HomeMy WebLinkAboutAPA1774AUGUST 1884
DOCUMENT No.1774
SUSITNA
HYDROELECTRIC PROJECT
FEDERAL ENERGY REGULATORY COMMISSION
PROJECT No.7114
ALASKA POWER AUTHORITY
COMMENTS
ON THE
FEDERAL ENERGY REGULATORY COMMISSION
DRAFT ENVIRONMENTAL IMPACT STATEMENT
OF MAY 1984
VOLUME 3
APPENDIX I-
FUELS PRICING AND ECONOMICS
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'--_-ALASKA .POWER AUTHORITY_--,
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FEDERAL ENERGY REGULATORY COMMISSION
SUSITNA HYDROELECTRIC PROJECT
PROJECT NO.7114
ALASKA POWER AUTHORITY
COMMENTS
ON THE
FEDERAL ENERGY REGULATORY COMMISSION
DRAFT ENVIRONMENTAL IMPACT STATEMENT
OF MAY 1984
Volume 3
Appendix I -Fuels Pricing and Economics
Document No.1774
Susitna File No.6.4.6.~
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APPENDIX I
FUELS PRICING AND ECONOMICS
TABLE OF CONTENTS
Chapter
1.0 Introduction
1.1 Purpose of Updated Analysis
1.2 Summary of Conclusions
1.3 Contents of this Appendix
2.0 World Oil Prices
2.1 Introduction
2.2 License Application Reference Case
2.3 Revised World Oil Price Forecast
3.0 Natural Gas Availability and Prices
3.1 Introduction
3.2 License Application Projections of Natural
Gas Availability and Prices
3.3 Revised Natural Gas Price Projections
4.0 Coal Availability and Prices
4.1 Introduction
4.2 License Application Projections of
Coal Availability and Prices
4.3 Updated Forecast of Coal Prices and
Availability
4.3.1 Nenana Coal Markets and Prices
4.3.2 Beluga Coal Prices and Availability
5.0 Thermal Plant Costs and Characteristics
5.1 Introduction
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1-1
1-3
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2-1
2-3
3-1
3-2
3-4
4-1
4-1
4-4
4-4
4-7
5-1
5.3 Refinement of Thermal Options 5-1
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Chapter
5.2 Summary of License Application Thermal
Options
5-1
5.3.1 Unit Size Study of Coal-Fired Power Plants 5-1
5.3.2 Location of Coal-Fired Power Plants 5-3
5.3.3 Location of Gas-Fired Power Plants 5-4
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5.3.4 Capital Cost Estimates for Coal-Fired
Power Plants
5.3.5 Capital Cost Estimates for Gas-Fired
Power Plants
5-4
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5.3.6 Operation and Maintenance Cost Estimates 5-5
for Coal-Fired Power Plants
5.3.7 Operation and Maintenance Costs of Gas-Fired 5-5
Power Plants
5.3.8 Cycle Efficiency of Coal-Fired Power Plants 5-6
5.3.9 Cycle Efficiency of Gas-Fired Power Plants 5-7
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5.3.10 Coal Quality
6.0 Load Forecast
6.1 Introduction
6.2 License Application Load Forecast
6.3 Continuing Studies
7.0 Design Refinement and Revised Project Cost Estimate
7.1 Introduction
7.2 Proposed Design Refinements
7.3 Project Cost Estimate
8.0 Economic Evaluation
8.1 Introduction
5-7
6-1
6-1
6-2
7-1
7-1
7-2
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ARLIS
Alaska ResouI'ces
Library &InformatIon Servtces
Anchorage,Alaska
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TABLE NO.
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3-1
4-1
5-1
5-2
5-3
5-4
5-5
5-6
8-1
8-2
8-3
8-4
8-5
LIST OF TABLES
TITLE
Comparison of Oil Price Projections
Comparison of Natural Gas Price
Projections
Coal Price Forecasts
Analysis of Coal Unit Size
Assumptions and Data
Economic Analyses of Coal Unit
Sizes
Operation.and Maintenance Cost
200 MW Coal-fired Unit 1983/$
Nenana Coal Analysis.1983 Yearly
Average
Nenana Raw Coal Analysis -Weight
1984 Nenana Coal Analysis
License Application Economic
Parameters
Appendix Economic Parameters
Revised Schedule of Railbe1t
Requirements
Revised Expansion Plans-Capacity
Additions
Net Benefits and Benefit-Cost Ratio
of With-Susitna Alternative
iv
PAGE
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3-6
4-11
5-9
5-10
5-11
5-13
5-13
5-14
8-5
8-9
8-12
8-13
8-14
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Chapter
8.2 Methodology
8.3 License Application Economic Parameters
8.4 Changes in Economic Principles and
Parameters
8.5 Revised System Expansion Plans
8.6 Economic Comparison
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8-2
8-3
8-4
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Appendix I
FUELS PRICING AND ECONOMICS
1.0 INTRODUCTION
1.1 PURPOSE OF UPDATED ANALYSIS
This Appendix updates data and analyses presented in the
Susitna Hydroelectric Project License Application related to the
prices of oil,natural gas and coal,and the economics of the Susitna
Project.The Alaska Power Authority and its consultants have
conducted ongoing studies in these areas since the License Application
was accepted for processing by the Federal Energy Regulatory
Commission (FERC)in July 1983.The resulting information not only
confirms the License Application analyses but also demonstrates that
the Susitna Project has a more favorable benefit/cost ratio than
presented in the Application.Thus,Susitna remains the economically
preferred means of meeting the predicted electrical demand in the
Alaska Railbe1t .
1 .2 SUMMARY OF CONCLUSIONS
The conclusions presented in this Appendix,based on data
related to world oil prices,natural gas pricing and availability,
coal pricing and availability,refinements in the design and cost
estimate of the Proj ect,and alternative thermal plant costs and
characteristics are as follows:
o The Power Authority's oil price forecast,revised in May
1984 by Sherman H.Clark Associates,now projects higher
prices in the later years of the planning period than the
forecast utilized in the License Application,improving the
economic attractiveness of Susitna.
The revised natural gas forecast contains higher Alaskan
natural gas prices than those presented in the License
Application,making the operation of gas-burning units more
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the
were
Appendix demonstrates that
in the License application
costly (and,therefore,less attractive compared to Susitna)
than previously estimated.
The validity of the coal price forecast set forth in the
License Application has been confirmed by examination of
markets available to Alaska coal and the prices attainable
in those markets.The coal price forecast in the License
Application shows that a generating plan based on coal is
more costly than a Susitna-based plan.
A closer examination of the prototype coal-fired powerplant
used in the License Application studies has demonstrated
that the heat rate and the capital and operating and main-
tenance costs of that plant are somewhat higher than
earlier believed.Moreover,the coal quality is lower than
presented in the License Application.These factors further
reduce the economic attractiveness of coal-fired units in
any generating plan.
The new oil,gas and coal forecasts do not significantly
alter the electrical load forecast in the License
Application.Susitna,therefore,remains appropriately
sized to the projected load.
Design and cost refinements considered since the License
Application reduce the cost of Susitna,thus improving its
economic attractiveness.
The conclusion of the economic analysis in this Appendix is
that the Susitna Hydroelectric Project has a net benefit of
$2,326 million over the "Without-Susitna"Plan.In other
words,the "With-Susitna"Generating Plan has a benefit/cost
(B/C)ratio of 1.41.These figures indicate a greater
benefit than the License Application figures where Susitna
was calculated to have a net benefit of $1,827 million and a
B/C ratio of 1.33.
The information in this
and forecasts contained
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analyses
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somewhat conservative and that the Susitna Proj ect is economically
more attractive than stated in the License Application.
1.3 CONTENTS OF THIS APPENDIX
This Appendix is organized into eight chapters.Chapter 2
reviews world oil price projections included in the License
Application and presents a revised 1984 oil price forecast.
Chapter 3 describes the cost of natural gas used in the
thermal plant alternatives analyses,both in the License Application
and in this Appendix,and presents revised natural gas reserve figures
based on studies performed subsequent to the License Application
filing.As explained more fully in Chapter 3,new analyses have been
performed that afford greater recognition to the effect that world
energy markets have on the production and price of natural gas in
Alaska.
Chapter 4 provides revised information on Alaska coal
pricing and availability.Chapter 5 reviews the "Without-Susitna"
thermal generation alternatives.The costs and performance
characteristics of these generation alternatives are updated to
reflect the latest available information.Chapter 6 provides a report
of sensitivity analyses conducted on the Power Authority's electric
demand forecast based primarily on revisions made for the 1984 oil
price forecast.Chapter 7 presents engineering refinements which have
been proposed for the Susitna Project which would reduce its total
capital cost.The Power Authority filed these design refinements with
the FERC August 14,1984.
Finally,Chapter 8 is a summary chapter in which the revised
data presented in the previous sections are utilized,along with
certain new economic parameters,to generate economic indicators.As
in the analysis performed in the License Application,this process
involves comparing alternate means of meeting the forecasted Rai1be1t
electrical demand.The optimum "Without-Susitna"mix of generating
units is compared with the system which would be built around the
Susitna Project in a "With-Susitna"plan to assess the economic
feasibility of the Project.
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2.0 WORLD OIL PRICES
2.1 INTRODUCTION
The revised oil prices forecast contained in this Appendix
tracks the forecast in the License Application in the early years of
the projections and rises significantly above the prior forecast
beginning in the year 2000.Forecasted oil prices are crucial to the
economic analyses in the License Application and in this Appendix
because the world price of oil plays an important role in the Alaskan
economy.In addition to driving the general economy,oil prices
establish alternate fuel prices and directly affect the State's
ability to finance the Project.Nearly 85 percent of State revenues
are derived from petroleum royalties and taxes based upon the value of
oil at the wellhead,which value is,in turn,a function of the world
price of oil.Because of these functions,world oil prices are an
important input to the econometric models utilized by the Power
Authority in predicting future Railbelt electrical demand.
2.2 LICENSE APPLICATION REFERENCE CASE
In selecting a reference case forecast of world oil prices
for use in preparing the License Application,the Power Authority
studied a number of world oil price forecasts prepared by various
government agencies and economic consultants.The Power Authority
selected as the reference case a forecast prepared by Sherman H.Clark
Associates (SHCA).
As explained more fully in the License Application,SHCA
annually prepares a detailed 25 to 30 year projection for all types of
energy of the world supply and demand and estimated pricing.The May,
1983 SHCA forecast of world oil prices was used in preparing the
License Application.That analysis contained three pricing cases
based on three different political-economic scenarios:Supply
Disruption (SD),Zero Economic Growth (ZEG),and No Supply Disruption
(NSD).
SHCA's SD case assumed a severe supply disruption in the
world oil market in the late 1980's,followed by production-limiting
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decisions by several key petroleum producing countries.These factors
resulted in projected world oil prices of $40.00 in 1990,$53.76 in
2000 and $87.80 in 2040.!/The ZEG scenario assumed no severe supply
disruption,combined with zero economicgro'irth in the United States
and 0.4 percent growth per year in the free world through 1990 and a
gradual rise thereafter.The predicted oil prices under this scenario
were $17.00 in 1990 and $45.11 in 2010.Falling between these two
scenarios was the No Supply Disruption case.
The NSD case was similar to the Supply Disruption case,but
it assumed that there would be no supply disruption in the late 1980s.
Economic growth after 1988 was assumed to be at an annual rate of 3
percent in the United States,slowing gradually to an annual rate of
2.5 percent.Economic grow_th in the free world was assumed to be 3.6
percent annually.
For the years 1983-1988,projected oil prices were the same
for both the NSD and SD case scenarios in the May,1983 forecast.
From 1988 to 2010,prices increased under the NSD case at a 3.0
percent annual rate because of the relatively high rate of world
economic growth.The rate of price escalation was then assumed to
taper off as the oil price approached a level that would bring forth
supplies of alternative fuels.This market condition occurred between
the years 2035 and 2040.
The SHCA NSD case was selected as the Reference Case in the
FERC License Application filing.The NSD case assumed that OPEC would
continue operating as a viable entity,and would successfully support
its benchmark pricing system.It also assumed that economic growth in
the United States and the free world would continue at reasonable
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-rates.In addition,the NSD case fell in
forecasts examined by the Power Authority
the middle range of
and,therefore,was
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are
All fuels prices in this Appendix,unless otherwise indicated,
stated in 1983 dollars.
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determined to be an appropriately conservative forecast for the
economic feasibility analysis presented to the FERC.
The three sets of oil price proj ections are presented in
Exhibit B,Chapter 5 (Volume 2A),of the License Application.It
should be noted that in May 1983 the SD case was assumed by SHCA to
have the greatest likelihood of occurrence.SHCA had assigned a
probability of occurrence of 40%to the SD case.It haQ assigned the
NSD case a 35%probability and 25%to the ZEG.Therefore,the
probability of equaling or exceeding Reference Case prices was 75%.
The probability of occurrence of an oil price scenario lower than the
Reference Case was only 25%.
As presented in greater detail in Volume 2A of the License
Application,the Power Authority also studied world oil price
forecasts prepared by the Alaska Department of Revenue (DaR)and Data
Resources Incorporated (DRI),as well as analyzed hypothetical cases
presented by the FERC Staff.These forecasts were analyzed as a means
of testing and bracketing the SHCA NSD Reference Case.
2.3 REVISED WORLD OIL PRICE FORECAST
The principal assumptions upon which SHCA based its NSD
forecasts have been proven sound by recent events in the United States
and world economies,and the world oil markets.In keeping with its
practice of performing annual updates of its projections,in May 1984
SHCA revised and reassessed its forecasts.SHeA now believes the NSD,
rather than the SD,scenario represents the most likely set of assump-
tions.SHCA has therefore designated the NSD scenario as its 1984
base case.The probability of occurrence assigned to the NSD case is
now 50 percent,the SD case 30 percent and the ZEG case 20 percent.
Therefore the NSD case price forecasts have an 80 percent probability
of being equaled or exceeded.Table 2-1 compares the License Appli-
cation forecast with the May,1984 SHCA NSD forecast.
As can be seen,the May 1984 forecast is the same as the
License Application forecast through the early 1990's,but thereafter
the prices in the May 1984 forecast rise more rapidly.The similarity
in the early years is due to the fact that the primary assumptions on
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which the License Application forecasts were based have been revised
relatively little.The primary assumptions of the 1984 projection are
as follows:
Growth in the United States economy is still projected
in the 1984 scenario to continue at about 3 percent per
year;the free world economy is also expected to grow
at approximately the same rate.
No major war or other oil supply disruption is assumed
to occur in the NSD case,although SHCA still considers
a major disruption to be a strong possibility,
particularly in light of the continued hostilities in
the Middle East;
Steady improvements in energy technology will continue
consistent with recent trends,although oil and gas
finding rates will be somewhat lower than the rates
assumed in the License Application forecast,consistent
with the latest U.S.Geological Survey resource base
estimates;
o OPEC will continue to allocate production among its
member countries and to hold official prices for marker
crude at its present level of $29 per barrel;and
o Little non-conventional petroleum supply will be
developed prior to the year 2000.
These assumptions are based on events of the past year.For
example,for the first five months of 1984,the U.S.economy has grown
by 5.9%,while the growth rate for the free world has been over 3%.
The Iran-Iraq war has not caused a major supply disruption nor has it
had any lasting impact on prices.
The posted price for OPEC oil remains at $29 per barrel and
OPEC has recently affirmed both existing production quotas and the
posted price.The spot price for marker crude was quite stable from
April 1983 through May 1984,generally running 25 cents to 50 cents
per barrel below posted.
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Generally,there can be a seasonal summer decline in spot
price due to a seasonal decline in demand and a failure to lower
production in the second quarter in anticipation of the summer decline
in demand.The Power Authority and its consultants had anticipated
such a seasonal reduction in spot crude prices of $1 to $2 per barrel
by Mayor June 1984.The overproduction did take place,but the spot
price did not decline at that time because producing countries and oil
companies increased stocks in anticipation of a supply interruption.
The supply interruption has not taken place and for various
war-related reasons,OPEC continued to overproduce for the seasonal
market through July 1984.Finally,the spot prices for all types of
crude oil began to drop sharply and reached levels in some cases more
than $2 per barrel below posted.This is a seasonal as well as a
war-related phenomenon,not caused by reduction in the annual rate of
demand for OPEC crude oil.Production will be adjusted to the market
and spot prices will strengthen toward posted prices,most likely
stabilizing to within 50 cents of posted prices.The Iran-Iraq war
may have caused a brief supply interruption with resulting price
fluctuation over the short-term,but it holds no significance for
long-term pricing or production.
The higher long term oil prices of the May 1984 NSD forecast
compared to the License Application forecast can be explained by a
change in assumptions which SHCA has made concerning oil finding
rates.In the 1983 NSD case,SHCA assumed that the oil finding rate
would be well above an extrapolation of the past trend.In the
current NSD forecast,SHCA has assumed that the past trend in the
finding rate will continue.This is confirmed by SHCA's evaluation of
the latest country by country estimates of the remaining oil resource
base.The result of using a lower NSD finding rate is a more rapid
rate of price increase after 1990,as shown in Table 2-1.
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Table 2-1
COMPARISON OF OIL PRICE PROJECTIONS
Price of Marker Crude
(1983 Dollars per Barrel)
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Date
1983
1984
1985
1986
1987
1988
1989
1990
1995
2000
2005
201C
2020
2030
2040
2050
1983 SHCA-NSD Forecast
License Application
Reference Case
$28.95
27.61
26.30
26.30
26.30
26.30
27.09
27.09
32.34
37.50
43.47
50.39
64.48
74.84
82.66
2-6
1984 SHCA NSD Forecast
$
27.61
26.30
26.30
26.30
26.30
27.09
27.90
32.50
40.00
50.00
60.00
80.00
90.00
100.00
110.00
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3.0 NATURAL GAS AVAILABILITY AND PRICES
3.1 INTRODUCTION
It is necessary to evaluate the price and availability of
natural gas over the next 50 years in order to determine Susitna's
economic feasibility because gas-fired generating units are potential
alternatives to the Susitna Proj ect.The revised estimates in this
Appendix of future natural gas uses and reserves reflect only small
changes from the License Application estimates.However.the revised
price forecast.which puts greater emphasis on the effects of world
energy conditions and markets on the production and price of Alaskan
natural gas.projects higher prices for natural gas consumed in the
Railbelt beginning about 2005.
Approximately three-fourths of the current electric energy
generated in the Railbelt is fueled by natural gas produced from the
vicinity of Cook Inlet.During the next decade it is expected that
Cook Inlet natural gas will continue to play an important role in
electric power generation,home heating,and other uses in the
Railbelt.However.as discussed more fully in the License
Application,planning on the availability of Cook Inlet natural gas
for power generation after 2000 involves the assumption of
considerable risk.for it places an inordinate and unwarranted
reliance upon the future availability of natural gas supplies from
undiscovered reserves which may not exist (see Appendix D1 of the
License Application)•Moreover.given current Powerplant and
Industrial Fuel Use Act (Fuel Use Act)constraints on fueling new
electric generating plants with natural gas,there is considerable
regulatory uncertainty in this approach.
There is the technical potential of delivering natural gas
to the Railbelt from fields on the North Slope of Alaska,although use
of such gas at present would be subj ect to the Fuel Use Act.The
basic issue is transportation cost.Large quantities of natural gas
are known to exist on the North Slope.making this source of gas.
along with Cook Inlet reserves.the principal deposits to consider in
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evaluating the long term use of natural gas as a fuel for generating
electric power in the Railbelt.
3.2 LICENSE APPLICATION PROJECTIONS OF NATURAL GAS
AVAILABILITY AND PRICES
The analyses presented in the License Application found chat
proven reserves of Cook Inlet natural gas totalled approximately 3.5
trillion cubic feet (Tcf),and the ~conomically recoverable,but
presently undiscovered,reserves were approximately 2 Tcf.Based on
the continued use of natural gas at then-current levels in the
industrial and military sectors,moderate growth in the retail sector,
and continued use of natural gas as a fuel for electric power
generation in the Railbelt,it was concluded that proven Cook Inlet
reserves would be exhausted by about the year 1998.Horeover,the
License Application estimated that economically recoverable,undis-
covered reserves would be exhausted by about 2007.These conclusions
are graphically illustrated in Figure D-l.4 of the License
Application.It was recognized that many factors could affect these
conclusions,including the discovery of larger or smaller volumes of
economically recoverable natural gas,the commitment of larger quan-
tities of gas to either existing or new customers,or changes in legal
aspects of natural gas exploration and development.
The forecasted prices of Cook Inlet natural gas available
for generating electricity were estimated through a systematic
examination of existing contracts,expectations of new contracts,the
potential for additional export of natural gas,and other Railbelt
market factors.It was found that in 1983 the purchase price of Cook
Inlet natural gas was approximately $2.47 per million Btu (MMBtu),not
including transportation costs from the wellhead.If the addition of
a large export project of liquefied natural gas (LNG)were taken into
account,it was concluded that the price would increase to over $3.00
per 11MBtu.
The price of natural gas has closely paralleled the world
price of oil in recent years.For this reason natural gas prices were
escalated in the License Application as a direct function of world oil
3-2
prices in the License Application filing.The results of applying
this forecast method for several oil price scenarios,including
projections based on the Reference case oil price forecast,are
presented in Table D-1.9 of the License Application.The projected
price of natural gas based on the License Application Reference Case
is shown in Table 3-1.
The License Application noted that,while natural gas
supplies from Cook Inlet are somewhat limited,much larger quantities
of natural gas (estimated at approximately 29 Tcf)are available from
the North Slope.At the time of the License Application filing (as
well as at present),however,there was no means of utilizing this gas
to generate electricity for the Railbelt.In the License Application
four plans for future use of North Slope gas for electric generation
were evaluated:
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The Alaska Natural Gas Transportation System (ANGTS),a
proposed natural gas pipeline from the North Slope to
the lower 48 States;gas could be taken from this
pipeline for generating power in the Railbelt.Plans
for construction are apparently dormant.
Trans-Alaska Gas System (TAGS),a proposed pipeline
from the North Slope to the north shore of the Kenai
Peninsula;from the Kenai Peninsula the gas would be
liquefied and shipped to the Pacific Rim.Gas might be
made available from TAGS for use in Railbelt
powerplants.There was no active plan for constructing
TAGS at the time of the License Application filing.
A natural gas pipeline from the North Slope to
Fairbanks to fuel electric power generation facilities
and to provide fuel.for home heating and other uses.
This is a particularly expensive source of natural gas
for Railbelt power generation,and no plan has been
developed for implementing this option.
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o Electric power generation on the North Slope,with a
transmission line to the Railbelt;this option is also
expensive and there is no plan for pursuing it.
The cost of developing North Slope natural gas for use in
Railbelt electric power generation would range,as indicated on Table
D-1.8 in the License Application,from approximately $4.00 per MMBtu
to in excess of $6.00 per MMBtu,depending upon the means selected.
For purposes of the License Application analysis,a conservative base
year cost estimate of $4.00 per MMBtu was selected and escalated using
the same method as that used for Cook Inlet natural gas.The result-
ing price forecast is shown in Table 3-1.
3.3 REVISED NATURAL GAS PRICE PROJECTIONS
Several refinements have been made in the forecasts of Cook
Inlet natural gas consumption and North Slope natural gas prices
contained in the License Application.Revised estimates of future
natural gas uses and reserves reflect only small changes from the
License Application in the volume of natural gas needed for electric
power generation.
The revised estimates also expand the scope of the natural
gas analyses to afford greater recognition to the effects that world
energy conditions and markets have on the production and price of
natural gas in Alaska.These analyses,undertaken by SHCA,indicate
that natural gas prices will rise at a greater rate than forecasted in
the earlier studies.The intent of having SHCA perform this natural
gas analysis was to ensure consistency between the forecast of natural
gas prices and the projected world oil price forecast previously
developed by SHCA (See Section 2.3 above).
As in the License Application analysis,SHCA assumes that
natural gas is a substitute fuel for petroleum in certain uses.
Therefore,world oil prices play a determinant role in setting gas
prices in the SHCA analysis.SHCA's analysis indicates that ANGTS
could be feasible as early as 1995.TAGS,which filed a right-of-way
application with the Bureau of Land Management in May,1984,might be
feasible in approximately the same time period.In the economic
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analysis,the Railbelt price for natural gas after the Cook Inlet
supplies are exhausted (about 2007)was assumed to be the projected
price of North Slope gas delivered to the Railbelt via ANGTS.The
resulting projection of gas prices to Railbelt power plants,which is
presented in Table 3-1,considers the transition from Cook Inlet to
North Slope gas and is internally consistent with SHCA's oil price
projections,Lower 48 and world gas supply/demand balances,and
projections of the world economy.
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Table 3-1
COMPARISON OF NATURAL GAS
PRICE PROJECTIONS
(1983 $per MMBtu)
2.47 4.00 2.47
2.16 3.64 2.25
2.74 3.98 2.80 2.86
3.18 4.61 3.14 4.00
3.69 5.35 3.37 4.93
4.27 6.20 4.94 6.14
4.95 7.18 7.37
6.34 9.20 9.83
7.36 10.67 11.00
8.13 11.79 12.00
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Year-1983
1985
1990
1995
2000
2005
2010
2020
2030
2040
2050
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License Application
Reference Case
Cook Inlet North Slope
Wellhead Delivered
3-6
Revised Forecast
Cook Inlet North Slope
Wellhead Delivered
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4.0 COAL AVAILABILITY AND PRICES
4.1 INTRODUCTION
The studies on coal prices and availability performed since
the License Application explore the methods and assumptions used to
predict Alaskan coal prices and refine the escalation rate used in
forecasting prices in greater detail.The new studies indicate that
the two major coal fields with vast quantities of coal in Alaska are
the Nenana and Beluga fields.These coal fields will serve what are
essentially separate markets.Nenana coal.serving the mainly
domestic interior Alaska market.would have a price of $2.05 per MMBtu
in 1993 when delivered to the town of Nenana.Beluga coal,which
would serve both the export as well as domestic market.would have a
mine-mouth price of $1.95 per MMBtu in 2000 which would rise to $4.75
per MMBtu in 2050.
At present coal is used for electric power generation for
Fairbanks and the surrounding area.The coal is mined by the Usibelli
Coal Company operating in the Nenana Field.southwest of Fairbanks.
Nenana coal.along with coal from the undeveloped Beluga coal field
west of Anchorage.could provide fuel for electric power generation
throughout the Railbelt.Other coal deposits are located on the Kenai
Peninsula,the MatanuskaValley.and elsewhere in Alaska.The Nenana
and Beluga fields are most likely to provide the larger quantities of
long-term coal supplies for electric power plants in the Railbelt for
the foreseeable future in the Without-Susitna Plan.The uncertainties
surrounding the development of Nenana and Beluga reserves are the
timing of Beluga coal availability in the Railbelt area.and the
prices at which both Beluga coal and expanded Nenana coal development
would be available.
4.2 LICENSE APPLICATION PROJECTIONS OF COAL
AVAILABILITY AND PRI-=C=E-=S----"--"----
Coal availability and price studies conducted in support of
the License Application established that the coal resource base of
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Alaska,as concentrated in the fields discussed,is more than adequate
for generating electric power sufficient to meet the projected demand
of the Railbelt for at least the next 75 years.The large quantity of
reserves in the Nenana field,for example.is estimated to be in
excess of 450 million tons.The identified resource base in the
Nenana area,some of which probably cannot economically be mined.is
approximately 7 billion tons.
In the Nenana area.the only significant commercial mine
currently operating is the Usibelli Coal Company mine.In the License
Application it was noted that this mine is currently producing
approximately 830,000 tons per year of subbituminous coal with heating
value of approximately 7.400-8.200 Btu per pound (see Section 2.2 in
Appendix D-1 of Exhibit D of the License Application).It was also
noted that there is an export agreement pending finalization for
Nenana coal which would require doubling the current Usibelli
production level.This doubling will require the current mine to
operate at or near full capacity.To provide coal fer Railbelt
electric power generation under the Without-Susitna expansion plan,
Usibelli production would have to again double.rising to close to 3.5
million tons per year by year 2010.Some 2 million tons per year
(MMTPY)of production capacity would have to be added at the field.
Nenana area coal fields could sustain this level of production over a
long period of time.
In the License Application the average mine-mouth production
cost for Nenana coal was estimated to be approximately $1.40 per
million Btu (MMBtu)in 1983 dollars.However.in establishing the
price of coal at hypothetical electric power plants,it was necessary
to add transportation costs for moving coal from the Nenana mine to
hypothetical power plants at Nenana and Willow.Alaska.Those costs
were estimated in the License Application to be $0.32 and $0.51 per
4-2
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MMBtu,respectively,resulting in a delivered coal price of $1.72 -
$2.18 per }llirntu.l /
The identified resource base in the Beluga field is
10 billion tons.In the License Application the price of Beluga coal
was estimated on its value in the Pacific Rim market,since the
principal basis for the development of the Beluga field would be to
supply coal to this market.The average price of coal at a Beluga
port (FOB Granite Point)calculated on this basis was estimated to be
$1.86 per MMBtu.The cost of opening a small (1 to 3 million tons per
year)Beluga coal mine exclusively for use in Alaska was found to
result in substantially higher prices --$2.72/MMBtu and $l.91/MMBtu,
respectively.In developing an estimate of the cost of the
lJ
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Without-Susitna expansion plan,a conservative estimate of Beluga coal
prices using the export price of $1.86 in the base year was used.
In the License Application,Nenana coal prices were
escalated at a real (inflation free)rate of 2.6 percent per year,
reflecting the experience in United States energy markets during the
past few years.Escalation rates in the price of coal in the Pacific
Rim market,however,were estimated to remain below those domestic
coal rates due to continued and increased international competition
among suppliers and the possible effects of a weakening United States
dollar in international currency markets.Escalation of Beluga coal
prices was therefore estimated to be 1.6 percent per year}./
It should be noted that both Nenana and Beluga coal prices
were assumed in the License Application to escalate until the date a
given generating unit enters operation.At that time,the coal price
The basis for these cost estimates and other conclusions from
these studies are presented in detail in Appendix Dl of Exhibit D of
the License Application.
The License Application forecasts of Nenana and Beluga coal
prices based on these assumptions are shown on Table D-2.14 of Exhibit
D of the License Application.
4-3
for the unit is assumed to remain constant in real terms until the
unit is replaced.Using this approach,the average coal price
-
escalation rate in the License Application was about 1%per year after
1993.
4.3 UPDATED FORECAST OF COAL PRICES AND AVAILABILITY
The new studies on coal prices and availability were
designed to explore in greater detail the pricing of Alaska coal.
Detailed analyses were conducted of net back pricing and production
cost pricing in addition to refinement of the escalation rates used in
making the price forecasts.11 Net back pricing is the calculation of
what price could be obtained for Alaska coal at the mine (net of
transportation costs)considering its sales price into an export
market;production cost pricing is,as implied,the price of coal set
on the basis of the total cost of producing coal from a mine over a
long term.The studies which have been completed indicate that the
Nenana and Beluga fields will serve what are essentially separate
markets,due to different access to ocean transportation facilities
and the timing of mine development.
4.3.1 Nenana Coal Markets and Prices
The Usibe11i Coal Company's existing production of 830,000
tons per year primarily serves electric generating plants in the
Fairbanks area.If arrangements for the proposed export of 800,000
metric tons (880,000 tons)per year of Nenana coal to Korea are
completed under the Sunee1 contract,it will require a doubling of
Neither coal production costs nor coal prices can be expected to
remain constant in either real or nominal terms over a fifty-year
planning period.Since 1900,real coal prices have shown different
trends and cycles,as well as apparently random variations.The
average overall real price increased at a rate of 1.22%.This history
of coal price escalation supports the proposition that Nenana and
Beluga coal costs will escalate in the future,as developed more fully
below.
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Usibelli production to 1.7 MMTPY}:..I The doubling could be supported
within the existing capacity of the mine.The operators of the
Usibelli mine have said they could expand their operations to as much
as 4 MMTPY by doubling mine capacity.Further,it is recognized that
other organizations besides Usibelli control substantial quantities of
coal in the Nenana Field and that these deposits could also be
developed.The Power Authority has made an analysis of the price that
Usibelli and other producers would require to elicit this expanded
production.
The size of the potential electric generation market for
Nenana coal can be determined by reference to the Without-Susitna
expansion plan developed by the Power Authority.In a refinement of
the plan presented in the License Application,the Power Authority has
estimated that six 200 MW coal-fired plants would be needed in the
optimal Without-Susitna expansion plan.The first two of these plants
would be located in the Fairbanks region for purposes of electrical
system.expansion (see discussion in Chapter 5).Given the estimate of
Nenana coal quality,it has been calculated that each 200 MW coal
plant would consume approximately 1 MMTPY of coal,for a total Nenana
consumption of 2 ~lliITPY.
Usibelli has said it is capable of producing 2 MMTPY in
addition to the 2 MMTPY which is to be dedicated to the pending export
arrangement and to meeting its current domestic market requirements.
Since Usibelli is the primary operating mine in the Nenana Field,it
is therefore reasonable to assume that Usibelli would be the most
likely supplier of the additional 2 MMTPY needed by the Nenana-area
power plants discussed above.The production cost for the 2 MMTPY
The proposed export to Korea is possible because production for
this quantity comes from an incremental expansion of existing
capabilities,which operations are relatively inexpensive.This
enables Usibelli Company to absorb the high transportation cost to
Seward and still establish a viable sales price.
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"incremene'from the Usibelli operation has been estimated to be $1.50
per MMBtu in 1983 dollars.
That cost estimate is only the starting point for the Nenana
price analysis,because it estimates the production cost per ton for
the Usibelli 2 MMTPY increment in the first year of operation.For
long term proj ections,the real increases in the cost of Usibelli's
operations in the second and succeeding years of operation must be
considered.In addition,in light of environmental conditions which
preclude burning coal at the Nenana Field,the cost of transporting
the coal from the mine to the powerplants must be added to derive a
"delivered"price,which is the proper basis for comparing coal with
other fuel prices in the economic analyses.
The Power Authority has performed additional analyses of the
escalation rate by reviewing those components of coal production which
are expected to escalate in real terms:labor,fuels and lubricants,
and electricity.Based upon the studies of historic labor rates in
the United States,it is estimated that labor costs will escalate at
1.5 percent per year.Relying upon projections of future petroleum
prices generated by SHCA,as described in Chapter 2,Section 2.3,
projected future escalation in diesel fuel and lubricants is estimated
to be 2.2 percent.Utilizing data generated by the system expansion
models,electricity is estimated to escalate at approximately 1.3
percent per year in the Fairbanks region.The cost escalation rates
for each factor discussed above result in the overall cost of
production from the "incremental"operation escalating at a rate of
0.8 percent per year.
Consistent with the assumptions in the License Application,
the analysis of Nenana pricing includes a transportation cost of $0.37
per MMBtu in 1983,which is estimated to be subj ect to real price
escalation of 1.8%percent per year.
The result of these analyses is an estimated price of $2.05
per MMBtu in 1993 for the total delivered price of coal to the two new
coal-fired plants forecasted for the Fairbanks load center,as set
forth in Table 4-1.
4-6
4.3.2 Beluga Coal Prices and Availability
As previously stated,the License Application price of
Beluga coal was predicated on the development of an export market.It
was anticipated that Alaska coal could be sold competitively in the
world market to the Pacific Rim countries.The competitive price in
this market less the cost of transportation across the Pacific yields
a net back price in Alaska.
In further evaluating the potential for Beluga coal to enter
the Pacific Rim market,it was determined that it was essential to
assess the long term demand for coal in terms of the world energy
balance as projected by SHCA.SHCA forecasts that energy demand per
unit of GNP will continue to decline over the forecasting period.
This decline reflects increasing efficiency of energy use in economies
throughout the world.There will be a growing demand for all fossil
fuels which will exceed the supply of alternate fossil fuels that can
be expanded.It is predicted that world demand for coal will increase
and maintain the longest and strongest sustained growth of any
existing established form of energy.Volumetrically,coal demand
'if
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should grow at least as fast as the world economy for the next 40
years.
It is proj ected that Beluga coal will enter the export
market in a significant manner after 1990.The quantities of Alaska
coal exported will increase from 15 million MTCE~/in 2000 to 105
million MTCE in 2040.It is further assumed that,because of a strong
market,the Pacific Rim market will dictate the price of the coal
received by Alaskan producers,due to The Pacific Rim Market's favor-
able location and because it constitutes a major portion of projected
free world demand.
MICE,Metric Ton of Coal Equivalent,is a metric ton of coal with
a heat content of 12,600 Btu's per pound.One MTCE equals 1.85 Beluga
"short tons"(2000 pound tons).
4-7
The production cost of coal available to the Pacific Rim
market will vary not only with the producing country,but from sources
within the producing markets within the country.Because production
cost for Beluga coal will be lower than that of many producing
countries,Beluga producers will be able to capture a significant
portion of the Pacific Rim market;however,the Pacific Rim countries'
desire to diversify their suppliers,the lower quality (heat content)
of Alaska coal,and the international monetary exchange rates are some
of the factors that would prohibit Alaska from capturing a larger
share than 20%of the total market.
The price of coal in the Pacific Rim market will rise during
the period that the Alaska coal exports are increasing.The price of
coal will rise due to the increase in demand,due to interfuel
competition,and to reflect increases in real costs of the following
coal production components:labor,leasing and operations,equipment,
fuels,transportation rates and distances.The increasing coal prices
also reflect costs associated with government policies and regulation,
such as monetary exchange rates,imposition of taxation,stricter
environmental constraints,and production or export constraints.
In order to determine whether Alaska coal can be competitive
with other coal exports to the Pacific Rim,the Power Authority's
analysis developed an "envelope"of prices for Alaska coal,to
establish the highest and lowest prices at which Alaska coal.could be
marketed.The Power Authority has identified the upper and lower
limits to this envelope,respectively,as the gas-equivalent price of
coal and the production costs.
In theory,the highest long-term price at which a producer
could possibly sell his coal would be a price which could not exceed
the price of natural gas as an alternate fuel.These "alternative
fuel equivalent prices"have been keyed to the SHCA gas analysis set
forth in Chapter 3 of this Appendix.It is estimated that this
alternative fuel equivalent price would range from $1.54 per MMBtu in
2000 to $7.93 per MMBtu in 2050 in 1983 dollars.The alternative fuel
equivalent price will occur infrequently,generally when there are
4-8
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severe constraints upon the availability of other supplies due to
strikes in various regions,sudden increases in demand that cannot be
met due to lack of mining capacity,and so forth.
At other times,there will be an excess of supply,market or
monetary conditions unfavorable to the producer,or similar
conditions.At such times,the producer will have to accept a lesser
price,which would in no event fall below the level of production
costs.Thus,the envelope is established by the gas equivalency price
at the high end and production costs at the low end.
Given this envelope,a net back line was developed showing
the trend for long term prices.This trend line was developed based
upon SHeA world energy demand forecasts.Alaska producers may sell
supplies at higher and lower prices at a given time in light of
current market forces in the Alaska market,prevailing international
energy market factors,international monetary exchange rates or other
considerations.It should be understood that this line is a "trend
line"which recognizes that coal prices will cycle within the envelope
over time,as they have done historically.As a result of the
foregoing,the export price of Alaska coal at the mine-mouth is
I~
projected to be $1.95/MMBtu in 1983 dollars in 2000,rising to
$4.75/MMBtu in 2050,as indicated in Table 4-1.Following the logic
of the License Application that producers will attempt to obtain the
maximum price for their coal that the market will allow,the net back
line is adopted as the coal price forecast for the Beluga field.
As a step in reviewing all scenarios that constitute the
envelope for pricing Alaska coal,the Power Authority reassessed the
production costs in the License Application.To test the full econ-
omies of scale which could be captured from production of the Beluga
field,the Power Authority estimated the cost of production from large
Beluga mines ranging from 8 to 12 MMTPY.The results of these studies
showed that the 8 MMTPY mine would produce coal at a slightly lower
cost than the 12 MMTPY mine;therefore the 8 }lliTPY was selected for
economic analysis.The economic cost of production from that mine in
1983 would be $1.22 per MMBtu.
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As with the estimate of Nenana mining costs,it is necessary
to escalate the Beluga prices.Following the same methodology uti-
lized for determining the escalation rate of the Nenana 2 ~illTPY case,
it was calculated that the 8 ~n.rrpy Beluga mine total costs would
escalate at 0.8 percent per year.The same generic escalation rates
for labor and fuel and lubricants used at Nenana (1.5 and 2.2 percent,
respectively)are used for Beluga escalation.Electricity escalation
is estimated to be 1.9 percent.The result is that the escalated
production cost of Beluga coal at mine-mouth ranges from $1.31 per
MMBtu in 1993 to $2.08 per MMBtu in 2050 in 1983 dollars (less than
the export price of $1.95 and $4.75 per MMBtu,respectively).As
previously noted,therefore,the Beluga producers will seek to sell
their supplies at the price established by the export market.
In the License Application,the Power Authority also
considered the unlikely possibility that an export market would not
develop.Under that scenario,Beluga would be developed with small
mines to meet only the Railbelt's generation requirements under the
Non-Susitna Alternative.Production cost studies were conducted,and
further refinements of the small mine studies were done subsequently
using a new mine design reflecting a more efficient mining operation
for the 1 MMTPY case.In addition,the new 1 MMTPY study assumed that
transportation ended at the point the coal was delivered to the
mine-mouth,rather than at port facilities as in the earlier study.
The price of coal produced for the hypothetical 1 MMTPY mine was
estimated to be $2.22 per MMBtu.The earlier 3 MMTFY study was
revised to change the assumption regarding the delivery point;
however,a new mine design was not done for the 3 MMTPY case.The
result of these refined 3 M}ITPY mine studies was to reduce the cost to
$1.72 per MMBtu.These costs are significantly higher than the cost
of the 8 t~PY mine.
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1 I J J J )J 'j
Table 4-1
COAL PRICE FORECASTS
(1983 $per MMBtu)
J )J -J --J )'J 1
License Application
Reference Case Revised Forecast
Nenana Prod.Cost
Year FOB Nenana-
1993 2.15
2000 2.53
2010 3.18
2020 3.99
.p-
I 2030 5.01I-'
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2040 6.29
2050 7.89
Beluga Export Price
Mine-mouth
2.44
2.85
3.35
3.92
4.60
5.39
Nenana Production Cost
FOB Nenana
2.05
2.20
2.43
2.69
3.00
3.35
3.76
Beluga Export Price
Mine-mouth
1.95
2.40
2.80
3.35
4.00
4.75
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5.0 THERMAL PLANT COSTS AND CHARACTERISTICS
5.1 INTRODUCTION
The description of the thermal plant costs and character-
istics submitted in the License Application considered a number of
alternative generating plants.These plants were coal-fired steam
electric stations and natural gas-fired simple cycle and combined
cycle combustion turbines.
Further analysis and refinement of the costs and charac-
teristics of these plants has been conducted since the filing of the
License Application.The purpose of these refinements was to document
the assumptions made previously and to consider the effects of new
information on these previous assumptions.
The following paragraphs present the assumptions made in the
License Application and the update of that work.
5.2 S~JffiY OF THE LICENSE APPLICATION THERMAL OPTIONS---
Section 4.5 of Exhibit D discusses the thermal options
considered in the License Application.The size,capital cost,and
operating characteristics of coal-and gas-fired units which were
generally defined in the Railbelt Electric Power Alternatives Study,
performed in 1982 by Battelle Northwest Laboratories,were used in the
License Application analysis.Table 8-1 provides the detailed system
parameters used in the License Application economic analysis.
5.3 REFINEMENT OF THERMAL OPTIONS
5.3.1 Unit ~Study of Coal-Fired Power Plants
The 1982 Railbelt Alternatives study selected a 200 MW
coal-fired power plant as a representative unit size that would be
reasonable for a system expansion analysis.Further analysis was
subsequently conducted to confirm that this size is the most
economical coal option for the IIWithout-Susitna"plan.
In reviewing the assumptions for the appropriate size of a
hypothetical coal-fired power plant,an evaluation of the options for
unit size ranging from 100 MW to 400 MW was performed.The evaluation
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considered the trade-off between two major driving forces or factors:
economies of scale and unplanned outages.
As the size of powerplant units increases,economies of
scale are realized as lower capital and O&M costs are derived on a
unit kilowatt basis.For example,a single 400 MW unit has a capital
cost of about 80%of two 200 MW units and requires about 60%of the
operations and maintenance staff.
The factor of reliability and unplanned outages recognizes
that the output of a utility system is made up of diverse generation
stations all combining their capacity to meet the load.The loss of
the largest single generating unit represents the design basis for the
reliability and loss of load analysis.
A trade-off between the two factors of economies of scale
and unplanned outages were performed using the OGP model.Within that
mbdel the reliability assessment is based upon determining the
cumulative capacity outages of the system.As generating unit sizes
become larger,more capacity is installed to meet the reliability
requirement specified in the model.Another calculation performed in
the OGP analysis is spinning reserve.The spinning reserve criteria
provides the grid with the capability of meeting system load should
the largest unit experience an unplanned outage.
Since any hypothetical coal-fired unit larger than 200 MYl
would represent the largest unit in a Without-Susitna system,a number
of OGPexpansion planning analyses were performed.The unit size
evaluation initially consisted of allowing the OGP expansion planning
program to select among 100,200,300,and 400 MW units.(Sizes up to
600 MW were considered,but never selected by the program.)The
resulting system plan included 100 MW and 200 MW units.In the next
step,unit sizes of only 100,150,200,and 250 MW were made available
for system expansion.The program then selected a mixture of 150 MW
and 200 MW units.An expansion planning program using only 200 MW
units showed that the total present worth of the mixture of 150 MW and
200 MW units was essentially the same as the present worth of the pro-
gram that limited plants to 200 MW as the only size.The 200 ~m
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expansion program utilized in the License Application was therefore
validated and retained.The assumptions used in this analysis are
found in Table 5-1 and the results set forth in Table 5-2.
5.3.2 Location of Coal-Fired Power Plants
The location and timing of coal-fired power plants in the
Without-Susitna scenario of the License Application were reviewed to
ensure that the location of power plants considered economic and
system planning perspectives.In the License Application,it was
assumed that the initial coal-fired power plant site development would
take place near the Beluga coal field,due to its proximity to the
Anchorage load center.A subsequent review of this assumption was
made which recognized the geographical limitations on the availability
of natural gas requiring that all combined cycle and simple cycle
gas-fired power plants be located in the Cook Inlet region of the
Railbelt.The only alternative available in the Northern Railbelt in
the Without-Susitna plan is coal-fired power plants.A comparison was
therefore prepared between the License Application expansion plan and
a plan called the IINenana plan.1I The Nenana plan assumes the initial
coal-fired power plants would be constructed in the Northern region of
the Railbelt and fueled by the coal from the Nenana Field,rather than
constructed at Beluga.A closer matching of the ideal distribution of
generation,based on a peak comparison,is provided in the Nenana plan
rather than the License Application plan.Therefore,this plan has
been adopted.It resembles the DEIS coal scenario,where the initial
plants also are installed in Nenana.
The existing mining operation in the Nenana field
constitutes a known capacity to produce.In contrast,the development
of the Beluga field is tied to the potential existence of an export
market and the development of a larger infrastructure.On this basis,
also,a reasonable Without-Susitna expansion plan would call for the
siting of the first coal-fired power plant (two 200 MW units)in the
Nenana region.
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5.3.3 Location of Gas Fired Power Plants---------
As previously noted,the Without-Susitna plan assumes that
all combined cycle and simple cycle power plants will be fueled from
Cook Inlet region natural gas supplies.
Specific site locations would likely be in the Beluga gas
field,Kenai field area,and sites located near yet undiscovered gas.
It is assumed that the natural gas powerplants would be sited close to
the source of existing transportation networks and transmission lines.
This is consistent with the License Application analysis.
5.3.4 Capital Cost Estimates for Coal-Fired Power
Plants
The License Application used capital cost estimates for
coal-fired power plants which were based upon the Railbelt Electrical
Power Alternatives study.A detailed review of the actual equipment
requirements with present labor rates,budgetary equipment quotations,
and shipping costs has caused a revision to the capital cost estimate.
The results of this review show an average capital cost of $2300/kW
installed (1982$)for a two unit coal-fired power plant in the Beluga
region.The individual installed costs are $2710/kW for the first
unit and $1880/kW for the extension unit.Based upon the cost
differential determined in the Railbelt Study between Beluga region
and Nenana region power plants,a Nenana region two-unit power plant
would have an installed cost of $2350/kW.
5.3.5 Capital Cost Estimates for Gas-Fired Power
Plants
The License Application values used for the capital cost
estimates for simple-cycle and combined-cycle power plants were based
upon work performed in the Railbelt Electric Power Alternatives Study.
Subsequent to this study,costs were developed for plants based in the
Kenai region in a study entitled nUse of North Slope Gas.n These
costs included updated technical information from original equipment
manufacturers for combustion turbines that affect unit size,
performance,and costs.As a result of this later study,the capital
costs associated with a simple cycle gas-fired power plant have been
5-4
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revised to $616/kW (1982$).For a combined cycle gas-fired power
plant.the capital costs in the Kenai region were found to be $546/kW
A review was conducted of the operation and maintenance
costs (O&M costs)associated with an Alaska based coal-fired power
plant.This review was performed to account for the changes in
environmental regulations which translate into increased operation and
maintenance expenses.In addition to the new regulatory requirements,
existing data was analyzed in detail from coal-fired power plant
operation in other parts of the country.given the absence of
comparable units in operation in Alaska.
Table 5-3 provides a summary of the costs associated with
operation and maintenance of a 200-MW unit that were developed during
the review.As noted previously.cost increases in environmental
protection systems have caused a general increase in O&M costs of
coal-fired power plants.The limited experience with this equipment
in the utility industry during the preparation of the Railbelt Study
resul ted in an overly optimistic proj ection of system performance.
The updated review indicates that higher maintenance costs should be
assessed to the environmental control devices.
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(1982$)•
5.3.6 Operation and Maintenance Cost Estimates for
Coal-Fired Power Plants
In addition to environmental changes.actual utility labor
rates were used to establish costs in Alaska,as well as
transportation and construction costs associated with unit operation.
The basis for these values are shown in the footnotes to Table 5-3.
5.3.7 Operation and Maintenance Costs of Gas-Fired
Power Plants
The gas-fired 200-MW power plants were configured first
around the 200-MW combined cycle system (nominal rating)utilizing two
70-MW nominal rated gas turbines exhausting the products of combustion
to a waste heat recovery boiler,which in turn provides steam at 850
psig,950°F to a60-MW steam turbine generator.The second gas-fired
option is a 200 MW simple cycle plant configuration.represented by
5-5
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three 70 MW combustion turbines operating with individual inlet and
exhaust systems,and with no waste heat recovery.
An analysis of operation and maintenance expenses was
conducted for both cycle configurations utilizing utility report O&M
costs,original equipment manufacturers suggested maintenance
intervals,and FERC operating records.As the analysis progressed,it
became evident that operation and maintenance costs differed for
utilities operating units in the Lower 48 states from the Alaska
utilities.As evidenced by the data,the Alaska utilities operate
their units base loaded on average over 8,000 hours per year,while
the Lower 48 utilities operate their simple and combined cycle plants
as peaking units over the year at 2,000 to 4,000 hour intervals.For
this reason,the reported costs for the Alaska utilities were utilized
in this analysis.The combined cycle plant operation and maintenance
costs were broken into fixed and variable costs and adjusted for site
conditions.The fixed costs were approximately $11.75/yr./kW while
the variable costs were $O.54/MWh.
For the simple cycle plant utilizing three 70 MW (nominal)
gas turbines,fixed costs were approximately $6.71/yr.!kW,while the
variable costs were $0.28/Mvi'h.An important aspect of the Alaska
utility fixed costs is the fact that a greater percentage of in-house
parts repair is carried out while less outside contracted maintenance
services are utilized.This is one of the contributing factors to the
higher fixed costs experienced by the Alaskan utilities than the Lower
48 utilities.
5.3.8 Cycle Efficiency of Coal-Fired Power Plants
The cycle efficiency or Net Station Heat Rate (NSHR)for
power plants is affected by three major factors.These factors are
thermal cycle efficiency,auxiliary power requirements,and fuel
conditions.
A review of the auxiliary power requirements was conducted
for coal-fired power plants of similar size with similar equipment.A
value of 8.5%of gross output was used for the auxiliary power
requirements in the Appendix studies.This value was confirmed with a
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......
-
-
....
survey of similar operating units burning similar coal.The use of
8.5%represent a realistic expected value for a 200 MW unit.The
higher the auxiliary power,the lower the net output of the plant and
higher the heat rate,and therefore the lower the overall efficiency
of the power plant.
Based upon the changes in coal quality discussed in
Section 5.4 of this document,and changes in auxiliary power
requirements,the NSHR for 200-MW units has been revised.The
revision results in an NSHR of 10,300 Btu/kWh,compared with a 10,000
Btu/kWh rating in the License Application analysis.
5.3.9 Cycle Efficiency of Gas-Fired Power Plants
The cycle efficiency of gas-fired power plants is affected
by the same factors --thermal cycle conditions,auxiliary power and
fuel quality --as coal-fired plants.Since the preparation of the
License Application,changes have occurred in values assigned to the
thermal cycle conditions and auxiliary power requirements.
In the License Application,combustion turbine performance
data was used to estimate plant performance.This information has
subsequently been revised by the equipment manufacturer based on a
later model of combustion turbine.This change affects both the
simple cycle and combined cycle gas-fired power plants.
The License Application plant characteristics assumed
different conditions with respect to the auxiliary power requirements
of the simple cycle and combined cycle power plants.The assumptions
were the use of wet/dry cooling towers and a plant performance based
upon no water injection for control of nitrogen oxides (NO).Thex
current requirement for auxiliary power includes a dry cooling tower
and water injection for NO control.x
5.3.10 Coal Quality
The License Application contains the analysis of Nenana
Field coal shown in Table D-2.3 of Exhibit D.Further investigation
into the quality of the coal from the Nenana field has been performed
and indicates that the coal performance specifications contained in
the License Application should be revised.
5-7
,-
......
-
The quality of the coal from the Usibelli Company mining
operation,which could supply coal for two 200-M-]units from a 2
million ton per year expansion,is best represented by an analysis of
the coal being burned today.Table 5-4,which is based upon average
1983 coal data from Fairbanks Municipal Utility System's (FMUS)Chena
plant,presents these data.These data were confirmed at a conference
held in Alaska on October 21-23,1980,where the average values for
the Nenana Field's Poker Flats seam were shown to be those in
Table 5-5.The Usibelli Company is currently mining the Poker Flats
seams.
The information in Tables 5-4 and 5-5 indicate that the coal
analysis presented in the License Application should be revised to
reflect flmS's 1983 average value;therefore the values shown in
Table 5-6 are used in this Appendix.
5-8
Table 5-1
AJjALYSIS OF COAL UNIT SIZE ASSUMPTIONS AND DATA
Economic Assumptions
.-
Year in which costs are quoted
Discount rate
Coal Plant Life
Planning Horizon
Load Forecast
Fuel Prices
Gas
Coal
Reliability Index (LOLP)
Spinning Reserve Criteria
1983
=3.5%
=30 years
1993-2020 by OGP
2021-2050 by extension
SHCA-NSD Update
(10%transmission
losses)
=SHCA Gas price based
on 1984 oil price
projections
=$1.70/MMBtu in 1983.
One percent annual
escalation thereafter
=0.2 days/year
=Equal to the capacity
of the largest unit
on-line in a
particular month
-
.-
Coal Plant Data -1983$
Maximum Operation and
Unit Construction Cap ita1 1 /Heat Maintenance Costs
Size Period Cost -Rate Fixed
Variable
(MW)(Yrs)(S/kw)(Btu/kWh)($/kW/yr)(S/MWh)
100 5 2,589 11,000 74.40 3.10
150 5 2,434 11 ,000 68.40 3.10
200 5 2,290 10,876 60.36 3.10
300 5.5 2,149 10,828 49.14 3.10
400 6 2,011 10,700 37.92 3.10
.!.I-
-
Includes interest during
construction periods shown.
construction at 3.5 percent for the
5-9
,~
Table 5-2
ECONOMIC ANALYSES OF COAL UNIT SIZES
Unit Size,MW 1983 Cumulative Present Worth
combinations in $1,000 to 2050
100,200,300,400 7,919
100,150,200,250 7,851
200 only 7,753
5-10
TABLE 5-3
OPERATION &~~INTENANCE COST
200 MW Coal Fired Unit 1983/$
""'"
""'"
Item
Plant Staff }j
Security 'l:../
Routine Maintenance '}../
TOTAL
Fixed Cost
$8,236,800
438,000
534,300
1,640,000
80,000
$10,929,100
Variable Cost
at 80%capacity
factor
$2,531,500
1,102,500
1,770,000
$5,384,000
Fixed Cost per kW
Variable cost per MWh
$54.65/kW
$3.84/NWh
51.36.
3.61.
Costs in 1982 $ -Based on Ebasco Fossil Plant Indices 6.4%
escalation.
Fixed Cost per kW
Variable Cost per kW
Footnotes:
!/Plant staff level of 110 personnel.86 maintenance,supervisory,
and administration personnel and 18 operations personnel.Average
hourly rate $36/hr.
'l:../Security cost based upon 2 guards,24 hours a day,365 days per
year.Average hourly rate $25/hr.
l/Based upon FERC Utility Records,conversations with utility
operations personnel,and original equipment-manufacturers estimates
of costs.
-~/Based upon original equipment manufacturers
intervals,and actual operating experience.
5-11
recommended
Footnotes:(continued)
'if Based upon 70%removal,use of limestone delivered in Anchorage
at $380/ton,and consumption of 838 lbs/hr.at full load.
£/Based upon an annual capital expenditure of $1,550,000 to dispose
of 1,670,000 ft.of scrubber sludge,fly ash,bottom ash,and lime.
7/Cost includes fuel,vehicles and repairs on vehicles based upon
operating plant data.
5-12
Table 5-4
NENANA COAL ANALYSIS
as received,1983 Yearly Average
Higher Heating Value
Btu/lb.
Moisture Content %
Ash Content,%
7,592
26.54
8.34
Source:Fairbanks Municipal Utility System
Table 5-5
NENANA RAW COAL ANALYSIS
Weight,%as received
Poker Flat
No.6
Seam
Top
Poker Flat
No.6
Seam
Top
Poker Flat
No,6
Seam
Bottom
Poker Flat
No.4
Seam
Average
No.4 &
No.6
Seams
Analysis
Volatile
Matter 32.8 35.71 34.12 32.51 33.16
Fixed
Carbon 26.54 31.40 29.83 32.51 30.88
Moisture 23.61 25.23 25.68 25.29 25.05
Ash 17.05 7.66 10.37 9.85 10.77
Higher
Heating'
Value (Btu/lb)7,022 81.36 7,516 7779 7668
Carbon 40.59 46.08 43.87 45.28 44.40
Hydrogen 5.98 6.30 6.05 6.30 6.20
Nitrogen .56 .60 .59 1.13 .86
Oxygen 35.70 39.24
38.99 37.11 37.54
Sulfur (total).17 .12 .13 .33 .24
Source:MIRL Report No.50,University of Alaska -Mining and
Mineral Resource and Research Institute (1980)
5-13
Table 5-6
1984 NENANA COAL ANALYSIS
Source:Fairbanks Municipal Utility System
""'"I
I-I
!
-
-
F"
I
-
Higher Heating
Value,Btu/lb
Moisture content,%
Ash content,%
Sulfur content,%
7,600
26
8.3
.2
5-14
....
....
....
.....
6.0 LOAD FORECAST
6.1 INTRODUCTION
The major driving force in the Alaskan economy is oil
revenues.which are dependent on world oil prices as discussed in
Chapter 2.Load forecasts for the Railbelt contained in the License
Application were made by using a series of three econometric computer
models:a petroleum revenue forecasting model operated by Alaska
Department of Revenue (DOR);the Man-in-the-Arctic Program (MAP)model
operated by the Institute of Social and Economic Research (ISER);and
the Railbelt Electricity Demand (RED)model operated by Battelle
Northwest Laboratories.The petroleum revenue model produces State
revenue forecasts based upon petroleum price forecasts.MAP converts
these revenue projections into projections of State-wide economic
conditions.including population.housing.and employment.The RED
model then uses MAP model output.along with additional data,to
produce an electrical energy and peak demand forecast for the
Railbelt.
6.2 LICENSE APPLICATION LOAD FORECAST
Table B.103 of Exhibit B of the License Application sum-
marizes the Reference Case forecast input and output data utilized in
the modeling effort for the period 1983 through 2010.This was the
License Application forecast period for both the MAP and RED models.
That table shows that Railbelt population is expected to increase from
about 320.000 in 1983 to approximately 530,000 by the year 2010.The
corresponding number of households would increase from approximately
110.000 in 1983 to 196.000 in 2010.The electric energy consumption
is predicted to increase from 2,803 GWh in 1983 to approximately 5,900
GWh in 2010.The corresponding average annual growth rate over the
period 1983 through 2010 is 2.8 percent.Peak demand is expected to
increase from about 580 MW in 1983 to approximately 1,200 MW in the
year 2010.
6-1
.....
,..
-
,...
..".
6.3 CONTINUING STUDIES
Although the three models described above undergo continuous
refinement,for the purpose of the analyses conducted in this
Appendix,the versions of the models used in the License Application
have been retained.
The variables which have been changed since the License
Application and which are put into the three models are:(1)the
world oil price forecast input to the petroleum revenue model and (2)
fuel oil,natural gas and electricity prices used by the RED model.A
comparison of the updated load forecast with that in the License
Application shows a decrease of less than 2 percent,which would have
no significant impact on these economic analyses.Therefore the
License Application load forecast was used for the studies presented
in Chapter 8.
6-2
"""
-
'"""I
i
i
-i
-
7.0 DESIGN REFINEMENTS AND REVISED PROJECT COST ESTIMATE
7 •1 INTRODUCTION
Since the filing of the License Application the Power
Authority has conducted additional geotechnical and engineering
investigations.This additional review of the area's geology and
project engineering has shown that by refining certain design
concepts,project design could be improved and the estimated
construction costs of the project could be reduced from those
originally filed.On August 14,1984,the Power Authority submitted
the proposed design refinements and revised cost estimate to the FERC.
The cost savings relating to these design refinements are taken into
account in the economic evaluation presented in this Appendix.
The design of the Susitna Proj ect as filed is fully set
forth in Exhibits A,C and D of the License Application,and no
attempt will be made here to summarize that information.Only the
specific components of the original design which are affected by the
refinements will be addressed in the following discussion.
7.2 PROPOSED DESIGN REFINEMENTS
The following design refinements are contemplated for the
Watana Development:
1.Reduced bedrock and alluvium excavation treatment for
the dam embankment foundation.
2.Revised configuration and composition of the dam and
the cofferdams'internal zoning.
3.Revised vertical setting and size of diversion tunnels
and increased cofferdam height.
4.Relocation and reorientation of the transformer
gallery,powerhouse and surge chamber caverns.
5.Revised arrangement of power conduits and power intake.
6.Increase in size of main service spillway to pass the
Probable Maximum Flood (PMF)and elimination of the
emergency (fuse-plug type)spillway.
7-1
r
i
.....
7.Revised layout of approach channels to the power intake
and spillway.
8.Construction facilities reduced in accordance with
reductions in construction work.
9.Rotational speed of turbine-generator units increased
from 225 to 257.1 rpm.
10.Underground SF6 gas-insulat:ed switchgear and and SF6
gas insulated bus to the ground surface selected
instead of an open-air switchyard supplied by
oil-filled main leads from the underground powerhouses.
11.Selection of open-cut trench instead of tunnel for
spillway chute drainage.
The savings that would result from the adoption of these
changes has been calculated to be approximately $360 million.
7.3 PROJECT COST ESTIMATE
In reanalyzing the Project in conjunction with the design
refinements,the Power Authority has had the opportunity also to
re-calculate the cost for the Susitna Project based on more refined
estimating procedures,to include cost savings in the relict channel
and to consider the Project's actual and projected pre-design
expenses.In the License Application,the Susitna Project was
estimated to cost $5.15 billion in 1982 dollars.The re-calculation
of the cost of the Project as filed has resulted in a revised cost
estimate of $5.19 billion (1982 $).Adoption of the design refine-
ments noted above would reduce the Project construction cost as noted
above to result in a revised total Project costs of $4.83 billion or a
total reduction of approximately $320 million over the License
Application estimate.
7-2
8.0 ECONOMIC EVALUATION
8.1 INTRODUCTION
This chapter summarizes the methodology and key variables
used to analyze the economic feasibility of the Susitna Project.
8.2 METHODOLOGY
The economic analyses contained in the License Application
and in this Appendix compare the costs of alternative means of meeting
the electrical demand of the Alaska Railbelt during the planning
period 1993-2051.Load forecasts were developed and energy supply
plans were formulated and compared over this planning period.For
electric generation planning,a capacity expansion optimization model
developed by General Electric --the Optimized Generation Planning
(OGP)program --was used to develop alternative equivalent expansion
plans.
The Power Authority used OGP to develop alternative electric
generation expansion plans for the period January,1993 to December,
2020 to establish the least costly system for that period with and
without the Susitna Project.In the With-Susitna case,it was assumed
that Watana would start operation in 1993,and Devil Canyon in 2002.
In that plan all of the Susitna Project's energy would be absorbed in
the system by about the year 2020.For purposes of evaluating
Without-Susitna generating plans,several different plans were
considered.Varying amounts of coal-fired and gas-fired thermal
generation were added to the existing units to create these optional
plans.The total costs for the alternatives include all costs of fuel
and the O&M costs of the generating units.In addition,the costs
include the annual investment costs of any plants and transmission
facilities added during the period.
The annual costs from 1993 through 2020 were developed by
the OGP model,and then converted to a 1982 present worth figure.The
long-term system costs (2021-2051)were estimated by extending the
2020 annual costs,with no load growth,and adjusting fuel prices to
reflect any real fuel price escalation for the 3D-year period.The
8-1
""'"
-
selection of 2051 as the last year of the planning horizon recognizes
the full 50-year economic life of the Devil Canyon project,which is
added to the With-Susitna expansion plan in 2002.This extended
period of time is necessary to ensure that the full economic lives of
hydroelectric plants are taken into account in the economic planning
process.
The With-Susitna and Without-Susitna expansion plan costs
are used to assess the economic benefits of the Susitna Project.
Benefits are based on the difference between the costs of the most
feasible,least costly Without-Susitna plan and the With-Susitna plan
(net benefits).For the Susitna Project to be considered economically
feasible,generally the benefit/cost ratio of the With-Susitna alter-
native over the Without-Susitna alternative should be greater than
one.
8.3 LICENSE APPLICATION ECONOMIC PARAMETERS
Table 8-1 summarizes the principal economic parameters that
were used in economic analysis contained in the License Application.
The studies on fuel availability and cost are contained in the License
Application Exhibit D,Appendix D-1,Fuels Pricing Studies,which are
reviewed and summarized in Chapters 3 and 4 of this Appendix.Thermal
plant characteristics and costs are discussed in Chapter 5.The
License Application Reference Case oil price forecast and load
forecast are discussed in Chapters 2 and 6,respectively.
8.4 CHANGES IN ECONOMIC PRINCIPLES AND PARAMETERS
The key variables and assumptions used in this Appendix
analysis are discussed in this section and summarized in Table 8-2.
The capital costs,fuel and operation and maintenance costs of the
alternatives have been estimated with reference to 1982 price levels.
Costs incurred in future years reflect relative price changes only.
The base year for the present worth analysis,or the year to which all
costs are discounted for comparison,is 1982.The real discount rate,
which was 3.0 percent in the License Application,was revised to 3.5
percent in this analysis to reflect a change in financial parameters
8-2
-
--
-
-
adopted by the Power Authority,after consultation with its advisors
and members of the financial community.
Recent studies on fuel availability and costs are described
in Chapters 3 and 4.A review of the construction,operation and
maintenance costs,and heat rates used in the License Application
resulted in revisions that better reflect the type of plants which
would be installed in the Without-Susitna alternative.The revised
values discussed in Chapter 5 were used in the present analysis.In
addition,more detailed estimates were made of the operation and
maintenance costs of the Susitna Project.The revised costs are shown
on Table 8-2,Page 1 of 3.
The cost estimate of the Susitna Project has been revised in
accordance with the discussion presented in Chapter 7.The economic
life of each generating plant type used in the economic analysis is
based on 20 years for combustion turbines,30 years for combined cycle
and steam turbines,and 50 years for hydroelectric plants.Transmis-
sion lines have an economic life of 40 years.These are revised
values from those used by the Power Authority for the economic studies
contained in the License Application.The reduced lifetime for
combustion turbines reflects a current Alaska Public Utilities
Commission ruling.The revised retirement schedule of existing
Railbelt generating units is shown in Table 8-3.
8.5 REVISED SYSTEM EXPANSION PLANS
The OGP-6 program was run using the revised economic
parameters and data discussed in the previous chapters.The resulting
With-Susitna and Without-Susitna system expansion plans are shown in
Table 8-4.In the Without-Susitna plan,the first two coal-fired
generating units would be installed in Nenana and the remaining four
units in the Beluga field,as more fully described in Chapter 5.The
revised Wi~hout-Susitna expansion plan differs from that presented in
the License Application by the location of the initial two coal-fired
units.The installation dates of some of the units in both the
Without-Susitna and With-Susitna plans have also changed due to
8-3
,...
-
......
,....
-
changed assumptions regarding the first plants to be added to the
expansion plans.
8.6 ECONOMIC COMPARISON
The"net benefits and benefit/cost ratio of the With-Susitna
alternative compared to the Without-Susitna alternative using the
revised parameters are set forth in Table 8-5.
Also shown in Table 8-5 are the net benefits and
benefit-cost ratio presented in the License Application.It may be
observed that net benefits have increased by $499 million and that the
benefit/cost ratio has increased to 1.41 from 1.33 based on the
revised parameters.
8-4
-.
,....
Table 8-1
Page 1 of 4
LICENSE APPLICATION ECONOMIC PARAMETERS
.-
Price Level
Base Year Present Worth A~alysis
Planning Horizon
Discount Rate
Fuel Prices
Thermal Generating Plant Parameters
Load Forecast
Economic Life of Projects --
1982
1982
1993-2020 by
OGP-6
2021-2051 by
extension
3.0%
See Table 8-1
Page 2 of 4
see Table 8-1
Page 3 of 4
Reference Case
See Table 8-1
Page 4 of 4
Large Coal-Fired Steam Turbines (greater than 100 MYl):30 years
Small Coal-Fired Steam Turbines (less than 100 MW):35 years
Oil-Fired Combustion Turbines:20 years
Natural Gas-Fired Combustion Turbines:30 years
Combined Cycle Turbines:30 years
Conventional Hydro:50 years
Diesels:30 years
Susitna Project Construction Cost,million $
-Watana
Devil Canyon
TOTAL
3,596
1,554
5,150
Susitna Project Annual Operation and Maintenance Cost,million $
-
Watana
Devil Canyon
TOTAL
10.4
4.8
15.2
8-5
Table 8-1
Page 2 of 4
LICENSE APPLICATION ECONOMIC PARAMETERS
FUEL PRICES
(1983 Price Level)
Oil Price
Year ($/bbl)Coal Price ($/MM Btu)Gas Price ($/MM Btu)
Nenana Beluga Cook Inlet North Slope
Delivered Minemouth Wellhead Delivered
1983 28.95 1.72 1.86 2.47 4.00
1985 26.30 1.77 1.92 2.16 3.64
1990 27.90 2.02 2.08 2.74 3.98
r-
Combined
1995 32.34 2.21 3.18 4.61
2000 37.50 2.33 3.69 5.35
2005 43.47 2.44 4.27 6.20
2010 50.39 2.57 4.95 7.18-2020 64.48 2.84 6.34 9.20
2030 74.84 3.13 7.36 10.67
2040 82.66 3.46 8.13 11.79
2050 91.32 3.82 8.99 12.63
8-6
Table 8-1
Page 3 of 4
LICENSE APPLICATION ECONOMIC PARAMETERS
SUMMARY OF THERMAL GENERATING PLANT
PARAMETERS/1982$
Parameter
Heat Rate (Btu/kWh)
Earliest Availability
O&M Costs
Fixed O&M ($/yr/kW)
Variable O&M ($/MWH)
Outages
Coal
200 MW
10,000
1989
16.83
0.6
Combined
Cycle
200 MW
8,000
1980
7.25
1.69
Gas
Turbine
70 MW
12,200
1984
2.7
4.8
Diesel
10 MW
11 ,500
1980
0.55
5.38
Planned Outages (%)8
Forced Outages (%)5.7
Construction Period (yrs)6
Startup Time (yrs)6
Unit Capital Cost ($/kW)1
Railbelt 2,051
Beluga
Nenana 2,107
Unit Capital Cost ($/kW)2
7
8
2
4
1,075
3.2
8
1
4
627
1
5
1
1
856
Railbelt
Beluga
Nenana
Notes:
2,242
2,309
1,107 636 869
(1)As estimated by Battelle/Ebasco without AFDC.
(2)Including IDC at 0 percent escalation and 3 percent
interest,assuming an S-shaped expenditure curve.
Source:Battelle 1983,Vol.II,IV,XII,XIII
8-7
Table 8-1
Page 4 of 4
LICENSE APPLICATION ECONOMIC PARAMETERS
REFERENCE CASE LOAD FORECAST
Net Generation2/1/Total System Sales-
Year Peak Demand Sales
(MW)(GWh)
Peak Demand
(MW)
Energy Demand
(GWh)
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
579
609
639
667
695
722
750
777
796
814
832
850
868
884
899
914
930
945
968
991
1013
1036
1059
1091
1122
1154
1186
1217
2803
2950
3096
3224
3352
3481
3609
3737
3724
3911
3997
4084
4171
4245
4319
4394
4468
4542
4652
4762
4872
4983
5093
5246
5388
5552
5705
5858
637
670
703
734
765
794
825
855
876
895
915
935
955
972
989
1005
1023
1040
1065
1090
1114
1140
1165
1200
1234
1269
1305 3 /
1339-
1373
1408
1444
1481
1519
1558
1598
1639
1681
1724
3083
3245
3406
3546
3687
3829
3970
4111
4096
4302
4399
4492
4588
4670
4751
4833
4915
4996
5117
5238
5359
5481
5602
5771
5939
6107
6276 3 /
6444-
6610
6780
6955
7135
7318
7507
7701
7899
8103
8312
1/Source:RED Model output;Table B.11?,Volume 2A,FERC License
July 1L 1983.
~/Includes 10 percent for transmission and distribution losses.
3/The load forecasts produced by the RED Model were extended from
2010 to 2020 using the average annual growth for the period 2000 to
2010.
8-8
Table 8-2
Page 1 of 3
APPENDIX ECONOMIC PARA}lliTERS
.....
-
Price Level
Base Year Present Worth Analysis
Planning Horizon
Discount Rate
Fuel Prices
Thermal Generating Plant
Parameters
Load Forecast
Economic Life of Projects
Coal-fired Steam Turbines:
Combustion Turbines:
Combined Cycle Turbines:
Hydroelectric Projects:
Diesels:
1982
1982
1993-2020 by OGP-6
2021-2051 by extension
3.5
See Table 8-2
Page 2 of 3
See Table 8-2
Page 3 of 3
License Application
Reference Case
See Table 8-1
Page 4 of 4
30 years
20 years
30 years
50 years
20 years
Susitna Project Construction Cost,million $
Watana
Devil Canyon
Total
3,361
1,469
4,830
Susitna Annual Operation and Maintenance Cost,million $
.....
Watana (initial)
Devil Canyon (initial)
Total Susitna (combined)
8-9
8.5
2.5
7.3
8-10
-
-
-
-
Table 8;...2
Page 3 of 3
APPENDIX ECONOMIC PARlJ.fETERS
SUMMARY OF THERMAL GENERATING PLANT
PARAMETERS/1982~
Combined Combustion
Coal Cycle 3/4/Turbine3 /4 /Diesel
Parameter 200 MW 228 MW--87 WI1 - -10 MW
Heat Rate (Btu/kWh)1/10,300 8,300 II ,060 II ,500
Earliest Availability 1992 1988 1985 1985
O&M Costs
Fixed O&M ($/yr/kw)l~/51.36 11.75 7.61 0.55·
Variable O&M ($/MWh)-3.61 0.54 0.28 5.38
Outages
Planned Outages (%)8 7 3.2 1
Forced Outages (%)5.7 8 8 5
Construction Period (yrs)6 2 1 1
Startup Time (yrs)6 4 1 1
Unit Capital Cost ($/kW).!.!
Beluga/Railbelt 2,300 595 471 856
Nenana 2,350
Unit Capital Cost ($/kW)~/
Beluga/Railbelt 2,552 616 479 871
Nenana 2,607
Notes:
,....
1/
2/
3/
i/
As estimated without AFDC based on 33°F rating for combustion
turbines.
Including AFDC at 0 percent escalation and 3.5 percent
interest,assuming an S-shaped expenditure curve.
Based on 33°F rating for combustion turbines.
Includes water injection for NO,control for combustion
turbines.Actual net output ISO is 217 MW and 79 MW
for combined-cycle and simple-cycle plants,respectively.
8-11
Table 8-3
REVISED SCHEDULE OF
RAILBELT RETIREMENTS
Capaci ty (MW)Retired
Combustion
Turbine Combined Annual
Year Coal Gas Oil Diesel Cycle Total Cumulative
1993 53 53 53
1994 53
1995 58 7 65 118
1996 94 94 212
1997 25 65 90 302
1998 26 26 328
1999 1 1 329
2000 21 6 27 356
2001 356
.-2002 116 116 472!2003 472
2004 472
2005 472
2006 472
2007 472
2008 472
2009 139 139 611
2010 13 13 624
2011 624
~2012 178 178 802
2013 802
2014 802
2015 802
8-12
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TABLE 8-4
REVISED EXPANSION PLANS
CAPACITY ADDITIONS
With-Susitna Expansion Plan
Railbelt Watana (1993)+Devil Canyon (2002)Without-Susitna Plan
Demand Energy Combustion Total (a)Combustible Combined Total (a)
Year Peak Requirements Coal Turbine Susitna Capability Coal Turbine Cycle Capability
(MW)(GWh)(MW)(MW)(MW)(MW) (MW) (MW)(MW)(MW)
1993 915 4397 87 539 1518 200 87 228 1408
1994 935 4492 87 1605 1408
1995 955 4588 87 1627 87 1430
1996 972 4670 1533 200 1536
1997 989 4751 1443 87 1533
1998 1005 4833 1417 1507
1999 1023 4915 1416 1506
2000 1040 4996 87 1476 87 1566
2001 1065 5117 1476 1566
2002 1090 5238 635 1995 174 1624
2003 1114 5359 1995 1624
2004 1140 5481 1995 1624
2005 1165 5602 1995 200 1825
2006 1200 5771 1995 1825
2007 1234 5939 1995 1825
2008 1269 6107 1995 1825
2009 1305 6276 1856 200 1886
2010 1339 6444 49 1892 1873
2011 1373 6610 1892 87 1960
2012 1408 6780 87 1801 200 1982
2013 1444 6955 174 1888 87 1982
2014 1481 7135 174 1975 1982
2015 1519 7318 87 1888 174 2069
2016 1558 7507 1975 2069
2017 1598 7701 1975 200 2182
2018 1639 7899 87 1975 2182
2019 1681 8103 2062 87 2269
2020 1724 8312 200 2175 87 2269
(a)Includes existing generation plants less retirements.
Table 8-5
NET BENEFITS AND BENEFIT-COST RATIO OF
WITH-SUSITNA ALTERNATIVE
1982 Present Worth
License
Application
Revised
Analysis
Costs of Without Susitna Plan 7,316 8,025
f!l11IB!Costs of With Susitna Plan 5,489 5,699
Net Economic Benefits 1,827 2,326
Benefit Cost Ratio 1.33 1.41
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8-14