Energy Conversion and Management xxx (2014) xxx–xxx

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Energy Conversion and Management

journal homepage: www.elsevier .com/ locate /enconman

Determining the economic consequences of natural gas substitution

http://dx.doi.org/10.1016/j.enconman.2014.03.0120196-8904/� 2014 Elsevier Ltd. All rights reserved.

⇑ Corresponding author. Address: Department of Chemical Engineering, Building35, Clayton Campus, Monash University, Vic. 3800, Australia. Tel.: +61 3 99024403.

E-mail addresses: shaun.rimos@monash.edu (S. Rimos), andrew.hoadley@monash.edu (A.F.A. Hoadley), david.brennan@monash.edu (D.J. Brennan).

Please cite this article in press as: Rimos S et al. Determining the economic consequences of natural gas substitution. Energy Convers Managehttp://dx.doi.org/10.1016/j.enconman.2014.03.012

Shaun Rimos ⇑, Andrew F.A. Hoadley, David J. BrennanDepartment of Chemical Engineering, Clayton Campus, Monash University, Vic. 3800, Australia

a r t i c l e i n f o a b s t r a c t

Article history:Available online xxxx

Keywords:Resource depletionNatural gasResource substitutionEconomic consequences

Resource depletion is a key aspect of sustainability, because the consumption of finite resources impactson their availability for future generations. There are many proposed methods for accounting for thedepletion of a particular resource, amongst which include the proportion of the resource depleted, therate of resource depletion, and the energy, exergy, or monetary cost of extraction as the resource becomesharder to find or extract.

This paper is part of a wider study to measure resource depletion using its environmental and economicimpacts for the case of natural gas, where depletion of natural gas requires substitution by black coal orcoal seam gas. The capital and operating costs are estimated both for upstream fuel extraction and puri-fication and downstream use of the fuel to produce electricity, hydrogen and ammonia. These costs arebased on a commercial scale of operation, using the same basis for economic modelling in each case. Blackcoal was found to have the lowest transfer price from upstream to downstream processing among thethree feedstocks, but the highest capital and operating costs in the downstream processes. Conventionalgas produced slightly higher transfer prices and downstream processing costs compared to coal seam gas.

The favourable economic and environmental indicators for natural gas and coal seam gas are expected tolead to increased demand for these resources over coal, running the risk of a gas shortage. The economicconsequence of a scarcity of either gas resource will be a penalty in capital and operating costs to producethe three products should gas be substituted with black coal.

� 2014 Elsevier Ltd. All rights reserved.

1. Introduction

Australia is rich in high-quality and diverse energy resources,such as natural gas and coal. Energy exports were reported by theBureau of Resource and Energy Economics (BREE) [1] to accountfor one third of the value of Australia’s total commodity exportsin 2010–2011. Unlike minerals which are mined solely for theirchemical components, fossil fuels are extracted for their inherentenergy properties as well. From a sustainability viewpoint, increas-ing exploitation of fossil fuel resources will hasten their depletion,impacting on future generations. Various indicators have beendeveloped using Life Cycle Assessment (LCA) methodology to en-able resource depletion of fossil fuels to be measured. LCA is anenvironmental assessment method used to identify and quantifypotential environmental burdens and impacts of a product orprocess. Typically, the output of the LCA is a set of environmentalimpact indicators under a common basis (e.g. environmentalimpact for every tonne of product produced).

Traditionally, the ISO LCA framework only covers environmen-tal burdens. As a result, the economic consequences, such as thechange in operating and capital costs for products derived fromthe different fossil fuels, are not captured for resource depletion.Additionally, there are economic risks associated with extractingresources from more remote or environmentally sensitive loca-tions as well as risks of higher government taxes on greenhousegas emissions for inferior quality resources.

A methodology was proposed to measure the full impacts ofresource depletion, which includes environmental and economicdifferences between alternatives. Previous work had beenperformed by the authors using LCA to capture the environmentalimpacts due to the substitution of natural gas by coal in a scarcityscenario [2]. In this work, existing resource depletion approacheswere examined in the context of natural gas depletion. Theseapproaches included the role of resource depletion based on esti-mates of consumption rate and reserves, as well as estimates ofthe energy, exergy or monetary cost of extraction as the resourcebecomes depleted. An additional methodology was proposed tomeasure impact changes when fossil fuel substitution occurs as aresult of scarcity. The methodology was applied to a scarcity situ-ation of natural gas in Australia where black coal is substituted for

(2014),

Nomenclature

A annualised capital costA$ Australian dollarsb capacity exponentFC fixed costs which are unaltered with change in produc-

tion rateGJ giga (109) jouleHHV higher heating value, assumes that the latent heat of

vaporisation of water in fuel and reaction products isrecovered

i fractional interest rate per year, %Ip fixed capital investment cost of proposed plantIr fixed capital investment cost of reference plantMW mega (106) wattMW h mega (106) watt-hour

n project life, yearsOL operating labour costs in the form of wages or salaries

for shift operators responsible for the operation of theplant

PC production costs which are a total of fixed and variableoperating costs, excluding non-manufacturing costs

PO payroll overheads, additional employee costs incurredby the employer

£ British poundsQp production capacity of proposed plant, 2011AUDQr production capacity of reference plant, 2011AUDt tonneUS$ US dollars

2 S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx

gas for production of electricity and hydrogen. The resultingimpacts or emissions to air and water, as well as solid wastegeneration and water depletion were determined.

The current study is a continuation of the previous work, whichis to incorporate capital and operating cost differences incurredfrom fuel extraction and purification to downstream product man-ufacture to reflect the economic impacts of resource depletion. Acase study has been undertaken involving the substitution of nat-ural gas with coal or coal seam gas. All three fuels are plentiful inAustralia, but they are also being rapidly consumed. The conse-quences of switching between them are evaluated by comparingtheir respective capital and operating costs over their extraction,purification and downstream processing stages. The evaluationwill consider three product systems: electricity, hydrogen andammonia. Each of these products is of key commercial and strate-gic importance to Australia.

2. Definition and assumptions

Each production system contains an upstream section, wherethe feedstock is extracted from its natural state and processed intoa saleable fuel, and a downstream section, where conversion offeedstock into the end product occurs. The cost of transport fromthe upstream section to the production section, as well as the dis-tribution of the final product to the market, is not included in theanalysis, although the effect of relevant distances and fuel formsare recognized as having a significant influence on fuel and productcosts.

The economic parameters examined are capital and operatingcosts. In the process of substitution, capital costs could be incurredin decommissioning and dismantling, but these are not included inthis study. All capital and operating costs are expressed in or ad-justed to 2011 Australian dollars (A$). The exchange rate at theyear 2011 is used for currency conversions (e.g. 0.9687 A$ for1 US$) [3].

3. Methodology

In this study, capital and operating costs for the upstream anddownstream sections of conventional natural gas, black coal, andcoal seam gas systems are estimated using a set of commonassumptions (e.g. discount rate). The projects examined in thisstudy are new, greenfield plants with the purpose of replacingexisting plants. Firstly, the capital and operating costs of the extrac-tion and purification sections are estimated for all alternatives. Thisallows the calculation of a transfer price for each purified feedstock

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for use in the downstream manufacturing process. Transfer pricesaccount for cash operating costs, annualized capital costs and roy-alties but exclude further margins derived from market opportuni-ties or distribution costs.

Capital costs for a number of Australian upstream projects havebeen compiled for each feedstock type to ensure reasonableestimates. A baseline project is selected from these projects onthe basis of a suitable configuration (e.g. domestic gas rather thanLNG exports) and level of supporting detail in cost breakdown andassumptions. The capital costs are accounted for as annualizedcapital costs over the operating life of the system and calculatedusing the following equation:

A ¼ Ipið1þ iÞn

ð1þ iÞn � 1

� �ð1Þ

Annualized capital costs are added together with the cash oper-ating costs, which consist of feedstock and utility costs, wages,fixed operating costs and administrative, research and marketingcosts, to obtain total operating costs. Cash operating costs arecalculated based on literature data for technology performancesupported by cost assumptions listed in Table 1.

Royalties are paid to the owners of fossil fuel resources, and areintegrated into the transfer price of the feedstock. Royalties are cal-culated as a percentage of the value of production (total revenueless allowable deductions). Based on Australian state governmentwebsites [6–8], the royalty rates for petroleum royalties liebetween 10.00% and 12.5% of the wellhead value of petroleumproduced, while for coal royalties, the percentage is between6.2% and 8.2% of the mined value of the coal. A mid-point percent-age is taken for each feedstock.

Transfer prices for conventional gas, black coal and coal seamgas were derived from data outlined in Table 1. The productioncapacities for each product system were brought to a commonbasis in MW (electricity) or tonnes per year (hydrogen and ammo-nia), independent of the feedstock.

It was assumed that the capital cost of upstream and down-stream processing plants can be adjusted to account for variationsin capacity using Eq. (2), and adopting a value of b = 0.7 as outlinedin Table 1.

Ip ¼ IrQ p

Q r

� �b

ð2Þ

The operating costs for all process plants are calculated using aconventional operating cost model and the economic parametersfrom Table 1.

onsequences of natural gas substitution. Energy Convers Manage (2014),

Table 1Economic parameters required to calculate capital costs and operating costs.

Item Units Value

Plant life Years 30Discount rate %/year 10Plant capacity exponent – 0.7Availability % 85Coal royalty rate % of transfer

cost7

Petroleum royalty rate (for conventional gas or coalseam gas)

% of transfercost

11

Payroll overheads (PO)a % OLb 50Supervisiona % (OL + PO)c 15Maintenance and repairsa % FCd 2Consumablesa % (OL + PO)c 10Plant overheadsa % (OL + PO)c 100Laboratorya % (OL + PO)c 10Insurancea % FCd 1Property taxesa % FCd 1Administrative costsa % PCe 5Marketing costsa % PCe 1Research and development costsa % PCe 5

a Factors were chosen based on Brennan [4] and Peter and Timerhaus [5].b OL, operating labour = number of process operators per shift x number of shift

teams x annual wages.c OL + PO =

P(operating labour and payroll overheads).

d FC, fixed cost = % of plant capital cost.e PC, production costs = % of total operating cost.

S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx 3

4. Case studies

Fig. 1 summarizes the different pathways from the extractionand purification of the feedstock to its conversion into the finalproduct. The extraction stage and the processing stage form theupstream section, and the production section includes the processplant for the production of electricity, hydrogen and ammonia.

4.1. Upstream sections

For conventional gas, the offshore Reindeer field linked to theonshore Devil Creek gas processing plant jointly owned by Apacheand Santos was chosen to represent the upstream section. The pro-ject was completed at A$1.05 billion Australian dollars [9], with a

Fig. 1. Flow diagrams for processes using (a) conventional natural gas, (b) coa

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gas processing component capacity of 78 petajoules per year [9]that had a cited cost of A$280 million after being adjusted to2011 Australian dollars [10]. The operating cost performance esti-mates were based on U.S. Gulf of Mexico wellhead operating costsreported by the U.S. Energy Information Administration (EIA) [11].

For upstream black coal, the Range Project located in Queens-land and owned by Stanmore Coal [12] was selected. The exportopen cut coal mine produces 5 million tonnes of thermal coal peryear, and under the owner mining option, the mining capital wasestimated to be A$169 million (excluding export-related infra-structure) and the operating expenditure was estimated to beA$23.50 per tonne of coal mined (pre-royalty, overheads inclusive,but excluding capital repayment and processing costs related toexport requirements).

The upstream section for coal seam gas is different from that ofconventional natural gas, as both extraction and processing alwaysoccurs onshore and incurs different technologies as shown in Fig. 1.Gas is extracted from a large number of small wellheads and gath-ered at a central processing plant. Water from the extracted coalseam gas is released and directed to a water treatment plant. TheSpring Gully project owned by Origin was chosen to representthe coal seam gas upstream section, which has a total gas process-ing capacity of 38 petajoules per year. The operating costs werebased on U.S. coalbed methane wellhead operating cost data re-ported by the U.S. Energy Information Administration (EIA) [11].A portion of the capital costs were allocated to the gas and watertreatment plants using estimates from the Australian Energy Mar-ket Operator (AEMO) [13], and the remainder was attributed to theupstream gas extraction.

The capital costs, operating costs and transfer price for eachfeedstock is summarised in Table 2. The transfer price of conven-tional gas was found to be 2.5 times that of black coal on a $ pertonne basis, and slightly higher than the transfer price of coal seamgas. ACIL Tasman [14] quotes marginal coal prices into New SouthWales power stations ranging from A$1.01 to A$1.80 per gigajoule,and from A$0.75 to A$2.20 for coal into Queensland power stationsin real 2009–2010 dollars. ACIL Tasman [14] also reports estimateddelivered natural gas costs ranging from A$0.80 to A$7.42 per giga-joule in real 2009–2010 dollars for Queensland, New South Wales,Victoria, South Australia, and Tasmania. Western Australia andNorthern Territory delivered gas costs were not included. Skoufa

l seam gas and (c) black coal (transportation is excluded from the study).

onsequences of natural gas substitution. Energy Convers Manage (2014),

Table 2Economic results for upstream projects of conventional gas, coal and coal seam gas (2011A$).

Product output Conventional gas Black coal Coal seam gas1.30x106 t/year 5 � 106 t/year 0.63 � 106 t/year

Extraction Processing Extraction Extraction Processing

Capital costs (A$million) 770 280 169 324 236Annualised capital costs (A$/t) 62.9 22.8 3.6 54.1 39.5Cash operating costs (A$/t)a 39.3 15.8 23.5 1.3 29.2Total operating costs (A$/t)b 140.8 27.1 124.1Royalty costs (A$/t)c 17.4 2.0 15.4Transfer price (A$/t)d 158.3 29.2 139.5Transfer price (A$/GJ-HHV)e,f 3.1 1.2 2.7

a Cash operating costs excludes annualised capital costs.b Total operating costs =

P(annualised capital costs + cash operating costs).

c Royalty costs = total operating costs/(100% � royalty rate) � royalty rate.d Transfer price = total operating costs + royalty costs.e Higher heating value of conventional gas and coal seam gas = 51.34 GJ-HHV/t [16].f Higher heating value of black coal = 24.4 GJ-HHV/t [16].

4 S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx

and Tamaschke [15] reported 2008 average prices for Queenslandblack coal, Queensland gas and Victorian gas to be $1.40/GJ,$3.67/GJ and $4.19/GJ respectively. These average coal and gascosts are higher than the transfer prices estimated in this studybut reflect additional delivery costs of purified feedstock fromthe producer to the user, however they have similar ratios to thosein Table 2.

4.2. Production sections

Each system will employ a manufacturing process based on theproduct and the feedstock used. No distinction is made betweenplants using conventional natural gas or coal seam gas, where com-position differences are relatively minor since the gas is required tomeet a common pipeline specification. For each system, whetherelectricity, hydrogen or ammonia, the capital costs for both thenatural gas and coal fed plants are sourced from the same litera-ture. Where the reference plant capacities are not equal, the capitalcost of one process is scaled according to Eq. (2) to match the pro-duction capacity of the other. The economic parameters used tocalculate the capital and operating costs are summarised inTable 3.

4.2.1. Selection of reference plant capacityThe nominated basis for the generation capacity of the electric-

ity generation plant is restricted by the maximum available capac-ity of the natural gas power plant. The largest combined cyclepower station in Australia is the Darling Downs power stationowned by Origin energy [22]. It has a generating capacity of630 MW, which is produced by three gas turbines each with acapacity of 120 MW and a steam turbine with a capacity of270 MW. The size of the combined cycle power station used in thisstudy (750 MW) is representative of a current generation green-field gas-fired power station.

Table 3Economic parameters specific to power, hydrogen and ammonia plants according to feeds

Capacity Electricity [17]750 MW

Natural gas Coal

Feedstock input (� 106 t/year) 0.79 2.17Capital costs (A$million) 972 2497Annual wage (� 103 A$/year)a 114.5 114.5Number of process operators 30 50

a Based on wages and salaries per employee from Australia Industry 2010–2011 by AB

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The hydrogen plant capacity of 380 tonnes per day used in thisstudy was chosen by the Australian Department of Resources, En-ergy and Tourism [23] as a size suited for a centralized hydrogenproduction facility with delivery to users. This was for both largescale natural gas reforming and large scale coal gasification in Aus-tralia. For the ammonia plant, the chosen capacity of 2000 tonnesper day was representative of an existing large scale ammoniaplant in Australia. The Yara Pilbara Fertilizers ammonia plant[24] in the Burrup Peninsula, situated in Karratha, Western Austra-lia, has a production capacity of 850,000 tonnes per year.

4.2.2. Electricity generationAccording to BREE [1], nearly 30% of domestic natural gas and

89% of domestic coal was used to generate electricity in Australiain 2009–2010. A thermal electricity generation capacity of3887 MW was from combined cycle gas turbine technology, where2492 MW was recorded for conventional gas and 1395 MW forcoal seam gas. The electricity generation capacity for black coalthrough steam turbines in the same year was 22,437 MW. Fig. 2shows the pathway from natural gas and coal to electricity. Theefficiencies for the gas-fired and coal-fired power plants are49.5% and 38.0% respectively on a higher heating basis.

Capital costs for a 750 MW pulverized black coal-fired powerstation and a 750 MW combined cycle power station were basedon an Australian study performed by Bedilion et al. [17], in whichthe coal power plant was shown to have a capital cost 2.5 timesthat of a combined cycle power station. An Australian sustainabil-ity study by May and Brennan [25] estimated total system capitalcosts for black coal power plants and combined cycle power plantsof equal capacity to be A$3.4 billion and A$1.95 billion respectively(after adjustment for capacity using Eq. (2) and inflation from2000A$ to 2011A$). According to Stamford and Azapagic [26], pul-verized coal power plants in the United Kingdom have capital coststhat range from 2.3 to 5.6 times that of combined cycle power

tock (2011A$).

Hydrogen [18] Ammonia [19]380 t/day 2000 t/day

Natural gas Coal Natural gas Coal

0.40 1.00 0.34 1.21219 648 319 79891.3 91.3 91.3 91.320 30 25 35

S [20], adjusted to 2011 Australian dollars using the Wage Price Index by ABS [21].

onsequences of natural gas substitution. Energy Convers Manage (2014),

Fig. 2. Flow diagram for (a) combined cycle gas turbine power station and (b) pulverised coal steam turbine power station.

S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx 5

plants on a £/MW h basis. A capital cost of £1 billion for a 2 giga-watt capacity combined gas power plant in the United Kingdomwas also provided, which is approximately A$840 million for a sim-ilar plant after adjustment to a capacity of 750 MW. The capitalcost data from Bedilion et al. [17] shows good correlation with thisrecent publication.

4.2.3. Hydrogen productionSteam methane reforming is the most widely established

hydrogen production technology, while gasification technology isrequired to produce hydrogen from coal. The process steps areshown in Fig. 3 as (a) and (b) respectively. BREE [1] reported thatin Australia, 119.1 petajoules of natural gas were used to makechemicals, while only 7.9 petajoules of coal and coal by-productswere used to make chemicals in 2009–2010.

Bartels et al. [27] provided capital cost data for various hydro-gen plants and adjusted them to 2007US$. After adjustment to acommon capacity of 380 tonnes of hydrogen per day and 2011A$,it was shown that the capital costs for steam methane reforminghydrogen plants range from A$145 million to A$246 million, whilecoal gasification plants range from A$638 million to A$773 million.The capital cost for the steam reforming plant agree with the

Fig. 3. Flow diagram for (a) steam methane reformer hydrog

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capital cost range from Rutkowski [18], while the capital cost ofthe coal gasification plant falls beneath the range. Some divergencefor coal gasification could reflect both the evolving and alternativecharacteristics of gasifier technologies.

4.2.4. Ammonia productionAmmonia is used in Australia in the manufacture of down-

stream chemicals principally (ammonium nitrate and sodium cya-nide). Currently, ammonia in Australia is produced largely fromnatural gas through catalytic steam methane reforming as shownin Fig. 4(a). It is estimated from existing ammonia plants (Burrup,Gibson Island, Kwinana, Mooranbah, and Kooragang Island) thatthe total ammonia production capacity is approximately 1.9million tonnes per year. There are two competing natural gas-to-ammonia pathways used in Australia: the conventional technol-ogy supplied by Uhde and others as shown in Fig. 4 encompassinga second reformer to increase the production of hydrogen andintroduce nitrogen. The alternative is proposed by Linde wherenitrogen is provided by an air separation unit. There are currentlyno commercial ammonia-from-coal plants operating in Australia.Possible ammonia-from-coal technologies include the Koppers-Totzek process, the Lurgi dry gasification technology and the

en plant and (b) entrained flow gasifier hydrogen plant.

onsequences of natural gas substitution. Energy Convers Manage (2014),

Fig. 4. Flow diagram for (a) natural gas based ammonia plant and (b) black coal based ammonia plant.

6 S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx

Texaco coal slurry gasification technology [19]. The pathway inFig. 4(b) is the flow diagram of the Texaco process. Australianammonia plants rely on low natural gas gas prices to remain com-petitive with imported ammonia made from cheaper gas sources(e.g. U.S. shale gas).

The ammonia plant capital costs for natural gas and coal weretaken from Appl [19] and adjusted to 2011 Australian dollars.There is general agreement [19,28] that the capital investment costfor coal-based ammonia plants are 2.5 times that of naturalgas-based ammonia plants.

5. Results and discussion

Table 4 summarizes the estimated operating costs for eachproduct case. The estimates are based on assumptions detailed inTable 1, and from estimates of transfer prices from upstreamextraction of coal and gas (Table 2) and downstream production

Table 4Summary of operating cost estimates for electricity, hydrogen and ammonia using natura

Electricity HydCapacity 750 MW 380Output (Units/year) 5.58 � 106 MW h/year 1.18

NG BlC CSG NGUnits A$/MW h A$/

Annualised capital costs 18.5 47.4 18.5 197

Cash operating costsa

Variable costsb 22.3 13.1 20.2 553Fixed costsc 9.0 21.3 9.0 125Other costsd 3.9 4.2 3.6 83.8

Totale 35.2 38.6 32.8 762

Total operating costsa,f 53.7 86.0 51.3 959

a Cash operating costs excludes annualised capital costs.b Variable costs consist of raw material and utilities.c Fixed costs include labour, supervision, maintenance, consumables, payroll and pland Other costs are non-manufacturing costs which include administrative, research ande Total cash operating costs = variable costs + fixed costs + other costs.f Total operating costs = annualised capital costs + cash operating costs.

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of electricity, hydrogen and ammonia from coal or gas (Table 3).Variable costs include the feedstock costs which were calculatedby multiplying the transfer prices for each feedstock in Table 2with the consumptions required in Table 3, and utilities costswhich were relatively minor in magnitude. Annualized capitalcosts were calculated by taking the capital costs in Table 3, the dis-count rate and plant life in Table 1, and using them in Eq. (1). Allfixed costs are a percentage of the capital cost or the labour plusoverheads; the percentages are given in Table 1. The other costs(administrative, research and marketing) are taken as 11% of thetotal cash operating costs.

The data shows similar trends in relative costs for each of thethree products (electricity, hydrogen and ammonia). Feedstockcosts make up the majority of the variable costs, and the resultsfrom Table 4 show that the difference in transfer prices betweencoal and natural gas is not sufficient to give coal an economicadvantage. The capital costs of coal projects are much higher thanthose of conventional gas and coal seam gas, leading to a higher

l gas (NG), black coal (BlC) and coal seam gas (CSG) as feedstocks.

rogen Ammoniat/day 2000 t/day� 105 t/year 6.21 � 105 t/year

BlC CSG NG BlC CSGt H2 A$/t NH3

.0 582.7 197.0 54.6 136.5 54.6

.0 339.9 475.8 158.5 143.4 145.6

.3 296.2 125.3 32.7 68.4 32.778.6 74.3 23.6 26.2 22.0

.1 714.7 675.4 214.8 238.0 200.3

.1 1297 872.4 269.4 374.5 254.9

t overheads, laboratory, insurance and property taxes.marketing costs.

onsequences of natural gas substitution. Energy Convers Manage (2014),

S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx 7

fixed operating cost and cash operating cost, as well as a higherannualized capital cost.

Due to the assumption that the same process plant configura-tions are shared between conventional gas and coal seam gas(e.g. both have the same capital costs), the operating costs for thesetwo feedstocks were found to be almost equivalent. The operatingcosts for processes using conventional gas were approximately 5–7% higher than for processes using coal seam gas because of thehigher transfer price of conventional gas. Further competing eco-nomic risks between the two fossil fuels may affect this result.For example, conventional gas will become more expensive asthe resources become harder to find and extract, while the costof coal seam gas will be higher if the amount of associated wateris large and requires more extensive treatment, a high number ofwells are required, or landowners receive compensation payments.

Bedilion et al. [17] provided levelised costs of electricity (sum ofcapital, O&M and fuel) for both pulverized coal power stations andcombined cycle power stations. The fuel cost component was ad-justed to account for the fuel costs used in this study. The adjustedlevelised costs of electricity (in 2011A$) are A$83.27/MW h for pul-verised coal power stations and A$59.75/MW h for combined cyclepower stations. These values are slightly higher than the results inTable 4. May and Brennan [25] gave annualized costs (sum of oper-ating costs and annualized capital costs) of A$99.42/MW h andA$51.57/MW h (adjusted for inflation from 2000A$ to 2011A$)for coal power stations and combined cycle power stations respec-tively. Stamford and Azapagic [26] reported a range of levelisedelectricity costs (sum of capital, O&M, and fuel) in 2012£/MW h(adjusted to 2011A$). Mid-range levelised electricity costs ofA$114.44/MW h were reported for pulverised coal power stations,and A$101.13/MW h for combined cycle power stations. Theseelectricity costs are much higher than the Australian basedestimates with a smaller difference between coal and gas. This islargely due to different fuel cost assumptions.

Klett et al. [29] reported levelised costs for hydrogen from coaland gas in 2000US$. These are adjusted to 2011A$, and the fuelcosts used were US$3.15/MMBtu for natural gas and US$1.00/MMBtu for coal, which are similar to the transfer costs from Table 2.The levelised hydrogen production costs from natural gas were re-ported to be A$511.94/t H2 and levelised carrying capital charges tobe A$126.03/t H2, giving a total production cost of A$637.97/t H2.For hydrogen from coal, the levelised production costs were re-ported to be A$257.60/t H2 and the levelised carrying capitalcharges to be A$468.51/t H2, thus producing a total production costof A$726.11/t H2. These costs were lower than those found inTable 4, but show similar trends between the gas and coal options.

Appl [19] provided production costs for ammonia based on par-tial oxidation of coal or steam reforming of natural gas in 2004US$.After adjusting the fuel cost component to account for thefuel costs used in this study and adjusting for inflation andcurrency (2011A$), the production costs for the coal option was$509/t NH3, while the gas option was $292/t NH3. The gas option

Table 5Impact of a carbon tax on total operating costs (2011A$).

Electricity Hy

NG BlC CSG NG

Greenhouse gas emissions a t CO2-eq./MW h t CUpstream 0.04 0.01 0.02 0.9Downstream 0.37 0.82 0.37 8.8

Carbon tax scenarios $/MW h $/tWithout carbon tax 53.7 86.0 51.3 95With carbon tax ($23/t CO2-eq.) 63.2 105.3 60.4 11

a LCA data adapted from [2].

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production cost was consistent with the ammonia production costsin Table 4, but cost for ammonia from coal was much higher thanthe one in this study.

Table 4 concludes that gas-produced electricity has lower capi-tal and operating costs than black coal, which is consistent withthe findings from the literature discussed. Gas-produced electricityalso has lower CO2 emissions than black coal. This explains whymost new power stations built in Australia have been combinedcycle gas turbine plants. Coal-fired power stations have a disadvan-tage when competing with natural gas due to their high capitalcosts, which can be more than 2.5 times that of gas-fired powerplants. In addition, coal-fired power plants with higher levels ofemissions may incur additional environmental costs such as an in-creased carbon tax and/or more extensive effluent treatment to en-sure emissions limits are achieved. In Australia, many existingcoal-fired power plants can produce cheaper electricity, becausethey have been fully depreciated and capital repayments are com-pleted. The higher capital cost and derived operating cost for coal-fired plants drives plant capacities higher in order to compete withgas-fired plants. This in turn escalates the capital investment forprojects, which coupled with longer construction times, slowsresponsiveness to demand and increases the overall level of invest-ment risk.

For hydrogen and ammonia plants, coal seam gas or conven-tional gas remains the most economically favourable option overcoal due to their higher hydrogen component, relative ease of con-version into chemical products, and lower capital and operatingcosts.

Australia like many other countries currently has a carbon taxsystem which charges polluters for every tonne of carbon they re-lease into the atmosphere. The carbon intensity of each productacross its life was obtained using LCA in previous work [2], whichis used to calculate the carbon prices under different pricing sce-narios in Table 5. The initial Australian cost was set at $23 pertonne in mid-2012 and increases by a nominal 5% every year. Withor without the carbon tax, the products derived from coal havehigher production costs than products derived from gas. Underthe carbon tax scenario, the products derived from coal are affectedthe most as the coal processes produce more carbon dioxide perunit product than gas processes, thus further increasing the gap be-tween the production costs of coal processes and gas processes.Thus, a natural gas scarcity requiring substitution with coal will re-sult in a price increase that is more significant if a carbon tax is inplace.

A sensitivity analysis was performed by changing the plant cap-ital costs, transfer price and discount rate individually while keep-ing the other parameters constant. This is performed only on thealternatives to conventional natural gas, which are black coal andcoal seam gas. The results for black coal are summarised in Table 6and the results for coal seam gas are summarised in Table 7. Thediscount rate used has a significant influence on the total operatingcosts and is dependent on the perceived risk, source of money and

drogen Ammonia

BlC CSG NG BlC CSG

O2-eq./t H2 t CO2-eq./t NH3

6 0.29 0.57 0.20 0.05 0.129 19.25 8.89 1.80 2.97 1.80

H2 $/t NH3

9.1 1297 872.4 269.4 374.5 254.985.8 1746.5 1090.0 315.4 443.8 299.1

onsequences of natural gas substitution. Energy Convers Manage (2014),

Table 6Sensitivity analysis of key parameters on the annualised capital (AC), cash operating (CO) and total operating (TO) costs of black coal processes.

Electricity (A$/MW h) Hydrogen (A$/t H2) Ammonia (A$/t NH3)

Operating costs AC CO TOa AC CO TOa AC CO TOa

Base 47.4 38.6 86.0 582.7 714.7 1297.5 136.5 238.0 374.5Parameter % change

Discount rate+50% 68.1 38.6 106.7 836.6 714.7 1551.4 195.9 238.0 433.9�50% 29.1 38.6 67.7 357.4 714.7 1072.1 83.7 238.0 321.7

Plant capital costb

+10% 52.2 40.6 92.8 641.0 739.4 1380.4 150.1 243.8 393.9�10% 42.7 36.6 79.3 524.5 690.0 1214.5 122.8 232.2 355.1

Transfer price+10% 47.4 40.0 87.4 582.7 745.9 1328.6 136.5 245.3 381.7�10% 47.4 37.1 84.5 582.7 683.6 1266.3 136.5 230.8 367.2

a TO = AC + CO.b Includes the capital cost of the downstream plant only.

Table 7Sensitivity analysis of key parameters on the annualised capital (AC), cash operating (CO) and total operating (TO) costs of coal seam gas processes.

Electricity (A$/MW h) Hydrogen (A$/t H2) Ammonia (A$/t NH3)

Operating costs AC CO TOa AC CO TOa AC CO TOa

Base 18.5 32.8 51.2 197.0 675.4 872.4 54.6 200.3 254.9Parameter % change

Discount rate+50% 26.5 32.8 59.3 282.9 675.4 958.3 78.4 200.3 278.7�50% 11.3 32.8 44.1 120.8 675.4 796.2 33.5 200.3 233.8

Plant capital costb

+10% 20.3 33.5 53.8 216.7 683.7 900.5 60.1 202.7 262.7�10% 16.6 32.0 48.6 177.3 667.0 844.4 49.1 198.0 247.2

Transfer price+10% 18.5 35.0 53.5 197.0 726.7 923.7 54.6 209.2 263.8�10% 18.5 30.5 49.0 197.0 624.1 821.1 54.6 191.5 246.1

a TO = AC + CO.b Includes the capital cost of the downstream plant only.

8 S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx

the financial environment. Raising the discount rate from 10% to15% had a larger effect on total operating costs from black coal pro-cesses than from gas processes, with a 24% increase for electricitycosts, 19.6% for hydrogen costs, and 15.9% for ammonia costs. Achange in plant capital costs by 10% will have a greater influenceon production costs than a change in the transfer price by 10%.The same trend can be seen for changes in the discount rate andplant capital costs for coal seam gas processes. For coal seam gasprocesses, the transfer price has a greater influence on total oper-ating costs due to the feedstock costs making up a major portion ofthe total operating costs. A separate analysis on the effects ofincreasing product output (e.g. increasing plant capacity) will re-sult in a decrease in total operating costs per unit product, demon-strating the effects of scale economies on total operating costs.

In the event of a fuel scarcity, capital costs could be incurred indecommissioning upstream and downstream plants [30]. Decom-missioning involves plant dismantling, site remediation to avoidor mitigate potential long-term pollution risks, and rehabilitation.There are also other factors that affect the economics of decommis-sioning such as post-closure human resource and land usemanagement and selecting the best demolition strategy (e.g. alter-native use, sale, salvage, recycling and disposal) to maximise cost(and environmental) benefits. These costs will differ dependingon the fuel system chosen. The conventional gas industry willrequire handling of pipelines and wellheads located offshore,whereas the coal seam gas industry will have to manage the re-moval and disposal of an extensive number of onshore pipelines.Mitigation of spills and leaks of both gas and liquids is also very

Please cite this article in press as: Rimos S et al. Determining the economic chttp://dx.doi.org/10.1016/j.enconman.2014.03.012

important for the decommissioning of natural gas systems. Decom-missioning of black coal systems will require the closure and reha-bilitation of generally large mine sites, and the management ofplant related structures and hazardous substances (e.g. ash pondclosures, asbestos and lead abatement, and contaminated soil dis-posal). Part of these decommissioning costs can be mitigated bythe salvage value of the plant.

If natural gas remains the preferred feedstock for electricitygeneration and chemicals manufacture both in Australia and inthe overseas export markets, this could accelerate the depletionof natural gas resources in Australia, increasing the risk of a naturalgas shortage. Due to its abundance, coal is likely to then be aprevalent substitute for gas for each product option, but with thecapital and operating cost penalties indicated in Table 4. While coalseam gas is an alternative to natural gas with little apparent eco-nomic penalty, only one of these two resources occurs naturallyin most Australian states. This limits the opportunity for substitu-tion because of the associated costs of transport by pipeline or byliquefaction and shipping.

Hence, whatever the alternative for conventional gas, whetherit is black coal or coal seam gas, each alternative comes with itsown set of economic consequences.

6. Conclusion

This study has examined the capital and operating costs ofextracting conventional gas, black coal and coal seam gas in

onsequences of natural gas substitution. Energy Convers Manage (2014),

S. Rimos et al. / Energy Conversion and Management xxx (2014) xxx–xxx 9

Australia, and downstream production of electricity, hydrogen andammonia from each of the three feedstocks. Using baseline cases asa starting point, the transfer price was found to be A$3.05 per giga-joule for natural gas, A$1.36 per gigajoule for black coal, andA$2.76 per gigajoule for coal seam gas. The price differential be-tween conventional gas and coal seam gas was small.

Based on these transfer prices, the downstream processes utiliz-ing black coal had higher capital costs and higher total operatingcosts than conventional or coal seam gas. In a carbon tax scenario,the black coal processes remain at a disadvantage due to theirhigher carbon dioxide equivalent emissions compared to theirgas-based alternatives. Sensitivity analysis reveals that the selec-tion of the discount rate can significantly raise or lower the totaloperating costs by as much as 24%. The costs of downstream prod-ucts are most sensitive to capital related parameters such as plantcapital costs and discount rates. Products derived from coal seamgas are more sensitive to changes in transfer price compared toproducts derived from black coal, as the feedstock cost is a majorcomponent of the coal seam gas transfer price.

With the prospect of increased consumption of Australian con-ventional and coal seam gas, for both domestic and export markets,driven by environmental and cost considerations, there is a grow-ing risk of gas shortage. The economic penalty is the increase incapital and operating costs of producing electricity, hydrogen andammonia if the alternative is to substitute with black coal. Conven-tional gas can be substituted for coal seam gas and vice versa withlittle economic penalty, but due to the geography of the gas re-serves, this option is often not possible. Replacement of black coalwith either conventional or coal seam gas, on the other hand, pro-duces minimal economic risks and is feasible for an Australianscenario.

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