Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms

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Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms Sean B. Walker 1, Daniel van Lanen 1, Michael Fowler*, Ushnik Mukherjee 1 University of Waterloo, Faculty of Engineering, Department of Chemical Engineering, 200 University Ave West, Waterloo, N2L 3G1, Canada

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abstract

Article history:

Power-to-Gas systems provide a versatile and effective form of energy storage. By utilizing

Received 28 July 2015

renewable and off-peak electricity to create hydrogen through electrolysis, an alternative

Received in revised form

energy vector is created which can be utilized for grid management and energy trans-

7 December 2015

portation through the natural gas infrastructure. The rapid response of electrolysers has

Accepted 12 December 2015

been proven to be able to match fluctuating demand signals means that they are not only

Available online xxx

useful for creating hydrogen for energy storage but can also provide important ancillary power services. As the largest market for hydrogen current is in the refining of petroleum,

Keywords:

it makes sense that creating hydrogen through electrolysis provides an opportunity to

Power-to-Gas

purchase electricity at low cost while reducing the greenhouse gas emissions that would

Market mechanisms

result from using the current steam methane reformation (SMR) approach for the pro-

Hydrogen generation

duction of the needed hydrogen. It is shown through MatLAB simulations that by using known electrical costs and hydrogen pricing or credit rates, reasonable payback periods and internal rates of return are attainable when the cost value of the hydrogen energy is compared to renewable ethanol costs, or when the production of the hydrogen considers cap-and-trade carbon emissions revenues. Copyright © 2016, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights reserved.

Introduction Power-to-Gas, or the production of hydrogen through electrolysis, is an excellent way to generate clean hydrogen fuels and provide energy storage for off-peak or intermittent renewable power. As there has been a significant shift away from coal and other carbon-rich energy sources to renewable

energy sources, there is a need for energy storage and supply management technologies like Power-to-Gas to improve the existing energy infrastructure. This transition is historical and can be cataloged as part of society's shift in fuels from burning organic material to coal to oils to petroleum and natural gas and, eventually to a CO2-free power generation in the hydrogen economy. During the transition to the hydrogen economy existing natural gas infrastructure can be used to

* Corresponding author. Tel.: þ1 519 888 4567x33415. E-mail addresses: [email protected] (S.B. Walker), [email protected] (D. van Lanen), [email protected] (M. Fowler), [email protected] (U. Mukherjee). 1 Tel.: þ1 519 888 4567x31607. http://dx.doi.org/10.1016/j.ijhydene.2015.12.214 0360-3199/Copyright © 2016, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights reserved. Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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efficiently distribute and store the hydrogen providing a potentially low cost transition as the energy grids are integrated into a smart energy network. This ability to handle intermittent energy is of particular importance within jurisdictions that are switching their energy mix away from carbon sources, such as oil and coal, to green sources of energy. Another issue, which also would benefit from the ability of Power-to-Gas to provide energy storage, is the management of excess base load power. In the Canadian province of Ontario, for example, the majority of the energy generated comes from nuclear generation, which provides a constant energy base [1]. During periods of peak demand, other sources of energy are drawn on in order to increase the energy supply. However, at off-peak times, the supply of energy exceeds the demand and, as the output of the facilities cannot be easily altered, and the excess energy is exported. As the province lacks an ability to store significant amounts of energy, this excess is exported at a reduced price to neighboring jurisdictions including Quebec, Manitoba, New York, New Jersey and Pennsylvania. For example, approximately 18.3 TWh of energy was exported to these jurisdictions in 2013 from Ontario at a significantly undervalued price, potentially costing the province up to $1 million in profits annually [2]. A study of the adoption of Power-to-Gas in Great Britain finds that not only does Powerto-Gas increase the ability of the energy system to handle high amounts of energy from wind generation during high winds, but that the overall cost of operating the natural gas and electricity grids decreases significantly [3]. Another source of potentially wasted energy that can be managed with Powerto-Gas is renewable energy produced by wind or solar power. With these energy sources, the production of energy does not necessarily line up with the demand of energy, meaning that some energy is wasted or sold at a low price. In this case, gaseous hydrogen could be produced for energy storage and to provide fuel for hydrogen fuel cells. Guandalini et al. [4] find that using Power-to-Gas provides stability and reduces renewable energy penetration into the electricity market but greatly increases the amount of green hydrogen that can be produced. A number of energy storage technologies have been evaluated for the kind of large-scale grid support needed to reduce these energy exports, including flywheels, lead-acid batteries, lithium-ion batteries, compressed air energy storage (CAES) and pumped hydro energy storage [5,6]. In spite of the potential performance of CAES much more infrastructure is need than is necessary for the application of Power to Gas, as investigated by Alberta Innovates [7]. Besides storing energy through these approaches, another use for the energy is to power electrolyzers to produce H2. In the Power-to-Gas scenarios shown in Fig. 1 energy can be stored when H2 is generated. The supply of energy for the system comes from the aforementioned renewable energy sources or excess base load energy on the electrical grid. This electricity is used to power the electrolyzer, which separates water into H2 and O2. Next, the H2 is either injected into the natural gas infrastructure, or stored by tank for immediate use. The H2 stored for immediate use can be used to power hydrogen fuel cell forklifts, vehicle fleets or entire facilities [8]. The rest of the H2 is added to the natural gas grid creating Hydrogen Enriched Natural Gas (HENG) [9]. Until technical concerns such as

material compatibility are fully understood it is necessary for the H2 concentration within the natural gas system to remain below 5 percent by volume [10], but this is unlikely to be a limitation in the near term. The advantages of Power-to-Gas energy storage include:  highest energy storage density of available technologies;  ability to transport energy efficiently;  ability to store and distribute the energy in exiting natural gas infrastructure;  ability to store the energy for long periods, including from season to season;  delay or offset the need for building additional power generation or transmission capacity;  proven commercialized electrolyzer technology;  hydrogen can be use as mixed gas with natural gas in all existing applications with the added benefit of reduced emissions; and,  hydrogen can also be used as industrial gas, transportation fuel, for lift trucks or to generated energy in a distributed fashion on demand [11]. As shown in Fig. 1, Power-to-Gas is a multi-faceted system which can have a number of different pathways from energy input to deliverable electricity or gas outputs. The effects of integrating the two large energy infrastructures involved in Power-to-Gas has been studied by Vandewalle et al. [13], who find that combining the two systems moves some of the uncertainty of the electrical system to the natural gas system. The complexity of the new integrated system is greater due to the multiple markets: natural gas, electricity and CO2 which affect the overall profitability of each energy stream at a given point in time. In addition to Power-to-Gas's ability to provide efficient, high density energy storage, it can also be used to meet the demand for industrial hydrogen. Although the future of hydrogen production is based on the ability to provide a clean fuel for vehicles operating with a hydrogen fuel cell, the vast majority of hydrogen is currently used in the chemical industry, as shown below in Fig. 2 [14]. The most prevalent pathways are those which are used to produce industrial hydrogen which makes up about 90% of the global $60 billion hydrogen market [14,15]. As thousands of kilograms of hydrogen are produced daily to meet the needs of petroleum refineries alone, the potential for CO2e reduction through the substitution of SMR hydrogen with renewable clean electrolytic hydrogen is quite large. As such hydrogen produced in this way should be considered as ‘renewable energy vector’ such as ethanol or biodiesel, and price compared to these energy vectors. In the pathway to producing industrial hydrogen, electricity is used to power an electrolyzer and the hydrogen is then sent by a dedicated pipeline to the customer. No CO2 emissions actually occur through the electrolysis process, while the production of SMR hydrogen involves the emission of both CO and CO2 as shown in the equations below:

CH4 þ H2O # CO þ 3H2

(1)

CO þ H2O # CO2 þ H2

(2)

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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Fig. 1 e Hydrogen economy and Power-to-Gas energy flow (adapted from Ref. [12]).

Ammonia production for nutrient manufacturing

9.8% 9.8%

Petroleum Refining 54.9%

Methanol Production

25.5% Other uses (including food manufacture)

Fig. 2 e Uses of hydrogen in industry [14].

As CO produced by the first SMR reaction can be subsequently consumed in second reaction which forms CO2, there are opportunities to limit some of the unwanted outputs. In order to reduce the CO2 emissions of the production of industrial hydrogen by SMR, a number of technologies have been considered. Bonaquist [16] suggests that carbon capture and sequestration can be used to reduce the CO2 emissions while a thermo-catalytic decomposition could also be used [17,18], but neither of these technologies is in widespread commercial use. El Emam et al. [19] also provide an economic analysis of hydrogen production using tools provided by the hydrogen economy evaluation program. Due to the high demand for industrial hydrogen, substituting electrolytic hydrogen for hydrogen for the more commonly used steam methane reformation for industrial uses, such as petroleum refining, represents the best

opportunity to reduce greenhouse gas emissions considering current hydrogen use pathways. For example, Simons and Bauer [20] find that in a life cycle study a grid mixture dominated by nuclear energy approximately 3 kg CO2e is emitted per kg of H2 are produced by electrolysis, while the SMR processes emits about 15 kgCO2e per kgH2. Suleman et al. [21] find that SMR releases approximately 11 kg kgCO2e per kgH2 while electrolysis from renewable sources releases less than 400 g CO2e per kgH2. In order to implement more renewable fuel use a number of incentive programs are advanced. In this work hydrogen is benchmarked to the market price of ethanol. Ethanol pricing include a variety of incentives throughout its life cycle. The hydrogen produced under Power-to-Gas technology can be considered as a ‘green’ fuel as it is making use of excess power of which the intermittent renewable sources, such as wind and solar, are significant contributors as these sources are not dispatchable. With the prospect of thermochemical production of hydrogen well off in the distant future, in spite of the potential of CueCl water-splitting, there is a need to also better integrate the baseload nuclear power with demand profiles [22]. The use of electrolysis to manage off-peak power can help with this. As the technology providing critical energy storage to enable the smart grid hydrogen produced via Power-to-Gas should be compared, on an energy pricing basis, to other ‘renewable’ and ‘green’ fuels such as ethanol and biodiesel. However a future work will consider life cycle pricing/ incentives/subsidies of various ‘renewable’ fuels, noting that fuels such as ethanol and biodiesel are not fully carbon neutral, and do contribute other criteria emissions (e.g. PM, NOx, VOCs) to urban air quality. Such complete life cycle comparisons is beyond the scope of this work.

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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Lifecycle analysis of Power-to-Gas for the reduction of emissions have previously examined the use of hydrogen in vehicles and in power generation. For example, Klell et al. [23] discuss the use of Power-to-Gas and blending methane and hydrogen for reduced emissions in vehicles; Yazici et al. [24, 25] examine the energy storage with batteries and fuel cells for a mobile off-grid platform powered with renewable energy. To encourage reductions in CO2 emissions, a number of carbon reduction systems have been proposed. Carbon taxes have been proposed whereby organizations are made to a pay a premium for the carbon emissions that they are responsible for [26,27]. One criticism of the carbon tax, however, is that it generally increases the costs of energy and transportation for consumers without encouraging innovation [28]. Cap-andtrade systems, however, have been successfully implemented in the European Union and North America [29,30]. The cap-and-trade systems work on the premise that companies who are able to reduce their CO2 emissions to lower levels should be able to reap financial benefits. It does this by setting a ‘hard cap’ of global emissions from a region or nation and for individual businesses [30]. Under the hard cap, companies who reduce their emissions below the hard cap are given permits that they are able to sell to other companies. Companies who are unable to meet the hard cap must purchase the permits from the market. The importance of carbon trading systems cannot be understated. By monetizing greenhouse gas emissions, technologies that may be more expensive, but are capable of providing carbon reductions, cap-and-trade encourages technological improvements. TerMaath et al. [31] find that blending hydrogen with gas, one of many Power-to-Gas pathways, to power turbines reduces emissions and can be used in a cap-and-trade type scheme. As the province of Ontario transitions into a cap-and-trade system for industry, the analysis of how such a system could be used for hydrogen production by Power-to-Gas is of current interest [32].

Methodology Firstly hydrogen in the proposed Power-to-Gas system can be considered as a renewable fuel, so in this study hydrogen is benchmarked to energy value of ethanol as well as the per kg value of hydrogen produced by SMR. To analyze how the capand-trade system will affect the economics of producing electrolytic hydrogen, a plant function is created to simulate the electrolysis production. The function, plant.m, is used to determine both the electricity use and the quantity of hydrogen produced by the electrolyzer. The plant function uses specific input characteristics and logic parameters for the facility including the electrolytic capacity, minimum and maximum operating percentages, and electricity pricing information. These factors work together, as shown in the flow diagram outlined in Fig. 3, to produce results that can be further examined in additional functions. In this model, only the wholesale electrical price influences when the facility operates at the minimum and maximum operating percentage of its full operational capacity. The plant's operation is determined by a preset switch price (i.e.

price at switch electricity is purchased to produce hydrogen) which is built into the function. When the wholesale electricity price is less that the switch price the plant operates at the maximum operating percentage to maximize the production and take advantage of lower operational costs. Alternatively, when the base electricity price is above the switch price the plant operates at the minimum operating percentage to minimize the impact of higher operational costs. Polymer electrolyte membrane (PEM) electrolyzers have previously been simulated at a range of 5e93 percent in Power-to-Gas simulations [28]. The analysis herein was also conducted with the electrolyzer operating in this range, but it was found that this significantly decreased the ability of the system to reduce greenhouse gas emissions. Thus the range of 1%e100% was selected in order that the CO2 reductions can be maximized. The limitations of such an operating decision are that they do not take into account the wear and tear on the electrolyzer from running at the extreme ends of its operating range. The type of electrolyzer that is capable of accomplishing this breadth of range is a Polymer Electron Membrane or PEM electrolyzer [33,34]. An added benefit of this technology is that is has been demonstrated to be capable of both power arbitrage and ancillary electrical services and responds almost instantaneously to changes in operation. Future analysis will consider the added revenue of the sale of ancillary services from the electrolyzer operation. For the analysis performed herein, four switch prices are used: $40 per MWh, $30 per MWh, $20 per MWh, and $0 per MWh. At $40 per MWh price, it is possible to run the electrolyzer at a high capacity while still using electricity that would likely be exported. The plant takes advantage of low cost and negatively base priced electricity which not only helps the company by reducing costs but helps the jurisdiction by using more electricity internally. This process also more efficiency uses electricity distribution infrastructure. In addition, energy storage could be utilized at a later date, providing additional benefit and reducing sunk costs associated with exports. Another potential additional benefit, which is made possible by improving methods for hydrogen production, is that, in future electrolysis could be used to provide fuel for industrial application (e.g. refineries, and nutrient production), as well hydrogen fuel cell vehicles, such as those being released by major vehicle manufactures in the next couple of years [35]. When the switch price is set to $0 per MWh exported energy which would otherwise be sold at a negative price is used to generate hydrogen. When this price is used, the main objective is to utilize export energy and thereby provide a service to the grid system. At the switch price values between $40 per MWh and $0 per MWh a smaller and smaller amount of energy is drawn from the grid. In addition to the variation of switch prices, five power scenarios are considered, 2 MW, 5 MW, 20 MW, 30 MW and 40 MW, as shown in Table 1. Utilizing the switch price as the control logic, as shown in Fig. 3, each hour in the years 2009e2013 are examined to determine the amount of hydrogen produced. To keep the size of the matrix constant and to allow for proper year over year evaluation leap years have been removed. For each hour the function determines the amount of hydrogen produced in the hour using the maximum and minimum operating percentage. To account for ramping from one power level to another

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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Fig. 3 e Logic for the determination of plant operation and production.

Table 1 e Power-to-Gas facility scenarios examined. Scenario 2 MW capacity with a switch price of $0 per MWh 5 MW capacity with a switch price of $0 per MWh 20 MW capacity with a switch price of $0 per MWh 30 MW capacity with a switch price of $0 per MWh 40 MW capacity with a switch price of $0 per MWh 2 MW capacity with a switch price of $20 per MWh 5 MW capacity with a switch price of $20 per MWh 20 MW capacity with a switch price of $20 per MWh 30 MW capacity with a switch price of $20 per MWh 40 MW capacity with a switch price of $20 per MWh 2 MW capacity with a switch price of $30 per MWh 5 MW capacity with a switch price of $30 per MWh 20 MW capacity with a switch price of $30 per MWh 30 MW capacity with a switch price of $30 per MWh 40 MW capacity with a switch price of $30 per MWh 2 MW capacity with a switch price of $40 per MWh 5 MW capacity with a switch price of $40 per MWh 20 MW capacity with a switch price of $40 per MWh 30 MW capacity with a switch price of $40 per MWh 40 MW capacity with a switch price of $40 per MWh

the code also references the previous hour. Should the plant switch between the two operating percentages, a weighted average is used to determine the hydrogen production. The hydrogen production is then stored in a three dimensional matrix in the form of power consumption (kWh), volume (Nm3), mass (kg), and energy (mmBTU). The matrix can then be used in post processing for financial calculations.

Financial calculation function A MATLAB function, financial.m, is used to determine the feasibility of the system by examining the different market mechanisms that must be utilized. The various market mechanisms are applied through a two stage process, as outlined in Fig. 4. First, a profit matrix is created in which the yearly base electricity cost, additional electricity fees, operational cost, and revenue from hydrogen production from 2011 to 2013. This matrix is then manipulated to determine the average yearly profit. The base electricity price and maintenance costs are constant when examining the different market mechanisms. Though the code is designed to accommodate any 5 year period where hourly data is available, only the Hourly Ontario Energy Price (HOEP) is considered in this work. This is to better compare the impact the market mechanisms have on the plant. The HOEP is collected and made available through the

Focus of operation Reduction of greenhouse gas emissions and electricity exports

Reduction of greenhouse gas emissions and production of hydrogen

Production of hydrogen

IESO [36]. To account for the upkeep of the electrolyzer and facilities operating and maintenance fees have been set to $0.00446 per MWh, as previously determined by Zakeri and Syri, [37]. This operating and maintenance fee does not include electricity. These constant parameters are used in each scenario and case for the 5 year period. An additional electricity fee is charged to account for transmission and distribution charges. In 2012 a review of the export tariff for electricity exports was examined by Charles River Associates for the IESO. The export tariff in 2012 was $2 per MWh, and was under review [33]. One option is to set the tariff to the Equivalent Annual Network Charge (EANC) which is equal to $5.8 per MWh [38]. As the electricity for the plant is used internally to the jurisdiction the EANC is used as an additional market mechanism for the electricity fee cost. The cost is calculated for each year from 2011 to 2013. Market mechanisms that treat hydrogen solely as an energy source and as a product are considered in this work. A common method for analyzing hydrogen production is to utilize a natural gas price (on an energy value comparison basis), such as is found in Henry Hub data obtained from the US Energy Information Administration (EIA) [39]. This data gives the monthly natural gas price for the examined time period hydrogen can be sold for its energy value. However, this price is far inferior to regular hydrogen pricing and represents, more clearly perhaps, the price of hydrogen-enriched

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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Fig. 4 e Logic for the calculation of financial viability of specific market mechanisms.

natural gas (HENG). Hydrogen can also be sold as a product on a mass basis. Utilizing data from the Department of Energy a current price of $5.08 per kg is considered [40]. This is equivalent to the total hydrogen cost, and includes production and dispensing. This pricing is used to see if a Power-to-Gas system with this structure can be competitive with SMR hydrogen production and industrial hydrogen practices. Hydrogen can also be sold for its renewable alternative energy value by examining the price of ethanol. The current price of ethanol is $2.58 per gal which is equal to $30.47 per mmBTU or $4.12 per kg, in US dollars [41]. By selling the hydrogen at this price the energy value of both renewable alternative fuel sources is explored and compared. In addition to revenues for selling hydrogen, the value of carbon credits is introduced and applied to the value of the hydrogen produced. There are a number of proposed prices for hydrogen ranging from $1 per tonne CO2e emitted to $175 per tonne [42]. The highest value for carbon credits currently is $100 per tonne, as offered in Sweden [42]. Currently, Carbon Credit Canada gives the value of a carbon credit as approximately $40 per t CO2e emitted [43]. This value can be converted to a $ per kg H2 produced when a 15 kg of CO2e per kgH2 savings from producing electrolytic hydrogen by renewable power instead of traditional SMR is determined from Simons and Bauer [20]. This works out to increased revenue for the production of hydrogen of approximately $0.6 per kg H2 produced. After the revenue streams are determined the capital costs and viability are determined. Capital costs are calculated based off of numbers given by the industrial partners. The capital cost of the PEM electrolyzer is calculated by setting the low end cost to $1.5 per W and $1.25 per W installed for a 5 and a 30 MW plant respectively, in US dollars. The capital cost is then interpolated to obtain the investment for the in between plant sizes. The operational cost of the hydrogen production through electrolysis has been estimated at $4 per kg H2 [44]. In an evaluation of electrolysis versus other hydrogen production technologies, the overall cost of electrolysis is competitive with thermochemical methods, but higher than fuel reforming [45]. Assuming a typical electrical grid, with an electrolyzer not optimized to reduce emissions, the social and environmental costs would be higher for electrolysis [45]. Capital costs of electrolysis have been estimated to be $0.1 per GJ higher than Steam Methane Reforming [46]. Utilizing this profit matrix and the capital cost the function calculates the

simple payback period and the internal rate of return (IRR). A lifetime of 10 years is used in this work to calculate the IRR [32]. The ability of the electrolyzer to meet this 10 year lifespan will significantly impact the profitability of the hydrogen production system. The results are then used to compare the viability of the different system costs and market mechanisms summarized in Tables 2 and 3.

Results and discussion Each scenario is run utilizing the industrial hydrogen (SMR), and ethanol benchmarked hydrogen market mechanisms as well as the two different carbon credit prices from the Canadian carbon credit price and carbon price based on the state of California price. Different characteristics of the plant are examined for the scenario as well the financial viability of each case. This allows for an examination of the systems and mechanisms that need be put in place for Power-to-Gas systems.

Plant statistics and cost The basic plant characteristics do not vary with plant capacity but rather the switch price by which the facility changes between maximum and minimum operating percentages. When the switch price is set to $0 per MWh the focus of the plant is to reduce undesired exports from the jurisdiction. During the simulation the plant utilizes only 3.4% of its useable capacity. As the plant primarily operated when the base electricity price was negative, the average price is $7.31 per MWh. Though the plant could operate at 0% availability, 1% was chosen to allow other services to be performed during the minimum operating capacity performance and to reduce wear and tear on the electrolyzer. In addition, shutting the electrolyzer down entirely reduces the speed at which it can respond to signals from the controller. When the focus was shifted to the production of hydrogen both factors increase. The capacity factor increases to 0.26, or 26%, at the switch price of $20 per MWh until eventually reaching 0.87 or 87% at a switch price of $40 per MWh. By operating at a higher switch price more hydrogen is created and sold with each market mechanism. The increased production does however have additional costs. The average base electricity price at this switch price is $24.20 per MWh which is

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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Table 2 e Annual system costs for Power-to-Gas. Parameter Electricity Base Price Electricity Fees Operation and Maintenance

Type of cost

Value (all $ Canadian)

Hourly Ontario Electricity Price Equivalent Average Network Charge Operation and Maintenance excluding electricity

IESO hourly data [36] $5.80 per MWh [38] $4.5  103 per MWh [37]

Hydrogen revenue mechanisms and profit Table 3 e Market mechanisms examined in financial simulations. Market Mechanism

Value per kg of H2

Natural gas price Industrial hydrogen price (SMR) Ethanol energy price Cap and trade Canada carbon credit price California carbon credit price

Henry Hub Value [39] $5.08 [40] $4.12 [41] $0.60 [43] $0.15 [29]

approximately 33% higher than the switch price of $30 per MWh. As can be seen in Table 4 at an electricity strike price of $0 per MWh the plant almost never operates, while at a strike prices of $20, $30 and $40 per MWh the plant operates at increasing capacities until it is operating almost all the time. Future reported scenarios in this work will report at $0 per MWh, and at $40 per MWh where the benefit of buying electricity at different pricing for energy arbitrage from converting electricity to energy stored as hydrogen, can be seen. In future works, this switch price will be optimized for different capacities. Though the capacity factor does not change with the plant size the costs associated with electricity and operation and maintenance change, as laid out in Table 5. Due to the nature of the calculations the costs are linear with plant capacity for each capacity factor. For a 0.034 capacity factor the total costs run between $590, and $61,000, for the plant capacities listed in Table 5. That is to say that, due to the prevalence of negative costs, it is possible to run the electrolyzer with negative costs. When the capacity factor increases to 0.87 to total cost increases to be in the range of $372,000 and $12,077,000, for the plant capacities given in Table 5 below. This increase in price is due to the increase in average electricity price and hydrogen production, causing the percent cost associated with the base electricity price to increase. When the power of the system is greater than 5 MW and the switch price is greater than $20 per MWh, the additional fees increase dramatically, according to the guidelines set out by the IESO. This causes a severe increase in annual operating costs for these larger systems.

Table 4 e Plant capacity factor and average price ($ per MWh) for each switch price. Switch price

$0 per MWh

$20 per MWh

$30 per MWh

$40 per MWh

Capacity factor Average price per MWh

0.034 $7.31

0.26 $10.58

0.55 $18.33

0.87 $24.20

In order to better evaluate the potential for Power-to-Gas the selling price of the hydrogen energy value is benchmarked as if it were to be sold at the natural gas energy value price, an equivalent ethanol energy value price, and an equivalent SMR generated hydrogen price. Thus the model assumes hydrogen is sold for the equivalent price of industrial hydrogen from SMR, and ethanol. Additionally, the hydrogen produces the aforementioned carbon credits. These different market mechanisms produce different revenues for the facility. As shown in Table 6 below, the revenue from hydrogen sales when priced equivalent to ethanol pricing ranges from about $35,000 to $395,000 and $874,000 to $6,126,000, in Canadian dollars for a switch price of $0 per MWh or a switch price of $40 per MWh, and capacities between 2 MW and 30 MW, respectively. This revenue is above the total operating costs and is further explored later in this work. Hydrogen could also be sold as an industrial hydrogen alternative, utilizing the given DOE current costs of SMR hydrogen [40]. When this hydrogen pricing is combined with the Canadian Carbon Credit Pricing, the highest revenue is achieved, ranging from about $47,500 to $475,000 and $1,18,000 to $7,450,000, in Canadian dollars, annually for capacity factors of 0.034 and 0.87, and capacities between 2 MW and 30 MW, respectively. Firstly, as can be seen in Table 6 above, operational scenarios with carbon credits are much more viable than scenarios that do not have this extra revenue. This additional value added for hydrogen production favors green technologies such as electrolysis powered by clean renewable or nuclear energy. Naturally, with higher carbon credit pricing such as that from the California market, the Power-to-Gas scenarios are economically viable. In this specific study of the potential Ontario regulatory market the introduction of a carbon cap and trade system has been announced, but the nature of the system is not yet known, nor is there is value for carbon credits established at this time. Thus, in this work the Canada system and California system as surrogates. In Fig. 5 below the profits for each size of plant at $0 per MWh, operating at a capacity of 0.034, and $40 per MWh, at a capacity of 0.87, are illustrated. The resulting annual profit is calculated from the costs in the previous section and each hydrogen market mechanism. The revenue when only a 0.034 capacity factor is used is significantly smaller than when a capacity factor of 0.87 is used. This is due to the significantly larger quantity of hydrogen produced with a less significant increase in average base electricity price. The annual profits, which are shown below in Table 7 vary from approximately, $3,793,000 to $941,000 in Canadian dollars, for the capacity factors given and capacities between 2 MW and 30 MW.

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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Table 5 e Total annual operating costs for selected scenarios. Costs

2 MW, $0 per MWh

2 MW, $40 per MWh

5 MW, $0 per MWh

5 MW, $40 per MWh

30 MW, $0 per MWh

30 MW, $40 per MWh

$4463 $5053 $590

$367,024 $5053 $372,076

$11,161 $5053 $6108

$917,555 $5053 $922,608

$66,978 $5053 $61,925

$12,072,599 $5053 $12,077,652

Electricity cost Maintenance cost Total costs

Table 6 e Total annual hydrogen revenues for multiple price points and capacities. Type of revenue

SMR revenue Ethanol revenue SMR revenue and California carbon credits Ethanol and California carbon credits SMR revenue and Canada carbon credits Ethanol and Canada carbon credits

2 MW, $0 per MWh

2 MW, $40 per MWh

5 MW, $0 per MWh

5 MW, $40 per MWh

30 MW, $0 per MWh

30 MW, $40 per MWh

$43,440 $35,231 $44,979 $39,336 $47,545 $39,336

$1,078,590 $874,762 $1,116,808 $976,676 $1,180,504 $976,676

$108,600 $88,077 $112,448 $98,339 $118,862 $98,339

$1,702,515 $1,380,780 $1,762,840 $1,541,647 $1,863,382 $1,541,647

$434,401 $352,309 $449,793 $393,355 $475,447 $393,355

$6,810,059 $5,523,118 $7,051,360 $6,166,589 $7,453,529 $6,166,589

It is important to note the impact for of the type of Powerto-Gas pathway being used when determining the optimal pricing. In this case, the two price points for the hydrogen itself, as opposed to the price for CO2 reductions, represent different pathways. Ethanol pricing shows a comparable ‘green fuel’ price for comparison. Thus, using the ethanol pricing to represent industrial hydrogen is not entirely

$1,000,000 $900,000

SMR Revenue

$800,000

Ethanol Revenue

$700,000 $600,000

SMR and California Carbon Credits Revenue

$500,000

Ethanol and California Carbon Credits Revenue

$400,000 $300,000

SMR and Canada Carbon Credits Revenue

$200,000

Ethanol and Canada Carbon Credits Revenue

$100,000 $0 2

5

20

30

Market mechanism viability

40

$15,000,000 $13,000,000

SMR Revenue

$11,000,000

Ethanol Revenue

$9,000,000

SMR and California Carbon Credits Revenue

$7,000,000

Ethanol and California Carbon Credits Revenue

$5,000,000 $3,000,000

SMR and Canada Carbon Credits Revenue

$1,000,000

Ethanol and Canada Carbon Credits Revenue

-$1,000,000

2

5

20

30

accurate. The ‘SMR pricing’ is a more accurate estimation of the pricing for industrial uses at this time if the hydrogen would be sold into the market without any incentives. In the future if the energy value of the hydrogen produced is the fact that demand for hydrogen is currently dominated by industrial facilities and not by transportation may be a factor on this price, and thus revenue and profit, difference. The resulting profit is calculated from the costs in the previous section and each hydrogen market mechanism. The revenue when only a 0.034 capacity factor is used is significantly smaller than when a capacity factor of 0.87 is used. This is due to the significantly larger quantity of hydrogen produced with a less significant increase in average base electricity price. As discussed previously, and as can be seen readily in Fig. 6, when larger capacities are being used at higher switch prices, the annual costs are much greater, making it difficult to produce profits. In the bottom plot of Fig. 5, plants larger than 5 MW operate at an annual loss in spite of the larger amounts of hydrogen than can be produced due to the additional costs tacked on to the cost of electricity.

40

Fig. 5 e Annual revenue for each market mechanism at switch price of $0 per MWh (top) and $40 per MWh (bottom).

The market mechanism viability is determined from the Simple Payback Period (SPP) and the Internal Rate of Return (IRR). Since pricing the hydrogen at the NG energy value market mechanism has already been eliminated due to the negative profit it is no longer considered in this work. Both the SMR and ethanol market mechanisms do produce positive profits and are examined for their viability. The simple payback period for a low capacity factor when purchasing electricity at the lowest price only, are higher than the expected equipment lifetime. This occurs because the profit is too low and a reasonable simple payback period is not seen. This makes a low capacity factor not a viable option as the plant would not make its return on investment within the 10 year assumed life of the electrolyzer. So though the market mechanisms for carbon credits and hydrogen pricing are viable, this electricity switch price does not provide enough

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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Table 7 e Annual profits for selected capacities and strike prices. Profit scheme

SMR profit Ethanol profit SMR and California carbon credits profit Ethanol and California carbon credits profit SMR revenue and Canada carbon profit Ethanol and Canada carbon credits profit

$1,000,000

2 MW, $0 per MWh

2 MW, $40 per MWh

5 MW, $0 per MWh

5 MW, $40 per MWh

30 MW, $0 per MWh

30 MW, $40 per MWh

$42,850 $34,641 $44,389 $38,746 $46,955 $38,746

$706,514 $502,686 $744,732 $604,600 $808,428 $604,600

$114,708 $94,185 $118,556 $104,447 $124,970 $104,447

$779,907 $458,172 $840,232 $619,039 $940,774 $619,039

$713,526 $590,389 $736,614 $651,958 $775,095 $651,958

$1,862,564 $3,792,974 $1,500,612 $2,827,769 $897,359 $2,827,769

SMR Profit

$800,000

Ethanol Profit

$600,000

SMR and California Carbon Credits Profit

$400,000

Ethanol and California Carbon Credits Profit

$200,000

SMR and Canada Carbon Profit Ethanol and Canada Carbon Credits Profit

$0 2

5

20

30

40

2

5

20

30

40

$1,000,000 SMR Profit

$0

Ethanol Profit

-$1,000,000 -$2,000,000

SMR and California Carbon Credits Profit Ethanol and California Carbon Credits Profit

-$3,000,000

SMR Revenue and Canada Carbon Profit

-$4,000,000

Ethanol and Canada Carbon Credits Profit

-$5,000,000

Fig. 6 e Annual revenue for each market mechanism at switch price of $0 per MWh (top) and $40 per MWh (bottom).

return on investment. The simple payback period for a 0.87 capacity factor associated with the higher electricity switch price of $40 per MWh, however, creates substantial profit to see some reasonably low simple payback periods. The simple

payback period ranges from as low as 0.8 years to as high as 62 years in Table 8 below. Although the difference in carbon credit pricing between the Canada Carbon Credit Bureau and the California Cap and Trade program is significant, the main cause of variance in the simple payback period is due to the costing structure. Although the simple payback period illustrates the ability of the investment to generate income, there are concerns with some of the values in Table 8 above. Specifically, at the bottom of the table, are simple payback periods that are both bolded and italicized. These values are remarkably low, however, given the large fees associated with running these larger projects during peak hours, the year net incomes of these projects are negative. Thus, in spite of the ability of the project to generate revenues, it is unlikely that it would be possible to create a profit using this device setup. The price also has a significant impact on the economic performance of the plant, as is seen below in Fig. 7. Here, as the plant increases in size from 2 MW to 40 MW, the internal rate of return increases, regardless of what pricing structure is used. The top line, representing a scenario where the hydrogen is sold at the current SMR price and the Carbon Credit Price is used increases from a slightly negative IRR value at a plant capacity of 2 MW to almost 25% at a plant capacity of 40 MW. Examining the specific case of a plant operating with a switch price of $20 per MWh and using the Canada carbon credit pricing two trends can be seen. First, the average IRR increases as the size of the facility increases. Additionally, SMR pricing with Canadian Carbon Credit pricing offers a significantly higher IRR than the other pricing options. If SMR

Table 8 e Simple payback period in years for each scenario and costing structure.

SMR Revenue Ethanol Revenue SMR and California Carbon Credits Ethanol and California Carbon Credits SMR and Canada Carbon Credits Ethanol and Canada Carbon Credits Price of $40 per MWh SMR Revenue Ethanol Revenue SMR and California Carbon Credits Ethanol and California Carbon Credits SMR and Canada Carbon Credits Ethanol and Canada Carbon Credits

Simple Payback period in years with a Threshold Energy Price of $0 per MWh 2 MW 5 MW 20 MW 30 MW 50.9 36.8 22.5 19.5 62.8 45.4 27.7 24.0 49.2 35.5 21.7 18.8 56.2 40.6 24.9 21.5 46.5 33.6 20.6 17.8 56.2 40.6 24.9 21.5

40 MW 17.6 21.7 17.0 19.4 16.1 19.4

2.0 2.5 2.0 2.3 1.9 2.3

0.7 0.9 0.7 0.8 0.7 0.8

2.3 2.9 2.3 2.6 2.1 2.6

1.4 1.8 1.4 1.6 1.3 1.6

1.2 1.5 1.2 1.4 1.1 1.4

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

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i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y x x x ( 2 0 1 6 ) 1 e1 2

Internal Rate of Return

30.0% SMR Revenue

25.0% 20.0%

Ethanol Revenue

15.0%

SMR and California Carbon Credits

10.0%

Ethanol and California Carbon Credits SMR and Canada Carbon Credits

5.0% 0.0% 0

10

20 30 Plant Capacity (MW)

40

Ethanol and Canada Carbon Credits

Fig. 7 e Internal rate of return for different plant sizes and market mechanisms for a switch price of $20 per MWh.

pricing is to be associated with the production of industrial hydrogen for the petroleum or chemical industries and ethanol pricing for the price as a green fuel than the obvious advantage is to sell the produced hydrogen for industrial use. As the capacity of the plants increases over 20 MW, the rate of increase of the IRR decreases due to the weight of the increased capital cost. As the capital cost has a non-linear relationship to the capacity of the plant, the IRR is also not perfectly linear. Additionally, the switch price of $20 per MWh represents an ideal case. When the switch price is at a value of $30 or $40 per MWh, the electrolyzer must operate at peak hours and thus pay significantly higher fees. Under that structure, none of the mechanisms are profitable and this relationship between IRR and capacity breaks down. Similarly, when a switch price of $0 per MWh is used, lower capacity electrolyzers do not produce enough hydrogen to payback the capital investment. As can be seen in Fig. 7, when comparing similar pricing structures the different carbon credit pricing results in a noticeable reduction in the IRR. This discernible change aligns with their impact on overall revenues. For example, when determining the impact of carbon credit pricing scheme on revenues, the change between them caused an approximately 7% change in total revenue when using SMR pricing and a 10% change in total revenue when using ethanol pricing.

Potential additional revenue sources Although there are potential profitable streams if industrial hydrogen or ethanol pricing is used as a benchmark it may be necessary to adopt further government incentives or finding alternative funding sources in order to make the facility profitable. As Power-to-Gas can be injected into natural gas pipelines to create hydrogen enriched natural gas (HENG) which burns cleaner than conventional natural gas, or used for fuel in an emissions free hydrogen vehicles, there are additional opportunities for funding based on environmental performance. Other programs encourage investment in environmentally sound projects by offering relief in ongoing costs. An example of this is that is often used in housing projects is tax increment-based financing which provides an alleviation in taxes equal to the capital investment of the project [47]. In California, a self-

generation incentive program is used to provide a government contribution to the cost of installing renewable energy projects, like clean hydrogen projection [48]. More consumer-directed incentives, such as the Ontario Clean Energy Benefit aim to encourage energy users to use renewable energy by changing their energy use patterns through reduced energy costs [49]. Also the Power-to-Gas concept would delay or offset the potential requirement to build additional energy generation and transmission capacity to balance the increased use of intermittent renewable sources such as wind.

Additional benefits In addition to significant economic gains through the sale of hydrogen for energy or as an industrial chemical, Power-toGas also offers flexible energy storage. As shown in Fig. 1, hydrogen can be produced from an electrolyzer or from agricultural waste gas feed. This gas can then be stored with natural gas to form HENG. Due to the large amount of natural gas infrastructure available in Ontario, it is conceivable that enough energy could be stored to provide for some seasonal energy arbitrage. This length of storage time separates Power-to-Gas from competing technologies and could allow the grid operator to manage periods of prolonged surplus or deal with increased loads caused by extreme weather events. Also with increased wind infrastructure development, the high wind availability in the winter can be applied to the high energy demand in the summer. The flexibility of the hydrogen generation technology also means that Power-toGas can be used to provide frequency regulation services to the grid. In these instances, the electrolyzer power would be managed to provide voltage regulation services. In 2014, IESO performed tests to verify the electrolyzers produced by Hydrogenics could be ramped up and down quick enough to provide these high value ancillary electrical services [33,34,49].

Conclusions Power-to-Gas facilities show the potential to provide substantial benefits to improve the operation of power grids by

Please cite this article in press as: Walker SB, et al., Economic analysis with respect to Power-to-Gas energy storage with consideration of various market mechanisms, International Journal of Hydrogen Energy (2016), http://dx.doi.org/10.1016/j.ijhydene.2015.12.214

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y x x x ( 2 0 1 6 ) 1 e1 2

providing increased grid management as well as important auxiliary services. The market mechanisms for how a facility that generates hydrogen in a Power-to-Gas system have not yet been determined, but are an important to examine to demonstrate the economic viability of Power-to-Gas systems. Though hydrogen cannot be sold efficiently for its energy value at the natural gas price, the project can be viable when the industrial hydrogen and renewable ethanol prices are used. This is only true, however, if higher capacity electrolyzers are used. The electrolyzer technology must, therefore, be used for energy arbitrage and provision of ancillary electrical services in order to be competitive. Even greater economic benefits can be realized with the sale of hydrogen into industrial or mobility markets. With high capacity systems and appropriate market mechanisms, internal rates of return between 15 and 21 percent are achieved. In addition to offering a high capacity for energy storage, Power-to-Gas also provides industrial hydrogen producers the opportunity to increase their profits through the sale of carbon credits. However, it is also seen that carbon credits for hydrogen producers can amount between 7 and 10% of the total costs to purchase and operate the plant. Because additional electricity tariffs are so significant, and the simple payback periods are reasonable for lower capacities, it is most reasonable to develop a 5 MW system operating with a switch price of $30 per MWh. Under such a plan the lower fees would apply and the plan is profitable. As the commodity pricing of hydrogen is more useful than the energy price of hydrogen, it is reasonable to assume that the producer would prefer to sell the hydrogen for petroleum refining, as opposed to selling it for transportation fuel at this time. With high capacity factors, set prices and appropriate market mechanisms internal rates of return between 20 and 30 percent are shown, which demonstrates the viability of using cap-andtrade to compare hydrogen production via power to gas with that of SMR pricing for electrolytic hydrogen. As the capand-trade system is coming to Ontario, such a plant could be profitably implemented, using these market prices. An advantage to supporting this for policy maker organizations and government is that Power-to-Gas encourages the convergence of the natural gas and electrical infrastructure, achieves energy management benefits, and improves the production of hydrogen to support a future hydrogen economy. These mechanisms should be implemented by governments and policy maker organizations in order that convergence of the natural gas and electrical infrastructure can achieve energy management benefits, as well as other benefits including energy storage, clean industrial hydrogen and future development of a clean hydrogen mobility infrastructure.

Acknowledgment This report was written with the financial support of National Science and Engineering Research Council (NSERC CRDPJ 451746-3), Ontario Center of Excellence (OCE MIS 20737), as well as and our research partners Enbridge, Hydrogenics,

11

Union Gas, GE, Energy Technology & Innovation Canada (ETIC).

Nomenclature CAD DOE EANC EIA GA HOEP IESO NG SMR

Canadian Dollar Department of Energy Equivalent Average Network Charge Energy Information Administration Global Adjustment Hourly Ontario Electricity Price Independent Electricity System Operator Natural Gas Steam Methane Reformation

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