Costs Of Generating Electrical Energy 1.0 Overview

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1.0Costs of Generating Electrical EnergyOverviewThe short-run costs of electrical energy generationcan be divided into two broad areas: fixed andvariable costs. These costs are illustrated in Fig. 1below.Fixed costsInterest on bondsReturn to stockholdersProperty taxesInsuranceDepreciationFixed O&MVariable costsFuel costsVariable O&MFig. 1Typical values of these costs are given in thefollowing Table 1 [1]. Some notes of interest follow: The “overnight cost” is the cost of constructingthe plant, in /kW, if the plant could beconstructed in a single day. The “variable O&M” is in mills/kWhr (a mill is0.1 ).These values represent mainly maintenancecosts. They do not include fuel costs. Fuel costs are computed through the heat rate.We will discuss this calculation in depth. The heat rate values given are average values.1

Table 12

We focus on operating costs in these notes. Our goalis to characterize the relation between the cost andthe amount of electric energy out of the power plant.2.0FuelsFuel costs dominate the operating costs necessary toproduce electrical energy (MW) from the plant,sometimes called production costs. We begin withnuclear. Enriched uranium (3.5% U-235) in a lightwater reactor has an energy content of 960MWhr/kg[2], or multiplying by 3.41 MBTU/MWhr, we get3274MBTU/kg. The total cost of bringing uranium tothe fuel rods of a nuclear power plant, consideringmining, transportation, conversion1, enrichment, andfabrication, has been estimated to be 2770/kg [3].Therefore, the cost per MBTU of nuclear fuel isabout 2770/kg / 3274MBTU/kg 0.85/MBTU2.To give some idea of the difference between costsof different fossil fuels, some typical average costs offuel are given in the Table 2 for coal, petroleum, andnatural gas. One should note in particular The difference between lowest and highest averageprice over this 20-year period for coal, petroleum,and natural gas are by factors of 1.72, 7.27, and“Conversion” here does not mean to electric energy. Rather, uranium concentrates are purified andconverted to uranium hexafluoride (UF6) or feed (F), the feed for uranium enrichment plants. See EPRIReport 1020659, “Parametric Study of Front-End Nuclear Fuel Cycle Costs Using Reprocessed Uranium,”January 2010.2This is a very low fuel cost! However, it is balanced by a relatively high investment (overnight) cost – seeTable 1.13

4.60, respectively, so coal has had more stableprice variability than petroleum and natural gas.During 2011, coal is 2.40/MBTU, petroleum 20.11/MBTU, and natural gas 4.71/MBTU, socoal is clearly a more economically attractive fuelfor producing electricity (gas may begin to lookmuch better if a CO2 cap-n-trade system is begun).Table 2: Receipts, Average Cost, and Quality of Fossil Fuels for theElectric Power Industry, 1991 through 2013, obtained from [4]Table 4.5. Receipts, Average Cost, and Quality of Fossil Fuels for the Electric Power Industry, 1992 through2012All FossilCoal [1]Petroleum [2]Natural Gas [3]FuelsAverage CostAverage CostAvg.Avg.Average AverageYear Receipts ( Receipts ( onper (dollars/ Percentper (dollars/ Percent(cents/ 10 (cents/ 10BTU)BTU)10 6ton) by Weight10 6 barrel) by Weight BTUs)6 Btu)6 90.9721,735,1011.69406,8698.6854.350.7321,152,358 0.9621,280,2582.0741.14375,684 .2143.74330,043 .2744.64275,058 .3946.65216,752 .3846.09116,937 2.3545.50123,567 20.59125.060.468,677,5444.333.1020131.30[1] Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.[2] Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil),jet fuel, kerosene, petroleum coke (converted to liquid petroleum, see Technical Notes for conversion methodology), and waste oil.[3] Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. Natural gas values for2001 forward do not include blast furnace gas or other gas.[4] Beginning in 2002, data from the Form EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report" for independentpower producers and combined heat and power producers are included in this data dissemination. Prior to 2002, these data were notcollected; the data for 2001 and previous years include only data collected from electric utilities via the FERC Form 423.[5] For 2003 only, estimates were developed for missing or incomplete data from some facilities reporting on the FERC Form 423.This was not done for earlier years. Therefore, 2003 data cannot be directly compared to previous years' data. Additional information4

regarding the estimation procedures that were used is provided in the Technical Notes.R Revised.Notes: Totals may not equal sum of components because of independent rounding. Receipts data for regulated utilities are compiledby EIA from data collected by the Federal Energy Regulatory Commission (FERC) on the FERC Form 423. These data are collected byFERC for regulatory rather than statistical and publication purposes. The FERC Form 423 data published by EIA have been reviewedfor consistency between volumes and prices and for their consistency over time. Nonutility data include fuel delivered to electricgenerating plants with a total fossil-fueled nameplate generating capacity of 50 or more megawatts; utility data include fuel delivered toplants whose total fossil-fueled steam turbine electric generating capacity and/or combined-cycle (gas turbine with associated steamturbine) generating capacity is 50 or more megawatts. Mcf thousand cubic feet. Monetary values are expressed in nominal terms.Sources: Energy Information Administration, Form EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report;" FederalEnergy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."Check http://www.eia.gov/electricity/monthly/more data on this.forDespite the high price of natural gas as a fuel relativeto coal, the 2000-2009 time period saw newcombined cycle gas-fired plants far outpace newcoal-fired plants, with gas accounting for over 85%of new capacity in this time period [5] (of theremaining, 14% was wind). The reason for this hasbeen that gas-fired combined cycle plants have lowcapital costs, high fuel efficiency, short constructionlead times, and low emissions.This trend has been ongoing for some time, asobserved in Fig. 2 [6], where the sharply rising curvefrom 1990 onwards is gas consumption for electric.5

Fig. 2: US Natural Gas ConsumptionNatural gas prices have declined significantly duringthe past several years, mainly due to the increase ofsupply from shale gas, as indicated in Fig. 3 and Fig.4 [6], and so it is likely natural gas will remain acentral player for some years to come.Fig. 36

Fig. 4Planned capacity will continue to emphasize gas andwind plants, as indicated in Fig. 5 below [7]. Thisfigure reflects predicted cumulative capacity in eachyear. Careful inspection of the figure indicates mostof the 100GW growth occurs in natural gas andrenewable resources. The report indicates that mostof the renewable resources is wind.Fig. 53.0 Fuels continued – transportation & emissions7

The ways of moving bulk quantities of energy in thenation are via rail & barge (for coal), gas pipeline, &electric transmission, illustrated in Fig. 6.CoalSubsystemGasSubsystemElectricSubsystemFig. 6An important influence in the way fuel is moved isthe restriction on sulfur dioxide (SO2).Coal is classified into four ranks: lignite (Texas, N.Dakota), sub-bituminous (Wyoming), bituminous(central Appalachian), anthracite (Penn), reflectingthe progressive increase in age, carbon content, andheating value per unit of weight.8

Table 3 below illustrates differences among coalthroughout the country, in terms of capacity, heatvalue, sulfur content, and minemouth price.Appalachian coal is primarily bituminous, mainlymined underground, whereas Wyoming coal issubbituminous, mainly mined from the surface.Table 3Although the above table is a little dated, its generalmessage is still relevant, as confirmed by the figuresbelow [8], where we see western coal productionclimbing, due to facts that (a) its /BTU is muchmore attractive, and (b) it has low sulfur content.9

As a result, a great deal of coal is transported fromWyoming eastward, as illustrated in Fig. 7.The Coal Dog .Powder River Basin CoalMovementNWPPPRBMAPPECARMAINAZNM23Fig. 7We do not have a national CO2 cap and trade marketyet, but there is a regional one called the RegionalGreenhouse Gas Initiative (RGGI) – seehttp://www.rggi.org/home. Most recently, the EPAClean Power Plan has taken precedent. We willdiscuss this more later.10

4.0 CO2 Emissions - overviewThere is increased acceptance worldwide that globalwarming is caused by emission of greenhouse gasses intothe atmosphere. These greenhouse gases are (in order oftheir contribution to the greenhouse effect on Earth) [9]: Water vapor: causes 36-70% of the effect Carbon dioxide (CO2): causes 9-26% of the effect Methane (CH4): causes 4-9% of the effect Nitrous oxide (N2O): Ozone (O3): causes 3-7% of the effect Chlorofluorocarbons (CFCs) are compounds containingchlorine, fluorine, and carbon, (no H2). CFCs arecommonly used as refrigerants (e.g., Freon).The DOE EIA was publishing an excellent annual report onannual greenhouse gas emissions in the US, for example,the one published in November 2007 (for 2006) is [10], andthe one published in December 2009 (for 2008) is [11]. Allsuch reports, since 1995, may be found at [12]. One figurefrom the report for 2006 is provided below as Figure 8. Theinformation that is of most interest to us in this table is inthe center, which is summarized in Table 4.Note that each greenhouse gas is quantified by “millionmetric tons of carbon dioxide equivalents,” or MMTCO2e.Carbon dioxide equivalents are the amount of carbondioxide by weight emitted into the atmosphere that wouldproduce the same estimated radiative forcing as a givenweight of another radiatively active gas [10].11

Fig. 8: Summary of US Greenhouse Gas Emissions, 2006Table 4: Greenhouse Gas Total, 2006SectorsMMTCO2e % total CO2From Power Sector 234439.1*From DFU-transp 188531.4*From DFU-other 166127.7From ind. processes 1091.8Total CO25999100Non-CO2 GHG1141Total GHG7140% total GHG32.8**26.4**23.3**1.5**84.016.0100.*The direct fuel use (DFU) sector includes transportation, industrial process heat, space heating, and cooking fueled bypetroleum, natural gas, or coal. The DFU-transportation CO2 emissions of 1885 MMT was obtained from the lowerright-hand-side of Fig. 9a. The DFU-other CO2 emissions of 1661 MMT was obtained as the difference between totalDFU emissions of 3546 MMT (given at top-middle of Fig. 9a) and the DFU-transportation emissions of 1885 MMT.** The “% total GHG” for the 4 sectors (power, DFU-transp, DFU-other, and ind processes) do not include the NonCO2 GHG emitted from these four sectors, which are lumped into the single row “Non-CO2 GHG.” If we assume thateach sector emits the same percentage of Non-CO2 GHG as CO2, then the numbers under “% total CO2” arerepresentative of each sector’s aggregate contribution to CO2 emissions. The only sector we can check this for istransportation, where we know Non-CO2 emissions are 126MMT, which is only 11% of the 1141 MMT total non-CO2,significantly less than the % of total CO2 for transportation, which is 31.4%.12

Figure 9 [11] is the same picture as Fig. 8 except it is forthe year 2008; the information is summarized in Table 5.Fig. 9: Summary of US Greenhouse Gas Emissions, 2008Table 5: Greenhouse Gas Total, 2008SectorsMMTCO2e % total CO2From Power Sector 235939.8*From DFU-transp 181930.8*From DFU-other 163627.6From ind. processes 1041.8Total CO25918100Non-CO2 GHG1213Total GHG7131% total GHG33.18**25.5**22.9**1.5**83.017.0100.*The direct fuel use (DFU) sector includes transportation, industrial process heat, space heating, and cooking fueled bypetroleum, natural gas, or coal. The DFU-transportation CO2 emissions of 1819 MMT was obtained from the lowerright-hand-side of Fig. 9b. The DFU-other CO2 emissions of 1636 MMT was obtained as the difference between totalDFU emissions of 3555 MMT (given at top-middle of Fig. 9b) and the DFU-transportation emissions of 1819 MMT.** The “% total GHG” for the 4 sectors (power, DFU-transp, DFU-other, and ind processes) do not include the NonCO2 GHG emitted from these four sectors, which are lumped into the single row “Non-CO2 GHG.” If we assume thateach sector emits the same percentage of Non-CO2 GHG as CO2, then the numbers under “% total CO2” arerepresentative of each sector’s aggregate contribution to CO2 emissions. The only sector we can check this for istransportation, where we know Non-CO2 emissions are 127MMT, which is only 10.5% of the 1213 MMT total nonCO2, significantly less than the % of total CO2 for transportation, which is 30.8%.13

Some numbers to remember from Tables 4 and 5 are Total US GHG emissions are about 7100 MMT/year. Of these, about 83-84% are CO2. Percentage of GHG emissions from power sector isabout 40% (see ** note for Tables 4 and 5). Percentage of GHG emissions from transportation sectoris about 31% (see ** note for Tables 4 and 5). Total Power Sector Transportation Sector emissions isabout 71% (see ** note for Tables 4 and 5).More recent indications of GHG emissions are given below[13].14

5.0 CO2 Emissions – power sectorFigure 10 [11] shows that CO2 emissions from the electricpower sector have been generally rising from 1990 to 2008,but the fact that they are rising more slowly than powersector sales suggests that emissions per unit of energyconsumed is decreasing. Note that the emissions valuesgiven in Fig. 10 have been normalized by the value in theyear 2000, which was 2293.5 MMT.15

Fig. 10: Electric power sector CO2 emissions by yearFigure 11 [6] provides another view of CO2 emissions byfuel where it is clear that, recently, emissions from coal andpetroleum dropped whereas that from natural gas increased.Fig. 11Table 6 [11] shows the year-by-year breakdown of electricpower sector CO2 emissions by fuel. We see the dominantcontributor is coal, with natural gas a distant second.Table 6:Yearly breakdown of electric sector CO2 emissions16

Table 6 is for CO2 emissions only – it does not includeNon-CO2 emissions.Coal is the largest contributor to CO2 emissions. Forexample, in year 2008, it contributed 1945.9 MMT, 82.5%of the total power sector CO2 emissions. The next highestcontributor was natural gas, at 362 MMT, which is 15.3%of the total. The two combined account for 97.8% of powersector CO2 emissions.Total CO2 emissions from gas are only 18.6% of Total CO2emissions from coal. This does NOT imply that CO2 emissions per MWhr from a natural gas power plantare 18.6% of the CO2 emissions per MWhr from a coal-fired powerplant!!!The fact that coal is the largest contributor to GHGemissions is due to(a) it is used to produce just under half of US electricity,(b) it has the highest emissions/energy content ratio, asindicated by Table 7 below [14],(c) its average conversion efficiency is not very good.17

Table 7: Emission Coefficients for Different FuelsFuelCodeEmission CoefficientsPounds CO2Pounds CO2 per UnitperVolume or MassMillion BtuPetroleum ProductsAviation GasolineDistillate Fuel (No. 1, No. 2, No. 4Fuel Oil and Diesel)Jet FuelKeroseneLiquified Petroleum Gases (LPG)Motor GasolinePetroleum CokeResidual Fuel (No. 5 and No. 6Fuel Oil)AV18.355per 9.56432.397per gallonper gallonper gallonper gallonper gallonper 6.033per gallon173.906116.3761133.759120.59312.669per 1000 ft3per 1000 ft3per 1000 ft3per 1000 ft3per 3715.92791.6per short tonper short tonper short tonper short ton227.4205.3212.7215.4Natural Gas and Other Gaseous FuelsMethaneLandfill GasFlare GasNatural Gas ousSubbituminousLigniteACBCSBLCRenewable SourcesBiomassGeothermal EnergyWindPhotovoltaic and Solar ThermalHydropowerTires/Tire-Derived FuelWood and Wood Waste 2Municipal Solid Waste 2BMGEWNPVHYTFWWMSNuclearNUVaries depending on the composition of the biomass000000006160per short ton189.5383812per short ton1951999per short ton199.85400One indication from Table 7, that the pounds CO2/MBTUis based on energy content of the fuel, could be misleading.What is of more interest is the CO2/MWhr obtained from18

the fuel together with a particular generation technology.To get this, we need efficiencies of the generationtechnologies. Fig. 12 provides such efficiencies; theresource from which it came [15] provides a good overviewof various factors affecting generation efficiencies.10090Efficiency (%)80706050403020100tttt)))))Crse)lls lant were) lant lantasne lanananFC GC FBC FBC ngFC etearkW cebippppog r plplrhCitoOIa0rrcrrsurbiteeeer(Pee(C(M ram ll (S rederta10alwwwwWnnllnd pow andicolow powow owooifirtit oMit opa l cevpo l poppppo l cetl(pW aroscpilydTalro idaoa bus bus ineeleotar(uam fu eas icitGere el-oCfuyd(e esrm SolrCmteclTm urbPh-fimttelesHsuoiuoocCifdantthteNCCBlealexiun rbicoedddeona itic d o-einasPtufirGtoHne urbBe e glibo -crBeisoroCrtbteSicgaca ltraed ised arg turmasedismedLideaidW alis ndmte ith urgtluuaallSeetrLFFwlaMStdgenalrstin riseec Smleiadlubosuasirc ntperFig. 12: Generation efficienciesTable 7 and Fig. 12 provide the ability to compare differenttechnologies in terms of CO2/MWhr. For example, let’scompare a natural gas combined cycle (NGCC) plant(η .58), a gas turbine (η .39), and a coal-fired power plant(η .39), where the CO2 content of the natural gas is 117.08lbs/MBTU and the CO2 content of the coal, assuming ituses (Powder River Basin) sub-bituminous coal is 212.719

lbs/MBTU. (Note that coal has a different energy & CO2content, depending on type, as shown below [16]).NGCC: 117.081MBTU INlbs3.41MBTU 688.5lbs / MWhrMBTU IN .58MBTU OUTMWhror117.08lbsMBTU IN 5.88 688.5lbs / MWhrMBTU INMWhrOUTGas turbine:117.081MBTU INlbs3.41MBTU 1023.7lbs / MWhrMBTU IN .39MBTU OUTMWhrCoal-fired plant:212.71MBTU INlbs3.41MBTU 1859.8lbs / MWhrMBTU IN .39MBTU OUTMWhrTable 8 below, from [17], indicates similar numbers for apulverized coal (PC) plant, a circulating fluidized bed(CFB) plant, an integrated gasification combined cycle(IGCC) plant, and a combined cycle plant. Note that thefuels for the first three of these are all coal, and they havesimilar emissions/MWhr ratios. The combined cycle planthas a bit higher ratio (810 instead of 688.5) because it useda lower efficiency (49.3% instead of 58%).20

Table 8In the calculations at

Costs of Generating Electrical Energy 1.0 Overview The short-run costs of electrical energy generation can be divided into two broad areas: fixed and variable costs. These costs are illustrated in Fig. 1 below. Fig. 1 Typical values of these costs are given in the following Table 1 [1]. Some notes of interest follow: .

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