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ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
DESIGN TRANSMITTAL
SUBTASK 6·36 -GENERATION PLANNING
PARAMETERS
JANUARY 1981
~CRES AMERICAN INCORPORATED
1000 Liberty Bank Building
Main at Court
Buffalo, New York 14202
Telephone (716) 853-75.25
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TABLE OF CONTENTS
1 -INTRODUCTION • • • • • • • • 0 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • ~ •
1.1-Objective ··························~········c··········
1.2 _,Approach 'to Analysis ................. ~ ..•..•.•.. ~ ....•...
1.3-Contents of Transmittal ................................ .
2-BASIC ASSUMPTIONS ··············~·····························
2c1 -Period ·of Analysis , .. -. ....••....•...• w ................... .
2.2 -Cost Esti.matiria ..... · •.•.•.... ~ ............................. .
2.3-Interest Rates"''and Annual Carrying Charges ·······e·····
2.4 -Cost Ex cal ati on Rates .. ., ............................... .
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3 -PLANNING METHODOLOGY • • • ... • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • 9
3.1 -Alternative Criteria ....... e.............................. 9
3.2 -Load An-a,lysis ................................... ;o......... 9
3.3-Planning Under Uncertainty ···-········~················ 9
3.4-Target Generation Plant Reliability •.•................. 11
3.5-Interconnection Capability................................. 11
3.6 -Base System .................... .., . ... . . . . . .. . ... . . .. . . . . . . . . . 11
4 -ATIACHMENT
-Letter dated January 20, -1981 from APA to Acres
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I LIST OF TABLES
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2 - 1
Page
Annual Fixed Carrying Charges Used in
Generation Planning Model • . .. . • . .. . • . . . • . . • . . . • . • • . . . • . . . 6
I 2 - 2 Fuel P~ices and Escalation Rates ........................ "... •. 7
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2 - 3 Summary of Economic and Financial
I Parameters for Generation Planning ...................... ,. 8
I 3 - 1 Load and Energy Forecasts .
-Alaska Rai lbelt Area ................................... .
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I 3 - 2 1980 Railbelt Existing Capacity ··H······~················· 15
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1 -INTRODUCTION
1.1 -Objective
The objective of this design transmittal is to document planning parameters to
be used in the generation system analyses of Subtask 6.36c The analyses will
involve making comparisons of alternatives with the assistance. of a productio-n
costing model. Costs will be spread over the study per-iod as appropriate and
compared on a present worth basis. The intent of the Subtask 6.36 analyses will
be to provide cost, size and timing input for selection of one or more Susitna
alternatives.
1.2 --~preach to !\nalysis
It is proposed that as a public investment, the Susitna project be evaluated
fh"st from a public or economic perspective, using economic parameters. Init·ial
analysis and screening of Susitna candidates will be supported by a numerical
analysis and a system-wide generation planning model (OGP-5}. A financial or
cost of power perspective and correspondin·g parameters wi11 also be adopted, but
only for those candidates that are judged most favorable fran the economic
evaluation. That is, the economically viable proposals wf11 be simulated using
the same generation planning model to determine the cost of power with and
without the proposed Susitna project(s). -
The differences between economic and financial perspectives pertain to the
following paramete~s.
(a) Proje.ct Life
In economic evaluations, an economic life is used without regard to the
terms (repa)111ent period) of debt ·capital employed to finance the-p·?oject ..
C()st of power (or. financial) perspective.uses ·an amortization period that is
tied to the terms. of financing. Retirement period (po.l icy) should be.
equivalent to project life in economic evaluations; cost of power ana~ysis
may use a retirement period that differs from the amortization pet'iot:L
(b) Denomination of Cash Flows and Discount Rates ..
The economic evaluation will use, real dollars and real discount, rates that·
exclude the effects of general price inflati~m with the exception of fuel
escalation. Cost of power analysis is in nominal or escalated dollar terms;
that is, it uses escalated cash flows and nominal interest rates .
. (c) Taxes and Subsidies
These intra-state transfer pa~ents are excluded from the economic analyses
and considering the current status of taxation needs in Alaska, taxes will
be considered as zero for the cost of power analysis,.
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(d) Market or Shadow Prices
Whenever market and shadow prices diverge, economic evaluations use shadow
prices (opportunity costs or values). Cost of power analysis uses market
prices projected as applicable based on Subtask 6.32 output~
The vaiues proposed in this transmittal are considered to be estimates. These
. values will be reviewed and updated as necessary when various studies are
undertaken in other subtasks. The planning parameters addressed are selected as
those which will be crit1ca1 to project analysis. These parameters are those
which impact all areas of system planning. They are not intended as a
substitute for data to be developed in other task 6, 9 or 11 subtasks but will
supply a common basis for costing and eval uatirJn of alternatives.
The parameters provide a basis for cost estimat'ion, interest rates, escalation,
load analysi·s, system reliability -and interconnection capabilities. Most
parameters cannot be associated with a single assumed value. At this time it is
not possible to define most likely or expected values with precision, and not
desirable to assume an exact value.
Initial trail values will be used for screening and will not be designated as
most likely or expected. They will represent a reasonably conservative vi~w.of
moderat-e values. The scenarios developed using these moderate parameters are
referred to herein as the base case. Sensitivity testing will be undertaken
using associated "high" trial values and 11 1ow" trial values. ·High and low trial
values should not be interpreted as extreme limits rather, a reflection of an
expected range. If a generation development approach is found to be reasonably
insensitive to high, mo(jerate and .low parameter· values, this would indicate the.
robustness of the development with respect to this parameter, a useful measure
of its va'lue. Initial screening will not be concerned with parameter robustness
as a selection criteria, but later sct-eening will take this measure into
account.
'It is important to note that application of the various parameters contained.
herein will not necessarily provide an accurate reflection of the true life
cycle cost of any single generating resource of the system. From the public
(State of Alask.a) perspective, the relevant J:WO,iect costs are based on
opportunity values and exclude transfer pa)111ent!; such as taxes and subsidies.
This comparative <:analysis of project economics amd state net economic benefits
will be addressed under Tas~ II ..
1.3 -Contents. of Transmittal
This transmittal contains study parameters separated into basic assumptions and
methodology. The assumptions include those values asso,ciated with cost
estimating, interest rates, period of analysis and cost escalation. Methodology
addresses generat.ion plant reliability, interconnection capability, alternative
criteria and load forecasts.
APA 1s comments on this design transmitta 1 are incorporated in the attachment ..
2
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2 -BASIC ASSUMPTIONS
2~1 -Period of Analysis
.
The time period Which will be modelBd in the generation planning phase will
extend from the present to 2010, corresponding to the ISER forecasts. It is
realized that the project 1 ife of .all Susitna alternatives may not be completed
in this period. However, the P~"'oject 1 ife cycle economics are not the primary
consideration of the generation planning subtask. Full life cycle analysis will
be addressed in Task 11. If necessary, to confirm cost trends, system costs may
be analyzed for an additi.onal per·iod beyond 2010. Annual system costs w111 be
present valued to the year 1980 in all cases.
./"
2. 2 -Cost E~)t imat in_g_
Cost estimates for generating .alter-natives developed for the generation planning
studies, except for Susitna hydroelectric alternatives, have been obtained from
previous studies of Alaska hyrdoe1(~ctric and thermal generating sources. These
existing estimates will be compa.red for consistency, accuracy, and level of
detail in Subtask 6.32 and 6.33 •
Cost estimates will be based on a January 1, 1980 price level, to be consistent
with work performed.in Subtasks 6.03 and 6.06. Costs will be updated to this
level using the Handy-Whitman Index of Public Utility Construction costs,
compiled by Whitman, Requardt and Associates. The indices for the Pacific Coast
Region will be used. Although this region does not include Alaska, it is·
expected to reflect Alaska price escalation reiationships.
Where appl ical11e the contingency factor to be used on project prei iminary
.construction cost estimate is 20 percent for hydro alternatives and 16 percent
for thermal alternatives. In addition, a 12 percent allowance for engineering,
administration and construction managanent will be placed on the subtotal of
construction cost plus contingency for projects greater than 100 MW and 14
percent engineering/administration will be added to projects less than 100 MW.
These factors are specific to the Task 6 alternative analysis and will be
reexamined as necessary for co.st estimation of other study elements.
Interest during construction (lOC) is accounted for by compounding the annual
investment expenditures to the in-service year of the project and comput.ing the
equivalent annual capital cost based on this 'future value' of the investment.
The interest rate used to compute future values will correspond to those
selected for economic and financial evaluations ..
2.3 -Interest Rates and Annual Carrying Charges
Generation' planning. based on economic parameters and criteria will use a 3
percent real discount rate in the base analysis. This figure corresponds to the
historical and expected real cost of the debt capital. s·ensitivity analysis
will examine in 1981 the effects of low and high real discount rates, using a
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range of 1 .. 5 percent (recent re.al return on Alaska P~rmanent Fund investments)
to 5 per ... cent. The issue of tax-exempto financing does not impinge on these
economic evaluations. ·
Financial or cost of power analyses require a nomina.l or market rate of interest
for discounted cash flow analysis. This rate will depend on~ among others,
general price inflation, capital structure (debt-equity ratios) and tax-exempt
status c In the base case~ a general rate of price inflation of 7 percent is
assumed for the period 1980 to 2010. Given a 100 percent debt capitalization
and a 3 percent r~eal discount rate, the ap~ropriate nominal interest rate is
approximately 10 percent in the base case._/
To calculate annual carrying charges:! the following assumptions were made
regarding the economic life of various power projects.
0 Large steam plant -30 years
0 Small steam plant -35 years
0 Hydroel~ctric project -50 years
0 Gas turbine, oil-fired -20 years
0 Gas turbine~ gas-fired -30 years
0 ·Diesel -30 years
' It should be noted that the 50-year 1 ife for hydro projects was selected as a
conservative estimate and does not include rep 1 a cement investment expenditures.
The factors for insurance costs (0.10 percent for hydro projects and 0.25
percent for all others} are based 'Gn FERC guidelines.Y State and federal
taxes were assumed to be zero for all types of po\'Jer projects. This assumption
is valid for planning based on economic criteria since all intra-state taxes
should be excluded as transfer pa)ments from Alaska's perspective. The
subsequent financial analyses may relax this assumption if non-zero state and/or
local taxes or pa)fllents in ,.lieu of identified. Table 2-1 summarizes the annual
fixed carrying charges relevant to the generation planning analysis based .on
economic and financial parameters.
•t
2.4 -Cost Escalation Rates
In the initial set of generation planning parameters~ it is assumed that all
cost items except energy escalate at the rate of general price escalation (7
percent per year) . This results in rea 1 growth rates of zero percent for
non-energy casts in the set of economic parameters used in real dollar
generation planning and nominal growth rates of 7 percent for the subsequent
escalated dollar cost of power analysis.
_l/ -
2/ -
The nominal interest rate is computed as (1 + inflation rate} x (1 + real
interest rate), or 1~07 x 1.03.
Federal Energy Regulatory Commission, Hydroelectric Power Evaluation~
Washington, August 1979.
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Base period (January 1980) energy prices will be estimated based on both market
and shadow {opportunity) values. The initial set of generation planning
parameters will use base period costs (market and shadow prices) of $1.15/106
Btu and $4.00/106 Btu for coal and distill ate resgectively. For natural gas 3
the current actual market price is about $1.05/106 Btu and the shadow price is
estimated to be $2.00/106 Btu. The shadow price for gas represents the
expected market value assl.liling an export market'were developed. This assumption
and value is to be used for both the economic and cost of po\'Jer analysis.
Real growth rates in energy costs (excluding general price inflation) are shown
in Table 2-2. These are based on fuel escalation rates from the Department of
Energy (DOt) m jd-term Energy Fq_recast ing System for DOE Region 10 ( i ncl ud i ng the
States of Alaska, Washington, Oregon and Idaho) .3/ Price escalators
pertaining to the industrial sector were selected over those avail able for the
commercial and residential sectors to reflect utilities' bulk purchasing
advantage. A composite escalation rate has been computed for the period 1980 to
1995 reflecting average compound growth rate per year. As DOE has suggest~d
that the forecasts to 1995 may be extended to 2005, the composite escalation
rates are assumed to prevail in the period 1996 to .2005. Beyond 2005, zero real
gro\"lth in energy prices is assiJlled.
In sensitivity analysis~ the impacts of alternative energy price escalators will
be analyzed with respect to the economic vi ab i1 ity of proposed Susitna
developnents. This analysis will include a case where fuel prices are held
constant in real terms.
For cost of power analyses., the nominal ( inflation-inclusive) rates of energy
price escalation will be used. These .J.re defined as (1 + general price
inflation rate) x (1 +energy price escalator}. For example, using 7 percent
and 3 percent values for the rates of general price inflation and fuel prices,
the nominal escalator for fuel would be 1.07 x 1.03, or 10.2 percent.
Table 2-3 s umnari zes the sets of economic and financial parameters proposed for
generation planning.
3/ Department of Energy, Office of Conservation and .Solar Energy, Methodolog,x
and Procedures for Life Cycle Cost Analysis, Federal Register, October 7,
i980. -
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I PARAMETERS
I ECONOMIC PARAMETERS
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Cost of Money
Sinking Fund
Insurance
TOTALS
I FINANCIAL PARAMETERS
I Non-exempt
Cost of Money
Amortization
I Insurance
TOTALS
I Tax-exempt .
Cost of Money
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Amort i zat ion
Insurance
TOTALS
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TABLE 2-1
ANNUAL FIXED CARRYING CHARGES
USED IN GENERATION PLANNING MODEL
PROJECT LIFE/TYPE
30-Year
Thermal
%
3.00
2.10
0.25
5.35
10.00
0.61
0.2.5
10.86
8.00
0.88
0.25
9.13
35-Year
Thermal
%
3.00
1.65
0.25
4.90
. 10.00
0.37
0.25
10.62
8.00
0.58.
0.25
8.83
50-Year
Hydro
%
3.00
0.89
0.10
3.99
10.00
0.09
0.10
10.19
8.00
0.17
0.10
8.27
20-Year
Thermal
%
3.00
3.72
0.25
6.97
10.00
1.75
0.25
12.00
8.00
2.19
0.25
10.44
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TABLE 2-2
FUEL PRICES AND ESCALATION RATES
Base Period (January 1980)
Prices ('$/million Btu) Natural Gas
f~arket Prices $1.05 _
Shadow (Opportunity) Values 2.00
Rea 1 Esc a 1 ati on Rates (Percentage)
Change Compounded An~ually) ·
1980 --1985 '
1986 -1980
1991 -1995
Composite (average) 1980 -1995
1996 -2005
2006 -2010
1.79%
6.20
3.99
3.98
-3.98
0
7
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Coal
$1 .. 15
1.15
9.56%
2.39
-2.87
2.93
2.93
0
Di sti 11 ate
$4.00
4.00
3.38%
3.09
4.27
3 .. 58
3 .. 58
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TABLE 2· 3 -
SUMMARY OF ECONOMIC AND FINANCIAL PARAMETERS FOR GENERATION PLANNING
1 -Base Period (January 1980)
Energy Prices {$/million Btu)
1.1 -Natural Gas
1.2 -Coal
1. 3 -Di s t i 11 ate .
2 -Genera 1 Price Inflation Per Year (%)
3 -Discount & Interest Rates Per Year (%)
3.1 -Real Discount Rate
3.2 -Nominal Interest Rate
( Non-_exempt Case)
3.3 -Nominal Interest Rate
{Tax-exempt Case)
4 -Non-energy Cost Escalation
Per Year (%)
5 -Energy Price Escalation Per Year
5.1 -Natural Gas
1980 -2005
2006 -2010
5.2 -Coal
1980 -2005
2006 -2010
5 .• 3 -lJisti 11 ate
1980 -2005
2006 ... 2010
6 -Economic Life
6.1 -Large Steam Turbine
6.2 -Small Steam Tut~bine
6.3 -Hydro
6.4 -Diesel and Gas Turbine
(Gas-fired)
6.5 -Gas Turbine (Oil-fired)
7 -Amortization Period
7.1 -Steam
7.2 -Hydro
7.3 Diesel and Gas Turbine
(Gas-fired)
7.4 ~ Gas Turbine (Oil-fired)
(%)
_§~neration Planning Analysis
Economic*
2.00
1.15
4.00_
not applicable
3
not applicable
not applicablE
0
3 .. 98
{)
2.93
0
3.58
0
30
35
50
30
20
not applicable
· not applicable
not applicable
not applicable
Financial*
2 .. 00
L.l5
4.00
7
not app 1 icab l e
10
8
7
11.26
7.00
10.14
7.00
10.83
7.00
not applicable
not appl icab 1 e
not applicable
not app 1 icab 1 e
not applicable
30
50
30
20
*Note that economic and financi a1 parameters. apply to re.a1 ool 1 ar and escalated
dollar analyses re-spectively.
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3 -PLANNING METHODOLOGY
3.1 -Alternative Criteria
Generation alternatives will be selected for inclusion in planning scenarios
based upon relative merits in the area of fuel availability, environmental and
-technical viability, robustness with respect to inflation and other parameter
changes,-oper.ating characteri-stics and costs. In effect, if two alternatives
are comparable in all other areas except cost, the less expensive alternative
will be used in generation planning, and the more expensive alternative will be
rejected.
A base scenario with and without the Susitna alternatjves will be estab1 ished,
made up of those alternatives which are the least expensive among viable
altern at ive~s. The resultant selection of a Susitna alternative will be tested
against the existing systen in competition with these viable alternatives and
with furthmr testing as to the sensitivity of cost to selected parameters.
. 3.2 -Load Analysis
The forecasts to be used for generation planning wi 11 be based on Acres analysis
of the ISI:R energy forecast. The energy forecast that will be used by Acres as
the basis for generation planning is the mid-range forecast. Sensitivity
analyses will be carried out using variable loads developed using the ISER
scenarios, of high and low economic activity and government spending.
The energy and load forecasts developed by ISER and Woodward Clyde Consultants
include energy projections from self-supplied industrial and military generation
sectors. It is forseeable that these markets will be unavafl able for the future
electrical suppliers to a large extent. By the same token, the capacity owned
by these sectors will not be avail able as a supply by the general market.
A review of the industrial self suppliers indi-cates that they are primarily
offsho~e operations, drilling operational and others which would not likely add
nor draw power from the system. Thus, th9se amounts have been deleted from the
ISER totals .
Additionally, although it is considered likely that the military would purchase
available cast effective power from a general market, much of their capacity
resource is tied to district heating systems, and thus waul~ need to contiTroe
operation. For these reasons only one-third of the military generation total
will be considered as a load on the total system. This amount is about 4
percent of tot.al energy in 1980 and decreases to 2.5 percent in 1990. This
method of accounting for these loads has no real effect total capacity additions
needed to meet projected loads after 1.985.
The adjusted forecast was used in generation planning as shown in Table 3-1 ..
3.3 -Planning Under Uncertainty
In order to. incorporate the variable forecasts and uncertainty of the load
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forecasts into planning, a probability based 1 oad model ·_Jeature of the OGP
program will be used.. A bried -description of this feature follow!:,.
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The middle level forecast ·or most likely forecast, is introduced into the
program in,detail. This would include dai.ly load shapes, monthly variability
and annual growth of peaks and energy. -Additio_nal variables are added which
introduce forecast uncertainty in terms of higher and 1 ov1er 1 e.veifs of peak
demand and the probabH ity of the occurrence of these forecasts. For example:
in year 1985 the middle level demand forecast entered is 1000 MW., Variable
forecasts are enter·ed for 850, 900, 1100 and 1.150 MW, with associated
probabilities of occurrence of .10, .. 20~ .20 and .10, leaving the middle. level
as .40.
The OGP program will use this variable forecast in generating system reliability
calculation only. A loss of 1 oad probability will be calculate~d for each
projected demand level as compared to the available capacity and a weighted
average will be taken. This loss of load probability wil"l them be used for
capacity addition decisions. After capacity decisions are madta, the program
uses the middle 1 evel forecast detail for operating the production cost model.
This method of deal ing with uncertainty is directly a ppl i cab l!a to the data
available for 6.36 studies. There are five forecasts which could be plugged in
to the reliability calculations, the three by ISER and the two extremes
ca 1 culated by Acres. Subjectivity is reduced to the decision of placing
probab il it i es on the 1 oad forecasts. ·
The probability set will be the same as that intrQGuced in the. example. Thts is
based on the assumption that each outside forecast is half as likely to happen
as the adjacent foreGast towards the middle. The 1 oads and probab i1 ity \'lill be
analyzed as:
FORECAST
LES-LG*
LES-HG
MES-~1G
HES-MG
HES-HG
*ES -Economic Activity
G -Government
L s M ~ H -Low, M ed i urn, Hi g h
Probability Set 1
.10 .zo
.40
.20
.10
An inquiry will be made to ISER to gain their opinions of these probability ~sets
and invite a probability set of their own.
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3.4 -Target Generation Plant Reliability
In order to perform this system study, a criteria for generating plant system
reliability are necessary. These criteria are important to determine the
adequacy of the available generating capacity as well as the sizing and timing
of additional units.
There appear to be no specific criteria currehtly applied to generation planning
in the Rail belt area. The primary reason for this is that utilities have
developed individually without the benefits of reliable· interconnections .. Since
Susitna planning is to meet region needs some 15 to 20 years hence, it is
assumed that within this time frame an interconnected system will exist or be in
the process of implementation. There are two alternative methods to account for
rel iabi1 ity which are cw~rently in wide use in eletric generation system.
planning; the use of a reserve margin or a loss of load probability (LOLP).
A reserve i11argin refers to the excess available capacity to a system during the
peak power demand of the year. Typical target reserve margins are from 15 to 25
percent~ In recent years, reserve margins have been greater than planned in
some regions due to the depressed load growth trends. These margins have in
some cases approached 45 percent.
A LOLP for a system is a calculated probability based on the characteristics of
capacity, forced and scheduled outage and cycling ability of individual units in
the generctting system. The pr.obability aefines the likelihood of not meeting
the full demand within a one year period. For example, a LOLP of 1 relates to
the probability of not meeting demand one day in one year; a LOLP of 0,1 is one
day in ten years. For this study, a LOLP of 0 .. 1 will be adopted. This value is
widely used by utility planners fn the country as a target for independent
systems. This target value will. be used both for the base plan and for
sensitivity analyses dealing with the effects of over/under c~pacity
availability.
3.5 -Interconnection Capability
The assumption of a fully int!artied system will not be assumed for generation
pl.anning. A 138 kV line will be assumed to be in place by 1984 with limited
tran~fer capabilities between Fairbanks and Anchorage. The addition of future
capacity will bear the .:ost of transmission to either the 138 kv-line, or to the
load centers, as applicable to the location of the generation alternative.
3. 6 -Base System
The system to be used as existing capacity in the Railbelt will inc'iud~ the
capacity of all utilities in the region, plus all utilities committed by these
utilities~ The Corps of Eng·ineers Bradley Lake project, although not ~{tility
owned, will also be included. To develop the existing generation rnt>del for
Railbelt utilities, a number of sources were consulted:
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-Woodward Clyde Consultants 11 Forecasting Peak Electrical Demand for Alaska's
Rai1belt11
, September, 1980.
-IECO Transmission Report for the Railbelt, 1978.
-U.S. DOE, 11 Inventory of Power Plants in the U.S.11 , April, 1979 •
-Electrical World Directory of P~blic Utilities 1979 -1980 edition.
-FERC Form 12A for the following utilities.
-Anchorage Municipal Light & Power (AMLP)
-Chugach Electric Association (CEA)
-Homer Electric Association (HEA) _
-Fairbanks Municipal Utility System (FMUS)
-Wi 11 iams Brothers Engineering Company
1978 Report on FMUS and GVEA Systems (Golden Valley Electric Association).
-Discussions with:
-AMLP -Mr. Hank Nichols
-FMUS -Larry-Co lp
-GVEA -Woody Baker
-APA -Don Gotschall
Table 3.2 summarizes the information received from these sources. Some
discrepancies \vere apparent especially with respect to AML&P and Capper Valley
Electric Association {CVEA). According to two sources, CVEA has no ins.talled
capacity and is a purchaser. At~L&P has a recently installed combined cycle
addition of 33 MW to the George M. Sullivan Plant No. 2 (Unit 6) wnich is not
reflected in the other estimates. The column: ACRES GM represents the in_stalled
capacity to be used in the OGP-5 Generation Model for Task 6.36 studies \'lhich is
a resolution of all data sources collected.
The 943.6 rv1W consists of 53 units as follows:
No. Units
1
2
18
6
5
21
53
Type .
Combined Cycle
Hydro
NG Gas Turbines (Anchorage)
Oil Gas Turbines {Fairbanks)
Coal-Fired Steam
Small Diesels
Capacity (MW)
140 .. 9
45.0
470.-5
168.3
54.0
64.9
943.6
In order to establish a retirement policy for Raflbelt utilities, a number of
references were consulted including the APA draft feasi:bility report guidelines,
FERC guidelines~ historical records and consultation with utilities, particu-
larly in the. Fairbanks area. from consideration of a'll of these sources, the
following retirement policy is ptoposed for use: ··
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0 Large Steam Turbines (> 100 MW} = 30 years
0 Sma 11 Steam Turbines ( < 100 MW) = 35 years
0 Oil-Fired Gas Turbines = 20 'years
0 Natural Gas-Fired Gas Turbines = 30 years
0 Diesels = 30 years
0 Combined Cycle Units = 30 years
0 Conventional Hydro = 50 years**
** 100 years changed to 50 years for consistency in economic approach to all
alternatives.
The Power Plant and Industrial Fuel Use Act prohibits the use of natural gas in
existing major electric generating plants after 1990. Alaska, however, \~as
exempted from that portion of the Act.
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TABLE 3-1
LOAD AND ENERGY FORECASTS* ALASKA RAILBELT AREA
Low Forecast Mid Forecast High Forecast
YEAR MW Gwh MW Gwh MW Gwh ----
1980 Base 514 2!t789 514 2,787 514 2,789
1985 578 3,158 650 3,565 695 3,859
.1990 641 3,503 735 4,032 920 5,085
1995 797 4,351 944 5,171 1,294 7,119
2000 952 5,198' 1,173 6., 413 1,669 9~153
2005 1,047 5,707 1,379 7$526 2,287 12~543
2010 1,141 6,215 1,.635 8,938 2,901 15!t 933
* Derived from the Woodward-Clyde Consultants submitta 1 of September 23, 1980,
adjusted to eliminate industrial self-supplied and two-thirds of the
military sector. ·
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TABLE 3-2
1980 RAILBELT EXISTING CAPACITY
RAILBELT UTILITY
AMLP
CEA
GVEA
F~1US
CVEA*
MEA*
HOMER (HEA)
SES*
A PAd*
TOTAL
*SES -Seward Electrical System
wee
1980
184.0
420.0
211.0
67.0
18.0
0.9
2.6
5.5
909.0
MEA -Matanuska Electrical Association
APAd - A 1 aska Power Admin i strati on
0 -:
15
Installed Capacity (1980) MW
· IECO
1978
130.5
411.0
218.6
65.5
0 .. 6
9.2
5.5
30.0
870.9
DOE
1979
148.0
402.~.2
230.0
68.2
13~0
3.0
1.7
5.5
30.0
901.6
ELEC. WO. ACRES
1979 GM
108.8 215.4
410.9 411.0
211.0 211.0
67.4 67.2
0.9 0.9
3.5 2.6
5.5 5.5
30.0 30.0
838.0 943.6
J
I ALASKA POlfER AUTHORITY
133 WEST 4th AVENUE-SUITE 31 -ANCHORAGE, ALASKA 99501
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4 -Attachment
Attachment: Be 1 uga" Coal Market Study . ·
(transmitted to Chuck Debelius·,
January '20 !'. 1981) · .. · .. · -~ ,,
16
January 20, 1981
...
Phone: (907) 277-7641
{907) 276-2715
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