Nuclear Air Brayton Combined Cycle and Mark 1 Pebble Bed FluorideSalt-Cooled High-Temperature Reactor economic performance in a regulated electricity market

Understanding the financial performance of an engineered system is a key step to its commercialization. In this study, the economic performance of the Mk1 PB-FHR using a nuclear air combined cycle to produce base load nuclear power, and highly efficient peaking power with gas co-firing, was estimated for a regulated electricity market structure.

Nuclear Engineering and Design 323 (2017) 474–484 Contents lists available at ScienceDirect Nuclear Engineering and Design journal homepage: www.elsevier.com/locate/nucengdes Nuclear Air Brayton Combined Cycle and Mark Pebble Bed FluorideSalt-Cooled High-Temperature Reactor economic performance in a regulated electricity market Charalampos Andreades a,⇑, Per Peterson b a b University of California, Berkeley, 4118 Etcheverry Hall, Berkeley, CA 94720, United States University of California, Berkeley, 4167 Etcheverry Hall, Berkeley, CA 94720, United States h i g h l i g h t s  Mk1 FHR performs favorably compared to both utility and IPP built NGCCs  Mk1 FHR main performance drivers: electricity price, NG price, and the discount rate  Mk1 is much more attractive in markets where NG prices are high compared to NGCCs a r t i c l e i n f o Article history: Received 28 April 2016 Accepted 11 December 2016 Available online 29 December 2016 Keywords: Nuclear economics Nuclear Air Brayton Combined Cycle Flexible nuclear FHR Regulated electricity market NGCC a b s t r a c t Understanding the financial performance of an engineered system is a key step to its commercialization In this study, the economic performance of the Mk1 PB-FHR using a nuclear air combined cycle to produce base load nuclear power, and highly efficient peaking power with gas co-firing, was estimated for a regulated electricity market structure Initially, a survey of major U.S nuclear utility holding companies’ financials was performed to estimate a credible range of input parameters In combination with the main cost parameters of the Mk1 estimated in a companion paper, a base case analysis was performed, demonstrating the economic attractiveness of the Mk1 A sensitivity study demonstrated that the main metrics of concern were electricity price, natural gas price, and the discount rate These all pointed to possible ways to further reduce the Mk1’s investment risk, such as long term fuel contracts and improved construction management, in order to further increase the attractiveness of Mk1 deployment Finally, a comparison between the Mk1 and two different natural gas combined cycle (NGCC) plants was made The Mk1 performance lies in between a utility built and an independent power producer built NGCC The Mk1 becomes a much more attractive investment than conventional NGCCs in markets where natural gas prices are high Ó 2016 The Authors Published by Elsevier B.V This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/) Introduction One of the most important aspects of designing a new commercial technology is understanding its revenues and long term economic viability There are certain instances where an investor or business is willing to accept a loss on a specific product (e.g loss leaders, technical displays), but in general the aim is to create value and generate profit in the long term The profit of a product depends on two specific components, namely cost and revenue, the difference between the two being the profit/loss This paper assesses revenues for Mark-1 Pebble Bed, Fluoride Salt Cooled ⇑ Corresponding author E-mail addresses: charalampos@berkeley.edu (C Andreades), peterson@nuc berkeley.edu (P Peterson) Reactors (Mk1 PB-FHRs) coupled to nuclear air combined cycle (NACC) power conversion (Andreades et al., 2014a, 2016) Narrowing our focus to the electricity sector, the main market of the FHR and NACC (Mk1), it is important to understand the fundamentals of this sector’s operation and the ways in which it has evolved over its lifetime Here we focus on the U.S electricity sector, although the conclusions can be generalized to other countries During the nascent years of the electricity industry at the turn of the 20th century, U.S electric utilities operated in a fiercely competitive environment, competing primarily in price with gas lighting and self-generation There was discussion of appropriate rate structures, such as time-of-use and block pricing, however the need for stability and investor attractiveness pushed industry pioneers, such as Samuel Insull, to promote demand charges and government regulation of utilities as protected monopolies This http://dx.doi.org/10.1016/j.nucengdes.2016.12.013 0029-5493/Ó 2016 The Authors Published by Elsevier B.V This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/) 475 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 structure, in which utilities are guaranteed cost recovery at a regulated rate – cost plus x – allowed them to be shielded from competition, take advantage of economies of scale, and expand Thus was the status quo for the next seven decades Around the 1990s, an interest in electricity market liberalization and deregulation took shape due to success in deregulating other industries, such as telecommunications, trucking and commercial aviation, and a resurgence in competitive pricing in electricity markets was in vogue This shifted electricity pricing away from average cost (AC) based to marginal cost (MC) based The changing nature of modern electricity markets was and remains compounded by the large scale introduction of intermittent renewable energy sources Flexible and quickly ramping capacity is needed to maintain grid stability, since traditional fossil fuel sources have physical ramp constraints and battery reserves are not well suited to utility scale capacities and demands The Mark (Mk1) NACC is a novel power conversion system based on a modified General Electric (GE) 7FB natural gas (NG) turbine The turbine is retrofitted to accept external heating from a heat source in the range of 600–700 °C, in this application an FHR, while also maintaining its ability to combust NG or other combustible fuel When coupled to the 232 MWt Mk1 PB-FHR, NACC provides 100 MWe of baseload electricity with a 42% efficiency, and a boosted power output of 240MWe under NG cofiring with a NG-to-electricity conversion efficiency of 66%, well above current state of the art NGCCs A full technical description of the NACC can be found in Andreades et al (2014b, 2014c) The NACC, with its ability to peak on-demand and provide flexible capacity make it an attractive and well suited candidate for the current and future low carbon electricity markets, with high penetration of intermittent renewable energy sources To assess the Mk1 economic allure vis-à-vis its operating and physical benefits, this study aimed at initially quantifying the Mk1’s revenue under certain hypotheses and constraints in a regulated electricity market A description of the methodology used to perform the revenue estimation is given, followed by a summary of the relevant operating and cost inputs from a companion paper (Andreades, 2015) The revenue and profitability results are then presented, followed by discussion of the Mk1 results and a comparison made to its main competitors Methodology In order to create a regulated market revenue model, an industry standard commercial software package, THERMOFLEX/PEACEÒ, was used (Thermoflow) Once a baseline NACC configuration was established based on the Mk1 PB-FHR commercial point design (Andreades et al., 2014a, 2016), and as detailed in Andreades et al (2014b, 2014c), relevant cost estimates were given A market survey of major U.S nuclear utilities was performed to obtain a plausible range of financing and electricity market data A base case was run with average values to establish a baseline reference, followed by a sensitivity study on each parameter separately Two additional cases were run, an ‘optimistic’ and a ‘pessimistic’ one, in order to bound the results Finally, a comparison was carried out between the NACC and a NGCC power plant based on the GE 7FB of similar power output, in order to establish how well the proposed design performed against its assumed main competitor All currency units are set to 2014 USD Input data The first step to performing a profitability analysis is assessing costs of the system in question, as given by Eq (1) ProfitLossị ẳ Rev enue Cost 1ị The relevant costs for the Mk1 were estimated in a companion paper and a summarized version is presented in Table The next step is to appropriately identify and estimate financing numbers and structures that fit such a project and as required for input by THERMOFLEX/PEACEÒ’s, ‘Economic and regional costs’ tab Some basic operating assumptions were made The Mk1 is anticipated to have a 60 year lifespan; however, THERMOFLEX/ PEACEÒ is limited to a 40 year assessment In lieu, one can simply extrapolate the 40 year results to a 60 year lifetime For the purposes of this study and for added conservatism a 40 year lifetime was assumed The first year of plant operation was assumed to be 2021, following an assumed 5-year construction period, for a 12-unit plant THERMOFLEX/PEACEÒ does not account for staggered construction/operation which would provide added realism and thus results are conservative as initial revenue is generated at a later date, rather than as individual units come online Such a modeling approach can be considered as a counterbalance to potential construction delays The NACC is anticipated to operate in a load-following mode due to its flexible capacity provided by its ability to produce peaking power by injecting NG or other liquid and gaseous fuels when quick ramping is needed by the electricity grid For this study it was assumed that the 12-unit Mk1 NACC station ran at either 1200 MWe nuclear capacity or at a full 2832 MWe co-fired capacity The capacity factor of the plant was assumed to be the 10-year nuclear industry average of 90%, with range between 80% and 95% (Nuclear Energy Institute, 2014) The Mk1’s online refueling capability might enable a higher capacity factor, but current industry average was used for the base case instead for conservatism Typically, nuclear installation depreciation terms are set at 15 years (Department of Commerce Bureau of Economic Analysis, 2004) The Nuclear Energy Institute is proposing lowering this term to years, as it affects a plant owner’s tax expense (Fertel, 2004) A shorter depreciation term allows for a larger accounting expense each year and therefore reduced taxes in earlier years A 30 year high was used for the depreciation range Debt terms for nuclear facilities are typically set at 15 years (OECD-NEA, 2009; IAEA, 1993) Longer terms allow for longer periods to repay and service the debt and are therefore more attractive A 30 year maturity date was used on the high side, while the 15 year term was used as the base and lower range The following three financing components, namely debt percentage, debt interest rate, and discount rate, are usually highly project specific and in many cases confidential to the parties Table Overview of Mk1 costs Description Capital construction costs Preconstruction costs Total direct cost Indirect cost Total contingency Total capital investment Specific capital investment (nuclear) Specific capital investment (CF) Production Costs Total annual O&M Fuel cost (annual) Decommissioning cost (annual) Overall production cost Marginal production cost Single unit 12 Unit 80,484,991 214,846,727 142,462,635 71,461,872 509,256,225 5093 263,622,515 2,578,160,727 1,709,551,614 857,542,468 5,408,877,325 4507 $ $ $ $ $ $/kW 2133 1870 $/kW 62,086,683 7,750,516 1,165,920 71,003,119 81.05 311,631,799 93,006,192 13,991,046 418,629,037 39.82 $ $ $ $ $/ MW h Bolded numbers are the key comparison metrics used to compare electricity generation technologies 476 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 involved Additionally, no major nuclear construction of new plants beyond Vogtle in Georgia and VC Summer in South Carolina, has happened in the United States the past two decades so reliable or relevant numbers are in short supply Although Watts-Bar was completed in 2015 with an approved cost of $4.7bn, it does not provide relevant information since its construction began in 1972 with a 22 year hiatus between 1985 and 2007 (World Nuclear Association, 2016) The approach taken to estimate these numbers was to study and average the financial statements and fillings of the major nuclear utilities, as shown in Table In order to use these numbers correctly, a corporate financing structure rather than a project financing structure was assumed This assumption is particularly appropriate for small modular reactor stations like the Mk1 PB-FHR station, because the capital placed at risk before initial electricity is delivered to the grid is substantially smaller than for conventional large reactor plants Corporate financing usually implies gentler financing terms and higher leverage since lenders have a recourse on the utility’s balance sheet, not just the project itself Table Major U.S nuclear utility holding companies Name NYSE Number of plants Exelon Entergy Duke NextERA TVA Dominion First Energy Southern XCEL SCANA EXC ETR DUK NEE TVA D FE SO XEL SCG 15 3 3 Assets ẳ Liability ỵ Equity 2ị Next, debt interest rate and tax rate were obtained from nuclear utility 10k filings Finally, the discount rate was assumed to be the rate of return to equity investors To approximate the discount rate, the weighted average cost of capital (WACC), as defined in Eq (3), was obtained from financial analysis companies (GuruFocus.com LLC, 2015) and modified to yield our estimate WACC ¼ Equity Liability Cost equity ỵ Cost liability À TaxrateÞ Assets Assets ð3Þ The overall results for all major U.S nuclear utility holding companies are presented in Table The three remaining inputs that were estimated were the price of carbon tax and the prices of electricity and natural gas The price of carbon was assumed to vary between zero, to reflect the current U.S status quo, and 120 $/tCO2e as a ceiling with a base of 40 $/tCO2e (Interagency Working Group on Social Cost of Carbon, 2013) The natural gas price range was obtained from the historical range of prices from the past 15 years (Chicago Mercentile Exchange, 2015) An electricity price range was obtained from the 2015 Annual Energy Outlook (U.S Energy Information Administration, 2014) The input parameters are summarized in Table A final note is that escalation rates for costs were assumed to be constant and equivalent to inflation Results 49a Total Debt percentage was estimated from each company’s most recent public annual balance sheet from the basic accounting Eq (2) a Number of plants is different to number of reactors Each nuclear plant can have one or more reactors on site The results for the base case assumptions are presented in Table 5, for both baseload and co-fired operation What is apparent from the results in Table is that under constant full capacity operation the Mk1 seems to be an attractive Table Summary of financial data for major U.S nuclear utility holding companies a Name NYSE Total assets [bn $] Total equity [bn $] Equity [%] Debt [%] Tax rate [%] WACC [%] Cost of debt [%] ROR [%] Exelon Entergy Duke NextERA TVA Dominion First Energy Southern XCEL SCANA Average EXC ETR DUK NEE TVAa D FE SO XEL SCG 86.8 46.5 120.7 74.9 45.6 54.3 52.2 70.9 37.0 16.9 60.6 22.8 10.1 40.9 19.9 6.10 11.60 12.40 20.90 10.20 5.00 16.0 26.27 21.72 33.89 26.57 13.38 21.36 23.75 29.48 27.57 29.59 25.40 73.73 78.28 66.11 73.43 86.62 78.64 76.25 70.52 72.43 70.41 74.60 32.22 30.83 36.27 32.02 4.50 4.57 4.08 5.18 7.58 9.75 7.22 11.25 29.21 4.825 32.83 33.85 31.84 29.30 4.56 4.32 3.46 4.34 4.49 4.40 5.02 4.53 3.88 4.39 7.25 4.90 4.50 3.46 4.09 5.02 4.70 8.58 4.44 6.18 8.63 7.03 7.90 Not a publicaly traded company, Data from 2014 10K filings Table Financing and market input parameters Capacity factor Depreciation Debt term Debt% Debt interest Discount rate CO2 price Natural gas price Electricity price Base Low High Unit 90 15 15 74.6 4.7 7.9 40 4.45 (4.22) 0.103 80 – 66.1 3.5 4.4 2.23 (2.11) 0.062 95 30 30 86.6 7.3 11.2 120 15.6 (14.8) 0.132 % yrs yrs % % % $/tCO2e $/MMBtu ($/GJ) $/kW h 477 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 investment, with a net present value (NPV) of $18.8bn, a levelized cost of electricity (LCOE) of $0.045/kW h and a breakeven price of NG of $21.6/GJ (22.8 $/MMBtu), i.e the price of NG up until which the plant remains profitable On the other hand, under base load operation the Mk1 is an unprofitable investment and is thus discounted for the rest of this analysis A note to make is that the Mk1 will run in its peaking mode only when prices of electricity are above the price where electricity revenues exceed natural gas costs, and it is quite unlikely that it will run at full capacity at all times The results for the co-fired deviating cases are presented graphically for compactness in Figs 1–5 The effect of each input variable on selected major dependent variables is illustrated Fig demonstrates that NPV is most sensitive to discount rate, electricity price, and NG price Electricity price affects the revenue cash flow of the Mk1, with reduced prices resulting in reduced revenue NG prices affect the cost stream of the Mk1, with increased prices reducing profit margin The results vary dramatically as parameters vary Other input parameters have much smaller, yet not negligible effects A counterintuitive result is the relatively small effect of an imposed carbon tax (12% range in NPV from base case) compared to the dominating parameters The high conversion efficiency of NG to electricity allows the NACC to burn less NG and thus reduce its carbon tax cost and thus mitigate a more pronounced impact; however, if considered separately, an approximately 10% swing in NPV is still significant Table Mk1 base case (40 $/tCO2e) economic performance under peaking and baseload operation Plant capacity Annual electricity exported Annual heat exported Annual fuel imported (NG) Annual water IMPORTED Annual CO2 emission Total investment Specific investment Initial equity Cumulative net cash flow Internal rate of Return on Investment (ROI) Internal rate of Return on Equity (ROE) Years for payback of equity Net present value Levelised cost of electricity Break-even NG LHV price @ input electricity price Co-fired Baseload Units 2892 21,753 72,067 7570 1344 5,437,727,000 1971 1,381,183,000 109,520,200,000 25.037 63.769 1.68 18,805,650,000 0.0454 22.8 (21.6) 1200 9076 0 3825 5,148,817,000 4473 1,307,800,000 9,763,285,000 5.16 6.02 23.16 À1,285,687,000 0.12 2.68 (2.53) MW 10^6 kW h TJ TJ LHV 10^6 L ktonne $ $/kW $ $ % % years $ $/kW h $/MMBtu ($/GJ) Fig Net present value of project 478 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 Fig demonstrates that return on investment (ROI) is most sensitive to NG price, electricity price, and capacity factor for co-fired operation This makes sense since electricity price and capacity fac- tor determine the revenue stream, while NG price affects the cost stream and thus the time and amount needed to pay back investors in a timely manner, in turn affecting return on investment Fig Return on investment of project Fig Levelized cost of electricity of project C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 Fig illustrates that the LCOE is most sensitive to NG price, discount rate, and to a lesser extent carbon price A carbon tax is a price adder by definition Higher discount rate increases LCOE by 479 increasing returns demanded by investors NG price is directly linked to the cost of producing electricity It is imperative to note that only high NG prices push LCOE to exceed 0.05$/kW h, but on Fig Years to payback equity Fig Break-even natural gas price at input electricity price 480 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 the other hand can lower it down below 0.04$/kW h All other parameters keep LCOE within that range As NG price increases it keeps imposing a larger production cost, up to a certain point where it then makes the plant unprofitable (i.e the break-even price of NG) If electricity market feedback is considered, the BL capacity provided by nuclear heat will have a larger profit margin as NG price increases, since the price will be set by competing NGCCs or GTs, as the NACC’s co-fired capacity has a much higher thermal efficiency Fig shows that NG price and electricity price affect years of payback of equity by shifting the profit margin on cost and revenue for production costs All other variables have negligible effects and a range of payback on co-fired operation between a year and two years Fig depicts the effects of discount rate, electricity price, and capacity factor on the break-even NG price at input electricity price As discount rate increases, the NG price threshold is lowered, thus becoming more restrictive As electricity price and capacity factor increase, so does the NG threshold, meaning that the cofired Mk1 can remain profitable even at higher NG prices, up to $31/GJ The bounding cases, where all input parameters were set to either optimal or worst case, are presented in Table What becomes immediately clear is that the range of results is too broad Table Bounding case financial results for Mk1 Annual electricity exported Annual fuel imported (NG) Annual CO2 emission Total investment Specific investment Initial equity Cumulative net cash flow Internal rate of Return on Investment (ROI) Internal rate of Return on Equity (ROE) Years for payback of equity NPV LCOE Break-even fuel LHV price @ input electricity price Optimistic Base Pessimistic Units 22,990 76,162 8000 5,437,727,000 1970.8 728,655,500 180,443,800,000 39.433 242.372 0.4203 64,084,140,000 0.0302 32.84 21,753 72,067 7570 5,437,727,000 1970.8 1,381,183,000 109,520,200,000 25.037 63.769 1.68 18,805,650,000 0.0454 21.6 19,865 135,557 6443 5,437,727,000 1970.8 1,843,389,000 À20,482,060,000 0 N/A À6,094,365,000 0.0948 4.878 10^6 kW h TJ LHV ktonne USD USD/kW USD USD % % years USD USD/kW h USD/GJ Fig GE 7FB gas turbine and HRSG THERMOFLEX/PEACEÒ schematic C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 481 Fig Three pressure steam turbine for combined cycle THERMOFLEX/PEACEÒ schematic Table NGCC operation and financial parameters Lead time Project Life Depreciation Contingency Debt term Debt percentage Debt interest rate Tax rate Discount rate Overnight cost Total overnight cost Variable O&M Fixed O&M Capacity factor IPP Utility 20 15 70 8.75 30 20 977 1055 3.32 15.61 87 30 15 30 50 7.75 30 10 977 1055 3.32 15.61 87 years years years % years % % % % $/kW $/MWh $/kW/yr % to make any definitive conclusions, other than that both cases are unlikely Discussion What is distilled from the results in the previous section is that three parameters recurrently affect the economic performance of the Mk1, namely NG and electricity prices, and discount rate Additionally, these parameters are mainly market and not operation (capacity factor) driven Although other variables should also be kept in mind, they not have as pronounced an effect as the aforementioned This leads us to concentrate on understanding how one might try to positively affect each parameter, if at all possible The price of NG or combustible fuel is to a large extent external and can only be set advantageously through long term delivery contracts, rather than being purchased on the volatile spot market In many international markets, natural gas prices are sufficiently high that the Mk1 economics will be attractive Electricity price to a certain extent can be affected by bringing on or taking off the Mk1’s flexible capacity, when the opportunity cost might warrant it However, there needs to be a strong consideration to avoid applying market power to manipulate spot prices of electricity, since a full Mk1 plant has a significant peaking reserve capacity The amount of remuneration demanded by equity investors, namely through the discount rate, signals the risk perception of the individual project in tandem with that of the industry as a whole What the Mk1 needs to accomplish to become attractive is to convince investors of a superior risk profile vis-à-vis its competitors Steady and added revenues from its flexible capacity, reduced capital investment due to stacked construction and operation, economies of series due to factory production should all help to reduce the risk profile of the Mk1 Furthermore, steady, manageable, and predictable costs should also be a priority On an industry front, nuclear needs to be perceived as investor friendly, through streamlined regulation, improved construction and supply chain management A deeper elaboration on these issues is beyond the scope of this study 482 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 5.1 Comparison to conventional NGCC In order to obtain a better perspective of the previous economic results of the Mk1, a comparison between it and its competitors was deemed necessary The most obvious candidate to compare the Mk1 to was an unmodified NGCC based on the GE 7FB This comparison essentially shows whether the Mk1’s more efficient burning of NG during peak operation compared to a conventional NGCC could make up for the added capital cost of the nuclear component of the system A THERMOFLEX/PEACEÒ model using a five  1GE 7FB and steam turbine configuration was used to match the power output of the Mk1 at 2800 MWe, as shown in Figs and The main input parameters for the NGCC were selected from industry averages of advanced NGCC from the Energy Information Administration’s 2015 Annual Energy Outlook (U.S Energy Information Administration, 2015) and Alstom (Bozzuto, 2006) and are presented in Table A utility and independent power producer (IPP) financing structure were used to compare the two different scenarios of constructing NGCCs The base case results of the co-fired Mk1 were compared to those of the NGCC and are presented in Table A sensitivity study was performed on the price of carbon, electricity price, and NG price and compared to the Mk1 graphically in Figs 8–10, with all metrics being normalized to the values of the Mk1 base case Under base case assumptions with a 40 $/tCO2e carbon price, the co-fired Mk1 compared favorably to both an IPP NGCC installation and a utility built NGCC The Mk1 managed a NPV of 1$8.8bn as compared to $4.4bn of an IPP NGCC and $12.7bn of a utility NGCC Return on investment was nearly double for the NGCCs due to the smaller initial capital required compared to the Mk1 The LCOE of the Mk1 was lower than an IPP NGCC and slightly higher than a utility owned NGCC The break-even price of NG, i.e the price of NG up until which the plant remains profitable, was significantly higher than both NGCCs, demonstrating that the Mk1 would perform very favorably in markets with high NG prices, such as Europe and Japan The main difference between the IPP and utility NGCCs is the longer running period of the utility plant, which led to more favorable financial results This should also be considered when looking at the results for the Mk1, since Table Financial performance of competitors under base case assumptions Annual electricity exported Annual fuel imported (NG) Annual CO2 emission Total investment Specific investment initial equity Cumulative net cash flow Internal rate of Return on Investment (ROI) Years for payback of equity NPV LCOE Break-even fuel LHV price @ input electricity price Mk1 IPP NGCC Utility NGCC Units 21,753 72,067 4033 5,437,727,000 1971 1,381,183,000 109,520,200,000 25.04 1.68 18,805,650,000 0.045 21.60 (22.81) 21,365 135,483 7684 2,959,311,000 1055 887,793,300 30,452,090,000 40.57 1.13 4,351,637,000 0.055 11.81 (12.47) 21,365 135,483 7684 2,959,312,000 1055 1,479,656,000 61,093,990,000 40.66 1.49 12,741,680,000 0.043 13.63 (14.39) 10^6 kW h TJ LHV ktonne $ $/kW $ $ % years $ $/kW h $/GJ ($/MMBtu) Fig Normalized financial parameters under electricity price variation 483 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 only two thirds of its operational lifetime were accounted for in this study An additional fact to consider is that the Mk1 managed to produce more power with a smaller carbon footprint compared to a NGCC of a similar size, due to its improved power conversion efficiency and producing part of the power by non-emitting nuclear fuel Changing electricity price can have a dramatic effect on the performance of plants as pointed out in the previous section As shown in Fig 8, as electricity price increased all plants performed better All results were normalized to the Mk1’s base case results The IPP NGCC could not compete with the co-fired Mk1 on NPV even under high electricity prices The utility owned NGCC also struggles to compete with Mk1 as electricity prices vary The same basic comparative outcomes as the base case still applied under the electricity sensitivity study Fig Normalized financial parameters under NG price variation Carbon tax variaƟon 1.8 1.6 Normalized Value 1.4 1.2 0.8 0.6 0.4 0.2 Mk1 IPP UƟlity NGCC NGCC NPV Mk1 IPP UƟlity NGCC NGCC LCOE $120/tCO2 Mk1 IPP UƟlity NGCC NGCC ROI $40/tCO2 $0/tCO2 Fig 10 Normalized financial parameters under carbon tax variation Mk1 IPP UƟlity NGCC NGCC NG Price B.E 484 C Andreades, P Peterson / Nuclear Engineering and Design 323 (2017) 474–484 Where a dramatic shift in comparative results was seen was under NG price variation, the main fuel input and running cost for the two NGCC plants, as depicted in Fig As NG prices were increased, performance of the NGCCs fell significantly in all financial metrics LCOE nearly doubled for both NGCC plants, NPV and ROI became negative, i.e making them a poor investment, and the NG breakeven price fell quite significantly for both NGCCs The co-fired Mk1 managed to maintain positive financials under all scenarios, pointing out that in a high NG price environment, e.g Japan or parts of Europe, it would be the better choice as pointed out in a prior section Additionally, what is apparent from Fig 10 is that a carbon tax did not have a tremendous impact on financial results for the three plants, and the comparative results remained the same as in the co-fired base case A final note to make in this comparative study is that a more accurate comparison for the Mk1 would have been between a combination of a conventional nuclear plant and a NGCC, since the Mk1 is a hybrid plant that performs the functions delivered by these plants separately However, due to the performance improvement of the Mk1 compared to a standalone NGCC, the combined plant comparison becomes redundant, since it also performs better than a conventional nuclear power plant Conclusion Understanding the financial performance of an engineered system is a key step to its commercialization In this study, the economic performance of the Mk1 PB-FHR with NACC was estimated under a regulated electricity market structure Initially, a survey of major nuclear utility holding companies’ financials was performed to estimate a credible range of input parameters In combination with the main cost parameters of the Mk1 estimated in a companion paper (Andreades et al., 2014a), a base case analysis was performed, demonstrating the economic attractiveness of the Mk1 A sensitivity study demonstrated that the main metrics of concern were electricity price, natural gas price, and the discount rate These all pointed to possible ways to mitigate the co-fired Mk1’s investment risk, such as long term natural gas (or other combustible) fuel contracts and improved construction management, in order to make it a more attractive venture Finally, a comparison between the Mk1 and two different NGCCs was made The Mk1 performs favorably compared to both a utility built and an IPP built NGCC, outperforming them in several key metrics The Mk1 becomes a much more attractive investment in markets where natural gas prices are high compared to the NGCCs A caveat to mention in the results of this study is that a 40 year lifetime was modeled rather than the anticipated 60 year lifetime of the Mk1, thus understating the Mk1’s economic perfor- mance vis-à-vis the NGCCs Future study might be merited in the performance of the Mk1 in a deregulated electricity market as described in the introduction and a more in-depth look at risk mitigation strategies for attracting investment Acknowledgments This research was performed using funding received from the U S Department of Energy Office of Nuclear Energy’s Nuclear Energy University Program References Andreades, Charalampos, 2015 Nuclear Air-Brayton Combined Cycle Power Conversion Design, Physical Performance Estimation and Economic Assessment (Ph.D Thesis) University of California, Berkeley Andreades, C et al., 2014a Technical Description of the ‘Mark 1’ Pebble-Bed Fluoride-Salt-Cooled High-Temperature Reactor (PB-FHR) Power Plant Report UCBTH-14-002 Department of Nuclear Engineering, U.C Berkeley Andreades, C., Scarlat, R., Dempsey, L., Peterson, P., 2014b Reheat Air-Brayton Combined Cycle (RACC) power conversion design and performance under nominal ambient conditions J Eng Gas Turbines Power 136 (7) Andreades, C., Dempsey, L., Peterson, P., 2014c Reheat Air-Brayton Combined Cycle (RACC) power conversion design and performance under off-nominal conditions J Eng Gas Turbines Power 136 (6) Andreades, C et al., 2016 Design summary of the Mark-I Pebble Bed, fluorde-saltcooled, high-temperature reactor commercial power plant Nucl Technol 195 (3), 223–238 Bozzuto, C., 2006 Power Plant Economics Alstom, Washington, DC Chicago Mercentile Exchange, 2015 Henry Hub Natural Gas Settlement Prices,‘‘ CME Group Inc., 2015 (Accessed 25 September 2015) Fertel, M.S., 2004 Testimony for the Record, U.S Senate Committee Energy and Natural 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(Andreades et al., 2 014 a, 2 016 ), and as detailed in Andreades et al (2 014 b, 2 014 c), relevant cost estimates were given A market survey of major U.S nuclear utilities was performed to obtain a. .. a plausible range of financing and electricity market data A base case was run with average values to establish a baseline reference, followed by a sensitivity study on each parameter separately... considered separately, an approximately 10 % swing in NPV is still significant Table Mk1 base case (40 $/tCO2e) economic performance under peaking and baseload operation Plant capacity Annual electricity