or Biomass with CO2 Capture

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Gasoline from Coal and/or Biomass with CO2 Capture and Storage, Part B: Economic Analysis and Strategic Context Guangjian LIU, Eric D. Larson, Robert H. Williams, and Xiangbo Guo Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/ef502668n • Publication Date (Web): 28 Jan 2015 Downloaded from http://pubs.acs.org on February 3, 2015

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Energy & Fuels 27 January 2015

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Gasoline from Coal and/or Biomass with CO2 Capture and Storage, Part B: Economic Analysis and Strategic Context Guangjian Liu,a,* Eric D. Larson,b Robert H. Williams,b Xiangbo Guod a

School of Energy and Power Engineering, North China Electric Power University, Beijing, China

b

Princeton Environmental Institute, Princeton University, Guyot Hall, Princeton, NJ, USA

c

Research Institute of Petroleum Processing, SINOPEC, Beijing, China

* Corresponding author: [email protected]

Abstract The detailed performance simulation results for fifteen alternative process designs for the production of synthetic gasoline from coal, biomass, or coal+biomass via gasification, methanol synthesis, and methanol-to-gasoline synthesis presented in the companion paper provide the basis for capital and operating cost estimates and the economic and strategic analysis described in this paper. Economic analyses for the fifteen process designs are carried out for different assumed crude oil and greenhouse gas (GHG) emissions prices; for the cases involving CO2 capture the economic analysis is carried out for storage both in deep saline formations and via CO2 injection for enhanced oil recovery. In the absence of any GHG emission price, large plants that use only coal and produce primarily liquids provide the highest internal rate of return on equity (IRRE) for 20-year levelized crude oil prices of $80/bbl to $106/bbl. At the latter crude oil price, modest-scale coproduction systems with low or zero GHG emissions considered as electricity producers provide higher IRRE when captured CO2 is stored via enhanced oil recovery than an investment in a new natural gas combined cycle power plant. At lower oil prices, a sufficient rate of biomass coprocessing would maintain this advantage for coproduction systems if a strong GHG emissions mitigation policy were in place. Keywords: coal, biomass, gasification, methanol-to-gasoline; GHG emissions; coproduction; CCS; economics 1

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Nomenclature AGR ASU

Acid gas removal Air separation unit

ATR BEOP BF bbl BTG CBTG CCC CCS CGEA CO2 EOR CO2e CTG

Auto-thermal reformer Breakeven oil price Biomass fraction of total feedstock energy input (HHV basis) Barrel Biomass-to-gasoline Coal+biomass-to-gasoline Cost of CO2 capture CO2 capture and storage Cost of greenhouse gas emissions avoided CO2 Enhanced oil recovery CO2 equivalent Coal-to-gasoline

DSF EF GHG FT FTL GHGI

Deep saline formation Electricity fraction of energy in products (energy in liquid fuels expressed as LHV) Greenhouse gas Fischer Tropsch Fischer Tropsch Liquids Greenhouse gas emissions index

IGCC IRRE (L) LCOE LCOG MDC MEGE MTG NETL NGCC OC ORV PB RC (S) SRMC Sup PC TPC V WGS

Coal integrated gasification combined cycle power plant Internal rate of return on equity Large Levelized cost of electricity Levelized cost of gasoline Minimum dispatch cost for electricity generation Marginal electric generating efficiency Methanol-to-gasoline National Energy Technology Laboratory Natural gas combine cycle power plant Owner’s costs Ohio River Valley Partial bypass of methanol synthesis Recycle methanol synthesis Small Short run marginal cost of electricity Supercritical pulverized coal power plant Total plant cost (which excludes owner’s costs) Vent CO2 Water gas shift

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1. Introduction The companion paper1 presents detailed technical performance assessments of fifteen process configurations for the production of synthetic gasoline from coal and/or lignocellulosic biomass, without and with capture and storage of byproduct CO2, and with substantial electricity coproduction in some cases. The mass and energy balances described in that paper provide the basis for plant capital and operating cost estimates developed in this paper. Together with estimates of the full fuel-cycle GHG emissions in the companion paper, the cost estimates provide the basis for economic assessments under alternative assumed market and public policy conditions. In cases with CCS, the economics are evaluated both for CO2 storage in deep saline formations (DSFs) and storage via CO2 enhanced oil recovery (CO2 EOR). The analyses in these two companion papers use the process evaluation philosophy and analytical framework developed in Liu et al. (2011)2 for the design and analysis of Fisher-Tropsch fuels production from coal and/or biomass, with and without CCS and with and without substantial electricity coproduction.

2. Process designs summarized For ease of reference, Table 1 lists the common set of acronyms used in this and the companion paper to identify the 15 different process designs evaluated. The companion paper1 includes detailed descriptions of each process. The rationale for how the scale of each plant was selected is briefly described here (and summarized in Table 1). (Scale rationales are also reiterated at various points later in the paper.) Both large-scale (L) and small-scale (S) units are considered for systems that use only coal to make gasoline (CTG systems). For L systems with syngas recycle [CTG-RC-V(L) and CTG-RC-CCS(L)], the coal-input rate is fixed at 22,663 tonnes per day (as-received), resulting in a design synthetic gasoline output of 3


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50,000 bbls/d (petroleum-gasoline equivalent energy), a typical scale aspired to by coal synthetic fuel project developers. To facilitate meaningful economic comparisons, the same coal input rate is used for the CTG designs with partial syngas bypass [CTG-PB-V(L) and CTG-PB-CCS(L)]. The resulting liquids production capacity for these PB plants is about ⅔ of that for the recycle plants.

Table 1. Cases investigated in this study. Acronym Key process features and scale specifications CTG-RC-V(L) Coal feed, recycle unconverted syngas for maximum liquids, vent CO2, 50000 bbl/day gasoline output CTG-RC-CCS(L) Coal feed, recycle unconverted syngas for maximum liquids, capture/store CO2, 50000 bbl/day gasoline output CTG-PB-V(L) Coal feed, syngas partial bypass to coproduce electricity, vent CO2, coal input same as CTG-RC-V CTG-PB-CCS(L) Coal feed, syngas partial bypass to coproduce electricity, capture/store CO2, coal input same as CTG-RC-CCS BTG-RC-V Biomass feed, recycle unconverted syngas for max liquids, vent CO2, 106 t/yr biomass input (dry) BTG-RC-CCS Biomass feed, recycle unconverted syngas for max liquids, capture/store CO2, 106 t/yr biomass in (dry) CBTG-RC-CCS Coal+biomass feed, recycle unconverted syngas for max liquids, capture/store CO2, 106 t/yr biomass, GHGI= 0a CBTG-PB-CCS Coal+biomass feed, syngas partial bypass to coproduce electricity, capture/store CO2, 106 t/yr biomass, GHGI = 0a CTG-RC-CCS(S) CTG-RC-CCS(L) design, but scaled down to gasoline output capacity of CBTG-RC-CCS CTG-PB-CCS(S) CTG-PB-CCS(L) design, but scaled down to gasoline output capacity of CBTG-PB-CCS CBTG-CCS (39% B, 1% E) CBTG-RC-CCS design, 106 t/yr biomass input, BF set so GHGI = 0.17a CBTG-CCS (5% B, 73%E) CBTG-PB-CCS, partial bypass for 73% electricity fraction, BF set so GHGI = 0.17,a total capital cappedb CBTG-CCS (15% B, 47% E) CBTG-PB-CCS partial bypass for 47% electricity fraction, BF set so GHGI = 0.17,a total capital cappedb CBTG-CCS (25% B, 26% E) CBTG-PB-CCS, partial bypass for 26% electricity fraction, 106 t/yr biomass, BF set so GHGI = 0.17a CTG-PB-CCS(S*) CTG-PB-CCS(L) design, but scaled down to gasoline output capacity of CBTG-CCS (25% B, 26% E). (a) GHGI is the greenhouse gas emissions index defined in Box A. (b) Scale for this plant set by capping total capital investment at same level as CBTG-CCS (25% B, 26% E). See companion paper.1

Historically, plants as large as these designs were considered necessary to achieve scale economies to enable competitive liquid fuel production. But considering the difficulty in the present day of financing multi-billion dollar facilities, smaller-scale (S) plants are also analyzed for the -CCS variants. The CTG-RC-CCS(S) and CTG-PBCCS(S) plant scales were set such that their gasoline output capacities match those of the coal/biomass coprocessing plants, CBTG-RC-CCS and CBTG-PB-CCS, respectively. These two (S) cases thereby help illuminate the impact of scale economies via comparisons to their (L) counterparts, and they also help understand the impact of biomass coprocessing, independent of scale, via comparison to their CBTG counterparts. For the two CBTG and the two BTG plant designs, the biomass input rate was fixed at 3,581 metric tonnes (dry basis) per day. This results in an annual biomass input 4


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of approximately 1 million dry tonnes per year (assuming 90% capacity factor), which is considered a logistical maximum for truck-delivery of bales of herbaceous biomass in the U.S.3 For the two CBTG-CCS designs, the biomass fraction of input was selected to be adequate to realize a zero greenhouse gas emissions index (GHGI), the carbon footprint metric discussed in Box A in the companion paper.1 The four additional variants of the CBTG design involve alternative combinations of BF and EF that each result in GHGI = 0.17. For the two cases with the highest BF values [CBTG-CCS (39% B, 1% E) and CBTG-CCS (25% B, 26% E)], the biomass input was fixed at 1 million dry tonnes per year. For the remaining two variants [CBTG-CCS (5% B, 73% E) and CBTG-CCS (15% B, 47% E)], a 1 million t/yr biomass input scale would lead to impractically large plant sizes and prohibitively-large capital requirements. Instead, these plants were sized for a total required capital investment [total plant cost (TPC)] matched to that for the more costly of the other two variants [CBTG-CCS (25% B, 26% E)]. A CTG-PB-CCS(S*) option that has the same process configuration as CTG-PB-CCS(L), but with gasoline output capacity the same as CBTG-CCS (25% B, 26% E), is also considered.

3. Capital Cost Estimates Capital cost estimates are developed in constant mid-2012 U.S. dollars4 using the analytical framework and underlying reference equipment capital cost database described by Liu et al. (2011).2 That database includes reference costs and cost scaling factors for most of the upstream components and power island equipment found in the processes analyzed here, including coal and biomass gasifiers, ATRs, water gas shift reactors, Rectisol AGR systems, gas turbines, heat recovery steam generators, steam turbines, heat exchanger networks, and auxiliary equipment associated with each of these.5 This paper augments the Liu,et al. (2011)2 database with reference costs estimated for the methanol synthesis and methanol-to-gasoline process areas (Table 2). 5


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Table 2. Reference capital cost parameters for estimating the overnight installed capital cost (including associated balance of plant, general facilities, engineering, overhead and contingencies).a Plant component

Scaling parameter

Reference singleunit capacity, So

Max unit capacity

Scaling exponent

Base cost, Co (2012 M$)

Gas phase MeOHsynthesisb

Fuel-gradeMeOH production, t/day

5500

5500

0.65

227.4

16,667 16,667 5,556

0.70 0.70 0.70

63.8 142.4 11.6

DME reactor MTG reactors Gasoline finishere

MeOH to Gasoline Gasoline output, bbl/day 16,667 Gasoline output, bbl/day 16,667 Gasoline output, bbl/day 5,556

c,d

(a) The overnight cost, C, of a component having unit size, S, is related to the cost, Co, of a reference component of unit size, So, by the relationship: C = Co x (S/So)f, where f is the capital cost scaling exponent. For plants requiring multiple units (e.g., multiple MeOH synthesis reactors) to reach the design capacity, a scaling exponent of 0.9 is applied. For example, for a two unit system, the multiplier on the cost for a single unit would be 20.9. (b) The capital cost estimate for a gas-phase methanol synthesis island is based on an Eastman Gasification Services study.6 (c) We assume that a plant producing 50,000 bbl/day of finished gasoline would utilize three MTG trains equipped with one DME reactor and five conversion reactors in each train.7 In each train four conversion reactors would be operating at any given time to achieve full capacity. (The 5th reactor would be undergoing catalyst regeneration.) (d) The MTG reference costs are estimated by adjusting published costs of the mid-1980’s for the New Zealand gas-to-gasoline (GTG) project.8 (e) The finisher treats only the heaviest components of the gasoline, which constitute about 1/3 of the volume of the gasoline.

The reference component costs in Liu,et al. (2011)2 drew heavily on capital cost estimates for system components in the National Energy Technology Laboratory (NETL) “Baseline Power Study” of 2007.9 Subsequently, NETL revised its estimates,10,11 with the most significant revision being the addition of owner’s costs averaging about 23% of the total installed plant costs without owner’s costs (TPC). We have included this level of owner’s costs in the financial analysis here. As in Liu,et al. (2011),2 the main objective in the cost analysis here is to estimate with a high degree of confidence the relative costs for commercially mature versions of the different systems analyzed. However, in the absence of experience with actual projects, one cannot have a high degree of confidence in the absolute values of the costs estimated here. Two recent coal-gasification IGCC projects12 and a project involving a post-combustion CCS retrofit of an old pulverized coal plant13,14 in the U.S. suggest that reliance on the NETL Baseline Power Study capital cost database (and thereby the present analysis, which draws heavily on that database) leads to underestimating costs for real projects—especially for technologies that aren’t already established in the market. One consideration is that cost estimates in the NETL baseline studies are for inside-battery6


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limits (ISBL) costs, thereby excluding outside-battery-limits (OSBL) costs that can be significant in actual projects. Moreover, the latest revision of the Baseline Power Study11 acknowledges that its estimates, while aiming to represent costs for “next commercial offerings…,” “do not include the unique cost premiums associated with first-of-a-kind (FOAK) plants that must demonstrate emerging technologies and resolve the cost and performance challenges associated with initial iterations.” Table 3 gives capital cost estimates and performance summaries for ten of the plant configurations described in detail in the companion paper.1 The upstream areas of the plants – for syngas production and conditioning (ASU, gasification, gas cleanup) – account for between 60% and 70% of TPC in all cases. For the CCS cases, CO2 compression adds only modestly to the capital cost. Table 4 summarizes the capital cost and performance for the remaining five cases described in the companion paper.1

Table 3. Installed total plant cost estimates for ten process designs. Feedstock>>> Technology>>>

Coal Recycle Partial Bypass CTG-RCCTG-RC-CCS CTG-PBCTG- PB-CCS V(L) V(L) (L) (S) (L) (S) 7,112 7,112 1,404 7,112 7,112 1,914 0 0 0 0 0 0 0 0 0 0 0 0 2,913 2,913 575 1,977 1,977 532 50,000 50,000 9,871 33,924 33,924 9,128 359 359 71 248 248 67 110 12.4 2.4 959 790 213 3.3 0.4 30.1 26.2 1.9 1.1 1.5 0.59 5,418 5,518 1,355 5,510 5,842 1,883 950 950 222 995 992 357 0 0 0 0 0 0 1,650 1,650 384 1,650 1,650 519 715 715 193 715 845 265 0 69 20 0 89 30 687 687 191 480 480 179 614 615 160 468 468 152 0 0 0 287 278 90 148 148 50 177 224 72 654 685 135 739 815 219 108.4 110.4 137.3 162.4 172.2 206.3

Coal input rate, MWHHV Biomass input rate, MWHHV Biomass input, % of total energy input (HHV) Gasoline production,MWLHV COPa displaced (excl. LPG), bbls/d Co-product LPG, MWLHV Net export to grid, MW Electricity exports, % of energy output (LHV) Greenhouse Gas Emissions Index (GHGI)b Total Plant Cost (TPC), million 2012$a ASU plus O2 and N2 compression Biomass handling, gasification, gas cleanup Coal handling, gasification, quench WGS, acid gas removal, Claus/SCOT CO2 compression Methanol synthesis MTG synthesis & finishing Gas turbine topping cycle Steam turbine cycle HRSG and heat exchange network Specific TPC, $103per bbl/db (a) Crude oil products (b) See companion paper1 for detailed discussion of GHGI. (c) Excludes owner’s costs.

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Biomass Recycle BTGBTGRC-V RC-CCS 0 0 661 661 100 100 256 256 4,390 4,390 31 31 30 19 5.6 3.5 0.07 -1.1 1,012 1,030 153 153 351 351 0 0 181 181 2 15 117 117 89 89 0 0 37 37 83 87 230.6 234.5

Coal + Biomass Recycle PB CBTGCBTGRC-CCS PB-CCS 758 1,244 661 661 46.6 34.7 575 532 9,871 9,128 71 65 3.5 236 0.3 28.3 0.00 0.00 1,600 2,097 224 343 357 361 217 354 231 317 24 33 191 180 157 151 0 94 55 77 143 187 162.1 229.7

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Table 4. Process simulation and capital cost results for four CBTG variations having GHGI = 0.17 and for the CTG-PB-CCS(S*) design, for which GHGI = 0.59.

Biomass input fraction (HHV) Electricity output fraction (LHV) Feedstock input Coal input, MW HHV Biomass input, MW HHV Liquids output LPG output, MW LHV Gasoline, MW LHV bbl/day crude oil products displaced (excl. LPG) Net electricity export to grid, MW Greenhouse Gas Emissions Index (GHGI) Total Plant Cost (TPC), million 2012$

CBTG-CCS (5% B, 73% E) 0.050 0.73

PB designs CBTG-CCS CBTG-CCS (15% B, 47% E) (25% B, 26% E) 0.150 0.250 0.467 0.264

CTG-PBCCS (S*) 0 0.262

RC design CBTG-CCS (39% B, 1% E) 0.391 0.011

2,539 134

2,294 405

1,982 661

2,715 0

1,027 661

26.8 214 3,678 652.5 0.17 2,627

61.6 497 8,531 490.0 0.17 2,627

93.0 755 12,951 304.6 0.17 2,627

94.8 755 12,951 301.6 0.59 2,517

85.0 689 11,820 8.4 0.17 1,896

Table 5 illustrates the strong economies of scale that characterize the systems analyzed here: specific capital costs ($/MW feedHHV) for CTG-RC-CCS(L) and CTG-PBCCS(L) are considerably lower than for the corresponding small (S) versions of these plant designs. TPC increases with scale (as measured by the coal input rate) with exponents of 0.804 and 0.835 for CTG-RC-CCS and CTG-PB-CCS, respectively. Table 5 also enables a comparison of plant designs at the same scale of liquid fuels production but with one plant co-processing biomass (CBTG) and the other processing only coal [CTG(S)]. Coprocessing biomass adds 17% and 12% to the specific capital cost for the RC and PB cases, respectively. In the PB case, the higher capital cost is due to primarily to the higher specific capital cost for biomass gasification compared to coal gasification,15 and the loss of scale economy as a result of having two gasifiers instead of one for essentially the same rate of primary fuel input. The ATR in CBTG-RC-CCS also contributes to the added capital cost compared to CTG-RC-CCS(S), which has no ATR.

Table 5. Comparison illustrating the impact on capital cost of plant scale and of biomass partial substitution for coal. Gasoline output capacity (bbl/day) 50,000 CTG-RC-CCS(L) 9,871 CTG-RC-CCS(S) 9,871 CBTG-RC-CCS 33,924 CTG-PB-CCS(L) 9,128 CTG-PB-CCS(S) 9,128 CBTG-PB-CCS (a) Excludes owner’s costs.

Electricity net export capacity (MWe) 12.4 2.4 3.5 790 213 236

Total feedstock input capacity (MWfeed HHV) 7,112 1,404 1,419 7,112 1,914 1,904

TPC (106 2012$)a 5,518 1,355 1,600 5,842 1,883 2,097

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TPC (103 per MWfeed HHV) 776 965 1,128 821 984 1,101

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4. Financial Analysis The capital cost estimates provide inputs to financial analysis carried out for different assumed crude oil prices and GHG emissions prices.

4.1 Financial Parameter Assumptions The financial analysis assumes plants have 20-year economic lifetimes and would be located in the Ohio River Valley (ORV), a coal-dependent, biomass-rich region of the United States. The analysis also assumes (except in Sections 4.4 and 4.5) that plants come on line in 2021. Table 6 lists parameter values for this analysis. All prices are in US $2012. Financial performance metrics: Considering that the plants analyzed here produce more than one product, the real internal rate of return on equity (IRRE) is an especially relevant metric for making financial comparisons of alternative energy conversion options. Additionally, the levelized cost of gasoline (LCOG) and the levelized cost of electricity (LCOE16) can be estimated. EPRI’s revenue requirement method,17 modified to include co-product revenues as credits, is applied for these calculations, assuming a 10.2% real rate of return on equity (a value that implies a 7% pre-tax average cost of capital, the assumed discount rate) and other parameter values as shown in Table 6. (The assumed selling prices for coproducts are discussed below.) The LCOG can also be expressed (equivalently) as a breakeven oil price (BEOP), the crude oil price at which the LCOG is the same as the refinery-gate price for crude oilderived gasoline.18

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Table 6. Exogenous prices and costs (2012$) and financial assumptionsa Levelized coal price to an average power generator in the ORV, 2021-2040, $/GJHHVa Levelized natural gas price to an average power generator in the ORV, 2021-2040, $/GJHHVa Biomass price delivered to conversion plants, $/GJHHVb Annual average capacity factor for CTG and CBTG plants, % Annual average capacity factor for power-only plants, % Assumed economic life of energy conversion plants, years Owner’s costs, as % of TPC Allowance for funds used during construction (AFUDC),as % of TPCc Debt/equity mix Return on equity (real) for calculating LCOE and LCOG, % per year Interest rate on debt (real), % per year Weighted average cost of capital (real) when the return on equity is 10.2% per year, % per year Annual capital charge rate (ACCR), fractiond Annual O&M costs at the conversion facility, as % of TPC CO2 transport and injection/storage costs for DSF storage, $ per tonne of CO2 CO2 transport cost for enhanced oil recovery applications, $ per tonne of CO2 CO2plant gate price as a function of crude oil price when sold for EOR, $ per tonne of CO2g (Poil is $/bbl crude oil price and CO2 transport cost is the table entry immediately above) 20-year levelized electricity sale price, price, $ per MWh Levelized crude oil price for zero GHG emissions price, 2021-2040, $/barreli Assumed refinery markups for gasoline displaced by synthetic gasoline, ¢/literj

2.86 5.72 5.4 90 85 20 22.8 7.16 55/45 10.2 4.4 7.0 0.1557 4 Varies with scalee 20f (1.0227*Poil)–45.03 – CO2 transport Cost LCOE for NGCCh 106.2 8.5

(a) These are fossil fuel prices projected for power generators in the Reliability First Corporation/West (RFCW) region of the U.S., which includes Indiana, Ohio, West Virginia, and parts of Pennsylvania and Virginia (see Figure B1 in the online supporting material). These are levelized over the period 2021-2040 (assuming a 7% discount rate), based on the Reference Scenario projection of the Energy Information Administration’s Annual Energy Outlook 201422 (see Figure B2 in the online supporting material). (b) For comparison, a detailed biomass logistics analysis for seventeen states in the central U.S. estimated the costs for annually delivering one million tonnes (dry basis) of biomass to a central conversion facility range from $4.2 to $6.9 per GJHHV (for corn stover biomass) and from $5.6 to $9.6 per GJHHV (for low-yield, low-planting density mixed prairie grasses).3 (c) AFUDC is based on a 3-year construction schedule with equal annual payments and a weighted average cost of capital of 7%/year. (d) This is the annualized capital charge rate (ACCR) calculated using the EPRI TAG methodology17 and applied to (TPC+AFUDC) to calculate annual capital charges. The ACCR accounts for the owner’s costs, debt/equity ratio, return on equity, interest on debt, and plant lifetimes included in this table, as well as for a 39.2% corporate income tax rate, a 2% property tax/insurance rate, and a MACRS depreciation schedule. (e) For designs incorporating CCS, CO2 is available at 150 bar at the plant gate. This CO2 is assumed to be transported 100 km to wells where it is injected into a DSF 2 km underground. Costs per tonne of CO2 stored are estimated using a model for CO2 transmission and storage developed by Ogden19,20 that takes into account various non-linear variations in costs with scale (tonnes per year), distance, and disposal well depth. (f) This estimate, based on a National Coal Council Study,21is for the construction and operation of a pipeline network that includes feeder pipelines that deliver CO2 from multiple coproduction plants in the Ohio River Valley to a trunk pipeline that carries CO2 to the Gulf Coast region, where distribution lines carry CO2to EOR sites. The total average CO2 transport distance is assumed to be 1,600 km. The pipeline system has the capacity to carry about 20,000 tonnes per day of CO2. (g) See Part D in the online supporting material for a derivation of this CO2 price function. (h) The electricity selling price is assumed to be the lesser of the LCOE for NGCC-V and NGCC-CCS for CO2 storage in a DSF when the natural gas price is $5.72/GJHHV (see Figure B4 in the online supporting material). (i) This is the crude oil price at a zero GHG emissions price levelized over the period 2021-2040 (7% discount rate), based on the Reference Scenario projection of the Energy Information Administration Annual Energy Outlook 201422 (see Figure B3 in the online supporting material). (j) This is the assumed value in the absence of a price on GHG emissions. It was estimated as the levelized difference between the US annual average refiner’s acquisition cost of imported crude oil and the US annual average wholesale price of gasoline for 2021-2040 (7% discount rate) based on the Reference Scenario projection of the Energy Information Administration Annual Energy Outlook 2014.22

Feedstock prices: The assumed coal and natural gas prices for energy conversion plants in the ORV region ($2.86/GJHHV and $5.72/GJHHV, respectively) are levelized prices for the period 2021-2040 based on the Reference Scenario of the Energy Information Administration’s Annual Energy Outlook 201422 [see Table 6, note (a)]. Value of products: Key determinants of energy conversion system profitability 10


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are the assumed values of system products (liquid fuels, electricity, and CO2). Liquid fuel products (gasoline and LPG) are assumed to be sold at the wholesale (refinery-gate) prices for the crude oil-derived products they would displace, including the costs of fuel-cycle-wide GHG emissions [(see Table 7, note (c) in the companion paper1] under different assumed costs per tonne of GHG emissions. The assumed base case crude oil price is $106 per barrel, the US average levelized imported crude oil price over the period 2021-2040 based on the Reference Scenario projection of AEO 2014.22,23 To reflect how, as a result of the shale gas revolution, natural gas has come to play a major role in shaping the US electricity market, it is assumed that the selling price for baseload electricity is the estimated levelized cost of electricity (LCOE) for a new baseload (85% capacity factor) natural gas combined cycle (NGCC) plant at the assumed natural gas price, including the cost of fuel-cycle-wide GHG emissions. At each GHG emissions price, the lower of the LCOE for a NGCC venting CO2 (NGCC-V) and the LCOE for a NGCC-CCS with captured CO2 stored in a deep saline formation (DSF) is used. NGCC-V provides a lower LCOE for GHG emissions prices less than $100/tCO2e. NGCC-CCS provides a lower LCOE above $100/tCO2e (see Figure B4 in the online supporting material). This approach to valuing electricity enables understanding the prospects that coproduction systems (such as the PB designs considered here) evaluated as power generators might be able to compete in electricity markets with NGCC plants, the dominant source anticipated for new electricity generation in the U.S. in coming decades. For CO2 EOR applications of captured CO2, the assumed plant-gate selling price of CO2 is given as a function of oil price in Table 6. The development of this price model is described in Part A of the online supporting material. The model aims to approximate the CO2 price when marginal CO2 supplies come from anthropogenic sources, and gives a market price that is considerably higher than CO2 prices in current EOR markets, where 11



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marginal CO2 supplies are from low-cost natural sources. For systems deployed in the ORV, it is assumed for the present analysis that the CO2 is transported about 1600 kilometers to large EOR markets in the Gulf region, so that the plant-gate price seen by CO2 providers in the ORV is the assumed market price at the wellhead minus the cost of transporting CO2 to the Gulf region. For DSF applications of captured CO2, the cost of CO2 transport and storage (including capital recovery) is treated as an operating cost. For these cases it is assumed that CO2 is transported 100 km for injection into a DSF 2 km underground (see Table 6).

4.2 Financial Performances at a Zero GHG Emissions Price Table 7 shows, for the ten systems described in Table 3, values for IRRE, LCOG, BEOP, and LCOE for CO2 stored in a DSF and for CO2 stored via EOR, along with estimated CO2 capture costs (CCC) and costs of GHG emissions avoided (CGEA). The latter two metrics are defined in Table 7 notes. A crude oil price of $106 per barrel and a GHG emissions price of zero are assumed for all results in Table 7. Consider first the four large (L) CTG options. For base case financial assumptions (Table 6), the IRRE for CTG-RC-V(L) is 21%/year. The CTG-PB-V(L) design, with its larger electricity output fraction, gives a lower return (15%/y) reflecting the higher value per unit of energy for liquid fuels than for electricity under the assumed conditions. When CCS with DSF CO2 storage is considered for these two plant designs, the IRREs fall 2 to 4 percentage points. However, when CO2 is instead sold for EOR, IRRE values are ~ 5 to 6 percentage points higher than for the CO2 venting cases—because the assumed plantgate CO2 selling price ($43.5/t) is much higher than the CO2 capture costs ($8/t to $13/t). (Capture costs are inherently low for synfuel systems because most CO2 is removed from syngas upstream of synthesis as an inherent part of the production process. For recycle system configurations the capture cost is thus just the cost of CO2 compression.) Thus 12


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even in the absence of a price on GHG emissions, capturing CO2 would be more profitable than venting it if EOR were an option.

Table 7. Financial findings when the crude oil price is $106/bbl and the GHG emissions price is $0/t CO2e Feedstock>>> Technology>>>

Coal Recycle Partial Bypass CTG-RC-CCS CTG-PB-CCS CTG-RCCTG-PBV(L) V(L) (L) (S) (L) (S)

Biomass Recycle BTG- BTG-RCRC-V CCS

Coal + Biomass Recycle PB CBTGCBTGRC-CCS PB-CCS

WITH STORAGE IN DSFs FOR CCS CASES Real internal rate of return on equity, %/yr 21.1 18.8 12.1 14.6 10.4 5.5

or Biomass with CO2 Capture

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