projections without additional GHG abatement technologies or fuels other than already agreed policies and measures. The projections are
principally driven by demand scenarios consistent with achieving a global temperature increase of less than 2°C

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oil and coal, but a commensurate increase in demand for transporting raw materials and products – themajority continue to show strong growth in demand. The demand projections in the IMO’s fourthgreenhouse gas study show demand growth of 58% to 153% by 2050, relative to 2018, depending on
the scenario.
Historically, emissions of greenhouse gases from the maritime sector have been dominated by carbon
dioxide (CO2), with three vessel categories (bulk carriers, container ships and tankers) contributing the
majority. In recent years, emissions of methane have increased strongly as more vessels using liquefied
natural gas (LNG) as fuel have entered service. These methane emissions are largely associated with
fugitive emissions from the engines (known as methane slip) and the strong growth has caused concern
in the maritime industry. Recent technological developments, such as the use of low-speed and highpressure diesel-cycle engines now provide significant reductions in methane slip.
Fuels, technologies and operational measures for decarbonising shipping have been selected into three‘packages’ depicting possible pathways to reaching the IMO ambition
The study reviewed available literature, and interviewed multiple stakeholders, to identify thetechnologies and alternative fuels that are available to decarbonise international shipping. The different
technologies and fuels are shown in the following figure.

Each of these technologies has been assessed for its applicability (ship categories), availability (entryinto-service dates), carbon reduction potential and cost (capital and operating).

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The different alternative fuels and technology options were combined into three “fuels and technology”
packages for subsequent analyses of their impacts. The packages were not defined as the “most likely
pathways”, but more to exemplify possible pathways, with significant variations to illustrate the range ofroutes available towards decarbonisation. These packages were characterised as:Package 1 ‘early pursuit of zero carbon fuels’
o

o





Ammonia and hydrogen for some newbuild vessels from 2025, ramping up to
all new-build ships by 2035.
Transitioning from “grey” to “blue” to“green” pathways for alternative fuels.
Medium take up of energy efficiency
technologies
andoperational
measures. 10% speed reduction
assumed for slow steaming.

Grey: Fossil fuel based
Blue: Fossil fuel based with carbon
captureOrange: Combining fossil & Green;
fossil & blue; or Bio and fossil
Green: Fully renewable

Package 2 ‘moderate uptake of interim anddrop-in fuels’oFrom 2025, HFO, MDO and LNG use increasingly substituted with drop-in biofuels(FAME, HVO and bio-methane (BioLNG)).

oMedium take up of energy efficiency technologies and operational measures. 20%
speed reduction is assumed for slow steaming.

Package 3 ‘initial maximisation of vessel decarbonisation measures’oFocuses on maximising technology use with subsequent transition to alternative fuels.

oHigh take up of energy efficiency technologies and operational measures. 30% speed
reduction assumed for slow steaming. Onboard carbon capture included in some newvessels (using carbon-containing fuels) post-2030.

oAmmonia and methanol fuel gradually introduced on new-build vessels by 2035, with
LNG being used by the remainder of new vessels. Transitioning from grey to blue togreen pathways (and LNG to BioLNG) for alternative fuels.

Further information on the fuels and technologies assigned to the three packages are shown below.

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5

In addition to the packages shown above, a sensitivity analysis was performed in which the alternative
fuels assumptions of packages 1 and 2 were combined with the advanced technology assumptions of
package 3, forming packages 1A and 2A.

5

Under package 2, FAME (Fatty Acid Methyl Esters) and HVO (Hydrotreated Vegetable Oils) were selected as examples of drop-in biofuels. Other
examples of drop-in fuels are under development, such as alternative conversion pathways based on similar biological feedstocks (such ashydrogenated palm oil (HPO) or hydrothermal liquefaction of biomass) or synthetic fuels (e-fuels). These may provide alternative options for dropin fuels for the maritime sector in the future. For this report, FAME and HVO were selected as biofuel examples based on their higher level ofmaturity.

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A new model was developed to estimate the impacts that these packages would have on the future
fleet, operations, CO2e emissions and costs
An entirely new bottom-up modelling methodology was developed to assess the impacts that these fueland technology packages would have on the future fleet, operations, emissions and costs. The
modelling methodology started from a definition of the present day fleet and used as input three baseline
scenarios (low, central, high) of future demand out to 2050 selected from the IMO’s fourth GHG study.
The model calculates:

The future development of the fleet (number of vessels by build year) under each of the baseline
scenarios, using a fleet retirement and growth/replacement approach;The future development of fuel consumption and emissions under the baseline scenarios, using
derived fuel consumption and emissions per unit work (tonne-mile);

The impacts of the fuel and technology package assumptions on the future fleet efficiency andfuel used (for the different fuel types);

The impacts of the different types of fuels used on the emissions;

The impact of the changes in the fleet definition (including the new technologies) on the vessel
prices and hence the capital costs;



The impact of the changes in the fuel consumption on the operating costs.

The overall analysis presented in this report is based on a scenario model, investigating the potential
emissions to 2050 under the three scenarios, together with the potential reductions in those emissions
arising from the implementation of the sets of technologies and alternative fuels identified. It is
important to recognise that these scenarios do not indicate the “most likely” future, nor definitive
indications of the costs to achieve particular levels of emissions savings, but indicate what may beachieved under certain assumptions.
The impacts on the capital and operating costs of the fuel production infrastructure were also calculated.
Although they are not included in the overall cost calculations, as they would be expected to beamortised through the increased fuel prices, these impacts are of importance to the oil and gas industry,
who would be critical in ensuring the availability of the alternative fuels to meet the future demand.
The IMO ambition is estimated to be met by all three packages when emissions are calculated on awell-to-wake basis; however only packages 1 and 3 would meet the ambition on a tank-to-wake basis
The results of the modelling showed that, by 2050, the emissions under the baseline scenario would be
between 4% and 82% higher than in 2008, depending on the demand scenario assumed, compared to
the IMO ambition of a 50% reduction (also relative to 2008). These increases in emissions were
calculated on a “well-to-wake” (WTW) basis, as this represents the full impact on the global climate andis important when considering the impact of alternative fuels.
Under the three fuel and technology packages, these increases in emissions are replaced by significant
decreases in most cases by 2050:


Under package 1, emissions are reduced by over 70% relative to 2008 under all three demand
scenarios, comfortably exceeding the IMO ambition.



Under package 2, the reductions in emissions are very similar to those under package 1.

Under package 3, the reductions in emissions relative to 2008 reach approximately 100% under
all three demand scenarios. The package includes a transition to “green”, but carbon-containing,fuels and the use of on-board carbon capture technology. The combination leads to a net captureof CO2 over the complete fuel production and combustion process, leading to a net negativeemission and a reduction of slightly over 100%. Carbon capture is therefore assumed to be

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available in time for this scale of deployment; under the assumptions used in the modelling, forthe central scenario, by 2050, approximately 35% of the global fleet is equipped with carbon
capture technology. Carbon capture then contributes approximately 16% of the total well-to-wakeemissions reductions under this package.
These changes in CO2e emissions are shown in more detail for 2050 (relative to 2020) in the figure
below. Results are shown for both well-to-wake and tank-to-wake emissions, with the results for thecentral demand scenario shown as coloured bars and the range between the low and high demand
scenarios represented by the error bars.
80%

Change in CO2e emissions compared to 2020

60%

Well to wake

Tank to wake

Baseline Package 1 Package 2 Package 3

Baseline Package 1 Package 2 Package 3

40%
23%

23%

20%

0%

-20%
-23%
-40%

-60%

-73%

-80%

-79%

-81%
-87%

-100%

-101%
-120%

All three packages are estimated to exceed the IMO ambition on maritime decarbonisation by 2050,
but this is only assured if the emissions are considered on a well-to-wake basis. The continued useof carbon containing alternative fuels under package 2 still produces significant levels of emissions
at the ship exhaust, even though they are offset by zero or negative emissions in the production(“well-to-tank”) process. Consideration may need to be given to reformulating the IMO ambition on awell-to-wake basis and incorporating well-to-wake emissions in policy measures to capture thedecarbonisation benefits of such alternative fuels and to enable their deployment.
Under package 3, about 16% of the total reduction in emissions to 2050 (relative to the baseline) is dueto the use of on-board carbon capture. The relative contributions of vessel technologies, alternative
fuels and carbon capture to the emissions reductions achieved under the three packages are shown
below.
Package 1

Package 2

Package 3

Technology

31%

34%

44%

Fuel

69%

66%

40%

-

-

16%

Carbon Capture

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The reductions in CO2e emissions shown above are accompanied by improvements in carbon intensity(CO2e emissions per unit work, expressed as g/tonne-mile) of between 50% (Package 1) and 65%(Packages 2 and 3) in 2030, relative to 2008, and between 91% (Packages 1 and 2) and 101% (Package3) in 2050. These changes in carbon intensity are similar across the three demand scenarios.
The cumulative quantities of the different fuels required to 2050 under the three packages to achieve
the emissions reductions described are shown below.
500
450

466
26
370

Energy consumption to 2050 (EJ)

400

123
350

359

0.2
20

305

49
300

116

HVO

30
27

49

250

47

72

20
200

25

60
54

317

150

49

154
50

FAME
Battery
HydrogenAmmonia

BioLNG
LNG
MDO
HFO

38

100

Methanol

127

97

0
Baseline

Package 1

Package 2

Package 3

The additional costs of implementing the packages are likely to be significant but vary between the
packages
The overall costs of implementing the packages described above have been estimated. The total capital
investment costs and operating costs to 2050 (both discounted to 2020 at a 10% discount rate) arepresented in the next two tables respectively, with the costs separated by the part of the industry
affected.
Change in discounted
capital costs frombaseline ($ billions)

Vessel capital costs

Alternative fuels
production investment

Port investment foralternative fuelhandling

Package 1

+$39

+$386

+$8.4

Package 2

+$34

+$29

$0.0

Package 3

+$413

+$79

+$0.2

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Vessel fuel costs

Vessel operating
costs (exc. fuel)

Fuel production
operating costs

Package 1

+$113

+$83

+$51

+$79

Package 2

+$364

+$91

+$37

+$0.5

Package 3

-$186

-$46

+$26

+$0.7

Change in discounted
operating costs frombaseline ($ billions)Ports fuelinfrastructure
operating costs

In practice, it would be expected that the increased costs for the fuel supply industry (both capital
investment and operating costs) would be recovered through the increased fuel prices. Therefore, it isinappropriate to sum the different cost elements in the cost tables above, as that would double-countthose costs. As shown in the results in the next sections, the total costs can be summarised as thevessel capital costs, plus the fuel costs and the other vessel operating costs, i.e. excluding thoseitalicised above.
The investment costs in vessel fleets and in fuel production infrastructure are of similar magnitudes(though both vary significantly between packages), while those in the ports infrastructure are
significantly lower. Under packages 1 and 3, the additional investment in fuel production infrastructure(compared to the baseline) significantly exceeds the increase in vessel fuel costs (and hence theincrease in income for the fuel producers). This reflects the need for new production infrastructure for
all alternative fuel production, while much of the conventional fuel required in the baseline will be
produced by existing infrastructure, so the saving in investment in conventional fuel production
infrastructure (under the packages) is comparatively smaller.
There are greater variations in the operating costs, with large positive changes for vessel operating
costs under packages 1 and 2, but negative ones under package 3. The increases in fuel production
operating costs are of a similar magnitude for all three packages, while the ports infrastructure operating
costs are significant for package 1, but much lower for packages 2 and 3.
The results of the emissions analyses indicate that the IMO ambition can be met (and, indeed,surpassed) with a high confidence under the assumptions described – that is to say that if the fuels
are switched to as described, there is high confidence on the resulting emissions from using thesefuels; there is however naturally a lower level of confidence in the calculated costs. In addition to theuncertainty inherent in the fuel price projections, the actual costs will be sensitive to decisions madein the future (for example, a high uptake of one alternative fuel type could lead to prices for different
fuel types significantly different from those assumed for this study, which were based on projections
assuming a more balanced marketplace)

The net present value of the accumulated additional total costs on the ships from 2020 to 2050 of
packages 1 and 3 are estimated to be less than half those of package 2
The cost analyses show that the achievement of the emissions reductions will increase costs by 4%(package 1), 9% (package 2) and 3% (package 3) over the central baseline scenario, based on total
costs to 2050 (using a 10% discount rate). The total additional costs incurred are a combination ofvessel capital costs, fuel costs and other vessel operating costs 6. The fuel price projections used in this6

The additional vessel capital costs include the addition of specific technologies but do not change with fuel type. The fuel costs are based on
specific pathways for the production – these were selected from a range of options identified as providing high levels of well-to-wake emissions
reductions, but they are not necessarily the pathways that would be adopted most widely

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study were provided by IHS Markit. The modelling also includes estimates for the additional fuelbunkering costs. Some insight into the additional fuel production infrastructure costs is provided in
Section 8 of the report; however, as the additional fuel production costs are expected to be amortised
through higher fuel prices, they are not separately included in the results discussed here. These costs
are calculated for each of the fuel and technology packages and the baseline; the impacts of the
packages are then seen as the difference from the baseline.
These costs are calculated as incurred over the full period from 2020 to 2050; net present values (NPV)
are then calculated using a range of discount rates. The results for the central demand scenario using
a discount rate of 10% are shown below.
Discounted costs Vessel capitalin $ billions
costs

Other operating
costs7

Fuel costs

Total NPV

Baseline$52$1,638$3,848$5,539Package 1$91$1,751$3,932$5,774

Package 2$86$2,002$3,939$6,027

Package 3$465$1,452$3,803$5,720

The total NPV increases under each of the packages relative to the baseline: package 3 is the least
expensive and package 2 the most expensive. Packages 1 and 3 produce delta NPV values (from thebaseline) of similar magnitudes (and the differences may be within the uncertainty of the calculations).
Further insight can be gained by examining the changes in NPV from the baseline for the threepackages, again for a discount rate of 10%, shown in the following table.
Change indiscounted costs
from baseline ($billions)

Vessel capital
costs

Other operating
costs

Fuel costs

Total delta NPV

Package 1

+$39

+$113

+$83

+$235

Package 2

+$34

+$364

+$91

+$489

Package 3

+$413

-$186

-$46

+$181

For packages 1 and 2, the additional total costs over the baseline are dominated by the increased fuelcosts, while for package 3 vessel capital costs dominate (as expected as it has the highest level ofadditional vessel technologies applied of the three packages). The high fuel costs under package 2 areprimarily related to the use of drop-in fuels, principally BioLNG, FAME and HVO 8. The investigations
under this study identified higher projected fuel prices to 2050 for these fuels than other types.
Combining the calculated emissions reductions and additional costs, with a discount rate of 10% applied
to both emission savings and costs, gives cost-effectiveness values in $/tonneCO 2e:

7

Other operating costs include crew costs, stores costs, lubricant costs, maintenance costs, insurance costs and administration costs.

8

There is a higher level of uncertainty in the price projections for BioLNG as IHS Markit did not provide projections for it consistent with those forthe other fuels; therefore, additional information was used when deriving the projection for BioLNG for this study. Further information on the fuelprice assumptions, and their contribution to the overall cost calculations, is given in Sections 6.2.1 and 7.3 of the report.

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Discounted costVessel capitaleffectivenesscosts($/tonneCO2e)

Other operating
costs

Fuel costs

Total NPV

Package 1

$12

$35

$26

$73

Package 2

$8

$84

$21

$113

Package 3

$88

-$40

-$10

$39

Package 3 has a slightly lower cost increase over the baseline than Package 1 and has significantly
greater emissions savings, leading to a lower cost per tonne CO 2. Both packages have lower (better)cost-effectiveness values than Package 2; as for the cost results presented above, the higher cost per
tonne CO2 for Package 2 is primarily due to the higher fuel costs (noting the uncertainty in the relative
and absolute price evolution of alternative fuels).
In general, as in the table above, when presenting cost-effectiveness results, it is conventional to
discount the emissions savings at the same rate as the additional costs, to recognise the greater
benefits of emissions savings in the short-term. However, there can be interest in viewing the resultswith the full aggregated emissions savings (i.e. undiscounted). Using such an approach, with the costs
discounted (at 10%), but the emissions savings are not discounted, the total NPV values reduce to $13
per tonne CO2e (package 1), $22 per tonne CO2e (package 2) and $8 per tonne CO2e (package 3).
The calculated emissions reductions and costs vary significantly under a sensitivity analysis combining
the advanced technology assumptions of package 3 with packages 1 and 2A sensitivity analysis
considered cases in which the alternative fuels assumptions of packages 1 and 2 were combined withthe technology assumptions of Package 3 (referred to as packages 1A and 2A, respectively).

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The increased deployment of vessel technologies under packages 1A and 2A (relative to packages 1
and 2) give increased emissions reductions, so that packages 1A, 2A and 3 all meet the IMO ambition
on both a tank-to-wake and a well-to-wake basis. These reductions in 2050, relative to 2020, are shownin the figure below.
80%

Change in CO2e emissions compared to 2020

60%

Well to wake

Tank to wake

Baseline Package 1A Package 2A Package 3

Baseline Package 1A Package 2A Package 3

40%
23%

23%

20%

0%

-20%

-40%

-60%
-65%
-73%

-80%

-86%
-92%

-100%
-101%
-120%

-112%

-140%

A significant additional technology that is included in packages 1A and 2A (that is not included inpackages 1 and 2) is the use of on-board carbon capture. This has only limited impact on package 1A,
as almost all fuel used by new vessels is zero-carbon by 2035 (the technology is assumed not to beincorporated in vessels that use zero-carbon fuels), but it has a significant impact on package 2A. As aresult, package 2A has the greatest reduction in emissions of all three on a well-to-wake basis.
The inclusion of the additional vessel technologies in packages 1A and 2A (compared to packages 1
and 2) reduces the energy demand and hence the fuel costs. Under package 1A, this reduction in fuelcosts is greater than the increase in vessel costs associated with the additional technologies, leading
to overall costs that are significantly lower than under package 1. Under package 2A, however, theincreased vessel costs are almost equal to the reduction in fuel costs, leading to a small reduction in
total costs compared to package 2. These results assume a 10% discount rate.

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The cost stack-ups (shown as net present values of the aggregated costs from 2020 to 2050, using a
10% discount rate, in the figure below) show that package 2A has the greatest increase in costs overthe baseline, with the majority being due to vessel capital costs (CAPEX). Package 1A has the smallest
increase in total costs, with fuel costs showing a significant reduction relative to the baseline. Package
3 also has a lower fuel cost than the baseline (slightly less than under package 1A), but a greater
increase in CAPEX than package 1A, due largely to the greater deployment of on-board carbon capturesystems.

The table below shows the overall cost-effectiveness (as $ per tonne CO2 abated) of the main analysis
packages and the sensitivity analysis packages.
10% discount rate

5% discount rate

Package 1

$73

$120

Package 1A

$11

$47

Package 2

$113

$149

Package 2A

$83

$120

Package 3

$39

$83

The sensitivity analysis packages (packages 1A and 2A) show significantly lower cost per tonne CO 2abated than packages 1 and 2 in the main analysis with, in particular, very low values for package 1A.
This is largely due to a significant negative contribution to the cost per tonne from the fuel costs, arising
due to the significant reduction in fuel demand (due to the use of the additional vessel energy efficiency
technologies) combined with a moderate increase in fuel price relative to the baseline (primarily due toammonia fuel). Package 2A also shows a reduction in fuel consumption relative to package 2; however,the costs do not show such a large reduction due to the prices of the alternative fuels used in thispackage.

Barriers identified to the successful deployment of the fuels and technologies include:

For all three packages, the production and supply of alternative fuels will need to be
substantially increased

By 2050, between 9 EJ and 12 EJ of alternative fuels will be required per annum, compared toa total fuel demand in 2020 of approximately 14 EJ; the fuel production infrastructure investment
needed to achieve this is estimated to be between $66 billion and $436 billion (between 2020

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and 2050 under the central demand scenario, combining capital and operating expenditure,using a 10% discount rate)9The adoption of alternative maritime fuels depends on the availability of the associatedinfrastructure for their supply to vessels. With the exception of ‘drop-in’ fuels, associatedbunkering infrastructure and port refuelling facilities will need to be scaled up significantly andrapidly. Given the increased number of fuel types included in the future projections, it might bechallenging for all ports to offer all fuel types, in particular during transition. Therefore, vessel
operators will need to pay attention to the availability of the fuels they require at the locations
they need.

Although engine technology to accommodate alternative fuels (such as ammonia) is alreadyunder development by engine manufacturers, this will need to be scaled up once demonstrated.
Similarly, the development of fuel cells needs to scale up to the MW capacities needed, if fuelcells rather than engines will power the vessels (e.g. from hydrogen).

Significant investments will need to be made in the developments of technologies (particularly
those associated with the use of alternative fuels). There is currently a lack of certainty
regarding the specific fuels (and, perhaps to a lesser extent, technologies) that will be required.
The industry needs greater clarity on these issues before committing to such investments.



The price differential between traditional marine fuels and alternative fuels remains a large
barrier to successful deployment of all three packages. While there is a clear desire on the partof stakeholders for the maritime sector to achieve the decarbonisation targets set by the IMO,
the increased costs of the alternative fuels are a significant commercial barrier to a widespread
uptake. Some regulatory intervention may be required to reduce the price differential and,hence, the commercial disadvantages of changing to the alternative fuels.

Marine fuels considered in this study that can be produced from fossil fuels or renewable energy(ammonia, hydrogen, methanol), will need to have reliable certification schemes to provide
assurance that the chemically-identical fuel is from green sources. Class Rules are yet to be
developed by ship classification societies for most alternative fuels.



Other transport modes, and other sectors, are also attempting to decarbonise in the same
timeframe as maritime shipping. Competition for alternative fuels, or feedstocks, may provide
additional challenges to the industry in its efforts



Slow steaming has shown benefits to date in reducing emissions from shipping. However, there
is little further benefit to be gained as it is already widely practised and the benefits for anindividual vessel on a single voyage are offset by the reduction in productivity and, hence, theincreased number of voyages (and, possibly vessels) necessary to meet the demand.

Recommended actions for the supply of alternative fuels:
Taking a lead on refining the choices of alternative fuels. The analysis has shown that a transition
away from conventional fuels to alternative fuels will be needed if the maritime sector is to meet the IMO
ambition by 2050. However, maritime industry stakeholders have indicated that there is a lack of clarity
regarding the “right” or “best” options for such fuels, leading to difficulties in planning for future fleets
and investments. The oil and gas industry, in cooperation with the IMO and/or states, should help indeveloping a roadmap for the future supply of alternative fuels to reach IMO ambitions for the maritime
sector. This needs to account for the well-to-wake emissions benefits, and account for the impacts ofother greenhouse gases in addition to CO2, such as N2O and methane.

9

The fuel production infrastructure investment required is not included in the cost results presented above; however, as noted, it would be expectedthat the investment costs would be recovered through the increased fuel prices.

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Supporting proof of concept demonstrations. Although all the alternative fuels described in thisreport are widely considered to be suitable for maritime transport, there has been only limited
demonstration of their practicality for long-distance transport with the key vessel categories of bulk
carriers, container ships and tankers. The oil and gas industry could support the design of infrastructure
for alternative fuel proof of concept demonstrations, to provide confidence that the supply of these fuels
can be scaled up to meet the potential future demand. This would also provide assurance to vesselowners regarding future acquisitions of vessels using these fuels. Taking this a step further, oil and gas
industry players could work (and have been working) at the vessel level with designers and builders toprove the concepts of working with alternative fuels on board.
Accommodating the increased demand for alternative fuels. This report has shown the scale offuture demand for alternative fuels under different scenarios and fuel and technology packages. These
have shown that significant scaling up of production and supply of these fuels, including a transition to
decarbonised pathways. To ensure the availability of these alternative fuels in the future, investment in
new production facilities, and ensuring the availability of the relevant feedstocks, will need to be planned.
Providing “green” certification and fuel sustainability information. The different pathways for thealternative fuels produce chemically-identical products. To provide assurance that an operator ispurchasing sustainable fuels will need the introduction systems to certify products and inform theoperator. The oil and gas industry could help in developing and implementing such systems as themarket for, and supply of, alternative maritime fuels develops.
Supporting a reformulation of the IMO ambition. Benefits of low carbon fuels occur in the production
process, giving low or zero well-to-tank emissions. The industry could, through activities in the IMO,
support a reformulation of the IMO ambition for 2050 and policy measures to be focused on reductions
in well-to-wake emissions, rather than tank-to-wake as at present, to be able to recognise the true
carbon intensity of these alternative fuels.
Recommendations for the maritime industry are:
Vessel designers and builders to ensure that the vessels that they design and produce incorporate
the best available technology for energy efficiency.
Vessel owners and operators should plan their future investments in new vessels to include theadditional costs associated with decarbonisation technologies and low, or zero, carbon fuels.
They could consider obtaining “green” finance from banks to support these investments.
Vessel operators could lobby for regulatory changes to support the uptake of alternative fuels.
These fuels currently have a significant cost over conventional fuels. Regulatory support for alternative
fuels may be needed to reduce the cost differential and ensure that they are commercially competitive
against conventional fuels. Support from the industry for such regulatory changes may enable their
uptake to be accelerated.
As their fleets transition to alternative fuels, vessel operators will need to ensure that the relevant
fuels are available at the ports at which they need to refuel. Early discussions with port operators
are required to ensure that the necessary fuels infrastructure will be in place as they begin to use the
new fuels.
A potentially key technology for maritime decarbonisation (if continuing to use conventional fuels as inpackage 3) is the use of on-board carbon capture technology in conjunction with carboncontaining fuels. The industry should monitor and support the development of this technology toensure that it can be incorporated in new vessels if the demand arises. The need for carbon capture
technology is avoided if a rapid switch to zero carbon fuels is made.

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Table of contents
1

2

3

4

5

6

7

Introduction ................................................................................................................. 1
1.1

Context: the IMO Decarbonisation Ambition ......................................................................1

1.2

Report structure ..................................................................................................................3

Maritime transport market overview .......................................................................... 4
2.1

Evolution of transport demand ...........................................................................................4

2.2

Maritime transport market drivers.......................................................................................6

2.3

Split incentives....................................................................................................................8

2.4

Comparison with other transport sectors ...........................................................................9

Historic maritime metrics ......................................................................................... 11
3.1

Environmental footprint ................................................................................................... 11

3.2

Carbon intensity............................................................................................................... 15

3.3

Costs ............................................................................................................................... 16

3.4

Regulations and incentives ............................................................................................. 22

Fuels and technologies to decarbonise shipping .................................................. 27
4.1

Future energy carriers ..................................................................................................... 30

4.2

Vessel design measures ................................................................................................. 48

4.3

Power assistance measures ........................................................................................... 50

4.4

Alternative propulsion measures ..................................................................................... 51

4.5

Engine and aftertreatment technologies ......................................................................... 52

4.6

Carbon capture (CC) ....................................................................................................... 53

4.7

Voyage optimisation ........................................................................................................ 54

4.8

Fuel quality ...................................................................................................................... 55

Fuel and technology packages ................................................................................ 56
5.1

Selection of fuels and technologies for the packages ..................................................... 57

5.2

Package definition ........................................................................................................... 63

Modelling methodology ............................................................................................ 73
6.1

Fleet and emissions ........................................................................................................ 74

6.2

Costs ............................................................................................................................... 86

Decarbonisation potential and costs of fuel and technology packages ............... 97
7.1

Fuel consumption ............................................................................................................ 98

7.2

Emissions ...................................................................................................................... 106

7.3

Costs associated with the fuel and technology packages ............................................. 113

7.4

Cost-effectiveness of the fuel and technology packages .............................................. 120

7.5

Fuel and technology sensitivity analysis results ............................................................ 124

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8

Risks and investment requirements ...................................................................... 139
8.1

Barriers to successful deployment ................................................................................ 139

8.2

Investment requirements for alternative fuels supply .................................................... 142

8.3

Investment requirements for maritime industry ............................................................. 145

8.4

Summary of investment and operating cost implications .............................................. 146

9Implications for the fuel production industry ....................................................... 148

10

Implications for the global maritime industry ....................................................... 151
10.1

Vessel designers/builders ............................................................................................. 151

10.2

Vessel owners/operators ............................................................................................... 152

11

Regional developments and opportunities ........................................................... 153

12Conclusions and recommendations...................................................................... 156

13

References .............................................................................................................. 167

A

Appendices ............................................................................................................. 196
A.1

Appendix 1 – Further analysis on the split incentive problem for shipping ................... 196

A.2

Appendix 2 – Example detailed results from analyses of THETIS-MRV data .............. 198

A.3

Appendix 3 – EEDI effectiveness .................................................................................. 203

A.4

Appendix 4 – Environmental Ships Index ..................................................................... 205

A.5

Appendix 5 – Fuel descriptions from Phase 1 report .................................................... 206

A.6
Appendix 6 – Assessment of applicability, current implementation, and future ownershipof technologies from Phase 1 report ......................................................................................... 224
A.7

Appendix 7 – Summary tables of technologies identified ............................................. 226

A.8
Appendix 8 – Full decision matrix used to inform fuel and technology package
development ............................................................................................................................. 230
A.9

Appendix 9 – Fuel production infrastructure CAPEX and OPEX data .......................... 232

A.10

Appendix 10 – Fuel price development narrative .......................................................... 234

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1

Introduction

The Oil and Gas Climate Initiative (OGCI) and Concawe contracted Ricardo to perform a study on the
decarbonisation of the global maritime sector. The study comprised two phases:Phase 1 – Identify and assess the vessel level technologies and opportunities to reduce
maritime greenhouse gas (GHG) emissions by 2050, including the corresponding challenges,
through a literature review, analysis of historical data and expert interviews.

Phase 2 – Assess potential GHG emissions reduction scenarios for the sector using a range of“fuel and technology packages” in different vessel types and applications.

This report presents the final outcomes from the study. The main body of the report presents anintroduction and the results and conclusions from Phase 2.
The detailed descriptions of the technologies and alternative fuels considered in the study, as presented
to OGCI and Concawe in the Phase 1 report, are given in the appendices.

1.1 Context: the IMO Decarbonisation Ambition
At its 72nd session of the Marine Environment Protection Committee (MEPC), the International Maritime
Organization (IMO) adopted its initial strategy on the reduction of GHG emissions from ships as
Resolution MEPC.304(72). This set out the IMO’s vision of reducing GHG emissions from international
shipping, with the aim of phasing them out as soon as possible.
The initial strategy included three levels of ambition:
1) Carbon intensity of the ship to decline through implementation of further phases of the energy
efficiency design index (EEDI) for new ships;
2) Carbon intensity of international shipping to decline;
3) GHG emissions from international shipping to peak and decline.
Ambition (1) noted that the further phases of the EEDI for new ships would involve percentage
reductions in the limit values for each phase to be determined by ship type. Ambition (2) specified that(fleet average) CO2 emissions per transport work (i.e. per tonne-mile or equivalent) should be reduced
by at least 40% (relative to 2008) by 2030, with the pursuit of reductions of 70% by 2050. Ambition (3)included the aim to peak (total) GHG emissions from international shipping as soon as possible and to
reduce the total emissions by 50% (relative to 2008) by 2050, while continuing to pursue efforts to phasethem out.
Importantly, while the strategy targets reductions in GHG emissions from international shipping, itremains largely fuel and technology-neutral as to how they should be achieved. This study is rooted in
the context of how the IMO’s decarbonisation ambition might be achieved in terms of technologies,
operation measures and energy pathways, and what the implications may be for the sector.
The IMO resolution identified potential emissions growth (in the absence of further action) to 2050,
based on the results presented in the third IMO GHG study (2014). Since then, the IMO has publishedits fourth GHG study (International Maritime Organization, 2020), which provides an update on historicemissions and forecasts of future emissions growth. These are summarised in Figure 1-1.

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Figure 1-1: CO2e emissions from international shipping from 2008 to 2018 and projections to 2050 underscenarios consistent with a 2°C global temperature rise

Source: Ricardo analysis of results presented in the IMO 4th GHG study for vessel-based allocation ofemissions of CO2, CH4 and N2O.
These latest estimates are projecting emissions in 2050 to be between 90% and 130% of the emissions
in 2008. This result was obtained using projections for economic activity and (non-shipping sector)
decarbonisation efforts consistent with a 2°C global temperature rise over pre-industrial levels. The
report also includes results for other scenarios that are consistent with different impacts on temperaturerise, ranging from 1.5°C to 2.8°C (referred to as reference concentration pathways (RCP) 1.9 and 6.0;
Figure 1-1 uses data for RCP2.6). For the analyses presented later in this report, the scenarios selected
were based on the full range presented in the IMO report, not just those represented in Figure 1-1.

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1.2 Report structureThis report is structured as follows:Section 2 provides an overview of the development of the demand for maritime transport andthe drivers of that demand.

Section 3 describes key metrics associated with maritime transport, including the environmental
footprint (carbon dioxide and other pollutants), carbon intensity and costs. It also provides an
overview of the current regulatory situation.

Section 4 presents the different alternative fuels, vessel technologies and operational measures
identified to decarbonise maritime transport.

Section 5 presents the collation of the alternative fuel options and technologies into three “fueland technologies” packages for assessment of their costs and benefits.

Section 6 describes the methodology developed to assess the impacts of the fuel andtechnology packages on future emissions and costs.



Section 7 presents the results of the emissions and cost modelling, including the overall costeffectiveness of the three packages.

Section 8 discusses the risks associated with achieving the targeted decarbonisation and theinvestments that will be required by both the oil and gas industry and the maritime industry.

Sections 9 and 10 discuss the implications of the results of the analyses for the oil and gas
industry and the maritime industry.

Section 11 presents an analysis of the regional aspects of the outcomes of the study.

Section 12 then completes the study with conclusions and recommendations.

Additional details of the analyses are provided in the appendices.

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2 Maritime transport market overview
Key points:


Ships carry 80-90% of international goods by weight or distance, and 60-70% by value.



Demand for maritime transport is closely tied to economic development, and is expected –despite a short term shock due to the COVID-19 pandemic – to continue with significant growth
to 2050 at annual average growth rates of 3 to 3.5% (both freight and passenger)

Economic growth is not expected to be uniform geographically nor across shipping subsectors.
Trends in energy resource demand, shifts in economically growing regions to service based
economies, containerisation and geopolitical factors will all influence maritime transport demand.

Technological trends are also affecting maritime transport demand by improving end-to-end
efficiency. Ship fuel efficiency gains reduce fuel costs; economies of scale reduce costs; anddigitalisation optimises operations as well as enabling new business models.



Regulation is seen as the main way to advance the decarbonisation of shipping in the short andmedium term, until new solutions become economically attractive.

Split incentives, where ship owners responsible for ship energy efficiency do not pay for fuel when
the ship is chartered, are a barrier to reducing GHG emissions in many maritime segments.

Other transport sectors are also under pressure to decarbonise and are taking steps to do so.
Competition for fuels between modes could affect the decarbonisation of the maritime sector.

2.1 Evolution of transport demand
Shipping carries the vast majority of international trade, with its share ranging between 80% and 90%
of total trade10 in terms of both tonne-miles transported (OECD, 2019) and weight of transported goods(United Nations Conference on Trade and Development, 2018). In terms of trade value, the shipping
share is considerably lower with various estimates being around 60% to 70% of trade, as higher valuecargo is often transported by air. The predominance of sea transport is particularly pronounced indeveloping countries, where trade structures and volumes of intraregional trade give a smaller role toland transport.
Regardless of the mode considered, higher economic activity, triggered by an increase in consumption,
production, intensification of trade, or a combination of several factors, usually implies an increase indemand for transportation (OECD, 2019). Population growth, economic growth and their geographicaldistribution are key determinants of the structure and distribution of demand by mode and geography.
Figure 2-1 shows the historic data on seaborne trade and world gross domestic product (GDP) being
highly correlated. Historically, world GDP doubles approximately every 25 years, while seaborne trade
has been increasing at a faster rate – around 2.5 times every 25 years.

10

Contribution of maritime transport to international trade compared to other modes is discussed in more detail in Section 2.3.

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Figure 2-1: Correlation between world GDP and seaborne trade90
80

12,00070
10,000
60
8,000

50

6,000

40
30

4,000
20
2,000

10

0

0
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Seaborne trade (mln ton)

World GDP (trln 2010USD)

Source: World Bank (World GDP), Clarksons Research (seaborne trade)

OECD projects both passenger and freight demand to triple in the period between 2015 and 2050 as
well as change its regional distribution. With this growth rate, seaborne trade would increase fromapproximately 11,800 million tonnes in 2019 to almost 30,000 million tonnes in 2050. Asia is expected
to increase its demand significantly, and to increase its capacity to be able to accommodate thisincreasing demand. Sea transport is projected to remain the main mode for freight (Table 2-1).
Projecting transport demand requires a deep understanding of economic growth and international
activity patterns; increased protectionism or a global economic downturn would have an important
impact on demand for transport. This is especially true for maritime transport, being highly dependent
on the international trade intensity, more than other transport modes. The OECD (2019) notes that the
future of the maritime freight sector depends in particular on international trade agreements, thedevelopment of transcontinental inland routes, changes in global energy use and e-commerce growth.
Table 2-1: OECD projected growth rates of transport demand (global compound annual growth rate oftonne-miles in %)Transport demand

Share in 2015

2015-30

2015-50

Sea

70%

3.0

3.6

Road

18%

3.5

3.2

Rail

9%

2.7

2.5

Inland waterways

2%

3.4

3.8

Aviation

1%

5.5

4.5

Passenger transport (pas-miles)

-

4.3

3.4

Freight transport (tonne-miles)

-

3.1

3.4

Source: OECD, ITF Transport Outlook 2019

The long-term impacts of the response to the COVID-19 pandemic on maritime transport remain highly
uncertain. While it is clear that the demand for transport decreased significantly in 2020 relative to 2019,
over 4% according to UNCTAD11, it is still not fully clear what shape the recovery will take. As theexperience of the financial crisis a decade ago shows (see the figure above), seaborne trade returned
to its pre-crisis path one year after the negative shock in 2009, while the economic growth has been
recovering at a slower speed. UNCTAD also anticipates that the global maritime trade may recover in
2021 and show growth of 4.8%.

11https://unctad.org/news/covid-19-cuts-global-maritime-trade-transforms-industry

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World GDP (trillion 2010USD)

World Seabone trade (million tonnes)

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2.2 Maritime transport market drivers
Economic growth is the basis for demand for trade, regardless of the type of goods transported. As
economies grow, existing routes accommodate higher volumes of transport and new sea routes may
emerge, reflecting changes in trade patterns for deep sea, short sea and coastal shipping.
There are, however, multiple levels of the relationship between economic activity and trade. In addition
to the economic growth and total transport demand relationship on a macro level, the structure of
economic growth shapes the structure of transport demand in terms of cargo type.

2.2.1 Markets, policies and geopolitics
Energy trends
Although almost all modes of transport currently rely heavily on oil and gas products as fuels, maritime
transport is also strongly related to the oil and gas industry, through the transport of resources. Morethan 30% of wet bulk cargo transported currently is crude oil, oil products or natural gas12. Further, asignificant part of the dry bulk cargo transported consists of coal.
As the result of new policies in energy and environment implemented across the globe, the share offossil fuels in the overall primary energy mix is expected to decline in coming years. IEA’s World Energy
Outlook projects oil demand decreasing by a third and coal demand by two thirds by 2030 in their
Sustainable Development Scenario13, which will lead to a reduction in demand for coal bulk carriers andoil tankers in the medium to long term. Oil price reductions, however, might contribute to an initial
increase or softer decrease in oil trade before entering long-term decline.
The demand for liquefied natural gas (LNG) as a fuel on land, and hence its transport by sea, has been
increasing recently and is expected to continue to increase in the medium term, although there is much
uncertainty associated with the level of activity and significant differences across regions. On the supply
side, natural gas trade has emerged in new locations due to the recent evolution of costs and shale gas
production, and it is expected that gas flows will change significantly in the future. Overall, ship operators
expect that LNG business will show continuing growth over the next 20 years.
For all energy products, significant variations in shipping demand may arise due to geographicalredistribution of routes in medium to long term.
Economic growth trends
Global minor bulk trade (e.g. steel products, sugars, cement) will continue to reflect basic production
activity, including production of metals, steel, wood and other materials. Demand for bulk carriers for
agricultural products will likely continue following growth patterns of population and output per capita ofwell established and emerging grain-importing regions.
Global non-coal bulk volume has been dominated by growth in China, where the trend in recent years
indicates a slower industrial production growth and a gradual shift towards a more service-oriented andconsumption-driven economy. These trends would translate to lower demand growth for non-coal bulk
carriers. Ship operators have noted that demand to carry iron ore/coal to Asia is decreasing, but thismay be offset by growing demand from developing countries.
In the container segment, the relationship between seaborne trade and GDP has been gradually
weakening in recent years (DNV GL, 2017). Ship operators recognise that demand would be impacted
by moves toward local production, especially for roll-on-roll-off (RoRo) ships.
Containerisation of trade continues to develop into new areas. As well as increasing container trade, it
may also reduce other cargo trades. For example, food importers in Asia are switching from dry bulk

12

UNCTAD (2019), Clarksons Research data

13

Oil and coal demand by region and scenario, 2018-2040 https://www.iea.org/reports/world-energy-outlook-2019/oil#abstract

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carriers to container vessels, filling empty containers after unloading consumer goods in Westerncountries. With all these developments, container trade is expected to continue to grow in the near term.
Lloyds projects container trade to increase at 4.6% per annum for the next 5 years (Lloyd's List, 2019).
Geopolitical factors
UNCTAD projects that maritime freight volumes will be conditioned by the development of international
trade agreements. The Economic Partnership Agreement between the European Union and Japan aswell as the Comprehensive Economic and Trade Agreement between the EU and Canada will likely
lead to further increases in trade volumes. Changing global value chains in rapidly developing
economies such as China and India will also determine how freight flows evolve.
Significant trade volumes between big actors – such as China and India on one side, and Russia andCentral Asia countries on the other – may flow via other modes, such as rail and pipelines, as analternative to seaborne transportation. Large infrastructure-development projects, such as China’s One
Belt and One Road initiative and the Japan-Asian Development Bank partnership, will stimulate growthand demand for seaborne transport (United Nations Conference on Trade and Development, 2016).
For the energy segment, geopolitics is key for trade patterns: North America is already, and is expected
to remain, a major global LNG exporter, while developments in Australia are likely to play a key role inproviding LNG to the Asian countries. In addition, new projects such as Yamal in Russia, Malaysia and
Cameroon will also influence the future global trade of LNG.
The geopolitical situation in the Middle East will determine the development for oil tanker owners. The
evolving strategy of the Organization of Petroleum Exporting Countries on production will determine
crude oil shipping in the short to medium term. Stability in Iran, Iraq, Saudi Arabia, and neighbouring
countries is also considered important for the oil sector.

2.2.2 Technological factors
Many studies assume a significant improvement in transportation fuel efficiency worldwide over the next
few years, partially due to technological improvements and partially due to reductions in navigation
speed. Ship operators note that since 2008, the significant reduction in ships’ navigation speed has led
to a general reduction in engine power output (for a given vessel size) in newer vessels. Innovative shipconcepts may also emerge to create a leap forward in performance. Examples include ballast-free ships,
and low- and zero-emission hybrid ships, incorporating various advances such as innovative lightmaterials, alternative powering, and energy-storage modules. These are the subject of later sections of
this report.
On the other hand, ship size is increasing, driven by economics of shipping, especially for container
vessels, now available for 20,000+ twenty-foot equivalent units (TEU) and ore carriers (e.g. Valemax).
The impacts of increasing vessel size, the expansion of the Panama Canal, and the emergence of megaalliances could also lead to improved fleet capacity utilisation.
Digitalisation can reduce the cost of shipping, while improving safety. It is set to enable reduced
downtime, predictive maintenance, performance forecasting, real-time risk management, and energy
efficiency. Operators will generate cost savings through advanced data analytics, process digitalisation,
robotic process automation, and connecting and sensing technology (DNV GL, 2014b). Improvements
in logistics and operations, as well as optimal weather routing, also contribute to reductions in fuel costs.
Indirectly, digitalisation can enable new business models and better ship operation, with a positive
impact on energy use. Autonomous ships could sail at very low speeds without incurring high crew
costs, allowing greater use of batteries and other fuel types (DNV GL, 2014b).

2.2.3 Regulatory factors
The industry players and port authorities consulted during this study agree that regulation is the main
force that is likely to advance the decarbonisation agenda for shipping in the short and medium term.

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The role of investment in research and development (R&D) is key in this process to inform regulatory
effort or accelerate technological maturity and cost reductions.
Regulation is seen as the main driver of decarbonisation now, and is expected to stay in this role in thenear future, as operators react to economic incentives. R&D expenditures are viewed as enablers fordevelopment and implementation of novel technologies and are helpful to inform policy decisions.
Other potential regulatory mechanisms, such as market-based measures or voluntary agreements arealso considered to be important to encourage fuel efficiency and potentially the uptake of cleaner fuels.
The effectiveness of these instruments, however, will need to be carefully assessed against social andeconomic costs as well as benefits.

2.3 Split incentives
The structure of the shipping sector makes it more susceptible than other transport sectors to
introducing new technology, known as the ‘split incentive’ problem.
Currently, some seemingly cost-effective carbon reduction measures (including the use of technologies
and alternative fuels) are not implemented to the scale expected. The difference between the higher
implementation level appearing to be cost-effective from the consumers or firms’ point of view andtechno-economic analysis, and the actual/observed lower implementation levels of cost-effective
measures, is known as the ‘energy efficiency gap’ (Jaffe et al, 1994). One such barrier causing this gap
has been recognised as the ‘principal agent’ or ‘split-incentive’ problem. Split incentives refer to any
situation where the benefits of a transaction do not accrue to the actor who pays for the transaction. For
example, in the context of energy efficiency, this can occur when the party paying for the investment in
the efficiency measure, is not the direct beneficiary of the financial gains of that implemented measure,i.e. fuel cost savings (European Commission, 2013).
Table 2-2: Cost allocations in the shipping sector
Cost element

Voyage Charter ($/tonne)

Time Charter ($/day)

Cargo handling

Charterer

Charterer

Voyage Expenses

Ship Owner

Charterer

Operating Expenses

Ship Owner

Ship Owner

Capital Costs

Ship Owner

Ship Owner

Adapted from ( Rehmatulla et al, 2015)

For the shipping sector the specific structure of the market means it is particularly susceptible to thischallenge ( Rehmatulla et al, 2015). The reason why the shipping sector is more susceptible to thisproblem than other transport sectors is because of cost allocations, see Table 2-2. In the shipping
sector, responsibilities such as fuel charges, operational measures, technological investments andcargo loading can be allocated to Ship Owners or Ship Charterers. Chartered ships can constitute asignificant portion of the global vessels in operation. For example, over 60% of ships operated by“leading container ship operators” are chartered (Statista, 2020). In this way there is an asymmetry
between the Ship Owner and Ship Charterer financial gains.
These split incentive barriers have been investigated in the building & manufacturing industry. Thirdparty financing models from the built environment could be adapted for the shipping industry to enablesignificant capital costs to the Ship Owner or Ship Charterer to be overcome. The key to these financing
mechanisms is that they incorporate measurement and verification technology into the financial
package (Stulgis et al, 2014).
Further analysis on the split incentive problem in the context of the shipping sector can be found in
Appendix A.1.

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2.4 Comparison with other transport sectors
As noted in section 2.1, maritime transport meets the majority of global demand for freight transport.
Based on data from OECD and the International Civil Aviation Organisation (ICAO), maritime transport
meets approximately 81% of global demand for freight transport (in tonne-miles), with road and rail
providing approximately 12% and 7% respectively and aviation an almost negligible 0.16% of demand( (OECD, 2019) and (International Civil Aviation Organisation, 2019)). These fractions have not changedin the recent years despite the overall increase in global freight demand.
Although there is a dominant position for maritime transport in meeting the demand for moving freight,
there are other aspects to consider. Much of maritime freight transport is over very long distances, whileroad and rail transport tend to be over much shorter distances. The delivery of the freight carried bymaritime shipping also frequently depends on road or rail (or inland waterway shipping) to reach its finaldestination. Although the quantity of freight transported by air is a very small part of the total demand,the products that are transported tend to be of higher value than those transported by other modes, so
the percentage of the total value of goods transported by air is much higher.
While the dominance of long-distance transport by sea (when measured by volume of goods
transported) provides the potential for significant global savings in emissions as the industry
decarbonises, it is already relatively efficient and the associated low costs of transport provide additional
challenges in achieving decarbonisation without significantly increasing transport costs.
Other transport sectors are also under pressure to decarbonise and are taking steps to do so. As wellas continuing strong efforts to improve the efficiency of aircraft (largely driven by economics, but alsowith additional impetus from a new regulation on the fuel efficiency of new aircraft14), ICAO has
implemented the Carbon Offsetting and Reduction Scheme for International Aviation 15 (CORSIA), whichis intended to keep net emissions from international aviation at or below 2019 levels. Aviation may prove
more challenging to decarbonise, given the need for high energy densities by both mass and volume(related to aircraft mass and aerodynamic drag) and the requirement for certification of fuels from asafety perspective. If countries or regions implement mandates on minimum blends of sustainableaviation fuels (SAF), as has been suggested, this could lead to a prioritisation of particular fuels andpathways for aviation use.
The light duty vehicle road transport sector is much easier to decarbonise. At least for individual
passenger transport (i.e. cars) the vehicles have much shorter lifetimes leading to a more rapid fleet
turnover. Further, most road transport is owned and operated primarily within an individual country,
increasing the role that national regulation can play. Heavy duty vehicles, particularly goods vehicles,
also have challenges in decarbonising due to the increased energy requirements of transporting
payloads for the long distances travelled; most of the current (short-term) focus is on the use of biodiesel for such vehicles, although there has also been significant progress in using LNG as a fuel for
long distance heavy goods vehicles, with, for example, about 11,000 LNG-fuelled trucks and over 300
public LNG refuelling stations already in use in Europe 16. There is also considerable interest in hydrogenas a zero-emissions future fuel.
Similarly to the other transport modes, there is also pressure on the rail sector to decarbonise. In thiscase, a significant part of the sector is already electrified, using electricity supplied through the rail
infrastructure (e.g. overhead line or third rail), rather than recharging batteries. This provides an optionthat can be extended more widely, although at considerable infrastructure cost, to achieve a greater
decarbonisation (depending on the source of the electricity used).Other technologies, such ashydrogen, are also considered by the rail sector to lower its GHG emissions.

14

https://www.icao.int/environmental-protection/Documents/EnvironmentalReports/2016/ENVReport2016_pg112-114.pdf

15

https://www.icao.int/environmental-protection/CORSIA/Pages/default.aspx

16

https://www.ngva.eu/medias/the-necessary-rise-of-lng/

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In summary, the demand to decarbonise other transport sectors will also affect the decarbonisation of
the maritime sector, in particular for cases where alternative fuel demands overlap, such as demand for
LNG from the road transport sector and demand for feedstocks for drop-in fuels for aviation, which could
lead to challenges in meeting the demand for alternative fuels from the maritime transport sector. Crosssectoral benefits could accrue however through the development of technology in one sector leading tocost reductions for another (e.g. battery development driven by the road vehicle sector increasing
opportunities for small battery powered vessels).

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3 Historic maritime metrics
This section presents the historic development of maritime metrics such as environmental footprint
and carbon intensity of the fleet.
Key points:


The fourth IMO greenhouse gas study identifies that total emissions in 2050 are expected to lie
between 90% and 130% of 2008 levels

Over 75% of global emissions are produced by three vessel categories: bulk carriers, container
ships and tankers

Illustrative examples of total annual vessel costs, including capital, operating and voyage costs,
have been estimated for these three key vessel types. Voyage costs were found to make up 60%70% of total costs. Because fuel costs form the largest component of voyage costs, total costs
are sensitive to (volatile) fuel prices.



Existing IMO level regulatory measures to decrease GHG emissions include the Energy
Efficiency Design Index (EEDI), Ship Energy Efficiency Management Plan (SEEMP), mandatory
Fuel Oil Data Collection System (DCS) and the Energy Efficiency Operational Indicator (EEOI).



Upcoming measures include Energy Efficiency Existing Ship Index (EEXI), and the establishmentof a Carbon Intensity Indicator (CII), both of which will likely enter into force in 2023 following
adoption at MEPC 76 in June 2021.

Port area regulations and voluntary incentive schemes can also be useful drivers in decarbonising
the shipping sector

This section presents the historic development of maritime metrics such as environmental footprint andcarbon intensity of the fleet.

3.1 Environmental footprint
Carbon dioxide
CO2 remains the most important greenhouse gas to account for from maritime transport. The fourth IMO
GHG study (International Maritime Organization, 2020) includes two methodologies for estimating
emissions from shipping17. Its voyage-based allocation method estimates that international shipping
produced 740 million tonnes of CO2 (or 755 million tonnes CO2e) in 2018, which is about 2% of global
total emissions. Its vessel-based allocation method estimates that international shipping produced
almost 920 million tonnes of CO2 (or almost 940 million tonnes CO2e) in 2018, representing about 2.5%of total man-made emissions in that year.
The report also estimated that by 2050, emissions are projected to be between 90% and 130% of thelevels in 2008 under different scenarios that are consistent with a 2°C global temperature rise. This
growth, set against the vessel-based allocation estimates, was shown in Figure 1-1 for context against
the IMO decarbonisation ambition.

17

The third IMO GHG study used a calculation of CO2 emissions from shipping based on the vessel type and size, with assumed allocationsof vessel categories (combinations of types and sizes) to either domestic or international operations. The calculation of emissions thenassumed that all vessels within a category operated similarly. The fourth GHG study introduced a new approach, using automatic identification
system (AIS) data to identify port calls and, hence, identify individual voyages as either domestic or international. The two approaches havebeen termed “vessel-based” and “voyage-based”, respectively.

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Further insight into the distribution of the emissions between the different elements of the maritime
transport sector can be obtained from the fourth IMO GHG study. Figure 3-1 shows the percentage ofthe total emissions emitted by different ship categories in 2018.
Figure 3-1: Percentage of total CO2 emitted by different ship categories in 201830%

Percentage of total CO2 emissions

25%

20%

15%

10%

5%

0%
Container Bulk Carrier Oil Tanker

Liquefied
ChemicalGas Tanker
Tanker

GeneralCargo

Ferries

CruiseRo-Ro

Refrigerated
Bulk

Other
Liquids
Tankers

Source: Fourth IMO GHG study

The three highest emitting types of ship are container ships, bulk carriers and oil tankers (with significant
emissions also by other tankers, such as chemical and liquefied gas). Between them, these three
categories of ship produced 75% of the total GHG emissions from international maritime shipping.
Other key pollutants, including recent trends in methane emissions from LNG fuelled vessels
The fourth IMO GHG study also presented historic evolutions of other pollutants, including oxides ofnitrogen (NOx), particulate matter (PM), methane (CH4) and nitrous oxide (N2O). The first two of theseare primarily of concern in relation to local air quality (e.g. around ports), although they are also
implicated in climate change (indirectly, through the production of ozone, in the case of NOx), while thelatter two are primarily of concern as greenhouse gases. Figure 3-2 shows the evolution of the global
emissions of these four pollutants since 2012. The changes are shown relative to a 100% baseline in2012.

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Figure 3-2: Evolution of emissions of other pollutants from global shipping, 2012 to 2018 (indexed to avalue of 100 in 2012)
Historic emissions of other pollutants from global shipping
300

Emissions of pollutant (indexed to 100 in 2012)

250

200

NOx
PM

150

Methane
N2O
100

50

0

2012

2013

2014

2015

2016

2017

2018

Source: Fourth IMO GHG study

The results in Figure 3-2 show almost constant levels of NOx, PM and N2O emissions (average annual
increases of 0.4%, 0.7% and 1.4%, respectively), but quite rapid increase in methane emissions (17%average annual increase). This reflects the recent trend to using more LNG-powered vessels and theirassociated ‘methane slip’. The fourth IMO GHG study also notes that the nature of the propulsion
systems of vessels using LNG has changed since 2012, with a greater proportion using low-pressure
Otto-cycle engines and a reduced number using steam turbines (which have comparatively low methane
emissions) The actual emissions of methane from shipping are still small in comparison to other sources
such as agriculture (global methane emissions have been estimated at about 9.4 billion tonnes CO2e18,
or about 290 million tonnes methane, so international shipping represents about 0.05%), but such a
rapid growth could lead to a significantly higher percentage in the future if left unchecked. This also
shows the increasing importance of considering non-CO2 greenhouse gases for future fuel scenarios.
As context, Figure 3-3 shows the growth in total DWT of ships delivered that can use LNG as a main
fuel since 2006, showing the continued growth in the LNG-powered fleet, predominately in the LNG
carrier category.

18

https://www.globalmethane.org/documents/gmi-mitigation-factsheet.pdf

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Figure 3-3: Cumulative DWT of ships capable of using LNG as fuel by year
Total DWT of ships built to date with LNG as fuel40,000,000

Total DWT of ships built up to year

35,000,000

30,000,000

25,000,000

20,000,000

15,000,000

10,000,000

5,000,000

0
2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Year
Oil Tankers

Bulk CarriersContainer Ships

Chemical Tankers

General CargoLPG Carriers

Ro-Ro Ships

LNG Carriers

Crude Tankers

The size of the LNG-powered fleet (in terms of total DWT) is now over three times the size that it wasin 2012. The IMO 4th GHG study takes account of emissions of unburnt methane from LNG-fuelled
engines, with different emission factors depending on the engine type (slow-speed or medium speed
Otto-cycle (spark ignition), lean-burn spark ignition or diesel cycle) . Most recent LNG-fuelled vessels
either use high-pressure diesel-cycle engines (which have lower methane slip) or use other technologies
to reduce methane slip from Otto-cycle engines. Recent commentary from Lindstad (2019) also concurs
that LNG fired in 2-stroke high pressure dual fuel engines provides overall a reduction in GHG intensity
compared to HFO (in comparison to LNG fired in e.g. low pressure engines which does not offer GHG
savings or worse, increases, compared to HFO).
Comparison with other modes
In 2018 all modes of transport were responsible for ~8 Gtonnes19 of CO2 emitted into the atmosphere,
an increase of ~15% since 2010 and ~40% since 2000 (International Energy Agency, 2019) (Figure3-4). Road transport, both passenger and freight, makes up the majority of these emissions, and has
been responsible for the majority of the increase in emissions in the 2000-2020 period (around 75% of
total emissions). In comparison, shipping is responsible for around 11% of total emissions, only about
one-third that of road freight, while representing five times more tonne-miles moved (International
Transport Forum, 2019).
The IEA projections to 2030, based on the Sustainable Development Scenario, suggest that total CO2
emissions from transport will decline to 7.3 Gtonnes, with road transport responsible for over 80% of
the reduction in emissions. This reduction is expected to happen because of the diminishing relianceon petroleum-based fuels (partially replaced by electricity from renewable sources in the road sector,
for example). The proportion of total transport emissions attributable to shipping is not expected tochange by 2030.

19

A gigatonne (Gtonne) is 1,000 million tonnes.

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Figure 3-4: Transport sector CO2 emissions by mode, historically and projected, 2000-203020.
9.0

8.0

CO2 emissions (Gtonnes)

7.0

6.0

5.0

4.0

3.0

2.0

1.0

0.0

2000

2005
Passenger road vehicles

2010

2015

Road freight vehicles

2020
Aviation

Shipping

2025
Rail

2030

Other

Source: (International Energy Agency, 2019).

3.2 Carbon intensity
In July 2020, the EU published information on the CO2 emissions by ships that had performed maritime
transport activities related to the European Economic Area (EEA) in 201921, through the THETIS-MRV
portal22. This follows the introduction of the requirement from 2018 for large ships that load or unload
cargo or passengers at ports in the EEA to monitor and report their related CO2 emissions in conformity
with Regulation 2015/757. Although the data are only a subset of the global fleet, they do cover almost
11,200 ships of a full range of categories and sizes, representing 38% of the world merchant fleet (above
5,000 gross tonnage).
Using the ship data from the World Fleet Register, published by Clarksons Research (Clarksons
Research, n.d.), where feasible, the entries in the THETIS-MRV data have been mapped to the relevant
ship information, such as the deadweight tonnage (DWT) and gross tonnage (GT). This allows the
carbon intensity (mass of CO2 emission per unit of transport work, such as per tonne-mile) and fuelconsumption per unit work to be analysed against the size of the ship (as represented by DWT) for
different ship types. Figure 3-5 shows the average fuel consumption per unit work, split into different
bands of ship DWT.

20

Please note that while this IEA forecast predicts a decrease of 6% in aviation CO 2 emissions between 2018 and 2030, the International Civil
Aviation Organisation (ICAO) forecasts that emissions of the aviation sector will increase around 45% in the same period (ICAO, 2019).
21

https://ec.europa.eu/clima/news/commission-publishes-information-co2-emissions-maritime-transport_en22

https://mrv.emsa.europa.eu/#public/eumrv

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Figure 3-5: Average fuel consumption per unit work for DWT ranges
Variation of average fuel consumption per unit work with Dead Weight Tonnage (DWT)

Fuel consumption per unit work (g/tonne-mile)

12.0

10.0

8.0

6.0

4.0

2.0

0.0

Dead Weight Tonnage (tonnes)

Source: Ricardo analysis using EU ship emissions MRV data and Clarksons World Fleet Register data

Figure 3-5 shows that, on an overall average, the fuel consumption per unit work decreases from about
11 g/tonne-mile for the smaller ships to less than 2 g/tonne-mile for the largest. As well as the overall
vessel size, these results are influenced by the characteristics of individual vessel categories and themanner in which they are operated (for example, gas carriers and Ro-Ro ships have consistently higher
fuel consumption per tonne-mile than container ships or tankers).
For input to the fleet and emissions modelling (Section 6.1), the same THETIS-MRV data have been
analysed in greater detail, considering the variations with vessel category, size (DWT) and build year
(i.e. age in 2019).
Additional details of these analyses are given in Appendix A.2.

3.3 Costs
Costs of owning and operating a vessel vary significantly in terms of routes, vessels types, sizes andages. Although the data is available for all vessel types and sizes 23, to illustrate the most representative
elements of the maritime sector, this section outlines the illustrative cost structure of three vessel types:
dry bulker, oil tanker and container ship. These three vessel types were chosen as they make up thelargest proportion of the sector’s CO2 emissions (section 3.1) and are the most representative ones interms of fleet size, according to fleet statistics published by UNCTAD (2019).

3.3.1 Vessel costs methodology
For all types of vessels, the main components of the costs are:23

This data will be used in the analysis performed in the second phase of the Project.

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022Capital costs, that is the costs associated to ownership of the vessel, permanent or temporary.
The costs presented below were built under the assumption of an ownership model24. In thiscase, the capital costs were composed of the following components:oCapital (or equivalent of capital amortisation when the vessels are purchased with aloan). These costs also reflect the average depreciation schedule of the vessels overtheir useful life. The useful life of the vessels for the depreciation schedule is assumed
to vary by vessel type: for example, 25 years for bulk carriers and tankers and 20 years
for container ships, corresponding to average demolition ages by vessel type
(Clarksons Research fleet data).

o

Costs of capital or interest payments, that is additional capital costs associated with theweighted average cost of capital in the sector. The rate is assumed to be 6.75%,
reflecting the assumption of 60% debt financing and corresponding interest rates ofdebt (6.3%) and equity (7.4%)25.

oOther costs, such as pre-delivery expenses, initial registration fees and taxes. This
component of the costs is small and varies across countries. For simplicity, the costs
outlined below exclude these costs.

Operating costs, that is, the costs associated with operation of the vessel but not to thevoyages the vessel makes. The operating costs were obtained from benchmarks published by
Moore Stephens (Dec 2017) and BCG Shipping Benchmarking Initiative. The main components
of shipping operating costs are:oCrew costs, including crew wages, travel and training.

oStores (including materials, supplies, equipment) and lubricants.

o

Maintenance, including repairs, dry dock and spares.

o

Insurance costs.

oAdministration costs, including inspection and overheads.

Operating costs vary significantly across vessels, fleets and companies. Stakeholders admitthat operating cost optimisation is one of the most used strategies of cost management forlarger fleets.
Voyage costs are the variable costs associated with the voyages or trips that a given vessel
makes in a year. These costs will be zero for a vessel not used in a particular year. The main
components of voyage costs are:o

Fuel costs, calculated as the product of vessel fuel consumption (UNCTAD, 2019) and
fuel price (The Association of European Vehicle Logistics, 2020) according to average
fuel consumption composition (REPSOL, 2019). For this assessment of cost
breakdown we used average values for the last 5 years for the results presented in thenext sub-section and explore sensitivities after discussing main results.
Fuel costs are highly dependent on fuel prices, so that oil and fuel price fluctuations are
the most important determinants of shipping costs and vary between 30% to 50% under
pre-COVID-19 fuel prices (e.g. average fuel price of 540 USD/tonne under Brent pricesof 60 to 65 USD/barrel) as of Q4-2019) and varied between 25% to 35% under the low
fuel prices at the beginning of 2016 during the oil price crisis (e.g. average fuel price of
280 USD/tonne under Brent prices of 30 to 35 USD/ barrel as of Q1-2016).

24

For rented or chartered vessels, it is assumed that, on average, the capital-related charter rate would be equivalent to the sum of capitaland interest payments plus a premium to reach a reasonable level of profitability.
25

Hamburg Financial Research Center (2015), “Maritime Investment Appraisal and Budgeting”

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022oPort charges paid to the port authorities and cargo handling costs paid to port operators.
These were calculated as averages by vessel type taken from benchmarks by Hong
Kong’s and South Africa’s maritime authorities 26.

oCanal dues and tolls paid to the canal operators for using the facilities (e.g. Panama
Canal company, Suez Canal company).

For each vessel type, a typical route portfolio was assumed, according to the mostrepresentative routes for each vessel type and size (Baltic dry index routes, EEX tanker index
routes and World Shipping Council trade routes as a proxy for container routes).

3.3.2 Illustrative average annual costs for three vessel types
The costs for three vessel types are presented in Figure 3-6 (dry bulker), Figure 3-7 (tanker) and Figure
3-8 (container). All costs are expressed in millions of USD per year, the most common metrics used at
the global scale, and assume an average fuel price of 481 USD/tonne under average Brent prices of 50
to 55 USD/ barrel in 2015-2019.
For relatively new vessels, on average, capital costs represent around 15%-25% of total costs of thevessels, while operating costs account for 10%-25% of the costs. Voyage costs are by far the mostsignificant costs component for all vessel types and sizes due to the fuel consumption, and account for
60% to 70% of total costs per year.
Figure 3-6: Illustrative annual costs for a 75,000 dwt Panamax dry bulk carrier, 5 years old, USD per year

Source: Ricardo literature review and calculations

26

Note: These charges do not factor in the nature of future fuels and their associated implications (e.g. storage).

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Figure 3-7: Illustrative annual costs for a 100,000 dwt Aframax oil tanker, 5 years old, USD per year

Source: Ricardo literature review and calculations
Figure 3-8 Illustrative annual costs for a 13,000 TEU container liner, 5 years old, USD per year

Source: Ricardo literature review and calculations

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3.3.3 Key determinants and sensitivities
Fuel price is by far the most important and most volatile determinant of the average vessel costs, being
especially pronounced for older and less efficient vessels. Figure 3-9 highlights this27. A calculation
performed in May 2020 showed average fuel prices of $251/tonne, 47% lower than the average pricein the preceding 5 years (i.e. average fuel price of $481/tonne under average Brent prices of $50 to $55
per barrel in 2015-2019) and 57% lower than average prices in 2018, the highest in this 5 year period(e.g. average fuel price of $588/tonne under Brent prices of $65 to $70 per barrel in 2018). This highdependence of vessel operating costs on fuel price provides a strong driver to reduce the cost of fuels
used, and has been a key determinant in the almost universal adoption (historically) of HFO (in general
the lowest priced liquid fossil fuel) for maritime transport.
For a 13,000 TEU 5-year-old container ship, the fuel costs change from $7.2 million per year undercurrent prices to $13.7 million per year under average historic prices or to $16.7 million per year underhigh prices as in 2018. This means very important increments of 32% and 47% in total annual costs
respectively (Figure 3-9).

27

These are for illustration of the variability. Different fuel price assumptions are used in the modelling described in later sections of the report.

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Figure 3-9 Fuel price sensitivities for 13,000 TEU container liner, 5 years old, USD per year

251 USD/tonne

481 USD/tonne

588 USD/tonne

Source: Ricardo literature review and calculations

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The age of the vessel is a key determinant of both capital and fuel costs (Figure 3-10), because ingeneral, the vessels depreciate faster at the beginning of their useful life and newer vessels are more
efficient.
Figure 3-10 Age sensitivities for a 75,000 dwt bulk carrier on capital and fuel costs (fuel costs of 481
UDS/tonne), USD per Bulk
year Carrier - 60,000-99,000 DWT, Costs Million USD/yr
6

Million USD/yr

5
4

50%
2.52

3

60%
2.94

57%
2.69

75%
3.36

2

91%
3.77

98%
4.19

99%
4.52

0.08

0.04

20

24

2.57

1

2.04

1.94
1.11
0.36

0
0

2

5

Capital Costs

10
Age

15

Fuel Consumption

Fuel consumption data derived from analyses of EU MRV data (European Commission (DG CLIMA), 2019); capital cost data
derived from analyses of Clarksons Global Fleet Register (Clarksons Research, n.d.)

For new bulk carriers, for example, capital costs are of the same magnitude as fuel costs, 2.5 million
USD per year approximately. For older vessels, however, the capital costs are lower and the fuel costs
are higher, with the latter more pronounced for higher fuel prices scenarios.

3.4 Regulations and incentives
3.4.1 IMO and MARPOL
The international maritime sector is subject to a range of regulations, both international and national. At
a global level, maritime regulations are defined by the International Maritime Organization (IMO). The
IMO is the specialised agency of the United Nations with responsibility for the safety and security ofshipping and the prevention of marine and atmospheric pollution by ships. The IMO provides the forum
for the agreement, adoption and implementation of international regulations.
The primary international regulations for maritime environmental protection fall under The International
Convention for the Prevention of Pollution from Ships 28 (MARPOL). Regional implementation of such
regulations can be stricter than MARPOL. The sixth Annex of MARPOL limits emissions of oxides ofsulphur (SOx) by limiting the sulphur content of fuel29; limits oxides of nitrogen (NOx) through engine
NOx controls; and aims to address greenhouse gases (GHG) through technical and operational energy
efficiency measures.

28

http://www.imo.org/en/About/Conventions/ListOfConventions/Pages/International-Convention-for-the-Prevention-of-Pollution-from-Ships(MARPOL).aspx
29

SOx emissions occur when sulphur in fuel is oxidised during combustion. Therefore, limiting the fuel sulphur content also limits the SOx emissions
from the ship. The latest rules came into force from 2020 limiting marine fuel sulphur content to 0.5% globally and 0.1% in emission control areas.

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3.4.2 IMO measures to address GHG emissions
The IMO has been working on possible solutions to reduce GHG emissions from shipping for several
years. The measures that have been put in place for addressing maritime GHG emissions are theEnergy Efficiency Design Index (EEDI), Ship Energy Efficiency Management Plan (SEEMP), mandatory
Fuel Oil Data Collection System (DCS) and the Energy Efficiency Operational Indicator (EEOI).
During MEPC 75 in November 2020, draft new mandatory regulations were approved by the IMO,
including the introduction of a measure or existing vessels, known as the Energy Efficiency Existing
Ship Index (EEXI) (IMO, 2020). Following their adoption at MEPC 76 in June 2021 (IMO, 2020), theserequirements will enter into force in 2023. These amendments also include the establishment of aCarbon Intensity Indicator (CII), which will further address ship performance. The IMO will likely review
the effectiveness of the implementation of the EEXI and CII by January 2026 (IISD, 2020). Issues
around the development of lifecycle GHG/carbon intensity guidelines for all relevant types of fuels havealso been discussed. The position of the EU is that the guidelines should include a methodology thatallows ship operators to compare the well-to-wake emissions of different alternative fuels (European
Parliament, 2020).
Under the new amendments, ships will be required to meet a specific EEXI. The CII indicates theaverage CO2 emissions per transport work applied to individual ships. A reference line and a reduction
factor will be determined to target continuous improvement of the ship's operational carbon intensity(IISD, 2020). The contributions of SEEMP, CII, EEDI, EEXI, EEOI and DCS to different ship efficiency
strategy components are visualised in Figure 3-11.
Figure 3-11: Contributions of SEEMP, CII, EEDI, EEXI and EEOI to different ship efficiency strategy
components



EEDI is an index that estimates gCO2 per transport work (gCO2 per tonne-mile) and is calculated
based on the technical design parameters for a new ship. It is a function of installed power, speedof vessel and cargo carried. The EEDI aims to increase the uptake of more energy efficientequipment and engines within the sector, requiring new ships to adhere to a minimum energy
efficiency level. The regulation will be strengthened every five years, with the level adjusted
according to ship type and size.



EEXI is an efficiency design index for existing ships, approved in November 2020 (IMO, 2020). The
EEXI is very similar to the newbuilding related EEDI, with adjustments to extend to existing vessels



SEEMP provides a mechanism for shipping companies to manage the efficiency and performanceof their fleets, allowing for an assessment of technological or operational changes (e.g. through the

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EEOI)). SEEMP urges the ship owner and operator at each stage of the plan to consider new
technologies and practices when seeking to optimise the performance of a ship.


CII is an indicator that determines the annual reduction factor needed to ensure continuous
improvement of the ship's operational carbon intensity within a specific rating level. The actual
annual operational CII achieved will be verified against the required annual operational CII. This
would enable the operational carbon intensity rating to be determined. The rating will be given on ascale that shows the performance level (rating A, B, C, D or E). The performance level will then berecorded in the ship’s SEEMP (IMO, 2020).



EEOI is the total carbon emissions in a given time period per unit of revenue tonne-miles. This wasdeveloped by the IMO in order to allow ships to monitor the carbon emissions of their shipping
activities. The EEOI enables operators to measure the fuel efficiency of a ship in operation and togauge the effect of any changes in operation.



MRV refers to the monitoring, reporting and verification (MRV) of CO 2 emissions for vessels during
their voyages from 2018, and globally amendments to MARPOL Annex VI on Data collection system(DCS) for fuel oil consumption of ships entered into force on 1 March 2018 (IMO, 2018). The EU’s
MRV regulation has additional elements compared to the IMO’s Data Collection System: data are
published, the data are verified, and the data include cargo tonnages carried which enables a viewon the operational efficiency of the ships.

3.4.3 IMO regulation effectiveness
In April 2016 a review of EEDI target values indicated over two-thirds of new built container ships, halfof cargo ships and over a quarter of tankers launched in 2015 already meet or exceed EEDI standards
set for 2020 without using innovative novel technologies. This raised concerns that the EEDI is notstringent enough to significantly reduce GHG emissions and that there is still a large amount of scope
to improve its effectiveness (The Royal Institution of Naval Architects, 2017).
The literature also indicates it is now widely accepted that ship design efficiency requirements alone will
fall short of what is required in order to achieve the targeted decarbonisation of the shipping sector by
2050. The European Commission has stated it will propose further measures to tackle GHG emissions
from ships, in the absence of adequate progress in the framework of IMO, thereby effectively
highlighting that the adoption of EEDI is not sufficient (Psaraftis H. , 2012). Further analysis regarding
EEDI effectiveness is found in Appendix 3 – EEDI effectivenessAs for the more recent set of amendments, (covering EEXI and CII), opinions on the effectiveness ofthese measures are divided. Whilst welcomed by industry, NGOs such as Transport & Environment(T&E) see the amendments as simply ‘business as usual draft text’, and state they will not reduce
emissions this decade (T&E, 2020). According to T&E, this is due to three reasons. Firstly due to the
reduced stringency of the EEXI for many vessels, secondly because non-compliant ships will be able
to continue underperforming for three consecutive years before they have to file a plan to make
improvements, and thirdly because there is a lack of enforcement as all clauses that would create
consequences for non-compliance (e.g. increased EEXI stringency) have been removed (T&E, 2020).

3.4.4 Port area regulations and incentive programmes
Port area regulations can also be useful drivers in decarbonising the shipping sector. Specific port area
regulations and policies include those at IMO level (e.g. Port development under the IMO Initial Strategy2018), EU level (Directive 2009/16/EC on Port State Control30) and local level (e.g. California Air
Resources Board Regulation (CARB) on airborne toxic control of auxiliary diesel engines operated on

30

Under review at present (2021): https://ec.europa.eu/info/law/better-regulation/have-your-say/initiatives/12641-Port-State-control-Furtherimproving-safety-security-and-sustainability-of-maritime-transport

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vessels at-berth) (International Chamber of Shipping, 2018). Generally, Port Authorities do not monitor
and enforce regulations. It is under the remit of Port State control (PSC) authorities to inspect foreign
ships in national ports to verify ship condition, equipment and certificates of compliance withinternational regulations. Any Party to the MARPOL Convention can exercise enforcement jurisdiction
against any ships visiting its ports to ensure compliance with the Convention (International Maritime
Organization, 2018).
The IMO has encouraged the establishment of regional PSC co-operation on enforcement31. To thisend, nine Memoranda of Understanding on PSC have been concluded covering much of the world’s
oceans. In the possible enforcement of future carbon-based policies these MoU may become usefulmeans through which Port States check compliance on behalf of larger regions.
Another lever that ports can use to incentivise decarbonisation measures is through differentiated portfees. As noted in section 3.3, whilst port fees are not a dominant proportion of total ship operator costs,
they are sufficiently large to provide the possibility to provide an incentive. In this way, ports utilise thepre-existing fees paid by ships by applying either a fixed or proportionate reduction for low emission
ships (and may need, in order to remain revenue neutral, to as a compensation increase the fees forhigh emission ships). Early adoption of this measure began in Sweden with the introduction of theirDifferentiation of Fairway Dues in 2018 which incentivises low SOx and NOx emissions (Vierth, 2020)..
Similar measures have been used in many ports since. Many ports’ incentive schemes are based on
the Environmental Ship Index32 (ESI). The ESI rates ships in four separate elements, three of whichrate the environmental performance of the ship against the international standard for a particularpollutant (NOx, SOx, CO2 with bonus points available for the latter for energy efficiency), while the fourthreflects the ability to use shore-side power while at berth. Appendix A.4 includes the structure of thecalculation of the ESI and lists the ports using the ESI in different regions.

Environmental Ship Index (ESI)

Falls within the scope of the World Ports Sustainability program (WPSP), a commitment from theworld’s key ports to reduce greenhouse gas emissionsIs a voluntary numerical index that can be used to promote clean ships and to reward the mostefficient ships

The ESI is used by over 50 ports and has over 8,000 ships registered.

Discounted port dues and other incentives (for example use of clean ship scores as promotional
instruments) are examples of how voluntary measures can encourage early adoption of emission
reduction measures in advance of regulations. Voluntary incentive programmes may be an importantdriver for the introduction of new technologies within fleets. However, there is some uncertainty about
the effectiveness and appropriateness of voluntary measures (Clyde&Co, 2017). Nevertheless, several
voluntary instruments have contributed to the uptake of gas engines, selective catalytic reductions(SCR) catalysts, sulphur oxides (SOx) scrubbers and other technologies, resulting in an increase ofexperience with these technologies in the industry (Anderson, et al., 2015). Globally, in total around ten
extra-legal incentive schemes are in place to improve air quality, with the Environmental Ship Index(ESI) being the most widely implemented (Tester, MacKenzie, Kouboura, & Hanly, 2017). However,compared to the overall number of cargo ships in operation worldwide, the share of ships joining
voluntary schemes is estimated to be around 5%.
The use of alternative fuels as a basis for port-incentive schemes is again growing in popularity. Initialfuel incentives supported the reduction of SOx and NOx outputs but since the adoption of the 0.1% fueloil sulphur limit, attention could be directed to decarbonisation fuels. There are several LNG schemes
31

Resolution A.682(17) on Regional co-operation in the control of ships and discharges

32

https://www.environmentalshipindex.org/Public/Home

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established in major ports and they are an important driver for uptake of this fuel. A more recently
developed incentive scheme surrounds berth times and berth priority based on the environmental
impact of the ship. Ports’ berth allocation policies have evolved from traditional first-come-first-serve toa system which minimises waiting times, and there is room to incorporate the environmental impact of
the ship, as evidenced by Panama’s implementation of the Environmental Premium Ranking in 2017,
which contributes to ships’ allocation in the booking system for the canal.
Despite relatively low overall participation rates in terms of global fleet, incentive programs have been
known to develop into compulsory programs, therefore they can remain a key driver in not only shaping
future shipping fleets but are often a prerequisite for future regulation. For example, following on frominitial voluntary programs, management of ships' ballast water and sediments became a mandatory
requirement adopted by consensus at IMO Headquarters in London on 13 February 2004, completewith fines, penalties and potential civil liability exposure as well (International Maritime Organization,2017).

3.4.5 Carbon offsetting
Another potential market-based measure that can be considered to mitigate GHG emissions is the useof “carbon offsetting”. According to the IPCC, “a carbon offset is a reduction in emissions of carbon
dioxide or other greenhouse gases made in order to compensate for (“offset”) an emission madeelsewhere” (IPCC, 2018). Planting trees (removing CO2 from the atmosphere as they grow) or investingin energy efficiency and renewable projects (avoiding future CO 2 emissions) are examples of carbon
offsetting initiatives (UN Environment, 2019). Carbon offsetting has been criticised as being “a free passfor inaction”, allowing sources of GHG emissions to buy carbon offsetting credits without acting to
reduce their emissions (UN Environment, 2019). For the Paris Agreement climate goals to be achieved
carbon offset projects will not be enough to reduce emissions to the level required (UN Environment,2019).
In the transport industry, the most prominent example of carbon offsetting is the ‘Carbon Offsetting andReduction Scheme for International Aviation’ (CORSIA). Under this programme, airlines will have tooffset all their emissions resulting from international flights above a certain threshold, based on the 2019
emissions of the sector (Flight Global, 2020). In the maritime industry, there are currently no plans touse carbon offsetting as part of the strategy to achieve the IMO’s decarbonisation targets. In 2009,
Cyprus, Denmark, the Marshall Islands, Nigeria and the International Parcel Tankers Association (IPTA)
submitted a proposal33 to the IMO for the creation of an international fund for GHG from ships. This
proposal would establish a target for decarbonisation 34, and any emissions above the target would beoffset by the use of carbon offsetting. This offsetting would be financed by a contribution paid by ships
on every tonne of bunker fuel purchased (IMO, 2020). While some organisations have put forwards
proposals for the use of carbon offsetting in the maritime sector 35, at the IMO level the topic does not
currently appear to be under consideration.

33

An International Fund for Greenhouse Gas emissions from ships, MEPC 60/4/8 (IMO - MEPC, 2009).

34

A target was eventually adopted in 2018 (see section 1.1).

35

See, for example, Kachi et al. (2019) and Cabbia Hubatova (2020).

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4 Fuels and technologies to decarbonise shipping
Key points:

A long list of measures to decarbonise the shipping sector was developed. Key decarbonisation
measures identified include:oFuture energy carriers with lower well-to-wake GHG emissions compared to traditional
marine fuels, such as LPG, LNG, BioLNG, biofuels (FAME, HVO), ammonia, hydrogen,methanol and batteries.

oVessel design measures that reduce vessel resistance and fuel consumption (such as hull
coatings and optimum ship size dimensions)oPower assistance measures that reduce main engine power demand (e.g. solar panels,
flettner rotors, sails)oAlternative propulsion technologies including different propellers (large area propellers,
contra-rotating propellers and podded thrusters) as well as propulsion improving devices
such as post-swirl fins and rudder bulbs.

oEngine technologies that improve engine/vessel efficiency, including enhanced fuelinjection systems, early intake valve closing and waste heat recovery.

oOn-board carbon capture reducing exhaust emissions of CO2 (the captured CO2 may thenbe stored or re-used).

oVoyage optimisation measures that reduce fuel consumption (e.g. advanced port logistics,
speed reduction, weather routing).

The detailed analysis of the decarbonisation potential and practical considerations related to eachof these measures can be found in this section.

The main fuel used for shipping was and remains residual fuel, or heavy fuel oil (HFO 36). Specifically,
the global demand for marine fuel is predominately met by HFO (66%), followed by marine diesel oil(MDO) (30%) (IMO, 2020). However the shipping fuel landscape is evolving.
The falling costs of net zero carbon energy technologies has reduced the cost differential of sustainable
alternative fuels to conventional fuels, although it remains significant. Whilst the use of alternative fuels(such as LNG) have long been explored previously, in recent years the search for alternative fuels has
expanded. Now, some fuels that until very recently were not considered as marine fuel alternatives areincluded in research and development activities. For example, key recent outlook reports such as ABS’s
Setting the Course to Low Carbon Shipping (2019) and DNV GL’s Maritime Forecast to 2050 (2018)
feature newly considered fuel solutions such as ammonia, hydrogen and methanol.
As well as fuels, different technologies for decarbonising the shipping sector have also been explored.
Categorisation of technologies tend to be broadly agreed upon, such as vessel design, power andpropulsion, operational measures (e.g. slow-steaming) and alternative energy sources.

36

Following the introduction of the IMO regulation on the sulphur content in fuel from 2020, the fuel used should be very low sulphur fuel oil (VLSFO)
or ultra-low sulphur fuel oil (ULSFO), unless the vessel is equipped with an approved exhaust gas cleaning system (scrubber). For simplicity, thisreport refers to all residual fuels as HFO.

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The cumulative emission reductions these technologies entail and their contribution to decarbonisation
by 2050 vary across studies. For example, a literature review by Bouman et al 37 indicates that emission
reductions between 33-77% could be achieved in 2050 based on current technologies, encouraged
through a combination of policy measures (Bouman et al, 2017). Another aspect to be considered is therelative role of current technologies versus alternative fuels in decarbonisation by 2050. Other studies,such as the OECD report on zero-carbon shipping by 2035, have highlighted a greater role of alternative
fuels, such as hydrogen and ammonia penetrating the sector and supplemented by technical andoperational measures (European Commission, 2018) (OECD, 2018).
This section considers the alternative fuel options as well as vessel and engine technologies, together
with operational measures, to decarbonise the shipping sector. Looking forward to 2050, this section
identifies and quantifies the emission reduction potential of measures and establishes their current
implementation. Figure 4-1 provides a broad overview of the options to decarbonise shipping by 2050 38.

Bouman et.al.(2017), State-of-the-art technologies, measures, and potential for reducing greenhouse gas emissions from shipping – a review,
Transportation Research Part D 52, 408-421
37

38

Note: this diagram serves as an overview and is not an exhaustive list of technologies and fuels.

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Figure 4-1 Broad overview of options to decarbonise shipping by 2050

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To assess GHG reduction potential it is also important to understand the Technology Readiness Levels(TRL) of different measures and fuels. TRL show the steps required from research through to vessel
deployment and indicate the market maturity of technologies. These are summarised in Figure 4-2.
Some decarbonisation measures may already be at deployment whilst others are at earlier stages ofdevelopment or demonstration. TRLs have been identified for each technology and fuel to enable
comparison.
Figure 4-2: Technology Readiness Levels (TRL)

Source: Based on US DoD TRL

A full detailed analysis of the different GHG emissions and production pathways of the fuels assessedcan be found in Appendix 5 (A.5). A more detailed breakdown of the applicability to different vessels,
current implementation, and future ownership of each of the technologies is presented in Appendix 6(A.6).
The remainder of this section summarises alternative fuel options, power assistance measures,
alternative propulsion measures, engine and aftertreatment technologies, carbon capture (CC), voyage
optimisation and fuel quality improvements, and their potential contributions to decarbonising the sector.

4.1 Future energy carriersThis section assesses in detail the GHG reduction potential of different alternative fuels, their costs andthe GHG emissions associated with their different production routes. The practical limitations of thesefuels in terms of storage, market feasibility and infrastructure as well as their capital costs and otherenvironmental impacts are discussed. Table 4-1 shows an overview of the candidate fuels considered.
The TRL for each fuel considers both the readiness of the fleet (i.e. the existence of in-service vessels
using the fuel) and the production and bunkering infrastructure (e.g. blue and green alternative fuels
may not be at the same technology readiness as their grey counterparts).

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Table 4-1: Summary of future potential energy carriers.
Fuel

GHG reduction
potential(%)*

TRL for transoceanic

Compatibility

HFO (low sulphur)

-

9

-

MDO

-

9

-

10

9

Requires gas/dual fuel engine and associatedcryogenic storage.

72

9Same requirements as for LNG.

20

9

Requires LPG/dual fuel engine.

(emissions > HFO)

9

Pathway

LNG
Global average

BioLNG
Liquid manure**

LPG
Natural gas (propane)

Methanol (Grey)
Natural gas

Not drop-in. Compatible with internal combustion
engines.

Methanol (Green)95

7(emissions > HFO)

7

Synthetic (renewable)

Ammonia (Grey)
Natural gas

Ammonia (Blue)

85

4/5/6

75

3/4/5

(emissions > HFO)

7

84

4/5/6

75

3/4/5

73

9

Drop-in (blended only < 20% FAME)

77

9

Drop-in (blended and neat)

66%

4/5/6

Natural gas + CCS

Ammonia (Green)
Renewable electrolysis

Hydrogen (Grey)
Natural gas

Hydrogen (Blue)
Natural gas + CCS

Hydrogen (Green)
Renewable electrolysis

FAMEe.g. Waste cooking oil

HVOe.g. Waste cooking oil

Batteries
Attractive

Not drop-in. Compatible with engines underdevelopment (spark ignition with a hydrogen blend,or dual-fuel with pilot diesel). Safety and toxicity
concerns.

Moderate

Not drop-in. Compatible with internal combustion
engines (spark ignition & dual-fuel) but requires
development and a supporting fuel.

Not compatible with ICE. Require their own storage
systems and equipment. Weight and size
challenges.

Unfavourable

TRL =Technology readiness level. CCS = Carbon capture and storage. Cost = production cost of alternative fuel pathway (USD 2020). Costs presented are based on
estimates available from the literature. Costs are those associated with production costs excluding transportation costs. For blue ammonia and hydrogen theoretical costs
were calculated based on detailed research rather than data from actual projects. *Refers to % reduction in Well-to-Wake emissions compared to HFO emission baseline.
Maximum potentials are shown with the exception of green ammonia, green hydrogen, green methanol and battery electric. In theory, 100% reduction (or higher) may beachievable with 100% renewable electricity for these fuels and with off grid renewable energy; however the timeframe and costs for these production pathways are not clear
at present. **The processing of manure for the production of BioLNG can capture methane that would otherwise be emitted to the atmosphere. Accounting for this canincrease the emissions reduction potential to over 170%.

In Table 4-1, the GHG reduction potential values given for “green” hydrogen and ammonia are basedon life cycle analyses performed by Ricardo and include the emissions embedded in the renewableelectricity generation plant. As the production of these fuels involves large quantities of electricity, theseembedded emissions have a significant effect on the potential GHG reductions, to the extent that thegreen hydrogen and ammonia appear to have lower reduction potential in 2020 than their blue
counterparts. These embedded emissions are forecast to reduce significantly over time as technology
improves, so by 2050, the GHG reduction potentials for green hydrogen and ammonia improve to 90%.

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Included in Table 4-1 are examples of drop-in alternative fuels (i.e. those compatible with existing dieselcycle engines) that have a high level of maturity. There are other examples of drop-in fuels that areunder development, such as alternative conversion pathways based on similar biological feedstocks(such as hydrogenated palm oil (HPO) or hydrothermal liquefaction of biomass) or synthetic fuels (efuels). These may provide alternative options for drop-in fuels for the maritime sector in the future. For
this report, FAME and HVO are used a examples of drop-in fuels, based on their higher level of maturity.
Figure 4-3 also provides a graphic overview of the key characteristics of candidate fuels assessed inthis study to facilitate comparison. For this figure, the cost per GJ values are those used for year 2030
in the cost modelling for this study; further details on their derivation are given in Section 6.2.1.
Figure 4-3 Candidate marine fuel comparison of cost, GHG reduction potential and Technology Readiness
Level (TRL) – fuel cost values for year 2030

TRL =Technology readiness level. Cost = production cost of alternative fuel pathway (USD 2020). Costs presented are based on estimates available
from the literature. For blue ammonia and hydrogen theoretical costs were calculated based on detailed research rather than data from actual
projects. GHG reduction refers to % reduction in Well-to-Wake emissions compared to HFO emission baseline. Maximum potentials are shown withthe exception of green ammonia, green hydrogen, green methanol and battery electric. In theory, 100% reduction (or higher) may be achievablewith 100% renewable electricity for these fuels; however the timeframe and costs for these production pathways are not clear at present. The
processing of manure for the production of BioLNG can capture methane that would otherwise be emitted to the atmosphere. Accounting for thiscan increase the emissions reduction potential to over 170%.

A key barrier to the widespread uptake of low-carbon alternative fuels (with the possible exception of
LNG) is their considerably higher production costs, and hence price to the end-user, compared toconventional maritime fuel. This cost differential will need to be addressed if alternative fuels are to becommercially competitive with conventional fuels.
For many of the candidate fuels, (e.g. green/blue ammonia and hydrogen, green methanol and BioLNG),
their GHG emissions hinge on the share of renewables of the electricity used in their production. The
exact evolution of renewable electricity in the sources available to fuel producers (whether from thenational grid or from their own generation) is not clear at present. To deliver the full potential reductions

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in GHG emissions, it is important that the electricity used in their production is 100% renewable; fuelproduced with other electricity sources may not be truly “green”.
In 2017 the global estimated renewable share of total final energy consumption was 10.6% (REN21,2020). Looking forwards global renewable energy share projections for 2050 vary. The exact share will
be highly dependent on geopolitics, national level policies and supply.
For example, in IRENA’s 2020 Global Renewables Outlook report, the ambitious deeper
decarbonisation perspective projects that the global share of renewable electricity in generation has torise to 57% by 2030 and 86% by 2050 (IRENA, GLOBAL RENEWABLES OUTLOOK, 2020). In contrast,
the Stated Policies Scenario (STEPS) developed by IEA and based on existing and announced policies
predicts the global share of modern renewables will reach 15.4% of total final energy consumption in
2030.
Despite this variation, what is clear is that projections indicate increases in renewable energy share andthe generation of renewable electricity is growing fast.
The renewable electricity supply (grid mix) and cost will also vary by region and this will impact specificfuel pathways. The international nature of shipping means fuels may be produced all around the world.
In this way, the region in which a fuel is produced, impacts its carbon reduction potential. For example,
currently the EU has a renewable energy share higher than the global average. In 2019, renewableenergy represented 19.7% of energy consumed in the EU and is expected to meet 2020 target of 20%(Eurostat, 2020). The EU’s current targets stand at a 32% share by 2030, working towards 1.8%-3.4%
annual increases over the period 2030-2050 (from a range of eight scenarios published in theCommission's 2050 long term strategy).The long term objective being 100% renewable energy sourcesof electricity by 2050 (EEA, 2019).
Further, at least for the initial pilot plants for green fuels, the locations in which the plants are built may
be selected because of the local availability of feedstocks and renewable electricity. If this continues as
production increases to match future demand, a result could be an increased need to transport maritime
fuels from the production facilities to the ports. The additional energy consumption and costs associatedwith this transport may be reduced by locating production facilities closer to key shipping routes (and tothe major maritime ports), provided that this does not result in significant increases in transport costs
for the feedstock to the production facility.
As well as cost and renewable electricity availability, fuel characteristics are also important indetermining a fuel’s suitability and hence uptake. For example, fuels with lower energy densities requirea larger volume of storage for a given amount of energy. Key fuel characteristics are summarised inTable 4-2.
Table 4-2: Comparison of fuel properties

Fuel type

Lower
heatingvalue(MJ/kg)Liquid Density at
15°C at 1 bar(kg/l)

GaseousDensity at 0°C
at 1 bar(kg/m3)

Energydensity(GJ/m3)*

Flash point

Autoignition
temperature

HFO

40.2

0.98

-

39.40

65~80°C

400°C

MGO

42.8

0.855

-

36.59

>60°C

232°C

LNG

48.6

-

0.742

0.04

-175°C

537°C

LPG

45.5

-

1.986

0.09

-104°C

470°C

Methanol

19.9

0.791

-

15.74

11-12°C

464°C

Ammonia

18.6

-

0.72

0.01

132 °C

651°C

Hydrogen

120.0

-

0.09

0.01

-

560°C

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Fuel type

Lower
heatingvalue(MJ/kg)Liquid Density at
15°C at 1 bar(kg/l)

GaseousDensity at 0°C
at 1 bar(kg/m3)

Energydensity(GJ/m3)*

Flash point

Autoignition
temperature

Methane(BioLNG)

48.6

-

0.742

0.04

-175 °C

537°C

FAME

37.2

0.88

-

32.74

173°C

261°C

HVO

34.0

0.78

-

40.48

55 °C

204°C

*for liquids presented at 15°C at 1 bar and for gases presented at 0°C at 1 bar

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4.1.1 Liquefied natural gas (LNG)
LNG
GHG performance and production route emissions
Well-to-tank: Emissions estimated at 18.5 g CO2eq/MJ (Thinkstep, 2019).



Tank-to-wake: Variation between studies. Some indicate GHG reduction levels up to 26% compared to traditional marine
fuels (DNV GL, 2019) (American Bureau of Shipping, 2019), whilst others indicate no climate benefit of LNG compared to
HFO (ICCT, 2020) once emissions of unburnt methane (methane slip) are taken into account (Lutsey et al, 2013). Most
recent high-pressure engines are considered to reduce methane slip to very low levels.



Expected Well-to-wake GHG reduction potential: 10.4% for a global average production pathway (Thinkstep, 2019).
Emissions reduction for BioLNG depends on the production pathway; 69% for biomethane production using liquidmanure and closed digestate storage (Verbeek, 2015)39 .

Production pathway availabilityCommercially mature.

Compatibility and technology

The technology needed to use LNG as a maritime fuel is commercially available and mature (TRL=9).



By the end of 2019 the LNG fleet encompassed 601 vessels (Statista, 2021).



Methane slip could be reduced through new technologies, for example through Intelligent Control by Exhaust Recycling(iCER). This recirculates methane to reduce the amount that is left in the exhaust system (Vessel Performance
Optimisation, 2021). Also, the latest high-pressure diesel-cycle engines produce low levels of methane emissions.

Infrastructure

Global infrastructure is growing but remains a limitation. Over 40 European coastal ports have LNG bunkering in operation;
10 more in the Australasia/Middle East region. In the EU by 2025 more than 100 bunkering facilities should be available;
at least 15 projects are under development in the Australasia/Middle East regions; projects under development across the
USA as well (Gulf of Mexico, Southeast region and Pacific Northwest). Delivery by rail or truck is also possible.



Rules on LNG bunkering have been developed locally at each port, however harmonisation is lacking. consistent portlevel bunkering regulation has not been established, which may cause information barriers

Storage & handling

Low energy density: LNG requires more storage-tank volume than HFO for the same range.



Cryogenic storage handling: LNG fuel supply and containment systems require three or four more times on board
deck space, as the spatial arrangement of cryogenic tanks involves specific segregation distances between cryogenic
tanks.



Flammability; gas under pressure: More crew training is needed to ensure safety requirements are reached. It is also
critical that safeguards prevent a flammable mixture from occurring and that ignition sources are far way (American
Bureau of Shipping, 2019).

Supply

Global LNG demand for all sources in 2019 ~360 Mt, and expected to double by 2040 (Shell, 2020) Available worldwide(at large-scale import and export terminals). Further investments underway to improve availability (DNV GL, 2019).



Total global shipping LNG consumption in 2018 ~11.4 Mt (HFO equivalent Mt) (IMO, 2020) the most widely consumed
fuel in the maritime sector other than HFO and MDO.

Cost

LNG prices are similar to conventional fuels (on a per unit of energy basis.)Capital costs and operational costs remain significantly higher for LNG compared to conventional fuels.

39

The differences are due to feedstock. Biomethane using liquid manure can be seen as producing negative emissions if viewed as avoiding
methane emissions.

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Other environmental impacts
Near zero SOx emissions and lower particulate matter compared to HFO.



Significantly lower NOx emissions, allowing spark ignition (Otto cycle) engines to meet IMO Tier III regulation without
exhaust aftertreatments. Diesel-cycle gas-fuelled engines require aftertreatment to meet Tier III.



During LNG storage and transportation heat enters the cryogenic tank which results in a part of the LNG in the tankcontinuously evaporating, referred to as Boil-Off Gas (BOG). Tank pressure and temperature are maintained by meansof oxidizing BOG in a gas combustion unit (e.g. the vessel engine) or via re-liquefication. BOG is not normally vented toatmosphere. (Tagliaferri et al, 2017)

Depending on the design of the engine (combustion pressure and fuel injection design), combustion of LNG may resultin some gas escaping to atmosphere without being combusted, known as methane slip. High pressure engine design
can be effective at reducing methane slip to very low levels.

Remaining challenges


Fugitive methane emissions, being addressed by IMO.

4.1.1.1

LNG drop-in fuels

LNG powered ships could also use LNG-compatible drop-in fuels in the future. Liquefied bio-methane(“BioLNG”) and liquefied synthetic methane (LSM) have recently been shown to be compatible with
LNG fuelled ships without requiring major modifications (CE Delft, 2020). BioLNG can be used inexisting LNG engines with little, or no, modification and transported, stored and bunkered in ports
utilising existing LNG infrastructure (EBA, SEA-LNG, GIE and NGVA, 2020).
Some key examples of commercial applications where BioLNG is already being supplied include; CMCGM’s container ship Jacques Saadé (13% BioLNG), ESL Shipping’s dry bulk carrier m/s Viiki, Preem’s
two tankers (10% BioLNG blend), and Destination Gotland’s two high-speed ropax ferries that are bothusing a BioLNG blend (EBA, SEA-LNG, GIE and NGVA, 2020).
BioLNG demand volume for maritime shipping by 2030 is expected to increase, although opinions
diverge on feedstock availability and allocation between sectors. Whilst future demand varies according
to different projects, in the CE Delft study, under a scenario where national policies proceed in line with
Paris agreement commitments, 30% of LNG is replaced by BioLNG by 2030.
BioLNG can be produced through anaerobic digestion or gasification. The majority of anaerobic
digestion technologies (e.g. manure digestion) are commercially mature. The digestate pathways areavailable now. BioLNG from municipal waste production is already regionally present in/near someports, such as Rotterdam and Bristol (CE Delft, 2018) (GENECO, 2020). In contrast, gasification
technologies are not as commercially mature and demonstration units are only available at asemi-commercial scale.
The CE Delft analysis of the global sustainable biomass resource showed that biomethane from energy
crops, agricultural residues, forestry products and residues could already exceed the global total energy
demand of the maritime sector. However, this does not include potential competition from other transportmodes.
Another feedstock that can be used to produce BioLNG is liquid manure. This BioLNG production
pathway has been identified in the literature as having very high GHG reduction potential. In 2018,global biogas production from animal manure feedstocks reached 11Mtoe (IEA, 2020).
BioLNG production emissions are estimated as follows:

Well-to-tank: Emissions estimated at 26.5 g CO2eq/MJ (JRC, EUCAR and Concawe, 2020)



Tank-to-wake: Variation between on GHG savings and depend on methane accounting andproduction technology

Expected Well-to-wake GHG reduction potential: 70% for liquid manure (closed digestate storage)
production pathway (calculated using WTW emissions above)..

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4.1.2 Liquefied petroleum gas (LPG)
Liquefied petroleum gas (LPG) is a by-product of oil and gas production / oil refining processes. It is a
mixture of mainly butane and propane. LPG is already available globally (HellenicShipping, 2020).
LPG
GHG performance and production route emissions
Well-to-tank: Emissions are highly dependent on the source (natural gas, petroleum), ranging from about 8g CO2eq/MJ
to 13g CO2eq/MJ).



Tank-to-wake: Emissions estimated at 65.4g CO2eq/MJ (JRC, EUCAR and Concawe, 2020)Expected Well-to-wake GHG reduction potential: 16% for natural gas derived LPG production pathway (calculated using(JRC, EUCAR and Concawe, 2020))

Production pathway availabilityBoth conventional natural gas and petroleum derived LPG production pathways are available now.

Compatibility and technology
Engine technologies as well as retrofitting options have been developed for LPG, for example MAN ME-LGI dual fuelengine and Wärtsilä’s retrofit LPG Fuel Supply Systems (LFSS) .

Engine developments for LPG have led to new potential for ammonia. Materials used for LPG tanks and systems will inmost cases be suitable for ammonia (MAN Energy Solutions, 2019)

InfrastructureTerminals still need to be developed into a dedicated network to enable LPG supply where demanded.



Developing LPG bunkering infrastructure, operating systems and equipment, would be less costly than those requiredfor LNG, predominately due to easier handling and storage properties (American Bureau of Shipping, 2019).



Many ports already have LPG import/export terminals, and safety procedures already exist to deal with the substance.

Simple modifications would be needed to adapt existing LPG installations to also become bunkering facilities.

Storage & handling

Low energy density: LPG storage requires three times the volume of HFO for the same energy content. Tanks can be
up to 5,000 m3. However, LPG does not require cryogenic storage.



Safety and flammability: LPG is heavier than air, therefore leaks can accumulate in the lower sections of a space. LPG
vaporises rapidly and is flammable when the percentage in air is between 1.5-11%.

Supply

Currently natural gas and petroleum reduction leads to surpluses and an LPG supply ranging from 15 to 27 million tonnes
per year. This has driven low prices along with the shale gas revolution (WLPGA, 2017). However, LPG supply remains
a barrier. This is because LPG is a by-product and with decreasing future demand for fossil fuels, LPG production will also
decrease. Future LPG availability will likely be limited as renewables increase.

Cost

Between May 2020 and February 2021 the price of propane has ranged from $0.33 to $0.92 per gallon (Trading
Economics, 2020), equivalent to approximately $160 to $440 per tonne40.

Other environmental impacts
Emits 90% to 97% less sulphur (SOx), 20% less nitrogen oxide (NOx), 90% less particulate matter (PM)..

Remaining challenges
40

LPG was not considered by stakeholders as a viable alternative fuel given the need to transition to lower-carbon fuels. It
has a likely limited future supply.

Note: the market price of LPG varies and depends on pressure and temperature

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4.1.3 Ammonia
Ammonia
GHG performance and production route emissions
Well-to-tank: Varies depending on production pathway. Traditionally, (grey) ammonia production involves steam
reforming, which produces no GHG saving. The production of green ammonia uses renewable electricity powered
electrolysis to separate hydrogen from oxygen using electrolysers.



Tank-to-wake: No emissions.



Expected Well-to-wake GHG reduction potential: 0% for grey natural gas ammonia production pathway, 85% for blue
natural gas & CCS ammonia production pathway and 75% for green renewable electrolysis ammonia production pathway(if the electricity is 100% renewable the WTW emissions are zero) (DECHEMA, 2017)

Production pathway availabilityElectrolysis: Ammonia production through electrolysis can be achieved with commercially proven equipment (Ash,2019). These production pathways have not yet become widely available due to renewable electricity costs. However,green ammonia plants are being developed such as the Enaex project in Chile, Incitec Pivot in Australia and the JGC
Corporation project in Japan (Ammonia Industry, 2019) (Ammonia Energy Association, 2019). A pilot project by Yara
and Nel to reduce electrolyser costs should be in operation in Norway by 2022 (Yara, 2019). Given these developments,
there may be wider availability as early as 2025 of the ammonia production pathways using electrolysis.

High temperature electrolysis:. This production pathway may not be available until 2030 or beyond.

Conventional production: Steam methane reforming using natural gas technology available now but do not offer GHG
savings. This production route can be coupled with CCS to make blue ammonia.

Compatibility and technology
Ammonia can be used in modified internal combustion engines that use spark- or compression-ignition systems. Marine
engine supplier MAN Energy Solutions recently embarked in October 2020 on a project to design, develop anddemonstrate at full-scale a large marine two-stroke engine running on ammonia as well as an associated fuel supply
system. Development of the engine is scheduled for 2024 (MAN Energy Solutions, 2020).



Various collaborations are researching and developing ammonia-engined vessels, including:o

Malaysia-based shipowner MISC, Samsung Heavy Industries (SHI), Lloyd’s Register and MAN Energy
Solutions are developing an ammonia-fuelled tanker (announced early 2020)oJapanese shipping company NYK Line, shipbuilder Japan Marine United Corporation (JMU), and ClassNK areaiming to commercialise an ammonia-fuelled ammonia gas carrier and an ammonia floating storage andregasification barge (announced August 2020).
The Nordic Green Ammonia Powered Ships (NoGAPS) project aims to prove the concept of an ammonia
powered vessel and potentially a first demonstration green ammonia powered ship in operation by 2025
(announced May 2020) (Nordic Innovation, 2020).

oo

The American Bureau of Shipping (ABS), MAN Energy Solutions and the Shanghai Merchant Ship Design &Research Institute (SDARI) announced a collaboration to produce an ammonia fuelled 2,700 TEU feeder
vessel (December 2019) (ABS, 2019)

Ammonia may not be opted for as a fuel for passenger-carrying vessels due to odour concerns.



In the longer term, ammonia could potentially be used in fuel cells for propulsion so that even emissions of NOx are
eliminated. The ShipFC consortium project was awarded €10m funding in 2020 to deliver the first high-power fuel cell tobe powered by green ammonia. The result will be an offshore vessel, named Viking Energy, that can sail solely on theclean fuel for up to 3,000 hours annually by using an ammonia-powered fuel-cell (Equinor, 2020).

InfrastructureCurrently no bunkering infrastructure for ammonia as a fuel in place.



Dedicated ammonia infrastructure would need to be rolled out. American classification society ABS, Nanyang
Technological University (NTU), Singapore, and the Ammonia Safety and Training Institute (ASTI) are investigating
supply and safety challenges around bunkering ammonia in Singapore (announced January 2021) (Offshore-Energy,2021).



While not used as a maritime fuel, ports are already experienced in dealing with ammonia, with facilities available forloading/unloading and safety procedures developed to deal with the substance.



No known efforts to install ammonia as a fuel supplied in ports.

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Ammonia (continued)
Storage & handlingCorrosion: Ammonia is corrosive to skin and some substances such as copper, brass and zinc-containing alloys as wellas natural rubber and some plastics. Material compatibility requirements are well understood, and it is straightforward toselect suitable materials to avoid damage to onboard equipment, piping, valves and other fittingsHighly toxic and combustible: Although also combustible and toxic, safety standards are already understood because
it has an existing market as a fertiliser. Stakeholders indicated that no barriers were foreseen that could not be overcome
through engineering or safety-based protocols.



Low volumetric density

Supply‘Grey’ ammonia is already produced in large quantities (~180 Mt/year) for e.g. use in fertiliser; ~11% of this isimported/exported. Ammonia plants are located where natural gas is abundantly available.

‘Green’ ammonia is not currently produced, apart from in demonstration plants. Recent announcements of planned green
ammonia plant include a pilot plant producing 0.005 Mt/year in Denmark from 2022 (Skovgaard Invest, Vestas, Haldor
Topsoe) and a production plant for 1.2 Mt/year in Saudi Arabia from 2025 (Air Products, ACWA Power, NEOM)

By comparison, 30% of maritime fuel consumption would be equivalent to ~220 Mt/year of ammonia (based on thecalculated total maritime energy consumption in 2020).

Cost


The cost of building a green ammonia plant varies depending on capacity. Upcoming Air Products hydrogen-basedammonia plant is expected to cost $5 billion (Bloomberg Green, 2020).

Other environmental impacts


Zero SOx emissions.

NOx emissions are expected to be similar to conventional fuels (requiring selective catalytic reduction (SCR) to meet Tier
III standards) and so are higher than some of the other zero-emitting fuels. Further tests may be required to understandthe levels of NOx emissions produced.



As a nitrogen-containing fuel, there is a potential for increased emissions of nitrous oxide (N2O). There is currently limited
information on the likely scale of such emissions, but there is some indication that they may be lower than conventional
diesel engines (Ash, 2019). It is possible that the use of an ammonia slip catalyst could affect N2O out. Further researchis needed to understand this issue better.



In case of a marine spill, is toxic to aquatic life. Ammonia has a distinct and unpleasant odour.

Remaining challengesEstablishing first green ammonia production facilities at scale. Potential for regional infrastructure requirements to resolve
chicken/egg problem, e.g. in the EU through the Alternative Fuels Infrastructure DirectiveMarine engines are yet to be developed and low pressure injection type engines may produce N2O.

Certification of ammonia fuel systems for use on-board vessel, including related safety regulations and guidance (IGF
Code needs to be amended to accommodate ammonia as a fuel).

Certification of blue and green ammonia to differentiate from chemically identical grey ammonia.



Developing bunkering infrastructure for ammonia at maritime ports.

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4.1.4 Hydrogen
Hydrogen
GHG performance and production route emissions
Well-to-tank: Reduction potential of hydrogen hinges on its production emissions as well as other supply chain
emissions. Steam methane reforming using natural gas (grey hydrogen) leads to GHG emissions (87.9 g CO2eq/MJ)
very similar to the well-to-wake emissions of conventional fuels. However, the production pathway of electrolysis
powered by 100% renewable electricity leads to zero GHG emissions.



Tank-to-wake: At the point of combustion (or if used in a fuel cell) – zero GHG emissions



Expected Well-to-wake GHG reduction potential: 0% for grey natural gas hydrogen production pathway41, 84% for blue
natural gas & CCS hydrogen production pathway and 75% for green renewable electrolysis hydrogen production pathway(up to 100% if 100% renewable electricity share) (Ricardo, 2019)

Production pathway availabilityNatural Gas and Steam Methane Reforming (SMR): Multiple technologies exist that enable the production of hydrogenfrom natural gas, but steam methane reforming (SMR) is currently the most widely use and is available today.

Renewable Electrolysis: Electrolysis is a mature technology, but has not been scaled up. The production pathway using
the current electricity mix is available today. To be zero-carbon, the electricity should be generated by renewable sources.



Gasification (coal and biomass) : Coal gasification is commercially mature. This broad gasification process can beapplied to biomass feedstocks. However, the formation of tar during gasification can be an issue and the technology isless developed (TRL less than 5). Biomass gasification has not yet reached a commercial stage (IEA, 2020).

Compatibility and technology
Hydrogen can be used in (suitably designed) internal combustion engines and in fuel cells. For example four-stroke engine
concepts: Spark-ignited (SI) engines with low-pressure hydrogen admission, and dual-fuel (DF) engines with low-pressurehydrogen and pilot fuel ignition have been developed by MAN Energy Solutions (MAN ES, 2021).



Fuel production pathway commercially mature, but on-vessel application at scale is not yet widely commissioned or
operated (TRL = 3/4/5). Smaller demonstration vessels using hydrogen fuel cells have started (GreenPort, 2020).
Demonstrations are underway to improve its use in shipping propulsion and for use as a fuel for longer crossings. The
Norwegian Maritime Authority is currently working on the HYBRIDShips innovation project in Trondheim which isdeveloping the world’s first hydrogen powered ferry (Norweigan Maritime Authority, 2017).

InfrastructureCurrently no bunkering infrastructure for hydrogen as a fuel in place. Dedicated infrastructure would need to be rolled
out

Storage & handling

Cryogenic storage and low density: For hydrogen the additional required storage is 7.6 times the size of storage
required compared to MGO (Ash, 2019). In liquid form, storage tanks for hydrogen can be smaller, but the trade-off thisentails is the need for cryogenic storage (-235°C). Because of limited deck space, this is a particular challenge for its
application to nonstop, long-distance voyages.

Flammable and gas under pressureLack of regulation: The IMO is not currently developing hydrogen-focused requirements, therefore an additional practicalconstraint may be establishing safe handling of hydrogen. Additional safety measures and optimal design to emphasise
ventilation and space configuration are required.

SupplyGreen hydrogen is not currently produced at scale. The recently announced ammonia production plant in Saudi Arabia(Air Products, ACWA Power, NEOM) may also produce green hydrogen.

The supply of hydrogen hinges on whether current power generation systems can support hydrogen production fromrenewables. Different levels of national transition to renewables may slow its adoption.

Cost

Projections suggest production plant capital cost reductions over time, which will lead to lower fuel costs.

Green hydrogen production capital expenditure has been predicted to decrease to 840 USD$/kW between 2020-2030
with the potential decrease to 200 USD$/kW between 2040-2050 (IRENA, 2019).

41

As with any of the emissions values presented, there is a level of uncertainty around these emissions savings. As a result, the use of greyhydrogen could produce slightly greater overall emissions than conventional fuels.

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Other environmental impacts
When used in fuel cells, hydrogen leads to zero CO2, PM, SOx and NOx.



When hydrogen is combusted in an ICE, NOx is generated.

Hydrogen is not toxic to aquatic life.

Remaining challenges


Hydrogen density is a limiting factor on vessel range, but new developments indicate with minor changes such as one
additional port call, major shipping route voyages could be completed with hydrogen as a fuel (ICCT, 2020).



Developing bunkering infrastructure for hydrogen at maritime ports.

4.1.5 Methanol
Methanol
GHG performance and production route emissions
Well-to-tank: Varies depending on production pathway (whether grey or green) Currently, methanol is mainly produced
from natural gas but can be produced from a number of different feedstock resources, these can be renewable such as
black liquor from pulp and paper mills, agricultural waste or forest thinning, or even directly from CO2 that is captured
from power plants (DNV GL, 2019). If electricity is provided by the grid is 100% renewable the CO 2 emissions of thisproduction pathway are zero.

Tank-to-wake: Emissions estimated 22.2g CO2eq/MJ (Winebrake, 2018) (Nyári, 2018)

Expected Well-to-wake GHG reduction potential: 0% for grey natural gas methanol production pathway, and 92% forgreen synthetic (renewable) methanol production pathway (Winebrake, 2018) (Nyári, 2018)

Production pathway availabilityConventional production: Natural gas and coal-based pathways are available now.



Biomass gasification: Methanol derived from biomass expected to be available from 2030 (IEA, 2020).



Flared and landfill gas production: Methanol flared gas and landfill gas will most likely not be available until 2030. Small
scale pilot projects such as the Primus Green Energy Methanol demonstration plant are underway. This process being issuitable for deployment with landfill and flared gas (Mazanec, 2016)). (Primus Green Energy, 2020)

Synthetic production: Commercially available now at limited scale – a renewable methanol plant (Carbon Recycling
International) in Iceland delivering industrial scale synthetic methanol since 2012, demonstrates feasibility. Significant
expansion would be required to meet maritime fuel demand.

Compatibility and technology.
Green (synthetic) methanol production and methanol vessel technology has been achieved.

Commercial deployment has been achieved but mostly for vessels carrying methanol and using methanol produced byconventional methanol production (from fossil fuels).



Dual methanol-HFO engines are already commercially available. Methanol can be used either in a two-stroke dieselcycle engine or a four-stroke, lean-burn Otto-cycle engine.



There are various example of newbuild vessels running on methanol: in 2020 Waterfront Shipping confirmed the
addition of eight newbuild methanol-fuelled tankers to its fleet. Retrofitting is also a possibility with RoPax, Stena
Germanica, vessel being the first vessel to be retrofitted to burn methanol (American Bureau of Shipping, 2019).

Infrastructure

Methanol has extensive established chemical industry infrastructure (Methanex, 2020). This is an advantage, as thisexisting infrastructure could be leveraged and extended for distribution to marine terminals and port (DNV GL, 2019).

In 2017 the first methanol infrastructure for shipping supply chain was successfully established in Germany.

While not used as a maritime fuel, ports are already experienced in dealing with methanol, with facilities available forloading/unloading and safety procedures developed to deal with the substance.



Limited/no bunkering infrastructure for methanol as a fuel in place. Simple modifications to current bunkering
infrastructure would be needed.

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Storage & handling

Low energy density: Methanol still requires 2.3 times more storage volume than conventional fuels for the same energy
content (Ash, 2019).

Safety regulations are required: Methanol has a low flashpoint, is flammable, has acute toxicity and causes specifictarget organ toxicity. Methanol is not covered by current IGF Code, although in September 2018, the IMO sub-committee
on carriage of cargos and containers indicated its intention to draft interim guidelines for ships using methanol or ethanol
fuels42. Understanding the characteristics and properties of low flashpoint methanol gas is key to minimise safety hazards
associated with its alternative use as a marine fuel.



Methanol vapour leaks: For the fuel supply system, consideration is also needed in terms of methanol leakage. Methanol
vapour is heavier than air and leaks can accumulate in the bilges or low sections of a space. Double-walled piping should
be installed and the use of nitrogen as inert gas in the fuel storage tank itself could also be an additional safety measure(Offshore Energy, 2018)

Supply and demand

As methanol is already produced for other industries, globally it has a high annual production, with over 80m t/y ofproduction in 2018.



Maritime sector used ~0.16 Mt methanol (HFO-equivalent Mt) as fuel in 2018 (International Maritime Organization, 2020)

Cost


Between 2017-2020 global methanol prices varied from $220 to $500 USD per tonne. The $220 minimum value wasduring the COVID-19 pandemic (MMSA , 2020).



The investment cost for a methanol plant varies from 200-1200 € /kW fuel.



Approximate additional costs for a newbuild and a retrofit methanol RoRo vessel with 24 MW main engine power and tankcapacity for 3 days of sailing (IMO, 2016):

Other environmental impacts


Methanol is readily dissolvable in water, which from an environmental perspective means it could lessen potential impacts
from spills (American Bureau of Shipping, 2019).

NOx emissions upon combustion require SCR or EGR systems to be used (DNV GL, 2019)

Although methanol is not as toxic as ammonia, it still presents health hazards to humans.

Remaining challenges
Scaling up of methanol production, in particular securing supply of green / blue methanol.

Ensuring adequate port bunkering infrastructure of methanol.

4.1.6 Biofuels (FAME and HVO)
Currently, biofuels are not widely used in shipping. In Europe, almost all biofuels are consumed in theroad transport sector (ECOFYS, 2019). Whilst their use in shipping and aviation is currently negligible,
several of the world’s largest container shipping companies are exploring or using biofuels, and this use
is growing. Examples include; Maersk’s 2019 pilot of a vessel sailing solely on a second–generation
biofuel blend that has yielded positive results (Maersk, 2019), MSC Group’s successful trials that werecompleted with a minimum 10% blend fuel that paved the way for the company to now use much higher(30%) blends (MSC, 2019), and Hapag Lloyd’s successful trial using “B20” fuel, which consists of 80
percent low-sulphur fuel oil and 20 percent biodiesel based on cooking oils and fats (Hapag-LLoyd,
2020)

42

https://www.imo.org/en/MediaCentre/MeetingSummaries/Pages/CCC-5-5th-session.aspx

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Two major biofuels used in biofuel blends include Fatty Acid Methyl Esters (FAME) and Hydrotreatedvegetable oils (HVO). Other examples of drop-in fuels are under development, such as alternative
conversion pathways based on similar biological feedstocks (such as hydrogenated palm oil (HPO) or
hydrothermal liquefaction of biomass) or synthetic fuels (e-fuels). These may provide alternative options
for drop-in fuels for the maritime sector in the future. For this report, FAME and HVO were selected as
biofuel examples based on their higher level of maturity.
FAME consists of esters of fatty acids. FAME is produced from vegetable oils, animal fats or waste
cooking oils by transesterification, and has properties similar to conventional diesel ( Swedish
Knowledge Centre for Renewable Transportation Fuels (F3), 2017). FAME is often referred to as
renewable biodiesel and depending on feedstock, could have GHG reduction potential when used as amarine fuel compared to HFO.
HVO is also known as hydrotreated esters and fatty acids (HEFA). HVO is a high-quality fuel in which
the oxygen has been removed using hydrogen, which results in long-term stability. HVO is free ofsulphur and aromatics and usually consists of vegetable oils or animal fats that have undergonehydroprocessing and refining, in the presence of a catalyst. HVO is considered as a fuel that can
substitute HFO and reduce GHG emissions and SOx (IEA Bioenergy, 2017).

FAME

HVO

GHG performance and production route emissions
Well-to-tank: Depend on feedstock and allocations(indirect and direct land use change) (as high as to111gCO2eq/MJ for rapeseed feedstock) (European
Commission, 2013)



Well-to-tank: Depend on feedstock and allocations(indirect and direct land use change) (as high as 112
gCO2eq/MJ for rapeseed feedstock) (European
Commission, 2013)



Well-to-wake: Estimated at 13.8g CO2eq/MJ (Verbeek,2015). Includes zero TTW emissions as they are offset
by the absorption from the atmosphere by the feedstock
crop.



Well-to-wake: Estimated at 8.1g CO2eq/MJ (Verbeek,2015). Includes zero TTW emissions as they are offset
by the absorption from the atmosphere by the feedstock
crop.



Expected Well-to-wake GHG reduction potential:
84% for waste cooking oil FAME production pathway(Verbeek, 2015) as pure (unblended) FAME.



Expected Well-to-wake GHG reduction potential:
91% for waste cooking oil HVO production pathway(Verbeek, 2015) as pure (unblended) HVO.

Hydroprocessing/Hydrotreatment: Production isalready at commercial scale. HVO can also be
produced in oil refineries, as they are already equippedwith hydrotreating facilities.

Transesterification: All HVO purification andtransesterification production pathways are available
now.

Production pathway availabilityTransesterification: FAME production is already at acommercial scale. All FAME feedstock production
pathways are available now.

Compatibility and technology


FAME in blends with conventional marine fuels such as
HFO has been proven as compatible in blends
containing up to 20% FAME.



Drop-in fuel and no upper limit for blend-in of HVO
according to the ISO 8217:2017 fuel standard, i.e. up to
100%.



Higher FAME blends have not yet been widely
deployed and their uptake towards 2050 is not foreseenHigher blends require engine modernisation,
maintenance adaptations and fuel system modifications(Moirangthem et al, 2016).

Despite engine compatibility, currently there is limited
commercial application of HVO in the shipping sector
and low bunkering availability.

Algal oils could be hydrotreated and would also function
as a non-sulphur ‘drop-in’ fuels. However, algae biofuel
companies are still in the technology development
phase.



Not an issue as drop-in fuel

Due to the hydrogenation process all of the oxygenfrom the feedstock is removed therefore HVO can be
stored for longer and there is less of a chance of fueloxidation (IEA Bioenergy, 2017).

Infrastructure

Not an issue as drop-in fuelStorage & handlingFew requirements: Low FAME blends should be able tobe stored and handled in the same storage andmachinery as that used for conventional marine
distillate fuels

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FAME

HVO



Short degradation time: can be negative for long-term
storage, due to producing corrosive hydrogen sulphidethan can corrode metal storage tanks. Fast degradationin water can reduce the environmental impacts of oil
spills (American Bureau of Shipping, 2019).



HVO has a higher fuel efficiency which is attributed toits almost zero oxygen content (Dimitriadis, 2018).

Potential oxidation - loss of lubrication which may causewear and require anti-static additives.



Production of HVO is currently concentrated in the US,
Singapore, the Netherlands and Finland with ~4.5
million tonnes (5.5 billion litres) of HVO produced in2017 (SEA LNG Ltd, 2019).



Currently, HVO fuel volumes required to support shortand long-distance maritime energy demand are notsufficient (SEA LNG Ltd, 2019).



The potential supply of sustainable renewable diesel(including both FAME and HVO) is estimated to be 1020 Mt per annum (IEA Bioenergy, 2017).



The 2020 price of HVO is ~ $1600/ tonne according tostakeholder inputs and average from S&P Global Platts.
Production process of HVO is typically more costly thanfor FAME.

Supply

The current FAME production could satisfy just under
60% of the energy needs of the maritime sector (DNV
GL, 2019). However, real FAME supply is likely to belower when factoring in direct and indirect land usechange as well as competition from other sectors



The potential supply of sustainable renewable diesel(including both FAME and HVO) is estimated to be 1020 Mt per annum (IEA Bioenergy, 2017).

Cost
The 2020 price of FAME per metric tonne has been
estimated at ~ $1180$ /tonne according to Neste dataand stakeholder inputs.

Other environmental impacts


FAME is not toxic.



HVO is not toxic.

The sulphur content of FAME is very lowNear zero sulphur content and hence emissions.



Exhaust gas treatment systems needed to control NOx
and PM.



Exhaust gas treatment systems needed to control NOx
and PM.



Indirect land use change impacts

Indirect land use change impacts

Availability of supply

Remaining challenges


Availability of supply

Biofuel competition with sectors such as aviation



Biofuel competition with sectors such as aviation

Difficulty in ensuring sustainability of feedstock

Difficulty in ensuring sustainability of feedstock

For both FAME and HVO, a significant issue is ensuring the sustainability of feedstocks. After factoring
direct land use change (LUC) and indirect land use change (ILUC), the supply of sustainably produced
FAME and HVO are likely to be lower than estimates in the literature. This is because a major challenge
is securing a sustainable feedstock supply, which is particularly pronounced given the global nature of
the shipping sector. Global shipping fuel consumption has been estimated at ~339 Mt/year according
to the Fourth IMO Greenhouse Gas Study (International Maritime Organization, 2014). However, thepotential supply of sustainable renewable diesel is estimated to be 10-20 Mt per annum, and thesecurrent renewable diesel type fuels are mainly produced from plant-based oils or products thereof, suchas used cooking oil (UCO) (IEA Bioenergy, 2017). Other biofuel technology such as algae-based third
generation fuels are not at a technological level that enables long term projections of their supply
potential. Further information on the sustainability of biomass supply for biofuel production is given in
the box below.

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Sustainable biomass supply
Global primary energy supply from biomass is currently around 53 exajoules (EJ) per year, reduced to around
25 EJ if traditional uses of biomass are excluded (Sustainable Ship Initiative, 2019), (International Energy
Agency, 2017). Biofuels used in road transport only account for around 3.6 EJ of this total, and for shipping thisvalue is far lower. The fuel production pathways of many of the fuels covered in this report (including FAME,
HVO, DME, Ammonia), have different levels of scalability towards 2050 depending on biomass availability.
How much sustainable biomass supply may become available by 2050?
A range of studies have estimated future biomass supply and many of these values depend on key assumptions
made. The table below highlights this variation and summarises total biomass availability of different feedstock
under different scenarios (Sustainable Ship Initiative, 2019). Nevertheless, despite this variation, there is a levelof agreement in the literature that about 50-100 EJ per year of bioenergy could be produced sustainably.
Total
availability(EJ /yr)

Energycrops

Municipal
solidwastesAgricultural
Residues

Forestry(including
residues)

UK CCC (2050)

14-84

4-57

-

3-12

7-15

IEA (2060)

131-240

60-100

10-15

46-95

15-30

70

Excluded

10

45

15

SourceEnergy Transition
Commission (2050)

Source: (Sustainable Ship Initiative, 2019)
Projected availability also varies by feedstock type (IEA Bioenergy, 2020):
Municipal wastes (MSW): global supplies are more limited than some other feedstock types.
Forestry (including residues): much larger supplies of wastes and residues from forestry andagriculture are expected in the coming years than currently available.

Agricultural residues: Much larger supplies of wastes and residues agriculture are expected
than currently available.
Energy crops: There is considerable scope for raw material supply from crops that can be coproduced with food crops or using contaminated or abandoned land43. However, ensuring
sustainability is a challenge and the crops must be produced on land in ways which do notthreaten food crop availability/security.
How would this meet the demands of the shipping sector?
Global shipping fuel consumption has been estimated at ~339 Mt/year according to the Fourth IMO Greenhouse
Gas Study (International Maritime Organization, 2014). One tonne of HFO contains ~42 GJ of energy, hence
the energy needs of the total shipping sector from recent years is ~14 EJ/year, which could increase to~19 EJ/year by 2050 according to the upper trajectory in the IMO 4th GHG study.
If 50 to 100 EJ of sustainable bio-feedstock becomes available, it is difficult to anticipate what proportions thiswill be demanded by different sectors. However, it is clear that the cumulative energy demands from othersectors aviation, road transport and construction will far exceed ~50-100 EJ. Although, in reality, this energy
demand may be lower if the road transport sector electrifies. Even if shipping’s demand remains below thereasonable supply range of 50-100EJ/year by 2050, meeting all sectors’ demands with the projected available
biomass will be extremely challenging (Sustainable Ship Initiative, 2019). The European Commission Joint
Research Centre also publishes estimates of European biomass availability through its ENSPRESO database(European Commission, Joint Research Centre, 2019), with an estimated 12.3EJ of biomass available acrossEurope in 2050.
Given the differing fuel quality requirements for different transport modes (at least based on current engine
technologies), with aviation requiring the highest fuel quality and maritime the lowest, with their associated cost
implications, there may be scope for differentiating the demand for feedstock and processing for the different
transport modes by quality and processing costs.
The SSI (2019) inquiry into the Sustainability and Availability of Biofuels for Shipping asked stakeholders theirviews. The majority agreed that 10-30% of shipping’s energy needs could be met by biofuels in 2030 to 2050
(those stakeholders with responses of over 50% represented outliers). The stakeholders also anticipated that
biofuel use would be higher in 2030 than 2050, implying this is a short rather than long-term solution. This isconsistent with the findings of this study, although the achievement of high levels of biofuel availability by 2030
will be highly dependent on the availability of feedstock and the development of commercial production facilities.

43

This list can be expanded to include unused, degraded, marginal and fallow land.

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4.1.7 Batteries
Batteries
GHG performance and production route emissions
The energy efficiency of electric propulsion systems can exceed 90%, compared to about 40% for conventional
propulsion with diesel engines (American Bureau of Shipping, 2019).



Zero tailpipe emissions (of e.g. CO2, NOx and SOx) of pure battery-electric vessels;
reduced tailpipe emissions of hybrid (battery and diesel) configurations.

Life cycle emissions of batteries accounts for energy intensive battery manufacture. CO2e emissions of battery RoRo
passenger vessel are estimated to be two thirds lower than an equivalent diesel vessel (Perčić, 2020).

Compatibility and technologyBattery powered vessels use electric motors, and may be used in diesel-electric propulsion, hybrid propulsion or allelectric battery drive systems. Examples of battery hybrid vessels: RoRo Stena Jutlandica.



Fully electric operation of vessels is currently only technically feasible for short-sea shipping / smaller vessel types thathave lower power demands. This limitation is likely to remain in the future: Stena announced in February 2021 a launchof battery electric Ro-Pax vessels by 2030 (60,000–70,000 kWh, 50nm range). With current and anticipated battery
technology the size and weight of batteries needed to supply the power demands of a trans-oceanic voyage would sinkthe vessel. For deep-sea shipping, increased uptake of hybrid systems or use of battery-electric for auxiliary power only
appears more likely.

TRL 9 with examples of fully electric (small) vessels: 70m Ro-Ro ferry ‘Ellen’ in Denmark (2019; 4300 kWh; 22 nm
range); 80m car ferry ‘Ampere’ in Norway (2015; 1,000kWh); 70m 120 TEU container vessel ‘Yara Birkeland’ (2020;
9,000 kWh; 30nm range).

InfrastructureShore power required to recharge ship batteries when in port. This is an additional demand beyond that consideredwhen designing the current shore power systems which are typically sized to replace the auxiliary engine supply.

Onshore power is now available at many ports. In 2020, around 58% of European ports offered onshore power supplies,
up from 53% in 2019, with 46% of those (i.e. 27% of all ports) offering high-voltage supplies (suitable for larger vessels)(ESPO, 2020). Given public pressure for cleaner air around ports, it is expected that the number of ports making
onshore power available will continue to grow, regardless of the adoption of electric-powered ships. Limited electrical
capacity and space at port to allow ships to fully charge could be an issue.

Storage & handlingThermal runaway remains the largest risk related to the use of lithium ion batteries, which can lead to fires and explosions(Ship Technology Global, 2018). In 2019, a fire on the car ferry MF Ytteroyningen highlighted the need for improved battery
fire safety in the industry (GCaptain, 2019). Whilst classification and standardisation societies help ensure the quality
control of systems, this remains a key safety issue.



Inadequate space for retrofitting existing ships with batteries and associated machinery for an electric propulsion system.
The additional weight and spatial arrangement of the battery system means ship stability will most likely need to berecalculated and adjusted, and the hull structure reconfigured.

Supply

Maritime demand for batteries currently represents <1% of global lithium-ion battery production.

However, one pure battery electric transoceanic ship would require battery capacity of about 15 GWh. For comparison,
this is approximately one third of the Tesla Gigafactory annual output; therefore the supply of battery capacity for significant
maritime industry take-up would impact significantly on global production.

Cost

Battery cost has previously been a large barrier to electric powered ships. For a trans-oceanic pure-battery ship, the costof the battery alone with present day technology could exceed the cost of the rest of ship.

With battery technology development, and with scale, battery prices are however decreasing rapidly due to demand fromthe automotive and consumer electronics sectors (American Bureau of Shipping, 2019): lithium ion batteries have halved
in price since 2016.



But, as well as the battery itself, large scale installations in ships also require battery control hardware and software,system integration, thermal management and power electronics. These costs are often significant with the system
integration cost of the battery system sometimes equivalent to the cost of the battery system itself (American Bureau of
Shipping, 2019).

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Batteries (continued)
Other environmental impacts


Require large quantities of mined material, which can have both environmental and human rights considerations.



Depleted lithium-ion cells can also cause environmental degradation if not correctly recycled.

Electrifying cargo ships could significantly accelerate this problem if the recycling industry is not ready to handle a rapid
increase in depleted lithium-ion cells, which entail several storage and handling challengesCurrent problems with end-of-life stage vessels being inappropriately dumped on Indian and Pakistani beaches (ashighlighted by the NGO Shipbreaking Platform) could be exacerbated by a switch from fossil-fuel engine based vessels
to lithium-ion battery powered vessels leading to potential exposure to toxic chemicals (NGO Shipbreaking Platform, 2020)

Remaining challenges
Reductions in battery size, weight, and cost.



Shore power systems to provide enough capacity to recharge as well as displace auxiliary engine hotel load.

4.1.8 Fuel cells
Fuel cells
GHG performance and production route emissions


Fuel cells offer the potential for zero tailpipe emission operation. This is because, if the fuel used is hydrogen, the only
products of fuel cell reactions are water, electricity and excess heat. However the emissions depend on the fuel used to
power the fuel cell. Using LNG or methanol will produce CO2 emissions unless a carbon capture system is installed.

Compatibility and technology
The fuel used to power fuel cells is usually hydrogen, but other fuels can be used (e.g. LNG, methanol and ammonia)(UMAS, 2016). To date, different fuel cell types with distinct characteristics have been developed, including:

Low and high temperature polymer electrolyte membrane fuel cell (LT/HT-PEMFC), also known as proton
exchange membrane.

Solid oxide fuel cell (SOFC)

Phosphoric acid fuel cell (PAFC)

Molten carbonate fuel cell (MCFC)

Fuel cells would likely need significant battery electric capability to operate successfully in a ship system, allowing for load
variation. Fuel cells also require their own storage systems and equipment. Corvus Energy and Toyota are set to startdevelopment and production of sustainable, large scale maritime-certified hydrogen fuel cell systems which will be located in
Norway. The development is expected to showcase its first marine fuel cell system onboard a vessel in 2023 with the productmarine certified and ready for commercial delivery from 2024 (Corvus Energy, 2021).
Storage & handlingMain fuel cell considerations:Complex support and control systems and unfamiliarity with handling procedures means adequate training and safety
precautions are needed when transitioning to using fuel cells.

Size and weight: The combined size and weight of fuel cells and their associated support systems and fuel storage (ofe.g. hydrogen, ammonia) is higher than that of an internal combustion engine.

Longevity of fuel cells: shorter lifetimes than diesel engines, particular in harsher marine environments. The exchange
of individual fuel cells within a fuel cell stack could help to alleviate this technological concern, but cost may still be anissue.

SupplyThe supply electrofuels requires transportation to site for fuel cell use as well as production and distribution. Current
bunkering stations and distributional networks are at different levels of maturity for some of these fuels. See respective
sections 4.1.1 (LNG), 4.1.4 (hydrogen), 4.1.3 (ammonia), and 4.1.5 (methanol). Scaling up of the fuel cells to the capacities
required for large vessels is a challenge.

Solid oxide fuel cells (necessary for using ammonia) are not yet commercially available (Ash, 2019).



Lack of access to bunkering facilities may also prove a challenge if journeys are in areas without adequate production anddistribution networks for the fuels powering the fuel cells.

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Fuel cells
Cost

Cost remains a key barrier to fuel cell use, and to date, fuel cell systems remain significantly more expensive than ICEs
(American Bureau of Shipping, 2019).

Other environmental impacts


Hydrogen fuel cells have zero emissions.



Ammonia used in low temperature fuel cells can also offer zero NOx emissions (Ash, 2019). However, if ammonia is used
in a SOFC which operates at higher temperatures, thermal NOx emissions may occur.

As with batteries, future disposal of fuel cells may cause environmental impacts in relation to ship recycling

Remaining challenges


Cost, robustness in a harsh marine environment and scaling up

4.2 Vessel design measures
The efficiency of new vessels has improved substantially since the 1980s, primarily driven by the costof fuel and freight rates (CE Delft, 2016). Nevertheless, there remain vessel design measures offering
further GHG reduction potential, through reducing vessel resistance and fuel consumption. The
measures are not only for optimisation at the design and build stage of new vessels, but some are also
applicable as retrofits to improve existing design.
The GHG reduction potential of each of these measures, as well as the associated costs of the measure
per vessel and their TRLs, are summarised in Table 4-3. These measures are mostly technologicallymature (TRL 9) and have already been widely implemented with high market penetration (confirmed bystakeholders). Stakeholder feedback highlighted that how much these additional measures will reduce
emissions will depend on existing vessel design (Naval architect).
In Table 4-3 (and the subsequent similar measures), the cost estimates are based on information related
to the application of the technology in 2020.

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Table 4-3: Summary of vessel design measures
Cost of measure(USD $) per
vesselVessel Design
MeasureBrief description

GHG reduction
potential (%)

Optimum ship
size dimensions

Large ships tend to be more fuel efficientas they have lower total hull resistance.

~9%Construction
weightLighter ships are more fuel efficient.

~9%

Hull dimensions(form
optimisation)

The shape and dimension of hulls impact
ship resistance. Computational fluid
dynamics modelling is used.

4 - 8%$150,000 to$500,000

9

Bulbous bow
retrofit

Initial ship design is sometimes optimised
for an operating profile different to theoperating profile of the vessel at sea.
Retrofitting a new bulbous bow may
enable fuel savings to be achieved withbespoke bow designs.

3% - 5%$100,000 withadditional material
cost of $250,000
to $700,000
depending on size

9

Bow thruster
tunneloptimisation

Bow thrusters are propulsion devices inthe bow or stern of a ship to makemanoeuvring easier without using themain propulsion mechanism. Improving
their design can reduce drag.

0.5% - 1%~ $10,000

9Hull coatings

Coatings prevent/reduce the build-up of
waste deposits and counteract organic
growth, reducing surface friction.

0.5 - 5%$30,000 to$500,000

9Trim tabs used to optimise trim arehorizontally installed at the end of thevessel. The interceptor reduces
resistance and controls the trim bychanging the interceptor height.

1 - 5%-

9/8

Lengthening the stern of a ship reduces
the resistance of the ship.

3 - 7%-

9

The pumping of compressed air into a
recess in the bottom of the ship’s hull.
The entrained air reduces frictional
resistance between the hull and thewater, reducing propulsion power
demand.

7%$130,000 to$3,380,000

7/8/9

By effectively loading cargo, vessel trim
and/or draft can be optimised to reducehull resistance. In order to effectively
optimise the trim and draft, additional
equipment is necessary such as a betterloading computer or a dedicated trim
optimiser.

0.5 - 3%

$15,000 to$75,000

9

An extension to ballast reduction is theballast free ship concept. Ballast freedesigns are based on multi-hull concepts
and make use of low-weight materials
such as composite thermoplastics andaluminium. Through the reduced weight
this leads to emissions savings.

~9%

Included in total
new-build cost

5/6/7

Interceptors

Ducktailwaterline
extension
Air lubrication

Ballast reduction
and trim
optimisation

Ballast freevessel design

Included in total
new-build cost

TRL

9
9

Sources : (Ciuffo, Giovine, Marra, & Miola, 2010) (International Maritime Organization, 2009) (GloMEEP IMO, 2015)

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4.3 Power assistance measures
Alternative power sources reduce GHG emissions by reducing main engine power demand. Table 4-4
summarises such power assistance technologies. Most alternative propulsion and power assistancetechnologies are not yet widely implemented (confirmed with stakeholders).
The wind power assistance measures require integration with weather / fleet / logistics and voyage
optimisation software, to maximise overall voyage fuel consumption reduction. Fuel savings that can beachieved from wind-assistance technologies depend on ship design, operating speed, and the windspeeds and directions experienced (Rehmatulla et al, 2017). In general, wind assistance measures canbe applied with slow steaming (International Transport Forum, 2018) because wind propulsion is mosteffective at slow speed.
Table 4-4: Summary of power assistance measures
Power
assistancetechnology

Brief description

GHG reduction
potential (%)

Cost of measure (USD$) for one vessel

TRL

Flettner rotors

Cylindrical rotors placed on thedeck are spun using an electricmotor to capitalise of the Magnus
effect.

10-30%$1,000,000 - $3,000,000(for typical delivery withmultiple rotor sails, a
single rotor is $400,000
to $950,000)

9

Towing kites

Dynamic kites installed on a ship’s
bow to make use of higher-altitude
winds.

1-5%$280,000 -$2,590,000*(installation cost)

7/8/9

Sails

Fixed installations in the form of aflexible sail, rigid sail or turbosail.

6%$300,000-$1,000,000(installation and mast)

9

Solar panels

Use of conventional solar panels
on top deck roofs to replace someof the power generated by auxiliary
engines.

1.25% (of auxiliary
engine fuelconsumption**)~$1,400,000

9Shore power
supplyShoreside electrical power isprovided to a ship whilst it is atberth, so allowing the ship to turnits auxiliary engines off.

50-100%*$50,000 - $750,000***

8/9*this reduction is in port only and refers to the reduction of the electrical motors on board**although overall GHG reduction in practice may be less ( ~0.1%).
***this cost excludes the costs for ports of fitting the connection and power provision

Sources: (Ciuffo, Giovine, Marra, & Miola, 2010) (International Maritime Organization, 2009) (GloMEEP IMO, 2015)

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4.4 Alternative propulsion measures
Several propulsion technologies are currently available on the shipping market. Fixed pitch propellers
are currently the most common type and occupy the greatest proportion of the shipping fleet (Royal
Academy of Engineering, 2013) (Westshore Marine & Leisure, 2020). However, harnessing alternative
propulsion technologies such as Large Area propellers (LAPs), contra-rotating propellers (CRP) and
podded thrusters could lead to energy efficiency improvements and GHG emissions reductions.
Propulsion improving devices (PIDs) are devices that can help improve vessel hydrodynamics. Much of
their effectiveness hinges on original ship design, hull geometry and the operational profile of the vessel.
If the existing vessel design has been optimised, the additional savings from these measures are most
likely lower than the values reported. Further, applying multiple technologies together (where feasible)
may not deliver the total improvement obtained by adding those for the different technologies. The GHG
reduction potential, costs and the TRL of these measures are summarised in Table 4-5. Propeller design
measures are widely applicable to different vessel types and are already widely implemented (confirmedwith stakeholders).
Table 4-5 Summary of alternative propulsion technologies and adaptions measures
Propulsion
technology /adaptations

Brief Description

GHG
reduction
potential(%)

Cost of measure(USD $) for one
vesselTRL

2-5%$630,000-$2,690,000

9Large area
propellers (LAP)

Concept involves moving the propeller
towards the stern behind the hull to allow
larger propeller diameters to be used.

Contra rotating
propellers (CRP)

CRP technology improves fuel efficiency
because the aft propeller recovers energy
loss from the rotational flow behind the fore
propeller.

Podded thrusters(PID)

This propulsion device is external to theship’s hull and houses a propeller powering
capability.

Up to 15%

$2,000,000 $3,000,000

9Propellor Ducts(PID)

Propellor ducts (also known as Kort nozzles)
consist of an annular duct that surrounds thepropeller (which operates inside the duct).
By fitting the propeller with a non-rotating
nozzle, the efficiency of the propeller isimproved.

0.5-5%$525,000 – $575,0009Pre-swirl (PID)

There are often substantial rotationalenergy losses in the propeller slip stream.
Pre-swirl PIDS are mounted on the stern
boss in front of the propeller. Pre-swirl
PIDS optimise flow into the propeller andprevent power losses.

Up to 10%$250,000 – $300,000

9

Post-swirl fins andrudder bulbs (PID)

Post-swirl fins and rudder bulbs canrecover some of the associated flow energy
losses through customised design of the
propulsion and steering system.

0.5-2%$100,000 – $150,000(Boss cap fin)
$250,000 – $300,000(Costa bulb)

9

Sources (GloMEEP IMO, 2015) (Wärtsilä , 2017) (Ciuffo, Giovine, Marra, & Miola, 2010) (ThordonBearings, 2016)

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4.5 Engine and aftertreatment technologies
The vast majority of the global maritime fleet is currently powered by diesel cycle engines, either twostroke or four-stoke cycles, running on heavy fuel oil (HFO) (from 2020 usually a very-low sulphur variant
to comply with the IMO 2020 regulation) or a distillate fuel such as marine diesel oil (MDO). The literature
survey performed for this study identified a number of “new” technologies with the potential to improvethe efficiency of the engines, or the overall energy use of the vessel (Table 4-6). However, discussions
with industry stakeholders indicated that the technologies were all already implemented in engines whenappropriate (with some contributing to reductions in other pollutants, such as NOx, more than CO 2).
Marine engine manufacturers indicated that most future reductions in emissions from engines are likely
to be achieved through the use of alternative fuels. The engine manufacturers are now putting significant
efforts into developing engines compatible with alternative fuels such as hydrogen and ammonia (theengines for these fuels are not included in Table 4-6 as the emissions reductions are achieved throughthe characteristics of the fuel rather than improved efficiency). Other developments are also underway
to address the issue of methane slip from LNG-fuelled engines, including exhaust gas recycling systems
and exhaust aftertreatments.
Table 4-6: Summary of engine technologies

Brief description

GHG reduction
potential (%)

Cost ofmeasure(USD $) for
one vessel

TRL

Enhanced fuelinjection system

Changes to fuel injector design andcontrol parameters (e.g. pressure, timing)
to improve mixing of fuel with air; assistsin controlling pollutant emissions

-

-

9

Hybrid dieselelectricEngine configuration in which the diesel
engine drives a generator to produce
electricity. Vessel propulsion is thenachieved by electric motors driving
multiple propellers. Can assist in
improving flexibility for particular
categories of ships (e.g. ferries), but
generally less efficient than direct-drive
systems on key vessel categories(tankers, bulk carriers, container ships)
due to multiple energy conversion
processes.

-

-

9

Early intake valve
closing

Also known as Miller cycle engines. Early
closure of the cylinder intake valve
reduces the pumping work required tocompress the air in the cylinder, but thenormal opening of the exhaust valve
allows the full power stroke to be retained.
High-pressure turbocharging is used torecover the full engine power output.

-

-

9

Waste heatrecovery (WHR)

Extraction of energy (as heat, or electricity
through steam turbine or turbo-generator
systems) to reduce the use of on-board
auxiliary power systems during voyages(and hence their additional emissions).
Some waste heat is already used foronboard heading to heat the fuel and theamount of waste heat available reduces
significantly at the lower power settings
used for slow steaming.

3% - 8%$5,000,000
to$9,500,000

9Propulsion design /technology

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4.6 Carbon capture (CC)
Carbon capture (CC), defined as the collection, transportation and eventual storage or recycling, ofcarbon dioxide emissions, has been seen as a way to reduce emissions from existing CO 2-creatingprocesses. While most discussions revolve around land-based and stationary CC solutions (a field
where there are already many commercial applications and many more under study), more recently
there has been a discussion on the potential of onboard CC as a way to reduce emissions in shipping.
Onboard CC has potential to help the maritime industry meets its CO 2 reduction targets, but the concept
is not well developed enough at this point to be of practical use in the short term. Although several
theoretical technological concepts and estimated costs have been put forward, as far as we are aware,
only one effort is planning to move to the prototype stage (the HyMethShip project44). Another project(from PMW Technology and Houlder (Willson, et al., 2019)) will test the possibility of applying cryogenic
CC in the maritime sector. Furthermore, onboard CC has many challenges associated with it. These
include the capital and operational costs, space and energy requirements (increases in fuelconsumption of up to 20% can be expected) and the effectiveness in capturing CO2 (can potentiallyreach 100% but this is untested; 80% is a more realistic expectation).
Table 4-7: Summary of carbon capture emissions reduction and costTechnology

Brief description

GHG reduction potential (%)

Cost of measure(USD $) for one
vesselTRL

Carboncapture (CC)

Onboard collection of CO2
emissions resulting from the
combustion of carboncontaining fuels

80% carbon capture
potential. May be
accompanied by up to 20%
increase in fuel consumption.

Up to $27,000,000
for an average ship
size

5-6

In addition to the feasibility of implementing carbon capture systems on board vessels, the adoption ofthis technology will also depend on the availability of handling facilities in ports and subsequent storage
or use options. Projects are now underway to establish facilities for receiving, and transporting to longterm storage, captured CO2. These include the Northern Lights 45 project, in which the first phase aims
to build a facility with a capacity of 1.5 million tonnes CO 2 per year by mid-2024. In the Netherlands, theproject Porthos, based at the port of Rotterdam, also plans to build a facility with a capacity of 2 to 2.5
million tonnes CO2 per year. Although these projects are not specifically targeted at CO 2 captured onboard vessels, they are indicative of progress being made towards a capability for receiving captured
CO2 at ports and for the subsequent long-term storage of that CO2.
Expert opinion from Ricardo is that some additional time will be required to build up the complete
infrastructure to allow vessels equipped with on-board CC to routinely off-load their captured CO2;
regulations similar to the EU Alternative Fuels Infrastructure Directive 46 (AFID) may be required toensure a sufficient network of facilities. Even if the on-board technology is technically feasible inadvance, initial implementations of the complete system are unlikely before 2030.
There is currently very little information on the potential costs, capital and operational, of facilities forreceiving and transporting captured CO2. A study47 for the UK Department for Business, Energy andIndustrial Strategy (BEIS), identified amortised costs of £10 ($14) per tonne CO 2 if transported by shipand £21 ($29) per tonne CO2 if transported by pipeline. Averaging these two values gives a cost of$21.62 per tonne CO2.

44

Project website availabe at https://www.hymethship.com/

45

https://northernlightsccs.com/

46

https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32014L0094&from=EN

47

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/761762/BEIS_Shipping_CO2.pdf

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4.7 Voyage optimisation
New voyage optimisation and operational measures as well as existing measures such as slowsteaming offer GHG reduction potential. The GHG reduction potential, costs and the TRL of thesemeasures are summarised in Table 4-8.
Table 4-8: Summary of vessel operational measures
Propulsion design /technology
Speed reduction(10%)
Speed reduction(20%)
Speed reduction(30%)
Advanced port
logistics

Brief description

GHG reduction
potential (%)

Speed reduction or ‘slow
steaming’ is an operational
practice that reduces fuelconsumption (and hence costs
and emissions).48

10-15%
18-28%
24-38%

Cost of measure ($)
for one vessel
No investment
costs, but may
impact the total
revenue due tolonger sailing time.

TRL

9
9
9

Through flexible planning,
improved collaboration, realtime data exchange anddigitalised cargo flows, asmoother ship-port interface
can result in a significant
reduction in the time ships
spend waiting.

Up to 1%-

8/9

Optimisation ofvessel capacity
utilisation

This measure is based on theability to counterbalance supply
and demand. Optimising
capacity utilisation reduces thecost per transported unit andsave emissions per tonne-mile.

0-30%

-

8/9

Advanced
autopilots

Minimises movements from therudder, which otherwise
creates additional drag to thehull and consequently
increases ship resistance.

0.25-1.5%

No cost of
implementation
assuming that
autopilot is alreadyinstalled.

9

Weather routing and voyageplanning minimise exposure tounsheltered water.

0-5%$25,000

9

Up to 6%

Due to low TRL,
reliable data on
capital costs per
vessel are lacking.

5/6/7

Weather routing

Autonomous
shipping

Rapidly advancing technology
is making crewless operations
increasingly possible.

The “baseline” speed against which the improvement from slow steaming is measured varies with vessel design (and when it was built) Recent
vessels are designed for a lower design speed, so increase the benefit further. As a general rule (and for the derivation of the GHG reduction
potential), the measure is interpreted as being relative to vessel speeds for vessels built prior to about 2010.
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Propulsion design /technology

Brief description

GHG reduction
potential (%)

Cost of measure ($)
for one vessel

Power demand
management e.g.
lighting

Each piece of equipment andmachinery on board consumes
energy and can individually beassessed to optimise theenergy efficiency and possibly
be replaced with higher
efficiency models.

0.25-5%$100,000*
compared to
traditional lighting
installations

9

Engine efficiency
measurements

Main engine efficiency
measurement enables
improved power managementof the engine(s).

Up to 5%

$20,000 to $75,000

9Hull cleaning

Thorough cleaning of thevessel’s hull on a regular basis
can improve the surface finish,
reducing resistance andimproving fuel efficiency.

1-5%$5,000 to $50,000

9Cleaning and polishing thepropeller regularly can improve
the surface finish and, hence,the propeller efficiency.

3-4%$4,000 to $8,000

9Propeller cleaning
polishing

TRL* Refers to the additional cost of $100,000 (USD) compared to traditional lighting installations on normal ships and $200,000 to$1,000,000 (USD) on passenger and cruise ships. Sources: (Ciuffo, Giovine, Marra, & Miola, 2010) (International Maritime
Organization, 2009) (GloMEEP IMO, 2015) (Seatrade-Maritime, 2018) (MDPI, 2018) (Smith, et al., 2019).

4.8 Fuel quality
The global shift of the maritime sector to using higher quality low-sulphur fuels, reduces SOx, PM andblack carbon emissions. However, the CO2 reduction potential from the switch in fuel quality is limited,
when considering life cycle emissions. This may even cause a marginal increase in overall CO 2
emissions.
The global shift of the maritime sector to using higher quality low-sulphur fuels, will have marginal or
positive impacts on lube oil and consequently engine efficiency, with the exception of biofuels. Switching
to biofuels may create engine-related challenges around lube oil. In diesel engines running onconventional fuels, one of the functions of the lube oil is to neutralise SOx produced when marine fueloil burns. Without neutralisation these oxides are corrosive to engine piston liners, which can have anegative impact on engine performance and efficiency. However, a small amount of acidic oxides canbe beneficial in cleaning the piston and liner surfaces, improving the adherence of the lube oil to thesurface. A complete absence of the acid, resulting from a sulphur-free fuel (such as biofuels) can leadto polishing of the surfaces resulting in the breakdown of the lubricating oil film (SwedishClub, 2015).
The engine efficiency improvements from the other fuels have not been quantified, and most likely do
not correspond to the scale of CO2 emission reductions needed to play a significant role in reaching the
IMO ambition.

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5 Fuel and technology packages
Key points:

Three possible future ‘packages’ of fuels, technologies and operational measures are defined.
Fuel pathways are stipulated. Selections are made based on the potential, applicability andavailability of the technologies and fuels, together with views on likely uptake from stakeholders.



Package 1 ‘early pursuit of zero carbon fuels’





o

Ammonia (deep-sea shipping) and hydrogen (short-sea shipping49) for some new build
vessels from 2025, ramping up to all new-build ships by 2035. Transitioning from grey toblue to green fuels over 2025-2035 period.

oMedium take up of energy efficiency technologies and operational measures. A 10%
speed reduction is assumed for slow steaming. No onboard CCS.

Package 2 ‘moderate uptake of interim and drop-in fuels’oFrom 2025, HFO and MDO use is assumed to be increasingly substituted with drop-in
biofuels (FAME, HVO). LNG transitions to bio methane (BioLNG) from 2030 onwards.

oMedium take up of energy efficiency technologies and operational measures. A 20%
speed reduction is assumed for slow steaming. No onboard CCS.

Package 3 ‘initial maximisation of vessel decarbonisation measures’oFocuses on maximising technology use with a later transition to alternative fuels.

oHigh take up of energy efficiency technologies and operational measures. A 30% speed
reduction is assumed for slow steaming. Onboard CCS applied to 50% of new ships(using carbon-containing fuels) post-2030, ramping up to 100% of new ships post 2040

oAmmonia and methanol for some new build vessels from 2025, ramping up to 50% newbuild ships by 2035. Transitioning from grey to blue to green fuels over 2025-2035 period.
Increased use of LNG, then transitioning to BioLNG from 2030 onwards, reaching 50%
of new build ships by 2050.

Section 4 described the vessel and engine technologies, operational improvements and alternative fuelsthat could contribute to decarbonising the shipping sector. The GHG abatement efficiencies and costs
shown in that section were at the vessel level. To move forward to assess the aggregate impact oftechnologies and fuels at the fleet level, and thus estimate the sectoral GHG emission reductions in thecontext of meeting the IMO’s ambition, section 5 considers three possible future ‘packages’ oftechnologies and fuels.
This section first provides a decision process for selecting fuels and technologies for the packages(section 5.1) and then describes the three packages in section 5.2.
As has been noted in the preceding sections, many of the vessel and engine technologies are alreadyin widespread use, although there is the potential for increased use, or more complete exploitation of
the potential, for some. The main options for achieving the 2050 ambition of the IMO, therefore, dependon the adoption of alternative fuels in the future.

The European Commission defines short-sea shipping as “the maritime transport of goods over relatively short distances, as opposed to theintercontinental cross-ocean deep sea shipping” (https://ec.europa.eu/eurostat/statistics-explained/index.php/Glossary:Short_sea_shipping_(SSS)). For the current study the term is used to distinguish smaller vessels with shorter ranges from the large vessels with transoceanic capability.
For the vessel categories analysed in this study, divided into small, medium and large sub-categories, this generally means the small sub-category.
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5.1 Selection of fuels and technologies for the packages
5.1.1 Fuel selection
Fuel pathways were selected based on stakeholder feedback, GHG reduction potential and the need toreach the IMO 2050 GHG reduction ambition, cost-effectiveness, and with the intention to reflect
different plausible pathways to decarbonisation. For this reason, not only green production pathways
but grey and blue production pathways were included in the selection for hydrogen and ammonia. The
final candidate fuels selected for the packages are summarised in Table 5-1. The emissions data
included in the table have been derived as averages of multiple references (where available) and, assuch, represent those for an average engine. In practice, the emissions (for engines using carboncontaining fuels) will vary depending on the engine cycle and design.
The emissions values for several of the fuels, particularly the blue and green versions, are from a
Ricardo analysis using lifecycle analyses of the production pathways, including the embedded
emissions in the renewable electricity generation plant (if appropriate). As these pathways are expected
to improve over time, the well-to-wake (WTW) emissions values also reduce. Therefore, Table 5-1
includes estimated WTW emissions for both 2020 and 2050 (values for fuels not calculated in thismanner are assumed to remain constant).
Table 5-1 Final candidate fuel pathways selected for packages

Fuel

Production pathway

Well-to-Wake (WTW) emissions(g CO2eq/MJ)
2020

2050

Reference pathway

87.2

87.2

Grey

Steam reforming from natural
gas

98.5

90.1

Blue

Natural gas and CCS*

21.5

19.2

Green

Renewable electrolysis

22.2

7.7

Grey

Natural gas

98.9

98.9

Blue

Natural gas and CCS*

20.9

20.9

Green

Renewable electrolysis

22.2

7.7

Grey

Natural gas

98.1

98.1

Green

Synthetic (renewable)

22.2

7.2

LNG

Global average

83.8

83.8

BioLNG

Average of liquid manure**,municipal organic waste,
sewage sludge and maize

24.6

27.5

FAME

Waste cooking oil

23.2

23.2

HVO

Waste cooking oil

20.4

20.4

HFO

HydrogenAmmonia

Methanol*Assumes production pathway with carbon capture and storage with 90% carbon capture efficiency**Pathway includes positive effect of preventing methane emissions by storage and use of biogas instead of releasing to theatmosphere. Basic calculations and conversions have been completed by Ricardo Plc for comparability. Sources: HFO ( Lindstad
and Rialland, 2020), Grey hydrogen (Ricardo, 2019), Grey ammonia (DECHEMA, 2017), Grey methanol (Winebrake, 2018)(Nyári, 2018), LNG (Thinkstep, 2019) , BioLNG, FAME and HVO (Verbeek, 2015) and (JRC, EUCAR and Concawe, 2020). Blue
hydrogen/ammonia and Green hydrogen/methanol/ammonia (Ricardo calculations based on lifecycle analysis of production
pathways)..

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5.1.2 Technology selection
In order to differentiate between the technologies and operational measures, a decision matrix wasdeveloped. The matrix includes three main equally weighted criteria:
1. Readiness Level:
This is based on the TRL of the technologies/ measures, as determined from literature and fromconsultation with stakeholders as to whether the technologies are already widely implemented. The
majority of the design measures were confirmed as widely applicable to different vessel types andalready widely implemented, with the exception of air lubrication and interceptors. Similarly, propeller
design measures were also confirmed as already widely implemented, and, in general, ship design isalready optimised to have the largest propeller diameter possible. Whilst the power assistancemeasures are not already widely implemented, the technology has been piloted. Engine aftertreatment
technologies were also found to be widely implemented. Onboard carbon capture remains theoreticalwith a lack of practical application. The ratings were applied as follows:

A rating of 0 refers to measures that should already be included in the baseline or a lack of dataA rating of 1 refers to measures with TRL less than 5A rating of 2 refers to TRL of 5/6/7



A rating of 3 refers to TRL of 8/9

2. Likely adoption rate:
This is based on the expectation of the use of the technology/measure and interest expressed bystakeholders.


A rating of 0 refers to technologies already included in the baseline or a lack of dataA rating of 1 refers to low likely adoption and stakeholder interestA rating of 2 refers to moderate likelihood of adoption and stakeholder interestA rating of 3 refers to high likely adoption rate.

3. Cost-effectiveness:
This is based on cost-effectiveness ($/ tonne CO2 abated) calculated with the savings in CO2 emissions
over the lifetime of the vessel (assumption: 30 years) divided by the cost of implementing the technology
on the vessel. These have been calculated assuming an average annual tonne-miles delivered andenergy consumption values derived from analysis of the 2018 EU MRV data. The “average ship size”
that these values correspond to is approximately 60,000 DWT. The ratings are applied as follows:

A rating of 0 shows a lack of dataA rating of 1 if cost-effectiveness estimated to be more than $50/tonne CO2,

A rating of 2 if cost-effectiveness estimated to be between $10/tonne CO2 and $50/tonne CO2,

A rating of 3 if cost-effectiveness estimated to be less than $10/tonne CO2 or negative.

The selection of each technology and operational measure into each package is based on the combined
criteria scores. Technologies that had a decision matrix score total of under 5 were not included in any
packages. Technologies that are considered to be widely implemented already, but with little continued
used, are not included in the technology/fuel packages as they considered to be current technology.
These are assumed as included in the new build ships in the baseline analysis.
The results of the decision matrix are in Table 5-2; for a more detailed breakdown of the raw values andcriteria scores assigned to inform fuel and technology package development, see Appendix 8 (A.8).

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Table 5-2 Maritime decarbonisation technology and operational measure decision matrix.
Criteria
Costeffectiveness

Optimum ship size dimensions

3

3

0

6

Construction weight

3

3

0

6

Hull dimensions (form optimisation)

3

3

3

9

Bulbous bow retrofit

3

2

3

8

Bow thruster tunnel optimisation

3

2

3

8

Hull coatings

3

2

3

8

Interceptors

3

0

3

6

Ducktail waterline extension

3

1

0

4

Air lubrication

3

1

2

6

Ballast reduction and trim optimisation

3

3

3

9

Flettner rotors

3

2

2

7

Towing kites

2

1

2

5

Sails

3

1

3

7

Solar panels

3

2

1

6

Shore power supply

3

2

0

5

Large area propellers (LAP)

3

2

3

8

Contra rotating propellers (CRP)

3

1

2

6

Podded thrusters

3

2

2

7

Ducts (PID)

3

2

2

7

Pre-swirl (PID)

3

2

3

8

Post-swirl fins and rudder bulbs (PID)

3

2

2

7

Fuel injection valve improvements (slide valves)

3

0

0

3

Common rail fuel injection

3

0

0

3

Water in Fuel Emulsion (WiFE)/Water Injection

3

0

0

3

Hybrid diesel-electric

3

0

0

3

Early Intake Valve Closing (Miller cycle)

3

0

0

3

Waste heat recovery (WHR)

Engine / aftertreatment

Vessel design measures

Likelyadoption rate

Power assistance

Final
Score

Readiness
level

Propulsion devices

Technology/Measure

2

1

6

2

1

2

5

Speed reduction

3

3

3

9

Advanced port logistics

3

2

3

8

Optimisation of vessel capacity utilisation

3

2

3

8

Advanced autopilots

3

2

3

8

Voyage planning and weather routing

3

3

3

9

Autonomous shipping

2

1

3

6

Power demand management e.g. lighting

3

3

3

9

Engine efficiency measurements

3

3

3

9

Hull cleaning

3

3

3

9

Propeller cleaning and polishing

3

3

3

9

Vessel operational measures

3

Carbon capture & storage (CCS)

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5.1.3 Cost-effectiveness ranking
Figure 5-1 to Figure 5-6 show the cost-effectiveness of the different fuels and technologies, as used in
the derivation of the cost-effectiveness ratings in Table 5-2. These cost-effectiveness values have all
been derived for an average ship size, using assumptions for the vessel lifetime and the tonne-milesdelivered per year. For the vessel and operational technologies, the values derived in this way include
the changes to the vessel capital costs, but do not include the reductions in lifetime fuel costs (as fuelcost savings have the potential to swamp the implementation costs). An exception to this is for the
onboard carbon capture and storage (CCS) technology under the engine technologies in Figure 5-4. In
this case, the implementation of the technology also results in an increase in fuel consumption (andhence fuel costs) because of the demands of the CCS system. Therefore, the cost-effectiveness isshown both excluding and including the additional fuel costs. For the alternative fuels, the assessment
was based on the increased price and CO 2 savings per unit of fuel. As for the results shown in Figure
4-3, this analysis used the fuel price projections for 2030.
The cost-effectiveness values presented in the following charts are shown in order of increasing costeffectiveness value (i.e. increasing cost to achieve the same reductions in emissions) to assist in theidentification of the “better” and “less good” options. As shown in Table 5-2, however, this is not the only
criterion used in the selection of the technologies to include in the packages. The ducktail waterline
extension technology is not included in Figure 5-1 as no cost data were identified and it is applicable
only to a limited range of vessels (RoRo ships and ferries). The “optimum ship size and hull dimensions”
and “construction weight” technologies are both shown as having zero cost per tonne CO 2. These twotechnologies were identified as being widely applicable and are already widely employed in vessel
design, so they were considered as being able to be implemented at low cost compared to the othertechnologies.
Figure 5-1: Cost-effectiveness ranking for vessel design measures

Cost per tonne CO2 saved for vessel technologies$20.0

Cost effectiveness ($ per tonne CO2 saved)

$18.0
$16.0
$14.0
$12.0
$10.0
$8.0
$6.0

$4.0
$2.0
$0.0
Optimum ship
size and hulldimensions

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Construction
weightBow thruster Ballast reduction
tunneland trim
optimisation
optimisationForm
optimisation

Hull coatings

Bulbous bow(retrofit)

Air lubrication

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Figure 5-2: Cost-effectiveness ranking for power assistance measures

Cost per tonne CO2 saved for power assistance technologies$80.0

Cost effectiveness ($ per tonne CO2 saved)

$70.0

$60.0

$50.0

$40.0

$30.0

$20.0

$10.0

$0.0
Sails

Flettner rotors

Towing kites

Solar power

Figure 5-3: Cost-effectiveness ranking for propulsion technologies

Cost per tonne CO2 saved for propulsion technologies$35.0

Cost effectiveness ($ per tonne CO2 saved)

$30.0

$25.0

$20.0

$15.0

$10.0

$5.0

$0.0
Pre-swirl

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Large area propellers(LAPs)

Ducted propellers

Post-swirl

Podded thrusters

Contra-rotating
propellers (CRPs)

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Figure 5-4: Cost-effectiveness ranking for engine technologies

Cost per tonne CO2 saved for engine technologies$90.0

Cost effectiveness ($ per tonne CO2 saved)

$80.0

$70.0

$60.0

$50.0

$40.0

$30.0

$20.0

$10.0

$0.0
Carbon capture & storage (CCS)CCS including additional fuel costs

Waste heat recovery (WHR)

Figure 5-5: Cost-effectiveness ranking for voyage optimisation measures

Cost per tonne CO2 saved for voyage optimisation$3.0

Cost effectiveness ($ per tonne CO2 saved)

$2.5

$2.0

$1.5

$1.0

$0.5

$0.0
Propeller cleaning andpolishingRicardo Confidential

Hull cleaning

Voyage planning andweather routing

Energy efficiency
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Figure 5-6: Cost-effectiveness ranking for alternative fuels

Cost per tonne CO2 saved for alternative fuels
LNG

BioLNGBlue
AmmoniaBlue
HydrogenGreen
Ammonia

FAME

Green
Hydrogen

HVO

Green
Methanol$600.0

Cost effectiveness ($ per tonne CO2 saved)$500.0$400.0$300.0$200.0$100.0$0.0-$100.0-$200.0

5.2 Package definition
Three packages of technologies and fuels have been defined for analysis. These packages are driven
by the potential contributions of technologies (also including operational measures) and alternative fuels
to deliver the decarbonisation of the sector. A summary of the three packages is shown in Figure 5-7.
Figure 5-7 Overview of three technology/fuel packages developed for analysis

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5.2.1 Package 1 – Early pursuit of zero-carbon fuels
The package is characterised by an early pursuit of carbon-free alternative fuels (hydrogen andammonia). This package reflects the view expressed by some stakeholders that the adoption of interim
alternative fuels such as LNG would be a diversion from the focus on achieving the comprehensive
decarbonisation of the industry as soon as possible.
This package focuses on the highest scoring decarbonisation measures. It includes vessel design
measures with the highest decision matrix scores (8/9) and power assistance measures with highest
scores (7). It assumes 50% Flettner rotor implementation and 50% sail implementation post 2025. This
package also includes the highest scoring propulsion devices (8) which consist of large area propellers
and pre-swirl devices. Although, post-swirl fins and rudder bulbs also scored 8, these were not included
as they are more expensive than the other PIDs. WHR is included. The highest scoring operational
measures are included (9), and a 10% speed reduction is assumed for slow steaming.
Given the focus of this package is on the early pursuit of low carbon green fuels to reduce GHG
emissions, onboard CCS is not included in this package.
The key parameters and timeframes corresponding to package 1 for the modelling are shown in Figure
5-8.
The application of the different vessel technologies included in the modelling of this package are shownin Table 5-3. The package also includes assumptions around the production pathways used forhydrogen and ammonia. These are summarised in Table 5-4.
Figure 5-8 Overview of timeline and components of Package 1.

*Note: Ammonia and hydrogen first transition using the grey production pathways in 2025, followed by blue (CCS) and finallygreen pathways from 2035 onwards. **Bulbous bow retrofit is only in Ro-Ros, ferries and containers

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Yes

Yes

Yes

Yes

Yes

General cargovessels

Yes

Yes

Yes

Yes

Yes

Yes

Yes

LNG carriers

Yes

Yes

Yes

Yes

Yes

Yes

Yes

LPG carriers

Yes

Yes

Yes

Yes

Yes

Yes

Yes

RoRo vessels

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Cruise ships

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Pre-swirl

Post-swirl

Largevessels
only

Large
vessels
only

Large
vessels
only

Large
vessels
only

Large
vessels
only

Large
vessels
only

Yes

Yes

Table 5-4 Fuel specifications for the modelling of Package 1
FuelApplicability

Additional specification for the modelling

Ammonia from-2025 build year

Deep sea shipping

Assumed to use three pathways; grey ammonia
followed by blue ammonia then transitioning togreen ammonia

Hydrogen from-2025 build year

Short sea shipping

Assumed to use three pathways; grey hydrogentransitioning to blue hydrogen, then transitioning togreen hydrogen by 2050.

Battery from-2025 build year

Coastal shipping

Assumed to use 100% renewable electricity by
2050.

Overall the assumed timeline of implementation for the fuels for package 1 is as follows:

2020 - Assumes 72% HFO, 28% MDO for all ship categories except LNG carriers (100%
LNG).



2025 - Assumes grey hydrogen and grey ammonia in use (2025-2030)



2030 - Assumes grey hydrogen and grey ammonia start to transition out, (2030-2035), bluehydrogen and blue ammonia transition in (2030-2035)



2035 – Assumes blue hydrogen and blue ammonia start to transition out (2035-2040), greenhydrogen and green ammonia transition in (2035-2050).



2050 – Assumes by 2050, 100% green hydrogen and 100% green ammonia use

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Waste heat recovery (WHR)

Yes

Yes

Carbon capture & storage (CCS)YesContainer vessels

Yes

Contra-rotating propellers (CRPs)

Bulk carriers

Yes

Large area propellers (LAPs)

Yes

Sails

Yes

Flettner rotors

Hull coatings

Yes

Construction weight

Bow thruster tunnel optimisation

Yes

Ducktail waterline extension

Ballast reduction and trim optimisation

Tankers

Interceptors

Form optimisation

Optimum ship size and hull dimensions

Table 5-3: Application of vessel technologies under Package 1 to different vessel types and sizes

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

5.2.2 Package 2 - Moderate uptake of interim and drop-in fuelsThis package represents a moderate uptake of an interim alternative fuel (represented by LNG) in the
short-term and continuing to increase to 2040. From 2025 the HFO and MDO use is assumed to be
increasingly substituted with drop-in biofuels (FAME, HVO). This is followed by a later transition to
BioLNG in the 2040s to displace the LNG, with its use dependent on the build of ships using dual-fuelengines. The significant increase in the use of LNG (and, subsequently, BioLNG) could bring a risk ofincreased methane emissions through methane slip. However, during the study, stakeholders haveindicated that latest gas-fuelled engine designs have significantly reduced methane slip. This isparticularly true of low-speed engines (and emissions from medium-speed engines may increase underlower load conditions when employing slow steaming); an increased use of LNG may provide a drive
towards increased use of low-speed engines.
In terms of technologies, this package focuses on the high-to-moderate scoring technologies. Similarly
to package 1, it includes vessel design measures with decision matrix scores (8/9), and power
assistance measures with highest scores (7) and same assumption for Flettner rotor and sail
implementation post 2025. However, with respect to propulsion devices this package also includes
those scoring 7, and includes contra rotating propellers (CRPs), podded thrusters and ducts. The
highest scoring operational measures are included (9) as well as three additional measures scoring 8;
advanced port logistics, optimisation of capacity utilisation, and advanced autopilots.
In contrast to package 1, a 20% speed reduction is assumed for slow steaming. Given the reduced
effectiveness of waste heat recovery with significant speed reductions, waste heat recovery is notincluded in this package. Given the focus of this package on pursuing interim and drop-in fuels to reduce
GHG emissions, onboard CCS is assumed to not be needed in this package.
The key parameters and timeframes corresponding to package 2 for the modelling are shown in Figure5-9. The application of the different vessel technologies included in the modelling of this package areshown in Table 5-5. The package also includes assumptions around the production pathways used for
LNG, BioLNG, FAME and HVO. These are summarised in Table 5-6.

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Figure 5-9 Overview of timeline and components of Package 2.

* Bulbous bow retrofit is only in Ro-Ros, ferries and containers. **Not compatible with other propulsors

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67Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Yes

Yes

Yes

Yes

Yes

Container
vessels

Yes

Yes

Yes

Yes

Yes

General cargovessels

Yes

Yes

Yes

Yes

Yes

Yes

LNG carriers

Yes

Yes

Yes

Yes

Yes

LPG carriers

Yes

Yes

Yes

Yes

Yes

RoRo vessels

Yes

Yes

Yes

Yes

Cruise ships

Yes

Yes

Yes

Yes

Large
vessels
only

Yes

Mediumandlarge
vessels
only

Mediumandlarge
vessels
only

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Sails

Large
vessels
only

Flettner rotors

Large
vessels
onlyConstruction weightLargevessels
only

Yes

Table 5-6 Fuel specifications for the modelling of Package 2
FuelApplicability

Additional specification for the modelling

LNG

All LNG vessels

Assumed to use global average pathway.

BioLNGAll LNG vessels

Assumed to use liquid manure pathway

Biofuels

All vessel types

Assumed to use waste cooking oil feedstock pathway forboth FAME and HVO.

Overall the assumed timeline of implementation for the fuels for package 2 is as follows:

2020 – Assumes 50% conventional fuel (HFO), 50% Grey LNG (gas-only and dual-fuel vessels)(LNG) for new vessels from 2020

2025 – Assumes FAME and HVO start to be used to replace HFO (equal 50/50 split), gradualtransition from 2025-2045. By 2045 fully replaced HFO. Initial use of BioLNG in some vessels.

2030 – BioLNG starts to be used more widely; gradual transition from 2030-2050.



2045 – Assumes by 2045 100% FAME and HVO replacement of HFO2050 – By 2050, 100% BioLNG replacement of LNG, together FAME and HVO replace 100% of
HFO

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Waste heat recovery (WHR)

Bulk carriers

Largevessels
only

Yes

Carbon capture & storage (CCS)

Yes

Post-swirl

Yes

Pre-swirlYes

Contra-rotating propellers (CRPs)

Hull coatings

Yes

Large area propellers (LAPs)

Bow thruster tunnel optimisation

Yes

Ducktail waterline extension

Ballast reduction and trim optimisation

Tankers

Interceptors

Form optimisation

Optimum ship size and hull dimensions

Table 5-5: Application of vessel technologies under Package 2 to different vessel types and sizes

Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

5.2.3 Package 3 – Initial maximisation of vessel decarbonisation measures
This package represents an emphasis on the maximum use of fuel efficiency technologies to deliver
maximum reductions in emissions while using conventional fuels. The package then includes a latertransition to reduced carbon alternative fuels, and includes fuel pathways for LNG, ammonia andmethanol, subsequently followed by a transition to “green” versions of the same fuel types. The initialdeliveries of new vessels using ammonia and methanol is modelled as starting in 2025 and increasing
linearly over time to reach maximum percentages (25% of all new vessels using ammonia, 25% using
methanol and 50% using LNG) by 2035. Although it is possible that one of the reduced carbon liquid
fuels, methanol and ammonia, will be taken up more widely (they both require new engine types andfuel systems, methanol is easier to handle as it is a liquid at room temperature, but ammonia offers
greater emissions savings, at least at the vessel exhaust), they are modelled as having an equal share
due to the uncertainty as to which may end up dominating.
In terms of technologies, this package focuses on maximising technology use, therefore it includes alltechnologies with scores of 6/7/8/9 in the decision matrix. In addition to the measures deployed inpackage 2, package 3 also harnesses measures including air lubrication, towing kites and solar panels.
A 30% speed reduction is assumed for slow steaming, and similar to package 2, given the reduced
effectiveness of waste heat recovery with significant speed reductions, waste heat recovery is notincluded in this package. However, despite the score assigned to it, onboard CC is included in thispackage due to the longer continued use of conventional carbon containing fuels: the package assumes
initial deployment of new ships with carbon capture in 2030, with penetration increasing over time sothat all new ships (using carbon-containing fuels) are equipped from 2040.
The key parameters and timeframes corresponding to package 3 for the modelling are shown in Figure5-10. The application of the different vessel technologies included in the modelling of this package areshown in Table 5-7. The package also includes assumptions around the production pathways used for
LNG, BioLNG, ammonia and methanol. These are summarised in Table 5-8.

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Figure 5-10 Overview of timeline and components of Package 3* Note: Ammonia and methanol first transition using the grey production pathways in, followed by blue (CCS) (ammonia only) andfinally green pathways from 2035 onwards.** Bulbous bow retrofit is only in Ro-Ros, ferries and containers. *** Only in cruise
ships and Ro-Ros. **** Tankers and bulk carriers only. ******Not compatible with other propulsors

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Yes

Bulk
carriers

Yes

Yes

Yes

Yes

Yes

Yes

Container
vessels

Yes

Yes

Yes

Yes

Yes

Yes

Generalcargo
vessels

Yes

Yes

Yes

Yes

Yes

Yes

Yes

LNG
carriers

Yes

Yes

Yes

Yes

Yes

Yes

LPG
carriers

Yes

Yes

Yes

Yes

Yes

RoRo
vessels

Yes

Yes

Yes

Yes

Yes

Yes

Cruise
ships

Yes

Yes

Yes

Yes

Yes

Yes

Large
vessels
only

Large
vessels
only

Large
vessels
only

Large
vessels
only

Yes

Yes

Yes

Yes

Large
vessels
only

Large
vessels
only

Large
vessels
only

Large
vessels
only

Yes

Yes

Yes

Mediumandlarge
vessels
only

Mediumandlarge
vessels
only

Mediumandlarge
vessels
only

Mediumandlarge
vessels
only

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Table 5-8 Fuel specifications for the modelling of Package 3
FuelApplicability

Additional specification for the modelling

LNG

All LNG vessels

Assumed to use global average pathway

BioLNGAll LNG vessels

Assumed to use liquid manure pathway

Ammonia

All vessel types

MethanolAll vessel types

Assumed to use three pathways; grey ammonia followedby blue ammonia then transitioning to green ammonia
Assumed to use two pathways; grey methanol followed bygreen methanol

Overall the assumed timeline of implementation for the fuels for package 3 is as follows: 2020 – Assumes 72% HFO, 28% MDO for all ship categories except LNG carriers, which are 100%
grey LNG.
2025 - Grey ammonia starts to be used in 2025 but transitions out and is replaced by blue ammonia(2025-2035). Grey methanol starts to be used in 2025 but starts to transition out and be replacedby green methanol by 2040 (2025-2040). BioLNG starts to be used, gradual replacement of LNG
from 2025-2050

2035 - Blue ammonia starts to transition out (2035-2040), green ammonia transitions in (20352040). Grey methanol starts to transition (2035-2040).



2040 - By 2040, 100% green methanol and 100% green ammonia2050 - By 2050, 100% BioLNG replacement of LNG, 100% green methanol and green ammonia.

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Air lubrication

Yes

Waste heat recovery (WHR)

Sails

Yes

Carbon capture & storage (CCS)

Flettner rotors

Yes

Post-swirl

Construction weightYes

Pre-swirl

Optimum ship size and hull dimensions

Yes

Contra-rotating propellers (CRPs)

Hull coatings

Yes

Large area propellers (LAPs)

Bow thruster tunnel optimisation

Yes

Ducktail waterline extension

Ballast reduction and trim optimisation

Tankers

Interceptors

Form optimisation

Table 5-7: Application of vessel technologies under Package 3 to different vessel types and sizes

71Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

5.2.4 Technologies and fuel sensitivity studies
The three packages described above differ both in the technologies assumed to be implemented in newvessels and in the range of alternative fuels used. To give further insight into the effects of these different
elements of the packages, two additional sensitivity analyses have been performed. These are:

Package 1A:o Early pursuit of zero-carbon alternative fuels as in Package 1
o Same maximisation of vessel decarbonisation technologies as in Package 3

Package 2A:o Use of interim lower-carbon fuels and drop-in fuels as in Package 2
o Same maximisation of vessel decarbonisation technologies as in Package 3
The results of these analyses are presented in Section 7.5.

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6 Modelling methodology
This section describes the approach taken to modelling the impacts of the different fuel andtechnology packages on the fleet, fuel consumption, emissions and costs. Key points:


A global vessel fleet model has been constructed, with a baseline set (low, central, high) ofmaritime transport demand scenarios following selected pathways from the IMO’s 4 th GHG study.
The central scenario sees demand in tonne-miles nearly double by 2050 from 2020.



The future fleet has been estimated matching both the demand profile of the scenarios as wellas accounting for turnover of the vessel fleet. The fleet turnover is calculated separately for each
vessel category utilising recent historical vessel lifetimes. Vessel productivity decline with age isaccounted for.



Under the central demand scenario, we estimate the fleet size will need to grow to accommodate
the increased demand from ~49,000 ships in 2020 (~47,000 existing ships and ~2,000 newly built
ships) to ~71,000 ships by 2050 (comprising ~67,000 built since 2020, and ~4,000 ships fromprior to 2020 remaining in the fleet). Under the low and high demand scenarios, the fleet size in
2050 is 18% lower and 21% higher than in the central scenario, respectively.

Baseline CO2 emissions estimated in the central demand scenario to grow by ~22% between
2020 and 2050 (grow by 53% in the high demand scenario; decline by 13% in low demand).



The packages are implemented in the model by changes to the fuel efficiency and fuel used by
newly built ships, and the emissions characteristics of the fuel used by new and existing ships.
The impact of the fuel and technology packages are taken as the difference from the baseline.

The cost impacts of the packages account for alternative fuel costs (future price reductions are
forecast), vessel capital and operating costs. The net change in fuel production infrastructure
costs (capital and operating) are estimated. Cost-effectiveness of the packages is derived.

The analysis to estimate the decarbonisation potential and associated costs for the three packages was
performed using two components of a model. The two components were:i.

Estimating fleet changes and emissions impacts

ii.

Estimating cost impacts

As well as the fuel and technology packages, the model also calculates a baseline case, allowing theimpacts of the packages to be derived as the difference from the baseline. To address uncertainty inthe possible future maritime transport demand, the baseline and packages are estimated for threedemand scenarios (low, central and high). The two components of the model are linked by the fleet(numbers of ships constructed and in the fleet), fuel consumption (by fuel type) and emissions. Figure
6-1 shows an overview of the complete modelling structure used in this study, including the interaction
between the two components.

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Figure 6-1: Structure of modelling framework

This section describes the methodology deployed for the modelling in both components. The results ofthe modelling are shown in Section 7.

6.1 Fleet and emissions
The fleet and emissions modelling consists of a number of discrete steps, as listed in Table 6-1.
Table 6-1: Steps in the fleet and emissions modelling

Step

Step nameSummary

Baseline definition
1

Future demand
scenarios

Definition of future maritime transport demand under different
growth assumptions

2

Base year fleet

Definition of the numbers of vessels by type and size in the baseyear

3

Survivor curves

Derivation of a set of functions defining the percentage ofvessels built that survive to a given age before being demolished

4

Vessel productivity

Derivation of average annual productivity (tonne-miles delivered
per annum) by vessel type and size

For each demand scenario
5

Future year fleet

Calculation of the vessel fleet numbers by type and size, as
driven by the demand scenarios

6

Baseline fuelconsumption andemissions

Calculation of the fuel consumption and emissions under thebaseline assumptions

For each demand scenario and fuel and technology package
7

Impacts of technologies
and alternative fuels on
emissions

Calculation of the fuel consumption and emissions under theassumptions for the future technology development andalternative fuel use under the three packages

These steps are described in additional detail, with examples of the intermediate results, in the following
subsections.

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6.1.1 Future demand scenarios
A key input to the analysis of the development of the future fleet and emissions is the demand scenario.
This specifies, for each vessel type and hence the nature of the transport of the goods, the global
demand in tonne-miles. Three scenarios were included, representing low, central and high demand
growth scenarios. These were selected from the IMO fourth greenhouse gas study (IMO, 2020). As
mentioned in Section 1.1, the conclusions from the IMO study indicate expected growth in CO2emissions to 2050 of between 90% and 130% of the 2008 value, based on a limited set of the scenarios
considered in the study. The different scenarios are defined in terms of the assumptions on futuresocioeconomic development (known as “Shared Socioeconomic Pathways” (SSP)) and the atmosphericgreenhouse gas concentration development (known as “Representative Concentration Pathways”(RCP)). The scenarios on which the IMO report bases its headline ‘90% to 130%’ change statement arethose associated with RCP 2.6 (limiting global temperature increase to below 2°C). However, beyond
the executive summary of the IMO report, a fuller range of future maritime demand scenarios consistent
with additional pathways, from RCP 1.9 (1.5°C global temperature rise) to RCP 6.0 (2.8°C global
temperature rise, is provided. From reviewing the demand projections provided, the following
projections were selected for the low, central and high demand scenarios for this study.
Low

SSP4, RCP6.0 (“Inequality, a road divided” + “2.8°C medium baseline, high mitigation”)

CentralSSP2, RCP2.6 (“Middle of the Road” + “2.0°C low GHG emissions”)

High

SSP1, RCP4.5 (“Sustainability, Taking the High Road” + “2.4°C, medium-low mitigation”)

The total demand under these three projections, together with those for other scenarios in the IMO
250,000
reportare shown in Figure 6-2.50

Total demand for maritime freight (10^9 Tonne-miles)

Figure 6-2: Low, central and high demand projections selected, together with other demand scenarios fromthe IMO fourth greenhouse gas study report
200,000

ITF 2019
IMO GHG4 SSP1 RCP1.9
IMO GHG4 SSP1 RCP4.5
IMO GHG4 SSP1 RCP6.0
IMO GHG4 SSP2 RCP2.6

150,000

IMO GHG4 SSP2 RCP4.5
IMO GHG4 SSP2 RCP6.0
IMO GHG4 SSP3 RCP3.4
IMO GHG4 SSP3 RCP4.5
100,000

IMO GHG4 SSP3 RCP6.0
IMO GHG4 SSP4 RCP2.6
IMO GHG4 SSP4 RCP4.5
IMO GHG4 SSP4 RCP6.0
IMO GHG4 SSP5 RCP3.4

50,000

0
2000

IMO GHG4 SSP5 RCP6.0

2005

2010

2015

2020

2025

2030

2035

2040

2045

2050

50

The scenarios selected from those shown in Figure 6-2 represent reasonable bounds on future demand growth, rather than representing scenariosthat are more likely than others. The IMO report also included two further scenarios (based on SSP5) with demand levels above the selected “high”
scenario; however, it was felt that these represented an overly high level of demand and, therefore, they were not included in the scenarios modelled.

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The split of demand between different vessel types under these three scenarios are shown for 2050 in
Figure 6-3. By 2050, the greatest levels of demand are met by non-coal bulk carriers and container
ships. It is notable that, although the total demand for maritime transport is highest under the highdemand scenario, the demand for the transport of oil is lower than under the central scenario. This isbecause the cases are based on different global SSPs, with the high scenario being based on one withlower global demand for oil products (SSP1 rather than SSP2).
Comparisons of demand in 2050 under three scenarios
Figure6-3: Split of total demand between vessel types in 2050
160000140000Demand (billion tonne-miles)

120000100000

Other cargo
Other bulk carriers
Oil tankers

80000

Gas carriersContainer ships
Coal bulk carriers

60000

Chemical tankers

40000

20000

0
Low scenario

Central scenario

High scenario

6.1.2 Base year fleet
The baseline calculations in this model started from a description of the global maritime fleet in 2020
(the base year for the fleet analysis). This defined the numbers of ships in each category (and size subcategory) and age; these were obtained by analyses of the current fleet using data from the Clarksons
World Fleet Register (Clarksons Research, n.d.). The vessel categories included in the model are shownin Table 6-2, including the total fleet size at the start of the base year; Figure 6-4 shows the distributionof ages in these categories.

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Table 6-2: Definition of vessel size sub-categories and numbers of vessels in the base year

Vessel category

Tankers

Bulk carriersContainer ships

General cargo ships

Number of vessels
at the start of 2020

Size sub-category

Vessel sizes included

Small

Up to 40,000 DWT

10,052Medium40,000 to 100,000 DWT

2,170

Large

Over 100,000 DWT

383

Small

Up to 50,000 DWT

4,431

Medium50,000 to 100,000 DWT

5,848

Large

Over 100,000 DWT

1,793

Small

Up to 4,000 TEU

3,255

Medium4,000 to 13,000 TEU

1,730

Large

Over 13,000 TEU

399

Small

Up to 1,000 DWT

4,192

Medium

1,000 to 2,500 DWT

4,300

Large

Over 2,500 DWT

4,820

LNG Carriers

597

LPG Carriers

1,480

Ro-Ro Ships

836

Cruise Ships

465

Total fleet

46,751Figure 6-4: Age distributions for the different vessel categories in the base year
Fleet age distributions in base year for different vessel categories
100%

Percentage of vessel type fleet in age band (%)

90%
80%
70%
60%
Over 30 years

50%

26 to 30 years
21 to 25 years

40%

16 to 20 years
11 to 15 years

30%

6 to 10 years
up to 5 years

20%
10%
0%

For tankers and bulk carriers, the fleets are comparatively young, with larger numbers of vessels in the“younger” age bands. This is consistent with a stable situation with vessels being constructed on abroadly steady basis and then retired gradually over time. Large container ships (over 13,000 TEU) are

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a more recent development, and so this age profile analysis shows almost all vessels are very young(up to 10 years) .A few vessel categories, such as the small general cargo category, show a dominanceof older ships; this may indicate a limitation of the data source or a long vessel lifetime having led to a
reduced demand for new vessels.

6.1.3 Survivor curves
The modelling of the packages under future scenarios requires an estimate of the future fleet
characteristics, giving the number of vessels by category (and size) and age in each year between thebase year and 2050. A fleet turnover model is applied to achieve this aim. For each year, this identifies
the fraction of the fleet from the previous year that would survive to the new year and, hence, the fractionthat would be retired (i.e. demolished). To do so, the model applies a set of survivor curves that specify
the percentage of the fleet that survive to different ages. These curves were derived from vessel
demolition data obtained from the Clarksons’ World Fleet Register (Clarksons Research, n.d.). The
analysis of the demolition data produced distributions of the ages to which vessels survived; these werethen fitted with logistic curves to produce the functions applied in the model. The main curves used areshown in Figure 6-5. In Figure 6-5, the solid lines show the original data (percentage of vessels surviving
to beyond a given age, based on the ages in the demolition data), with the fitted curves shown asdashed lines.
Figure 6-5: Survivor curves developed for key vessel categories

Survivor curve profiles for different ship categories
100%

90%

Percentage surviving to Age

80%

70%
Bulk Carrier
Container

60%

Ro-Ro
Tanker50%

General Cargo
Bulk Carrier Fit

40%

Container Fit
RoRo Fit

30%

Tanker Fit
General Cargo Fit

20%

10%

0%

0

10

20

30

40

50

60

Age

6.1.4 Vessel productivity
Once the number of ships that survive to operate in the next year has been calculated, their capacity todeliver cargo is calculated using a set of productivity curves. To estimate the productivity (in tonne-miles

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per year for a vessel), the data published through the THETIS-MRV portal51 were analysed to develop
distributions of productivity against age and size of vessel. Data were available (with sufficient
information) for almost 10,000 vessels to include in this analysis. The analysis of the fleet average
productivity as a function of vessel age showed a strong dependence, as shown in Figure 6-6.
Figure 6-6: Productivity curve showing strong dependence on vessel age

Fraction of Productivity Acheived compared to Productivity at Age 1

1.0
0.9

Fraction of Productivity at Age 1

0.8
0.7
0.6
0.5

Fraction of Productivity
at Age 1

0.4

Curve fit

0.3
0.2
0.1
0.0

0

10

20

30

40

50

60

70

80

90

100

Age (years)

The curve shown in Figure 6-6 was used to model the reduction the productivity of the vessels as they
aged; their productivity at age of 1 year was based on the average values by ship category from the
THETIS-MRV data; they were then adjusted to ensure a balance between the number of vessels in the
fleet in the base year and the demand (total tonne-miles) required to be transported.52
The resulting age-dependant productivity of each vessel type is shown in Figure 6-7 for vessels of age
one year. As expected, the largest ship categories (large tankers, large bulk carriers and large container
ships) have the highest productivity values, with the smaller vessels having lower productivity. The small
and medium general cargo vessels can be seen to have very low productivity values (the numbers ofsuch vessels in the modelled fleet is comparable to other categories, so their contribution to the overall
demand is also small).

51

https://mrv.emsa.europa.eu/#public/eumrv. These EU level data are the most detailed information available, and have been assumed to be
representative of global vessel productivity.
52

The fleet data, productivity data and demand were derived from different sources, so some manual adjustment was required to ensure consistent
operation of the model.

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Figure 6-7: Calculated productivity (tonne-miles delivered per year) at a vessel age of 1 year
Vessel productivity at age of 1 year

Vessel productivity (Gtonne-miles per year

12

10

8

6

4

2

0

6.1.5 Future year fleet
The fleet in operation in future years (defined by the number of vessels in each category, including theage profiles) are calculated using a fleet turnover model that, in each year, calculates the number ofvessels (and their capacity to transport goods) that survive from the previous year and the number of
new vessels that must be built to enable the fleet to meet the transport demand.
The combination of the fleet size (including the age profile) surviving to the future year and the
productivity data shown in Figure 6-6 and Figure 6-7 determine the capacity of the existing fleet totransport goods. The gap between this capacity of the existing fleet and the demand for that year gives
the capacity that must be met by new vessels. The productivity at age zero is then used to determine
how many new vessels are required to be delivered during the year to ensure that the transport demandis met.
As a result of this calculation process, the maritime fleet in a future year consists of a number of vessels
from the base year fleet (with this number reducing over time) and a number of vessels built after thebase year. This is an important output as the differentiation between existing and new vessels is criticalto the assumptions of the three technology and fuels packages related to which are the new vesselsthat are able to be equipped with new technologies, or to use new fuels. Figure 6-8 shows the increasein the size of the future fleet and how it consists of different numbers of ships built in different years.

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Figure 6-8: Fleet development (total number of vessels) to 2050 under the central scenario, showing thosebuilt prior to and after 2020
Change in fleet to 2050 in the central scenario
80,000~67,000 ships built from2020 onwards~4,000 ships remain fromfleet prior to 2020

70,000~47,000 existing ships in 2020
~2,000 ships built in 2020

Number of Ships

60,00050,00040,00030,00020,00010,000

0
2020

2025

Ships built prior to 2020

2030
2020 to 2025

2025 to 2030

2035
2030 to 2035

2040
2035 to 2040

2045
2040 to 2045

2050
2045 to 2050

As can be seen, the number of vessels in a band of delivery years (e.g. 2025 to 2030) increases overthe five years of the band, then decreases gradually out to 2050 as the application of the survivor curves
takes effect.

6.1.6 Baseline fuel consumption and emissions
Using the calculated fleet in the future year, and the number of tonne-miles delivered in each vessel
category, the model calculates the fuel consumption and CO 2 emissions. This calculation relies on a setof fuel consumption per tonne-mile values derived from the data from the THETIS-MRV portal. The
calculated fuel consumption values are converted to energy consumption figures to simplify theapplication of the alternative fuels under the three technology and fuels packages.
For each vessel category and each future year, the demand met (in tonne-miles) is multiplied by therelevant energy consumption value for that category to give the total energy consumed by the fleet (inthat vessel category). For the baseline cases, the energy efficiency values for new build vessels areheld constant for vessels delivered from 2020 (i.e. vessels built after 2020 are assumed to have thesame efficiency as those built in 2020). This reflects the assumption that the historic improvements inefficiency for new vessels are the result of the introduction of improved technologies, along similar lines
to those implemented under the packages; projecting continuing improvements in the baseline would
lead to double counting of efficiency improvements under the packages. This approach is known as a“technology freeze” model assumption. The fuel consumption is calculated separately for each fuel type,so that the total fuel consumption by fuel type can be determined and so that the CO2 emissions can becalculated using standard emissions factors for the different fuels. In addition to CO2 emissions, themodel also calculates CO2-equivalent (CO2e) emissions, which include the impacts of methane (CH 4)
and nitrous oxide (N2O) emissions, factored by the relevant ratios of global warming potential. The CO 2e

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emissions are calculated applied separately for well-to-wake53 (WTW) and tank-to-wake (TTW)
emissions so that the effects of the different fuel pathways can be identified as well as the different fueltypes. The assumptions behind the definition of the different fuel types and pathways was presented in
Section 4. The emissions factors for 2020 used in the model are shown (based on mass of CO 2 or CO2eemissions per energy content to ease comparisons between the different fuel types) are shown in Table
6-3. As shown previously in Table 5-1, for some of the “green” fuels, the WTW emissions are higher
than the equivalent “blue” fuels in 2020; these are expected to reduce over time as the embedded
emissions in the renewable electricity generation plants reduce, thus giving them lower emissions thanthe “blue” variants in future years.
Table 6-3: Summary of fuel CO2 emission factors for 2020 used in model

Fuel

CO2 TTW (g/MJ)

CO2e TTW (g/MJ)

CO2e WTW (g/MJ)

HFO

77.5

77.6

87.2

MDO

75.1

76.1

93.5

LNG

57.3

59.6

78.1

BioLNG

57.3

59.6

27.5

Hydrogen (Grey)

0.0

0.0

92.4

Hydrogen (Blue)

0.0

0.0

21.5

Hydrogen (Green)

0.0

0.0

22.2

Ammonia (Grey)

0.0

0.0

100.6

Ammonia (Blue)

0.0

0.0

20.9

Ammonia (Green)

0.0

0.0

22.2

Methanol (Grey)

69.1

76.1

98.1

Methanol (Green)

69.1

76.1

22.2

FAME

75.5

76.5

13.8

HVO

70.7

71.6

8.1

For fuel types with different pathways (hydrogen, ammonia and methanol), the TTW emissions are thesame for the different pathways, as the fuel loaded into the tank is chemically identical in each case.
For hydrogen and ammonia, these values are zero, as they do not produce any CO 2 on combustion; all
the WTW emissions relate to the production process.
Figure 6-9 shows the calculated global emissions from 2020 to 2050 under the three baseline scenarios.
The baseline calculations assume that no new technology is introduced into newly built vessels after
2020, so all vessels delivered after that date have the same characteristics as those built in 2020. The
overall fleet continues to improve (efficiency) as the newest vessels form a greater portion of the fleet.

Well-to-wake emissions include the emissions associated with the production of the fuel, as well as those from the combustion in the ship’s
engines, while tank-to-wake emissions include only those from combustion.
53

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Figure 6-9: Emissions of CO2e from 2020 to 2050 under three baseline (technology freeze) scenarios

Maritime CO2 equivalent emissions (Mtonnes per year)

1,800
1625Mt CO2e
1,600

1,400
~ 380 Mt to 1,080 Mt ofCO2e emissions
reduction to be achieved

1,200

1,000
Low
925Mt CO2e

~ 1060Mt CO2eemissions in 2020

800

Central
High

600

400

~ 540 Mt CO2eemissions in 2050
IMO ambition(adjusted)

200

0
2015

2020

2025

2030

2035

2040

2045

2050

2055

Figure 6-9 shows calculated CO2e emissions in 2020 of approximately 1,060 Mtonnes. This isapproximately 15% higher than the value for 2018 reported by IMO in their fourth greenhouse gas study(IMO, 2020). The reasons for this difference in emissions could include:

Difference in base year (although the effect of this would be expected to be small as the datain the IMO study does not indicate a rapid rise in emissions approaching 2018);Differences in scope and assumptions behind the allocation of vessel types to deliver theidentified demand;

Differences in modelling of fuel consumption by different vessel types.

The current modelling uses data from the EU THETIS-MRV database from 2018 and 2019 to estimate
the fuel consumption of different vessels. The IMO study uses different data to estimate fuelconsumption; as a result, this effect probably has the greatest impact on the differences in the calculated
fuel consumption and emissions.
The IMO third greenhouse gas study (International Maritime Organization, 2014) reported CO2eemissions in 2008 of 940 Mtonnes. The achievement of the ambition of, at least, a 50% reduction inemissions by 2050 would imply emissions from international shipping of no more than 470 Mtonnes. As
the current study has calculated higher emissions in the base year than those in the IMO fourthgreenhouse gas study, it is sensible to compare the achievements of the measures against a target for2050 that is also increased by a similar percentage. Therefore, the results of the analyses are comparedagainst a 2050 target of no more than 540 Mtonnes CO2e.

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6.1.7 Impacts of technologies and alternative fuels on emissions
The calculation process described above is applied for the baseline and package cases. The impactsof the different packages are then identified as the difference (in fuel consumption, emissions, etc.)
between the baseline and the package results.
The implementation of the packages in the calculations consists of three separate elements:


Vessel-based technologies



Operational improvements



Alternative fuels

For the vessel-based technologies, the fleet turnover calculation, described in Section 6.1.5, retains theage profile of the fleet in the future years. For each future year, this allows the percentage of theoperating fleet that was delivered in each previous year to be identified. Each vessel-based technology
is specified by an initial year of introduction into new-build vessels, and the percentage of new vesselsthat it is applied to. Using the numbers of vessels built in each year, as described in Section 6.1.5, thepercentage of the operating fleet in the future year equipped with the technology can be calculated. This
percentage is then used, with the defined efficiency improvement for the technology, to calculate thereduction in energy requirements for the fleet in that year.
The resulting increased penetration of the different technologies into the operating fleet (over any
penetration in the baseline), under the three packages, is illustrated in Figure 6-10 to Figure 6-12.
Figure 6-10: Penetration of technology into the in-service fleet under Package 1

In-service fleet penetration of new technologies, Package 1, Central
demand scenario

Percentage of in-service fleet with technology(increase over baseline, if appropriate)50%45%Form optimisation, Ballast reduction andtrim optimisation, Bow thruster tunnel
optimisation, Hull coatings, Waste heatrecovery (WHR)
Flettner rotors

40%
35%
30%

Sails
25%
20%

Large area propellers (LAPs), Pre-swirl

15%
Post-swirl

10%
5%
0%
2020

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2030

2035

2040

2045

2050

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Figure 6-11: Penetration of technology into the in-service fleet under Package 2

In-service fleet penetration of new technologies, Package 2, Central
demand scenario

Percentage of in-service fleet with technology(increase over baseline, if appropriate)

50%
45%
40%

Form optimisation, Ballast reduction andtrim optimisation, Hull coatings, Optimum
ship size and hull dimensions

35%

Bow thruster tunnel optimisation

30%

Flettner rotors, Sails

25%
Large area propellers (LAPs)
20%
Contra-rotating propellers (CRPs)
15%
Pre-swirl

10%
5%
0%
2020

2025

2030

2035

2040

2045

2050

Figure 6-12: Penetration of technology into the in-service fleet under Package 3

In-service fleet penetration of new technologies, Package 3, Central
demand scenario

Percentage of in-service fleet with technology(increase over baseline, if appropriate)50%

Form optimisation, Ballast reduction andtrim optimisation, Bow thruster tunnel
optimisation, Hull coatings, Optimum
ship size and hull dimensions,
Construction weight, Waste heatrecovery (WHR)
Interceptors, Ducktail waterline extension

45%
40%
35%
30%

Flettner rotors, Sails

25%
20%
15%

Large area propellers (LAPs), Pre-swirl,
Post-swirl

10%
5%
Contra-rotating propellers (CRPs)
0%
2020

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2025

2030

2035

2040

2045

2050

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As several technologies are given the same initial implementation dates and applicability, some curvesin these charts represent multiple technologies, as shown. The highest levels of fleet penetrationachieved by 2050 are just over 45% under each package.
Operational improvements are assumed to be available to all operating vessels in the future year, notjust those built after a given year. Therefore, the energy reductions resulting from the take-up of the
improvement are applied across the full fleet (factored by the assumed percentage take-up in the futureyear).
The take-up of alternative fuels is dependent on the ability of the vessel to use that fuel, which also
depends on its build year (in a similar way to the vessel-based technologies). Therefore, the calculated
fleet in each future year is also defined by the fuel used (HFO, MDO, LNG, ammonia, etc). The approachdescribed above for calculating the fuel consumption from the energy consumption is then applied
separately by each fuel type. In doing so, it is assumed that the fuel type does not change the energy
needed for the vessel to deliver a tonne-mile, this energy requirement having been reduced by any
vessel-based technologies and operational improvements included in the package.

6.2 Costs
The cost modelling takes the results for the vessel fleet, fuel consumption and emissions calculations
described in Section 6.1 and applies estimated values for vessel and infrastructure capital andoperational costs, to derive overall costs in each year under the baseline and fuel and technology
package cases. As for the fleet and emissions modelling, the cost impacts of the packages were
calculated as the difference between the total costs under the package and those under the baseline.
The methodological steps in the cost modelling are summarised in Table 6-4 and described in thefollowing subsections.
Table 6-4: Steps in cost modelling

Step

Step name

Description

1

Fuel specification

Define fuel specification, including price projections to2050, for all fuel types

2

Define vessel prices

Define the prices for the different vessel types, including
the impact of the inclusion of the different technologies
under the package cases

3

Calculate vessel capital costs

Calculate total capital costs, including costs of capital(e.g. interest on loans) for the fleet, by vessel type4

Calculate vessel operating
costs

Calculate annual operating costs for the fleet, by vessel
type5

Calculate fuel production
infrastructure capital costs

Based on the calculated demand for fuels of each types,
calculate the number of production plants required andtheir associated capital costs

6

Calculate fuel production
infrastructure operating costs

For the number of plants calculated to be required foreach fuel type, calculate the annual operating costs

7

Calculate port refuelling
infrastructure costs

Based on the calculated demand for the fuels of different
types, calculate the refuelling infrastructure required andthe associated costs (capital and operating)8

Calculate port CO2 handlingcosts

Based on the calculated CO2 captured by on-board CC
systems, calculate the costs for offloading and handlingthe fuel in ports

9

Calculate total costs and costeffectivenessThe cost modelling uses the emissions results from thefleet and emissions modelling to output cost-effectivenessvalues (net cost per tonne CO2 reduction).

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6.2.1 Fuel specification
This first step specifies the assumptions on the prices for the different fuel types out to 2050. Illustrative
current (or recent) prices for the different fuel types considered in the study are shown in Section 4.1.
The modelling of future costs needs to account for future prices of fuels. Since many of the fuel pathways
considered are in their infancy from a TRL perspective, it would be overly cautious and an overestimate
to assume these prices (e.g. green hydrogen/ammonia) would not drop over time. Therefore, estimatesof future fuel prices have been developed in order to calculate the fuel costs over time. The prices havebeen developed in constant 2020 US dollars (i.e. not including the effects of general inflation). To ensurethat the price projections for the different fuel types are all developed in a consistent manner, IHS Markit(under a separate contract to Concawe) developed a set of price projections, using prices from multiple
regions for current prices and their own knowledge and intelligence to derive the expected future
development of these prices. The exceptions were for BioLNG and green methanol, for which IHS Markit
were not able to provide price projections. In these two cases, previous Ricardo price projections for
LNG and BioLNG, and for grey methanol and green methanol, were used to derive price deltas, whichwere added to the IHS Markit projections for LNG and grey methanol, respectively. To provide the inputs
to the modelling, the fuel price projections were averaged across the three regions for which they were
provided. The averaging weighted the values provided for the three regions using data for deliveries ofoil products to international marine bunkers from the IEA. The weighting factors calculated were:

Northwest Europe31%

US Gulf Coast

17%

South East Asia

52%

The price projections for the different fuels, averaged across the regions as described and converted to$/GJ, are shown in Table 6-5. The narrative accompanying the fuel price projections is included inAppendix A.10
Table 6-5: Fuel price values used in the cost modelling (values in $/GJ)

Fuel

2020

2030

2040

2050

HFO

$8.22

$10.99$10.39

$9.27

MDO

$8.61

$12.61$12.08$11.08

LNG

$6.78

$8.29

$9.28

$9.42

BioLNG$10.52$41.29$42.28$42.42

MethanolGrey$13.65$19.52$19.61$19.13

MethanolGreen$48.35$39.59$30.27$26.44

AmmoniaGrey$13.40$21.05$21.71$23.14

AmmoniaBlue$15.93$24.27$23.36$24.46AmmoniaGreen$36.58$36.43$31.61$29.43

HydrogenGrey$12.34$13.99$14.65$14.80HydrogenBlue$17.62$19.57$20.66$20.66

HydrogenGreen$41.17$24.73$19.99$18.49FAME$34.74$33.34$30.76$27.19HVO$39.94$37.91$34.40$30.62

All prices are based on those provided by IHS, with the exception of BioLNG and green methanol. These are basedon the IHS values for LNG and grey methanol, adjusted using deltas derived from in-house Ricardo analyses.

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6.2.2 Define vessel prices
The prices for new vessels have been developed using analyses of vessel price data from the Clarksons
World Fleet Register (Clarksons Research, n.d.). A regression analysis was performed on these data
against vessel size (in DWT, or TEU for container ships) to derive the new vessel prices as functions ofvessel size. These functions were then used to derive average prices for vessels in each category (andsize sub-category), based on the average size of vessel in the category. The prices used in the cost
analysis are shown in Figure 6-13.
Figure 6-13: Average new build vessel prices used in the cost analysis

The prices derived in this manner were used for the calculation of capital costs in the baseline cases(assuming that the vessel prices would remain constant over time, consistent with the technology freeze
assumption applied in the baseline case).
For the calculations including the fuel and technology packages, the estimated costs of including thetechnologies in the vessels, as described in Section 4.2 to Section 4.7, were added to the baseline
vessel prices for inclusion in the capital cost calculations (for vessels delivered in years following theassumed adoption of the technology). In cases where a range of costs were identified for the technology,
an average value was used; the costs were included as identified, no learning factors were applied.

6.2.3 Calculate vessel capital costs
As the modelling calculated costs for each year from 2020 to 2050, the capital costs are also annualised.
The total capital costs consist of two elements:


Vessel purchase cost

Costs of capital

The annualised vessel purchase costs are calculated by spreading them evenly over an average vessel
lifetime. The vessel lifetimes used, derived from the same analyses used to derive the survivor curves
described in Section 6.1.3, are shown in Table 6-6. Lifetimes for vessel types not included in this tablewere set to those for the nearest equivalent vessel type (e.g. tanker for LNG carrier).

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Table 6-6: Vessel average lifetimes used in capital cost analyses

Vessel type

Average lifetime (years)

Bulk Carrier

26.3

Container

21.4

Cruise

35.5

RoRo

33.3

Tanker27.1

The costs of capital (representing, for example, interest on loans) were derived as additional capitalcosts associated with the weighted average cost of capital in the sector. The same rates as mentioned
in section 3.3 were applied.

6.2.4 Calculate vessel operating costs
The total vessel operating costs included in the analysis include:

Crew costs

Stores

Lubricant costs

Maintenance costsInsuranceAdministration



Fuel costsPort charges

The annual costs for crew, stores, maintenance, insurance, administration and lubricants were derived
from benchmark reports published by Moore Stephens (Dec 2017) 54 and the BCG Shipping
Benchmarking Initiative55.
The port charges were calculated using averages of charges for a number of international ports,
published by the Hong Kong Maritime Department56, multiplied by an estimated number of port visits by
the fleet. For each vessel type, a typical route portfolio was assumed, according to the mostrepresentative routes for each vessel type and size (Baltic dry index routes, EEX tanker index routes
and World Shipping Council trade routes as a proxy for container routes). As such, the modelling of port
charges does not take account of any changes in those charges as the nature of the fuels suppliedchange over time under the different packages.
The fuel cost calculations use the total fuel consumed by each type of fuel, multiplied by the assumed
price for those fuels in each year, as described in Section 6.2.1.

6.2.5 Calculate fuel production infrastructure capital costs
The three technology and fuels packages include future transitions to alternative fuels (hydrogen,ammonia, FAME, BioLNG, etc.); these also include transitions in the production pathways of some ofthose fuels (from grey fuels in the short term to green production pathways in the longer term). The54

http://greece.moorestephens.com/MediaLibsAndFiles/media/greeceweb.moorestephens.com/Documents/1-Richard-Greiner.pdf

55

https://www.bcg.com/industries/transportation-travel-tourism/shipping--benchmark-initiative/benchmarks

56

https://www.mardep.gov.hk/en/publication/pdf/port_bm_study.pdf

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consumption of these alternative fuels implies a need for increased production, which will require
investment in the construction of those facilities.
Under normal commercial considerations, it would be expected that the investment costs of those newfacilities would be recovered through the higher prices for the fuels. Therefore, to account for both theinfrastructure investment costs and the increased fuel prices in the final cost calculations could beconsidered as double counting.57 Nonetheless, it is valuable to understand the implications of the uptakeof the different alternative fuels for the industry’s investment requirements in fuel production
infrastructure, so these costs were calculated as described in this section (impacts on fuel distribution
and bunkering infrastructure were not included in this analysis). The results are presented in 7.3.
The calculations of the total capital expenditure (CAPEX) on fuels production infrastructure considers
the annual demand for the alternative fuels (as calculated by the fleet and emissions modelling) anddetermines how many additional fuel production plants would be required to meet the demand. The
calculation includes the expected lifetime for the plant, with new plants being built to maintain total
production capacity to meet demand as plants are decommissioned (or equivalently, existing plants
renewed). The cost calculations also take account of the corresponding reduction in demand, and hence
production capacity requirements, of conventional fuels (HFO and MDO), leading to some offsetting of
the additional capital costs of the alternative fuel plants.
The capital cost data for the different fuel types have been obtained from a range of sources, as shownin Table 6-7. The data identified cover a range of different plant sizes (and capacities), which leads tosome uncertainties in comparing the different values, so the costs are also shown divided by the total
lifetime production capacity to improve this. The lifetime production capacities were derived in totalenergy (GJ) terms, again to enable comparisons between the plants for different types of fuels. The
capital expenditure per GJ of fuel produced values for the different fuels are also compared in Figure
6-14.

57

Whilst adding plant investment and operation to fuel price would lead to double counting the capex and opex of the operator, this is not necessarily
the case for any infrastructure which is shared and/or developed by public authorities in case needed (pipelines, new storage facilities at port, etc.)

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Table 6-7: Fuel (including alternative fuels) plant CAPEX values for infrastructure cost calculations

Fuel type

Fuel pathway

Exampleplant capacity(Mt/yr)Exampleplant CAPEX($m)

Example plant
CAPEX/totalenergy ($/GJ)

References

HFO

Conventional

1.47

1190

$1.01

(FuelsEurope,
2018)(JWEnergy,
2017)

MDO

Conventional

3.91

3720

$1.11

(FuelsEurope,
2018)(JWEnergy,
2017)

LNG

Globalaverage LNG

10.00

10000

$0.52

(CBC,
2020)
(OffshoreEnergy,
2015)

BioLNG

Liquid manure(closeddigestatestorage)

0.01

14

$2.05

(Navigant, 2019)

Grey
HydrogenSteamreforming
natural gas

0.08

223

$1.18

(IEAGHG, 2017)

Blue
HydrogenNaturalgas
and CCS

0.04

411

$4.69

(IEAGHG, 2017)

GreenHydrogenHydrogenElectrolysis(renewableenergy)

-

0.04

719

$8.21

(FCH2 JU, 2017)(Morgan, 2013)

Grey
Ammonia

Conventional
naturalgas
feedstock - EUelectricity mix

0.44

705

$4.24

(Brown, 2017)

Blue
Ammonia

Naturalgas
and CCS

0.21

357

$4.56

(Morgan, 2013)

Green
Ammonia100%
renewable
production

1.20

5,000

$11.02(Morgan, 2013)

Grey
MethanolNatural gas

1.50

1166

$1.30

(ADI
2017)

Green
Methanol

Synthetic
methanolPower to fuel3.6

10,71858$4.99(ADI analytics,
2017)

FAME

Waste
cooking oil

0.25

581

$4.15

(ECOFYS, 2013)

analytics,

HVO

Waste
0.50
321
$0.97
(TOTAL, 2019)
cooking oil
All values converted to 2020 USD. A more detailed breakdown can be found in Appendix A.9

58This value includes $1,854 million quoted in the reference, plus the scaled value for an equivalent capacity green hydrogen plant.

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Figure 6-14: Capital costs for different fuel production infrastructure expressed as $/GJ

Plant CAPEX divided by lifetime fuel production ($/GJ)

$12

$10

$8

$6

$4

$2

$0
HFO

MDO

LNG

BioLNG

Grey
Blue
Green
Grey
Blue
Green
Grey
Green
Hydrogen Hydrogen Hydrogen Ammonia Ammonia Ammonia Methanol Methanol

FAME

HVO

The fuel types with the greatest capital cost (per GJ of fuel produced) are the green hydrogen andammonia plants, with the plants for the blue fuels also significant. This contrasts with the costs for themethanol plants and grey hydrogen (based on steam reforming of natural gas), all of which are similar
in magnitude to the conventional fuels. It is important to note that the production of green methanol
requires the production of green hydrogen as part of the process; therefore, the significantly lower value
for green methanol in Table 6-7 and Figure 6-14 indicate some uncertainties (particularly in the green
methanol data) due to the limited range of sources of data available and suggest some caution should
be used in relation to these results.

6.2.6 Calculate fuel production infrastructure operating costs
The calculation of the fuel production infrastructure operating costs follows a very similar approach tothat for the capital costs. Similar sources have been used to identify the annual operating costs for thedifferent plant types. For the cost modelling, the costs per GJ of fuel produced were multiplied by theannual demand for the fuels, to produce a total annual operating cost for the fuel production
infrastructure by fuel type.
The cost inputs are shown in Table 6-8, with the calculated annual operating costs per GJ of fuelproduced for the different fuel types compared in Figure 6-15.

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Table 6-8: Fuel (including alternative fuels) plant OPEX values for infrastructure cost calculations

Fuel type

Fuel pathway

Exampleplant
capacity(Mt/yr)ExampleExample plant References
plant OPEX OPEX/total($m/yr)energy ($/GJ)

HFO

Conventional

1.47

4.15

$0.07

(FuelsEurope,
2018) (JWEnergy,
2017)

MDO

Conventional

3.91

12.96

$0.08

(FuelsEurope,
2018) (JWEnergy,
2017)

LNG

Global
LNG

average 10.00

0.56$0.0012(OffshoreEnergy,
2015)

BioLNG

Liquidmanure 0.01
(closed digestatestorage)

0.86

$3.07

Grey
Hydrogen

Steam reforming 0.08
natural gas

7.55

$0.80

Blue
HydrogenNatural gas and 0.04
CCS

7.60

$1.74

Green
HydrogenElectrolysis(renewableenergy)

0.04

1.12

$0.25

Grey
Ammonia

Conventional
0.44
naturalgas
feedstock - EUelectricity mix

5.89

$0.71

Blue
Ammonia

Natural gas and 0.21
CCS

18.80

$4.80

Green
Ammonia

100% renewable 1.20
production

7.50

$0.33

Grey
MethanolNatural gas

1.50

5.62

$0.19

Green
Methanol

Synthetic
3.60
methanol - Powerto fuel

1,072

$0.50

FAME

Waste cooking oil

0.25

7.53

$0.81

HVO

Waste cooking oil 0.50
(standalone
plants)

7.07

$0.32

Ricardo Confidential(Navigant, 2019)(IEAGHG, 2017)(IEAGHG, 2017)(FCH2 JU, 2017)(Morgan, 2013)(Brown, 2017)(Morgan, 2013)(Morgan, 2013)(Nyári, 2018)(ADI analytics,
2017)(ECOFYS, 2013)(TOTAL, 2019)93

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Figure 6-15: Operating costs for different fuel production infrastructure expressed as $/GJ

Plant OPEX divided by annual fuel production ($/GJ)

$6

$5

$4

$3

$2

$1

$0
HFO

MDO

LNG

BioLNG

Grey
Blue
Green
Grey
Blue
Green
Grey
Green
Hydrogen Hydrogen Hydrogen Ammonia Ammonia Ammonia Methanol Methanol

FAME

HVO

On a per unit energy basis, the BioLNG, blue hydrogen, blue ammonia and green methanol fuel types
have a significantly higher production cost than the other fuel types. That for LNG is significantly lower.
As noted above, the costs of building and operating the fuel production infrastructure were implicitly
included in the overall cost results through the fuel prices and, therefore, the costs as described here
were not added to the total, but are presented separately to assist in understanding the implications forthe fuel supply industry. As noted above in relation to the capital costs, the different fuel production
infrastructure costs were derived from different sources, and based on different sizes of plants. Although
they have been expressed in costs per unit of energy, to improve comparability, there is still significant
uncertainty in the different values presented.

6.2.7 Calculate port refuelling infrastructure costs
The fuel price projections presented in Section 6.2.1 are those for the fuel as sold by the producers. As
such, they do not include the additional costs related to the provision of the new refuelling infrastructure
at the ports. As the alternative fuels may require more complex storage and transfer facilities than forconventional fuels (particularly for those that are stored at high pressures and/or low temperatures, suchas hydrogen and ammonia), the additional facilities may have significantly higher costs. Unlike the fuelproduction infrastructure costs, which are expected to be recovered through the fuel prices, therefuelling infrastructure costs are in addition to the fuel prices and, therefore, are included in the total
cost calculations.
The calculation identified the quantity of the alternative fuel that needs to be supplied in each year; theincrease in the fuel demand in each year was used to identify the additional global refuelling capacitythat was required. The assumed facility lifetime was used to identify the refuelling capacity that will be
decommissioned and, hence, will need to be replaced (unless the demand is reducing, in which casenot all of the decommissioned capacity will need to be replaced).
Available sources were reviewed to identify estimated costs for the provision of refuelling facilities foralternative fuels at example ports. These were converted to a cost per GJ of fuel supplied (with the

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capital costs amortised over the estimated lifetime of the facility), which were multiplied by the additional
refuelling capacity required in each year to give the associated costs. For presentation, these additionalcosts were then added to the fuel costs as described in Section 6.2.1.
The estimated values for the provision of port refuelling infrastructure, together with the sources on
which they were based, are shown in Table 6-9.
Table 6-9: Assumed costs for refuelling infrastructure for alternative fuels
Fuel type

Bunkercapacity(tonnes/annum)Portfacility
lifetime(years)

CAPEX

OPEX

($ million)($ million per
year)

Source

HFO

1,000,000

30

10.00

0.50

No detailed data found.
Estimated value to provide
somebalancing
cost
reductions.

MDO

1,000,000

30

10.00

0.50

Assumed same as HFO

LNG

1,935,000

30

53.27

5.03

LNG bunkering financing
opportunities(OceanShipping
Consultants,
201659)BioLNG

1,935,000

30

53.27

5.03

Assumed same as LNG

Hydrogen

255.5

30

23.00

0.92

Feasibility
bunkering201960)

Ammonia

255,500

20

41.00

1.33

A blueprint for commercialscale zero-emission shipping
pilots (Energy Transitions
Commission, 202061)

Methanol

255,500

20

8.00

0.17

Same source as Ammonia

FAME

1,000,000

30

10.00

0.50

Assumed same as HFO

HVO

1,000,000

30

10.00

0.50

Assumed same as HFOofhydrogen(ITMPower,

6.2.8 Calculate port CO2 handling costs
As described in Section 4.6, in addition to the additional vessel costs for its implementation, theintroduction of on-board carbon capture under Package 3 will result in additional port costs for offloading
and onward transport of the captured CO2. As also noted in Section 4.6, a study62 for BEIS was used to
identify an average cost of $21.62 per tonne CO2 handled by ports.

59

http://www.anave.es/images/seguridad/eu_lng_bunkering_financing_opportunities_osc.pdf

60https://northsearegion.eu/media/9385/feasibility-of-hydrogen-bunkering-final-080419.pdf

61https://www.globalmaritimeforum.org/content/2020/11/The-First-Wave-%E2%80%93-A-blueprint-for-commercial-scale-zero-emission-shippingpilots.pdf
62

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/761762/BEIS_Shipping_CO2.pdf

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To calculate the overall costs, the quantity of CO 2 captured by on-board carbon capture systems wascalculated from the results of the emissions modelling and then multiplied by the value above.
For presentation, the additional operating costs associated with the handling of the captured CO 2 werecombined with the other vessel operating costs.

6.2.9 Calculate total costs and cost-effectivenessThe different cost elements described in the preceding sections were integrated into a set of total costs
for each demand scenario and each technology and fuels package (including the baseline). The
additional costs related to the packages were then calculated as the difference between the results forthe package and the equivalent results for the baseline scenario.
All costs were calculated separately for each year between 2020 and 2050. Discounting was thenapplied to the calculation of the total costs when summed over the period from 2020 to 2050, to reflect
different views on the future value of money, interest rates, etc., to derive the net present value (NPV)
results. The main results presented in this report are derived using a discount rate of 10%; additional
sensitivity results are also presented for a discount rate of 5%.
By combining the total costs and the total emissions savings under each of the packages, costeffectiveness values, in $/tonne CO2, were calculated to provide an overall comparison of the threepackages. These were again summed over the period from 2020 to 2050, with discounting applied, tocalculate the NPV. By default, the calculations of cost-effectiveness included discounting of both thecosts (reflecting the future value of money) and the emissions savings (reflecting perceptions that early
emissions savings are more valuable than later savings), with the same discount rate applied to both.
However, opinions in literature vary as to whether emissions savings should be discounted in this way,so the model also calculates cost-effectiveness values with the costs discounted and the emissions
savings not discounted.

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7 Decarbonisation potential and costs of fuel andtechnology packages
This section describes the results of the analyses of the different fuel and technology packages on
the future emissions, the levels of decarbonisation achieved and their associated costs and costeffectiveness. Key points relating to vessel technologies and fuel consumption:


Fuel consumption in the central baseline scenario (two thirds HFO, one quarter MDO, 10% LNG)
is estimated to increase by around 20% by 2050 compared to 2020 despite the demand growing
much more strongly, showing the effects of energy efficiency gains in the fleet.



In contrast, also under the central baseline scenario, the total fuel consumption of package 1
drops by about 8% by 2050 and is made up of ~72% ammonia, ~12% hydrogen, and ~16%
conventional fuels (HFO/MDO/LNG)

Package 2 total fuel consumption in 2050 is about 12% lower than in 2020. This package sees
methane (LNG, BioLNG) increase to just over half of total fuel consumption by 2050, with LNG
dominating until the late 2030s before giving way to drop-in substitute BioLNG. The remainder isassumed to be split between drop-in biofuels HVO and FAME.



The increased emphasis on energy efficiency measures in package 3 means it has the lowest
total fuel consumption (about 23% lower in 2050 than in 2020). Its fuel mix remains dominatedby conventional fuels until 2040. By 2050, the mix is ~50% BioLNG, ~20% each of ammonia andmethanol and remainder HFO/MDO.

Under the central demand scenario, baseline CO2e emissions rise to 1,300 Mtonnes by 2050



Under all packages, CO2e emissions in 2050 are reduced to between 260 and -20 Mtonnes on awell-to-wake basis, better than the IMO ambition

Packages 1 and 3 also meet the IMO ambition for 2050 when emissions are compared on a tankto-wake basis, with emissions of 160 and 290 Mtonnes; TTW emissions for Package 2 areapproximately 800 Mtonnes

Package 3 is the least cost solution, reaching $39 / tonneCO2e WTW in a mid-demand scenario

Package 2 is the highest cost solution driven by high fuel costs, reaching $113 / tonneCO2e WTW
in a mid-demand scenario



Cost-effectiveness figures are highly sensitive to discounting or not discounting the CO 2e in theanalysis. The same is true for the discount rate for both costs and CO2e (this report provides arange of ratios.)

The fleet and emissions modelling, described in Section 6.1, has been applied to the calculation of thefuel consumption and emissions under the three demand scenarios and the three technology and fuels
packages (plus the baseline cases).

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7.1 Fuel consumption
The overall development of the fuel consumption by the global maritime fleet under the central baseline
scenario is shown in Figure 7-1. To enable the consumption of the different fuels to be combined into asingle chart, they are presented as million barrels of oil equivalent (Mboe) values.
Figure 7-1: Baseline fuel consumption to 2050 under the central scenario

Maritime fuel consumption (Million barrels of oil equivalent))

3,500

3,000

LNG

2,500

MDO
2,000

1,500

HFO

1,000

500

0
2020

2025

2030

Heavy Fuel Oil (HFO)

2035

2040

Marine Diesel Oil (MDO)

2045

2050

LNG

Source: Ricardo calculation based on central scenario projection and modelling described in Section 6
Under the baseline scenarios, the fuel efficiency of new vessels built after 2020 remain at the samelevels as those built in 2020. Therefore, the lower rate of growth in the fuel consumption in Figure 7-1,
compared to the rate of growth in demand under the central baseline (as was shown in Figure 6-2) isdue to the increased fleet penetration of the 2020-technology vessels over time. For reference, thecentral scenario demand (Figure 6-2) has an average annual growth rate between 2020 and 2050 of
2.2%, while the fuel consumption increases by 0.7% per annum on average.
A comparison of the fuel consumption under the three baseline scenarios is shown in Figure 7-2.

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Figure 7-2: Comparison of 2050 fuel consumption under three baseline scenarios

Maritime fuel consumption (Million barrels of oil equivalent)

4,500

4,000

3,500

3,000

2,500
LNG
Marine Diesel Oil (MDO)
2,000

Heavy Fuel Oil (HFO)

1,500

1,000

500

0
Low

CentralHigh

Under the central scenario, the total fuel consumption in 2050 is approximately 3,180 Mboe; thisdecreases by 29% to 2,260 Mboe under the low demand baseline, and increases by 25% to 3,960 under
the high demand baseline. The proportions of the three fuel types remain approximately constant acrossthe three baselines (because the demand is defined at a vessel type level for each of the threebaselines, there are small variations in the fuel proportions under the different baselines, but they areless than 1% across all three baselines).
As expected, the inclusion of the technology and fuels packages leads to significant changes in the fuelconsumption over time, both in terms of total consumption and the distribution across the different fueltypes. Of significance is that, under package 1, the alternative fuels adopted were split betweenhydrogen (for short-sea shipping) and ammonia (for deep-sea shipping). The reasons for the allocationof the fuels in this manner was to distinguish between vessels that (mostly) travel short distances
between ports and, hence, have frequent opportunities to refuel, and those that travel long distancesand must be able to hold sufficient fuel for a long journey. Although the difference between short-sea
and deep sea shipping is primarily associated with the nature of the vessel operation, the short-sea
operations are mostly fulfilled by smaller vessels and deep sea operations by larger vessels. The
European Community Shipowners’ Associations (ECSA) has indicated that vessels used in short-sea
operations are generally below 10,000 tonnes DWT63; the analysis presented here has adopted thesame threshold.
Using the threshold of 10,000 tonnes DWT, the demand in 2020 can be analysed to identify, under each
vessel category, the fraction of the demand (in tonne-miles) met by vessels below the threshold(classified as ‘short-sea’) and above it (classified as ‘deep sea’), as shown in Figure 7-3.

63https://www.ecsa.eu/images/NEW_Position_Papers/ECSA_SSS_Download%201.pdf

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Figure 7-3: Split of demand in 2020 by above and below 10,000 DWT, to identify short-sea and deep sea
demand2020 demand by short-sea vs. deep-sea

Maritime transport demand (109 tonne-miles)

16000

14000

12000

10000

8000

6000

Deep-sea
Short-sea

4000

2000

0

Using this threshold, the short-sea operations are met using mostly small tankers and small, medium
and large general cargo vessels, with small additional contributions from small container vessels andro-ro ships. Calculated using these allocations for package 1, and the splits defined previously for thedifferent alternative fuels under packages 2 and 3, the resulting fuel consumption under the threepackages are shown, for the central demand scenario, in Figure 7-4 to Figure 7-6. Under the threepackages, the fuel consumption in 2050 is reduced from the 3,180 Mboe of the central baseline to
between 2,000 Mboe and 2,400 Mboe, reductions of 26% to 37% relative to the baseline.

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Figure 7-4: Fuel consumption to 2050 under the central scenario for package 1
3,000

Maritime fuel consumption (Million barrels of oil equivalent)Battery powered ships
as very thin line on topof hydrogen

100% of new ships
adopt alternative fuel by
2035

Phased introduction ofalternative fuel ships
2,500

Hydrogen
2,000

LNG

MDO

1,500

Ammonia
1,000

HFO

500

0
2020

2025

2030

Heavy Fuel Oil (HFO)

2035

Marine Diesel Oil (MDO)

2040

LNG

Ammonia

2045

Hydrogen

2050

Battery

Figure 7-5: Fuel consumption to 2050 under the central scenario for package 2

Maritime fuel consumption (Million barrels of oil equivalent))

3,000
From 2020, 40% of new-build ships
LNG and 10% bio-LNG
2,500

From 2030, transition to bio-LNG
for new and existing LNG-engine
vessels

From 2025, transition to bio-diesel
for new and existing
conventionally-engined vessels

2,000

BioLNG
LNG
1,500

MDO
1,000

HVO
500

0
2020

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HFO

2025
2030
Heavy Fuel Oil (HFO)
Fatty Acid Methyl Ester (FAME)

FAME

2035

2040
2045
Marine Diesel Oil (MDO)
Hydrotreated Vegetable Oil (HVO)

2050

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Figure 7-6: Fuel consumption to 2050 under the central scenario for package 3

Maritime fuel consumption (Million barrels of oil equivalent)

3,000
Phase in from 2025 of LNG,
bioLNG, methanol and ammonia
ships

2,500

From 2030,
transition ofexisting LNG
ships to use
bioLNG

By 2035, newvessels:
40% LNG,
10% bio-LNG,
25% methanol,
25% ammonia.

2,000

Ammonia
1,500

Methanol
MDO
1,000

500

Voyageoptimisation
measuresdramaticallydecrease whole
fleet energy
demand in first 5
years

0
2020

LNG

BioLNG
HFO

2025

Heavy Fuel Oil (HFO)

2030

Marine Diesel Oil (MDO)

2035

LNG

2040

BioLNG

2045

Methanol

2050

Ammonia

Under package 1 (Figure 7-4), there is a significant drop in fuel consumption between 2020 and 2025
as the technology improvements (including the operational improvements) impact the fleet fuelefficiency. Beyond 2025, the technology improvements continue to penetrate the fleet, but they do notprovide sufficient efficiency improvements to offset the increase in demand and the total fuelconsumption begins to increase again. From 2025, there is a gradual increase in the use of alternative
fuels by the fleet, represented in package 1 by ammonia (for deep-sea vessels) and hydrogen (for shortsea vessels). Deep-sea vessels account for a greater proportion of the total maritime energy
consumption, so the consumption of ammonia is significantly greater than that of hydrogen (on anenergy basis), although there is still a considerable consumption of hydrogen by 2050. Under thispackage, by 2050, the consumption of conventional fuels (HFO and MDO) has reduced by 91% relative
to the value in 2020; at this point alternative fuels make up almost 91% of the total fuel consumption.
LNG carriers, which use LNG in the baseline scenario, are assumed to continue to use LNG under thispackage. The small growth of the use of LNG in Figure 7-4 is due to the growth in demand for thetransport of LNG. A third alternative fuel included in this package is electricity, deployed by batteryelectric vessels. The expectation is that, despite the advances in battery technology, these will still only
be used by relatively small vessels on local (generally coastal) operations. The energy consumed bybattery-electric vessels remains very small (their consumption is presented as a thin red line on top of
the other fuels).
Under this package, the pathways assumed for the hydrogen and methanol fuels change over time,
evolving from grey (fossil fuel-based), through blue (fossil fuel-based, with carbon capture during
production) to green (using renewable resources) pathways. Figure 7-7 and Figure 7-8 show how thequantities of fuel required vary between the different pathways.

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Figure 7-7: Split of hydrogen consumption under package 1 by grey, blue and green (million barrels of oil
equivalent per year)
300

Quantity of fuel consumed (Mboe per year)

250

200

150

100

50

0

Grey hydrogen

Blue hydrogen

Green hydrogen

Figure 7-8: Split of ammonia consumption under package 1 by grey, blue and green (million barrels of oil
equivalent per year)
1800

Quantity of fuel consumed (Mboe per year)

1600

1400

1200

1000

800

600

400

200

0

Grey ammonia

Blue ammonia

Green ammonia

For both of these fuels, the demand is quite small during the period that only grey fuel is available, As
demand picks up, the fuel supply also transitions to blue fuel, leading to a larger total demand for blue
fuel than grey fuel, even though the blue fuel transitions to green in a relatively short timeframe. The
demand for the green fuels is then considerable, leading to annual demands for green hydrogen andRicardo Confidential

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ammonia in 2050 of about 280 and 1,710 Mboe, respectively. The transition from blue fuel to green fuelwill result in increased fuel costs for vessel operators; the inclusion of this transition in the modelling,based around the lower GHG emissions, assumes some form of driver for this transition, most likely
regulatory.
Under package 2 (Figure 7-5), there is a slightly greater reduction in fuel consumption from 2020 to2025, but with an expanding use of LNG and BioLNG fuel, as specified in the definition of the package.
From 2025 onwards, the liquid biofuels (FAME and HVO) start to replace conventional fuels on a dropin basis, and LNG and BioLNG further increase their contribution. By 2030, the consumption of
conventional fuels (HFO and MDO) has reduced by 62% relative to 2020, with alternative fuels(including LNG) now representing 53% of total fuel consumption. From 2030 onwards, BioLNG starts tocompletely replace the remaining LNG and, similarly, FAME and HVO replace the remaining HFO andMDO so that, by 2050, 100% of fuel consumption is alternative.
Under package 3 (Figure 7-6), the fuel consumption in the early years after 2020 is impacted by thehigher penetration of vessel and operational technologies under this package. By 2025, theconsumption of conventional fuels has decreased by 35% relative to 2020. This is a significant reduction
in a short timeframe and depends on a widespread adoption of the operational measures, particularly
slow steaming and vessel capacity utilisation. Although both measures are already adopted to someextent, strong policy signals and coordinated action would be likely to be required to achieve suchsignificant changes in a short time. By 2050, the total fuel consumption is 37% lower than in the baseline
case. However, this package includes the use of carbon capture technology on vessels using carboncontaining fuels, with an associated 20% fuel consumption increase. Without that fuel consumption
increase, the fuel consumption under package 3 would be 45% lower than the baseline case (but would
not have the same level of CO2 reduction as can be achieved with the carbon capture).
Similarly to package 1, the split of methanol and ammonia fuel demand by pathway is shown in Figure
7-9 and Figure 7-10.

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Figure 7-9: Split of methanol consumption under package 3 by grey and green (million barrels of oil
equivalent per year)
450

Quantity of fuel consumed (Mboe per year)

400

350

300

250

200

150

100

50

0

Grey methanol

Green methanol

Figure 7-10: Split of ammonia consumption under package 3 by grey, blue and green (million barrels of oil
equivalent per year)
450

Quantity of fuel consumed (Mboe per year)

400

350

300

250

200

150

100

50

0

Grey ammonia

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Green ammonia

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A comparison of the different fuel splits for the three packages, and the baseline case, under the central
demand scenario, aggregated over the 2020 to 2050 period, is shown in Figure 7-11.
Figure 7-11: Fuel demand per fuel and technology package by fuel type for central demand scenario(cumulative 2020-2050)

500
450

466
26
370

Energy consumption to 2050 (EJ)

400

123
350

359

0.2
20
49

300

116

49

250

20

72

200

54

317

30
27
47

49

154
50

97

FAME
Battery
HydrogenAmmonia

BioLNG
LNG
MDO
HFO

38

100

Methanol
HVO

25

60
150

305

127

0
Baseline

Package 1

Package 2

Package 3

7.2 Emissions
Whilst the previous subsection has commented on the fuel consumption impacts of the packages, thekey focus of this study is on measures to reduce greenhouse gas emissions from maritime transport to2050. The CO2e emissions to 2050 under the three baseline scenarios were presented in Figure 6-9.
The trajectories to 2050 range from a small reduction relative to 2020 under the low baseline scenario
to a 53% increase under the high scenario. As was shown in Figure 6-9, the achievement of the IMO
ambition for 2050 implies reductions of between 380 Mtonnes and 1,080 Mtonnes CO2e in 2050,
depending on the growth scenario assumed.
To present the trajectories in CO2e emissions under the three packages, it is important to consider the
production pathways assumed for the fuels. A “green” alternative fuel (produced using renewableenergy, for example) will give considerably greater reductions in total emissions than a “grey” fuel (analternative fuel produced from fossil fuel feedstock). Accordingly, the following charts show theemissions under the three packages, presenting both the CO 2e emissions from the ship itself (known
as tank-to-wake, or TTW) and the full emissions including those from the fuel production (well-to-wakeor WTW).

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Figure 7-12: Total CO2e emissions (TTW and WTW) to 2050 under package 1CO2e emissions to 2050 under Technology Package 1 for three demand scenarios
1,600

Maritime CO2e emissions (Mtonnes per year)

1,400

Adoption of alternative
fuels from 2025 onwards

Energy efficiency
measures included in all
new-build ships by 2025

1,200

1,000
~ 540Mt CO2eemissions target
achieved in all cases

800

600

400

200

0
2015

2020

2025

2030

2035

2040

2045

2050

Low - TTW CO2e

Central - TTW CO2eHigh - TTW CO2e

Low - WTW CO2e

Central - WTW CO2eHigh - WTW CO2e

2055

Figure 7-13: Total CO2e emissions (TTW and WTW) to 2050 under package 2CO2e emissions to 2050 under Technology Package 2 for three demand scenarios
1,600

Maritime CO2e emissions (Mtonnes per year)

1,400

Transition of whole fleet to biofuels from2040 onwards.
Decoupling of tailpipe CO2e emissions
from WTW due to use of biofuels

Energy efficiency
measures included in all
new-build ships by 2025

1,200

1,000

800

600

~ 540Mt CO2e target
not achieved in terms of
TTW* emissions

400

200

0
2015

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2025

2030

2035

2040

2045

2050

Low - TTW CO2e

Central - TTW CO2eHigh - TTW CO2e

Low - WTW CO2e

Central - WTW CO2eHigh - WTW CO2e

2055

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Figure 7-14: Total CO2e emissions (TTW and WTW) to 2050 under package 364
CO2e emissions to 2050 under Technology Package 3 for three demand scenarios
1,600

Maritime CO2e emissions (Mtonnes per year)

1,400

From 2025 gradual introduction of LNG,
bioLNG, ammonia and methanol

Energy efficiency
measures included in all
new-build ships by 2025

From 2040, transition in production
pathway for ammonia and methanol togreen alternatives, all LNG transitioned
to bioLNG

1,200

1,000
~ 540Mt CO2eemissions target
achieved in all cases

800

600

400

200

0
2015

2020

2025

2030

2035

2040

2045

2050

2055

-200
Low - TTW CO2e

Central - TTW CO2eHigh - TTW CO2e

Low - WTW CO2e

Central - WTW CO2eHigh - WTW CO2e

Under package 1, the TTW and WTW emissions follow broadly similar trends , with a gradual reduction
from current levels to significantly lower levels by 2050, under all three baseline demand scenarios. The
WTW emissions show an increase in the period from 2025 to 2030, as “grey” alternative fuels start tobe used (with relatively high WTT emissions). As these grey fuels are replaced by blue and then green
variants, the WTW emissions reduce towards the low levels in 2050. Under this package, the global
emissions in 2050 are less than 200 Mtonnes CO2e, less than half of the ambition of the IMO65.
Under package 2, the TTW emissions are reduced relative to the baseline by the use of the technologies
and the alternative fuels (particularly methane, in the form of LNG and BioLNG) by over 31% undereach of the three baseline demand scenarios. However, this is limited by the fuels employed all being
carbon-containing (and hence producing CO2e emissions on combustion), together with some methane
slip when using LNG or BioLNG, and hence insufficient to meet the IMO ambition in each case. Viewing
the results from a WTW perspective, however, provides significantly greater reductions, as the CO 2
emissions produced on combustion are offset to a large extent by the absorption of CO 2 during theirproduction, giving low WTW emissions. This could alternatively be summarised as fuels being ‘CO2
neutral’ in package 2, rather than the ‘zero carbon’ fuels in package 1. From this perspective, the global
WTW CO2e emissions in 2050 are between 170 and 300 Mtonnes, well under the IMO ambition under
all three baseline demand scenarios.
The results for package 3 show reductions in TTW emissions similar to those from package 1 by 2050.
As noted above, under this package the reduction achieved in fuel consumption through vessel
technologies is offset partially by the fuel consumption increase due to the use of carbon capture

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Negative emissions occur by 2050 on a WTW basis, due to the use of green carbon-containing fuels (with the caron content having been captured
from the atmosphere during production), combined with on-board carbon capture technology that removes most of the CO2 from the ship’s exhaust.
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As specified, the IMO ambition relates to the exhaust emissions from the ships, rather than the full well-to-wake emissions associated with thefuels consumed. However, as the supply of alternative fuels transitions towards a greater degree of renewability (green fuels), much of the additional
benefit is seen in the WTT emissions. Therefore, in this study, the results of the calculations for both TTW and WTW are compared to the IMO
ambition.

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technology on-board ships. The CO2e emissions show much stronger reductions as much of theemission is captured by this technology. When considering WTW emissions, the achievement of small
negative net emissions can be seen under each of the baseline demand scenarios. This is caused by
the low WTT emissions of the green fuels, combined with the capture of the CO 2 emissions from thecarbon-containing fuels (BioLNG and green methanol) from the ship exhaust. Overall, the process
results in a net capture of CO2 from the atmosphere through the complete fuel production andcombustion process.
As noted previously, the IMO ambition on CO2 emissions is framed as a 50% reduction relative to 2008
levels by 2050. For comparison with this ambition, Table 7-1 shows the changes in emissions in 2030
and 2050 relative to 2008 levels for each of the packages under each baseline scenario. Also included
are the baseline results; for these, and the TTW results for package 2 in 2050, there is an increase inemissions relative to 200866.
Table 7-1: Changes in CO2e WTW emissions relative to 2008 (TTW values in parentheses)

Baseline

Package 1

Package 2

Package 3

Low scenario
2030

9% (4%)-13% (-25%)-39% (-25%)-33% (-37%)2050

4% (-2%)-80% (-88%)-84% (-39%)-99% (-77%)2030

22% (16%)-2% (-17%)-31% (-17%)-25% (-31%)2050

46% (39%)-74% (-85%)-77% (-13%)-101% (-69%)2030

30% (24%)

4% (-13%)-26% (-12%)-21% (-27%)2050

82% (73%)-70% (-83%)-71% (8%)-103% (-63%)

Central scenario

High scenario

The results show that all three packages meet the IMO ambition on a WTW basis in 2050, with package
3 showing reductions of over 100%, indicating a net absorption of CO 2, as described above. Packages
1 and 2 show reductions of over 80% under the low scenario and 74% or 77% under the central
scenario. Under the high scenario, the emissions reduction under package 1 remains above 80%, butthat for package 2 reduces to 70%.
Table 7-1 also includes the emissions reductions calculated on a TTW basis. For some cases,
particularly under package 2, these show considerably lower reductions than on the WTW basis as thefuels contain carbon and much of the overall reduction occurs in the fuel production phase.
Figure 7-15 compares the CO2e emissions on a WTW basis between the baseline and three packages
under the central demand scenario, with results shown for 2030 and 2050. Reductions are evident for
the three packages in 2030, but the most significant reductions do not appear until 2050, when the fulltransition to alternative fuels (particularly green fuels) is achieved.

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For these comparisons, the WTW emissions values for 2008 were derived from the TTW values (as reported in the IMO Third Greenhouse Gas
Study (International Maritime Organization, 2014)) were factored by the same WTW and TTW emissions factors for HFO as used in the calculations
being reported here. For both WTW and TTW emissions, the 2008 emissions from the IMO report were scaled up for consistency with thecalculations described in this report.

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Figure 7-15: WTW CO2e emissions intensity in 2030 and 2050 for the baseline and three packages under
the central scenario
International CO2e (WTW) emissions intensity (emissions per tonne-mile) under Baseline andTechnology Packages in 2030 and 2050
18.0International CO2 emissions intensity (g/tonne-mile)

16.0

14.0

12.0

10.0
Baseline CO2e (WTW)
Package 1 CO2e (WTW)

8.0

Package 2 CO2e (WTW)
Package 3 CO2e (WTW)

6.0

4.0

2.0

0.0

2030

2050

-2.0

In addition to the overall CO2 (including CO2e) results, an important parameter for the maritime industry
is the carbon intensity, expressed as grams of CO2 emitted per tonne-mile transported. Table 7-2 shows
the changes relative to 2008 levels, again including both WTW and TTW values. The carbon intensity
values were calculated using the emissions for 2008, published in the IMO third greenhouse gas study(International Maritime Organization, 2014), combined with demand values for the same year publishedin the International Transport Forum’s Transport Outlook (International Transport Forum, 2019). Under
the baseline cases, despite the assumption of a technology freeze for new ships at 2020 levels,
reductions in carbon intensity of over 50% are achieved by 2050, as a result of the latest technology
vessels contributing a greater part of the fleet; these are, however, short of the initial IMO strategy targetof 70%. Under the fuel and technology packages, with the additional technologies and the alternative
fuels, the reductions achieved by 2050 are all over 90% relative to 2008 on a WTW basis. On a TTW
basis, package 1 also exceeds 90% reductions by 2050, with package 3 approaching the same
threshold; package 2 barely meets the initial IMO strategy target of 70%.
Table 7-2: Changes in CO2e WTW emissions intensity relative to 2008 (TTW values in parentheses)

Baseline

Package 1

Package 2

Package 3

Low scenario
2030-41% (-44%)-53% (-59%)-67% (-59%)-63% (-66%)

2050-53% (-56%)-91% (-94%)-93% (-72%)-100% (-90%)2030-38% (-41%)-50% (-58%)-65% (-57%)-62% (-65%)

2050-48% (-51%)-91% (-95%)-92% (-69%)-100% (-89%)2030-38% (-41%)-50% (-58%)-65% (-58%)-62% (-65%)

2050-49% (-51%)-91% (-95%)-92% (-70%)-101% (-89%)

Central scenario

High scenario

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The results presented above show significant reductions in emissions to 2050 through the impacts ofthe changes in fuels and technologies under the three packages. Figure 7-16 to Figure 7-18 show thecontributions of vessel technologies and fuels to the reductions achieved and how these vary over time.
For Package 3 (Figure 7-18), the contribution of carbon capture is separated out from the othertechnologies.
Figure 7-16: Contributions of technology and fuels to WTW emissions reductions under Package 1
WTW CO2e emissions - contribution of technology and fuels - Central scenario - Package 1
1600

WTW CO2e emissions (million tonnes)

1400

1200

1000

Package 1 Fuel800

Package 1 Technology only
Baseline

600

400

200

2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

0

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Figure 7-17: Contributions of technology and fuels to WTW emissions reductions under Package 2
WTW CO2e emissions - contribution of technology and fuels - Central scenario - Package 2
1600

WTW CO2e emissions (million tonnes)

1400

1200

1000

Package 2 Fuel800

Package 2 Technology only
Baseline

600

400

200

2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

0

Figure 7-18: Contributions of technology and fuels to WTW emissions reductions under Package 3
WTW CO2e emissions - contribution of technology and fuels - Central scenario - Package 3
1600

1400

WTW CO2e emissions (million tonnes)

1200

1000

Package 3 CCS

800

Package 3 Fuel
Package 3 Technology only

600

Baseline

400

200

2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

0

-200

For each chart, the emissions under the central baseline are shown as a black line close to the top of
the chart. The emissions reductions are then represented by the shaded areas below that line. Undereach package, the contribution of technology, largely operational measures, is dominant in the initial

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years, followed by a steady increase in the reduction due to technology, but a more rapid rise in the
reduction due to alternative fuels. Under Package 3, the contribution of on-board carbon capture toemissions reductions also increases noticeably from 2025 onwards. Under this package, the emissions
reductions delivered by technology and fuels (i.e. excluding carbon capture) in 2050 is slightly greaterthan that delivered under Package 1. This would suggest that the more cost-effective technologies
implemented in Package 1 deliver nearly all the improvements available from the technologies
identified. The percentage contributions to the emissions reductions achieved in 2050 are compared
for the three packages in Table 7-3.
Table 7-3: Percentage contributions to total TTW CO2e emissions reduction by technology and fuel for thethree packages

Package 1

Package 2

Package 3

Technology

31%

34%

44%

Fuel

69%

66%

40%

Carbon Capture

-

-

16%

Under Packages 1 and 2, the splits of the contributions between technology and fuels is broadly similar
at one third / two thirds. For Package 3, the contribution from technology and carbon capture increases,
with a commensurate reduction in the contribution from fuel.

7.3 Costs associated with the fuel and technology packages
The evolution of the calculated costs under the central baseline, separated by fuel costs, operating costs(excluding fuel) and capital costs, are shown in Figure 7-19.
Figure 7-19: Annualised costs under the central baseline scenario
Annualised costs under central demand baseline scenario$1,000,000$900,000$800,000

Annual costs ($ millions)$700,000$600,000$500,000$400,000$300,000$200,000$100,000$0

Fuel Cost

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CAPEX New Ship

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The operating costs include port charges, canal dues, cargo handling, crew, stores, lubricants,
maintenance, insurance, and administration costs. The capital costs include the capital costs of newships by ship category as well as the capital costs of the additional technologies applied (e.g. carbon
capture). Under this baseline, the total costs for the sector are forecast to increase by approximately
30% between 2020 and 2050, driven primarily by the increased transport demand in the forecast. In
2020, operating costs (excluding fuel) account for fuel costs account for approximately 72% of annual
costs with fuel costs accounting for approximately 27%. Capital costs (annualised) account for less than
1% of total costs. These percentage splits remain approximately constant through to 2050 under thisbaseline scenario.
For comparison, Figure 7-22 to Figure 7-22 show the evolution of the calculated costs under Packages
1 to 3 applied to the same baseline.
Figure 7-20: Annualised costs under Package 1 on the central demand baseline
Annualised costs under central demand baseline scenario, package 1 fuels and technologies$1,000,000$900,000$800,000

Annual costs ($ millions)$700,000$600,000$500,000$400,000$300,000$200,000$100,000$0

Fuel Cost

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CAPEX New Ship

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Figure 7-21: Annualised costs under Package 2 on the central demand baseline
Annualised costs under central demand baseline scenario, package 2 fuels and technologies$1,000,000$900,000$800,000

Annual costs ($ millions)$700,000$600,000$500,000$400,000$300,000$200,000$100,000$0

Fuel Cost

OPEX (excl fuel)

CAPEX New Ship

Figure 7-22: Annualised costs under Package 3 on the central demand baseline
Annualised costs under central demand baseline scenario, package 3 fuels and technologies$1,000,000$900,000$800,000

Annual costs ($ millions)$700,000$600,000$500,000$400,000$300,000$200,000$100,000$0

Fuel Cost

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CAPEX New Ship

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All three packages show total costs having a greater increase to 2050 (up to 116% increase over 2020
for Package 3) than the baseline. The operating costs (excluding fuel) increase by a slightly greater
amount for package 3 than under the baseline, but the fuel costs increase significantly, reaching 41%of the total costs by 2050. For this package, the increase in the capital costs is very evident, reaching
12% of the total costs by 2050. In contrast, packages 1 and 2 show only marginal increases in capitalcosts.
Figure 7-23 to Figure 7-25 show the change in annualised costs for each of the three packages relative
to the central baseline.
Figure 7-23: Change in annualised costs relative to the central baseline for Package 1
Change in annualised costs relative to baseline, package 1 fuels and technologies(central demand baseline) - undiscounted$250,000

Change in annual costs ($ millions)$200,000$150,000$100,000$50,000$0-$50,000

Fuel Cost

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Figure 7-24: Change in annualised costs relative to the central baseline for Package 2
Change in annualised costs relative to baseline, package 2 fuels and technologies(central demand baseline) - undiscounted$300,000

Change in annual costs ($ millions)$250,000$200,000$150,000$100,000$50,000$0-$50,000

Fuel Cost

OPEX (excl fuel)

CAPEX New Ship

Figure 7-25: Change in annualised costs relative to the central baseline for Package 3
Change in annualised costs relative to baseline, package 3 fuels and technologies(central demand baseline) - undiscounted$250,000

Change in annual costs ($ millions)$200,000$150,000$100,000$50,000$0-$50,000-$100,000

Fuel Cost

OPEX (excl fuel)

CAPEX New Ship

Under each package, the early improvements in vessel efficiency, mainly driven by operational
measures, lead to an initial reduction in fuel costs. The fuel costs subsequently rise (to be substantiallygreater than the baseline) as alternative fuels, particularly the ‘green’ variants, are adopted. The

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operating costs (excluding fuel) also show a small rise above the baseline out to 2050. Under Packages
1 and 2, the capital costs also show a small increase over the baseline as the result of the adoption of
new technologies on new vessels; this increase is substantially greater under Package 3 due to thefocus of that package on the early adoption of new vessel technologies.
Total costs have been calculated by summing the fuel costs, operating costs and capital costs of newships and new technologies over a period of 30 years, with discounting of future costs applied to derive
net present values (NPV). The primary discount rate applied here is 10%, reflecting an industry focusof the cost analysis; additional results are also presented for a discount rate of 5%, reflecting a public
sector focus.
Table 7-4 shows the results of the total costs for the baseline package and the three fuel and technology
packages at various discount rates under the central demand scenario. Results for package 2 show thehighest costs compared to the baseline while package 1 shows the lowest costs compared to thebaseline scenario.
Table 7-4: Net present values (2020-2050) of total costs by package for the central demand scenario

Baseline

Package 1

Package 2

Package 3($ billion)($ billion)($ billion)($ billion)

10%

5,539

5,774

6,027

5,720

5%

8,912

9,764

10,2489,713

Discount rate

Table 7-5 shows the breakdown of the changes in NPV by fuel and technology package compared tothe baseline by cost component. The fuel costs are calculated using the fuel prices shown in Table 6-5.
Table 7-5: Changes in NPV by fuel and technology package relative to the baseline at 10% and 5% discountrates for the central demand scenario

Package

Fuel cost

OPEX (exc. Fuel ) CAPEX($ billion)($ billion)

Total change in
NPV($ billion)($ billion)

10% discount rate
Package 1

+113

+83

+39

+235

Package 2

+364

+91

+34

+489

Package 3

-186

-46

+413

+181

Package 1

+517

+260

+75

+852

Package 2+1,024+246+66+1,336

Package 3

-47

-23

+871

+800

5% discount rate

The outcome of the total costs for the three packages show increases in total costs of between 4% (forPackage 1) and 9% (for Package 2) of the baseline value (when discounted at 10%). The fuel priceassumptions for packages 1 and 2 through to 2050 are the key determinants of the package total costs67,
while the capital cost assumptions in package 3 is the driving force behind its total costs. This is
illustrated for the 10% discount rate results in Figure 7-26.

67

It is worth noting that the results for package 2 are sensitive to the price assumption for BioLNG; as noted in Section 6.2.1, this was derived
slightly differently from most other fuels as IHS Markit did not provide a price projection for it

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Figure 7-26: Change in NPV at 10% discount rate by fuel and technology package for the central demand
scenario compared to the baseline

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Figure 7-27 shows how the fuel costs for each package are built up from the fuel mix. The volumes offuel needed in each package was shown in section 7.1. The high fuel cost change in package 2 can bemainly attributed to the high proportion of Bio LNG, FAME and HVO and their anticipated high prices.
Figure 7-27: Net present value of aggregated fuel costs from 2020 to 2050 per package by fuel type forcentral demand scenario

Net present value (discount rate 10%) of fuel cost to 2050($ Billion)$2,5002002$2,000

1638

59

302

1750

131

Methanol$1,500

477

1452

HVO
FAME

411

93
102
219
58

292

MDO

431
48

$1,000

268

341

138
262

$500

HydrogenAmmonia
BioLNG
LNG
HFO

1103

799

621

688

Package 2

Package 3$0Baseline

Package 1

7.4 Cost-effectiveness of the fuel and technology packages
As described in section 7, and in particular as illustrated in Figure 7-12, Figure 7-13 and Figure 7-14 forthe three packages respectively, the CO2 and CO2e emissions can be compared to the baseline (onboth a TTW and WTW basis) for each package. The differences divided by the total discounted costs
provide then the cost-effectiveness for each fuel and technology package in $/tonneCO2e. The results
for the default calculation based on discounting both the costs and the emissions savings (using savings
in WTW CO2e) are shown in Table 7-6.
Table 7-6: Net present value of cost-effectiveness of the three different packages to 2050 ($/tonneCO2e)

10% discount rate

5% discount rate

Package 1

$73

$120

Package 2

$113

$149

Package 3

$39

$83

Package 2 is the least cost-effective (highest cost per tonne CO2e) under both discount rates, withpackage 3 being the most cost-effective.

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For comparison, the IMO fourth GHG study (IMO, 2020) presents higher values for the marginal
abatement costs in 2050, with values of about $260/tonne CO 2e and $410/tonneCO2e, depending on
the scenario. These values differ from those presented in this report in that they are for 2050 (rather
than cumulative to 2050) and are undiscounted. For the technology and fuel packages presented here,
the undiscounted cost-effectiveness values (cumulative to 2050) are approximately $160/tonneCO2e
for package 1, $180/ tonneCO2e and $130/tonneCO2e for package 3.

7.4.1 Sensitivity calculations
In addition to the “default” calculation, using WTW CO 2e and with both costs and emissions savings
discounted at the same rate (emissions savings are discounted to reflect the additional benefits on
short-term reductions relative to the longer-term), additional sensitivity cases have also been calculated,to reflect alternative views on the application of discounting to emissions savings and on the use of TTW
or WTW emissions. These sensitivity cases are defined in Table 7-7.
Table 7-7: Definition of sensitivity cases for cost-effectiveness calculations

Case

Emissions calculation

Discounting applied toemissions?

Default

WTW

Yes

Sensitivity 1

WTW

No

Sensitivity 2

TTW

Yes

Sensitivity 3

TTW

No

The changes in emissions and costs for these sensitivity cases are shown, for a discount rate of 10%,in Table 7-8.
Table 7-8: Changes in CO2e and cost by package for central demand scenario, including sensitivity cases

Emissions scope(change in CO2e)

Discount rate applied
to emissions

Changes in CO2e emissions

Package
1

Package
2

Package
3

(Mt)

(Mt)

(Mt)

Default

WTW

10%

3,202

4,312

4,680

Sensitivity 1

WTW

N/A

18,62621,98423,762

Sensitivity 2

TTW

10%

3,131

2,358

3,822

Sensitivity 3

TTW

N/A

17,85910,34917,978($ billion)($ billion)($ billion)

235

489

181

Discounted costs (change in NPV)
Change in Total Cost
(NPV)

10%

Combining the costs and emissions savings presented in Table 7-8 gives the cost-effectiveness values
shown in Table 7-9.

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Table 7-9: Cost-effectiveness for central demand scenario, including sensitivity cases

Emissionsscope(CO2e)

Discount rateapplied toemissionsDefault

WTW

Sensitivity 1

Package 1($/tonneCO2e)

Package 2($/tonneCO2e)

Package 3($/tonneCO2e)

10%

$73

$113

$39

WTW

N/A

$13

$22

$8

Sensitivity 2

TTW

10%

$75

$207

$47

Sensitivity 3

TTW

N/A

$13

$47

$10

Package 2 consistently has the highest calculated abatement costs overall. This highlights the fact that
BioLNG, HVO and the use of FAME through to 2050 is costly and only slightly more effective on carbon
reductions than Package 1 (on a WTW basis). The sensitivity cases with the emissions savings notdiscounted show lower cost-effectiveness values (by a factor of about 5 for each package when
considering WTW emissions), but do not impact the relative magnitude of the results for the threepackages.
As Figure 7-28 shows, the highest abatement cost is reflected in package 2 at $113 per tonneCO2(WTW). Package 3 is the least costly package (Figure 7-26) and the abatement costs for this package
are $39 per tonne CO2e (WTW) for the central demand scenario. Note that all analysis above is basedon a 10% discount rate and the cost-effectiveness would increase at lower discount rates and vice versa
for higher discount rates. The changes in NPV results for the various discount rates are shown in Table
7-5 above.

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Figure 7-28: Cost-effectiveness of each package (as $/tonneCO2 WTW abated, both 10% discount rate),
central demand scenario

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7.5 Fuel and technology sensitivity analysis results
7.5.1 Fuel and emissions calculations
As noted in Section 5.2.4, additional sensitivity analyses were performed to provide further insight into
the changes in emissions and costs due to the technologies and fuels, and to enable an easiercomparison of the differences due to the different fuel assumptions between the packages. Thesesensitivity analyses applied the technology assumptions from Package 3 (including the use of on-board
carbon capture) with the fuel assumptions from Package 1 (forming Package 1A) and Package 2(forming Package 2A).
The calculated fuel consumption from 2020 to 2050 under the central demand scenario is shown foreach sensitivity package in Figure 7-29 to Figure 7-31, with a summary of the cumulative total, split bypackage and fuel type, in Figure 7-32. Like other figures in this section, the results for Package 3 (Figure7-31) are unchanged from those presented earlier in the report.
Figure 7-29: Fuel consumption to 2050 under the central scenario for Package 1A
3,000
100% of new ships
adopt alternative fuel by
2035

Maritime fuel consumption (Million barrels of oil equivalent)

Phased introduction ofalternative fuel ships
2,500

Battery powered ships
as very thin line on topof hydrogen

2,000

Hydrogen
1,500

MDO

LNG

Ammonia

1,000

HFO

500

0
2020

2025

Heavy Fuel Oil (HFO)

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Marine Diesel Oil (MDO)

2035

LNG

2040

Ammonia

2045

Hydrogen

2050

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Figure 7-30: Fuel consumption to 2050 under the central scenario for Package 2A

Maritime fuel consumption (Million barrels of oil equivalent))

3,000
From 2020, 40% of new-build ships
LNG and 10% bio-LNG

From 2030, transition to bio-LNG
for new and existing LNG-engine
vessels

2,500
From 2025, transition to bio-diesel
for new and existing
conventionally-engined vessels

2,000

LNG

BioLNG

1,500

MDO

LNG

1,000

HVO
HFO

500

0
2020

FAME

2025
2030
Heavy Fuel Oil (HFO)
Hydrotreated Vegetable Oil (HVO)

2035
Marine Diesel Oil (MDO)
LNG

2040

2045
2050
Fatty Acid Methyl Ester (FAME)BioLNG

Figure 7-31: Fuel consumption to 2050 under the central scenario for Package 3

Maritime fuel consumption (Million barrels of oil equivalent)

3,000
Phase in from 2025 of LNG,
bioLNG, methanol and ammonia
ships

2,500

From 2030,
transition ofexisting LNG
ships to use
bioLNG

By 2035, newvessels:
40% LNG,
10% bio-LNG,
25% methanol,
25% ammonia.

2,000

Ammonia
1,500

Methanol
MDO
1,000

500

Voyageoptimisation
measuresdramaticallydecrease whole
fleet energy
demand in first 5
years

0
2020

LNG
HFO

2025

Heavy Fuel Oil (HFO)

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2030

Marine Diesel Oil (MDO)

2035

LNG

2040

BioLNG

2045

Methanol

2050

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Figure 7-32: Fuel demand per fuel and technology package by fuel type for central demand scenario(cumulative 2020-2050)
500

466
26

450

Energy consumption to 2050 (EJ)

400

123
350

300
250

295

308

305

0.1
14

43

88

43

30
27

16

62

200

317

150

49

44

47
25
49

Methanol
HVO
FAME
Battery
HydrogenAmmonia

BioLNG
LNG
MDO
HFO

33

100

127

127

50

84

0
Baseline

Package 1A

Package 2A

Package 3

Compared to the main calculation (Figure 7-11), the fuel consumption reduces from 370 EJ (Package1) to 295 EJ (Package 1A) and from 359 EJ (Package 2) to 308 EJ (Package 2A). The fuel consumption
for Package 3 is unchanged.
Although Packages 1A, 2A and 3 all implement the same vessel technology and operational
assumptions, there are small differences in the fuel (energy) consumption. This results from theinclusion of on-board carbon capture in each package. The different packages include different
proportions of carbon-containing and zero-carbon fuels; on-board carbon capture is not used on vessels
fuelled by zero-carbon fuels, so the energy consumption penalty associated with it is applied to different
proportions of the fleet. There is, therefore, a greater use of carbon capture in Package 2A than Package
3 and, similarly, a greater use in Package 3 than Package 1A.
The CO2e emissions profiles to 2050 under the three packages are shown in Figure 7-33 to Figure 7-35.

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Figure 7-33: Total CO2e emissions (TTW and WTW) to 2050 under package 1A
CO2e emissions to 2050 under Technology Package 1A for three demand scenarios
1,600

Maritime CO2e emissions (Mtonnes per year)

1,400

Adoption of alternative
fuels from 2025 onwards

Energy efficiency
measures included in all
new-build ships by 2025

1,200

1,000

800

~ 540Mt CO2eemissions target
achieved in all cases

600

400

200

0

-200
2015

2020

2025

2030

2035

2040

2045

2050

Low - TTW CO2e

Central - TTW CO2eHigh - TTW CO2e

Low - WTW CO2e

Central - WTW CO2eHigh - WTW CO2e

2055

Figure 7-34: Total CO2e emissions (TTW and WTW) to 2050 under package 2A

CO2e emissions to 2050 under Technology Package 2A for three demand scenarios
1,600

Maritime CO2e emissions (Mtonnes per year)

1,400

Transition of whole fleet to biofuels from2040 onwards.
Decoupling of tailpipe CO2e emissions
from WTW due to use of biofuels

Energy efficiency
measures included in all
new-build ships by 2025

1,200

1,000

800
~ 540Mt CO2eemissions target
achieved in all cases

600

400

200

0

-200
2015

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2020

2025

2030

2035

2040

2045

2050

Low - TTW CO2e

Central - TTW CO2eHigh - TTW CO2e

Low - WTW CO2e

Central - WTW CO2eHigh - WTW CO2e

2055

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Figure 7-35: Total CO2e emissions (TTW and WTW) to 2050 under package 3

CO2e emissions to 2050 under Technology Package 3 for three demand scenarios
1,600

Maritime CO2e emissions (Mtonnes per year)

1,400

From 2025 gradual introduction of LNG,
bioLNG, ammonia and methanol

Energy efficiency
measures included in all
new-build ships by 2025

From 2040, transition in production
pathway for ammonia and methanol togreen alternatives, all LNG transitioned
to bioLNG

1,200

1,000
~ 540Mt CO2eemissions target
achieved in all cases

800

600

400

200

0

-200
2015

2020

2025

2030

2035

2040

2045

2050

Low - TTW CO2e

Central - TTW CO2eHigh - TTW CO2e

Low - WTW CO2e

Central - WTW CO2eHigh - WTW CO2e2055

Under these sensitivity assumptions of maximising the energy efficiency technology uptake, all threepackages are estimated to meet the IMO ambition on a TTW basis by 2050. Packages 2A and 3 show
negative WTW emissions by 2050 as they are using low-carbon fuels combined with carbon capture in
the vessel exhaust. Package 1A does not achieve the negative emissions as, by 2050, the fuel used is
predominantly zero-carbon, so there is little use and, consequently, little benefit from on-board carbon
capture (leading to the lower energy consumption in Figure 7-32). The cost analyses do not apply thecosts of carbon capture systems on vessels using zero-carbon fuels, so the overall vessel costs arealso lower under this package.
The changes in WTW and TTW CO2e emissions from 2008 to 2030 and 2050 are shown, for thebaseline and packages 1A, 2A and 3 under the low, central and high demand scenarios, in Table 7-10.
Table 7-10: Changes in CO2e WTW emissions relative to 2008 (TTW values in parentheses)

Baseline

Package 1A

Package 2A

Package 3

Low scenario
2030

9% (4%)-31% (-41%)-51% (-39%)-33% (-37%)2050

4% (-2%)-87% (-93%)-110% (-71%)-99% (-77%)2030

22% (16%)-24% (-35%)-45% (-33%)-25% (-31%)2050

46% (39%)-83% (-91%)-115% (-61%)-101% (-69%)2030

30% (24%)-19% (-31%)-41% (-29%)-21% (-27%)2050

82% (73%)-80% (-90%)-119% (-52%)-103% (-63%)

Central scenario

High scenario

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By 2050, all three (sensitivity) packages meet the IMO ambition of a 50% reduction in emissions relative
to 2008 with a significant margin on both a TTW and WTW basis under the low and central demand
scenarios. Under the high demand scenario, packages 2A and 3 meet the 50% reduction ambition by asmall margin on a TTW basis, but a significant margin on a WTW basis. The use of different fuels under
the three packages continues to give different emissions reductions, but the spread across the threepackages on a TTW basis is significantly lower than in the main analysis (comparing to the results inTable 7-1).
Table 7-11 similarly shows the changes in emissions intensity relative to 2008 for the baseline and three
sensitivity packages under each demand scenario.
Table 7-11: Changes in CO2e WTW emissions intensity relative to 2008 (TTW values in parentheses)

Baseline

Package 1A

Package 2A

Package 3

Low scenario
2030-41% (-44%)-63% (-68%)-73% (-67%)-63% (-66%)

2050-53% (-56%)-94% (-97%)-104% (-87%)-100% (-90%)2030-38% (-41%)-61% (-67%)-72% (-66%)-62% (-65%)

2050-48% (-51%)-94% (-97%)-105% (-86%)-100% (-89%)2030-38% (-41%)-61% (-67%)-72% (-66%)-62% (-65%)

2050-49% (-51%)-94% (-97%)-105% (-86%)-101% (-89%)

Central scenario

High scenario

By 2050, all three packages show reductions of over 90% on a WTW basis and of over 85% on a TTW
basis. In 2030, the reductions are lower, but still exceed 60% relative to 2008 on both a WTW and TTW
basis.
Figure 7-36 shows the reductions in WTW emissions associated with technology, fuels and carbon
capture systems under packages 1A, 2A and 3; Table 7-12 then summarises the percentage
contributions in TTW emissions in 2050. As expected from the previous results, carbon capture provides
only a small contribution to the emissions reductions under Package 1A (as the majority of new vessels
use zero-carbon fuels by this time), with technology and fuel having an approximately even contribution
to the emissions reductions. Under packages 2A and 3, carbon capture contributes about 20%, withtechnology and fuels again having an approximately even split of the remaining reductions.

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Figure 7-36: Contributions of technology (blue), fuels (green) and carbon capture (orange) to WTWemissions reductions under Package 1A (top), 2A (middle) and 3 (lower) from the baseline
WTW CO2e emissions - contribution of technology and fuels - Central scenario - Package 1A
1600

WTW CO2e emissions (million tonnes)

1400

1200

1000
Package 1A CCS

800

Package 1A Fuel
Package 1A Technology only
Baseline

600

400

200

2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

0

WTW CO2e emissions - contribution of technology and fuels - Central scenario - Package 2A
1600

1400

WTW CO2e emissions (million tonnes)

1200

1000

800
Package 2A CCS
Package 2A Fuel600

Package 2A Technology only
Baseline

400

200

2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

0

-200

-400

WTW CO2e emissions - contribution of technology and fuels - Central scenario - Package 3
1600

1400

WTW CO2e emissions (million tonnes)

1200

1000

Package 3 CCS

800

Package 3 Fuel
Package 3 Technology only

600

Baseline

400

200

2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

0

-200

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Table 7-12: Percentage contributions to total WTW CO2e emissions reduction by technology and fuel forthe three packages

Package 1A

Package 2A

Package 3

Technology

50%

40%

44%

Fuel

48%

40%

40%

Carbon Capture

2%

20%

16%

7.5.2 Cost calculations
The costs associated with the emissions reductions achieved under packages 1A and 2A have been
calculated using the same approach and assumptions as for the main analysis. Figure 7-37 shows thedevelopment of costs to 2050 under Package 1A, split by fuel cost, OPEX and CAPEX.
Figure 7-37: Annualised costs under Package 1A on the central demand baseline
Annualised costs under central demand baseline scenario, package 1A fuels andtechnologies$1,100,000$1,000,000$900,000

Annual costs ($ millions)$800,000$700,000$600,000$500,000$400,000$300,000$200,000$100,000$0

Fuel Cost

OPEX (excl fuel)

CAPEX New Ship

Unlike Package 1 under the main analysis (Figure 7-20), CAPEX now shows a significant increase incosts under Package 1A, due to the inclusion of the additional vessel technologies. However, OPEX
still forms the dominant cost under this package.
Similar cost profiles are shown for packages 2A and 3 in Figure 7-38 and Figure 7-39 (the latter beinga copy of Figure 7-22 as shown for the main analysis).

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Figure 7-38: Annualised costs under Package 2A on the central demand baseline
Annualised costs under central demand baseline scenario, package 2A fuels andtechnologies$1,100,000$1,000,000$900,000

Annual costs ($ millions)$800,000$700,000$600,000$500,000$400,000$300,000$200,000$100,000$0

Fuel Cost

OPEX (excl fuel)

CAPEX New Ship

Figure 7-39: Annualised costs under Package 3 on the central demand baseline (repeat of Figure 7-22)
Annualised costs under central demand baseline scenario, package 3 fuels and technologies$1,100,000$1,000,000$900,000

Annual costs ($ millions)$800,000$700,000$600,000$500,000$400,000$300,000$200,000$100,000$0

Fuel Cost

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Under packages 2A and 3, the costs associated with technology are significantly higher than under
Package 1A, reflecting the much higher use (and associated costs) of carbon capture technology underthat package.
The changes in costs relative to the baseline are shown for the three packages in Figure 7-40 to Figure7-42. For each package, the fuel costs are initially lower than under the baseline as the fuel efficiency
technologies and operational measures have a greater impact than the demand growth, but increase to
be the highest cost element by 2050.
Figure 7-40: Change in annualised costs relative to the central baseline for Package 1A
Change in annualised costs relative to baseline, package 1A fuels and technologies(central demand baseline) - undiscounted$250,000

Change in annual costs ($ millions)$200,000$150,000$100,000$50,000$0-$50,000-$100,000

Fuel Cost

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CAPEX New Ship

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Figure 7-41: Change in annualised costs relative to the central baseline for Package 2A
Change in annualised costs relative to baseline, package 2A fuels and technologies(central demand baseline) - undiscounted$250,000

Change in annual costs ($ millions)$200,000$150,000$100,000$50,000$0-$50,000-$100,000

Fuel Cost

OPEX (excl fuel)

CAPEX New Ship

Figure 7-42: Change in annualised costs relative to the central baseline for Package 3 (repeat of Figure
7-25)
Change in annualised costs relative to baseline, package 3 fuels and technologies(central demand baseline) - undiscounted$250,000

Change in annual costs ($ millions)$200,000$150,000$100,000$50,000$0-$50,000-$100,000

Fuel Cost

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As expected from the inclusion of the additional vessel technologies, packages 1A and 2A show asignificantly greater contribution of technology to the overall costs than packages 1 and 2 (Figure 7-23
and Figure 7-24). The overall impacts of the three packages on the NPV of costs to 2050, again split byfuel, OPEX and CAPEX, are shown in Figure 7-43.
Figure 7-43: Change in NPV at 10% discount rate by fuel and sensitivity technology package (packages
1A, 2A, 3) for the central demand scenario compared to the baseline

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To provide more insight into the fuel cost element of the total costs (as shown in Figure 7-43), the splitof the fuel costs amongst the different fuel types for the baseline and the three sensitivity packages areshown in Figure 7-44 (note that the fuel costs are not discounted for this figure, unlike those in Figure7-43).
Figure 7-44: Net present value of aggregated fuel costs from 2020 to 2050 per sensitivity package by fueltype for central demand scenario

Net present value (discount rate 10%) of fuel cost to 2050($ Billion)$2,000$1,8001726
1638$1,600

59

254
1441

$1,400477$1,20096

326$1,000

39

$800

292

$600

226
347
114

1452

93
102

Methanol

219

FAME

58
292

232

HydrogenAmmonia
BioLNG
LNG
MDO
HFO

1103

$400

HVO

688

$200

553

688

$0
Baseline

Package 1A

Package 2A

Package 3

Compared to the results from the main analysis (Figure 7-27), the increased use of vessel technologies
under packages 1A and 2A results in a reduced fuel consumption in later years and hence a reduced
cost associated with the alternative fuels. As a result, the conventional fuels (HFO, MDO and LNG) forma slightly greater proportion of the total fuel cost from 2020 to 2050 (and hence the NPV of those costs)
than for packages 1 and 2 (as shown in Figure 7-27). Package 1A and package 3 have the same costs
associated with the consumption of conventional fuels HFO and MDO. These two packages share thesame technology assumptions and same phase-out of new vessels using conventional fuels, although
they have different assumptions for the alternative fuels that replace them. In contrast, package 2A has
an increased take-up of new vessels using LNG and BioLNG before 2030, leading to a reduction in theuse of HFO and MDO.

7.5.3 Cost-effectiveness calculations
The cost-effectiveness of the packages has been calculated using the same approach as for the main
analysis. Table 7-6 summarises the NPV of the cost-effectiveness to 2050 of all five packages (including
packages 1, 2 and 3 from the main analysis as well as packages 1A and 2A from this sensitivity analysis)
under both 10% and 5% discount rates.

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Table 7-13: Net present value of cost-effectiveness of the different packages to 2050 ($/tonneCO2e)

10% discount rate

5% discount rate

Package 1

$73

$120

Package 1A

$11

$47

Package 2

$113

$149

Package 2A

$83

$120

Package 3

$39

$83

Package 2A can be seen to have slightly lower cost per tonne CO2e abated than Package 2, but still
greater than Package 3. In contrast, Package 1A can be seen to have much reduced cost per tonne
values compared to Package 1, to such an extent that they are significantly lower than Package 3. As
illustrated in Figure 7-45, this is largely due to a significant negative contribution to the cost per tonne
from the fuel. This arises due to the significant reduction in fuel demand (due to the use of the additional
vessel energy efficiency technologies) combined with a moderate increase in fuel price relative to thebaseline (primarily due to ammonia fuel).

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Figure 7-45: Cost-effectiveness of each package (as $/tonneCO2 WTW abated, both 10% discount rate),
central demand scenario

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8 Risks and investment requirements
This section discusses the key risks to the successful achievement of the decarbonisation potentialof the fuel and technology packages, including the associated investments required
Key points:


Risks and barriers: Barriers include the scale-up of the production and supply of alternative
fuels, current inadequate infrastructure, need for engine technology scale up, uncertainty leading
to investment impasse, the lack of standards for the sustainability of alternative fuels production
and the lack of regulation to drive the transition to alternative fuels. There also specific barriers
facing different fuels and different technologies that will need to be overcome.



Investment requirements: Investments in fuel production infrastructure are highest for package
1 which is driven by ammonia and hydrogen plant costs and specifically by green ammonia andgreen hydrogen plant costs post 2035. Both Package 2 and Package 3 show less than half thatamount of investment needed to meet the fuel requirements in that package.

8.1 Barriers to successful deployment
The results of the modelling in this study – as well as several other contemporary literature sources –suggest it is technologically feasible, though challenging, to decarbonise the global shipping sector to
the ambition level of the IMO. However, despite this technical feasibility we have not so far seen rapid
decarbonisation at the rate and scale required. Hence, barriers to decarbonising the shipping sector
remain. These will need to be addressed and overcome to reach the IMO 2050 ambition.

8.1.1 Overarching barriers
8.1.1.1

Availability of alternative fuels

For all three packages, the production and supply of alternative fuels will need to be substantially
increased. Whilst the fuel types requiring increased supply varies by package, this supply barrier applies
to all packages. Increasing the supply will require a large increase in alternative fuel production facilities
or conversion of traditional refineries, appropriately located across world’s key ports and trade routes tosupply port refuelling facilities, to adequately supply the world’s global fleet. A threshold level of demandis required to make this economic.
8.1.1.2

Fuel bunkering infrastructureWith the exception of ‘drop-in’ fuels (such as FAME and HVO that can be used in conventional two
stroke diesel engines and BioLNG that can be used as a drop-in replacement for LNG), associatedbunkering infrastructure and port refuelling facilities will need to be scaled up rapidly. An additional
challenge may be that the required bunkering locations are currently not necessarily where alternative
fuels are/will be produced. In Europe bunkering facilities for ammonia are closer to production facilities
than in other regions. This may require additional transport of fuels, although the impact of this on theindustry (e.g. costs) may not be significant. (Note that bunkering infrastructure costs are assumed to be
recovered through increased fuel prices in the modelling presented in this report).
8.1.1.3

Engine technology

Although engine technology to accommodate alternative fuels such as hydrogen and ammonia isalready under development by engine manufacturers, such as MAN and Wärtsilä, this will need to bescaled up once demonstrated. A threshold level of expected demand for vessels equipped with these

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types of engine is required to make this economic. This then has an interaction with the demand required
for fuel suppliers to invest in production facilities (as noted in Section 8.1.1.1).
8.1.1.4

Investment impasse and lack of certainty

For global-scale investments to be made, a higher degree of certainty and a threshold level of demandis required to make large scale manufacture economic. Currently, this is not the case. There is an
impasse, as customers and charterers are not willing to pay or co-fund lower emission solutions andthere is lack of clarity on how the preferred fuel(s) will be chosen to allow for scale (Shell, 2020). An
increased uptake of drop-in fuels, as analysed under Package 2, does provide a short-term way aroundthis impasse. Bunkering providers and ship operators are waiting on each other to make the initialinvestments in net-zero ships and infrastructure, in turn preventing the growth in supply of fuels that will
be eventually unavoidable. This impasse is exacerbated by the long lifespans that vessels have,requiring significant time for fleet turnover.
In general, there is a lack of certainty regarding how the sector will reach the IMO ambition across themaritime supply chain (e.g. fuels/technologies/offsetting). The technology and fuel neutral approach of
the IMO regulation is designed to ensure a level playing field for the sector, however the result is that it
does not increase certainty. It does not indicate how the sector will move towards decarbonisation.
Further policies will be required to provide direction towards meeting the IMO 2050 ambition, but thesepolicies will need (and are expected) to remain technology-neutral.
8.1.1.5

Price differential

The price differential between traditional marine fuels and alternative fuels remains a large barrier tosuccessful deployment of all 3 packages. HFO is difficult to match in terms of commercial attractivenessand existing scale (Shell, 2020). Whilst decreasing the gap between alternative fuels and HFO requires
additional financing and investments in research and scale-up, financiers do not have the risk appetite
to fund unproven technologies or specific alternative fuels. Investors have no incentives to invest incompanies with lower emission solutions as there is a lack of certainty around which solutions will befrontrunners. Stakeholders interviewed for this study have indicated that regulatory intervention or
guidance, particularly regarding the adoption of alternative fuels, may be needed to achieve
decarbonisation in line with the IMO ambition. The price differential is expected to be minimised with
policy mechanisms and regulatory frameworks. Options include a bunker tax on fossil fuels or a levy on
fuel carbon content, low carbon fuel standards, thresholds for renewable fuel content or a “cap andtrade” scheme, but opinions about the most effective option vary.
8.1.1.6

Split incentives

For many of the technologies in the packages, because of the structure of the shipping sector, there isalso a greater susceptibility to the “split incentive” problem ( Rehmatulla et al, 2015). To date, some of
the carbon reduction technologies that are cost-effective are not implemented to the scale expected.
Split incentives need to be overcome. Furthermore, because the global fleet is owned by many small
companies and multiple stakeholders are involved in ship operations, this can complicate decisionmaking around new technologies (Shell, 2020). Nevertheless, according to an interview with theNorwegian Shipowners Association, some charterers are willing to pay higher rates for more fuelefficient ships (Agnolucci, 2014). As for the container sector, a poll of twenty brokers showed that fuelefficiency was the single most important factor for the hiring of vessels on time charters, and that more
efficient vessels obtain rate premiums compared to standard vessels (Agnolucci, 2014).
8.1.1.7

Sustainability of fuels and lack of robust certification

The final major barrier that needs to be overcome is the certainty of the sustainability and the way thefuel has been produced. Fuels that can be produced from fossil fuels or renewable energy (ammonia,
hydrogen, methanol), will need to have reliable certification schemes to provide assurance that thechemically-identical fuel is from green sources. Biofuel (HVO, FAME) carbon reduction also hinges on
feedstock sustainability, and this presents a major challenge as it is difficult to measure and track the

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indirect impacts of biofuels (such as indirect land use change). Therefore, there is a need for standards
for the different fuels and pathways, including sustainability criteria, to be adopted by the IMO to provide
guidance for organisations investing in alternative fuel production. Furthermore, there will be a need fora rigorous certification system in order to provide guidance to purchasers and to avoid rogue trading(e.g. grey ammonia labelled as green ammonia).

8.1.2 Package barriers
Beyond the overarching barriers, each package has more specific barriers associated with theirfuel/energy carrier mix and these are summarised in Table 8-1. For package 1, the use of battery electric
vessels will entail specific challenges, as lithium ion batteries require large quantities of mined material,
which have both environmental and human rights considerations. Depleted lithium-ion cells can beharmful to the environment if not correctly recycled. As for ammonia in package 1 and package 3 thismay in the longer-term be used in low temperature fuel cells. However, the necessary solid oxide fuelcell technology is not yet commercially available for marine application. For packages 2 and 3 the useof LNG requires that engines are developed to reduce methane slip (e.g. high pressure diesel cycle
engines). The use of ammonia, hydrogen and methanol in packages 1 and 3 also requires thedevelopment of engines to operate on these alternative fuels. For package 2, the biofuels included(FAME, HVO) not only face barriers to deployment regarding sustainability of feedstock supply, but ashigh quality ‘drop-in’ fuels, will face competition for feedstocks for use in other difficult to decarbonise
sectors, such as aviation, if feedstock availability (sustainable biomass) becomes a problem.
Table 8-1 Barriers to deployment mapped on to packages.
Applies to package:
Fuel

LNG
BioLNG
Ammonia

Hydrogen
MethanolFuel related barriers
Methane slip & lifecycle emissions, suitable bunkering
infrastructure, cost
Need for BioLNG bunkering infrastructure, seasonalchanges in waste quantities impacting availability
Production and supply, price parity, technology
development of fuel cells, suitable bunkering
infrastructure, cost, supply network infrastructure
Green hydrogen production and supply, cost, and priceparity, suitable bunkering infrastructure, cost, supply
network infrastructure
Green methanol production and supply, suitablebunkering infrastructure

1

2

3

X

X

X

X

X

X

X

X
X

FAME

Ensuring sustainability of feedstocks, competition withother transport sectors

X

HVO

Ensuring sustainability of feedstocks, competition withother transport sectors

X

Batteryelectric

Limited range, cost, weight/size, end-of-life disposal

X

Each package also has barriers associated with their technological and operational measures, andthese are summarised in Table 8-2.
One barrier facing slow-steaming is that it has little further GHG reduction potential to be unlocked
especially for the existing fleet as this is already widely practised. Furthermore, slow steaming leads tolonger journey times, thus needing more ships to meet the same demand. When used as an alternative
to “rush and wait”, slow steaming brings significant advantages and does not really introduce additionalcosts (except for investment in voyage management systems to make sure the ship arrives at the port
at just the right time). However, if slow steaming reduces goods being transported to a point that means

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demand is not being met, there will be a need to invest in new ships. There are also some limitations
with slow-steaming as some products need to be delivered quickly.
For the vessel technologies and propulsion technologies, the fact there is little remaining GHG reduction
potential to still be harnessed presents a barrier. The packages also face the barrier of power variability
because power assistance measures such as harnessing wind (e.g. Flettner rotors) and solar energy
heavily depend on conditions and have significant deck space requirements. Package 1 faces thechallenge of high capital investment of waste heat recovery (WHR), whilst the lack of current productionready carbon capture systems is a challenge facing package 3.
Table 8-2 Technology related barriers to deployment
Applies to package:
Technology category
Vessel technology

Related barriers
Low GHG reduction potential to still be harnessed

1

2

3

X

X

X

X

X

X

Engine technologies

Power variability depending on conditions, deck
space requirements
High capital investment of WHR

Carbon capture

Not yet well developed, barriers to scaling up

Propulsion technologies

Low GHG reduction potential to still be harnessed

X

X

X

Voyage optimisation

Co-ordination/ information challenges regarding
port logistics, legal issues around automation

X

X

X

Power assistanceXX

8.2 Investment requirements for alternative fuels supply
In sections 6.2.5 and 6.2.6 the fuel production infrastructure capital costs and operating costs were
described and referenced. This section presents the results of calculations using those assumptions toderive the investments needed to deliver the projected demand, taking into consideration the plant
capacities68 (Table 6-7). The investment and operating costs analyses for fuel production infrastructure
are shown in the following total costs tables for a range of discount rates. The results are presented forthe range of discount rates as the cost of capital in this new industry may vary due to green financing
support; in addition the timeframe through to 2050 makes predictions on discount rates difficult.
Table 8-3: NPV (2020-2050) of total investment and operating costs at 10% discount ratebn US $

68

Baseline

Package 1

Package 2

Package 3

Low demand

170

486

221

235

Mid demand

203

639

269

307

High demand

225

762

310

368

This section focuses on the fuel production infrastructure. It does not include any increased investment in fuel transport or bunkering infrastructure.

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Table 8-4: NPV (2020-2050) of total investment costs at 5% discount ratebn US $

Baseline

Package 1

Package 2

Package 3

Low demand

255

1021

399

497

Mid demand

316

1383

502

670

High demand

356

1677

588

810

In Table 8-5 the split between OPEX and CAPEX proportion is illustrated for the central demand
scenario at a discount rate of 10%. The OPEX in package 2 is relatively high (at 18%), followed by the
OPEX for package 3 which is due to high operating cost assumptions for BioLNG in these scenarios.
All input assumptions on the operating costs are listed in Table 6-8.
Table 8-5: NPV of investment costs by new plant OPEX and CAPEX at 10 % discount rate for central demand
scenariobn US $

Baseline

Package 1

Package 2

Package 3

TOTAL

203

639

269

307

OPEX

10

61

47

36

OPEX %

5%

10%

18%

12%

CAPEX

193

579

222

271

CAPEX %

95%

90%

82%

88%

With the inputs assumptions under section 6.2 in mind, the total capacity (in PJ/year) of new plants
needed to be built in order to meet the demand is shown in Table 8-6 to Table 8-8.
All packages show still an initial investment requirement for conventional fuels and increased refining
capacity until new investment in that sector is entirely substituted by new fuels after 2035.
Package 1 is very much driven by ammonia and hydrogen investment, initially into grey ammonia andhydrogen production which eventually is substituted by green ammonia and hydrogen plants in later
years. For blue fuel production, there may be opportunities to reduce the investment costs by upgrading
existing (grey fuel) production facilities with the relevant carbon capture and storage systems; similarly,
there may be scope to reduce the costs for green fuel plants by replacing the reforming systems byelectrolysis units. These potential reductions are not reflected in the costs calculations presented in thissection, and therefore the costs should be considered upper bounds.

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Table 8-6: New plant capacity to be installed to meet demand for fuel and technology package 1 in central
demand scenario (total plant capacity in PJ per year)
HFO

MDO

LNG

Ammonia Ammonia Ammonia Hydrogen Hydrogen Hydrogen(Grey)(Blue)(Green)(Grey)(Blue)(Green)20212025

1,415

1,002

960

-

-

-

-

-

-

20262030

2,359

1,337

-

656

-

-

47

-

-

20312035

1,238

167

-

75

2,343

-

9

1,484

-

20362040

-

-

-

-

423

4,332

-

250

2,610

20412045

-

-

-

-

-

1,474

-

-

705

20462050

-

167

-

-

-

1,179

-

-

469

In total, this package requires additional capacity of over 10 EJ/year of ammonia production (grey, blueand green combined) and over 6 EJ/year of hydrogen production capacity to be installed by 2050.
Package 2 requires rapid and large investments into LNG and Bio LNG plants, as well as into HVO andFAME production capacities post-2025.
Table 8-7: New plant capacity to be installed to meet demand for fuel and technology package 2 in central
demand scenario (total plant capacity in PJ per year)
HFO

MDO

LNG

Bio LNG

FAME

HVO

2021-2025

885

668

1,920

350

-

-

2026-2030

59

501

1,440

408

1,343

1,342

2031-2035

1,179

167

960

315

802

814

2036-2040

-

-

480

301

233

220

2041-2045

-

-

-

3,032

1,902

1,914

2046-2050

-

-

-

3,390

1,110

1,122

By 2050, nearly 8 EJ/year of BioLNG capacity is required to be installed, in addition to almost 5 EJ/yearof new LNG capacity.
Package 3 requires investments post 2025 into BioLNG plants as well as into grey methanol production
which will be substituted with green methanol from 2035. Similar for ammonia, the pathways change
from grey to blue to green in 2025, 2030 and 2035 respectively.

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Table 8-8: New plant capacity to be installed to meet demand for fuel and technology package 3 in central
demand scenario (total plant capacity in PJ per year)
HFO

MDO

LNG

Bio
LNG

Methanol(Grey)

Methanol(Green)Ammonia(Grey)

Ammonia(Blue)

Ammonia(Green)20212025

-

334

480

-

-

-

-

-

-

20262030

2,595

1,504

480

145

239

-

241

-

-

20312035

1,592

334

960

310

627

-

25

842

-

20362040

-

-

1,440

383

-

1,576

-

153

1,565

20412045

-

-

-

2,096

-

501

-

-

499

20462050

-

-

-

2,765

-

358

-

-

363

This package requires an investment into over 3 EJ/year each of methanol and ammonia production
capacity (combining grey, blue and green as appropriate) by 2050. It also implies investment in almost
6 EJ/year of BioLNG production capacity in the same timeframe.

8.3 Investment requirements for maritime industry
The major investments that take place on the vessel themselves are reflected in technology package 3
where large amounts of various carbon saving technologies are applied and, to a lesser extent, inpackages 1 and 2. The technology types are listed in Sections 4.2 to 4.8. The following table shows theaverage additional costs by type of vessel post 2025. For package 3, a further increase in capital costs
for carbon capture roll out is estimated from 2035 onwards.
Table 8-9: Average additional CAPEX per vessel by category from 2025 (and 2035 in package 3) in $millions
Large tankers andbulk carriers

Small and medium
container ships

Large container
ships

Other small,medium vessels

Package 1 from 2025

3,176

1,426

2,426

2,176

Package 2 from 2025

2,851

1,551

2,101

1,851

Package 3 2025-2034

21,466

14,736

17,613

18,588

Package 3 from 2035

34,80028,07030,94831,923

Table 8-10 shows the aggregated investments into new ships necessary over the three decades to 2050

(values are presented undiscounted; the total NPV is presented at a discount rate of 10%). The CAPEX

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for new ships for package 3 is particularly high as a large number of expensive technologies are applied
to the fleet.
Table 8-10: Capital costs of newly built ships by package for the central demand scenario

Year

Number of newly built ships

CAPEX new ships ($ billion)
Baseline

Package 1

Package 2

Package 3

2020-2030

23,894

53

89

85

344

2031-2040

21,370

56

120

113

852

2041-2050

20,884

62

132

124

1,126

Total

66,148

-

-

-

-

52

91

86

465

NPV (10%)

The results show that the investment proportion for the marine operators and ship building industry
heavily depends on the future pathways. Should conventional fuels persist longer than expected, thenpackage 3 still saves large amounts of CO2 by dealing with the emissions on board of the ship. The cost
figures take into account (see package definitions in section 5) the implementation of CC in new vessels
starting in 2030 and reaching 100% of new vessels by 2040 and is reflected in the high capital costs for
new ships.

8.4 Summary of investment and operating cost implications
Pulling together the different capital cost elements described in the report, Table 8-11 summarises the
additional investments (compared to the baseline) required in the maritime and fuels supply industries(all discounted using a 10% discount rate), separating the costs for the different parts of the industry.
As described earlier in the report, it would be expected that the increased costs for the fuel supply
industry (both capital investment and operating costs), including those for ports for storing andtransferring fuel to vessels, would be recovered through the increased fuel prices. Therefore, it would
be inappropriate to sum the different cost elements in these tables, as that would double-count those
costs
Table 8-11: Summary of capital investment implications of the different packages compared to the baseline(discounted at 10%)

Change in discounted
capital costs frombaseline ($ billions)

Vessel capital costs

Alternative fuelproduction investment

Alternative fuel port
infrastructure
investment

Package 1

+$39

+$386

+$8.4

Package 2

+$34

+$29

$0.0

Package 3

+$413

+$79

+$0.2

Similarly, Table 8-12 summarises the operating cost changes for the maritime and fuels supply
industries.

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Table 8-12: Summary of operating cost implications of the different packages compared to the baseline(discounted at 10%)

Change in discounted
operating costs frombaseline ($ billions)

Vessel fuelcosts

Vessel operating
costs (exc. Fuel)

Fuel production
operating costs

Ports fuelinfrastructure
operating costs

Package 1

+$113

+$83

+$51

+$79

Package 2

+$364

+$91

+$37

+$0.5

Package 3

-$186

-$46

+$26

+$0.7

The investment costs in vessel fleets and in fuel production infrastructure are of similar magnitudes(though both vary significantly between packages), while those in the ports infrastructure are
significantly lower. There are greater variations in the operating costs, with large positive changes forvessel operating costs under packages 1 and 2, but negative ones under package 3. The fuel production
costs are of a similar magnitude for all three packages, while the ports infrastructure operating costs
are significant for package 1, but much lower for packages 2 and 3.
For packages 1 and 3, the additional investment required in production infrastructure for alternative fuels
exceeds the additional costs of fuel to the vessel operators (and hence the income received by the fuelcompanies). This significant increase in investments compared to the baseline reflects the need for
additional infrastructure for the production of all the alternative fuels, while much of the required
production of conventional fuels in the baseline uses the existing infrastructure, so the reduction in theinvestment in conventional fuel production infrastructure under the packages is comparatively smaller.

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9 Implications for the fuel production industry
This section discusses the implications of the results of the analyses for the oil and gas industry.
Key points:

The oil and gas industry has a role in reducing uncertainties in the alternative fuel choices for the
futureThe oil and gas industry could support proof of concept demonstrations



There is a need to invest in fuel production infrastructure to ensure that future demand for fuelsupply can be met (for Packages 1 and 3)



There is a need for a robust certification system for green fuels

There is a role for refiners and fuel suppliers in this transition. They could help overcome some of thesebarriers through the following:

1. Reducing uncertainties around the alternative fuel choices
As previously described, maritime industry stakeholders are seeking further clarity/certainty about theiralternative fuel choices and are looking for leadership on the selection of the “best” alternative fuelsfrom the myriad options available. Fuel suppliers could help overcome this barrier through providing
what clarity they can, via technical studies, on fuel options and through robust long-term strategies.
Identifying leading fuel candidates is helpful. Detailed investigations of different fuels and pathways
have shown a range of emissions reductions (including some increases on a well-to-wake (WTW)
basis), but further insight from a production viewpoint would be beneficial. The changing fuel market
and IMO regulations present strategic opportunities for fuel suppliers and refiners in the next few years.
Those able to identify and secure demand can create a competitive advantage (Mckinsey, 2019).
Publishing robust long-term strategies that clearly state refiners’ and fuel suppliers’ roles in the shippingtransition will be important for not only their own navigation of the energy transition, but also for otheractors, by increasing the certainty surrounding future fuel supplies (Bain & Company, 2019). Refiners
could harness opportunities to invest in storage capacity, in order to manage more diverse fuel supplies(Mckinsey, 2019). Fuel suppliers could also help overcome the barriers to decarbonisation by leading
the way and being involved in co-ordinated industry commitments and working to increase the reach ofexisting initiatives – such as the Getting to Zero Coalition, the Clean Cargo Working Group and others– by consolidating objectives and strengthening the coordination of various concurrent workstreams.
This will also serve to decrease uncertainty around fuel options. This can encourage shipping
companies to set decarbonisation targets and make related investments through activist shareholding(Shell, 2020)

Case study: Shell – Decarbonisation Strategy


A founding member of the Getting to Zero coalition and an active participant in the First Movers
group within the Global Maritime Forum

Working to establish a consortium to develop a fuel cell trial on a commercial deep-sea vessel, pullingin partners from across the value chainAnnounced one of the largest green hydrogen projects in Europe, the NortH2 project, in February
2020, with its consortium partners, Gasunie and Groningen SeaportsooProject envisages the construction of wind farms in the North Sea
First turbines could be ready in 2027 and will be used for green hydrogen production,
producing up to 800,000 tonnes per year by 2040.

Source: (Shell, 2020)

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2. Providing proof of concept and investing in R&D
Providing proof of concept that a vessel can operate on an alternative fuel and have a (predetermined/pre-arranged) refuelling point for its return journey can be a catalyst for more rapid
progression and transition to alternative fuels. Refiners and fuel suppliers could increase research anddevelopment (R&D) investments and get involved in initiatives in partnership with ship operators andport authorities to not only demonstrate the feasibility of providing forerunner zero/low carbon fuels,
such as hydrogen/ammonia/methanol/biofuels/LNG, at ports, but also their scaling up. Partnerships
could be intensified through joint R&D across not only shipping, but other harder-to-abate sectors andthe refining industry. Co-operation across the entire industry is required to develop robust solutions.
Running end-to-end green pilot projects involving customers, charterers, operators, owners and ports
on specific routes and vessel types will also be important. Smaller initiatives that establish infrastructure
for large scale pilots should be combined and pilot requirements and results (e.g. routes and types ofcargo suited to specific types of fuel) shared across the whole maritime supply chain, to inform all actors.
Through greater cross-sectoral collaboration, the energy sector could play a role in contributing to alarger pool of capital and expertise and increase the likelihood that production and transportation
infrastructure will be available once future fuels are commercially viable (Shell, 2020).

Case study: BP and Ørsted – Lingen Green Hydrogen PartnershipBP and Ørsted will collaborate on a 50 MW electrolyser in Germany in the first stage of a greenhydrogen partnership. This could scale up to 500 MW.
Electricity is expected to be supplied from an Ørsted offshore wind farm to power the electrolysers.
The initial 50 MW phase will produce 9,000 tonnes of green hydrogen per year, enough todisplace 20 % of the refinery’s existing fossil-fuel-derived hydrogen.
Excess hydrogen produced at Lingen could become the feedstock for synthetic fuelproduction.

Source: (GTM, 2020)

3. Accommodating the increased alternative fuel demand
Although the technological improvements identified in this report can provide substantial improvements
in energy efficiency, the results of the analyses to date indicate that alternative fuels will still be required
to achieve the IMO’s ambition for 2050. To accommodate the increased demand for alternative fuels,
refiners could pursue solutions by adopting new processes and capabilities, such as the directhydrogenation of bio streams, carbon capture and eventually co-processing or waste streams (at therefinery), the development of low-emission fuels, and the production of green hydrogen for use as fuel(Bain & Company, 2019). Fuel suppliers, terminal operators and other stakeholders could strategicallyinvest in growth of fuel production facilities in close geographic proximity to supply port refuelling
facilities, and adequately supply the world’s global fleet. The lowest cost renewable energy sources
should be considered. Solar PV and onshore wind are currently the cheapest sources of new-build
generation for at least two-thirds of the global population (BNEF, 2020), and the costs of renewables
are projected to continue to decline in the 2020s (EnergyPost, 2020).
These locations should ideally mirror key shipping trading lanes to minimise additional requirements totransport fuel to the ports. Fuel production could be scaled up if refiners and suppliers establish longterm strategic partnerships with ports. Similarly, refiners and fuel suppliers could play a part in thescaling-up of secure bunkering infrastructure of alternative fuels by establishing strategic partnerships
with bunkering companies in the largest ports. Demand for green fuels could be not only met by actions
taken by refiners and fuel suppliers, but also scaled up through refiners and fuel suppliers drawing up
charterers’ and customers’ commitments that include long-term contracts and green procurement
criteria (Shell, 2020).

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Case study: Eni energy company – refinery conversions
Working on developing technologies to convert conventional fossil-fuel refineries into bio-refineries to produce
high-quality, cleaner fuels has also resulted in patented innovative solutions.

Porto Marghera refineryThe first conventional refinery in the world
to be converted into a bio-refinery.
Since 2014, about 360,000 tonnes ofvegetable oil are treated and converted
annually
In 2019 Eni launched feasibility studies of a
Waste to Fuel plant at Porto Marghera with a
FORSU processing capacity until 150,000
tonnes per year

Gela refineryOperational in August 2019 and replaces thepreceding large petrochemical plant
Can process up to 750,000 tonnes annuallyof waste vegetable oil, frying oil, fats, algae
and waste by-products to produce quality
biofuel.
Conversion has cost €294 million, in addition
to an estimated €73 million of investment in
preparatory work.

Source: (Eni, 2020)

4. Provide ‘Green’ certification and fuel sustainability information
As the demand for ship owners/operators to know the provenance of the fuels they are purchasing
increases, fuel suppliers and refiners could facilitate this. Specifically, where there are various possible
production routes for the same fuel, knowing and verifying the upstream GHG emissions of the fuel will
be important for shippers who are seeking to offer carbon-free transport. The market will also need arigorous certification system in order to avoid rogue trading of e.g. grey ammonia labelled as green
ammonia. The possible actions from fuel suppliers and refiners is that they could support theestablishment of a robust certification system. Collaborating the IMO and key stakeholders in themaritime supply chain to adequately develop, test and prepare monitoring systems before demand for“green” alternative fuels is widely used on the market. Refiners also need to educate their customers
about the fuels specifications they intend to supply and the ports where such fuels will be available (S&P
Global Platts, 2019). Such a certification system would in any case be necessary if future policy
measures or regulations place scrutiny on the fuel carbon content / associated GHG emissions.

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10 Implications for the global maritime industry
This section discusses the implications of the results of the analyses for the maritime industry.
Key points:


Vessel designers and builders have a role in ensuring that the best fuel efficiency technologies
are available on future ships, including carbon reduction technology, and that they are ready foralternatively fuelled ships.



Vessel owners and operators should seek options for funding the acquisition of more fuel efficient
vessels, and/or those using alternative fuels, to assist in greening the future fleet

The analysis has shown that significant reductions in emissions are feasible for the global maritime
industry out to 2050, but that there will be considerable changes required to the vessels and fuels if that
potential is to be realised.

10.1 Vessel designers/builders
For vessel designers and builders, there is a need to ensure that the vessels that they design andproduce incorporate the best available technology for energy efficiency. (Although not resolving theidentification of the preferred zero/low carbon fuel, the reduced energy demand of a more energy
efficient ship is a de-risking strategy for future price fluctuations.) The most energy efficient ships will
require the lowest amounts of any energy source. In particular, the analysis has shown that meeting the
IMO ambition for 2050 will require a shift to alternative fuels as well as the use of best available
technologies. There is still debate on which fuel, or combination of fuels, will be the “best” option going
forwards, but vessel designers will need to be able to incorporate the relevant engines and, perhaps
more significantly, fuel storage and systems, to be able to take advantage of the decarbonisation
offered.
This study has identified that the future decarbonisation may be met with different fuel types being used
for different applications. For example, using ammonia for deep-sea shipping, hydrogen for short-sea
shipping and battery-electric for coastal shipping. Designers and builders should consider how thesedifferent fuels will affect the design of the different ship types going forwards.
Another potentially key technology is the use of on-board carbon capture technology in conjunction withcarbon-containing fuels. Currently, this technology is in its infancy, with only initial trials being performed.
In the longer term, this technology could take on a much greater significance for reducing emissions
while retaining carbon-containing fuels. For example, the IMO regulation on fuel sulphur content allows
operators to use either very low sulphur fuels or to use sulphur dioxide capture technology (“scrubbers”)
when using higher sulphur fuels. Although there is currently no regulation on CO 2 emissions from ships
of a similar nature, carbon capture devices might allow operators to meet such a regulation while
continuing to operate on carbon-containing fuels. There is also a need to develop the business modelfor the subsequent treatment of the captured CO 2 (transfer at ports, storage or subsequent re-use insynthetic fuel production, etc.). It will be important to monitor the development of this technology toensure that it can be incorporated in new vessels if the demand arises and the technology is proven.
The need to invest in R&D for carbon capture would be removed if an early switch to zero-carbon fuels
is made.
The need to incorporate these technologies (and fuels options) into new ships will bring additional costs
for the industry. However, there are also potential opportunities for vessel designers and builders who
are able to offer such capabilities in their ships at an early stage.

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10.2 Vessel owners/operators
For vessel owners and operators, there are clear implications of additional costs in investing in newtechnologies (and fuel options on their vessels). These additional costs could challenge investment
decisions, with possible implications for fleet renewal. Following the Paris agreement on climate change,
there have been moves in some countries and regions to ensure that banks provide finance for “green”
projects on preferential terms69. These moves may ensure that vessel owners can access the funding
they require to invest in vessels with new technologies in the future.
Vessel owners and operators (and designers and builders) should also be involved in the coordinatedindustry initiatives referred to in Section 9, to ensure that the whole industry can contribute to aconsistent response to the need for decarbonisation.
Vessel owners could invest in R&D programmes to develop and demonstrate zero- and low-carbon
technologies implemented on specific vessel types (particularly the large bulk carriers, container ships
and tankers identified by this study as contributing most to global emissions) to confirm the transferabilityof the technologies to real-world applications. Sharing the results of these projects would also contributeto a wider uptake of key technologies in the medium term.
Although the initial investment in new vessels may be increased as a result of the inclusion of newtechnologies, the resulting improvements in efficiency will reduce total fuel consumption and hencecosts; the precise implications for this will depend on the particular fuel types used and any increases
in prices as the fuel is transitioned from a grey to blue or green variety. Vessel operators will need to beaware of the implications of any fuel changes on their operating costs and also on decisions on theirroute structure. Discussions will be necessary with bunkering ports to ensure that the fuel for the vesselsthat they invest in will be available at all ports that they are likely to visit (or need to refuel at).
Further, the uptake of alternative fuels will have significant implications for vessel operating costs; thetransition to such fuels will only occur if they are competitive with conventional fuels or throughregulatory intervention. Owners and operators could provide support for regulatory measures to reduce
price differentials and ensure the competitiveness of alternative fuels (or to minimise the cost impactsof any regulation-enforced transition).

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11 Regional developments and opportunities
This section provides context to the results at a regional level. Key points:
Europe’s ambition to be climate neutral by 2050, the European Green Deal and potential shipping
sector inclusion in the EU ETS will drive industry and investors toward emission reductions in the
sector. Existing funding schemes are in place to support decarbonisation initiatives.
oKey projects include: NorthH2 project in the Netherlands, Green ammonia plants in
Spain, and a 2.1 billion EUR carbon capture project in Norway.

In the Middle East, climate policies are not as well developed as in Europe. However, there is anincreasing trend of state-owned industrial companies proactively investing in cleaner fuels. A bluehydrogen economy is under consideration. Dubai and other Emirates are heavily investing in
Solar and Hydro Electric power generation.
o

Key projects include: NEOM city related projects (hydrogen, ammonia, fuel cells), andbiofuel projects (Uniper Energy DMCC biofuels for shipping, HVO production in Fujairah)

Asia’s climate policies are increasing in number and ambition. China, Japan and Korea now havezero emission targets and plans for 2060 and 2050 respectively, Multi-donor initiatives promoting
low emission technologies and fuels are already in place. Asia is also gearing up to the scale upof hydrogen.

Key projects include: Green ammonia consortium driving strategy and R&D projects (inc. Shell,
Mitsubishi and Kanshair), as well as fuel cell development (Toshiba ESS & NEDO). CCS piloting
has also been announced by Mitsubishi and Kawasaki Kisen Kaisha.

The IMO ambition to decarbonise the shipping sector will also present opportunities that will vary acrossmajor geographic regions. Different key regional policies, variation in technology access and project
financing, along with business developments are summarised in Table 11-1.

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Table 11-1 Regional developments related to decarbonisation of the shipping sector
Topic

Europe

Policies asa driver

Access totechnology

The EU aims to be
climate-neutral by 2050 –an economy with net-zerogreenhouse gas
emissions.
The European Green
Deal will prove a key
driver in ensuring demand
for low carbon
fuels/technology given the
inclusion of international
shipping in its targets andthe promotion of a market
for green maritime fuels.

This driver may be further
increased if the shipping
sector is included in thescope of the EU ETS and
if the exemption ofmaritime fuel from tax isremoved.

Green/ sustainable
Finance (EU taxonomy
and TCFD) are driving
investors and industry
toward emission
reductions, including
shipping

Several funding schemes
are already in place tosupport decarbonisation
initiatives (e.g. Project
CHECK that focuses onlong-distanceshipping
decarbonisation)



Economies of scale are
driving lower operating
costs for green hydrogenand associatedprocesses. Numerous
hubs and large consortia
are being created for thispurposeBusinessRicardo Confidential

Middle East

Converting
existing
infrastructure will likely
provide a competitive
advantage and save initialinvestment
costs
for
traditional
Europeanindustrial clusters



Policy development andclimate ambitions are notas well developed.

State-owned industrial
companies areproactively investing incleaner fuelsThis region may become anet exporter of cleaner
green electrofuels (e.g.
ammonia and hydrogen)

Oil and gas heavy
investment funds arebeing reinvested inrenewables andalternative fuels



NEOM
and
other
worldwide flagship large
projects are attracting
worldwide players (e.g.
suppliers/ developers)

In oil-rich countries, ablue hydrogen economy
is being extensively
studied as a viable means
for transitioning.



The UAE and other Middle
East countries are heavily
investing in Solar andHydro Electric power
generation.

Asia



China and Japan now
have zero emission
targets and plans for2060 and 2050
respectively, which will
likely boost the supply ofand demand for cleaner
fuels (both electrofuelsand biofuels).

India is yet to announce atarget of achieving net
zero emissions.



Fuels such as FAME andHVO may be required tominimiseScope3emissions from industry



Decarbonisation of thecurrently carbon intensive
chemical sector, will likely
impact the availability ofalternative fuels and fueloptions for ships

Multi donor initiatives (e.g.
the World Bank and the
Asian Development Bank)
promoting and developing
low emission technologies
and fuels are already in
place



Asia is also gearing up to
the scale up of hydrogen.
Japan was the first
country to adopt a “Basic
Hydrogen Strategy”
targeting 300 kt ofhydrogen production perannum.

This will likely be pairedwith hydrogen imports.
Imports from Australia are
attractivedue
tocompetitive prices andgeographic location.

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Emerging front-running alternative fuels will likely vary depending on region, and existing developments
and pilot / scaled-up projects. Figure 11-1 captures some of these major projects and developments,
mapping them by location.
Figure 11-1 Regional alternative fuel projects and developments

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12 Conclusions and recommendations
Meeting the IMO’s 2050 decarbonisation ambition will need significant change in the shipping industry
This study was commissioned by the Oil and Gas Climate Initiative (OGCI) and Concawe, to investigate
the “Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions
Towards 2050”. The context for this study is the International Maritime Organization’s level of ambition
to reduce the total GHG emissions from international shipping by at least 50% in 2050 relative to 2008
levels, as well as reducing the carbon intensity of international shipping by at least 40% by 2030 and
70% by 2050 (again compared to a 2008 base year)70.
The IMO’s fourth greenhouse gas study, published in 2020, indicates that significant progress has been
made, with global emissions in 2018 being almost the same as those in 2008. However, their future
projections71 of emissions from the sector in 2050, of between 90% and 130% of 2008 levels, miss the2050 ambition by a considerable margin. To achieve the IMO ambition will require the introduction andlarge scale deployment of new technologies and/or alternative low-carbon fuels across international
shipping.
Traditionally, demand for maritime transport is well correlated to global gross domestic product.
Although projections for the future development show changes in the nature of goods transported –largely due to decarbonisation efforts in other sectors leading to a reduction in demand for transporting
oil and coal, but a commensurate increase in demand for transporting raw materials and products – themajority continue to show strong growth in demand. The demand projections in the IMO’s fourthgreenhouse gas study show demand growth of 58% to 153% by 2050, relative to 2018, depending on
the scenario.
Historically, emissions of greenhouse gases from the maritime sector have been dominated by carbon
dioxide (CO2), with three vessel categories (bulk carriers, container ships and tankers) contributing the
majority. In recent years, emissions of methane have increased strongly as more vessels using liquefied
natural gas (LNG) as fuel have entered service. Whilst currently still small, these growing emissions ofmethane would become problematic without the ramp-up of technologies to better control the upstream
and in-use methane releases.
Fuels, technologies and operational measures for decarbonising shipping have been selected into three‘packages’ depicting possible pathways to reaching the IMO ambition
The study reviewed available literature, and interviewed multiple stakeholders, to identify thetechnologies and alternative fuels that are available to decarbonise international shipping. The different
technologies and fuels are shown in the following figure.

70

It should be noted that the IMO has started to discuss potential tightening of the ambition level, including a possible revision of the ambition in
2023.
71

Projections without additional GHG abatement technologies or fuels other than already agreed policies and measures. The projections are
principally driven by demand scenarios consistent with achieving a global temperature increase of less than 2°C

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Each of these technologies has been assessed for its applicability (ship categories), availability (entryinto-service dates), carbon reduction potential and cost (capital and operating).
The different alternative fuels and technology options were combined into three “fuels and technology”
packages for subsequent analyses of their impacts. These packages were characterised and fuels andtechnologies assigned as:

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In addition to the packages shown above, a sensitivity analysis was performed in which the alternative
fuels assumptions of packages 1 and 2 were combined with the advanced technology assumptions of
package 3, forming packages 1A and 2A.
A new model was developed to estimate the impacts that these packages would have on the future
fleet, operations, CO2e emissions and costs
An entirely new bottom-up modelling methodology was developed to assess the impacts that these fueland technology packages would have on the future fleet, operations, emissions and costs. The
modelling methodology started from a definition of the present day fleet and used as input three baseline
scenarios (low, central, high) of future demand out to 2050 selected from the IMO’s fourth GHG study.
The model calculates:

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The future development of the fleet (number of vessels by build year) under each of the baseline
scenarios, using a fleet retirement and growth/replacement approach;The future development of fuel consumption and emissions under the baseline scenarios, using
derived fuel consumption and emissions per unit work (tonne-mile);

The impacts of the fuel and technology package assumptions on the future fleet efficiency andfuel used (for the different fuel types);

The impacts of the different types of fuels used on the emissions;

The impact of the changes in the fleet definition (including the new technologies) on the vessel
prices and hence the capital costs;



The impact of the changes in the fuel consumption on the operating costs.

The impacts on the capital and operating costs of the fuel production infrastructure were also calculated.
Although they are not included in the overall cost calculations, as they would be expected to beamortised through the increased fuel prices, these impacts are of importance to the oil and gas industry,
who would be critical in ensuring the availability of the alternative fuels to meet the future demand.
The IMO ambition is estimated to be met by all of packages 1, 2 and 3 when emissions are calculated
on a well-to-wake basis; however only packages 1 and 3 would meet the ambition on a tank-to-wakebasis
The results of the modelling showed that, by 2050, the emissions under the baseline scenario would be
between 4% and 82% higher than in 2008, depending on the demand scenario assumed, compared to
the IMO ambition of a 50% reduction (also relative to 2008). These increases in emissions were
calculated on a “well-to-wake” (WTW) basis, as this represents the full impact on the global climate andis important when considering the impact of alternative fuels.
Under the three fuel and technology packages, these increases in emissions are replaced by significant
decreases in most cases.


Under package 1, emissions are reduced by over 70% relative to 2008 under all three demand
scenarios, comfortably exceeding the IMO ambition.



Under package 2, the reductions in emissions are very similar to those under package 1.

Under package 3, the reductions in emissions relative to 2008 are close to or exceed 100% under
all three demand scenarios. The package includes a transition to “green”, but carbon-containing,fuels and the use of on-board carbon capture technology. The combination leads to a net captureof CO2 over the complete fuel production and combustion process, leading to a net negativeemission and a reduction of over 100%. Carbon capture is therefore assumed to be available intime for this scale of deployment.

These changes in CO2e emissions are shown in more detail for 2050, relative to 2020, in the following
figure. Results are shown for both well-to-wake and tank-to-wake emissions, with the results for thecentral demand scenario shown as coloured bars and the range between the low and high demand
scenarios represented by the error bars.

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80%

Change in CO2e emissions compared to 2020

60%

Well to wake

Tank to wake

Baseline Package 1 Package 2 Package 3

Baseline Package 1 Package 2 Package 3

40%
23%

23%

20%

0%

-20%
-23%
-40%

-60%

-80%

-73%
-79%

-81%
-87%

-100%

-101%
-120%

All three packages are estimated to exceed the IMO ambition on maritime decarbonisation by 2050,
but this is only assured if the emissions are considered on a well-to-wake basis. The continued useof carbon containing alternative fuels under package 2 (as well as the associated methane slip of
LNG/BioLNG; although, as noted in the report, the latest high-pressure diesel engines reduce
methane slip to very low levels) still produces significant levels of emissions at the ship exhaust, eventhough they are offset by zero or negative emissions in the production (“well-to-tank”) process.
Consideration may need to be given to reformulating the IMO ambition on a well-to-wake basis tocapture the decarbonisation benefits of such alternative fuels.

The reductions in CO2e emissions shown above are accompanied by improvements in carbon intensity(CO2e emissions per unit work, expressed as g/tonne-mile) of between 50% (Package 1) and 65%(Packages 2 and 3) in 2030, relative to 2008, and between 91% (Packages 1 and 2) and 101% (Package3) in 2050. These changes in carbon intensity are relatively constant across the three demand
scenarios.

The additional costs of implementing the packages are likely to be significant but vary between the
packages
The overall costs of implementing the packages described above have been estimated. The total capital
investment costs and operating costs to 2050 (both discounted to 2020 at a 10% discount rate) arepresented in the next two tables, with the costs separated by the part of the industry affected.

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Change in discounted
capital costs frombaseline ($ billions)

Vessel capital costs

Alternative fuels
production capital
costsPort capital costs foralternative fuelhandling

Package 1

+$39

+$386

+$8.4

Package 2

+$34

+$29

$0.0

Package 3

+$413

+$79

+$0.2

Change in discounted
operating costs frombaseline ($ billions)

Vessel fuelcosts

Vesseloperating costs(exc. fuel)

Fuel production
operating costs

Ports fuelinfrastructure
operating costs

Package 1

+$113

+$83

+$51

+$79

Package 2

+$364

+$91

+$37

+$0.5

Package 3

-$186

-$46

+$26

+$0.7

In practice, the increased costs for the fuel supply industry (both capital investment and operating costs)
would be expected to be recovered through increased fuel prices. Therefore, it would be inappropriate
to sum the different cost elements in the cost tables above, as that would double-count those costs.
The capital investment costs in vessel fleets and fuel production infrastructure are of similar magnitudes(though both vary significantly between packages), while those for ports infrastructure are significantly
lower. Under packages 1 and 3, the additional investment in fuel production infrastructure (comparedto the baseline) significantly exceeds the increase in vessel fuel costs (and hence the increase in income
for the fuel producers). This reflects the need for new production infrastructure for all alternative fuelproduction, while much of the conventional fuel required in the baseline will be produced by existing
infrastructure. As a result, the saving in investment in conventional fuel production infrastructure (under
the packages) is comparatively smaller.
There are greater variations in the operating costs, with large positive changes for vessel operating
costs under packages 1 and 2, but negative changes under package 3. The increases in fuel production
operating costs are of a similar magnitude for all three packages, while the ports infrastructure operating
costs are significant for package 1, but much lower for packages 2 and 3.
The results of the emissions analyses indicate that the IMO ambition can be met (and, indeed,surpassed) with a high confidence under the assumptions described – that is to say that if the fuels
are switched to as described, there is high confidence on the resulting emissions from using thesefuels; there is however naturally a lower level of confidence in the calculated costs. In addition to theuncertainty inherent in the fuel price projections, the actual costs will be sensitive to decisions madein the future (for example, a high uptake of one alternative fuel type could lead to prices for different
fuel types significantly different from those assumed for this study, which were based on projections
assuming a more balanced marketplace)

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Under the central scenario, the net present value of the accumulated total costs on the ships from 2020
to 2050 of packages 1 and 3 are estimated to be less than half the costs of package 2
The cost analyses show that the achievement of the emissions reductions will incur considerable costs.
The total costs incurred are a combination of vessel capital costs, fuel costs and other vessel operating
costs. These are calculated for each of the fuel and technology packages and the baseline; the impactsof the packages are then seen as the difference from the baseline. There are greater uncertainties
associated with the projections of fuel costs than the other cost elements.
These costs are calculated as incurred over the full period from 2020 to 2050; net present values (NPV)
are then calculated using assumed discount rates.
For a discount rate of 10%, the NPV of the total costs under the three packages, as compared to thebaseline, under the central demand scenario vary between $181 billion and $489 billion:
Change in discounted
Vessel capitalcosts from the baselinecosts($ billions)

Other operating
costs

Fuel costs

Total NPV

Package 1

+$39

+$113

+$83

+$235

Package 2

+$34

+$364

+$91

+$489

Package 3

+$413

-$186

-$46

+$181

Package 3 has the lowest total costs, and package 2 the highest. For packages 1 and 2, the total costs
are dominated by the increased fuel costs (package 3 has reduced fuel costs compared to the baseline),
while for package 3 vessel capital costs dominate (as expected as it has the highest level of additional
vessel technologies applied of the three packages). The high fuel costs under package 2 are primarily
related to the use of drop-in fuels, specifically BioLNG, FAME and HVO; this study identified higher
projected fuel prices to 2050 for these fuels than other types. There is a higher level of uncertainty inthe price projections for BioLNG as IHS Markit were unable to provide projections for it consistent withthose for the other fuels; therefore, additional information was used when deriving the projection for
BioLNG for this study.
The results of these calculations are sensitive to the discount rate used, but changes in discount rate
do not affect the relative magnitudes of the results across the three packages. Reducing the discountrate to 5% increases the total NPV to between $800 billion and $1,340 billion.
Combining the calculated emissions reductions and the costs, with discounting at 10% applied to bothemission savings and costs, gives cost-effectiveness values in $/tonneCO2e:
Discounted costVessel capitaleffectivenesscosts($/tonneCO2e)

Other operating
costs

Fuel costs

Total NPV

Package 1

$12

$35

$26

$73

Package 2

$8

$84

$21

$113

Package 3

$88

-$40

-$10

$39

Again, these results are sensitive to the discount rate assumed, but changes in discount rate do notsignificantly affect the relative magnitudes across the packages. Reducing the discount rate to 5%
increases the total NPV to between $83 and $149 per tonne CO2e.

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Under calculations in which the costs are discounted (at 10%), but the emissions savings are notdiscounted, the total NPV values reduce to between $8 per tonne CO2e (package 3) and $22 per tonne
CO2e (package 2).
The calculated emissions reductions and costs vary significantly under a sensitivity analysis combining
the advanced technology assumptions of package 3 with packages 1 and 2
A sensitivity analysis considered cases in which the alternative fuels assumptions of packages 1 and 2
were combined with the technology assumptions of Package 3 (referred to as packages 1A and 2A,
respectively).
The increased deployment of vessel technologies under packages 1A and 2A (relative to packages 1
and 2) give increased emissions reductions, so that packages 1A, 2A and 3 all meet the IMO ambition
on both a tank-to-wake and a well-to-wake basis. These reductions in emissions in 2050, relative to2020, are shown in the figure below.
80%

Change in CO2e emissions compared to 2020

60%

Well to wake

Tank to wake

Baseline Package 1A Package 2A Package 3

Baseline Package 1A Package 2A Package 3

40%
23%

23%

20%

0%

-20%

-40%

-60%
-65%
-73%

-80%

-86%
-92%

-100%
-101%
-120%

-112%

-140%

A significant additional technology that is included in packages 1A and 2A (that is not included inpackages 1 and 2) is the use of on-board carbon capture. This has only limited impact on package 1A,
as almost all fuel used by new vessels is zero-carbon by 2035 (the technology is assumed not to beincorporated in vessels that use zero-carbon fuels), but it has a significant impact on package 2A. As aresult, package 2A has the greatest reduction in emissions of all three on a well-to-wake basis.
The inclusion of the additional vessel technologies in packages 1A and 2A (compared to packages 1
and 2) reduces the energy demand and hence the fuel costs. Under package 1A, this reduction in fuelcosts is greater than the increase in vessel costs, leading to overall costs that are significantly lower
than under package 1; under package 2A, however, the increased vessel costs are almost equal to the
reduction in fuel costs, leading to a small reduction in total costs (when discounted at 10% discountrate).
The table below shows the overall cost-effectiveness (as $ per tonne CO2 abated) of the main analysis
packages and the sensitivity analysis packages aggregated over 2020 to 2050, as net present values
using discount rates of 10% and 5%.

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10% discount rate

5% discount rate

Package 1

$73

$120

Package 1A

$11

$47

Package 2

$113

$149

Package 2A

$83

$120

Package 3

$39

$83

The sensitivity analysis packages (packages 1A and 2A) show significantly lower cost per tonne CO 2abated than their corresponding packages 1 and 2 respectively in the main analysis with, in particular,very low values for package 1A. This is largely due to a significant negative contribution to the cost per
tonne from the fuel costs, arising due to the significant reduction in fuel demand (due to the use of theadditional vessel energy efficiency technologies) combined with a moderate increase in fuel pricerelative to the baseline (primarily due to ammonia fuel). Package 2A also shows a reduction in fuelconsumption relative to package 2; however, the costs do not show such a large reduction due to theprices of the alternative fuels used in this package.

Barriers identified to the successful deployment of the fuels and technologies include:

For all three packages, the production and supply of alternative fuels will need to be
substantially increased

By 2050, between 9 EJ and 12 EJ of alternative fuels will be required per annum; theinfrastructure investment needed to achieve this is estimated at between $66 billion and $436
billion (combining capital and operating expenditure, between 2020 and 2050, discounted at
10%)

The adoption of alternative maritime fuels depends on the availability of the associatedinfrastructure for their supply to vessels. With the exception of ‘drop-in’ fuels, associatedbunkering infrastructure and port refuelling facilities will need to be scaled up significantly andrapidly. Given the increased number of fuel types included in the future projections, it might bechallenging for all ports to offer all fuel types, in particular during transition. Therefore, vessel
operators will need to pay attention to the availability of the fuels they require at the locations
they need.

Although engine technology to accommodate alternative fuels (such as ammonia) is alreadyunder development by engine manufacturers, this will need to be scaled up once demonstrated.
Similarly, the development of fuel cells needs to scale up to the MW capacities needed, if fuelcells rather than engines will power the vessels (e.g. from hydrogen).

Significant investments will need to be made in the developments of technologies (particularly
those associated with the use of alternative fuels) and infrastructure. There is currently a lackof certainty regarding the specific fuels (and, perhaps to a lesser extent, technologies) that will
be required. The industry needs greater clarity on these issues before committing to suchinvestments.



The price differential between traditional marine fuels and alternative fuels remains a large
barrier to successful deployment of all three packages. While there is a clear desire on the partof stakeholders for the maritime sector to achieve the decarbonisation targets set by the IMO,
the increased costs of the alternative fuels are a significant commercial barrier to a widespread
uptake. Some regulatory intervention may be required to incentivise the uptake of alternative

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fuels, including reducing the price differential and, hence, the commercial disadvantages ofchanging to the alternative fuels.
Standards are required for the alternative fuels and pathways, including sustainability criteria.

Marine fuels that can be produced from fossil fuels or renewable energy (ammonia, hydrogen,methanol), will need to have reliable certification schemes to provide assurance that thechemically-identical fuel is from green sources.



Slow steaming has shown benefits to date in reducing emissions from shipping. However, there
is little further benefit to be gained as it is already widely practised and the benefits for anindividual vessel on a single voyage are offset by the reduction in productivity and, hence, theincreased number of voyages (and, possibly vessels) necessary to meet the demand.

Recommended actions for supply of alternative fuels are:Taking a lead on refining the choices of alternative fuels. The analysis has shown that a transition
away from conventional fuels to alternative fuels will be needed if the maritime sector is to meet the IMO
ambition by 2050. However, maritime industry stakeholders have indicated that there is a lack of clarity
regarding the “right” or “best” options for such fuels, leading to difficulties in planning for future fleets
and investments. The oil and gas industry should help in developing a roadmap for the future supply ofalternative fuels to reach the IMO ambitions for the maritime sector. This needs to account for the wellto-wake emissions benefits, and account for the impacts of methane not just CO2.
Supporting proof of concept demonstrations. Although all the alternative fuels described in thisreport are widely considered to be suitable for maritime transport, there has been only limited
demonstration of their practicality for long-distance transport with the key vessel categories of bulk
carriers, container ships and tankers. The oil and gas industry could support the design of infrastructure
for alternative fuel proof of concept demonstrations, to provide confidence that the supply of these fuels
can be scaled up to meet the potential future demand. This would also provide assurance to vesselowners regarding future acquisitions of vessels using these fuels. Taking this a step further, oil and gas
industry players could (and have been) working at the vessel level with designers and builders to provethe concepts of working with alternative fuels on board.
Accommodating the increased demand for alternative fuels. This report has shown the scale offuture demand for alternative fuels under different scenarios and fuel and technology packages. These
have shown that significant scaling up of production and supply of these fuels, including a transition
from the current “grey” pathways to “green” fuels (with “blue” fuels providing an opportunity for reduced
emissions in the medium term). To ensure the availability of these alternative fuels in the future,investment in new production facilities, and ensuring the availability of the relevant feedstocks, will need
to be planned.
Providing “green” certification and fuel sustainability information. The different pathways for thealternative fuels, giving “grey”, “blue” and “green” versions, produce chemically-identical products. To
provide assurance that an operator is purchasing, and using, sustainable fuels will need the introductionof a sustainability certification system. The oil and gas industry could take the lead in developing andimplementing such a system as the market for, and supply of, alternative maritime fuels develops.
Supporting a reformulation of the IMO ambition. The benefits of green, but carbon-containing, fuels
mainly occur in the production process, giving low or zero well-to-wake emissions. The industry could,
through activities in the IMO, support a reformulation of the IMO ambition for 2050 to be focused on
reductions in well-to-wake emissions, rather than tank-to-wake as at present, to be able to recognise
the benefits of these alternative fuels.

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Recommendations for the maritime industry are:
Vessel designers and builders to ensure that the vessels that they design and produce incorporate
the best available technology for energy efficiency.
Vessel owners and operators should plan their future investments in new vessels to include theadditional costs associated with decarbonisation technologies and low, or zero, carbon fuels.
They could consider obtaining “green” finance from banks to support these investments.
Vessel operators could lobby for regulatory changes to support the uptake of alternative fuels.
These fuels currently have a significant price premium over conventional fuels, which is expected toremain in place in the future. Regulatory support for alternative fuels may be needed to reduce the pricedifferential and ensure that they are commercially competitive against conventional fuels. Support fromthe industry for such regulatory changes may enable their uptake to be accelerated.
As their fleets transition to alternative fuels, vessel operators will need to ensure that the relevant
fuels are available at the ports at which they need to refuel. Early discussions with port operators
are required to ensure that the necessary fuels infrastructure will be in place as they begin to use the
new fuels.
A potentially key technology for maritime decarbonisation (if continuing to use conventional fuels as inpackage 3) is the use of on-board carbon capture technology in conjunction with carboncontaining fuels. The industry should monitor and support the development of this technology toensure that it can be incorporated in new vessels if the demand arises. The need for carbon capture
technology is avoided if a rapid switch to zero carbon fuels is made.

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WSP. (2018, March 29). THE CEILING ON ECONOMIES OF SCALE IN CONTAINER VESSELS.
Retrieved from https://www.wsp.com/en-GL/insights/the-ceiling-on-economies-of-scale-incontainer-vessels
Yara. (2019, August 20). Yara and Nel collaborate to produce carbon free hydrogen for fertilizer
production. Retrieved from https://www.yara.com/news-and-media/news/archive/2019/yaraand-nel-carbon-free-hydrogen-for-fertilizer-production/
YARA. (2020). Yara Birkeland status. Retrieved from https://www.yara.com/news-and-media/presskits/yara-birkeland-press-kit/
Zero Emission Ship Technology Association . (2020). Market Ready Solutions Emissions Reductions
Today.

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A AppendicesA.1 Appendix 1 – Further analysis on the split incentive
problem for shipping
When a Ship Owner hires out the use of their vessel to a Charterer, the responsibilities and costs
incurred by each entity hinges on the contract between parties, the charter party. Whether there is an
incentive for a Ship Owner to implement energy efficiency measures, is often highly dependent on the
net daily charter-hire ($/day) the Charterer pays to the Ship Owner. In this way whether split incentive
is an issue, depends on whether or not Ship Owners are rewarded through higher time charter rates formore efficient ships ( Rehmatulla et al, 2015). For example, Agnolucci, Smith & Rehmatulla (2014) haveshown that on average around 40% in the Panamax sector is recouped by Ship Owners through higher
time charter rates (2008 – 2012). For £1000 saved on fuel, the Ship Owner sees an increase of £400 in
the charter rate (Agnolucci, Smith, Rehmatulla et al, 2014). In this way there is an asymmetry between
the Ship Owner and Ship Charterer financial gains. There are many different cost allocation
combinations arising from different charter party contracts. Voyage and time charters divide
responsibility for costs as seen in Table 2-2 and these differences can also led to a temporal dimensionof conflicting or converging interests where the different parties strive to reduce their share of costs at
different points in time. Normally, fuel costs are not covered by operating expenses but included invoyage expenses. Fuel costs are often responsible for a large portion of the of the voyage cost.
Operational expenses usually involve crew costs, repair and maintenance costs and marine insurance.
Given these different combinations of cost responsibilities present, for the shipping sector the following
main scenarios can occur ( Rehmatulla et al, 2015):
1. No split incentive
There is no split incentive as the Principal (Charterer) pays for both the ship energy bill and the Principal
can also implement the energy efficiency measure or technology. The Principal & Agent are responsible
for energy efficiency operation, energy payments (fuel) and energy efficiency investment. This can occur
when the Principle is a Bareboat Charterer responsible for energy efficiency and energy payments, and
the Agent is a beneficial owner that simply supplies the bare ship. This is the case with Cargo Owner
operated ships and can also occur when the Ship Owner is also the operator.
2. Split incentive – Efficiency problem
In this case the Principal (Charterer) is in charge of the ship energy bill but cannot select or implement
the energy efficiency measure or technology. This is often the case for Time Chartered Ships. In thetime charter, the Agent is the Ship Owner and provides the service of the ship. The Agent is responsiblefor determining the level of technological efficiency. The Principal demands the service of being supplieda ship but cannot improve the ships efficiency. The Principal bears the cost or benefit associated withthe energy efficiency level but does not determine it. In this case, how well the charter rate reflects ship
energy efficiency dictates how large the split incentive is.
3. Split incentive – Usage problem
This has also been referred to as the “reverse” split incentive. In this case, the Principal (Charterer)
does not pay the energy bill nor can the Principal implement the energy efficiency measure or
technology. In this way the Principal (Time Charterer) does not face the marginal cost of its own energy
use and operational measures therefore there is no energy efficiency incentive. This can be the case invoyage-chartered ships.

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Overcoming split incentives
Despite presenting a major barrier to the deployment of energy efficiency measures, technologies andalternative fuels in the shipping sector, split incentive challenges have not been investigated in great
detail to date. However, these barriers have been investigated in the building & manufacturing industry.
Third-party financing models from the built environment could be adapted for the shipping industry toenable significant capital costs to the Ship Owner or Ship Charterer to be overcome. The key to thesefinancing mechanisms is that they incorporate measurement and verification technology into thefinancial package (Stulgis et al, 2014).
One such mechanism has been based on the Energy Service Companies (ESCO) model. The
mechanism would be a Self-Financing Fuel-Saving Mechanism that could facilitate the adoption of fuelefficiency technologies by either long-term time-chartered ships or owner-operated ships. This could
overcome split incentives by securing upfront capital investment cost of retrofit fuel efficiency
technologies, from a third-party financier. The financier could recoup returns of fuel costs savings
generated by the gains in fuel efficiency from the technology. Ship baseline performance statistics andconsequent improvements would be used to calculate return rates. In this way, for Time – charteredships, the Ship Owner can receive financing for improved measures without the fear of the additional
investment costs not being recouped / passed on to the Charterer, as it would now be provided by athird-party. Another proposed mechanism could be use of third-party finance to enable vessels toconvert to running primarily on LNG whilst retaining the ability to switch to conventional bunker fuels ifnecessary. Again, the cost is now passed to the third-party with the financiers receiving their returns byhedging against the pricing spread between low-sulphur bunker fuels and natural gas.
Finally, demand-side stakeholders within the industry (e.g. Charterers) have increasingly expressed
their desire for more efficient vessels through a variety of market signals. For example, retailers
including IKEA and WalMart, as part of the Clean Cargo Working Group are collaborating with leading
container shippers to reduce their carbon footprints. In this way the Split incentive – Efficiency problem
may be reduced through the Shipping Owner being incentivised to implement measures to avoid
foregone revenue from the Charterers choosing to use an alternative ship. Although the benefit would
still not be directly derived from the measure itself, the benefit would be retaining Charterers. This is thecase for the tank and bulk charter market in particular, where Charterers are beginning to factor vessel
efficiency into their commercial decision making. For example, as early as 2012, Cargill, Huntsman, andUNIPEC UK publicly announced they would no longer charter the least efficient ships in the global fleet.
To what extent the split incentive problem has prevented the uptake of carbon reduction measures has
not been quantified to date. Split incentives can also be exacerbated though lack of reliable informationon costs and savings of a particular technology. An additional complexity to the split incentive problem
in the shipping sector is that it most likely impacts technological, operational measures and uptake ofalternative fuels differently. For operational measures such as weather routing, where the Charterer has
operational control and also has fuel as a cost under their account, the split incentive problem may not
be present. This is because the Charterer also has an incentive to save fuel. Technological measureswith high levels of uncertainty can also compound the problem and are more likely to be a part of split
incentives. The question of which new technology will be the most efficient and will work in the longterm makes residual value risk more contentious than it would otherwise be. In this way, each party
aims to reduce risk. This can lead to Charterers trying to keep tenures as short as possible to leave theassociated risk of the measure / potential gain with the Ship Owner, and Ship Owners being reluctant
to pay the upfront capital costs for novel technologies.

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A.2 Appendix 2 – Example detailed results from analyses of
THETIS-MRV data
This appendix provides some additional results from the analyses of vessel fuel consumption data fromthe EU THETIS-MRV portal. In addition to the overall average fuel consumption per unit work presented
in Section 3.2, the additional analyses have investigated the characteristics of the individual vessel
categories and the variation by build year (or vessel age in 2019).
Figure 13-1 shows the variations of fuel consumption with ship size for the different vessel categories.
Figure 13-1: Average fuel consumption per unit work for a range of vessel categories and sizes
Variation of average fuel consumption per unit work with Dead Weight Tonnage (DWT) andvessel type
35.0

Fuel consumption per unit work (g/tonne-mile)

30.0

25.0

Bulk Carrier

20.0

Chemical Tanker
Container Ship

Gas Carrier

15.0

LNG Carrier
Oil tanker
Ro-Ro ship

10.0

5.0

0.0
0-20000

20000-40000

40000-60000

60000-80000

80000-100000

100000-120000

Dead Weight Tonnage (tonnes)

Source: Ricardo analysis using EU ship emissions MRV data and Clarksons World Fleet Register data

Figure 13-1 shows large differences between the fuel consumption per unit work, with gas carriers andRo-Ro ships having the highest values (of up to 28 or 34 g/tonne-mile) and bulk carriers, chemical
tankers and oil tankers generally having the lowest (of down to about 2.0). There are some anomalies
present, such as the 80,000 to 100,000 DWT size category for chemical tankers. For most results, theaverages shown have been calculated using data for multiple hundreds of ships; however, there arealso some results that are based on very few ships, which can give rise to some of the anomalies seen(for example, the 80,000 to 100,000 DWT chemical tankers category includes only two ships).
For some ship categories, an increasing efficiency with vessel size is generally evident. For example,
gas carriers, LNG carriers and oil tankers all show generally reducing fuel consumption per unit workwith increasing DWT.
The combined use of the EU MRV data and the Clarksons World Fleet Register data allows the fuelconsumption per unit work to be examined in greater detail, showing the development of the values withthe build year of the ships. Figure 13-2 and Figure 13-3 show examples of these, for bulk carriers andoil tankers respectively.

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Figure 13-2: Variation of average fuel consumption per unit work with build year and DWT for bulk carriers
Variation of average fuel consumption per unit work with build year for Bulk Carriers
9.0

Fuel consumption per unit work (g/tonne-mile)

8.0

7.0

6.0
DWT0-40000
DWT40000-80000

5.0

DWT80000-120000
DWT120000-160000

4.0

DWT160000-200000
DWT200000-240000
DWT240000-280000

3.0

DWT280000-320000

2.0

1.0

0.0
1981-1985

1986-1990

1991-1995

1996-2000

2001-2005

2006-20102011-20152016-2020

Build Year

Source: Ricardo analysis using EU ship emissions MRV data and Clarksons World Fleet Register data

Figure 13-3: Variation of average fuel consumption per unit work with build year and DWT for oil tankers
Variation of average fuel consumption per unit work with build year for Oil Tankers
16.0

Fuel consumption per unit work (g/tonne-mile)

14.0

12.0

DWT0-40000

10.0

DWT40000-80000
DWT80000-120000

8.0

DWT120000-160000
DWT160000-200000
DWT200000-240000

6.0

DWT240000-280000
DWT280000-320000

DWT320000-360000

4.0

2.0

0.0
1981-1985

1986-1990

1991-1995

1996-2000

2001-2005

2006-20102011-20152016-2020

Build Year

Source: Ricardo analysis using EU ship emissions MRV data and Clarksons World Fleet Register data

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Some gaps are evident in the distributions, as the limited number of ships for which data are available
becomes more evident as the data are analysed at a more refined level.. However, for cases wheredata are available across all build year groups, there is commonly evidence of a reducing fuelconsumption over time, indicating the manner in which the incorporation of improved vessel design andother technologies has contributed to the improvements in fuel efficiency of new ships.
The results shown above, plus those for other ship categories, have been to define baseline fuelefficiency values, and their rates of improvement over time, which were applied to the modelling of thedevelopment of the global fleet (as new ships are built and enter into the fleet, replacing older ships)
and the development of demand, to define baseline fuel consumption in future years.
Although the main analyses performed for this study considered the emissions by different ship types
and sizes, it is constructive to consider the overall average emissions per unit work based on the buildyear of the ships. The results, with averages calculated using the emissions per unit work weighted by
the total distance travelled by the ship in 2019, are shown in Figure 13-4.
Figure 13-4: Overall average fuel consumption per unit work for the fleet in 2019 as a function of build year
Average fuel consumption per unit work for all ship categories against build year

Average fuel consumption per unit work (g/tonne-mile)

25

20

15

10

5

0
1990

1995

2000

2005

2010

2015

2020

Build year

Source: Ricardo analysis using EU ship emissions MRV data and Clarksons World Fleet Register data

The data shown in Figure 13-4 are limited to ships built from 1990 onwards, as the limited number ofships (for which data are available) with earlier build years led to very large levels of scatter. A consistent
reduction in the fuel consumption per unit work is evident from the data points in Figure 13-4, and thisis captured by the curve fitted to the data (using a best fit of a curve representing a constant percentage
reduction each year). The curve shown represents a 4.2% annual reduction in the fuel consumption perunit work for newly built ships. This is a greater improvement rate than has been reported in otherstudies. For example, Scarbrough, Tsagatakis, et al. used an estimate of 1% per annum improvement
based on a review of previous studies (Scarbrough, et al., 2017). The rate is also higher than has beenreported for other modes; for example, ICAO has used assumptions of annual improvement rates ofbetween 0.96% and 1.50% in their environmental trends assessments (Fleming & de Lepinay, 2019),
while the IEA have identified average annual improvements of 1.85% for light duty road vehicles

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between 2005 and 201672, although this had slowed for 2017. A potential reason for the high rate of
improvement calculated here is that, being based on the total fleet delivered in each year, it also includes
the influence of a trend of increasing ship size over time. Figure 13-5 shows how average ship size,
represented by DWT, has increased over the same period.
Figure 13-5: Overall average vessel size (DWT) as a function of build year
Average deadweight tonnage (DWT) for all ship categories against build year
100,000

90,000

Average deadweight tonnage (tonnes)

80,00070,00060,00050,00040,00030,00020,00010,000

0
1990

1995

2000

2005

2010

2015

2020

2025

Build year

Source: Ricardo analysis using EU ship emissions MRV data and Clarksons World Fleet Register data

The curve fitted through the points in Figure 13-5 represents an annual increase of 5.5% in the DWT of
newly delivered vessels; this would be expected to contribute to an improvement in fuel efficiency(expressed per unit of cargo transported) as larger vessels are, in general, more fuel efficient thansmaller ones.
Significantly, the results shown in Figure 13-4 show that the ongoing reductions in fuel consumption areevident for ships built considerably before 2011, when the EEDI came into force for new ships. Thismay be seen as corroborating some views that have been expressed that to date the EEDI has had
little impact on the fuel consumption of the fleet, which has been driven more by economic
considerations (e.g. the cost of fuel) than by regulation.
The average build year of the ships whose data are shown in Figure 13-4 is 2009, giving an averageage in 2019 of 10 years. Extrapolating these data forward, and assuming that the profile of distancecovered by ships of a given age remains constant in the future and that, in the absence of further
changes in policy or regulation, the annual improvement of newly built ships remains valid, in 2030 thisestimates that the average fuel consumption per unit work of the fleet will be 58% lower than in 2008,
while in 2050 it will be 81% lower than in 2008. There is clearly significant uncertainty around theseassumptions, but these results indicate that the trajectory of ship technology improvements to date, if
maintained, should be sufficient to meet the IMO ambition on the carbon intensity of the future fleet, as
described in Section 1.1. The achievement of this continuing improvement in fuel consumption per unit72

https://www.iea.org/reports/fuel-consumption-of-cars-and-vans

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work would imply the continued development of new vessel and engine technologies and theirimplementation in new ships. As discussed earlier in this report, the technologies identified during thisstudy may not be sufficient to enable this trajectory to be continued, hence the requirement to consider
alternative fuels to enable the targeted reductions in emissions to be achieved.

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A.3 Appendix 3 – EEDI effectiveness
Whilst the average design efficiency of all ship types has improved substantially since the 1980s,
changes in ships’ design speeds and in power requirements to overcome resistance, can only explain
a fraction design efficiency changes observed. Other aspects of ship design have been more important,such as hull, propeller and rudder design (Faber, Maarten, Vergeer, & Calleya, 2016). This period wasthen followed by a period of deterioration of average ship energy efficiency after 1999, but in more
recent years ship efficiency has improved once again. Whilst some attribute EEDI amendments as thecause of the positive efficiency changes witnessed in recent years, others indicate these changes are
actually the result of high fuel prices, rather than regulation (Faber, Maarten, Vergeer, & Calleya, 2016).
The role of EEDI may be reduced in the upcoming years due to past shipping sector trends such as the
shipbuilding boom, which lasted for 10 years with a peak in demand for ordering of new ships in 2008.
Because many technologies are fitted at the newbuild stage, the opportunity to reduce carbon emissions
through the EEDI has declined since the boom came to end, given the reduced demand for new ships
post 2008 (Stott, 2014). The average age of ships is approximately 22 years, therefore EEDI reductions
in CO2 emissions may occur far more slowly than anticipated, given fleet time lags in complete turn over
(Chu Van, Ramirez, Rainey, Ristovski, & Brown, 2019).
Further amendments to the EEDI programme will bring forward phase 3 to 2022 and introduce stronger
EEDI reduction levels for certain vessels, indicated in Table 13-1. However, these have been seen as
controversial, with stakeholder feedback highlighting unequal targeting by sector.
Table 13-1: Amendments to EEDI regulation adopted in May 2019
Vessel Type

Size (DWT)

CO2 reduction level*

10,000 to 14,999

15% to 30%

15,000 to 39,999

30%

40,000 to 79,999

35%

80,000 to 119,999

40%

120,000 to 199,999

45%

200,000+

50%

3,000 to 14,999

0 to 30%

15,000+30%

LNG Carriers

10,000+30%

Gas Carriers

15,000+30%

25,000 to 84,999

0 to 30%

85,000+30%

Container Ships

General Cargo

Cruise Ships* Relative to a reference line representing the average efficiency of ships built between 2000 and 2010
Source: American Bureau of Shipping MEPC-74 Brief (https://ww2.eagle.org/content/dam/eagle/regulatorynews/2019/MEPC-74-Brief-r4.pdf)

Beyond newbuild ship design regulation, recently Japan proposed an EEXI ahead of MEPC74 which
has received support from Greece, Japan, Norway, Panama, United Arab Emirates, ICS, BIMCO andIntertanko. The EEXI would build upon the EEDI (IMO, n.d.), which applies to new ships, by applying
technical efficiency standards to the existing fleet (Chambers, 2019). Their aim being for this to beapproved at MEPC 75 with entry into force in 2022. This is somewhat controversial as a mandatory flat
rate engine power limit on all ships was initially suggested (i.e. even ships with EEXI equal or lower than
the required EEXI would have to comply). However, the latest proposal has moved forward to use thegoal-based EEXI proposal as the basis for further consideration in technical approach, without
incorporating the prescriptive measure.

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EEDI developments such as the third phase of controls being brought forward and the EEXI may
improve EEDI effectiveness. However, stakeholders confirmed that EEDI issues such as unequaltargeting by sector remain a barrier to EEDI effectiveness. This echoes the literature that indicates it is
now widely accepted that ship design efficiency requirements alone will fall short of what is required inorder to fully decarbonise the shipping sector by 2050. The European Commission has stated it willpropose further measures to tackle GHG emissions from ships, in the absence of adequate progress inthe framework of IMO, thereby effectively highlighting that the adoption of EEDI is not sufficient(Psaraftis H. , 2012).

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A.4 Appendix 4 – Environmental Ships Index
Table 13-2: Structure of the calculation of the Environmental Ships Index
ESI element

Calculation

Overall
Score

ESI = ESI-NOx + ESI-SOx + ESI-CO2 + OPS; capped at 100

ESI

ESI-NOx is based on the certified NOx ratings of the engines fitted to the vessel, relative to theregulatory limit, expressed as:
ESI-NOx

𝐸𝑆𝐼 − 𝑁𝑂𝑥 = 2/3 ×100
𝑇𝑜𝑡𝑎𝑙 𝑟𝑎𝑡𝑒𝑑 𝑝𝑜𝑤𝑒𝑟 𝑜𝑓 𝑎𝑙𝑙 𝑒𝑛𝑔𝑖𝑛𝑒𝑠×Σ(𝑁𝑂𝑥 𝑙𝑖𝑚𝑖𝑡 𝑣𝑎𝑙𝑢𝑒−𝑁𝑂𝑥 𝑟𝑎𝑡𝑖𝑛𝑔)×𝑅𝑎𝑡𝑒𝑑 𝑝𝑜𝑤𝑒𝑟
𝑁𝑂𝑥 𝑙𝑖𝑚𝑖𝑡 𝑣𝑎𝑙𝑢𝑒

where the sum (Σ) is taken over all main and auxiliary engines

ESI-SOx

ESI-SOx is defined by the relative differences of the sulphur contents of the fuels used, comparedto the limit values for those fuels, expressed as:
ESI-SOx = 1/3 x
30 x relative difference of sulphur content of HIGH S fuel (HFO with sulphur content
between 0.5% and 3.5%) +35 x relative difference of sulphur content of MID S fuel (MDO with sulphur content
between 0.1% and 0.5%) +35 x relative difference of sulphur content of LOW S fuel (MDO with sulphur content lessthan 0.1%)

ESI-CO2= 5 for reporting fuel and distance every half year; additional points are added for each % increasein efficiency (total ESI-CO2 is capped at 15)

OPS= 10, if on-shore power supply installation is fitted

Source: https://www.environmentalshipindex.org/Public/Home/ESIFormulas

To May 2020, 9,200 ships have been awarded an ESI score, and it is used in > 50 ports worldwide. The
number of ports by region is shown in Table 13-3.
Table 13-3: Numbers of ports using the ESI to rate ships’ environmental performance
RegionNumber of ports

Europe

43

Asia

4

North America

3South America

3

Australasia

2

Middle East

1

Source: https://www.environmentalshipindex.org/Public/PortIPs

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A.5 Appendix 5 – Fuel descriptions from Phase 1 report
This appendix reproduces the descriptions of the different fuel and their associated production pathways
from the Phase 1 report on this study. It should be noted that the work on Phase 2 of the study, leading
to the production of this final report, has including updating many of the cost assumptions; therefore,
the values presented in the appendix may not match those in the main report.
The presentation of the fuels information in the Phase 1 report included summary information in themain report, together with an extended table in Appendix A.1. The latter table is reproduced at the endof this appendix.
As noted in Section 6.2.1 of the report, the fuel price projections used for the cost modelling in his study
were provided by IHS Markit. As these replaced the fuel price data that were developed in Phase 1, andare described in detail in Section 6.2.1 and Appendix A.10, no fuel price data are included here.

LNG
Table 13-4: Production pathway GHG emissions, life cycle emissions (well-to-wake), GHG reduction
potential and fuel costs for different LNG pathways.

LNG Production Pathway

Production
Pathways GHG
emissions (WTT)
g CO2eq/MJ

g CO2eq/MJ

GHG reduction
potential (%) [negativevalues are increases in
GHG]

Total life cycle GHG
emissions (WTW)

HFO reference

9.6

87.2

0

Global average LNG (A)

18.5

78.1

10.4

LNG onshore Qatar

10.7

80.2

8.3

Regional pathway not
specified

19.1

92.7

US supply LNG

16

115.54-32.5

Global average LNG (B)18.5

127.03

-45.7

-6.3

Table 13-5: Examples of LNG production pathway emissions.
LNG Production Pathways (WTT)

g CO2eq/MJ

HFO reference

9.6

LNG supplied from Qatar by tanker

10.7

LNG Natural Gas North Sea

8.9

LNG Natural Gas Russia via pipeline

23.1

Source (Verbeek et al, 2011)

Natural gas liquefaction technologies can also impact emission reductions, with industrial gas turbines(IGT) being the most energy intensive (see Table 13-6). Nevertheless, the largest proportion of LNG
life-cycle emissions arise from combustion and from methane slip.
Table 13-6: Effect of four natural gas liquefaction technologies on GHG emissions.
LNG Liquefaction technology

g CO2eq / kg LNG

g CO2 eq / MJ

Industrial gas turbine (IGT)

360

7.41

Aero-derivative gas turbine (AGT)

220

4.53

AGT and helper motor

150

3.09

Electric-driven compressor

50

1.03

Source: (Sharafian et al, 2019)

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BioLNG
Table 13-7: Production pathway GHG emissions, life cycle emissions (well-to-wake), GHG reduction
potential and costs of different BioLNG pathways.
Production
Production
Tank-toTotal life
GHG
pathway GHG
pathway GHG well GHG cycle GHG
BioLNG
reduction
Production emissions (WTT*) emissions (WTT) emissions emissions potential
exc. iLUC**
inc. iLUC(TTW)(WTW)*
Pathways
gCO2eq
HFO
reference
Municipal
waste(closeddigestatestorage)

%

9.6

-

77.6

87.2

-

24.1

24.1

0

24.1

72.4

-60.5

-60.5

0

-60.5

169.4

24.5

27.5

0

27.5

68.5

50.1

53.1

0

53.1

39.1

15.9

15.9

0

15.9

81.8

Liquidmanure(closeddigestatestorage withmethaneemission
reduction***)Liquidmanure(closeddigestatestorage)

Whole
plant
(closeddigestatestorage)

Wood(Gasification)*Values do not include possible differences in engine efficiency and engine methane emissions.
**iLUC=Indirect Land Use Change***Pathway includes positive effect of preventing methane emissions by storage and use of biogas instead of
releasing to the atmosphere.

LPG
Table 13-8: Production pathway GHG emissions, life cycle emissions (well-to-wake) and GHG reduction
potential and costs of different LPG pathways.

LPG Production Pathway

Production
pathway GHG
emissions (WTT)

Total life cycle
GHG emissions(WTW)

g CO2eq/MJ

GHG reduction
potential%

HFO reference

9.6

86.7

-

Natural gas LPG

8.8

69.9

19.4

Petroleum derived LPG

13.3

77.6

10.5

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Ammonia
Table 13-9: Production pathway GHG emissions, life cycle emissions (well-to-wake) and GHG reduction
potential from different ammonia production pathways.
Production pathway
GHG emissions(WTT)

Ammonia Production Pathway*

Total life cycle
GHG emissions(WTW)*

g CO2eq/MJ
HFO reference
Ammonia (Green) - Municipal wastebased electrolysis

Ammonia (Green) - Hydropower based
electrolysis

Ammonia (Nuclear) - Nuclear hightemperature electrolysis**Ammonia (Green)- Biomass based
electrolysis

Ammonia (Green) - 100% renewableproduction (theoretical)***Ammonia (Green) – renewable 70%
Alkaline electrolyser + 30% PEM electrolyser

Ammonia (Grey) - Partial oxidation ofheavy oil (POX)

Ammonia (Grey) - Conventional natural
gas feedstock - EU electricity mix

Ammonia (Blue) – SMR + CCS

GHG
reduction
potential
%

9.6

86.7

0

18.1

18.1

79.3

20.2

20.2

76.8

44.7

44.7

48.8

45.2

45.2

48.2

0

0

100

22.15

22.15

74.6

158.9

158.9

-83.2

97.3

97.3

-11.6

12.8

12.8

85.3

*Well-to-wake emissions assumed to be the same at Well-to-tank as ammonia combustion is carbon free.
** Electrolysis is assisted with excess heat from the nuclear power plant.
*** Assuming future electricity provided by the grid is completely renewably generated.

HydrogenTable 13-10: Production pathway GHG emissions, life cycle emissions (well-to-wake) and GHG reduction
potential and costs for different hydrogen pathways.

Hydrogen Production
Pathway

Production
Pathways GHG
emissions (WTT)

Total life cycle
GHG emissions(WTW)*

g CO2eq/MJ
HFO reference

GHG reduction
potential*
%

9.6

87.2

0

87.9

87.9

-0.8

N/A

13.9

84.1

122.0

122.0

-39.9

47

47

46.1

22.19

22.19

74.6

Hydrogen (Grey)
Conventional - Steam reforming
natural gas

Hydrogen (Blue) – SMR +CCSHydrogen (Grey) Electrolysis(UK average grid mix)

Hydrogen (Green) Electrolysis(UK projected grid mix 2030)

Hydrogen (Green) –renewable 70% Alkaline
electrolyser + 30% PEM
electrolyser

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Hydrogen (Green)- theoreticalelectrolysis (100% renewableelectricity)

Hydrogen (Green) Gasification biomass

0

0

100.0

4.6

4.6

94.7

*Well-to-wake emissions assumed to be the same as Well-to-tank as hydrogen combustion is carbon free.

Methanol
Table 13-11: Production pathway GHG emissions, life cycle emissions (well-to-wake), GHG reduction
potential and costs from different methanol production pathways.
Methanol Production
Pathway

Production Pathway
GHG emissions (WTT)

Total life cycle GHG
emissions (WTW)

gCO2eq/MJ
HFO reference

GHG reduction
potential
%

9.6

86.7

0

22.0

98.1

-13.2

-38.3

37.9

56.3

24.4

100.5

-15.9

5.6

81.7

5.8

-40.0

36.1

58.6

Synthetic – Power-to-Fuel(PtF) renewable

-68.9

7.2

91.7

Methanol (Grey) - Coal

120.9

197.0

-126

Methanol (Grey) - Naturalgas

Methanol (Grey) - Flaredgas

Methanol (Grey) Conventional gas

Methanol (Green) Biomass - forest residue
Methanol (Green) Landfill gas

Methanol (Green) –Table 13-12: Approximate additional costs for a newbuild and a retrofit with the methanol fuel system.
New build / retrofit

Newbuild

Retrofit

System component

Cost (Million USD $) *Engine and equipment costs

5.5

Storage of methanol

0.1

Total costs for a newbuild

5.6

Engine costs

3.5

Other equipment

3.5

Additional shipyard costs

3.5

Total costs for a retrofit

10.5*costs calculated for a ro-ro vessel with 24 000 kW installed main engine power and tank capacity for 3 days sailing.

Source: (IMO, 2016)

FAME
Table 13-13: Production pathway GHG emissions, life cycle emissions (well-to-wake) and GHG reduction
potential from different FAME pathways

FAME Production Pathways

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Production
pathway GHG

Production
pathway GHG

Tank-towell GHG

GHG
Total life reduction
cycle GHG potential

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emissions (WTT) emissions (WTT)
exc. iLUC**
inc. iLUC

emissions(TTW)

emissions(WTW)*

gCO2eq/MJ%

HFO reference

9.6

-

77.6

87.2

-

Rapeseed feedstock (glycerine

57.0

111.0

0

111.0

-27.3

37.0

91.1

0

91.1

-4.5

51.0

94.5

0

94.5

-8.4

63.0

107.0

0

107.0

-22.7

31.0

74.5

0

74.5

14.6

13.8

13.8

0

13.8

84.2

26.3

26.3

0

26.3

69.8

export as chemical or animal feed)

Rapeseed feedstock (glycerine
to internal biogas production)

Palm oil feedstock (No CH4
recovery, no heat credit from residue)

Palm oil feedstock (No CH4
recovery, heat credit from residue)

Palm oil feedstock (CH4
recovery, heat credit from residue)

Waste cooking oil feedstock(purification and transesterification)

Tallow feedstock (purificationand transesterification)*iLUC=Indirect Land Use Change. Note: There is a limit to FAME blending with HFO (up to 20%).

HVO
Table 13-14: Production pathway GHG emissions, life cycle emissions (well-to-wake) and GHG reduction
potential from different HVO pathways

HVO
Production
Pathways

Production
pathway GHG
emissions (WTT*)
exc. iLUC**

Production
pathway GHG
emissions (WTT)
inc. iLUC

Tank-towell GHG
emissions(TTW)

Total life
cycle GHG
emissions(WTW)*

gCO2eq/MJ

GHG
reduction
potential%

HFO reference

9.6

-

77.6

87.2

-

Rapeseedfeedstock (meal

57

112

0

112

-28.4

37

92

0

92

-5.5

48.6

104

0

104

-19.3

8.1

8.1

0

8.1

90.7

24.5

24.5

0

24.5

71.9

export to animal
feed, hydrotreat oil)Rapeseedfeedstock (mealexport to internalbiogas production,hydrotreat oil)Palm oilfeedstock (NoCH4 recovery, heatcredit from residue)

Waste cooking
oil feedstock(purification andtransesterification)

Tallow
feedstock(purification andtransesterification)

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Summary of alternative fuels
Table 13-15: Summary of alternative fuels options
Technology

LNG

BioLNG

Options/
Applications

Already
widely used?

Availability
date

Potential fuelconsumption/
CO2 reduction

LNG-1 (Global average LNG (A)*)

Moderate

Now

10.4%

LNG-2 (Global average LNG (B)*)

Moderate

Now-45.7%

LNG-3 (US supply LNG)

Moderate

Now-32.5%

LNG-4 (Regional pathway not
specified)Moderate

Now

-6.3%

LNG-5 (LNG onshore Qatar)

Moderate

Now

8.3%

BioLNG-1 (Municipal waste (closed
digestate storage))

No

Now

72.4%

BioLNG-2 (Liquid manure (closed
digestate storage with methane
emission reduction**))

No

Now

169.4%

BioLNG-3 (Liquid manure (closed
digestate storage))

No

Now

68.5%

BioLNG-4 (Whole plant (closed
digestate storage))

No

Now

39.1%

BioLNG-5 (Wood (Gasification))

No

2025

81.8%

LPG-1 (Natural gas LPG)

No

Now

19.8%

LPG-2 (Petroleum derived LPG)

No

Now

11.0%

Ammonia-1 (Municipal wastebased electrolysis)

No

2025

79.3%

Ammonia-2 (Hydropower based
electrolysis)

No

2025

76.8%

Ammonia-3 ( Nuclear hightemperature electrolysis)

No

2030

48.8%

Ammonia-4 (Biomass-based
electrolysis)

No

2025

48.2%

Ammonia-5 (Electrolysis - 100%
renewable production)

No

2025

100.0%

Ammonia-6 (Partial oxidation ofheavy oil (POX))

No

Now

-82.2%

Ammonia-7 (Conventional natural
gas feedstock - EU electricity mix)

No

Now

-11.6%

Ammonia-8 - renewable 70%
Alkaline electrolyser + 30% PEM
electrolyser

No

2030

74.6

Ammonia -9 SMR + CCS

No

2030

85.3

Hydrogen-1 (Conventional -Steamreforming natural gas)

No

Now

-0.8%

Hydrogen-2 (Electrolysis (average
grid mix))

No

Now

-39.9%

Hydrogen-3 (Electrolysis (2030))

No

2030

46.1%

Hydrogen-4 (Electrolysis(renewable energy))

No

N/A

100.0%

LPG

Ammonia

Hydrogen

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Technology

Methanol

Biofuels(including
drop-in fuels)

Ricardo Confidential

Options/
Applications

Already
widely used?

Availability
date

Potential fuelconsumption/
CO2 reduction

Hydrogen-5 (Gasification biomass)

No

2030

94.7%

Hydrogen -6 (Renewable 70%
Alkaline electrolyser + 30% PEM
electrolyser

No

2030

74.6

Hydrogen -7 (Blue SMR + CCS)

No

2030

84.1

Methanol-1 (Methanol Natural gas)

No

Now

-12.5%

Methanol-2 (Methanol Flared gas)

No

2030

56.6%

Methanol-3 (Methanol
Conventional gas)

No

Now

-15.2%

Methanol-4 (Methanol Biomass forest residue)

No

2030

6.3%

Methanol-5 (Methanol Landfill gas)

No

2030

58.6%

Methanol-6 (Methanol coal)

No

Now

-126.0%Methanol-7 (Synthetic Methanol Power to Fuel (PtF))

No

2030

91.7%

FAME-1 (Rapeseed feedstock(glycerine export as chemical oranimal feed))

No

Now

-27.3%

FAME-2 (Rapeseed feedstock(glycerine to internal biogas
production))

No

Now

-4.5%

FAME-3 (Palm oil feedstock (NoCH4 recovery, no heat credit fromresidue))

No

Now

-8.4%

FAME-4 (Palm oil feedstock (NoCH4 recovery, heat credit fromresidue))NoNow-22.7%

FAME-5 (Palm oil feedstock (CH4
recovery, heat credit from residue))

No

Now

14.6%

FAME-6 (Waste cooking oil
feedstock (purification andtransesterification))

No

Now

84.2%

FAME-7 (Tallow feedstock(purification andtransesterification))

No

Now

69.8%

HVO-1 (Rapeseed feedstock (mealexport to animal feed, hydrotreat
oil))

No

Now

-28.4%

HVO-2 (Rapeseed feedstock (mealexport to internal biogas
production, hydrotreat oil))

No

Now

-5.5%

HVO-3 (Palm oil feedstock (NoCH4 recovery, heat credit fromresidue))NoNow-19.3%

HVO-4 (Waste cooking oil
feedstock (purification andtransesterification))

No

Now

90.7%

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Technology

Already
widely used?

Availability
date

Potential fuelconsumption/
CO2 reduction

HVO-5 (Tallow feedstock(purification andtransesterification))

No

Now

71.9%

DME-1 (Waste wood DME)

No

2030

97.6%

DME-2 (Farmed wood DME)

No

2030

92.5%

DME-3 (Coal EU mix DME)

No

Now

-122.5%

DME-4 (Natural Gas EU production
DME)

No

Now

-12.0%

Batteries

Small, short-range vessels

No

2025

65.5%

Nuclear

Nuclear power is consideredunsuitable for commercial vessels
due to political and public
sensitivities

No

Now

N/A

Synthetic fuels

Options/
Applications

Notes:*
LNG-1 and LNG-2 differ in the assumptions regarding methane slip**
The emissions reduction for BioLNG-2 include the positive effect of preventing methane emissions by storage and useof biogas as fuel instead of releasing to the atmosphere.
For several of the fuel pathways shown the potential reduction in CO2 emissions is negative, indicating that these pathways
produce more emissions than HFO. These pathways are not considered to be valid decarbonisation options and so the costeffectiveness is given as “N/A”. The use of battery electric vessels is likely to remain a niche application (for relatively small, shortrange vessels), so the same cost-effectiveness calculation (based on savings for a significantly larger vessel) is not appropriate.

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Table 13-16 is a reproduction of the table presented in Appendix A.1 of the Phase 1 report on this study.
Table 13-16: Production pathway and lifecycle emission values

Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

HFO

LNG

LNG

HFO reference

LNG-1

LNG-2

HFO reference

Global average LNG (A)Global average LNG (B)

9.6

18.5

18.5

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ
87.2

78.1

127.0

GHG reduction
potential
calculated (%)

0

10.4

-45.7

Comment

Sources( Lindstad and Rialland,
2020)

WTP converted from g/kwh using
assumed engine efficiency of 0.48

(Thinkstep, 2019)

Differences in global averagepathways are due to the way
methane slip is calculated in thestudies. For price, average gas valueof minimum and maximum between
May 2017 and May 2020 used.
Includes additional assumedliquefaction cost of 4$/mmBT.

(Lindstad, 2019)

Differences in global averagepathways are due to the way
methane slip is calculated in thestudies. For price, average gas valueof minimum and maximum between
May 2017 and May 2020 use.
Includes additional assumedliquefaction cost of 4$/mmBT.

LNG

LNG-3

US supply LNG

16.0

115.5

-32.5

(ICCT, 2020)

For price the value for US supply
LNG in June 2019 was used.
Adjusted for inflation.

LNG

LNG-4

Regional pathway not
specified

19.1

92.7

-6.3

(Verbeek, 2015)

-

LNG

LNG-5

LNG onshore Qatar

10.0

80.0

8.3

(DNV GL , 2014) (Reuters,
2020)

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For price, average of minimum andmaximum value for LNG between
July 2020 and October 2019 used.

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Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

BioLNG

BioLNG

BioLNG

BioLNG

BioLNG

BioLNG-1

BioLNG-2

BioLNG-3

BioLNG-4

BioLNG-5

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Municipal waste (closed
digestate storage)

Liquid manure (closed
digestate storage withmethane emission
reduction**)Liquid manure (closed
digestate storage)

Whole plant (closed
digestate storage)

Wood (Gasification)

24.1

-60.5

27.5

53.1

15.9

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

24.1

-60.5

27.5

53.1

15.9

GHG reduction
potential
calculated (%)

SourcesComment(Verbeek, 2015) (European
Commission, 2017)

For price, average taken of values ofwaste biomethane in 2017. Adjusted
for inflation and converted to USD.
Includes additional assumedliquefaction cost of 4$/mmBT.

(Verbeek, 2015) (IRENA,
BIOGAS FOR ROAD
VEHICLES TECHNOLOGYBRIEF, 2018)

For price, 2017 manure-based value
used. Adjusted for inflation andconverted to USD. Includes
additional assumed liquefaction costof 4$/mmBT. Methane emission
reduction comes from avoided
emissions from the traditional
storage and management of raw
manure. It is assumed this does notincur a cost.

(Verbeek, 2015) (IRENA,
BIOGAS FOR ROAD
VEHICLES TECHNOLOGYBRIEF, 2018)

For price, 2017 manure-based value
used. Adjusted for inflation andconverted to USD. Includes
additional assumed liquefaction costof 4$/mmBT.

(Verbeek, 2015) (IRENA,
BIOGAS FOR ROAD
VEHICLES TECHNOLOGYBRIEF, 2018)

For price, 2017 methane fromindustrial waste-based biogas
production value used. Adjusted for
inflation and converted to USD.
Includes additional assumedliquefaction cost of 4$/mmBT.

(Verbeek, 2015) (European
Commission, 2017)

For price, average taken of values offrom biomethane from wood in 2015.
Adjusted for inflation and converted
to USD. Includes additional assumedliquefaction cost of 4$/mmBT.

72.4

169.4

68.5

39.1

81.8

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Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

GHG reduction
potential
calculated (%)

Sources

LPG

LPG-1

Natural gas LPG

8.8

69.9

19.8

(Unnasch and Waterland,2011) (GlobalPetrolPrices,
2020)

LPG

LPG-2

Petroleum derived LPG

13.3

77.6

11.0

(Unnasch and Waterland,2011) (GlobalPetrolPrices,2020)

Ammonia

Ammonia

Ammonia-1

Ammonia-2

Ammonia - Municipal
waste electricity source

Ammonia - Hydropowerelectricity source

18.1

20.2

18.1

20.2

79.3

76.8

Ammonia

Ammonia-3

Ammonia - Nuclear powerelectricity source

44.7

44.7

48.8

Ammonia

Ammonia-4

Ammonia - Biomass
electricity source

45.2

45.2

48.2

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Comment

Uses WTW methodology adapted foroff-road application. Assumed asuitable proxy for shipping. For price,average price of LPG globally as ofJuly 2020 was used.

(Bicer et al, 2019) (IRENA,
2019) (UK Government,
2019)

Converted from kg CO2eq per kg ofammonia. Using energy content
of ammonia (18.8 MJ/kg). Average
production cost taken (2019),
adjusted for inflation and converted
to USD.

(Bicer et al, 2019) (IRENA,
2019) (UK Government,
2019)

Converted from kg CO2eq per kg ofammonia. Using energy content
of ammonia (18.8 MJ/kg).
Hydropower electricity global
average cost identified (Table 1) andused to determine range of values
then average calculated. Valueadjusted for inflation and converted
to USD.

(Bicer et al, 2019) (World
Nuclear, 2020) (UKGovernment, 2019)

Converted from kg CO2eq per kg ofammonia. Using energy content
of ammonia (18.8 MJ/kg). Nuclear
electricity global average cost
identified (and used to determine
range of values then averagecalculated. Value adjusted for
inflation and converted to USD.

(Bicer et al, 2019)(IRENA, 2019) (UKGovernment, 2019)

Converted from kg CO2eq per kg ofammonia. Using energy content
of ammonia (18.8 MJ/kg). Bioenergy
electricity global average cost216

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Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

GHG reduction
potential
calculated (%)

Comment

Sources

identified (and used to determine
range of values then averagecalculated. Value adjusted for
inflation and converted to USD.
Assumes future production from
100% renewable electricity.

Ammonia-5

Ammonia - 100%
renewable production**

Ammonia

Ammonia-6

Ammonia - Partial
oxidation of heavy oil
(POX)

158.9

158.9

-82.2

(Lasocki, 2018) (Cox et al,
2015)

Cost value assumes heavyhydrocarbon feedstock for partial
oxidation. Value adjusted for inflationand converted to USD.

Ammonia

Ammonia-7

Ammonia - Conventional
natural gas feedstock - EUelectricity mix

97.3

97.3

-11.6

(DECHEMA, 2017) (Cox etal, 2015)

Cost assumed equivalent to POX
process. Value adjusted for inflationand converted to USD.

HydrogenHydrogen-1

Conventional - Steamreforming natural gas

87.9

87.9

-0.8

(Ricardo, 2019) (Policy
Exchange, 2018)

For price, SMR value in 2018 used.
Adjusted for inflation and converted
to USD.

HydrogenHydrogen-2

Electrolysis (average grid
mix)

122.0

122.0

-39.9

(Ricardo, 2019) (Policy
Exchange, 2018)

For price, electrolysis average gridvalue in 2018 used. Adjusted for
inflation and converted to USD.

(Ricardo, 2019) (Policy
Exchange, 2018)

For price, electrolysis value in 2018
used. Calculated from average gridmix but assumes a reduction in priceby 30% in 2030. The IEA estimates
the price of renewables will fall 30%
by 2030. Adjusted for inflation andconverted to USD.

Ammonia

0.0

0.0

100.0

HydrogenHydrogen-3

Electrolysis (2030)

47.0

47.0

46.1

HydrogenHydrogen-4

Electrolysis (renewableenergy)

0.0

0.0

100.0

Ricardo Confidential-(Ricardo, 2019)

Assumes future production from
100% renewable electricity.

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Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

Hydrogen

Methanol

Methanol

Methanol

MethanolHydrogen-5

Methanol-1

Methanol-2

Methanol-3

Methanol-4

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Gasification biomass

Methanol Natural gas

Methanol Flared gas

Methanol Conventional gas

Methanol Biomass - forest
residue

4.6

22.0

-38.3

24.4

5.6

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

4.6

98.1

37.9

100.5

81.7

GHG reduction
potential
calculated (%)

94.7

Sources(Ricardo, 2019) (Policy
Exchange, 2018)

For price, gasification value in 2018
used. Adjusted for inflation andconverted to USD.

(Winebrake, 2018) (Nyári,2018)

CO2e was calculated from CO2 andNOx. GWP of 1 (GHG Protocol) and
GWP of 30 used (Lammel et al,1995). For price, average production
cost of natural gas based methanol
in 2013 was adjusted for inflation andconverted to USD.

(Winebrake, 2018)(Lundgren, 2013)

CO2e was calculated from CO2 andNOx. GWP of 1 (GHG Protocol) and
GWP of 30 used. For price, methanol
based on furnace gas and excess
coke oven gas (Case A) cost in 2013
was adjusted for inflation andconverted to USD.

(Winebrake, 2018) (Nyári,2018)

CO2e was calculated from CO2 andNOx. GWP of 1 (GHG Protocol) and
GWP of 30 used (Lammel et al,1995). Conventional gas assumed
the same as the average production
cost of natural gas based methanol(Methanol-1)(Winebrake, 2018)(European Commission,
2017)

CO2e was calculated from CO2 andNOx. GWP of 1 (GHG Protocol) and
GWP of 30 used (Lammel et al,1995). For price, average taken frommethanol based on wood cost in
2013. Value was adjusted for
inflation and converted to USD.

-12.5

56.6

-15.2

6.3

Comment

218

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

Methanol

Methanol

Methanol

Methanol-5

Methanol-6

Methanol-7

Methanol Landfill gas

Methanol coal

Synthetic Methanol –Power-to-Fuel (PtF)

-40.0

120.9

-68.9

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

36.1

197.0

7.2

GHG reduction
potential
calculated (%)

SourcesComment(Winebrake, 2018) (Lee et al,2020)

CO2e was calculated from CO2 andNOx. GWP of 1 (GHG Protocol) and
GWP of 30 used (Lammel et al,1995). For price average price takenof estimated production cost of
methanol production process fromlandfill gas in 2020.

(Winebrake, 2018) (Quirina
et al, 2019)-126.0CO2e was calculated from CO2 andNOx. GWP of 1 (GHG Protocol) and
GWP of 30 used (Lammel et al,1995) . For price used value of
estimated production cost for coalbased methanol production in 2017.
Value was adjusted for inflation andconverted to USD.

91.7

(Eggemann , 2020) (Bos etal, 2020)

Combustion emissions of methanol
added to WTT value. For price usedvalue of estimated production costfor renewable methanol production(synthetic) from water and CO2 air
capture in 2020. Value was adjusted
for inflation and converted to USD.
For price DME from wood average
cost in 2015 was taken (assumes
lower feedstock price). Value wasadjusted for inflation and converted
to USD.
For price DME from wood average
cost in 2015 was taken (assumes
higher feedstock price). Value was

58.6

DME

DME-1

Waste wood DME

2.1 - 2.2

2.1

97.6

(JRC,EUROCAR and
CONCAWE, 2014)(European Commission,
2017)

DME

DME-2

Farmed wood DME

5.1 - 18.9

6.5

92.5

(JRC,EUROCAR and
CONCAWE, 2014)(European Commission,
2017)

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

GHG reduction
potential
calculated (%)

SourcesComment

adjusted for inflation and converted
to USD.

DME

DME

FAME

FAME

FAME

DME-3

Coal EU mix DME

DME-4

Natural Gas EU production
DME

FAME-1

FAME-2

FAME-3

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Rapeseed feedstock(glycerine export aschemical or animal feed)

Rapeseed feedstock(glycerine to internalbiogas production)

Palm oil feedstock (NoCH4 recovery, no heatcredit from residue)

117.3 - 136.1

24.8 – 33.6

111.0

91.1

94.5

194.0

97.7

111.0

91.1

94.5

-122.5(JRC,EUROCAR and
CONCAWE, 2014) (Williams,
2015)

Average taken of coal-based DME in
2015. Value was adjusted for
inflation and converted to USD.

-12.0

(JRC,EUROCAR and
CONCAWE, 2014) (Brito
Alves, 2005)

Average taken of DME production
costs from natural gas feedstock in
2005. Value was adjusted for
inflation and converted to USD.

(Verbeek, 2015) (European
Commission, 2013)

Also includes values excluding andincluding indirect land use change(ilUC). Average taken of FAME
production costs using rapeseed
feedstock in 2013. Value wasadjusted for inflation and converted
to USD.

(Verbeek, 2015) (European
Commission, 2013)

Also includes values excluding andincluding indirect land use change(ilUC). Average taken of FAME
production costs using rapeseed
feedstock in 2013. Value wasadjusted for inflation and converted
to USD.

(Verbeek, 2015) (European
Commission, 2013)

Also includes values excluding andincluding indirect land use change(ilUC). Average taken of FAME
production costs using palm oil
feedstock in 2013. Value wasadjusted for inflation and converted
to USD.

-27.3

-4.5

-8.4

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

FAME

FAME

FAME

FAME

FAME-4

FAME-5

FAME-6

FAME-7

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Palm oil feedstock (NoCH4 recovery, heat credit
from residue)

Palm oil feedstock (CH4
recovery, heat credit fromresidue)

Waste cooking oil
feedstock (purification andtransesterification)

Tallow feedstock(purification andtransesterification)

107.0

74.5

13.8

26.3

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

107.0

74.5

13.8

26.3

GHG reduction
potential
calculated (%)

-22.7

14.6

84.2

69.8

SourcesComment(Verbeek, 2015) (European
Commission, 2013)

Also includes values excluding andincluding indirect land use change(ilUC). Average taken of FAME
production costs using palm oil
feedstock in 2013. Value wasadjusted for inflation and converted
to USD.

(Verbeek, 2015) (European
Commission, 2013)

Also includes values excluding andincluding indirect land use change(ilUC). Average taken of FAME
production costs using palm oil
feedstock in 2013. Value wasadjusted for inflation and converted
to USD.

(Verbeek, 2015) (European
Commission, 2013)

Also includes values excluding andincluding indirect land use change(ilUC). Also includes values
excluding and including indirect land
use change (ilUC). Value of FAME
production cost from UCO taken from
Table 13 (2013). Assumed feedstock
based on average market prices for
UCO in 2015. Value derived was
adjusted for inflation and converted
to USD.

(Verbeek, 2015) (European
Commission, 2013)

Also includes values excluding andincluding indirect land use change(ilUC). Also includes values
excluding and including indirect land
use change (ilUC). Value of FAME
production cost from animal fat(tallow) feedstock taken from Table
13 (2013). Assumed feedstock based

221Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

GHG reduction
potential
calculated (%)

SourcesComment

on average market prices for animal
fat in 2015. Value derived was
adjusted for inflation and converted
to USD.

HVO

HVO

HVO

HVO

HVO-1

HVO-2

Rapeseed feedstock (mealexport to animal feed,hydrotreat oil)Rapeseed feedstock (mealexport to internal biogas
production, hydrotreat oil)

HVO-3

Palm oil feedstock (NoCH4 recovery, heat credit
from residue)

HVO-4

Waste cooking oil
feedstock (purification andtransesterification)

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112.0

92.0

104.0

8.1

112.0

92.0

104.0

8.1

-28.4

-5.5

-19.3

90.7

(Verbeek, 2015) (European
Commission, 2017)

Also includes values excluding andincluding indirect land use change(ilUC). Average taken of HVO
production cost range in 2015.
Assumes higher cost for rapeseed oil
feedstock. Value was adjusted for
inflation and converted to USD.

(Verbeek, 2015) (European
Commission, 2017)

Also includes values excluding andincluding indirect land use change(ilUC). Average taken of HVO
production cost range in 2015.
Assumes higher cost for rapeseed oil
feedstock. Value was adjusted for
inflation and converted to USD.

(Verbeek, 2015) (Festel,2014)

Also includes values excluding andincluding indirect land use change(ilUC). Also includes values
excluding and including indirect land
use change (ilUC). Average taken of
HVO production cost range in 2015.
Assumes lower cost for palmoil
feedstock. Value was adjusted for
inflation and converted to USD.

(Verbeek, 2015) (European
Commission, 2017)

Also includes values excluding andincluding indirect land use change(ilUC). Also includes values
excluding and including indirect land
use change (ilUC). Uses HVO
production cost in 2015. Assumes for222

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Fuel

Pathway code

Production Pathway
description

Production
Pathway GHG
emissions(WTT)
g CO2eq/MJ

Total life cycle
GHG emissions(WTP)
g CO2eq/MJ

GHG reduction
potential
calculated (%)

SourcesComment

waste cooking oil there would be alower feedstock price, lower boundvalue therefore selected from range.
Value was adjusted for inflation andconverted to USD.

HVO

HVO-5

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Tallow feedstock(purification andtransesterification)

24.5

24.5

71.9

(Verbeek, 2015) (European
Commission, 2017)

Also includes values excluding andincluding indirect land use change(ilUC). Also includes values
excluding and including indirect land
use change (ilUC). Uses HVO
production cost in 2015. Assumes fortallow there would be a lower
feedstock price, lower bound value
therefore selected from range. Value
was adjusted for inflation andconverted to USD.

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

A.6 Appendix 6 – Assessment of applicability, current
implementation, and future ownership of technologies from
Phase 1 report
Table 13-17: Summary of applicability of design measures by ship type, as well as their implementationand further uptake.
Applicable to Vessel type
Vessel Design
MeasureAlready
LNG widely
tanker implemented

Futureownership /operation (1-5)*

Gen.
cargo

Bulk
carrierOiltankerChem.
tankerContainer

Ro-Ro/
Passenger

Optimum ship size
dimensions

X

X

X

X

X

X

X

Yes

5

Construction
weight

X

X

X

X

X

X

X

Yes

5

Hull dimensions(form optimisation)

X

X

X

X

X

X

X

Yes

5

Bulbous bow
retrofit

X

X

X

X

X

X

X

Yes

3

Bow thruster
tunnel optimisation

X

X

X

X

X

X

X

Yes

3

Hull coatings

X

X

X

X

X

X

X

Yes

3

Cruise and RoRo only

3

Yes

1

Icebreakers onlyor pilot projects

1

Interceptors
Ducktail waterline
extension

X
X

X

Air lubrication
Trim optimisation
and ballast
reduction

X

X

X

X

X

Not widely applicable (Naval Architect)

X

X

X

Ballast free vessel
design

X

X

X

X

X

Yes

5

X

X

X

No

NA

* On a scale of 1 to 5, with 1 being never and 5 being definitely, likelihood that operators/ owners will operate/own ships withthese measures within the next 10 years.

Table 13-18: Summary of applicability of power assistance measures by ship type, as well as theirimplementation and further uptake.
MeasureApplicable to Vessel
Gen. Bulk
Oil Chem.
Container
cargo carrier tanker tanker

Flettner rotors

X

Towing kites

X

X

X

X

X

X

Solar panels

X

Shore power supply

X

X

X

X

Futureownership /operation (15)*Ro-Ro/
Passenger

LNG
tanker

X

X

No

4

X

No

1

No

1

No

3

No

3

X

Not widely applicable – niche applications

Sails

Already widely
implemented

X

X

X

X

X

* On a scale of 1 to 5, with 1 being never and 5 being definitely, likelihood that operators/ owners will operate/own ships withthese measures within the next 10 years

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224Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Table 13-19: Summary of applicability of alternative propulsion technologies and adaptations by ship type,as well as their implementation and further uptake.
MeasureApplicable to Vessel

Futureownership/
operation(1-5)*

Gen.
cargo

Bulk
carrierOiltankerChem.
tankerContainer

Ro-Ro/
Passenger

LNG
tankerAlready
widelyimplemented

Large area
propellers (LAP)

X

X

X

X

X

X

X

Yes

3

Contra rotating
propellers (CRP)

X

X

X

X

X

X

X

Yes

1

Podded thrusters

X

X

X

X

X

X

X

Yes

3

Ducts (PID)

X

X

X

X

X

X

X

Yes

3

Pre-swirl (PID)

X

X

X

X

X

X

X

Yes

3

Post-swirl fins andrudder bulbs

X

X

X

X

X

X

X

Yes

3

*On a scale of 1 to 5, with 1 being never and 5 being definitely, likelihood that operators/ owners will operate/own ships with thesemeasures within the next 10 years.

Table 13-20: Summary of applicability of operational measures by ship type, as well as their implementationand further uptake.
Applicable to Vessel

MeasureAlready
Futurewidelyoperation
Gen. Bulk
Oil Chem.
Ro-Ro/
LNG
Container(1-5)*
cargo carrier tanker tanker
Passenger tanker implemented

Speed reduction (10%)

X

X

X

X

X

X

Yes

5

Speed reduction (20%)

X

X

X

X

X

X

Yes

5

Speed reduction (30%)

X

X

X

X

X

Yes

5

Advanced port logistics

X

X

X

X

X

X

X

No

3

Optimisation of vessel capacity
utilisation

X

X

X

X

X

X

X

Yes

3

Advanced autopilots

X

X

X

X

X

X

X

Yes

3

Weather routing

X

X

X

X

X

X

X

Yes

5

Autonomous shipping

X

X

X

X

X

X

X

No

1-2

Power demand management e.g.
lighting

X

X

X

X

X

X

X

Yes

5

Engine efficiency measurements

X

X

X

X

X

X

X

Yes

5

Hull cleaning and propeller cleaningand polishing

X

X

X

X

X

X

X

Yes

5

*On a scale of 1 to 5, with 1 being never and 5 being definitely, likelihood that operators/ owners will operate/own ships with thesemeasures within the next 10 years.

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225Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

A.7 Appendix 7 – Summary tables of technologies identified
Table 13-21: Summary of power assistance technologies
Technology

Options/
Applications

Already
widely used?

Availability
date

Likelyadoption
rate

Potential fuelconsumption/
CO2 reduction

Costeffectiveness($/tonne CO2)Wind
assistance

Flettnerrotors; notfor container
ships

No

Now

Low

3% - 15%$15.98

Towing kites;tankers andbulk carriers
only

No

Now

Low

1% - 5%$30.57

Sails

No

Now

Low

1% - 10%$1.88

Solar powerNot
container
ships

No

Now

Medium

0.5% - 2% (ofauxiliary engine
consumption)$278.01

Onshorepower supply

All vessel
types

No

Now

Medium(implement
ation
depends on
port
infrastructu
re)50% - 100% ofconsumption in
port

No cost data
available

Table 13-22: Summary of propulsion technology options
Technology

Options/
Applications

Already
widely used?

Availability
date

Likelyadoption
rate

Potential fuelconsumption/
CO2 reduction

Costeffectiveness($/tonne CO2)

Large area
propellers(LAPs)All large
vessels

Moderate

Now

Medium2% - 5%$8.22

Contrarotating
propellers(CRPs)All large
vessels; notcompatible
with otherpropulsors

Moderate

Now

Medium2% - 5%$8.22

Ductedpropellers

All vessel
types; notcompatible
with otherpropulsors

Moderate

Now

Medium

0.5% - 5%$12.78Poddedthrusters

All vessel
types; notcompatible
with otherpropulsors

Moderate(but not onlarge cargovessels)

Now

MediumUp to 15%

$19.97Pre-swirl

All vessel
types; only
compatible
with LAPs
and CRPs

Moderate

Now

MediumUp to 10%

$3.52

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226Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Technology

Options/
Applications

Already
widely used?

Availability
date

Likelyadoption
rate

Potential fuelconsumption/
CO2 reduction

Costeffectiveness($/tonne CO2)

Post-swirl

All vessel
types; only
compatible
with LAPs

Moderate

Now

Medium

0.5% - 2%$14.06

Table 13-23: Summary of engine technology options
Technology

Options/
Applications

Already
widely used?

Availability
date

Likelyadoption
rate

Potential fuelconsumption/
CO2 reduction

Fuel injection
valve
improvements(slide valves)

Diesel-cycle
engines

Yes

Now

High

0%

Common rail
fuel injection

Diesel-cycle
engines

Yes

Now

High

0.40%

No cost data
available

Water in Fuel
Emulsion/Water
Injection

Diesel-cycle
engines

No

Now

Low

Small – main
benefits are on
NOx andparticulatematteremissions

No cost data
available

Hybrid dieselelectric

Diesel-cycle
enginesYes forcruise ships,
not for large
cargovessels

Now

MediumMay cause
increase in fuelconsumption
for large
ocean-goingvessels

No cost data
available

Early Intake
Valve Closing(Miller cycle)

Diesel-cycle
engines

Yes

Now

High

Unclear, butalready widelyadopted, so
little future
benefit

No cost data
available

Dual fuel/gas
engines

Low pressure(Otto cycle)

No

Now

High
(scenario
dependent)

None(emissions
reduction due
to alternative
fuel, notenginetechnology)

No cost data
available

High pressure(diesel cycle)

No

Now

High
(scenario
dependent)

None(emissions
reduction due
to alternative
fuel, notenginetechnology) provides
reducedmethane slip

No cost data
available

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Costeffectiveness($/tonne CO2)
No cost data
available

227

Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Technology

Options/
Applications

Already
widely used?

Availability
date

Likelyadoption
rate

Potential fuelconsumption/
CO2 reduction

Costeffectiveness($/tonne CO2)

Ammoniaengines (diesel
cycle)

Diesel-cycle
engines

No

2025

High
(scenario
dependent)

None(emissions
reduction due
to alternative
fuel, notenginetechnology)

No cost data
available

Carbon capture(CC)

All vessel
types (somelimitations
due to spacerequirements)

No

2025

Low

Up to 100%emissions
reduction; maybeaccompanied
by up to 20%
increase in fuelconsumption.

$35.37**

Waste heatrecovery (WHR)

All vessel
types

Moderately

Now

Medium3% - 8%

No cost data
available** Only very limited cost data for mobile CC systems are available. The calculation of cost-effectiveness presented
here uses an average value estimated for a, 8,000 tonne DWT vessel scaled up to a 60,000 tonne DWT vessel
and assumes that the vessel fuel consumption is increased by 20%. It should be noted that other studies (e.g.
(Feenstra, et al., 2019)) have identified significant higher costs per tonne CO2, with a strong non-linear dependence
on vessel size.

Table 13-24: Summary of operational improvements options
Technology

Options/
Applications

Already
widely used?

Availability
date

Likelyadoption
rate

Potential fuelconsumption/
CO2 reduction

Costeffectiveness($/tonne CO2)

Speed
reduction

10% speed
reduction

Yes

Now

High

10% - 15% pership, combinedwith 5% to 7%
increase in fleet
size-$56.0320% speed
reduction

Yes

Now

Medium

18% - 28% pership, combinedwith 12% to 15%
increase in fleet
size-$56.36

30% speed
reduction

Yes

Now

Low

24% - 38% pership, combinedwith 21% to 26%
increase in fleet
size-$56.31

Voyageplanning andweatherrouting

-

Yes

Now

High

0% - 5%-$56.24

Advanced
autopilots

-

No

Now

Medium

0.25% - 1.5%-$58.10Autonomous
shipping

-

No

2030

Low

Up to 6%-$55.39

Ship systemmanagement

Powerdemand

Yes

Now

High

0.25% - 5%-$56.54

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Technological, Operational and Energy Pathways for Maritime Transport to Reduce Emissions Towards 2050
Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

Technology

Options/
Applications

Already
widely used?

Availability
date

Likelyadoption
rate

Potential fuelconsumption/
CO2 reduction

Costeffectiveness($/tonne CO2)

Energyefficiency
measuremen
t

Yes

Now

High

Up to 5%-$56.24

Hull cleaning

Yes

Now

High

1% - 5%-$55.39

Propellercleaning andpolishing

Yes

Now

High

3% - 4%-$56.61

Vesselcapacity
utilisation

-

Yes

Now

Medium0% - 30%-$56.24

Port logistics

-

No

Now

MediumUp to 1%-$51.13

Hull andpropeller
condition
management

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Ref: ED 13389 | Final Report | Issue number 6 | Date 31/01/2022

A.8 Appendix 8 – Full decision matrix used to inform fuel andtechnology package development
Criteria score (1-3)
Readinesslevel

Likelyadoption
rate

Costeffectiveness

Total
score

TRL
(1-9)

Adoption(1-5)

Costeffectiveness*($/tonne CO2)

Optimum ship size
dimensions

3

3

0

6

9

5

-

Construction weight

3

3

0

6

9

5

-

Hull dimensions (form
optimisation)

3

3

3

9

9

5

$3.46

Bulbous bow retrofit

3

2

3

8

9

3

$9.19

Bow thruster tunnel
optimisation

3

2

3

8

9

3

$1.44

Hull coatings

3

2

3

8

9

3

$6.77

Interceptors

3

2

0

5

9

3

-

Ducktail waterline
extension

3

1

0

4

9

1

-

Air lubrication

2

1

2

5

7/8/9

1

$17.27

Ballast reduction and trim
optimisation

3

3

3

9

9

5

$1.44

Flettner rotors

3

2

2

7

9

4

$15.98

Towing kites

2

1

2

5

7/8/9

1

$30.57

Sails

3

1

3

7

9

1

$6.92

Solar panels

3

2

1

6

9

3

$70.05

Shore power supply

3

2

0

5

8/9

3

-

3

2

3

8

9

3

$8.22

Propulsion devices

Power assistance

Vessel design measures

Technology/MeasureEngine / aftertreatment

Assessment

Large area propellers(LAP)
Contra rotating propellers
(CRP)

3

1

2

6

9

1

$30.26

Podded thrusters

3

2

2

7

9

3

$19.97

Ducts (PID)

3

2

2

7

9

3

$12.78Pre-swirl (PID)

3

2

3

8

9

3

$3.52

3

2

3

8

9

3

$14.06

3

0

0

3

9

Common rail fuel injection

3

0

0

3

9

Water in Fuel Emulsion(WiFE)/Water Injection

3

0

0

3

9

Hybrid diesel-electric

3

0

0

3

9

-

3

0

0

3

9

-

3

2

1

7

9

3

$81.34

2

1

2

5

4

1

$37.23**Post-swirl fins and rudder
bulbs (PID)
Fuel injection valve
improvements (slide
valves)

Early Intake Valve Closing(Miller cycle)
Waste heat recovery(WHR)

Carbon capture & storage (CCS)

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was toinclude inbaseline.

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Criteria score (1-3)
Readinesslevel

Likelyadoption
rate

Costeffectiveness

Total
score

TRL
(1-9)

Adoption(1-5)

Costeffectiveness*($/tonne CO2)

Speed reduction

3

3

3

9

9

5

$0.0

Advanced port logistics

3

2

3

8

8/9

3

$0.0

Optimisation of vessel
capacity utilisation

3

2

3

8

8/9

5

$0.0

Advanced autopilots

3

2

3

8

9

3

$0.0

Voyage planning andweather routing

3

3

3

9

9

5

$0.64

Autonomous shipping

2

1

3

6

5/6/7

1-2

$0.0

3

3

3

9

9

5

$2.46

3

3

3

9

9

5

$0.0

Hull cleaning

3

3

3

9

9

5

$0.59

Propeller cleaning andpolishing

3

3

3

9

9

5

$0.11

Technology/Measure

Vessel operational measures

Assessment

Power demand
management e.g. lighting
Engine efficiency
measurements

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A.9 Appendix 9 – Fuel production infrastructure CAPEX and OPEX data
Fuel
type

Exampleplant
capacity(Mt/yr)Fuel pathway

HFO

MDO

Conventional

1.47

Conventional

3.91

Example
plant
CAPEX
($m)

1190

3720

Example plant
CAPEX/total energy($/GJ)

Reference(s)Comment$1.01(FuelsEurope, 2018)(Canadian Fuels
Association, 2013)(JWEnergy, 2017) (BP,2019)

Assumes a split of 0.4% diesel and 0.128%
heavy fuel oil production based on FuelsEurope(OECD & IEA) source. Calculations undertaken
to convert barrels to tonne for capacity and
CAPEX by product type using BP conversion
values.

$1.11(FuelsEurope, 2018)(Canadian Fuels
Association, 2013)(JWEnergy, 2017) (BP,2019)

Assumes a split of 0.4% diesel and 0.128%
heavy fuel oil production based on FuelsEurope
source. Calculations undertaken to convert
barrels to tonne for capacity and CAPEX byproduct type using BP conversion values.

10.00

10000

$0.52

(CBC, 2020)(OffshoreEnergy, 2015)

Proposed $10B liquefied natural gas project inGuysborough County (Goldboro). Lifetime value
taken "for end use in FTA countries for a periodof 20 year". Capacity "10 million metric tons perannum" value used. CAPEX of 10 Billion $ value
used.

Liquidmanure(closed digestatestorage)

0.01

14

$2.05

(Navigant, 2019)

Anaerobic digestion plant values (including
upgrading unit).

Grey Hydrogen

Steam reforming
natural gas

0.79

223

$0.12

(IEAGHG, 2017)

Total capital for base case H2 plant (SMR
without CCS)Blue Hydrogen

Natural gas and
CCS

0.04

411

$4.69

(IEAGHG, 2017)

Total capital for SMR with CCS and liquefaction.
SMR plant includes electricity for own
consumption from heat recovery.

Green Hydrogen

HydrogenElectrolysis(renewableenergy)

0.04

719

$8.21

(FCH2 JU, 2017) (Morgan,
2013)

Green hydrogen PEM including liquefaction.

LNG

GlobalLNG

BioLNG

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Exampleplant
capacity(Mt/yr)Example
plant
CAPEX
($m)

Example plant
CAPEX/total energy($/GJ)

Grey Ammonia

Conventional
naturalgas
feedstock - EUelectricity mix

0.44

705

$4.24

(Brown, 2017)

Blue Ammonia

Natural gas and
CCS

0.21

357

$4.56

(Morgan, 2013)

Green Ammonia

100% renewableproduction

1.20

5000

$11.02(Morgan, 2013)

Grey Methanol

Natural gas

1.50

1166

$1.30

(ADI analytics, 2017)

Green Methanol

Synthetic
methanol - Powerto fuel

3.60

1854

$0.86

(Nyári, 2018)

FAME

Waste cooking oil

0.25

581

$4.15

(ECOFYS, 2013)

Values taken for the Harvest Energy operational
plant that produces biodiesel (FAME) fromprimarily waste oils

HVO

Waste cooking oil(standalone
plants)

0.50

321

$0.97

(TOTAL, 2019)

Based on Total's La Mède HVO biorefinery.

Fuel
type

Fuel pathway

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Reference(s)Comment

Natural gas ammonia plant CAPEX.

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A.10 Appendix 10 – Fuel price development narrative
As noted in Section 6.2.1 of the report, the fuel price projections used for the cost modelling in this study were provided by IHS Markit. This Appendix provides
the accompanying narratives on the development of those projections.

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