 Original research article
 Open Access
Conditions for economic competitiveness of pumped storage hydroelectric power plants in Egypt
 Diaa Abdellatif^{1},
 Rameen AbdelHady^{2}Email author,
 Ahmed M. Ibrahim^{3} and
 Essam Abu ElZahab^{3}
https://doi.org/10.1186/s4080701800481
© The Author(s) 2018
 Received: 26 November 2017
 Accepted: 21 February 2018
 Published: 1 March 2018
Abstract
Pumped storage hydroelectric power plants are one of the most applicable energy storage technologies on largescale capacity generation due to many technical considerations such as their maturity, frequency control and higher ramp rates, thus maintaining following loads in case of high penetration of renewables in the electrical grid. Economic viability of PSHPPs is still questionable when compared with other electricity generation technologies. In this manuscript, the key factors that affect the viability of constructing PSHPP in Attaqa Mountain, Egypt, are defined. An economic comparison between PSHPPs and simple cycle gas turbine power plants has been carried out to identify the conditions at which PSHPPs will have competitiveness as an onpeak solution, over traditional SCGT power plants. This assessment is based on calculating levelized cost of electricity taking into account different scenarios for PSHPP pumping cost and capital cost, and different scenarios for SCGT fuel prices. The results showed the key factors of the best case at which PSHPPs have the highest economic competitiveness over SCGT power plants when fuel prices are nonsubsidized. This is only valid provided that the PSHPP’s capital cost should not exceed 4180 $/kW at zero pumping cost.
Keywords
 Pumped storage hydroelectric power plant
 Levelized cost of electricity
 Simple cycle gas turbine
 Onpeak demand
Introduction
Energy strategic planning is one of the world’s main concerns to cover the fastgrowing energy demand taking into account the wise use of available energy resources to achieve the optimum electricity generation mix. One of the main difficulties of energy planning for any country is selecting the most compatible alternative to fulfill its requirements, as the selected alternative will have a longterm impact on its economy and the utilization of the available resources.
Typically, reservoir hydropower plants (HPPs) and PSHPPs supply primary control power. However, it is not the case for the Egyptian National Grid. In Egypt, the daily onpeak periods are met with peaking units, especially simple cycle gas turbine (SCGT) (specific), or using electrical interconnection between neighboring countries because they can quickly start up and shut down to meet brief peaks in demand. These solutions for onpeak periods are typically the most expensive to operate when considering peaking units and have low reliability when considering interconnection because it is dependent on other countries’ technical and political situations. Peaking units also serve as spinning reserve and as “quick start” units which are able to go from shutdown to full load in minutes. A peaking unit typically operates for only a few hundred hours a year. They run only as needed to meet the highest loads (Kaplan 2008).
Another solution that can cover onpeak demand through the day is electrical energy storage (EES) technologies whose operation is based on storing electrical energy when there is an excess generation then releasing this energy when needed, so this released electricity can promptly follow the electricity demand.
Many energy storage technologies are technically applicable, but they still have challenging issues related to the scale of their use, their capital costs and the installing site selection. Another challenge of energy storage technologies is the loss between charging and discharging energy that requires a specific technique of pricing and new energy market rules, thus increasing their economic viability.
This energy storage technology can provide two main services: supplying electricity during onpeak or high ramp demand rates and putting off some capacity expansions in the electrical grid.
According to this study, the site can involve six reversible turbines (overall flow rate 318 m^{3}/s) with a total power capacity of 2100 MW with an upper reservoir, of 9 mcm volume capacity, at a height of 850 m. The horizontal distance between the upper and the lower reservoir is expected to be 1450 m; hence, the effective head is 600 m.
There are six vertical steel lined penstocks (with inner diameter of 3.6 m) for the flow of water up and down between the reservoirs, linked two by two to horizontal circular concrete lined tunnels with larger diameters. The access to the underground power plant is by a long tunnel, while there are three horizontal lower tunnels between the lower reservoir and the turbines. There will be a machinery hall (180 m long and 16 m wide) and a specific area (175 m long and 15 m wide) to include the power transformers (SWECO 1997).
This process can be operated using a reversible turbine to pump up water. The turbine is connected to a motor for generating electricity. The efficiency of PSHPPs to make full water cycle (cycle efficiency) ranges typically between 70 and 85% (Barbour et al. 2016). Therefore, the required energy to pump up water is higher than the generated energy from PSHPP by 15–30% due to losses, which is what the debate of PSHPPs is about. This can be solved by different tariff mechanisms (e.g., double tariff structure). Double tariff is the two times of use tariff (ToU) and it has two fixed values over the day based on times of configuration.
It is also possible to get benefit of excess electricity during lowerdemand periods to charge water into upper reservoirs then this water can be discharged down to start up a turbine to generate electricity during the highdemand periods. The economic benefit of PSHPPs comes from pumping with lowcost offpeak and generating onpeak to displace highcost energy, to reduce total generation cost by time shifting (IEC 2011). Moreover, PSHPP plays an important role in providing power factor correction and voltage regulation in the generating or pumping mode and they can also operate unloaded as synchronous condensers, thus enhancing the electrical power system stability.
The first designs of PSHPPs in the 1890s used separate pump motors and turbine generators. Since the 1950s, a single reversible pump turbine has become the dominant design for PSHPPs (Baxter 2006).
PSHPP has some advantages, when compared with SCGT power plants to cover the onpeak electricity demand; one of these advantages is that PSHPPs do not have the capacity reduction experienced by combustion turbines due to high ambient temperature, and at the same time, it has a higher reliability than combustion turbines. Other benefit of PSHPPs is their lifetimes because hydropower plants usually have very long lifetimes (in the range of 30–80 years) and their components can be sustained in operation (IRENA 2012).
Energy storage also has an important role in the efficient utilization of electricity from renewable energy resources. Many renewable energy resources, such as wind, solar, HPPs and tidal energy, are variable and inconstant and so are unable to supply electrical power continuously. Integrating some energy storage with renewable resources improves the expected generated energy from renewables, removes their uncertainties and increases the value of the electricity generated (Breeze 2014).
Although PSHPP and SCGT are technically viable to operate as onpeak generation power plants, the economic drawbacks of PSHPP due to its high capital cost and its cycle efficiency limit its feasibility. In this manuscript, a comparison of both PSHPP and SCGT in Egypt is presented. This comparison is based on a standard levelized cost of energy (LCOE) approach that enables decision makers to compare between different technologies of diverse lifetimes, capacities, heat rates and other specifications, to choose the most economic technology in $/kWh. LCOE is the summation of all the costs that are borne through a generating technology lifetime divided by the energy generated from that technology and is expressed in $/kWh.
The time value of money concept is also taken into consideration in calculating LCOE represented in the discount rate (r) which mathematically refers to the interest rate used to calculate the present value of future cash flow. LCOE of PSHPP and SCGT is calculated based on financial modeling, using Microsoft Excel spreadsheets, taking into consideration the different technical and economic aspects of each technology such as heat rate, lifetime, capacity factor, fixed and variable O&M and capital costs. An analysis of different scenarios is also performed to define the conditions at which PSHPP has competitiveness over SCGT power plants. These cases include scenarios for PSHPP pumping cost and scenarios for SCGT fuel costs which have a significant impact on the LCOE of both power plants; also, different values of r are considered. This is a simplified approach, as PSHPPs have many additional features of their operation in the common grid. The cost estimate of those features cannot be represented so easily, but they are of crucial importance for the parameters of the grid and PSHPPs operation.
Methodology
The calculation of LCOE for PSHPP and SCGT includes the capital investment costs, operation and maintenance costs and different discount rates. Other LCOE elements such as pumping cost of PSHPP and fuel costs of SCGT were calculated under different scenarios.
PSHPP LCOE calculation
In general, the term \(\mathop \sum \nolimits_{t = 1}^{n} \frac{{I_{{t + M_{t} + P_{t} }} }}{{(1 + r)^{t} }}\) refers to the discounted project lifetime costs, while the term \(\mathop \sum \nolimits_{t = 1}^{n} \frac{{E_{t} }}{{(1 + r)^{t} }}\) represents the discounted project lifetime generated energy.

Capital investment costs.

Operation and maintenance costs (O&M).

Pumping cost.

Discount rate (r).
Capital investment costs
The investment costs are those costs needed to construct PSHPP including all capital costs (overnight costs) and the required investments to cover them. These costs are required mainly for: engineering, procurement and construction works of PSHPP including civil, mechanical and electrical works.

Electromechanical system comprising turbines, actuators, regulators, generators, circuit breakers, a grounding system and a protection system;

Control and monitoring system including supervisory control and data acquisition (SCADA); and

Water supply system containing water depressing and drainage systems.
Other costs included in the capital investment cost are civil works, the cost of interconnecting the PSHPP to the grid and the water and piping system.
Civil works
Due to the topography of the site, SWECO International’s study (SWECO 1997) assumed this civil cost to count an amount of 25% of the total project capital cost. The tunnel cost is a very large part of the civil works; therefore, it is important to find the tunnel cross section that gives the lowest cost (Rognlien 2012). Optimization of the tunnel cross section was elaborated by SWECO (SWECO 1997); for further details, refer to (SWECO 1997). The cost of interconnecting the PSHPP to the grid:
Based on data from Egyptian Electricity Transmission Company, the average cost of a 500 V three phase transmission line is 0.4 M$/km with a capacity of 1750 MVA. The 2100 MW PSHPP will need three transmission lines to be able to absorb/evacuate electricity from/to the Egyptian Unified Grid. Another extra bundle of three phase transmission line type is assumed to be interconnected with the PSHPP for emergency. The nearest point to the Egyptian Unified Grid that the PSHPP can be interconnected is at a distance of 8 km. According to these assumptions, the total interconnection cost in the study will amount to 12.8 M$.
Water and piping system
PSHPP will need a large volume of water at the startup, to run the PSHPP with its full power capacity. This water volume amounts to 9 mcm (SWECO 1997). This volume acts as an active volume of the upper reservoir, bearing in mind that there will be daily evaporation, which can be calculated according to the annual evaporation rate in Suez (3400 mm/year) (Edgell 2006). The leakage expected during operation was also taken into account, so the total daily backup water amount is assumed to be 10^{4} m^{3}/day.
PSHPP has a site specific capital investment cost, which is significantly variable from one site to another; the above costs are site specific to the area of Mount Attaqa in Egypt. This unpredictability in the capital investment costs is mainly due to the changing civil works costs, where the plant component cost variability is slight. In this study, the cost of plant components is assumed to be fixed at 1600 $/kW, while the civil works cost varies from 600 to 3600 $/kW at a fixed step of 200 $/kW to generalize the analysis. This assumed range is made to acquire the minimum and maximum possible values of LCOE of the PSHPP in Egypt based on the world’s lowest and highest figures of constructing such kind of power plants (2200–5200 $/kW including the costs of plant components). The cost of interconnecting the PSHPP to the grid and the cost of water and piping system per kW is included in the variable number of civil works to sum up the value of the capital investment cost.
All the abovementioned costs were assumed as the total fixed capital costs required to completely construct the PSHPP; however, there are extra costs that will be incurred to secure financing to all these capital costs. The finance structure of the PSHPP was assumed to be divided into two debt loans as follows:
Loan from local banks
It amounts 40% of the total project capital costs to be repaid over 10 years with an annual interest rate of 11% and grace period 2 years with a commitment fee 0.5% on the remaining balance at each year during the construction period of the project.
Loan from foreign banks
It amounts 60% of the total project capital costs to be repaid over 20 years with an annual interest rate of 6% and grace period 3 years with a commitment fee 0.5% on the remaining balance at each year during the construction period of the project.
Operation and maintenance (O&M) costs
The O&M costs are those costs needed to ensure the proper operation of the PSHPP and are divided into fixed O&M costs and backup water costs.
Fixed O&M costs
These costs were assumed to be 30.8 $/kW annually according to Black and Vetch Consultancy Company projections report of performance and cost data for power plants (Black and Vetch 2012). These costs include the wages and salaries of the PSHPP operators and engineers as well as the spare parts and the refurbishment of mechanical and electrical equipment.
Backup water cost
As stated above, PSHPP will require backup water during PSHPP operation to recover the evaporated amounts and its cost is included in the operational costs. The cost of backup water is calculated using Eq. (2) taking into account that the number of years (N) will be 1 because this cost will be encountered annually. The upper reservoir water capacity UR_{ c } term in the equation will be equal to zero because the loss in water is only calculated. P_{ w } is assumed to be escalated annually during the lifetime of the PSHPP by 3% following the consumer price index (CPI) in USA which amounted 2.34–2.39% in 2015 (Trading Economics 2016).
Pumping cost
First scenario
The pumping cost is assumed to be equal to the price of buying electricity from the Egyptian Unified Grid at offpeak time on the extra high voltage level (220 kV) and this cost will include capacity payments (1.54 $/kW Month) and energy payments (0.0248 $/kWh) (EgyptERA 2015).
Second scenario
The pumping cost is assumed to be 70% of the total energy payment cost in the first scenario (0.01736 $/kWh), while this percentage represents the average cost of fuel usage in electricity generation according to the Egyptian Electricity Holding Company (EEHC).
Third scenario
The pumping cost is assumed to be zero. This assumption is based on supplying electricity for pumping, from renewable power plants that are connected to grid and do not generate electricity during peak times, or from the available spinning reserve from the traditional thermal power plants during offpeak time.
The pumping cost is assumed to be escalated by 3% annually over the project lifetime in the first and second scenarios.
Discount rate
In some studies, the discount rate used for a project is considered equal to the project weighted average cost of capital (WACC) and this is when discounting the cash flow from a utility or firm point of view. Typically, a utility finances its assets and projects either through debt, bank loans, bonds. WACC is the weighted average of costs related to financing a certain project from loans (Deloitte 2014).
According to the WACC in Eq. (4) and based on the study assumptions, the PSHPP project is totally financed by two debt loans. The corporate tax is assumed zero because such kind of power plants are normally executed by the governmental sector. According to this, the WACC value 8% is assumed to be the discount rate of the study for both PSHPP and SCGT LCOE.
From a national point of view, the discount rate value can be equal to the country’s discount rate which includes all financial risks related to the country, such as credit rating and risk premium. The Central Bank of Egypt (CBE) announced in 2015 a discount rate of 9.75% (almost 10%). Consequently, r values of 10%, besides the 8%, as well as two other values of 12 and 14%, representing pessimistic cases, were taken into consideration. It should be noted that a higher risk may be encountered because PSHPP has a long lifetime (over 60 years).
General assumptions
There are other assumptions that have been taken into account in calculating LCOE for PSHPP including its lifetime which is assumed to be 60 years (IRENA 2012), supposing the operation of the PSHPP to start at the end of the year 2020 taking 5 years as a construction period for PSHPP. The PSHPP is expected to deliver energy for 10 h a day (EBASCO 1993). This assumption is for design purposes.
This is a simplified representation. It should be noted that in this connection, several lines of financial project development are running parallel: design, administration and permits, construction, supply and installation of equipment, and more complicated financing processes are included.
LCOE calculations for SCGT

Capital investment costs.

Operation and maintenance costs (O&M).

Fuel costs.

Discount rate.
Capital investment cost
Capital investment cost of SCGT power plant does not vary much from one site to another within the same country, in contrast to capital investment cost of PSHPP which is site specific. Therefore, one average value for capital investment cost of SCGT will be used in the study which is 968 $/kW. This value, according to the Annual Energy Outlook 2015 (EIA 2013), represents an average for utility scale SCGT power plants electricity projects.
The abovementioned capital investment cost is the overnight costs required to completely construct an SCGT power plant and this cost is assumed to be financed by two debt loans as follows:
Loan from local banks
It amounts 20% of the total project capital costs to be repaid over 10 years with an annual interest rate of 11% and grace period 2 years with a commitment fee 0.5% on the remaining balance at each year during the construction period of the project.
Loan from foreign banks
It amounts 80% of the total project capital costs to be repaid over 20 years with an annual interest rate of 6% and grace period 3 years with a commitment fee 0.5% on the remaining balance at each year during the construction period of the project. A different financing structure for SGT from that of PSHPP (60% foreign loan + 40% local loan) is assumed, due to the fact that PSHPP construction has many local works such as civil infrastructure, drillings and piping systems.
Operation and maintenance (O&M) costs
The O&M costs can be classified into fixed O&M and nonfuel variable O&M. The fixed O&M cost includes all costs that are independent of the electricity generation production of the SCGT power plant such as wages. The annual fixed cost for SCGT used in this study is 7.34 $/KW (EIA 2013). The nonfuel variable O&M cost includes all costs that are dependent on the electricity production level such as equipment outage maintenance, utilities and consumables such as chemicals. According to (EIA 2013), the variable cost used in calculating LCOE of SCGT is 15.44 $/MWh.
Fuel costs

International fuel prices are assumed fixed over the different technologies lifetime based on year 2014 prices for NG and year 2015 prices for LFO.

International fuel prices are assumed to be annually escalated by 3% over the different technologies lifetime based on year 2015 prices.
Discount rate
Similar to that of the PSHPP, the values of r were assumed to be 8, 10, 12 and 14%. All the study calculations will be in foreign currency US dollars ($) using the exchange rate to convert between the local currency in Egyptian pounds (L.E.) and US dollars as 10 L.E./$. This exchange rate is assumed to be fixed over the project lifetime and is applied at the start of year 2015, which is the base year for the study.
The currency exchange rate may have a significant effect on the project capital cost during the construction period and a slight effect during the PSHPP operation. This is because the components that will be imported from outside using foreign currencies for construction and maintenance purposes during process of installation. Accordingly, contingencies and escalation rates were taken into consideration to overcome such exchange rate issues. The escalation rates in O&M during the project lifetime were assumed to be 3% annually. Thus, the assumption of 3% as escalation rate in O&M is a reasonable assumption for all O&M costs of PSHPP and SCGT and for pumping cost too.
For each scenario and specific discount rate (8, 10, 12 and 14%), the relation between the LCOE of PSHPP and the capital investment cost ranging between 2200 and 4200 $/kW is fitted through regression (using least square method). The LCOE of SCGT is to be used to determine the competitiveness range allowed for PSHPP’s capital investment costs. The relationship is fitted such that the investment cost is the dependent variable, while the LCOE is the independent variable.
Summary of assumptions of the study
Financial data  
Installation cost excluding civil works  1600 $/kW 
Civil work costs  2400 $/kW 
Interconnection costs  12.80 M US$ 
Water piping system  20.0 M US$ 
Fixed costs  30.8 $/kWyear 
Variable costs  0 
Escalation in O&M  3% 
Escalation in water price  3% 
Base year of the study  2015 
Pumping electricity cost (offpeak) at 500 kV  0.0248 $/kWh 
Selling price of generated electricity (onpeak)  0.0511 EG $/kWh 
Capacity payment for intensive industries  0.015 $/kWmonth 
Exchange rate  10 
Tax rate  0% 
Commitment fee  0.5% 
Discount rate of the project  10% 
Loan data  
Foreign loan  60% 
Term to repay  20 years 
Grace period  3 years 
Interest rate  6% 
Local loan  40% 
Term to repay  10 years 
Grace period  2 years 
Interest rate  11% 
Technical data  
Unit capacity  350 Mw 
Number of units  6 units 
Project lifetime  60 years 
Construction period  5 years 
Cycle efficiency  0.75% 
Scheduled maintenance  20 days 
Forced outage rate  0.05% 
Generating hours per day  10 years 
Capacity factor  34% 
Pumping efficiency  0.95% 
Height (upper reservoir effective head)  600 m 
Total expected annual generated energy  6274 Gwh 
Total required pumping energy  8365 Gwh 
Water flow rate  376 m^{3}/s 
Water capacity  13.53 mcm 
Evaporation rate in Suez Region  3.4 m/year 
Losses of water per year  3.65 mcm/year 
Project total amount of water during construction  104.6 mcm 
Average grid fuel consumption (2013/2014)  211 gm/kWh 
NG price  3 $/MMBtu 
Kwh generated fuel price  8.37248 kWh 
WACC  8% 
Results
Constants derived for each pumping scenario and discount rate
Pumping cost scenario  r (%)  Regression equation 

Scenario 1: pumping cost is equal to the price of buying electricity from the Egyptian Unified Grid at offpeak time  8  \(I = 25650 \;{\text{LCOE}}  2013\) 
10  \(I = 22510 \;{\text{LCOE}}  1632\)  
12  \(I = 20340\;{\text{LCOE}}  1387\)  
14  \(I = 18870\;{\text{LCOE}}  1246\)  
Scenario 2: pumping cost is 70% (fuel portion cost) of the total energy payment cost in first scenario  8  \(I = 25540 \;{\text{LCOE}}  1537\) 
10  \(I = 22540\;{\text{LCOE}}  1272\)  
12  \(I = 20380\;{\text{LCOE}}  1083\)  
14  \(I = 18850\;{\text{LCOE}}  963.9\)  
Scenario 3: pumping cost is assumed to be zero  8  \(I = 25590\;{\text{LCOE}}  503.3\) 
10  \(I = 22450\;{\text{LCOE}}  407.4\)  
12  \(I = 20390\;{\text{LCOE}}  360\)  
14  \(I = 18860\;{\text{LCOE}}  323\) 
LCOE of SCGT at different discount rates and in the two fuel scenarios
Fuel cost scenario  LCOE of SCGT at different r (¢/kWh)  

r: 8%  r: 10%  r: 12%  r: 14%  
Fixed international fuel costs  13.45  13.47  13.5  13.52 
Escalated international fuel costs  18.3  17.98  17.69  17.45 
Pumping cost scenario 1
Adopting the case that pumping cost is equal to the price of buying electricity from the Egyptian Unified Grid at offpeak time, when substituting by values in Table 3 with the corresponding regression equation in Table 2 it is found that PSHPP has competitiveness over SCGT power plants only in the escalated international fuel costs fuel scenario at r 8, 10 and 12%, provided that the capital cost for PSHPP should not exceed 2680.95, 2415.298 and 2211.146 $/kW, respectively. These milestones are shown clearly in Fig. 7 on the curves of different discount rates and it is noticed that on the curve (r 8%) there is a tolerance of the capital cost of the PSHPP to range from 2200 $/kW (minimum capital cost of any PSHPP assumed in this study) to 2679 $/kW, while on the curve where r is assumed to be 12% the tolerance is very tight (2200–2222 $/kW).
PSHPP’s LCOE does not have any competitiveness over that of SCGT in the escalated international fuel cost scenario as a whole, and at r 14% in the fixed fuel cost scenario (the points of intersection are out of PSHPP’s capital cost range).
Pumping cost scenario 2
Take the assumption that the pumping cost is 70% (fuel portion cost) of the total energy payment cost in first scenario. When checking the possibility of intersection between LCOE values of PSHPP and those of SCGT (Fig. 8), it is found that PSHPP has competitiveness over SCGT power plants still only in the case of escalated international fuel costs, but in this scenario the range of the possibility of the capital cost is more flexible; also, its competiveness at r 14% exists. PSHPP has competitiveness over SCGT power plants at r 8, 10, 12 and 14% (Table 3), on condition that the capital cost for PSHPP should not exceed 3136.82, 2780.692, 2522.222 and 2325.425 $/kW, respectively.
Pumping cost scenario 3
Conclusion
In this manuscript, a simplified approach to define the conditions at which PSHPP has competitiveness over SCGT power plants. PSHPPs have many additional features of their operation in the common grid whose cost estimate cannot be represented so easily.
It can be concluded from the results that PSHPP does not have an absolute economic competitiveness compared with SCGT power plant, but the economic viability of constructing PSHPP is variable according to different factors and conditions. From the perspective of electricity sector in Egypt, as long as the government subsidizes the fuel prices supplied to SCGT power plants, there will be no need to construct PSHPP in Attaqa Mountain.
The pure economic competitiveness of PSHPP over SCGT power plant will appear in case of using the international fossil fuel prices and taking into account the huge amounts of foreign currency to import such fossil fuels to cover the domestic demand from fuel in other sectors than electricity sector. This competitiveness of PSHPP can be increased also by decreasing the pumping cost to lift water up in PSHPP, which is a strategic decision by the government. PSHPP competitiveness over SCGT technology increases more when the limitations and conditions at which installing PSHPP in Egypt are more relaxed. Therefore, ideally, there should be a double tariff structure mechanism designed to get the advantages of PSHPPs as a clean energy source to maximize its benefits.
Declarations
Authors’ contributions
DA took part in compiling the required data, conducting the literature review, programming the mathematical model, verifying its accuracy, running the program, plotting the results, writing some parts of the paper and placing it in the required format for publication. RA determined the methodology and selected the research tools, and was involved in organizing the scenarios required to simulate, analyzing the results, code error debugging, results verification, reviewing the paper in terms of form and content, writing some parts and following up the publication of the paper. AMI proposed the research topic and general approach, reviewed the methodology and approved the scenarios to be simulated and verified the results and reviewed language and terminology used in the text. EAE performed approving the research topic and general approach, reviewing and verification of the results, and final review of language and terminology used in the text. All authors read and approved the final manuscript.
Competing interests
The authors declare that they have no competing interests.
Availability of data and materials
All data and materials are presented in the main paper.
Funding
Not applicable.
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