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Long-distance renewable hydrogen transmission via cables and pipelines

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Intermittency is one of the main obstacles that inhibit the wide adoption of the renewable energy in the power sector. Small-scale fluctuations can be tackled by short-term energy storage system, whereas long-term or seasonal intermittencies rely on large-scale energy management solutions. Besides the supply and demand mismatch in temporal domain, renewable energy sources are usually far away from consumption points. To connect the energy sources to the demand cost-effectively, cable transmission is usually the default option, and considering the long distance, other emerging energy carriers such as hydrogen could be a feasible option. However, there is handful studies on the quantitative evaluation of the long-distance energy transmission cost. This paper investigated the economic feasibility of renewable energy transmission via routes of power cable and gas pipeline. In the direct power transmission case, renewable energy is transmitted via HVDC cable and then converted to hydrogen for convenient storage. The alternative case converts renewable energy into hydrogen at the source and transports the hydrogen in the gas pipeline to consumers. Existing data available from public domain are used for cost estimation. Results show that the improvements of capacity factor and transmission scale are the most cost-effective approach to make the renewable hydrogen economically viable. At 4000 km of transmission distance, renewable hydrogen LCOE of 7 US/kgand9US/kg and 9 US/kg are achievable for the corresponding optimum cases, respectively.
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Long-distance renewable hydrogen transmission
via cables and pipelines
Bin Miao
a,b
, Lorenzo Giordano
a,b
, Siew Hwa Chan
a,b,*
a
School of Mechanical and Aerospace Engineering, Nanyang Technological University, 50 Nanyang Avenue,
Singapore 639798
b
Energy Research Institute at NTU (ERIAN), 1 CleanTech Loop, Singapore 637141
highlights
The Power-to-Gas technology converts renewable energy into hydrogen for low-cost transmission.
Renewable power fluctuations could be mitigated spatially with power cables and gas pipelines.
The levelized cost of the cable/pipeline transmitted hydrogen are evaluated.
The renewable hydrogen are most sensitive to the capacity factor and transmission capacity.
article info
Article history:
Received 20 October 2020
Received in revised form
5 March 2021
Accepted 8 March 2021
Available online xxx
abstract
Intermittency is one of the main obstacles that inhibit the wide adoption of the renewable
energy in the power sector. Small-scale fluctuations can be tackled by short-term energy
storage system, whereas long-term or seasonal intermittencies rely on large-scale energy
management solutions. Besides the supply and demand mismatch in temporal domain,
renewable energy sources are usually far away from consumption points. To connect the
energy sources to the demand cost-effectively, cable transmission is usually the default
option, and considering the long distance, other emerging energy carriers such as
hydrogen could be a feasible option. However, there is handful studies on the quantitative
evaluation of the long-distance energy transmission cost. This paper investigated the
economic feasibility of renewable energy transmission via routes of power cable and gas
pipeline. In the direct power transmission case, renewable energy is transmitted via HVDC
cable and then converted to hydrogen for convenient storage. The alternative case converts
renewable energy into hydrogen at the source and transports the hydrogen in the gas
pipeline to consumers. Existing data available from public domain are used for cost esti-
mation. Results show that the improvements of capacity factor and transmission scale are
the most cost-effective approach to make the renewable hydrogen economically viable. At
4000 km of transmission distance, renewable hydrogen LCOE of 7 US$/kg and 9 US$/kg are
achievable for the corresponding optimum cases, respectively.
©2021 Hydrogen Energy Publications LLC. Published by Elsevier Ltd. All rights reserved.
*Corresponding author. School of Mechanical and Aerospace Engineering, Nanyang Technological University, 50 Nanyang Avenue,
Singapore 639798.
E-mail address: mshchan@ntu.edu.sg (S.H. Chan).
Available online at www.sciencedirect.com
ScienceDirect
journal homepage: www.elsevier.com/locate/he
international journal of hydrogen energy xxx (xxxx) xxx
https://doi.org/10.1016/j.ijhydene.2021.03.067
0360-3199/©2021 Hydrogen Energy Publications LLC. Published by Elsevier Ltd. All rights reserved.
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
Introduction
Background
Environmental challenges induced by the non-renewable
fossilfuelcombustionaswellastheenergyinsecurity
concerns on the sustainable energy supply stimulated the
rapid development of renewable energy sources (RESs)
[1e4]. Among all the motivations, the tendency to achieve
energy independence was found to promote the most for
the adoption of renewables [1,2], whereas CO
2
emission
and oil &gas price increases appear not as significant in
helping the RESs growth [1]. With the mass production and
technology breakthrough, the capital cost and levelized
cost of renewable energy are now nearly competitive to the
conventional power plant. For instance, the installation
cost of utility-scale solar PV has dropped from 5.52 US$/W
to 1.13 US$/W from 2010 to 2018 and the corresponding
LCOE of electricity now is around 50 US$/MWh [5]. The unit
installation costs of onshore and offshore wind are ranging
from 1.50 US$/W to 4.35 US$/W. The equivalent electricity
costs are in range of 60 US$/MWh to 130 US$/MWh [6,7]. As
benchmark, according to IEA [8], the highly efficient
Combined-Cycle Gas Turbine (CCGT) generates power at
the cost of 38.24e123.84 US$/MWh which varies with their
locations and fuel supply.
The renewable energy intermittency remains one of the
most challenging obstacles for its wide penetration [9].
Along with the demand side fluctuations, the power
mismatch in a regional grid can be as high as tens of GWs,
which is far beyond the handleability of conventional en-
ergy storage, mitigation and power management measures
[9,10]. The existing power grids are dynamically matching
the electricity demand and supply in the network thus
unable to adapt with drastic change of power input [11].
The incorporation of RESs into the grid requires new reg-
ulations, standards, and codes to be established to inte-
grate the different voltage, frequency, ride through, power
quality requirements between new facilities and the
existing infrastructures [12,13]. One way of balancing the
mismatch is to implement energy storage system to shift
thepeak.Theexistingenergystoragesystemshavebeen
systematically reviewed by these works [14e16]. Briefly, the
short-term power fluctuation can be absorbed by quick
response energy storage techniques such as batteries, fly-
wheels, and capacitors [17]. The long-duration, non-dis-
patchable power capacity, usually in the scale of hundreds
of GWh, however, have to be stored with larger-scale
storage such as pumping hydro in high reservoirs [17],
compressed air in salt caverns [18]andelectrolyzed
hydrogen via Power-to-Gas technologies [19e22]. The
pumped hydro is a proven scheme to store electricity in the
scale of GW. By far, some 96% of the existing energy stor-
age capacity, roughly 176 GWs, is dominated by pumped
hydro storage built on natural reservoirs [23]. With the
round trip efficiency 70%~80%, the pumped hydro tech-
nology has emerged as an economically and technologi-
cally viable option for peak load shaving and grid-scale
renewable energy storage [24]. The capital cost of pumped
hydro varies with geological conditions and is in the range
of 1.00 US$/W to 2.50 US$/W with payback period of 40e80
years [25]. The calculation of levelized cost of the pumped
stored water back to electricity is not straight forward, as it
highly depends on the utilization rate of the facilities. A
solar PV integrated pumped storage system in the medium
and long term usage delivers electricity at the cost of 35
EUR/MWh to 300 EUR/MWh which varies with facility costs,
efficiencies, utilization rate, and lifespans [26]. On the
other hand, compressed air storage has not become a
widespread storage technology competitive to pumped
hydro due to a variety of both technical and economic
reasons [18]. The power capacity of compressed air storage
varies with storage cavern size and generally ranges be-
tween hundreds of MW up to GW [18].
Other than energy shifts in the time domain, the other
intermittency mitigation measure could be the energy
transfer from one place to others. For the RESs trans-
mission, electricity is no doubt the most convenient energy
form as conversion losses are eliminated [27]. The main
stream of utility scale electric energy transmission over
long-distances are either using High Voltage Alternating
Current (HVAC) cable or High Voltage Direct Current cable
(HVDC) [28]. The AC cable possesses higher dissipative
losses and higher material cost over high voltage and long-
distance energy transmission due to the skin effectof the
alternating current. On average, the losses on the HVDC
lines are roughly 3.5% per 1000 km, contrasted with HVAC
lines of 6.7% at similar conditions [29]. It has been found
that for transmission distance longer than 60 km subsea or
200kmoverheadHVDChasbettereconomicsperformance
[29]. Europe is leading the subsea HVDC cable in length,
water depth, transmission capacity. Specifically more than
70% of the HVDC submarine cables in the world are located
in European adjacent seas, but most of the projects are less
than300kminlength[28]. The longest power transmission
projects are HVDC overhead transmission cables and are
mainly located in the continent countries [30]. The elec-
tricity is either produced from hydropower or primary
sources that are located far away from energy consumers.
The existing transmission cables are usually in capacity of
several GW with voltage ranges from 400 kV to 1100 kV
overthedistanceofupto3000km[31,32].
Considering the distance effect and the losses incurred
along the power cable, the transmission energy carrier
does not have to be electricity. The existing natural gas
networks can be utilized to transfer the renewable energy
in the form of hydrogen gas with the aid of Power-to-Gas
(PtG) technologies [33e38]. The PtG projects around the
world has been reviewed recently and most of which are
still in pilot plant stage [33e35]. The main steps of PtG
technologies consist of water electrolysis using surplus
renewable power [21,39,40], hydrogen storage and
hydrogen carriers [21,41e44], and the hydrogen reconver-
sion back to electricity [45,46]. It was found that the 100%
renewable power for grid operation is technically feasible
via PtG but significant amount of RESs installation is
needed to cover the grid peak load situation [36]. The use of
mixed renewable power sources to maximize the PtG fa-
cility utilization is important to bring down the levelized
international journal of hydrogen energy xxx (xxxx) xxx2
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
cost [38]. What is more, the further decrease of the RESs
electricity cost and the scaling up of PtG are critical to the
economic viability of the hydrogen produced [38]. Water
electrolysis is the pivot step that converts the energy from
electricity to chemical potential [47]. There are commercial
alkaline electrolysis cells (AEC) and polymer electrolyte
membrane electrolysis cells (PEMEC) and the system cost
areexpectedtodroptotherangeof787e906 V
2017
/kW for
AEC and 397~955 V
2017
/kW for PEMEC, rated by output H
2
higher heating value by 2030 [48]. Whereas the high tem-
perature solid oxide electrolysis cells (SOEC) are in mainly
the emerging and demonstration stage [47,49].
The hydrogen produced, if not consumed immediately,
need to be stored in the form of compressed phase, liquid
phase, or chemical compounds [21,41,42]. For the down-
stream usage of hydrogen, it was found that the hydrogen
reconversion back to electricity via Combined Cycle Gas
Turbines (CCGT) is the most cost-effective option [45]. The
other application could be the energy consumption using
hydrogen fuel cell in certain niches market such as forklift
trucks, while large-scale applications such as fuel cell vehi-
cles (FCVs) are forthcoming in the near future [46]. For the
transmission infrastructure, the existing natural gas net-
works can be utilized to transport the produced hydrogen at
high pressure [50,51]. It has been found that at relatively low
hydrogen concentrations, specifically 5~15% by volume, the
hydrogen blending into natural gas network appears to be
viable without significantly affecting the existing gas supply
chain [52,53]. However, the further increase of the hydrogen
blend concentration, especially at high pressure, would
require extensive investigations case by case and additional
cost may incurred [52]. For example, the investigation of
various metal pipeline embrittlement mechanisms and
hydrogen permeation through the subsurface of the metal
are crucial to the safe utilization of the existing pipelines
[54,55]. On the economic aspect, Michael et al. compared the
urban area hydrogen supply techniques such as truck de-
livery (compressed and liquid phase) and pipeline trans-
portation (low pressure and high pressure) [56]. Their study
showed that with the increase of the hydrogen demand ca-
pacity, pipeline transportation become the lowest-cost op-
tion [56]. Estimation shows that the use of existing natural
gas pipeline can reduce the hydrogen transmission costs by
more than 60% [57].
The scanning of the existing energy transmission infra-
structure reveals great potential to exploit the surplus
renewable energy in spatial domain. The renewable electricity
could be sold to other regions that demand the power
instantly. However, given the high economic risk of such
multinational projects, precedent cases rarely exist, and
feasibility studies are hard to elaborate the full details of the
projects. Besides, none of the existing studies have compared
the long-distance transmission solutions side by side. It is
unknown which energy transmission route is the most suit-
able for certain applications. The costs of various trans-
mission technologies are not in the same equivalent unit and
thus hard to see the advantage and disadvantage of each en-
ergy carrier. It is necessary to establish the conceptual un-
derstanding of the cost in the order-of-magnitude accuracy of
implementing such projects. It is also necessary to know
whether the existing mature technologies can solve the
renewable intermittency issues.
Objectives and scope
The objective of this study is to establish the equivalent cost
comparisons of utility-scale, long-distance energy trans-
mission technologies for non-dispatchable renewable en-
ergies such as solar and wind mitigation. The scope of this
study covered two cases: 1. Direct electricity transmission via
HVDC cable and 2. Renewable hydrogen transportation via gas
pipeline. Considering the low capacity factor of the renewable
power, charge storage in battery is not a practical option.
Thus, the transmitted electricity is assumed to be converted to
hydrogen for storage and downstream applications. At both
cases, onshore and offshore facilities CAPEX, OPEX of major
components are considered in the estimation. At first, the
capital investment of the transmission technology with
respect to the distance between energy source and energy
sink are evaluated. To quantitively examine the cost of long-
distance transfer of renewable energy, the LCOE of the
transported hydrogen in unit of US$/kg is estimated for
comparison. Lastly, the sensitivity studies of key parameters
are conducted.
Methods
Basic cases
Publicly available transmission line [28,29] and gas pipeline
data are used for the cost estimation. The renewable energy is
either transferred directly in the form of electricity in power
cables or converted to hydrogen before the transmission in
gas pipelines. It should be noted that the power cable trans-
mitted electricity is to be converted to hydrogen at the desti-
nation eventually. The fundamental assumption is that the
grid-scale electricity is not economically storable at current
stage, meanwhile the capacity factor of the renewable energy
is not capable of sustaining a stable grid operation. The
referenced costs are the lump-sum of the entire project which
inclusive of all the necessary components. For instance, a
typical HVDC transmission link consists of renewable sources,
AC transmission lines, an AC to DC converter station, HVDC
transmission lines, a DC to AC converter station, AC trans-
mission and distribution lines [29]. The pipeline infrastructure
comprised of energy conversion via PtG facilities, gas buffer
storage tanks, compressors, gas pipeline, and receiving in-
frastructures [58]. This study is not elaborating the project
components detail implicitly as they vary drastically with
project locations. Instead, the parametric scanning of key
parameters in a broad range should cover the uncertainty
incurred by the project cost variations.
A conceptual illustration of both energy transfer routes is
shown in Fig. 1.
Assumptions
Despite the cost of the projects may vary with construction
year, location, topographic features along the line, the capital
international journal of hydrogen energy xxx (xxxx) xxx 3
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
cost in this study is simply calculated by taking the average of
publicly available data of long-distance power cable and gas
pipeline projects. Also, it is assumed that the capital cost is
linearly related to the transmission distance. This assumption
may underestimate the short-distance capital cost and over-
estimate the capital long-distance cost. The transmission ca-
pacity is scaled down with empirical equation to match
1000 MW renewable energy source. The hydrogen pipeline
cost was assumed to be similar to that of natural gas pipelines
with an additional 10% increase [27]. The other key assump-
tions are supported with credible data sources from respective
industry authorities and communities and are listed in Table
1:
For the operation and maintenance (O&M) cost, cables are
considered as maintenance-freeexcept incident fault re-
pairs [60]. The O&M cost also inclusive of routine inspections
and scheduled services. Report shows that the annual O&Mof
transmission cable roughly contributes to 0.46%~0.50% of its
CAPEX for offshore projects [60] and 0.09%~0.11% of CAPEX for
onshore overhead cables [60]. The onshore pipeline O&Mis
assumed to be 4% [57] and the offshore pipeline O&Mis
assumed to be 7% [61]. The electricity cost of 78.67 US$/MWh is
taken from global weighted average LCOE of renewable power
[7]. The cost is simply averaged from solar PV, onshore and
offshore wind costs. The averaged capacity factor of 32.7% for
the renewable power is taken from the same source [7]. HVDC
power transmission loss is roughly 3.5% per 1000 km [29]. The
fugitive emission from high-pressure gas pipeline is roughly
0.02%e0.05% per 1000 km per year [63].
Calculations
The capital cost is annualized using Eq. (1) Capital Recovery
Factor (CRF) which reflects the time value of money. The time
in unit of year is determined by the facility operator. The
capital cost shown in Eq. (2) in unit of percentage is a weighted
average value of capital interest rate, opportunity cost, risk,
and the company tax, dept and so on [64]. The Levelized Cost
of Electricity (LCOE) is then calculated from the annualized
capital and fixed operational cost by dividing the amount of
annually transported energy, as shown in Eq. (3). Variable cost
and fuel cost are directly added to the LCOE.
CRF ¼hið1þiÞti.hð1þiÞt1i(1)
iWACC ¼grfþDPð1rtaxÞþð1gÞ
rfþbequity rmrf (2)
LCOE ¼Ccap CRF tþFO&MN
NEtrans
þ0
@Cenergy ÷Y
j
hj1
A(3)
Where in Eq. (1) CRF is the capital recovery factor that
converts the present value into a stream of equal annual
payments over the period of t,iis the capital cost. In Eq. (2) iis
equivalent to the weighted average cost of capital (WACC), in
which all the economic parameters are taken from Energy
Market Authority (EMA) in the gas turbine power plant oper-
ating cost estimation report [64]. The WACC is the weighted
Fig. 1 eSchematic of power-to-gas in spatial domain. The basic cases are 1. Renewable hydrogen transmission via gas
pipelines and 2. Renewable power transmission in electricity cables.
Table 1 eTable of key assumptions.
Offshore Cable Onshore Cable Offshore Pipeline Onshore Pipeline
Transmission Capacity [MW] 1000 1000 1000 1000
Electrolyzer Capital [US$/kW] 1500 [59] 1500 [59] 1500 [59] 1500 [59]
Cable/Pipeline Normalized Cost [M US$/km] 2.00 0.34 0.96 0.34
O&M [%] 0.5% [60] 0.1% [60] 7.0% [61] 4.0% [57]
Renewable Electricity [US$/MWh] 78.67 [7] 78.67 [7] 78.67 [7] 78.67 [7]
Electrolysis efficiency 62.0% [59] 62.0% [59] 62.0% [59] 62.0% [59]
Lifespan [Year] 40 [60]40[60]40[62]40[62]
Capacity Factor [%] 32.7% [7] 32.7% [7] 32.7% [7] 32.7% [7]
Capital Interest [%] 8.0% 8.0% 8.0% 8.0%
CRF [%] 14.9% 14.9% 14.9% 14.9%
Capital payback [Year] 10 10 10 10
Trans. Efficiency [%] 86.0% [29] 86.0% [29] 99.8% [63] 99.8% [63]
Transmission distance [km] 4000 4000 4000 4000
international journal of hydrogen energy xxx (xxxx) xxx4
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
combination of g, gearing of the company, rf, the risk-free
interest, DP, dept premium, rtax, the tax rate of the company,
bequity, the measure of the sensitivity of the company’s returns
to market returns, ðrmrfÞ, the market risk premium. The
typical values of the WACC parameters are found in reference
[64]. The calculated interest rate is round up to 8% in this study
for simplicity. In Eq. (3),Ccap is the capital cost of the plant in
unit of US$, FO&Mis the fixed operating and maintenance cost,
N is the lifespan of the facility, Etrans is the energy transmitted
each year, Cenergy is the energy cost, and Q
j
hjis the multiplica-
tion of efficiencies for the energy conversion and trans-
mission. The subscript jrepresents the jth stage of energy
conversion. The existing projects for both cable and pipeline
are rated at different transmission capacity. Before averaging
the cost, the pipeline and cable capitals are normalized to
1000 MW equivalent transmission capacity according to the
following equation [65]:
C2¼C1Q2
Q1x
(4)
Where C is the cost of the project and Q is the flow rate or
power capacity of the transmission line, and xis the empirical
exponential factor which normally determined from previous
data and typical valued as 0.6. The normalized project costs
are projected to 2020 US$ using annual inflation rate of 4%.
Results and discussion
Hydrogen levelized cost breakdown
The hydrogen cost per kilogram breakdown is shown in Fig. 2.
Similar to a typical utility cost breakdown, the capital and
fuelportions occupied the main fractions. In this study
fuelrefers to surplus electricity which reflects the averaged
auction price of renewable energy. Overall, onshore trans-
missions are cheaper than offshore transmissions. Cable
transmission is more expensive than pipeline in the offshore
cases and for the onshore cases both cable and pipeline have
similar cost at 4000 km transmission distance. The cables are
relatively maintenance free and undertaking more trans-
mission loss, which has been reflected in the higher electricity
cost terms. The pipelines on the other hand need to spend
compression energy all along the line and the cost of the
compression is embedded in the pipeline O&M.
The results show that the long-distance transmitted
hydrogen costs are too high for certain downstream applica-
tions such as power generation or town gas usage. Even in the
onshore cases the hydrogen LCOEs are around US$10 per kg.
In the power generation market, the transmitted hydrogen is
not competitive to the conventional natural gas unless the
electricity tariff to be increased by an order of magnitude. To
overcome the high cost, more hydrogen must be transmitted
through the lines to share the heavy CAPEX. This can be done
either by increase the capacity factor or the transmission ca-
pacity of the lines.
Hydrogen levelized cost and capacity factor
Assuming 1000 MW of renewable power is to be transmitted in
the cable or pipeline, the LCOEs with respect to the increase of
capacity factor are shown in Fig. 3. It can be found that the
LCOE is very sensitive to the capacity factor from 10% to 50%
but the further increase of capacity factor is not cost effective
thereafter. At the base case where capacity factor was set to
32.7% all the routes deliver hydrogen at an of cost higher than
10 US$/kg. With the capacity factor increased to roughly 40%,
the costs of onshore transmitted hydrogen are below 10 US$/
kg. Whereas for the offshore hydrogen costs, at least 50% ca-
pacity factor is necessary to bring it down to 15 US$/kg.
A well-managed conventional power plant has a capacity
factor of 50%, but it is challenging to bring up renewable ca-
pacity factor above that benchmark. To fully utilize the
transmission facilities, the mixing of multiple sources of
renewable could be helpful. However, the fluctuation of these
sources persisted which results to the underutilization of the
renewable facilities themselves.
Fig. 2 eLCOE of Power-to-Gasin Spatial Domain at 4000 km, 32.7% capacity factor, 1000 MW transmission capacity.
international journal of hydrogen energy xxx (xxxx) xxx 5
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Hydrogen levelized cost and transmission capacity
On the other hand, with more renewable power trans-
mitted, the levelized cost can be further reduced, even
when the utilization rate of the facilities is low. With the
same 32.7% capacity factor applied, the LCOE with respect
to the increase of transmission capacity is plotted in Fig. 4.
The onshore hydrogen LCOEs dropped below 10 US$/kg at
the capacity of 1000e1500 MW, and the offshore hydrogen
LCOEs dropped below 15 US$/kg when the capacity reached
2000 MW. These results indicate that with the scaling-up
of the transmission capacity, more energy is carried
through the linesthus lower cost of hydrogen can be
expected.
At an optimum case with 50% capacity factor (possibly
achievable at mixture of renewable energy sources and proper
optimization) the LCOEs with the increase of transmission
capacity is shown in Fig. 5. Results show that the simulta-
neous improvement of capacity factor and transmission ca-
pacity is the most effective approach to reduce the hydrogen
cost. At this optimum case, the onshore pipeline hydrogen is
below 7 US$/kg with the capacity scaling-up to 3000 MW, and
the offshore cable hydrogen is below 9 US$/kg with capacity of
5000 MW and beyond.
Fig. 3 eHydrogen LCOE with respect to facility capacity factor at 4000 km transmission distance, 1000 MW transmission
capacity.
Fig. 4 eHydrogen LCOE with respect to renewable capacity at 4000 km transmission distance, 32.7% capacity factor.
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The offshore cases are more sensitive to the capacity
growth. Unlike capacity factor that reduces the LCOE free of
charge, the increase of transmission capacity incurs CAPEX
increment. The benefit of capacity expansion comes from the
scale effect of building larger capacity at one step, thus save
the cost. However, the scale effect is empirical which merely
reflects the effectiveness of Eq. (3) and the exponential factor
x. To compensate the scaling equation uncertainty, a para-
metric scanning on the transmission capacity and trans-
mission line unit cost is tabulated in Appendix 1 Table 6 for
reference. The dependency between facility unit cost and its
transmission scale is eliminated in Table 6 so that the LCOE is
not affected by the empirical equation.
Hydrogen levelized cost and transmission distance
Remaining transmission capacity to be 1000 MW and ca-
pacity factor of 32.7%, the LCOE of hydrogen is plotted
against the transmission distance as shown in Fig. 6. The
LCOEs are roughly proportional to the transmission distance
for all the cases except that for the cable cases the trans-
mission loss generates a slight exponential upper bending to
the cost. This is due to the accumulation of energy loss of
3.5% per each 1000 km transmitted on the cable. Comparing
the offshore transmissions, the cost discrepancy between
cable and pipeline is increasing with the distance increment.
Whereas for the onshore transmissions, cable transmitted
hydrogen cost is slightly lower than that of pipeline trans-
mitted but the difference is not significant. Due to the limited
cases used in this study, the variation between cables and
pipelines could be affected by a single extreme case, thus no
concluding remark can be made. Overall, with the distance
further increases to 10,000 km, the cost of offshore cable
transmitted hydrogen grows rapidly. The hydrogen costs of
offshore pipeline, onshore cable, onshore pipeline are rising
at a modest pace.
Assuming that the transmission can be scaled up to
5000 MW, the plot of hydrogen LCOEs with respect to trans-
mission distance is shown in Fig. 7. With the capacity scaling
up, LCOEs dropped down significantly at all cases. At 4000 km
distance, the hydrogen LCOE of offshore cases are around 11
US$/kg and the onshore cases are below 9 US$/kg. Along the
transmission distances, onshore pipeline transmission wins
over all other options.
In comparison with the results of Fig. 6, offshore cable
transmission benefits the most from the scaling up. At
transmission distance shorter than 7000 km, the offshore
cable transmission is a cheaper option compared to offshore
pipeline. This is in consistence with results from Figs. 4 and 5
that with the increase of transmission capacity the hydrogen
LCOE transmitted from cables dropped down more rapidly
than pipelines. However, a marginal effect starts to emerge
when the capacity increased to 4000 MWe5000 MW. The
further scaling up is not cost-effective after that.
Transmission line unit cost and total cost
The unit cost of cable and pipeline are listed in Table 2.By
simply averaging the available data, pipelines are more
expensive than cables in terms of per unit length constructed.
However, pipelines usually have much higher equivalent
energy carrying capacity than cables, hence they are not
compared in parallel normally. But situation may change for
long distance and bulk transmission. By normalizing the
transmission capacity to carry 1000 MW renewable energy,
the cables unit cost exceeds the pipelines cost for the offshore
transmission. For the onshore situation, cables and pipelines
have similar unit cost. The cable is directly transmitting the
intermittent renewable power which has a capacity factor of
as low as 32.7%, thus the cables are mostly underutilized than
the pipelines. For the pipelines, the amount of gas carried is
firstly reduced by the low capacity factor of renewable power
Fig. 5 eHydrogen LCOE with respect to renewable capacity at 4000 km transmission distance, 50% capacity factor.
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of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
and secondly diminished by the electrolyzer efficiency
(assumed 62%) thus much lesser gas transmission capacity is
required.
The total capital costs of cables and pipelines are tabulated
in Table 3 according to the distance transmitted. The cost of
each components is normalized using Eq. (3) which scales
down the capacity to carry 1000 MW (or 1 GW) equivalent
renewable power with unit of Billion US$/GW. The capacity
normalization diminished the pipeline cost extensively and
make it cheaper than cable cost at the same transmission
Fig. 6 eHydrogen LCOE with respect to transmission distance from 1000 to 10000 km at 1000 MW transmission capacity,
32.7% capacity factor.
Fig. 7 eHydrogen LCOE with respect to transmission distance from 1000 to 10000 km at 5000 MW transmission capacity,
32.7% capacity factor.
Table 2 eCapital cost per unit transmission distance for 1000 MW renewable energy transmission capacity.
Offshore Cable Onshore Cable Offshore pipeline Onshore Pipeline
Average Cost [M US$/km] 2.00 0.96 8.99 3.64
Normalized Cost [M US$/GW/km] 2.02 0.34 0.96 0.34
Normalized Cost Present Value [M US$/GW/km] 3.03 0.43 1.34 0.76
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capacity. The capital investments of cables and pipelines are
in the order of billion US$ and are proportional to the trans-
mission distance. The fully utilization of the high cost lines is
the key to bring down the transmitted energy cost.
Sensitivity study
Sensitivity study has been conducted to evaluate the effects of
key parameters to the hydrogen cost. The evaluation includes
the renewable electricity price, project lifespan, capacity fac-
tor of facilities, electrolyzer cost and electrolysis efficiency.
For those highly flexibleparameters such as electrolyzer
cost and renewable power cost, plus and minus 50% of the
basic case is applied. Since it is unlikely to achieve high per-
centage of improvement for the electrolysis efficiency and
capacity factor thus plus and minus 10% are applied for the
two parameters. This section provides quantitative evalua-
tions of key parameters whereas detailed tables are attached
in Appendix 1 for reference.
Overall, the increase of electrolysis efficiency, facility life-
span, and capacity factor are favorable to the LCOE reduction
to different extents. The offshore cable results show that ca-
pacity factor has the most effect, especially at the positive
side, as shown in Fig. 8. The decrease of 10% capacity factor
will incur nearly 30% of the LCOE surge. This possibly reflects
that the cable is highly underutilized, and the further reduc-
tion of the capacity factor is undesired. The electrolysis effi-
ciency plays a key factor for all the offshore and onshore cases
as it directly affects the amount of energy converted to
hydrogen.
The impact of renewable electricity cost on the onshore
cables is stronger than that on the offshore cables, as shown
in Fig. 9. This is because onshore facilities have relative lower
CAPEX than offshore facilities thus the electricity occupied
larger fraction. The further utilization (higher capacity factor
and longer lifespan) of a cheaperfacility does not level
down the LCOE significantly, which also explains the minor
effects of capacity factor and facility lifespan on the onshore
cables.
On the aspect of pipeline transmission, as shown in Fig. 10
and Fig. 11, the electrolysis efficiency, electricity cost, and
capacity factor have high impacts on the LCOE. Specially, the
O&M cost takes up a big portion in the offshore pipeline
transmission cost and the LCOE are very sensitive to the O&M.
This is in consistence with the practical cases for the offshore
pipeline projects where the annual O&M contributes to
approximately 5e10% of the CAPEX [66]. On the other hand,
the renewable electricity cost has a stronger effect on the
onshore pipeline since the CAPEX is relatively lower.
In general, parameters that affect both CAPEX and OPEX
have the most impact on the hydrogen LCOE. For instance,
capacity factor and electrolysis efficiency influence the lev-
elized CAPEX (the denominator part) and OPEX thus imposing
a strong impact on the LCOE for all cases. With these param-
eters enhanced, more energy is transmitted which reduced
the levelized CAPEX, but they also lead to higher OPEX. The
sensitivity of these parameters is usually facing an asymptotic
limit when they reach certain percentage, and the boundary
improvement of these parameters are not cost effective. On
the other hand, parameters that affect individually on CAPEX
or OPEX normally have secondary impact on the LOCEs. For
example, facility lifespan influences the levelized CAPEX de-
nominator portion by increasing the year of usage, but it does
not affect the operation cost of each year. Similarly, electro-
lyzer capital moderately changes the CAPEX nominator
portion and its influence on LCOE is narrowing down with the
increases of transmission distance. The effects of a parame-
ters generally depend on their proportion in the LCOE cost
Table 3 eTotal capital cost with respect to transmission distance.
CAPEX [Billion US$/GW] Distance [km]
500 1000 1500 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Offshore Cable 2.80 4.32 5.83 7.34 10.37 13.40 16.42 19.45 22.47 25.50 28.53 31.55
Onshore Cable 1.51 1.72 1.94 2.16 2.59 3.03 3.46 3.90 4.33 4.77 5.20 5.64
Offshore Pipeline 2.17 2.84 3.51 4.19 5.53 6.87 8.21 9.56 10.90 12.24 13.59 14.93
Onshore Pipeline 1.88 2.26 2.64 3.02 3.78 4.54 5.30 6.06 6.82 7.59 8.35 9.11
Fig. 8 eSensitivity study of offshore cable hydrogen LCOE at 4000 km transmission distance.
international journal of hydrogen energy xxx (xxxx) xxx 9
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of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
breakdown. For example, electricity cost is always occupying
a large fraction in the LCOE cost breakdown, though it only
affects the OPEX of the hydrogen cost. With the scaling-up and
further development of key technologies, some parameters
such as electrolyzer efficiency and its cost, renewable elec-
tricity cost, facility lifespan are expected to reduce the
renewable hydrogen cost to certain extends. The further
improvement of capacity factor is more challenging as it
involved system level optimization and multinational
collaborations.
General discussion
Power cables and gas pipelines are two distinct energy
transmission techniques and are sustaining different energy
sectors. Cables transmit renewable electricity directly without
energy conversion loss, but the intermittent renewable energy
arouses challenges for the subsequent grid integration. At the
same cost per unit length, pipelines transmission capacity is
much higher than that of cables, due to the much larger en-
ergy density of the carriers. However, renewable electricity
Fig. 9 eSensitivity study of onshore cable hydrogen LCOE at 4000 km transmission distance.
Fig. 10 eSensitivity study of offshore pipeline hydrogen LCOE at 4000 km transmission distance.
Fig. 11 eSensitivity study of onshore pipeline hydrogen LCOE at 4000 km transmission distance.
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of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
needs to be converted to hydrogen prior to the pipeline
transmission.
The feasibility for long-distance renewable energy trans-
mission varies with several factors. The determining factors
are not only limited to the parameters of cable and pipeline
themselves but also involved other competing technologies.
For example, shipping is inevitably a competitive third option
for long-distance transmission route, although the selection of
hydrogen carriersis also full of tradeoffs. Specifically, hydrogen
has to be transmitted via its compressed or liquified form or to
be converted to other liquid carriers, which incurs further en-
ergy losses during the carrier synthesis and reforming stages.
Plants for the carrier synthesis andreforming also accumulates
the investment risks unless existing plants can be utilized.
Other than the factors from alternative transmission technol-
ogies, upper and downstream infrastructure and technology
breakthroughs are adding variations to the selection of energy
transmission. For the upper stream aspect, decentralized
generator makes it cost-effective and environmentally friendly
to deploy the spinning reserves for the grid, which raise the
possibility of balancing the renewable intermittency and
enhance the renewable capacity factor. This is favorable for the
direct cable transmission yet there is a long way to go to fill in
the gap of GW-scale renewable energy fluctuations. For the
downstream, electrification of the transportation sector could
benefit the cable option. Nonetheless, the cable losses over
long-distance are still too high.
On the other side, except for the motivations of decar-
bonization and renewable power utilization, energy security is
another critical factor for long-distance, multinational energy
trading. This concern is valid for both energy importers and
exporters. Conventional chemical forms of energy carriers
possess stable characteristics and cheap storage facilities thus
are suitable for long-term storage. Hydrogen economy could
be a pivotal connector between renewable energy and existing
oil &gas infrastructure and could enhance the rigidity of en-
ergy supply chain, by providing more options. On the aspect of
energy suppliers, the green hydrogen generated from renew-
ables could change the geographical distribution of energy
resources in a long run. For the energy consumers’ perspec-
tive, the transportation sector can be readily hydrogenated
via fuel cell vehicles (FCVs) to mitigate the greenhouse emis-
sion challenge. The FCVs fuel market has much higher toler-
ance to hydrogen price compared with power generation and
industrial sectors, though hydrogen distribution infrastruc-
ture urged to be built to bridge the broader consumer market.
A proven niche market has been established in the fuel cell
forklift, buses, and heavy-duty trucks for routine operations.
Conclusion
In this paper, the costs of renewable hydrogen transmitted via
power cable and gas pipeline are evaluated. Existing publicly
available projectsdata are used for the cost estimation. Onlythe
major components along the transmission line are considered
in the calculation. The pipeline installation cost per unit length
is much higher than cables but they also have higher energy
transmission capacity. Thus, the normalized pipeline capital
costs are cheaper. From the aspect of operational cost, it was
found that cables have higher energy loss over long distance
whereas pipeline have higher O&M for gas compression. Other
than that, the electrolyzer CAPEX &OPEX are occupying small
fractions as they are not depending on transmission distance. In
the basic cases, pipeline transmitted hydrogen is cheaper,
especially for long distance. But cable transmission benefits
more from scaling up and higher utilization. The increase of
capacity factor is always beneficial to both cables and pipelines.
To further leveling the high CAPEX, theincrease of transmission
capacity and capacity factor are the most practical approaches,
while the decrease of renewable electricitycost and the increase
of electrolysis efficiency are also effective options to reduce
hydrogen LCOE. For both cables and pipelines transmitted
renewable hydrogen, low utilization is one of the main reasons
its high cost. Unfortunately, it is challenging to further increase
the renewable energy capacity factor beyond 50% in the short-
term. The existing energy storage systems are not in the same
order of magnitude compared to grid energy demand. Supple-
menting the renewable with fossil fuel power plant will violate
the purposeof decarbonization. Also, the supplement fossil fuel
power plant is again facing the problem of low utilization and
idling as spinning reserve. To gain economic advantage, scaling-
up the transmission capacity is the out of thebox solution. Other
than that, technology development on the electrification and
hydrogenationare two promising directionsfor energy sector
transformation. The intermittency will remain challenge with
the further development of renewable power. Meanwhile, it
may provide new opportunities in the emerging supply chain
such as regional renewable power grid or gas grid, international
shipping of liquid form of renewable energy carriers and so on.
In the foreseeable future, renewable power will continueto play
a vital role to tackle the GHG emission, sustain energy self-
sufficiency, and drive the energy transition, towards a better
world.
Declaration of competing interest
The authors declare that this paper is purely an independent
academic study. The opinions and results in this paper
represent the outcome of the studies based on some as-
sumptions obtained from open literature and have nothing to
do with anyone others than the authors.
Appendix 1. Parameter Scanning
The renewable hydrogen costs are so sensitive to the scale of
transmission thus it is important to know the threshold ca-
pacity to make the economic sense. With the increase of
transmission capacity to 10 GW and the capacity factor to
100% (probably with mixing of other sources of hydrogen) the
hydrogen LCOE is tabulated in Table 4 (Table 4.1, 4.2, 4.3 and
4.4). The other assumptions remain the same as Table 1.
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Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
Table 4.1 eOffshore cable optimum LCOE with respect to transmission capacity and capacity factor
[US$/kg] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 62.82 51.16 42.32 38.18 35.63 33.84 32.49 31.42 30.55 29.82 29.20
20% 34.27 28.44 24.02 21.95 20.67 19.78 19.10 18.57 18.13 17.77 17.46
33% 23.18 19.61 16.91 15.65 14.86 14.32 13.90 13.58 13.31 13.09 12.90
40% 19.99 17.08 14.87 13.83 13.19 12.75 12.41 12.14 11.93 11.74 11.59
50% 17.14 14.81 13.04 12.21 11.70 11.34 11.07 10.86 10.68 10.54 10.41
60% 15.23 13.29 11.82 11.13 10.70 10.40 10.18 10.00 9.86 9.73 9.63
70% 13.87 12.21 10.95 10.35 9.99 9.73 9.54 9.39 9.26 9.16 9.07
80% 12.85 11.40 10.29 9.78 9.46 9.23 9.06 8.93 8.82 8.73 8.65
90% 12.06 10.77 9.78 9.32 9.04 8.84 8.69 8.57 8.48 8.40 8.33
100% 11.43 10.26 9.38 8.96 8.71 8.53 8.39 8.29 8.20 8.13 8.06
Table 4.2 eOnshore cable optimum LCOE with respect to transmission capacity and capacity factor
[US$/kg] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 24.16 19.41 17.04 16.25 15.85 15.62 15.46 15.35 15.26 15.19 15.14
20% 14.94 12.56 11.38 10.98 10.79 10.67 10.59 10.53 10.49 10.46 10.43
33% 11.36 9.90 9.18 8.94 8.82 8.74 8.70 8.66 8.64 8.62 8.60
40% 10.33 9.14 8.55 8.35 8.25 8.19 8.15 8.12 8.10 8.09 8.07
50% 9.40 8.46 7.98 7.82 7.74 7.70 7.67 7.64 7.63 7.61 7.60
60% 8.79 8.00 7.60 7.47 7.41 7.37 7.34 7.32 7.31 7.30 7.29
70% 8.35 7.67 7.33 7.22 7.16 7.13 7.11 7.09 7.08 7.07 7.06
80% 8.02 7.43 7.13 7.03 6.98 6.95 6.93 6.92 6.91 6.90 6.89
90% 7.77 7.24 6.97 6.89 6.84 6.82 6.80 6.79 6.78 6.77 6.76
100% 7.56 7.09 6.85 6.77 6.73 6.71 6.69 6.68 6.67 6.66 6.66
Table 4.3 eOffshore pipeline optimum LCOE with respect to transmission capacity and capacity factor
[US$/kg] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 36.11 30.56 26.36 24.39 23.17 22.32 21.68 21.17 20.76 20.41 20.11
20% 26.08 21.88 18.69 17.20 16.28 15.63 15.14 14.76 14.45 14.18 13.96
33% 21.24 17.79 15.17 13.94 13.19 12.66 12.26 11.94 11.68 11.47 11.28
40% 19.64 16.45 14.04 12.90 12.20 11.72 11.35 11.06 10.82 10.62 10.45
50% 18.06 15.15 12.94 11.91 11.27 10.82 10.48 10.22 10.00 9.82 9.66
60% 16.92 14.21 12.16 11.19 10.60 10.18 9.87 9.62 9.42 9.25 9.11
70% 16.04 13.49 11.56 10.65 10.10 9.70 9.41 9.18 8.99 8.83 8.69
80% 15.33 12.91 11.08 10.23 9.70 9.33 9.05 8.83 8.65 8.50 8.37
90% 14.75 12.44 10.70 9.88 9.37 9.02 8.75 8.54 8.37 8.23 8.10
100% 14.25 12.05 10.37 9.59 9.10 8.76 8.51 8.31 8.14 8.00 7.88
Table 4.4 eOnshore pipeline optimum LCOE with respect to transmission capacity and capacity factor
[US$/kg] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 42.04 27.62 20.41 18.01 16.80 16.08 15.60 15.26 15.00 14.80 14.64
20% 23.14 15.93 12.32 11.12 10.52 10.16 9.92 9.75 9.62 9.52 9.44
33% 15.80 11.39 9.18 8.45 8.08 7.86 7.71 7.61 7.53 7.47 7.42
40% 13.69 10.08 8.28 7.68 7.38 7.20 7.08 6.99 6.93 6.88 6.84
50% 11.80 8.91 7.47 6.99 6.75 6.61 6.51 6.44 6.39 6.35 6.32
60% 10.54 8.13 6.93 6.53 6.33 6.21 6.13 6.07 6.03 6.00 5.97
70% 9.64 7.58 6.55 6.20 6.03 5.93 5.86 5.81 5.77 5.75 5.72
80% 8.96 7.16 6.26 5.96 5.81 5.72 5.66 5.61 5.58 5.56 5.54
90% 8.44 6.83 6.03 5.77 5.63 5.55 5.50 5.46 5.43 5.41 5.39
100% 8.02 6.58 5.85 5.61 5.49 5.42 5.37 5.34 5.31 5.29 5.28
international journal of hydrogen energy xxx (xxxx) xxx12
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of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
The effect of renewable electricity cost was estimated in
the sensitivity study section. Table 5 (Table 5.1, 5.2, 5.3 and 5.4)
tabulated the hydrogen LCOE at various renewable electricity
cost with different capacity factor. The other assumptions
remain the same as Table 1.
The scale up empirical equation may have distinct effects
on different transmission technologies thus introduce un-
certainties. Parametric scanning of both transmission line
unit cost and transmission capacity are tabulated in Table 6
Table 5.1 eOffshore Cable LCOE with respect to renewable electricity cost and capacity factor
[US$/kg] Renewable Electricity Cost [US$/MWh]
30.00 40.00 50.00 60.00 70.00 80.00 90.00 100.00
Capacity Factor [%] 10% 47.62 48.35 49.08 49.80 50.53 51.26 51.98 52.71
20% 24.90 25.63 26.36 27.08 27.81 28.54 29.26 29.99
33% 16.08 16.80 17.53 18.26 18.98 19.71 20.44 21.16
40% 13.54 14.27 14.99 15.72 16.45 17.17 17.90 18.63
50% 11.27 12.00 12.72 13.45 14.18 14.90 15.63 16.36
60% 9.75 10.48 11.21 11.93 12.66 13.39 14.11 14.84
70% 8.67 9.40 10.13 10.85 11.58 12.31 13.03 13.76
80% 7.86 8.59 9.31 10.04 10.77 11.49 12.22 12.95
90% 7.23 7.96 8.68 9.41 10.14 10.86 11.59 12.32
100% 6.72 7.45 8.18 8.90 9.63 10.36 11.08 11.81
Table 5.2 eOnshore Cable LCOE with respect to renewable electricity cost and capacity factor
[US$/kg] Renewable Electricity Cost [US$/MWh]
30.00 40.00 50.00 60.00 70.00 80.00 90.00 100.00
Capacity Factor [%] 10% 15.88 16.60 17.33 18.06 18.78 19.51 20.24 20.96
20% 9.03 9.75 10.48 11.21 11.93 12.66 13.39 14.11
33% 6.37 7.09 7.82 8.55 9.27 10.00 10.73 11.45
40% 5.60 6.33 7.06 7.78 8.51 9.24 9.96 10.69
50% 4.92 5.65 6.37 7.10 7.83 8.55 9.28 10.01
60% 4.46 5.19 5.92 6.64 7.37 8.10 8.82 9.55
70% 4.14 4.86 5.59 6.32 7.04 7.77 8.50 9.22
80% 3.89 4.62 5.35 6.07 6.80 7.53 8.25 8.98
90% 3.70 4.43 5.16 5.88 6.61 7.34 8.06 8.79
100% 3.55 4.28 5.00 5.73 6.46 7.18 7.91 8.64
Table 5.3 eOffshore Pipeline LCOE with respect to renewable electricity cost and capacity factor
[US$/kg] Renewable Electricity Cost [US$/MWh]
30.00 40.00 50.00 60.00 70.00 80.00 90.00 100.00
Capacity Factor [%] 10% 27.94 28.48 29.02 29.56 30.10 30.63 31.17 31.71
20% 19.26 19.79 20.33 20.87 21.41 21.95 22.49 23.03
33% 15.17 15.70 16.24 16.78 17.32 17.86 18.40 18.94
40% 13.83 14.37 14.91 15.44 15.98 16.52 17.06 17.60
50% 12.53 13.07 13.61 14.14 14.68 15.22 15.76 16.30
60% 11.59 12.13 12.67 13.20 13.74 14.28 14.82 15.36
70% 10.87 11.41 11.95 12.48 13.02 13.56 14.10 14.64
80% 10.29 10.83 11.37 11.91 12.45 12.99 13.52 14.06
90% 9.82 10.36 10.90 11.44 11.98 12.51 13.05 13.59
100% 9.42 9.96 10.50 11.04 11.58 12.12 12.66 13.19
international journal of hydrogen energy xxx (xxxx) xxx 13
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
(Table6.1,6.2,6.3and6.4) to avoid the dependency between
these two parameters.
Appendix 2. Total Hydrogen Transmitted
The amount of hydrogen transmitted per year through the
cable and pipeline with various transmission capacity and
capacity factor are tabulated in Table 7 (Table 7.1 and 7.2). The
scales of the transmitted hydrogen are within the range of
global hydrogen demand expectation in 2025 projected by
Australian Renewable Energy Agency (ARENA) [67].
Table 6.1 eOffshore Cable LCOE with respect to transmission line unit cost and capacity factor
[US$/kg] Offshore Cable Unit Cost [Million US$/km]
0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 6.0 7.0 8.0 9.0 10.0
Transmission Capacity [MW] 1000 10.3 12.1 14.0 15.8 17.7 19.5 21.4 23.2 25.0 26.9 30.6 34.3 38.0 41.6 45.3
2000 9.4 10.3 11.2 12.1 13.1 14.0 14.9 15.8 16.8 17.7 19.5 21.4 23.2 25.0 26.9
3000 9.1 9.7 10.3 10.9 11.5 12.1 12.8 13.4 14.0 14.6 15.8 17.1 18.3 19.5 20.7
4000 8.9 9.4 9.8 10.3 10.8 11.2 11.7 12.1 12.6 13.1 14.0 14.9 15.8 16.8 17.7
5000 8.8 9.2 9.6 9.9 10.3 10.7 11.0 11.4 11.8 12.1 12.9 13.6 14.4 15.1 15.8
6000 8.8 9.1 9.4 9.7 10.0 10.3 10.6 10.9 11.2 11.5 12.1 12.8 13.4 14.0 14.6
7000 8.7 9.0 9.2 9.5 9.8 10.0 10.3 10.6 10.8 11.1 11.6 12.1 12.7 13.2 13.7
8000 8.7 8.9 9.1 9.4 9.6 9.8 10.1 10.3 10.5 10.8 11.2 11.7 12.1 12.6 13.1
9000 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 10.9 11.3 11.7 12.1 12.6
10,000 8.6 8.8 9.0 9.2 9.4 9.6 9.7 9.9 10.1 10.3 10.7 11.0 11.4 11.8 12.1
Table 5.4 eOnshore Pipeline LCOE with respect to renewable electricity cost and capacity factor
[US$/kg] Renewable Electricity Cost [US$/MWh]
30.00 40.00 50.00 60.00 70.00 80.00 90.00 100.00
Capacity Factor [%] 10% 25.00 25.54 26.08 26.62 27.15 27.69 28.23 28.77
20% 13.31 13.85 14.38 14.92 15.46 16.00 16.54 17.08
33% 8.77 9.31 9.84 10.38 10.92 11.46 12.00 12.54
40% 7.46 8.00 8.54 9.08 9.62 10.15 10.69 11.23
50% 6.29 6.83 7.37 7.91 8.45 8.99 9.52 10.06
60% 5.51 6.05 6.59 7.13 7.67 8.21 8.74 9.28
70% 4.96 5.49 6.03 6.57 7.11 7.65 8.19 8.73
80% 4.54 5.08 5.62 6.15 6.69 7.23 7.77 8.31
90% 4.21 4.75 5.29 5.83 6.37 6.91 7.45 7.98
100% 3.95 4.49 5.03 5.57 6.11 6.65 7.19 7.72
Table 6.2 eOnshore Cable LCOE with respect to transmission line unit cost and capacity factor
[US$/kg] Onshore Cable Unit Cost [Million US$/km]
0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 6.0 7.0 8.0 9.0 10.0
Transmission Capacity [MW] 1000 10.1 11.8 13.5 15.1 16.8 18.5 20.1 21.8 23.5 25.1 28.5 31.8 35.2 38.5 41.8
2000 9.3 10.1 11.0 11.8 12.6 13.5 14.3 15.1 16.0 16.8 18.5 20.1 21.8 23.5 25.1
3000 9.0 9.6 10.1 10.7 11.2 11.8 12.3 12.9 13.5 14.0 15.1 16.2 17.4 18.5 19.6
4000 8.9 9.3 9.7 10.1 10.5 11.0 11.4 11.8 12.2 12.6 13.5 14.3 15.1 16.0 16.8
5000 8.8 9.1 9.5 9.8 10.1 10.5 10.8 11.1 11.5 11.8 12.5 13.1 13.8 14.5 15.1
6000 8.7 9.0 9.3 9.6 9.8 10.1 10.4 10.7 11.0 11.2 11.8 12.3 12.9 13.5 14.0
7000 8.7 8.9 9.2 9.4 9.6 9.9 10.1 10.4 10.6 10.8 11.3 11.8 12.3 12.7 13.2
8000 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 11.0 11.4 11.8 12.2 12.6
9000 8.6 8.8 9.0 9.2 9.4 9.6 9.8 9.9 10.1 10.3 10.7 11.1 11.4 11.8 12.2
10,000 8.6 8.8 9.0 9.1 9.3 9.5 9.6 9.8 10.0 10.1 10.5 10.8 11.1 11.5 11.8
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Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
Appendix 3. Direct Electricity Transmission LCOE
from Cable
Without consider the water electrolysis, the directly trans-
mitted electricity LCOE from cable is plotted with respect the
increase of transmission capacity as shown in Fig. 12. The
scale-up of the transmission capacity is beneficial to the
electricity cost tremendously at the beginning, but the
Table 7.1 eCable transmitted renewable hydrogen per year
[kilo ton/year] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 7.0 14.0 28.0 42.1 56.1 70.1 84.1 98.1 112.1 126.2 140.2
20% 14.0 28.0 56.1 84.1 112.1 140.2 168.2 196.2 224.3 252.3 280.3
30% 21.0 42.1 84.1 126.2 168.2 210.3 252.3 294.4 336.4 378.5 420.5
40% 28.0 56.1 112.1 168.2 224.3 280.3 336.4 392.5 448.5 504.6 560.7
50% 35.0 70.1 140.2 210.3 280.3 350.4 420.5 490.6 560.7 630.8 700.9
60% 42.1 84.1 168.2 252.3 336.4 420.5 504.6 588.7 672.8 756.9 841.0
70% 49.1 98.1 196.2 294.4 392.5 490.6 588.7 686.8 785.0 883.1 981.2
80% 56.1 112.1 224.3 336.4 448.5 560.7 672.8 785.0 897.1 1009.2 1121.4
90% 63.1 126.2 252.3 378.5 504.6 630.8 756.9 883.1 1009.2 1135.4 1261.5
100% 70.1 140.2 280.3 420.5 560.7 700.9 841.0 981.2 1121.4 1261.5 1401.7
Table 6.3 eOffshore Pipeline LCOE with respect to transmission line unit cost and capacity factor
[US$/kg] Offshore Pipeline Unit Cost [Million US$/km]
0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 6.0 7.0 8.0 9.0 10.0
Transmission Capacity [MW] 1000 11.0 15.0 19.1 23.1 27.1 31.1 35.2 39.2 43.2 47.2 55.3 63.3 71.4 79.4 87.5
2000 9.0 11.0 13.0 15.0 17.0 19.1 21.1 23.1 25.1 27.1 31.1 35.2 39.2 43.2 47.2
3000 8.3 9.7 11.0 12.3 13.7 15.0 16.4 17.7 19.1 20.4 23.1 25.8 28.4 31.1 33.8
4000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 16.0 17.0 19.1 21.1 23.1 25.1 27.1
5000 7.8 8.6 9.4 10.2 11.0 11.8 12.6 13.4 14.2 15.0 16.6 18.2 19.9 21.5 23.1
6000 7.6 8.3 9.0 9.7 10.3 11.0 11.7 12.3 13.0 13.7 15.0 16.4 17.7 19.1 20.4
7000 7.6 8.1 8.7 9.3 9.9 10.4 11.0 11.6 12.2 12.7 13.9 15.0 16.2 17.3 18.5
8000 7.5 8.0 8.5 9.0 9.5 10.0 10.5 11.0 11.5 12.0 13.0 14.0 15.0 16.0 17.0
9000 7.4 7.9 8.3 8.8 9.2 9.7 10.1 10.6 11.0 11.4 12.3 13.2 14.1 15.0 15.9
10,000 7.4 7.8 8.2 8.6 9.0 9.4 9.8 10.2 10.6 11.0 11.8 12.6 13.4 14.2 15.0
Table 6.4 eOnshore Pipeline LCOE with respect to transmission line unit cost and capacity factor
[US$/kg] Onshore Pipeline Unit Cost [Million US$/km]
0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 6.0 7.0 8.0 9.0 10.0
Transmission Capacity [MW] 1000 9.9 12.8 15.7 18.6 21.5 24.4 27.3 30.2 33.1 36.0 41.8 47.6 53.4 59.2 65.0
2000 8.4 9.9 11.3 12.8 14.2 15.7 17.1 18.6 20.0 21.5 24.4 27.3 30.2 33.1 36.0
3000 7.9 8.9 9.9 10.8 11.8 12.8 13.7 14.7 15.7 16.6 18.6 20.5 22.4 24.4 26.3
4000 7.7 8.4 9.2 9.9 10.6 11.3 12.1 12.8 13.5 14.2 15.7 17.1 18.6 20.0 21.5
5000 7.6 8.1 8.7 9.3 9.9 10.5 11.0 11.6 12.2 12.8 13.9 15.1 16.3 17.4 18.6
6000 7.5 7.9 8.4 8.9 9.4 9.9 10.4 10.8 11.3 11.8 12.8 13.7 14.7 15.7 16.6
7000 7.4 7.8 8.2 8.6 9.0 9.5 9.9 10.3 10.7 11.1 11.9 12.8 13.6 14.4 15.3
8000 7.3 7.7 8.1 8.4 8.8 9.2 9.5 9.9 10.2 10.6 11.3 12.1 12.8 13.5 14.2
9000 7.3 7.6 7.9 8.3 8.6 8.9 9.2 9.6 9.9 10.2 10.8 11.5 12.1 12.8 13.4
10,000 7.3 7.6 7.8 8.1 8.4 8.7 9.0 9.3 9.6 9.9 10.5 11.0 11.6 12.2 12.8
international journal of hydrogen energy xxx (xxxx) xxx 15
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electricity LCOE is approaching to a steady line near 100 US$/
MWh for both offshore and onshore cases at 50% capacity
factor. The further decrease of the cost must rely on other
technology improvements.
The full scanning of electricity costs with respect to
transmission capacity and capacity factor are tabulated in
Table 8 (Table 8.1 and 8.2). Though the non-dispatchable
electricity is hard to directly integrate with local grid due to
the fluctuation, it is worth exploring the possibility of combing
mixture of power sources to tackle the intermittency issues,
Table 7.2 ePipeline transmitted renewable hydrogen per year
[kilo ton/year] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 8.1 16.3 32.6 48.9 65.2 81.5 97.8 114.1 130.4 146.7 163.0
20% 16.3 32.6 65.2 97.8 130.4 163.0 195.6 228.2 260.8 293.4 326.0
30% 24.4 48.9 97.8 146.7 195.6 244.5 293.4 342.3 391.2 440.1 489.0
40% 32.6 65.2 130.4 195.6 260.8 326.0 391.2 456.4 521.6 586.8 652.0
50% 40.7 81.5 163.0 244.5 326.0 407.5 489.0 570.5 652.0 733.5 815.0
60% 48.9 97.8 195.6 293.4 391.2 489.0 586.8 684.6 782.4 880.1 977.9
70% 57.0 114.1 228.2 342.3 456.4 570.5 684.6 798.7 912.7 1026.8 1140.9
80% 65.2 130.4 260.8 391.2 521.6 652.0 782.4 912.7 1043.1 1173.5 1303.9
90% 73.3 146.7 293.4 440.1 586.8 733.5 880.1 1026.8 1173.5 1320.2 1466.9
100% 81.5 163.0 326.0 489.0 652.0 815.0 977.9 1140.9 1303.9 1466.9 1629.9
Fig. 12 eDirect electricity LCOE transmission with respect to transmission capacity via cables at 4000 km transmission
distance, 50% capacity factor.
international journal of hydrogen energy xxx (xxxx) xxx16
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
especially at large-scale when LCOE are as low as conven-
tional powers.
Appendix 4. Cable and Pipeline Data
The projects data used in the cost estimation are tabulated in
Table 9 (Table 9.1 and 9.2). The data used for the CAPEX
calculation is mostly found on open sources, and the accuracy
of the data need to be carefully examined should economic
decision be made.
Table 8.1 eOffshore cable transmitted electricity with respect to capacity factor and transmission capacity at 4000 km
transmission distance, 50% capacity factor.
[US$/MWh] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 1449.50 770.49 430.98 317.81 261.23 227.28 204.65 188.48 176.35 166.92 159.38
20% 770.49 430.98 261.23 204.65 176.35 159.38 148.06 139.98 133.91 129.20 125.43
33% 506.77 299.13 195.30 160.69 143.39 133.01 126.08 121.14 117.43 114.55 112.24
40% 430.98 261.23 176.35 148.06 133.91 125.43 119.77 115.73 112.70 110.34 108.45
50% 363.08 227.28 159.38 136.74 125.43 118.64 114.11 110.88 108.45 106.57 105.06
60% 317.81 204.65 148.06 129.20 119.77 114.11 110.34 107.64 105.62 104.05 102.79
70% 285.48 188.48 139.98 123.81 115.73 110.88 107.64 105.33 103.60 102.25 101.18
80% 261.23 176.35 133.91 119.77 112.70 108.45 105.62 103.60 102.09 100.91 99.96
90% 242.37 166.92 129.20 116.63 110.34 106.57 104.05 102.25 100.91 99.86 99.02
100% 227.28 159.38 125.43 114.11 108.45 105.06 102.79 101.18 99.96 99.02 98.27
Table 8.2 eOnshore cable transmitted electricity with respect to capacity factor and transmission capacity at 4000 km
transmission distance, 50% capacity factor.
[US$/MW] Renewable Energy Capacity [MW]
500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10,000
Capacity Factor [%] 10% 268.04 179.76 135.62 120.90 113.55 109.13 106.19 104.09 102.51 101.29 100.30
20% 179.76 135.62 113.55 106.19 102.51 100.30 98.83 97.78 96.99 96.38 95.89
33% 145.47 118.47 104.98 100.48 98.23 96.88 95.98 95.33 94.85 94.48 94.18
40% 135.62 113.55 102.51 98.83 96.99 95.89 95.16 94.63 94.24 93.93 93.68
50% 126.79 109.13 100.30 97.36 95.89 95.01 94.42 94.00 93.68 93.44 93.24
60% 120.90 106.19 98.83 96.38 95.16 94.42 93.93 93.58 93.32 93.11 92.95
70% 116.70 104.09 97.78 95.68 94.63 94.00 93.58 93.28 93.05 92.88 92.74
80% 113.55 102.51 96.99 95.16 94.24 93.68 93.32 93.05 92.86 92.70 92.58
90% 111.09 101.29 96.38 94.75 93.93 93.44 93.11 92.88 92.70 92.57 92.46
100% 109.13 100.30 95.89 94.42 93.68 93.24 92.95 92.74 92.58 92.46 92.36
international journal of hydrogen energy xxx (xxxx) xxx 17
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Table 9.1 eCable projects data.
Project Commission Year Investment [M$$] Total Length [km] Capacity [MW]
Offshore Cable NorNed [28] 2007 684 580 700
Nord.Link [28] 2021 1500 500 1400
SA.PE.I [28] 2012 832 420 1000
UK Western [28] 2016 1100 422 2200
NordBalt [28] 2015 935 450 700
Baltic Link [28] 1994 280 250 600
Onshore Cable Belo Monte Bipole I [68] 2017 1000
@
2092 4000
Belo Monte Bipole II [69] 2019 2140 2539 4000
Rio Madeira transmission link [70] 2013 3900 2375 7300
Jinping-Sunan transmission link [71] 2012 3500 2090 7200
Talcher-Kolar transmission link [72] 2003 220
@
1450 2500
@
estimated project cost.
Table 9.2 ePipeline projects data.
Project Commission
Year
Investment
[M$]
Total
Length [km]
Capacity
[billion m
3
/y]
Equivalent
Capacity [GW]
Offshore
Pipeline
Blue Stream [73] 1998 3400 1200 16 19.43
Nord Stream I [74] 2011 19,900e23,000 1224 55 66.80
Nord Stream II [75] 2020
#
20,200 1230 55 66.80
Baltic Pipeline [76,77] 2021 1920e2560 275 10 12.14
Yadana Gas Pipeline [66] 2010 1700 410 (1999)þ280
(2010)
5.1 6.19
Onshore
Pipeline
The Power of Siberia [78,79] 2022
#
17,500e20,000
@
[12] 3000 61 74.08
Trans-Mediterranean [80] 1983 6250 2475 33.5 40.69
Maghreb-Europe Pipeline [81] 1996 2300 1620 11.5 14.57
Yamal-Europe Pipeline [82] 1997 36,000 4107 50 60.72
Rockies Express [83] 2009 5000 2702 36 43.72
West-East Gas Pipeline I [84] 2004 14,500 3843 17 20.65
West-East Gas Pipeline II [85] 2012 22,500 8704 30 36.43
West-East Gas Pipeline III [85,86] 2014 18,400e19,900 7378 30 36.43
*assume 100% capacity factor, NG heating value ¼38.3 MJ/m.
3
.
#
expected year of commission.
@
estimated project cost.
international journal of hydrogen energy xxx (xxxx) xxx18
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
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international journal of hydrogen energy xxx (xxxx) xxx20
Please cite this article as: Miao B et al., Long-distance renewable hydrogen transmission via cables and pipelines, International Journal
of Hydrogen Energy, https://doi.org/10.1016/j.ijhydene.2021.03.067
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