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\A/TPIO >HRWORLD EBANK TECHNICAL PAPERt NUMBER. 106
iNDUSTRY AND ENERGY SERIES A~Us H989Demand and Netback Valuesfor Gas in Electricity
Neil Pinto and John Besant-Jones
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Demand and Netback Values for Gas in Electricity
Industhy and Energy Series
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WORLD BANK TECHNICAL PAPER NUMBER 106
INDUSTRY AND ENERGY SERIES
Demand and Netback Valuesfor Gas in Electricity
Neil Pinto and John Besant-Jones
The World BankWashington, D.C.
Copyright © 1989The International Bank for Reconstructionand Development/THE WORLD BANK
1818 H Street, N.W.Washington, D.C. 20433, U.S.A.
All rights reservedManufactured in the United States of AmericaFirst printing August 1989
Technical Papers are not formal publications of the World Bank, and are circulated to encour-age discussion and comment and to communicate the results of the Bank's work quickly tothe development community; citation and the use of these papers should take account oftheir provisional character. The findings, interpretations, and conclusions expressed in thispaper are entirely those of the author(s) and should not be attributed in any manner to theWorld Bank, to its affiliated organizations, or to members of its Board of Executive Directorsor the countries they represent. Any maps that accompany the text have been preparedsolely for the convenience of readers; the designations and presentation of material in themdo not imply the expression of any opinion whatsoever on the part of the World Bank, its af-filiates, or its Board or member countries concerning the legal status of any country, terri-tory, city, or area or of the authorities thereof or conceming the delimitation of itsboundaries or its national affiliation.
Because of the informality and to present the results of research with the least possibledelay, the typescript has not been prepared in accordance with the procedures appropriateto formal printed texts, and the World Bank accepts no responsibility for errors.
The material in this publication is copyrighted. Requests for permission to reproduce por-tions of it should be sent to Director, Publications Department, at the address shown in thecopyright notice above. The World Bank encourages dissemination of its work and will nor-mally give permission promptly and, when the reproduction is for noncommercial pur-poses, without asking a fee. Permission to photocopy portions for classroom use is notrequired, though notification of such use having been made will be appreciated.
The complete backlist of publications from the World Bank is shown in the annual Index ofPublications, which contains an alphabetical title list and indexes of subjects, authors, andcountries and regions; it is of value principally to libraries and institutional purchasers.The latest edition is available free of charge from the Publications Sales Unit, Department F,The World Bank, 1818 H Street, N.W., Washington, D.C. 20433, U.S.A., or from Publications,The World Bank, 66, avenue d'Iena, 75116 Paris, France.
Neil Pinto is group manager at Kennedy & Donkin Power Systems, Godalming, Surrey,United Kingdom, and a consultant to the World Bank's Industry and Energy Department.John Besant-Jones is a senior energy economist in the same department of the Bank.
Library of Congress Cataloging-in-Publication Data
Pinto, Neil, 1954-Demand and netback values for gas in electricity / Neil Pinto and
John Besant-Jones.p. cm. -- (World Bank technical paper, ISSN 0253-7494 ; no.
106. Industry and energy series)ISBN 0-8213-1280-41. Gas, Natural--Prices. 2. Gas power plants. I. Besant-Jones,
John II. Title. III. Series: World Bank technical paperno. 106. IV. Series: World Bank technical paper. Industry andenergy series.HD9581.A2P56 1989333.8'233--dc2O 89-16746
CIP
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ABSTRACT
This paper updates an analysis of relationships between price and demand fornatural gas in power generation that was carried out in 1982 in a greatlydifferent fuel price environment. The two analyses show the effect on theserelationships of large declines in oil and coal prices and changes incapital costs and fuel efficiencies of power generating plant.
The paper also presents the convenient but robust methodology developed tosiimplify the analysis. This methodology may be used to derive the netbackvalues of gas for power from savings in alternative fuel costs and the lowercapital costs of gas generating plant. It also captures the influences ofinvestment lumpiness and the dynamic character of power systems.
The methodology determines the quantity of gas that would be demanded for atrial gas price that represents a power producer's willingness to pay undera long-term gas supply contract. The analysis shows that the pattern (asdistinct from the level) of the relationships between price and demand forusing gas in a specific power system is not sensitive to changes incompeting fuel prices despite numerous influential factors. Furthermore,tlhere appears to be two distinct components to this relationship which arerelevant to the strategic planning of gas development. In particular, it isusually possible to identify a single price that reflects a power producer'swillingness to pay for a significant proportion of power system-dependentdemand for gas. This feature provides the scope for identifying a value ofgas for power that is analogous to the netback value for gas in non poweruses. Thus, it can be used to screen options for gas use. This featuresimplifies considerably the process of planning strategies for gasutilization that involve power.
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CONTENTS
PREFACE ..................... ix
1. INTRODUCTION AND SUMMARY ..................... 1
1.1 Introduction ..................... 11.2 Terms of Reference ....................................... 1
1.3 Summary ....................... 2
2. METHODOLOGY. 5
2.1 Introduction. 52.2 Approach. 52.3 Computer Program. 52.4 Generation Planning. 6
3. DATA AND ASSUMPTIONS. 9
3.1 Introduction. 93.2 Description of Systems Modelled. 93.3 Generating Plant Details .103.4 Fuel Prices .113.5 Characteristics of Converted Plants .12
4. RESULTS .15
4.1 Introduction .154.2 System A. 154.3 System B. 184.4 System C. 214.5 Comparison with 1982 results .23
5. CONCLUSIONS .26
5.1 Introduction .265.2 Generalised Conclusions .265.3 Changes since 1982 .27
Appendix A Basic Data and Assumptions ..................... 68
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LIST OF TABLES
4.1 Annual gas consumption for varying gas prices - System A .......... 284.2 Planting programmes for System A .................................. 294.3 Energy generation by gas fired plants - System A .................. 314.4 Annual gas consumption for varying gas prices - System B .......... 324.5 Planting programmes for System B .................................. 334.6 Energy generation by gas fired plants - System B .................. 374.7 Annual gas consumption for varying gas prices - System C .......... 384.8 Planting programmes for System C .................................. 394.9 Energy generation by gas fired plants - System C .................. 424.10 Comparison between annual discounted average gas consumptions
calculated in November 1982 report and current values ............. 43A.1 Inherited plant mix ............................................... 69A.2 Assumed retirement dates for inherited plants - System B .......... 70A.3 Committed plant - System B ........................................ 71A.4 Assumed plant characteristics ..................................... 72A.5 Fuel price assumptions ............................................ 77A.6 Costs of plant conversion to gas firing ........................... 79
LIST OF FIGURES
3.1 Annual fuel costs for Systems A and C ............................. 133.2 Annual fuel costs for System B .. 144.1 Gas demand curve for System A .. 444.2 Undiscounted gas demand curve for System A ........................ 454.3 Annual gas consumption for least cost programmes - System A ... 464.4 Gas demand curve for System A - 1990 .............................. 474.5 Gas demand curve for System A - 1995 .............................. 484.6 Gas demand curve for System A - 2000 .............................. 494.7 Gas demand curve for System A - 2005 .............................. 504.8 Gas demand curve for System B .. 514.9 Undiscounted gas demand curve for System B ........................ 524.10 Annual gas consumption for least cost programmes - System B ... 534.11 Gas demand curve for System B - 1990 .............................. 544.12 Gas demand curve for System B - 1995 .............................. 554.13 Gas demand curve for System B - 2000 .............................. 564.14 Gas demand curve for System B - 2005 .............................. 574.15 Gas demand curve for System C .. 584.16 Undiscounted gas demand curve for System C ........................ 594.17 Annual gas consumption for least cost programmes - System C ... 604.18 Gas demand curve for System C - 1990 .614.19 Gas demand curve for System C - 1995 .624.20 Gas demand curve for System C - 2000 .634.21 Gas demand curve for System C - 2005 .644.22 Comparison between November 1982 report and current demand curve -
System A .. 654.23 Comparison between November 1982 report and current demand curve -
System B .. 664.24 Comparison between November 1982 report and current demand curve -
System C .. 67
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PREFACE
Background and Objectives
Mary developing countries possess natural gas resources, but development isoften constrained by limited market opportunities. The power sector is oneof the largest potential users of gas in these countries, and it is animportant source of benefits to justify the initial investment in gasinfrastructure.
This Report updates the analysis of price/demand relationships for naturalgas in power generation presented in Energy Dept Paper No. 18 entitled"Value of Natural Gas in Power Generation" and published in November 1984.The former analysis was undertaken by the British consulting engineersMessrs. Kennedy & Donkin in 1982 and incorporated the then prevailing priceassumptions for capital plant and fuels. The same consultants werecommissioned in 1988 by the Industry and Energy Department of the World Bankto re-examine these relationships under the greatly different fuel priceenvironment for power supply of the late 1980s. This Report presents theresults of this analysis and also gives a full description of the convenientbut; robust methodology developed by the consultants to simplify theanalysis.
The two studies show the impact of three major changes in power economicsbetween 1982 and 1988 that affect gas values for power. The first is thedecline of about 60% in real international oil prices from an historicallyhigh level to one of the lowest recorded levels. A similar decline ofneiarly 50% has occurred in real coal prices, the main competitor to oil andgas for thermal power generation. Projections of fuel prices to the year2000 have also been lowered substantially. The second is the change inrelative capital costs between generating plant types, and the third is theimprovements in fuel use efficiency for power generation. The 1982 and 1988price/demand relationships represent extremes of the range of the economicvaiue of gas for power. In particular, they show that gas values aresensitive to oil and coal price movements.
Limitations of Average Netback Values
In a conventional analysis the initial stage of planning the development ofa gas resource is usually a process of screening a wide range of possibleuses on the basis of the average netback value in each use. This value iscalculated from the difference between the discounted present values ofannual product revenues and costs with zero cost being attributed to the gasquantity supplied, divided by the discounted present value of the annual gasquantities. The competing uses for gas are then ranked by average netbackvalues to identify those uses which warrant detailed consideration.
However, the average netback approach is unreliable for screening gas usingpower projects. This is because the approach does not reflect themultiplicity of a values for gas in power production, i.e. the priceelasticity of power demand for gas is not generally zero. Furthermore, thenetback approach yields overestimates of power demand for gas under a leastcost power development scenario, since the approach is based on the
assumption of zero gas cost for a quantity linked to gas availability. Noris average netback value an appropriate indicator of a power producer'swillingness t-o pay for gas since this value differs from the marginal valueof gas to the power producer.
The marginal value varies with the pattern of a gas use for powerproduction. This pattern changes substantially over time, can be highlyirregular and, in the case of predominantly hydropower systems, isunpredictable. This feature arises from changes in the utilisation of powergeneration plant types and the variable levels of capacity utilisation ofeach plant type. The main causes of this pattern are variation in systemload between daily peak and base load periods, seasonal variations in systemload and hydropower output, and the change in plant mix of a power systemdue to the commissioning of new plant or the retirement of old plant.Investment in gas using power plant can even be justified for a period inwhich it will have virtually zero demand for gas, since the relatively lowcapital costs of this plant type make it attractive as system reservecapacity. The possibility of converting existing oil-fired power plant togas usage and the installation of new plant that can operate on both oil andgas are additional complications for analysing the value of gas in power.
Thus for example, the marginal returns to increasing use of gas in a powersystem at a given time will diminish as more gas is used for the lower valuebase load after meeting the relatively small demand for the higher valuepeak load. Alternatively, the marginal returns to gas could increase overtime as system growth allows gas to be used at least cost in combined cycleplant which has greater fuel efficiency but higher unit capital cost thangas-fired turbines.
Advantages of Price/Demand Relationship
Reliable estimates of the values of gas for power can be obtained from theprice/demand relationship. This approach compares power system developmentprogrammes that involve gas with those that do not for a particulardevelopment of system loads. It thus derives the values of gas savings inalternative fuel costs and the lower capital costs of gas generating plantrelative to the costs of oil, coal and hydro-based plant. It does notreflect the economic value of any incremental demand for power that couldarise from a reduction in power producer's supply costs if gas prices wereset at lower levels than these values. It also captures the influences ofinvestment lumpiness and the dynamic character of power systems. Under aspecific annual system loading and plant operating mix, the relationshipusually takes the form of a series of discrete steps in the quantitydemanded at particular switching gas prices. In other words, the demandcurve consists of discontinuous segments with zero or infinite priceelasticities. The values of switching gas prices are particularly sensitiveto the prices of the major competitor fuels for power generation.
The demand for gas is expressed as a series of annual quantities consistentwith the least cost development program for a power system at a particulargas price. This price represents a level of willingness to pay by a powerproducer under a long term supply contract. The sum of the annualquantities demanded at a particular gas price in a given power system givesthe total quantity of gas that would be demanded at this price. The demandis computed for various gas prices to produce the relationship.
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The gas price/demand relationship for power, adjusted for costs ofdelivering gas to power plants, is analogous to marginal netback values forspecified quantities of gas for non-power uses. Analysis of these two setsof values gives the combination of uses which maximises the economic valueof the total amount of available gas. The relationship is also relevant tosetting the terms for gas supply.
This approach also provides a sound method for screening power uses for gaswith non-power uses. It is usually possible to identify from theprice/demand relationship a single gas price that reflects a powerproducer's willingness to pay for a large proportion of system dependentdemand, as outlined below. This price can be used with netback values ofgas in non-power uses for the screening process.
Proposed Methodology
The computational effort for deriving gas price/demand relationships forpower can be extremely heavy with rigourous optimisation of least cost powerdevelopment programs. The methodology proposed in this report derives thisrelationship with considerably less effort. This simplification isjustified because the gas price/demand relationship is not significantlysensitive to the minor compromises in the methodology for programming powersystem development.
The methodology has been applied in this Report to case studies for threepower systems. These systems were selected to illustrate various typicalfeatures of gas demand for power, particularly its relationships with systemsize, different competing fuel (distillate, residual oil and coal), theimpact of inherited generating plant, the conversion of this power plant togas firing, the influence of hydropower in the power system, and thepotential for advanced commissioning of gas-fired plant and retirement ofoil-fired plant. The methodology can also accommodate readily an escalationin the real price of gas, although this was omitted from the case studiesfor simplification.
Parameters for StrateQic Gas Planning
The case studies show that the demand for gas for power at a given gas priceis highly specific to the characteristics of the power system and tocompetitor fuel prices. Thus for power system planning, full analysis isrequired to establish this relationship reliably. However, the case studiesreveal a useful feature for identifying the important parameters forstrategic gas development planning. The underlying shape of theprice/demand curve, as distinct from the level, does not appear to besensitive to the wide range of competitor fuel prices evaluated.Furthermore, there appears to be two distinct components to gas demand forpower that arise from the segmentation of the price/demand curve. Therelevant parameters are the critical gas price for each of these componentsand the growth in gas demand over the long term at each of these gas prices.The case studies clearly illustrate this feature.
One of the two major components of total gas demand represents a base loaddemand. This component accounts for a large proportion of total gas demandbut at a relatively low price, and thus is critical to the economics of gas
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production and transmission investments for power use. It can thus be usedas the parameter for the power sector that corresponds to average netbackvalue in other uses in a screening process. The other component representsan equivalent peak load which accounts for a small proportion of the totaldemand but at a relatively high price. This component influences theeconomics of gas storage facilities at power plant sites and investments indelivery capacity dedicated to satisfying peak gas demands of a group ofproximate gas users.
1 INTRODUCTION AND SUMMARY
Li Introduction
This report is submitted in accordance with the terms of referencefor a study into the value of natural gas in power systems. Theterms of reference (detailed below) required Kennedy and DonkinPower Systems (henceforth referred to as the Consultant) to updatea previous study taking into consideration changes in capital costsand efficiencies of generating plant, and using current and themost recent forecast of fuel prices.
Previous studies were carried out by Kennedy and Donkin inSeptember 1982 and November 1982. The reports were entitled"Economic Value of Natural Gas in Power Generation" and "EconomicValue of Natural Gas in Power Generation (Supplementary Report)".The reports are referred to as the September 1982 Report and theNovember 1982 Report respectively.
The Consultant was required to produce demand curves for prototypepower systems which vary in terms of plant mix and size. The demandcurve for gas is a function of system specific factors such as theinherited plant mix (i.e. the relative proportions of hydro, coal-fired thermal plant, oil-fired thermal plant, gas turbines etc.),details of future plant mixes, generating unit sizes and rate ofgrowth in demand for electricity. The same three power systems wereused for the analysis as in the November 1982 Report.
Comparisons of the results of the analysis in this report with theresults of the November 1982 Report give an indication of theconsiderable variation in economic values for gas in power that canoccur over a few years, and the links between gas values, oil andcoal prices.
1.2 Terms of Reference
The terms of reference for the study are as follows:
1. The Consultant shall assess the demand for natural gas inpower generation. The methodology to be adopted for thiswork will be based on that used in two reports produced bythe Consultant for the World Bank in 1982.
2. The assumptions made regarding fuel prices and generatingplant capital costs and efficiencies will be updated to1988 values. All other assumptions contained in theNovember 1982 Report will remain unchanged, except that anotional depletion premium will not be included in gasprice projections. In particular these assumptions includedetails of inherited plant, load forecasts etc.. The leastcost generation development programmes will, however, bereoptimised to take account of the changes to the basicdata.
2-
3. Three prototype power systems will be optimised usingcomputer models to determine the least cost plant mix fordifferent assumed prices of natural gas, and thence thequantities of gas which the optimised power systems willutilise at each price of gas.
4. The gas prices to be assumed will be $1/MMBTU, $2/MMBTU,$3/MMBTU, $4/MMBTU, $5/MMBTU, and $6/MMBTU.
5. A calorific value for the gas of 1000 BTU/CFT will beassumed.
6. The timeframe for the study will be 20 years.
7. The rate of growth of demand for electricity shall beassumed to be 7% per annum for all three power systems.The effect of a lower growth rate on the results shall beconsidered.
8. The power systems' demand for gas shall be calculatedassuming an investment programme which allows for theconversion to gas-firing of inherited capacity.
9. Optimisation of the power systems will be based on adiscount rate of 10% per annum.
10. The Consultant shall not optimise generation plant unitsizes.
11. A report on the analysis shall be completed by 30 June1988.
1.3 Summary
In the reports for the previous study undertaken by the Consultant,a methodology was developed to estimate the economic value of gasin the electric power sector. Although this method6logy iscomputationally complex in terms of the amount of analysis, it ismore straightforward than the full methodology associated with thedetermination of least cost development analysis (which has notbeen used in this study). The methodology adopted was, however,sufficiently complete to fulfil the objective of the study, namelyto estimate gas consumption under a range of gas prices.
The 1982 studies formed part of a set to estimate the value of gasin a number of sectors. Other studies included use of gas as afeedstock for a fertiliser plant, domestic use and industrial use.Many other possible uses for gas exist. In the Middle East, forexample, gas is used in the production of aluminium. Liquefactionof gas is also possible for export to developed countries. Indetermining the optimal allocation of gas in the power sector, dueconsideration needs to be given to these alternative uses for gas.An overall demand/price curve covering all sectors can then beproduced which can be matched against a supply/cost curve. Thedemand/price curve will not be smooth and will include a number of
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discontinuities. With a supply curve also based on the economiccosts of exploitation of the gas reserves (or costs of import), afirst estimate can be made of the overall economic price of gas inthe country in question. This then enables identification of theoptimal allocation of gas between the various sectors.
This report is presented in a total of five sections. It is writtenso as to be read without recourse to the September 1982 andNovember 1982 Reports, and therefore the underlying principlesbehind the methodology adopted are restated. Inevitably, however, anumber of references still remain, especially comparison of keydata such as fuel prices, and consequent changes in gasdemand/price characteristics.
In Section 2 the methodology and computer modelling procedures usedin the study are discussed.
Section 3 presents the data base used for the study, includingdetails of the power systems modelled, assumptions on generatingplant costs and operational parameters and fuel prices.
In Section 4 the results of the study are given. Gas demand/pricecurves for all three systems are presented. In addition to theoverall curves, the demand/price curves in four specific years areexamined and the reasons for the shapes of the curves analysed. Thesensitivity of the results to load growth are examined for one ofthe systems. In conclusion the differences between the shapes ofthe curves as derived and those produced in the November 1982Report are discussed.
The final section of the report presents the conclusions to thestudy. The main conclusions of the study are reproduced below:
1. For all power systems there is a price of gas below whichdemand is relatively inelastic. This value is a functionof system specific variables such as the available fuels,the mix of generating plant etc.. For the three systemsinvestigated this critical price of gas was found to liein the range $2/MMBTU and $3.5/MMBTU. These criticalprices were found to be independent of the rate of loadgrowth.
2. As the price of gas varies, the demand for gas does notchange at a constant rate, but rather moves through aseries of discontinuities.
3. The precise shape of the demand/price curve is systemspecific. It can only be determined using generationplanning techniques whereby the operation of the system ismodelled over a twenty to thirty year period under anumber of gas price scenarios.
4. The discontinuities in the gas price/demand relationshipsoccur at prices which represent switches betweeninvestment decisions. These prices depend upon a number of
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factors the most important of which are the expectedfuture fuel prices and the relative costs of differenttypes of new generating plants.
5. The specific consumption of gas for power generation canvary between approximately 9 and 12.5 MMCFT per GWhgenerated, depending upon the efficiencies of thegenerating plants.
6. The most important factor which has resulted in reductionsin gas consumption at higher gas price levels is the fallin international fuel prices. The consequences of thisfactor on the consumption of gas are much greater than thepotential effects of technical improvements.
7. Below the critical gas prices (see 1 above) theconsumption of gas is similar to that observed in theNovember 1982 Report and is not, therefore, sensitive tothe substantial change in fuel prices that has occurredbetween 1982 and 1988.
8. In contrast, above the critical gas prices the relativelysmall consumption levels of gas pertain to much lower(about 60%) gas prices in 1988 compared to levels in theNovember 1982 Report.
9. The general shape of the demand curve is not greatlysensitive to changes in fuel prices.
10. The effect of technical changes in the design of gasturbine and combined cycle plants since the time of theNovember 1982 Report, resulting in improved efficienciesfor these plants, slightly increases gas demand at low gasprices.
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2 METHODOLOGY
2.1 Introduction
The objective of this study is to map the characteristics of demandfor natural gas in power systems by means of demand curves in threepower systems under six gas price scenarios. These priceassumptions range from $1/MMBTU to $6/MMBTU, delivered to powergenerating plant.. In all cases it was assumed that there was noconstraint on the supply of gas, and the generation mix on eachsystem was optimised to determine the amount of gas which theelectricity utility would burn in its power stations at the assumedgas price. A full rigorous determination of the least cost solutionunder each scenario was not carried out, as this exercise wasneither practical nor warranted in the context of this study.Rather the analysis sought to concentrate on those aspects whichmight most be expected to influence gas demand. The previousstudies undertaken by the Consultant have shown that this is acomplex issue.
2.2 ADproach
The demand for gas at a given price will be a function of, amongother variables, the price of substitute fuels, the capital costsof gas-fired generating units relative to those of other fuels, thecosts of converting existing (i.e. inherited) capacity to gas-firing, the demand for electricity in the base year and its rate ofincrease over time. The estimation of a price/demand curve for gasinvolves holding all of these variables constant except the priceof gas. The demand for gas should be estimated for each of anassumed range of gas prices. This process identifies a number ofpoints on the demand curve. A demand curve can then be derived by aprocess of interpolation.
The values of many of the parameters which are used for estimationof the demand for gas are system specific. The two systems denotedA and B were formulated for purposes of this analysis. They differsignificantly in size, inherited plant and expansion options. Thegas demand/price curve was also estimated for a third system whichmay be termed a greenfield case. This corresponds to a system withno restriction on inherited generating capacity, thus removing oneof the major system specific constraints in the analysis.
2.3 Computer Program
The Consultant's INVOPT computer program was used to create modelsof three thermal and mixed hydro-thermal power systems. Thesemodels simulate the operation of these systems and allow a numberof alternative system development programmes to be comparedquickly.
The version of INVOPT used for this analysis calculates the energyproduction of the available generating plant using a digital loadduration curve of elements 100 by 100. This digital approach
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enables the stacking configuration of generating plant to bereadily determined but suffers from the disadvantage of a roundingerror.
Hydro power plant on the system is lumped together and treated as acomposite unit. The total hydro power available is thus stacked onthe load duration curve, taking full account of the power andenergy potential of the composite unit. An iterative calculationdetermines this position, with the program selecting the best fit.
The results of the analysis would not be significantly affected byrefinements to the model, any distortions in gas consumptionestimates tending to be cancelled out over the period ofevaluation.
After the hydro power element has been stacked, the model thenseeks to stack thermal plant operating during that portion of timewhich has been declared to correspond to the peak period of demand.The available plant is stacked in merit order ignoring, ifapplicable, the element taken up by the composite hydro power unit.
Finally generating plant is stacked in merit order on the remainderof the load duration curve, taking into account restrictionsimposed by plant availability.
2.4 Generation Planning
The INVOPT computer model was used to determine the least costgeneration development programme for a given gas price. In order tolimit the number of alternatives to be considered, a screeningcurve analysis was adopted to derive quickly an approximation tothe optimum plant mix. In this approach the annual cost ofdifferent types of generating plants was calculated as a functionof load factor. The breakeven load factors between the differentplants were then calculated and related to the load duration curveto give estimates of the relative proportions of the generatingplant types which minimise overall system costs.
Generation planting programmes were broadly based on the results ofthe screening curve analysis for the six gas prices considered. Itwas not possible to undertake rigorous optimisation of the powersystems. A limited degree of marginal analysis was, however,undertaken to seek confirmation that the adopted programme at eachgas price was close to the optimum least cost programme, takinginto account the assumed changes in fuel price relationships overtime and the influence of inherited plant.
In the case of the greenfield system a close correlation was soughtbetween the theoretical optimum plant mix as determined by thescreening curve analysis and both the inherited and future plantmix. Some distortion from this optimal mix was, however, inevitablein some years because of the discrete size of generating units.
The candidate generating plant options were limited to thefollowing:
- 7 -
System A- 30 MW gas fired gas turbine(Initially 120 MW gas fired combined cycle100 MW) 40 MW residual oil fired steam
30 MW distillate fired gas turbine
System B- 70 MW gas fired gas turbine(Initially 400 MW gas fired combined cycle2400 MW) 600 MW gas fired steam
600 MW coal fired steam600 MW residual oil fired steam70 MW distillate fired gas turbine
System C- 50 MW gas fired gas turbine(Greenfield 200 MW gas fired steamCase 200 MW coal fired steamInitially 200 MW residual oil fired steam800 MW) 50 MW distillate fired gas turbine
In general for all three systems the candidate plants wererestricted to gas turbines, combined cycle units and steam units,with the fuel options of coal, oil and gas. In system A it wasassumed that the system was too small for the import of coal due tothe high costs associated with coal handling plant. In system B thecomplete feasible range of plant types and fuel types wasconsidered. Preliminary screening analysis indicated that combinedcycle plant is not economic when compared with gas fired steamplant in the 200 MW size range, on the capital cost and heat rateassumptions made. In system C, therefore, the candidate plants werelimited to gas turbines and steam plant.
The range of unit sizes considered was limited to avoid theanalytical complications which would be introduced by theoptimisation of unit size. This aspect of generation planning wasexplicitly excluded from the Terms of Reference for the study (seeitem 10) since the objective of the study is to determine thedemand for gas rather than carry out a rigorous least cost solutionanalysis. The level of optimisation carried out in the study isadequate to meet this objective.
In all cases the power systems were simulated on an annual basisover a 20 year period. A time slice approach was adopted in orderto avoid any calculations of residual values. In this approach theannual operating costs in the final year of simulation are keptconstant over a pre-determined runout period. Any plant which isscheduled to retire over this period is reinserted with identicalcapital costs to those incurred when it was first commissioned. Therunout period adopted was 10 years. Reserve margins for thegeneration programmes were estimated on a simple basis. The marginwas set to be equal to:
n x Largest unit on system
where n, an integer, is a function of the maximum demand of thesystem. Again in a rigourous least cost analysis the reserve margin
- 8 -
requirement would be calculated using a probabilistic approach.This sophistication is not necessary in the context of this study.
-9-
3 DATA AND ASSUMPTIONS
3.1 Introduction
This section describes the assumptions and data base used in thisanalysis. They are consistent with the corresponding bases used forthe September 1982 and November 1982 Reports, although they referto the 1988 market situation.
3.2 Description of Systems Modelled
Three different power systems were modelled in the analysis. Two ofthem were loosely based on actual systems, with appropriateassumptions made regarding inherited plant, shape of the loadduration curve etc.. The third system examined corresponds to a'greenfield' site with no pre-determined constraint on theinherited plant. These systems were also analysed for the November1982 Report, and the effects of updating both capital costs andfuel prices are identified.
System A is fairly sma'll with a current maximum demand ofapproximately 100 MW. The load factor of the system was assumed tobe constant over the simulation period at 54.5%. The power systemis entirely thermal with no possibility of future hydro. Theinherited plant mix consists of five 33 MW steam units fired byresidual fuel oil and various diesel units amounting to a total of70 MW s.o.. The steam units are new and are not retired over thesimulation period, whereas the diesels are retired between 6 and 14years hence. It was assumed that there is no committed plant andthe rate of load growth would be 7% p.a..
System B is significantly larger than System A with a currentmaximum demand of 2400 MW. The system load factor is also higherthan that of System A at 69.7%. Again it was assumed that therewould be no change in the system load factor over the period ofsimulation. System B has a varied plant mix comprising hydro withstorage, lignite-fired steam plant, gas turbines and diesel plant.The capacities of each of these categories together with theinherited plant mix for System A are shown in Table A.1 of AppendixA. All of the inherited thermal plant is retired over thesimulation period, and the assumed retirement dates are shown inTable A.2. Plants which were taken to be in the process ofconstruction have been assumed to be committed. Since they arecommon to all generating programmes evaluated, their capital costshave been excluded from the analysis. Details of these plants aregiven in Table A.3. A single rate of load growth of 7% p.a. wasadopted.
System C (the greenfield case) is taken to have an initial maximumdemand of 800 MW. It is assumed to have an identical load durationcurve to that adopted for System A. The rationale behind adoptionof this case is to eliminate the effects of inherited plantconstraints on the results. Two alternative assumptions were maderegarding the rate of load growth, namely 7% p.a. (as for Systems Aand B) and a lower rate of 3% p.a.. As for System A the effects of
- 10 -
possible hydro plants were eliminated by the assumption that thereis no hydro potential in the system.
3.3 Generating Plant Details
Details of the assumptions made regarding the thermal plants areshown in Table A.4. These assumptions include the following:
Nameplate ratingSent out ratingMaximum availabilityFull load heat rate (for steam plant)Average heat rate (for gas turbine and diesel plant)Variable operation and maintenance costsFixed staffing costsCapital costs (phased over the construction period)
These assumptions were similar to those made in the November 1982Report with the following important differences:
1. Improvements were assumed in the efficiency of gas turbineand combined cycle plants.
2. Capital costs of generating plants were assumed to haveincreased by 30%. This increase corresponds to a changeapproximately 5% lower than the change in manufacturingunit value (MUV) index over the period since 1982. Thereal reduction in price is due to increased efficiency inmanufacturing of power plant and the high level ofcompetition. It is very difficult to give precise valuesfor generating plant costs because of this competition andactual tendered values in specific instances can varygreatly from these values. In the case of gas turbineplant, however, a lower increase was assumed, with areduced cost for the first gas turbine unit in a powerstation.
3. Fixed operation and maintenance costs, and staffing costswere assumed to have increased by 35%.
It was assumed that gas fired steam plant would have identicalcharacteristics to those of oil fired steam plant, but with acapital cost saving of 9%.
Economic lives assumed for the different types of generating plantwere as follows:
Steam 25 yearsCombined Cycle 20 yearsGas Turbine 15 years
These lives are greater than those assumed in the November 1982Report for both steam and combined cycle plant by 5 years due totechnical advances.
- 11 -
3.4 Fuel Prices
Fuel price assumptions are shown in Table A.5. These values arebased on international world prices of coal of $35.1/Te and oil of$16.6/bbl (in 1988 $). It was assumed that fuel prices wouldescalate in real terms in line with World Bank forecasts. In thecontext of this study these forecasts are very important as fuelprices in the future are an important determinant on gasconsumption (ie after the construction of new gas fired capacity orthe conversion of existing capacity). Gas prices are assumed toremain constant in 1988 price terms. These prices are treated asequivalent to prices for long term gas supply contracts to powerutilities.
A range of gas prices ranging from average values of $1/MMBTU to$6/MMBTU were assumed for all three systems. The actual fuel pricesassumed for Systems A and B are shown in Figures 3.1 and 3.2 on aheat basis for the period of simulation of the systems. It wasassumed that the costs of fuel in System C were identical to thosein System A. For very low gas prices (i.e $2/MMBTU and below), gasis cheaper on a heat basis than residual fuel oil and coal over thewhole period of simulation in System A. In System B, however, coalis cheaper than gas at $2/MMBTU over the period 1988 to 1991. From1989 to 1995 significant real increases in the price of coal areforecast which result in coal becoming more expensive than gas. Inall systems $3/MMBTU represents an important gas price. At thislevel it is more expensive than coal over the whole period ofsimulation for System B and is cheaper for the period 1988 to 2005for Systems A and C. It is cheaper than residual fuel oil for theperiod from 1993 for Systems A and C and from 1994 for System B.Gas at $4/MMBTU is cheaper than residual fuel oil from 2000 in thecase of Systems A and C, and from 2002 in the case of System B.Above $4/MMBTU there are crossovers between the prices ofdistillate and gas. At $5/MMBTU gas is cheaper than distillate from1994 in both System A and System B. At $6/MMBTU gas is cheaper thandistillate from 2004 in System A and 2005 in System B. These datesare important in determining the types of fuel used in gas turbineplant which, it was assumed, could be fired by either gas ordistillate. Substitution possibilities for other fuels in othergenerating plant types are additionally dependant on differences incapital costs, forced and scheduled outage rates, fixed andvariable maintenance costs etc..
Geography can also play a significant role in the relativeeconomics of different fuel types. Transport costs, particularlyfor bulky fuels such as coal, can vary over a wide range dependingnot only on the distance the fuel is transported but also on thesize of the cargo lots. In this study it was assumed that thetransport cost of coal is 57% of its fob price in the case ofSystems A and C and 29% in the case of System B. For residual fueloil transport costs were taken to be 13% of the fob price forSystems A and C and 7% for System B. In the case of distillatetransport costs represent 4% of the fob price for Systems A and Cand 3% for System B. In practice it is probable that thesepercentages would tend to fall over time if the size of the cargo
- 12 -
lots increases (due to increases in fuel burn resulting from growthin energy demand).
3.5 Characteristics of Converted Plants
Costs of conversion of existing plant to gas firing are shown inTable A.6. In System A the only generating plants capable of beingconverted are the 33 MW oil fired steam units. These were notdesigned to allow for conversion and therefore a relatively highspecific conversion cost of $110/kW has been assumed.
In System B the following conversions were considered:
(a) existing 300 MW oil fired steam
(b) committed 80 MW distillate fired GT to gas fired GT
The same conversion assumptions were made in the November 1982Report.
ANNUAL FUEL COSTS FOR SYSTEMS A AND C
32 - _ _
30 -
26 -- X
24 - _ -
224
-> 20 V V v v v V v v v v v v v v v
v- . . I . . I . . I .- . I . . I . . I~~~~~~~~~~~~~~~~~~~.. .....
18 4.~†..-
16. ~ ~ ~ .4-..+or......
o ~14
U1 /MM8TU I3/MMBT $5/MM8TU-12 x x--*-
IL. 1~~i0 **.......
8
6-
4 A A A& A at A A c A di A A A I& AC A& A
2
0- . . I r
1988 1991 1994 1997 2000 2003 2006
Year*Distillate + Residual * Coal A Gas at x Gas at v Gas at
91 /MMBTu $3/MMBTU $5/MMBTU
ANNUAL FUEL COSTS FOR SYSTEM B30--
28 -o2
22 J
U 207 v v v r'V v v v v v v v v v v v v t
16-*'., +."".+.*+tF§+ 0~ 2
° 12 < ( .$ -5|! )( .... t . ......
14 !
6~~~ ~~ ~~~~ .r § - .
1 988 1 991 1 994 1 997 2000 2003 2006
Year* Distillate + Residual o Coal A Gas at x Gas at v Gas at
$1 /MMBTU $3/MMBTU $5/MMBTU
15
4 RESULTS
4.1 Introduction
The results for the three systems are separately presented, and thegas demand/price curves estimated are shown on three bases. Thefirst basis shows the demand for natural gas over the simulationperiod at each of the trial gas prices in terms of average annualdiscounted quantities of gas. The second basis shows therelationship between total undiscounted quantities of gas and gasprice. The third basis is presented in tabular form showing theyear by year consumption for each gas price.
Demand/price curves presented using the first two bases are summarymeasures and as such do not reveal any information about therelationship between the shape of the demand curve and, forexample, changes in the plant mix over time. Both the bases areillustrative only of the shape of the demand curve and do notindicate the rate of gas demand. The discount rate used for presentvaluing for the first basis was 10% p.a.. The effect of thisdiscounting is to reduce the impact on the demand curves of thehigher consumptions towards the end of the simulation period.
In a final section the comparison between the results derived inthis report and those in the November 1982 Report is discussed withparticular reference to System C.
4.2 System A
The estimated demand curves for System A are presented in Figures4.1 and 4.2. The annual quantities of gas consumed are shown inTable 4.1. The inherited plant in System A is entirely thermal asshown in Table A.1 of Appendix A. There is a considerable reservemargin in the early years of the simulation period, thus there ispotential for conversion to gas firing for some of this capacity.The consumption of gas is effectively limited initially to theseunits.
Details of the generation planting programmes considered for SystemA are shown in Table 4.2. A total of 12 programmes were considered.In programmes 1 to 7 the existing oil fired steam plant was assumedto be converted to gas firing. The plant mix gradually changesthrough these programmes as the relative proportion of new gasturbine plant is reduced, with varying amounts of gas firedcombined cycle plant introduced. The order of commissioning of gasturbine and combined cycle plant is also changed in theseprogrammes. In programmes 8 to 12 oil fired steam plant isintroduced into the plant mix. In all programmes no new capacity iscommissioned for 10 years, and the only possible change in plantmix is due to the conversion of the existing steam fired plant.
Table 4.3 shows the proportion of total energy demand which issupplied by the gas fired plants for each gas price assumption.
- 16 -
4.2.1 Gas Prices and Discounted Ouantities
Figure 4.1 shows the estimated demand curve at the various gasprices in terms of discounted gas quantities at a discount rate of10% per annum.
The curve is seen to be inelastic at gas prices between zero and$2/MMBTU, with a demand of 9.2 billion cubic feet per annum. Theleast cost generation development programme does not change overthis range of gas prices and gas consumption is maximised. Theleast cost programme over this gas price range is Programme 1,based entirely on gas turbine plant. Conversion of the steam unitsto gas firing in the early years of the period simulated is theleast cost option for this plant. As the gas price increases to$3/MMBTU, the improved efficiency of the combined cycle plantbecomes important and the gas consumption is correspondinglyreduced. Conversion of the steam units to gas firing is stilleconomic. Ignoring the costs of conversion, the breakeven cost atwhich this conversion is no longer worthwhile is $3.17/MMBTU (thecomparable value in the November 1982 Report was $6.4/MMBTU in 1982prices or $8.64/MMBTU in 1988 prices). This price thereforerepresents a discontinuity on the demand curve as, above thisprice, conversion of the steam units to gas firing is notworthwhile. At a gas price of $4/MMBTU there is no demand for gasuntil 1998. The least cost generation development programme at thisgas price involves the commissioning of additional fuel efficientcombined cycle plant.
As the gas price rises still further to $5/MMBTU and $6/MMBTU thepotential for use of gas progressively reduces. The least costplanting programme becomes one based on the commissioning of alimited number of steam units burning residual fuel oil and gasturbines which can burn either distillate or gas. At a gas price of$5/MMBTU, the gas turbines commissioned are assumed to be fired ongas from 1994 and at a gas price of $6/MMBTU from 1997. Since noenergy is generated by gas turbines until 1999, however, there isno consumption of gas until this time. Above a gas price of$7.60/MMBTU there will be no consumption of gas during the periodsimulated (cf $10.51/MMBTU in 1982 prices or $14.19/MMBTU in 1988prices in the November 1982 Report).
The demand curve linking the points has been plotted. The curvedemonstrates three distinct regions. For both low gas prices(<$2/MMBTU) and high prices (>$4/MMBTU) the demand is relativelyinelastic. In the intermediate range the least cost generationdevelopment programme is very sensitive to gas price and demand iscorrespondingly elastic. The shape is explored in more detail inSection 4.2.3 where demand/price curves are considered on a year byyear basis.
4.2.2 Gas Drices and undiscounted quantities
Figure 4.2 shows the estimated demand curve with undiscounted gasquantities. The 'x' axis in this Figure corresponds to the totalgas consumption over the 20 year period simulated and not an
- 17 -
average annual value as in Figure 4.1. As would be expected, thecurves are of broadly similar shape.
4 2.3 Gas Demand/Price curves over time
The annual consumptions of gas at each gas price are shown in Table4.1. These values are illustrated graphically in Figure 4.3. Thegas consumptions at $1/MMBTU and $2/MMBTU are identical. At$3/MMBTU the consumptions are marginally lower in the early yearsbecause the price of residual fuel oil is less than that of gas,and therefore the unconverted 33 MW plant operates at higher meritthan the converted units. (It was assumed that conversion of theunits would be phased over a five year period with a maximum of twoof the five units undergoing conversion at any one time.) After1993, however, gas at $3/MMBTU is cheaper. Conversion of the unitsis still, however, economic because the price of gas over thelives of the units is less than the average price of oil. Ideallyconversion of the units would be delayed to 1993, but such a delaywould result in unacceptably low reserve margins. From 2005consumptions at $3/MMBTU are below those for lower gas prices dueto the improved fuel efficiency of the combined cycle unitcommissioned in that year. A reduction in gas consumption is shownin 2005. This is because the combined cycle unit displaces theother less efficient gas fired plant higher up the load curveresulting in a reduction in consumption despite an increase in gasfired energy generated. A higher gas price of $4/MMBTU thus furtherimproves the economics of combined cycle plant. Conversion of the33 MW oil fired units is not economic at this price and thereforeconsumption of gas is delayed. The increases in consumption seen in1999 and 2003 correspond to the dates of commissioning of thecombined cycle units. At gas prices of $5/MMBTU and $6/MMBTUconsumption is further significantly reduced and, as already noted,gas is limited to use in gas turbine plant after the price of gasbecomes less than that of distillate fuel.
A more comprehensive analysis of the shape of the demand curves hasbeen undertaken for the four snapshot years: 1990, 1995, 2000 and2005. These curves are presented in Figures 4.4 to 4.7 inclusive.
In 1990 gas use is restricted to the converted 33 MW steam units,and therefore the discontinuities correspond to changes in meritorder of these plants and the price at which conversion becomeseconomic. At a 1990 gas price of $2.44/MMBTU the variable costs ofthe gas fired 33 MW units are equal to those of the oil fired 33 MWunits still awaiting conversion. The idealised demand curve wouldtherefore show a single discontinuity at a price of $2.44/MMBTU,with demand perfectly inelastic below this value and demand zeroabove it. However, as previously noted, at a price of $3/MMBTUconversion of the units to gas firing was not delayed to 1993 (thedate at which it would become economically viable) because of theimpact on the reserve plant margin. Since it was assumed thatconversion to gas eliminates the capability for oil burn on asignificant scale, a consumption of gas is shown for a gas price of$3/MMBTU. The demand curve shown in Figure 4.4 is based on theidealised values.
- 18 -
By 1995 there is no potential for a change in merit order over therange of gas prices for which conversion is economic as theconversion of the 33 MW units has been completed. The singlediscontinuity on the demand curve therefore corresponds to theprice at which this conversion is no longer economic ($3.52/MMBTU).
In 2000 the shape of the demand curve becomes more complex. Theprice at which conversion of the oil fired units would be economicis now $4.11/MMBTU. Conversion has, however, not taken placebecause the discounted savings at $4/MMBTU by burning gas from 2000to the end of the period of evaluation do not outweigh theadditional costs of gas burn prior to this date. Again, therefore,the difficulty is illustrated in interpreting snapshot demandcurves in the context of an overall power development programme.Between gas prices of $3/MMBTU and $4/MMBTU, the least costgeneration programme favours an increased amount of combined cycleplant. There is, therefore, likely to be a further discontinuity inthe curve between these prices as the plant mix changes. The curveis shown as a dotted line in this area. Above $4/MMBTU there willbe further changes in the optimal plant mix as oil fired steamunits become cheaper than gas fired combined cycle units, and thendistillate becomes cheaper than gas. The price at which distillatebecomes more expensive than gas is $6.53/MMBTU. Above this valuethe demand for gas drops to zero.
In 2005 the shape of the demand curve is essentially similar tothat in 2000, but with the added complication of an additional stepbetween the prices of $2/MMBTU and $3/MMBTU. This step correspondsto a change in plant mix due to the justification of combined cycleplant in the generation mix at the higher price. Above a gas priceof $7.60/MMBTU gas consumption will fall to zero.
Table 4.3 shows the energy generated and the proportion of totalenergy demand supplied by the gas fired plant on an annual basis ateach gas price. As previously noted the gas consumptions (andenergy generated using gas fired plants) are identical for gasprices of $1/MMBTU and $2/MMBTU. At $3/MMBTU the energy generationis less over the period to 1993 because of the change in meritorder between the converted and unconverted 33 MW steam units. Forgas at $4/MMBTU there is a delay of some nine years until asubstantial proportion of the energy is generated by gas firedplant, since conversion of the 33 MW units is not economic andtherefore there is no gas burning plant on the system until 1998.At the higher gas prices of $5/MMBTU and $6/MMBTU gas fired energygeneration does not rise to more than 11% of total demand even inthe long term.
4.3 System B
The estimated demand/price curves for System B are presented inFigures 4.8 and 4.9, and the annual quantities of gas consumed areshown in Table 4.4 . System B comprises a mix of thermal and hydroplant with storage. The hydro plant operates on the peak with lowcapacity factors. This limits the potential for the introduction
- 19 -
of new thermal peaking plant. There is some potential for theconversion of generating plants to gas firing; in particular a gasturbine unit committed to be commissioned in 1988 and a 300 MW oilfired unit.
Details of the planting programmes considered for System B areshown in Table 4.5. Six basic programmes were considered. These allincluded the conversion of the existing 80 MW gas turbine and300 MW steam turbine to gas firing. The programmes are based onalternative mixes of gas turbine, combined cycle and gas firedsteam plant. In programmes 1 to 5 new plants are limited to gasturbines and steam turbines; combined cycle units are introduced inprogramme 6. The proportion of new gas turbine plant reduces fromprogramme 1 to 5.
A further six programmes were derived based on these six basicprogrammes. These 'second generation' programmes (programmes 10 to60) assume identical commissioning dates to those in the basicprogrammes, but differ in that all steam plant is coal fired.Eleven 'third generation' programmes (11 to 61 and 12 to 52) werederived based on programmes 10 to 60. In these third generationprogrammes it was assumed that the 300 MW oil fired steam plantwould not be converted to gas firing (programmes 11 to 61) and thatthe committed 80 MW gas turbine would also not be converted(programmes 12 to 52).
Table 4.6 shows the annual energy generation and the proportion oftotal energy demand supplied by the gas fired plants at each gasprice.
4.3.1 Gas prices and discounted guantities
Figure 4.8 shows the estimated demand/price curve for various gasprices in terms of discounted gas quantities at a discount rate of10% per annum.
At a gas price of $1/MMBTU the discounted annual consumption of gasis 158.9 billion cubic feet. The least cost generation developmentprogramme is Programme 1, based on the future commissioning of amix of gas turbine and gas fired steam units. Below a gas price of$1/MMBTU it may be expected that the least cost generationdevelopment programme will change to one based entirely on gasturbine plant, thereby minimising capital costs. This has not beeninvestigated in the study and therefore the demand/price curve inFigures 4.8 and 4.9 has been shown dotted below $1/MMBTU. Asindicated, however, gas consumption will be increased due to thelower efficiency of the gas turbine units when compared with steamunits. Above $1/MMBTU the least cost generation programmes arethose based on Programme 5.
At $2/MMBTU the gas price is sufficiently high to penalise the gasturbine plant to such an extent that the least cost developmentbecomes that based solely on the commissioning of new gas firedsteam plant, with the hydro plant fulfilling the peakingrequirements of the system (Programme 5). Average annual discounted
- 20 -
gas consumption falls marginally to a level of 144.3 billion cubicfeet.
At $3/MMBTU conversion of the oil fired steam unit and the gasturbine continue to remain economic. The price differential betweencoal and gas is, however, sufficient to justify a generationplanting programme based on the commissioning of 600 MW coal firedsteam units (Programme 50). Gas consumption falls significantly atthis gas price to a discounted average annual level of 9.2 billioncubic feet. Above an average price of $3.1/MMBTU conversion of theoil fired unit is no longer economic (cf $6.14/MMBTU in 1982 pricesor $8.29/MMBTU in constant 1988 prices in the November 1982Report). At $4/MMBTU therefore, only the gas turbine is converted,and thus the consumption of gas is further significantly reduced toan average discounted value of 0.6 billion cubic feet. Above a gasprice of $4/MMBTU the consumption of gas falls to zero.
The peaking potential for gas turbines is probably underestimatedin the analysis. Any quantities consumed would, however, be smalland would not significantly affect the shape of the demand curve.
4.3.2 Gas orices and undiscounted guantities
Figure 4.9 shows the estimated demand curve with various gas pricesand undiscounted gas quantities. Again the difference in 'x' scalewhen comparing this Figure with Figure 4.8 should be noted.
4.3.3 Demand curves over time
The annual consumptions of gas at each gas price are showngraphically in Figure 4.10. The consumptions at $1/MMBTU and$2/MMBTU are significantly greater than those at higher gas prices.In some early years of the study the consumption is marginallyhigher for gas at $2/MMBTU. This apparent anomaly is due to thelumpy nature of the generating planting programmes. In the leastcost generation development programme at $2/MMBTU, a 600 MW gasfired steam unit is commissioned in 1991, whereas in the least costgeneration programme at $1/MMBTU only a 70 MW gas turbine iscommissioned in that year. The total potential for consumption ofgas is therefore greater at the higher gas price in 1991. As moregenerating units are commissioned, however, the additional demandfor gas at the lower gas price becomes evident. At higher gasprices the demand for gas is limited to those plants which havebeen converted to gas firing. At $3/MMBTU both the committed gasturbine and a 300 MW oil fired unit are converted. At $4/MMBTU onlythe gas turbine is converted.
Demand curves for the snapshot years of 1990, 1995, 2000 and 2005are presented in Figures 4.11 to 4.14.
In 1990 the demand curve consists of a number of steps. Over therange of gas prices from $1.27/MMBTU to $1.64/MMBTU the merit orderof the converted gas turbine changes such that it falls below thelignite fired and oil fired plants. Similarly over the range$1.79/MMBTU to $2.32/MMBTU the merit order of the converted steam
- 21 -
unit gradually falls below that of the lignite and oil fired plant.Neglecting differences in capital and operating costs the breakevengas price above which coal fired plants have lower operating costsis $1.91/MMBTU. In practice, however, because of the significantlyhigher costs associated with coal fired units the breakeven priceis in excess of this price. Excluding the costs of conversion thebreakeven gas price above which conversion of the gas turbine isnot economic is $3.88/MMBTU. Above this price there is no demandfor gas.
The shape of the demand curve in 1995 is broadly similar to that in1990. As the gas price gradually rises the merit order of theconverted plants change and thus the gas consumption falls. Between$2/MMBTU and $3/MMBTU the step changes in quantity of gas consumedcorrespond to the change in the least cost generation plant mixfrom gas fired steam plant to coal fired steam plant. Conversion ofthe oil fired steam unit is not economic at gas prices above$3.34/MMBTU, and conversion of the gas turbine is no longereconomic at gas prices above $5.59/MMBTU. In 1995 the converted gasturbine generates no electricity, however, and therefore at gasprices above $3.34/MMBTU gas consumption is zero.
Similar effects to those described above dictate the shape of thedemand curve in 2000.
In 2005 the shape of the demand curve is somewhat simpler in thatthe consumption of gas falls rapidly to zero at a gas price between$3/MMBTU and $4/MMBTU.
Table 4.6 shows the annual energy generation and the proportion oftotal energy demand supplied by the gas fired plant on an annualbasis at each gas price. At gas prices of $1/MMBTU and $2/MMBTU gasfired plants provide very high proportions of the total energyrequirements in the long term (up to 89% at $1/MMBTU and 81% at$2/MMBTU). The presence of hydro plant on the system means that theproportion of energy supplied cannot rise to 100%. As previouslynoted the effect of the lumpy nature of the generating plantingprogrammes is clearly identifiable, with higher gas firedgeneration at a higher gas price in some years. At $3/MMBTU the gasfired energy generation is significantly less, with no energygeneration at all in some years. Unlike at lower gas prices theproportion of gas fired energy declines over time. At higher gasprices gas fired energy generation is effectively zero.
4.4 System C
As noted in Section 3, System C corresponds to a greenfield casewith no pre-determined inherited plant. The estimated demand curvesare presented in Figures 4.15 and 4.16. The quantities of gas whichwould be consumed at each gas price are shown in Table 4.7.
Details of the alternative generation development programmesconsidered are given in Table 4.8. A total of 12 programmes werederived. In programmes 1 to 4 the plant mix was limited to gas
- 22 -
turbines and gas fired steam plant, with the proportion of gasturbines gradually reducing. In programmes 5 to 8 coal and oilfired steam plants were also considered in varying proportions. Inprogrammes 9 to 12 gas fired steam plant was eliminated from theplant mix.
The annual energy generation and the proportion of total energysupplied by gas fired plant is shown in Table 4.9 for each gasprice. At $3/MMBTU and below gas fired plant is responsible for100% of energy generation. There is a very sharp cut off above thisprice with gas fired plant only supplying between 7% to 9% of totalenergy in the long term.
4.4.1 Gas prices and discounted quantities
Figure 4.15 shows the estimated demand curve for various gas pricesin terms of discounted gas quantities at a discount rate of 10% perannum.
As for System B, at gas prices below $1/MMBTU the least costgeneration programme will change such as to increase the relativeproportion of gas turbine plant. Over the price range to $2/MMBTU,therefore, the demand curve has a conventional negative slope asthis trend continues, with the least cost generation developmentprogramme changing from Programme 1 at $1/MMBTU to Programme 4 at$2/MMBTU. It is probable that this gradual change in plant mixwould also occur up to $3/MMBTU, but the results of the analysisindicated that the least cost generation development programme wasunchanged in moving from gas price levels of $2/MMBTU to $3/MMBTU.Above $3/MMBTU generation based on coal fired steam plant offerslower cost than that based on gas fired steam plant. The least costgeneration development programme changes to Programme 11 and gasconsumption falls significantly. At $4/MMBTU the gas turbinesoperate on gas throughout the period of the study, but as the gasprice rises further to $5/MMBTU and $6/MMBTU gas is not used until1994 and 1997 respectively. For gas prices above $7.60/MMBTU gasconsumption falls to zero for the period of the study (cf$10.33/MMBTU in 1982 prices or $13.95/MMBTU in 1988 prices in theNovember 1982 Report).
4.4.2 Gas prices and undiscounted guantities
Figure 4.16 shows the demand curve for various gas prices andundiscounted quantities. As in the previous cases this curve isbroadly similar in shape to the discounted curve in Figure 4.15.
4.4.3 Demand curves over time
Table 4.7 shows the annual gas consumptions over the period 1988 to2017 at each gas price. The values are illustrated graphically inFigure 4.17. At low prices of $1/MMBTU and $2/MMBTU the gasconsumption profiles are very similar, with consumption beingmarginally higher at the lower price because of the increasedrelative proportion of gas turbine plant. At higher prices gas
- 23 -
consumptions are very much reduced as coal fired steam plant isproviding the base load energy.
Demand curves are shown for the snapshot years of 1990, 1995, 2000and 2005 in Figures 4.18 to 4.21 inclusive. The general shape ofthe curves is similar to that for the price and quantityrelationship graph shown in Figure 4.16, with a single stepcorresponding to the crossover gas price when the least costgeneration development programme changes to one based on coal firedgenerating plant. In the curves for 1995 onwards a further step isintroduced as gas becomes cheaper than distillate for use in gasturbines. The price at which gas usage falls to zero rises from$5.66/MMBTU in 1995 to $6.61/MMBTU in 2000 and $7.60/MMBTU in 2005.
4.5 Comparison with 1982 results
A table giving a comparison between the annual discounted averagegas consumptions as calculated in the November 1982 Report and thevalues calculated in this report for the three systems is presentedat the end of this section in constant 1988 $. Details are alsogiven of the datum fuel price assumptions in both the November 1982Report and this report. In the November 1982 Report the range ofgas prices considered was from $1/MMBTU to $9/MMBTU in 1982 $, orapproximately $1/MMBTU to $12/MMBTU in 1988 $, reflecting thehigher prices of alternative fuels at that time. The analysis wasnot carried out at all prices over this range, however, and thereare therefore some gaps in the estimated consumptions. The valuesare compared graphically for each system in Figures 4.22 to 4.24.
Care must, however, be exercised in this comparison because in theNovember 1982 Report the gas price was escalated in real terms. Theimpact of this escalation on the price/demand curve, however, wasnot generally significant.
For System A (Figure 4.22) the general shapes of the gas demandcurves are similar. At low gas prices ($2/MMBTU and below) annualdiscounted average consumptions are higher in this report. This isbecause the least cost generation development programme is based onthe commissioning of gas turbine plants only. Very low gas priceswere not investigated in the November 1982 Report. It is probablethat similar results would, however, have been produced, thoughwith increased consumptions due to the assumed lower efficiency ofthe gas turbines at that time. The consumptions at $3/MMBTU aresimilar in both this report and the November 1982 Report. Theslight increase in consumption displayed in this report is due tothe change in the least cost generation development programme. Inthis report the relative proportion of gas turbine is higher (dueto the assumptions regarding improvements in efficiency relative tothose made in the November 1982 Report). This in turn has led tothe slight increase in gas consumption. At a gas price of $5/MMBTUthere is a very large difference in gas consumption. This isbecause the breakeven price of gas, above which it is not economicto convert the oil fired steam units, occurs between $3/MMBTU and$4/MMBTU in this report, whereas the higher oil prices in 1982resulted in a breakeven price at that time of $8.6/MMBTU.
- 24 -
Furthermore the least cost generation development programme in thisreport at $5/MMBTU is based on residual oil fired steam units asopposed to the gas turbine and combined cycle programme in theNovember 1982 Report. In the case of System A, therefore, the mostsignificant changes in the shape of the demand curve would seem tobe due to the changes in fuel prices, with only minor changesresulting from improvements in technology.
In System B (Figure 4.23) the change in the demand curve is morecomplex due to the greater variation in fuel utilisation. At a gasprice of $1/MMBTU the annual discounted average consumptions of gasare very similar. In common with System A the consumption at lowprices is marginally higher in this report. This again is due tothe assumed improvement in efficiency of the gas turbine unitswhich has resulted in an increase in their relative proportion inthe least cost generation development programme. As the gas pricerises the breakeven value at which the costs of gas fired steamgeneration are equal to those of coal fired steam generation dropsfrom approximately $3.9/MMBTU in the November 1982 Report toapproximately $2.1/MMBTU in this report (excluding the effect ofcapital cost differences). At $3/MMBTU the consumption of gas islower in this report. This is again due to fuel price changes. Theenergy generated by the gas fired plant is reduced in this reportbecause of changes in merit order relative to the November 1982Report. In particular the price of lignite is significantly lowerin this report ($5.84/MMkcal in the first year of simulation,compared with $20.33/MMkcal). The lignite burning plant thereforedisplaces the gas burning plant in the merit order in this report.At higher gas prices gas consumption is effectively zero in thisreport because of the reduced cost of oil. In the November 1982Report the small level of gas consumption occurred only in gasturbine plant in a single year. In this report it was not economicto burn gas in place of distillate in the year in question.
The comparison in results for System C is shown in Figure 4.24.Again the overall shape of the demand curves is similar. As withSystems A and B higher gas consumptions are displayed in thecurrent report at very low gas prices. Unlike the other demandcurve comparisons, higher gas consumptions in the current study arealso seen for gas prices of $4/MMBTU to $6/MMBTU inclusive. This isbecause the least cost generation development programmes includehigher proportions of gas turbine units than those in the November1982 Report. The intrinsic flexibility of System C in allowingvarying inherited plant mixes at different gas prices is animportant factor in this result becoming apparent.
- 25 -
COMPARISON BETWEEN ANNUAL DISCOUNTED AVERAGE GAS CONSUMPTIONS
CALCULATED IN NOVEMBER 1982 REPORT AND 1988 VALUES
(1988 Prices)
System Report Gas Price in $/MMBTU1 2 3 4 5 6 7 10 12
A November 1982 8.3 8.1 3.3 0.41988 9.2 9.2 8.5 3.2 0.5 0.5
B November 1982 156.0 13.7 13.5 12.6 0.7 0.71988 160.5 148.7 14.2 1.3 0.0 0.0
C November 1982 70.1 69.2 2.5 1.8 0.3 0.31988 70.8 68.0 68.0 4.6 4.0 3.9
Notes 1. All consumption quantities are in Billion Cubic Feet per annum2. Gas prices for November 1982 Report rounded to nearest integral
value.
COMPARISON OF BASE YEAR INTERNATIONAL PRICE
ASSUMPTIONS FOR OIL AND COAL
Report Oil Coal$/bbl $/Te
November 1982 - 1982 $ 33 55.5- 1988 $ 45 76
1988 16.6 35.1
Note: The prices were projected over the planning periodsaccording to the prevailing World Bank forecasts.
- 26 -
5 CONCLUSIONS
5.1 Introduction
The conclusions to this study may be divided into two groups. Thefirst relates to generalised conclusions for the study as a whole.The second group relate to changes in the value of natural gassince the time of the November 1982 Report.
5.2 Generalised Conclusions
A number of general conclusions can be drawn from the analysis, asfollows :
1. For all power systems there is a price of gas below whichdemand is relatively inelastic. This value is a functionof system specific variables such as the available fuels,the mix of generating plant etc.. In the case of arelatively small system with an initial maximum demand of100 MW and no provision for coal burning and no hydrocapacity (System A), gas demand is not sensitive to pricereductions below $3/MMBTU. For a much larger system withan initial maximum demand of 2 400 MW, a mix of generatingplant including hydro with storage, coal and ligniteburning steam, and gas turbines (System B), the criticalprice of gas is approximately $2/MMBTU. For anintermediate size system with an initial demand of 800 MW,a full range of available fuel types and no constraint oninherited plant mix (System C), the critical price of gasis approximately $3/MMBTU.
2. At the price of gas varies, the demand for gas does notchange at a constant rate, but rather moves through aseries of discontinuities. Sharp increases in gas demandresult from the commissioning of new gas fired generationplant, and decreases can be the result of changes in meritorder of gas fired plant relative to other plant.
3. The discontinuities in the gas price/demand relationshipsoccur at prices which represent switches betweeninvestment and operating decisions, for example from gasfired steam units to coal fired steam units. These pricesdepend upon a number of factors the most important ofwhich are expected future fuel prices and the relativecosts of different types of new generating plants.
4. The precise shape of a demand curve is dictated both bythe critical prices of gas which are important indetermining the optimal plant mix (the investmentdecision) and by changes which alter the merit orderranking of plant. It is this system specific. Where thelatter is important the demand curve usually assumes theconventional shape of having a negative slope with respectto the price axis.
- 27 -
5. The specific consumption of gas for power generation canvary between approximately 9 and 12.5 MMCFT per GWhgenerated, depending upon the efficiencies of thegenerating plants.
5.3 Changes since 1982
Additional conclusions resulting from comparison of the results inthis report with those of the November 1982 Report may besummarised as follows:
1. Below the critical gas prices observed and discussed inSection 5.2, the consumptions of gas are similar to thoseobserved in the November 1982 Report and are not,therefore, sensitive to the substantial change in fuelprices that has occurred between 1982 and 1988.
2. In contrast, above the critical gas prices the relativelysmall consumption levels of gas pertain to much lower(about 60%) gas prices in 1988 compared to 1982.
3. Whilst the levels of the demand curves have changed, theirgeneral shape is not greatly sensitive to changes in theprices of fuels other than gas.
4. The effect of technical changes in the design of gasturbine and combined cycle plants since the time of theNovember 1982 Report, resulting in improved efficienciesfor these plants, slightly increases gas demand at low gasprices.
5. The most important factor which has resulted in reductionsin gas consumption at higher gas price levels is the fallin international fuel prices. The consequences of thisfactor on the consumption of gas are much greater than thepotential effects of technical improvements.
- 28 -
TABLE 4.1
ANNUAL GAS CONSUMPTION FOR VARYING GAS PRICES
SYSTEM A
(ALL vaLues in MMCFT)
l-…-…Year Gas prices in $/MMBTU 6
-- - - - -- - - - -- - - - -- - - - -- - - - -- - - -
Year 1 2 3 4 5 6
1988 1 219891990 4939 4939 36001991 4939 4939 39241992 7201 7201 72011993 7605 7605 76051994 8309 8309 83091995 8851 8851 88511996 9405 9405 94051997 9820 9820 98201998 10844 10844 10844 5281999 i11771 11771 11771 6222 42 4212000 12582 12582 12582 6391 139 1392001 13636 13636 13636 6507 1681 11532002 14735 14735 14735 6551 1083 10832003 I 15979 15979 15979 11209 611 6112004 j 17113 17113 17113 11556 792 7922005 18524 18524 15637 11982 1417 14172006 20146 20146 16938 12374 2444 24442007- 21551 21551 18290 12702 2611 26112017
AverageAnnual 9198 9198 8539 3150 474 460 IValue l
|Total| Gas 433454 433454 389142 213047 36931 36403
Demandl-
|Leas t|lCost 1 1 2 10 11 11
Programne.
-- - - - -- - - - -- - - - -- - - - -- - - - -- - - -
- 29 -
TABLE 4.2
PLANTING PROGRAMMES FOR SYSTEM 'A' Page 1 of 2
I P R 0 G R A M M EIYear -- ----------------------------------------- -~-~~~------------------------------------~
1 1 2 1 3 1 4 1 5 1 6
1988 1
119891 I I| 1990 12x33MW ST(G) |2x33MW ST(G) |2x33MW ST(G) 12x33MW ST(G) I2x33MW ST(G) 12x33MW ST(G) I119911
|1992 |2x33MW ST(G) 12x33MW ST(G) 12x33MW ST(G) 12x33MW ST(G) |2x33MW ST(G) 12x33MW ST(G) |
11993I1111994 |1 x33MW ST(G) |1 x33MW ST(G) |1x33MW ST(G) |1x33MW ST(G) |1 x33MW ST(G) 1X33MW ST(G)|
119951
19971 1 1 I
| 1998 |1 x30MW GT(G) |1 x30MW GT(G) |1x3OMW MT(G) |1 x12OMW CC(G)11x12OMW CC(G)|1x3OMW GT(G) I| 1999 |1 x3OMW GT(G) |1x3OMW GT(G) |1 x3OMW GT(G) I I 1
1x12OMW CC(G)|
120001 1 2001 |2x30MW GT(G) j2x30MW GT(G) |1x12OMW CC(G)l I
1 2002 |1 x30MW GT(G) |1 x30MW GT(G) I |1 x12OMW CC(G)|1 x30MW GT(G) I I
| 2003 |1 x30MW GT(G) j1x30MW GT(G) I I |1 x30MW GT(G) |1 x12OMW CC(G)|
I 2004 I I |1x12OMW CC(G)| |1X12OMW CC(G)j I| 2005 |1 x30MW GT(G) 1 1x120MW CC(G)l I I1 2006 |1x30MW GT(G) |I I I
I2007 1 I | 11x3OMW GT(G) I II- -- -- I- ---- ---- -I- ---- --- -- I ---- --- - --- I---- ---- ---I--------------I
- 30 -
TABLE 4.2
PLANTING PROGRAMMES FOR SYSTEM 'A' Page 2 of 2
| P-RIO G R A M M E
Year.7 8 9 j 10 11 12
---1988----- I- - - -- - - I-- - - - - - -- - - - - - -I-- - - - - - -I-- -- - -- -1989 8 I I I I
11990 |2x33MW ST(G) I
I 1991 1 1 I 1 | 1992 j2x33MW ST(G) I
11993 1 I 1 1994 |1 x33MW ST(G) I
I 1995
1996 I111III|1997|
| 1998 1X12OMW CC(G)|1 x30MW GT(G) j1x120MW CC(G)|1 x3OMW GT(G) |1 x3OMW GT(G) |1 x30MW GT(O) I| 1999 | 1 X12OMW CC(G)| 1 x120MW CC(G)|1x3OMW GT(G) |1 x3OMW GT(O) II 2000 1 1 1 1 1 I
| 2001 | I I I |2x3OMW GT(G) J2x3OMW GT(O) I
1 2002 |1X30MW GT(G) I |1X40MW ST(O) |1 X4OMW ST(O) |1x4OMW ST(O) I
1 2003 |1 x120MW CC(G)|1 x40MW ST(O) |ix4OMW ST(O) 1x12OMU CC(G)|1 x40MW ST(O) |1 x40MW ST(O)12004 1 I I I I| 2005 1x4OMW ST(O) |lx4OMW ST(O) |1x3OMW GT(O) |1 x3OMW GT(O) |
12006 1 1 I 1
2007 lx3OMW GT(G) |lx3OMW GT(G) | |1 x3OMW GT(O) |1X3OMW GT(O)
-- ----------------I…-- ------------------I ------
- 31 -
TABLE 4.3
ENERGY GENERATION BY GAS FIRED PLANTS - SYSTEM A
I---- I… I ………………--------------…-I--------
jYear;Energy Energy Generated by Gas Fired PLants for Gas Prices ofI Demand| ------------------------- I
1(GWh) I S1/MMBTU I $2/MMBTU $3/MMBTU S4/MMBTU_| S5/MMBTU S6/MMBTU_|
GWh % of Tot.| GWh % of Tot.1 GWh % of Tot.1 GWh % of Tot.1 GWh % of Tot.1 GWh % of Tot.
11988| 4771
119891 510 1
119901 546 1 428 78.4 1 428 78.4 | 312 57.2 |
119911 584 1 428 73.3 | 428 73.3 1 340 58.2 |
119921 625 1 624 99.9 1 624 99.9 1 624 99.9 1
1199531 669 | 659 98.6 | 659 98.6 1 659 98.6 j I119'41 715 | 715 100.0 1 715 100.0 1 715 100.0 I 1
119951 765 | 765 100.0 1 765 100.0 | 765 100.0 I
819961 819 | 815 99.5 | 815 99.5 815 99.5 1
119971 876 | 851 97.1 1 851 97.1 1 851 97.1 1
119981 938 1 932 99.4 1 932 99.4 1 932 99.4 1 38 4.1 |
|19991 1003 | 1003 100.0 1 1003 100.0 1 1003 100.0 1 700 69.8 1 3 0.3 1 3 0.3 |
120001 1074 1 1074 100.0 1 1074 100.0 | 1074 100.0 1 719 67.0 1 10 0.9 I 10 0.9 1
120011 1149 1 1149 100.0 | 1149 100.0 1 1149 100.0 1 732 63.7 1 121 10.5 | 121 10.5 |
120021 1229 | 1229 100.0 1 1229 100.0 1 1229 100.0 | 737 60.0 | 78 6.3 1 78 6.3 1
120031 1315 1 1315 100.0 | 1315 100.0 | 1315 100.0 | 1261 95.9 | 44 3.3 | 44 3.3 I120041 1407 | 1407 100.0 1 1407 100.0 1 1407 100.0 1 1300 92.4 1 57 4.1 | 57 4.1 |
120051 1506 | 1506 100.0 | 1506 100.0 | 1506 100.0 | 1348 89.5 | 102 6.8 1 102 6.8 1
120061 1611 | 1611 100.0 | 1611 100.0 | 1611 100.0 1 1392 86.4 1 176 10.9 | 176 10.9 1
120071 1724 | 1724 100.0 | 1724 100.0 1 1724 100.0 1 1429 82.9 | 188 10.9 | 188 10.9 |
I- --. I-- I- I- I I !
- 32 -
TABLE 4.4
ANNUAL GAS CONSUMPTION FOR VARYING GAS PRICES
SYSTEM B
(ALL values in MMCFT)
l … l…lGas prices in $/MMBTU
-- - - - -- - - - -- - - - -- - - - -- - - - -- - - -
Year 1 2 3 4 5 6
1988 1 l1989 25371 17816 102491990 25243 23520 22504 63611991 74920 56335 145421992 73945 54107 127941993 J 76954 55619 150701994 109806 98023 164381995 i 127296 117468 178621996 j 167214 153939 166971997 149674 148387 178991998 188157 181756 186481999 211760 205094 19011 14582000 235996 229341 321732001 263823 257174 36192 79962002 302609 276506 23333 81452003 324377 313966 71322004 353473 327203 18416 38502005 376371 3600802006 417041 383202 21188 15754
2007- 440827 422179 54222017
Average IAnnual 1 160505 148691 14210 1340Value -
TotaLGas 8335305 7903501 379785 43564
Demand l
l -. … … … … …lLeastCost 2 2 20 31 52 52
Progranmml
-- - -- - - -- - - -- - - -- - - -- - - -- - - -- - -
- 33 -
TABLE 4.5
PLANTING PROGRAMMES FOR SYSTEM 'B' Page 1 of 4
| | ~~~P R 0 G R A M M EIYear1 2 3 5 6
| 1989 |1x80MW GT(G) |1x80MW GT(G) |1X80MW GT(G) |1X80MW GT(G) |1 x80MW GT(G) |1x80MW GT(G)I 1990 j1x300MW ST(G)J1x300MW ST(G)j1x300MW ST(G)|1x300MW ST(G)| 1x300MW ST(G)|1x300MW ST(G)|
| 1991 |7x70MW GT(G) j3x70MW GT(G) |2x600MW ST(G)|3x70MW GT(G) |2x600MW ST(G)| 5x7OMW GT(G)|1992 lIx600MW ST(G)|1 x600MW ST(G)| I1x600MW ST(G)| |1x42OMW CC(G)|
11993 I I I I I I
| 1994 j1x600MW ST(G)j1x600MW ST(G)| |2x7OMW GT(G) | 1x600MW ST(G)l
| 1995 j2x70MW GT(G) I |1x7OMW GT(G) |1 x600MU ST(G)| I1 1996 |2x70MW GT(G) |1 x600MW ST(G)J1x600MW ST(G)| |1x600MW ST(G)l I1 1997 |1 x600MW ST(G)| | 1 x7OMW GT(G) I |1 x42OMW CC(G)l
1 1998 |1x70MW GT(G) |1 x7OMW GT(G) |2x600MW ST(G)I2x600tMW ST(G)I2x600MW ST(G)| 3x7OMW GT(G)|19 1x600MW ST(G) 1x600MW ST(G) 1x600MW ST(G)1999 4x70MW GT(G) 1 x600MW ST(G) i2x7OMW GT(G) 1x42OMW CC(G)l
1 2000 |1 x600MW ST(G)12x7OMW GT(G) |1 x600MW ST(G)|1x600MW ST(G)|1 x600MW ST(G)|lx600MW ST(G)|
| 2001 j2x70MW GT(G) |1 X600MW ST(G)12x70MW GT(G) 12x7OMW GT(G) |1 x600MW ST(G)| 1x7OMW GT(G)|
1 2002 |1x7OMW GT(G) j2x600MW ST(G)12x600MW ST(G)|1 x70MW GT(G) 12x600MW ST(G) *** I| 2x600MW ST(G)| |2X600MW ST(G)|
1 2003 |x600MW ST(G)|1x600MW ST(G)|1 x600MW ST(G)1lx600MW ST(G)|1x600MW ST(G)l[x600MW ST(G)|
| 2004 j2x70MW GT(G) j1X600MW ST(G)12x7OMW GT(G) |2x7OMW GT(G) |1x600MW ST(G)|1x42OMW CC(G)|1x600MW ST(G) 1x600MW ST(G) 1x600MW ST(G) 1x600MW ST(G)
I 2005 3x7OMW GT(G) I 2x600MW ST(G) 3x70MW GT(G) 1x600MW ST(G) 2x7OMW GT(G)| 1x600MW ST(G)| I |lx600MW ST(G)| 11x42OMW CC(G)l
| 2006 W7X7OMW GT(G) |3x7OMW GT(G) |3x7OMW GT(G) |3x70MW GT(G) |1x600MW ST(G) 1x600MW ST(G)llx600MW ST (G) 1x600MW ST(G) 1x600MW ST(G) 6
2007 1x600MW ST(G) 10MW ST(G)jlx 600MW ST(G) 1x600MW ST(G) 1x600MW ST(G)1lx600MW ST(G)1
---------- -- I----- ------- II I-- - - -- - -I -- - - - - -
3x7OMW GT(g)1x42OMW CC(G)1x600MW ST(G)
- 34 -
TABLE 4.5
PLANTING PROGRAMMES FOR SYSTEM 'B' Page 2 of 4
I P- R 10 G R- A M M E II 10 1 20 1 30 1 40 1 50 1 60
1-1988 1 - - - - - --I-- - - -- - -I-- - - - - - -I-- - - -- - -I-- - - - - - -I-- -- - -- -1 1989 11x80MW GT(G) 11x8xMW GT(G) |1 x8OMW GT(G) 1ixBOMW GT(G) |1x8OMW GT(G) 11x8OMW GT(G) I1990 J1x300MW ST(G)1lx300MW ST(G)11x300MW ST(G) 1 X300MU ST(G) 1x300MW ST(G) 1x300MW ST(G)j
1 1991 17x7OMW GT(G) j3x7OMW GT(G) 12x6OOMW ST(C)j3x7OMW GT(G) j2x600MW ST(C)| WX7OMW GT(G)|1x600MW ST(C)lx600MW ST(C) 1X600MU ST(C) 1x42OMW CC(G)
1992JI
11993 1 1 I I 11994 j1X600MW ST(C)1lx600MW ST(C)| 12x7OMW GT(G) I I|X6OOMW ST(C)1
1 1995 12x7OMW GT(G) I j1x7OMU GT(G) 1Ix6OOMW ST(C)| I I
1 1996 12x7OMW GT(G) 11x6OGMW ST(C)1lx600MW ST(C)I 11x6OOMW ST(C)I I
1 1997 11x600MW ST(C)| I 11x7OMW GT(G) I 11x42OMW CC(G)|
1 1998 j1x7OMW GT(G) 11x7OMW GT(G) 12x6OOMW ST(C)I2X6OOMW ST(C)j2x600MW ST(C)I 3x7OMW GT(G)I1| 9 |1x600MW ST(C)1lx600MW ST(C)l I I |1x600MW ST(C)l1999 4x7OMW GT(G) jlx600MW ST(C) I12x7OMW GT(G) I 11x42OMW CC(G)
12000 |1x6OOMW ST(C)12x7OMW GT(G) j1x6OOMW ST(C)1lx600MW ST(C)1lx600MW ST(C)j1X6OOMW ST(C)|
1 2001 12x7OMl GT(G) jlx600MI ST(C)12x7OMW GT(G) j2x7OMW GT(G) 11x6OOMW ST(C)| 1x7OMW GT(G)|1 2002 j1x7OMW GT(G) 12x6OMW ST(C)M2X6OOMW ST(C)I1 x7OMW GT(G) 12x6OOMW ST(C)| I
2x600MW ST(C) 2X600MW ST(C)TI2003 1x600MW ST(C) 1X600MW ST(C)IlX600MW ST(C)lX600MW ST(C 1X600MW ST(C)1x600MW ST(C)
1 2004 f2x7OMW GT(G) 11x6O0MW ST(C)I2x7OMW GT(G) 12x7OMW GT(G) 11x6OOMW ST(C)1lx420MW CC(G)|| 11x600MU ST(C)§ 11x600MW ST(C)1lx600MW ST(C)l 1x600MW ST(C)l
| 2005 |3x7OMW GT(G) I |2x6OOMW ST(C)13x7OMW GT(G) j1x60OMW ST(C)l 2x7OMW GT(G)I1x600MW ST(C)j I 11x600MW ST(C)i lx42OMW CC(G)l
2006 7x7OMW GT(G) 13x7OMW GT(G) j3x70MW GT(G) 3x7OMW GT(G) 11x600MW ST(C)I1x6OOMW ST(C)|1x600MU ST(C)W 1X600MW ST(C)M Cx600MW ST(C)j10x6TOM( ST(C)lI
2007 11x6OMW ST(Qlx600MW ST(C)1 lx600MW ST(C) Sx600MW ST(C)|
3x7OMW GT(g)1x420MW CC(G)1x600MW ST(G)
- 35 -
TABLE 4.5
PLANTING PROGRAMMES FOR SYSTEM 'B' Page 3 of 4
P R 0 G R A M M EYear
I 11 I 21 I 31 I 41 I 51 I 61
1 988 - I- - I I -I
1 1989 |1 x80MW GT(G) j1x8OMW GTt(G) j1x80MW GT(G) |1 x8OMW GT(G) |1 x80MW GT(G) l1x8GMW GT(G) I1 1990 1 I I I I I 1 1991 |7x70MW GT(G) |3x70MW GT(G) |2x600MW ST(C)13x7OMW GT(G) |2x600MW ST(C)j 5x7OMW GT(G)|| '1x6OOMW ST(C)lx600MW ST(C)l I'60MW ST(C)' |1x420MU CC(G)'1992 ( 1 160Wjx2M
1 1993 1 1 1 1 1 I| 1994 j1x600MW ST(C)jlx600MW ST(C)1 12x70MW GT(G) I |1 x600MW ST(C)j
1 1995 12x70MW GT(G) I |1x7OMU GT(G) |1x600MW ST(C)| I| 1996 2x7OMW GT(G) |1 x600MW ST(C)jlx600MW ST(C)| |1x600MW ST(C)1 I| 1997 lx600MW ST(C)| I |1 x70MW GT(G) I |1 x420MW CC(G)|
| 1998 |1 x7OMW GT(G) |1 x7OMW GT(G) 12x600MW ST(C)12x600MW ST(C)j2x600MW ST(C)1 3x7OMW GT(G)|I I1X600MW ST(C)|lx600MW ST(C) I 1x600MW ST(C)l| 1999 |4x7OMW GT(G) lx600MW ST(C)I 12x70MW GT(G) I |1x42OMW CC(G)
| 2000 |1 x600MW ST(C)12x7OMW GT(G) |1X600MW STCC)11x600MW ST(C)llx600MW ST(C)j1x600MW ST(C)1
| 2001 |2x7OMW GT(G) |1 x600MW ST(C)12x70MW GT(G) 12x70MW GT(G) |1 x600MW ST(C)j lx7OMW GT(G)|
| 2002 |1 x7OMW GT(G) |2x600MU ST(C)12x600MW ST(C)1 lx7OMW GT(G) 12x600MW ST(C)1 I| |2x600MW ST(C)| |2x600MW ST(C)l 1 62003 x. SC600MW S x WT)6 TC600MW ST(C)llx600MW ST(C)l
| 2004 |2x7OMW GT(G) |1 x600MW ST(C)|2x7OMW GT(G) 12x7OMW GT(G) |1 x600MW ST(C)j1x420MW CC(G)lI 1x600MW ST(C) lx600MW ST(C) 1x600MW ST(C) 1x600MW ST(C)
2005 3x7OMW GT(G) I 2x600MW ST(C) 3x7OMU GT(G) 1x600MW ST(C) 2x7OMW GT(G) j1x600MW ST(C)l | 1x600MW ST(C)l |1x420MW CC(G)j
| 2006 |7x7OMW GT(G) I3x7OMW GT(G) |3x70MW GT(G) |3x7OMW GT(G) |1x600MW ST(C)|1x600MW ST(C)l
1 2 1X600MW ST(C)|1x600MW ST(C)| jlx600MW ST(C) M I|2007 |1X600MU ST(C)|lx600MST(C)1 lx600MW ST(C)llx6O0MW ST(C)l
3x7OMW GT(g)lx42OMW CC(G)lx600MW ST(G)
- 36 -
TABLE 4.5
PLANTING PROGRAMMES FOR SYSTEM 'S' Page 4 of 4
|I|-P- R- O- G-R A M M E
Yer-----1-------!---------------------2-------------4--------!---------------!--------------1 Yer 1 -- 1 22 1 32 1 42 1 52 1
| 1988 |1x8OMW GT(O) j1x80MW GT(O) |1x80MW GT(O) 1x80#MW GT(O) 1lx80MW GT(O) I I11989 1 1 I
11990 I I I 1 1991 |7x70MW GT(O) j3x70MW GT(O) 12x600MW ST(C)j3x70MU GT(O) 12x600MW ST(C)( I|1992 J x600MW j ST(C)1 J1x600MW ST(C)| S
1 1993
1 1994 |1 x600MW ST(C)j1x600MW ST(C)| 12x70MW GT(O) I 1| 1995 12x70MW GT(O) I |1x7OMW GT(O) |1x600MW ST(C)|
1 1996 j2x70MW GT(0) |1 x600MW ST(C)f1x600MW ST(C)| |1x600MW ST(C)| II I11 1997 1
1x600MW ST(C)| | |1 x7OMW GT(O) I I
| 1998 j1x7DMW GT(O) j1x70MW GT(O) |2x600MW ST(C)|2x600MW ST(C)j2x600MW ST(C)| II l1x600MW ST(C)|1x600MW ST(C)| I Ii 1999 |4x70MW GT(O) |1x600MW ST(C)l |2x70MW GT(O) I
1 2000 |1 x600MW ST(C)12x70MW GT(O) |1 x600MW ST(C)|1x600MW ST(C)|lx600MW ST(C)| I200 1270M fl600W I(CI2xIMWII
1 2001 j2x7OMW GT(0) |1x600MU ST(C)12x7OMW GT(O) '2x70MW GT(O) 11x600MW ST(C)I
1 2002 |1x7OMW GT(O) j2x600MW ST(C)12x600MW ST(C)|lx70MW GT(O) 12x600MW ST(C)|I 2x600MW ST(C) j2x600MW ST(C)| 2003 1x600MW ST(C) 1x600MW ST(C)I1x600MW ST(C)I1x600MW ST(C) lx600MW ST(C)I
1 2004 12x7OMW GT(O) j1x60OMW ST(C)12x70MW GT(O) 12x70MW GT(O) |1 x600MW ST(C)| II j1x600MW ST(C) 1x600MW ST(C)jlx600MW ST(C)|| 2005 |3x70MW GT(O) I 12x600MW ST(C)13x7OMW GT(O) I1x600MW ST(C)|
1lx600MU ST(C)l 1x600MW ST(C)l2006 7x70MW GT(O) j3x70MW GT(O) 13x70MW GT(O) 13x70MW GT(O) 1lx600MW ST(C)l
0 1x600MU QMW S T(C) lx6OOMW ST(C)|2007 1x600MW ST(C) 1x600MW ST(C)j1x600MW ST(C)llx600MW ST(C)|1x600MW ST(C)|
Gas--- -- - I-- - - -- - -I-- - - -- - -I-- - - -- - -I-- - - -- - -I -- - - - - -Note : Gas Turbines commissioned in 1988 are committed items of plant which were
assumed to be converted to gas firing in other programmes.
- 37 -
TABLE 4.6
ENERGY GENERATION BY GAS FIRED PLANTS - SYSTEM B
------I- - -- - -- - -- - - -- - -- - -- - -- --…- -
IYear Energy Energy Generated by Gas Fired Plants for Gas Prices of II |Demanid|----------------------------------------------------------------------------------------------- I1 | ~(Gwh) SI/MMBTU I S2/MMBTU__ S3/MMBTU i S4/MMBTU_ | 5/MMBTU I S6/MMBTU_|
jj - [| GWh % of Tot.1 GWh % of Tot.1 GWh % of Tot.1 GWh % of Tot.1 GWh % of Tot.1 GWh % of Tot.
|11988114754 | 11989115786 | 544 3.4 1 1926 12.2 | 1622 10.3 | I I11S90116892 1 2437 14.4 | 2291 13.6 1 2247 13.3 1 458 2.7 1
|1991118074 1 7429 41.1 | 9457 52.3 1
11992119339 | 7268 37.6 | 8985 46.5 |
11993120693 | 7538 36.4 19011 43.5 | 1054 5.1 1
11993122141 111101 50.1 | 8854 40.0 1777 8.0 |
11994123691 112459 52.6 1 9510 40.1 1 1931 8.2 |
11995125350 116774 66.2 112823 50.6 1 1805 7.1 1
|1996127124 115427 56.9 113158 48.5 1 1935 7.1 1
11997129023 119447 67.0 119921 68.6 | 1737 6.0 |
I11,98131054 122175 71.4 119411 62.5 | 1743 5.6 | 36 0.1 I
11999133228 124446 73.6 124159 72.7 | 1612 4.9 1
12000135554 127392 77.0 126572 74.7 1439 4.0 9 112 0.3 |
12001138043 132075 84.3 129374 77.2 | 721 1.9 |
12002140706 135364 86.9 131806 78.1 |
12003143555 138072 87.4 134440 79.1 1
12004146604 140972 87.9 136898 79.2 1 1
12005149867 144271 88.8 140535 81.3 112006153357 147857 89.7 145192 84.7 | |
.I I--
- 38 -
TABLE 4.7
ANNUAL GAS CONSUMPTION FOR VARYING GAS PRICES
SYSTEM C
(All values in MMCFT)
ll-- ---Gas prices in S/MMBTU
-- - - - -- - - - -- - - - -- - - - -- - - - -- - - -Year 1 2 3 4 5 6
-- -- - I - - - - - - - - - - - - - - - ---- ----- --- --- ---
1988 I 37380 36188 36188 753 l1989 40757 38987 38987 12601990 44136 41315 41315 821991 45103 44288 44288 3561992 49172 47799 47799 15611993 53332 51428 51428 26971994 58086 54512 54512 1123 1123 1995 60000 58674 58674 2341 23411996 64174 62119 62119 397 3971997 69774 66761 66761 1383 1369 6369
1998 1 76668 71957 71957 3327 3327 33271999 I 80059 77849 77849 7544 7544 75442000 85713 82089 82089 2875 2875 28752001 90895 87729 87729 3655 3655 36552002 111491 95522 95522 10391 10391 1039120031 104165 102222 102222 11131 11131 11131200 1149109 0249 12910 12910 129102005 119932 117941 117941 12746 12746 12746 2006 |132435 127461 127461 13814 13814 13814|
|2007- |138483 134603 134603 17579 17579 175792012
AverageAnnuat 70829 68037 68037 4555 4075 3880Valuel
|Total|l| Gas 2961420 2855719 2855719 283712 276990 273130|
|Demand|l
LeastllCost 0 1 4 4 7 11 11
Programme114830-110249-110249-12910- 12910- 12910--
- 39 -
TABLE 4.8
PLANTING PROGRAMMES FOR SYSTEM 'C' Page 1 of 3
Year P R 0 G R A M M E S i
1 1 2 1 3 1 4 .
1988 (1) I (1) 1 (2) 1 (2)
1989 1x5OMW GT(G) l 1x5OMW GT(G) W 1x50MW GT(G) 1x5OMW GT(G)
1990 1x5OMV GT(G) 1x5OMW GT(G) 11x2001M ST(G) 11x200MW ST(G)
1991 j1x200MW ST(G) 11x200MW ST(G) I11992 1 11993 1x5OMW GT(G) 1x5OMW GT(G) 11x200W ST(G) MW GT(G)
1994 1x50MW GT(G) | 1x50MW GT(G) WO1x200M W ST(G)
1995 11x200MW ST(G) W1 X200MW ST(G) j1x200MW ST(G)
1996 WO l1x20W ST(G)
119976 2x50MW GT(G) 2x50MW GT(G) x200MW ST(G)
1998 2x50MW GT(G) G1x200MW ST(G) 1x5OMW GT(G)
1999 1x50MW GT(G) |WO 2x50MW GT(G) 3x5OMW GT(G)
|1X200MW ST(G) M ST(G)
2000 5x5OMW GT(G) 3x5OW GT(G) 3x5OMW GT(G) 2x5OMW GT(G)1lx200MW ST(G) l1x200MW ST(G) llx200MW ST(G) |
2001 j1x200MW ST(G) 2x5OMW GT(G) I1x200MW ST(G) |1x200MW ST(G)
2002 1x5OMW GT(G) 3x5OMW GT(G) 1x5OMW GT(G) 2x5OMW GT(G)
2003 i 9x50MW GT(G) | 9x50MW GT(G) |8x5OMW GT(G) | 8x5OMW GT(G)| 1x200MW ST(G) |1x200MU ST(G)|
2004 |3x50MW GT(G) |3x50MW GT(G) |1x200MW ST(G) |1x200MW ST(G)
2005 | 1x5OMW GT(G) 1x50MW GT(G) j 3x50MW GT(G) j 3x5OMW GT(G)| W1X00W ST(G) |1X200MW ST(G) I I
| 2006 | 3x50MW GT(G) |1 x200MW ST(G) |1x200MW ST(G) |1x200MW ST(G)
2007 j1x200MW ST(G) |1 x200MW ST(G) 11x200MW ST(G) |1x200MW ST(G)
I…- -.-. …- - -
(1) (2)9x5OMU GT(G) 5x5OMW GT(G)
3x200W W ST(G) 4X200MW ST(G)
- 40 -
TABLE 4.8
PLANTING PROGRAMMES FOR SYSTEM 'C' Page 2 of 3
-- --- -- -- -- -- -- - -- -- -- -- -
Year P R O G R A M M E S |
I- I | 5 1 6 1 7 1 8
1988 (3) J (3) (4) (3)
1989 11x200MW ST(C) |1 x200MW ST(C) I1x5OMW GT(G) 1x50MW GT(G)
1990 W O1x200MW ST(C) 11x200MW ST(C)
119911 1992 1x50MW GT(G) |1 x200MW ST(C) I
1993 |1 x200MW ST(C) I 2x5OMW GT(G) 2x50MW GT(G)
1994 1 1x200MW ST(C) W1x200MW ST(C) W1x200MW ST(C)
1995 1x5OMW GT(G) I M G C
1996 |1x200MW ST(C) I 1x50MW GT(G) |1x200MW ST(C) 1x200MW ST(C)
1997 O |1x200MW ST(C) j I19981 WW GT(G) I1 1x5OMW GT(G) 1x5OMW GT(G)
1999 |1x200MU ST(C) |1 x200MW ST(C) I3x5OMW GT(G) j 3x5OMW GT(G)
2000 I1x200MW ST(C) 1x50MW GT(G) 2x5OMW GT(G) 2x5OMW GT(G)1x200MW ST(O) 1x200MW ST(O) 1x200MW ST(C) 1x200MW ST(C)
2001 O |1x200MW ST(C) |1 x200MW ST(C) |1x200MW ST(O)
2002 |1x200MW ST(C) I1x5OMW GT(G) 2x5OMW GT(G) 2x5OMW GT(G)
2003 | 7x50MW GT(G) | 5x50MW GT(G) | 8x5OMW GT(G) 8x5MW GT(G)2003 GT(G)j |1x200MW ST(C) T
2004 j1x200MW ST(C) |1x200MMW1 ST(C) jx200MW ST(C)
2005 | 3x5OMW GT(G) 2x5OMW GT(G) | 3x5OMW GT(G) 3x50MW GT(G) |
2006 j1x200MW ST(C) 11x200MW ST(C) 11x200MW ST(C) 1x200MW ST(C)
2007 |lx200MW ST(C) I1 x200MW ST(C) |1x200MW ST(C) |1x200MW ST(C)
(3) (4)5x5OMW GT(G) 5x5OMW GT(G)
3x200MW ST(C) 4x200MW ST(C)1x2OOMW ST(O)
- 41 -
TABLE 4.8
PLANTING PROGRAMMES FOR SYSTEM IC' Page 3 of 3
I ---- -- - - -- - - - -- - - -- -I-
Yr P R O G R A M M E S |Year l-----------------------------------------------------------
… I 9 I 10 I 11 1 12
1988 (5) | 1 STC (6) | (5)
| 1989 |1 x200MW ST(C) |1 x200MW ST(C) I1x5OMW GT(O) 1x5OMW GT(O)
1990 11x200MW ST(C) 11x200MW ST(C)
1 1991 T I .11992 1x50MU GT(O) |1 x200MW ST(C)
| 1993 |1 x200MW ST(C) I I2x5OMW GT(O) | 2x5OMW GT(O)
1994 | 1lx200MW ST(C) |1x200MW ST(C) |1x20OMW ST(C)
1995 1 1x5OMW GT(O) I G T T
| 1996 |1 x200MW ST(C) 1x50MW GT(O) |1x200MW ST(C) lx200MW ST(C)
1997 | 11x200MW ST(C) |
|1998 1 2x5OMW GT(0) | T 1x5OMW GT(O) 1x50MW GT(O)
| 1999 |1 x200MW ST(C) |1 x200MW ST(C) I3x5OMW GT(O) J 3x50MW GT(O)2000 11x200MW ST(C) x50MU GT(O)i 2x5OMW GT(O) 2x50MW GT(O)
| 1x200MW ST(O) |1x200MW ST(O) |lx200MW ST(C) 1x200MW ST(C)2001 | 1lx200MW ST(C) 1x200MW ST(C) 11x200MW ST(O)
2002 |1x200MW ST(C) I1x5OMW GT(O) 2x5OMW GT(O) 2x5OMW GT(O)
2003 | 7x5OMW GT(O) I 5x5OMW GT(O) 8x5OMW GT(O) 8x5OMW GT(O) ||1x200MW ST(C)|j
2004 11x200MW ST(C) 11x200MW ST(C) j1x200MW ST(C) lx200MW ST(C)
2005 | 3x5OMW GT(O) I 2x5OMW GT(O) 3x50MW GT(O) 3x50MW GT(O)
2006 |1 x200MW ST(C) j1x200MW ST(C) |1 x200MW ST(C) I1x200MW ST(C)
2007 |1 x200MW ST(C) |1 x200MW ST(C) |1 x200MW ST(C) I1x200MW ST(C)
-…- …-
(5) (6)5x50MU GT(O) 5x5OMW GT(O)3x200MW ST(C) 4x2OOMW ST(C)1x200MW ST(O)
- 42 -
TABLE 4.9
ENERGY GENERATION BY GAS FIRED PLANTS - SYSTEM C
-----I--- - -- -- - -- - -- -- - -- -- - -- -- - -- -
{Year Energy Energy Generated by Gas Fired PLants for Gas Prices ofI |Demandi----------------------------------------------------------------------------------------------- I
| (GWh) I $1/MMSTU I $2/MMBTU $3/MMBTU $4/MMBTU $5/MMBTU $6/MMBTU
GWh X of Tot.1 GWh % of Tot.I GWh % of Tot.1 GWh % of Tot.1 GWh X of Tot.1 GWh % of Tot.
119881 3817 |3817 100.0 | 3817 100.0 | 3817 100.0 | 55 1.4 |
119891 4084 | 4084 100.0 1 4084 100.0 1 4084 100.0 1 92 2.3 |
119901 4370 1 4370 100.0 J 4370 100.0 | 4370 100.0 i 6 0.1 |
119911 4676 | 4676 100.0 | 4676 100.0 |4676 100.0 | 26 0.6 |
119921 5003 | 5003 100.0 | 5003 100.0 J 5003 100.0 1 114 2.3 J
119931 5354 |5354 100.0 1 5354 100.0 | 5354 100.0 1 197 3.7 1
119941 5728 1 5728 100.0 1 5728 100.0 1 5728 100.0 1 82 1.4 1 82 1.4
119951 6129 |6129 100.0 | 6129 100.0 1 6129 100.0 1 171 2.8 | 171 2.8 |
119961 6558 1 6558 100.0 6558 100.0 6558 100.0 1 29 0.4 1 29 0.4
119971 7017 1 7017 100.0 7017 100.0 7017 100.0 I 101 1.4 I 101 1.4 1 101 1.4
119981 7509 17509 100.0 7509 100.0 1 7509 100.0 1 243 3.2 1 243 3.2 1 243 3.2
119991 8034 1 8034 100.0 8034 100.0 8034 100.0 | 551 6.9 | 551 6.9 | 551 6.9
120001 8597 | 8597 100.0 | 8597 100.0 8597 100.0 | 210 2.4 | 210 2.4 2 210 2.4
|20011 9198 1 9198 100.0 | 9198 100.0 | 9198 100.0 | 267 2.9 | 267 2.9 | 267 2.9
20021 9842 1 9842 100.0 19842 100.0 I 9842 100.0 759 7.7 759 7.7! 759 7.7
2003110531 110531 100.0 110531 100.0 110531 100.0 1 813 7.7 1 813 7.7 1 813 7.7
12004111268 111268 100.0 111268 100.0 111268 100.0 1 943 8.4 1 943 8.4 1 943 8.4
12005112057 112057 100.0 112057 100.0 112057 100.0 931 7.7 | 931 7.7 | 931 7.7
12006112901 112901 100.0 12901 100.0 |12901 100.0 | 1009 7.8 | 1009 7.8 | 1009 7.8
2007113804 113804 100.0 113804 100.0 113804 100.0 1284 9.3 | 1284 9.3 1284 9.3
I I - -I- -- ---l~~~- - - - - - - --------------------------------------------------------------------..............
- 43 -
TABLE 4.10
COMPARISON BETWEEN ANNUAL DISCOUNTED AVERAGE GAS CONSUMPTIONS
CALCULATED IN NOVEMBER 1982 REPORT AND CURRENT VALUES
(Current Prices)
| System Report 2 Gas Price in S/MMBTU li | 1 ~~~1 2 3 4 5 6 7 8 9
A November 8.3 8.1 3.3 0.4Current 9.2 9.2 8.5 3.2 0.5 0.5
| INovemberl 156.0 13.7 13.5 12.6 0.7 0.7 |If iCurrent 160.5 148.7 14.2 1.3 0.0 0.0
I C iNovemberl 70.1 69.2 2.5 1.8 0.3 0.3 |Current 70.8 68.0 68.0 4.6 4.0 3.9
Not A l---- ---- --es in BiLlon-Cub-c-Feet---r--n
Note : All values in Billion Cubic Feet per annum
GAS DEMAND CURVE FOR SYSTEM A7,-
6-
5 -D -
m~~~~~~~~~~~~~~~
.'0 3 - __ 2- l
2 - _X 0~~~~~~~~~~~~~~
0 2 4 6 8 10
Average ainnual discounted consumption in Billion Cu Ft
UNDISCOUNTED GAS DEMAND C URVEFOR SYSTEM A
7 -
6 -
2 Z~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~T4 -
0 - l l l l
0 0.1 0.2 0.3 0.4
Total gas consumption in Trillion Cu Ft
ANNUAL GAS CONSUMPTION FOR LEAST COSTPROGRAMMES - SYSTEM A
22 -
20-
18- >
1 6
14 -99
Yecr~~~~~~~~~~~~~~c
12
Fo ~10
o ~8
o ~~6
4
2
01988 1991 1994 1997 2000 2003 2006
YeairI $I/MMBTU + $2/MMBTU 0 $3/mmBTU A S4/MMBTU X S5/MMBTU V $6/MMBTLU
GAS DEMAND CURVE FOR SYSTE M A1990
7 -
6 A
- l
4
m
3
0 2
1
G;as consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM A1995
7 -
6t
5
m~~~~~~~~~~~~~~~~
1~~~~~~~~~~~~~~~~~~~~~~~~~~~~P
o~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~(T .,Il,
C,)
2
0 2 4 6 8
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM A2000
7-
6
56 -
20~~~~~~~~~~~~~~
0 2 4 6 8 10 12
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM A2005
7 -
6 0
5
5 -
2 - ~ ~ ~ ~ ~ ~ ~ ~ ~~I-
XN 4- G
c) v - .'
0~~0
2
1 3 5 7 9 1 1 13 15 17 19
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM B7 -
6
5,;;
4
C ~~~~~~~~~~~~~~m
3 co
2
1
0 20 40 60 80 100 120 140 160
Average annual discounted consumption in Billion Cu Ft
UNDISCOUNTED GAS DEMAND CURVEFOR SYSTEM B
7-
6 A
5 A
[TI
(9~~~~~~~~ 4 6
Totail gas consumption in Trillion Cu Ft
ANNUAL GAS CONSUMPTION FOR LEAST COSTPROGRAMMES - SYSTEM B
450 -
400-
350 -
I-C-)
5 300
5~~~~~~~~~~~~~~~
250
_2 ,
1 200
0 0
V) 150
100
50
0-1988 1991 1994 1997 2000 2003 2006
Year* 51/MMBTU + S2/MMBTU 0 S3/MMBTU A $4/MMBTU X Ss/MMBTU V $6/MMBTU
GAS DEMAND CURVE FOR SYSTEM B1990
7-
6 A
5
m t m
A) 3-I
0 4 8 12 16 20 24
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM B1995
7 -
6
5
+,, ~4 *Am m
.'> ~~3 . -n2~~~~~~~~~~~~~~
0 -s0
0 20 40 60 80 100 120
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM B2000
7 -_
6 -1l
5 Al
m | c~~~~~~~~~~~~~~4 - .C~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~C
m
U@ 37
0
2
O -| 1 1- 1 1 I I I I I0 40 80 120 160 200 240
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM B2005
7 -
I-~~5 1
4 4
m
3 I .0n
2
0-0 100 200 300 400
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM C7 -
6-
5-
2-
mU) 4P-
Q-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-
Vj)
2
20 40 60 80
Average annucl discounted consumption in Billion Cu Ft
UNDISCOUNTED GAS DEMAND CURVEFOR SYSTEM C
7 -
6 -
:D
I-- 4 X_ r
co
2-
0.4 0.8 1.2 1.6 2 2.4 2.8
Total gas consumption in Trillion Cu Ft
ANNUAL GAS CONSUMPTION FOR LEAST COSTPROGRAMMES - SYSTEM C
140 -
130 -
120 -
110 _
H 100
90 -
80 -Ye:r
70 - m
o~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~o
o50
0 ~40-
30-
20-
1 0
1988 1991 1994 1997 2000 2003 2006
Yea rU S1/mmBTu 4- $2/M?vOTO $3/MME)TU t $4/mmBTu X $5/mmBTu V $6/M?BTU
GAS DEMAND CURVE FOR SYSTEM C1990
7 -
6-
I-~~4
m~~~~~~~~~~~~~~~~4 5
_ _
2
1-
0-~ ~ - 1' -I I I X I
0 1 0 20 30 40
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM C1995
7-
6 _
5 _
m
0
2-
0 20 40 60
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM C2000
7 -
6 _
5
I--T
4
m4P.
2
1 \
0-0 20 40 60 80
Gas consumption in Billion Cu Ft
GAS DEMAND CURVE FOR SYSTEM C2005
7-
6-
5 - 1
u. 4 I
1
2 -~ ~ ~ ~~~~~~~~~~~~~~~~~~~~~~~2
0 l 0 -
1 0 30 50 70 90 11 0
Gas consumption in 13illion Cu Ft
COMPARISON BETWEEN NOVEMBER 1982 REPORT ANDCURRENT DEMAND CURVE - SYSTEM A
13 -
12 -
11 1
10
I-3 I_ii
82
O-~~~ , , I Il l
7 ~
6
0~~
0 2 4 6 8Annual discounted consumption in Billion Cu Ft
O Current + November 1982 Report O November 1982 Report
(1988 $) (1982 $) (1988 $)
COMPARISON BETWEEN NOVEMBER 1982 REPORT ANDCURRENT DEMAND CURVE - SYSTEM B13 -i
12
11
10
8 -T.
7
_ ~ 20 406 010 121 016
a) 5
(198 $) I92$)(98$
2
1
0 20 40 60 80 100 120 140 160Annual discounted consumption in Billion Cu Ft
o Current + November 1982 Report November 1982 Report(1988 $) (1982 $) (1988 $)
COMPARISON BETWEEN NOVEMBER 1982 REPORT ANDCURRENT DEMAND CURVE - SYSTEM C
13 -
12
11
10
8 T
7 ;
6 -
4+
3 I
2
1
0 - I I I I I.
0 20 40 60 80
Annual discounted consumption in Billion Cu Ft
0 Current + November 1982 Report o November 1982 Report
(1988 $) (1982 $) (1988 $)
APPENDIX A
BASIC DATA AND ASSUMPTIONS
- 70 -
TABLE A.1
INHERITED PLANT MIX
|Generating PLant Type | System
I---A B c (1)
Steam - oil fired I 5x33MW 1x 30MW2x 75MW1x 87MW2x200MW3x300MW
Isteam- ;;ignite fired | 3x 75MWI | 3x 20MW
Gas Turbine - distilLate fired 234MW (so)…----------------------------- - -----------------------------------
Diesel 70MW (so) 34MW (so)
Hydro 1269MW
Note:(1) Effective inherited pLant mix for System C changed
for each gas price scenario
- 71 -
TABLE A.2
ASSUMED RETIREMENT DATES FOR INHERITED PLANT - SYSTEM B
Year 1it fired Lignite Gas DieselsSteam fired Turbines
I I Steam
I I1989 1 34MW
19901 2x 75MW 154MW ll x 87HWl
1991
1992k
1993(
1994 3x 20MW
1995 l
1996 l
1997
1998
19991
2000 |x200MW
2001 1x300MW
2002 |x300MW l
20031
2004 1x300MW 80MW 12005| 1x300MW l
l l- , …l
- 72 -
TABLE A.3
COMMITTED PLANT - SYSTEM B
Year- -- - - - - - - Ptant --- - - - -- -
1989 |4x 20MW GTj|x 72MW Hydro (209 GWh)l_11x 71MW Steam Residual fuel oil.
1990 1x133MW Hydro (200 GWh)lx 38MW Hydro (150 GWh)
i-- - - -- - - - -------- I- - - - -- - - - -
19911
1992 j1x300MW Hydra (806 GWh)1x 12MW Hydro ( 13 GWh)
11x150MW Steam Lignite
1993 l1x18oMW Hydro (406 GWh) I1x 9MW Hydro ( 9 GWh)1x150MW Steam Lignite-- - - -- - - -- - - -- - - -- - - -
TABLE A.4
ASSUMED PLANT CHARACTERISTICS Page 1 of 5
|Plant Type Unit MW Capacity Max. Average Variable Fixed Total Phased capital cost (X) ISpecific INo Name- Sent Avail Heat 0 & M 0 & M Capital YC-3 YC-2 YC-1 YC YC+1 Capital |
pLate out (X) Rate Cost CostIkcalkWh I$/MWh IS x 1000 $ miLlionl I S/kW
Steam - 1 33.0 30.9 87 2908 1.00 5277 -
oil 2+ 33.0 30.9 87 2908 1.00 0 - - - - -
I 40.0 37.5 87 2887 0.95 2707 59.88 15.8 50.6 22.8 5.8 5.0 15972+ 40.0 37.5 87 2887 0.95 675 37.43 10.0 20.0 45.0 20.0 5.0 998
1 60.0 56.4 87 2698 0.95 3185 79.16 15.8 50.6 22.8 5.8 5.0 1 14032+ 60.0 56.41 871 26981 0.95 864 49.97 10.0 20.0 45.0 20.0 5.01 886
1 100.0 94.0 87 2625 0.84 3549 | 112.74 15.8 50.6 22.8 5.8 5.0 | 11992+| 100.0 94.0 87 2625 0.84 1085 72.74 10.0 20.0 45.0 20.0 5.0 774
1| 150.0 141.0 1 87 1 2467 | 0.80 | 4124 | 156.73 15.8 50.6 22.8 5.8 5.0 | 1112 |I I 2+1 150.0 141.0 87 2467 1 0.80 1242 96.38 10.0 20.0 45.0 20.0 5.0 684
1 200.0 188.0 85 I 23621 0.77| 4567 194.48 15.8 50.6 22.8 5.8 5.0 I 10342+ 200.0 188.0 85 2362 0.77 1407 I 119.55 10.0 20.0 45.0 20.0 5.0 636
1 300.0 282.0 85 | 2331 0.73 | 5247 265.84 15.8 50.6 22.8 5.8 5.0 943s 1 2+1 300.0 282.01 851 2331 0.73 1717 163.45 10.0 20.0 45.0 20.0 5.01 580
1 400.0 377.0 80 2310 0.69 5901 333.33 15.8 50.6 22.8 5.8 5.0 I 8842+ 400.0 377.0 80 2310 0.69 2012 205.06 10.0 20.0 45.0 20.0 5.0 544
1 500.0 472.0 80 2294 0.66 6534 | 397.971 15.8 50.6 22.8 5.8 5.0 | 843 |I I 2+ 500.0 472.0 80 2294 0.66 2294 1 244.82 10.0 20.0 45.0 20.0 5.0 1 519
II 1+ I 600.0 567.0 80 I 2284 0.63 7151 I 460.32 I 15.8 50.6 22.8 5.8 5.0 i 812ii 2+ |600.0 567.0 80 2284 0.63 2565 283.14 I 10.0 20.0 45.0 20.0 5.0 499
1 2+ - - - - - - - --- -
TABLE A.4
ASSUMED PLANT CHARACTERISTICS Page 2 of 5
… i I …I… I I I… -I … I|Ptant Type Unit MW Capacity i Max. Average |Variable I Fixed Total Phased capital cost (%) |Specific
No Name- Sent Avail Heat 0 & N 0 O & M Capital YC-3 YC-2 YC-1 YC YC+1 I Capital II l | plate out (X) Rate Cost Costl l l l I~~~~~~~I kca l/kWh $ /MWh 1$ x 1000 1$ millioni $ /kW I
Steam - 1 150.0 140.0 85 2664 0.95 5156 216.07 15.8 50.6 22.8 5.8 5.0 1543coal 2+ 150.0 140.0 85 2664 0.95 1458 115.69 10.0 20.0 45.0 20.0 5.0 826
If iredI II1 200.0 187.0 83 2450 0.90 5670 I 263.98 I 15.8 50.6 22.8 5.8 5.0 14122+ | 200.0 187.0 83 I 2450 0.90 1654 143.43 10.0 20.0 45.0 20.0 5.0 767
1 300.0 280.0 I 83 I 24171 0.86 6489 I 354.78 I 15.8 50.6 22.8 5.8 5.0 1 12672+ 300.0 280.0 83 2417 0.86 2028 196.20 10.0 20.0 45.0 20.0 5.0 701
j1 400.0 375.01 78 2395 0.82 I 7274 I 440.87 15.8 50.6 22.8 5.8 5.0 I 11762+1 400.0 375.0 78 2395 0.82 2381 246.10 10.0 20.0 45.0 20.0 5.0 656
1 500.0 469.0 | 78 2378 0.80 1 8035 523.67 | 15.8 50.6 22.8 5.8 5.0 | 11172+ 500.0 469.0 78 2378 0.80 2718 293.72 10.0 20.0 45.0 20.0 5.0 1 626
1 I 600.0 564.01 78 2367 1 0.771 87781 603.601 15.8 50.6 22.8 5.8 5.0 10702+ 600.0 564.0 78 2367 I 0.77 3044 339.77 10.0 20.0 45.0 20.0 5.0 602
I--- . I. I . I. . . .- I. . I. I.
TABLE A.4
ASSUMED PLANT CHARACTERISTICS Page 3 of 5
I… …I… … … I… …I … I … I… …I … I …………… I…-------------IPlant Type Unit MW Capacity Max. Average iVariable I Fixed TotaL Phased capitat cost (%) SpecificI ~~~~No j Name- Sent Avail Heat 0 & N 0 & N Capitat YC-3 YC-2 YC-1 YC YC+1 Capitat pLate out % Rate Cost Cst kctkW /MWh Itx 1000 ISmCsf" k,/W to $/kW
-I I--I~~~~------UtLignite 2+ 20.0 180 8 13 1.62 I 20251
I I 1 J~~ 150.0 141.01 831 27731 1.081 12421 -I-~~~~2+_l150.0 141.0_ 831 27731 i.08.1 12421
TABLE A.4
ASSUMED PLANT CHARACTERISTICS Page 4 of 5
|Ptant Type f Unit MW Capacity Max. Average IVariable Fixed Total Phased capital cost () iSpecific INo Name- Sent | Avail Heat 0 & M 0 O & M Capital I YC-3 YC-2 YC-1 YC YC+1 Capital |
plate out (X) Rate I Cost Cost Ikcal/kWh S/MWh 1$ x 1000 S million| $/kW
1Comb. Cycle1 I - 90.0 87.0 - 80 2250 2.67 1 2749 82.16 10.0 35.0 38.0 13.0 4.0 - 944distillate/ 2+ 90.0 87.0 1 80 2250 2.67 937 62.01 - 40.0 40.0 15.0 5.0 I 713jgas fired I I i
I I 120.0 116.01 80 2240 2.67 ; 2749 109.85 10.0 35.0 38.0 13.0 4.0 9472+ 210.0 116.0 80 2240 2.67 937 83.46 - 40.0 40.0 15.0 5.0 719 ;
t 150.0 145.0| 80 1 2230 | 2.28 3345 120.38 10.0 35.0 38.0 13.0 4.0 8302+ 150.0 145.0 80 2230 2.28 1251 92.04 - 40.0 40.0 15.0 5.0 635
1 210.0 203.0 80 2090 2.09 3772 155.35 10.0 35.0 38.0 13.0 4.0 7652+ 210.0 203 80 2090 2.09 1517 119.73 - 40.0 40.0 15.0 5.0 590
11 300.0 291.0 801 20701 2.08 1 44091 211.38 I 10.0 35.0 38.0 13.0 4.0 I 726z 1 2+1 300.0 291.0 801 2070 2.08 1 1953 167.83 - 40.0 40.0 15.0 5.0 j 577
1 420.0 407.0 80 2050 2.07 5034 278.46 10.0 35.0 38.0 13.0 4.0 6842+ 420.0 407.0 80 2050 2.07 2417 218.14 - 40.0 40.0 15.0 5.0 536
…-- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --I … . I … I…. .-.- I … I
TABLE A.4
ASSUMED PLANT CHARACTERISTICS Page 5 of 5
IPtant Type Unit M HW Capacity Max. j Average IVariable Fixed Total I Phased capital cost (X) ISpecificI No I Name- Sent AvaiL j Heat 0 & M 0 O & M I Capital YC-3 YC-2 YC-1 YC YC+1 j CapitaL
plate out X) Rate c 100 Cost j Costkcal/Wh }S/HWh IS x 1000 IS milllionl /k
Gas Turbine 1 15.0 15.0 82.5 4000 4.59 1272 8.27 0.0 10.0 62.0 25.0 3.0 551distillate/ 2+ 1 15.0 15.0 82.5 4000 4.59 65 7.52 0.0 0.0 70.0 25.0 5.0 501igas fired II
1 I 30.5 30.0 82.5 3500 I 3.51 I 1300 11.931 0.0 10.0 62.0 25.0 3.0 I 3982+ | 30.5 30.0 82.5 3500 3.51 150 10.85 0.0 0.0 70.0 25.0 5.0 362
1 i 50.5 50.01 82.5 3450 1 2.971 1536 18.421 0.0 10.0 62.0 25.0 3.0 1 368I 1 2+ 1 50.5 50.0 82.5 3450 2.97 257 16.75 0.0 0.0 70.0 25.0 5.0 j 335
{ | 1 t 71.1 70.0 82.5 3300 2.70 1675 24.52 0.0 10.0 62.0 25.0 3.0 350l 2+ g 71.1 70.0 82.5 3300 2.70 342 22.29 0.0 0.0 70.0 25.0 5.0 318
- - - I-- -- -- I-- -- -- I-- -
- 7 8 -
TABLE A.5 Page 1 of 2
FUEL PRICE ASSUMPTIONS
I CCrude OiL Coal Lignite GasYear I$/bbL(1) S/bbL(2) % change S/Te(1) S/Te(2) % change I$/MMkcaL % change % change
- …1988 11.8 16.6 I 25.0 35.1 5.84 I
{ | ~~~~~~~-7.63 I .0f .0g 00 1989 10.9 15.3 6 25.0 35,1 0.00 5.90 1.00 I 0.00
1990 11.1 15.6 1.83 27.0 37.9 8.00 5.96 1.00 0.00
1991 16.8 7.59 5.33 6.02 1.00 0.00
1 ~~~~~~7.59 5.33 1.00 0.001992 18.0 42.0 6.08
I 1993 I 19.4 7 44.3 5 6.14 1.00 0.00I I 7.59 I 5.33 1.00 i 0.00
1994 20.9 I 46.6 I 6.20 I
1995 1 16.0 22.4 7 5 35.0 49.1 5 3 6.26 1.00 0.003.17 -0.58 I 1.00 0.00
1996 23.2 48.8 6.32
1998 1 24.6 3.17 44-0.55 1.00 0.00
1999 24.9 3.1 48.0 6.39
1 3.17 1 -0.58 65 1.00 I 0.00
2000 18.7 26.2 3 34.0 47.7 I 6.58 I 0
|post 20001 2.00 1.00 1.0 0 0
Notes :(1) 1985 DolLars(2) 1988 DolLars(3) Lignite price in 1988 Dollars (World Bank value)(4) Forecasts based on World Bank estimates for coal and oiL
Lignite forecast based on increasing difficulty in mining
- 79 -
TABLE A.5 Page 2 of 2
1988 DATUM FUEL PRICE ASSUMPTIONS
Values in 1988 S
-System -Fuel Basic cost Transport -TotaLl} % | ~~~~S/MMkcat S/1MMkcat S/MMkcalI--------I.-----------------------.----- I
A/C Residual 9.156 1.146 10.301Distillate 15.870 0.686 16.556jCoal 5.261 3.000 8.261 I
B |Residual I 9.156 0.625 9.781 |Distillate 15.870 0.490 16.360 ICoat 5.261 1.500 6.761 I
1 iLignite I - - 5.840.I- - I
Assumptions:(1) ResiduaL 75% of crude oiL price on heat content basis(2) Distillate 130% of crude oil price on heat content basis(3) Calorific values (on LCV basis) :
ResiduaL 9600 kcal/kgDistillate 10200 kcal/kgCoal 6667 kcal/kgGas 1000 BTU/scf
------ - I--- ------------- I - -----
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